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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year Ended December 31, 2000
OR
[_] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
IRS Employer
Commission Exact Name of Registrant State of Identification
File Number as specified in its charter Incorporation Number
----------- --------------------------- ------------- --------------
1-12609 PG&E CORPORATION California 94-3234914
1-2348 PACIFIC GAS AND ELECTRIC COMPANY California 94-0742640
Pacific Gas and Electric Company PG&E Corporation
77 Beale Street One Market, Spear Tower
P.O. Box 770000 Suite 2400
San Francisco, California San Francisco, California
(Address of principal executive (Address of principal executive
offices) offices)
94177 94105
(Zip Code) (Zip Code)
(415) 973-7000 (415) 267-7000
(Registrant's telephone number, (Registrant's telephone number,
including area code) including area code)
Securities registered pursuant to Section 12(b) of the Act:
Name of Each Exchange on
Title of Each Class Which Registered
------------------- ---------------------------
PG&E Corporation
Common Stock, no par value New York Stock Exchange and
Preferred Stock Purchase Rights Pacific Exchange
Pacific Gas and Electric Company
First Preferred Stock, cumulative, American Stock Exchange and
par value $25 per share: Pacific Exchange
Redeemable: 7.04%, 5% Series A, 5%, 4.80%,
4.50%, 4.36%
Mandatorily Redeemable: 6.57%, 6.30%
Nonredeemable: 6%, 5.50%, 5%
7.90% Cumulative Quarterly Income Preferred American Stock Exchange and
Securities, Series A (liquidation preference Pacific Exchange
$25), issued by PG&E Capital I and guaranteed by
Pacific Gas and Electric Company
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days.
Yes [X] No [_]
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to
the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [_]
Aggregate market value of the voting common equity held by non-affiliates of
the registrant as of April 9, 2001:
PG&E Corporation Common Stock $2,505 million
Common Stock outstanding as of April 9, 2001:
PG&E Corporation: 387,137,690 (inc
Pacific Gas and Electric Company: shares held by sub)
Wholly owned by PG&E Corporation
The market values of certain series of First Preferred Stock, for which
market prices as of a date within 60 days prior to the date of filing were not
available, were derived by dividing the annual dividend rate of each such
series of stock by the average yield of all of Pacific Gas and Electric
Company's Preferred Stock outstanding for which market prices were available.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the documents listed below have been incorporated by reference
into the indicated parts of this report, as specified in the responses to the
item numbers involved.
(1) Designated portions of the combined Annual Report to
Shareholders for the year ended December 31, 2000..... Part I (Item 1), Part II (Items 5, 6, 7, 7A, and 8),
Part IV (Item 14)
(2) Designated portions of the Joint Proxy Statement
relating to the 2001 Annual Meetings of Shareholders.. Part III (Items 10, 11, 12, and 13)
TABLE OF CONTENTS
Page
----
Glossary of Terms........................................... iv
PART I
Item 1. Business.................................................... 1
GENERAL..................................................... 1
Corporate Structure and Business............................ 1
Competition and the Changing Regulatory Environment......... 3
The Electric Industry...................................... 3
The Natural Gas Industry................................... 4
Regulation of PG&E Corporation.............................. 5
Regulation of Pacific Gas and Electric Company.............. 6
Federal Regulation......................................... 6
State Regulation........................................... 6
Licenses and Permits....................................... 6
Regulation of PG&E National Energy Group, Inc. Businesses... 7
Federal Regulation......................................... 7
State and Other Regulation................................. 7
UTILITY OPERATIONS.......................................... 9
Ratemaking Mechanisms....................................... 9
General Rate Case........................................ 9
Cost of Capital.......................................... 9
Electric and Gas Distribution Performance-Based
Ratemaking (PBR)......................................... 9
Electric Ratemaking........................................ 10
Rate Stabilization Plan Proceeding....................... 10
General Rate Case........................................ 11
2001 Attrition Rate Adjustment Request................... 12
Revenue Adjustment Proceeding............................ 12
Annual Transition Cost Proceeding........................ 12
Electric Industry Restructuring Implementation Costs..... 13
Electric Restructuring Costs Account (ERCA).............. 13
Revenues from Must-Run Contracts......................... 13
FERC Transmission Owner Rate Case........................ 13
AB 1890 Electric Base Revenue Increase................... 14
Electric Transmission Rates.............................. 14
Post-Transition Period Ratemaking Proceeding............. 14
Gas Ratemaking............................................. 15
Gas Accord............................................... 15
General Rate Case........................................ 15
Gas Procurement Costs.................................... 15
The Biennial Cost Allocation Proceeding (BCAP)........... 15
Public Purpose Programs..................................... 16
Electric Utility Operations................................. 16
Electric Industry Restructuring............................ 16
California Power Crisis.................................. 17
FERC Order............................................... 17
The California Independent System Operator and the
California Power Exchange................................ 18
New California Legislation............................... 19
i
Page
----
Recovery of Transition Costs, Wholesale Power Purchase
Costs, and End of Rate Freeze............................ 20
Retail Direct Access..................................... 21
Electric Operating Statistics............................... 23
Electric Resources.......................................... 24
Generating Capacity......................................... 24
Hydroelectric Generation Assets............................ 25
Diablo Canyon Nuclear Power Plant.......................... 25
Diablo Canyon Ratemaking................................. 26
Nuclear Fuel Supply and Disposal......................... 26
Insurance................................................ 27
Decommissioning.......................................... 27
Other Electric Resources.................................... 28
QF Generation and Other Power Purchase Contracts......... 28
Bilateral Agreements..................................... 30
Electric Transmission and Distribution..................... 30
Gas Utility Operations...................................... 32
Gas Operating Statistics................................... 33
Natural Gas Supplies........................................ 34
Gas Regulatory Framework.................................... 35
Transportation Commitments.................................. 36
PG&E NATIONAL ENERGY GROUP, INC. ........................... 36
Integrated Power Generation, and Energy Trading and
Marketing Business.......................................... 37
Ownership and Operation of Generating Facilities........... 37
New Power Plant Development and Construction............... 37
Contractual Control of Generating Capacity................. 38
Energy Marketing and Trading............................... 38
Description of Generating Facilities....................... 41
Competition................................................ 42
Natural Gas Transmission Business........................... 42
PG&E GT-Northwest (PG&E GTN)............................. 42
North Baja Pipeline...................................... 43
Competition.............................................. 43
ENVIRONMENTAL MATTERS....................................... 45
Environmental Matters....................................... 45
Environmental Protection Measures.......................... 45
Air Quality................................................ 45
Water Quality.............................................. 47
Hazardous Waste Compliance and Remediation................. 48
Potential Recovery of Hazardous Waste Compliance and
Remediation Costs.......................................... 49
Compressor Station Litigation.............................. 50
Electric and Magnetic Fields............................... 50
Low Emission Vehicle Programs.............................. 51
Item 2. Properties.................................................. 52
Item 3. Legal Proceedings........................................... 52
Pacific Gas and Electric Company Bankruptcy................. 52
Pacific Gas and Electric Company vs. California Public
Utilities Commissioners..................................... 52
Wilson vs. PG&E Corporation and Pacific Gas and Electric
Company..................................................... 52
Moss Landing Power Plant.................................... 53
ii
Page
----
Compressor Station Chromium Litigation........................ 54
Texas Franchise Fee Litigation................................ 55
Item 4. Submission of Matters to a Vote of Security Holders........... 55
EXECUTIVE OFFICERS OF THE REGISTRANTS......................... 56
PART II
Item 5. Market for the Registrant's Common Equity and Related
Stockholder Matters........................................... 59
Item 6. Selected Financial Data....................................... 59
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations..................................... 59
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.... 59
Item 8. Financial Statements and Supplementary Data................... 59
Changes in and Disagreements with Accountants on Accounting
Item 9. and Financial Disclosure...................................... 60
PART III
Item 10. Directors and Executive Officers of the Registrant............ 60
Item 11. Executive Compensation........................................ 60
Item 12. Security Ownership of Certain Beneficial Owners and
Management.................................................... 60
Item 13. Certain Relationships and Related Transactions................ 60
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form
8-K........................................................... 61
Signatures.................................................... 68
Independent Auditors' Report (Deloitte & Touche LLP).......... 69
Report of Independent Public Accountants (Arthur Andersen
LLP).......................................................... 70
Report of Independent Public Accountants (Arthur Andersen
LLP).......................................................... 71
iii
GLOSSARY OF TERMS
AB 1890........................ Assembly Bill 1890, the California electric
industry restructuring legislation
AEAP........................... Annual Earnings Assessment Proceeding
Alstom......................... Alstom Power, Inc.
ATCP........................... Annual Transition Cost Proceeding
BCAP........................... Biennial Cost Allocation Proceeding
bcf............................ billion cubic feet
Betz........................... Betz Chemical Company
BFM............................ block forward market
BRPU........................... Biennial Resource Plan Update
BTA............................ best technology available
Btu............................ British thermal unit
CARE........................... California Alternate Rates for Energy
CCAA........................... California Clean Air Act
CEC............................ California Energy Commission
CEMA........................... Catastrophic Event Memorandum Account
Central Coast Board............ Central Coast Regional Water Quality Control
Board
CEQA........................... California Environmental Quality Act
CERCLA......................... Comprehensive Environmental Response,
Compensation, and Liability Act
CFCA........................... Core Fixed Cost Account
CLF............................ Conservation Law Foundation
core customers................. residential and smaller commercial gas
customers
core subscription customers.... noncore customers who choose bundled service
CPA............................ California Procurement Adjustment
CPIM........................... core procurement incentive mechanism
CPUC........................... California Public Utilities Commission
CTC............................ competition transition charge
Diablo Canyon.................. Diablo Canyon Nuclear Power Plant
DOE............................ United States Department of Energy
DSM............................ demand side management
DWR............................ California Department of Water Resources
EDRA........................... Electric Deferred Refund Account
EIR............................ environmental impact report
EMF............................ electric and magnetic fields
EPA............................ United States Environmental Protection Agency
ERCA........................... Electric Restructuring Costs Account
ESP............................ energy service provider
EWG............................ exempt wholesale generator
FERC........................... Federal Energy Regulatory Commission
GABA........................... Generation Asset Balancing Account
Gas Accord..................... Gas Accord Settlement
GRC............................ General Rate Case
PG&E GTN....................... PG&E Gas Transmission, Northwest Corporation,
formerly known as Pacific Gas Transmission
Company
PG&E GTN Expansion............. PG&E Gas Transmission, Northwest
Corporation's portion of the Pipeline
Expansion
Holding Company Act............ Public Utility Holding Company Act of 1935
Humboldt....................... Humboldt Bay Power Plant
HWRC........................... hazardous waste remediation costs
iv
GLOSSARY OF TERMS--(Continued)
ICIP........................... Incremental Cost Incentive Price
IPP............................ independent power producer
ISO............................ Independent System Operator
kV............................. kilovolts
kVa............................ kilovolt-amperes
kW............................. kilowatts
LEV............................ low emission vehicle
LIEE........................... Low-Income Energy Efficiency
Mcf............................ thousand cubic feet
MDt............................ thousand decatherms
MMcf........................... million cubic feet
MMcf/d......................... million cubic feet per day
MW............................. megawatts
MWh............................ megawatt-hour
NEES........................... New England Electric System
NEIL........................... Nuclear Electric Insurance Limited
NGL............................ natural gas liquids
NOI............................ Notice of Intent
noncore customers.............. industrial and larger commercial gas
customers
NOx............................ oxides of nitrogen
NPDES.......................... National Pollutant Discharge Elimination
System
NRC............................ Nuclear Regulatory Commission
NTP&S.......................... non-tariffed products and services
Nuclear Waste Act.............. Nuclear Waste Policy Act of 1982
ORA............................ Office of Ratepayer Advocates, a division of
the California Public Utilities Commission
PBR............................ performance-based ratemaking
PECA........................... Purchased Electric Commodity Account
PGA............................ Purchased Gas Account
PG&E Expansion................. the Pacific Gas and Electric Company portion
of the Pipeline Expansion
PG&E ET........................ PG&E Corporation's energy commodities
activities, PG&E Energy Trading or PG&E ET
PG&E ES........................ PG&E Corporation's energy services
operations, PG&E Energy Services or PG&E ES
PG&E Gen....................... PG&E Generating Company, LLC and its
affiliates
PG&E GT........................ PG&E Corporation's gas transmission
operations, PG&E Gas Transmission or PG&E GT
PG&E GTT....................... PG&E Gas Transmission, Texas Corporation
PG&E OSC....................... PG&E Operating Services Company
Pipeline Expansion............. PG&E GT NW/PG&E Pipeline Expansion
PPPs........................... public purpose programs
Price Act...................... Price Anderson Act
PRP............................ potentially responsible party
PTO............................ Participating Transmission Owner
PURPA.......................... Public Utility Regulatory Policies Act of
1978
PVC............................ Pacific Venture Capital, LLC
PX............................. California Power Exchange
PY............................. Program Year
QF............................. qualifying facility
v
GLOSSARY OF TERMS--(Continued)
RAP............................ Revenue Adjustment Proceeding
RCRA........................... Resource Conservation and Resource Act
RMR............................ reliability must-run
ROE............................ return on common equity
ROR............................ rate of return
RSP............................ Rate Stabilization Plan
RTO............................ regional transmission organization
SEC............................ Securities and Exchange Commission
SCS............................ Scheduled Coordinator Services
SO2............................ sulfur dioxide
SoCal Gas...................... Southern California Gas Company
SPE............................ special purpose entity
SRAC........................... short-run avoided costs
TAC............................ Transmission Access Charge
TCBA........................... Transition Cost Balancing Account
throughput..................... the amount of natural gas transported through a pipeline system
TRA............................ Transition Revenue Account
TRBA........................... Transition Revenue Balancing Account
Transwestern................... Transwestern Pipeline Company
TURN........................... The Utility Reform Network
USGenNE........................ USGen New England, Inc.
vi
PART I
ITEM 1. Business.
GENERAL
Corporate Structure and Business
PG&E Corporation is an energy-based holding company headquartered in San
Francisco, California. Effective January 1, 1997, Pacific Gas and Electric
Company (sometimes referred to herein as the "Utility") and its subsidiaries
became subsidiaries of PG&E Corporation, which was incorporated in 1995.
Pacific Gas and Electric Company, incorporated in California in 1905, is an
operating public utility engaged principally in the business of providing
electricity and natural gas distribution and transmission services throughout
most of Northern and Central California. The Utility is primarily regulated by
the California Public Utilities Commission (CPUC) and the Federal Energy
Regulatory Commission (FERC). In the holding company reorganization, Pacific
Gas and Electric Company's outstanding common stock was converted on a share-
for-share basis into PG&E Corporation common stock. Pacific Gas and Electric
Company's debt securities and preferred stock were unaffected and remain
securities of Pacific Gas and Electric Company.
On April 6, 2001, Pacific Gas and Electric Company filed a voluntary
petition for relief under the provisions of Chapter 11 of the U.S. Bankruptcy
Code in the U.S. Bankruptcy Court for the Northern District of California.
Pursuant to Chapter 11 of the U.S. Bankruptcy Code, the Utility retains
control of its assets and is authorized to operate its business as a debtor in
possession while being subject to the jurisdiction of the bankruptcy court.
The factors causing the Utility to take this action are discussed in
"Management's Discussion and Analysis" and in Notes 2 and 3 of the "Notes to
the Consolidated Financial Statements," appearing in the PG&E Corporation and
Pacific Gas and Electric Company combined 2000 Annual Report to Shareholders,
which information is incorporated by reference into this report.
The consolidated financial statements of PG&E Corporation incorporated
herein include the accounts of PG&E Corporation and its wholly owned and
controlled subsidiaries (collectively, PG&E Corporation). The consolidated
financial statements of Pacific Gas and Electric Company incorporated herein
include the accounts of Pacific Gas and Electric Company and its wholly owned
and controlled subsidiaries.
The principal executive offices of PG&E Corporation are located at One
Market, Spear Tower, Suite 2400, San Francisco, California 94105, and its
telephone number is (415) 267-7000. The principal executive offices of Pacific
Gas and Electric Company are located at 77 Beale Street, P.O. Box 770000, San
Francisco, California 94177, and its telephone number is (415) 973-7000.
PG&E Corporation's subsidiary, PG&E National Energy Group, Inc. (NEG), is
an integrated energy company with a strategic focus on power generation, new
power plant development, natural gas transmission, and wholesale energy
marketing and trading in North America. NEG businesses include its power plant
development and generation unit, PG&E Generating Company, LLC and its
affiliates (collectively, PG&E Gen); its natural gas transmission unit, PG&E
Gas Transmission Corporation (PG&E GT); and its wholesale energy and marketing
trading unit, PG&E Energy Trading Holdings Corporation, which owns PG&E Energy
Trading--Gas Corporation, and PG&E Energy Trading--Power, L.P. (collectively,
PG&E Energy Trading or PG&E ET). During 2000, NEG sold its energy services
unit, PG&E Energy Services Corporation. Also, during 2000, NEG sold its Texas
natural gas and natural gas liquids business carried on through PG&E Gas
Transmission, Texas Corporation and PG&E Gas Transmission Teco, Inc. and their
subsidiaries (PG&E GTT). For more information about NEG's businesses, see
"PG&E National Energy Group, Inc." below.
In December 2000, and in January and February 2001, PG&E Corporation and
NEG undertook a corporate restructuring of NEG, known as a "ringfencing"
transaction. The ringfencing complied with credit rating agency criteria
enabling NEG, PG&E Gas Transmission, Northwest Corporation (PG&E GTN), and
PG&E ET to receive
1
or retain their own credit ratings based on their own creditworthiness. The
ringfencing involved the creation or use of special purpose entities (SPEs) as
intermediate owners between PG&E Corporation and its non-CPUC regulated
subsidiaries. These SPEs are: PG&E National Energy Group, LLC which owns 100%
of the stock of NEG, PG&E GTN Holdings LLC which owns 100% of the stock of PG&E
GTN, and PG&E Energy Trading Holdings LLC which owns 100% of the stock of PG&E
Energy Trading Holdings Corporation. In addition, in March 2001, NEG's
organizational documents were modified to include the same structural elements
as the SPEs to meet credit rating agency criteria. Ringfencing is intended to
reduce further the likelihood that the assets of the ringfenced companies would
be substantively consolidated in a bankruptcy proceeding involving such
companies' ultimate parent, and to thereby preserve the value of the
"protected" entities as a whole. The SPEs require unanimous approval of their
respective boards of directors, including at least one independent director,
before they can (a) consolidate or merge with any entity, (b) transfer
substantially all of their assets to any entity, or (c) institute or consent to
bankruptcy, insolvency, or similar proceedings or actions. The SPEs may not
declare or pay dividends unless unanimously approved by the SPE's board of
directors and the company meets specified financial requirements.
PG&E Corporation has identified four reportable operating segments. The
Utility is one reportable operating segment and the other three are part of NEG
(PG&E Gen, PG&E GT, and PG&E ET). Financial information about each reportable
operating segment is provided in "Management's Discussion and Analysis" in the
2000 Annual Report to Shareholders and in Note 16 of the "Notes to Consolidated
Financial Statements" beginning on page 86 of the 2000 Annual Report to
Shareholders, which information is incorporated by reference into this report.
As of December 31, 2000, PG&E Corporation had $35.3 billion in assets. Of
this amount, Pacific Gas and Electric Company had $22 billion in assets. PG&E
Corporation generated $26.2 billion in operating revenues for 2000. Of this
amount, the Utility generated $9.6 billion in operating revenues for 2000. As
of December 31, 2000, PG&E Corporation and its subsidiaries and affiliates had
20,850 employees (including 18,393 employees of the Utility).
The following report includes forward-looking statements about the future
that are necessarily subject to various risks and uncertainties. These
statements are based on current expectations and assumptions which management
believes are reasonable and on information currently available to management.
These forward-looking statements are identified by words such as "estimates,"
"expects," "anticipates," "plans," "believes," and other similar expressions.
Actual results could differ materially from those contemplated by the forward-
looking statements. Although PG&E Corporation and the Utility are not able to
predict all the factors that may affect future results, some of the factors
that could cause future results to differ materially from those expressed or
implied by the forward-looking statements include:
. the reorganization plan that is ultimately adopted by the bankruptcy
court;
. the regulatory, judicial, or legislative actions (including future ballot
initiatives) that may be taken to meet future power needs, mitigate the
higher wholesale power prices, provide refunds for prior power costs, or
address the Utility's financial condition;
. the extent to which the Utility's undercollected wholesale power purchase
costs may be collected from customers;
. any changes in the amount of transition costs the Utility is allowed to
collect from its customers, and the timing of the completion of the
Utility's transition cost recovery;
. future market prices for electricity and future fuel prices which, in
part, are influenced by future weather conditions, the availability of
hydroelectric power, and the development of competitive markets;
. the method and timing of valuation of the Utility's hydroelectric
generation assets;
. future operating performance at the Diablo Canyon Nuclear Power Plant
(Diablo Canyon) and the future ratemaking applicable to Diablo Canyon;
2
. legislative or regulatory changes, including the pace and extent of the
ongoing restructuring of the electric and natural gas industries across
the United States;
. future sales levels and economic conditions;
. the extent to which NEG's current or planned generation development
projects are completed and the pace and cost of such completion;
. generating capacity expansion and retirements by others;
. the outcome of the Utility's various regulatory proceedings;
. fluctuations in commodity gas, natural gas liquids, and electric prices
and the ability to successfully manage such price fluctuations;
. the effect of compliance with existing and future environmental laws,
regulations, and policies, the cost of which could be significant; and
. the outcome of pending litigation.
As the ultimate impact of these and other factors is uncertain, these and
other factors may cause future earnings to differ materially from results or
outcomes currently sought or expected.
Competition and the Changing Regulatory Environment
Historically, energy utilities operated as regulated monopolies within
specific service territories where they were essentially the sole suppliers of
natural gas and electricity services. Under this model, the energy utilities
owned and operated all of the businesses necessary to procure, generate,
transport, and distribute energy. These services were priced on a combined
(bundled) basis, with rates charged by the energy companies designed to
include all of the costs of providing these services. Under traditional
regulation, utilities were provided the opportunity to earn a fair return on
their invested capital in exchange for a commitment to serve all customers
within a designated service territory. The objective of this regulatory policy
was to provide universal access to safe and reliable utility services.
Regulation was designed in part to take the place of competition and ensure
that these services were provided at fair prices. In recent years, energy
utilities faced intensifying pressures to "unbundle," or price separately,
those activities that are no longer considered natural monopoly services. The
most significant of these services are electricity generation and natural gas
supply.
The driving forces behind these competitive pressures have been customers
who believe they can obtain energy at lower unit prices and competitors who
want access to those customers. Regulators and legislators responded to those
customers and competitors by providing for more competition in the energy
industry. Regulators and legislators required utilities to "unbundle" rates
(separate their various energy services and the prices of those services) and
to sell their electric generation facilities to outside parties. This was
intended to allow customers to compare unit prices of the utilities and other
providers when selecting their energy service provider.
The Electric Industry. In 1998, California became one of the first states
in the country to implement electric industry restructuring with the goal of
establishing a competitive market framework for electric generation. The
framework for electric industry restructuring was established in Assembly Bill
1890 (AB 1890) passed by the California Legislature and signed by the Governor
in 1996 which turned over operation of the state's transmission system to the
California Independent System Operator (ISO) and the pricing of unregulated
generation to the California Power Exchange (PX). Californians were given the
choice to purchase electricity from generation providers other than the
traditional utilities (such as unregulated power generators and unregulated
retail electricity suppliers such as marketers, brokers, and aggregators). For
those customers who have not chosen an alternative generation provider,
investor-owned utilities, such as Pacific Gas and Electric Company, were to
continue to purchase electric power on their behalf. Investor-owned utilities
continue to provide distribution services to substantially all customers
within their service territories, including those customers who choose an
alternative generation provider.
3
Beginning in June 2000, the wholesale price of electric power in California
has steadily increased, reflecting a dysfunctional wholesale power market.
Under AB 1890, the Utility's electric rates were frozen at levels insufficient
to recover the Utility's cost of purchasing power for its customers. Further,
the Utility was required to buy all the power it needed to serve its customers
from the PX. The combination of these factors created a financial crisis for
the Utility and its parent, PG&E Corporation. The Utility's undercollected
power purchase costs grew to $6.6 billion at December 31, 2000. As the
Utility's creditworthiness deteriorated, the Utility was unable to continue
financing these purchases. Federal and state legislators and regulators have
recognized that the wholesale power market is seriously flawed and have been
seeking solutions to the California electricity crisis. On January 19, 2001,
the California Legislature passed and the Governor signed Senate Bill 7X which
authorized the California Department of Water Resources (DWR) to purchase
electric power for the retail end use customers of California's investor-owned
utilities through January 31, 2001. On February 1, 2001, the California
Governor signed Assembly Bill 1 (AB 1X) which was passed by the California
Legislature during a special session to take effect immediately as an urgency
statute. AB 1X authorizes the DWR to purchase power and sell that power
directly to the utilities' retail end use customers. For more information
about California electric industry restructuring, see "Utility Operations--
Electric Utility Operations--California Electric Industry Restructuring"
below.
As of December 31, 2000, 24 other states had enacted electric industry
restructuring legislation or issued comprehensive regulatory orders, including
Texas, Illinois, Pennsylvania, New Jersey, Massachusetts, Rhode Island, New
York, and Connecticut.
In October 1999, the CPUC issued a decision outlining how the CPUC, in
cooperation with other regulatory agencies and the California Legislature,
plans to address the issues surrounding distributed generation, electric
distribution competition, and the role of the utility distribution companies
(such as Pacific Gas and Electric Company) in the competitive retail
electricity market. Distributed generation enables siting of electric
generation technologies in proximity to electric load (load is a measure of
electric power consumed over time). The CPUC decision opened a new rulemaking
proceeding to examine various issues concerning distributed generation,
including interconnection issues, who can own and operate distributed
generation, environmental impacts, the role of utility distribution companies,
and the rate design and cost allocation issues associated with the deployment
of distributed generation facilities. In July 2000, the CPUC's Division of
Strategic Planning and the CPUC's Energy Division issued a report on electric
retail markets and distribution services as required by the October 1999
decision. The report proposed that if the CPUC chooses to consider expanding
or consolidating competition in the electric industry, the CPUC should (a)
separately identify utility services and establish cost-based rates for these
services, (b) consider allowing providers of billing and metering services to
market directly to customers, (c) consider allowing multiple providers of
default service, and (d) investigate whether to allow competition in certain
aspects of distribution services that utilities currently perform. There is
currently no active proceeding on electric distribution and the role of
utility distribution companies.
The Natural Gas Industry. Restructuring of the natural gas industry on both
the national and the state level has given choices to California utility
customers to meet their gas supply needs. FERC Order 636 issued in 1992
required interstate pipeline companies to divide their services into separate
gas commodity sales, transportation, and storage services. Under Order 636,
interstate gas pipelines must provide transportation service regardless of
whether the customer (often a local gas distribution company) buys the gas
commodity from the pipeline.
In August 1997, the CPUC approved the Gas Accord settlement agreement (Gas
Accord) which restructured the Utility's gas services and its role in the gas
market. Among other matters, the Gas Accord separated, or "unbundled," the
rates for the Utility's gas transmission services from its distribution
services. As a result, the Utility's customers may buy gas directly from
competing suppliers and purchase transmission-only and distribution-only
services from the Utility. Most of the Utility's industrial and larger
commercial customers (noncore customers) now purchase their gas from marketers
and brokers. Substantially all residential and smaller
4
commercial customers (core customers) buy gas as well as transmission and
distribution services from the Utility as a bundled service. For more
information about the Gas Accord and regulatory changes affecting the
California natural gas industry, see "Utility Operations--Gas Utility
Operations--Gas Regulatory Framework" below.
Regulation of PG&E Corporation
PG&E Corporation and its subsidiaries are exempt from all provisions,
except Section 9(a)(2), of the Public Utility Holding Company Act of 1935
(Holding Company Act). At present, PG&E Corporation has no expectation of
becoming a registered holding company under the Holding Company Act.
