2012 Court Opinion Case Summaries
Calpine Corp. v. FERC, No. 11-1122 (D.C. Cir. Dec. 18, 2012)
In Calpine Corp. v. FERC, No. 11-1122 (D.C. Cir. Dec. 18, 2012), the D.C. Circuit denied Calpine Corporation’s (Calpine) petition for review of FERC orders interpreting the agency’s authority to regulate charges to independent generators for the use of station power-"the electricity necessary to operate a generator’s requirements for light, heat, air conditioning, etc.” Slip Op. at 2. At issue was whether the FERC had jurisdiction to set netting intervals, which would in turn determine whether a generator’s use of station power was a retail or wholesale transaction. The FERC had acknowledged, on remand from an order vacated by the D.C. Circuit in Southern California Edison Co. v. FERC, 603 F.3d 996 (D.C. Cir. 2010), that it "lacked a jurisdictional basis to determine when the provision of station power constitutes a retail sale,” and determined that "the netting interval in the CAISO tariff could only govern Commission-jurisdictional transmission charges, not retail charges.” Slip Op. at 8.
Calpine challenged FERC’s order on the grounds that it failed to consider alternate grounds for jurisdiction over the netting intervals. The D.C. Circuit found that, even though FERC "[a]dmittedly . . . exaggerate[d] the impact of” Southern California Edison, the alternative bases for jurisdiction "are difficult to understand and ultimately fallacious.” Slip Op. at 10. These alternate bases included arguments that (1) the netting determination could result in undue discrimination; (2) station power somehow constitutes a wholesale transaction; and (3) the potential for conflicting state and federal regulations over the same energy requires FERC to preempt netting regulation. The D.C. Circuit found none of these arguments persuasive, and concluded that FERC’s "jurisdictional determination was not arbitrary or capricious.” Slip Op. at 17. To the Petitioner’s concerns about the effect of the order on the overall justness and reasonableness of the CAISO Tariff, the D.C. Circuit found that alternative avenues for review of those concerns were available and were not required to be addressed in the instant proceeding. Id. at 17-18.
Northern Natural Gas Co. v. FERC, No. 11-1240 (D.C. Cir. Nov. 27, 2012),
In Northern Natural Gas Co. v. FERC, No. 11-1240 (D.C. Cir. Nov. 27, 2012), the D.C. Circuit denied Northern Natural Gas Company’s (Northern) petition for review of Federal Energy Regulatory Commission (FERC) orders interpreting section 4(f) of the Natural Gas Act (NGA), 17 U.S.C. § 717c(f). NGA section 4(f) permits FERC to authorize a natural gas company to provide storage and storage-related services at market-based rates for new storage capacity related to a specific facility placed into service after August 8, 2005, even though the company is unable to demonstrate that it lacks market power. The FERC may do so only if it determines that "market-based rates are in the public interest and necessary to encourage the construction of the storage capacity in the area needing storage services” and "customers are adequately protected.” 17 U.S.C. § 717c(f)(1).
In 2006, the FERC authorized Northern to charge market-based rates for services at a new storage expansion project in Iowa, but the authorization was limited to the initial shippers who submitted winning bids in an open season and who signed precedent agreements for 20-year contracts. Northern v. FERC, slip. op. at 3 (citing Northern Natural Gas Co., 117 F.E.R.C. ¶ 61,191 at P 9 & n.4 (2006), order on reh’g, 119 F.E.R.C. ¶ 61,072 at P 1 (2007)). In 2010, Northern proposed tariff revisions seeking to extend the authorization to cover resale of market-based rate capacity that became available (1) through expiration of existing market-based rate agreements, or (2) as a result of turnback by a shipper upon bankruptcy or another event during the 20-year term of the original contracts. Northern v. FERC, slip. op. at 3. The FERC rejected Northern’s proposal to resell capacity upon the expiration of existing agreements as inconsistent with NGA section 4(f) because it related to storage capacity that Northern already had constructed, and thus was not necessary to encourage the construction of additional storage capacity, but accepted Northern’s proposal with respect to turnback capacity. Id. at 4 (citing Northern Natural Gas Co., 133 F.E.R.C. ¶ 61,210 at P 11-12 (2010), reh’g denied, 135 F.E.R.C. ¶61,085 (2011)).
In response to Northern’s challenge to the FERC’s partial rejection of its proposal, the court stated that the FERC’s interpretation of section 4(f) "is fully consistent with the obvious meaning of the statute[,]” Northern v. FERC, slip. op. at 4, and was also consistent with the FERC’s original reading of the provision, in which it emphasized that its "goal under the statute was to provide an ‘incentive to build new storage infrastructure[.]’” Id. at 5 (quoting Rate Regulation of Certain Natural Gas Storage Facilities, 115 F.E.R.C. ¶ 61,343 at P 167 (2006)). The court saw a potential inconsistency in the FERC’s decision to grant Northern’s request with respect to turnback capacity, but reconciled this element of the order with the FERC’s incentive rationale on the ground that the FERC could reasonably interpret its grant of market rates for the original 20-year contracts as encompassing replacement contracts that "fill in a gap” resulting from the failure of an original shipper. Northern v. FERC, slip. op. at 6.
Northern argued in the alternative that even if the FERC’s interpretation of section 4(f) were upheld, it should be effective only prospectively with respect to the storage expansion project at issue. Id. at 7. Northern claimed that in deciding to go forward with construction of the project it had relied upon language in a 2007 FERC order that suggested that the FERC would consider the possibility that market-based rates could apply beyond the term of the original service agreements. Id. at 7-8 (citing Northern Natural Gas Co., 120 F.E.R.C. ¶ 61,233 at P 18 (2007)). The court rejected this alternative contention, stating that Northern had not demonstrated that it actually relied upon the language in the 2007 order in deciding to construct the project. Northern v. FERC, slip. op. at 8-9. The court further concluded that even if Northern had relied upon the language at issue, its reliance would not have been reasonable, as the language was "arguably dictum” and in any event did not "suggest that market-based rates would necessarily be available” at the end of the terms of the initial 20-year contracts. Id. at 9 (emphasis in original).
International Swaps and Derivatives Ass’n v. CFTC, No. 11-2146 (D.D.C. Sept 28, 2012)
The United States District Court for the District of Columbia issued a decision in International Swaps and Derivatives Ass’n v. CFTC, No. 11-2146 (D.D.C. Sept 28, 2012) (ISDA), vacating and remanding rules that the Commodity Futures Trading Commission (CFTC) promulgated in 2011 to establish position limits on futures contracts, options, and swaps tied to 28 physical commodities, including crude oil, natural gas, heating oil, and gasoline blendstock. See Commodity Futures Trading Commission, Position Limits for Futures and Swaps, 76 Fed. Reg. 71,626 (Nov. 18, 2011) (Position Limits Rule). The Position Limits Rule was enacted by the CFTC pursuant to its authority under the Commodity Exchange Act of 1936 (CEA), 7 U.S.C. § 6a, as amended by the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act). The Position Limits Rule established caps on the maximum number of derivatives contracts to purchase or sell a commodity that an individual trader or group of traders may own during a given period. The enacted position limits established by the rule applied to both "spot-month” positions and "non-spot-month” positions. "A spot-month position limit . . caps the position that a trader may hold or control in contracts approaching their expiration. A non-spot-month position limit caps the position that may be held or controlled in contracts that expire in periods further in the future or in all months combined.” ISDA, Slip Op. at 3. The Position Limits Rule also established the circumstances under which a trader must aggregate positions held in multiple accounts or in connection with entities that a person owns or controls (Aggregation Rules).
The court stated that the main issue in the case was "whether the Dodd-Frank amendments to section 6a of the CEA mandated that the CFTC impose a new position limits regime in the commodity derivatives market.” ISDA, Slip Op. at 3.Prior to the enactment of the Dodd-Frank Act, it was undisputed that the CFTC’s authority to impose position limits under CEA section 6a was subject to the agency’s finding that such limits "are necessary to diminish, eliminate, or prevent [burdens on interstate commerce caused by excessive speculation].” 7 U.S.C. § 6a(a)(1). However, in enacting the Position Limits Rule, the CFTC took the position that the Dodd-Frank Act amendments to CEA section 6a required the agency to impose position limits on certain commodity-linked derivatives within a timeframe specified by the statute, regardless of whether the CFTC determined that such limits were "necessary” or "appropriate” to prevent a burden on interstate commerce from excessive speculation. The plaintiffs contended that, contrary to the agency’s position, the Dodd-Frank Act did not relieve the CFTC of its obligation to find that any position limits established under section 6a of the CEA were necessary to prevent an undue burden on interstate commerce from excessive speculation. Accordingly, the court stated that the case "largely turn[ed] on whether the CFTC, in promulgating the Position Limits Rule, correctly interpreted section 6a as amended by [the] Dodd-Frank [Act].” Id. Slip Op. at 10.
Because the controversy involved the CFTC’s interpretation of a statute it was charged by Congress with implementing, the court determined that it must apply the two-part test of Chevron U.S.A. Inc. v. Natural Res. Def. Council, Inc., 467 U.S. 837 (1984) to determine whether the agency’s interpretation of the statute was permissible. Under step one of the Chevron test, a reviewing court must consider "whether Congress has directly spoken to the precise question at issue.” If Congress has clearly spoken, a reviewing court must give effect to the clear intention of Congress, notwithstanding a contrary interpretation by the agency. However, if the statute is silent or ambiguous, the court will proceed to Chevron step two and defer to the interpretation of the agency charged with administering the statute if the agency’s interpretation is based on a permissible construction of the statute.
The court observed that if it determined under Chevron step one that Congress had clearly spoken on the issue of the CFTC’s discretion to implement the position limits in question, then the court would owe no deference to the agency’s construction of the statute. ISDA, Slip Op. at 14-15. The court stated that it is well-settled that a statute is "ambiguous” for the purposes of the first step of the Chevron test if the statute can be plausibly read more than one way. With this standard in mind, the court held that the interpretation of the Dodd-Frank Act proffered by both the plaintiffs and the CFTC were plausible, and found that it could not hold that either interpretation was required by the plain meaning of the statute.
In holding that the Dodd-Frank Act amendments to the CEA were, as a whole, ambiguous as to the requirement to impose position limits, the court first found that, standing on its own, the provision of CEA section 6a(a)(1) clearly and unambiguously requires the CFTC to make a finding of necessity prior to imposing position limits. The relevant portion of section 6a(a)(1) provides:
For the purpose of diminishing, eliminating, or preventing [a burden on interstate commerce from excessive speculation], the [CFTC] shall, from time to time, . . . by rule, regulation, or order, proclaim and fix such limits on the amounts of trading which may be done or positions which may be held by any person [under certain futures contracts or swaps] as the Commission finds are necessary to diminish, eliminate, or prevent such burden.
The court generally rejected several alternative arguments from the CFTC, which purported to interpret section 6a(a)(1) in a manner that would not have required the CFTC to make a necessity finding prior to imposing any position limits.
Although the district court found that section 6a(a)(1), by itself, clearly and unambiguously required the CFTC to make a "necessity finding” prior to implementing new position limits, it could not find that other provisions of the Dodd-Frank Act were equally clear and unambiguous. Specifically, the court examined several other statutory provisions added by the Dodd-Frank Act to CEA section 6a, which, according to the CFTC, required the agency to impose certain position limits without respect to the "finding of necessity” requirement of CEA section 6a(a)(1). The court conceded that these new provisions, CEA sections 6a(a)(2), (a)(3), and (a)(5), utilized "traditionally mandatory” language when describing the CFTC’s obligation to impose position limits. However, the court stated that the CFTC’s interpretation led to potential conflicts with other statutory language used in section 6a, and the court found that it must attempt to give effect to all parts of the statute to the extent possible. Although the court found that the CFTC’s reading of section 6a was not unreasonable, it stated that the agency’s interpretation was also not inevitable and therefore not mandatory. Accordingly, the court stated that it could not hold that the amendments of the Dodd-Frank Act "constitute a clear and unambiguous mandate” to impose position limits without the CFTC engaging in the "necessity finding” set forth in section 6a(a)(1).
