Summary
dismissing Commission argument as "specious because it does not address the valid concern raised by" party
Summary of this case from Cal. Pub. Utils. Comm'n v. Fed. Energy Regulatory Comm'nOpinion
Nos. 14–1103 14–1104 14–1105.
12-22-2015
TRANSCANADA POWER MARKETING LTD., Petitioner v. FEDERAL ENERGY REGULATORY COMMISSION, Respondent. Essential Power Massachusetts, LLC, et al., Intervenors.
Kenneth L. Wiseman argued the cause for petitioners. With him on the briefs were Mark Sundback, Allison Hellreich, William M. Rappolt, and Elizabeth W. Whittle. Carol J. Banta, Attorney, Federal Energy Regulatory Commission, argued the cause for respondent. With her on the brief were David L. Morenoff, General Counsel, and Robert H. Solomon, Solicitor. David T. Musselman and Cara J. Lewis were on the brief for intervenors The Essential Power Companies and PSEG Companies in support of respondent. Jodi L. Moskowitz entered an appearance.
Kenneth L. Wiseman argued the cause for petitioners. With him on the briefs were Mark Sundback, Allison Hellreich, William M. Rappolt, and Elizabeth W. Whittle.
Carol J. Banta, Attorney, Federal Energy Regulatory Commission, argued the cause for respondent. With her on the brief were David L. Morenoff, General Counsel, and Robert H. Solomon, Solicitor.
David T. Musselman and Cara J. Lewis were on the brief for intervenors The Essential Power Companies and PSEG Companies in support of respondent. Jodi L. Moskowitz entered an appearance.
Opinion
Opinion for the Court filed by Senior Circuit Judge EDWARDS.
EDWARDS, Senior Circuit Judge:
In June 2013, pursuant to section 205(d) of the Federal Power Act (“FPA”), 16 U.S.C. § 824d(d) (2012), the Independent System Operator for New England (“ISO New England”) filed a tariff revision with the Federal Energy Regulatory Commission (“Commission” or “FERC”). The tariff filing reflected ISO New England's concern over “the region's growing reliance on natural gas-fired generators, which can be vulnerable to supply shortages and price volatility.... [ISO New England] had found that many dual-fuel or oil-fired generators did not keep sufficient fuel supplies on hand to meet increased demand in extended or repeated periods of cold weather. Accordingly, [ISO New England] proposed [a] Winter Reliability Program [that] included an Oil Inventory Service component, which would compensate oil-fired and dual-fuel generators, selected through a bidding process, to maintain specified supplies of oil and to provide energy when system conditions were stressed.” Br. for Respondent at 3.
On September 16, 2013, the Commission issued an Order Conditionally Accepting Tariff Revisions in Docket ER13–1851. This Order tentatively approved the Winter 2013–14 Reliability Program (“Program”). In this same Order, however, FERC rejected the tariff proposal to allocate costs to Regional Network Load (i.e., to transmission owners) as inconsistent with cost-causation principles and directed ISO New England to submit a compliance filing that would allocate the costs of the Program to Real–Time Load Obligation (i.e., to Load–Serving Entities). On October 7, 2013, in Docket ER13–2266, the Commission issued an Order Accepting Bid Results, which effectively approved the Program and the results of ISO New England's bid-selection process. On October 15, 2013, ISO New England submitted a compliance filing that explained how it had considered and selected the bids. On April 8, 2014, FERC issued orders denying requests for rehearing of the Orders issued in Docket ER13–1851 and Docket ER13–2266.
On June 6, 2014, Petitioners TransCanada Power Marketing Ltd. (“TransCanada”) and the Retail Energy Supply Association filed petitions for review with this court challenging the Orders issued by FERC approving the Winter 2013–14 Reliability Program. TransCanada, which is a Load–Serving Entity, principally contends that FERC's actions should be overturned because, inter alia, (1) there was insufficient evidence in the record to allow FERC to determine whether the cost-based Program and resulting rates were just and reasonable; (2) FERC acted in contravention of cost causation principles when it allocated the costs of the Program to Load–Serving Entities; and (3) FERC abused its discretion in failing to consolidate the proceedings in Docket Nos. ER13–1851 and ER13–2266. The Retail Energy Supply Association, whose members include Load–Serving Entities, joins TransCanada only with respect to the issue relating to the allocation of cost.
We decline to assess FERC's conditional approval of the Program in Docket ER13–1851 because FERC made it clear that its decision was only tentative. Any alleged defects in the Program were subject to challenge by interested parties and final review by FERC in Docket ER13–2266. Indeed, that is exactly what happened.