PG&E Corporation is not a public utility under the laws of California and
is not subject to regulation as such by the CPUC. However, the CPUC approval
authorizing Pacific Gas and Electric Company to form a holding company was
granted subject to various conditions related to finance, human resources,
records and bookkeeping, and the transfer of customer information. The
financial conditions provide that the Utility is precluded from guaranteeing
any obligations of PG&E Corporation without prior written consent from the
CPUC, the Utility's dividend policy shall continue to be established by the
Utility's Board of Directors as though Pacific Gas and Electric Company were a
stand-alone utility company, and the capital requirements of the Utility, as
determined to be necessary to meet the Utility's service obligations, shall be
given first priority by the Boards of Directors of PG&E Corporation and
Pacific Gas and Electric Company. The conditions also provide that the Utility
shall maintain on average its CPUC-authorized utility capital structure,
although it shall have an opportunity to request a waiver of this condition if
an adverse financial event reduces the Utility's equity ratio by 1% or more.
The CPUC also has adopted complex and detailed rules governing transactions
between California's natural gas local distribution and electric utility
companies and their non-regulated affiliates. The rules permit non-regulated
affiliates of regulated utilities to compete in the affiliated utility's
service territory, and also to use the name and logo of their affiliated
utility, provided that in California the affiliate includes certain designated
disclaimer language which emphasizes the separateness of the entities and that
the affiliate is not regulated by the CPUC. The rules also address the
separation of regulated utilities and their non-regulated affiliates and
information exchange among the affiliates. The rules prohibit the utilities
from engaging in certain practices that would discriminate against energy
service providers that compete with the utility's non-regulated affiliates.
The CPUC has also established specific penalties and enforcement procedures
for affiliate rules violations. Utilities are required to self-report
affiliate rules violations.
In connection with the Utility's November 2000 request for an emergency
rate increase, the CPUC ordered that an audit be performed. On January 31,
2001, the CPUC released the report of its consultant of the overall financial
position of the Utility, PG&E Corporation, its other affiliates, and the flow
of funds between these entities and the Utility. The report covers credit and
default relationships, power purchases and cash flows, cash conservation
activities, accounting mechanisms to track stranded cost recovery, inter-
company cash flows, affiliate earnings in the California energy market, and
other matters.
On April 3, 2001, the CPUC issued an order instituting an investigation
into whether the California investor-owned utilities, including the Utility,
have complied with past CPUC decisions, rules, or orders authorizing their
holding company formations and/or governing affiliate transactions, as well as
applicable statutes. The order states that the CPUC will investigate (1) the
utilities' transfer of money to their holding companies since deregulation of
the electric industry commenced, including times when their utility
subsidiaries were experiencing financial difficulties, (2) the failure of the
holding companies to financially assist the utilities when needed; (3) the
transfer by the holding companies of assets to unregulated subsidiaries; and
(4) the holding companies' actions to "ringfence" their unregulated
subsidiaries. The CPUC will also determine whether additional rules,
conditions, or changes are needed to adequately protect ratepayers and the
public from dangers of abuse stemming from the holding company structure. The
CPUC will investigate whether it should modify, change, or add conditions to
the holding company decisions, make further changes to the holding company
structure, alter the standards under which the CPUC determines whether to
authorize the formation of holding
5
companies, otherwise modify the decisions, or recommend statutory changes to
the California Legislature. As a result of the investigation, the CPUC may
impose remedies (including penalties), prospective rules, or conditions, as
appropriate. PG&E Corporation and the Utility believe that they have complied
with applicable statutes, CPUC decisions, rules, and orders. As described
above, on April 6, 2001, the Utility filed a voluntary petition for relief
under Chapter 11 of the U.S. Bankruptcy Code. PG&E Corporation and the Utility
believe that to the extent the CPUC seeks to investigate past conduct for
compliance purposes, the investigation is automatically stayed by the
bankruptcy filing. Neither the Utility nor PG&E Corporation can predict what
the outcome of the investigation will be or whether the outcome will have a
material adverse effect on their results of operation or financial condition.
Regulation of Pacific Gas and Electric Company
Federal Regulation
The FERC regulates electric transmission rates and access, operation of the
California ISO and the California PX, uniform systems of accounts, and
contracts involving the wholesale sale of power. The ISO has responsibility
for meeting applicable reliability criteria and assuring the maintenance of
adequate reserves. The PX, which has now suspended operations, had the
responsibility of conducting an open, efficient auction for matching energy
bids to supply with demand bids to purchase energy. Both these entities were
subject to FERC regulation of tariffs and conditions of service. In addition,
the FERC has jurisdiction over the Utility's electric transmission revenue
requirements and rates. The FERC also regulates the interstate transportation
of natural gas. Further, most of the Utility's hydroelectric facilities are
subject to licenses issued by the FERC.
On December 20, 1999, the FERC issued its final rule (Order No. 2000) on
Regional Transmission Organizations (RTOs). The order encourages utilities
owning transmission systems to form RTOs on a voluntary basis. Typically, the
establishment of these entities results in the consolidation of transmission
charges imposed by successive transmission systems into a single tariff. The
Utility is a participant in the ISO, however the FERC has not yet approved the
ISO's status as an RTO under Order No. 2000.
The Nuclear Regulatory Commission (NRC) oversees the licensing,
construction, operation, and decommissioning of nuclear facilities, including
Diablo Canyon and the nuclear generating unit at Humboldt Bay Power Plant
(Unit 3). NRC regulations require extensive monitoring and review of the
safety, radiological, and environmental aspects of these facilities.
State Regulation
The CPUC has jurisdiction to regulate the following utility functions
within California: electric distribution service, gas distribution service,
and gas transmission service. The CPUC regulates Pacific Gas and Electric
Company's rates and conditions of service, sales of securities, dispositions
of utility property, rates of return, rates of depreciation, and long-term
resource procurement. The CPUC also conducts various reviews of utility
performance and conducts investigations into various matters, such as
deregulation, competition, and the environment, in order to determine its
future policies. The CPUC consists of five members appointed by the Governor
and confirmed by the State Senate for six-year terms.
The California Energy Commission (CEC) has the responsibility to make
electric-demand forecasts for the state and for specific service territories.
Based upon these forecasts, the CEC determines the need for additional energy
sources and for conservation programs. The CEC sponsors alternative-energy
research and development projects, promotes energy conservation programs, and
maintains a statewide plan of action in case of energy shortages. In addition,
the CEC certifies power plant sites and related facilities within California.
The CEC also administers funding for public purpose research and development,
and renewable technologies programs.
Licenses and Permits
Pacific Gas and Electric Company obtains a number of permits,
authorizations, and licenses in connection with the construction and operation
of its generating plants, transmission lines, and gas compressor station
6
facilities. Discharge permits, various Air Pollution Control District permits,
United States Department of Agriculture--Forest Service permits, FERC
hydroelectric facility and transmission line licenses, and NRC licenses are
the most significant examples. Some licenses and permits may be revoked or
modified by the granting agency if facts develop or events occur that differ
significantly from the facts and projections assumed in granting the approval.
Furthermore, discharge permits and other approvals and licenses are granted
for a term less than the expected life of the associated facility. Licenses
and permits may require periodic renewal, which may result in additional
requirements being imposed by the granting agency. The Utility currently has
10 hydroelectric projects and one transmission line project undergoing FERC
license renewal.
Regulation of PG&E National Energy Group, Inc. Businesses
Federal Regulation
The rates, terms, and conditions of the wholesale sale of power by the
generating facilities owned or leased by NEG through PG&E Gen, its
subsidiaries, and affiliates, and of power contractually controlled by them is
subject to FERC jurisdiction under the Federal Power Act. Various NEG
subsidiaries and affiliates have FERC-approved market-based rate schedules and
accordingly have been granted waivers of many of the accounting, record-
keeping, and reporting requirements imposed on entities with cost-based rate
schedules. This market-based rate authority may be revoked or limited were the
FERC to conclude that the rates charged are no longer just and reasonable.
Such a conclusion could be reached were the FERC to conclude, for example,
that a NEG subsidiary or affiliate has excess market power. The FERC also
regulates the rates, terms, and conditions for electric transmission in
interstate commerce. Tariffs established under FERC regulation provide NEG
with the necessary access to transmission lines.
The FERC also licenses all of NEG's hydroelectric and pumped storage
projects. These licenses, which are issued for 30 to 50 years, will expire at
different times between 2001 and 2020. The relicensing process often involves
complex administrative processes that may take as long as 10 years. The FERC
may issue a new license to the existing licensee, issue a license to a new
licensee, order that the project be taken over by the federal government (with
compensation to the licensee), or order the decommissioning of the project at
the owner's expense.
NEG-affiliated projects are also subject to other differing federal
regulatory regimes. Those qualifying as qualifying facilities (QFs) under the
Public Utility Regulatory Policies Act of 1978 (PURPA), are exempt from the
Holding Company Act, certain rate filings, and accounting, record-keeping, and
reporting requirements that the FERC otherwise imposes and from certain state
laws. Others qualify as Exempt Wholesale Generators (EWGs) under the National
Energy Policy Act of 1992. EWGs are not regulated under the Holding Company
Act, but are subject to FERC and state regulation, including rate approval.
NEG's natural gas transmission business is also subject to FERC
jurisdiction. Certificates of public convenience and necessity have been
obtained from the FERC for construction and operation of the existing
pipelines and related facilities and properties, and application has been made
to construct the U.S. segment of the North Baja Pipeline. The rates, terms,
and conditions of the transportation and sale (for resale) of natural gas in
interstate commerce is subject to FERC jurisdiction. As necessary, NEG
subsidiaries and affiliates file applications with the FERC for changes in
rates and charges that allow recovery of costs of providing services to
transportation customers. An October 1999 order permits individually
negotiated rates in certain circumstances.
The Department of Energy also regulates the importation of natural gas from
Canada and exportation of power to Canada.
State and Other Regulations
In addition to federal laws and regulation, NEG businesses are also subject
to various state regulations. First, public utility regulatory commissions at
the state level are responsible for approving rates and other terms and
7
conditions under which public utilities purchase electric power from
independent power producers. As a result, power sales agreements, which NEG
affiliates enter into with such utilities, are potentially subject to review
by the public utility commissions, through the commissions' power to review,
for example, the process by which the utilities have entered into these
agreements. Second, state public utility commissions also have the authority
to promulgate regulations for implementing some federal laws, including
certain aspects of PURPA. Third, some public utility commissions have asserted
limited jurisdiction over independent power producers. For example, in New
York the state public utility commissions have imposed limited requirements
involving safety, reliability, construction, and the issuance of securities by
subsidiaries operating assets located in that state. Fourth, state regulators
have jurisdiction over the restructuring of retail electric markets and
related deregulation of their electric markets. Finally, states may also
assert jurisdiction over the siting, construction, and operation of NEG's
generation facilities.
In addition, the National Energy Board of Canada and the Canadian gas-
exporting provinces issue licenses and permits for removal of natural gas from
Canada which can impact customers' ability to import gas for transport over
NEG pipelines.
Other regulatory matters are described throughout this report. For a
discussion of environmental regulations to which PG&E Corporation and it
subsidiaries are subject, see the section entitled "Environmental Matters"
below.
8
UTILITY OPERATIONS
Pacific Gas and Electric Company provides regulated electric and gas
distribution and transmission services in Northern and Central California. The
Utility's service territory covers 70,000 square miles with an estimated
population of approximately 13 million and includes all or portions of 48 of
California's 58 counties. The area's diverse economy includes aerospace,
electronics, computer technology, financial services, food processing,
petroleum refining, agriculture, and tourism.
Ratemaking Mechanisms
Customer rates are determined by the FERC or the CPUC and are designed to
recover the Utility's anticipated reasonable costs and a fair rate of return.
Some rates incorporate a performance incentive mechanism by providing rewards
and penalties for meeting certain performance criteria. Some of the ratemaking
mechanisms affecting both electricity and gas distribution operations are
discussed below.
General Rate Case. The CPUC authorizes an amount, known as "base revenues,"
to be collected from ratepayers to recover the Utility's basic business and
operational costs for its gas and electric distribution operations. Base
revenues, which include non-fuel-related operating and maintenance costs,
depreciation, taxes, and a return on invested capital, currently are
authorized by the CPUC in General Rate Case (GRC) proceedings. During the GRC,
which occurs every three years, the CPUC examines the Utility's costs and
operations to determine the amount of base revenue requirement the Utility is
authorized to collect from customers through base revenues. The revenue
requirement is forecasted on the basis of a specified test year. (The return
component of the Utility's revenue requirement is computed using the overall
cost of capital authorized in other proceedings.) Following the revenue
requirement phase of a GRC, the CPUC conducts a rate design phase, which
allocates revenue requirements and establishes rate levels for the different
classes of customers. Since base revenues are determined for a three-year
period by GRCs, the Utility may apply for a yearly increase in base revenues
(known as an attrition rate adjustment) to reflect inflation and the growth in
capital investments necessary to serve customers. The 1999 and 2002 GRCs are
discussed below.
Cost of Capital. Each year, the Utility files an application with the CPUC
to determine the authorized rate of return that the Utility may earn on its
electric and gas distribution assets and recover from ratepayers. Since
February 17, 2000, the Utility's adopted return on common equity (ROE) has
been 11.22% on electric and gas distribution operations, resulting in an
authorized 9.12% overall rate of return (ROR). The Utility's earlier adopted
ROR was 10.6%. The adopted ROR for 2000 resulted in an increase of
approximately $49 million in electric and gas distribution revenues. In May
2000, the Utility filed an application with the CPUC to establish its
authorized ROR for electric and gas distribution operations for 2001. The
application requests a ROE of 12.4%, and an overall ROR of 9.75%. If granted,
the requested ROR would increase electric distribution revenues by
approximately $72 million and gas distribution revenues by approximately $23
million. The application also requests authority to implement an Annual Cost
of Capital Adjustment Mechanism for 2002 through 2006 that would replace the
annual cost of capital proceedings. The proposed adjustment mechanism would
modify the Utility's cost of capital based on changes in an interest rate
index. The Utility also proposes to maintain its currently authorized capital
structure of 46.2% long-term debt, 5.8% preferred stock, and 48% common
equity. In March 2001, the CPUC issued a proposed decision recommending no
change to the current 11.22% ROE for 2001. A final decision is expected in the
second quarter of 2001.
The return on the Utility's electric transmission-related assets is
determined by the FERC. See "Electric Transmission Rates" below. The return on
the Utility's natural gas transmission and storage business was incorporated
in rates established in the Gas Accord settlement. See "Gas Ratemaking--Gas
Accord" below.
Electric and Gas Distribution Performance-Based Ratemaking (PBR). In June
2000, the CPUC granted the Utility's request to withdraw its PBR application
filed in November 1998. The Utility had requested the withdrawal in accordance
with the 1999 GRC decision issued in February 2000, which required a 2002 GRC
before a PBR revenue/rate indexing mechanism could be implemented. In closing
the PBR proceeding, the CPUC ordered the Utility to file a new PBR application
by September 2000.
9
In September 2000, the Utility filed an application with the CPUC to
establish (1) performance standards and associated financial rewards and
penalties for electric and gas distribution service, (2) a revenue-sharing
mechanism for new categories of non-tariffed products and services (NTP&S)
offered by the Utility and (3) ratemaking for proceeds from sales or transfers
of certain non-generation related land. The performance standards would cover
a period of five years beginning January 1, 2001. The total maximum annual
reward or penalty is $54 million per year, consisting of $52 million for
electric distribution and $2 million for gas distribution. The revenue-sharing
mechanism proposes to share net positive after-tax revenues from new
categories of NTP&S equally between ratepayers and shareholders. Finally, the
Utility requested that the CPUC establish basic rules about the allocation of
gains and losses from the Utility's non-generation-related land sales. In
November 2000, the CPUC suspended the schedule in the PBR proceeding until
further order.
Electric Ratemaking
As required by AB 1890, electric rates for all customers were frozen at the
level in effect on June 10, 1996, and, beginning January 1, 1998, rates for
residential and small commercial customers were reduced by 10% from 1996
levels. The rate freeze ends the earlier of March 31, 2002, or when the
Utility has recovered its eligible transition costs (uneconomic generation-
related costs). Most transition costs must be recovered during a transition
period that ends the earlier of December 31, 2001, or when the Utility has
recovered its eligible transition costs. In 1997, the Utility, through a
special purpose entity, refinanced the expected 10% rate reduction with $2.9
billion of rate reduction bonds. At December 31, 2000, $2 billion of bonds
remained outstanding. If the transition period ends before December 31, 2001,
the Utility may be obligated to return a portion of the economic benefits of
the transaction to customers. The timing of any such return and the exact
amount of such portion, if any, have not yet been determined.
The Utility has advised the CPUC that it had recovered all of its
transition costs during August 2000 (and possibly as early as May 2000,
depending on the final valuation of the Utility's hydroelectric generating
assets and when the rate freeze is determined to have ended). The Utility has
asked the CPUC to recognize that the rate freeze already has ended for the
Utility's customers. After the rate freeze, changes in the Utility's electric
revenue requirements in general will be reflected in rates. The Utility
believes that after the rate freeze is determined to have ended, the Utility
is entitled to recover from ratepayers the costs it incurred to purchase power
on behalf of retail customers. At December 31, 2000, the balance of the
Utility's undercollected power purchase costs was $6.6 billion. PG&E
Corporation and the Utility recognized a fourth quarter charge to earnings of
$6.9 billion ($4.1 billion after tax) to reflect the fact that the Utility
could no longer conclude that its generation-related regulatory assets and
undercollected purchased power costs were probable of recovery from
ratepayers.
Rate Stabilization Plan Proceeding. Consistent with the Utility's position
that it had recovered its transition costs thus requiring an end to the rate
freeze, in November 2000, the Utility filed an application with the CPUC
seeking approval of a five-year rate stabilization plan (RSP) designed to
protect the Utility's customers from the high and volatile wholesale power
prices, while increasing rates effective January 1, 2001, to allow the Utility
to begin recovery of the Utility's past and ongoing wholesale power purchase
costs. The Utility requested that its proposed RSP rates and tariffs be
adopted by January 1, 2001, on an interim basis, subject to refund, and that
the CPUC approve the application by no later than March 31, 2001.
The Utility also proposed to defer receiving a portion of its share of
profits from its retained generation facilities, primarily from the Diablo
Canyon nuclear power plant and its hydroelectric plants, until a later time
during the five-year period and allow those funds instead to be used to offset
uncollected power purchase costs. The Utility proposed that for the next two
years (after which the Utility expects the current supply shortage will be
less critical), the Utility retain its generation facilities and sell the
output of these facilities directly to its retail distribution customers on an
incentive ratemaking basis to lower the costs of procured power for such
customers.
On January 4, 2001, the CPUC issued an emergency interim decision denying
the Utility's emergency request for a rate increase. Instead of the requested
relief, the CPUC approved a 90-day temporary rate increase of 1 cent per
kilowatt hour (kWh), subject to refund and adjustment. This rate increase,
which raises
10
approximately $70 million per month, is grossly insufficient for the Utility
to pay its ongoing procurement bills or to make further financing of these
costs possible.
On March 27, 2001, the CPUC issued a decision making the 1 cent per kWh
surcharge permanent and authorizing the Utility to add an average 3 cent per
kWh surcharge to current rates. Although the increase is authorized
immediately, the 3 cent per kWh surcharge will not be collected in rates until
the CPUC establishes an appropriate rate design for the surcharge, which is
not expected to be adopted until May 2001, at the earliest. The revenue
generated by the rate increase is to be used only for electric power
procurement costs that are incurred after March 27, 2001. The rate increase is
subject to refund (1) if not used to pay for such power purchases, (2) to the
extent that generators and sellers of power make refunds for overcollections,
or (3) to the extent any administrative body or court denies the refunds of
overcollections in a proceeding where recovery has been hampered by a lack of
cooperation from the Utility. In addition, the CPUC ordered that the 3 cent
per kWh surcharge be added to the rate paid to the DWR as adopted by the CPUC
in a companion decision discussed below.
Also on March 27, 2001, the CPUC issued a decision ordering the Utility and
the other California investor-owned utilities to pay the DWR a per-kWh price
equal to the applicable generation-related retail rate per kWh established for
each utility as in effect on January 5, 2001, for each kWh the DWR sells to
the customers of each utility. The CPUC determined that the generation-related
component of retail rates should be equal to the total bundled electric rate
(including the 1 cent per kWh interim surcharge adopted by the CPUC on January
5, 2001) less the following non-generation-related rates or charges:
transmission, distribution, public purpose programs, nuclear decommissioning,
and the fixed transition amount. The CPUC determined that the Utility's
company-wide average generation-related rate component is 6.471 cents per kWh
and that this is the amount that should be paid to the DWR for each kWh
delivered by the DWR to the Utility's retail customers after February 1, 2001,
until specific rates are calculated. The CPUC ordered the utilities to pay the
DWR within 45 days after the DWR supplies power to their retail customers,
subject to penalties for each day that payment is late. The amount of power
supplied to retail end-use customers after March 27, 2001, for which the DWR
is entitled to be paid would be based on the product of the number of kWh that
the DWR provided 45 days earlier and the Utility's company-wide average
generation-related rate of 6.471 cents per kWh, and the additional 3 cent per
kWh surcharge described above.
The CPUC also ordered that the utilities immediately pay the sums owed to
the DWR for power sold by the DWR from January 18, 2001 through January 31,
2001, under California Senate Bill 7X. Based on an estimated number of kWh
sold by the DWR, the Utility paid approximately $30 million to the DWR at the
rate of 5.471 cents per kWh as adopted by the CPUC.
As the DWR has not advised the CPUC of its revenue requirement for the
DWR's power purchases, it is unclear how much of the 3 cent surcharge will be
needed by the DWR and how much, if any, may be used by the Utility to recover
its procurement costs incurred after March 27, 2001.
General Rate Case. In February 2000, the CPUC issued a decision in the
Utility's 1999 GRC for the period 1999-2001. The decision was retroactive to
January 1, 1999. The CPUC authorized base revenues for the Utility's electric
distribution function of approximately $2.3 billion, reflecting an increase of
$377 million over base revenues authorized in 1996. In March 2000, two
intervenors filed applications for rehearing of the decision, alleging that
the CPUC committed legal errors by approving funding in certain areas that
were not adequately supported by record evidence. In April 2000, the Utility
filed its response to these applications for rehearing, defending the GRC
decision against the allegations of error. A CPUC decision on the applications
for rehearing is pending.
The 1999 GRC decision also ordered that the Utility file a 2002 GRC. In
July 2000, the CPUC issued a decision requiring the Utility to file a Notice
of Intent (NOI) with the CPUC by May 1, 2001. The CPUC decision affirms that
rates would still become effective on January 1, 2002, although the CPUC
decision may not be rendered until late 2002. In January 2001, the Utility
filed a petition with the CPUC requesting that the May 1,
11
2001 deadline for filing the NOI be suspended, asserting that many assumptions
that would have to be made in order to forecast year 2002 costs would very
likely need to be changed based on how the wholesale electricity price and
natural gas supply crises are resolved. The Utility requested that it be
allowed to file an alternative to the schedule, or to the GRC itself, by May
1, 2001. The CPUC has not acted on the Utility's January 2001 petition. On
March 27, 2001, the CPUC extended the NOI filing date by the number of days
from March 5, 2001 to 30 days after the CPUC renders a decision on the
petition. The extension will become effective only if the CPUC denies the
petition. If the CPUC grants the petition, the Utility would be allowed to
file an alternative schedule or an alternative to the GRC and the CPUC would
subsequently decide how to proceed with the case.
2001 Attrition Rate Adjustment Request. In July 2000, the Utility filed an
attrition rate adjustment application with the CPUC to increase its 2001
electric distribution revenues by $189 million, effective January 1, 2001, to
reflect inflation and the growth in capital investments necessary to serve
customers. The Utility did not request an increase in gas distribution
revenues. On December 21, 2000, the CPUC issued an interim order finding that
a decision on the merits of this application cannot be rendered by January 1,
2001, and determining that if attrition relief is eventually granted, that
relief will be effective as of January 1, 2001. Hearings are scheduled to
begin in June 2001, and a CPUC decision is expected by January 2002.
Revenue Adjustment Proceeding. The CPUC established a separate annual
proceeding, the Revenue Adjustment Proceeding (RAP), to review and verify the
amounts recorded in the Utility's Transition Revenue Account (TRA), and to
verify each electric utility's authorized revenue requirements, including any
necessary adjustments to reflect the revenue requirements which are approved
in other proceedings. The RAP also establishes revenue allocation and rate
design, and identifies all electric balancing and memorandum accounts for
continued retention or elimination. The TRA is a regulatory balancing account
that is credited with total revenue collected from ratepayers through frozen
rates. From this total revenue, the following items are subtracted: (1)
revenues collected for transmission services and for the payment of rate
reduction bond debt service, (2) the authorized revenue requirement for
distribution services, public purpose programs, and nuclear decommissioning
costs, and (3) electric industry restructuring implementation costs, energy
procurement costs, and other costs. Remaining revenues, if any, are
transferred to the Transition Cost Balancing Account (TCBA), a regulatory
balancing account that tracks recovery of transition costs, to offset
transition costs. Due to the high wholesale power costs at which the Utility
has been required to purchase power for its distribution customers since June
2000, revenues from frozen rates have been grossly insufficient to recover the
Utility's operating costs, resulting in a TRA under-collection of $6.6 billion
at December 31, 2000. On January 4, 2001, the CPUC issued a decision in the
Utility's 1999 RAP approving the transfer of $967 million of residual revenue
in the TRA to the TCBA for the period from June 1, 1998 through June 30, 1999,
and adopted a PX credit adder of .007 cents per kWh for utility customers that
elect direct access to offset the energy costs included in the bundled rate.
The Utility will file its application for its next RAP to address revenues and
costs recorded in the TRA from July 1, 1999 through at least April 30, 2001,
on or before June 1, 2001. One of the CPUC's March 27, 2001, decisions
retroactively changes the TRA and TCBA accounting mechanisms. (See "Electric
Utility Operations--Electric Industry Restructuring--New California
Legislation," below.)
Annual Transition Cost Proceeding. The Annual Transition Cost Proceeding
(ATCP), applicable to all California investor-owned electric utilities, was
established to verify the accounting and recording of costs and revenues in
the TCBA and ensure that only eligible transition costs have been entered. The
TCBA tracks the revenues available to offset transition costs, including the
accelerated recovery of plant balances, and other generation-related assets
and obligations. Transition costs will receive a limited "reasonableness"
review. On January 4, 2001, the CPUC issued a decision in the Utility's 1999
ATCP finding that $2.6 billion recorded in the TCBA from July 1, 1998 through
June 30, 1999 are eligible for recovery as transition costs. In February 2000,
the Utility's request for approval of the Hunters Point power plant
decommissioning cost was bifurcated into a separate phase and will be
addressed in a separate decision expected to be issued in the second quarter
of 2001. In September 2000, the Utility filed its 2000 ATCP application
seeking approval of amounts recorded in the TCBA and generation-related
memorandum accounts for the period July 1, 1999 through June 30, 2000.
12
As required by the CPUC, in August 2000, the Utility made a filing with the
CPUC that estimated the market value of the Utility's remaining hydroelectric
generating assets at $2.8 billion (based on a negotiated value used in a
proposed settlement discussed below under "Electric Resources--Hydroelectric
Generation Assets.") The Utility credited its TCBA by $2.1 billion, the amount
of the estimated value over the assets' book value. At the same time, the
Utility made a corresponding debit entry of the same amount in the newly
established Generation Asset Balancing Account (GABA) to prevent an immediate
charge to earnings that would have otherwise resulted from the credit to the
TCBA. The filing will become effective after appropriate review by the CPUC's
Energy Division and the TCBA entries are subject to review in the 2001 ATCP to
be filed September 1, 2001. The Utility believes that with the credit to the
TCBA, the Utility has recovered all of its transition costs as of early August
2000. If the final value of the hydroelectric assets is higher than the
estimate, the Utility believes its transition costs would have been recovered
as of an earlier date, possibly as early as May 2000. However, in a decision
issued on March 27, 2001, the CPUC has stated that with the retroactive
accounting changes adopted in the decision, the conditions for meeting the
rate freeze have not been met. See "Electric Utility Operations--Electric
Industry Restructuring--New California Legislation," below.
Electric Industry Restructuring Implementation Costs. Under AB 1890,
certain electric industry restructuring implementation costs found reasonable
by the CPUC may be recovered from electric customers. In May 1999, the CPUC
approved a multi-party settlement agreement that, among other things, permits
the Utility to recover 1997 and 1998 restructuring implementation costs of
$41.3 million (reflecting a reduction of $10 million from the Utility's
requested revenue requirement). In addition, the Utility is authorized to
recover in its TRA costs related to the Consumer Education Program and the
Electric Education Trust funded by the Utility and FERC-approved ISO and PX
development and start-up costs. At the end of the transition period, if
recovery of these restructuring implementation costs recorded in the TRA
displaces recovery of transition costs recorded in the TCBA, the Utility may
recover up to $95 million of such displaced transition costs after the
transition period.
