Wisconsin Public Power Inc. v. Federal Energy Regulatory Commission

United States Court of Appeals
FOR THE DISTRICT OF COLUMBIA CIRCUIT

Argued April 26, 2007 Decided July 20, 2007

No. 04-1414

WISCONSIN PUBLIC POWER INC.,
PETITIONER

v.

FEDERAL ENERGY REGULATORY COMMISSION,
RESPONDENT

WPS RESOURCES CORPORATION, ET AL.,
INTERVENORS

Consolidated with
05-1006, 05-1007, 05-1198, 05-1203, 05-1358, 05-1427,
05-1428, 05-1429

On Petitions for Review of Orders of the
Federal Energy Regulatory Commission

Mark S. Hegedus argued the cause for petitioners Midwest
Transmission Dependent Utilities and Wisconsin Public Power
Inc. With him on the briefs were Cynthia S. Bogorad, David E.
Pomper, Louis R. Cohen, Jonathan J. Frankel, Heather
Zachary, and Michael R. Postar.
 2

Jeffrey L. Landsman argued the cause for petitioners
National Rural Electric Cooperative Association and Dairyland
Power Cooperative on grandfathered agreement issues. With
him on the briefs was Wallace F. Tillman.

John N. Estes, III argued the cause for petitioners Duke
Energy Shared Services, Inc. and Xcel Energy Services Inc.
With him on the briefs were Noel H. Symons, John L. Shepherd,
Jr., J. Alexander Cooke, Floyd L. Norton, IV, Stephen M. Spina,
and Joseph C. Hall.

Elizabeth E. Rylander, Attorney, and Judith A. Albert,
Senior Attorney, Federal Energy Regulatory Commission,
argued the cause for respondent. With them on the brief was
Robert H. Solomon, Solicitor.

Stephen L. Teichler argued the cause for intervenor
Midwest Independent Transmission System Operator, Inc. With
him on the brief were Ilia Levitine and Stephen G. Kozey.

Cynthia S. Bogorad, David E. Pomper, Mark S. Hegedus,
Louis R. Cohen, Jonathan J. Frankel, Heather Zachary, Jeffrey
L. Landsman, Alan I. Robbins, and Debra D. Roby were on the
brief for intervenors Wisconsin Public Power Inc., et al. in
support of respondent.

John N. Estes, III, Noel H. Symons, and John L. Shepherd,
Jr. were on the brief for intervenor Duke Energy Shared
Services, Inc. in support of respondent.

Before: GINSBURG, Chief Judge, and GARLAND and
KAVANAUGH, Circuit Judges.

Opinion for the Court filed PER CURIAM.
 3

PER CURIAM: The Midwest Independent System Operator,
known as MISO, is a nonprofit corporation that controls the
transmission of electricity over a grid spanning 15 Midwestern
states. Its original tariff was approved by the Federal Energy
Regulatory Commission and went into effect in 2002. Under
that tariff’s terms, MISO approved transmission requests,
scheduled service, monitored the grid to manage congestion, and
provided various ancillary services to support the regional
electricity market.

On March 24, 2004, MISO filed a revised tariff with FERC.
Under the new tariff, MISO administers two competitive
wholesale power markets: a “day-ahead” market that allows
transmission to be scheduled in advance, and a real-time or
“spot” market. Among other improvements over MISO’s
original operations, these markets incorporate more
sophisticated pricing and congestion-management mechanisms
that increase the efficiency and reliability of the transmission
grid. In a series of orders issued between May 2004 and
September 2005, the Commission accepted the proposed tariff
with modifications, and MISO’s new market began operating on
April 1, 2005. Three groups of petitioners now seek review of
various aspects of the Commission’s orders: the Transmission
Dependent Utilities, who rely on MISO’s transmission system
and markets to buy and sell electric power to retail customers;
the Transmission Owners, who are electricity sellers in MISO’s
markets subject to the new tariff’s rules and liabilities; and the
Cooperatives, who are electricity buyers under contracts
predating the establishment of MISO. For the reasons that
follow, we deny the petitions of the Transmission Dependents
and the Transmission Owners, and we dismiss those of the
Cooperatives for lack of standing.
 4

I

Section 201(b) of the Federal Power Act (FPA) grants the
Federal Energy Regulatory Commission exclusive jurisdiction
over the transmission and wholesale sale of electricity in
interstate commerce. See 16 U.S.C. § 824(b). Section 205 of
the FPA provides that “[a]ll rates and charges made, demanded,
or received by any public utility for or in connection with the
transmission or sale of electric energy subject to the jurisdiction
of the Commission . . . shall be just and reasonable, and any
such rate or charge that is not just and reasonable is hereby
declared to be unlawful.” Id. § 824d(a). Section 205 also
prohibits undue discrimination in rates, charges, or terms of
service. See id. § 824d(b). To enforce these requirements,
Section 205 requires that utilities file tariffs reflecting their rates
and service terms with the Commission, which must in turn
ensure that those rates and terms are just and reasonable and not
unduly discriminatory. Id. § 824d(c).

A

In the mid-1990s, FERC determined that longstanding
structural barriers to competition in the wholesale power market
constituted undue discrimination. Since then, it has been the
Commission’s policy to eliminate those barriers and promote
competition. This policy required a significant shift in the
Commission’s regulatory approach, which has in turn produced
dramatic changes in the electricity industry. Because the tariff
at issue in these petitions is part of that transformation, we begin
with some background on the development of FERC’s policy.
Rather than reinventing the wheel, we borrow the following
account from our opinion in Midwest ISO Transmission Owners
v. FERC:
 5

In the bad old days, utilities were vertically
integrated monopolies; electricity generation,
transmission, and distribution for a particular
geographic area were generally provided by and under
the control of a single regulated utility. Sales of those
services were “bundled,” meaning consumers paid a
single price for generation, transmission, and
distribution. As the Supreme Court observed, with
blithe understatement, “[c]ompetition among utilities
was not prevalent.” New York v. FERC, 535 U.S. 1, 5
(2002).

In its pathmarking Order No. 888, FERC required
utilities that owned transmission facilities to guarantee
all market participants non-discriminatory access to
those facilities. See Promoting Wholesale Competition
Through Open Access Non-Discriminatory
Transmission Services by Public Utilities, FERC Stats.
& Regs. ¶ 31,036, 31,635-36 (1996) (Order No. 888).
That is, FERC required all transmission-owning
utilities to provide transmission service for electricity
generated by others on the same basis that they
provided transmission service for the electricity they
themselves generated. To effectuate this introduction
of competition, FERC required public utilities to
“functionally unbundle” their wholesale generation and
transmission services by stating separate rates for each
service in a single tariff and offering transmission
service under that tariff on an open-access,
non-discriminatory basis. See New York, 535 U.S. at
11; see generally California Indep. Sys. Operator
Corp. v. FERC, 372 F.3d 395, 397 (D.C. Cir. 2004).

As the next step toward the goal of a more
competitive electricity marketplace, Order No. 888
 6

encouraged – but did not require – the development of
multi-utility regional transmission organizations
(RTOs). The concern was that the segmentation of the
transmission grid among different utilities, even if each
had functionally unbundled transmission, contributed
to inefficiencies that impeded free competition in the
market for electric power. Combining the different
segments and placing control of the grid in one entity
– an RTO – was expected to overcome these
inefficiencies and promote competition. Order No. 888
at 31,730-32; see also Public Util. Dist. No. 1 of
Snohomish County v. FERC, 272 F.3d 607, 610-11
(D.C. Cir. 2001). Better still if the RTO were run by
an independent system operator – an ISO. As
envisioned by FERC, an ISO would assume
operational control – but not ownership – of the
transmission facilities owned by its member utilities,
thereby “separat[ing] operation of the transmission grid
and access to it from economic interests in generation.”
Order No. 888 at 31,654; see also id. at 31,730-32.
The ISO would then provide open access to the
regional transmission system to all electricity
generators at rates established in “a single, unbundled,
grid-wide tariff that applies to all eligible users in a
non-discriminatory manner.” Id. at 31,731; see also
California Indep. Sys. Operator Corp., 372 F.3d at
397. FERC called this type of separation of generation
and transmission “operational unbundling,” a step
beyond “functional unbundling.” Order No. 888 at
31,654. Although several parties to the 1996
rulemaking had requested that FERC require
“operational unbundling” or even divestiture of
transmission assets, it was FERC’s considered
judgment that “the less intrusive functional unbundling
 7

approach . . . is all that we must require at this time.”
Id. at 31,655.

By 1999, FERC had come to a less sanguine view
of the curative powers of functional unbundling. In
FERC’s view, inefficiencies in the transmission grid
and lingering opportunities for transmission owners to
discriminate in their own favor remained obstacles to
robust competition in the wholesale electricity market.
FERC concluded that these problems could be
remedied through the establishment of RTOs,
explaining that “better regional coordination in areas
such as maintenance of transmission and generation
systems and transmission planning and operation” was
necessary to address regional reliability concerns and
to foster regional competition. See Regional
Transmission Organizations, Order No. 2000, FERC
Stats. & Regs. ¶ 31,089, 30,999 (1999) (Order No.
2000) (codified at 18 C.F.R. § 35.34) (citing Staff
Report to FERC on the Causes of Wholesale Electric
Pricing Abnormalities in the Midwest During June
1998, at 5-8 (Sept. 22, 1998)). FERC concluded that
RTOs would: “(1) improve efficiencies in transmission
grid management; (2) impose grid reliability; (3)
remove remaining opportunities for discriminatory
transmission practices; (4) improve market
performance; and (5) facilitate lighter handed
regulation.” Order No. 2000 at 30,993; Public Util.
Dist. No. 1, 272 F.3d at 611. To further encourage
RTO development, FERC directed
transmission-owning utilities either to participate in an
RTO or to explain their refusal to do so. Public Util.
Dist. No. 1, 272 F.3d at 612. Importantly, though,
Order No. 2000 still did not require utilities to join
 8

RTOs; participation remained voluntary. See id. at
616.

For those utilities opting to join an RTO, Order
No. 2000 retained a flexible approach, allowing the
RTOs to employ a variety of ownership and
operational structures, so long as the RTO established
that it had certain required characteristics and
functional capabilities. Id. at 611. FERC required,
inter alia, that an RTO be regional in scope, 18 C.F.R.
§ 35.34(j)(2); “have operational authority for all
transmission facilities under its control,”
id. § 35.34(j)(3); “be the only provider of transmission
service over the facilities under its control,” id.
§ 35.34(k)(1)(i); and “have the sole authority to
receive, evaluate, and approve or deny all requests for
transmission service,” id. Thus, whatever its structure,
once a utility made the decision to surrender
operational control of its transmission facilities to an
RTO, any transmissions across those facilities were
subject to the control of that RTO.

373 F.3d 1361, 1363-65 (D.C. Cir. 2004) (alterations in
original).

B

MISO developed in response to Order No. 888 and Order
No. 2000. On January 15, 1998, pursuant to Order No. 888, a
group of Midwestern transmission owners sought FERC’s
approval of their agreement establishing an Independent System
Operator. See Midwest Indep. Transmission Sys. Operator, Inc.,
84 F.E.R.C. ¶ 61,231, at 62,139 (1998) (“MISO Formation
Order”). Under the MISO Agreement, “[t]he participating
transmission owners . . . transfer[red] to the Midwest ISO
 9

functional control over all network transmission facilities”
above a specified voltage. Id. The transmission owners retained
ownership and physical control over the facilities, but operated
them according to MISO’s instructions. MISO, in turn, was
“authorized to provide non-discriminatory open access
transmission service,” “to receive and distribute transmission
revenues” to the transmission owners, and “to be responsible for
regional system security.” Id.; see also E. Ky. Power Coop., Inc.
v. FERC, No. 06-1003, slip op. at 5 (D.C. Cir. June 15, 2007)
(“MISO was responsible for functional control over the
transmission system, which included managing transmission
availability and capacity, requests for transmission service,
available ancillary services, and security.”). Along with the
MISO Agreement, the transmission owners also filed an Open
Access Transmission Tariff (OATT), which established the
terms and rates of transmission service on the MISO grid.
Under the proposed OATT, “all customers would pay a single
rate to use the entire MISO transmission system, based on the
volume of power the customer carried on the system.” Midwest
ISO Transmission Owners, 373 F.3d at 1365.

FERC conditionally approved the MISO Agreement and the
OATT on September 16, 1998, but suspended the tariff pending
a hearing to determine whether its terms were just and
reasonable. See MISO Formation Order, 84 F.E.R.C. ¶ 61,231,
at 62,181-82. While these proceedings were still ongoing,
FERC issued Order No. 2000, which directed all FERC-
approved ISOs to show that they had met the requirements for
RTO status. See 18 C.F.R. § 35.34(h). When MISO made the
required filing, the Commission found that it had satisfied Order
No. 2000’s requirements and granted it RTO status. See
Midwest Indep. Transmission Sys. Operator, Inc., 97 F.E.R.C.
¶ 61,326, at 62,500 (2001) (“RTO Formation Order”). The
Commission also approved the OATT, and MISO began
providing transmission service on February 1, 2002. See
 10

Midwest Indep. Transmission Sys. Operator, Inc., 97 F.E.R.C.
¶ 61,033, at 61,177 (2001) (“Opinion No. 453”), order on reh’g,
98 F.E.R.C. ¶ 61,141 (2002) (“Opinion No. 453-A”).

MISO’s development was complicated by the existence of
several hundred pre-existing bilateral contracts between its
transmission owners and other utilities. Midwest ISO
Transmission Owners, 373 F.3d at 1365. These long-term
contracts, known as grandfathered agreements (GFAs),
obligated the transmission owners to provide transmission
service under terms and rates that were inconsistent with the
OATT. See id. In order to balance the contract rights and
expectations of the parties to the GFAs with the benefits of
open-access service provided by an ISO, the MISO transmission
owners “proposed to not place . . . grandfathered wholesale load
under the Midwest ISO’s Tariff for at least a six year transition
period.” Opinion No. 453, 97 F.E.R.C. ¶ 61,033, at 61,169.1 In
other words, under the original version of the MISO Agreement,
two different types of transmission service would have coexisted
on the MISO grid: independent service provided by the
transmission owners under the terms of their bilateral GFAs, and
open-access service provided by MISO under the terms of the
OATT.