Ordinarily, when determining that the meaning of a statue is ambiguous as to a specific issue, a court will proceed to the second step of Chevron and grant deference to the agency’s interpretation of the statute if the court finds the interpretation to be based on a permissible reading of the statute. However, in this case, the CFTC did not recognize any ambiguity in CEA section 6a, as amended by the Dodd-Frank Act. Rather, it assumed that Congress had spoken clearly and unambiguously to the effect that the agency was required to impose position limits without first engaging an a "necessity finding” under section 6a(a)(1). Because of this error, the court found that the agency did not engage in any interpretation of the statute entitled to deference under Chevron step-two. Id. Slip Op. at 36 ("It is well-settled in this Circuit that deference to an agency’s interpretation of a statute is not appropriate when the agency wrongly believes that interpretation is compelled by Congress.”) (internal quotation omitted). Accordingly, the CFTC did not claim, nor did the district court grant any deference for an interpretation of the statute under step two of the Chevron analysis.
The court remanded the Position Limits Rule with instructions that the agency "bring its experience and expertise to bear in light of competing interests at stake to resolve the ambiguities in the statute.” Id. Slip Op. at 38 (internal quotation omitted). The court stated that where an agency has failed to interpret an ambiguous statue it has been charged with administering, it "is not for the court to choose between competing meanings.” Id. Slip Op. at 38 (internal quotation omitted). Rather, the court stated that it was appropriate "to remand the rule to the agency so that it can fill in the gaps and resolve the ambiguities.” Id. slip op. at 39.
In conjunction with its remand order, the court exercised its discretion to vacate the Position Limits Rule due to the seriousness of the CFTC’s error in failing to recognize and resolve the ambiguity in the statute and the disruption that would result by allowing the rules to go into effect notwithstanding the CFTC’s erroneous understanding of the statute. The court found that the Position Limits Rule represented a significant and unprecedented change in the operation of the commodity derivatives market, which change had not yet gone into effect. Thus the court found that a vacatur of the rule before it has gone into effect would not cause a change in the status quo. The court also observed that the CFTC is currently proposing to amend its Aggregation Rules applicable to positions held in multiple accounts and among entities a person owns or controls. Accordingly, the court held that it would be far more disruptive if the Position Limits Rule were allowed to go into effect while on remand.
The district court’s opinion vacating and remanding the Position Limits Rule is currently subject to a petition for review filed by the CFTC with the U.S. Circuit Court of Appeals for the District of Columbia in Docket No. 12-5362.
Green Island Power Authority v. FERC, No. 11-1960 (Sept. 25, 2012)
In Green Island Power Authority v. Federal Energy Regulatory Commission, the United States Court of Appeals for the Second Circuit issued a non-precedential, summary opinion affirming the orders of the Federal Energy Regulatory Commission (FERC) issued on remand from the Second Circuit’s decision in Green Island Power Authority v. F.E.R.C., 577 F.3d 148 (2d Cir. 2009), which vacated a license issued to Erie Boulevard Hydropower, L.P. (Erie) under Part I of the Federal Power Act for the existing School Street hydroelectric project on the Mohawk River (Project). On remand, the FERC was required to determine whether a 2005 offer of settlement (2005 Settlement) submitted by Erie "materially amended” Erie’s 1991 license application for the Project (1991 Application) within the meaning of the FERC’s regulations. A determination that an application has been "materially amended” pursuant to section 4.35(f)(1) of the FERC’s regulations could cause delays in the review of a license application, a loss of the applicant’s priority in the application process, or the necessity for the FERC to initiate an additional public notice and comment period. See 18. C.F.R. § 4.35(c). Following the Second Circuit’s order remanding the issue, the FERC determined that the 2005 Settlement did not materially amend Erie’s 1991 Application. Following the standard set forth in Auer v. Robbins., 519 U.S. 452, 461-62 (1997), the court deferred to the FERC’s interpretation of its own regulations and concluded that substantial evidence supported the agency’s decision.
Section 4.35(f)(1) of the FERC’s regulations defines a "material amendment” to a hydropower license application as "any fundamental and significant change” to "plans of development proposed in an application for a license.” 18 C.F.R. § 4.35(f)(1). An example of a "material amendment” provided in the text of the regulation is "[a] change in the installed capacity, or the number or location of any generating units of the proposed project if the change would significantly modify the flow regime associated with the project.” 18 C.F.R. § 4.35(f)(1)(i). The FERC determined that a project’s flow regime "is the set of rules governing how flows are to be managed and released from the project,” and that its primary elements "are its mode of operation and conditions that specify the amount, location, and timing of any required flow releases.” Erie Boulevard Hydropower, L.P, 131 F.E.R.C. ¶ 61,036, 61,228 (2010), reh’g denied, 134 F.E.R.C. ¶ 61,205 (2011). The FERC has construed section 4.35(f)(1)(i) of its regulation to inquire whether the change in installed capacity itself would "cause [or] require a corresponding change” to the flow regime. Erie, 131 F.E.R.C. at 61,229.
The 2005 Settlement required a proposed 21-megawatt (MW) generation unit to be removed from the Project. While the FERC’s order on remand recognized that this would result in a change in the installed capacity of the Project, the FERC found, based upon its previous interpretations of section 4.35(f)(1)(i), that the change in installed capacity would not significantly affect the Project’s flow regime because "the project would still be required to operate in run-of-river mode and could provide the same minimum flows to the bypassed reach of the Mohawk River.” Erie, 134 F.E.R.C. at 62,017. Accordingly, because the change in the installed capacity would not alter the flow regime of the Project, either by changing the mode of operation or the amount, location, and timing of any required flow releases, the FERC determined that the 2005 Settlement did not result in a material amendment to the 1991 Application, as contemplated by section 4.35(f)(1)(i).
The court upheld the FERC’s determination in the orders on remand that the 2005 Settlement did not constitute a "material amendment” to Erie’s 1991 Application. The court stated that the "FERC has consistently interpreted the material amendment regulation to ask whether there is a causal relationship between the change in the installed capacity and the flow regime associated with the project.” Green Island, Slip Op. at 5-6. The court also upheld the FERC’s conclusion that any changes to the minimum flows proposed in the 2005 Settlement were independent of and not caused by the proposed changes in installed capacity. Id. at 6.
In addition to changes in installed capacity that require a change in the flow regime of the project, section 4.35(f)(1)(ii) of the FERC’s regulations provides that a martial amendment to an application includes "[a] material change in . . . the location of the powerhouse, . . . if the change would . . . [c]ause adverse environmental impacts not previously discussed in the original application.” 18 C.F.R. § 4.35(f)(1)(ii). The 1991 Application proposed to house the new 21-MW unit in an addition to the existing powerhouse. The 2005 Settlement required a substitution of the 21-MW unit proposed in the 1991 Application with either an 11-MW unit or with no additional unit. The court upheld the FERC’s determination that the 2005 Settlement did not constitute a "material amendment” pursuant to section 4.35(f)(1)(ii) because the proposal did not require a material change in the location of the powerhouse. The 2005 Settlement required either no new generation unit at all or the addition of a smaller 11-MW generation unit to be housed in a new powerhouse or powerhouse addition at the same location. The court held that "[i]n either scenario, the location of the powerhouse would not change because it ‘would continue to exist at the same location, either with or without a new powerhouse or an addition.’” Green Island, Slip Op. at 7-8 (quoting Erie, 134 F.E.R.C. at 62,022).
City of Redding v. FERC, No. 09-72775 (Aug. 27, 2012)
In City of Redding v. Federal Energy Regulatory Commission, No. 09-72775 (Aug. 27, 2012), the United Stattes Court of Appeals for the Ninth Circuit denied the petitions for review of several orders issued by the Federal Energy Regulatory Commission, which established just and reasonable rates for wholesale power sales in the California energy market pursuant to section 206 of the Federal Power Act (FPA).
Following the California energy crisis that occurred in the early 2000s, the FERC conducted an investigation and subsequently issued an order in which it concluded that the rates charged by sellers of wholesale energy on the markets operated by the California Power Exchange (CalPX) and the California Independent System Operator (ISO) were unjust and unreasonable. In that order, the FERC set mitigated market clearing price, i.e., the price that would have been in effect "had there been competitive forces at work,” above which refunds may be required. San Diego Gas & Electric Co. v. Sellers of Energy and Ancillary Services into Markets Operated by the California Independent System Operator and the California Power Exchange, 94 F.E.R.C. ¶ 61,245, at 61,862 (2001). In an order issued on July 25, 2001 (July 2001 Order), the FERC ordered refunds both "public utilities,” as defined by the FPA, and those entities that are exempt from the FPA’s definition of "public utilities” - i.e., governments or government-owned utilities. See San Diego Gas & Electric Co. v. Sellers of Energy and Ancillary Services into Markets Operated by the California Independent System Operator and the California Power Exchange, 96 F.E.R.C. ¶ 61,120 (2001). In Bonneville Power Administration v. FERC, 422 F.3d 908 (9th Cir. 2005) (Bonneville), the Ninth Circuit vacated and remanded the July 2001 Order, holding that the FERC lacked authority to order refunds from those entities not under its jurisdiction, namely the non-public utilities. The court in Bonneville noted that for those who purchased electricity from non-public utility sellers "the remedy, if any, may rest in a contract claim, not a refund action,” under the FPA. Id. at 925. Following the remand of the July 2001 Order in Bonneville, the FERC issued a new series of orders asserting that the FERC had the authority under FPA section 206(b) to reset the market clearing price for the CalPX/ISO transactions for the purpose of establishing a just and reasonable rate as the basis for ordering refunds from jurisdictional public utilities. See San Diego Gas & Electric Co. v. Sellers of Energy and Ancillary Services into Markets Operated by the California Independent System Operator and the California Power Exchange, 121 FERC ¶ 61,067, at 61,346 (2007), order on clarification, 121 FERC ¶ 61,188, at 61,924 (2007), reh’g denied, 127 FERC ¶ 61,191, at 61,865 (2009).
Following the issuance of the FERC’s orders on remand, several parties filed suit against non-public utilities based upon state contract claims. These suits alleged that certain power sales agreements entered into by the non-public utilities had established the contract price as the rates on the CalPX/ISO markets found to be just and reasonable by the FERC. Since the FERC had allegedly reset these rates, the suits sought contractual remedies from the non-public utilities based upon the new rates. The petitioners, non-jurisdictional entities, filed a petition for review of the FERC’s orders on remand.
In its review of the threshold issues raised by the parties, the court rejected the FERC’s argument that the petitioners lacked standing to appeal the FERC’s orders on remand. The FERC contended that the petitioners had succeeded in the FERC proceeding inasmuch as the FERC did not order the non-jurisdictional petitioners to issue refunds. Therefore, the FERC contended that the petitioners lacked standing under FPA section 313(b), 16 U.S.C. 825l(b) as an "aggrieved” party to the challenged FERC order and that the petitioners lacked standing under Article III of the U.S. Constitution. However, the court determined that the FERC’s assertion on appeal that it had the authority to reset rates for all market participants, including the non-jurisdictional petitioners, resulted in a sufficiently concrete injury to the petitioners to afford them standing. The court reasoned that the "FERC’s action to reset rates in a way that could support a contract action against [p]etitioners would have an obvious and real impact on them.” Redding, at .
The court also rejected the contention that the petitioners appeal represented an impermissible collateral attack on prior FERC orders. Several parties claimed that the petitioners failed to raise their claims regarding the FERC’s jurisdiction to reset the CalPX/ISO rates when the issue was first presented in the July 2001 Order, which was vacated and remanded by the Ninth Circuit in Bonneville. These parties asserted that in raising the issue of the FERC’s jurisdiction to reset the CalPX/ISO rates for the first time in their challenge to the FERC’s orders on remand, the petitioners were engaging in an impermissible collateral attack on the FERC’s July 2001 Order. Section 313 of the FPA provides that "[n]o proceeding to review any order of the [FERC] shall be brought by any entity unless such entity shall have made application to the [FERC] for a rehearing thereon,” 16 U.S.C. § 825l(a), and that "[n]o objection to the order of the [FERC] shall be considered by the court [on review] unless such objection shall have been urged before the [FERC] in the application for rehearing unless there is reasonable ground for failure so to do,” id . § 825l(b) (quoted in Redding at . The court quoted the D.C. Circuit’s statement that "[t]he question of whether [a party] is collaterally attacking prior orders depends on whether those orders gave sufficient notice of the rule to which [the party] now objects.” Redding, at 9666 (quoting Southern Co. Services, Inc. v. FERC, 416 F.3d 39, 44 (D.C. Cir. 2005) (internal quotation marks omitted)). The court found that the FERC had not been sufficiently clear in the July 2001 Order or in subsequent orders whether its actions would result in the retroactive resetting of the CalPX/ISO rates, and therefore, the petitioners were not sufficiently on notice of this position and should not have been expected to raise the issue on appeal of the July 2001 Order. Accordingly, the court held that the petitioners’ appeal was not barred as an impermissible collateral attack on pervious FERC orders.