Electric Restructuring Costs Account (ERCA). The CPUC authorized the
Utility to establish the Electric Restructuring Costs Account (ERCA) to record
the restructuring implementation costs that were removed from its 1999 GRC
revenue requirement request, any unanticipated restructuring costs incurred as
a result of directives from the CPUC or the FERC, and certain other costs. In
July 2000, the Utility filed an application seeking approval of $142.5 million
of costs recorded in the ERCA. In August 2000, protests were filed by Enron
Corporation, the CPUC's Officer of Ratepayer Advocates (ORA), and The Utility
Reform Network (TURN), challenging the evidentiary support for the costs,
among other concerns. This matter is pending.
Revenues from Must-Run Contracts. The ISO has designated certain units at
electric generation facilities as necessary to remain available to maintain
the reliability of the electric transmission system. These units are called
"must-run" units. In general, the ISO dispatches these units under cost-based
contracts regulated by the FERC that allow the owners to recover a portion of
fixed and operating costs of the must-run units. The owners of must-run units
choose among two different forms of must-run contract, both of which cover
operating costs. One form provides payments of a percentage of the unit's
fixed cost revenue requirement and does not limit market participation. The
other form provides 100% fixed cost recovery but allows only very restricted
market participation. The Utility's two remaining fossil-fueled power plants
(Hunters Point and Humboldt Bay), three of its hydroelectric generation
facilities, and a combustion turbine located at a substation in San Jose,
California, are under must-run contracts. The form of must-run contract chosen
for all of these facilities (except Hunters Point and the combustion turbine)
is the one that does not limit market participation. The Utility currently
receives approximately $91 million per year as payments under these must-run
contracts, plus fuel costs. In addition, the Utility has the opportunity to
earn market revenues for all of these plants except Hunters Point and the
combustion turbine, when the ISO has not dispatched the plant.
FERC Transmission Owner Rate Case. The ISO controls most of the state's
electric transmission facilities. The Utility serves as the scheduling
coordinator to schedule transmission with the ISO to facilitate continuing
service under wholesale transmission contracts that the Utility entered into
before the ISO was established. The ISO bills the Utility for providing
certain services associated with these contracts. These ISO charges are
referred
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to as the "scheduling coordinator costs." As part of the Utility's
Transmission Owner rate case filed at the FERC, the Utility established a
balancing account, the Transmission Revenue Balancing Account (TRBA), to
record these scheduling coordinator costs in order to recover these costs
through transmission rates. Certain transmission-related revenues collected by
the ISO and paid to the Utility are also recorded in the TRBA. Through
December 31, 2000, the Utility has recorded approximately $33 million of these
scheduling coordinator costs in the TRBA. (The Utility has also disputed
approximately $26 million of these costs as incorrectly billed by the ISO. Any
refunds that ultimately may be made by the ISO would be credited to the TRBA.)
In September 1999, a proposed decision was issued denying recovery of these
scheduling coordinator costs. The proposed decision is subject to change by
the FERC in its final decision. The FERC is expected to issue a final decision
sometime in 2001. On January 11, 2000, the FERC accepted a proposal by the
Utility to establish the Scheduling Coordinator Services (SCS) Tariff that
would act as a back-up mechanism for recovery of the scheduling coordinator
costs if the FERC ultimately decides that these costs may not be recovered in
the TRBA. The FERC also conditionally granted the Utility's request that the
SCS Tariff be effective retroactive to March 31, 1998, but the FERC suspended
the procedural schedule until the final decision is issued regarding the
inclusion of scheduling coordinator costs in the TRBA.
AB 1890 Electric Base Revenue Increase. AB 1890 provided for an increase in
the Utility's electric base revenues for 1997 and 1998, for enhancement of
transmission and distribution system safety and reliability. The CPUC
authorized a 1997 base revenue increase of $164 million. For 1998, the CPUC
authorized an additional base revenue increase of $77 million. The CPUC will
determine how much of the authorized increases were actually spent on system
safety and reliability during 1997 and 1998, and adjust the amounts downward
if necessary. The Utility claims that it overspent the 1997 authorized revenue
requirement by approximately $11.8 million and that the Utility underspent
1998 incremental revenues by approximately $6.5 million. The Utility has
proposed that the underspent amount be credited to TRA revenues. In July 1999,
the ORA recommended that $88.4 million in expenditures for 1997 and 1998 be
disallowed. In August 1999, TURN recommended an additional $14 million
disallowance for a total recommended disallowance for 1997 and 1998
expenditures of $102.4 million. The Utility opposed the recommended
disallowances and hearings were held in October 1999. It is uncertain when a
proposed decision will be issued by the CPUC. Any proposed decision would be
subject to comment by the parties and change by the CPUC before a final
decision is issued.
Electric Transmission Rates. Since April 1998, electric transmission
revenues have been authorized by the FERC, including various rates to recover
transmission costs from the Utility's former bundled retail transmission
customers. The FERC has not yet acted upon a settlement filed by the Utility
that, if approved, would allow the Utility to recover $345 million in electric
transmission rates for the 14-month period of April 1, 1998 through May 31,
1999. During that period, somewhat higher rates were collected, subject to
refund. A FERC order approving this settlement is expected by the end of 2001.
The Utility has accrued $24 million for potential refunds related to the
period ended May 31, 1999. In April 2000, the FERC approved a settlement that
permits the Utility to recover $264 million in electric transmission rates
retroactively for the 10-month period from May 31, 1999 to March 31, 2000. In
September 2000, the FERC approved another settlement that permits the Utility
to recover $340 million annually in electric transmission rates and made this
retroactive to April 1, 2000. Further, in November 2000, the FERC accepted,
subject to refund, the Utility's proposal to collect $397 million in electric
transmission rates beginning on May 6, 2001.
Post-Transition Period Ratemaking Proceeding. In October 1999, the CPUC
issued a decision in the Utility's post-transition period ratemaking
proceeding. Among other matters, the CPUC decision prohibits the Utility from
collecting after the rate freeze any costs incurred during the rate freeze but
not recovered during the rate freeze, including costs that are not transition
costs and not related to generation assets such as undercollected wholesale
power purchase costs incurred on behalf of retail distribution customers. In
November 2000, the California Supreme Court denied the Utility's petition for
review of an appellate decision that had denied the Utility's petition for
review of the CPUC's decision. The Utility has filed a complaint against the
CPUC in federal court requesting the court to declare that the Utility is
permitted as a matter of federal law to recover from distribution customers
the wholesale power purchase costs it has incurred to purchase power on their
behalf. For more information, see "Item 3--Legal Proceedings," below.
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In the October 1999 decision, the CPUC also established the Purchased
Electric Commodity Account (PECA) for the Utility to track energy costs after
the rate freeze and transition period end. In June 2000, the CPUC issued a
decision in which the CPUC determined that the PECA would reflect a pass-
through of energy costs, possibly subject to after-the-fact reasonableness
reviews. The decision states that after the rate freeze ends, there will be
rate proceedings that will, among other matters, address electric energy
procurement practices and rates.
Gas Ratemaking
Gas Accord. The Gas Accord separated or "unbundled" the Utility's gas
transmission services from its distribution services, changed the terms of
service and rate structure for gas transportation, increased the opportunity
for core customers to purchase gas from competing suppliers, established a
form of incentive mechanism to measure the reasonableness of core procurement
costs, and established gas transmission and storage rates through 2002. In
November 2000, the Utility filed an advice letter requesting authorized
increases in the rates established for 2001 by the Gas Accord. Additional
information about the Gas Accord is provided below in "Utility Operations-Gas
Utility Operations."
General Rate Case. In February 2000, the CPUC issued a decision in the
Utility's GRC for the period 1999-2001. The decision is retroactive to January
1, 1999. The CPUC authorized base revenues for the Utility's gas distribution
function, including public purpose programs, of approximately $892 million,
reflecting an increase of approximately $93 million over base revenues
authorized in 1996. Revised gas transportation rates reflecting the revenue
changes resulting from the GRC and other regulatory proceedings were effective
March 1, 2000. (For a discussion of the 2002 GRC, see above under "Electric
Ratemaking.")
The Core Fixed Cost Account (CFCA) is the regulatory balancing account that
matches gas distribution and storage authorized revenue to the actual revenue
collected from core customers. During May 2000, the Utility refunded
approximately $320 million to core gas customers to reduce an over-collection
in the CFCA. Since the volumes of gas delivered to core customers during the
1998 and 1999 winter seasons were higher than the forecasted volumes used to
set the rates, an over-collection resulted. Beginning in December 2000,
storage activity is recorded in a new procurement balancing account, Core Firm
Storage Account, instead of in the CFCA, and are included in monthly core
procurement rates.
Gas Procurement Costs. The Utility procures gas for more than 90 percent of
its core customers. The Utility passes on the natural gas costs it incurs on
behalf of customers to ratepayers. The core procurement rate is set monthly
based on the forecasted cost of gas. Gas procurement activity is recorded in
the Purchased Gas Account (PGA). The PGA matches the actual gas commodity
costs to the revenue collected from customers. Over- or under-collections in
the PGA are collected or returned to customers through an adjustment to the
gas procurement rate in subsequent months.
The Biennial Cost Allocation Proceeding (BCAP). The BCAP remains the
proceeding in which distribution costs and balancing account balances are
allocated to customers. The BCAP normally occurs every two years and is
updated in the interim year for purposes of amortizing any accumulation in the
balancing accounts. Balancing accounts for gas distribution and public purpose
program revenue requirements accumulate differences between authorized revenue
requirements and actual base revenues. In April 2000, the Utility filed its
2000 BCAP application to cover the period of January 1, 2000 through December
31, 2002, requesting a decrease in the annual base revenue requirement of $132
million compared to the authorized revenue requirement of $941 million at the
time the application was filed. On October 27, 2000, the Utility filed with
the CPUC a settlement agreement between the Utility and various parties and
groups representing noncore industrial, electric generation, and co-generation
customers. The settlement agreement resolved all issues relating the 2000 BCAP
application raised by parties regarding customer throughput, marginal costs,
the allocation of balancing account balances, and core and noncore rate
design. If the settlement is adopted, there would be a decrease in the base
revenue requirement of approximately $113 million, subject to adjustment for
the most recent balancing account balances and CPUC decisions in place when
the CPUC acts on the proposed settlement. A decision is expected in the third
quarter of 2001.
15
Public Purpose Programs
Under state law, the Utility is authorized to collect not less than $198
million in a separate nonbypassable charge included in frozen electric rates
to fund Utility and other entities' investments in four public purpose
programs: (1) cost-effective energy efficiency and energy conservation
programs, (2) research, development and demonstration programs, (3) renewable
energy resources programs, and (4) low-income electricity programs including
targeted energy efficiency services and rate discounts. Low-income energy
efficiency programs are funded at the level of need, but are not to be funded
at less than the 1996 level of expenditures. The Utility is obligated to fund
through electric rates energy efficiency and conservation programs in an
amount not less than $106 million per year, public interest research and
development programs at not less than $30 million per year, renewable energy
technologies at not less than $48 million per year, and low-income energy
efficiency programs at not less than $14 million per year. The Utility also
collects funds for the California Alternate Rates for Energy (CARE) low-income
discount rate, a rate subsidy paid for by the Utility's other customers, which
is currently about $31 million per year.
Under the oversight of the CPUC, the Utility administers both the cost-
effective energy efficiency and low-income energy efficiency programs. These
two programs are reviewed annually in the Annual Earnings Assessment
Proceeding (AEAP). In March 1999, the CPUC determined that these programs
should continue to be administered by investor-owned utilities, subject to
CPUC oversight, through 2001. Effective January 1, 2000, Section 327 of the
California Public Utilities Code requires utilities to continue to administer
low-income energy efficiency programs. The California Energy Resources
Conservation and Development Commission (also called the California Energy
Commission (CEC)) administers both the public interest research and
development program and the renewable energy program on a statewide basis. The
Utility transfers $78 million per year to the CEC for these two programs.
In October 2000, the California Legislature passed and the Governor signed
legislation extending the existing surcharge on electricity to fund public
purpose energy efficiency, renewable energy, and research development and
demonstration programs for another 10 years, beginning January 1, 2002.
The AEAP determines shareholder incentives to be earned for the Utility's
demand side management (DSM) programs. The 1999 AEAP determines shareholder
incentives to be earned for the Utility's pre-1998 DSM activities and 1998 and
later energy efficiency programs. The Utility was authorized in 2000 to
collect $15.67 million for pre-1998 DSM earnings, $0.11 million for Program
Year (PY) 1998 Low-Income Energy Efficiency (LIEE) earnings, and $10.45
million for PY 1998 non-LIEE earnings. After consolidating the adjusted
incentive payment installments from prior years, the net revenue change in
2000 from shareholder incentives should be an electric increase of
approximately $3.4 million and a gas decrease of approximately $1.5 million.
In May 2000, the Utility filed its 2000 AEAP application seeking to recover
approximately $53 million of shareholder incentives for attainment of
milestones for PY 1999 energy efficiency programs, and for achieving savings
for PY 1998 and 1999 LIEE programs and for DSM accomplishments related to pre-
1998 program commitments. In October 2000, the CPUC postponed the proceedings
until further notice.
Electric Utility Operations
Electric Industry Restructuring
The goal of California electric industry restructuring (AB 1890) was to
open up the electric generation function of traditional utilities to
competition to give electric customers of investor-owned utilities (such as
Pacific Gas and Electric Company) the choice of continuing to purchase
electric power from investor-owned utilities or purchasing electric power from
alternative providers (including independent power generators and retail
electricity providers such as marketers, brokers, and aggregators). Purchasing
electric power from an alternative generation provider is called "direct
access." Beginning March 31, 1998, customers were permitted to choose direct
access. For those customers who did not choose direct access, investor-owned
utilities were to continue to purchase electric power on their behalf.
Investor-owned utilities continue to provide distribution services to
substantially all customers within their service territories, including those
customers who choose direct access. During the transition period, the
California investor-owned utilities were required to sell into the
16
PX all of their generated electric power. "Must-take" generation resources,
such as nuclear generation from Diablo Canyon, electric power generated by QFs
and electricity that the Utility is required to purchase under existing
contractual commitments, were also required to be scheduled through the PX.
These "must take" resources were bid into the PX at $0 per megawatt-hour (MWh)
to ensure that these resources are used to meet demand. During the transition
period, the California investor-owned utilities also were required to buy
power on behalf of their retail customers through the PX. Following the
divestiture of much of their power generation facilities in connection with
electric industry restructuring, the majority of the power purchased through
the PX was supplied by third party generators. The CPUC did not permit the
utilities to buy power directly from third parties through bilateral
agreements until August 2000.
California Power Crisis. California has endured a power crisis as demand
for power far outstripped supply. Since June 2000, wholesale power prices in
California have steadily increased to an average cost of 18.16 cents per kWh
for the seven month period of June 2000 through December 2000, as compared to
an average cost of 4.23 cents per kWh for the same period in 1999. During
2000, the Utility collected only approximately 5.4 cents per kWh through
frozen rates for the recovery of its wholesale power costs. Many factors have
contributed to the high wholesale power prices, including:
. Economic and population growth in California.
. A lack of new power supplies to meet the growing demand.
. A substantial increase in natural gas prices. Since many power plants
serving California are natural gas fired, the natural gas prices paid by
generators in producing electricity are reflected in the price of power
charged by the generators.
. Limited availability of hydroelectric power due to dryer than usual
conditions.
. Uncoordinated power plant outages due to scheduled maintenance or
unplanned outages.
. Dysfunctional power markets that produced unjust and unreasonable price
levels.
. The tendency of frozen retail rates to eliminate the incentive for
customers to conserve energy and reduce demand.
. Delays in regulatory approvals to permit the California investor-owned
utilities to enter into long-term power purchase contracts as a hedge
against price fluctuations. After permission was given in August 2000,
there have been further delays in regulatory approvals of reasonableness
standards for entering into bilateral contracts.
FERC Order. On December 15, 2000, the FERC issued an order adopting
remedies for what the FERC characterized as the seriously flawed electric
power markets in California. Among other matters, the FERC:
. Eliminated, effective December 15, 2000, the requirement that the
California investor-owned utilities sell all of their generation into and
buy all of their energy needs from the PX, which results in over reliance
on spot market (i.e., real-time) purchases. The order encourages the
utilities to meet their purchase power needs through bilateral long-term
contracts of two years or more and to adopt a balanced portfolio of
contracts to mitigate cost exposure. To encourage the execution of
bilateral contracts, the order requires the PX's rate schedules to
terminate effective at the close of business on April 30, 2001.
. Adopted a price benchmark at $74 per MWh for assessing prices of five-
year energy supply contracts to be used by the FERC in assessing any
complaints regarding justness and reasonableness of pricing long-term
contracts.
. Permitted penalties to be imposed on market participants who do not
schedule at least 95% of their load in advance of the ISO's real-time
market (through self-scheduling, bilateral contracts, or the PX markets),
to reduce the reliance on the ISO's real-time market to meet supply. A
penalty charge will be assessed when more than 5% of a market
participant's load is scheduled into the ISO's real-time market.
Penalties are to be disbursed to other market participants who schedule
their load properly. The FERC order does not contain provisions for
penalties to be imposed on generators who do not schedule in advance.
17
. Established an interim $150 per MWh "soft cap" modification of the single
price auction so that bids above $150 MWh will not set the market
clearing prices paid to all bidders at or below $150 per MWh. Bids above
the $150 MWh level will trigger certain weekly reporting requirements and
FERC monitoring. These price provisions will be in effect until April 30,
2001.
. Deferred the consideration of retroactive refund issues linked to
protective orders associated with the volatile prices experienced in
California this past summer. Although the period for potential refund
liability continues until December 31, 2002, with respect to specific
transactions, refund potential on a transaction will close after 60 days
unless the FERC has issued written notification to the seller that its
transaction is still under review.
PG&E Corporation and the Utility believe the actions outlined in the order
will not provide a complete solution that ensures reliability of the state's
electric supply and relief from future price increases, particularly since the
FERC order fails to require sellers to enter into forward contracts at
reasonable prices, and fails to provide an effective price cap. In addition,
the FERC order does not address issues associated with retroactive refund and
retroactive remedial authority issues. The Utility has filed a request for
rehearing of the FERC's order to the extent that it does not provide effective
mitigation of prices. In March 2001, the FERC ordered refunds of $68.7 million
for January 2001 and subsequently ordered refunds of $55 million for February
2001 and indicated it would continue to review December 2000 wholesale prices.
The generators have appealed the decision, and will supply cost justification.
Any refunds will be offset against amounts owed the generators.
The California Independent System Operator and the California Power
Exchange. The PX and the ISO, both California public benefit non-profit
corporations, began operating on March 31, 1998, as provided for under AB
1890. The FERC has jurisdiction over both the ISO and the PX. Pursuant to the
FERC order of December 15, 2000, the ISO Board of Governors, which included
representatives of market participants, was replaced with a non-stakeholder
board who are independent of market participants.
The ISO operates and controls most of the state's electric transmission
facilities (which continue to be owned and maintained by the California
utilities) and provides comparable open access to electric transmission
service. The ISO accepts balanced schedules for supply and load from
scheduling coordinators, including the PX and the Utility, and market
participants and manages the availability of electric transmission on a
statewide basis for these transactions. The ISO also purchases necessary
generation and ancillary services on a real-time basis to maintain grid
reliability. The ISO is required to ensure reliable transmission services
consistent with planning and operating reserve criteria no less stringent than
those established by the Western Systems Coordinating Council and the North
American Electric Reliability Council. Oversight of utility distribution
systems remains with the CPUC.
Until January 31, 2001, the PX provided an auction process, intended to be
competitive, to establish hourly transparent market clearing prices for
electricity in the markets operated by the PX. The PX operated two markets:
the day-ahead market where market participants purchase power for their
customers' needs on the following day and the day-of-or hour-ahead market
where market participants purchase power needed to serve their customers on
the same day. The PX set a market-clearing price for electricity by matching
all demand bids (the amount of energy that an eligible customer is willing to
purchase and the maximum price that the customer is willing to pay) with
supply bids (the price at which a seller is prepared to sell energy) ranked
from lowest to highest. The highest-accepted generation supply bid used to
serve load set the PX market-clearing price for electricity. The market-
clearing price then became the single cost for electricity throughout
California for that energy delivery hour. Due to downgrades in the Utility's
credit ratings and the Utility's alleged failure to post collateral for all
market transactions, the PX suspended the Utility's market trading privileges
as of January 19, 2001. On January 31, 2001, the PX suspended its day-of and
day-ahead markets in response to the FERC's order directing the PX to comply
with the terms of its December 15, 2000 order and implement a $150 per MWh
"soft" price cap. The FERC ordered the PX to recalculate all PX transactions
since December 15, 2000. The PX subsequently filed for bankruptcy protection.
18
In May 1999, the PX obtained FERC approval to operate the block forward
market (BFM), an exchange that matches bids to buy power with offers to sell
power more than one day in advance of the contracted delivery date. In July
1999, the Utility obtained CPUC authority to participate in the BFM for
contracts that called for delivery by October 31, 2000 and subject to a volume
limit. In March 2000, the CPUC raised the volume limit to permit the Utility
to cover its "net open position" (the amount of power to meet the Utility's
customers' needs that can not be met with Utility-owned generation or power
under contract to the Utility) and affirmed that all PX purchases made during
the transition period are deemed reasonable. The CPUC also expanded the
Utility's authority to participate in the BFM through the end of the
transition period. Participation in the BFM lessened after the FERC's December
15, 2000 order, discussed above. The PX sought to liquidate the Utility's BFM
contracts for the purchase of power. On January 25, 2001, a California
Superior Court judge granted the Utility's application for a temporary
restraining order, which thereby restrained and enjoined the PX from
liquidating the Utility's contracts, pending a hearing on a preliminary
injunction on February 5, 2001. Immediately before the hearing, California
Governor Gray Davis, acting under California's Emergency Services Act,
commandeered the contracts for the benefit of the State. Under the Act, the
State must pay the Utility the reasonable value of the contracts, although the
PX may seek to recover the monies that the Utility owes to the PX from any
proceeds realized from those contracts. The Utility has filed a claim with the
California Victim Compensation and Government Claims Board which will be heard
with other claims filed by the PX.
New California Legislation. Some generation providers refused to sell power
into the California markets based on their concern as to the credit quality of
the California investor-owned utilities whose rates were still frozen. The
Secretary of the U.S. Department of Energy (DOE) ordered such providers to
continue selling into the California markets on request by the ISO. On January
18, 2001, the California Assembly passed Senate Bill 7X that appropriated $400
million and authorized the DWR to use such funds to purchase power at no more
than 5.5 cents per kWh (far less than the current wholesale market rates in
early 2001) and then resell it to the Utility at cost to enable the Utility to
continue to serve its customers. The DWR was authorized to purchase power
through January 31, 2001. On February 1, 2001, the California Governor signed
Assembly Bill No. 1 (AB 1X) which was passed by the California Legislature
during a special session to take effect immediately as an urgency statute. AB
1X authorizes the DWR to enter into contracts for the purchase of electric
power for such periods and at such prices as the DWR deems appropriate
consistent with the objectives of AB 1X to have an overall portfolio of
contracts resulting in reliable service at the least cost. AB 1X prohibits the
DWR from entering into any contract after January 1, 2003. AB 1X requires the
DWR to sell power that it purchases directly to retail end use customers,
except as may be necessary to maintain system integrity.
AB 1X provides that the DWR will retain title to the power it purchases and
that payment for any sale of power by the DWR is a direct obligation of retail
end use customers to the DWR. The DWR may contract with the electric utilities
for the electric utilities to transmit and distribute the power purchased and
sold by the DWR and to provide billing, collection, and other related
services, as agent of the DWR, on terms that reasonably compensate the
utilities. AB 1X does not authorize the DWR to take ownership of transmission,
generation, or distribution assets of any electric utility. AB 1X states it
shall not be construed (1) to reduce or modify any electrical corporation's
obligation to serve, or (2) to obligate the DWR for any procurement cost
obligations of the utilities that existed before January 31, 2001.
AB 1X authorizes the CPUC to set rates to cover revenue requirements of
DWR's power purchasing program, but prohibits the CPUC from increasing
electric rates for residential customers who use less power than 130% of their
existing baseline quantities, until the DWR has recovered the costs of power
it has purchased for retail customers.
On March 27, 2001, the CPUC issued a decision in which it noted that
although the DWR has assumed responsibility to purchase some of the utilities'
power requirements, it has not committed to purchase all of the utilities' net
open position, i.e., the power needs of the retail electric customers that
cannot be met by utility-owned generation or power under contract to the
utilities. To the extent the DWR does not buy enough power to cover the
Utility's net open position, the ISO purchases emergency power on the high-
priced spot market to meet system reliability requirements and the net open
position. The ISO may attempt to charge the
19
Utility a proportionate share of the ISO's purchases. The Utility believes
that under the current circumstances and applicable tariffs it is not
responsible for such ISO charges.
In addition, on April 3, 2001, the CPUC adopted a method to calculate the
California Procurement Adjustment, as described in Public Utilities Code
Section 360.5 (added by Assembly Bill 1X). Section 360.5 requires the CPUC to
determine (1) the portion of each electric utility's electric retail rate
effective on January 5, 2001, the "California Procurement Adjustment" or CPA,
that is equal to the difference between the generation-related component of
the utility's retail rate in effect on January 5, 2001, and the sum of the
costs of the utility's own generation, QF contracts, existing bilateral
contracts (i.e., entered into before February 1, 2001), and ancillary
services, and (2) the amount of the CPA that is allocable to the power sold by
the DWR. The CPUC decided that the CPA should be a set rate calculated by
determining each utility's generation-related revenues (for the Utility the
CPUC has proposed that this be equal to 6.471 cents per kWh multiplied by
total kWh sales by the Utility to the Utility's retail customers), then
subtracting each utility's statutorily authorized generation-related costs,
and dividing the result by each utility's total kWh sales. Each utility's CPA
rate will be used to determine the amount of bonds the DWR may issue.
Using the CPUC's methodology, but substituting the CPUC's cost assumptions
with actual expected costs and including costs the CPUC has refused to
recognize, the Utility's calculations show that the CPA for the 11-month
period February through December 2001 would be negative by $2.2 billion,
(i.e., there would be no CPA available to the DWR) assuming the DWR purchases
84 percent of the Utility's net open position. If AB 1X were amended to also
include in the CPA all the incremental revenue from the 3 cent per kWh
increase discussed above (approximately $2.3 billion for 11 months), then the
amount available to the DWR for the CPA for the comparable 11-month period,
assuming the Utility were allowed to recover its costs first, would be
approximately $100 million. The Utility believes the method adopted by the
CPUC is unlawful and inconsistent with Section 360.5 because, among other
reasons, it establishes a set rate that does not reflect actual residual
revenues, overstates the CPA by excluding and/or understating authorized
costs, and to the extent it is dedicated to the DWR does not allow the Utility
to recover its own revenue requirements and costs of service. The Utility has
filed an application for rehearing of the decision.
Recovery of Transition Costs, Wholesale Power Purchase Costs, and End of
Rate Freeze. Based on the premise that market-based revenues would not be
sufficient to recover the utilities' uneconomic generation costs, AB 1890
provides the investor-owned utilities the opportunity to recover their
transition costs during a transition period ending the earlier of December 31,
2001, or when the particular utility has recovered its transition costs. Some
transition costs may be recovered after the transition period. Costs eligible
for recovery as transition costs, as determined by the CPUC, include (1)
above-market sunk costs (i.e., costs associated with utility generating
facilities that are fixed and unavoidable and that were included in customer
rates on December 20, 1995) and future sunk costs, such as costs related to
plant removal, (2) costs associated with long-term contracts to purchase power
at above-market prices from QFs and other power suppliers, and (3) generation-
related regulatory assets and obligations. (In general, regulatory assets are
expenses deferred in the current or prior periods to be included in rates in
subsequent periods.) The Utility tracks the recovery of its transition costs
in its TCBA.
Transition costs may be recovered only through the competition transition
charge (CTC) (the amount of revenues remaining after paying authorized
operating costs), the excess of market value of generating assets over book
value, and retained generation revenues. Due to the high wholesale power
prices the Utility has been required to pay to purchase power for its
customers, revenues from frozen rates since June 2000 have been insufficient
to provide any CTC revenues.