FERC accepted this proposed treatment of the GFAs when
it initially approved the formation of the Midwest ISO, but had
to revisit the issue in light of Order No. 2000. As the
Commission explained, “Order No. 2000 and Section 35.34(k)
of the Commission regulations require that an RTO be the only
provider of transmission services over the facilities under its
control.” Opinion No. 453, 97 F.E.R.C. ¶ 61,033, at 61,170

1
“Load” simply refers to demand for service on a transmission
grid. See Transmission Access Policy Study Group v. FERC, 225
F.3d 667, 725 n.11 (D.C. Cir. 2000).
 11

(citing 18 C.F.R. § 35.34(k)). The proposed MISO Agreement
and OATT did not satisfy this requirement because they allowed
transmission owners to provide independent transmission
service to fulfill their obligations under the GFAs. FERC
therefore directed that, “to the extent that certain transmission-
owning members of the Midwest ISO serve . . . grandfathered
load, those transmission-owning members will have to take
transmission service under the Midwest ISO Tariff for their use
of the Midwest ISO transmission system to serve . . .
grandfathered agreement customers.” Opinion No. 453-A, 98
F.E.R.C. ¶ 61,141, at 61,413. MISO complied. Under the
revised MISO Agreement, a transmission owner providing
service under a GFA took service from MISO under the terms
of the OATT and then re-sold the same service to the GFA
customer (this is known as providing “back-to-back”
transmission service).

Order No. 2000 demanded this formal integration of the
GFAs into MISO, but in financial terms the transmission owners
– with FERC’s approval – preserved the separate status of the
GFAs. The final version of the OATT provided that MISO
transmission owners “will be exempt, during the [six-year]
transition period, from rates under the Midwest ISO Tariff for
services provided pursuant to the existing [GFA] agreements.”
Id. Thus, although the transmission owners took service under
the OATT when serving GFAs, they did not pay MISO for that
service – financially, grandfathered load was effectively kept
outside of the OATT.2

2
FERC did, however, require that all load using the grid
contribute to MISO’s administrative costs, which are recovered by
Schedule 10 of the OATT. See Order No. 453-A, 98 F.E.R.C.
¶ 61,141, at 61,413. As we explained in the course of affirming
FERC’s determination, the imposition of Schedule 10 charges on
grandfathered load was consistent with the Commission’s “cost-
 12

C

Under MISO’s original OATT, MISO managed
transmission congestion primarily through the Transmission
Line Loading Relief procedure (TLR). The TLR procedure
required MISO to monitor real-time power flows and to order
the physical curtailment of any transactions that threatened to
exceed the system’s transmission capacity. See Midwest Indep.
Transmission Sys. Operator, Inc., 108 F.E.R.C. ¶ 61,236, at
62,279 PP 27-30 (2004) (“GFA Order”). This system of
congestion management was highly inefficient. “[R]eliance on
TLRs for congestion management inherently leaves transmission
capacity under-utilized because the TLR approach relies on
imprecise flow estimates” and because “each TLR curtailment
. . . may curtail too many or too few transactions.” Id. at 62,279
P 30. The uncertainty of the TLR process also undermined the
reliability of the grid because it made it “more difficult to
maintain power flows within operating security limits.” Id. at
62,280 P 32.

FERC recognized these shortcomings in the OATT, and it
granted MISO’s request for RTO status on the condition that
MISO begin planning a transition to more “dynamic”
operations, including more efficient market-based congestion
management. RTO Formation Order, 97 F.E.R.C. ¶ 61,326, at
62,512, 62,522. On March 31, 2004, MISO filed a revised Open
Access Transmission and Energy Markets Tariff (Tariff) that is
the subject of these petitions for review. The Tariff provides for
a “security-constrained, centralized bid-based scheduling and
dispatch system” similar to those currently operating in three

causation principle” because even transmission owners serving
grandfathered load “draw benefits from being a part of the MISO
regional transmission system.” Midwest ISO Transmission Owners,
373 F.3d at 1371.
 13

other RTOs. See Midwest Indep. Transmission Sys. Operator,
Inc., 108 F.E.R.C. ¶ 61,163, at 61,916-17 PP 2-6 (2004)
(“TEMT II Order”). In these systems, the ISO “administers two
sets of bid-based energy markets. First is the ‘Day-Ahead
Market,’ in which the [ISO] derives a market-clearing price
from the sellers’ and buyers’ price and quantity indications for
the next day; sales are then made at the market-clearing price.
Second is the ‘Real-Time Market,’ designed to ensure system
reliability by calculating hourly clearing prices and allowing
sellers to offer supplies to meet additional demand and even to
revise day-ahead bids.” Edison Mission Energy, Inc. v. FERC,
394 F.3d 964, 965 (D.C. Cir. 2005).

As directed by FERC, the Tariff includes a market-based
approach to congestion management. The Tariff establishes
markets based on a mechanism known as locational marginal
pricing (LMP), which incorporates the cost of congestion into
the price of energy. Under the LMP system, MISO takes into
account the limits on available transmission capacity when
determining the price of energy at each node in its transmission
grid. This results in higher energy prices at nodes that require
the use of congested transmission lines and lower prices in less
congested areas. See Prepared Direct Testimony of Dr. Ronald
R. McNamara 33. LMP reduces the need for inefficient TLRs
by giving market participants incentives to avoid congestion-
causing transactions. See id. It is also more economically
efficient: scarce transmission capacity is allocated to those who
value it most instead of being physically rationed by TLRs. See
id. at 35.

In order to protect market participants from variations in
congestion costs, the Tariff provides for a system of Financial
Transmission Rights (FTRs), which are financial instruments
that entitle their holders to be paid the congestion costs
associated with transmitting a given quantity of electricity
 14

between two specified points. See TEMT II Order, 108 F.E.R.C.
¶ 61,163, at 61,935-36 P 139. A party planning a transmission
can thus hedge its exposure to congestion costs by acquiring a
corresponding FTR. At the time of the transmission, the party
will pay MISO the applicable congestion costs, but will then
receive the same amount back from MISO in its capacity as the
holder of the FTR. MISO proposed annual allocations of FTRs
to existing users of the transmission grid, supplemented by
periodic adjustments and secondary auctions. See id.

Two additional features of the Tariff are relevant to the
petitions before us: market power mitigation measures and
marginal loss refunds. First, MISO recognized that, during
periods of transmission congestion and high demand, sellers
might be able to exercise market power and drive prices in
MISO’s markets to unreasonable levels. The Tariff therefore
provides for two types of market power mitigation: one for
Narrow Constrained Areas (NCAs) and one for Broad
Constrained Areas (BCAs). NCAs are determined annually and
are defined as areas where transmission constraints are expected
to be binding for at least 500 hours during a given year and
where at least one seller is “pivotal.” See id. at 61,955 P 276.
“A supplier is pivotal when the output of some of its generation
resources must be changed to resolve the transmission constraint
during some or all hours when the constraint is binding.” Id.
BCAs are areas where competitive conditions are generally
present but where transmission constraints may create
occasional opportunities for the exercise of market power.
BCAs are defined dynamically: when a transmission constraint
becomes active, MISO’s independent market monitor defines
those generators that affect the constraint as being within the
BCA. See id. at 61,953 PP 264-65.

The consequence of being within an NCA or BCA is that a
generator’s bids are subject to mitigation if they exceed
 15

“conduct” and “impact” thresholds. These thresholds are
defined in relation to the seller’s “reference level,” which is
based on an estimate of its marginal cost. In BCAs, the
“conduct” threshold is equal to either $100 per megawatt hour
above the seller’s reference level or 300 percent above the
reference level, whichever is less. See id. at 61,959 PP 307-12.
If a seller’s bid fails the conduct test, then it is subject to the
impact test. A bid fails the BCA impact test if it causes the
market-clearing price to increase by either $100 per megawatt-
hour or 200 percent above the price that would have resulted if
the seller had bid its reference level. See id. If a seller’s bid
fails both the conduct and impact tests, then it is “mitigated” –
that is, it is reduced to the reference level. FERC approved
MISO’s BCA mitigation measures, but imposed a “sunset”
provision requiring that they terminate after one year unless
MISO filed for an extension. See id. at 61,954-55 P 275.

Because of the greater risk of market power in NCAs, the
conduct and impact thresholds are lower than in BCAs. In
NCAs, both thresholds are the same: the seller’s reference price
plus a “fixed cost adder” equal to the “net annual fixed cost
divided by the constrained hours” expected that year. Id. at
61,959 PP 307-12. Net annual fixed cost is defined as “the fixed
cost of a new peaking generator minus revenue from applicable
resource reserve adequacy payments.” Id. at 61,959 n.209. The
purpose of the fixed-cost adder is to preserve incentives for
suppliers to enter the market (and to discourage existing
suppliers from exiting) by ensuring that market revenues cover
a generator’s fixed costs. See id. at 61,960 PP 316-17. FERC
approved MISO’s NCA mitigation measures without imposing
a sunset provision.

The second relevant feature of the Tariff is its marginal loss
refund mechanism. In addition to accounting for congestion
costs, the Tariff’s LMP mechanism includes a component for
 16

transmission losses. When electricity is transmitted across
power lines, some portion of the energy is lost as heat. The loss
is a function of (among other things) the length of the
transmission and the square of the amount of current being
transmitted. See Sithe/Independence Power Partners, L.P. v.
FERC, 285 F.3d 1, 2 (D.C. Cir. 2002). Under the OATT,
transmission losses within MISO were determined on an average
system-wide basis and allocated to all users pro rata. This
system did not account for the length of the transmission
required for each transaction, and thus led to “cross-subsidies”
between market participants – parties that scheduled long-
distance transmissions paid too little, while those that scheduled
shorter transmissions paid too much. See TEMT II Order, 108
F.E.R.C. ¶ 61,163, at 61,925-26 PP 66, 71. Therefore, FERC
instructed MISO to adopt “marginal loss pricing.” Id. at 61,925
P 66. Marginal loss pricing recovers transmission losses on a
transaction-by-transaction basis by incorporating them into the
LMP. In order to do so, however, it treats every transmission as
if it were the last (marginal) transmission on the system. This
pricing scheme sends more efficient signals to market
participants, but because transmission losses increase with the
amount of current in the system, treating every transmission as
the marginal transmission produces revenue in excess of actual
losses – the “marginal loss surplus.”

In order to provide transitional protection for market
participants who faced higher costs as a result of the new
marginal loss system, FERC required MISO to use this surplus
to “refund the difference between the marginal loss charge and
either an average loss or a historical loss charge to all existing
transmission customers” for the first five years of the Tariff. Id.
at 61,926 PP 73-74. MISO proposed, and FERC approved, a
refund mechanism that distributes marginal loss surpluses
through groups of market participants known as “Balancing
Authority Areas.” See Midwest Indep. Transmission Sys.
 17

Operator, Inc., 109 F.E.R.C. ¶ 61,285, at 62,364 P 160 (2004)
(“Compliance Order I”). The surpluses are distributed pro rata
within each Area, but “customers in Balancing Authority Areas
that have the highest actual losses . . . receive a greater
proportion of the Marginal Loss Surplus share than customers in
Balancing Authority Areas with relatively lower losses.” Id.

D

The Commission approved the Tariff in two parallel
proceedings. In the first set of orders, FERC considered the
justness and reasonableness of the terms of the Tariff, including
the features described above. These orders accepted the Tariff
with some modifications and subject to ongoing compliance
filings. See TEMT II Order, 108 F.E.R.C. ¶ 61,163, order on
reh’g, 109 F.E.R.C. ¶ 61,157 (2004) (“TEMT II Reh’g Order”),
order on reh’g, 111 F.E.R.C. ¶ 61,043 (2005) (“Compliance
Order III”), reh’g denied, 112 F.E.R.C. ¶ 61,086 (2005)
(“Compliance Order V”).3

In the second set of orders, the Commission considered the
relationship between MISO’s new markets and the GFAs, which
– as during the formation of MISO – posed special difficulties.
In the original MISO Agreement, the transmission owners
agreed to preserve the rates and terms of the GFA contracts for
at least a six-year transition period. But under the Tariff, with
its system of markets and centralized dispatch, the GFA parties
could only “exercise the scheduling and energy management
provisions of their GFAs in the same manner they did before” if

3
Petitioners also seek review of three related compliance orders.
See Compliance Order I, 109 F.E.R.C. ¶ 61,285, order on reh’g, 111
F.E.R.C. ¶ 61,053 (2005) (“Compliance Order IV”); Midwest Indep.
Transmission Sys. Operator, Inc., 110 F.E.R.C. ¶ 61,049 (2005)
(“Compliance Order II”).
 18

MISO reserved or “carved out” transmission capacity from its
day-ahead market to allow for the possibility that it would be
used by the GFA transactions. GFA Order, 108 F.E.R.C.
¶ 61,236, at 62,289 P 90. In its initial filing, MISO estimated
that GFAs accounted for up to 40 percent of the total load on its
transmission grid. Midwest Indep. Transmission Sys. Operator,
Inc., 107 F.E.R.C. ¶ 61,191, at 61,776 P 16 (2004) (“Procedural
Order”). MISO argued that carving out such a large fraction of
its transmission capacity would significantly reduce the
efficiency of the new markets, jeopardize reliability, and impose
significant costs on other market participants. See id. at 61,777
P 17. Therefore, MISO proposed that those GFA parties that did
not voluntarily agree to convert to service under the Tariff be
required to choose one of three options for scheduling their
transactions and settling transmission charges.

