Transcanada Power Marketing Ltd. v. Federal Energy Regulatory Commission ( 2015 )

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.
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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
3
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
4
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.
5
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
6
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.
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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 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.
8
****
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
9
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.
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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
11
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
12
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 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
14
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
15
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
16
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
17
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
18
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
19
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.
20
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
21
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
22
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
23
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.
24
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
25
Program are just and reasonable as required by 16 U.S.C. §
824d.
So ordered.
26
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-flows-from-wholesale-to-
retail (website provided by ISO New England) (providing an
overview of the energy pathway in the New England region);
27
“Glossary and Acronyms,” http://www.iso-
ne.com/participate/support/glossary-acronyms (website
provided by ISO New England) (defining “Independent
System Operator,” “Load-Serving Entity,” and “Transmission
Owner”).