Under current CPUC decisions, if undercollected power purchase costs
recorded in the TRA are not recovered through frozen rates by the end of the
transition period, they cannot be recovered or offset against over-collections
of transition costs. The Utility has filed a lawsuit in federal district court
against the CPUC challenging these decisions. See "Item 3--Legal Proceedings,"
below.
Under AB 1890, when the Utility has recovered its eligible transition
costs, the conditions for terminating the rate freeze and ending the
transition period will have been satisfied. At August 31, 2000, consistent
with
20
transition period accounting mechanisms adopted by the CPUC, the Utility
credited its TCBA by $2.1 billion, the amount by which a negotiated $2.8
billion hydroelectric generation asset valuation exceeded the aggregate book
value of such assets. Based on this credit, the Utility believes it recovered
its eligible transition costs during August 2000. At August 31, 2000, there
was a balance of approximately $2.2 billion of undercollected wholesale power
costs recorded in the TRA. If the final valuation for the hydroelectric assets
is greater than $2.8 billion, as the Utility expects, the Utility believes it
will have recovered its transition costs possibly as early as May 2000. The
undercollected TRA balance as of the end of the earlier determined transition
period will be less than the $2.2 billion August 31, 2000 balance and could be
zero depending on the ultimate valuation of the hydroelectric assets and when
the transition period actually ends. Under current CPUC decisions and AB 1890,
the Utility's customers are responsible for wholesale power purchase costs
after the Utility has recovered its transition costs.
In one of its March 27, 2001 decisions, the CPUC adopted TURN's proposal to
transfer on a monthly basis the balance in each utility's TRA to the utility's
TCBA. The accounting changes are retroactive to January 1, 1998. The Utility
believes the CPUC is retroactively transforming the undercollected power
purchase costs in the TRA into transition costs in the TCBA. However, the CPUC
characterized the accounting changes as merely reducing the prior revenues
recorded in the TCBA, thereby affecting only the amount of transition cost
recovery achieved to date. The CPUC also ordered that the utilities restate
and record their generation memorandum accounts balances to the TRA on a
monthly basis before any transfer of generation revenues to the TCBA. The CPUC
found that based on the accounting changes, the conditions for meeting the end
of the rate freeze have not been met.
The Utility believes the adoption of TURN's proposed accounting changes
results in illegal retroactive ratemaking and constitutes an unconstitutional
taking of the Utility's property, and violates the federal filed rate
doctrine. The Utility also believes the other CPUC decisions are similarly
illegal to the extent they would compel the Utility to make payments to the
DWR and QFs without providing adequate revenues for such payments. The Utility
plans to challenge the decisions in appropriate legal forums.
PG&E Corporation and the Utility recognized a fourth quarter charge to
earnings of $6.9 billion ($4.1 billion after tax) to reflect the fact that the
Utility could no longer conclude that its generation-related regulatory assets
and undercollected purchased power costs were probable of recovery from
ratepayers. Further, absent a regulatory judicial, or legislative solution,
the Utility cannot conclude that any power purchase costs it incurs during
2001 in excess of revenues from retail rates are probable of recovery through
future rates.
Retail Direct Access. Customers participating in direct access may purchase
their electric power directly either through (1) competing non-utility retail
electric providers such as brokers, marketers, aggregators, or other
retailers, or (2) direct negotiated contracts with electric generators. Energy
service providers (ESPs) supplying the direct access market had three billing
options: (1) consolidated energy supplier billing, under which the utility
bills the energy supplier for the services provided directly by the utility to
the customer, and the supplier, in turn, provides a consolidated bill to the
customer, (2) consolidated distribution company billing, under which the
utility places the supplier's energy charge on a distribution bill, or (3)
dual billing, under which the energy supplier and the utility bill separately
for their own services. All customers (with limited exceptions), whether they
choose direct access or not, were required to pay the nonbypassable CTC to be
collected by their distribution utility in connection with recovery of the
utilities' transition costs. The majority of direct access customers have been
small commercial and large industrial customers. In light of the California
electricity crisis, many ESPs have returned their direct access customers to
Utility service. As of March 30, 2001, the Utility only had 36,641 direct
access customers. AB 1X provides that, at a time to be determined by the CPUC,
the right of retail customers to procure service from other ESPs will be
suspended until the DWR no longer supplies power for retail end use customers.
There may be further legislation to address direct access.
Pursuant to CPUC regulations, the Utility has provided a PX energy credit
to direct access customers. As wholesale power prices began to increase
beginning in June 2000, the level of PX credits increased correspondingly to
the point where the credits exceeded the Utility's distribution and
transmission charges to direct access customers. Although the Utility paid
approximately $39 million in PX credits, the Utility has ceased
21
paying these credits. The Utility believes whether these credits are owed, and
if so in what amount, may be affected by the resolution of when the rate
freeze ended (the Utility believes its rate freeze ended as early as May 2000
depending on the final valuation of the Utility's hydroelectric generating
assets) and by whether the FERC ultimately orders refunds of wholesale prices
which have been found by the FERC to be unjust and unreasonable. As of March
29, 2001, the estimated total of accumulated credits potentially owing to
direct access customers that have not been paid by the Utility may be as high
as $503 million. Three ESPs have filed complaints against the Utility at the
CPUC arguing that the Utility violated CPUC orders and demanding payment for
credits accumulated for their customers. The large PX credits have reduced
revenues which, along with high PX costs, have contributed to the under-
collection in the Utility's TRA.
22
Electric Operating Statistics
At December 31, 2000, the Utility served approximately 4.6 million electric
distribution customers.
The following table shows the Utility's operating statistics (excluding
subsidiaries) for electric energy sold, including the classification of sales
and revenues by type of service. Before August 2000, the Utility was required
to buy from the PX all electricity needed to provide service to retail
customers that continue to choose the Utility as their electricity supplier.
2000 1999 1998 1997 1996
---------- ---------- ---------- ---------- ----------
Customers (average for
the year):
Residential............ 4,071,794 4,017,428 3,962,318 3,915,370 3,874,223
Commercial............. 471,080 474,710 469,136 465,461 459,001
Industrial............. 1,300 1,151 1,093 1,121 1,248
Agricultural........... 78,439 85,131 85,429 86,359 87,250
Public street and
highway lighting...... 23,339 20,806 18,351 17,955 17,583
Other electric
utilities............. 8 0 14 47 28
---------- ---------- ---------- ---------- ----------
Total................. 4,645,960 4,599,226 4,536,341 4,486,313 4,439,333
========== ========== ========== ========== ==========
Sales-kWh (in millions):
Residential............ 28,753 27,739 26,846 25,946 25,458
Commercial............. 31,761 30,426 28,839 28,887 27,868
Industrial(1).......... 16,899 16,722 16,327 16,876 15,786
Agricultural(1)........ 3,818 3,739 3,069 3,932 3,631
Public street and
highway lighting...... 426 437 445 446 438
Other electric
utilities............. 266 167 2,358 3,291 1,213
---------- ---------- ---------- ---------- ----------
Total energy
delivered............ 81,923 79,230 77,884 79,378 74,394
========== ========== ========== ========== ==========
Revenues (in thousands):
Residential............ $3,007,675 $2,961,788 $2,891,424 $3,082,013 $3,033,613
Commercial............. 2,693,316 2,837,111 2,793,336 2,932,560 2,840,101
Industrial............. 509,486 863,951 933,316 1,028,378 1,005,694
Agricultural........... 385,961 391,876 350,445 413,711 396,469
Public street and
highway lighting...... 43,403 49,209 51,195 53,183 55,372
Other electric
utilities............. 26,269 16,501 50,166 118,781 81,855
Revenues from energy
deliveries........... 6,666,110 7,120,436 7,069,882 7,628,626 7,413,104
Miscellaneous.......... 194,947 162,105 161,156 (9,439) 112,303
Regulatory balancing
accounts.............. (6,765) (50,780) (40,408) 71,441 (365,192)
---------- ---------- ---------- ---------- ----------
Operating revenues.... $6,854,292 $7,231,761 $7,190,630 $7,690,628 $7,160,215
========== ========== ========== ========== ==========
The following table shows certain customer information:
2000 1999 1998 1997 1996
Selected Statistics: ---------- ---------- ---------- ---------- ----------
Average annual
residential usage
(kWh)................. 7,062 6,905 6,776 6,627 6,571
Average billed revenues
per kWh (cents per
kWh):
Residential........... 10.46 10.68 10.77 11.88 11.92
Commercial............ 8.48 9.32 9.69 10.15 10.19
Industrial(1)......... 3.02 5.17 5.72 6.09 6.37
Agricultural(1)....... 10.11 10.48 11.42 10.52 10.92
Net plant investment
per customer ($)...... 1,969 2,388 2,705 3,027 3,198
- --------
(1) Beginning April 1998, the sales-kWh and average billed revenues per kWh
include electricity provided to direct access customers where the Utility
does not earn commodity charges.
23
Electric Resources
The Utility's sources of generation during 2000 were as follows: 15% from
the Utility's hydroelectric assets, 21% from the Utility's nuclear facilities
at Diablo Canyon, 1% from the Utility's fossil-fueled plants, and 63% from QFs
and other power suppliers. In 1995, the CPUC issued a decision which required
the Utility to "file a plan to voluntarily divest [itself] of at least 50% of
[its] fossil generating assets." As an incentive to divest, the CPUC reduced
the rate of return on the Utility's generating assets, including its
hydroelectric generation assets and Diablo Canyon, to 6.77%. The Utility has
sold all but two of its fossil-fueled electric generating plants and has sold
all of its geothermal generating facilities. The Utility's own generation
resources and contracted for generation resources serve approximately 36% of
the Utility's retail electric customers.
Until December 15, 2000, the Utility was required to sell all of its owned
generation, and generation purchased by the Utility under long-term contracts
with QFs and other power providers, to the PX. The December 15, 2000 FERC
order eliminated the requirement that the California investor-owned utilities
sell all of their generation into (and buy all of their energy needs from) the
PX. The PX suspended the Utility's trading privileges on January 19, 2001 and
the PX markets were suspended as of January 31, 2001. Since January 31, 2001,
the Utility has been scheduling its own generation through the ISO for use by
the Utility's customers. The remainder of the power needed to serve the
Utility's customers has been purchased by the DWR or the ISO.
Generating Capacity
Except as otherwise noted below, as of December 31, 2000, Pacific Gas and
Electric Company owned and operated the following generating plants, all
located in California, listed by energy source:
Number Net
of Operating
Generation Type County Location Units Capacity kW
--------------- --------------- ------ -----------
Hydroelectric:
Conventional Plants....... 16 counties in Northern and 107 2,684,100
Central California
Helms Pumped Storage
Plant.................... Fresno 3 1,212,000
--- ---------
Hydroelectric Subtotal.. 110 3,896,100
--- ---------
Steam Plants:
Humboldt Bay.............. Humboldt 2 105,000
Hunters Point(1).......... San Francisco 3 377,000
--- ---------
Steam Subtotal.......... 5 482,000
--- ---------
Combustion Turbines:
Hunters Point(1).......... San Francisco 1 52,000
Mobile Turbines(2)........ Humboldt and Mendocino 3 45,000
--- ---------
Combustion Turbines
Subtotal............... 4 97,000
--- ---------
Nuclear:
Diablo Canyon............. San Luis Obispo 2 2,174,000
--- ---------
Total................... 121 6,649,100
=== =========
- --------
(1) In July 1998, the Utility reached an agreement with the City and County of
San Francisco regarding the Hunters Point fossil-fueled power plant, which
the ISO has designated as a "must run" facility. The agreement expresses
the Utility's intention to retire the plant when it is no longer needed by
the ISO.
(2) Listed to show capability; subject to relocation within the system as
required.
The Utility is interconnected with electric power systems in 14 Western
states, Alberta and British Columbia, Canada, and Mexico.
24
Hydroelectric Generation Assets
The Utility's hydroelectric system consists of 110 generating units at 68
powerhouses with a total generating capacity of 3,896 megawatts (MW). The
system includes 99 reservoirs, 76 diversions, 174 dams, 184 miles of canals,
44 miles of flumes, 135 miles of tunnels, 19 miles of pipe, and 5 miles of
natural waterways. The system also includes 94 contracts for water rights and
163 statements of water diversion and use.
Under AB 1890 all generation assets must be market-valued by December 31,
2001 through appraisal, sale or other divestiture. In 1999, the Utility filed
an application with the CPUC to determine the market value of the Utility's
hydroelectric generation facilities and related assets through an open
competitive auction similar to the auction process used in the previous sales
of the Utility's fossil fueled and geothermal plants. In November 2000, the
CPUC's draft environmental impact report (EIR) reviewing the potential
environmental impacts of the proposed auction under the California
Environmental Quality Act (CEQA) was issued.
As an alternative to the auction proposal, in August 2000, the Utility and
other parties filed an application with the CPUC for approval of a settlement
under which the hydroelectric facilities would be transferred to a California-
based affiliate of PG&E Corporation at a value of $2.8 billion, subject to a
40-year revenue sharing agreement. In November 2000, the Utility withdrew its
support from the settlement. In December 2000, the Utility submitted updated
testimony in the valuation proceedings indicating that the market value of the
hydroelectric assets ranges from $3.9 billion to $4.2 billion assuming that
the assets were sold in a competitive auction or other arm's-length sale.
Updated joint testimony was also submitted by the CPUC's Office of Ratepayer
Advocates (ORA), TURN, and the California Farm Bureau Federation (CFBF). These
parties had previously submitted joint testimony in which they recommended a
valuation of $2.665 billion assuming the hydroelectric facilities would be
retained by the Utility. Their updated testimony estimates that recent higher
market prices result in an increase in the value of the assets by
approximately $943 million, although they do not recommend any change to their
previous valuation of $2.665 billion. Instead, they recommend that ratepayers
receive all future operating profits from hydroelectric generation operations,
which, based on higher price forecasts, will ensure that ratepayers obtain the
full value of the assets. Further, the joint parties recommend that the amount
of the final market valuation that exceeds book value be used to reduce the
Utility's undercollected wholesale power purchase costs recorded in the
Utility's TRA rather than crediting the Utility's TCBA. The Utility has
opposed this proposal, as it would unlawfully delay the completion of
transition cost recovery by the Utility as well as delay the end of the rate
freeze.
In response to the California wholesale electricity crisis, in January
2001, the California Governor signed Assembly Bill 6 (AB6) which prohibits
public utilities from disposing of any generation facility before January 1,
2006. In light of AB6, the hydroelectric valuation proceeding will no longer
address the disposition of the hydroelectric facilities. On February 21, 2001,
the Utility requested that the CPUC suspend the CEQA review in light of AB6.
Absent a resolution suspending the CEQA review, the Utility provided comments
on the draft EIR on March 9, 2001.
In its rate stabilization proceeding, the Utility has proposed to defer
receiving a portion of its share of profits from its hydroelectric plants
until a later time and allow those funds instead to be used to offset
uncollected power purchase costs. The Utility has proposed that for the next
two years (after which the Utility expects the current supply shortage will be
less critical), the Utility sell the output of these facilities directly to
its retail distribution customers on an incentive ratemaking basis to lower
the costs of procured power for such customers.
Diablo Canyon Nuclear Power Plant
Diablo Canyon consists of two nuclear power reactor units, each capable of
generating up to approximately 26 million kilowatt-hours (kWh) of electricity
per day. Diablo Canyon Units 1 and 2 began commercial operation in May 1985
and March 1986, respectively. The operating license expiration dates for
Diablo Canyon Units 1 and 2 are September 2021 and April 2025, respectively.
As of December 31, 2000, Diablo Canyon Units 1 and 2 had achieved lifetime
capacity factors of 82% and 84%, respectively.
25
The table below outlines Diablo Canyon's refueling schedule for the next
five years. Diablo Canyon refueling outages typically are scheduled every 19
to 21 months. The schedule below assumes that a refueling outage for a unit
will last approximately 35 days, depending on the scope of the work required
for a particular outage. The schedule is subject to change in the event of
unscheduled plant outages.
2001 2002 2003 2004 2005
----- ---- -------- -------- --------
Unit 1
Refueling............................... May February October
Startup................................. June March November
Unit 2
Refueling............................... April February October
Startup................................. June March November
Diablo Canyon Ratemaking. Since January 1, 1997, the Utility's sunk costs
in Diablo Canyon have been recovered from ratepayers through a sunk cost
revenue requirement, at a reduced return on common equity equal to 6.77% that
will remain in effect through the end of the transition period. (Sunk costs
are costs associated with the facility that are fixed and unavoidable.) The
Diablo Canyon sunk costs revenue requirement is being recovered as a
transition cost through the TCBA. In connection with the new ratemaking, the
CPUC ordered that a financial verification audit of Diablo Canyon plant
accounts be performed by an independent accounting firm, and that the CPUC
hold a proceeding to review the results of the audit, including any proposed
adjustments to Diablo Canyon accounts, following the completion of the audit.
The audit was completed in August 1998. In September 2000, the CPUC issued a
decision that concluded that because the audit found that Diablo Canyon costs
are presented fairly, no further action would be taken and the proceeding
would be closed.
Also since January 1, 1997, a performance-based Incremental Cost Incentive
Price (ICIP) mechanism has been used to recover Diablo Canyon's operating
costs and the cost of capital additions incurred after December 31, 1996. The
ICIP mechanism establishes a rate per kWh generated by the facility for the
period 1997 through 2001. The CPUC-authorized ICIP price for 2001 is 3.49
cents per kWh, resulting in estimated ICIP revenues of $552 million based on
an assumed capacity factor of 83.6%. The estimated sunk cost revenue
requirement for 2001 is approximately $1.1 billion. Any variance between ICIP
revenues and related costs is reflected in earnings.
After the transition period, Diablo Canyon generation must be sold at the
prevailing market price for power. Further, pursuant to the 1997 CPUC decision
establishing the ICIP, the Utility is required to begin sharing 50% of the net
benefits of operating Diablo Canyon with ratepayers beginning after the
transition period. In June 2000, the Utility filed an application with the
CPUC requesting approval of its proposal for sharing with ratepayers 50% of
the post-rate freeze net benefits of operating Diablo Canyon. The net benefit
sharing methodology proposed in the Utility's application would be effective
at the end of the current electric rate freeze for the Utility's customers and
would continue for as long as the Utility owned Diablo Canyon. Under the
proposal, the Utility would share the net benefits of operating Diablo Canyon
based on the audited profits from operations, determined consistent with the
prior CPUC decision. If Diablo Canyon experiences losses, such losses would be
accrued and netted against profits in the calculation of the net benefits in
subsequent periods (or against profits in prior periods if subsequent profits
are insufficient to offset such losses). Any changes to the net sharing
methodology would have to be approved by the CPUC. However, the CPUC has
suspended the proceeding to consider the net benefit sharing methodology. In
the Utility's rate stabilization proceeding (see "Electric Ratemaking" above),
parties have proposed that the requirement to establish a sharing methodology
be rescinded and that Diablo Canyon be placed on cost of service ratemaking.
It is uncertain what future ratemaking will be applicable to Diablo Canyon.
Nuclear Fuel Supply and Disposal. The Utility has purchase contracts for,
and inventories of, uranium concentrates, uranium hexaflouride, and enriched
uranium, as well as one contract for fuel fabrication. Based on current Diablo
Canyon operations forecasts and a combination of existing contracts and
inventories, the requirement for uranium supply will be met through 2004, the
requirement for the conversion of uranium to
26
uranium hexaflouride will be met through 2001, and the requirement for the
enrichment of the uranium hexaflouride to enriched uranium will be met through
2002. The fuel fabrication contract for the two units will supply their
requirements for the next seven operating cycles of each unit. These contracts
are intended to ensure long-term fuel supply, but permit the Utility the
flexibility to take advantage of short-term supply opportunities. In most
cases, the Utility's nuclear fuel contracts are requirements-based, with the
Utility's obligations linked to the continued operation of Diablo Canyon.
Under the Nuclear Waste Policy Act of 1982 (Nuclear Waste Act), the DOE is
responsible for the transportation and ultimate long-term disposal of spent
nuclear fuel and high-level radioactive waste. Under the Nuclear Waste Act,
utilities are required to provide interim storage facilities until permanent
storage facilities are provided by the federal government. The Nuclear Waste
Act mandates that one or more such permanent disposal sites be in operation by
1998. Consistent with the law, Pacific Gas and Electric Company signed a
contract with the DOE providing for the disposal of the spent nuclear fuel and
high-level radioactive waste from the Utility's nuclear power facilities
beginning not later than January 1998. However, due to delays in identifying a
storage site, the DOE has been unable to meet its contract commitment to begin
accepting spent fuel by January 1998. Further, under the DOE's current
estimated acceptance schedule for spent fuel, Diablo Canyon's spent fuel may
not be accepted by the DOE for interim or permanent storage before 2010, at
the earliest. At the projected level of operation for Diablo Canyon, the
Utility's facilities are sufficient to store on-site all spent fuel produced
through approximately 2006 while maintaining the capability for a full-core
off-load. It is likely that an interim or permanent DOE storage facility will
not be available for Diablo Canyon's spent fuel by 2006. The Utility is
examining options for providing additional temporary spent fuel storage at
Diablo Canyon or other facilities, pending disposal or storage at a DOE
facility.
In July 1988, the NRC gave final approval to the Utility to store
radioactive waste from the nuclear generating unit (Unit 3) at Humboldt Bay
Power Plant (Humboldt) at Humboldt before ultimately decommissioning the unit.
The Utility has agreed to remove all spent fuel when the federal disposal site
is available.
Insurance. The Utility has insurance coverage for property damage and
business interruption losses as a member of Nuclear Electric Insurance Limited
(NEIL). NEIL, which is owned by utilities with nuclear generating facilities,
provides insurance coverage against property damage, decontamination,
decommissioning, and business interruption and/or extra expenses during
prolonged accidental outages for reactor units in commercial operation. Under
these insurance policies, if the nuclear generating facility of a member
utility suffers a loss due to a prolonged accidental outage, the Utility may
be subject to maximum retrospective premium assessments of $12 million
(property damage) and $4 million (business interruption), in each case per
one-year policy period, if losses exceed the resources of NEIL.
The Price-Anderson Act, as amended by Congress in 1988 (Price Act), limits
public liability claims that could arise from a nuclear incident to a maximum
of $9.5 billion per incident. The Price Act requires that all nuclear
utilities share in the payment for nuclear liability claims resulting from a
nuclear incident. The Utility has purchased primary insurance of $200 million
for public liability claims resulting from a nuclear incident. An additional
$9.3 billion of coverage is provided by secondary financial protection
required by federal law and provides for loss sharing among utilities owning
nuclear generating facilities if a costly incident occurs. If a nuclear
incident results in claims in excess of $200 million, the Utility may be
assessed up to $176 million per incident, with payments in each year limited
to a maximum of $20 million per incident.
Decommissioning. The Utility's estimated total obligation to decommission
and dismantle its nuclear power facilities is $1.7 billion in 2000 dollars
($5.1 billion in future dollars). This estimate, which includes labor,
materials, waste disposal charges, and other costs, is based on a 1997
decommissioning cost study. A contingency to capture engineering, regulatory,
and business environment changes is included in the total estimated
obligation. Actual decommissioning costs are expected to vary from this
estimate because of changes in the assumed dates of decommissioning,
regulatory requirements, and technology, as well as differences in the amount
of labor, materials, and equipment needed to complete decommissioning. The
estimated total obligation needed to complete decommissioning is recognized
proportionately over the license term of each facility.
27
Nuclear decommissioning costs recovered in rates are placed in external
trusts. The funds in these trusts, along with accumulated earnings, will be
used exclusively for decommissioning and dismantling the nuclear facilities.
The trusts maintain substantially all of their investments in debt and equity
securities. All earnings on the funds held in the trusts, net of authorized
disbursements from the trusts and management and administrative fees, are
reinvested. Monies may not be released from the external trusts until
authorized by the CPUC. In December 1997, the CPUC granted the Utility's
request for authority to disburse up to $15.7 million from the Humboldt Bay
Power Plant decommissioning trusts to finance three partial nuclear
decommissioning projects at Humboldt Unit 3. Accordingly, as of December 31,
2000, $9.3 million ($15.7 million less $6.4 million in expected tax benefits)
has been disbursed from the Humboldt Unit 3 non-tax-qualified trust to
reimburse the Utility for nuclear decommissioning expenses associated with the
partial decommissioning projects. The remaining $6.4 million of the approved
expenses will be disbursed only if the Internal Revenue Service (IRS)
disallows the expected tax benefits. In February 2000, the CPUC granted the
Utility's request to disburse an additional amount of up to $7 million from
the Humboldt Bay Power Plant decommissioning trusts to explore licensing and
permitting of an on-site dry cask storage facility for the spent nuclear fuel
that would allow early decommissioning of Humboldt Bay Power Plant Unit 3. As
of December 31, 2000, $1.7 million ($2.9 million project cost less $1.2
million in expected tax benefits) has been disbursed from the Humboldt Unit 3
non-tax-qualified trust to reimburse the Utility for nuclear decommissioning
expenses associated with the dry cask storage facility. Additional licensing
and permitting activities are continuing.
As of December 31, 2000, the Utility had accumulated external trust funds
with an estimated liquidation value of $1.36 billion, based on quoted market
prices and net of deferred taxes on unrealized gains, to be used for the
decommissioning of the Utility's nuclear facilities.
The amount recovered in rates for nuclear decommissioning costs is
authorized by the CPUC as part of the GRC. The CPUC considers the trusts'
asset levels, together with revised earnings and decommissioning cost
assumptions, to determine the amount of decommissioning costs it will
authorize in rates for contribution to the trusts. The monies contributed to
the decommissioning trusts, together with existing trust fund balances and
projected earnings, are intended to satisfy the estimated future obligation
for decommissioning costs. For the year ended December 31, 2000, annual
nuclear decommissioning trust contributions collected in rates were
$26.47 million. Of this amount, the Utility was able to contribute only $14
million to the trusts in 2000 due to the Utility's liquidity crisis. The
Utility expects that it will be required to refund the difference to customers
in 2001. The Utility has filed for a new schedule of ruling amount (SRA) with
the IRS that would lower the amount collected through rates to $24 million.
The IRS has not yet approved the Utility's proposed SRA. If approved, the
difference between the previous amount collected in rates and the new amount
would be refunded to customers.
Since January 1, 1998, nuclear decommissioning costs, which are not
transition costs, have been recovered through a nonbypassable charge that will
continue until those costs are fully recovered. Recovery of decommissioning
costs may be accelerated to the extent possible under the rate freeze. The
CPUC has established a Nuclear Decommissioning Costs Triennial Proceeding to
determine the decommissioning costs and to establish the annual revenue
requirement and attrition factors over subsequent three-year periods.
Other Electric Resources
QF Generation and Other Power Purchase Contracts. The Utility is required
by CPUC decisions to purchase electric energy and capacity provided by
independent power producers that are qualifying facilities (QFs) under the
Public Utility Regulatory Policies Act of 1978 (PURPA). The CPUC required
California utilities to enter into a series of QF long-term power purchase
agreements (PPAs) and approved the applicable terms, conditions, price
options, and eligibility requirements. The PPAs require the Utility to pay for
energy and capacity. Energy payments are based on the QF project's actual
electrical output and capacity payments are based on the QF project's total
available capacity and contractual capacity commitment. Capacity payments may
be reduced if the facility does not meet the performance requirements
specified in the PPAs.
28
Until December 15, 2000, the Utility was required to schedule into the PX
all of the electric power generated by QFs and other providers that the
Utility is required to purchase under existing contractual commitments. (The
December 15, 2000 FERC order eliminated this mandatory sell requirement.) The
Utility has paid these suppliers directly pursuant to price provisions
contained in their PPAs. The invoices sent by the PX for the cost to serve the
Utility's retail customers included credits for power provided by these
suppliers based on electric market prices.