All three options proposed by MISO required the GFA
parties to designate a GFA Responsible Entity (GFA-RE), which
would be financially responsible for charges under the Tariff,
and a GFA Scheduling Entity (GFA-SE), which would submit
schedules for GFA transactions to MISO. See id. at 61,777 P 19
& nn.23-24. Under Option A, the GFA-RE would pay
congestion charges and loss charges under the Tariff and would
also be eligible for FTR allocations, just like any other market
participant. See id. at 61,777-78 P 20. Under Option B, as
under Option A, the GFA-RE would pay congestion and loss
charges. But instead of being required to obtain FTRs to hedge
congestion costs like other market participants, these GFA-REs
would receive a guaranteed reimbursement of congestion costs
and loss charges as long as their GFA-SEs provided MISO with
a day-ahead schedule of GFA transmissions. See id. at 61,778
P 21. Finally, under Option C, the GFA-RE would pay
congestion costs and marginal loss charges but would not be
eligible for refunds or FTRs. See id. at 61,778 P 22.
 19

The Commission responded to MISO’s proposal by
instituting a three-step process to gather additional information
about the GFAs and their impact on the new markets. Step one,
the “paper hearing,” required utilities to provide information
about their GFA contracts and sought additional information
from MISO on the impact of a “carve out” of GFA load on the
efficiency and reliability of the new markets. See id. at 61,785-
86 P 68. Step two was a “trial-type” hearing before two
administrative law judges to settle any disputes between GFA
parties about the information sought in step one. See id. at
61,787 P 75; see also Midwest Indep. Transmission Sys.
Operator, Inc., 108 F.E.R.C. ¶ 63,013 (2004) (“ALJ Findings”).
Finally, in step three the Commission issued an order on the
merits of MISO’s proposal. See Procedural Order, 107 F.E.R.C.
¶ 61,191, at 61,787 P 78. FERC also encouraged GFA parties
to avoid the time and expense of the three-step process by
voluntarily agreeing to convert to Tariff service or selecting one
of MISO’s proposed options. Id. at 61,787 P 77.

The Commission issued its order on the merits on
September 16, 2004. See GFA Order, 108 F.E.R.C. ¶ 61,236,
order on reh’g, 111 F.E.R.C. ¶ 61,042 (2005) (“GFA Reh’g
Order”), order on reh’g, 112 F.E.R.C. ¶ 61,311 (2005). Based
on the paper hearing and the ALJ findings, FERC determined
that MISO’s initial estimate of the scope of the problem had
been somewhat exaggerated. A total of 229 GFAs would be in
existence when the Tariff went into effect, representing 23
percent of MISO’s total load rather than 40 percent. See id. at
62,275 P 4. Furthermore, 52 of those GFAs – representing nine
percent of MISO’s total load – had voluntarily settled before the
Commission issued its order on the merits. See id.; see also id.
at 62,318 P 275. The largest group, representing roughly five
percent of MISO’s total load, selected Option B. See id. at
62,318 P 275.
 20

The Commission concluded that carving out the relatively
small number of remaining GFAs would not threaten the
reliability of MISO’s grid or seriously compromise the
efficiency of its markets. See id. at 62,288-91 PP 89-102.
FERC also explained that, if the GFAs were not carved out, the
result would “impose changes to the manner in which
transmission service is provided for transactions under the
GFAs” and could alter the original bargain between the GFA
parties by shifting costs between them. Id. at 62,296-97 P 138.
The Commission agreed with MISO, however, that any carve
out for GFAs “has the potential to result in additional costs for
non-GFA transactions.” Id. at 62,290 P 99.

In order to balance these competing considerations, the
Commission determined that the treatment of non-settling GFAs
should depend on the standard of review in each GFA contract.
FPA section 205 allows utilities to file changes to their rates at
any time and requires FERC to approve them as long as the new
rates are “just and reasonable.” 16 U.S.C. § 824d(d), (e).
“Under the Supreme Court’s Mobile-Sierra doctrine,” however,
“parties may negotiate a fixed-rate contract with a provision
relinquishing their right to file for a unilateral change in rates.”
Atl. City Elec. Co. v. FERC, 295 F.3d 1, 11 (D.C. Cir. 2002); see
also FPC v. Sierra Pac. Power Co., 350 U.S. 348 (1956); United
Gas Pipe Line Co. v. Mobile Gas Serv. Corp., 350 U.S. 332
(1956). If the parties to a contract adopt the Mobile-Sierra
standard of review, “FERC may abrogate or modify” the
contract “only if required by the public interest.” Atl. City Elec.,
295 F.3d at 14. This standard “is much more restrictive than the
just and reasonable standard of section 205.” Id.

FERC concluded that all non-settling GFA contracts that
were subject to unilateral modification under the “just and
reasonable” standard should be required to “choose between the
scheduling and settlement provisions of Option A or Option C.”
 21

GFA Order, 108 F.E.R.C. ¶ 61,236, at 62,297 P 139.4 The
Commission explained that the risk of imposing additional costs
on non-GFA parties made it “unjust and unreasonable to allow
GFAs that are subject to a just and reasonable standard of
review to remain outside the Midwest ISO Energy Markets.” Id.
at 62,296 P 137. The risk of unfair cost shifts between the GFA
parties was reduced, moreover, because “the terms and
conditions of GFAs subject to a just and reasonable standard of
review allow the parties to propose appropriate modifications to
reflect such new costs.” Id. at 62,297 P 138. These “just and
reasonable” GFAs accounted for another 4.5 percent of total
MISO load.

By contrast, the Commission directed MISO to “carve [the
Mobile-Sierra] GFAs out of the Energy Markets for the
remainder of the six-year transition period.” Id. at 62,297 P 143.
The Commission explained that it “cannot find today that the
public interest requires that [the Mobile-Sierra] GFAs be
modified” in the same manner as the just-and-reasonable GFAs
because the new energy markets “can be operated reliably, with
net benefits to the public, notwithstanding a carve-out” of these
GFAs. Id. at 62,297 P 142. FERC also explained that a carve
out of the Mobile-Sierra GFAs was needed to maintain the
bargain of the original MISO Agreement, in which the MISO
transmission owners agreed that GFAs would be kept outside of

4
FERC determined that both of these options were just and
reasonable, and that Option B was just and reasonable for those
parties that had already settled. See GFA Order, 108 F.E.R.C.
¶ 61,236, at 62,316 P 264. But the Commission explained that
“Option B was an incentive to settle,” and that “[i]t would be unfair
to allow this option” – with its guaranteed reimbursement of
congestion and marginal loss charges – “to those that did not settle
first and [a]waited (and even litigated) the outcome of this
proceeding.” Id.
 22

MISO for a six-year transition period. See GFA Reh’g Order,
111 F.E.R.C. ¶ 61,042, at 61,134 P 94. In total, the 127 carved-
out Mobile-Sierra GFAs accounted for approximately 9.5
percent of MISO’s total load. GFA Order, 108 F.E.R.C.
¶ 61,236, at 62,297 P 141.5

The Commission also addressed the designation of GFA-
REs and GFA-SEs. Unless the parties agreed otherwise, the
Commission determined that the transmission owner responsible
for providing service under the GFA should be both the GFA-
RE and the GFA-SE. See id. at 62,300-01 PP 161, 165.

Finally, the Commission addressed the assessment of MISO
charges on GFA agreements. It concluded that the
administrative costs associated with the new markets – known
as Schedule 17 charges – should be assessed on all load using
the MISO grid, including carved-out GFAs. See id. at 62,321-22
PP 297-98. Applying the “cost-causation” principle, the
Commission found that the new markets would “produce more
reliable service and more efficient Energy Markets that will
benefit all [parties] transacting over the Midwest ISO grid,” and
concluded that “GFAs should pay for the benefits they receive.”
Id. at 62,322 P 298. But the Commission concluded that carved-
out GFAs should not pay Schedule 16 charges, which cover the
cost of administering the market in FTRs, because carved-out
GFAs “do not benefit from the FTR Service.” Id. at 62,321
P 295.

5
These figures include contracts that did not specify a standard
of review, which the Commission decided to treat as if they had
incorporated the Mobile-Sierra standard. See GFA Order, 108
F.E.R.C. ¶ 61,236, at 62,298 PP 147-49. They also include a small
number of non-jurisdictional GFAs. FERC explained that these
GFAs had to be carved out because it “has no authority to make any
modifications to these contracts.” Id. at 62,298 P 150.
 23

E

Three groups of petitioners now seek review of the 11
orders approving the Tariff and addressing the treatment of the
GFAs. The first group, led by the Midwest Transmission
Dependent Utilities, is made up of buyers of power in the new
markets. They argue that FERC should have required more
stringent market power mitigation measures and that the
Commission’s approval of MISO’s marginal loss refund
mechanism was arbitrary and capricious. The second group, led
by the National Rural Electric Cooperative Association and the
Dairyland Power Cooperative (the Cooperatives), is composed
of buyers of power under GFA agreements. They argue that the
imposition of Schedule 17 charges on carved-out GFAs was
arbitrary and capricious and that the Commission’s denial of
their request for an evidentiary hearing violated the
Administrative Procedure Act and the Due Process Clause of the
Constitution. The third group consists of Duke Energy Shared
Services, Inc., and Xcel Energy Services Inc. – transmission
owners who sell power in the new markets. They argue that all
GFAs should have been required to choose between conversion
to the Tariff, Option A, or Option C, and that FERC acted
arbitrarily by carving out some GFAs entirely and granting
others favorable treatment under Option B. In addition, Xcel
challenges FERC’s designation of the GFA-RE and GFA-SE.6

The remainder of this opinion addresses the issues raised by
each group of petitioners in turn. At the outset, however, we set

6
The Transmission Dependents intervened in support of FERC
on the issues raised by Duke and Xcel, while Duke (but not Xcel)
intervened to support FERC on the issues raised by the other two
groups of petitioners. Finally, MISO intervened to support FERC on
the issues raised by the Transmission Dependents and the
Cooperatives.
 24

forth the standard of review that is common to the objections
asserted by all three. We review FERC’s orders by applying the
Administrative Procedure Act’s “arbitrary and capricious”
standard. See 5 U.S.C. § 706(2)(A); Midwest ISO Transmission
Owners, 373 F.3d at 1368. Under this deferential standard, we
must affirm the Commission’s orders as long as it has
“examine[d] the relevant data and 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 v. State Farm Mut. Auto. Ins. Co., 463 U.S. 29, 43
(1983) (quoting Burlington Truck Lines, Inc. v. United States,
371 U.S. 156, 168 (1962)). We treat the Commission’s factual
findings as conclusive as long as they are supported by
substantial evidence. See 16 U.S.C. § 825l(b). Finally, we
recognize that “matters of rate design . . . are technical and
involve policy judgments at the core of FERC’s regulatory
responsibilities. Hence, the court’s review of whether a
particular rate design is just and reasonable is highly
deferential.” Me. Pub. Utils. Comm’n v. FERC, 454 F.3d 278,
287 (D.C. Cir. 2006).

II

The Transmission Dependent Utilities buy power for resale
to retail customers in the new markets overseen by the Midwest
Independent System Operator (MISO). These petitioners
challenge two aspects of MISO’s operations under the Tariff.
See Midwest Indep. Transmission Sys. Operator, Inc., 108
F.E.R.C. ¶ 61,163 (2004) (“TEMT II Order”), order on reh’g,
109 F.E.R.C. ¶ 61,157 (2004) (“TEMT II Reh’g Order”). First,
the Transmission Dependents challenge MISO’s market power
mitigation measures, which seek to prevent electricity suppliers
from unduly raising prices above competitive levels in certain
areas of MISO’s grids where transmission constraints sometimes
give suppliers the power to influence prices. Second, the
 25

Transmission Dependents challenge MISO’s allocation of
refunds for marginal loss charges, which account for the extra
energy that generators must inject into a grid to supply
electricity to faraway buyers (because electricity dissipates the
further it travels from its source). We hold that FERC’s
conclusions on these points were reasonable, and we therefore
deny the Transmission Dependents’ petitions for review.

A

When electricity demand is high and the grids become
congested, the possibility arises that sellers in some transmission
constrained areas will be able to exercise their market power and
charge higher-than-competitive prices. The Tariff separated
these areas into Narrow Constrained Areas (NCAs), which pose
more persistent competitive concerns, and Broad Constrained
Areas (BCAs), which pose only intermittent competitive
concerns. Under the Tariff, the independent market monitor
compares bids in constrained areas to reference levels calculated
from suppliers’ historical costs. If those bids exceed the
reference level by a certain increment and fail a market impact
test, the independent market monitor mitigates the bids –
replacing them with lower amounts designed to give sellers an
appropriate but not higher-than-competitive investment return.
See TEMT II Order, 108 F.E.R.C. ¶ 61,163, at 61,949-50
PP 242, 245, 247. “The conduct screen sifts out prices that by
some amount or percentage exceed a reference price. . . . The
impact screen tests whether that price increment actually would
cause market-clearing prices to rise a certain amount or
percentage over the price that would prevail in the event of
mitigation.” Edison Mission Energy, Inc. v. FERC, 394 F.3d
964, 965-66 (D.C. Cir. 2005) (internal quotation marks omitted).

FERC concluded that the Tariff’s approach to the
mitigation of sellers’ market power in the NCAs and BCAs
 26

adequately responded to the market power problem by avoiding
under-mitigation, and at the same time, not over-mitigating and
squelching suppliers’ incentives to invest in additional capacity
in those areas. Challenging that conclusion, the Transmission
Dependents focus on features of FERC’s choices concerning the
NCAs (Parts 1 and 2 below) and BCAs (Parts 3 and 4 below).

