FOR PUBLICATION

UNITED STATES COURT OF APPEALS

 FOR THE NINTH CIRCUIT

PUBLIC UTILITIES COMMISSION OF

THE STATE OF CALIFORNIA,

 Petitioner,

PUBLIC UTILITIES COMMISSION OF

NEVADA; ALLEGHENY ENERGY

SUPPLY COMPANY, LLC,

 Petitioner-Intervenor,

ENERGY PRODUCER

COGENERATION COGENERATION

ASSOCIATION OF CALIFORNIA AND

ENERGY PRODUCERS AND USERS

COALITION; AVISTA CORPORATION;

PINNACLE WEST CAPITAL

CORPORATION; CALIFORNIA

ELECTRICITY OVERSIGHT BOARD;

MIRANT CALIFORNIA; MIRANT

DELTA LLC; MIRANT POTRERO LLC;

MIRANT AMERICAS ENERGY

MARKETING, LP; ENRON POWER

MARKETING, INC.; SOUTHERN

CALIFORNIA EDISON COMPANY;

NORTHERN CALIF. TRANSMISSION

AGENCY OF NORTHERN

CALIFORNIA (“TANC”); MODESTO

IRRIGATION DISTRICT (MID); M-S-R

PUBLIC POWER AGENCY; CITY OF

REDDING; CITY OF PALO ALTO;

CITY OF SANTA CLARA; PORT OF

No. 01-71051

FERC No. FERC-EL00-000

AMENDED OPINION

FILED

AUG 31 2006

CATHY A. CATTERSON, CLERK

U.S. COURT OF APPEALS
2

SEATTLE WASHINGTON; CITY OF

TACOMA, WASHINGTON; PUBLIC

SERVICE COMPANY OF COLORADO;

PACIFIC GAS AND ELECTRIC

COMPANY; CORAL POWER, L.L.C.;

EXELON CORP.; CITY & COUNTY OF

SAN FRANCISCO; OFFICE OF

ATTORNEY GENERAL FOR THE

STATE OF NEVADA, BUREAU OF

CONSUMER PROTECTION;

PORTLAND GENERAL ELECTRIC

COMPANY; AUTOMATED POWER

EXCHANGE, INC.; ALLEGHEY

ENERGY SUPPLY CO., LLC; PUGET

SOUND ENERGY, Puget Sound Energy,

Inc.; DYNEGY POWER MARKETING,

INC.; EL SEGUNDO POWER LLC;

LONG BEACH GENERATION LLC;

CABRILLO POWER I LLC; CABRILLO

POWER II LLC; PACIFICORP’S; PPL

ENERGYPLUS, LLC; PPL MONTANA;

PPL SOUTHWEST GENERATION

HOLDINGS, LLC; RELIANT ENERGY

POWER GENERATION, INC.;

RELIANT ENERGY SERVICES, INC.;

OERTHERN; PEOPLE OF THE STATE

OF CALIFORNIA, ex rel. Bill Lockyer;

WILLIAM ENERGY MARKETING &

TRADING COMPANY; CALPINE

CORPORATION; EL PASO

MERCHANT ENERGY L.P.; SEMPRA

ENERGY TRADING CORP.; AVISTA

ENERGY, INC.; CITY OF LOS

ANGELES; CITY OF LOS ANGELES

DEPARTMENT OF WATER AND

POWER; CALIFORNIA ELECTRICITY

OVERSIGHT BOARD; IDACORP
3

ENERGY L.P.; CITY OF PASADENA,

 Intervenors,

 And

INTERNATIONAL PACIFIC

ENTERPRISES, LTD.,

 Intervenor,

 v.

FEDERAL ENERGY REGULATORY

COMMISSION,

 Respondent.

PUBLIC UTILITIES COMMISSION OF

THE STATE OF CALIFORNIA,

 Petitioner,

IDA CORP. ENERGY,, IDA Corp.

Energy, L.P.,

 Petitioner-Intervenor,

SAN DIEGO GAS AND ELECTRIC

COMPANY; DUKE ENERGY NORTH

AMERICA, LLC, DUKE ENERGY

TRADING AND MARKETING, LLC,

(COLLECTIVELY, “DUKE ENERGY”);

CALIFORNIA ASSEMBLY;

SOUTHERN CALIFORNIA EDISON

No. 01-71321

FERC No. EL 00-95-000
4

COMPANY; MIRANT AMERICAS

ENERGY MARKETING, LP, MIRANT

CA, LLC, MIRANT DELTA, LLC, AND

MIRANT POTEREO, LLC

(COLLECTIVELY, “MIRANT”;

MIRANT CALIFORNIA, Mirant

California, LLC; MIRANT DELTA, LLC

IRAN; MIRANT POTRERO, LLC;

PUGET SOUND ENERGY, Puget Sound

Energy, Inc.; CALIFORNIA

INDEPENDENT SYSTEM OPERATOR

CORPORATION; CALPINE

CORPORATION; ENRON POWER

MARKETING, INC.; CORAL POWER,

L.L.C.; TRANSMISSION AGENCY OF

NORTHERN CALIFORNIA; THE M-S-R

PUBLIC POWER AGENCY; THE

MODESTO IRRIGATION DISTRICT;

CITY OF PALO ALTO; THE CITY OF

SANTA CLARA; CITY OF REDDING;

EL PASO MERCHANT ENREGY, L.P.;

NORTHERN CALIFORNIA POWER

AGENCY; CHILD PROTECTIVE

SERVICES; CONSTELLATION

ENERGY COMMODITIES GROUP,

INC.; WILLIAMS ENERGY

MARKETING & TRADING COMPANY;

CITY AND COUNTY OF SAN

FRANCISCO; PUBLIC SERVICE

COMPANY OF NEW MEXICO;

CALIFORNIA ELECTRICITY

OVERSIGHT BOARD; PEOPLE OF THE

STATE OF CALIFORNIA; PEOPLE OF

THE STATE OF CALIFORNIA;

PACIFIC GAS AND ELECTRIC

COMPANY; PPL ENERGY PLUS; PPL

MONTANA; PPL SOUTHWEST
5

GENERATION HOLDINGS, LLC;

SEMPRA ENERGY TRADING CORP.;

AVISTA ENERGY, INC.; CITY OF LOS

ANGELES; CITY OF LOS ANGELES

DEPARTMENT OF WATER AND

POWER; MARCIA HABER KAMINE;

CITY OF LOS ANGELES

DEPARTMENT OF WATER AND

POWER; CITY OF TACOMA; PORT OF

SEATTLE; PINNACLE WEST COS.;

PUBLIC SERVICE COMPANY OF

COLORADO; PORTLAND GENERAL

ELECTRIC COMPANY; DYNEGY

POWER MARKETING, INC., EL

SEGUNDO POWER LLC, LONG

BEACH GENERATION LLC,

CABRILLO POWER I LLC, AND

CABRILLO POWER II LLC

(COLLECTIVELY, “DYNEGY”); CITY

OF SAN DIEGO; CITY OF SAN DIEGO;

PORTLAND GENERAL ELECTRIC

COMPANY; CALIFORNIA

ELECTRICITY OVERSIGHT BOARD;

CALIFORNIA ELECTRICITY

OVERSIGHT BOARD; PUBLIC

UTILITIES COMMISSION OF

NEVADA,

 Intervenors,

 v.

FEDERAL ENERGY REGULATORY

COMMISSION,

 Respondent.
6

CITY OF SAN DIEGO,

 Petitioner,

CALIFORNIA PUBLIC UTILITIES

COMMISSION; CITY OF TACOMA;

PORT OF SEATTLE; SOUTHERN

CALIFORNIA EDISON COMPANY;

CALIFORNIA ELECTRICITY

OVERSIGHT BOARD; PEOPLE OF

STATE OF CALIFORNIA,

 Petitioner-Intervenor,

PINNACLE WEST CAPITAL

CORPORATION; ARIZONA PUBLIC

SERVICE COMPANY; MORGAN

STANLEY CAPITAL GROUP, INC.;

MERRILL LYNCH CAPITAL

SERVICES, INC.; PUBLIC SERVICE

COMPANY OF COLORADO; LONG

BEACH GENERATION LLC.;

CABRILLO POWER I LLC; CABRILLO

POWER II LLC.; CITY OF LOS

ANGELES DEPARTMENT OF WATER

AND POWER; TRANSPORTATION

AGENCY OF NORTHERN

CALIFORNIA; THE METROPOLITAN

WATER DISTRICT OF SOURTHERN

CALIFORNIA; THE M-S-R PUBLIC

POWER AGENCY; THE MODESTO

IRRIGATION DISTRICT; CITY OF

PALO ALTO; CITY OF REDDING;

CITY OF SANTA CLARA; CITY AND

COUNTY OF SAN FRANCISCO; PPL

MONTANA, LLC; PPL SOUTHWEST

GENERATION HOLDINGS, LLC; EL

No. 01-71544

FERC No. 
7

PASO MERCHANT ENERGY L.P.;

SEMPRA ENERGY TRADING CORP.;

AVISTA CORPORATION; AVISTA

ENERGY, INC.; PPL ENERGYPLUS,

LLC; PORTLAND GENERAL

ELECTRIC COMPANY; EL SEGUNDO

POWER LLC; LONG BEACH

GENERATION LLC; CABRILLO

POWER I LLC; CABRILLO POWER II

LLC; TRANSMISSION AGENCY OF

NORTHERN CALIFORNIA; PUBLIC

SERVICE COMPANY OF NEW

MEXICO; ENERGY PLUS, LLC, ET AL;

CALIFORNIA ELECTRICITY

OVERSIGHT BOARD; PUBLIC

UTILITIES COMMISSION OF

NEVADA,

 Intervenors,

 v.

FEDERAL ENERGY REGULATORY

COMMISSION,

 Respondent,

NORTHERN CALIFORNIA POWER

AGENCY; PACIFIC GAS AND

ELECTRIC COMPANY; IDACORP

ENERGY L.P.; PACIFICORP; MIRANT

AMERICAS ENERGY MARKETING,

LP, MIRANT CALIFORNIA, LLC,

MIRANT DELTA, LLC, AND MIRANT

POTRERO, LLC.; PUGET SOUND

ENERGY; DYNEGY POWER

MARKETING, INC., EL SEGUNDO
8

POWER LLC, LONG BEACH

GENERATION LLC, CABRILLO

POWER I LLC, AND CABRILLO

POWER II LLC (COLLECTIVELY,

“DYNEGY”); CORAL POWER, L.L.C.;

CONSTELLATION ENERGY

COMMODITIES GROUP, INC.; THE

SALT RIVER PROJECT

AGRICULTURAL IMPROVEMENT

AND POWER DISTRICT; ENRON

POWER MARKETING INC.,

 Respondent-Intervenor.

POWEREX CORPORATION,

 Petitioner,

M-S-R PUBLIC POWER AGENCY;

MODESTO IRRIGATION DISTRICT

(MID); CITY OF PALO ALTO; CITY OF

REDDING; CITY OF SANTA CLARA;

METROPOLITAN WATER DISTRICT

OF SOUTHERN CALIFORNIA,

 Petitioner-Intervenor,

AVISTA CORPORATION; CORAL

POWER, L.L.C.; CONSTELLATION

ENERGY COMMODITIES GROUP,

INC.,

 Intervenors,

 v.

No. 02-70254

FERC Nos. EL-0095-0004

EL00-95-001
9

FEDERAL ENERGY REGULATORY

COMMISSION,

 Respondent,

PACIFICORP,

 Respondent-Intervenor.

PACIFIC GAS AND ELECTRIC

COMPANY,

 Petitioner,

SOUTHERN CALIFORNIA EDISON

COMPANY; PORT OF SEATTLE

WASHINGTON; CITY OF TACOMA,

WASHINGTON; NEVADA POWER

COMPANY; SIERRA PACIFIC POWER

COMPANY; CITY OF SEATTLE;

AVISTA CORPORATION; CORAL

POWER, L.L.C.; CONSTELLATION

ENERGY COMMODITIES GROUP,

INC.; PUBLIC UTILITIES

COMMISSION OF NEVADA;

TRANSALTA ENERGY MARKETING

(CALIFORNIA), INC.,

 Intervenors,

 v.

FEDERAL ENERGY REGULATORY

COMMISSION,

No. 02-70266

FERC Nos. EL00-95-000

EL00-95-000

ER01-607-000

EL00-95-017

EL00-95-012

EL00-95-031

EL00-95-004

EL00-95-001
10

 Respondent,

METROPOLITAN WATER DISTRICT

OF SOUTHERN CALIFORNIA;

NORTHERN CALIF. TRANSMISSION

AGENCY OF NORTHERN

CALIFORNIA (“TANC”); M-S-R

PUBLIC POWER AGENCY; MODESTO

IRRIGATION DISTRICT (MID); CITY

OF PALO ALTO; CITY OF REDDING,

CALIFORNIA; CITY OF SANTA

CLARA; PACIFICORP,

 Respondent-Intervenor.

CALIFORNIA ELECTRICITY

OVERSIGHT BOARD,

 Petitioner,

PORT OF SEATTLE; CITY OF

TACOMA; PEOPLE OF THE STATE OF

CALIFORNIA; CITY OF PASADENA;

CITY OF SAN DIEGO; CA STATE

ASSEMBLY,

 Petitioners - Intervenors,

 v.

FEDERAL ENERGY REGULATORY

COMMISSION,

 Respondent.

No. 02-70275

FERC No. FERC-EL95-000
11

CITY OF SAN DIEGO,

 Petitioner,

CORAL POWER, L.L.C.;

CONSTELLATION ENERGY

COMMODITIES GROUP, INC.,

 Intervenors,

 And

SOUTHERN CALIFORNIA EDISON

COMPANY; PORT OF SEATTLE; CITY

OF TACOMA,

 v.

FEDERAL ENERGY REGULATORY

COMMISSION,

 Respondent,

PACIFICORP,

 Respondent-Intervenor.

No. 02-70282

FERC No. FERC-00-95-000

CITY OF OAKLAND, CALIFORNIA

ACTING BY AND THROUGH ITS

BOARD OF PORT COMMISSIONERS,

 Petitioner,

CORAL POWER, L.L.C.;

CONSTELLATION ENERGY

No. 02-70285

FERC No. FERC-00-95-000
12

COMMODITIES GROUP, INC.,

 Intervenors,

 v.

FEDERAL ENERGY REGULATORY

COMMISSION,

 Respondent,

PACIFICORP,

 Respondent-Intervenor.

SAN DIEGO GAS & ELECTRIC

COMPANY,

 Petitioner,

CALIFORNIA ATTORNEY GENERAL,

 Intervenor,

CORAL POWER, L.L.C.;

CONSTELLATION ENERGY

COMMODITIES GROUP, INC.,

 Intervenors,

 v.

FEDERAL ENERGY REGULATORY

COMMISSION,

No. 02-70301

FERC No. 02-1058
13

 Respondent.