In general, before the steep increase in wholesale power prices that began
in June 2000, the price for energy payments under QF contracts was higher than
the market price. The amount of the contract payment exceeding the market
price is recoverable as a transition cost. Under Section 390(c) of the Public
Utilities Code (PUC) adopted in AB 1890 and implemented by a November 1999
CPUC decision, QFs could make a one-time election to receive energy payments
based on the PX day ahead market clearing price, on an interim basis and
subject to true-up, instead of receiving short-run avoided costs energy
payments based on the "transition formula" adopted by AB 1890 and set forth in
PUC Section 390(b). Those that elected not to exercise this option continued
to receive PPA payments based on the Utility's short-run avoided costs. As the
wholesale market price of power rose dramatically, many QFs elected to receive
PX-based payments, causing the Utility's procurement costs to increase
significantly. For the period from June 2000 through December 2000, energy
costs for deliveries from QFs who switched to PX pricing were approximately
$375 million more than these QFs would have received under the transition
formula. On January 10, 2001, the Utility filed an emergency motion with the
CPUC requesting that the CPUC true-up payments made to switching QFs since
June 2000 to the Utility's "transition formula" short-run avoided cost energy
rates or, in the alternative, to PX-based rates capped at $67.45 per megawatt-
hour. On February 22, 2001, the CPUC issued a decision ordering that QFs that
had exercised their one-time option to switch to PX-pricing would be paid
short-run avoided cost energy payments based on the transition formula
effective on January 19, 2001.
The Utility paid approximately 15 percent of amounts due QFs for deliveries
made in December 2000 and January 2001. The Utility made no payment for QF
deliveries received in February 2001. On March 27, 2001, the CPUC issued a
decision requiring the Utility and the other California investor-owned
utilities to pay QFs fully for energy deliveries made on and after the date of
the decision. The CPUC decision requires the Utility to pay QFs for energy and
capacity deliveries within 15 days following the current monthly billing
period instead of the 30 days after the close of the billing period required
by the PPAs. The CPUC stated that its change to the payment provision was
required to maintain energy reliability in California. The CPUC held that a
failure to make a required payment would result in a fine in the amount owed
to the QF. The decision also adopts a revised pricing formula relating to the
California border price of gas applicable to energy payments to all QFs,
including those that do not use natural gas as a fuel. Based on the Utility's
preliminary review of the decision, the revised pricing formula would reduce
the Utility's 2001 average QF energy and capacity payments from approximately
12.7 cents per kWh to 12.3 cents per kWh.
Most of the PPAs expire on various dates through 2028, though some have no
stated expiration date. Deliveries from these power producers account for
approximately 23% of the Utility's 2000 electric energy requirements and no
single contract accounted for more than 5% of the Utility's energy needs.
As of December 31, 2000, the Utility had commitments to purchase
approximately 5,200 MW of capacity under CPUC-mandated PPAs. Of the 5,200 MW,
approximately 4,400 MW are operational. Development of the majority of the
balance is uncertain and it is estimated that very few of the remaining
contracts will become operational. The 4,400 MW of operational capacity
consists of 2,700 MW from cogeneration projects, 700 MW from wind projects,
and 1,000 MW from other projects, including biomass, waste-to-energy,
geothermal, solar, and hydroelectric.
The Utility also has contracts with various irrigation districts and water
agencies to purchase hydroelectric power. Under these contracts, the Utility
must make specified semi-annual minimum payments whether or not any energy is
supplied (subject to the supplier's retention of the FERC's authorization) and
variable payments for operation and maintenance costs incurred by the
suppliers. These contracts expire on various dates from 2004
29
to 2031. Costs associated with these contracts to purchase power are eligible
for recovery by the Utility as transition costs through the collection of the
nonbypassable CTC. At December 31, 2000, the undiscounted future minimum
payments under these contracts are approximately $31.5 million for each of the
years 2001 through 2004 and a total of $221 million for periods thereafter.
Irrigation district and water agency deliveries in the aggregate account for
approximately 4.6% of the Utility's 2000 electric energy requirements.
The amount of energy received and the total payments made under all these
power purchase contracts were:
2000 1999 1998 1997
------ ------ ------ ------
($ in millions)
Kilowatt-hours received............................ 25,446 25,910 25,994 24,389
Energy payments.................................... $1,549 $ 837 $ 943 $1,157
Capacity payments.................................. $ 519 $ 539 $ 529 $ 538
Irrigation district and water agency payments...... $ 56 $ 60 $ 53 $ 56
Bilateral Agreements. Until August 2000, CPUC decisions required the
Utility to purchase power for its retail customers solely through the PX and
ISO. On July 21, 2000, the Utility filed an emergency motion with the CPUC
seeking authorization to enter into bilateral agreements directly with third
parties to purchase power, capacity, and ancillary services, citing the need
to better hedge against high power prices in the PX day-ahead and ISO real-
time markets and to introduce new supply into California. In its July 2000
request, the Utility proposed that the CPUC adopt prospective reasonableness
standards which would allow the CPUC to determine at the time of inception
whether a transaction was reasonable per se compared to specific market
prices. Without such prospective reasonableness standards, the CPUC can
second-guess the Utility's decision to enter into contracts and disallow some
or all of those costs deemed after-the-fact to be "unreasonable."
On August 3, 2000, the CPUC approved the Utility's emergency motion and
allowed the Utility to enter into bilateral contracts, subject to previous
limits established for BFM purchases (i.e., used to cover the Utility's net
open position), provided that all such contracts must expire on or before
December 31, 2005. The CPUC's approval of bilateral contracting authority was
subject to agreement on implementation details, such as appropriate pricing
benchmarks, with ORA and the CPUC's Energy Division. ORA and the Energy
Division rejected the Utility's proposed standards and neither has suggested
alternative standards. Despite this stalemate, during September and October
2000, the Utility held an auction soliciting offers for energy purchases at
fixed prices for one to five years. In October 2000, the Utility entered into
bilateral power purchase contracts with several suppliers. In December 2000,
the Utility again solicited offers from power suppliers, but the responses
were priced above then-current market prices so the Utility elected not to
enter into any contracts at that time. The downgrade of the Utility's credit
ratings since December 2000 has effectively barred the Utility from entering
into additional long-term contracts.
In its December 15, 2000 order, the FERC noted that it was critical for the
CPUC to give timely and predictable approval of the prudence of a balanced
portfolio of short- and long-term contracts. On December 22, 2000, the CPUC
issued a decision requesting comments from interested parties on a set of
reasonableness standards proposed in the decision. In this decision, the CPUC
proposed price benchmarks which were well below the then current market
prices, making it impossible for the Utility to enter into bilateral purchases
which the CPUC could deem reasonable. The Utility filed comments to the
proposed decision objecting to the proposed standards as unworkable. In
January 2001, the CPUC issued another proposed decision adopting similar
unrealistic price benchmarks for bilateral purchases. Again, the Utility filed
comments expressing its concerns with the new draft decision. It is uncertain
whether or when the CPUC will issue appropriate realistic reasonableness
standards.
Electric Transmission and Distribution
To transport energy to load centers, Pacific Gas and Electric Company as of
December 31, 2000 owned approximately 18,376 circuit miles of interconnected
transmission lines of 60 kilovolts (kV) to 500 kV and
30
transmission substations having a capacity of approximately 39,859,000
kilovolt-amperes (kVA), including spares, excluding power plant
interconnection facilities. Energy is distributed to customers through
approximately 115,131 circuit miles of distribution system and distribution
substations having a capacity of approximately 23,524,000 kVA.
In connection with electric industry restructuring, in 1998 the utilities
relinquished control, but not ownership, of their transmission facilities to
the ISO. The FERC has jurisdiction over the transmission facilities and
revenue requirements and rates for transmission service are set by the FERC.
The ISO commenced operations on March 31, 1998. The ISO, regulated by the
FERC, controls the operation of the transmission system and provides open
access transmission service on a nondiscriminatory basis. As control area
operator, the ISO is also responsible for assuring the reliability of the
transmission system.
In 1998, the FERC approved the forms of agreements for reliability must-run
(RMR) generating facilities that have been entered into between RMR facility
owners and the ISO to ensure grid reliability and avoid the exercise of local
market power. The costs of RMR contracts attributed to supporting the
Utility's historic transmission control area are charged to the Utility as a
Participating Transmission Owner (PTO). These costs, which were approximately
$178 million in 2000, are currently recovered from the Utility's retail
customers and, subject to the outcome of current FERC proceedings, wholesale
transmission customers.
In March 2000, the ISO filed an application with the FERC seeking to
establish its own Transmission Access Charge (TAC) as directed in AB 1890. The
FERC accepted the ISO's TAC filing, subject to refund, but suspended the
proceeding to allow the parties to enter into settlement discussions. In late
December 2000, the ISO made a further implementation filing, also accepted by
the FERC subject to refund, to establish specific TAC rates because a
transmission-owning municipality had applied to become a new PTO, thereby
triggering effectiveness of the ISO TAC rate methodology. The ISO's TAC
methodology provides for transition to a uniform statewide high voltage
transmission rate, based on the revenue requirements of all PTOs associated
with facilities operated at 200 kV and above. The TAC methodology also
requires original PTOs such as the Utility to pay certain increases incurred
by new PTOs resulting from joining the ISO during a 10-year transition period.
The Utility's obligation for this cost shift is currently capped at $32
million per year.
The Utility has been working closely with the ISO to remedy transmission
constraints on the Utility's electric transmission system. Of particular
concern are the constraints on Path 15, which is located in the southern
portion of the Utility's service area, and serves as the part of the primary
transmission link between Northern and Southern California. At times, the
current facilities cannot accommodate all low-cost power intended to be
transmitted between Southern California (where the Utility's Diablo Canyon
nuclear power plant is located) and Northern California. This often results in
significant wholesale power price differentials between Northern and Southern
California with relatively high power prices in Northern California and
relatively low power prices in Southern California.
The Utility's investment in maintenance and expansion of its transmission
system has been growing substantially over the past several years. The Utility
anticipates making an additional capital investment of approximately $260
million in its transmission system in 2001. Through the ISO's Long-Term Grid
Planning Process, the Utility annually files its transmission upgrade plans
and provides the ISO the opportunity to concur with the Utility's planned
upgrades.
As a result of the ISO concluding that the available power reserves were
precipitously low, the ISO ordered the Utility to implement emergency
procedures in the Utility's service territory frequently during the summer
2000 and winter 2001, and as recently as March 2001. On some occasions these
measures included rolling outages affecting a large number of retail
customers. It is anticipated that a projected power supply shortage for peak
demand periods, including the summer of 2001, will result in further rolling
outages. To the extent conservation efforts are successful, the need for such
emergency measures may be lessened. Depending on the location of the available
power supply relative to the load, transmission constraints could exacerbate
the supply problem. Completion of the Utility's planned transmission projects
before the summer 2001 peak are expected to mitigate most of these
constraints.
31
Most of the Utility's distribution services remain subject to CPUC
jurisdiction. The CPUC is considering whether it should pursue further reforms
in the structure and regulatory framework governing electricity distribution
service.
Gas Utility Operations
Pacific Gas and Electric Company owns and operates an integrated gas
transmission, storage, and distribution system in California. The Utility
served approximately 3.8 million gas customers at December 31, 2000. Most of
these customers continue to obtain gas supplies from the Utility under
regulated tariff rates.
The Utility offers transmission, distribution, and storage services as
separate and distinct services to its industrial and larger commercial gas
(non-core) customers. Customers have the opportunity to select from a menu of
services offered by the Utility and to pay only for the services that they
use. Access to the transmission system is possible for all gas marketers and
shippers, as well as non-core end users. The Utility's residential and smaller
commercial gas (core) customers can select the commodity gas supplier of their
choice. However, the Utility continues to purchase gas as a regulated supplier
for those core customers who request it.
At December 31, 2000, the Utility's system consisted of approximately 6,261
miles of transmission pipelines, three gas storage facilities, and
approximately 37,958 miles of gas distribution lines. The Utility's
Line 400/401 interconnects with the natural gas transmission system of the
Utility's sister subsidiary, PG&E Gas Transmission, Northwest Corporation
(PG&E GTN). The PG&E GTN pipeline begins at the border of British Columbia,
Canada, and Idaho, and extends through northern Idaho, southeastern Washington
and central Oregon, and ends on the Oregon-California border where it connects
with the Utility's Line 400/401. The 840-mile combined Utility-PG&E GTN
pipeline provides about 2,700 million cubic feet per day (MMcf/d) of capacity.
More than 1,800 MMCf/d can be delivered to Northern and Southern California;
and the remaining capacity can be delivered to the Pacific Northwest. The
Utility's Line 300, which connects to the U.S. Southwest pipeline systems
(Transwestern, El Paso, and Kern River) owned by third parties has a capacity
of 1,140 MMcf/d. The Utility's underground gas storage facilities located at
McDonald Island, Los Medanos, and Pleasant Creek, have a total working gas
capacity of 98 billion cubic feet (Bcf).
The Utility's peak day send-out of gas on its integrated system in
California during the year ended December 31, 2000, was 3,795 million cubic
feet (MMcf). The total volume of gas throughput during 2000 was approximately
937,000 MMcf, of which 281,000 MMcf was sold to direct end-use or resale
customers, 49,000 MMcf was used by the Utility primarily for its fossil-fueled
electric generating plants, and 606,000 MMcf was transported as customer-owned
gas.
The California Gas Report, which presents the outlook for natural gas
requirements and supplies for California over a long-term planning horizon, is
prepared annually by the California electric and gas utilities. A
comprehensive biennial report is prepared in even-numbered years with a
supplemental report in intervening odd-numbered years updating recorded data
for the previous year.
The 2000 California Gas Report updates the Utility's annual gas
requirements forecast (excluding bypass volumes) for the years 2000 through
2020, forecasting average annual growth in gas throughput served by the
Utility of approximately 1.4%. The gas requirements forecast is subject to
many uncertainties and there are many factors that can influence the demand
for natural gas, including weather conditions, level of utility electric
generation, fuel switching, and new technology. In addition, some large
customers, mostly in the industrial and enhanced oil recovery sectors, may
have the ability to use unregulated private pipelines or interstate pipelines,
bypassing the Utility's system entirely.
32
Gas Operating Statistics
The following table shows Pacific Gas and Electric Company's operating
statistics (excluding subsidiaries) for gas, including the classification of
sales and revenues by type of service.
Years Ended December 31,
---------------------------------------------------------
2000 1999 1998 1997 1996
---------- ---------- ---------- ---------- ----------
Customers (average for
the year):
Residential........... 3,642,266 3,593,355 3,536,089 3,491,963 3,455,086
Commercial............ 203,355 203,342 200,620 198,453 198,071
Industrial............ 1,719 1,625 1,610 1,650 1,500
Other gas utilities... 6 4 5 3 2
---------- ---------- ---------- ---------- ----------
Total.............. 3,847,346 3,798,326 3,738,324 3,692,069 3,654,659
========== ========== ========== ========== ==========
Gas supply--thousand
cubic feet (Mcf) (in
thousands):
Purchased from
suppliers in:
Canada............... 216,684 230,808 298,125 280,084 253,209
California........... 32,167 18,956 17,724 10,655 28,130
Other states......... 75,834 107,226 122,342 131,074 110,604
---------- ---------- ---------- ---------- ----------
Total purchased.... 324,685 356,990 438,191 421,813 391,943
Net (to storage) from
storage.............. 19,420 (980) (14,468) 14,160 6,871
---------- ---------- ---------- ---------- ----------
Total.............. 344,105 356,010 423,723 435,973 398,814
Pacific Gas and
Electric Company use,
losses, etc.(1)...... 62,960 47,152 129,305 173,789 134,375
---------- ---------- ---------- ---------- ----------
Net gas for sales.. 281,145 308,858 294,418 262,184 264,439
========== ========== ========== ========== ==========
Bundled gas sales and
transportation
service--Mcf
(in thousands):
Residential........... 210,515 233,482 223,706 191,327 190,246
Commercial............ 66,443 70,093 66,082 60,803 62,178
Industrial............ 4,146 5,255 4,616 10,054 12,015
Other gas utilities... 41 28 14 0 0
---------- ---------- ---------- ---------- ----------
Total.............. 281,145 308,858 294,418 262,184 264,439
========== ========== ========== ========== ==========
Transportation service
only--Mcf (in
thousands):
Vintage system
(Substantially all
Industrial)(2)....... 606,152 484,218 396,872 218,660 189,695
PG&E Expansion (Line
401)(3).............. 0 0 0 233,269 237,776
---------- ---------- ---------- ---------- ----------
Total.............. 606,152 484,218 396,872 451,929 427,471
========== ========== ========== ========== ==========
Revenues (in thousands):
Bundled gas sales and
transportation
service:
Residential.......... $1,680,745 $1,542,705 $1,414,313 $1,170,135 $1,109,463
Commercial........... 513,080 448,655 426,299 374,084 362,819
Industrial........... 35,347 24,638 24,634 46,592 42,520
Other gas utilities.. 0 77 1,072 3,701 510
---------- ---------- ---------- ---------- ----------
Bundled gas
revenues.......... 2,229,172 2,016,075 1,866,318 1,594,512 1,515,312
Transportation only
revenue:
Vintage system
(Substantially all
Industrial)......... 324,319 267,544 232,038 207,160 180,197
PG&E Expansion (Line
401)................ 13,392 19,091 42,194 90,180 85,144
---------- ---------- ---------- ---------- ----------
Transportation service
only revenue......... 337,711 286,635 274,232 297,340 265,341
Miscellaneous......... 84,526 (47,311) 41,364 50,295 (9,271)
Regulatory balancing
accounts............. 131,762 (259,648) (448,351) (137,787) 57,864
---------- ---------- ---------- ---------- ----------
Operating
revenues.......... $2,783,171 $1,995,751 $1,733,563 $1,804,360 $1,829,246
========== ========== ========== ========== ==========
- --------
(1) Includes fuel for Pacific Gas and Electric Company's fossil-fueled
generating plants.
(2) Does not include on-system transportation volumes transported on the PG&E
Expansion of 4,833 MMcf, 1,251 MMcf, 34,169 MMcf, 72,958 MMcf, and 78,552
MMcf for 2000, 1999, 1998, 1997, and 1996, respectively.
(3) Starting in 1998, Vintage system and PG&E Expansion are combined and
reported as total transportation service.
33
Years Ended December 31,
----------------------------------
2000 1999 1998 1997 1996
------ ------ ------ ------ ------
Selected Statistics:
Average annual residential usage (Mcf)..... 59 65 63 55 55
Heating temperature--% of normal (1)....... 101.2 108.5 93.0 71.7 75.7
Average billed bundled gas sales revenues
per Mcf:
Residential............................... $ 7.98 $ 6.61 $ 6.32 $ 6.12 $ 5.83
Commercial................................ 7.72 6.40 6.45 6.15 5.84
Industrial................................ 8.53 4.69 5.36 4.63 3.54
Average billed transportation only revenue
per Mcf:
Vintage system............................ 0.54 0.66 0.66 0.71 0.67
PG&E Expansion (Line 401)................. 2.04 0.53 0.54 0.39 0.36
Net plant investment per customer (2)..... $1,003 $1,011 $1,040 $1,031 $1,061
- --------
(1) Over 100% indicates colder than normal.
Natural Gas Supplies
The objective of Pacific Gas and Electric Company's Gas Procurement
Department is to maintain a balanced supply portfolio that provides supply
reliability and contract flexibility, minimizes costs, and fosters competition
among the Utility's gas suppliers. To ensure a diverse and competitive mix of
natural gas to serve the Utility's customers, the Utility purchases gas
directly from producers and marketers in both Canada and the United States.
Due to the Utility's deteriorating financial condition resulting from the
dysfunctional California wholesale power market, in December 2000 and January
2001, several gas suppliers demanded prepayment, cash on delivery, or other
forms of payment assurance before they would deliver gas, instead of the
normal payment terms under which the Utility would pay for the gas after
delivery. As the Utility was unable to meet such demands at that time, several
gas suppliers refused to supply gas accelerating the depletion of the
Utility's gas storage reserves, and potentially accelerating the electric
power crisis if the Utility were required to divert gas from industrial users,
including natural gas fired power plant operators.
The U.S. Secretary of Energy issued a temporary order on January 19, 2001,
requiring the gas suppliers to make deliveries to avoid a worsening natural
gas shortage emergency. However, this order expired on February 7, 2001, and
certain companies, representing about 10% of the Utility's natural gas
suppliers, terminated deliveries after the orders expired. The Utility tried
to mitigate the worsening supply situation by withdrawing more gas from
storage and, when able, purchasing additional gas on the spot market.
Additionally, on January 31, 2001, the CPUC authorized the Utility to pledge
its gas account receivables and its gas inventories for up to 90 days
(extended to 180 days in a CPUC draft decision issued on February 15, 2001) to
secure gas for its core customers. At March 29, 2001, the amount of gas
accounts receivables pledged was approximately $900 million. As of March 29,
2001, approximately 30% of the Utility's suppliers of natural gas had signed
security agreements with the Utility and discussions were continuing with the
Utility's other suppliers. Additionally, the Utility is currently implementing
a program to obtain longer-term summer and winter supplies and daily spot
supplies.
The Utility has also filed an application with the CPUC to declare a gas
emergency, and require one of the Utility's larger gas suppliers to sell
incremental gas supplies to the Utility. The gas supplier has protested the
application. The CPUC is expected to rule on the application at its meeting on
April 19, 2001.
Under current CPUC regulations, the Utility purchases natural gas from its
various suppliers based on economic considerations, consistent with
regulatory, contractual, and operational constraints. During the year ended
December 31, 2000, approximately 67% of the Utility's total purchases of
natural gas consisted of
34
Canadian-sourced gas transported by Canadian pipeline companies and PG&E GTN,
and Rocky Mountain-sourced gas transported by PG&E GTN, approximately 10% was
purchased in California, approximately 21% was purchased in the U.S. Southwest
and was transported primarily by the El Paso Natural Gas Company and
Transwestern Pipeline Company pipelines, and approximately 2% was purchased in
the Rocky Mountains and transported by Kern River Gas Transmission Company.
California purchases include supplies from various California producers and
supplies transported into California by others. The following table shows the
total volume and average price of gas in dollars per thousand cubic feet (Mcf)
purchased by the Utility from these sources during each of the last five
years.
2000 1999 1998 1997 1996
------------------ ------------------ ------------------ ------------------ ------------------
Thousands Avg. Thousands Avg. Thousands Avg. Thousands Avg. Thousands Avg.
of Mcf Price(1) of Mcf Price(1) of Mcf Price(1) of Mcf Price(1) of Mcf Price(1)
--------- -------- --------- -------- --------- -------- --------- -------- --------- --------
Canada................. 216,684 $4.05 230,808 $2.50 298,125 $2.00 280,084 $1.77 253,209 $1.57
California............. 32,167 8.20 18,956 2.45 17,724 2.44 10,655 2.12 28,130 1.90
Other states
(substantially all
U.S. Southwest)....... 75,835 5.99 107,227 2.42 122,342 2.62 131,074 3.75 110,604 3.72
------- ----- ------- ----- ------- ----- ------- ----- ------- -----
Total/Weighted
Average............... 324,686 $4.92 356,991 $2.47 438,191 $2.19 421,813 $2.39 391,943 $2.21
======= ===== ======= ===== ======= ===== ======= ===== ======= =====
- --------
(1) The average prices for Canadian and U.S. Southwest gas include the
commodity gas prices, interstate pipeline demand or reservation charges,
transportation charges, and other pipeline assessments, including direct
bills allocated over the quantities received at the California border.
Beginning March 1, 1998, the average price for gas also includes
intrastate pipeline demand and reservation charges. These costs previously
were bundled in gas rates.
Gas Regulatory Framework
In August 1997, the CPUC approved the Gas Accord, which restructured the
Utility's gas services and its role in the gas market. Among other matters,
the Gas Accord separates, or "unbundles," the rates for the Utility's gas
transmission services from its distribution services. As a result of the Gas
Accord, the Utility's customers may buy gas directly from competing suppliers
and purchase transmission-only and distribution-only services from the
Utility. Most of the Utility's industrial and larger commercial customers
(noncore customers) now purchase their gas from marketers and brokers.
Substantially all residential and smaller commercial customers (core
customers) buy gas as well as transmission and distribution services from the
Utility as a bundled service. Customer rates for gas are updated on a monthly
basis to reflect changes in the Utility's gas procurement costs.
The Gas Accord also established an incentive mechanism (the core
procurement incentive mechanism or CPIM) for recovery of the Utility's core
gas procurement costs in rates through 2002. The CPIM provides the Utility
with a direct financial incentive to procure gas and transportation services
at the lowest reasonable costs. Under the CPIM, all Utility procurement costs
are compared to an aggregate market-based benchmark. If costs fall within a
range (tolerance band) around the benchmark, costs are deemed reasonable and
fully recoverable from ratepayers. If procurement costs fall outside the
tolerance band, the Utility's ratepayers and shareholders share savings or
costs, respectively. The Utility has recovered all gas costs through October
31, 1999. In February 2001, the Utility filed a CPIM performance report for
the period of November 1, 1999, through October 31, 2000. The report
determined that all gas commodity and transportation costs for the period are
within the tolerance band, and therefore should be deemed reasonable and
recoverable in full from ratepayers.
The Gas Accord also established gas transmission and storage rates for the
period from March 1998 through December 31, 2002. Rates for gas distribution
service continue to be set by the CPUC in BCAP proceedings, and are designed
to provide the Utility an opportunity to recover its costs of service and
include a return on investment. See "Utility Operations--California Ratemaking
Mechanisms--Gas Ratemaking--The Biennial Cost Allocation Proceeding (BCAP)."
35
In January 1998, the CPUC opened a rulemaking proceeding to explore
alternative market structures in the natural gas industry in California. In
January 2000, the Utility and a broad-based coalition of shippers, consumer
groups, marketers, and others filed a settlement with the CPUC which
reaffirmed the basic structure of the Gas Accord and would continue the Gas
Accord through its original term of December 31, 2002. In May 2000, the CPUC
approved the uncontested settlement.
Transportation Commitments
The Utility has gas transportation service agreements with various Canadian
and interstate pipeline companies. These agreements include provisions for
payment of fixed demand charges for reserving firm capacity on the pipelines.
The total demand charges that the Utility will pay each year may change due to
changes in tariff rates. The total demand and volumetric transportation
charges paid by the Utility under these agreements were approximately $94
million in 2000. This amount includes payments made to PG&E GTN of
approximately $46 million in 2000, which are eliminated in the consolidated
financial statements of PG&E Corporation.
As a result of regulatory changes, the Utility no longer procures gas for
most of its noncore customers, resulting in a decrease in the Utility's need
for firm transportation capacity for its gas purchases. The Utility continues
to procure gas for almost all of its core customers and, up until February
2001, procured gas for those noncore customers who chose bundled service (core
subscription customers). (Core subscription service ended on February 28,
2001, and most former core subscription customers elected to receive bundled
service as core customers.) The Utility is continuing its efforts to broker or
assign any of its remaining contracted-for but unused interstate and Canadian
transportation capacity, including unused capacity held for its core and core-
subscription customers.
Under a firm transportation agreement with PG&E GTN that runs through
October 31, 2005, the Utility currently retains capacity of approximately 600
MMcf/d on the PG&E GTN system to support its core and core-subscription
customers. The Utility has been able to broker its unused capacity on PG&E
GTN's system, when not needed for core and core-subscription customers.
The Utility may recover demand charges through the CPIM and through
brokering activities.
PG&E NATIONAL ENERGY GROUP, INC.
PG&E Corporation's wholly owned subsidiary, PG&E National Energy Group,
Inc. (NEG), is an integrated energy company with a strategic focus on power
generation, new power plant development, natural gas transmission, and
wholesale energy marketing and trading in North America.
On December 22, 2000, NEG completed the sale of PG&E Gas Transmission,
Texas Corporation and PG&E Gas Transmission Teco, Inc. and their subsidiaries,
to El Paso Field Services Company, a subsidiary of El Paso Energy Corporation.
The Texas operations that were sold included gas gathering, transportation,
and processing facilities, and natural gas liquids (NGL) pipelines. In
addition, during 2000, NEG completed the sale of the retail energy services
and value-added services businesses of its subsidiary, PG&E Energy Services
Corporation.
NEG's ability to anticipate and capture profitable business opportunities
created by deregulation will have a significant impact on PG&E Corporation's
future operating results. Implementation of PG&E Corporation's national energy
strategy depends, in part, upon the opening of energy markets to provide
customer choice of supplier. Undue delays in deregulation of the electric
generation and natural gas supply business could impact the pace of growth of
NEG's businesses.
36
Integrated Power Generation, and Energy Trading and Marketing Business
NEG manages the operations, fuel supply, and sale of electric output of its
owned and leased generating facilities as an integrated portfolio with its
contractually controlled generating facilities and its other marketing and
trading activities. NEG had a net ownership interest in 5,230 MW of generating
capacity as of December 31, 2000. In addition, NEG had 19,993 MW of gas-fired
generating facilities in construction or under development for which NEG has
secured the necessary turbines. NEG controls the output of 518 MW of operating
generating capacity and 3,722 MW of generating capacity in construction or
development through various long-term contracts as of December 31, 2000.
