Filed: Aug. 31, 2006
Latest Update: Mar. 02, 2020
Summary: FILED FOR PUBLICATION AUG 31 2006 CATHY A. CATTERSON, CLERK UNITED STATES COURT OF APPEALS U.S. COURT OF APPEALS FOR THE NINTH CIRCUIT PUBLIC UTILITIES COMMISSION OF No. 01-71051 THE STATE OF CALIFORNIA, FERC No. FERC-EL00-000 Petitioner, PUBLIC UTILITIES COMMISSION OF AMENDED OPINION 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 C
Summary: FILED FOR PUBLICATION AUG 31 2006 CATHY A. CATTERSON, CLERK UNITED STATES COURT OF APPEALS U.S. COURT OF APPEALS FOR THE NINTH CIRCUIT PUBLIC UTILITIES COMMISSION OF No. 01-71051 THE STATE OF CALIFORNIA, FERC No. FERC-EL00-000 Petitioner, PUBLIC UTILITIES COMMISSION OF AMENDED OPINION 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 CA..
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FILED
FOR PUBLICATION AUG 31 2006
CATHY A. CATTERSON, CLERK
UNITED STATES COURT OF APPEALS U.S. COURT OF APPEALS
FOR THE NINTH CIRCUIT
PUBLIC UTILITIES COMMISSION OF No. 01-71051
THE STATE OF CALIFORNIA,
FERC No. FERC-EL00-000
Petitioner,
PUBLIC UTILITIES COMMISSION OF AMENDED OPINION
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
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
2
ENERGY L.P.; CITY OF PASADENA,
Intervenors,
And
INTERNATIONAL PACIFIC
ENTERPRISES, LTD.,
Intervenor,
v.
FEDERAL ENERGY REGULATORY
COMMISSION,
Respondent.
PUBLIC UTILITIES COMMISSION OF No. 01-71321
THE STATE OF CALIFORNIA,
FERC No. EL 00-95-000
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
3
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
4
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.
5
CITY OF SAN DIEGO, No. 01-71544
Petitioner, FERC No.
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
6
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
7
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, No. 02-70254
Petitioner, FERC Nos. EL-0095-0004
EL00-95-001
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.
8
FEDERAL ENERGY REGULATORY
COMMISSION,
Respondent,
PACIFICORP,
Respondent-Intervenor.
PACIFIC GAS AND ELECTRIC No. 02-70266
COMPANY,
FERC Nos. EL00-95-000
Petitioner, EL00-95-000
ER01-607-000
SOUTHERN CALIFORNIA EDISON EL00-95-017
COMPANY; PORT OF SEATTLE EL00-95-012
WASHINGTON; CITY OF TACOMA, EL00-95-031
WASHINGTON; NEVADA POWER EL00-95-004
COMPANY; SIERRA PACIFIC POWER EL00-95-001
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,
9
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 No. 02-70275
OVERSIGHT BOARD,
FERC No. FERC-EL95-000
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.
10
CITY OF SAN DIEGO, No. 02-70282
Petitioner, FERC No. FERC-00-95-000
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.
CITY OF OAKLAND, CALIFORNIA No. 02-70285
ACTING BY AND THROUGH ITS
BOARD OF PORT COMMISSIONERS, FERC No. FERC-00-95-000
Petitioner,
CORAL POWER, L.L.C.;
CONSTELLATION ENERGY
11
COMMODITIES GROUP, INC.,
Intervenors,
v.
FEDERAL ENERGY REGULATORY
COMMISSION,
Respondent,
PACIFICORP,
Respondent-Intervenor.
SAN DIEGO GAS & ELECTRIC No. 02-70301
COMPANY,
FERC No. 02-1058
Petitioner,
CALIFORNIA ATTORNEY GENERAL,
Intervenor,
CORAL POWER, L.L.C.;
CONSTELLATION ENERGY
COMMODITIES GROUP, INC.,
Intervenors,
v.