SOUTHERN CALIFORNIA EDISON

COMPANY,

 Petitioner,

PORTLAND GENERAL ELECTRIC

COMPANY; DYNEGY POWER

MARKETING INC,.; EL SEGUNDO

POWER; LONG BEACH GENERATION

LLC; CABRILLO POWER; CABRILLO

POWER II LLC; MORGAN STANLEY

CAPITAL GROUP, INC.; AVISTA

ENERGY; PUGET SOUND

INVESTMENT GROUP; THE CITY OF

LOS ANGELES DEPARTMENT OF

WATER AND POWER; SEMPRA

ENERGY; CALIFORNIA POWER

AGENCY; MODESTO IRRIGATION

DISTRICT (MID); METROPOLITAN

WATER DISTRICT OF SOUTHERN

CALIFORNIA; EL PASO MERCHANT

ENERGY L.P.; POWEREX

CORPORATION; CORAL POWER,

L.L.C.; MIRANT AMERICAS ENERGY

MARKETING, LP; MIRANT

CALIFORNIA, LLC; MIRANT DELTA,

LLC IRAN; MIRANT POTRERO, LLC;

TRANSCANADA ENERGY LTD.; CITY

OF TACOMA, Washington; PORT OF

SEATTLE, Washington,

 Intervenors,

No. 02-72113

FERC No. EL-95-000
14

 v.

FEDERAL ENERGY REGULATORY

COMMISSION,

 Respondent.

PACIFIC GAS AND ELECTRIC

COMPANY,

 Petitioner,

DYNEGY POWER MARKETING INC,.;

EL SEGUNDO POWER; LONG BEACH

GENERATION LLC; ENRON POWER

MARKETING, INC.; PUBLIC UTILITY

DISTRICT NO. 1 OF SNOHOMISH

COUNTY, WASHINGTON; ENRON

ENERGY SERVICES, INC.;

CALIFORNIA ELECTRICITY

OVERSIGHT BOARD; PEOPLE OF

CALIFORNIA; CALIFORNIA PUBLIC

UTILITIES COMMISSION;

CALIFORNIA INDEPENDENT

SYSTEM OPERATOR CORPORATION;

M-S-R PUBLIC POWER AGENCY;

MODESTO IRRIGATION DISTRICT

(MID); CITY OF SANTA CLARA; CITY

OF REDDING; CORAL POWER;

CONSTELLATION ENERGY

COMMODITIES GROUP, INC.;

POWEREX CORP; THE SALT RIVER

PROJECT AGRICULTURAL

IMPROVEMENT AND POWER

DISTRICT; SACRAMENTO

No. 03-73887

FERC No. Federal Power Act
15

MUNICIPAL UTILITY DISTRICT;

SOUTHERN CALIFORNIA EDISON

COMPANY; TUCSON ELECTRIC

POWER COMPANY; PORTLAND

GENERAL ELECTRIC COMPANY;

PINNACLE WEST CAPITAL

CORPORATION; ARIZONA PUBLIC

SERVICE COMPANY; PACIFICORP;

PUBLIC SERVICE COMPANY OF NEW

MEXICO; NORTHERN CALIFORNIA

POWER AGENCY; TRACTEBEL

ENERGY MARKETING INC.; BP

ENERGY COMPANY; AVISTA

ENERGY; PUGET SOUND ENERGY;

CITY OF LOS ANGELES

DEPARTMENT OF WATER AND

POWER; AVISTA CORPORATION;

SEMPRA ENERGY; EL PASO

MERCHANT ENERGY L.P.; IDACORP

ENERGY; BP ENERGY CO.;

WILLIAMS POWER COMPANY, INC;

PORT OF SEATTLE; TRANSCANADA

ENERGY LTD.; EXELON CORP,

 Intervenors,

 v.

FEDERAL ENERGY REGULATORY

COMMISSION,

 Respondent.

SACRAMENTO MUNICIPAL UTILITY

DISTRICT,

No. 03-74252
16

 Petitioner,

 v.

FEDERAL ENERGY REGULATORY

COMMISSION,

 Respondent.

FERC No. Federal Power Act

STATE WATER CONTRACTORS; THE

METROPOLITAN WATER DISTRICT

OF SOUTHERN CALIFORNIA,

 Petitioners,

TRANSCANADA ENERGY;

CALIFORNIA INDEPENDENT

SYSTEM OPERATOR CORPORATION;

POWEREX CORP.; PACIFICORP;

TUCSON ELECTRIC POWER

COMPANY; PINNACLE WEST

CAPITAL CORPORATION; PACIFIC

GAS AND ELECTRIC COMPANY;

CALIFORNIA POWER AGENCY;

PEOPLE OF THE STATE OF

CALIFORNIA; CALIFORNIA PUBLIC

UTILITIES COMMISSION; POWEREX

CORP.; SOUTHERN CALIFORNIA

EDISON COMPANY; CALIFORNIA

ELECTRICITY OVERSIGHT BOARD;

WILLIAMS POWER COMPANY, INC.;

M-S-R PUBLIC POWER AGENCY;

MODESTO IRRIGATION DISTRICT

(MID); CITY OF SANTA CLARA; CITY

OF REDDING; CONSTELLATION

No. 03-74527

FERC No. EL00-95-081
17

ENERGY COMMODITIES GROUP,

INC.; CITY OF VERNON,

 Intervenors,

 v.

FEDERAL ENERGY REGULATORY

COMMISSION,

 Respondent.

MODESTO IRRIGATION DISTRICT

(MID),

 Petitioner,

 v.

FEDERAL ENERGY REGULATORY

COMMISSION,

 Respondent.

No. 03-74531

FERC No. EL00-95-081

PEOPLE OF THE STATE OF

CALIFORNIA EX REL. BILL

LOCKYER,

 Petitioner,

CALIFORNIA INDEPENDENT

SYSTEM OPERATOR CORPORATION,

 Intervenor,

No. 03-74594

FERC No. 
18

 v.

FEDERAL ENERGY REGULATORY

COMMISSION,

 Respondent.

CITY OF LOS ANGELES

DEPARTMENT OF WATER AND

POWER,

 Petitioner,

 v.

FEDERAL ENERGY REGULATORY

COMMISSION,

 Respondent.

No. 04-73501

FERC No. Federal Power Act

On Petition for Review of an Order of the

Federal Energy Regulatory Commission

Argued and Submitted April 13, 2005

San Diego, CA

Filed

Before: THOMAS, McKEOWN, and CLIFTON, Circuit Judges.

Opinion by Judge Sidney R. Thomas 
1

 We express our appreciation to Lisa Evans of the Ninth Circuit Court of

Appeals Mediation Unit; Cole Benson, Supervisor of the Ninth Circuit Procedural

Motions Unit; Cecilia Dennis, formerly with the Ninth Circuit Staff Attorney’s

Office; and our colleague Judge Edward Leavy for their extensive work with the

parties in organizing judicial management of the cases. We also express our

appreciation to the parties and their attorneys for their cooperation,

professionalism, and the quality of their presentations.

19

THOMAS, Circuit Judge:

This case comes to us on petitions for review of a series of orders issued by

the Federal Energy Regulatory Commission (“FERC”) relating to the energy crisis

that occurred in California in 2000 and 2001. Nearly 200 petitions for review of

the various FERC orders have been filed in our Court. We consolidated these

petitions for administrative management.1

On November 24, 2004, we issued a consolidated order in this case

separating certain issues for decision in two consolidated proceedings, the first of

which we termed the “Jurisdictional Cases”; the second we termed the

“Scope/Transactions Cases.” In the Jurisdictional Cases, we considered whether

FERC’s refund authority extended to certain governmental entities. We heard oral

arguments on Jurisdictional Cases on April 12, 2005, and issued an opinion

concerning the Jurisdictional Cases on September 6, 2005. Bonneville Power

Admin. v. FERC, 422 F.3d 908 (9th Cir. 2005). 
20

The Scope/Transaction Cases before us here involve numerous questions

pertaining to the proper scope of FERC’s refund orders, including the appropriate

temporal reach and the type of transactions properly subject to the refund orders. 

We heard oral arguments on the Scope/Transaction Cases on April 13, 2005. This

opinion covers the issues presented in the Scope/Transaction Cases. 

We grant in relief in part and deny relief in part. In general, we hold that all

the transactions at issue in this case that occurred within the California Power

Exchange Corporation (“CalPX”) or California Independent System Operator

(“Cal-ISO”) markets, or as a result of a CalPX or Cal-ISO transaction, were the

proper subject of the refund proceedings instituted by FERC. Therefore, we deny

the petitions for review that challenge FERC’s inclusion of such transactions; we

grant the petitions for review that challenge FERC’s exclusion of such transactions.

We deny the petitions for review that seek to expand FERC’s refund

proceedings into the bilateral markets beyond the CalPX and Cal-ISO markets. In

particular, we hold that FERC properly excluded from the refund proceedings

bilateral transactions between the California Energy Resources Scheduling

(“CERS”) Division of the California Department of Water Resources and other

entities that occurred outside the CalPX and Cal-ISO markets. 
2

 The California Parties consist of the People of the State of California, ex

rel Bill Lockyer, Attorney General; the Public Utilities Commission of the State of

California; the California Electricity Oversight Board; Pacific Gas and Electric

Company, and Southern California Edison Company.

21

We hold that FERC properly established October 2, 2000 as the refund

effective date for the § 206 proceedings, rather than October 29, 2000, as argued by

some parties. However, we hold that FERC erred in excluding § 309 relief for

tariff violations that occurred prior to October 2, 2000. We reserve consideration

of all other issues raised in the various petitions for review for the next phase of

our appellate proceedings.

The net effect of our decision is to preserve the scope of the existing FERC

refund proceedings, but to expand those refund proceedings to include: (1) tariff

violations that occurred prior to October 2, 2000, (2) transactions in the CalPX and

Cal-ISO markets that occurred outside the 24-hour period specified by FERC, and

(3) energy exchange transactions in the CalPX and Cal-ISO markets. 

I

Parties and Claims

With that brief summary of the issues, we turn to the specific claims of the

parties. The State of California and several intervenors (collectively, “the

California Parties”)2 seek review of a number of FERC’s decisions, namely: (1)

FERC’s denial of relief for sales of electricity made at unjust rates prior to October
3

 This group consists of Powerex Corp.; Avista Energy, Inc.; Constellation

Energy Commodities Group, Inc.; Coral Power, L.L.C.; Exelon Corporation on

behalf of Exelon Generation Company, LLC; PECO Energy Company;

Commonwealth Edison Company; IDACORP Energy LP; Portland General

Electric Company; PPL EnergyPlus, LLC; PPL Montana, LLC; Public Service

Company of New Mexico; Puget Sound Energy, Inc.; Sempra Energy Trading

Corp.; TransAlta Energy Marketing (CA), Inc.; TransAlta Energy Marketing (US),

Inc.; and Tucson Electric Power Company. 

22

2, 2000, the refund effective date set by FERC; (2) FERC’s denial of relief for

energy sales in which CERS was the purchaser; (3) FERC’s refusal to order relief

for energy exchange transactions; and (4) FERC’s refusal to order relief for certain

forward market transactions. 

A group of energy suppliers and generators called the Competitive Suppliers

Group3 also petitions for review of several of FERC’s decisions, namely: (1)

FERC’s decision to set the refund effective date at October 2, 2000, rather than

October 29, 2000; (2) FERC’s order of refunds for transactions that took place

during non-emergency hours, and (3) FERC’s inclusion of certain out-of-market

transactions in its refund proceedings. 

The Port of Oakland, along with other petitioners and intervenors, petitions

for review of FERC’s decision to exclude certain bilateral transactions from its

refund order.
4

 This group consists of municipal entities, including the Modesto Irrigation

District, the City of Los Angeles Department of Water and Power, the Sacramento

Municipal Utility District, the City of Redding, and the State Water

Contractors/The Metropolitan Water District of Southern California (which

represents 27 of the 29 California public entities that provide substantial funding

for the California Department of Water Resources’ operation of the State Water

Project). 

23

Also before us in this case are the Public Entities’4 and the Bonneville Power

Administration’s petitions for review of FERC’s determination that it had authority

to order relief for certain transactions known as “sleeve” and “multi-day”

transactions, as well as transactions occurring under § 202(c) of the Federal Power

Act. The California Parties have moved to strike, and El Paso Merchant Energy

Company has moved to defer, consideration of the arguments until the next phase

of our consideration of the FERC orders. 

II

Factual Background

During the mid-1990's, FERC began examining whether the wholesale

electric power industry should have been restructured and deregulated to separate

generation, transmission, and distribution functions. Generation involves the

production of power through a variety of means. Transmission generally refers to

the conveyance of high voltage electric power from the points of generation to

substations for conversion to delivery voltages. Distribution refers to the delivery
24

of the converted low voltage energy from substations to individual consumers. The

theory behind separating these functions, known as “unbundling,” was that

wholesale power competition would be promoted, and consumers would benefit, if

public utilities were required to provide nondiscriminatory, open access,

transmission. See Promoting Wholesale Competition Through Open Access

Non-Discriminatory Transmission Services by Public Utilities, 60 Fed. Reg. 17,662

(proposed April 7, 1995) (codified at 18 C.F.R.§ 35.0 et. seq.). This examination

culminated in the issuance of FERC Order No. 888 in 1996. Order No. 888,

Promoting Wholesale Competition Through Nondiscriminatory Transmission

Services by Public Utilities, 61 Fed. Reg. 21,540, 21,541 (May 10, 1996) (“FERC

Order No. 888”), on reh’g, 62 Fed. Reg. 12,274 (Mar. 14, 1997), on reh’g, 62 Fed.

Reg. 64,688 (Dec. 9, 1997), on reh’g, 82 F.E.R.C. ¶ 61,046 (Jan. 20, 1998), aff’d

Transmission Access Policy Study Group v. FERC, 225 F.3d 667 (D.C. Cir. 2000)

(per curiam), aff’d sub nom. New York v. FERC, 535 U.S. 1 (2002). Among other

provisions, FERC Order No. 888 included a series of regulations that provided for

the creation of competitive markets for wholesale electric power, including the

creation of independent regional transmission companies that would allow the

development of a competitive electric transmission market. 
25

Prior to these events, the California electricity market was composed of

investor-owned utilities, whose generation, transmission, and distribution of

electricity were vertically integrated and regulated by the California Public Utilities

Commission (“CPUC”), the state agency charged with regulating retail electricity

rates. Cal. Pub. Util. Code § 451. The CPUC set retail electrical rates charged by

the investor-owned utilities providing service in exclusive service territories. 

There are three major investor-owned utilities in California: Pacific Gas and

Electric Company (“PG&E”), Southern California Edison Company (“Edison”),

and San Diego Gas and Electric Company (“SDG&E”) . 

In response to FERC Order No. 888 and energy problems in 1995, the CPUC

and the California legislature commenced initiatives to restructure the California

electric energy industry. The aim was to convert California’s investor-owned,

regulated utilities, to a deregulated market, in which the price of electricity would

be established by competition, and consumers could select their electrical power

supplier. The theory was that competition would lead to better service and a price

reduction for consumers. 