On consideration of the merits, the court reviewed the FERC’s interpretation of its authority under FPA section 206 pursuant to the standards set forth in Chevron, U.S.A., Inc. v. Natural Res. Def. Council, 467 U.S. 837, 842 (1984). The Ninth Circuit concluded that under the first step of the Chevron analysis, the intent of Congress was clear that FPA section 206 does not grant the FERC the broad authority to retroactively reset rates charged by all market participants. Slip Op. at . Section 205 of the FPA gives the FERC authority over all rates charges by public utilities for the wholesale sale of power in interstate commerce and declares unlawful the assessment of any rates for such sales not determined by the FERC to be "just and reasonable.” 16 U.S.C. 825d. The court stated that under FPA section 206(a), whenever the FERC determines a rate to be unjust and unreasonable, the FERC "shall determine the just and reasonable rate . . . to be thereafter observed and in force.” 16 U.S.C. § 824e(a). The court observed that on its face, the FERC’s authority under FPA section 206(a) "is limited by being prospective only, and does not permit retroactive adjustments to rates. Redding, Slip Op. at  (citing City of Anaheim v. FERC, 558 F.3d 521, 523 (D.C. Cir. 2009)).
In 1988, Congress amended the FPA by adding section 206(b). That section gave the FERC authority to establish a "refund effective date” and to order refunds of amounts charged by a public utility in excess of the rates ultimately determined by order of the FERC to be just and reasonable. The refund effective date can be no earlier than the date a complaint is filed under FPA section 206 or the date on which the FERC publishes notice of its intention to investigate the rates of a public utility to determine whether they are just and reasonable. The public utility will be liable for refunds of rates charged above the rates ultimately determined to be just and reasonable for a "refund period,” generally determined by section 206(b) to be the fifteen months following the refund effective date. 16 U.S.C. § 824e(b). In effect, this provision allows the FERC to order refunds from public utilities for a limited period occurring prior the date the FERC determines a rate to be unjust and unreasonable. Prior to the enactment of FPA section 206(b), the FERC could only order refunds commencing on the date it issued an order finding the public utility’s rates to be unjust and unreasonable and fixing a new just and reasonable rate.
The FERC asserted in its pleadings that it has the authority under FPA section 206(b) to retroactively reset the market rates for all market participants. Although the court noted that several cases cited by the FERC appeared to suggest that FPA section 206(b) granted the FERC the authority to retroactively determine the just and reasonable rate changed by sellers in the market, the court found that none of these cases had directly addressed the issue at the heart of the case - i.e., whether section 206(b) grants the FERC authority to retroactively change rates charged by non-jurisdictional sellers. Redding, Slip Op. at . Citing the text and structure of the statute, the Ninth Circuit ruled that FPA section 206(b) does not confer this authority upon the FERC. The court noted that the structure of FPA section 206 indicated that the FERC was not granted retroactive authority to reset just and reasonable rates. The court noted that FPA section 206 "separates the power to set rates in [section] 206(a) from the power to order refunds in [section] 206(b). This bifurcation points to the unambiguous congressional decision that these provinces remain distinct.” Redding, Slip Op. at . "Section 206(a), not [section] 206(b), authorizes [the] FERC to set rates and . . . it does not permit retroactive ratesetting.” Id. The court rejected the FERC’s contention that a reading of the statute which denied the agency the authority to retroactively establish a just and reasonable rate would diminish its ability to order refunds during the refund period under FPA section 206(b). The court observed that the FERC would be free to determine the just and reasonable rates retroactively for the purposes of ordering refunds under section 206(b), without resetting the rates for all market participants. Because it determined that the statute was unambiguous on its face, the court did not proceed to determine whether the agency’s interpretation of the statute was reasonable and therefore entitled to deference under the second step of Chevron.
Although the Ninth Circuit ruled that the FERC lacked authority under FPA section 206 to retroactively reset rates applicable to all jurisdictional and non-jurisdictional sellers in the market, it nevertheless upheld the FERC’s orders as a legitimate exercise of its authority under FPA section 206(b) to "passively” determine what would have been a just and reasonable rate en route to ordering refunds only from jurisdictional entities. Redding, Slip Op. at . In several contract actions brought in other forums, it has been claimed that non-public utilities that were parties in the Redding case are liable for charges collected in excess of the just and reasonable prices subsequently calculated by the FERC for the purposes of ordering refunds under FPA section 206(b). Those non-public utilities sought to protect themselves against such contract claims by preventing the FERC from retroactively recalculating the market rates. The court noted that its decision could impact these claims, but declined clarify what effect its ruling might have on these proceedings.
In dissent, Judge McKeowan agreed with the majority’s conclusion that the FPA prohibited the FERC from retroactively resetting rates for all participants. However, the dissent disagreed with the majority’s conclusion that the FERC orders could be read to have merely determined a just and reasonable rate as a means of establishing the amount that must be refunded by jurisdictional public utilities. The dissent stated that the FERC’s orders demonstrated the agency’s intent to use its authority to retroactively reset the rates applicable to all market participants, including non-jurisdictional entities. City of Redding v. FERC, Slip Op. at 9679 (J McKeowan, dissenting), The dissent faulted the majority for improperly reading into the FERC’s orders a legal rationale that the orders themselves did not support. Id., Slip. Op. at 9681 (citing Securities and Exchange Commission v. Chenery Corp., 332 U.S. 194, 196 (1947)).
Council of New Orleans v. FERC, No. 11-1043 (Aug. 14, 2012)
In Council of New Orleans v. Federal Energy Regulatory Commission, No. 11-1043 (Aug. 14, 2012), the United States Court of Appeals for the District of Columbia Circuit upheld the orders of the Federal Energy Regulatory Commission (FERC) accepting the withdrawal of Entergy Arkansas, Inc. and Entergy Mississippi, Inc. from the Entergy System Agreement (Agreement), a rate schedule establishing an operating framework for the six Entergy companies servicing Arkansas, Louisiana, Mississippi, and Texas (the Operating Companies). The orders upheld by the court accepted the withdrawal of Entergy Arkansas and Entergy Mississippi from the Agreement without imposing conditions beyond the eight-year notice to the other Operating Companies specified in the Agreement.
The Agreement establishes a centralized process for determining when and where the Operating Companies will build new power plants within their respective territories. Under the Agreement, each of the Operating Companies is responsible for the costs of constructing and operating the generation plants in its own area and retains the rights to the energy generated from such facilities. The Agreement specifies that excess capacity from such plants must be made available to the other Operating Companies as a backstop during periods when demand exceeds the Operating Companies’ self-supply. New Orleans, Slip Op. at 2. The FERC has interpreted the Agreement to require that the cost of producing electricity be "roughly equal” among the Operating Companies. Id. (quoting La. Pub. Serv. Comm’n v. FERC, 522 F.3d 378, 384 (D.C. Cir. 2008) (Louisiana)). Because the cost of producing energy is likely to be varied as between the Operating Companies due to the different generation fuel sources employed, the FERC has required the Operating Companies with lower production costs to make "rough equalization” payments to those companies with higher expenses. Louisiana, 522 F.3d at 384.
The Agreement specifies that any Operating Company seeking to withdraw from the Agreement must provide notice of its intent to withdraw to the other Operating Companies a minimum of eight years prior to the date of withdrawal. Accordingly, on December 19, 2005 and November 8, 2007, Entergy Arkansas and Entergy Mississippi, respectively, notified the four other Operating Companies of their intent to withdraw from the Agreement. On February 2, 2009, Entergy Services, Inc., the corporate parent of the Operating Companies, submitted formal notices of cancellation to the FERC on behalf of Entergy Arkansas and Entergy Mississippi, pursuant to 18 C.F.R. § 35.15, stating that Entergy Arkansas and Entergy Mississippi would exit the Agreement. On November 19, 2009, the FERC issued an order accepting the notices of cancellation submitted on behalf of Entergy Arkansas and Entergy Mississippi. Entergy Services, Inc., 129 FERC ¶ 61,143 (2009), reh’g denied, 134 FERC ¶ 61,075 (2011). The FERC’s November 19 order found that the withdrawing entities were not required to compensate the remaining Operating Companies and were not otherwise subject to any continuing obligations to the remaining Operating Companies prior to withdrawal from the Agreement. The November 19 order found that the only obligation imposed upon the withdrawing entities was the requirement to provide notice eight years prior to withdrawal, which Entergy Arkansas and Entergy Mississippi duly provided. The Council of the City of New Orleans and the Louisiana Public Service Commission filed a petition for review of the FERC’s order with the D.C. Circuit.
Upon review, the court upheld the FERC’s interpretation of the Agreement under the Administrative Procedure Act and the deferential standard set forth in Chevron, U.S.A., Inc. v. Natural Resources Defense Council, 467 U.S. 837 (1984). The petitioners claimed that the FERC misinterpreted the Agreement, which they claimed required a withdrawing Operating Company to compensate the remaining companies for the assets taken. The petitioners further asserted that after any such withdrawal, the Agreement required a withdrawing company to continue making "rough equalization” payments to the remaining Operating Companies. Although the petitioners conceded that the text of the Agreement was silent about the rights and obligations of withdrawing companies regarding the assets under the Agreement, they argued that the Agreement’s purpose required that withdrawing Operating Companies to leave behind the assets built for the system or pay for any assets taken after the withdrawal. New Orleans, Slip Op. at 6. The court upheld the FERC’s rejection of this argument, noting that under the Agreement, each Operating Company was entitled to independent ownership of the plants constructed in its area and each company was individually responsible for the costs to build and operate such plants. Although the Agreement established a process for determining when and where plants would be built, the court found that the FERC reasonably determined that the other Operating Companies had no claim to ownership of the assets constructed under the Agreement. Id.
The court also rejected the petitioners contention that a previous FERC order interpreting the Agreement required withdrawing parties to pay fees to the remaining parties to compensate for any assets taken following withdrawal. The petitioners noted that in La. Pub. Serv. Comm’n v. Entergy Corp., 119 F.E.R.C. ¶ 61,224, 62,315 (2007), the FERC stated that given the Operating Companies’ history in planning and operating their facilities under the Agreement "it is possible that it may ultimately be appropriate to require transition measures or other conditions to ensure just and reasonable wholesale rates and services for affected Operating Company members going forward from the effective date of Entergy Arkansas’ withdrawal.” The petitioners claimed that the cited language mandated the type of exit fees they sought. However, the court noted that even though the FERC had put the Operating Companies on notice that it might impose additional conditions upon authorization to withdraw from the Agreement, the agency had not bound itself to do so. The court concluded that the FERC had reasonably determined that the eight-year prior notice provided by Entergy Arkansas and Entergy Mississippi under the Agreement had provided the remaining Operating Companies with sufficient time to undertake alternative system supply arrangements and that no further transition measures or conditions were required. New Orleans, Slip Op. at 7. The court also determined that the petitioners reliance on a 2001 FERC order mandating a withdrawing Operating Company to continue to provide rough equalization payments was misplaced, since that order applied only to companies seeking to withdraw from the Agreement prior to the eight-year notice period and did not consider the obligations of parties withdrawing after having timely provided their required eight-year notice. Id. at 8 (citing La. Pub. Serv. Comm’n v. Entergy Corp., 95 F.E.R.C. ¶ 61,266 (2001))..
Finally, the petitioners argued that because the requirement for the Operating Companies to achieve rough generation cost equalization was based upon imbalances arising from the Operating Companies’ historical practice of planning generation construction as a single system, and not on the specific contract language of the Agreement, the obligation to provide equalization payments should survive an Operating Company’s withdrawal from the Agreement. The court rejected this argument, stating that it had long held that the "rough equalization” obligation had stemmed from the language of the Agreement itself. New Orleans, Slip. Op. at 8 (citing La. Pub. Serv. Comm’n v. FERC, 551 F.3d 1042, 1043 (D.C. Cir. 2008)). Therefore, the court found that it was reasonable for the FERC to conclude that once an Operating Company leaves the Agreement, it need not continue to make the equalization payments.
Coalition for Responsible Growth and Resource Conservation v. FERC, No. 12-566-ag (2d Cir. Jun. 12, 2012), http://www.ferc.gov/legal/court-cases/opinions/2012/12-566-opinion.pdf
On June 12, the U.S. Court of Appeals for the Second Circuit issued a summary order denying petitions for judicial review filed by several environmental groups challenging the Federal Energy Regulatory Commission’s (FERC) orders authorizing Central New York Oil & Gas Company to construct and operate its MARC I Hub Line project. Coalition for Responsible Growth and Resource Conservation v. FERC, No. 12-566-ag (2d Cir. Jun. 12, 2012). In its orders approving the project, the FERC prepared an environmental assessment, issued a finding of no significant impact, and concluded that a formal environmental impact statement (EIS) was not required. Before the court, the environmental groups argued that the FERC’s environmental analysis for the project was inadequate.