1

NCAs are areas where transmission constraints are expected
to be binding for at least 500 hours during a given year, and
where at least one seller is “pivotal” in that the constraint can
only be resolved if the seller increases its generation output. See
TEMT II Order, 108 F.E.R.C. ¶ 61,163, at 61,955 P 276. The
NCA definition thus focuses on individual seller conduct. See
id. The NCA definition does not account for the possibility that
even where a single seller lacks the influence over output
necessary to be pivotal, a group of sellers in collusion may
exercise such influence. More specifically, the NCA definition
does not take into consideration how concentrated the relevant
geographic section of the market is – even though there is a
connection between market concentration and the likelihood of
anticompetitive collusion: “Significant market concentration
makes it easier for firms in the market to collude, expressly or
tacitly, and thereby force price above or farther above the
competitive level.” FTC v. H.J. Heinz Co., 246 F.3d 708, 724
(D.C. Cir. 2001) (internal quotation marks omitted); see also
Brooke Group Ltd. v. Brown & Williamson Tobacco Corp., 509
U.S. 209, 227 (1993) (“Tacit collusion . . . describes the process,
not in itself unlawful, by which firms in a concentrated market
might in effect share monopoly power, setting their prices at a
profit-maximizing, supracompetitive level by recognizing their
shared economic interests and their interdependence with
respect to price and output decisions.”).
 27

The Transmission Dependents challenge the omission of
market concentration analysis from the NCA definition. They
proposed that MISO focus on multilateral conduct and use a
market concentration metric – such as the Herfindahl-
Hirschmann Index (HHI), which “is calculated by totaling the
squares of the market shares of every firm in the relevant
market.” H.J. Heinz Co., 246 F.3d at 716 n.9. (When the
Department of Justice and Federal Trade Commission review
proposed mergers, those agencies treat a market with an HHI
value exceeding a certain level (1,800) as highly concentrated,
meaning the merger warrants careful attention because of the
risk of abuse of market power that might result from increased
concentration. See id.). FERC rejected that proposal,
concluding that market concentration analysis was not
mandatory in defining NCAs. See TEMT II Reh’g Order, 109
F.E.R.C. ¶ 61,157, at 61,704-05 PP 235, 241-44. FERC did,
however, note that the independent market monitor could use the
HHI to identify areas where market power is enough of a
concern to warrant designation as NCAs; FERC thus deemed
HHI analysis optional, not compulsory. See TEMT II Order,
108 F.E.R.C. ¶ 61,163, at 61,956 P 283.

We conclude that FERC reasonably refused to direct MISO
to define NCAs using the HHI or another market concentration
measure. Petitioners’ argument that FERC precedent required
a different determination errs in two respects: first, in
misreading a prior FERC order in one case concerning market-
based rates, and second, in mistaking the binding force of a
subsequent FERC order in another case concerning the
Pennsylvania-New Jersey-Maryland (PJM) Regional
Transmission Organization (RTO).

First, in AEP Power Marketing, Inc., FERC addressed
aspects of its market-based rate evaluation framework, which
applies to electricity suppliers that have received FERC’s
 28

permission to charge market-based rates (rather than rates
subject to “traditional cost-based rate ceilings”). See 107
F.E.R.C. ¶ 61,018, at 61,054-70 PP 30-127 (2004); Grand
Council of the Crees v. FERC, 198 F.3d 950, 953 (D.C. Cir.
2000). FERC requires an applicant that wants to charge market-
based rates to establish, among other things, “that it, and its
affiliates, either do not have, or have adequately mitigated,
market power in both generation and transmission.” Grand
Council of the Crees, 198 F.3d at 953. To help determine which
suppliers exercise market power and therefore ought not be
given the latitude to charge market-based rates, FERC decided
in AEP to use two analytical screens, one of which focuses on
the generator’s seasonal market share. Generators with a market
share of 20 percent or more are presumed to have market power,
but they can produce evidence rebutting the presumption. See
107 F.E.R.C. ¶ 61,018, at 61,060-61 PP 71-72, 61,065-66
PP 101-03.

Because the AEP order did not embrace use of the HHI, it
cannot be taken as precedent requiring its use here. Looking at
a single firm’s individual market share, as FERC did in AEP, is
obviously not the same thing as looking at all of the market
shares of all of the firms in the market, which is what a
concentration metric such as the HHI does – and which is what
petitioners demanded MISO had to do in defining NCAs.
Moreover, the market-based rate framework used in AEP is
concerned with shifting the burden of proof on market power to
generators with seasonal market shares of 20 percent or more;
in contrast, all supplier bids in NCAs are reviewed under the
conduct and impact tests, and suppliers have no opportunity to
forestall application of those tests by offering evidence that they
do not possess market power. Thus, as FERC properly noted,
the market-based rates framework and the NCA concept are
sufficiently distinct that “pieces of one should not automatically
 29

be used as precedent for the other.” TEMT II Reh’g Order, 109
F.E.R.C. ¶ 61,157, at 61,705 P 242.

Second, petitioners are mistaken in relying on a subsequent
proceeding in which FERC asked the PJM RTO to explain why
it did not use the market power tests described in FERC’s AEP
order. See PJM Interconnection, LLC, 110 F.E.R.C. ¶ 61,053,
at 61,249 PP 80, 84 (2005). FERC issued the PJM order after
FERC issued the rehearing order approving the MISO Tariff
(dated November 8, 2004); it is that rehearing order that is
challenged in this case. See TEMT II Reh’g Order, 109
F.E.R.C. ¶ 61,157, at 61,663. Agencies are ordinarily not
required to “explain alleged inconsistencies in the resolution of
subsequent cases,” when the subsequent case is not “part of a
pattern of arguably inconsistent decision-making that began
before the challenged action.” AT&T Inc. v. FCC, 452 F.3d 830,
839 (D.C. Cir. 2006) (internal quotation marks omitted).
Petitioners have not established that there was any such pattern
of inconsistency beginning before FERC’s original order
approving the MISO tariff, so the ordinary rule governs, and in
this case we cannot require FERC to square the PJM order with
its decision concerning MISO.

In any event, the PJM order simply reflected a line of
inquiry by FERC concerning the reasonableness of the RTO’s
proposed concentration metric, but it in no way required all
RTOs to use concentration metrics in all market power
mitigation frameworks. In fact, the PJM proceedings ended in
a settlement that decided nothing. As FERC noted: “The
Commission’s approval of the settlement agreement does not
constitute approval of, or precedent regarding, any principle or
issue in this proceeding.” PJM Interconnection, LLC, 114
F.E.R.C. ¶ 61,076, at 61,282 P 3 (2006) (emphasis added). And
this Court has already held that neither FERC nor challengers
may rely on an uncontested settlement as precedent. Kelley ex
 30

rel. Mich. Dep’t of Natural Res. v. FERC, 96 F.3d 1482, 1490
(D.C. Cir. 1996).

FERC’s orders in the AEP and PJM proceedings, then, did
not compel it to direct MISO to perform market concentration
analysis in defining NCAs. And FERC reasonably explained
that market concentration analysis carried too great a risk of
over-mitigation in the context of this market power mitigation
scheme. See Motor Vehicle Mfrs. Ass’n v. State Farm Mut.
Auto. Ins. Co., 463 U.S. 29, 43 (1983) (“[T]he agency must
examine the relevant data and articulate a satisfactory
explanation for its action including a rational connection
between the facts found and the choice made.”) (internal
quotation marks omitted). Requiring the market power
mitigation framework to focus on market concentration carried
the risk of over-mitigation, and FERC reasonably took that into
account. In sum, FERC’s conclusion that market concentration
analysis was not necessary to properly identify areas warranting
NCA treatment was reasonable.

2

Within an NCA, the conduct test compares (i) a supplier’s
bid to (ii) the supplier’s reference price – calculated from
historical cost data – plus a “fixed cost adder” set at the
supplier’s “net annual fixed cost divided by the constrained
hours” for the given year. See TEMT II Order, 108 F.E.R.C.
¶ 61,163, at 61,959 P 312. The Tariff defined the net annual
fixed cost to be “the fixed cost of a new peaking generator
minus revenue from applicable resource reserve adequacy
payments.” Id. at 61,959 n.209. The fixed cost adder is
designed to ensure that suppliers earn enough money not only to
pay for generation of each additional unit of electricity within
the NCA, but also to recover fixed costs such as the cost of
 31

building generation facilities. The premise is straightforward:
If sellers are unable to recover fixed costs, they will have little
reason to remain in the area or to invest in new capacity for the
area. See id. at 61,960 PP 316-17.

The Transmission Dependents seek to invalidate the fixed
cost adder. They contend that the adder was vaguely defined
and overly generous to suppliers at the expense of buyers such
as the Transmission Dependents. According to petitioners, in
those few NCAs where recovery of fixed costs poses a genuine
problem, MISO should simply have set the adder at the
supplier’s marginal cost plus a 10-percent booster. FERC
rejected that approach, concluding that the fixed cost adder as
defined in the Tariff “provides a careful balance between the
need to mitigate market power and to provide an efficient
incentive to invest.” Id. at 61,960 P 317.

Petitioners fail to convince us that FERC’s approval of the
fixed cost adder was unsupported by the evidence or
inadequately explained. FERC’s overall task, of course, was to
ensure, based on record evidence, that the rates and practices set
forth in the MISO Tariff were just, reasonable, and not unduly
discriminatory. See 16 U.S.C. § 824d(a), (b). “The burden,”
however, “is on the petitioners to show that the Commission’s
choices are unreasonable and its chosen line of demarcation is
not within a zone of reasonableness as distinct from the question
of whether the line drawn by the Commission is precisely right.”
ExxonMobil Gas Mktg. Co. v. FERC, 297 F.3d 1071, 1084 (D.C.
Cir. 2002) (internal quotation marks omitted).

Petitioners’ argument that the appropriate investment
incentive should have been limited to marginal-cost-plus-10-
percent certainly casts no doubt upon the reasonableness of the
adder that FERC approved. “[T]he just and reasonable
standard,” the Supreme Court has explained, “does not compel
 32

the Commission to use any single pricing formula.” Mobil Oil
Exploration & Producing Se., Inc. v. United Distribution Cos.,
498 U.S. 211, 224 (1991). Petitioners essentially submit that
fixed cost recovery is universally guaranteed by setting the
adder at marginal cost (as estimated from historical cost data)
plus 10 percent, but that mistakenly presupposes the existence
of a “single pricing formula” for fixed cost recovery that meets
the just and reasonable standard. Id. Petitioners’ argument goes
astray, in other words, by substituting a pinpoint (marginal cost
plus 10 percent, and not a penny more) for a zone of reasonable
options FERC can choose from. See ExxonMobil Gas Mktg.,
297 F.3d at 1084.

Moreover, FERC’s conclusion that the fixed cost adder was
necessary “to provide an efficient incentive to invest” was a
judgment about the future behavior of entities FERC regulates.
TEMT II Order, 108 F.E.R.C. ¶ 61,163, at 61,960 P 317. This
forecast – that approval of the fixed cost adder would help
ensure that electricity suppliers continue to invest in NCAs –
was a reasonable predictive judgment that warrants judicial
deference. It is well established that an “agency’s predictive
judgments about areas that are within the agency’s field of
discretion and expertise are entitled to particularly deferential
review, as long as they are reasonable.” EarthLink, Inc. v. FCC,
462 F.3d 1, 12 (D.C. Cir. 2006) (internal quotation marks
omitted and emphasis altered); see Envtl. Action, Inc. v. FERC,
939 F.2d 1057, 1064 (D.C. Cir. 1991) (“[I]t is within the scope
of the agency’s expertise to make . . . a prediction about the
market it regulates, and a reasonable prediction deserves our
deference notwithstanding that there might also be another
reasonable view.”).

Petitioners contend that FERC’s predictive judgment failed
to account for the testimony of two experts, who essentially
opined that not every supply-constrained area of a power grid –
 33

a load pocket – needs an investment incentive like the fixed cost
adder.

The expert testimony that petitioners rely on, however, did
not refute FERC’s conclusion that a fixed cost adder was
appropriate for NCAs. The analysis by the Transmission
Dependents’ witness, Laurence Kirsch, was not anchored in the
particular terms used in the Tariff (such as the NCA definition
or the fixed cost adder definition); rather, Kirsch made claims at
a high level of generality. He stated, for example, that FERC
“should be aware that there may be some times and places”
where the “efficiency justification for high electricity prices is
lacking.” Kirsch Aff. at 7 (emphasis added). That testimony
fell short of establishing that the fixed cost adder was
inappropriate for the NCAs as defined in the Tariff. The
testimony from the market monitor’s witness, David Patton,
likewise did not contradict FERC’s conclusion. He stated that
“new investment is not always necessary in the load pocket.”
Protest of Midwest [Transmission Dependent Utilities], FERC
Docket No. ER04-691-000, at 134 (May 7, 2004) (internal
quotation marks omitted and emphasis altered). That statement
made the undisputed point that an effective market power
mitigation scheme is one that seeks to distinguish between price
increases attributable to resource scarcity (which signal a need
for investment to reduce the scarcity) and price increases
attributable to exercise of market power (which do not signal
investment need and instead reflect lack of competition). If
anything, the portion of Patton’s testimony that petitioners quote
suggests that interference with market prices should be avoided:
“Markets,” he testified, “should establish transparent price
signals that accurately reveal the marginal value of resources in
the load pockets.” Id. (internal quotation marks omitted). That
statement did not cast doubt upon the logic of the fixed cost
adder – which, by affording suppliers latitude in setting prices,
embraces rather than undermines the notion that transparent
 34

price signals are good for the market. In short, petitioners have
not identified relevant record evidence that compelled FERC to
invalidate the fixed cost adder.

Petitioners’ final argument concerning the fixed cost adder
is that FERC unreasonably declined to require MISO to revise
the Tariff to clarify that the fixed cost adder calculation takes
into account (“nets”) all sources of fixed cost recovery – such as
retail rates approved by state authorities. But petitioners
informed FERC that they understood how the calculations
would be performed, noting their understanding that the
independent market monitor would “net any retail rate recovery
against the numerator of the fixed cost adder.” Id. at 129. So
even assuming that the Tariff was imprecise in explaining how
the adder would be calculated, petitioners’ argument on this
point does not warrant relief; they have admitted that they
understand the very Tariff term they deem confusing.

3

Supplier bids in constrained areas may exceed reference
levels by a certain amount under the conduct test before they are
subject to the impact test for mitigation. In NCAs that certain
amount is the fixed cost adder. BCAs are structured differently
to account for their more robust competitive conditions. A
supplier’s bid in a BCA fails the conduct test if it exceeds the
reference level by the lesser of $100 per megawatt hour or 300
percent. The bid goes on to fail the impact test if it would cause
the market-clearing price to rise – by the lesser of $100 per
megawatt-hour or 200 percent – above the price that would have
prevailed had the supplier bid at the reference level. See TEMT
II Order, 108 F.E.R.C. ¶ 61,163, at 61,959 PP 307-12.

The Transmission Dependents urged FERC to revise those
numbers, arguing that they afford suppliers in BCAs too much
 35

leeway to charge high prices before mitigation kicks in. FERC
rejected those arguments. See TEMT II Reh’g Order, 109
F.E.R.C. ¶ 61,157, at 61,700-01 PP 215-21.