Toward this end, the California legislature enacted Assembly Bill 1890 (“AB

1890”). Act of September 23, 1996, 1996 Cal. Legis. Serv. 854 (codified at Cal.

Pub. Util. Code §§ 330-398.5). The deregulation was to proceed in several phases,
5The California legislature recognized that the transition to a deregulated

market would leave the investor-owned utilities with some unrecoverable

“stranded costs.” “Stranded costs” are those costs, generally associated with

facility construction, that cannot be recovered because either the charged rate is

insufficient to cover the costs or the utility cannot sell enough power. In the case

of sales made pursuant to the divestiture requirements, recoverable stranded costs

meant the difference between the sales price and the book value of the assets. 

During the transition to a deregulated market, the investor-owned utilities were to

recover certain stranded costs through individual cost-recovery plans, which

provided that rates would be frozen for a period of time to allow the investorowned utilities to generate sufficient profits to recover their stranded costs. 

26

beginning with the deregulation of the wholesale electricity market. After a

transition period during which the investor-owned utilities were to recover their

“stranded costs” through fixed prices for electricity, the retail market was to be

deregulated.5 

Under AB 1890, the major investor-owned, vertically integrated utilities

were required to divest a substantial portion of their power generation plants,

including fossil fuel generation plants (but excluding hydroelectric facilities and

nuclear power plants), to unregulated, non-utility producers. This divestiture was

accomplished by a process of market valuation, based on a discount of projected

future revenue streams. See Order Instituting Rulemaking on Commission’s

Proposed Policies Governing Restructuring California’s Electric Service Industry

and Reforming Regulation, 64 CPUC 2d. 1, 1995 WL 792086 (Dec. 20, 1995)
27

(“CPUC Decision 95-12-063”). Between 1998 and 1999, 22 electrical generation

plants were sold. 

After divesting the bulk of their generation assets, the investor-owned

utilities were required to sell all of their remaining output to CalPX, a nonprofit

wholesale clearinghouse created by AB 1890. CalPX was to provide a centralized

auction market for trading electricity. It was deemed a public utility pursuant to the

Federal Power Act, see 16 U.S.C. § 824(e), and thus subject to regulation by

FERC, see 16 U.S.C. § 824(b), (d). It operated pursuant to a FERC-approved tariff

and FERC wholesale rate schedules. Pacific Gas & Elec. Co., 77 FERC ¶ 61,204

at 61,803-05, (1996), reh’g denied, 81 FERC ¶ 61,122 (1997). The investor-owned

utilities were required to purchase all of electrical energy that they required from

the CalPX markets and to conduct all of their sales through the CalPX market. Part

of the underlying theory was that the investor-owned utilities could not exercise

market power in a single transparent market, either as a buyer or a seller, because

prices would be posted and all market participants would be paid the same price.

CalPX commenced operations in 1998. Initially, it operated only a single

price auction for its “spot markets,” defined as “sales that are 24 hours or less and

that are entered into the day of or day prior to delivery.” San Diego Gas & Elec.

Co., et. al., 95 FERC ¶ 61,418 at 62,545 (“June 19, 2001 Order”). The price in the
28

CalPX spot market was determined by evaluating bids submitted by market

participants. As we described the procedure in Public Utility Dist. No. 1 of

Snohomish County v. Dynegy Power Marketing, Inc. (“Dynegy”), 384 F.3d 756,

759 (9th Cir. 2004):

A seller could submit a series of bids that consisted of price-quantity

pairs representing offers to sell (e.g. 5 units at $50 each, but 10 units if

the price is $100 each). Similarly, a buyer could submit a series of

bids that consisted of price-quantity pairs representing offers to buy. 

The PX would then establish aggregate supply and demand curves and

set the “market clearing price” at the intersection of the two curves. 

 Once the market clearing price had been established, “every exchange would take

place at the market clearing price, even though some buyers had been willing to pay

more and some sellers had been willing to sell for less.” Id.

The CalPX spot market, or “core market” as it is sometimes called, consisted

of: (1) “day-ahead” trading, in which the market clearing price was derived from the

sellers’ and buyers’ price and quantity determinations for the next day’s energy

transactions and (2) “day of” or “hour-ahead” trading, in which CalPX would

determine on an hourly basis, a single market clearing price which all suppliers

would be paid. Purchases made in the CalPX spot market were deemed by CPUC to

be “prudent per se.” See CPUC Decision 95-12-063, 1995 WL 792086 at *26-*27. 
29

In practice, the CalPX spot market generated considerable price uncertainty. 

Therefore, CalPX started a division, termed CalPX Trading Services (“CTS”), to

operate a block forward market by matching supply and demand bids for long term

electricity markets. In 1999, CalPX allowed the investor-owned utilities to purchase

only a limited percentage of their combined load in the CTS forward market. They

were required to purchase the balance of their load in the CalPX spot market. 

 AB 1890 created another nonprofit entity, the Independent System Operator

(“Cal-ISO”), also subject to FERC jurisdiction, which was to be responsible for

managing California’s electricity transmission grid and balancing electrical supply

and demand. Although the investor-owned utilities continued to own the

transmission facilities, Cal-ISO exercised operational control over the grid. The

Cal-ISO grid included the transmission systems of PG&E, Edison, SDG&E, and the

cities of Vernon, Anaheim, Banning, and Riverside, California. To maintain the

grid, Cal-ISO was authorized to procure both energy needed to balance the grid

(“imbalance energy”) and operating reserves (sometimes referred to as “ancillary

services”). The imbalance energy market is the so-called “real time” market, in

which bids to supply energy were to be made no later than 45 minutes prior to the

operating hour. Cal-ISO would rank the supply bids and purchase the required

energy at the market-clearing price. Cal-ISO would then bill CalPX for electricity it
30

required. CalPX would, in turn, bill the investor-owned utilities, who were forced

to pay whatever price that Cal-ISO paid its suppliers, even though that price might

have exceeded what the utilities could have charged their consumers as a

consequence of the retail price freeze. 

Because Cal-ISO was responsible for ensuring that all electricity demand was

met, Cal-ISO was required to buy energy outside the CalPX market to make up the

energy shortfall if sellers in the CalPX market were unable or unwilling to provide

enough supply to meet California’s demand during a particular period. Cal-ISO

acquired operating reserves, constituting capacity that could be converted to energy

and delivered to the grid in response to unexpected events, such as power outages,

from ancillary services suppliers who would agree to reserve capacity during the

specified period. The ancillary suppliers would agree to supply the required

electricity during the specified period on demand from Cal-ISO, and were to be paid

regardless of whether their capacity was used. All of these operations were to be

governed by a tariff and protocols filed with FERC. 

As we now know, something happened on the way to the trading forum, and

the best laid regulatory plans went astray. The plan to establish a competitive

market, while keeping the exercise of monopoly and monopsony power in check,

failed to account for energy economics and the sophistication of modern energy
31

trading. As became clear in hindsight, even those who controlled a relatively small

percentage of the market had sufficient market power to skew markets artificially. 

In short, the old assumptions, based on antitrust theory, that market power could not

be exercised by those who possessed less than 20% of the market share proved

inaccurate in California’s energy market. 

With the new structure, over 80% of the transactions were being made in the

spot markets – the converse of most other electricity markets, in which more than

80% of transactions are made through long term forward contracts, lending stability

to the markets. Sellers quickly learned that the California spot markets could be

manipulated by withholding power from the market to create scarcity and then

demanding extremely high prices when scarcity was probable. The energy market is

highly dependent upon weather; heat waves or cold snaps inevitably produce

demand. Thus, it was quickly apparent to sellers that there was little risk and great

profit in withholding capacity when high demand was anticipated based on weather

forecasts. In addition, traders soon developed other purely artificial means of

market manipulation, such as shutting down power plants when electric demand was

high in order to destabilize the electric grid, and to increase prices. In order to

maximize profit, traders engaged in anomalous bidding practices, including

“hockey-stick bidding,” in which an extremely high price is demanded for a small
32

portion of the market, and “round trip trades,” in which an entity artificially creates

the appearance of increased revenue and demand through continuous sales and

purchases.

Enron Corporation allegedly gamed the California markets with impunity,

using manipulative corporate strategies, such as those nicknamed “FatBoy,” “Get

Shorty,” and “Death Star.” Under the “Death Star” strategy, Enron allegedly sought

to be paid for moving energy to relieve congestion without actually moving any

energy or relieving any congestion. All of the demand was created artificially and

fraudulently, creating the appearance of congestion, and then satisfied artificially,

without the company providing any energy. “FatBoy” refers to a strategy through

which Enron allegedly withheld previously agreed-to deliveries of power to the

forward market so that it could sell the energy at a higher price on the spot market. 

The company would over-schedule its load; supply only enough power to cover the

inflated schedule, and thus, leave extra supply in the market, for which Cal-ISO

would pay the company. Via the “Get Shorty” strategy, traders were able to

fabricate and sell operating reserves to Cal-ISO, receive payment, then cancel the

schedules and cover their commitments by purchasing through a cheaper market

closer to the time of delivery. 
33

The California Parties allege that Enron was not alone and that other entities

engaged in fraudulent power scheduling to serve false load schedules and adopted

other manipulative strategies.

Beginning in May 2000, energy prices in California began to escalate

dramatically. Low cost hydroelectric power from the Northwest was not available

in the volume of previous years, and wholesale electricity prices skyrocketed,

particularly in the CalPX spot markets. In May 2000, the average prices in the

CalPX spot market were double those of May 1999. 

 On June 14, 2000, energy consumers in Northern California experienced

their first wave of rolling blackouts. The California Parties allege that this occurred

because of market manipulation. They claim that the data indicates that the large

California generators utilized economic or physical withholding strategies 94% of

the time during the May through November 2000 period. 

Under its operating procedures, Cal-ISO would declare a “System

Emergency” when its operating reserves dipped below a predetermined percentage

of its projected demand. Whenever reserves in California fell below seven percent,

the ISO declared a “Stage 1 System Emergency.” June 19, 2001 Order, 95 FERC ¶

61,418 at 62,546. The hours during which Cal-ISO declared a system-wide

emergency are also called “reserve deficiency hours.” San Diego Elec. Co., et. al.,
6A brownout occurs when power is not lost completely, but is provided at

reduced voltage levels.

34

97 FERC ¶ 61,275 at 62,246 (2001) (“December 19, 2001 Order”). During the

summer of 2000, high temperatures and lack of supply forced the Cal-ISO to

declare system emergencies 39 times. See San Diego Elec. Co., et. al., 93 FERC ¶

61,121 at 61,353 (2000).

In addition to blackouts, brownouts,6 and system emergencies, the crisis

proved enormously expensive to purchasers of retail power, who were unable to

pass along the increased cost to their consumers. In June 2000, California spent

more on purchasing energy than in the entire summer of 1999. This increase

occurred despite the fact that peak demand was lower in 2000 than in 1999. The

California investor-owned utilities, who were still subject to the price freeze that

was supposed to lock in their profits, lost billions of dollars. Cooler weather in the

fall did not cool prices. Prices continued to escalate throughout the last quarter of

2000. 

In August 2000, SDG&E filed a complaint under § 206 of the Federal Power

Act, 16 U.S.C. § 824e(a), against all sellers of energy and ancillary services in the

CalPX and Cal-ISO markets. SDG&E requested that FERC impose a price cap on
35

sales into those markets. Other parties, including PG&E and the State of California,

joined the complaint. 

On August 23, 2000, FERC issued an order denying the relief requested by

SDG&E, but determining that it was appropriate to investigate the justness and

reasonableness of the rates for all sales in the CalPX and Cal-ISO markets. San

Diego Gas & Elec. Co., et. al., 92 FERC ¶ 61,172(2000) (“August 23, 2000 Order”). 

Therefore, it established its own investigatory proceeding in FERC Docket Nos. EL00-95 and EL00-98 (“the Remedy Proceedings”). The August 23, 2000 Order

established October 29, 2000 as the refund effective date, which was determined by

calculating the date sixty days after publication of notice of the order in the Federal

Register. Id. at 61,608.

On November 1, 2000, FERC issued an order proposing structural changes to

the operation of the CalPX and Cal-ISO markets. San Diego Gas & Elec. Co., et.

al., 93 FERC ¶ 61,121 (2000) (“November 1, 2000 Order”). In the November 1,

2000 Order, FERC concluded that: 

[T]he electric market structure and market rules for wholesale sales of

electric energy in California are seriously flawed and . . . these

structures and rules, in conjunction with an imbalance of supply and

demand in California, have caused, and continue to have the potential

to cause, unjust and unreasonable rates for short-term energy (DayAhead, Day-of, Ancillary Services and real-time energy sales) under

certain conditions.
36

Id. at 61,349.

FERC concluded that there was “clear evidence” that sellers could “exercise

market power when supply is tight” and produce “unjust and unreasonable rates” for

wholesale power sales. Id. at 61,349-50. 

The November 1, 2000 Order proposed, effective sixty days after the date of

the order, to (1) eliminate the requirement that the investor-owned utilities buy and

sell power exclusively through the CalPX; (2) require market participants to

schedule 95 percent of their transactions in the day-ahead market or be subject to a

penalty charge; (3) replace the existing CalPX and Cal-ISO stakeholder boards with

independent non-stakeholder boards; and (4) require the filing of generator

interconnection procedures. 

In addition to ordering structural and rule changes, FERC ordered an

evidentiary hearing to determine the appropriate refund. At the behest of the

California Parties, FERC changed the refund effective date from October 29, 2000

to October 2, 2000, based on the filing of the SDG&E complaint. FERC also

limited the refund to Cal-ISO and CalPX spot market transactions completed during

the period from October 2, 2000 through June 20, 2001 (hereinafter referred to as

the “Refund Period”).
37

Emergency conditions continued following the issuance of the November 1,

2000 Order, requiring Cal-ISO to serve increasingly larger portions of its load

through the real time imbalance energy market and depleting Cal-ISO’s operating

reserves. As a result, Cal-ISO proposed changes to its tariff, which FERC approved

in an order dated December 8, 2000. Cal. Indep. Operator Corp., et. al., 93 FERC ¶

61,239 (2000). One provision of this order lifted the Cal-ISO price caps, with the

goal of attracting more supply into the auction markets. 

On December 15, 2000, FERC issued an order substantially adopting the

remedies proposed in the November 1, 2000 Order. San Diego Gas & Elec. Co., et.

al., 93 FERC ¶ 61,294 (2000) (“December 15, 2000 Order”). The December 15,

2000 Order attempted to reduce the reliance on spot markets by terminating

CalPX’s wholesale rate schedules, thereby eliminating the requirement that the

investor-owned utilities buy and sell all generation through CalPX. CalPX sought a

writ of mandamus from our Court challenging the December 15, 2000 Order’s

prohibition of the investor-owned utilities’ selling power on a voluntary basis in the

CalPX market and the termination of the wholesale tariff. The City of San Diego

also challenged the December 15, 2000 Order by writ of mandate, arguing that

FERC had unreasonably delayed taking action on the purchasers’ requests for
38

refunds. We denied those petitions on April 11, 2001. In re Cal. Power Exch.