The court concluded that the FERC had indeed taken a hard look at the possible effects of the project and that its decision that an EIS was not required was not arbitrary or capricious. The court stated that the 296-page environmental assessment thoroughly considered the issues, and that the FERC explained its basis for issuing the finding of no significant impact. The court added that the FERC reasonably concluded that the cumulative impacts of development in the Marcellus Shale region were not sufficiently causally related to the project to warrant a more in-depth analysis than that already provided, and that the FERC had considered and addressed the specific environmental concerns that had been identified by the commenting parties. The court, therefore, denied the petitions for review.
New York v. NRC, No. 11-1045 (D.C. Cir. Jun. 8, 2012)
In New York v. Nuclear Regulatory Commission, No. 11-1045 (D.C. Cir. Jun. 8, 2012) (New York), the United States Court of Appeals for the District of Columbia Circuit vacated and remanded to the Nuclear Regulatory Commission (NRC) a rulemaking instituted by the NRC regarding the temporary storage of nuclear waste. The court concluded that the rulemaking constituted a major federal action under the National Environmental Policy Act of 1969 (NEPA), 42 U.S.C. § 4321 et seq. and that the NRC’s analysis of the risks associated with the rulemaking was deficient inasmuch as it ignored the potential environmental effects of the federal government’s failure to secure a permanent storage repository for spent nuclear fuel (SNF) and failed to properly examine the risks associated with the long-term storage of SNF on site at nuclear plants following the expiration of the plant’s license. Accordingly, the D.C. Circuit vacated the NRC’s orders and remanded them to the agency for further proceedings consistent with the court’s opinion.
SNF, a byproduct of the production of nuclear energy, poses a dangerous, long-term health and environmental risk. "Experts agree that the ultimate solution [for the disposal of SNF] will be a ‘geologic repository,’ in which SNF is stored deep within the earth, protected by a combination of natural and engineered barriers.” New York, Slip Op. at 4. However, due to the federal government’s inability to establish such a permanent repository for the nation’s civil nuclear waste, SNF is currently placed in temporary storage on site at the nuclear plants where the SNF is generated.
The court in New York examined a 2010 update to the NRC’s Waste Confidence Decision (WCD). The NRC relies upon the conclusions of the WCD in issuing site-specific licenses and relicenses for nuclear reactors. The WCD contains the agency’s analysis and conclusions "whether there is reasonable assurance that an off-site storage solution [for SNF] will be available by . . . the expiration of the plants’ operating licenses, and if not, whether there is reasonable assurance that the fuel can be stored safely at the sites beyond those dates.” New York, Slip Op. at 5 (quoting Minnesota v. NRC, 602 F.2d 412 (D.C. Cir. 1979)).
When it was originally adopted in 1984, the WCD found, among other things, that a mined geologic repository suitable for the safe, long-term storage of SNF would be available by 2007"2009 and that SNF can be stored safely on-site at nuclear plants for at least thirty years beyond the licensed life of each plant. See Waste Confidence Decision, 49 Fed. Reg. 34,658, 34,659"60 (Aug. 31, 1984). In 2010, following public comment, the NRC updated its findings and conclusions in the WCD. Waste Confidence Decision Update, 75 Fed. Reg. 81,037 (Dec. 23, 2010) (WCD Update). The WCD Update revised the NRC’s previous findings with respect to the availability of a geologic repository. Whereas, the NRC had initially projected that a repository would be available within the first quarter of the twenty-first century, the Updated WCD found that a repository would become available "when necessary,” rather than by a date certain. Id. at 81,038. The WCD Update also revised the NRC’s findings with respect to the length of time that SNF could be stored on-site without significant environmental effects from thirty years to sixty years past the end of each reactor’s licensed life. In support of its finding regarding the length of time SNF can be safely stored on-site, the NRC discussed the environmental risks associated with continued on-site storage, including risks from pool leakage and pool fires. Relying upon its environmental analysis in the Updated WCD, the NRC issued an amendment to its existing regulation, 10 C.F.R. § 51.23(a), to enact the conclusions in the Updated WCD. See Consideration of Environmental Impacts of Temporary Storage of Spent Fuel after Cessation of Reactor Operation, 75 Fed. Reg. 81,032 (Dec. 23, 2010).
Under the NEPA, prior to undertaking any major federal action significantly affecting the quality of the human environment, a federal agency must either complete a full environmental impact statement (EIS) or complete a less-intensive environmental assessment (EA), which results in the agency’s issuance of a finding of no significant impact (FONSI). New York, Slip Op. at 7; 42 U.S.C. § 4332(2)(C). The issuance or reissuance of a reactor license is a major federal action affecting the quality of the human environment and requires the issuance of an EIS or an EA resulting in a FONSI. .New York, Slip Op. at 7 (citing New York v. Nuclear Regulatory Comm’n, 589 F.3d 551, 553 (2d Cir. 2009). The parties differed on whether the WCD, by itself, constitutes a "major federal action.” In its opinion in New York, the D.C. Circuit stated it was well established that environmental issues must "be considered at every important stage in the decision making process concerning a particular action.” New York, Slip Op. at 8 (quoting Calvert Cliffs' Coordinating Comm., Inc. v. Atomic Energy Comm'n, 449 F.2d 1109, 1118 (D.C. Cir. 1971). The court found that because the generic findings made in the WCD relating to the safety of storage of SNF would have a preclusive effect in all future licensing decisions for specific nuclear reactors (i.e., the conclusions embodied in the WCD Update could not be later challenged in a site-specific licensing proceeding) the issuance of the WCD Update and implementing regulation was "a pre-determined ‘stage’ of each site-specific licensing decision.” New York, Slip Op. at 8; 10 C.F.R. § 51.23(b).Therefore, the court determined that the rulemaking enacting the regulation constituted a major federal action under the NEPA requiring either the issuance of a FONSI or an EIS. New York, Slip Op. at 8.
The NRC contended that even if the rulemaking were considered a major federal action, the agency had properly issued an EA containing the necessary FONSI in the form of the environmental analysis set forth in the WCD Update. To the contrary, the court found that even if it assumed that the WCD Update constituted a valid EA, the analysis of the WCD Update was insufficient to support a FONSI with respect to the findings in the WCD Update that: (1) a "reasonable assurance exists” that a permanent repository would be obtained "as necessary”; or (2) that SNF can be stored safely on the site of nuclear reactors for up to sixty years following the expiration of a reactor’s license.
Specifically, the court found that the NRC had not sufficiently assessed the environmental impacts that would arise if no permanent repository were found, requiring the storage of SNF at the site of nuclear reactors on a long-term basis. The court observed that under the NEPA, an agency must examine both the probabilities of potentially harmful events and the consequences if those events come to pass. New York, Slip Op. at 12 (citing Carolina Envtl. Study Grp. v. U.S., 510 F.2d 796, 799 (D.C. Cir. 1975)); New York, Slip Op. at 18 ("[A]n agency conducting an EA generally must examine both the probability of a given harm occurring and the consequences of that harm if it does occur.”). An agency may issue a FONSI if either the probability of an event occurring is so low as to be "remote and speculative,” or if the combination of the assessed probability and harm is sufficiently minimal that the resulting expected harm is negligible. New York, Slip Op. at 12 (citing City of New York v. Dep’t of Transp., 715 F.2d 732, 738 (2d Cir. 1983)); see also New York, Slip Op. at 19 (an agency can only dispense with the assessment of the potential harm of an occurrence if the agency finds the harm in question to be so "remote and speculative” as to "reduce the effective probability of its occurrence to zero.”). However, the court stated that the NRC’s conclusion that a "reasonable assurance exists that sufficient mined geologic repository capacity will be available when necessary,” 75 Fed. Reg. at 81,041, was "a far cry from finding the likelihood of nonavailability to be ‘remote and speculative.’” New York, Slip Op. at 12-13. Given its conclusion that the NRC had not demonstrated that the likelihood of the federal government’s inability to procure a permanent storage site was "remote and speculative,” the D.C. Circuit concluded that the NRC’s analysis must include an assessment of the probability and the magnitude of the environmental effects of a failure to obtain a long-term repository, requiring the continued storage of SNF on site at nuclear plants on a long-term basis. Id. at 13. Such an analysis could support a FONSI if the agency found that the magnitude and probability of harm resulted in negligible impacts.
The court next considered the NRC’s conclusion in the WCD Update that the SNF can be safely stored on site at the nuclear plants where it is produced for up to sixty years following the expiration of the license for the nuclear plant. This analysis in the WCD Update "was conducted in generic fashion by looking to environmental risks across the board at nuclear plants, rather than by conducting a site-by-site analysis of each specific nuclear plant.” New York, Slip Op. at 13. The two primary risks that the NRC examined were the risk of pool leakage and the risk of pool fires from exposure to air. New York, Slip Op. at 14. The D.C. Circuit accepted the NRC’s generic approach to this risk analysis and did not find, as the petitioners had requested, that a site-by-site examination of the risks associated with on-site storage was required. Even so, the court held that "whether the analysis is generic or site-by-site, it must be thorough and comprehensive.” New York, Slip Op. at 16. To the contrary, the court determined that the NRC’s analysis was insufficient to support a conclusion that the agency’s findings were supported by substantial evidence. Id.
In its analysis of pool leaks in the WCD Update, the NRC acknowledged the past occurrence of "several incidents of groundwater contamination originating from leaking reactor spent fuel pools and associated structures.” New York, Slip Op. at 16-17 (quoting 75 Fed. Reg. at 81,070). While the WCD Update noted that such past occurrences had only negligible health effects, the analysis was silent regarding the probability and degree of possible impacts from future leaks. The D.C. Circuit stated that since the NRC’s analysis in the WCD Update was intended to support an extension of time for which pools are considered safe for on-site storage, a proper analysis of the risks would have been forward-looking, "to examine the effects of the additional time in storage, as well as examining past leaks in a manner that would allow the [NRC] to rule out the possibility that those leaks were only harmless because of site-specific factors or even sheer luck.” New York, Slip Op. at 17. Even granting the most deferential treatment to the NRC’s scientific and technical expertise, the court found that it could not "reconcile a finding that past leaks have been harmless with a conclusion that future leaks at all sites will be harmless as well.” New York, Slip Op. at 18.
The D.C. Circuit likewise concluded that the WCD Update’s assessment of the impact of pool fires was "plagued by a failure to examine the consequences of pool fires in addition to the probabilities.” New York, Slip Op. at 18. While the NRC determined that the probability of the occurrence of pool fires was "very low,” it did not find that the chances were so low as to be "remote and speculative.” As with the court’s rejection of the NRC’s analysis its conclusion that regarding the certainty of obtaining a suitable long-term repository, "as necessary,” because the NRC neither found that the likelihood of the occurrence of pool fires was "remote and speculative,” nor engaged in an adequate analysis of the magnitude and probability of such fires, the court determined that the agency’s analysis was not supported by substantial evidence. New York., Slip Op. at 19.
Because the NRC failed to conduct a sufficient analysis of the environmental risks of temporary on-site storage of SNF, the court ruled that it could not defer to the NRC’s conclusions in the WCD Update. Accordingly, it vacated and remanded the agency’s rulemaking orders. Although the court stated that it would not require the NRC to conduct a site-specific analysis for each plant, it noted that any generic analysis must be forward-looking and be broad enough to support the NRC’s findings. New York, Slip Op. at 20. Further, the court stated that any analysis contained in the NRC’s EA must account for the consequence of any analyzed risk, unless the NRC specifically found the probability of a given risk to be effectively zero. Id.
Williams v. Duke Energy International, Inc., No. 10-3604 (6th Cir. June 4, 2012), http://www.ca6.uscourts.gov/cgi-bin/opinions.pdf/12a0167p-06.pdf.
In Williams v. Duke Energy International, Inc., No. 10-3604 (6th Cir. June 4, 2012), the Sixth Circuit determined that the "filed-rate doctrine” did not apply to claims arising out of "side agreements” between a utility and certain customers, which side agreements allegedly provided for unlawful rebates in exchange for withdrawal of objections to a rate filing. Reversing and remanding a decision by the United States District Court for the Southern District of Ohio, the court held that the filed-rate doctrine did not apply because plaintiffs did not challenge a filed rate, but rather challenged side agreements that had not been filed with any agency.