The Commission's decision regarding the allocation of the costs of the Program to Load–Serving Entities was a final action in Docket ER13–1851. It is therefore ripe for review. However, we find no merit in Petitioners' challenges to the cost-allocation decision. The Commission reasonably explained that its decision, unlike the proposed alternative, adhered to cost-causation principles and agency precedent. We therefore deny the petitions for review of the cost-allocation decision in Docket ER13–1851.
In Docket ER13–2266, FERC gave its stamp of approval to the Program and found that the arrangement pursuant to which suppliers would be compensated at their as-bid price was just and reasonable. TransCanada challenges FERC's decision in Docket ER13–2266, principally on the ground that the record upon which FERC relied is devoid of any evidence regarding how much of the Program cost was attributable to profit and risk mark-up. TransCanada argues that, without this information, FERC could not properly assess whether the Program's rates were just and reasonable. We agree and thus grant in part the petition for review of Docket ER13–2266. The case is hereby remanded to FERC so that it may either offer a reasoned justification for the Order or revise its disposition to ensure that the rates under the Program are just and reasonable.
Because we remand only one of the two dockets, we need not address whether the Commission abused its discretion in declining to consolidate them.
I. Background
ISO New England is a “private, non-profit entity [that] administer[s] New England energy markets and operate[s] the region's bulk power transmission system.” PSEG Energy Res. & Trade LLC v. FERC, 665 F.3d 203, 205–06 (D.C.Cir.2011) (alterations in original) (quoting Blumenthal v. FERC, 552 F.3d 875, 878 (D.C.Cir.2009)). To provide access to the transmission system, ISO New England sets rates “in a single, unbundled, grid-wide tariff.” See Braintree Elec. Light Dep't v. FERC, 667 F.3d 1284, 1286 n. 1 (D.C.Cir.2012) (quoting NRG Power Mktg., LLC v. Me. Pub. Utils. Comm'n, 558 U.S. 165, 169 n. 1, 130 S.Ct. 693, 175 L.Ed.2d 642 (2010)). “Under its tariff, ISO[ ] [New England] is obligated to assure that New England's power supply ‘conforms to proper standards of reliability.’ ” Id. (quoting ISO New England, Inc., Transmission, Markets, and Services Tariff § I.1.3 (“Tariff”)). ISO New England must file its tariff with the Commission for approval under section 205 of the FPA. Braintree Elec. Light Dep't v. FERC, 550 F.3d 6, 9 (D.C.Cir.2008) (citing 16 U.S.C. § 824d(d)). The Commission can reject the proposed rates only if it finds that the rates are not “just and reasonable.” Atl. City Elec. Co. v. FERC, 295 F.3d 1, 9 (D.C.Cir.2002) (citing 16 U.S.C. § 824d(e)).
A. The Winter 2013–2014 Reliability Program
On June 28, 2013, ISO New England filed with the Commission proposed revisions to section III of its Tariff. The revisions, which were titled the “Winter 2013–14 Reliability Program,” were intended to maintain system reliability during the 2013–2014 cold-weather months. In its filing, ISO New England explained that during the mild 2012–2013 winter, it had seen instances where generators had lacked sufficient fuel to allow for reliable operation during extended periods of cold weather. Therefore, an immediate solution was needed to avoid serious threats to system reliability for the upcoming winter. The Program was designed to be a time-limited, discrete, out-of-market solution, which, in future years, would yield to a market-based solution.
In order to better understand the Program, it is helpful to have at least a general sense of the New England region's power system and electricity markets, as well as the parties who participated in or were affected by the Program. The following summary outlines the system and the principal parties:
The Energy Pathway: First, a “generator” produces the required electric energy. Next, a “transmission owner” (i.e., an entity that owns and maintains transmission facilities) “transmits” the energy to a “local distributor” (also called a “network customer,” “transmission customer,” or “local public utility”). Finally, the local distributor “distributes” the energy to end-users. The amount of energy demanded by end-users is often called “Load.” This entire system (i.e., the network of facilities, equipment, and transmission lines) is called “the grid.”
The Various Parties and “Load” Concepts:
• Load–Serving Entities (such as TransCanada) secure electric energy, transmission service, and related services to serve the demands of their customers. Load–Serving Entities sell the energy that they acquire pursuant to contracts with local distributors and end-users. After a local distributor or end-user purchases energy, the transmission owner transmits the energy to the local distributor, who then distributes it to the end-user.