Corp., 245 F.3d 1110 (9th Cir. 2001). 

On December 26, 2000, Edison filed a suit against FERC, alleging that it had

failed in its responsibility to ensure that wholesale electricity was sold at reasonable

rates.

The CalPX market began to collapse and the investor-owned utilities were

fast becoming insolvent. On January 17, 2001, the Governor of California declared

a State of Emergency and ordered the California Department of Water Resources to

purchase energy on behalf of California consumers to halt the rolling blackouts. 

Subsequently, the California legislature on February 1, 2001 enacted Assembly Bill

1 of the 2001-2002 First Extraordinary Session authorizing the Department of Water

Resources to purchase power until December 31, 2002. Cal. Water Code § 80000,

et. seq. 

Following the Governor’s declaration, CERS began buying power on January

18, 2001. Energy sellers began refusing to sell to Cal-ISO, and instead sold directly

to the investor-owned utilities and CERS through bilateral contracts. Most sales

after January 18, 2001 were made directly to CERS, rather than through CalPX or

Cal-ISO. CalPX ceased market operations on January 30, 2001 and filed for

protection under Chapter 11 of the Bankruptcy Code on March 9, 2001. The
39

California Parties allege that from January 18, 2001 to June 18, 2001, CERS

purchased more than $5 billion of energy in the spot market.

On March 1, 2001, the California Electricity Oversight Board (“Cal-EOB”)

filed a motion with FERC, asking FERC to clarify that the Remedy Proceedings

included CERS transactions outside of the CalPX and Cal-ISO markets. The CalEOB contended that the sellers that had manipulated the markets were now charging

the same or higher rates for the CERS sales.

On March 9, FERC issued an order establishing a provisional formula

governing refunds during the January 2001 period. San Diego Gas & Elec. Co., et.

al., 94 FERC ¶ 61,245 (2000) (“March 9, 2001 Order”). The order directed

wholesale sellers to provide refunds or, alternatively, to justify their charges and

costs for transactions made during power emergencies that were above a rate it

calculated as appropriate. FERC estimated that approximately $69 million in

January 2001 electricity sales would be subject to refunds. 

On April 6, 2001, PG&E filed a voluntary petition in bankruptcy pursuant to

Chapter 11 of the Bankruptcy Code. Although Edison and SDG&E were in similar

financial peril, they avoided bankruptcy filings through arrangements with creditors. 
40

On April 26, 2001, FERC issued an order establishing a prospective

mitigation and monitoring plan for wholesale prices through the real time markets

operated by Cal-ISO. San Diego Gas & Elec. Co., et. al., 95 FERC ¶ 61,115 (2001)

(“April 26, 2001 Order”). The April 26, 2001 Order established a pricing

mechanism for sales by California generators made to Cal-ISO when reserves fell

below seven percent. The order also established conditions, including refund

liability, for market-based rate authority with the goal of preventing anticompetitive bidding behavior in the real time Cal-ISO market.

On June 19, 2001, FERC issued an order reaffirming that “as a result of the

seriously flawed electric market structure and rules for wholesale sales of electric

energy in California, unjust and unreasonable rates were charged, and could

continue to be charged during certain times and under certain conditions, unless

certain targeted remedies were implemented.” June 19, 2001 Order, 95 FERC at ¶

62557.

 The June 19, 2001 Order imposed price caps on all spot market sales from

June 20, 2001 through September 30, 2002, and imposed a “must-offer” obligation

on generators to prevent them from withholding supply. The prospective price

mitigation plan applied to all sellers that voluntarily sold power into the Cal-ISO

and other designated spot markets, or that voluntarily used Cal-ISO’s or other
41

interstate transmission facilities subject to FERC jurisdiction. According to the

California Parties, the effect of the June 19 Order was to put an end to the rolling

blackouts, catastrophically high prices, and near-continuous power emergencies.

On July 12, 2001, the Administrative Law Judge (“ALJ”) issued a report and

recommendation to FERC regarding a refund methodology to govern sales during

the Refund Period. San Diego Gas & Elec. Co., et. al., 96 FERC ¶ 63,007 (2001). 

In response to the report and recommendation, FERC issued an order on July 25,

2001 in the Refund Proceedings establishing the framework for refunds of past sales

in the spot markets operated by CalPX and Cal-ISO. San Diego Gas & Elec. Co. et.

al., 96 FERC ¶ 61,120 (2001) (“July 25, 2001 Order”). FERC ordered limited

refunds for the rates it had determined to be unjust and unreasonable and established

a mitigated market clearing price (“MMCP”) in an attempt to replicate what it

believed to be the just and reasonable rates that an unmanipulated competitive

energy market would have produced. Under the MMCP methodology, refunds were

to be determined by the difference between the market clearing price, which was the

price charged by all electricity suppliers at a given time, and the MMCP calculated

for each hour of the Refund Period, subject to certain adjustments. FERC also

ordered an evidentiary hearing to calculate the appropriate MMCPs for each hour of

the Refund Period and the amount of refunds owed.
42

However, FERC declined to order refund relief for sales that occurred before

the Refund Period, or for any sales outside of the CalPX and Cal-ISO markets. 

FERC also excluded transactions of more than twenty-four hours in length, even if

those sales were made in the CalPX and Cal-ISO markets within the Refund Period. 

The California Parties contend that refunds for sales prior to the Refund Period

would total $2.3 billion in seller overcharges; that refunds for emergency purchases

made by CERS would total $3.5 billion in seller overcharges; and that other

improperly excluded transactions would amount to over $200 million in seller

overcharges. 

On December 2, 2001, Enron Corporation filed a voluntary petition in

bankruptcy under Chapter 11 of the United States Bankruptcy Code.

On December 19, 2001, FERC issued another order addressing mitigation of

the California spot market prices and conditions. December 19, 2001 Order, 97

FERC ¶ 61,275, et. seq. The order clarified that the price mitigation plans applied

to all sales into the FERC-regulated spot markets and provided further explanation

for why FERC chose October 2, 2000 as the refund effective date. FERC issued an

order denying rehearing of the December 19, 2001 Order on May 15, 2002. 

On February 13, 2002, FERC opened a non-public investigation (“FERC

Enforcement Proceeding”) pursuant to 18 C.F.R. § 1b.1 et. seq. into seller market
43

manipulation of the energy markets in the Western United States. Fact-Finding

Investigation of Potential Manipulation of Elec. & Natural Gas Prices, 98 FERC ¶

61,165 at 61,614 (2002). FERC noted that allegations had been made in the Enron

bankruptcy that Enron had used its market position to distort electric and natural gas

markets. FERC directed its staff to investigate “whether any entity, including Enron

Corporation (through its affiliates or subsidiaries), manipulated short-term prices in

electric energy or natural gas markets in the West or otherwise exercised undue

influence over wholesale prices in the West, for the period January 1, 2000,

forward.” Id.

 In June 2002, some of the California Parties moved this Court for permission

to present additional evidence of market manipulation in the Remedy Proceedings. 

FERC opposed the motion. On August 21, 2002, we directed FERC to allow the

parties to present evidence of market manipulation in the Remedy Proceedings, to

reconsider its earlier orders denying relief, and to provide to the Court supplemental

findings of fact and any recommended modifications to FERC’s orders on the basis

of such new evidence. 

On March 20, 2002, the State of California, through its Attorney General,

filed a complaint alleging that generators and marketers selling power into markets

operated by CalPX and Cal-ISO, as well as those making spot market sales of
44

energy to CERS, violated § 205 of the Federal Power Act by failing to comply with

various filing requirements. The complaint also challenged FERC’s approval of

market-based tariffs. On May 31, 2002, FERC dismissed the complaint as

constituting a collateral attack on prior FERC orders and denied the complaint with

respect to the allegations that FERC’s market-based rate filing requirements

violated the Federal Power Act as a matter of law. State of California ex. rel.

Lockyer v. B. C. Power Exch., et. al., 99 FERC ¶ 61,247 (2002) (“May 31, 2002

Order”). California filed a petition for review of the May 31, 2002 Order.

In December 2002, the ALJ determined that suppliers owed approximately

$1.8 billion to Cal-ISO and CalPX for sales at rates in excess of a just and

reasonable rate. San Diego Gas & Elec. Co., et. al., 101 FERC ¶ 63,026 (2002). 

FERC adopted in part, and modified in part, the ALJ’s proposed findings in an order

issued March 26, 2003 Order, 2003. San Diego Gas & Elec. Co., et. al., 102 FERC

¶ 61,317 (2003) (“March 26, 2003 Order”). 

In its March 26, 2003 Order, FERC stated that it would not alter any of its

previous orders in the Remedy Proceedings concerning the time or transaction

limitations in light of the evidence presented to the ALJ. This position was

reaffirmed in subsequent FERC orders on October 16, 2003, which also clarified

some refund calculation issues. San Diego Gas & Elec. Co., et. al., 105 FERC ¶
45

61,066 (2003); San Diego Gas & Elec. Co., et. al., 105 FERC ¶ 61,065 (2003). 

Subsequently, FERC issued a number of orders pertaining to calculation of refunds

during the Refund Period. San Diego Gas & Elec. Co., et. al., 107 FERC ¶ 61,165

(2004); San Diego Gas & Elec. Co., et. al. 107 FERC ¶ 61,166 (2004); San Diego

Gas & Elec. Co., et. al., 108 FERC ¶ 61,311 (2004), and San Diego Gas & Elec.

Co., et. al., 109 FERC ¶ 61,219 (2004), order on reh’g, 109 FERC ¶ 61,074 (2004). 

On September 9, 2004, we granted in part California’s petition for review

challenging the May 31, 2002 Order. State of California ex. rel. Lockyer v. FERC,

383 F.3d 1006 (9th Cir. 2004) (“Lockyer”). We held that FERC’s decision to

approve market-based tariffs in the wholesale electricity market did not violate the

Federal Power Act. Id. at 1013. We also held that FERC erred as a matter of law in

concluding retroactive refunds were not available under § 205. Id. at 1015. We

remanded the case to FERC for further proceedings.

Before us in the instant case are those portions of the petitions for review that

involve the Scope/Transaction issues. We review FERC orders to determine

whether they are “arbitrary, capricious, an abuse of discretion, unsupported by

substantial evidence, or not in accordance with law.” Cal. Dep’t of Water Res. v.

FERC, 341 F.3d 906, 910 (9th Cir. 2003). FERC’s factual findings are conclusive if

supported by substantial evidence. 16 U.S.C. § 825l(b); Bear Lake Watch, Inc. v.
46

FERC, 324 F.3d 1071, 1076 (9th Cir. 2003). Substantial evidence “means such

relevant evidence as a reasonable mind might accept as adequate to support a

conclusion.” Id. (quoting Eichler v. SEC, 757 F.2d 1066, 1069 (9th Cir. 1985)). “If

the evidence is susceptible of more than one rational interpretation, we must uphold

[FERC’s] findings.” Id. We review questions of law de novo. Am. Rivers v. FERC,

201 F.3d 1186, 1194 (9th Cir. 1999). We review FERC’s interpretation of the FPA

under the familiar analysis established in Chevron U.S.A., Inc. v. Natural Res. Def.

Council, 467 U.S. 837, 842 (1984) and its progeny. Bonneville Power Admin., 422

F.3d at 914.

III

Temporal Scope of Refunds

Under § 206(a) of the Federal Power Act, FERC may investigate whether a

particular rate or charge is “just and reasonable.” 16 U.S.C. § 824d(a). If FERC

finds a rate unreasonable, it must order the imposition of a just and reasonable rate. 

Id. § 824d(d). FERC may then order refunds for any period subsequent to the

“refund effective date,” a date FERC establishes that must be at least sixty days after

the filing of the complaint. Id. § 824e(b). Under the express language of § 206,

however, FERC may not order refunds for any period prior to the filing of the

complaint. Id. Section 309 of the Federal Power Act, on the other hand, gives
47

FERC authority to order refunds if it finds violations of the filed tariff and imposes

no temporal limitations. Consol. Edison v. FERC, 347 F.3d 964, 967 (D.C. Cir.

2003); 16 U.S.C. § 825h. 

In its August 23, 2000 Order, FERC established October 29, 2000 as the

refund effective date pursuant to § 206. In its November 1, 2000 Order, FERC

modified the refund effective date to October 2, 2000. The Competitive Suppliers

Group argues that October 29, 2000 was the proper refund effective date. The

California Parties do not dispute FERC’s establishment of October 2, 2000 as the

refund effective date for the § 206 proceedings, but argue that FERC arbitrarily and

capriciously refused to order refunds for tariff violations under § 309 for periods

prior to October 2, 2000. 

A

We conclude that FERC’s order establishing October 2, 2000 as the refund

effective date for the § 206 Refund Proceedings was not arbitrary or capricious, an

abuse of discretion, unsupported by substantial evidence, or not in accordance with

law. 

SDG&E filed its initial § 206 complaint on August 2, 2000. In its response to

SDG&E’s filing, FERC, in its August 23, 2000 Order, announced that it would
48

commence its own investigation and set the refund effective date sixty days after

FERC published an announcement of the investigation. The notice was published

August 29, 2000; therefore, the refund effective date was set as October 29, 2000. 

On September 22, 2000, some of the California Parties, notably PG&E and

Edison, requested that FERC establish an earlier refund date based on the filing of

the SDG&E complaint, rather than on FERC’s commencement of the Enforcement

Proceedings. Given SDG&E’s August 2, 2000 filing date, the earliest possible

refund effective date was October 2, 2000. In the November 1, 2000 Order, FERC

granted the request and reset the refund effective date to October 2, 2000. 

Thus, the question at issue here is whether FERC properly tethered the refund

effective date to the SDG&E complaint. Although FERC denied the remedy sought

by SDG&E in its complaint, it did not dismiss the SDG&E complaint; rather, it

consolidated the SDG&E complaint with its own investigation “for purposes of

hearing and decision in view of their common issues of law and fact.” December

19, 2001 Order, 97 FERC ¶ 61,275 at 62,198. Despite consolidation, FERC made it

clear that the August 23, 2000 Order “established two separate, but related,

investigations.” Id. at 62,197. According to FERC, the investigation into the

“justness and reasonableness of sellers’ rates in the ISO and PX markets” that

resulted in the refund order grew out of SDG&E’s complaint. Id.
49

In addition, FERC noted that its policy “is to establish the earliest refund

effective date allowed in order to give maximum protection to consumers.” Id. at

62,198. This interpretation is consistent with FERC’s “primary purpose” in

“protecting consumers.” Lockyer, 383 F.3d at 1017. 

The Competitive Suppliers Group argues that the SDG&E complaint cannot

form the basis for establishing the refund effective date because SDG&E did not

seek refunds pursuant to § 206 in its complaint, and third-party FERC complaints

must specify relief sought. To be sure, § 206(a) requires third-party complaints to

FERC to “state the change or changes to be made in the rate, charge, classification,

rule, regulation, practice, or contract then in force. . . .” 16 U.S.C. § 824e(a). It is

also quite true that SDG&E did not seek a refund remedy in its initial complaint. 