NEG's energy marketing and trading activities are focused in markets in
which it owns or controls generating facilities and in developed competitive
markets. NEG's integrated power generation, and energy marketing and trading
business is principally engaged in the following areas:
. ownership and operation of generating facilities,
. new power plant development and construction,
. contractual control of generating capacity,
. energy marketing and trading, and
. risk management.
Ownership and Operation of Generating Facilities. As of December 31, 2000,
NEG had ownership or leasehold interests in 19 operating generating facilities
with a net generating capacity of 5,230 MW. These facilities include five gas-
fired generating facilities with a net generating capacity of 1,055 MW, ten
generating facilities that primarily burn coal or waste coal, in some cases in
combination with oil or gas, with a net generating capacity of 2,997 MW, three
hydroelectric systems or pumped storage facilities with a net generating
capacity of 1,166 MW, and one 12 MW wind generating facility. NEG provides
operating and management services for 16 of its 19 owned and leased generating
facilities.
NEG's generating facilities fall into two categories: merchant plants and
independent power projects. Merchant plants sell their electrical output in the
competitive wholesale electric market on a spot basis or under contractual
arrangements of various terms. Independent power projects sell all or a
majority of their electrical capacity and output to one or more third parties
under long-term power purchase agreements tied directly to the output of that
plant. In order to provide fuel for independent power projects, natural gas and
coal supply commitments are typically purchased from third parties under long-
term supply agreements. All of the generating facilities developed or placed in
operation before 1997 are independent power projects. NEG had a net ownership
interest of 1,100 MW in independent power projects as of December 31, 2000. All
other generating facilities acquired, placed in operation, or controlled
through contracts, during or after 1997 are merchant plants. Generating
facilities under construction or in development are expected to be operated as
merchant plants.
New Power Plant Development and Construction. NEG manages the development
and construction of power generating facilities (sometimes referred to as
"greenfield" development), which include natural gas-fired and coal-fired
generating facilities, and facilities that use other power generating
technologies, including hydroelectric power and wind. NEG considers a
generating facility to be under construction once NEG or the lessor has
acquired the necessary permits to begin construction, broken ground at the
project site, and contracted to purchase the major machinery for the project,
including the combustion turbines. In addition, NEG has a number of generating
facilities in development. NEG considers a generating facility to be in
development when NEG has contractual commitments or options to purchase the
turbines necessary to complete the project or when NEG has made substantial
progress in site selection, control of the site and permitting. The completion
of planned development projects is subject to many factors, including but not
limited to changes in governmental regulations, the timing of regulatory and
environmental approvals or the failure to obtain such approvals, failure to
obtain adequate financing on satisfactory terms, failure to obtain necessary
equipment to operate, failure of
37
third party contractors to perform their contractual obligations, a
competitor's development of a lower-cost generating plant, fluctuations in
natural gas and electricity prices and the ability to successfully manage such
price fluctuations, and the risks associated with marketing and selling power
in the newly competitive energy market.
As of December 31, 2000 NEG owned or had committed to lease or acquire six
generating facilities currently under construction in five states,
representing 3,006 MW. These projects are expected to be placed in service in
2001 and 2002 and since year end, NEG has placed 350 MW in commercial
operation. In addition, NEG has five generating facilities in advanced
development in five states, representing over 5000 MW, which it expects to be
able to place into construction during 2001. NEG has secured contractual
commitments and options for 60 new combustion turbines for large, gas-fired
facilities, representing 19,808 MW of net generating capacity. Ten of these
turbines, representing approximately 2,821 MW, are for generating facilities
under construction as of December 31, 2000, (the Millennium, Lake Road, La
Paloma, and Attala power plant projects). Most of these turbine commitments
use the latest generation of combustion technology, commonly known as G
technology.
The Lake Road and La Paloma facilities are being constructed by Alstom
Power, Inc. (Alstom) under fixed price construction contracts with guaranteed
dates for commercial operations. Alstom has advised NEG that it may take up to
three years to develop and implement modifications to its G technology
turbines that are necessary to achieve the guaranteed level of efficiency and
output. NEG expects that the Lake Road and La Paloma facilities will begin
commercial operations at reduced performance and output levels because of the
technology issues with Alstom's G technology turbines.
NEG also encountered start-up problems with the Siemens Westinghouse G
technology turbine installed at its Millennium facility. These problems have
delayed the expected date of commercial operations for this facility, which
began commercial operations in April 2001. NEG does not expect that the start-
up problems with the Siemens Westinghouse G technology turbine installed at
the Millennium facility will result in a reduction in the guaranteed level of
efficiency or output.
The construction contracts for each of the Millennium, Lake Road, and La
Paloma projects provide for liquidated damages. However, these liquidated
damages will not offset fully the financial impact associated with the delays
of these turbines in achieving their expected level of performance.
Contractual Control of Generating Capacity. NEG has increased its
generating capacity through contractual control of the electric output of
generating facilities owned by others. NEG has executed various long-term
contracts representing 4,240 MW of generating capacity, which result in
control of 518 MW of operating generating capacity and 3,722 MW of generating
capacity in construction or development as of December 31, 2000. The primary
method of achieving contractual control of generating capacity is through
tolling agreements. Tolling agreements establish a contractual relationship
that grants NEG the right to use a third party's generating facility to
convert NEG's fuel, typically natural gas, to electricity. NEG has the right
to decide the timing and amount of electricity production within agreed
operating parameters. The owner of the facility typically receives a fixed
capacity payment for the committed availability of its facility and a variable
payment for production costs. The fixed payment is subject to reduction if the
owner fails to meet specified targets for facility availability or other
operating factors.
The terms of the seven tolling agreements NEG has entered into as of
December 31, 2000, range from 10 to 25 years commencing on the date of initial
commercial operations of the generating facility. Most of the generating
facilities are under construction or in development, with commercial
operations expected to commence between 2001 and 2004. These tolling
agreements provide NEG with control of gas-fired plants in the Mid-Atlantic,
Midwestern, Southern, and Western regions of the United States.
Energy Marketing and Trading. NEG's marketing and trading operations manage
fuel supply procurement and sale of electrical output of NEG's owned and
controlled generating facilities as an integrated portfolio with NEG's trading
positions. During the year ended December 31, 2000, NEG sold approximately
$283 million MW hours of power and an average of over 6.5 Bcf of natural gas
per day.
38
Through over-the-counter and futures markets across North America, NEG
engages in the marketing and trading of (1) electric energy, (2) capacity and
ancillary services, (3) fuel and fuel services such as transport and storage,
(4) emission credits, and (5) other related products. NEG markets and trades
all types of fuels necessary for its owned and controlled generating
facilities, including natural gas, coal, and oil.
NEG uses derivative financial instruments to provide flexible pricing to its
customers and suppliers and manage its purchase and sale commitments, including
those related to NEG's owned and controlled generating facilities, gas
pipelines, and storage facilities. NEG also uses derivative financial
instruments to reduce its exposure relative to the volatility of market prices.
Financial instruments are also used to hedge interest rate and currency
volatility.
NEG also evaluates and implements highly structured long-term and short-term
transactions. These transactions include (1) management of third party energy
assets, (2) short-term tolling arrangements, (3) management of the requirements
of aggregated customer load through full requirement contracts,
(4) restructured independent power project contracts, and (5) purchase and sale
of transportation, storage and transmission rights through auctions and over-
the-counter markets.
NEG's energy marketing and trading operations provide the following products
and services:
Electricity Marketing and Trading. NEG aggregates electricity and related
products from its owned and controlled generating facilities and other from
generators and marketers. NEG then packages and sells such electricity and
related products to electric utilities, municipalities, cooperatives, large
industrials, aggregators and other marketing and retail entities. NEG also
buys, sells and transports power to and from third parties under a variety of
short-term contracts. NEG manages all of its power positions, whether from its
owned and controlled generating facilities or from other contracts, as an
integrated power portfolio.
Natural Gas Marketing and Trading. NEG purchases natural gas from a variety
of suppliers under daily, monthly, seasonal and long-term contracts with
pricing, delivery and volume schedules to accommodate the requirements of NEG's
owned and controlled generating facilities and its obligations under long-term
structured transactions. NEG also buys, sells and arranges transportation to
and from third parties under a variety of short-term agreements. NEG's natural
gas marketing activities include contracting to buy natural gas from suppliers
at various points of receipt, arranging transportation, negotiating the sale of
natural gas, and matching natural gas receipt and delivery points to the
customer based on geographic logistics and delivery costs. NEG sold an average
of 6.5 Bcf per day of natural gas in 2000 transported on 44 pipelines
throughout North America.
NEG arranges for transportation of natural gas on interstate and intrastate
pipelines through a variety of means, including short-term and long-term firm
and interruptible agreements. NEG also enters into various short-term and long-
term firm and interruptible agreements for natural gas storage in order to
provide peak delivery services to satisfy winter heating and summer electric
generating demands.
Coal, Oil and Emissions Marketing and Trading. NEG buys, secures
transportation for and manages the sulfur content of the coal and oil
requirements of its owned and controlled generating facilities. NEG also
purchases and sells coal, oil, and emissions credits from and to third parties.
Load Management or Full Requirements Arrangements. Deregulation of the
energy industry has provided many consumers with the ability to seek and
receive customized energy services. Consumers are particularly interested in
purchasing volumes of fuel and electricity that closely match their specific
needs. In order to satisfy this consumer demand, an increasing number of
companies aggregate blocks of customers, buy power at wholesale and deliver it
to end-user consumers. As part of NEG's integrated generation, energy marketing
and trading business, NEG enters into contracts to supply natural gas and
electricity, known as load management or full requirements supply, to these
load aggregator companies in the exact amount and quality purchased by their
end-user customers.
39
NEG's largest load management contracts are the wholesale standard offer
service agreements with affiliates of New England Power, from whom NEG
purchased 4,800 MW of owned and controlled generating capacity in 1998. Under
the wholesale standard offer service agreements, NEG supplies a fixed
percentage of the full requirements of the retail customers of New England
Power's affiliates who receive standard offer service in Massachusetts and
Rhode Island. The price NEG receives for the electricity it provides under the
wholesale standard offer service agreements has a fixed floor (which escalates
automatically over time) and is subject to upward escalation if the price of
natural gas and fuel oil exceed a specified threshold. NEG receives a fixed
price for the electricity it provides under the standard offer service
agreements. Standard offer service is intended to stimulate the retail
electric markets in these states by gradually increasing the fixed price of
electricity under this service. The fixed price increases by a specified
amount each year and also increases if the prices of natural gas and fuel oil
exceed a specified threshold. These retail customers may select alternative
suppliers at any time. NEG's sales volumes and revenues under the wholesale
standard offer service agreements totaled 13.2 million MW hours and $563.4
million in 2000. The wholesale standard offer service agreement for
Massachusetts terminates on December 31, 2004, and the wholesale standard
offer service agreement for Rhode Island terminates on December 31, 2009.
Fuel Supply, Transport, and Electric Transmission Management. NEG enters
into contracts for fuel supply, fuel transportation, and electric transmission
primarily to meet the needs of its owned and controlled generating facilities
and to capitalize on other trading opportunities.
Risk Management Controls. NEG manages the risk associated with its
marketing and trading operations through a comprehensive set of policies and
procedures involving senior levels of its management. NEG's senior management
sets value-at-risk limitations and regularly reviews NEG's risk management
policies and procedures. Within this framework, NEG's risk management
committee oversees all of NEG's marketing and trading activities. All of NEG's
risk management models are validated by third party experts, such as
independent accountants and consultants with extensive experience in specific
derivative applications.
NEG's risk management group is structured as a separate unit in its
organization. This management group is responsible for the day-to-day
enforcement of the policies, procedures and limits of its trading and
marketing activities and evaluating the risks inherent in proposed
transactions. These key activities include evaluating and monitoring the
creditworthiness of trading counterparties, setting and monitoring volumetric
and loss limits on portfolio risks, establishing and monitoring trading limits
on products, as well as on individual traders, validating trading
transactions, and performing daily portfolio valuation reporting including
mark-to-market valuation.
40
Description of Generating Facilities. The following table provides
information regarding each of NEG's owned or controlled operating generating
facilities, as well as those under construction as of December 31, 2000.
NEG Net
Interest Date of
Total in Total Primary Output Sales Commercial
Generating Facility State MW MW(1) Structure Fuel Method Status Operation
------------------- -------------- -------- --------- --------------- ------------------------- ------------ ----------
New England Region
Brayton Point
Station............. MA 1,599 1,599 Owned Coal/Oil Competitive Market Operational 1963-1974
Salem Harbor
Station............. MA 745 745 Owned Coal/Oil Competitive Market Operational 1952-1972
Bear Swamp Facility.. MA 599 599 Leased Water Competitive Market Operational 1974
Manchester St.
Station............. RI 495 495 Owned Natural Gas Competitive Market Operational 1995
Connecticut River
System.............. NH/VT 484 484 Owned Water Competitive Market Operational 1909-1957
Masspower............ MA 267 35 Owned Natural Gas Power Purchase Agreements Operational 1993
Pittsfield(2)........ MA 173 143 Leased Natural Gas Power Purchase Agreements Operational 1990
and Competitive Market
Milford Power(2)..... MA 171 96 Contract Natural Gas Competitive Market Operational 1994
Deerfield River
System.............. MA/VT 83 83 Owned Water Competitive Market Operational 1912-1927
Pawtucket Power(2)... RI 69 69 Contract Natural Gas Competitive Market Operational 1991
14 Smaller
Facilities(2)....... Various 193 193 Contract Renewable/Waste Competitive Market Operational Various
Millennium(3)........ MA 360 360 Owned Natural Gas Competitive Market Construction 2001
Lake Road............ CT 840 840 Leased Natural Gas Competitive Market Construction 2001
------ -----
Subtotal............ 6,078 5,741
Mid-Atlantic and New York
Region
Selkirk.............. NY 345 145 Owned Natural Gas Power Purchase Agreements Operational 1992
and Competitive Market
Carneys Point........ NJ 269 135 Owned Coal Power Purchase Agreements Operational 1994
Logan................ NJ 225 113 Owned Coal Power Purchase Agreement Operational 1994
Northampton.......... PA 110 55 Owned Waste Coal Power Purchase Agreements Operational 1995
Panther Creek........ PA 80 40 Owned Waste Coal Power Purchase Agreement Operational 1992
Scrubgrass........... PA 87 44 Owned Waste Coal Power Purchase Agreement Operational 1993
Madison.............. NY 12 12 Owned Wind Competitive Market Operational 2000
Liberty.............. PA 530 530 Contract Natural Gas Competitive Market Construction 2002
------ -----
Subtotal............ 1,658 1,074
Midwest Region
Georgetown........... IN 240 160 Contract Natural Gas Competitive Market Operational 2000
Ohio Peakers......... OH 141 141 Owned Natural Gas Competitive Market Operational 2001
------ -----
Subtotal............ 381 301
Southern Region
Indiantown........... FL 360 126 Owned Coal Power Purchase Agreement Operational 1995
Cedar Bay............ FL 269 135 Owned Coal Power Purchase Agreement Operational 1994
Attala............... MS 500 500 Owned Natural Gas Competitive Market Construction 2001
SRW(4)............... TX 420 250 Contract Natural Gas Competitive Market Construction 2001
------ -----
Subtotal............ 1,549 1,011
Western Region
Hermiston............ OR 474 237 Owned Natural Gas Power Purchase Agreement Operational 1996
Colstrip............. MT 40 5 Owned Waste Coal Power Purchase Agreement Operational 1990
Mountain View........ CA 44 44 Owned(5) Wind Competitive Market Construction 2001
La Paloma............ CA 1,121 1,121 Leased Natural Gas Competitive Market Construction 2002
------ -----
Subtotal............ 1,679 1,407
------ -----
Total............ 11,345 9,534
====== =====
- -------
(1) NEG's net interest in an independent power project is determined by
multiplying NEG's percentage of the project's expected cash flow by the
project's total MW.
(2) NEG controls all or a portion of the output of 17 smaller generating
facilities under long-term power purchase agreements. In return for NEG's
assumption of the purchase obligations under these agreements from the New
England Power Company, the New England Power Company has agreed to pay an
average of $111 million per year through January 2008 to offset NEG's
payment obligations under these contracts. The facilities NEG controls in
whole or in part through these power purchase agreements include the
Milford Power Project, the Pittsfield Project, the Pawtucket Power
Project, and 14 other small generating facilities with a total generation
capacity of 193 MW fueled by municipal waste, water, landfill gas, or
wood. The power purchase agreements terminate between 2009 and 2029.
(3) Millenium achieved commercial operation in April 2001.
(4) An NEG subsidiary entered into a contract with SRW Cogeneration Limited
partnership dated as of July 30, 1999 pursuant to which NEG would control
250 MW of a 420 MW cogeneration facility the limited partnership is
building and is to operate. The limited partnership has provided NEG with
notice of its purported termination of the contract, which NEG is
contesting.
(5) NEG has executed a contract to purchase the Mountain View facility. The
purchase has not yet closed.
41
Competition. Some of the competitive factors affecting the results of
operations of NEG's owned and controlled generating facilities include new
market entrants, construction by others of more efficient generating
facilities and the number of years and extent of operations in a particular
energy market. Other competitors operate generating facilities in the regions
where NEG has invested in generation facilities. Although local permitting and
siting issues often reduce the risk of a rapid growth in supply of generating
capacity in any particular region, projects are likely to be built over time
which will increase competition and lower the value of some of NEG's
generating facilities.
There is also significant competition for the development and acquisition
of domestic unregulated generating facilities. NEG competes against a number
of other participants in the non-utility power generation industry.
Competitive factors relevant to the non-utility power industry include
financial resources, development expenses, and regulatory factors. Some of
NEG's competitors have greater financial resources than NEG has.
NEG's energy marketing and trading operations compete with other energy
merchants based on the ability to aggregate supplies at competitive prices
from different sources and locations and to efficiently utilize transportation
from third-party pipelines and transmission from electric utilities. These
operations also compete against other energy marketers on the basis of their
relative financial position and access to credit sources. This competitive
factor reflects the tendency of energy customers, wholesale energy suppliers,
and transporters to seek financial guarantees and other assurances that their
energy contracts will be satisfied. As pricing information becomes
increasingly available in the energy marketing and trading business and as
deregulation in the electricity markets continues to evolve, NEG anticipates
that its energy, marketing and trading operations will experience greater
competition and downward pressure on per-unit profit margins.
Natural Gas Transmission Business
NEG's natural gas transmission business currently consists of the PG&E GT-
Northwest (PG&E GTN) pipeline, a 5.2% interest in the Iroquois Gas
Transmission System and the North Baja pipeline under development.
The following table summarizes NEG's gas transmission pipelines:
12 month
In Service Capacity capacity Length Ownership
Pipeline Name Location Date (MMcf/d) factor (miles) Interest
- ------------- -------- ---------- -------- -------- ------- ---------
PG&E GT-Northwest....... ID, OR, WA 1961 2,700 96% 1,335 100%
Iroquois Gas
Transmission System.... NY 1991 900 95% 375 5.2%
North Baja.............. AZ, CA, 2002 500 N/A 80 100%
PG&E GT-Northwest (PG&E GTN). PG&E GTN owns and operates the PG&E GTN
pipeline. This pipeline consists of over 1,300 miles of natural gas
transmission mainline pipe with a capacity of 2.7 Bcf of natural gas per day.
The PG&E GTN pipeline begins at the British Columbia-Idaho border, extends
through northern Idaho, southeastern Washington and central Oregon, and ends
on the Oregon-California border where it connects with other pipelines. This
pipeline is the largest transporter of Canadian natural gas into the United
States. For the year ended December 31, 2000, this pipeline transported 967
Bcf of natural gas, resulting in a 5% growth in transported volumes from the
previous year. Since this pipeline commenced commercial operations in 1961, it
has experienced a five-fold increase in peak system capacity. The PG&E GTN
pipeline is the only interstate pipeline directly connecting the large and
rapidly growing gas markets of California, Nevada, and the Pacific Northwest
with the abundant natural gas supplies of the Western Canadian Sedimentary
Basin and potentially the natural gas rich North Slope of Alaska and Northwest
Territories of Canada. The pipeline transports over 30% of California's
natural gas demand requirements and over 20% of the Pacific Northwest natural
gas demand requirements.
42
The mainline system of the PG&E GTN pipeline consists of two parallel
pipelines with 13 compressor stations totaling approximately 414,450
horsepower. This dual-pipeline system consists of approximately 639 miles of
36-inch mainline pipe and approximately 590 miles of 42-inch mainline pipe.
The original pipeline commenced commercial operations in 1961 and was expanded
throughout the 1960's and 1970, 1981, 1993, 1995 and 1998. The PG&E GTN
pipeline includes two laterals, the Coyote Springs Lateral that supplies
natural gas to Portland General Electric Company and the Medford Lateral that
supplies natural gas to Avista Utilities. This pipeline interconnects with
facilities owned by the Utility at the Oregon-California border and with
interstate pipelines in northern Oregon, eastern Washington, and southern
Oregon. It also delivers gas along various mainline delivery points to two
local gas distribution companies of various mainline delivery points.
The PG&E GTN pipeline provides firm and interruptible transportation
services to third party shippers on a nondiscriminatory basis. Firm
transportation services means that the customer has the highest priority
rights to ship a quantity of gas between two points for the term of the
applicable contract. The pipeline's long-term capacity is 100% committed to
firm transportation services agreements with terms in excess of one year. The
remaining terms of these agreements range between one and 26 years with a
volume-weighted average of approximately 13 years. In addition, due to
weather, maintenance schedules, and other conditions, additional firm capacity
may become available on a short-term basis. Interruptible transportation is
offered when short-term capacity is available due to a firm transportation
customer not fully utilizing its committed capacity. Hub services are also
offered, which allow customers the ability to park or lend volumes of gas on
the pipeline.
The PG&E GTN pipeline currently provides transportation services for over
65 customers, including local retail gas distribution utilities, electric
utilities that utilize natural gas to generate electricity, natural gas
marketing companies that purchase and resell natural gas on a wholesale and
retail basis, natural gas producers, and industrial companies. The customers
are responsible for securing their own gas supplies and delivering them to the
pipeline system. The customers' natural gas supplies are transported either to
downstream pipelines and distribution companies or directly to points of
consumption.
PG&E GTN's current rates were set in a rate settlement approved by the FERC
in September 1996.
North Baja Pipeline. NEG recently joined with Sempra Energy International
and Mexico's Proxima Gas, S.A. de C.V. to develop a 215-mile pipeline that
will supply natural gas to Northern Mexico and Southern California. This
pipeline will begin at an interconnection with El Paso Natural Gas Company
near Ehrenberg, Arizona, traverse southeastern California and northern Baja
California, Mexico and terminate at an interconnection with the Rosarito
Pipeline south of Tijuana. An application has been filed with the FERC for a
certificate to build the 80-mile U.S. segment of this proposed $230 million
project. Sempra Energy International and Proxima Gas will direct development
of the 135-mile Mexico segment. This pipeline will have an initial capacity of
500 million cubic feet per day with expansion capability to 800 million cubic
feet per day.
NEG has signed agreements with five anchor customers to transport almost
90% of the projected daily capacity of 500,000 million cubic feet of natural
gas. The average term of these agreements is 20 years. NEG is continuing
discussions and negotiations with other potential customers. This pipeline is
projected to be in service by the fourth quarter of 2002. In its initial
design, this pipeline is intended primarily to serve electric generating needs
in northern Mexico and Southern California, as well as industrial and local
distribution company load along the Mexico segment. Further, NEG believes that
this pipeline will also have the potential to serve delivery points along its
entire route.
Competition. NEG's gas transmission business competes with other pipeline
companies for transportation customers on the basis of transportation rates,
access to competitively priced gas supply and growing markets served by its
pipelines, and the quality and reliability of transportation services. The
competitiveness of a pipeline's transportation services to any market is
generally determined by the total delivered natural gas price from a
particular natural gas supply basin to the market served by the pipeline.
43
The PG&E GTN pipeline accesses natural gas supplies from Western Canada and
serves markets in the Pacific Northwest, California, and Nevada. PG&E GTN
competes with other pipelines to access natural gas supplies in Western
Canada, the Rocky Mountain, the Southwest, and British Columbia.
NEG's transportation volumes are also affected by the availability and
economic attractiveness of other energy sources. Hydroelectric generation, for
example, may become available based on ample snowfall and displace demand for
natural gas as a fuel for electric generation. Finally, in providing
interruptible and short-term firm transportation service, NEG competes with
released capacity offered by shippers holding firm contracts for NEG's
capacity.
44
ENVIRONMENTAL MATTERS
Environmental Matters
The following discussion includes certain forward-looking information
relating to estimated expenditures for environmental protection measures and
the possible future impact of environmental compliance. This information below
reflects current estimates, which are periodically evaluated and revised.
Future estimates and actual results may differ materially from those indicated
below. These estimates are subject to a number of assumptions and
uncertainties, including changing laws and regulations, the ultimate outcome
of complex factual investigations, evolving technologies, selection of
compliance alternatives, the nature and extent of required remediation, the
extent of the facility owner's responsibility, and the availability of
recoveries or contributions from third parties.
PG&E Corporation, the Utility, and various NEG affiliates (including USGen
New England, Inc. (USGenNE)) are subject to a number of federal, state, and
local laws and regulations designed to protect human health and the
environment by imposing stringent controls with regard to planning and
construction activities, land use, air and water pollution, and treatment,
storage, and disposal of hazardous or toxic materials. These laws and
regulations affect future planning and existing operations, including
environmental protection and remediation activities. The Utility has
undertaken compliance efforts with specific emphasis on its purchase, use, and
disposal of hazardous materials, the cleanup or mitigation of historic waste
spill and disposal activities, and the upgrading or replacement of the
Utility's bulk waste handling and storage facilities. The costs of compliance
with environmental laws and regulations generally have been recovered in
rates.
Although the Utility has sold most of its fossil-fueled power plants and
its geothermal generation facilities in connection with electric industry
restructuring, the Utility has retained liability for certain required
environmental remediation of pre-closing soil or groundwater contamination for
fossil and geothermal generation facilities that have been sold. See "Utility
Operations--Electric Utility Operations--California Electric Industry
Restructuring--Voluntary Generation Asset Divestiture" above.
Environmental Protection Measures
The estimated expenditures of PG&E Corporation's subsidiaries for
environmental protection are subject to periodic review and revision to
reflect changing technology and evolving regulatory requirements. It is likely
that the stringency of environmental regulations will increase in the future.
As a result of the Utility's divestiture of most of its fossil-fueled power
plants and its geothermal generation facilities, the Utility's oxides of
nitrogen (NOx) emission reduction compliance costs have been reduced
significantly.
Air Quality
Pacific Gas and Electric Company's thermal electric generating plants are
subject to numerous air pollution control laws, including the California Clean
Air Act (CCAA) with respect to emissions. Pursuant to the CCAA and the Federal
Clean Air Act, two of the local air districts in which the Utility owns and
operates fossil-fueled generating plants have adopted final rules that require
a reduction in NOx emissions from the power plants of approximately 90% by
2004 (with numerous interim compliance deadlines).
The Gas Accord authorizes $42 million to be included in rates through 2002
for gas NOx retrofit projects related to natural gas compressor stations on
Pacific Gas and Electric Company's Line 300, which delivers gas from the
Southwest. Other air districts are considering NOx rules that would apply to
the Utility's other natural gas compressor stations in California. Eventually
the rules are likely to require NOx reductions of up to 80% at many of these
natural gas compressor stations. The Utility currently estimates that the
total cost of complying with these various NOx rules will be up to $101
million from 2001 through 2004. The Utility is planing to replace some
compressor units because proven NOx retrofit technology is not available for
these units. Substantially all of these costs will be capital costs.
45
Compliance by NEG affiliates with certain future regulatory requirements
limiting the total amount of NOx emissions from its fossil-fueled power plants
is expected to be achieved through installation of additional controls, fuel
switching, and purchase of NOx allowances. USGenNE has agreed to be bound by a
number of state and regional initiatives that will require it to achieve
significant reductions of sulfur dioxide (SO2) and NOx emissions by the time
its older fossil-fueled power plants have been in operation for 40 years or by
2010, whichever comes first. It is expected that USGenNE can meet these
requirements through utilization of allowances it currently owns, installation
of additional controls, or purchase of additional allowances. (SO2 allowances
are emission credits that are traded in a national market under the United
States Environmental Protection Agency's (EPA) Acid Rain Program. NOx
allowances are emission credits that are traded in a regional market
consisting of seven Northeast states known as the Ozone Transport Region.)