Real–Time Load Obligation is a Load–Serving Entity's total energy commitment for a certain time period. If the costs of the Program are allocated to Real–Time Load Obligation (which is fulfilled by Load–Serving Entities such as TransCanada), then the Load–Serving Entities assume the responsibility for the cost of the Program. The Load–Serving Entities try to recoup these costs from end-users under their existing contracts.
• Transmission Owners own the energy transmission lines that are used to transmit energy from the generators to the local distributors. This service is called “Regional Network Service.” Transmission owners charge Regional Network Service charges for their services.
Regional Network Load: At any particular time, a certain amount of energy will require Regional Network Service. This energy is called Regional Network Load. If the Winter Reliability Program costs are allocated to Regional Network Load, then transmission owners bear those costs. Transmission owners, in turn, can recoup these costs through Regional Network Service charges.
• Independent System Operators (“ISOs”) are independent, federally regulated organizations formed at the recommendation of FERC to impartially coordinate, control, and monitor the operation of a regional bulk electric power system, including the dispatch of electric energy over the system, and the monitoring of the electricity markets to ensure the safety and reliability of the system.
• End-users are the consumers who use the energy.
See the Addendum for references that define and discuss the New England region's power system, the principal parties in the system, and “load” concepts.
* * * * * *
The Program proposed by ISO New England included an Oil Inventory Service component. ISO New England indicated that it would first solicit bids from oil-fuel and dual-fuel generators. The bid sheets would instruct generators to state the price at which they would agree to establish a specified quantity of fuel by December 1, 2013. ISO New England would then select generators (to provide up to 2.4 million megawatt-hours (“MWh”) of energy) based on the following criteria:
(a) Cost (dollars/MWh of providing the service);
(b) Asset's historical availability and performance;
(c) Asset's ability to respond within the Operating Day to contingencies and other changed conditions;
(d) Diversity of location and sensitivity to North/South and East/West constraints;
(e) Dual fuel capability; and
(f) Replenishment capability.
ISO New England retained discretion to accept or reject any and all bids received. Generators selected to participate in the Program would receive their “as-bid” price. Obligations would lapse on February 28, 2014, or on the date on which a generator had fully depleted its offered fuel inventory, whichever was earlier.
ISO New England estimated that “the costs of providing the Winter Reliability Program services ... [would] range from $16 to $43 million.” ISO New England, Winter 2013–14 Reliability Program Proposal 25 n. 68 (June 28, 2013), reprinted in Joint Appendix 25 (citation omitted). It proposed allocating this cost to Regional Network Load, which is the energy that a transmission customer designates for transmission service. Tariff § I.2.2. As explained above, Regional Network Load is paid for by transmission owners, who, in turn, pass on the cost to transmission customers. ISO New England Inc., 144 FERC ¶ 61,204, 62,140 & n. 54 (2013) (“Order Conditionally Accepting Tariff Revisions ”). The alternative would have been to allocate the cost to Real–Time Load Obligation, which is paid for by Load–Serving Entities (i.e., suppliers who contract with distribution companies and end-users to provide energy). Id.
The term “Real–Time Load Obligation[ ], or Real–Time Load, refers to [a] load serving entit[y's] [total energy] obligation ... during a given hour of operation.” ISO New England, Inc., 115 FERC ¶ 61,145, 61,516 n. 4 (2006) ( “2005–2006 Order On Rehearing ”) (citing Tariff § III.3.2.1(b)(i)). Although Real–Time Load costs may be unforeseeable, Load–Serving Entities are able to offset the risk of unanticipated costs by negotiating appropriate arrangements in their contracts with distribution companies and end-users. Id. at 61,517.
Due to the Program's urgent nature, ISO New England requested the Commission to approve the Program prior to receiving information regarding the accepted bids. However, ISO New England acknowledged that the accepted bids would also require Commission approval, as those bids would constitute the Program's rates. ISO New England agreed to provide not only the bid prices, but also a description of its evaluation process.
On August 26, 2013, ISO New England filed the bid results with the Commission. Of the 2.29 million MWh offered, ISO New England proposed accepting 1.995 million MWh at a price of $78.8 million—nearly double ISO New England's estimated cost of providing Program services. ISO New England provided the Commission with information on the prices and energy amounts, stating that publication of more granular information might convey sensitive commercial information.
B. The Commission's Conditional Approval of the Program and Its Final Decision on Cost Allocation
On September 16, 2013, the Commission issued an Order in Docket ER13–1851 conditionally approving the Program. Order Conditionally Accepting Tariff Revisions, 144 FERC ¶ 61,204. The Commission made it very clear that, apart from cost allocation, its approval of the principal aspects of the Program was tentative and subject to further review. On this point, the Commission said:
ISO[ ] [New England]'s procurement decisions under the [Program] remain subject to Commission review. ISO[ ] [New England] is required to file ... the results of the bid submission and selection process.