SDG&E’s complaint sought an emergency order capping prices in the CalPX and

Cal-ISO markets and a ruling enforcing the cap through limitations on market-based

authorizations. 

However, the relief sought in the initial complaint is not dispositive of this

issue. The key question is whether the SDG&E complaint afforded sufficient notice

to alert market participants that sales and purchases might be subject to refund. The

gravamen of the SDG&E complaint was that the rates charged by sellers were unjust

and unreasonable. As FERC points out, a complaint challenging the reasonableness
50

of the rates can lead to a refund under § 206, even if a refund remedy is not

specifically designated in the initial complaint. FERC is empowered to investigate

the reasonableness of a rate either in the context of a third-party complaint or sua

sponte. Indeed, as we have noted, the Federal Power Act requires FERC to

establish a refund effective date whenever it institutes a § 206 investigation. 16

U.S.C. § 824e(b).

Further, some of the California Parties promptly sought rehearing of FERC’s

initial determination of the refund effective date in its August 23, 2000 Order. In

short, market participants were quickly apprised that the original refund effective

date might be subject to revision. As FERC noted: “Requests for rehearing of the

August 23 Order raising the refund effective date issue were timely filed. Thus, any

reliance by sellers on the October 29 refund effective date prior to the issuance of a

final order was at their own risk.” December 19, 2001 Order, 97 FERC ¶ 61,275 at

62,198. Therefore, because SDG&E’s § 206 complaint unquestionably could have

led to a FERC refund order, because the original FERC order establishing the

refund effective date was not final, and because rehearing petitions were timely filed

challenging the refund effective date, SDG&E’s filing of its complaint provided

sufficient notice to the market to satisfy § 206.
51

The fact that two investigations were initiated by FERC does not alter this

conclusion. The investigation initiated by SDG&E’s complaint focused on whether

the sellers’ rates in the CalPX and Cal-ISO markets were just and reasonable; the

separate FERC investigation focused on whether the CalPX and Cal-ISO market

rules and institutional factors required modification. As FERC noted in its August

23, 2000 Order:

While the SDG&E has focused on the performance of sellers in the

market, the action of sellers may in part be caused by the current

market rules and institutional structures. Accordingly, we conclude

that it is appropriate to investigate not only the justness and

reasonableness of public utility sellers’ rates in the PX and ISO

markets, but also to investigate the tariffs and agreements of the ISO

and PX to determine whether market rules or institutional factors

embodied in those tariffs and agreements need to be modified.

92 FERC ¶ 61,172 at 61,606.

In short, FERC launched a § 206 investigation into the justness and

reasonableness of the rates pursuant to the SDG&E complaint and initiated its own

investigation into the CalPX and Cal-ISO tariffs and agreements to determine

whether market rules required modification. The Competitive Suppliers Group

argues that the § 206 investigation became subsumed into the market investigation. 

However, this contention contradicts the plain language employed by FERC when it

established the two investigations and the subsequent treatment of the investigations
52

in later FERC orders. No substantive consolidation was ever ordered. Even if the

cases had been substantively consolidated, consolidation would not necessarily

eviscerate a validly established refund effective date based on the original SDG&E

complaint. Refunds were eventually ordered as a direct result of the SDG&E

complaint. Given all these considerations, we conclude that FERC did not act

arbitrarily or capriciously, abuse its discretion, or act in violation of law in setting

the refund effective date based on the SDG&E complaint.

B

FERC’s authority to order refunds for filed rates that are later determined to

be unjust, unreasonable, or discriminatory derives from §§ 205 and 206 of the

Federal Power Act. FERC also has remedial authority to require that entities

violating the Federal Power Act pay restitution for profits gained as a result of a

statutory or tariff violation. Consol. Edison, 347 F.3d at 967; Towns of Concord,

Norwood & Wellesley v. FERC, 955 F.2d 67 (D.C. Cir. 1992), S. Cal. Edison Co. v.

FERC, 805 F.2d 1068, 1071-72 (D.C. Cir. 1986). This authority derives from § 309

of the Federal Power Act, which authorizes FERC “to perform any and all acts, and

to prescribe, issue, make, amend, and rescind such orders, rules, and regulations as

it may find necessary or appropriate to carry out the provisions of this Act.” 16
53

U.S.C. § 825h. Unlike refund proceedings commenced under § 206, no time limits

apply to remedial actions filed pursuant to § 309.

In its July 25, 2001 Order, FERC declined to award any relief pursuant to §

309. The California Parties sought review of that decision. We granted the

California Parties’ motion for an order requiring FERC to entertain further evidence

of market manipulation and tariff violation and to reconsider its orders limiting

remedies. After receiving further evidence, FERC ruled that it would not consider

further remedies. March 26, 2003 Order, 102 FERC ¶ 61,317 at 62,083. The

California Parties petition for review of FERC’s refusal to consider § 309 remedies. 

We conclude that FERC’s decision not to consider a § 309 remedy for tariff

violations was arbitrary and capricious, an abuse of discretion, and not in

accordance with law. On appellate review, FERC “must be able to demonstrate that

it has made a reasoned decision based upon substantial evidence in the record.” N.

States Power Co. v. FERC, 30 F.3d 177, 180 (D.C. Cir. 1994) (internal quotations

omitted). FERC must “articulate a satisfactory explanation for its action including a

rational connection between the facts found and the choice made.” Motor Vehicle

Mfrs. Assn of the U. S., Inc. v. State Farm Mut. Ins. Co., 463 U.S. 29, 43 (1983).
54

In this case, FERC offers several rationales for refusing to grant tariff relief. 

First, it claims that § 206 precludes refunds prior to the refund effective date. 

Second, it contends that no tariff violations occurred. Third, it argues that it need

not provide remedies to the California Parties because it has commenced

prosecutorial investigations into the question of whether tariff violations occurred,

and those investigations may result in remedies which would make the market

whole. None of these justifications is sufficient to sustain FERC’s decision under

the applicable standard of review. 

First, FERC’s claim that it is precluded from ordering pre-Refund Period

relief under § 206 may be quickly dispatched. The relief sought by the California

Parties in this part of the proceeding is based on § 309, not § 206. Although the §

206 proceedings seeking refunds because of unjust and unreasonable rates are

limited to the Refund Period, § 309 proceedings based on tariff violations are not. 

FERC’s apparent conclusion that the time limits applicable to § 206 proceedings

also apply to § 309 proceeding is incorrect as a matter of law. Indeed, FERC

emphasized as much in its own filings in the investigatory proceedings:

Thus, with respect to the period prior to the October 2, 2000 refund

effective date, the Commission can order disgorgement of monies

above the post October 2, 2000 refunds ordered in the California

Refund Proceeding, if it finds violations of the ISO and PX tariffs and

finds that a monetary remedy is appropriate for such violations.
55

Further, while refund protection has been in effect for sales in the ISO

and PX short-term energy markets since October 2, 2000, the

Commission can additionally order additional disgorgement of unjust

profits for tariff violations that occurred after October 2, 2000 (i.e., to

June 20, 2001). 

Enron Power Mktg, Inc., 103 FERC ¶ 61,346 at 62,351 (2003).To the extent that

FERC is claiming that the § 206 time limits apply to § 309 proceedings, FERC is

wrong.

Second, FERC alleges there were no tariff violations, contending that “there

is no basis for finding that the sellers acted inconsistently with Commission-filed

tariffs or with specific requirements in their filed rate authorizations.” July 25, 2001

Order, 96 FERC at 61,508. This conclusion is flatly inconsistent with FERC’s

commencement of the FERC Enforcement Proceeding, which was initiated to

investigate and prosecute tariff violations. It contradicts the conclusion of FERC

staff, accepted by FERC, that bid prices in the pre-Refund Period were “excessively

elevated solely for the purpose of raising prices” in violation of the Cal-ISO and

CalPX rules. Investigation of Anomalous Bidding Behavior and Practices in the

Western Markets, 103 FERC ¶ 61,347 at 62,360 (2003). FERC concluded that “the

remedy for these tariff violations, if found to exist, would be the disgorgement of

any unjust profits attributable to these tariff violations.” Id. at 62,359. 
56

FERC’s assertion in this proceeding that there were no tariff violations prior

to the Refund Period is contravened by its own findings in American Electric Power

Services Corp., to wit:

As discussed below, the entities listed in the caption (Identified

Entities) appear to have participated in activities (Gaming Practices),

that constitute gaming and/or anomalous market behavior in violation

of the California Independent System Operator Corporation’s (ISO)

and California Power Exchange’s (PX) tariffs during the period

January 1, 2000 to June 20, 2001, that warrant a monetary remedy of

disgorgement of unjust profits and that may warrant other additional,

appropriate non-monetary remedies. These determinations are based on

certain of the tariffs’ provisions, an ISO study, a report by Commission

Staff, and evidence and comments submitted by market participants.

103 FERC ¶ 61,345 at 62,328 (2003). See also Enron Power Mktg, Inc., 103 FERC

¶ 61,346.

In addition to FERC’s own conclusions, the California Parties also presented

significant evidence of pervasive tariff violations during the pre-Refund Period. In

sum, there is no support for FERC’s second rationale for denying the California

Parties’ request for pre-Refund Period relief. 

FERC’s third stated reason for denying the request is that it is pursuing tariff

violations in the separate FERC Enforcement Proceeding. Obviously, this rationale

contradict’s FERC’s second rationale – that no tariff violations exist. This reason

for rejecting the California Parties’ request for § 309 relief is also unsupportable. 
57

In explaining its third reason for denying the request, FERC describes at

length its broad investigatory and prosecutorial authority under § 307(a) (16 U.S.C.

§ 825(f)) and § 309 (16 U.S.C. § 825h). However, no one disputes this authority. 

What FERC fails to explain, or support, is how its inherent authority to commence

investigations and enforcement proceedings under 18 C.F.R. § 1b.1 et. seq.

precludes a civil proceeding instituted by third party complaint. 

The two types of proceedings are quite distinct. One is investigative and

prosecutorial; the other is a contested proceeding. FERC enjoys broad discretion in

the management of its own § 1b prosecutorial investigations. FERC

“[i]nvestigations may be formal or preliminary, and public or private.” 18 CFR §

1b.4. In contrast to an adjudicated, contested proceeding, in a § 1b proceeding,

FERC may settle claims without review, and need not justify its decision to order

refunds, or to decline to order refunds.

Because §1b investigations are prosecutorial in nature, third parties do not

participate. 18 C.F.R. § 1b.11. For example, in this case FERC denied the

California Parties’ motion to intervene in the FERC Enforcement Proceeding,

explaining:

The Commission intends the proceedings listed in the caption of this

order to proceed as investigative and, where appropriate, enforcement

proceedings. Their purpose is to examine instances of potential
58

wrongdoing and take remedial action where needed. The Commission

is thus acting in a prosecutorial manner in these matters, rather than

strictly as an adjudicator. . . . 

. . . [This] has important implications, particularly with respect to

potential intervenors. There are no parties to an investigative

proceeding. 18 C.F.R. § 1b.11 (2003). Moreover, only a party can

contest a settlement, 18 C.F.R. § 385.602(h) (2003). . . . Another

implication of the application is the Commission’s rules governing

off-the-record communications. These rules apply only to contested,

on-the-record proceedings; they do not apply to Part 1b investigations

unless the Commission specifically makes an exception to allow

formal interventions and party status. 18 C.F.R. § 385.2201(c) (2003)

. . . . 

. . . Consequently, the Commission is treating all pending motions for

intervention as motions to file comments and, to the extent the

Commission to date may have erroneously allowed intervention,

rescinding those interventions that have heretofore been granted.

Fact-Finding Investigation of Potential Market Manipulation of Elec. & Natural Gas

Prices, 105 FERC ¶ 61,063 at 61,352(2003) 

Commissioner Massey dissented from this decision, writing:

I do not agree that the investigation of Anomalous Bidding Behavior

and Practices in the Western Markets should be treated exclusively as

an investigation under Part 1b and that there should be no parties to the

proceeding. Much of the evidence supporting the investigation was

adduced by parties pursuant to a court order in the California refund

proceeding. The California parties are integral to the assessment of and

weight to be given the evidence. The Commission should not decide,

in isolated enforcement proceedings, issues upon which the courtordered adduced evidence has a bearing where those that adduced the

evidence are not parties and have no appeal rights.
59

Id. at 61,353.

 At various times, FERC has stated that it reserves the right to impose marketwide inquiries in the FERC Enforcement Proceedings; however, in these

proceedings to date, it has only pursued “company-specific” investigations into the

actions of various market participants, rather than conducting a market-wide

inquiry. San Diego Gas & Elec. Co., et. al., 105 FERC ¶ 61,066 at 61,385. FERC

itself casts its company-specific approach as supplemental to the adjudicative refund

proceedings undertaken pursuant to § 206. See, e.g., San Diego Gas & Elec. Co., et.

al., 105 FERC ¶ 61,066 at 61,391 (“Any such company-specific disgorgement or

other appropriate remedies would be in addition to the refunds associated with the

mitigated market clearing prices developed pursuant to this order and could apply to

conduct both prior to the Refund Period and during the Refund Period.”); 102

FERC ¶ 61,108 at 61, 289 (2003) (“The payment to be made by Reliant will be in

addition to any refund ultimately owed by Reliant as part of the refund proceeding

in Docket No. EL00-95, et. al.”). 

In contrast, the California Parties seek a market-wide refund remedy for tariff

violations pursuant to § 309 through its adjudicative filing. The fact that FERC may

be seeking similar remedies against specific companies in its §1b investigations

does not justify its denial of the California Parties’ request for § 309 relief. When
60

parties seek adjudicative relief from an agency, they are entitled to a reasoned

response from the agency. Here, the California Parties filed a cognizable request for

relief and tendered credible evidence in support of their request. A party’s valid

request for relief cannot be denied purely on the basis that the agency is considering

its own enforcement action that may impart a portion of the relief sought. If an

aggrieved party tenders sufficient evidence that tariffs have been violated, then it is

entitled to have FERC adjudicate whether the tariff has been violated and what

relief is appropriate. 

In sum, none of the reasons given by FERC for refusing to adjudicate whether

tariffs were violated is sustainable. Section 309 relief is not limited by § 206. 

FERC’s determination that no tariff violations occurred is not supported by the

record. FERC cannot avoid adjudicating a third-party petition because it may or

may not choose to commence a separate enforcement action. For these reasons, we

conclude that FERC’s categorical rejection of the California Parties’ request for §

309 relief was arbitrary, capricious, and an abuse of discretion. Therefore, we grant

the petition for review as it pertains to the California Parties’ challenge to FERC’s

foreclosure of relief for tariff violations. We deny the California Parties’ petition

insofar as it calls for us to decide the merits of its request for § 309 relief. We do

not prejudge how FERC should address the merits or fashion a remedy if
61

appropriate. FERC cannot, however, categorically refuse to entertain the

application; it must address the merits.