The dispute arose out of a rate-stabilization plan (RSP) filed with the Public Utilities Commission of Ohio (PUCO) by the former Cincinnati Gas & Electric Company (Duke). Williams v. Duke, slip op. at 3-4. A number of parties challenged the RSP, including major consumers and the Ohio Consumers’ Counsel (OCC). Id. at 4. Thereafter, Duke submitted a stipulation pursuant to which a number of parties agreed to withdraw their objections to the RSP. Id. The OCC opposed the stipulation, and sought discovery to determine whether Duke had entered into side agreements in an effort to persuade large consumers to withdraw their objections to the RSP. Id.
The PUCO initially approved the stipulation, but the Ohio Supreme Court reversed the PUCO’s refusal to permit discovery of the side agreements because any inducements offered outside of the terms of the stipulation could be relevant to whether the negotiations had been fairly conducted. Id. at 4-5 (citing Ohio Consumers’ Counsel v. Pub. Util. Comm’n, 856 N.E.2d 213, 234-35 (Ohio 2006)). On remand, the PUCO rejected the stipulation because the existence of the side agreements called into question the fairness of the negotiations leading to the stipulation. Id. at 5. Instead, the PUCO approved the original RSP with modifications, and the Ohio Supreme Court upheld the PUCO’s decision over the OCC’s argument that the PUCO should have considered whether Duke engaged in illegal discounting or discrimination as a result of the side agreements. Id. at 6 (citing Ohio Consumers’ Counsel v. Pub. Util. Comm’n, 904 N.E.2d 853, 856-57 (Ohio 2009)).
Plaintiffs sued Duke and others, alleging violations of the Robinson-Patman Act of 1936, 15 U.S.C. §§13-13b, 21 (2006) (RPA) and Ohio’s Pattern of Corrupt Activity Act, Ohio Rev. Code §§2923.31-.36 (2011) (OPCA), as well as advancing a civil Racketeer Influenced and Corrupt Organizations Act (RICO) claim pursuant to 18 U.S.C. §1962(c) (2006) and common-law claims of fraud and civil conspiracy. Williams v. Duke at 2-3. The district court dismissed the case, finding that the filed-rate doctrine deprived it of federal question subject-matter jurisdiction, and further finding that the PUCO had exclusive jurisdiction over plaintiffs’ state-law claims, thereby depriving the court of diversity jurisdiction. Id. at 2.
On appeal, the Sixth Circuit stated that the filed-rate doctrine "precludes a challenge to the reasonableness of the rates of common carriers if the rates have been approved by an appropriate regulatory agency.” Id. at 7. By contrast, the district court erroneously held "that any claim that requires ‘analysis of [a] filed rate’ is barred by the filed-rate doctrine.” Id. (quoting Williams v. Duke Energy Int’l, Inc., 606 F. Supp. 2d 783, 790 (S.D. Ohio 2009)). The Sixth Circuit explained that plaintiffs did not challenge the rate established by the PUCO, but instead contended that defendants indirectly granted illegal rebates to certain favored consumers, to the detriment of plaintiffs. Id. at 9. The court added that the filed-rate doctrine applies only to filed rates, whereas the side agreements at issue had never been filed with any agency. Id. at 9-10 (citing Town of Norwood v. New England Power Co., 202 F.3d 408, 419 (1st Cir. 2000)).
Accordingly, the Sixth Circuit reversed the district court’s holding that the filed-rate doctrine deprived it of jurisdiction. Id. at 11. The court further determined that the district court’s federal question subject-matter jurisdiction was sufficient to allow supplemental jurisdiction over plaintiffs’ state law tort claims of fraud and civil conspiracy. Id. at 12.
Defendants had moved to dismiss the case for failure to state a claim pursuant to Fed. R. Civ. P. 12(b)(6), but the district court did not reach the issues raised by the motion because it believed it lacked jurisdiction. Slip op. at 12. The court proceeded to address these issues. With respect to plaintiff’s RPA price discrimination claim, the court first held that electricity is a "commodity” within the meaning of 15 U.S.C. §13(a) (2006). Slip op. at 14-15 (citing Metro Commc’ns Co. v. Ameritech Mobile Commc’ns, Inc., 984 F.2d 739, 745 (6th Cir. 1993)). The court then rejected defendants’ contention that RPA applies only to price discrimination among purchasers for resale of a purchased product. Williams v. Duke at 15 (citing FTC v. Morton Salt Co., 334 U.S. 37, 39 (1948)). The court also determined that plaintiffs adequately alleged injury and competitive disadvantage sufficient to survive a motion to dismiss the RPA claim. Williams v. Duke at 15-16.
With respect to defendants’ motion to dismiss plaintiffs’ civil RICO claim, the court noted that plaintiffs alleged transfers of money from favored customers to Duke (in the form of payments for electricity charges), from Duke to an affiliate, and from the affiliate back to the favored customers (as "rebates”). Id. at 17. The court determined that the civil RICO claim should not be dismissed because plaintiffs’ allegations set out a cognizable claim of money laundering based upon mail fraud, and that the alleged injuries suffered by the plaintiffs were "fairly traceable” to defendants’ conduct. Id. at 18-19. The court also determined that plaintiff’s OPCA and common-law fraud claims were adequate to withstand a motion to dismiss. Id. at 19-20. Finally, the court concluded that although Duke provides competitive retail electric service, it nevertheless remains subject to Ohio statutory provisions prohibiting rebates and undue preferences by public utilities, and thus the court rejected defendants’ argument that plaintiffs’ common-law civil conspiracy claim should be dismissed. Id. at 21-22.
California ex rel. Brown v. United States, No. 07-184C (Fed. Cl. May 2, 2012), http://www.uscfc.uscourts.gov/sites/default/files/SMITH.PEOPLE050212.pdf and
Pacific Gas & Electric Company v. United States, Nos. 07-157C &07-167 (Fed. Cl. May 2, 2012) http://www.uscfc.uscourts.gov/sites/default/files/SMITH.PACIFIC050212.pdf
In California ex rel Brown v. United States, No. 07-184C (Fed. Cl. May 2, 2012) and Pacific Gas & Electric Company v. United States, Nos. 07-157C & 07-167 (Fed. Cl. May 2, 2012), the Court of Federal Claims issued two identical decisions finding that: (1) the Bonneville Power Administration and the Western Area Power Administration (collectively, "Agencies”) were subject to present contractual obligations under agreements with the California Independent System Operation Corporation (Cal ISO) and the California Power Exchange (PX) to refund the difference between the price at which the Agencies sold electric power in the Cal ISO and PX wholesale markets during the California energy crisis of 2000 and 2001 and the mitigated market clearing price (MMCP) established by the Federal Energy Regulatory Commission (FERC) for that time period; and (2) that the Agencies breached their obligations by nonpayment.
The cases arose from a series of FERC and appellate court decisions concerning the Agencies’ refund obligations during the California energy crisis. In San Diego Gas & Electric Co., 96 F.E.R.C. ¶ 61,120 (2001), the FERC made two rulings in this regard. First, the FERC adopted the MMCP for the period of October 2, 2000 through June 20, 2001 (the "refund period”). The MMCP corrected the sale prices of wholesale power in the Cal ISO and PX markets by altering the pricing formulas in the Cal ISO and PX tariffs on file with the FERC. On appeal, the Ninth Circuit affirmed the FERC’s authority to correct the market clearing price during the refund period and to establish October 2, 2000 as the refund effective date under Section 206 of the Federal Power Act (FPA). However, the Ninth Circuit found that the FERC erred in excluding FPA Section 309 relief for tariff violations that occurred prior to October 2, 2000. California Pub. Util. Comm’n v. FERC, 462 F.3d 1027, 1048-49, 1051-53 (9th Cir. 2006) (CPUC) (this matter is still pending before the FERC on remand). Second, the FERC required government-owned utility sellers to make refunds along with investor-owned utilities. This requirement was reversed by the Ninth Circuit, which held that the FERC lacked the statutory authority to enforce governmental utilities’ refund obligations. Bonneville Power Admin. v. FERC, 422 F.3d 908, 911 (9th Cir. 2005) ("Bonneville”). The Ninth Circuit, noted, however, that purchasers in the Cal ISO and PX markets might have actions for breach of contract against governmental utility sellers.
In light of Bonneville, the plaintiffs - investor-owned utilities, California state agencies, and California ratepayers - all of whom were purchasers in the Cal ISO and PX markets, brought suit in the Court of Federal Claims under two alternative legal theories of contract recovery. First, the plaintiffs asserted that the Agencies anticipatorily breached their contracts by repudiating their obligation to refund their overcharges to plaintiffs, entitling plaintiffs to sue immediately for damages. Second, and alternatively, the plaintiffs argued that the Agencies had a present contractual duty to pay the refunds they owed, and that the Agencies breached that duty by nonpayment. The plaintiffs argued that the Agencies contractually agreed to abide by the prices set by the FERC, and were obligated to refund the amounts they charged in excess of those prices. California ex rel Brown v. United States, No. 07-184C, slip op. at 12 (Fed. Cl. May 2, 2012)
The court based its breach of contract determination on the second legal theory and did not address the first. The court explained that the agreements between the Agencies and Cal ISO and PX incorporated the respective tariffs of Cal ISO and PX and stated that the signatory parties would abide by the terms and conditions of the relevant tariff. Id. at 5-6. The tariffs included "Memphis clauses,” which provided parties the right to petition the FERC to correct prices it determined to be unjust and unreasonable. Id. at 17. The court determined that the FERC had authority to reset the market clearing prices and that the FERC’s price correction was prospective from the refund effective date. The court concluded that the FERC’s correction contractually bound the Agencies to pay the difference between what the Agencies charged and the MMCP, since the Cal ISO and PX issued settlement statements to the Agencies that were re-run to reflect the adjusted price and neither of the Agencies contested these re-run settlement statements. Id. at 16-19.
The court dismissed the defendants’ argument that the plaintiffs had failed to identify any obligation on the part of the Agencies to pay the plaintiffs directly. The court found that the manner in which damages eventually will be paid is irrelevant to the Agencies’ liability to refund their overcharges. Id. at 20. The court also found that letters the Agencies solicited from the Cal ISO and PX did not demonstrate that the Agencies owed no refunds and that invoicing by Cal ISO and PX was not a condition precedent to the Agencies’ duty to pay. The court found that because the plaintiffs provided the Agencies with the best information available to them regarding the amounts of the plaintiffs’ claims, the plaintiffs satisfied the requirement under the Federal Acquisition Regulations to submit a sum-certain claim to a contracting officer. Thus, the plaintiffs cause of action was properly before the Federal Court of Claims under that jurisdictional statute. Id. at 21-23.
Finally, the court denied the Agencies’ request to defer judgment in these cases until the question of the authority of the FERC to reset rates retroactively had been determined - a question presently before the Ninth Circuit in Modesto Irrigation District v. FERC, No. 09-72775, et al. The court stated that because the Ninth Circuit had previously held that the FERC is entitled to reset prices, the court was not persuaded to stay the cases before it. Id. at 13 (citing, e.g., Bonneville, 422 F.3d 908 (9th Cir. 2005); CPUC, 462 F.3d 1027 (9th Cir. 2006)).
Mobil Pipe Line Co. v. FERC, No. 11-1021 (D.C. Cir. Apr. 17, 2012)
In Mobil Pipe Line Co. v. FERC, No. 11-1021 (D.C. Cir. Apr. 17, 2012), the court vacated and remanded an order of the Federal Energy Regulatory Commission (FERC), which denied Pegasus Pipeline’s (Pegasus) application to charge market-based rates for the transportation of crude oil. The FERC allows crude oil pipelines to charge market-based rates for transportation services upon receiving authorization from the FERC. 18 C.F.R. § 342.4(b) (2011); Order No. 572, Market-Based Ratemaking for Oil Pipelines, 1991-96 F.E.R.C. Stats. & Regs. ¶ 31,007, pp. 31,179-180, 59 Fed. Reg. 59,148 (1994). Pegasus is an 858-mile, 20-inch diameter crude oil pipeline owned and operated by Mobil Pipe Line Company that transports approximately 66,000 barrels per day of Western Canadian crude oil from Illinois to Texas, which the court noted only comprises 3 percent of the Western Canadian crude oil produced. Mobil, No. 11-1021, slip op. at 5. The FERC rejected Pegasus’ request for authorization to charge market-based rates, finding that Pegasus had a 100 percent market share and thus had market power in the relevant origin market. Mobil Pipe Line Co., 133 F.E.R.C. ¶ 61,192, P 54 (2010), aff’g, Mobil Pipe Line Co. 128 F.E.R.C. ¶ 63,008 (2009). The FERC had previously determined that Pegasus lacked significant market power in the relevant destination market. Mobil Pipe Line Company, 121 F.E.R.C. ¶ 61,268, P 16 (2007). The FERC reached this decision regarding Pegasus’ market power in the origin market despite the fact that the FERC staff expert (FERC Staff) determined that Pegasus clearly lacked market power in its origin market and should be a "slam-dunk” for being granted market-based rate authority. Mobil, No. 11-1021, slip op. at 2.