Petitioners fear that suppliers in BCAs will hike their prices
to just below the specified limits – to rake in as much money as
they can without triggering mitigation. But FERC reasonably
concluded that petitioners’ scenario is not likely to become
reality. In BCAs, concerns about market power are “minimal”
or “not expected to be significant on an on-going basis.” TEMT
II Order, 108 F.E.R.C. ¶ 61,163, at 61,953 P 264; TEMT II
Reh’g Order, 109 F.E.R.C. ¶ 61,157, at 61,701 P 221. That
means – by definition – that suppliers in these areas ordinarily
face competition and must therefore charge what the market will
bear, but suppliers may not charge more than that without
risking the loss of customers to competing suppliers. Rivals will
quickly undercut a supplier that insists on pushing its
permissible pricing to the limit (by charging an amount just
below mitigation-triggering levels). Again, most of the time a
BCA is a competitive market. And in “a competitive market,
where neither buyer nor seller has significant market power, it
is rational to assume that the terms of their voluntary exchange
are reasonable, and specifically to infer that price is close to
marginal cost, such that the seller makes only a normal return on
its investment.” Tejas Power Corp. v. FERC, 908 F.2d 998,
1004 (D.C. Cir. 1990).

Equally unavailing are the other arguments advanced
against FERC’s approval of the BCA mitigation framework. In
deciding that the BCA ceilings are just and reasonable, FERC
emphasized that approving the MISO market power mitigation
scheme required striking a balance between, on the one hand,
detecting and dampening exercises of market power and, on the
other hand, allowing generators to charge prices that are high
enough for them to recover their fixed costs. See TEMT II
 36

Reh’g Order, 109 F.E.R.C. ¶ 61,157, at 61,701 P 221.
Mitigation within NCAs takes fixed cost recovery into account
through the fixed cost adder. But in BCAs, there is no fixed cost
adder. Rather, in these areas, the more lenient ceilings to which
prices may rise above reference before triggering mitigation
allow for fixed cost recovery.

Those ceilings, FERC concluded, reflect an appropriate
trade-off between the interests of buyers and sellers – and, of
course, setting a just and reasonable rate necessarily “involves
a balancing of the investor and the consumer interests.” FPC v.
Hope Natural Gas Co., 320 U.S. 591, 603 (1944) (quoted in
Grand Council of the Crees, 198 F.3d at 956). As FERC
recognized in this case, “[t]he potential for over-mitigation
would increase as BCA thresholds are tightened,” and
petitioners have failed to show that FERC acted unreasonably in
choosing precisely what degree of over-mitigation risk was
appropriate. TEMT II Reh’g Order, 109 F.E.R.C. ¶ 61,157, at
61,701 P 221. Indeed, this choice is a classic example of
ratemaking that “involves policy determinations in which the
agency is acknowledged to have expertise,” and, of course, our
review of such determinations “is particularly deferential.” Pub.
Serv. Comm’n of Ky. v. FERC, 397 F.3d 1004, 1006 (D.C. Cir.
2005) (internal quotation marks omitted).

4

The Transmission Dependents next challenge FERC’s
decision to authorize mitigation within BCAs one year at a time,
rather than to make such mitigation a permanent feature of the
BCA landscape.

To begin with, we reject the suggestion that the claim is
nonjusticiable because it is either moot or not ripe. A federal
court must satisfy itself that the party invoking federal
 37

jurisdiction has presented a justiciable case or controversy. See
U.S. CONST. art. III, § 2, cl. 1 The mootness doctrine ensures
that judicial relief can still redress the asserted injury. See
Spencer v. Kemna, 523 U.S. 1, 7 (1998). The ripeness doctrine
prevents the court from prematurely deciding a question. See
Ohio Forestry Ass’n v. Sierra Club, 523 U.S. 726, 733 (1998);
see also Nevada v. Dep’t of Energy, 457 F.3d 78, 83-85 (D.C.
Cir. 2006).

FERC authorized BCA mitigation for only one year. See
TEMT II Order, 108 F.E.R.C. ¶ 61,163, at 61,954-55 P 275. But
after initially declining to renew that authority, FERC renewed
it for a second year ending August 1, 2007. See Midwest Indep.
Transmission Sys. Operator, Inc., 116 F.E.R.C. ¶ 61,068, at
61,403 PP 22-24, reconsidering 115 F.E.R.C. ¶ 61,158, at
61,549-50 PP 22-25 (2006). Because mitigation authority exists
at this moment, the justiciability argument goes, the
Transmission Dependents are not being injured, and the case is
amenable to judicial resolution only when the mitigation
authority has actually expired.

That theory overlooks, however, the continuing economic
injury that the one-year sunset provision causes petitioners in
planning future transactions – in an industry where long-term
transactions are a matter of course. Cf. Protest of Midwest
[Transmission Dependent Utilities] 115 (“MISO retail utilities
typically obtain their power supply either from their owned
generation facilities or from generation purchased under long-
term contracts.”) (emphasis added). Although FERC may
repeatedly renew the mitigation authority after August 1, 2007,
such renewal is not guaranteed, and the lack of such a guarantee
has an effect now. Cf. S. Co. Servs., Inc. v. FERC, 416 F.3d 39,
42-43 (D.C. Cir. 2005) (challenge to FERC order regarding
petitioner’s one-year agreement with third party not moot where
agreement, as renewed or “rolled-over,” remained in effect).
 38

When the Transmission Dependents negotiate long-term
wholesale power contracts with generators, the sunset provision
requires petitioners to factor into the negotiations the fact that
they could be subject to unmitigated prices – reflecting potential
abuse of market power rather than legitimate supply costs –
when transmission constraints are active within the BCAs.

Petitioners’ inability to rely on mitigation after the
expiration of mitigation authority thereby reduces their
bargaining power in the here-and-now; that reduction of
bargaining power is an economic injury that vacatur of the one-
year limitation would certainly help redress. We are satisfied
that this aspect of the Transmission Dependents’ claim cannot
be considered moot or unripe. See Ohio Forestry Ass’n, 523
U.S. at 733; Calderon v. Moore, 518 U.S. 149, 150 (1996).
Petitioners’ challenge to the sunsetting provision therefore is
justiciable.

On the merits, the Transmission Dependents challenge
FERC’s decision to impose the one-year sunset because there
was no evidence in the administrative record that market power
abuse would be a problem within BCAs for only one year. On
the contrary, the Transmission Dependents emphasize, BCAs
are by definition those in which a transmission constraint raises
market power concerns at least some of the time (although less
often than in NCAs).

Petitioners’ argument has a surface appeal. It is logical to
believe that a time limit on the solution to a problem should be
adopted only if the problem itself is time-limited. But this does
not render FERC’s determination either irrational or
unsubstantiated. FERC adopted the sunset provision as a
response to concerns that the Tariff vested the independent
market monitor with excessive discretion in mitigating conduct
within BCAs – which, again, are not listed as such in advance,
 39

but rather designated dynamically by the monitor when
transmission constraints become active. “Should we find
problems” with the monitor’s discretion, FERC noted, “we will
take appropriate action including consideration of terminating
the BCA provision before the end of the one-year period.”
TEMT II Order, 108 F.E.R.C. ¶ 61,163, at 61,955 P 275.

Again, BCAs are competitive most of the time. And as this
Court recognized in evaluating FERC’s decisions concerning the
market power mitigation framework of a different RTO, “the
presence of workable competition would suggest that many,
perhaps most, possibly all, of the bids triggering mitigation will
be due not to market power but to temporary scarcity.” Edison
Mission Energy, 394 F.3d at 968. The power conferred on the
monitor to impose mitigation is a substantial one, and it
accordingly is reasonable for FERC to limit the discretion to use
that power.

Although the order approving the Tariff may have been less
than crystal clear on the point, it is evident that FERC
concluded that limiting the monitor’s discretion would help
attain the proper balance between under- and over-mitigation –
by making it less likely that the monitor would be too aggressive
in mitigating high bids attributable not to market power but to
legitimate supply costs. It is also evident from context that
FERC concluded that adopting a one-year time limitation on the
mitigation authority was one means to cabin the discretion. The
sunset provision made MISO responsible for seeking and
adequately justifying renewal of BCA mitigation authority if
necessary. FERC indicated as much on rehearing. “We are
concerned that the application of mitigation” in BCAs “could
result in excessive mitigation. This is especially true,” FERC
noted, to the extent that the independent market monitor “may
have some discretion in applying that mitigation.” Therefore,
FERC concluded that “the need for mitigation within BCAs
 40

should be re-evaluated after there is some operational market
experience,” while noting that MISO could “file to continue
such mitigation” in the future. TEMT II Reh’g Order, 109
F.E.R.C. ¶ 61,157, at 61,703 P 231 (emphasis added).

We find reasonable FERC’s concern about over-mitigation
and the contribution of unfettered discretion on the part of the
independent market monitor to that over-mitigation. Thus, we
conclude that placing a one-year limitation on the BCA
mitigation authority was a permissible response to the excessive
discretion problem FERC sought to solve – a choice that
satisfies the requirement of “reasoned decisionmaking” that the
arbitrary or capricious standard embodies. Allentown Mack
Sales & Serv., Inc. v. NLRB, 522 U.S. 359, 374 (1998) (internal
quotation marks omitted).

B

The amount of electricity a supplier injects into the grid
always exceeds the amount the customer receives; some
electricity dissipates as heat during transmission (and is referred
to as transmission loss). See Sithe/Independence Power
Partners, L.P. v. FERC, 285 F.3d 1, 2 (D.C. Cir. 2002). MISO’s
initial practice was to calculate the average transmission losses
for the entire system and then to charge each market participant
a pro rata share; at FERC’s prompting, MISO’s Tariff replaced
that allocation scheme with “marginal loss pricing” for
transmission losses, as reflected in the Locational Marginal
Pricing (LMP) concept. TEMT II Order, 108 F.E.R.C. ¶ 61,163,
at 61,925 P 66; see also supra Part I.C. For present purposes,
the most significant point is FERC’s recognition that marginal
loss charges would exceed the average loss charges that utilities
previously paid. To soften the blow from the new marginal loss
pricing policy, FERC accordingly directed MISO to give
refunds to market participants so that they would pay no more
 41

than their average losses for a five-year transition period. See
id. at 61,926 P 73 (refund directive aimed “to give market
participants more time to adjust to the LMP approach for setting
prices and to develop confidence in market processes”).

In particular, FERC ordered MISO to “refund the difference
between the marginal loss charge and either an average loss or
a historical loss charge to all existing transmission customers.”
Id. at 61,926 P 74. “Entities will be given this refund,” FERC
directed, “based either on historical loss charges associated with
existing transmission service, or otherwise on average loss
charges calculated by the Midwest ISO.” Id.

The Transmission Dependents interpret those sentences to
mean that FERC required MISO to issue refunds based on the
average losses incurred by each individual transmission
customer. Petitioners insist that directive cannot be reconciled
with FERC’s subsequent approval of MISO’s “Balancing
Authority” approach to the refunds – which groups transmission
customers by geographic territory and computes average losses
on a grouped rather than an individual basis. See, e.g., Midwest
Indep. Transmission Sys. Operator, Inc., 109 F.E.R.C. ¶ 61,285,
at 62,364 n.76, 62,365 PP 171-72 (2004) (“Compliance I”).
That inconsistency, petitioners contend, makes FERC’s
decisions arbitrary and capricious.

At the outset, FERC urges us not to reach the merits of this
contention, on the theory that FERC has not made a final
decision on the matter. In FERC’s view, a compliance order
issued after the last of the orders challenged in this case directed
MISO to continue entertaining petitioners’ suggested method for
computing average losses, therefore deferring for another day a
final FERC endorsement of MISO’s method for those
computations. See Midwest Indep. Transmission Sys. Operator,
Inc., 117 F.E.R.C. ¶ 61,142, at 61,765 P 28 (2006).
 42

But the very compliance order on which FERC relies
squarely refutes the jurisdictional argument. As that order
explains, in an earlier compliance order – one challenged in this
case – FERC concluded that MISO’s “method for allocating the
refund of marginal loss surplus revenue is just and reasonable.”
Id. at 61,765 P 25 & n.17 (citing Compliance I, 109 F.E.R.C.
¶ 61,285, at 62,365 P 171 (2004)). The Transmission
Dependents’ claim focuses on precisely that just and reasonable
conclusion in Compliance I. Although FERC has instructed
MISO to consider the Transmission Dependents’ proposals for
further refining MISO’s method for computing average losses,
FERC has never stated it is willing to revisit the conclusion that
the method is just and reasonable. See id. at 61,765 PP 25-31.
And FERC has clarified that “any revisions in the future will be
prospective in nature.” Midwest Indep. Transmission Sys.
Operator, Inc., 112 F.E.R.C. ¶ 61,086, at 61,595 n.16 (2005).
Therefore, that conclusion is reviewable “final” agency action
because, under Supreme Court precedent, it embodies “the
consummation of the agency’s decisionmaking process” on what
is just and reasonable, and it carries “legal consequences” for
petitioners who have been denied refunds calculated according
to the exact method they believe FERC initially promised them.
Bennett v. Spear, 520 U.S. 154, 177-78 (1997) (internal
quotation marks omitted). The mere fact that FERC has
continued to allow fine-tuning through additional compliance
filings does not affect the finality of Compliance I:
“Commission rate orders often appear to leave detail issues to
‘compliance’ filings, without anyone supposing that this
deprives them of finality.” Pub. Utils. Comm’n of Cal. v. FERC,
894 F.2d 1372, 1378 (D.C. Cir. 1990).

On the merits, we reject the Transmission Dependents’
arguments concerning MISO’s average loss computation
method. In approving that method, FERC reasonably
 43

interpreted its initial instructions that refunds be distributed
“based either on historical loss charges associated with existing
transmission service, or otherwise on average loss charges
calculated by the Midwest ISO.” TEMT II Order, 108 F.E.R.C.
¶ 61,163, at 61,926 P 74.