In October and November 1999, the EPA and several states filed suits or
announced their intention to file suits against a number of coal-fired power
plants in Midwestern and Eastern states. These suits relate to alleged
violations of the Clean Air Act. More specifically, they allege violations of
the deterioration prevention and non-attainment provisions of the Clean Air
Act's new source review requirements arising out of certain physical changes
that may have been made at these facilities without first obtaining the
required permits.
In May 2000, USGenNE received a request for information pursuant to Section
114 of the Clean Air Act from the EPA seeking detailed operating and
maintenance history for the Salem Harbor and Brayton Point power plants, which
USGenNE acquired in 1998 from the New England Electric System (NEES). USGenNE
believes that this request for information is part of the EPA's industry-wide
investigation of coal-fired electric power generators to determine compliance
with environmental requirements under the Clean Air Act associated with
repairs, maintenance, modifications, and operational changes made to coal-
fired facilities over the years. If the EPA were to find that there were
physical changes made in the past that were undertaken without first receiving
the required permits under the Clean Air Act, then penalties may be imposed
and further emission reductions might be necessary at these plants.
A new ambient air quality standard was adopted by the EPA in July 1997 to
address emissions of fine particulate matter. It is widely understood that
attainment of the fine particulate matter standard may require reductions in
NOx and SO2, although under the time schedule announced by the EPA when the
new standard was adopted, non-attainment areas were not to have been
designated until 2002 and control measures to meet the standard were not to
have been identified until 2005. In May 1999, the United States Court of
Appeals for the District of Columbia Circuit held that Section 109(b)(1) of
the Clean Air Act, the section of the Clean Air Act requiring the promulgation
of national ambient air quality standards, as interpreted by the EPA, was an
unconstitutional delegation of legislative power. The Court of Appeals
remanded both the fine particulate matter standard and the revised ozone
standard to allow the EPA to determine whether it could articulate a
constitutional application of Section 109(b)(1). On February 27, 2001, the
Supreme Court, in Whitman v. American Trucking Associations, Inc., reversed
the Circuit Court's judgment on this issue and remanded the case to the Court
of Appeals to dispose of any other preserved challenges to the particulate
matter and ozone standards. Accordingly, as the final application of the
revised particulate matter ambient air quality standard is potentially subject
to further judicial proceedings, the impact of this standard on the Utility's
and NEG's facilities is uncertain at this time. If an ambient air quality
standard for fine particulates is promulgated, further NOx and SO2 reductions
may be required for those Utility and NEG facilities located in areas where
sampling indicates the ambient air does not comply with the final standards
that are adopted.
Since the adoption of the United Nations Framework on Climate Change in
1992, there has been worldwide attention with respect to greenhouse gas
emissions. In December 1997, the Clinton Administration participated in the
Kyoto, Japan negotiations, where the basis of a Climate Change treaty was
formulated. Under the treaty, known as the Kyoto Protocol, the United States
would be required, by 2008-2012, to reduce its greenhouse gas emissions by 7%
from 1990 levels. However, because of opposition to the treaty in the United
States Senate, the Kyoto Protocol has not been submitted to the Senate for
ratification. If the U.S. Senate ultimately ratifies the Kyoto Protocol and
greenhouse gas emission reduction requirements are implemented, the resulting
limitations on power plant carbon dioxide emissions could have a material
adverse impact on all fossil fuel-fired facilities, including Utility and NEG
facilities.
46
The EPA has announced that it will regulate steam electric generating
plants under Title III of the Clean Air Act, which addresses emissions of
hazardous air pollutants from specific industrial categories. Power plants are
a source of mercury air emissions. The EPA recently signed a regulatory
finding that commits it to propose a mercury-emissions rule applicable to
fossil-fuel fired power plants by 2003 and to promulgate a final rule by 2004.
According to this regulatory finding, affected facilities will have to comply
with this final rule in 2007-2008. The rulemaking process will likely include
significant stakeholder and public participation both before and after the
emission standards are proposed. The applicable control level is uncertain, as
is the cost of these future rules.
In addition to the EPA, states may impose more stringent air emissions
requirements. The Commonwealth of Massachusetts is considering the adoption of
more stringent air emission reductions from electric generating facilities. If
adopted, these requirements will impact Salem Harbor and Brayton Point. NEG
has proposed an emission reduction plan that may include modernization of the
Salem Harbor power plant and use of advanced technologies for emissions
removal. It is also studying various advanced technologies for emissions
removal for the Brayton Point power plant.
NEG currently estimates that USGenNE's total capital cost for complying
with the requirements described here will be approximately $300 million.
Water Quality
Pacific Gas and Electric Company's existing power plants, including Diablo
Canyon, are subject to federal and state water quality standards with respect
to discharge constituents and thermal effluents. The Utility's fossil-fueled
power plants comply in all material respects with the discharge constituents
standards and the thermal standards. Additionally, pursuant to Section 316(b)
of the Federal Clean Water Act, the Utility is required to demonstrate that
the location, design, construction, and capacity of power plant cooling water
intake structures reflect the best technology available (BTA) for minimizing
adverse environmental impacts at its existing water-cooled thermal plants. The
Utility has submitted detailed studies of each power plant's intake structure
to various governmental agencies and each plant's existing intake structure
was found to meet the BTA requirements.
The Diablo Canyon Power Plant employs a "once through" cooling water system
which is regulated under a National Pollutant Discharge Elimination System
(NPDES) permit issued by the Central Coast Regional Water Quality Control
Board (Central Coast Board). This permit allows Diablo Canyon to discharge the
cooling water at a temperature no more than 22 degrees above ambient receiving
water, and requires that the beneficial uses of the water be protected. The
beneficial uses of water in this region include industrial water supply,
recreation, commercial/sport fishing, marine and wildlife habitat, shellfish
harvesting, and preservation of rare and endangered species. In January 2000,
the Central Coast Board issued a proposed draft cease and desist order
alleging that, although the temperature limit has never been exceeded, Diablo
Canyon's discharge was not protective of beneficial uses. In October 2000, the
Central Coast Board and the Utility reached a tentative settlement of this
matter pursuant to which the Central Coast Board has agreed to find that the
Utility's discharge of cooling water from the Diablo Canyon plant protects
beneficial uses and that the intake technology meets the BTA requirements. As
part of the settlement, the Utility will take measures to preserve certain
acreage north of the plant and will fund approximately $4.5 million in
environmental projects related to coastal resources. The parties are
negotiating the documentation of the settlement. The final agreement will be
subject to public comment prior to final approval by the Central Coast Board
and, once signed by the parties, will be incorporated in a consent decree to
be entered in California Superior Court.
For a description of another environmental regulatory matter affecting the
Utility, see "Item 3--Legal Proceedings--Moss Landing Power Plant," below.
NEG's existing power plants, including USGenNE facilities, are subject to
federal and state water quality standards with respect to discharge
constituents and thermal effluents. Three of the fossil-fueled plants owned
and operated by USGenNE are operating pursuant to NPDES permits that have
expired. As to the facilities for which their NPDES permit has expired, permit
renewal applications are pending, and it is anticipated that all
47
three facilities will be able to continue to operate under existing terms and
conditions until new permits are issued. It is estimated that USGenNEs cost to
comply with the new permit conditions could be as much as $55 million through
2005.
The promulgation or modification of statutes, regulations, or water quality
control plans at the federal, state, or regional level may impose increasingly
stringent cooling water discharge requirements on the Utility's and NEG's power
plants in the future. Costs to comply with new permit conditions required to
meet more stringent requirements that might be imposed cannot be estimated at
the present time.
Hazardous Waste Compliance and Remediation
PG&E Corporation subsidiaries assess, on an ongoing basis, measures that may
need to be taken to comply with laws and regulations related to hazardous
materials and hazardous waste compliance and remediation activities. The
Utility has a comprehensive program to comply with hazardous waste storage,
handling, and disposal requirements promulgated by the EPA under the RCRA and
the Comprehensive Environmental Response, Compensation, and Liability Act
(CERCLA), along with other state hazardous waste laws and other environmental
requirements.
One part of this program is aimed at assessing whether and to what extent
remedial action may be necessary to mitigate potential hazards posed by certain
disposal sites and retired manufactured gas plant sites. During their
operation, manufactured gas plants produced lampblack and tar residues,
byproducts of a process that Pacific Gas and Electric Company, its predecessor
companies, and other utilities used as early as the 1850s to manufacture gas
from coal and oil. As natural gas became widely available (beginning about
1930), the Utility's manufactured gas plants were removed from service. The
residues that may remain at some sites contain chemical compounds that now are
classified as hazardous. The Utility has identified and reported to federal and
California environmental agencies 96 manufactured gas plant sites that operated
in the Utility's service territory. The Utility owns all or a portion of 29 of
these manufactured gas plant sites. The Utility has a program, in cooperation
with environmental agencies, to evaluate and take appropriate action to
mitigate any potential health or environmental hazards at sites that the
Utility owns. It is estimated that the Utility's program may result in
expenditures of approximately $5 million in 2001. The full long-term costs of
the program cannot be determined accurately until a closer study of each site
has been completed. It is expected that expenses will increase as remedial
actions related to these sites are approved by regulatory agencies or if the
Utility is found to be responsible for cleanup at sites it currently does not
own.
In addition to the manufactured gas plant sites, the Utility may be required
to take remedial action at certain other disposal sites if they are determined
to present a significant threat to human health and the environment because of
an actual or potential release of hazardous substances. With respect to the
Casmalia site near Santa Maria, California, the Utility and several other
generators of waste sent to the site have entered into a court-approved
agreement with the EPA that requires these generators to perform certain site
investigation and mitigation measures, and provides a release from liability
for certain other site cleanup obligations. Recently, the EPA asserted that the
Utility sent more waste to the site than was believed previously. The Utility
is evaluating the significance of this information, which may impact the amount
the Utility ultimately has to pay for this site. Although the Utility has not
been formally designated a potentially responsible party (PRP) with respect to
the Geothermal Incorporated site in Lake County, California, the Central Valley
Regional Water Quality Control Board and the California Attorney General's
office have directed the Utility and other parties to initiate measures with
respect to the study and remediation of that site.
In addition, Pacific Gas and Electric Company has been named as a defendant
in several civil lawsuits in which plaintiffs allege that the Utility is
responsible for performing or paying for remedial action at sites the Utility
no longer owns or never owned.
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The cost of hazardous substance remediation ultimately undertaken by
Pacific Gas and Electric Company is difficult to estimate. It is reasonably
possible that a change in the estimate may occur in the near term due to
uncertainty concerning the Utility's responsibility, the complexity of
environmental laws and regulations, and the selection of compliance
alternatives. At December 31, 2000, the Utility expected to spend $320 million
for hazardous waste remediation costs at identified sites, including divested
fossil-fueled power plants, where such costs are probable and quantifiable.
(Although the Utility has sold most of its fossil-fueled power plants, the
Utility has retained pre-closing environmental liability with respect to these
plants.) The Utility had an accrued liability of $294 million at December 31,
2000, representing the discounted value of these costs. Environmental
remediation at identified sites may be as much as $462 million if, among other
things, other PRPs are not financially able to contribute to these costs or
further investigation indicates that the extent of contamination or necessary
remediation is greater than anticipated at sites for which the Utility is
responsible. The Utility estimated the upper limit of the range of costs using
assumptions least favorable to the Utility based upon a range of reasonably
possible outcomes. Costs may be higher if the Utility is found to be
responsible for cleanup costs at additional sites or identifiable possible
outcomes change.
USGenNE acquired the onsite environmental liability associated with its
acquisition of electric generating facilities from NEES, but did not acquire
any offsite liability associated with the past disposal practices at the
acquired facilities. NEG has obtained pollution liability and environmental
remediation insurance coverage to limit the financial risk associated with the
on-site pollution liability at all of its facilities.
During April 2000, an environmental group served various affiliates of NEG,
including USGenNE, with a notice of intent to file a citizen's suit under
RCRA. The group stated that it planned to allege that USGenNE, as the
generator of fossil fuel combustion wastes at Salem Harbor and Brayton Point,
has contributed and is contributing to the past and present handling, storage,
treatment and disposal of wastes at those facilities which may present an
imminent and substantial endangerment to the public health or the environment.
During September 2000, USGenNE signed a series of agreements with the
Massachusetts Department of Environmental Protection and the environmental
group that address and resolve these matters. The agreements, which have been
filed in federal court and are now incorporated in a consent decree, require,
among other things, that USGenNE alter its existing waste water treatment
facilities at both facilities by replacing certain unlined treatment basins,
submit and implement a plan for the closure of such basins, and perform
certain environmental testing at the facilities. These activities are now well
underway. The cost of these activities is expected to be approximately $21
million.
Potential Recovery of Hazardous Waste Compliance and Remediation Costs
In 1994, the CPUC established a ratemaking mechanism for hazardous waste
remediation costs (HWRC). That mechanism assigns 90% of the includable
hazardous substance cleanup costs to utility ratepayers and 10% to utility
shareholders, without a reasonableness review of such costs or of underlying
activities. Under the HWRC mechanism, 70% of the ratepayer portion of Pacific
Gas and Electric Company's cleanup costs is attributed to its gas department
and 30% is attributed to its electric department. Insurance recoveries are
assigned 70% to shareholders and 30% to ratepayers until both are reimbursed
for the costs of pursuing insurance recoveries. The balance of insurance
recoveries is allocated 90% to shareholders and 10% to ratepayers until
shareholders are reimbursed for their 10% share of cleanup costs. Any
unallocated funds remaining are held for five years and then distributed 60%
to ratepayers and 40% to shareholders over the next five years. The Utility
can seek to recover hazardous substance cleanup costs under the HWRC in the
rate proceeding it deems most appropriate. In connection with electric
industry restructuring, the HWRC mechanism may no longer be used to recover
electric generation-related cleanup costs for contamination caused by events
occurring after January 1, 1998.
For each divested generation facility where the Utility retained
environmental remediation liabilities, the plant's decommissioning cost
estimate was adjusted by the Utility's estimated forecast of environmental
remediation costs. (The buyers assumed the non-environmental decommissioning
liability for these plants.) The CPUC ordered that excess recoveries of
environmental and non-environmental decommissioning accruals related to the
divested plants be used to offset other transition costs. As of December 31,
2000, the Utility has recovered
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from ratepayers approximately $114 million for environmental decommissioning
accrual related to the divested plants. This amount will earn interest at 3%
per year that will be used to meet the future environmental remediation costs
for the divested plants. The net decommissioning accruals recovered from
ratepayers attributable to the non-environmental liability for the divested
plants was approximately $53 million. Because the Utility no longer has this
non-environmental decommissioning liability, it has used this excess recovery
amount to reduce other transition costs.
The $320 million accrued liability at December 31, 2000 mentioned above
includes (1) $140 million related to the pre-closing remediation liability,
discounted to present value at 7%, associated with divested generation
facilities (see further discussion in the "Generation Divestiture" section of
Note 2 of the Notes to the Consolidated Financial Statements of the 2000
Annual Report to Shareholders), and (2) $180 million related to remediation
costs for those generation facilities that the Utility still owns. Of the $320
million environmental remediation liability, the Utility has recovered $168
million through rates, and expects to recover another $87 million in future
rates. The Utility is seeking recovery of the remainder of its costs from
insurance carriers and from other third parties as appropriate.
In 1992, Pacific Gas and Electric Company filed a complaint in San
Francisco County Superior Court against more than 100 of its domestic and
foreign insurers, seeking damages and declaratory relief for remediation and
other costs associated with hazardous waste mitigation. The Utility previously
had notified its insurance carriers that it seeks coverage under its
comprehensive general liability policies to recover costs incurred at certain
specified sites. In general, the Utility's carriers neither admitted nor
denied coverage, but requested additional information from the Utility.
Although the Utility has received some amounts in settlements with certain of
its insurers (approximately $83 million through December 31, 2000), the
ultimate amount of recovery from insurance coverage, either in the aggregate
or with respect to a particular site, cannot be quantified at this time.
Insurance recoveries are subject to the HWRC mechanism discussed above.
Compressor Station Litigation
Several cases have been brought against Pacific Gas and Electric Company
seeking damages from alleged chromium contamination at the Utility's Hinkley,
Topock, and Kettleman Compressor Stations. See Item 3, "Legal Proceedings--
Compressor Station Chromium Litigation" below, for a description of the
pending litigation.
Electric and Magnetic Fields
In January 1991, the CPUC opened an investigation into potential interim
policy actions to address increasing public concern, especially with respect
to schools, regarding potential health risks that may be associated with
electric and magnetic fields (EMF) from utility facilities. In its order
instituting the investigation, the CPUC acknowledged that the scientific
community has not reached consensus on the nature of any health impacts from
contact with EMF, but went on to state that a body of evidence has been
compiled that raises the question of whether adverse health impacts might
exist.
In November 1993, the CPUC adopted an interim EMF policy for California
energy utilities that, among other things, requires California energy
utilities to take no-cost and low-cost steps to reduce EMF from new and
upgraded utility facilities. California energy utilities are required to fund
a $1.5 million EMF education program and a $5.6 million EMF research program
managed by the California Department of Health Services. It is expected that
the CPUC and the California Department of Health Services will complete its
EMF research program by December 2001.
As part of its effort to educate the public about EMF, Pacific Gas and
Electric Company provides interested customers with information regarding the
EMF exposure issue. The Utility also provides a free field measurement service
to inform customers about EMF levels at different locations in and around
their residences or commercial buildings.
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The Utility currently is not involved in third-party litigation concerning
EMF. In August 1996, the California Supreme Court held that homeowners are
barred from suing utilities for alleged property value losses caused by fear
of EMF from power lines. The Court expressly limited its holding to property
value issues, leaving open the question as to whether lawsuits for alleged
personal injury resulting from exposure to EMF are similarly barred. The
Utility was a defendant in civil litigation in which plaintiffs alleged
personal injuries resulting from exposure to EMF. In January 1998, the appeals
court in this matter held that the CPUC has exclusive jurisdiction over
personal injury and wrongful death claims arising from allegations of harmful
exposure to EMF and barred plaintiffs' personal injury claims. Plaintiffs
filed an appeal of this decision with the California Supreme Court. The
California Supreme Court declined to hear the case.
If the scientific community reaches a consensus that EMF presents a health
hazard and further determines that the impact of utility-related EMF exposures
can be isolated from other exposures, the Utility may be required to take
mitigation measures at its facilities. The costs of such mitigation measures
cannot be estimated with any certainty at this time. However, such costs could
be significant, depending on the particular mitigation measures undertaken,
especially if relocation of existing power lines ultimately is required.
Low Emission Vehicle Programs
In December 1995, the CPUC issued its decision in the Low Emission Vehicle
(LEV) proceeding, which approved approximately $42 million in funding for
Pacific Gas and Electric Company's LEV program for the six-year period
beginning in 1996. The CPUC's decision on electric industry restructuring
found that the costs of utility LEV programs should continue to be collected
by the utility for the duration of the six-year period. The Utility continues
to run its LEV program as funded. Annual LEV accomplishment reports are filed
with the CPUC on November 1.
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ITEM 2. Properties.
Information concerning Pacific Gas and Electric Company's electric
generation units, electric and gas transmission facilities, and electric and
gas distribution facilities is included in response to Item 1. All of the
Utility's real properties and substantially all of the Utility's personal
properties are subject to the lien of an indenture that provides security to
the holders of the Utility's First and Refunding Mortgage Bonds.
Information concerning properties and facilities owned by PG&E National
Energy Group, Inc. and other PG&E Corporation subsidiaries is included in the
discussion under the heading of this report entitled "PG&E National Energy
Group, Inc."
ITEM 3. Legal Proceedings.
See Item 1, Business, for other proceedings pending before governmental and
administrative bodies. In addition to the following legal proceedings, PG&E
Corporation and Pacific Gas and Electric Company are subject to routine
litigation incidental to their business.
Pacific Gas and Electric Company Bankruptcy
On April 6, 2001, Pacific Gas and Electric Company filed a voluntary
petition for relief under the provisions of Chapter 11 of the U.S. Bankruptcy
Code in the U.S. Bankruptcy Court for the Northern District of California.
Pursuant to Chapter 11 of the U.S. Bankruptcy Code, the Utility retains
control of its assets and is authorized to operate its business as a debtor in
possession while being subject to the jurisdiction of the Bankruptcy Court.
For more information about the Utility's financial condition and the factors
leading up to the filing for bankruptcy protection, see "Management's
Discussion and Analysis" and Notes 2 and 3 of the 2000 Annual Report to
Shareholders, which portions are incorporated herein by reference and filed as
Exhibit 13 to this report.
Pacific Gas and Electric Company vs. California Public Utilities Commissioners
On November 8, 2000, Pacific Gas and Electric Company filed a lawsuit in
the United States District Court for the Northern District of California
against the CPUC commissioners, asking the court to declare that the federally
approved wholesale power costs the Utility has incurred to serve its customers
are recoverable in retail rates. As of December 31, 2000, the uncollected
wholesale power purchase costs recorded in the Utility's TRA was $6.6 billion.
(As described above, the Utility recognized a fourth quarter 2000 charge to
earnings of $6.9 billion ($4.1 billion after tax), reflecting the write-off of
undercollected power purchase costs and other generation-related regulatory
assets.) The complaint states that the wholesale power costs which the Utility
has prudently incurred are paid pursuant to filed rates which the FERC has
authorized and approved, and that under the United States Constitution and
numerous court decisions, such costs cannot be disallowed by state regulators.
The Utility's complaint also alleges that to the extent that the Utility is
denied recovery of these mandated wholesale power costs by order of the CPUC,
such action constitutes an unlawful taking and confiscation of the Utility's
property. The Utility argues that the CPUC's decisions violate federal
preemption law and the filed rate doctrine, which requires the CPUC to allow
the Utility to recover in full its reasonable procurement costs incurred under
lawful rates and tariffs approved by the FERC, a federal governmental agency.
The complaint also pleads claims under the Commerce Clause, Due Process
Clause, and Equal Protection Clause of the United States Constitution.
On January 29, 2001, the Utility's lawsuit was transferred to the U.S.
District Court for the Central District of California where a similar lawsuit
filed by Southern California Edison is pending. On March 19, 2001, the court
heard argument on the CPUC's motion to dismiss the case. The judge took the
matter under submission.
Wilson vs. PG&E Corporation and Pacific Gas and Electric Company
On February 13, 2001, two complaints were filed against PG&E Corporation
and Pacific Gas and Electric Company in the Superior Court of the State of
California, San Francisco County: Richard D. Wilson v. Pacific
52
Gas and Electric Company et al. ("Wilson I"), and Richard D. Wilson v. Pacific
Gas and Electric Company et al., ("Wilson II").
In Wilson I, the plaintiff alleges that in 1998 and 1999, PG&E Corporation
violated its fiduciary duties and California Business and Professions Code
Section 17200 by causing the Utility to repurchase shares of Pacific Gas and
Electric Company common stock from PG&E Corporation at an aggregate price of
$2.326 billion. The complaint alleges an unlawful business act or practice
under Section 17200 because these repurchases allegedly violated PG&E
Corporation's fiduciary duties, a first priority capital requirement allegedly
imposed by the CPUC's decision approving the formation of a holding company,
and also an implicit public trust imposed by AB 1890, which granted authority
for the issuance of rate reduction bonds. The complaint seeks to enjoin the
repurchase by the Utility of any more of its common stock from PG&E
Corporation or other entities or persons unless good cause is shown, and seeks
restitution from PG&E Corporation of $2.326 billion, with interest, on behalf
of the Utility. The complaint also seeks an accounting, costs of suit, and
attorney's fees.
In Wilson II, the plaintiff alleges that PG&E Corporation, the Utility, and
other subsidiaries have been parties to a tax-sharing arrangement under which
PG&E Corporation annually files consolidated federal and state income tax
returns for, and pays, the income taxes of PG&E Corporation and participating
subsidiaries. According to the plaintiff, between 1997 and 1999, PG&E
Corporation collected $2.957 billion from the Utility under this tax-sharing
arrangement, but paid only $2.294 billion (net of refunds) to all governments
under the tax-sharing arrangement. Plaintiff alleges that these monies were
held under an express and implied trust to be used by PG&E Corporation to pay
the Utility's share of income taxes under the tax-sharing arrangement.
Plaintiff alleges that PG&E Corporation overcharged the Utility $663 million
under the tax-sharing arrangement and has declined voluntarily to return these
monies to the Utility, in violation of the alleged trust, the alleged first
priority capital condition, and California Business and Professions Code
Section 17200. The complaint seeks to enjoin PG&E Corporation from engaging in
the activities alleged in the complaint (including the tax-sharing
arrangement), and seeks restitution from PG&E Corporation of $663 million,
with interest, on behalf of the Utility. The complaint also seeks an
accounting, costs of suit, and attorney's fees.
PG&E Corporation and the Utility believe these complaints to be without
merit. The Utility filed a notice of automatic stay on April 11, 2001,
pursuant to the Bankruptcy Code. PG&E Corporation believes that these actions
also are stayed against PG&E Corporation. PG&E Corporation and the Utility are
unable to predict whether the outcome of this litigation, if it were to
proceed, will have a material adverse affect on their financial condition or
results of operation.
Moss Landing Power Plant
In December 1999, the Utility was notified by the purchaser of its former
Moss Landing power plant that it had identified a cleaning procedure used at
the plant that released heated water and organic debris from the intake, and
that this procedure is not specified in the plant's National Pollutant
Discharge Elimination System (NPDES) permit issued by the Central Coast
Regional Water Quality Control Board (Central Coast Board). The purchaser
notified the Central Coast Board of its findings and the Central Coast Board
requested additional information from the purchaser. The Utility initiated an
investigation of these activities during the time it owned the plant. The
Utility notified the Central Coast Board that it had undertaken an
investigation and that it would present the results to the Central Coast Board
when the investigation was completed. In March 2000, the Central Coast Board
requested the Utility to provide specific information regarding the
"backflush" procedure used at Moss Landing. The Utility provided the requested
information in April 2000. The Utility's investigation indicated that while
the Utility owned Moss Landing, significant amounts of water were discharged
from the cooling water intake. While the Utility's investigation did not
clearly indicate that discharged waters had a temperature higher than ambient
receiving water, the Utility believes that the temperature of the discharged
water was higher than that of the receiving water. In December 2000, the
executive officer of the Central Coast Board made a settlement proposal to the
Utility under which the Utility would pay $10 million, a portion of which
would be used for environmental projects and the balance of which would
constitute civil penalties. Settlement negotiations are continuing.
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PG&E Corporation and the Utility believe that the ultimate outcome of this
matter will not have a material adverse impact on PG&E Corporation's or the
Utility's financial position or results of operations.
Compressor Station Chromium Litigation
Pacific Gas and Electric Company is currently a defendant in nine civil
actions pending in California courts. These cases are (1) Aguayo v. Pacific
Gas and Electric Company, filed March 15, 1995 in Los Angeles County Superior
Court, (2) Aguilar v. Pacific Gas and Electric Company, filed October 4, 1996
in Los Angeles County Superior Court, (3) Acosta, et al. v. Betz Laboratories,
Inc., et al., filed November 27, 1996 in Los Angeles County Superior Court,
(4) Adams v. Pacific Gas and Electric Company and Betz Chemical Company, filed
on July 25, 2000 in Los Angeles Superior Court, (5) Baldonado vs. Pacific Gas
and Electric Company, filed On October 25, 2000 in Los Angeles Superior Court,
(6) Gale v. Pacific Gas and Electric Company, filed on January 30, 2001 in Los
Angeles Superior Court, (7) Monice v. PG&E, filed March 15, 2001, in San
Bernardino County Superior Court, (8) Puckett v. PG&E, filed March 30, 2001,
in Los Angeles Superior Court, and (9) Alderson, et al. v. PG&E Corporation,
Pacific Gas and Electric Company, Betz Chemical Company, et al., filed April
11, 2001, in Los Angeles Superior Court. PG&E has not yet been served with the
complaint in Gale v. PG&E, Puckett v. PG&E, or Alderson v. PG&E. There are now
approximately 1,150 plaintiffs in the compressor station chromium litigation
with claims against the Utility. PG&E Corporation has been named as a
defendant in Alderson v. PG&E, et al., a complaint brought on behalf of
approximately 100 plaintiffs. PG&E Corporation has not yet been served with
the complaint. Betz Chemical Company (Betz), the supplier of water treatment
products containing chromium used at the gas compressor stations, also was
named as a defendant in some of these cases. During 2000, pursuant to a
settlement that Betz reached with the approximately 1,650 plaintiffs suing
Betz, the Utility received a credit of up to $40 million to be allocated among
the approximately 900 plaintiffs suing the Utility at the time of the Betz
settlement. The credit will apply to future awards of damages against the
Utility with respect to all claims and causes of actions by these plaintiffs
except claims for punitive or exemplary damages.