Id. at 62,137. TransCanada also understood that, in conditionally approving the Program in Docket No. ER13–1851, “FERC had no evidence regarding the costs upon which a rate would be based. That evidence was to be submitted in Docket No. ER13–2266.” Br. of Petitioners at 28.
In addition to tentatively approving the Program in Docket ER13–1851, FERC positively rejected ISO New England's proposal to allocate cost to Regional Network Load. Order Conditionally Accepting Tariff Revisions, 144 FERC at 62,142. The Commission explained that, under cost-causation principles, the entities that benefit from the Program should bear its cost. Id. On this point, FERC determined that the “Program does not address ... a transmission-related concern,” and, therefore, costs should not be allocated to Regional Network Load. Id. at 62,143. Rather, according to FERC, Load–Serving Entities benefit because the Program “protect[s] reliability by ensuring that sufficient energy will be available to satisfy the needs of entities that are obligated to serve load in New England.” Id. at 62,142–43 (quoting ISO New England, Inc., 113 FERC ¶ 61,220, 61,877 (2005) (“2005–2006 Order ”)). Therefore, the Commission concluded that, “[b]ecause real-time load is the primary beneficiary, ... [the] costs of the Program should be allocated to Real–Time Load Obligation.” Id. at 62,142.
In further support of its decision on cost allocation, the Commission looked to agency precedent. In particular, FERC noted that a “similar ... time-limited, out-of-market ... reliability measure[ ] directly benefitting real-time load” had been approved for the 2005–2006 winter, with the cost allocated to Real–Time Load Obligation. Id. (citing 2005–2006 Order, 113 FERC ¶ 61,220). In light of this precedent, the Commission found no merit in the concerns raised by some parties that, because Load–Serving Entities could not foresee the Program's cost, they would need to include risk premiums in their contracts. Id. at 62,143. According to the Commission, risk premiums are the appropriate way for Load–Serving Entities to recoup such costs. See 2005–2006 Order, 113 FERC at 61,878.
On April 8, 2014, Petitioners' requests for rehearing of the Commission's Order in Docket ER13–1851 were denied. ISO New England Inc., 147 FERC ¶ 61,026 (2014) (“Order Denying Rehearing of Tariff Revisions ”). On June 6, 2014, Petitioners filed timely petitions for review with this court.
C. The Commission's Approval of the Program's Rates
On October 7, 2013, in Docket ER13–2266, the Commission issued an order approving the Program's rates. ISO New England Inc., 145 FERC ¶ 61,023 (2013) (“Order Accepting Bid Results ”). In response to concerns over the Program's high cost, the Commission ordered ISO New England to explain, among other things, how it applied its bid selection criteria. Id. at 61,103. ISO New England's subsequent compliance filing indicated that it had first arranged the bid results by price, and then, based on a supply offer curve, had chosen a discernible breaking point from which to select the bid winners. ISO New England then had reviewed the remaining criteria and had determined that no changes to its selection were necessary. No party protested the compliance filing, which the Commission accepted by letter order on November 13, 2013.
During the course of the proceedings in Docket ER13–2266, TransCanada argued that the record lacked information regarding the generators' costs. Br. of Petitioners at 28, 38–41. According to TransCanada, such information was needed for the Commission to determine how much of the total cost of the Program was attributable to a profit and risk mark-up. Id. at 42–43. To support this argument, TransCanada pointed to the large disparity between the Program's estimated and actual cost as potential evidence of high mark-ups. Id. at 33–38. The Commission was unpersuaded. On November 6, 2013, TransCanada filed a timely request for rehearing of the Order Accepting Bid Results, which the Commission denied on April 8, 2014. ISO New England Inc., 147 FERC ¶ 61,027 (2014) (“Order Denying Rehearing of Bid Results ”).
In denying the request for rehearing, the Commission gave its final stamp of approval to the Program. Id. FERC dismissed TransCanada's main argument—that the Commission could not properly assess whether the Program's rates were just and reasonable without inquiring into how much cost was attributable to a profit and risk mark-up:
Under a competitive as-bid program in which resources are selected based on both price and non-price factors, it is reasonable that participants with greater reliability benefits will be paid higher prices, and the record in this case does not persuade us that participants included excessive profits “unrelated to actual risks and costs” in submitting their bids.