We review FERC’s interpretation of its own orders for
reasonableness. See Natural Gas Clearinghouse v. FERC, 108
F.3d 397, 399 (D.C. Cir. 1997). Petitioners point to no textual
commitment by FERC to require individual, rather than group,
calculation of the average losses; the initial order was simply
silent on that individual-versus-group question. There is nothing
unreasonable about FERC’s interpretation of that silence as
permission for MISO to take a group loss approach.

Even apart from the asserted conflict with the initial order,
petitioners also argue that approval of the “Balancing Authority”
approach was arbitrary. To that end, petitioners have identified
various ways in which they believe average loss computations
tailored to individual transmission customers would be more
equitable than those tailored by geographic sorting. Some of
these assertions may have merit, as FERC itself appears to have
recognized. In requiring MISO to make ongoing compliance
filings on the subject, FERC has noted, for example, that under
the group approach large entities within a group might receive
more of a refund than deserved, while small entities might
receive less than deserved. See Midwest Indep. Transmission
Sys. Operator, Inc., 111 F.E.R.C. ¶ 61,053, at 61,252 PP 49-50
(2005).

FERC’s acknowledgment that the computation method can
and should be refined does not, however, undercut FERC’s
conclusion that the overall method affords a just and reasonable
rate for the transmission customers. Merely because petitioners
can conceive of a refund allocation method that they believe
 44

would be superior to the one FERC approved does not mean that
FERC erred in concluding the latter was just and reasonable.
Again, reasonableness is a zone, not a pinpoint. See
ExxonMobil Gas Mktg., 297 F.3d at 1084 (“The burden is on the
petitioners to show that the Commission’s choices are
unreasonable and its chosen line of demarcation is not within a
zone of reasonableness as distinct from the question of whether
the line drawn by the Commission is precisely right.”) (internal
quotation marks omitted). Of course, the “question is not
whether record evidence supports petitioners’ version of events,
but whether it supports FERC’s.” Ariz. Corp. Comm’n v. FERC,
397 F.3d 952, 954 (D.C. Cir. 2005) (internal quotation marks
and alterations omitted). FERC explained its conclusion that the
allocation method it approved furthered the purpose of the
refunds, and that reasoned explanation warrants judicial
deference.

III

The Cooperatives’ petitions challenge FERC’s treatment of
Schedule 17 of the TEMT, which recovers the administrative
costs of MISO’s energy market services. Midwest Indep.
Transmission Sys. Operator, Inc., 111 F.E.R.C. ¶ 61,042, at
61,147 P 176 (2005) (“GFA Reh’g Order”). Applying the cost-
causation principle – “under which costs are to be allocated to
those who cause the costs to be incurred and reap the resulting
benefits,” NARUC v. FERC, 475 F.3d 1277, 1285 (D.C. Cir.
2007) – the Commission concluded that the services paid for by
Schedule 17 “will have both economic and reliability benefits”
for all parties using the MISO grid, “including parties
transacting under GFAs.” GFA Reh’g Order, 111 F.E.R.C.
¶ 61,042, at 61,148 P 181. FERC therefore concluded that
Schedule 17 charges should be assessed on the transmission
owners providing service under GFA agreements, including
carved-out GFA agreements. See id.
 45

The Cooperatives dispute FERC’s finding that the parties
to GFA transactions benefit from the TEMT markets. They
argue that the Commission’s ultimate conclusion was
unsupported by substantial evidence, that its acceptance of some
of the supporting material filed by MISO constituted an
unexplained reversal, and that its refusal to hold an evidentiary
hearing violated the Administrative Procedure Act and the Due
Process Clause.

Before reaching the merits of these arguments, we consider
Intervenor Duke’s assertion that the Cooperatives lack standing
to raise them. We must address this threshold question of the
jurisdiction of the court, notwithstanding that FERC does not
raise it. See Steel Co. v. Citizens for a Better Env’t, 523 U.S. 83,
101-02 (1998). For the reasons stated below, we conclude that
the Cooperatives have not been aggrieved by the orders under
review, and we therefore dismiss their petitions without reaching
the remaining issues.

“[A] party seeking judicial review of a FERC order must be
aggrieved by that order.” N.M. Att’y Gen. v. FERC, 466 F.3d
120, 121 (D.C. Cir. 2006); see 16 U.S.C. § 825l(b). “A party is
aggrieved within the meaning of [§ 825l(b)] if it can establish
both the constitutional and prudential requirements for
standing.” Pub. Util. Dist. No. 1 of Snohomish County v. FERC,
272 F.3d 607, 613 (D.C. Cir. 2001). The test for constitutional
standing has three elements. “First, the plaintiff must have
suffered an injury in fact – an invasion of a legally protected
interest which is (a) concrete and particularized, and (b) actual
or imminent, not conjectural or hypothetical. Second, there
must be a causal connection between the injury and the conduct
complained of – the injury has to be fairly traceable to the
challenged action of the defendant, and not the result of the
independent action of some third party not before the court.
Third, it must be likely, as opposed to merely speculative, that
 46

the injury will be redressed by a favorable decision.” Lujan v.
Defenders of Wildlife, 504 U.S. 555, 560-61 (1992) (citations,
internal quotation marks, footnote, and alterations omitted).

Intervenor Duke argues that the Cooperatives cannot satisfy
the injury-in-fact requirement because the orders under review
did not approve the imposition of any additional charges on
them. As explained above, the orders approve the imposition of
Schedule 17 charges on the GFA providers – the transmission
owners that provide service under GFA contracts. None of the
Cooperatives, however, is a GFA provider. Instead, they are
GFA customers – utilities that purchase power from the GFA
providers under those contracts. The orders before us therefore
do not inflict any injury on the Cooperatives. Any injury to
them would arise only out of a subsequent proceeding in which
the GFA providers submitted – and FERC approved – a
modified tariff providing for a “pass-through” of Schedule 17
charges to GFA customers.

The Cooperatives freely concede that the injury they seek
to avoid is the pass-through of Schedule 17 charges from GFA
providers to customers like themselves. See Cooperatives’
Reply Br. 17-19. They nonetheless argue that they have been
aggrieved by the orders under review because those orders
conclusively determined that the TEMT markets provide
benefits to both GFA providers and GFA customers. See id. at
17-18 (citing GFA Reh’g Order, 111 F.E.R.C. ¶ 61,042, at
61,147 P 175). The Cooperatives argue that, because of the
cost-causation principle, this finding predetermined the outcome
of any proceeding on a pass-through of Schedule 17 charges.
See id. They also claim that the orders under review signaled
FERC’s intention to approve a pass-through. See id. at 18-19.

As a threshold matter, the Cooperatives’ arguments rest on
an untenable reading of the Commission’s orders. Far from
 47

predetermining the outcome of a pass-through proceeding, the
orders under review explicitly rejected requests that FERC
approve a pass-through of Schedule 17 charges from providers
to customers. The Commission instead reserved the issue for
future proceedings, explaining that it lacked a “concrete
proposal” for a pass-through and that the issue therefore was
“not ripe for consideration.” Midwest Indep. Transmission Sys.
Operator, Inc., 108 F.E.R.C. ¶ 61,236, at at 62,322 P 302 (2004)
(“GFA Order”). On rehearing, FERC was even more explicit:
“[I]n the GFA Order, the Commission did not predetermine the
outcome of future proceedings involving proposals to pass
TEMT related costs through to customers under particular
GFAs.” GFA Reh’g Order, 111 F.E.R.C. ¶ 61,042, at 61,143
P 151.

But even if the Cooperatives were correct, and FERC’s
reasoning in the orders under review would govern subsequent
proceedings on a pass-through, we have repeatedly held that this
sort of “injury” is insufficient to establish standing. A
petitioner’s “interest in the Commission’s legal reasoning and its
potential precedential effect does not by itself confer standing
where, as here, it is ‘uncoupled’ from any injury in fact caused
by the substance of [FERC’s] adjudicatory action.” Telecomms.
Research & Action Ctr. v. FCC, 917 F.2d 585, 588 (D.C. Cir.
1990). Indeed, “mere precedential effect within an agency is
not, alone, enough to create Article III standing, no matter how
foreseeable the future litigation.” Sea-Land Serv., Inc. v. DOT,
137 F.3d 640, 648 (D.C. Cir. 1998); see also Ala. Mun. Distribs.
Group v. FERC, 312 F.3d 470, 473 (D.C. Cir. 2002); Shell Oil
Co. v. FERC, 47 F.3d 1186, 1201-02 (D.C. Cir. 1995); Crowley
Caribbean Transp., Inc. v. Peña, 37 F.3d 671, 674 (D.C. Cir.
1994).

As it turns out, MISO’s transmission owners did file a
“concrete proposal” for a pass-through of Schedule 17 charges
 48

to certain carved-out GFA customers, and FERC approved it in
orders that are not before us in these petitions. See Transmission
Owners of the Midwest Indep. Transmission Sys. Operator, Inc.,
110 F.E.R.C. ¶ 61,339, at 62,343 P 1 (2005), reh’g denied, 113
F.E.R.C. ¶ 61,122 (2005). Those orders allow a GFA provider
to pass-through Schedule 17 charges to a carved-out GFA
customer if it “affirmatively demonstrate[s]” that those charges
are not “otherwise being recovered from the GFA customer.”
Id. at 62,352 P 54. And this Court has denied a separate petition
seeking review of those orders. See E. Ky. Power Coop., Inc. v.
FERC, No. 06-1003, slip op. at 3 (D.C. Cir. June 15, 2007).

The fact that the Commission approved a pass-through of
Schedule 17 charges to GFA customers in orders not currently
before us does not alter our standing analysis. The Cooperatives
may be aggrieved by those orders, but a petitioner must show
that it has been aggrieved by the final order under review. See
16 U.S.C. § 825l(b) (“Any party to a proceeding under this
chapter aggrieved by an order issued by the Commission in such
proceeding may obtain a review of such order in the . . . [D.C.
Circuit].”). The fact that a petitioner may be aggrieved by other,
related orders does not cure a failure to show an injury in fact
caused by the order actually under review. See N.M. Att’y Gen.,
466 F.3d at 121-22 (holding that a petitioner lacked standing to
challenge an order that was conditional on a further compliance
filing, and that “[t]he fact that FERC accepted [the] compliance
filing after the Petitioners sought judicial review of the
[conditional] orders is insufficient, of itself, to cure the defect in
the Petitioners’ request for judicial intervention”); see also DTE
Energy Co. v. FERC, 394 F.3d 954, 960-61 (D.C. Cir. 2005)
(same). The place to challenge this pass-through was in the
petition to review the orders that permitted it.

Finally, the Cooperatives argue that, even if they are barred
from raising their substantive claims in this proceeding, they
 49

have standing to raise their procedural challenges here.
Cooperatives’ Reply Br. 21-22. It is true that we apply a
modified standing analysis to procedural claims: “[a] person
who has been accorded a procedural right to protect his concrete
interests can assert that right without meeting all the normal
standards for redressability and immediacy.” Defenders of
Wildlife, 504 U.S. at 572 n.7. That is, “‘[a petitioner] who
alleges a deprivation of a procedural protection to which he is
entitled never has to prove that if he had received the procedure
the substantive result would have been altered. All that is
necessary is to show that the procedural step was connected to
the substantive result.’” Massachusetts v. EPA, 127 S. Ct. 1438,
1453 (2007) (quoting Sugar Cane Growers Coop. of Fla. v.
Veneman, 289 F.3d 89, 94-95 (D.C. Cir. 2002)). But a petitioner
asserting a procedural right “must nonetheless show [that] it has
itself ‘suffered personal and particularized injury’” because of
the challenged substantive result. Int’l Bhd. of Teamsters v.
TSA, 429 F.3d 1130, 1135 (D.C. Cir. 2005) (quoting Fla.
Audubon Soc’y v. Bentsen, 94 F.3d 658, 664 (D.C. Cir. 1996)
(en banc)); see Defenders of Wildlife, 504 U.S. at 572 n.7; Ctr.
for Law & Educ. v. Dep’t of Educ., 396 F.3d 1152, 1157 (D.C.
Cir. 2005). And that is what is lacking here.

As explained above, the Cooperatives have not shown that
they have suffered a concrete and particularized injury caused
by the orders under review. Consequently, they cannot satisfy
either Article III’s standing requirements, or 16 U.S.C. § 825l’s
requirement that a party seeking review of a FERC order be
“aggrieved” by that order. We are therefore barred from
considering their claims, including their procedural arguments.
 50

IV

The Transmission Owners are two utilities (Duke Energy
Shared Services, Inc., and Xcel Energy Services Inc.) that
provide transmission service under the Midwest Independent
System Operator (MISO) Tariff. They maintain that FERC’s
solution to the problem of contracts pre-dating MISO’s
formation (the grandfathered agreements, or GFAs) has
impermissibly shifted to ordinary market participants –
including the Transmission Owners – the congestion costs that
GFA transactions cause. The Transmission Owners accordingly
seek to vacate FERC’s decision approving as just and reasonable
MISO’s solution to the GFA problem. See Midwest Indep.
Transmission Sys. Operator, Inc., 108 F.E.R.C. ¶ 61,236 (2004)
(“GFA Order”), order on reh’g, 111 F.E.R.C. ¶ 61,042 (2005)
(“GFA Reh’g Order”), order on reh’g, 112 F.E.R.C. ¶ 61,311
(2005).

The tension between GFA terms and practices on the one
hand and the MISO Tariff on the other hand was from the very
beginning a “fundamental problem in the proposed design and
operation” of MISO. Midwest Indep. Transmission Sys.
Operator, Inc., 97 F.E.R.C. ¶ 61,033, at 61,169 (2001)
(“Opinion No. 453”), order on reh’g, 98 F.E.R.C. ¶ 61,141
(2002). FERC’s solution to the problem hinged on sorting the
GFAs into different classes and reaching appropriate
accommodations for each.

Specifically, 229 GFAs remained in effect in March 2005.
GFA Order, 108 F.E.R.C. ¶ 61,236, at 62,275 P 4. FERC
approved the settlement of 22 GFAs that are not at issue here.
One settlement option – which petitioners do challenge in this
Court – was Option B, under which MISO reimbursed the GFA
parties for congestion costs linked to transactions scheduled
through the Day-Ahead market. See id. at 62,316 P 264, 62,318
 51

P 275. MISO shifts the costs of reimbursing the 30 GFAs that
settled under Option B to the ordinary market participants, who
bear them pro rata.