IV

Out of Market Spot Transactions

FERC’s July 25, 2001 Order mandated retrospective relief for sales to CalISO, including out-of-market (“OOM”) transactions. These purchases were made

by Cal-ISO from sellers outside the Cal-ISO single price auction market within 24

hours or less of delivery, and served to stabilize the grid when supply was

insufficient to meet demand. Because Cal-ISO had no choice but to buy energy to

ensure grid reliability, potential sellers were in a position to exercise improper

market leverage by exploiting the structural flaws in the market. FERC concluded

that the OOM transactions provided the best opportunity for extracting unjust and

unreasonable rates and therefore, made them subject to potential refunds.

The Competitive Suppliers Group petitions for review of FERC’s decision to

include OOM sales into the Cal-ISO because (1) FERC made no express finding

that the rates charged for OOM sales were unjust and unreasonable and (2) the

Remedy Proceedings had been limited since their inception to the Cal-ISO/CalPX

single-price auction market. We deny this petition for review. 

A
62

Section 206(a) of the Federal Power Act requires that before FERC can

exercise its remedial power to mitigate an existing rate, it must find an existing rate

“unjust, unreasonable, unduly discriminatory or preferential.” 16 U.S.C. § 824e(a);

Fed. Power Comm’n v. Sierra Pac. Power Co., 350 U.S. 348, 353 (1956). The

Competitive Suppliers Group argues that although FERC made a finding that prices

within the auction markets were unjust and unreasonable, they never made such a

finding with respect to OOM sales to Cal-ISO.

In its July 25, 2001 Order, FERC adopted the MMCP to calculate just and

reasonable rates for Cal-ISO and CalPX. The MMCP was the benchmark for

determining the amount of refunds that sellers had to pay – FERC simply looked at

their transactions during the refund period then ordered them to pay the difference

between the rate and the MMCP. 

Application of the MMCP was a determination that a rate was unjust and

unreasonable. As FERC explains in its brief, 

[B]ecause the conditions under which [Cal-ISO] OOM spot

transactions were entered into made it likely that the rates for

those transactions were unjust and unreasonable, FERC required

that all transactions be examined to decide which ones would be

subject to refund. . . . [A] market-wide mitigation methodology

was needed in the [Cal-ISO] and CalPX auction markets because

systemic dysfunctions caused by structural problems in those

markets had the potential to cause unjust and unreasonable rates

‘independent of any conclusive showing of a specific abuse of
63

power.’ In addition, a showing of market power abuse is not a

prerequisite for finding rates are outside the zone of

reasonableness and, therefore, unjust and unreasonable. 

FERC Br., citing July 21, 2001 Order. 

FERC’s analysis of this issue is correct. The Federal Power Act does not

require the detailed individualized finding that Competitive Suppliers Group

requests, nor does it require a showing of market power abuses, and no court has

held that it does. 

FERC found that there was systemic dysfunction in the wholesale energy

market and that, during the time that Cal-ISO was making OOM purchases, it was

in an emergency must-buy situation, which gave the sellers even greater market

power, and thus increased the likelihood that the rates were unjust and

unreasonable. These facts constituted a sufficient finding that the rates were unjust

and unreasonable. FERC was not required to make an additional individualized

finding, in addition to the imposition of the MMCP, that rates for Cal-ISO OOM

transactions were unjust and unreasonable. 

B

Contrary to the Competitive Suppliers Group’s argument, the Remedy

Proceedings were not limited to the Cal-ISO and CalPX single-price auction

markets. First, nothing in the language of the August 2, 2000 complaint or early
64

orders necessarily limited the Remedy Proceedings to the Cal-ISO and CalPX inmarket transactions. Indeed, the SDG&E complaint was “directed against all

sellers in the ISO and PX markets.” FERC did not add the Cal-ISO OOM

transactions to the proceeding. Rather, it clarified in its orders that the transactions

were encompassed in the scope of the SDG&E complaint proceeding. 

Second, FERC offered a sufficient explanation as to why the Cal-ISO OOM

transactions were subject to refunds, namely that the purchases, like in-market

purchases, were made to “procure the resources necessary to reliably operate the

grid.” July 25, 2001 Order, 96 FERC ¶ 61,120 at 61,515. Therefore, there was no

meaningful distinction to be drawn between the in- and out-of-market transactions. 

FERC further noted that the Cal-ISO OOM transactions were contemplated in the

Cal-ISO tariff as a backstop to the Cal-ISO auction market. 

The Competitive Suppliers Group points out that OOM transactions made by

Cal-ISO are fundamentally different from those made in the Cal-ISO market. 

Certainly, there are significant differences. The OOM transactions at issue here

were bilaterally negotiated sales of power at different prices than the market

clearing price established in the auction market. However, as FERC points out,

these bilateral transactions were closely intertwined with the Cal-ISO single price

auction spot market because manipulation of the single price auction market could
65

create artificial market forces, making it probable that rates charged in the OOM

transactions were unjust and unreasonable. Although different in form, both the

single price auction purchases and Cal-ISO OOM purchases occurred in the same

market, so the structural flaws that allowed unjust and unreasonable prices to be

charged in the single-price auction also allowed unjust and unreasonable prices to

be charged in the Cal-ISO OOM transactions. Given this structural relationship, it

was reasonable for FERC to examine those Cal-ISO OOM transactions that were

affected by the manipulated market conditions and order refunds when appropriate.

It is also significant to note that FERC did not order refunds for all Cal-ISO

OOM transactions. Rather, FERC ordered all Cal-ISO OOM spot transactions to

be examined to decide which ones would be subject to potential refund. An

agency’s discretion is at its zenith when it is “fashioning [] policies, remedies and

sanctions, including enforcement and voluntary compliance programs in order to

arrive at maximum effectuation of Congressional objectives.” Niagara Mohawk

Power Corp. v. Fed. Power Comm’n, 379 F.2d 153, 159 (D.C. Cir. 1967). Given

this level of deference, coupled with FERC’s reasoned explanation of its decision,

we conclude that FERC did not act arbitrarily, capriciously, or in abuse of its

discretion when it included the Cal-ISO OOM transactions in the Remedy

Proceedings. 
66

V

Non-Emergency Hours Transactions

A

In its initial mitigation orders, FERC limited price mitigation only to

“emergency hours” when supply was deficient and suppliers knew that their bids,

however high, would be accepted. June 19, 2001 Order, 95 FERC ¶ 61,418 at

62,546-62,547. FERC believed that during hours when there were sufficient

energy reserves to ensure that the Cal-ISO controlled grid would remain reliable,

called “non-emergency hours,” suppliers would be motivated to bid competitive

prices. FERC reasoned that with excess supplies in the market, suppliers would bid

competitively because they ran the risk that their bids would not be accepted. See

id. at 62,547.

Over time, however, FERC observed that because energy supply was

generally low, suppliers could count on their bids being accepted in both

emergency and non-emergency hours. So, the incentive to bid high prices was as

evident during non-emergency hours as it was during emergency hours. See

December 19, 2001 Order, 97 FERC ¶ 61,275 at 62,247 (“[D]uring non-emergency

periods where there were no excess supplies in the market and all suppliers would

be dispatched, the incentive to bid high prices remained.”). Although FERC’s
67

targeted remedies had improved the wholesale power market to some extent, see

June 19, 2001 Order, 95 FERC ¶ 61,418 at 62,546, the market remained generally

dysfunctional, id. at ¶ 62,556. 

Thus, in an attempt to provide “the incentives needed to correct the

[remaining] market dysfunctions,” FERC expanded the market monitoring and

mitigation plan to address all operating hours. Id. at ¶ 62,547. FERC

implemented prospective relief for non-emergency hours by modifying the formula

it had used to set the market clearing price in emergency hours. Id. at ¶ 62,558. 

Recognizing that rates should decrease in non-emergency hours due to an increase

in supply, FERC set the market clearing price for non-emergency hours at 85

percent of the market clearing price established during the last system emergency.

Id. at ¶ 62,548. FERC would permit a higher bid only if justified by the supplier. 

Id. at ¶ 62,558. FERC’s intention was to “emulate . . . a competitive market,” and

“prevent possible abuses that could lead to unjust and unreasonable rates.” Id. at

62,558. 

In its July 25, 2001 Order, FERC declined to order refunds because it felt

that an evidentiary hearing was necessary to resolve “material issues of fact” before

deciding whether to order a refund. July 25, 2001 Order, 96 FERC ¶ 61,120 at
68

61,519-61,520. FERC ordered Cal-ISO to apply the MMCP to each operating hour

and report the data to an ALJ. Id. at ¶ 61,520. FERC then directed the ALJ to 

make findings of fact with respect to: (1) the mitigated price in each

hour of the refund period; (2) the amount of refunds owed by each

supplier according to the methodology established herein; and (3) the

amount currently owed to each supplier (with separate quantities due

from each entity) by the ISO, the investor owned utilities, and the

State of California. 

Id. 

FERC explained that its decision to review rates in all operating hours was

based on its original finding of systemic market dysfunction, which “was not

limited to reserve deficiency periods.” December 19, 2001 Order, 97 FERC ¶

61,275 at 62,246. Referencing the finding in its November 1, 2000 Order that the

market was structurally flawed, FERC stated: “We determined that structural

problems, which existed in all hours, had the potential to cause market prices to

exceed that which one would expect in a competitive market. While our solution

requires review for all hours, that does not mean that this will result in refunds for

all hours.” Id.

The Competitive Suppliers Group petitions for review of FERC’s decision to

apply the MMCP to non-emergency operating hours. It argues that FERC’s

decision to order mitigation for non-emergency hours was arbitrary and capricious
69

because FERC did not expressly find that rates during non-emergency hours were

unjust and unreasonable.

B

As we have noted, before FERC can exercise its remedial powers under FPA

§ 206, it must find that the rate at issue is unjust and unreasonable. 16 U.S.C.

824e(a). The Competitive Suppliers Group attacks the adequacy of FERC’s

general finding of systemic market dysfunction, arguing that it did not satisfy the

condition precedent to § 206(a) authority. 

The Competitive Suppliers Group claims that FERC was required to make

explicit findings that specific rates charged in each operating hour were unjust or

unreasonable. However, as we have noted, no such requirement exists. FERC

“may rely on ‘generic’ or ‘general’ findings of a systemic problem to support

imposition of an industry-wide solution.” Interstate Natural Gas Ass’n of Am. v.

FERC, 285 F.3d 18, 37 (D.C. Cir. 2002). “[P]roportionality between the identified

problem and the remedy is the key.” Id.

To be sure, if FERC found isolated problems within the wholesale electric

energy market, its market-wide remedy would have been inappropriate. See Assoc.

Gas Distribs. v. FERC, 824 F.2d 981, 1019 (D.C. Cir. 1987) (“Neither Wisconsin
70

Gas nor any other case of which we are aware supports an industry-wide solution

for a problem that exists only in isolated pockets. In such a case, the disproportion

of remedy to ailment would, at least at some point, become arbitrary and

capricious.”). However, faced with a market plagued by structural problems and

operating under “seriously flawed” rules, FERC could have reasonably considered

a market-wide remedy necessary. 

FERC’s response was proportional to the identified problem: It ordered

wholesale review of a market that it had identified as wholly dysfunctional. 

Moreover, the method FERC used to review the system resulted in an

individualized analysis of the rates charged in each operating hour. FERC

explained that its expansion of mitigation measures over time was a reflection of

both the “rapidly changing circumstances” during the refund period and its attempt

to balance competing interests while fulfilling its FPA obligations: 

In response to [its November 1 dysfunctional market] findings, the

Commission has sought to intervene in markets in as limited a manner

as possible consistent with its responsibilities to ensure just and

reasonable rates under the FPA, to rely on market principles whenever

it can, and to balance carefully the need for price relief against the

need for price signals to attract critical supply entry.

December 19, 2001 Order, 97 FERC ¶ 61,275 at 62,246.
7

 As a threshold matter, FERC argues that the California Parties’ and CalISO’s arguments are procedurally defaulted because they were not raised on

rehearing. 16 U.S.C. § 825l(b) provides that a party may obtain review in this

(continued...)

71

Given all of these considerations, we cannot say that FERC’s decision to

include non-emergency hours transactions in its market mitigation orders was

arbitrary, capricious, or an abuse of discretion.

VI

Spot Market Limitation (24-Hour Limit)

A

In it July 25, 2001 Order, FERC restricted the refund proceedings to “spot

transactions in the organized markets operated by the ISO and PX during the

[Refund Period].” July 25, 2001 Order, 96 FERC ¶ 61,120 at 61,499. In its June

19 Order, it defined the spot market at issue as constituting “sales that are 24 hours

or less and that are entered into the day of or day prior to delivery.” June 19, 2001

Order, 95 FERC ¶ 61,418 at 62,545. By these two orders, FERC excluded sales

made in the Cal-ISO and CalPX spot markets of greater than 24 hours. Although

this limitation was made without explanation, it apparently was based on FERC’s

construction of the original SDG&E complaint. The California Parties petition for

review of this limitation.7
7

(...continued)

court by filing a petition “within sixty days after the order of the Commission

upon the application for rehearing.” We, however, cannot consider an objection

“unless such objection shall have been urged before the Commission in the

application for rehearing.” Id. In their multiple requests for rehearing of FERC’s

orders, the California Parties fairly raised objections to FERC’s limitation of price

mitigation to the Cal-ISO real-time market, and its limitation of refunds to “spot

sales.” Thus, FERC had the opportunity to address the Caifornia Parties’

challenges and we have jurisdiction to consider FERC’s limitation. See

Transmission Access Policy Study Group, 225 F.3d at 685 n. 4. 

72

In order to analyze this issue properly, a brief procedural review is

appropriate. In the original complaint, SDG&E asked FERC to put a price cap on

all sales into the Cal-ISO and CalPX markets and urged FERC to enter into a “full

examination of the reasons why the ISO/PX markets are not workably

competitive.” In its August 23, 2000 Order, FERC instituted hearing proceedings

to “detect and . . . to resolve as expeditiously as possible, any defects in the

operation of competitive power markets in California.” 92 FERC ¶ 61,172 at

61,603. 

Although FERC mentioned the “spot market” in the body of its August 23

order, it did not explicitly define spot transactions or limit its investigation to

transactions of a certain length. See id. at 61,605, 61,607. FERC did inform

interested parties that it may “further refine” or “narrow the focus” of the hearing

after it reviewed its own staff’s investigative findings. See id. at 61,603, 61,609. 
73

On November 1, 2000, after FERC’s staff issued its findings, FERC issued

an order identifying serious market flaws that had caused and “ha[d] the potential

to cause, unjust and unreasonable rates for short-term energy (Day-Ahead, Day-of,

Ancillary Services and real-time energy sales) under certain conditions.” 

November 1, 2000 Order, 93 FERC ¶ 61,121 at 61,349. FERC proposed remedies

designed to “facilitate forward contracting” and discourage an “over reliance on

spot markets.” Id. at 61,359.