FERC Staff had asserted that Pegasus was a relatively smaller pipeline that was also a new entrant to a competitive market, and the Western Canadian crude oil producers had viable and competitive alternatives to Pegasus to move their crude oil to markets. Id. at 6-8.
In rejecting the FERC’s determinations, the court stated that the FERC’s "rather extraordinary conclusion that Pegasus possessed a 100 percent market share” in the origin market was "unsustainable.” Id. at 8. The court concluded that the proper question was whether "Pegasus can be said to possess market power ... [and] could profitability raise rates for its transportation services above competitive levels for a significant period o time because of a lack of competition.” Id. The court pointed to the fact that Pegasus only transports about three percent of the Western Canadian crude oil produced each day, and stated that the answer was "an emphatic no.” Id
The court also stated that a market power analysis should look at the alternatives reasonably available to consumers and the cross-elasticity of demand that can constrain a firm’s ability to charge prices above a competitive level for a significant period of time. The court stated this involves an inquiry into the extent to which consumers will respond to an increase in the price of one good by substituting or switching to another. Id. at 9. Because crude oil in a particular area or market can either be exported out of the market or refined in the area, the competitive alternatives in crude oil origin markets include additional pipelines and local refineries. Id. The court stated that FERC Staff had determined that 97 percent of the Western Canadian crude oil gets to refineries by means other than Pegasus, and the FERC provided no explanation as to how a pipeline that only transports three percent of the oil can be said to possess market power. Id. at 9-10. The court added that while Pegasus may have been the primary means for producers of Western Canadian crude oil to get their oil to Gulf Coast markets, there was nothing "unique” about these markets that provided Pegasus with market power over the producers and shippers of Western Canadian crude oil. Id. at 11-12. The court also stated that Pegasus was a new entrant into a previously competitive market, and that "economic logic dictates” that the introduction of a new entrant into a competitive market will not make the market suddenly "less competitive.” Id. at 11. The court stated that when an agency such as the FERC is obliged to adhere to "basic economic and competition principles” the agency must follow these principles in adjudicating individual cases. Id. at 13. Finding that the FERC failed to do so, the court vacated and remanded the FERC’s order for further proceedings. Id.
Occidental Permian Ltd. v. FERC, No. 10-1381 (D.C. Cir. March 27, 2012)
In Occidental Permian Ltd. v. FERC, No. 10-1381 (D.C. Cir. March 27, 2012) (Occidental), the United States Court of Appeals for the District of Columbia Circuit dismissed a challenge to the orders of the Federal Energy Regulatory Commission (FERC) granting negotiated rate authority to Tres Amigas LLC (Tres Amigas) based upon a finding that the petitioners, Occidental Permian Ltd. (Occidental) and its subsidiaries lacked standing to challenge the FERC’s orders approving negotiated rate authority for the Tres Amigas project.
Tres Amigas has proposed to develop an energy transmission project in New Mexico, which would tie together all three of the independent electrical grids in the United States " the Eastern Interconnection, the Western Electricity Coordinating Council and the Electric Reliability Council of Texas. Currently power cannot automatically flow between, the three electrical grids and must be converted at each interchange. The Tres Amigas facility is designed to address this problem and to facilitate the movement of power across the country. The project was proposed as a stand-alone interconnection facility and regional utilities will have to expend the funds to build any new transmission lines connecting to the Tres Amigas project. Occidental Slip Op. at 2.
Historically, the FERC has relied upon cost-of-service models in reviewing and approving the rates charged by public utilities for electric transmission service under the Federal Power Act. However, the FERC has permitted merchant transmission developers, which have no preexisting transmission network in which costs can be determined and no captive customers, to request authority to charge negotiated rates, rather than cost-based rates. Id. at 3. The FERC has required project developers seeking negotiated-rate authority to satisfy criteria to ensure that negotiated rates charged are just and reasonable. Specifically, "the developer must have no captive customers, must not have the ability to exercise monopoly power, and must bear the full market risk of the project failing.” Id. (citing Chinook Power Transmission, LLC, 126 F.E.R.C. ¶ 61,134, 61,765 (2009); TransEnergie U.S., Ltd., 91 F.E.R.C. ¶ 61,230, 61,838"39 (2000)).
In 2009, Tres Amigas filed an application with the FERC requesting negotiated-rate authority for its proposed transmission service. Tres Amigas’s application stated that the project would have no captive customers and would not be located in a transmission network in which costs could be recovered. Therefore, the application contended that cost-based rates would be infeasible. Occidental, Slip Op. at 3. In its protest of the application, Occidental claimed that Tres Amigas failed to meet the criteria to qualify for negotiated rate authority because the developer would have captive customers and would exercise monopoly power while bearing none of the project’s risk. The FERC rejected Occidental’s arguments and approved the request for negotiated-rate authority. Tres Amigas LLC, 130 F.E.R.C. ¶ 61,207, reh’g denied, , 132 F.E.R.C. ¶ 61,233 (2010). Occidental filed a petition with the D.C. Circuit seeking review of the FERC orders approving Tres Amigas’s negotiated-rate authority.
The court did not reach the merits of Occidental’s challenge to the FERC’s orders because it found that Occidental lacked standing to bring the challenge inasmuch as it had failed to demonstrate "a concrete injury that has either transpired or is ‘imminent,’ that is causally connected to the agency action, and that will likely be redressed by a favorable decision from [the court].” Occidental, Slip Op. at 4 (quoting Lujan v. Defenders of Wildlife, 504 U.S. 555, 560"61 (1992)). The court considered and rejected three bases for standing alleged by Occidental.
First, Occidental claimed that public utilities near the Tres Amigas project would be required to pay the cost of constructing transmission lines to interconnect with the project and that those utilities would in turn recover the costs of that construction from regional energy consumers, including Occidental’s subsidiaries. Occidental alleged that the negotiated-rate authority granted by the FERC would lead to higher costs for its subsidiaries as consumers. The court rejected this argument as "far too speculative to represent a ‘concrete’ injury to Occidental.” Occidental, Slip Op. at 5 (quoting Lujan, 504 U.S. at 560). The court observed that "[e]ven if all of these additional events transpired, Occidental’s injury would be caused by some action other than [the] FERC’s approval of the orders before [the court].” Occidental, Slip Op. at 5. The opinion stated that Occidental’s argument relied upon assumptions about actions taken by others, which actions were not imminent or certain to occur. Specifically, Occidental’s argument relied upon the assumption that neighboring utilities would build connecting transmission lines to the Tres Amigas project, and that these utilities would recover costs from captive customers, and that doing so would result in higher rates for Occidental’s subsidiaries. The court found that Occidental had not demonstrated that any neighboring utilities were willing and able to construct interconnecting transmission lines. Even if Occidental could have done so, the court stated that the challenged FERC orders themselves would not authorize any such interconnecting utilities to charge a specific rate to energy consumers, including Occidental’s subsidiaries. "The question of what rate Occidental’s subsidiaries will pay on future connecting lines would thus be the subject of some future FERC proceeding, at which FERC would have to determine whether that rate was just and reasonable.” Occidental, Slip. Op. at 6 (emphasis in original) (citing Tres Amigas, 132 F.E.R.C. at 62,302. Occidental complained that it would be unable to challenge Tres Amigas’s negotiated-rate authority in a subsequent rate proceeding because of the sixty-day limit on filing appeals to final FERC orders. However, the court stated that there was nothing inappropriate about this result since Occidental could not demonstrate that it had actually been injured by the FERC’s orders. Occidental, Slip Op. at 7.
Second, Occidental argued that the FERC failed to impose sufficiently stringent limitations upon Tres Amigas’s negotiated-rate authority to ensure that any rates charged by the project remain at a just and reasonable level. Occidental urged that this failure would lead to higher prices ultimately paid by its subsidiaries as energy consumers. The D.C. Circuit rejected this argument because the FERC had not yet approved any specific rates for the project. The court acknowledged that it had previously held that the "‘failure to impose more stringent limitations on the prices that . . . utilities would be allowed to charge’ is a cognizable injury.” Occidental, Slip Op. at 8 (quoting Envtl. Action v. FERC, 996 F.2d 401, 407 (D.C. Cir. 1993)). However, the opinion noted that the court had "always required actual, decided-upon numbers and limitations before finding an injury. . . because without them, [the court] would have no way of assessing a claim of unreasonableness.” The court observed that "once rates are set, Occidental will have the chance to challenge them.” Occidental, Slip Op. at 8.
Finally, Occidental alleged that its power marketing affiliates would suffer harm from increased competition. Although the D.C. Circuit has ruled that "parties suffer constitutional injury in fact when agencies lift regulatory restrictions on their competitors or otherwise allow increased competition,” Louisiana Energy & Power Auth. v. FERC, 141 F.3d 364, 367 (D.C. Cir. 1998), the court in Occidental found that no such increased competition had occurred or would imminently occur. Occidental, Slip Op. at 9 (citing Sherley v. Sebelius, 610 F.3d 69, 73 (D.C. Cir. 2010)). The FERC’s orders authorizing Tres Amigas’s negotiated rate authority neither authorized the construction of interconnecting transmission lines nor lifted any restrictions on such lines. Further, even assuming such lines would be built, the court stated that Occidental had failed to demonstrate that cheaper power was likely to flow on the lines interconnecting to the Tres Amigas facility, thus depressing the market price and causing an injury to Occidental’s affiliates.
Accordingly, because the court ruled that Occidental lacked standing to challenge the FERC’s orders, it dismissed the petition for review without expressing an opinion on the merits of Occidental’s objections.
Niagara Mohawk Power Corp. v. Hudson River-Black River Regulating Dist., No. 10-4402 (2d Cir. Mar. 7, 2012)
In Niagara Mohawk Power Corp. v. Hudson River-Black River Regulating Dist., No. 10-4402 (2d Cir. Mar. 7, 2012) (Niagara Mohawk), the United States Court of Appeals for the Second Circuit reviewed a challenged brought by Niagara Mohawk Power Corporation, doing business as National Grid (National Grid) to the constitutional and statutory authority of the appellees, Hudson River-Black River Regulating District (District), to assess costs associated with operating certain dams and reservoirs in the state of New York. In the district court proceeding below, National Grid claimed that the District’s actions in assessing costs were preempted by the Federal Power Act (FPA), and that the assessment scheme violated the petitioner’s equal protection rights under the federal constitution and its rights against unlawful takings under the federal and New York state constitutions. The Second Circuit in Niagara Mohawk upheld the district court’s determination that the District’s actions were not preempted by the FPA, but found that the lower court had abused its discretion by dismissing National Grid’s state and federal constitutional claims on abstention grounds. Accordingly, the court vacated and remanded the decision to the district court on the issue of National Grid’s constitutional claims.
The District is a New York State public benefit corporation, charged by New York statute with regulating the flow of the Hudson River and the Black River as "required by the public welfare, including health and safety.” See N.Y. Envtl. Conserv. L. § 15-2103(1). The District possesses broad statutory authority to carry out its mission, including the power "to build and operate reservoirs, issue bonds, and apportion costs on statutorily defined beneficiaries to finance the construction, maintenance, and operation of its reservoirs. Niagara Mohawk, Slip Op. at 4. In the 1920s, the District’s predecessor agency constructed the Conklingville Dam and the Great Sacandaga Lake Reservoir (collectively, the "GSL Project”). New York law required that the District apportion the costs of the GSL Project, less the portion attributable to the state, "among the public corporations and parcels of real estate benefited, in proportion to the amount of benefit which will inure to each such public corporation and parcel of real estate by reason of such reservoir.” N.Y. Envtl. Conserv. L. § 15-2121.