For the GFAs that did not settle, FERC’s response varied
according to the applicable standard for contract modification.
One set, consisting of 50 GFAs, was subject to the “just and
reasonable” standard of review. See id. at 62,295 P 130. FERC
ordered that set to conform to the MISO Tariff under Options A
or C, after finding that it was just and reasonable to do so. See
id. at 62,296 P 137 & n.104, 62,297 P 139. For a distinct set of
127 GFAs whose transactions represented about 10 percent of
MISO’s peak load, FERC took a different course. Those GFAs
allow modification or abrogation only when necessary in the
“public interest” under the Mobile-Sierra doctrine. See id. at
62,297 P 141 & n.108. FERC concluded that compelling those
GFAs to obey the MISO Tariff terms would not be necessary in
the public interest, and FERC therefore concluded that they had
to be carved out – essentially exempting the parties to that
narrow class of GFAs from Tariff requirements, including
congestion costs and scheduling rules, for a six-year transition
period. See id. at 62,297 P 143. (The 127 GFAs carved out
include some that did not specify a standard of review, and some
that were outside FERC’s jurisdiction; we will refer to all of
them as GFAs protected by the Mobile-Sierra doctrine and
subject to the public interest standard of review. See id. at
62,298 PP 147-50; see also supra Part I.D & n.5).

In this Court, the Transmission Owners first claim that
FERC erred in approving the carve out of the 127 GFAs subject
to the public interest standard. Second, they claim that FERC
erred in approving the Option B settlement terms for 30 GFAs.
Third, they assert that even if the carve out and Option B
settlements were adequately supported as individual decisions,
FERC erred in approving the carve out and Option B settlements
 52

together as just and reasonable. (Xcel presses a fourth claim
concerning FERC’s designation of entities responsible in the
first instance for paying GFA charges.) We hold that these
claims are unsound, and we therefore deny the Transmission
Owners’ petitions for review.

A

In the companion cases for which the Mobile-Sierra
doctrine is named, the Supreme Court interpreted the Federal
Power Act to substantially preserve the rights of federally
regulated utilities to make private contracts among themselves,
subject to only limited FERC intervention. See United Gas Pipe
Line Co. v. Mobile Gas Serv. Corp., 350 U.S. 332, 337-38, 347
(1956); FPC v. Sierra Pac. Power Co., 350 U.S. 348, 352-55
(1956). The parallel Federal Power Act and Natural Gas Act
struck a balance between “contract stability on the one hand and
public regulation on the other.” Mobile, 350 U.S. at 344. As the
Supreme Court has explained, Congress pre-supposed in
enacting those statutes that in the wholesale market “the party
charging the rate and the party charged were often sophisticated
businesses enjoying presumptively equal bargaining power, who
could be expected to negotiate a ‘just and reasonable’ rate as
between the two of them.” Verizon Communications Inc. v.
FCC, 535 U.S. 467, 479 (2002); see generally id. at 479-81
(describing historical difference between federal regulation of
wholesale transactions and state or local regulation of retail
transactions in energy and telephone markets). Facing such rate
contracts, “the principal regulatory responsibility was not to
relieve a contracting party of an unreasonable rate,” but instead
“to protect against potential discrimination by favorable contract
rates between allied businesses to the detriment of other
wholesale customers.” Id. at 479 (citing Sierra, 350 U.S. at
355).
 53

Thus, under the Mobile-Sierra doctrine, if and only if the
public interest requires, FERC may “abrogate or modify freely
negotiated private contracts that set firm rates or establish a
specific methodology for setting the rates for service, and deny
either party the right to unilaterally change those rates.” Atl.
City Elec. Co. v. FERC, 295 F.3d 1, 14 (D.C. Cir. 2002).
FERC’s abrogation or modification of an existing contract rate
may not hinge on the mere fact that one of the parties finds it
unprofitable. Rather, to meet the public interest standard –
gleaned from Section 201(a)’s recital that the Federal Power Act
“is necessary in the public interest,” 16 U.S.C. § 824(a) – FERC
must make a finding that the existing rate “might impair the
financial ability of the public utility to continue its service,” or
that the rate would “cast upon other consumers an excessive
burden, or be unduly discriminatory,” among other
“circumstances of unequivocal public necessity.” Sierra, 350
U.S. at 355; Permian Basin Area Rate Cases, 390 U.S. 747, 822
(1968); see also Ark. La. Gas Co. v. Hall, 453 U.S. 571, 582
(1981) (FERC “lacks affirmative authority, absent extraordinary
circumstances, to abrogate existing contractual arrangements.”)
(internal quotation marks omitted).

The public interest standard is “much more restrictive than
the just and reasonable standard” that FERC applies to rates not
contractually shielded. Atl. City Elec., 295 F.3d at 14. In any
event, as FERC’s Mobile-Sierra analysis hinges on
interpretation of utility contracts, our review of that analysis is
deferential. See, e.g., Vt. Dep’t of Pub. Serv. v. FERC, 817 F.2d
127, 134-35 (D.C. Cir. 1987).

1

The first step in the Mobile-Sierra analysis is to determine
whether the challenged regulatory action constitutes an
abrogation or modification of the contracts protected by the
 54

doctrine. The Transmission Owners insist that requiring the
GFA parties to obey MISO Tariff terms would not abrogate or
modify the GFAs. We reject that view. The central flaw in
petitioners’ argument is its radical oversimplification of the
GFA problem. Giving short shrift to the tensions between the
GFAs and the MISO Tariff, petitioners essentially claim that
instead of carving out GFA transactions (thereby shifting the
congestion costs they create onto all other market participants),
FERC should have required MISO to simply impose a
congestion charge on each GFA transaction – which, petitioners
contend, would have placed the GFA and non-GFA transactions
on equal footing. As FERC recognized in the orders at issue
here, however, subjecting GFA transactions to Tariff terms
would be far more disruptive for the GFA parties than that
account of the problem suggests.

A critical concern that petitioners’ account omits is the
direct collision between GFA scheduling practices and the
MISO Tariff’s scheduling requirements. “‘Carving out’ GFAs,”
FERC explained, “means that parties to GFAs are allowed to
exercise the scheduling and energy management provisions of
their GFAs in the same manner they did” before MISO’s new
markets started up. GFA Order, 108 F.E.R.C. ¶ 61,236, at
62,289 P 90 (2004) (emphasis added). Were their transactions
not exempted, the GFA parties would have been pressed to
conform to the MISO Tariff scheduling provisions of the Day-
Ahead market. Centralized transmission markets, such as those
the Tariff established, cannot function unless market participants
provide the central coordinator with advance information about
the timing and amount of electricity they intend to transmit. The
extent of advance notice required depends on the kind of market
(e.g., day-ahead versus real-time); and the centralized
coordinator must receive information on the transactions early
enough to be able to compile and process that information. Cf.
Midwest Indep. Transmission Sys. Operator, Inc., 107 F.E.R.C.
 55

¶ 61,191, at 61,784 n.53 (2004) (“Procedural Order”) (even in
hour-ahead markets bids cannot simply be submitted last minute
because “significant computing time is necessary to produce
final hour-ahead schedules”) (internal quotation marks omitted).

But centralized scheduling in the Day-Ahead market is
utterly foreign to the GFAs, some of which date back to the
1950s and 1960s and certainly are out of sync with FERC’s
post-1990 efforts to spur the development of competitive bulk
power markets. In particular, a number of the GFAs do not spell
out the quantity of electricity to be purchased or the precise time
when the buyer will take delivery; those details have often been
worked out in the course of dealing on a real-time (not a day-
ahead) basis between the GFA parties. “[S]pecific details of the
contracts, such as usage, scheduling requirements and megawatt
quantity or capacity, are not readily apparent on the face of some
of the contracts.” Id. at 61,776 P 16 (emphasis added). That is
why FERC could only discern “the number and location of
megawatts represented under GFAs, and how the GFAs are used
in practice” after conducting a factual investigation. Id. at
61,785-86 P 68 (emphasis added).

FERC’s investigation led it to conclude that “while the
[MISO Tariff] does not rewrite the GFAs, it would impose
significant changes in the manner in which transmission service
is provided for [in] transactions under the GFAs that could result
in cost shifts between the parties to the individual GFAs and
thus affect the bargain between the parties to the individual
GFAs.” GFA Reh’g Order, 111 F.E.R.C. ¶ 61,042, at 61,133
P 87 (2005). Because GFA commercial practices – including
the scheduling terms developed through the parties’ course of
dealing – are not all set forth in the text of the contracts
themselves, FERC accurately determined that subjecting the
GFA parties to MISO Tariff terms would not “rewrite” the plain
text of the GFAs. Nevertheless, the scheduling problem
 56

justified FERC’s conclusion that subjecting the GFA parties to
Tariff terms – in particular, coercing them through congestion
charges to conform to the scheduling requirements of the Day-
Ahead market – would result in “significant changes . . .
affect[ing] the bargain between the parties to the individual
GFAs.” Id.

Although FERC’s wording may have been less than precise
on this point, “the agency’s path may reasonably be discerned,”
as FERC’s “significant changes” conclusion was tantamount to
a finding that not carving out this narrow class of GFAs would
modify them, thereby triggering application of Mobile-Sierra’s
public interest standard. See Alaska Dep’t of Envtl.
Conservation v. EPA, 540 U.S. 461, 497 (2004) (“Even when an
agency explains its decision with less than ideal clarity, a
reviewing court will not upset the decision on that account if the
agency’s path may reasonably be discerned.”) (internal
quotation marks omitted); Nat’l Ass’n of Home Builders v.
Defenders of Wildlife, No. 06-340, slip op. at 11 (U.S. June 25,
2007). FERC’s conclusion on the point was reasonable. The
Commission determined that not carving out the GFAs at issue
would have changed the terms of the GFA parties’ bargain, in
part by pervasively disrupting the GFA parties’ scheduling
practices – which as we have explained is an aspect of the
problem petitioners completely omit from their account. Under
this reasonable view, rejecting the proposed carve out would
have not only affected the contracts but modified them –
requiring FERC to satisfy the public interest standard under the
Mobile-Sierra doctrine. Cf. Am. Gas Ass’n v. FERC, 428 F.3d
255, 263 (D.C. Cir. 2005) (if after FERC action terms of
“service for which the parties have bargained remain
unchanged,” then action “does not modify contracts, even if it
affects them,” and public interest standard does not apply).
 57

2

The second step in the Mobile-Sierra analysis is to
determine whether the challenged modification or abrogation of
the contracts protected by the doctrine is necessary in the public
interest. If not, then FERC had no choice but to carve out these
127 GFAs. FERC decided that it could not meet the public
interest standard: Because “the Energy Markets . . . can be
operated reliably, with net benefits to the public” even with the
Mobile-Sierra GFAs carved out, FERC determined that
“unequivocal public necessity” did not support subjecting the
relevant GFAs to the MISO Tariff. See GFA Order, 108
F.E.R.C. ¶ 61,236, at 62,297 P 142; Permian Basin Area Rate
Cases, 390 U.S. at 822. The Transmission Owners maintain
FERC’s reasoning was erroneous, but we disagree.

In Sierra, although the Supreme Court did not purport to
enumerate all the circumstances in which the public interest
standard may be satisfied, the Court did provide three concrete
examples of such circumstances: where the contract rate FERC
aims to modify “might impair the financial ability of the public
utility to continue its service, cast upon other consumers an
excessive burden, or be unduly discriminatory.” 350 U.S. at
355. To succeed in their challenge to FERC’s conclusion that
the public interest standard was not met, petitioners must show
FERC ignored relevant record evidence establishing one of these
circumstances, or another similarly extraordinary circumstance
of “unequivocal public necessity.” Permian Basin Area Rate
Cases, 390 U.S. at 822.

But petitioners have demonstrated nothing like that.
Although petitioners complain that the carve out will
impermissibly shift congestion costs to everyone else in the
market (except for those GFA parties that took the Option B
settlement), petitioners do not claim – let alone prove – that the
 58

cost shift was so severe as to threaten the “financial ability” of
any utility “to continue its service,” or that the cost shift
amounted to an “excessive” burden on any other market
participants.

Moreover, although petitioners’ argument about the cost
shift might be construed as presenting a claim that the cost shift
was “unduly discriminatory” within Sierra’s meaning, that claim
fails. Even when conduct amounts to undue discrimination in
violation of Section 205 of the Federal Power Act, see 16 U.S.C
§ 824d(b), such conduct is not automatically “unduly
discriminatory” within the meaning of the Mobile-Sierra
doctrine, thereby justifying a rate modification: “[I]t is possible
to have discrimination that violates § 205(b) but does not
dismantle the protection generally afforded to fixed-rate
contracts under Mobile-Sierra.” Town of Norwood v. FERC,
587 F.2d 1306, 1314 n.21 (D.C. Cir. 1978). In other words, a
claim of undue discrimination under Mobile-Sierra must
overcome a higher hurdle than a claim of discrimination under
Section 205. See 16 U.S.C. § 824d(b) (prohibiting utilities from
showing “undue preference” or “unreasonable difference”
among ratepayers). If the discrimination alleged does not
constitute an “undue preference” forbidden by Section 205, then
it also does not constitute undue discrimination permitting
contract modification or abrogation in the public interest. That
is the situation here: The alleged discrimination did not violate
Section 205, so it did not justify contract modification under
Mobile-Sierra.

To be sure, exempting the GFA parties from Tariff
requirements was in some loose sense discriminatory, in part
because it allows GFA parties to “schedule on short notice, with
greater flexibility than non-GFA transmission users.”
Procedural Order, 107 F.E.R.C. ¶ 61,191, at 61,784 P 61. And
it is true that exempting some GFA transactions from congestion
 59

costs means that remaining market participants subject to the
Tariff must bear the congestion costs pro rata. FERC reasonably
concluded, however, that such discrimination was inherent in the
solution to the GFA problem, and that the extent of the
discrimination was relatively small and not “undue.” Carving
out the GFAs protected by Mobile-Sierra, FERC explained, “is
possible only because of the small number of megawatts
involved; larger carve-outs, in contrast, would require us to
reevaluate this treatment.” GFA Order, 108 F.E.R.C. ¶ 61,236,
at 62,297 P 143; see id. at 62,290 P 99.