Id. at 61,078 (footnote omitted). The Commission simply stated that, after “balanc[ing] the actual costs ... with the [Program's pressing] need,” it had concluded that the Program's rates were reasonable. Id.
On June 6, 2014, TransCanada filed a timely petition for review with this court. The petitions for review of FERC's decisions in Docket ER13–1851 and ER13–2266 were consolidated by the court. The Essential Power Companies and the PSEG Companies—organizations some of whose members include generators selected by ISO New England to participate in the Program—intervened on behalf of the Commission.
II. Analysis
“We review final orders of the Commission under the arbitrary and capricious standard of the Administrative Procedure Act, 5 U.S.C. § 706(2)(A). An agency action will be upheld if the agency articulate[d] a satisfactory explanation for its action including a rational connection between the facts found and the choice made. Motor Vehicle Mfrs. Ass'n of United States, Inc. v. State Farm Mut. Auto. Ins. Co., 463 U.S. 29, 43, 103 S.Ct. 2856, 77 L.Ed.2d 443 (1983). The Commission's factual findings will be upheld if supported by substantial evidence. 16 U.S.C. § 825l(b).” FirstEnergy Serv. Co. v. FERC, 758 F.3d 346, 352 (D.C.Cir.2014) (alteration in original) (citation omitted).
A. Docket ER13–1851
Petitioners' challenges to FERC's decisions in Docket ER13–1851 focus on two claims: first, in conditionally approving the Program, “the Commission failed to adequately consider the costs of the Program before accepting it,” and second, FERC erred in ordering ISO New England to allocate Program costs to Real–Time Load Obligation. Order Denying Rehearing of Tariff Revisions, 147 FERC at 61,073; see also Br. of Petitioners at 16–17. We hold that the first claim is unripe for judicial review and that the second claim lacks merit.
We decline to assess FERC's conditional approval of the Program in Docket ER13–1851 because FERC made it clear that its decision was only tentative. Any alleged defects in the Program, apart from Petitioners' challenges to cost allocation, were subject to final review by FERC in Docket ER13–2266. Petitioners clearly understood that, in conditionally approving the Program in Docket No. ER13–1851, “FERC had no evidence regarding the costs upon which a rate would be based. That evidence was to be submitted in Docket No. ER13–2266.” Br. of Petitioners at 28.
Although FERC generally approved the Program in the Order Conditionally Accepting Tariff Revisions, the Commission conditioned its final approval of the Program on review of ISO New England's procurement process, bid results, and explanation of costs. In other words, it was not until FERC issued its Order in Docket ER13–2266, accepting ISO New England's bid results, that the questions relating to the procurement process, bid results, and cost of the Program became live issues. The Commission's Order in Docket ER13–2266 addressed the issues that arose from the Commission's tentative approval of the Program in Docket ER13–1851.
The Commission's approach was made clear in its Order Accepting Bid Results. In that Order, FERC explained that in the earlier “September 16, 2013 Order, the Commission relied in part on the fact that ISO[ ] [New England] must submit the Bid Results (including a description of the evaluation process), considering the Tariff revisions as a whole and ISO[ ] [New England's] own record statements regarding what the description would entail.” Order Accepting Bid Results, 145 FERC at 61,102. In other words, no final approval of the Program would be given until FERC assessed ISO New England's submissions on these matters. Indeed, as a part of the Order Accepting Bid Results, FERC required ISO New England to submit a compliance filing “further detailing its evaluation process in selecting winning bids.” Id.
Under 16 U.S.C. § 825l(b), we have jurisdiction to review “an order issued by the Commission” that is challenged by an aggrieved party. Although the statute does not specifically limit our review to “final orders,” we have held that we will not entertain challenges to Commission decisions that are not ripe for review. For example, in OMYA, Inc. v. FERC, 111 F.3d 179 (D.C.Cir.1997) (per curiam), the court refused to “decide whether the economic analysis the Commission adopted ... and applied in th[at] case, g[a]ve [ ] unequal consideration to power purposes,” because “[t]he issue [was] not yet ripe.” Id. at 182. The court explained that “[h]ow much each challenged requirement will cost [the petitioner] is not yet certain. Until these figures are set, any economic assessment of the conditions on the license would be speculative and premature.” Id. Tellingly, the court found that the petitioner “may raise this issue before the Commission once the costs of each condition are established.” Id. Likewise, in Northern Indiana Public Service Co. v. FERC, 954 F.2d 736, 740 (D.C.Cir.1992), we held that there was no agency decision ripe for review because the Commission merely approved the concept of a program but did not give its final authorization. These decisions are controlling here.