FEDERAL ENERGY REGULATORY
COMMISSION,
12
Respondent.
SOUTHERN CALIFORNIA EDISON No. 02-72113
COMPANY,
FERC No. EL-95-000
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,
13
v.
FEDERAL ENERGY REGULATORY
COMMISSION,
Respondent.
PACIFIC GAS AND ELECTRIC No. 03-73887
COMPANY,
FERC No. Federal Power Act
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
14
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 No. 03-74252
DISTRICT,
15
Petitioner, FERC No. Federal Power Act
v.
FEDERAL ENERGY REGULATORY
COMMISSION,
Respondent.
STATE WATER CONTRACTORS; THE No. 03-74527
METROPOLITAN WATER DISTRICT
OF SOUTHERN CALIFORNIA, FERC No. EL00-95-081
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
16
ENERGY COMMODITIES GROUP,
INC.; CITY OF VERNON,
Intervenors,
v.
FEDERAL ENERGY REGULATORY
COMMISSION,
Respondent.
MODESTO IRRIGATION DISTRICT No. 03-74531
(MID),
FERC No. EL00-95-081
Petitioner,
v.
FEDERAL ENERGY REGULATORY
COMMISSION,
Respondent.
PEOPLE OF THE STATE OF No. 03-74594
CALIFORNIA EX REL. BILL
LOCKYER, FERC No.
Petitioner,
CALIFORNIA INDEPENDENT
SYSTEM OPERATOR CORPORATION,
Intervenor,
17
v.
FEDERAL ENERGY REGULATORY
COMMISSION,
Respondent.
CITY OF LOS ANGELES No. 04-73501
DEPARTMENT OF WATER AND
POWER, FERC No. Federal Power Act
Petitioner,
v.
FEDERAL ENERGY REGULATORY
COMMISSION,
Respondent.
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
18
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).
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
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.
20
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
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
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.
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
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
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
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.
24
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,
25
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)
5
The 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 investor-
owned utilities to generate sufficient profits to recover their stranded costs.
26
(“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
27
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.
28
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
29
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
30
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
31
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.
32
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.,
33
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
6
A brownout occurs when power is not lost completely, but is provided at
reduced voltage levels.
34
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. EL-
00-95 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 (Day-
Ahead, Day-of, Ancillary Services and real-time energy sales) under
certain conditions.
35
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”).
36
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
37
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
38
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 Cal-
EOB 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.
39
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 anti-
competitive 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
40
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.
41
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
42
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
43
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 ¶
44
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.
45
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
46
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
47
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.
48
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
49
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.
50
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
51
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
52
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).
53
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.
54
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.
55
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.
56
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
57
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 court-
ordered adduced evidence has a bearing where those that adduced the
evidence are not parties and have no appeal rights.
58
Id. at 61,353.
At various times, FERC has stated that it reserves the right to impose market-
wide 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
59
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
60
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 Cal-
ISO, 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
61
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
62
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
63
orders necessarily limited the Remedy Proceedings to the Cal-ISO and CalPX in-
market 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
64
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.
65
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
66
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
67
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
68
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
69
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.
70
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
As a threshold matter, FERC argues that the California Parties’ and Cal-
ISO’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
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.
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
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
73
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
74
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
75
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
76
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.
77
For instance, FERC expanded its mitigation measures to include non-
emergency 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
78
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
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
Exchange transactions involved two different sellers. The first seller, the
“Exchange Seller,” agreed to provide Cal-ISO with energy in exchange for an in-
kind 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. Cal-
ISO 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
80
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 in-
kind 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
81
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
82
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 hydro-
electric 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
83
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 ¶
84
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
85
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
86
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
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 fact-
specific issues related to implementation, as opposed to a categorical challenge,
we grant the California Parties’ motion.
87
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
88
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
89
(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
90
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.
91
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
92
in substance were indistinguishable from transactions within the CalPX and Cal-
ISO 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
93
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 investor-
owed 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.
94
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
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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
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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.
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