Until 2010, the District apportioned the vast majority of the GSL Project’s costs to parcels of land with a fall (or "head”) on the Hudson River, reasoning that these parcels either derived or had the potential to derive the benefit of increased water-power production from the project. The District’s apportionment did not take into consideration whether the properties with a head on the river were used for hydroelectric purposes or industrial purposes, or were undeveloped. National Grid owns several parcels of vacant land within the District’s boundaries (Subject Parcels) that were assessed by the District for headwater benefits from the GSL Project. Although National Grid claimed that the Subject Parcels "are not hydroelectric generating properties, are not developable as such, and are not FERC licensed to be hydroelectric properties,” these properties have been assessed costs for the GSL Project since the 1920s, based on their potential to utilize the headwater benefits of the project. Niagara Mohawk, Slip Op. at 8. In the 1990s, the Federal Energy Regulatory Commission (FERC) determined that the GSL Project required a hydropower license under Part I of the FPA. In 2002, the FERC issued a license to the District for the dam and reservoir at the GSL Project and issued licenses to a hydropower company for four in-stream hydroelectric projects located downstream from the GSL Project, on the Sacandaga and Hudson rivers.
The Second Circuit briefly summarized the three tests courts have applied to determine whether a of federal statute preempts state laws and regulations: " i.e., (1) express preemption, whereby Congress expresses a specific intent in the text of a statute to preempt state regulation; (2) field preemption, whereby Congress has manifested an intent to "occupy the field” in a certain area, and has left "no room for the States to supplement it”; and (3) conflict preemption, whereby a state law "actually conflicts with federal law,” including where "it is impossible for a private party to comply with both state and federal requirements, or where state law stands as an obstacle to the accomplishment and execution of the full purposes and objectives of Congress.” Niagara Mohawk, Slip. Op. at 16 (quoting English v. Gen. Elec. Co., 496 U.S. 72, 79 (1990)).
National Grid argued that the FPA represented a comprehensive effort on the part of Congress to occupy the field of regulation over navigable waterways. Specifically, National Grid contended that that section 10(f) of the FPA, 16 U.S.C. § 803(f), which established a framework for license holders to assess costs for benefits conferred upon licensed and unlicensed downstream projects, evidenced an intent by Congress to preempt the state regulation of cost allocation from federal water projects. National Grid claimed that "Congress did not permit or authorize FERC licensees to collect assessments from any [sources other than downstream power projects], including undeveloped vacant lands.” Niagara Mohawk, Slip Op. at 21. Contrary to this position, the court ruled that "[r]ather than occupying the entire field of all regulation related to navigable waterways, as National Grid suggests, section 10(f) focuses on the relationships between multiple FERC licensees, and between FERC licensees and non-licensee power projects.” Niagara Mohawk, Slip Op. at 21. Because the court ruled that FPA section 10(f) only deals with the apportionment of costs in association with power-related benefits from a licensed project, it found that the statute neither granted the FERC the authority to assess costs for non-power project related benefits, nor precluded the state from doings so.
Likewise the court rejected National Grid’s argument that the savings clause in FPA section 27 evidences a congressional intent to occupy the field of regulation over federal waterways. That section provides that nothing in Part I of the FPA shall be construed to affect "the laws of the respective States relating to the control, appropriation, use, or distribution of water used in irrigation or for municipal or other uses, or any vested right acquired therein.” National Grid argued that this clause only saved from federal preemption those state laws "relating to the control, appropriation, use, or distribution of water used in irrigation or for municipal or other uses,” and, therefore, the District may only exercise authority to assess those benefits related to irrigation or municipal uses. Niagara Mohawk, Slip Op. at 22. The Second Circuit disagreed, observing that the fact that Congress chose to explicitly save from preemption state assessments of uses related to irrigation and municipal uses did not necessarily mean that it intended to prohibit state assessments for other uses. "In other words, just because the savings clause fails to mention certain state-law powers does not mean that all unmentioned powers are federally preempted.” Niagara Mohawk, Slip Op. at 22. The court rejected National Grid’s "strained interpretation” of the FPA. Because it rejected National Grid’s assertion that the FPA occupied the field of regulation of federal waterways, the Second Circuit upheld the lower court’s determination that the FPA did not preempt the District’s assessment of costs to parcels, such as National Grid’s Subject Parcels, that are not used for the purpose of power generation.
In addition to its preemption claim, National Grid brought several state and federal constitutional claims based upon the Districts alleged disparate treatment of National Grid. Noting that these issues were the subject of several pending state court actions brought by National Grid, the district court declined to rule on National Grid’s constitutional claims, invoking the general doctrine of abstention expressed in Colorado River Water Conservation Dist. v. United States, 424 U.S. 800 (1976) and the more lenient standard for judicial abstention for declaratory judgment actions set forth in Wilton v. Seven Falls Co., 515 U.S. 277 (1995). The Second Circuit ruled that the district court had misapplied the factors in exercising its discretion to abstain from ruling on the merits under both the Colorado River and Wilton abstention analyses. Accordingly, the Second Circuit remanded the case to the district court to decide National Grid’s constitutional claims on their merits. Niagara Mohawk, Slip Op. at 28-39.
Braintree Electric Department v. FERC, No. 09-1231 (D.C. Cir. Feb. 7, 2012), http://www.cadc.uscourts.gov/internet/opinions.nsf/DB24885C8D655AFB8525799D00548367/$file/09-1231-1356885.pdf
In Braintree Electric Light Department v. FERC, Nos. 09-1231 et al. (D.C. Cir. Feb. 7, 2012), the D.C. Circuit rejected a challenge by municipally-owned utilities in southeastern Massachusetts to four FERC orders that denied the petitioners' claim that they were being unjustly charged in order to maintain electric system reliability on Cape Cod. The dispute was first addressed in a FERC-approved settlement agreement that reserved certain litigation rights to the petitioners. The Court held that FERC was entitled to deference in construing the settlement agreement without the agency making an explicit finding of ambiguity, and that FERC reasonably interpreted the agreement's litigation rights provisions to bar petitioners' claims.
This dispute arises from a 2006 decision of the ISO New England (ISO-NE) that operating two otherwise uneconomic oil-fired generators on Cape Cod would be necessary to avoid blackouts on Cape Cod. Under ISO-NE's tariff, the costs of operating these units were allocated to all of southeastern Massachusetts, including the service areas of Braintree Electric Light Department and other municipal electric utilities that were not located on Cape Cod. Braintree v. FERC, slip op. at 2-3. The municipal utilities disputed the charges, and a FERC-mediated settlement agreement adjusted the payments, but stated that future charges would be paid by all load serving entities under the ISO-NE tariff, subject to certain litigation rights. Id. at 3-5.
Invoking their reserved rights, the municipal utilities filed a complaint at FERC in 2008, arguing that they should no longer be allocated costs for the Cape Cod units because alternative power system arrangements could maintain reliability and because the region over which the oil units' costs were spread should be redefined. Id. at 5. FERC rejected the proffered reliability alternative because it would degrade reliability, and found that the settlement agreement barred the utilities from litigating the allocation of the charges. FERC found that the agreement also barred dispute of the reliability area boundary change because that issue became hypothetical after ISO-NE redefined the reliability area in its tariff in 2009. Id. at 5-6.
On review, the Court held that FERC's interpretation of the settlement agreement was entitled to deference under Chevron U.S.A., Inc. v. Natural Resources Defense Council, Inc., 467 U.S. 837 (1984). Slip op. at 7. The Court rejected petitioners' argument that FERC must make an explicit finding of ambiguity in the settlement agreement, stating that "the Chevron two-step is a dance for the court, not the Commission." Id. at 8. If FERC erroneously asserts that the plain language of relevant wording is unambiguous, the Court said, it "'must remand the matter to the Commission to require the agency to consider the question afresh in light of the ambiguity we see.'" Id. (quoting Ameren Servs. Co. v. FERC, 330 F.3d 494, 498-99 (D.C. Cir. 2003)). The Court also deferred to FERC's technical judgment that the reliability alternative proffered by petitioners would expose Cape Cod to an unacceptable risk of involuntary load shedding. Id. at 9 (citing B&J Oil & Gas v. FERC, 353 F.3d 71, 76 (D.C. Cir. 2004)).
On the merits, the Court held that FERC reasonably rejected the utilities' argument that their dispute over billing raised only hypothetical reliability concerns because implementation of actual alternative reliable system configurations was the subject of the petitioner's reserved rights in the settlement agreement. Id. at 10-11. The Court also upheld FERC's conclusion that, following the realignment of the reliability region in 2009, the settlement precluded a claim for relief based on a hypothetical retroactive change to the reliability region for 2008 cost allocation purposes because the settlement agreement was ambiguous on that point. Id. at 13-14. FERC's reading of the settlement was "reasonable and entitled to deference," the Court said. Id. at 15.
The Court further held that FERC reasonably found that petitioners' argument that the agency's determinations violate cost causation principles went beyond the scope of litigation rights reserved in the settlement. Id. at 16. Given that FERC has a valid basis for its decision not to entertain that argument, the Court determined that it need not consider petitioners' cost causation argument on the merits, stating that "[w]hen 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 alternative grounds were unavailable." Id. at 16 n.8 (quoting BDPCS, Inc. v. FCC, 351 F.3d 1177, 1183 (D.C. Cir. 2003)).
Freeport-McMoRan Corporation v. FERC, No. 08-1349 (D.C. Cir. Jan. 17, 2012), http://www.cadc.uscourts.gov/internet/opinions.nsf/1C5AD12D8732726D852579880056CBBC/$file/08-1349-1352748.pdf.
In Freeport-McMoRan Corporation v. FERC, No. 08-1349 (D.C. Cir. Jan. 17, 2012), the D.C. Circuit denied two petitions for review of FERC orders concerning El Paso Natural Gas Company's 2005 pipeline rate case and settlement. The Court upheld FERC's determination that a provision of a 1996 settlement between El Paso and its customers remains in effect and limited the rates El Paso could charge certain of its shippers in its 2005 rate case. The Court further found that none of petitioners' arguments concerning FERC's application of that provision could overcome the elevated degree of deference it accords to FERC's interpretation of settlement provisions.
The dispute goes back to 1996, when El Paso's California-based shippers relinquished or "turned back" their capacity rights on El Paso's system as a result of California's restructuring of its electric industry. Freeport-McMoRan, slip op. at 3. This left roughly 35% of El Paso's total capacity unsubscribed, which threatened to increase the costs El Paso needed to recover from its remaining shippers drastically and thereby increase the rates charged to its remaining customers. Id. El Paso and its customers entered into a settlement (the "1996 Settlement"), approved by FERC, to spread the risk associated with the turned back capacity between El Paso and its customers. Id. at 3-4. In addition, Article 11.2 of the 1996 Settlement capped the rates El Paso could charge after the settlement term ended to those shippers with contracts in effect on December 31, 1995 and that remained in effect--in their 1996 form or as amended--on January 1, 2006. Id. at 4.
In 2000, El Paso experienced a shortfall of capacity on its system. El Paso was not able to meet all of its shippers' demands and thus invoked a tariff provision allowing it to curtail shippers on a pro rata basis. Id. El Paso's invocation of its curtailment authority disrupted service and caused shippers to file complaints with FERC. Id. In response, FERC instituted a "Capacity Allocation Proceeding" and issued a series of orders between 2002 and 2004 (the "CAP Orders"). Id. Without faulting either El Paso or its customers, FERC determined that El Paso's routine use of curtailment was not just and reasonable and invoked its Mobile-Sierra doctrine authority to prohibit contracts that are against the public interest. Id. at 4-5 (quoting United Distrib. Cos. v. FERC, 88 F.3d 1105, 1131 (D.C. Cir. 1996)). FERC directed El Paso to reserve the capacity needed to satisfy its existing contract demand customers and allocate all remaining capacity, including the turned back capacity, to its former full requirements customers, whose contracts were converted to contract demand contracts. Id. at 5. To implement the CAP Orders, FERC revised portions of the 1996 Settlement, rejected the contention of some shippers that the 1996 Settlement should be abrogated entirely, and left the 1996 Settlement's rate caps intact. Id.
In June 2005, El Paso filed a general rate case (the "2005 Rate Case") proposing rates to go into effect at the end of the 1996 Settlement term, including a proposal for rates above the Article 11.2 cap for shippers covered by that provision, based on El Paso's assertion that the provision had been abrogated by the CAP Orders. Id. FERC suspended the proposed rate increase and stated that it would not consider in its analysis of El Paso's rates Freeport-McMoRan's claim that El Paso had previously withheld capacity. Id. at 5-6. On March 20, 2006, FERC issued an order concluding the CAP Orders had not abrogated Article 11.2. Id. at 6. FERC also determined that Article 11.2 limited the rates El Paso could charge its former full requirements customers, but did not limit the rates El Paso could charge for capacity added to its system after the 1996 Settlement. Id. With rehearing requests of the March 2006 Order pending, El Paso and its shippers filed a proposed settlement of the 2005 Rate Case in December 2006 (the "2006 Settlement"). Id. FERC approved the 2006 Settlement, which did not resolve the Article 11.2 issues, over the objection of only one party: Freeport-McMoRan. Id.