TransCanada's claims relating to ISO New England's procurement process, bid results, and explanation of costs were properly raised and considered in conjunction with Docket ER13–2266. FERC did not purport to render any final decision on these matters in Docket ER13–1851, so it did not render a decision that was ripe for review.
* * * * * *
Petitioners' second challenge to Docket ER13–1851—that the Commission erred in ordering ISO New England to allocate Program costs to Real–Time Load Obligation—raises an issue that is ripe for review because FERC's decision on this point was indisputably final. Nonetheless, we find no merit in Petitioners' claim.
Petitioners first allege that the Commission failed to evaluate, as required by section 205(e), whether allocating cost to Regional Network Load would be just and reasonable. We disagree. The Commission's analysis in support of its decision is straightforward and reasonable. The Commission noted that “Regional Network Load ... is paid for by transmission owners,” Order Conditionally Accepting Tariff Revisions, 144 FERC at 62,140, but found that the “Program does not address ... a transmission-related concern,” id. at 62,143. In other words, the Commission found that ISO New England's proposal violated principles of cost causation. While the Commission did not use the magic words “not just and reasonable,” 16 U.S.C. § 824d(a), this did not reflect a fatal flaw in its decision. See R.I. Consumers' Council v. FPC, 504 F.2d 203, 213 n. 19 (D.C.Cir.1974) (holding that “an order is not invalidated by mere failure to use the magic words”); see also Interstate Nat. Gas Ass'n of Am. v. FERC, 285 F.3d 18, 47 (D.C.Cir.2002) (holding that no magic words were required under a similar provision of the Natural Gas Act); Papago Tribal Util. Auth. v. FERC, 723 F.2d 950, 956–58 (D.C.Cir.1983) (no magic words required under a similar provision of the FPA).
Petitioners also contend that end-users, and not Load–Serving Entities, are the real beneficiaries of the Program. Petitioners thus argue that Load–Serving Entities should not shoulder the burden of Program costs that they cannot easily pass on to end-users. In advancing this argument, Petitioners implicitly suggest that Real–Time Load refers solely to end-users. This assumption finds no support in the record.
In its Order Conditionally Accepting Tariff Revisions, FERC explained:
The Winter Reliability Program does not address, nor was it intended to address, a transmission-related concern. ISO[ ] [New England] proposed the Winter Reliability Program specifically to address concerns related to resource performance coupled with the region's increased dependence on natural gas, both of which are generation-related concerns.
144 FERC at 62,143. The Commission explained further that the Program benefits Load–Serving Entities by ensuring that sufficient energy will be available for them to meet their obligations. Id. at 62,142–43.
The Commission's decision was consistent with its precedent. In addressing the 2005–2006 Winter Package program, FERC explained:
We disagree with [petitioner] that the Commission acted inconsistently with cost causation principles when it approved the proposal to allocate the cost ... to Real–Time Load Obligations. Under cost causation principles, costs are allocated to the parties who cause the incurrence of such costs. Network Load, i.e., transmission customers, do not cause ISO[ ] [New England] to posture generation resources in order to maintain the stability and reliability of the transmission system. [Load–Serving Entities], on the other hand, purchase power in the real time energy market to serve load and are, therefore, the entities that directly cause ISO[ ] [New England] to posture generation resources to ensure that the [Load Serving Entities] have adequate generation to meet their real time load obligations. Thus it is reasonable and consistent with cost causation principles to allocate these costs to [Load Serving Entities].
2005–2006 Order On Rehearing, 115 FERC at 61,517. The simple point here is that because the Program was designed to allow Load–Serving Entities to meet their Real–Time Load obligations, the Commission's decision on cost allocation properly followed cost causation principles.
Finally, FERC rejected Petitioner's argument that it was unfair to impose the cost burden on Load–Serving Entities, especially on such short notice:
We are also unpersuaded by ISO[ ] [New England]'s argument that the timing of the Program warrants allocating the costs to Regional Network Load. At the crux of ISO[ ] [New England]'s argument is a concern that the timing of the Program is unfair to [Load Serving Entities] because it imposes unavoidable costs on short notice. The Commission was similarly unpersuaded by this argument in the 2005–2006 Winter Package proceeding. While ISO[ ] [New England]'s timing of its filing is not ideal, and we encourage ISO[ ] [New England] to plan for future winters further in advance, that timing and admonition has no bearing upon the appropriate application of cost causation principles here. As the Commission previously explained in the Winter 2005–2006 proceeding, [Load Serving Entities] “voluntarily assume Real–Time Load Obligation when entering into bilateral contracts with end-use customers[;]” those “contracts contain inherent risk associated with unforeseeable future costs, and we would expect that risk to be captured in bilateral contracts between [Load Serving Entities] and end-use customers.”