On December 15, 2000, FERC again stressed that high prices were mostly

due to over-reliance on short-term contracts, and encouraged market participants to

acquire both short-term and long-term contracts. December 15, 2000 Order, 93

FERC ¶ 61,294 at 61,993-61,994. Although market participants expressed

concerns that long-term contracts would be affected by the “spiraling spot prices”

from the previous summer, FERC assured them that it would “monitor prices in

[long-term] markets and also adopt a benchmark that we will use as a reference

point in addressing any complaints regarding the pricing of long-term contracts

negotiated over the next year.” Id. at ¶ 61,994.

FERC first explicitly limited refunds to spot markets in its July 25, 2001

Order, stating, “[t]he Commission makes clear that transactions subject to refund

are limited to spot transactions in the organized markets operated by the ISO and
74

PX during the [refund period].” July 25, 2001 Order, 96 FERC ¶ 61,120 at 61,499. 

FERC used the same description for “spot market” as it had in its June 19 order. 

Id. at ¶ 61,515-61,516.

In contesting this limitation, the California Parties offered testimony from

economist Dr. Peter Fox-Penner and Director of Market Monitoring and Analysis

for Southern California Edison Dr. Gary A. Stern to support their claim that sellers

manipulated both short-term energy markets and forward markets and succeeded in

raising rates above just and reasonable levels in both. Dr. Fox-Penner testified that

sellers had purposefully manipulated short-term energy markets to cause an

increase in forward rates by withholding supply from the short-term market,

forcing Cal-ISO to buy necessary energy outside of the spot market at higher prices

and for longer contract periods. Dr. Stern testified that if the MMCP mitigation

method were applied to Cal-ISO’s forward contracts, refunds would exceed $54.5

million.

Despite this testimony, FERC continued to limit refunds to “spot market”

transactions as described in its June 19, 2001 order. See March 26, 2003 Order,

102 FERC ¶ 61,317 at 62,084. The California Parties requested rehearing of

FERC’s decision, arguing that after they had submitted additional evidence

showing that the sellers’ insistence on longer duration sales was often an element
75

of the exercise of market power, and that FERC should have reconsidered its

decision to exclude forward contracts from the monitoring and mitigation plan. 

The California Parties argued that FERC should include in the Remedy

Proceedings all sales up to one month in duration. FERC responded on October

16, 2003, by rejecting the California Parties’ arguments as being “identical to those

they have already raised,” and stating that it had “already thoroughly considered

and rejected” the same arguments. San Diego Gas & Elec.. Co., et. al., 105 FERC

¶ 61,066, 61,365 (2003). 

B

FERC’s primary reason for excluding the forward market transactions is that,

in its view, these transactions were not included in the original SDG&E complaint. 

It notes that its § 206 refund authority “is discretionary and limited to those rates

challenged as the subject of a proceeding.” Thus, FERC argues that it was

prevented from mitigating forward transactions because the original complaint

limited the scope of the proceeding to only “spot market” transactions. 

The record does not support FERC’s conclusion. The original complaint

explicitly referred to both short-term and forward sales in the Cal-ISO and CalPX

markets. SDG&E expressed concern about the “day-ahead, hour-ahead, and block

forward markets conducted by the PX.” The complaint clearly challenged rates for
76

forward transactions, asserting that “until workable competition is established,

supply bids into the California forward and real-time markets should be capped at

$250 per Mwh.” (emphasis added). The complaint logically did not reference sales

outside the ISO and PX’s formal markets because SDG&E was, at that time,

required to purchase energy through the formal spot markets. However, within that

limitation, SDG&E cast as wide a net as possible, including challenging those

forward transactions it was allowed to enter. The original complaint did not limit

FERC’s section 206 refund authority to only “spot market” transactions. Thus, the

primary reason given by FERC for excluding the transactions is without adequate

foundation in the record.

FERC does not offer any other justification for excluding the transactions. 

Significantly, even in the face of new evidence concerning forward markets, FERC

simply reiterated that the issue was outside the scope of the original complaint. 

FERC’s failure to even address the additional evidence is another reason that we

reject its exclusion of these transactions. 

FERC initially thought spot prices would discipline forward prices, and that

more forward contracting was the answer to the market dysfunction. Thus, early in

the Remedy Proceedings, FERC focused its mitigation measures on short-term

sales and actually encouraged market participants to acquire more forward
77

contracts. See December 15, 2000 Order, 93 FERC ¶ 61,294 at 61,993-61,994. 

However, later evidence suggested that forward prices had not been reigned in by

FERC’s mitigation of the spot markets, and that sellers had successfully

manipulated forward markets to raise prices. 

In denying rehearing of its continued exclusion of forward transactions,

FERC did not explain why the new evidence had no effect on its decision. See 105

FERC ¶ 61,066 at 61,365-61,366. FERC merely referenced its previous

explanation, from its December 19, 2001 Order, in which it found that only the

rates in “spot markets” were potentially unjust and unreasonable. However, FERC

issued that order before the California Parties had offered additional evidence to

support their claim. FERC never explained why the additional evidence did not

affect its decision to limit mitigation procedures to only “spot market” transactions.

We should uphold FERC’s decision if its path to making that decision “may

reasonably be discerned.” See Motor Vehicle Mfrs. Ass’n, 463 U.S. at 43. 

However, it is difficult, if not impossible, to discern FERC’s analytical path here,

particularly when its decision is viewed in light of its simultaneous decision to

expand mitigation measures to include other previously excluded categories of

transactions. 
78

For instance, FERC expanded its mitigation measures to include nonemergency hours, even though it had earlier believed that rates in non-emergency

hours would be sufficiently disciplined by its mitigation measures in emergency

hours. See December 19, 2001 Order, 97 FERC ¶ 61,275 at 62,247. FERC later

recognized new evidence that refuted its earlier belief and acted accordingly,

expanding its mitigation measures to include all operating hours. When sellers

argued against this expansion, FERC responded:

As Commission orders are not final while subject to rehearing, and

rehearing was requested of all orders in this proceeding, the mitigation

measures and related procedures implemented in those orders were

subject to adjustment or replacement. Sellers could not reasonably

have expected therefore, that the mitigation measures and related

procedures implemented in earlier orders in this proceeding would

remain unchanged during the rehearing process.

Id. at 62,218.

FERC’s explanation applies with equal force here. Throughout the

proceedings, FERC emphasized that it was engaged in a continuing examination of

all market forces. Its investigation was not static and yet it proffered no reason for

rejecting the new evidence that suggested that the forward market was affected by

market manipulation that may have produced unjust and unreasonable rates. When

faced with a similar situation in which FERC acted differently in two related
8

 The Public Entities argue that FERC erred in finding that some of the

Public Entities’ transactions with Cal-ISO were spot market transactions – not

multi-day transactions – and thus subject to refunds pursuant to FERC’s orders. 

The California Parties have moved to strike this contention because it involves

implementation questions not appropriate for this phase of the proceedings. Given

our decision that the forward market transactions are subject to refund liability, the

issues raised by the Public Entities are likely moot. However, to the extent that

any issues remain, we grant the California Parties’ motion because the questions

raised by the Public Entities are fact-specific inquiries as to the nature of particular

transactions that are appropriately considered in conjunction with implementation

issues.

79

situations without offering a reasoned explanation, we have granted a petition for

review. See Cal. Dep’t of Water Res. v. FERC, 341 F.3d 906, 910 (9th Cir. 2003). 

FERC’s decision to foreclose relief in the forward markets cannot be

sustained. Its cramped reading of the original SDG&E complaint is not supported

by a close examination of the record, and FERC does not offer any other

explanation for its decision. In view of the evidence tendered by the California

Parties that sellers manipulated both the short term and long term spot markets,

FERC’s limitation of remedy without a reasonable explanation was arbitrary,

capricious, and an abuse of discretion.8 

VII

Energy Exchange Transactions

A
80

Exchange transactions involved two different sellers. The first seller, the

“Exchange Seller,” agreed to provide Cal-ISO with energy in exchange for an inkind return of the same amount of energy plus an additional agreed-upon amount. 

See March 26, 2003 Order, 102 FERC ¶ 61,317at 62,083-62,084. Cal-ISO then

purchased energy from the second seller, the “Spot Seller,” on the spot market and

used that energy to pay back the Exchange Seller. In a typical exchange

transaction, an Exchange Seller would provide Cal-ISO with one unit of power in

exchange for Cal-ISO’s promise to return two units of power at a later time. CalISO would use the one unit of power to supply its power grid. Then Cal-ISO

would buy two units of power from a Spot Seller in order to pay back the Exchange

Seller. Exchange transactions had varying return ratios. At times, the parties

agreed that Cal-ISO must return the energy in “like time,” for instance in “on-peak”

hours.

Cal-ISO’s purchases on the spot market were mitigated when FERC ordered

Spot Sellers to refund amounts they had charged in excess of the MMCP. See id. at

62,084. However, FERC declined to include Exchange Sellers in the Refund

Proceedings. 

The California Parties and Cal-ISO challenge the exclusion of Exchange

Sellers, contending that they also should be liable for refunds because they used
81

exchange transactions to exert market power by demanding exorbitant exchange

ratios. The California Parties’ witness, Dr. Carolyn Berry, an independent

economic consultant and former FERC economist, testified in support of their

claim that Exchange Sellers had violated the Federal Power Act. Dr. Berry testified

that “return ratios were excessively high.” She suggested that Exchange Sellers

“may have been hoping to avoid refund liability by making sales in-kind rather

than for explicit monetary payment.” Dr. Berry noted that some of the sellers’

internal emails supported her conclusion that those sellers were aware that using inkind exchanges was a way for them to avoid FERC’s scrutiny. 

Economist Dr. Peter Fox-Penner also testified on behalf of the California

Parties regarding exchange transactions. He testified that “[t]here is no economic

difference to a buyer between paying for a power purchase in dollars and paying

for it in a commodity whose price is well-established in dollars in the marketplace.

. . . [thus], there is no economic basis for excluding such transactions from

mitigation.” 

The Public Entities argue that Cal-ISO actually benefitted from exchange

transactions because the Exchange Sellers offered desperately needed flexibility in

a crisis situation. In support of their claim, the Public Entities referred to a Wall

Street Journal article in which Cal-ISO Vice President Jim Detmers was described
82

as praising exchange transactions because they were “a good deal” for California

and “might even have saved [the state] money because daily peak prices were

sometimes more than twice the off-peak prices the ISO paid for BPA’s replacement

power.” 

In its March 26, 2003 Order, FERC held that it would not subject the

Exchange Sellers to refund liability for exchange transactions. The primary reason

given by FERC in excluding Exchange Sellers from the Refund Proceedings was

the difficulty in calculating a refund. March 26, 2003 Order, 102 FERC ¶ 61,317 at

62,084.

B

FERC improperly excluded the Exchange Sellers from the refund

proceeding. There is no doubt that energy exchanges are considered sales, subject

to FERC’s jurisdiction. 18 C.F. R. § 35.2(a). By refusing relief simply because the

calculation was difficult, FERC abandoned its duty under the Federal Power Act to

ensure just and reasonable rates. See 16 U.S.C. § 824d(a). As we have previously

stated, “[t]he FPA cannot be construed to immunize those who overcharge and

manipulate markets in violation of the FPA.” Lockyer, 383 F.3d at 1017. FERC is

obligated to protect consumers from unjust or unreasonable rates, charges, or

classifications, and any rules, regulations, practices, or contracts affecting such
83

rates, charges or classifications. See 16 U.S.C. § 824e(a). Nothing in the Federal

Power Act limits its application to those transactions that are easy to value. 

Although multiple variables may make certain transactions difficult to analyze,

consumers must still be assured that those transactions are just and reasonable. 

FERC’s approach to the exchange transactions created a loophole through

which Exchange Sellers could exercise market power and manipulate the energy

market without being subjected to the requirements of the Federal Power Act. 

FERC’s failure to exercise its broad remedial discretion to analyze exchanges of

power during the Refund Period and address any unjust and unreasonable practices

was arbitrary and capricious, and an abuse of discretion.

FERC argues that it is impossible to determine whether the Exchange Sellers

demanded unjust and unreasonable exchange ratios because there is no way to

assign a monetary value to exchange transactions. FERC claims that, because

exchange transactions involved multiple variables like the shortage of hydroelectric generation power in the Pacific Northwest, it cannot determine whether

Exchange Sellers demanded and received value in excess of what would have been

just and reasonable under the circumstances. However, FERC did not conduct a

specific analysis to conclude that the rates were just and reasonable, given the
84

variables, nor did it make a finding that the variables showed that the rate was just

and reasonable. FERC simply concluded that the calculation was too difficult. 

The challenge of monetizing the transactions does not give FERC a safe

harbor to throw up its hands and say it can’t be done. Significantly, FERC did not

provide a reasoned explanation of impossibility, only a conclusory observation of

difficulty. But saying so doesn’t make it so. Constructing a methodology did not

prove too taxing for the California Parties, who tendered a mitigation methodology

for examining the Exchange Sellers’ transactions. FERC rejected the California

Parties’ proposed mitigation method because it did not account for all relevant

variables. See March 26, 2003 Order, 102 FERC ¶ 61,317at 62,084 (“The CA

Parties’ request to reform the exchange ratio completely ignores the severe energy

shortfall in the Pacific Northwest, where most of these energy exchange

transactions originated, during the 2001 time period.”). 

The fact that FERC was dissatisfied with the California Parties’ proposed

mitigation method does not justify its decision to exclude Exchange Sellers from

the refund proceeding on a categorical basis. FERC’s own precedent shows that

when parties have failed to propose an acceptable mitigation method, it may

fashion a method on its own. See Re Green Mountain Power Corp., 61 FERC ¶
85

61,203 (1992) (using the value of a contemporaneous cash sale from the same

power unit to value an exchange of capacity for purposes of ordering a refund). 

FERC also argues that because the energy exchanges were conducted over

periods greater than 24 hours, the transactions cannot be considered spot market

transactions subject to mitigation. However, we have already rejected this

argument as a general matter, so it does not afford FERC a valid basis for

excluding the transactions at issue here. 

In sum, because FERC did not articulate a valid basis for excluding the

energy exchange transactions from the Refund Proceedings, we conclude that its

action was arbitrary, capricious, and an abuse of discretion.

VIII

Sleeve Transactions

“Sleeve transactions” were used when the investor-owned utilities were on

the brink of insolvency and credit problems began to limit the ability of the

investor-owned utilities to purchase power. As FERC described it:

A “sleeve” transaction involves three parties: a seller, a purchaser and

a creditworthy third party “sleever” or “sleeving party” who provides

the financial underpinnings for the transaction. Thus, if either party to

a transaction determines that it cannot buy from or sell to its

commercial counterparty due to concerns about the other party’s
86

creditworthiness, the sleeving party steps in to provide the necessary

financial backing so that the transaction can go forward.

San Diego Gas & Elec. Co., et. al., 107 FERC ¶ 61,165 at 61,640 (2004). 

To obtain adequate supplies of energy to continue to power the grid, Cal-ISO

entered into transactions whereby sleeving parties would buy power directly from

energy sellers and then resell the power to Cal-ISO at a premium to reflect the

credit risk. 

