Document ID: s3://data.kl3m.ai/documents/govinfo/USCOURTS/USCOURTS-caDC-14-01105/USCOURTS-caDC-14-01105-0/pdf.json

Parties Involved:
Federal Energy Regulatory Commission
Respondent
ISO New England Inc.
Intervenor for Respondent
The Retail Energy Supply Association
Petitioner

Document Text:

United States Court of Appeals 

FOR THE DISTRICT OF COLUMBIA CIRCUIT

Argued September 15, 2015 Decided December 22, 2015 

No. 14-1103 

TRANSCANADA POWER MARKETING LTD., 

PETITIONER

v. 

FEDERAL ENERGY REGULATORY COMMISSION, 

RESPONDENT

ESSENTIAL POWER MASSACHUSETTS, LLC, ET AL., 

INTERVENORS

Consolidated with 14-1104, 14-1105 

On Petitions for Review of Orders of 

the Federal Energy Regulatory Commission 

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. 

USCA Case #14-1105 Document #1589995 Filed: 12/22/2015 Page 1 of 27
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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. 

Before: TATEL and PILLARD, Circuit Judges, and 

EDWARDS, Senior Circuit Judge. 

 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 

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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 LoadServing 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 

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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 costallocation 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. 

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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 (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 

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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 marketbased 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. 

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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 endusers 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. 

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* * * * 

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 dualfuel 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 

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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, LoadServing 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. 

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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 

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Load. Order Conditionally Accepting Tariff Revisions, 144 

FERC at 62,142. The Commission explained that, under costcausation 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 

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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”). 

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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 nonprice 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 

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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 (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 

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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 

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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 

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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 LoadServing 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 endusers. 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 

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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 RealTime 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 

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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. 

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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 

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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 

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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. 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 

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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 noncost 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. 

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 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 

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Program are just and reasonable as required by 16 U.S.C. § 

824d. 

So ordered. 

 

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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,” “RealTime 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/whatwe-do/in-depth/how-electricity-flows-from-wholesale-toretail (website provided by ISO New England) (providing an 

overview of the energy pathway in the New England region); 

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“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”). 

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