Order Conditionally Accepting Tariff Revisions, 144 FERC at 62,143 (alteration in original) (quoting 2005–2006 Order On Rehearing, 115 FERC at 61,517). We can find no flaws in this reasoning.
Petitioners contend that FERC's reliance on the decision addressing the 2005–2006 Winter Package is misplaced. We disagree. The Commission's explanation of its precedent is eminently reasonable. Furthermore, the decision in the case involving the 2005–2006 Winter Package surely does not compel the result that Petitioners seek in this case, and FERC's rationale in support of its decision on cost allocation here easily survives review.
In sum, we conclude that the Commission did not err in allocating the Program's cost to Real–Time Load Obligation.
B. Docket ER13–2266
In its decision in Docket ER13–2266, the Commission approved ISO New England's procurement process, bid selections, and Program rates. For the most part, we find FERC's decisions in support of the Program to be clear, well supported, and reasonable. TransCanada raises one compelling concern, however.
TransCanada points out that, in approving the Program, FERC relied on a record that is devoid of any evidence regarding how much of the Program cost was attributable to profit and risk mark-up. TransCanada reasonably contends that, without this information, FERC could not properly assess whether the Program's rates were just and reasonable. This is a valid concern, and one that requires further consideration by FERC.
In its Order Denying Rehearing of Bid Results, FERC said:
As to TransCanada's argument that the Commission failed to appropriately find that the rates associated with the Bid Results are just and reasonable, we disagree. In addressing cost concerns, including concerns about the disparity between the estimated and actual overall costs of the Program, the Commission in the October 7, 2013 Order emphasized that the Winter Reliability Program involved a novel approach to addressing reliability concerns, the costs of which could not be easily identified with certainty. In conditionally accepting the Bid Results, the Commission balanced the actual costs reflected in the Bid Results with the need to make such expenditures to address pressing reliability risks. The balancing of cost with other critical considerations is in keeping with the FPA, under which the Commission may consider a wide variety of factors in determining whether rates are just and reasonable. The mere fact that the actual costs of the program exceeded the cost estimate does not serve to make the Bid Results unjust and unreasonable. To that end, we are unpersuaded by TransCanada's assertion that the disparity indicates that market participants included “excessive profit margins” in their bids. This argument is speculative and not based on any evidence in this proceeding. Under a competitive as-bid program in which resources are selected based on both price and non-price factors, it is reasonable that participants with greater reliability benefits will be paid higher prices, and the record in this case does not persuade us that participants included excessive profits “unrelated to actual risks and costs” in submitting their bids.
147 FERC at 61,078 (footnotes omitted). In TransCanada's view, this response is vague and evasive, and hardly the product of reasoned decision making. We agree that the Commission's reasoning in response to the point raised by TransCanada is inadequate to support a determination that the contested Program rates were just and reasonable.
It is well established that the Commission must “respond meaningfully to the arguments raised before it.” Pub. Serv. Comm'n v. FERC, 397 F.3d 1004, 1008 (D.C.Cir.2005). It is indisputable that, under established ratemaking principles, rates that permit excessive profits are not just and reasonable. Farmers Union Cent. Exch., Inc. v. FERC, 734 F.2d 1486, 1502–03 (D.C.Cir.1984). To be sure, the Commission may determine rates via a variety of formulae, and rate determination methodologies may vary depending upon the circumstances of each case. Me. Pub. Utils. Comm'n v. FERC, 520 F.3d 464, 471 (D.C.Cir.2008) (per curiam), rev'd in part on other grounds sub nom. NRG Power Mktg., 558 U.S. 165, 130 S.Ct. 693. Nevertheless, in all cases, the Commission must explain its reasoning when it purports to approve rates as just and reasonable.
FERC's brief argues that the Commission understood from the outset that the prospective costs of the Program would be difficult to estimate. Therefore, according to FERC, “the fact that the Program resulted in an actual cost higher than the estimate does not alone demonstrate that the Program design is unjust and unreasonable.” Order Denying Rehearing of Tariff Revisions, 147 FERC at 61,074. This argument is specious because it does not address the valid concern raised by TransCanada. The point made by TransCanada is not that the cost disparity rendered the rates per se unreasonable. Rather, the claim is that, considering this disparity, the Commission should have either inquired into the profit and risk mark-up or explained its decision not to do so.