On review, El Paso argued the CAP Orders abrogated Article 11.2 of the 1996 Settlement by "fundamentally altering the bargain underlying the 1996 Settlement." Id. at 8. FERC's first counter argument was procedural, i.e., that El Paso was untimely, raising the abrogation argument only during the 2005 Rate Case not during the Capacity Allocation Proceeding itself. Id. The Court rejected this argument, noting that FERC "sang a different tune during the Capacity Allocation Proceeding itself," even assuring the parties in the Capacity Allocation Proceeding that El Paso's next rate filing would provide an opportunity to review the justness and reasonableness of El Paso's rates. Id. at 8-9. The Court, however, accepted FERC's determination on the merits of El Paso's argument, finding FERC's reasoning sound. Id. at 9. FERC found the CAP Orders had neither changed the bargain of the 1996 Settlement nor abrogated Article 11.2 because El Paso's ability to remarket the turned back capacity under the 1996 Settlement was always subject to its contractual obligations to its full requirements customers. Id. FERC concluded, therefore, that allocating the turned back capacity to El Paso's full requirements shippers in the CAP Orders "merely enforced the obligations El Paso already had when it entered into the 1996 Settlement." Id.
The Court then turned to petitioners' arguments concerning FERC's application of Article 11.2. El Paso advanced three arguments that FERC applied Article 11.2 too broadly, while Freeport-McMoran argued the opposite, making two arguments that FERC applied Article 11.2 too narrowly. Id. at 11-12. The Court found that none of the five could overcome "the 'high degree of deference' [it] afford[s] to the Commission's interpretation of settlement provisions." Id. at 12 (quoting Transcontinental Gas Pipe Line Corp. v. FERC, 485 F.3d 1172, 1178 (D.C. Cir. 2007)). Specifically, notwithstanding El Paso's arguments to the contrary, the Court found FERC had "reasonably determined" the full requirements contracts converted to contract demand contracts in the Capacity Allocation Proceedings were "amended" within the meaning of Article 11.2 (slip op. at 12), had "reasonably determined" the Article 11.2 rate cap applied to the turned back capacity (id. at 13), and had reasonably found the applicable Article 11.2 rate cap for the turned back capacity was determined by the Article 11.2 shipper's delivery point rather than by the relinquishing shipper's delivery point (id. at 14). Further, despite Freeport-McMoRan's claims, the Court found reasonable FERC's determination that Article 11.2 rate caps did not limit the rates for capacity added to the El Paso system after the 1996 Settlement, as well as FERC's adoption of a presumption as to the amount of capacity on El Paso's system on December 31, 1995. Id. at 15-19.
Finally, the Court rejected Freeport-McMoRan's claim that FERC's approval of the 2006 Settlement over Freeport-McMoRan's objections was procedurally and substantively infirm. The Court upheld FERC's finding that Freeport-McMoRan was collaterally estopped by the CAP Orders from raising El Paso's "capacity withholding liability" (arising from a 2002 administrative law judge decision that FERC subsequently vacated). Id. at 19-21. With respect to Freeport-McMoRan's substantive argument regarding the 2006 Settlement, the Court found FERC's approval of the 2006 Settlement appropriate "under the so-called second Trailblazer approach," under which FERC may approve a contested settlement if it leaves the contesting party "'in no worse position . . . than if the case were litigated,' and 'the overall result is just and reasonable.'" Id. at 21 (quoting Trailblazer Pipeline Co., 87 FERC P 61,110, 61,349 (1999)).
Indiana Utility Regulatory Commission v. FERC, No. 10-1313 (D.C. Cir. Jan. 17, 2012), http://www.cadc.uscourts.gov/internet/opinions.nsf/23D608DE3B1E818D852579880056CBED/$file/10-1313-1352763.pdf.
In Indiana Utility Regulatory Commission v. FERC, No. 10-1313 (D.C. Cir. Jan. 17, 2012), the D.C. Circuit rejected a state utility commission’s challenge to FERC’s acceptance of a procedure that allows retail demand-response resources to participate in PJM’s wholesale energy market. The Court found that the state commission waived certain arguments by failing to raise them with specificity in its request for rehearing of FERC’s order. The Court then denied the remaining objections in light of the substantial deference it gives to FERC’s interpretations of its own orders.
As relevant here, demand-response resources are entities that reduce their electricity consumption in exchange for wholesale energy market payments. In Order No. 719, FERC required RTOs to accept demand-response offers from aggregators of retail energy customers, unless the relevant state regulator prohibited their participation. FERC explained that its rule was not intended to interfere with retail demand-response programs, to raise concerns about the boundaries between state and federal jurisdiction, or to impose undue burdens on state regulatory authorities.
PJM filed a tariff in compliance with Order No. 719. Under the tariff, upon receiving an aggregator’s application, PJM notifies the retail utility that serves the customers being aggregated. IURC v. FERC, slip op. at 5. The retail utility then has 10 days to challenge the application and to show that the customer is ineligible under state law to sell demand response in PJM’s market. Id. Otherwise, PJM presumes the customer is eligible under state law and accepts the application. Id.
In response to Order No. 719, the Indiana Utility Regulatory Commission prohibited Indiana retail customers from selling demand response in wholesale markets without its prior approval. Id. at 5. It later protested PJM’s tariff filing as an interference with its retail regulatory regime, and sought rehearing of FERC’s acceptance of the tariff provision. Id. at 5-6.
The D.C. Circuit held that the Indiana Commission waived its jurisdictional objections to FERC’s order by failing to state them with sufficient specificity on rehearing. According to the Court, the Indiana Commission’s rehearing petition included just a single sentence touching on jurisdictional issues, which purported to maintain previously-articulated objections. That was insufficient, the Court held, to overcome the Federal Power Act’s "strict limitation” on judicial review. Id. at 6. Under FPA Section 313, judicial review is available only for those objections that were "urged before the Commission [on rehearing,] unless there is reasonable ground for [the petitioner’s] failure to do so.” 16 U.S.C. § 825l(a). The Court found that prerequisite was not satisfied, by "referring only in a general way” to arguments made in previous filings. IURC v. FERC, slip op. at 8 (quoting Conn. Dep’t of Pub. Util. Control v. FERC, 593 F.3d 30, 36 (D.C. Cir. 2010)). Nor did it matter that FERC was aware of the Indiana Commission’s jurisdictional concerns. Because FPA Section 313 limits judicial review to the grounds "set forth specifically” in the petitioner’s rehearing request, "[i]t … matters not what the Commission knew or should have known” about the petitioner’s claims. Id. at 8. In this respect, the FPA "differ[s] fundamentally” from other judicial-review statutes, which might excuse a failure to exhaust remedies so long as an agency has considered the argument at the urging of another party. Id. (quoting ASARCO, Inc. v. FERC, 777 F.2d 764, 774 n.7 (D.C. Cir. 1985)).
As to the merits, the Indiana Commission complained that FERC erred in putting the onus on the retail utility, rather than the demand-response aggregator, to check retail customers’ eligibility to sell demand response in wholesale markets. The Court readily upheld FERC’s decision, however, based on the Court’s "substantial deference” to FERC’s interpretation of its own orders—such as Order No. 719—which the Court upholds unless "plainly erroneous.” Id. at 9-10 (quotations omitted). The Court agreed with intervenor PJM that "a case probably could be made” under Order No. 719 for either outcome, that is, for placing responsibility on the aggregator or on the utility, but that "merely underscores” the reasonableness of FERC’s decision. Id. at 11 (quoting intervenor brief). Having upheld FERC’s decision on a "substantial deference” standard, the Court found no occasion to pass on FERC’s claim that an even more deferential standard applies to FERC ratemaking. Id. at 10 (quoting Alcoa Inc. v. FERC, 564 F.3d 1342, 1347 (D.C. Cir. 2009) (applying "highly deferential” standard).
PPL Montana, LLC, v. Montana, 132 S. Ct. 1215 (2012)
In PPL Montana, LLC v. Montana, 132 S. Ct. 1215 (2012) the Supreme Court addressed ownership of riverbeds of the Missouri, Madison, and Clark Fork Rivers in Montana on which PPL Montana, LLC (PPL) owned and operated hydroelectric facilities. These facilities had existed for decades, and PPL paid rent to the federal government to use the riverbeds. Id. at 1225. Montana did not attempt to collect rent until 2003, when residents sued PPL, arguing that the riverbeds "were state owned and part of Montana’s school trust lands.” Id. The Montana trial court granted summary judgment to the state on the issue of title and awarded $41 million for rent from 2000 to 2007. Id. at 1222, 1225-26. The Montana Supreme Court affirmed the ruling. Id. at 1226. Subsequently, the United States Supreme Court addressed whether the river segments where the facilities were located were navigable. Id. at 1222. The Court reversed the state court’s decision, holding that the federal government held title to the riverbeds. Id.
The Montana Supreme Court based its decision on "the background principle that ‘navigability for title purposes is very liberally construed.’” Id. at 1226 (quoting PPL Montana, LLC v. State, 229 P.3d 421, 446 (Mont. 2010)). It rejected the United States Supreme Court’s segment-by-segment approach of assessing navigability and instead focused on the river as a whole. Id. (discussing PPL Montana, 229 P.3d at 448-49). As a result, "[t]he Montana court accepted that certain relevant stretches of the rivers were not navigable but declared them ‘merely short interruptions’ insufficient as a matter of law to find nonnavigability, since traffic had circumvented those stretches by overland portage.” Id. (quoting PPL Montana, 229 P.3d at 446, 449). In its decision, the Montana high court relied extensively on present use of the Madison River. Id. (citing PPL Montana, 229 P.3d at 447).
The United States Supreme Court reversed based on the equal-footing doctrine, under which states gain title to riverbeds beneath navigable waters upon statehood, but the federal government retains title to riverbeds beneath nonnavigable waters. Id. at 1227-28. Under the equal-footing doctrine, the Court uses the "navigability in fact” rule to determine whether waters are navigable. Id. at 1228. Waters are navigable when they are or can be used "as highways for commerce, over which trade and travel” can be conducted. Id. (quoting The Daniel Ball, 77 U.S. (10 Wall.) 557, 563 (1871)). Furthermore, the Court uses a segment-by-segment approach to determine title to a riverbed by assessing whether each segment of the river is navigable. Id. at 1229.
The Court found that the "primary flaw” in the Montana Supreme Court’s approach was its treatment of the segment-by-segment approach and overland portage. Id. The Court observed that the segment-by-segment approach is "well settled” and supported by "practical considerations.” Id. at 1229-30. Here, the Court found that "a number of the segments at issue [were] discrete ... and substantial.” Id. at 1231. Consequently, the Court rejected the Montana Supreme Court’s "short interruptions” approach, under which a segment of river could be navigable if short breaks in navigability "could be managed by way of land route portage.” Id. Instead, portages would generally be indicative of nonnavigability "because they require transportation over land rather than over the water.” Id. ("Even if portage were to take travelers only one day, its significance is the same: it demonstrates the need to bypass the river segment, all because that part of the river is nonnavigable.”). The Supreme Court determined that a 17-mile segment of the Missouri River was "not navigable for purposes of riverbed title” because it required overland portage and was "not passable by boat at statehood.” Id. at 1232. The Court also determined "that there is a significant likelihood that some of the other river stretches” were not navigable, but remanded for further determination. Id. at 1232-33 (noting a report documenting falls, rapids, and obstructions in the Clark Fork River).
The Court also found that the Montana Supreme Court erred "in its reliance upon the evidence of present-day, primarily recreational use of the Madison River” because navigability is determined at "the time of statehood” and "concerns the river’s usefulness for trade and travel.” Id. at 1233. Consequently, evidence of present use may be relevant "to the extent it informs the historical determination whether the river segment was susceptible of use for commercial navigation at the time of statehood.” Id. But the watercraft used today must be similar to those used at the time of statehood and the condition of the river must not have changed materially. Id. at 1233-34. The Montana courts had not made such a determination. Id. at 1234.
The Supreme Court did not address PPL’s argument that the Montana Supreme Court erred by not placing the burden of proof on the state to show navigability. Id. The Court also did not determine whether laches or estoppel barred the state’s claim. Id. at 1235. The Court rejected Montana’s additional argument based on the public trust doctrine because the equal-footing doctrine governed the relevant issue. Id.