Cal-ISO decided that certain sleeve transactions should not be subject to

mitigation, but the ALJ reached the opposite conclusion. After considering the

ALJ report, FERC determined that the sleeve transactions should be subject to

mitigation; in other words, those transactions should not be excluded from

potential refund liability. FERC concluded that the sleeve transactions were

similar to other sales and that the sleeving parties assumed the same risks of

making spot energy sales to Cal-ISO, including the risk of refund liability. 

Therefore, FERC adopted the ALJ’s findings and included the sleeve transactions

as part of the refund proceedings. The Public Entities now petition for review of
9

 The California Parties moved to strike the portion of Public Entities’

briefs addressing sleeve transactions, and El Paso Merchant Energy moved to

defer consideration of sleeving issues. Both parties argue that consideration of

sleeving is an issue of implementation, not an issue of scope, and therefore

belongs in the next round of briefing. However, there is no principled way to

distinguish a hypothetical exemption for sleeve transactions, as a distinct category,

from the exemptions or non-exemptions FERC has considered, and we are now

considering, for OOM, energy exchange, forward market, and other categories of

transactions. Sleeve transactions appear to be a distinct category, subject to the

same type of analysis as the other issues. We therefore deny the California Parties

and El Paso Merchant Energy’s motions as to sleeve transactions and consider the

merits of Public Entities’s claim that sleeve transactions as a category should have

been exempted. However, to the extent that the Public Entities are raising factspecific issues related to implementation, as opposed to a categorical challenge,

we grant the California Parties’ motion.

87

that decision, arguing that sleeve transactions were individually negotiated

transactions outside the scope of the Remedy Proceedings.9

The Public Entities contend that the sleeve transactions should not be

included in the refund proceedings because the sleeving parties merely acted as

financial intermediaries and facilitators. In their view, the sleeve transactions were

individually negotiated transactions that did not take place in the single-price

auction market. FERC contends that the parties saw the sleeve transactions as

comprising two sales: one from the supplier to the sleeving party and the second

from the sleeving party to Cal-ISO. In FERC’s view, the sleeving parties were

subject to Cal-ISO rules because all sellers in the Cal-ISO market had the
88

responsibility to comply with market rules and the tariff. The final transaction of

the two-step process occurred, according to FERC, in the Cal-ISO market. 

The record supports FERC’s conclusion. All sleeve transactions that are

subject to challenge here occurred as spot market transactions in the Cal-ISO

market. The fact that the sleeving parties received a risk premium does not relieve

them from liability if, independent of the risk premium, they charged an unjust and

unreasonable rate in the spot market, which was part and parcel of the Cal-ISO

market. Thus, FERC did not act arbitrarily or capriciously, or abuse its discretion

in including the sleeve transactions in the refund proceeding.

IX

California Energy Resources Scheduling (“CERS”) Division Transactions

A

In its December 8, 2001 Order, FERC lifted the Cal-ISO price caps, hoping

to attract more supply into the auction markets. December 8, 2000 Order, 93 FERC

¶ 61,239. In its December 15, 2001 Order, FERC eliminated the requirement that

the investor-owned utilities buy and sell all energy through CalPX. December 15,

2001 Order, 93 FERC ¶ 61,294. As we have discussed, when these remedies did

not stem the rise of electricity prices, and the investor-owned utilities were on the

brink of insolvency, Governor Davis ordered CERS to enter into contracts to buy
89

power directly on behalf of California consumers. These purchases were made in

bilateral contracts outside the CalPX and Cal-ISO markets and totaled more than $5

billion of purchases.

On March 1, 2001, the Cal-EOB filed a motion with FERC, asking FERC to

clarify that the Remedy Proceedings included CERS transactions. FERC denied

the motion, concluding that the bilateral transactions were entered into outside the

CalPX and Cal-ISO markets, and therefore, were outside the scope of the Remedy

Proceedings. In its order, FERC noted that “if DWR or another party believes that

any of its contracts are unjust or unreasonable, it may file a complaint under FPA

Section 206 . . . .” CPUC and Cal-EOB filed such complaints, which are the

subject of separate petitions for review before this Court. See Pub. Utilits. Comm’n

of State of Cal. et. al. v. FERC, nos. 03-74207, et. al. In this case, the California

Parties petition for review of FERC’s decision to exclude the CERS transactions

from the Remedy Proceedings, and the various FERC orders denying rehearing. 

We conclude that FERC’s decision to exclude the CERS transactions was not

arbitrary, capricious, or an abuse of discretion. 

B

One of the fundamental tenets in FERC jurisprudence is the rule against

retroactive ratemaking. Arkansas Louisiana Gas Co. v. Hall, 453 U.S. 571, 578
90

(1981). This theory underpins the limitations on FERC’s remedies under § 206 to

the post-complaint period. § 824e(b). Consol. Edison Co. of N. Y., Inc. v. FERC,

347 F.3d 964, 967 (D.C. Cir. 2004). If FERC finds a rate unjust and unreasonable

pursuant to a § 206 complaint, it must order imposition of a just and reasonable

rate; however, the refund is limited to periods subsequent to the “refund effective

date” established by FERC, which must be at least sixty days after the filing of the

complaint. Id. By this procedure, once a complaint is filed, sellers are on notice

that their sales may be subject to refund. 

Thus, while FERC has considerable latitude in fashioning § 206 relief, the

remedies afforded pursuant to a third party § 206 complaint must have a sufficient

nexus to the substantive allegations of the complaint so that market participants are

placed on notice that they are at risk for sales made after the refund effective date. 

We have already concluded that the substantive allegations of the SDG&E

complaint were sufficient to put sellers on notice that the OOM, non-emergency,

energy exchange, and sleeve transactions might be subject to refund. All of these

transactions were directly associated with the CalPX and Cal-ISO markets. 

However, the bilateral CERS transactions occurred in a different market – one that

did not even exist when the SDG&E complaint was filed. Thus, neither the

SDG&E complaint nor the subsequent actions by FERC in establishing the Remedy
91

Proceedings were sufficient to put participants in the CERS transactions on notice

that their sales might be subject to refund. 

There are fundamental differences between the CalPX/Cal-ISO markets and

the bilateral contracts negotiated by CERS. As we have discussed, the CalPX and

Cal-ISO markets were centralized, single-price, auction markets, involving

multiple participants. In contrast, the CERS transactions were two-party contracts

of varying prices, terms and duration that were mutually negotiated – ostensibly at

arms-length – outside the CalPX and Cal-ISO markets. Unlike the Cal-ISO OOM

and sleeve transactions that we have concluded were properly considered in the

Refund Proceedings, the CERS transactions occurred in a market that was not

directly influenced by the market manipulations in the Cal-ISO and CalPX spot

markets. The record reflects no direct nexus between the CERS bilateral

transactions and the CalPX and Cal-ISO spot markets. 

Given these differences, and the fact that the entire focus of the SDG&E

complaint and FERC’s orders creating the Remedy Proceedings were directed at

the CalPX and Cal-ISO markets, it is clear that the substantive allegations of the

SDG&E complaint did not bear a sufficient nexus to the bilateral CERS

transactions to afford parties to the CERS contracts sufficient notice that their sales

might be subject to refund. 
92

Indeed, when the SDG&E complaint was filed, the investor-owned utilities

were required to conduct all of their sales and purchases through the CalPX and

Cal-ISO markets. It was not until FERC’s December 15, 2000 Order, some six

months after the filing of the SDG&E complaint, that investor-owned utilities were

free to conduct energy transactions outside the CalPX and Cal-ISO markets. And,

it was not until January, 8, 2001 that CERS began to make its purchases.

Thus, FERC concluded that:

DWR transactions are negotiated bilateral contracts for the

procurement of energy on behalf of California [investor-owned

utilities], and are distinctly beyond the realm of ISO and PX

centralized market operations that have been the subject of this

proceeding since its inception . . . . No party could reasonably have

believed that the Commission intended the proceeding to be broader.

December 19, 2001 Order, 97 FERC ¶ 61,275 at 62, 195.

We agree with FERC’s analysis. Because the SDG&E complaint was not

sufficient to put the CERS transaction participants on notice, expanding the Refund

Proceeding to include the CERS transactions would violate the rule against

retroactive ratemaking. 

The California Parties argue, with considerable force, that unjust and

unreasonable rates were charged in the CERS transactions and that the transactions
93

in substance were indistinguishable from transactions within the CalPX and CalISO markets. However, FERC did not close the door on potential § 206 relief

based on the CERS transactions; in fact, it invited aggrieved participants to file

new complaints directed specifically at the CERS transactions. Thus, while the

bilateral CERS transactions are beyond the scope of the Remedy Proceedings at

issue here, those transactions may be the subject of other challenges, the posture

and merits of which are beyond the scope of the instant case. 

Given all of this, we conclude that FERC’s construction of the SDG&E

complaint as not including the CERS transactions was not arbitrary, capricious, or

an abuse of discretion. 

X

Port of Oakland and Other Bilateral Transactions

The Port of Oakland argues that its bilateral contracts with energy suppliers,

entered into during the CERS period to meet the needs of Oakland’s airport, should

also be subject to the Refund Proceedings. FERC denied the request on the same

basis that it denied the California Parties’ entreaty to include the CERS transactions

in the Refund Proceedings. The analysis of the CERS and Port of Oakland

transactions is the same. We deny the petition for review filed by the Port of
94

Oakland for the same reasons that we deny the petition by the California Parities

for review of the CERS transactions. 

XI

Section 202(c) Transactions

By December 2000, in the middle of the energy crisis, energy suppliers were

reluctant to bid into the CalPX and Cal-ISO auction markets because the investorowed utility buyers in those markets were verging on insolvency. In order to

correct for this shortage of sales, Cal-ISO requested the United States Department

of Energy to intervene. Pursuant to Cal-ISO’s request, the Department of Energy 

issued a series of orders under the emergency provisions of Federal Power Act §

202(c), which required energy suppliers to sell excess available power to Cal-ISO. 

The Public Entities were parties to some of these sales, which were later exempted

from a refund by FERC because of the fact that they were compulsory. 

The Public Entities attack FERC’s affirmance of the ALJ’s conclusion that

certain of these sales were exempt from refund liability. The California Parties

have moved to strike this argument on the basis that it constitutes an

implementation issue to be decided in a different phase of this case, rather than an

issue that concerns the scope of the refund proceeding.
95

No party challenges FERC’s determination that sales pursuant to § 202(c)

are exempt from refund liability. The Public Entities do not argue that § 202(c)

transactions categorically should or should not be included in the scope of the

refund proceeding. Rather, the Public Entities contest the manner in which FERC

determined the definition – the scope – of the § 202(c) exemption. The Public

Entities do not argue that any particular category or subcategory of transactions

should be considered § 202(c) transactions. Instead, they take issue with the

methods and information FERC uses to determine what is a § 202(c) exemption. 

Thus, we conclude that the § 202(c) issues raised by the Public Entities should be

considered an implementation issue, rather than a scope transaction issue. 

Therefore, we grant the California Parties’ Motion to Strike with respect to §

202(c) transactions.

XIII

Conclusion

In general, we hold that all the transactions at issue in this case that occurred

within the CalPX or Cal-ISO markets, or as a result of a CalPX or Cal-ISO

transaction, were the proper subject of the Refund Proceedings. We deny the

petitions for review that challenge FERC’s inclusion of such transactions; we grant

the petitions for review that challenge FERC’s exclusion of such transactions. We
96

deny the petitions for review that seek to expand the Refund Proceedings into the

bilateral markets other than the CalPX and Cal-ISO markets. We hold that FERC

properly established October 2, 2000 as the refund effective date for the § 206

proceedings. We hold that FERC erred in excluding § 309 relief for tariff

violations that occurred prior to October 2, 2000. 

Specifically, we (1) deny the Competitive Suppliers Group’s petition for

review challenging FERC’s establishment of the effective refund date; (2) grant the

California Parties’ petition for review of FERC’s decision to exclude § 309 relief;

(3) deny the Competitive Suppliers Group’s petition for review challenging the

inclusion of the OOM transactions in the Refund Proceedings; (4) grant the

California Parties’ petition for review challenging FERC’s exclusion of forward

market transactions from the Refund Proceedings; (5) grant the California Parties’

petition for review challenging FERC’s exclusion of the energy exchange

transactions from the Refund Proceedings; (6) deny the Public Entities’ petition for

review challenging FERC’s includion of sleeve transactions in the Remedy

Proceedings; (7) deny the California Parties’ petition for review challenging

FERC’s exclusion of the CERS transactions from the Remedy Proceedings; (8)

deny the Port of Oakland’s petition for review challenging FERC’s exclusion of its

bilateral CERS transactions from the Remedy Proceedings; and (9) grant the
97

motion of the California Parties to exclude the Public Entities’ § 202(c) and

challenges to the categorization of multi-day transactions from this proceeding. 

Each party shall bear its own costs on appeal.

PETITIONS GRANTED IN PART; DENIED IN PART; REMANDED

FOR FURTHER PROCEEDINGS.
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COUNSEL

Stan Berman, Heller Ehrman White & McAuliffe, Seattle, Washington; Kevin J.

McKeon, Hawke McKeon Sniscak & Kennard, Harrisburg, Pennsylvnia for

petitioner-intervenor and respondent-intervenor California Parties. 

Robert A. O’Neil, San Diego City Attorney’s Office, San Diego, California for

petitioner-intervenor City of San Diego. 

Dennis Lane, Solicitor, Federal Energy Regulatory Commission, Washington, D.C.

for respondent Federal Energy Regulatory Commission. 

Mark W. Pennak, Department of Justice, Civil Division, Washington, D.C. for

respondent-intervenor and petitioner-intervenor Bonneville Power Administration. 

Harvey L. Reiter, Morrison & Hecker, Washington D.C. for respondent-intervenor

and petitioner-intervenor Indicated Public Entities. 

David C. Frederick, Kellogg, Huber, Hansen, Todd, Evans & Figel, Washington,

D.C.; Lawrence G. Acker, LeBoeuf, Lamb, Greene & MacRae, Washington, D.C.;

Ronald N. Carroll, Foley & Lardner, Washington, D.C. for petitioner-intervenor

and respondent-intervenor Competitive Suppliers Group. 

Charles F. Robinson, Folsom, California; J. Phillip Jordan, Swidler Berlin Shereff

Friedman, Washington, D.C. for intervenor California Independent System

Operator Corporation. 

David L. Alexander, Oakland, California; James M. Costan, McGuire Woods,

Washington, D.C. for petitioner Port of Oakland. 

Randolph Q. McManus, Baker Botts, Washington, D.C. for intervenor Indicated

Generators. 
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Natalie L. Hocken, Portland, Oregon; Stuart F. Pierson, Troutman Sanders,

Washington D.C. for respondent-intervenor PacifiCorp. 

Kenneth W. Irvin, McDermott Will & Emery, Washington, D.C. for intervenor El

Paso Merchant Energy, L.P.