In its Order Denying Rehearing of Bid Results, the Commission rejected as “speculative and not based on any evidence in this proceeding” any claim that the suppliers might have achieved “excessive profit margins” in their bids. 147 FERC at 61,078. This is a perplexing response to the query raised by TransCanada. There is no doubt that there is no evidence in the record on profit margins—that is precisely the point being pressed by TransCanada. FERC does not say that the figures for profit and risk mark-up are unavailable. They simply never addressed the matter.
The Commission also relies on the fact that, in approving the Program, it took non-cost criteria into account. As noted above, the Commission claimed that it “balanc[ed] [the actual cost] with other critical considerations,” such as the “pressing reliability risks.” Order Denying Rehearing of Bid Results, 147 FERC at 61,078. FERC also asserted that ISO New England selected the bids based on “both price and non-price factors,” which made it “reasonable that participants with greater reliability benefits will be paid higher prices.” Id. However, “when [the Commission] chooses to refer to non-cost factors in ratesetting, it must ... offer a reasoned explanation of how the [relevant] factor[s] justif[y] the resulting rates.” Farmers Union, 734 F.2d at 1502. Here, the Commission did not explain what its “balancing” entailed, or how it applied the non-cost factors. Rather, it simply concluded that the profit margins were not unreasonably high, without ever discussing the margins or their connections to particular suppliers.
It is true that the Commission referred to “reliability benefits,” as if to suggest that certain suppliers should be free to command high prices because of their reliability. 147 FERC at 61,078. But neither ISO New England nor FERC explained this in a way that demonstrates that there would be no excess of profits. This is not reasoned decision making.
Intervenors contend that Tejas Power Corp. v. FERC, 908 F.2d 998, 1004 (D.C.Cir.1990), permits the Commission to rely on competitive market forces to ensure that profits are not excessively high. Intervenors also point out that the Commission expressly referred to the Program as a “competitive as-bid program.” Order Denying Rehearing of Bid Results, 147 FERC at 61,078. The Commission, however, provided no explanation for why it believed that the Program was competitive. Nor did FERC purport to explain the economic forces that it believed restrained the suppliers in their confidential bid offers.
In this case, the Program occurred outside of the usual ISO New England energy markets, and the Commission made no effort to define the relevant market or determine the participants' market power. The Commission's reference to a “competitive as-bid program,” without further explanation, is simply a talismanic phrase that does not advance reasoned decision making. See Tejas, 908 F.2d at 1004–05 (concluding substantial evidence did not support a finding that the market was competitive where the Commission had made no finding regarding market power).
Because the Commission did not adequately explain its decision on this point, we are constrained to remand the case for further consideration.
III. Conclusion
For the reasons set forth above, we deny the petitions for review of the Commission's Order in Docket ER13–1851. We grant in part the petition for review of the Commission's Order in Docket ER13–2266, and remand the case to FERC so that it may either offer a reasoned justification for the Order or revise its disposition to ensure that the rates under the Program are just and reasonable as required by 16 U.S.C. § 824d.
So ordered.
Addendum
The following materials variously define and discuss the New England region's power system, the principal parties in the system, and “load” concepts:
ISO New England Inc., 144 FERC ¶ 61,204, 62,140 & n. 54, 62,143 (2013) (discussing “Load–Serving Entities,” “Real–Time Load Obligation,” and “Regional Network Load”).
ISO New England, Inc., 115 FERC ¶ 61,145, 61,516 n. 4 (2006) (defining “Real–Time Load Obligation”).
ISO New England, Inc., Transmission, Markets, and Services Tariff
• § I.2.2 (defining “Network Customer,” “Regional Network Load,” and “Transmission Customer”). http://www.iso-ne.com/static-assets/documents/regulatory/tariff/sect_1/sect_i.pdf
• § II.11 (defining and explaining “Regional Network Service”). http://www.iso-ne.com/static-assets/documents/regulatory/tariff/sect_2/oatt/sect_ii.pdf
• § III.3.2.1(b)(i) (defining “Real–Time Load Obligation”). http://www.iso-ne.com/static-assets/documents/2014/12/mr1_sec_1_12.pdf
“How Electricity Flows,” http://www.iso-ne.com/about/what-we-do/in-depth/how-electricity-flowsfrom-wholesale-to-retail (website provided by ISO New England) (providing an overview of the energy pathway in the New England region); “Glossary and Acronyms,” http://www.isone.com/participate/support/ glossary-acronyms (website provided by ISO New England) (defining “Independent System Operator,” “Load–Serving Entity,” and “Transmission Owner”).