Forcing the public-interest GFA parties to conform to the
MISO Tariff would thus have had comparatively small
advantages, compared to the distinct disadvantages that would
result from not exempting them. On this point, again,
petitioners’ analysis gives virtually no weight to the settled
expectations of the parties to GFAs protected by Mobile-Sierra;
FERC, of course, could not afford to be so dismissive. Thus, the
discrimination alleged by petitioners was not undue
discrimination forbidden by Section 205 – and necessarily fell
short of establishing that the public interest required modifying
or abrogating the narrow class of GFAs at issue. See Town of
Norwood, 587 F.2d at 1314 n.21.

Finally, there was yet another reason FERC reasonably
determined that “unequivocal public necessity” did not mandate
overriding the narrow class of GFAs at issue. Permian Basin
Area Rate Cases, 390 U.S. at 822. Doing so would have
disrespected the agreement between all the utilities that formed
MISO to give the GFAs a transition period before subjecting
them to the Tariff. MISO’s January 1998 formation agreement
“proposed to not place existing bundled retail load and any
grandfathered wholesale load under the Midwest ISO’s Tariff
for at least a six year transition period.” Opinion No. 453, 97
F.E.R.C. ¶ 61,033, at 61,169 (emphasis added). In the course of
its decisions concerning MISO, FERC sought to preserve to the
 60

extent possible “the bargain that many of the transmission
owners relied upon in creating” MISO by affording a transition
period for the GFA parties before they become fully subject to
the Tariff. GFA Reh’g Order, 111 F.E.R.C. ¶ 61,042, at 61,132
P 81. Having long ago approved a filing supporting the
expectation that the GFAs would receive “special treatment” in
the establishment of MISO’s new markets, FERC would have
upset that settled expectation if it did not carve out those GFAs
protected by the Mobile-Sierra doctrine. Procedural Order, 107
F.E.R.C. ¶ 61,191, at 61,776 P 15; see GFA Order, 108 F.E.R.C.
¶ 61,236, at 62,294 P 125. We conclude that FERC permissibly
weighed the need to preserve the terms of the formation bargain
in deciding that “unequivocal public necessity” did not call for
abrogating or modifying the GFAs protected by the Mobile-
Sierra doctrine. Petitioners’ argument for a contrary result
would essentially have FERC give no weight in its public
interest analysis to the formation agreement’s promise of
“special treatment” for the GFA parties, which we cannot
accept. Procedural Order, 107 F.E.R.C. ¶ 61,191, at 61,776
P 15. The MISO formation agreement, after all, is itself a
private contract, and we have previously cautioned FERC
against “cavalierly disregarding private contracts.” Union Elec.
Co. v. FERC, 890 F.2d 1193, 1195 (D.C. Cir. 1989) (internal
quotation marks omitted).

To sum up: Petitioners have underestimated the disruption
to the narrow class of GFAs protected by the Mobile-Sierra
doctrine that would have resulted had FERC not approved the
carve out. We therefore reject petitioners’ contention that
FERC’s reasoning in this case threatened to expand that doctrine
beyond its proper bounds; rather, FERC’s analysis was fully
consistent with the doctrine. FERC reasonably concluded that
the public interest standard was not satisfied here, and FERC
therefore was not arbitrary or capricious when it determined that
the GFAs protected by the Mobile-Sierra doctrine should not be
 61

forced to comply with the MISO Tariff and instead should be
carved out.

B

FERC approved Option B only for those 30 GFA parties
that settled before July 28, 2004, the end of a period FERC
afforded for trial-type hearings to resolve factual disputes about
the terms of the GFAs. See GFA Order, 108 F.E.R.C. ¶ 61,236,
at 62,316-17 P 264; Procedural Order, 107 F.E.R.C. ¶ 61,191, at
61,787 P 76. As FERC recognized, Option B presented the
GFA parties with a meaningful advantage over the other options
by reimbursing the GFA parties for congestion costs and loss
charges as long as the parties provide MISO with a day-ahead
schedule of their transmission service demands. That
reimbursement gave GFA parties a distinct financial incentive
to switch from real-time scheduling to the new, Day-Ahead
market. FERC thus endorsed Option B as a “carrot” to give
GFA parties a reason to settle. See GFA Order, 108 F.E.R.C.
¶ 61,236, at 62,316 P 264 (“Option B was an incentive to settle
and receive a hedge against congestion and marginal losses
charges.”). The settlements, FERC explained, would help to
“avoid the expensive and time-consuming hearing process that
would otherwise be necessary and to provide all parties the
benefits of a functional organized market in a more timely
manner than would otherwise be possible.” Procedural Order,
107 F.E.R.C. ¶ 61,191, at 61,787 P 80. For GFAs that settled,
FERC did not have to determine the applicable standard of
review (that is, whether the Mobile-Sierra doctrine applied).

Petitioners contend that FERC erred in allowing the Option
B settlements. We disagree. Contrary to petitioners’ claim, this
is not a case in which FERC “failed to provide an adequate
explanation for its decision to approve the settlement” under
Option B’s terms. Laclede Gas Co. v. FERC, 997 F.2d 936, 945
 62

(D.C. Cir. 1993). By giving an incentive for the GFA parties to
voluntarily conform their transactions to MISO Tariff terms, the
Option B settlements reduced the scope of the “fundamental
problem” that the GFAs presented; increased GFA participation
in the markets also increased the markets’ reliability (by
increasing the accuracy of MISO’s estimates of how much
electricity would flow through the grids each day).

To be sure, petitioners and other ordinary market
participants bore the cost of that incentive. For example, GFA
parties that settled under Option B transmit electricity over
MISO grids, but those parties receive compensation for
congestion costs on transmissions scheduled through the Day-
Ahead market – forcing ordinary market participants to bear
those congestion costs pro rata. But all market participants also
reaped the benefit of having MISO’s new markets start up faster
than would have been possible had FERC been forced into
litigation with all of the settling GFA parties. Difficult issues
might have arisen in that litigation (such as whether the Mobile-
Sierra doctrine would have applied to each GFA, and if so,
whether the public interest standard could be satisfied), and
resolution of those issues would have delayed the
commencement of market operations.

This Court previously has stated that FERC “must indicate
why the interest in avoiding lengthy and difficult proceedings
warrants acceptance” of a challenged settlement. Laclede Gas,
997 F.2d at 947. We have never, however, required FERC to
quantify the length and difficulty of the proceedings to be
avoided through settlement, and we see no basis for doing so.
FERC’s qualitative description of the costs and benefits
supporting approval of the Option B settlements reasonably
explained why those settlements were warranted.
 63

C

Petitioners next claim that even if FERC’s reasoning
correctly supported its decision to carve out the GFAs protected
by the Mobile-Sierra doctrine, and even if FERC reasonably
offered the Option B settlement terms, FERC erred in approving
the carve out and the Option B settlements in combination as
just and reasonable. Although one might question whether the
whole can be less than the sum of its parts as this argument
seems to suggest, FERC explicitly tied its approval of the carve
out and its approval of the Option B settlements together:
“[W]hile we discussed the impact of the carve-out and Option
B treatments separately . . . our assessment of the overall
benefits of the Energy Markets considered both the carve-out
and Option B treatments together.” GFA Reh’g Order, 111
F.E.R.C. ¶ 61,042, at 61,134 P 96. Petitioners’ claim, then,
amounts to a challenge to the adequacy of FERC’s conclusion
that the combined benefits of the carve out and Option B
settlements outweighed their combined burdens.

That claim is unsound. FERC’s balancing of the interests
was reasonable given the relatively small magnitude of the
impact on the markets that the carve out and the Option B
settlements were expected to create. FERC acknowledged “that
a carve-out of GFAs has the potential to result in additional
costs for non-GFA transactions. However, we expect those
impacts to be minor, in light of the small percentage of capacity
to be carved-out.” GFA Order, 108 F.E.R.C. ¶ 61,236, at 62,290
P 99; see also id. at 62,297 P 143. The transmission volume
transacted by the GFA parties who were carved out is indeed
relatively small – representing about 10 percent of MISO’s peak
load. See id. at 62,275 P 4. The impact of the Option B settling
GFA parties, representing about an additional five percent of
peak load transmission volume, likewise was small. The
relatively low volume of electricity transmissions in question
 64

rationally supported FERC’s conclusion that the overall harms
associated with the carve out and Option B – namely cost-
shifting and reduced reliability – did not outweigh the benefits
to be gained from FERC’s solution to the GFA problem. In
upholding FERC’s approval of the carve out and Option B
individually, we have already explained why FERC reasonably
evaluated those benefits. The carve out respected, first and
foremost, the bargain between the parties to GFAs protected by
the Mobile-Sierra doctrine; it had the secondary benefit of
preserving the promise of special treatment for GFAs set forth
in the MISO formation agreement. For their part, the Option B
settlements expanded the number of GFAs who abide by MISO
Tariff terms while streamlining the administrative proceedings
leading up to approval of the MISO Tariff.

Moreover, FERC’s conclusion respected the principle of
cost causation, “requiring that all approved rates reflect to some
degree the costs actually caused by the customer who must pay
them.” Midwest ISO Transmission Owners v. FERC, 373 F.3d
1361, 1368 (D.C. Cir. 2004) (internal quotation marks and
alteration omitted). “[G]iven the standard of review under the
APA,” this Court mandates only “that the cost allocation
mechanism not be ‘arbitrary or capricious’ in light of the
burdens imposed or benefits received.” Id. at 1369. FERC met
that requirement for the reasons we have already surveyed:
Although the carve out and Option B settlements shifted
congestion costs caused by GFA transactions to other market
participants, the market participants benefited from earlier
commencement of market operations (which protracted
litigation would have delayed) and the greater reliability that
resulted from having as many GFA parties as feasible participate
in the new markets.

Nor was FERC’s decision to approve the carve out (again,
for a narrow class of GFAs) and the Option B settlements
 65

inconsistent with its conclusion that all GFA parties should pay
the Schedule 17 charges covering MISO’s market operation and
administrative costs. Schedule 17 charges pay for the market
functions as a whole, and not for the costs created by a specific
transaction. See, e.g., GFA Reh’g Order, 111 F.E.R.C. ¶ 61,042,
at 61,147 P 176. That sets Schedule 17 charges apart from the
congestion charges that the GFA parties would have been forced
to pay had they been either not carved out or not allowed to
select Option B, which relieved settlers of congestion cost
liability on transmissions scheduled through the Day-Ahead
market. See id. at 61,134 n.111.

In short, FERC’s approval of the carve out and Option B in
combination was not “arbitrary, capricious, an abuse of
discretion, or otherwise not in accordance with law.” 5 U.S.C.
§ 706(2)(A).

D

Finally, Xcel Energy Services challenges the designation of
several of its subsidiaries, rather than their customers, as GFA
Responsible Entities (that is, the GFA parties liable in the first
instance for MISO Tariff charges).

To review: FERC initially asked the GFA parties to agree
among themselves which of them should be the Responsible
Entity for each GFA. See GFA Order, 108 F.E.R.C. ¶ 61,236,
at 62,291 PP 103-04. Numerous GFA parties, including Xcel’s
subsidiaries, failed to amicably resolve the issue. For those
recalcitrant GFA parties, FERC sought to streamline matters by
adopting a default rule designating the GFA provider – namely,
the utility that takes transmission service from MISO grids and
supplies it to the GFA customer – as the Responsible Entity for
each GFA. See id. at 62,300-01 PP 160-62. Although the
provider takes the MISO Tariff-constrained service for the
 66

ultimate benefit of the customer, FERC concluded that the
provider should be responsible because it is the provider that
interacts with MISO’s grids, and it is the provider that is
certified as a market participant “financially responsible” to
MISO “for all of its Market Activities and obligations,” whereas
some GFA customers are not so certified. Id. at 62,299 P 152 &
n.122 (internal quotation marks omitted).

Xcel falls short of demonstrating that FERC’s
determination was arbitrary or capricious. A GFA transaction
may be described in two analytical steps. In the first of these
analytical steps, the GFA provider receives electricity
transmitted over the MISO grids. MISO is not involved in the
second analytical step – the transmission of electricity on a
“back-to-back basis” from the GFA provider to the GFA
customer. See Transmission Owners’ Br. 12 (“MISO provides
TEMT service to the transmission owner that is a party to the
GFA, and the transmission owner in turn, on a back-to-back
basis, provides the GFA service to its GFA counterparty.”); see
also id. at 4. Because the Responsible Entity must pay charges
to MISO, FERC reasonably concluded that the GFA provider –
which does interact directly with MISO – should be responsible
in the first instance. This is particularly so given FERC’s refusal
in the orders at issue here to in any way prevent GFA providers
from passing their Tariff-related liability through to GFA
customers where appropriate. FERC simply “did not
predetermine the outcome of future proceedings involving
proposals to pass [Tariff] related costs through to customers
under particular GFAs.” GFA Reh’g Order, 111 F.E.R.C.
¶ 61,042, at 61,143 P 151. Thus, Xcel’s argument that FERC’s
designation rule deviated from cost-causation principles fails
because that rule simply did not foreclose Xcel’s subsidiaries
and other Responsible Entities from shifting ultimate liability
for the MISO charges onto the GFA customers.
 67

Moreover, it made sound business sense to require that the
Responsible Entity be a utility that was already required by the
Tariff definition to be financially responsible to MISO. See
GFA Order, 108 F.E.R.C. ¶ 61,236, at 62,299 P 152 & n.122.
The Responsible Entity designation does no more than identify
who will pay MISO’s bill in the first instance; someone has to
be on the hook to pay that bill, because otherwise MISO could
not fund its operations. By linking the Responsible Entity
designation to the definition of a market participant under the
MISO Tariff, FERC simply presumed that market participant
status ensured responsibility sufficient for administering the
various charges associated with the Tariff – and that
presumption was entirely rational.

V

We dismiss the Cooperatives’ petitions for review for lack
of standing, and we deny the Transmission Dependents’ and
Transmission Owners’ petitions for review.

So ordered.