Document ID: s3://data.kl3m.ai/documents/govinfo/USCOURTS/USCOURTS-caDC-05-01007/USCOURTS-caDC-05-01007-0/pdf.json

Parties Involved:
Dairyland Power Cooperative
Petitioner
Federal Energy Regulatory Commission
Respondent

Document Text:

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.

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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.

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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.

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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:

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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

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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

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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

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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

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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 FERCapproved 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

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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).

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

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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-

(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 transmissionowning 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

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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.

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

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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 congestioncausing 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

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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

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“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 megawatthour 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

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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 longdistance 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.

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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”).

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

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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.

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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.

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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.”

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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.

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

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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.

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 carvedout 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 GFAREs 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 GFARE 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 carvedout 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.

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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.

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

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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

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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

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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.”).

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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 HerfindahlHirschmann 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 marketbased 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

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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 marketbased 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

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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

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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

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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

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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 –

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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

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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

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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

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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

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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 longterm 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).

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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 oneyear 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,

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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

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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

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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).

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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

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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

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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 costcausation 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.

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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

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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

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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

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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

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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.

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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

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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

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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). 

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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

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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 DayAhead 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.

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¶ 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 dayahead) 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

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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 DayAhead 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).

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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

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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

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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

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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 MobileSierra 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

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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

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(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 DayAhead 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 MobileSierra 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.

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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

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rationally supported FERC’s conclusion that the overall harms

associated with the carve out and Option B – namely costshifting 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

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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

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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.

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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.

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