Each of the complaints alleges personal injuries and seek compensatory and
punitive damages in an unspecified amount arising out of alleged exposure to
chromium contamination in the vicinity of the Utility's gas compressor
stations located at Kettleman, Hinkley, and Topock, California. The plaintiffs
include current and former Utility employees and their relatives, residents in
the vicinity of the compressor stations, and persons who visited the gas
compressor stations. The plaintiffs also include spouses or children of these
plaintiffs who claim loss of consortium or wrongful death.
The discovery referee has set the procedures for selecting 18 trial test
plaintiffs and 2 alternates in the Aguayo, Acosta, and Aguilar cases (the
"Aguayo Litigation"). Ten of these trial test plaintiffs were selected by
plaintiffs' counsel, seven plaintiffs were selected by defense counsel, and
one plaintiff and two alternates were selected at random. Although a date for
the first test trial in the Aguayo Litigation has been set for July 2, 2001,
in Los Angeles Superior Court, the Utility's Chapter 11 bankruptcy filing on
April 6, 2001, automatically stayed all proceedings.
The Utility is responding to the complaints and asserting affirmative
defenses. The Utility will pursue factual defenses including lack of exposure
to chromium and the inability of chromium to cause certain of the illnesses
alleged and appropriate legal defenses including statute of limitations or
exclusivity of workers' compensation laws. At this stage of the proceedings,
there is substantial uncertainty concerning the claims alleged, and the
Utility is attempting to gather information concerning the alleged type and
duration of exposure, the nature of injuries alleged by individual plaintiffs,
and the additional facts necessary to support its legal defenses, in order to
better evaluate and defend this litigation.
There has been heightened media attention to the chromium litigation for a
variety of reasons. In a letter dated March 27, 2001, the California
Department of Health Services asked the California Environmental Protection
Agency's Office of Environmental Health Hazard Assessment, ("OEHHA") to
establish a public health goal for chromium 6 in drinking water. In turn,
OEHHA has asked the University of California to establish a blue-ribbon panel
of scientists to study the potential of chromium 6 to cause cancer when
ingested. These
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regulatory developments followed in part from substantial media attention
concerning the presence of chromium 6 in certain water sources in Los Angeles,
where the Aguayo Litigation is pending. The chromium issues have also been
mentioned in media stories concerning the California energy crisis. All of
this media and regulatory attention has the potential to adversely impact the
Utility's defense of these cases.
PG&E Corporation believes that the ultimate outcome of this matter will not
have a material adverse impact on its or the Utility's future financial
position or results of operations. See Note 15 of the "Notes to Consolidated
Financial Statements" beginning on page 83 of the 2000 Annual Report to
Shareholders, portions of which are filed as Exhibit 13 to this report.
Texas Franchise Fee Litigation
On December 22, 2000, NEG completed the sale of PG&E GTT to El Paso Energy
Field Services, Inc., a subsidiary of El Paso Energy Corporation. The PG&E GTT
entities which were sold included the defendants in several cases which have
been referred to as the Texas Franchise Fee Litigation in PG&E Corporation's
and the Utility's Annual Report on Form 10-K for the year ended December 31,
1999 and previous reports filed with the Securities and Exchange Commission.
Only one PG&E Corporation affiliate, PG&E Energy Trading--Gas Corporation,
remains as a nominal defendant in some of these cases and any potential
liability of this entity is expected to be immaterial.
ITEM 4. Submission of Matters to a Vote of Security Holders.
Not applicable.
55
EXECUTIVE OFFICERS OF THE REGISTRANTS
"Executive officers," as defined by Rule 3b-7 of the General Rules and
Regulations under the Securities and Exchange Act of 1934, of PG&E Corporation
are as follows:
Age at
December 31,
Name 2000 Position
---- ------------ --------
R. D. Glynn, Jr..... 58 Chairman of the Board, Chief Executive
Officer, and President
T. G. Boren......... 51 Executive Vice President; Chairman,
President, and Chief Executive Officer,
PG&E National Energy Group, Inc.
P. A. Darbee........ 48 Senior Vice President, Chief Financial
Officer, and Treasurer
T. W. High.......... 53 Senior Vice President, Administration and
External Relations
P. C. Iribe......... 50 Senior Vice President; President and Chief
Operating Officer, East Region, PG&E
National Energy Group, Inc.
T. B. King.......... 39 Senior Vice President; President and Chief
Operating Officer, West Region, PG&E
National Energy Group, Inc.
L. E. Maddox........ 45 Senior Vice President; President and Chief
Operating Officer, Trading, PG&E National
Energy Group, Inc.
G. R. Smith......... 52 Senior Vice President; President and Chief
Executive Officer, Pacific Gas and
Electric Company
G. B. Stanley....... 54 Senior Vice President, Human Resources
B. R. Worthington... 51 Senior Vice President and General Counsel
All officers of PG&E Corporation serve at the pleasure of the Board of
Directors. During the past five years, the executive officers of PG&E
Corporation had the following business experience. Except as otherwise noted,
all positions have been held at PG&E Corporation.
Name Position Period Held Office
---- -------- ------------------
R. D. Glynn, Chairman of the Board, January 1, 1998 to present
Jr. ............. Chief Executive
Officer, and President
Chairman of the Board, January 1, 1998 to present
Pacific Gas and
Electric Company
President and Chief June 1, 1997 to present
Executive Officer
President and Chief December 18, 1996 to May 31, 1997
Operating Officer
President and Chief June 1, 1995 to May 31, 1997
Operating Officer,
Pacific Gas and
Electric Company
T. G. Boren...... Executive Vice President August 1, 1999 to present
Chairman, President, and July 1, 2000 to present
Chief Executive
Officer, PG&E National
Energy Group, Inc.
President, and Chief
Executive Officer, PG&E
National Energy Group, August 1, 1999 to June 30, 2000
Inc.
President and Chief February 18, 1992 to July 31, 1999
Executive Officer,
Southern Energy, Inc.
Executive Vice June 1, 1999 to July 31, 1999
President, Southern
Company
Senior Vice President, February 16, 1998 to May 31, 1999
Southern Company
Vice President, Southern July 17, 1995 to February 15, 1998
Company
P. A. Darbee..... Senior Vice President, September 20, 1999 to present
Chief Financial
Officer, and Treasurer
Vice President and Chief June 30, 1997 to September 19, 1999
Financial Officer,
Advance Fibre
Communications, Inc.
Vice President, Chief January 10, 1994 to June 30, 1997
Financial Officer, and
Controller, Pacific
Bell
56
Name Position Period Held Office
---- -------- ------------------
T. W. High....... Senior Vice President, June 1, 1997 to present
Administration and
External Relations
Senior Vice President, June 1, 1995 to May 31, 1997
Corporate Services,
Pacific Gas and
Electric Company
P. C. Iribe...... Senior Vice President January 1, 1999 to present
President and Chief April 6, 2000 to present
Operating Officer, East
Region, PG&E National
Energy Group, Inc.
President and Chief November 1, 1998 to April 5, 2000
Operating Officer, PG&E
Generating Company
(formerly known as U.S.
Generating Company)
Executive Vice President September 1, 1997 to October 31, 1998
and Chief Operating
Officer, U.S.
Generating Company
Executive Vice May 17, 1994 to September 1, 1997
President, Marketing,
Development, and Asset
Management, U.S.
Generating Company
T. B. King....... Senior Vice President January 1, 1999 to present
President and Chief April 6, 2000 to present
Operating Office, West
Region, PG&E National
Energy Group, Inc.
President and Chief November 23, 1998 to present
Operating Officer, PG&E
Gas Transmission
Corporation
President and Chief February 14, 1997 to November 22, 1998
Operating Officer,
Kinder Morgan Energy
Partners, L.P.
Vice President, July 1, 1995 to February 14, 1997
Commercial Operations--
Midwest Region, Enron
Liquid Services
Corporation
L. E. Maddox..... Senior Vice President June 1, 1997 to present
President and Chief April 6, 2000 to present
Operating Officer,
Trading, PG&E National
Energy Group, Inc.
President and Chief May 12, 1997 to April 5, 2000
Executive Officer, PG&E
Energy Trading-Gas
Corporation
President, PennUnion May 1995 to May 1997
Energy Services, L.L.C.
G. R. Smith...... Senior Vice President January 1, 1999 to present
(Please refer to
description of business
experience for
executive officers of
Pacific Gas and
Electric Company
below.)
G. B. Stanley.... Senior Vice President, January 1, 1998 to present
Human Resources
Vice President, Human June 1, 1997 to December 31, 1997
Resources
Vice President, Human July 1, 1996 to May 31, 1997
Resources, Pacific Gas
and Electric Company
B. R.
Worthington...... Senior Vice President June 1, 1997 to present
and General Counsel
General Counsel December 18, 1996 to May 31, 1997
Senior Vice President June 1, 1995 to June 30, 1997
and General Counsel,
Pacific Gas and
Electric Company
57
"Executive officers," as defined by Rule 3b-7 of the General Rules and
Regulations under the Securities and Exchange Act of 1934, of Pacific Gas and
Electric Company are as follows:
Name Age at December 31, 2000 Position
---- ------------------------ --------
G. R. Smith........ 52 President and Chief Executive
Officer
K. M. Harvey....... 42 Senior Vice President, Chief
Financial Officer, and
Treasurer
R. J. Peters....... 46 Senior Vice President and
General Counsel
J. K. Randolph..... 56 Senior Vice President and Chief
of Utility Operations
D. D. Richard, 50 Senior Vice President, Public
Jr. ............... Affairs
G. M. Rueger....... 50 Senior Vice President, and Chief
Nuclear Officer
All officers of Pacific Gas and Electric Company serve at the pleasure of
the Board of Directors. During the past five years, the executive officers of
Pacific Gas and Electric Company had the following business experience. Except
as otherwise noted, all positions have been held at Pacific Gas and Electric
Company.
Name Position Period Held Office
---- -------- ------------------
G. R. Smith.......... President and Chief June 1, 1997 to present
Executive Officer
Chief Financial Officer, December 18, 1996 to May 31, 1997
PG&E Corporation
Senior Vice President June 1, 1995 to May 31, 1997
and Chief Financial
Officer
Vice President and Chief November 1, 1991 to May 31, 1995
Financial Officer
K. M. Harvey......... Senior Vice President, November 1, 2000 to present
Chief Financial
Officer, and Treasurer
Senior Vice President, January 1, 2000 to October 31, 2000
Chief Financial
Officer, Controller,
and Treasurer
Senior Vice President, July 1, 1997 to December 31, 1999
Chief Financial
Officer, and Treasurer
Vice President and June 1, 1995 to June 30, 1997
Treasurer
R. J. Peters......... Senior Vice President January 1, 1999 to present
and General Counsel
Vice President and July 1, 1997 to December 31, 1998
General Counsel
Chief Counsel, January 1, 1993 to June 30, 1997
Regulatory
J. K. Randolph....... Senior Vice President April 6, 2000 to present
and Chief of Utility
Operations
Senior Vice President July 1, 1997 to April 5, 2000
and General Manager,
Transmission,
Distribution and
Customer Service
Business Unit
Vice President and January 1, 1997,to June 30, 1997
General Manager, Power
Generation, Business
Unit
Vice President, Power November 1, 1991 to December 31, 1996
Generation
D. D. Richard, Jr. .. Senior Vice President, May 1, 1998 to present
Public Affairs
Senior Vice President, July 1, 1997 to April 30, 1998
Governmental and
Regulatory Relations
Senior Vice President, October 18, 2000 to present
Public Affairs, PG&E
Corporation
Vice President, July 1, 1997 October 17, 2000
Governmental Relations,
PG&E Corporation
Vice President, January 1, 1997 to June 30, 1997
Governmental Relations
Executive Vice President January 1993 to December 1996
and Principal, Morse,
Richard, Weisenmiller &
Assoc., Inc. (energy,
project finance, and
environmental
consulting)
G. M. Rueger......... Senior Vice President, April 6, 2000 to present
Generation and chief
Nuclear Officer
Senior Vice President November 1, 1991 to April 5, 2000
and General Manager,
Nuclear Power
Generation Business
Unit
58
PART II
ITEM 5. Market for the Registrant's Common Equity and Related Stockholder
Matters.
Information responding to part of Item 5, for each of PG&E Corporation and
Pacific Gas and Electric Company, is set forth on page 89 under the heading
"Quarterly Consolidated Financial Data (Unaudited)" in the 2000 Annual Report
to Shareholders, which information is hereby incorporated by reference and
filed as part of Exhibit 13 to this report. As of April 9, 2001, there were
132,612 holders of record of PG&E Corporation common stock. PG&E Corporation
common stock is listed on the New York, Pacific, and Swiss stock exchanges.
The discussion of dividends with respect to PG&E Corporation's common stock is
hereby incorporated by reference from "Management's Discussion and Analysis--
Dividends" on page 20 of the 2000 Annual Report to Shareholders.
Neither Pacific Gas and Electric Company nor PG&E Corporation made any
sales of unregistered equity securities during 2000, the period covered by
this report.
ITEM 6. Selected Financial Data.
A summary of selected financial information, for each of PG&E Corporation
and Pacific Gas and Electric Company for each of the last five fiscal years,
is set forth on page 5 under the heading "Selected Financial Data" in the 2000
Annual Report to Shareholders, which information is hereby incorporated by
reference and filed as part of Exhibit 13 to this report.
Pacific Gas and Electric Company's ratio of earnings to fixed charges for
the year ended December 31, 2000 was a negative 7.70. Pacific Gas and Electric
Company's ratio of earnings to combined fixed charges and preferred stock
dividends for the year ended December 31, 2000 was a negative 7.29. The
negative ratios of earnings to fixed charges and earnings to combined fixed
charges and preferred stock dividends indicates a deficiency in earnings of
$5,637 million and $5,673 million respectively. The statement of the foregoing
ratios, together with the statements of the computation of the foregoing
ratios filed as Exhibits 12.1 and 12.2 hereto, are included herein for the
purpose of incorporating such information and exhibits into Registration
Statement Nos. 33-62488, 33-64136, 33-50707, and 33-61959 relating to Pacific
Gas and Electric Company's various classes of debt and first preferred stock
outstanding.
ITEM 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations.
A discussion of PG&E Corporation's and Pacific Gas and Electric Company's
consolidated results of operations and financial condition is set forth on
pages 6 through 31 under the heading "Management's Discussion and Analysis" in
the 2000 Annual Report to Shareholders, which discussion is hereby
incorporated by reference and filed as part of Exhibit 13 to this report.
ITEM 7A. Quantitative and Qualitative Disclosures About Market Risk.
Information responding to Item 7A appears in the 2000 Annual Report to
Shareholders on pages 28-31 under the heading "Management's Discussion and
Analysis--Quantitative and Qualitative Disclosures about Market Risk," and on
pages 46-47, 60-62 and 68-71 under Notes 1, 4, 8 and 9 of the "Notes to the
Consolidated Financial Statements" of the 2000 Annual Report to Shareholders,
which information is hereby incorporated by reference and filed as part of
Exhibit 13 to this report.
ITEM 8. Financial Statements and Supplementary Data.
Information responding to Item 8 appears on pages 32 through 92 of the 2000
Annual Report to Shareholders under the following headings for PG&E
Corporation: "Statement of Consolidated Operations," "Consolidated Balance
Sheets," "Statement of Consolidated Cash Flows," and "Statement of
Consolidated Common Stock Equity;" under the following headings for Pacific
Gas and Electric Company: "Statement of Consolidated Operations,"
"Consolidated Balance Sheets," "Statement of Consolidated Cash Flows," and
59
"Statement of Consolidated Stockholders' Equity;" and under the following
headings for PG&E Corporation and Pacific Gas and Electric Company jointly:
"Notes to the Consolidated Financial Statements," "Quarterly Consolidated
Financial Data (Unaudited)," "Independent Auditors' Report," and
"Responsibility for the Consolidated Financial Statements," which information
is hereby incorporated by reference and filed as part of Exhibit 13 to this
report.
ITEM 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure.
Not applicable.
PART III
ITEM 10. Directors and Executive Officers of the Registrant.
Information regarding executive officers of PG&E Corporation and Pacific
Gas and Electric Company is included in a separate item captioned "Executive
Officers of the Registrant" contained on pages 56 through 58 in Part I of this
report. Other information responding to Item 10 is included on pages 3 through
5 under the heading "Item No. 1: Election of Directors of PG&E Corporation and
Pacific Gas and Electric Company" and page 40 under the heading "Section 16(a)
Beneficial Ownership Reporting Compliance" in the Joint Proxy Statement
relating to the 2001 Annual Meetings of Shareholders, which information is
hereby incorporated by reference.
ITEM 11. Executive Compensation.
Information responding to Item 11, for each of PG&E Corporation and Pacific
Gas and Electric Company, is included on pages 8 and 9 under the heading
"Compensation of Directors" and on pages 31 through 37 under the headings
"Summary Compensation Table," "Option/SAR Grants in 2000," "Aggregated
Option/SAR Exercises in 2000 and Year-End Option/SAR Values," "Long-Term
Incentive Plan--Awards in 2000," "Retirement Benefits," "Employment
Contracts/Arrangements," and "Termination of Employment and Change In Control
Provisions" in the Joint Proxy Statement relating to the 2001 Annual Meetings
of Shareholders, which information is hereby incorporated by reference.
ITEM 12. Security Ownership of Certain Beneficial Owners and Management.
Information responding to Item 12, for each of PG&E Corporation and Pacific
Gas and Electric Company, is included on pages 10 and 11 under the heading
"Security Ownership of Management" and on page 40 under the heading "Principal
Shareholders" in the Joint Proxy Statement relating to the 2001 Annual
Meetings of Shareholders, which information is hereby incorporated by
reference.
ITEM 13. Certain Relationships and Related Transactions.
Information responding to Item 13, for each of PG&E Corporation and Pacific
Gas and Electric Company, is included on page 9 under the heading "Certain
Relationships and Related Transactions" in the Joint Proxy Statement relating
to the 2001 Annual Meetings of Shareholders, which information is hereby
incorporated by reference.
60
PART IV
ITEM 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K.
(a) The following documents are filed as a part of this report:
1. The following consolidated financial statements, supplemental
information, and report of independent public accountants contained
in the Report to Shareholders, which have been incorporated by
reference in this report:
Statements of Consolidated Operations for the Years Ended
December 31, 2000, 1999, and 1998, for each of PG&E Corporation
and Pacific Gas and Electric Company.
Statements of Consolidated Cash Flows for the Years Ended
December 31, 2000, 1999, and 1998, for each of PG&E Corporation
and Pacific Gas and Electric Company.
Consolidated Balance Sheets at December 31, 2000 and 1999 for
each of PG&E Corporation and Pacific Gas and Electric Company.
Statement of Consolidated Common Stock Equity for the Years Ended
December 31, 2000, 1999, and 1998, for PG&E Corporation.
Statement of Consolidated Stockholders' Equity for the Years
Ended December 31, 2000, 1999, and 1998, for Pacific Gas and
Electric Company.
Notes to Consolidated Financial Statements.
Quarterly Consolidated Financial Data (Unaudited).
Independent Auditors' Report (Deloitte & Touche LLP).
2. Independent Auditors' Report (Deloitte & Touche LLP) included at page
69 of this Form 10-K.
3. Report of Independent Public Accountants (Arthur Andersen LLP)
included at page 70 of this Form 10-K.
4. Report of Independent Public Accountants (Arthur Andersen LLP)
included at page 71 of this Form 10-K.
5. Financial statement schedules:
I--Condensed Financial Information of Parent for the Years Ended
December 31, 2000 and 1999.
II--Consolidated Valuation and Qualifying Accounts for each of
PG&E Corporation and Pacific Gas and Electric Company for the
Years Ended December 31, 2000, 1999 and 1998.
Schedules not included are omitted because of the absence of conditions
under which they are required or because the required information is provided
in the consolidated financial statements including the notes thereto.
6. Exhibits required to be filed by Item 601 of Regulation S-K:
3.1 Restated Articles of Incorporation of PG&E Corporation effective as
of May 5, 2000 (incorporated by reference to PG&E Corporation's Form
10-Q for the quarter ended March 31, 2000 (File No. 1-12609),
Exhibit 3.1)
3.2 Certificate of Determination for PG&E Corporation Series A Preferred
Stock filed December 22, 2000
3.3 By-Laws of PG&E Corporation amended as of February 21, 2001
3.4 Restated Articles of Incorporation of Pacific Gas and Electric
Company effective as of May 6, 1998 (incorporated by reference to
Pacific Gas and Electric Company's Form 10-Q for the quarter ended
March 31, 1998 (File No. 1-2348), Exhibit 3.1)
61
3.5 By-Laws of Pacific Gas and Electric Company amended as of February
21, 2001
4.1 First and Refunding Mortgage of Pacific Gas and Electric Company
dated December 1, 1920, and supplements thereto dated April 23,
1925, October 1, 1931, March 1, 1941, September 1, 1947, May 15,
1950, May 1, 1954, May 21, 1958, November 1, 1964, July 1, 1965,
July 1, 1969, January 1, 1975, June 1, 1979, August 1, 1983, and
December 1, 1988 (incorporated by reference to Registration No. 2-
1324, Exhibits B-1, B-2, B-3; Registration No. 2-4676, Exhibit B-
22; Registration No. 2-7203, Exhibit B-23; Registration No. 2-
8475, Exhibit B-24; Registration No. 2-10874, Exhibit 4B;
Registration No. 2-14144, Exhibit 4B; Registration No. 2-22910,
Exhibit 2B; Registration No. 2-23759, Exhibit 2B; Registration No.
2-35106, Exhibit 2B; Registration No. 2-54302, Exhibit 2C;
Registration No. 2-64313, Exhibit 2C; Registration No. 2-86849,
Exhibit 4.3; Pacific Gas and Electric Company's Form 8-K dated
January 18, 1989 (File No. 1-2348), Exhibit 4.2)
In accordance with Item 601(b)(4)(iii) of Regulation S-K, each of
PG&E Corporation or Pacific Gas and Electric Company agrees to
furnish to the Commission any instruments respecting long-term
debt not required to be filed by application of such item
4.2 Form of Rights Agreement dated as of December 22, 2000 between
PG&E Corporation and Mellon Investor Services LLC, including the
Form of Rights Certificate as Exhibit A, the Summary of Rights to
Purchase Preferred Stock as Exhibit B, and the Form of Certificate
of Determination of Preferences for the Preferred Stock as Exhibit
C
10. The Gas Accord Settlement Agreement, together with accompanying
tables, adopted by the California Public Utilities Commission on
August 1, 1997, in Decision 97-08-055 (incorporated by reference
to PG&E Corporation and Pacific Gas and Electric Company's Form
10-K for the year ended December 31, 1997 (File No. 1-12609 and
File No. 1-2348), Exhibit No. 10.2), as amended by Operational
Flow Order (OFO) Settlement Agreement, approved by the California
Public Utilities Commission on February 17, 2000, in Decision 00-
02-050, as amended by Comprehensive Gas OII Settlement Agreement,
approved by the California Public Utilities Commission on May 18,
2000, in Decision 00-05-049
10.1 Stock Purchase Agreement By and Between PG&E National Energy
Group, Inc. and El Paso Field Services Company, dated as of
January 27, 2000 (incorporated by reference to PG&E Corporation's
Form 10-K for the year ended December 31, 1999 (File No. 1-12609),
Exhibit No. 10.1)
10.2 Credit Agreement between PG&E Corporation, General Electric
Capital Corporation and Lehman Commercial Paper, Inc. dated March
1, 2001
*10.3 PG&E Corporation Supplemental Retirement Savings Plan dated as of
January 1, 2000 (incorporated by reference to PG&E Corporation's
Form 10-K for the year ended December 31, 2000 (File No. 1-12609),
Exhibit 10.2)
*10.4 Description of Compensation Arrangement between PG&E Corporation
and Thomas G. Boren (incorporated by reference to PG&E
Corporation's Form 10-Q for the quarter ended September 30, 1999
(File No. 1-12609), Exhibit 10.2)
*10.5 Description of Compensation Arrangement between PG&E Corporation
and Peter Darbee (incorporated by reference to PG&E Corporation's
Form 10-Q for the quarter ended September 30, 1999 (File No. 1-
12609), Exhibit 10.3)
*10.6 Letter regarding Compensation Arrangement between PG&E Corporation
and Thomas B. King dated November 4, 1998
62
*10.7 Letter regarding Compensation Arrangement between PG&E
Corporation and Lyn E. Maddox dated April 25, 1997
*10.8 Letter Regarding Relocation Arrangement Between PG&E
Corporation and Thomas B. King dated March 16, 2000
(incorporated by reference to PG&E Corporation's Form 10-Q
for the quarter ended March 31, 2000 (File No. 1-12609),
Exhibit 10)
*10.9 Description of Relocation Arrangement Between PG&E
Corporation and Lyn E. Maddox
*10.10 PG&E Corporation Senior Executive Officer Retention Program
approved December 20, 2000
*10.10.1 Letter regarding retention award to Robert D. Glynn, Jr.
dated January 22, 2001
*10.10.2 Letter regarding retention award to Gordon R. Smith dated
January 22, 2001
*10.10.3 Letter regarding retention award to Peter A. Darbee dated
January 22, 2001
*10.10.4 Letter regarding retention award to Bruce R. Worthington
dated January 22, 2001
*10.10.5 Letter regarding retention award to G. Brent Stanley dated
January 22, 2001
*10.10.6 Letter regarding retention award to Daniel D. Richard dated
January 22, 2001
*10.10.7 Letter regarding retention award to James K Randolph dated
February 27, 2001
*10.10.8 Letter regarding retention award to Gregory M. Rueger dated
February 27, 2001
*10.10.9 Letter regarding retention award to Kent Harvey dated
February 27, 2001
*10.10.10 Letter regarding retention award to Roger J. Peters dated
February 27, 2001
*10.10.11 Letter regarding retention award to Thomas G. Boren dated
February 27, 2001
*10.10.12 Letter regarding retention award to Lyn E. Maddox dated
February 27, 2001
*10.10.13 Letter regarding retention award to P. Chrisman Iribe dated
February 27, 2001
*10.10.14 Letter regarding retention award to Thomas B. King dated
February 27, 2001
*10.11 Agreement and Release between PG&E Corporation and Thomas W.
High dated December 8, 2000
*10.12 PG&E Corporation Deferred Compensation Plan for Non-Employee
Directors, as amended and restated effective as of July 22,
1998 (incorporated by reference to PG&E Corporation's Form
10-Q for the quarter ended September 30, 1998 (File
No. 1-12609), Exhibit 10.2)
*10.13 Description of Short-Term Incentive Plan for Officers of
PG&E Corporation and its subsidiaries, effective January 1,
2000 (incorporated by reference to PG&E Corporation's Form
10-K for the year ended December 31, 1999 (File No. 1-
12609), Exhibit 10.7)
*10.14 Description of Short-Term Incentive Plan for Officers of
PG&E Corporation and its subsidiaries, effective January 1,
2001
*10.15 Supplemental Executive Retirement Plan of the Pacific Gas
and Electric Company, effective January 1, 1998
(incorporated by reference to PG&E Corporation's Form 10-K
for the year ended December 31, 1998 (File No. 1-12609),
Exhibit 10.7)
*10.16 Pacific Gas and Electric Company Relocation Assistance
Program for Officers (incorporated by reference to Pacific
Gas and Electric Company's Form 10-K for fiscal year 1989
(File No. 1-2348), Exhibit 10.16)
63
*10.17 Postretirement Life Insurance Plan of the Pacific Gas and
Electric Company (incorporated by reference to Pacific Gas and
Electric Company's Form 10-K for fiscal year 1991 (File No. 1-
2348), Exhibit 10.16)
*10.18 PG&E Corporation Retirement Plan for Non-Employee Directors, as
amended and terminated January 1, 1998 (incorporated by
reference to incorporated by reference to PG&E Corporation Form
10-K for the year ended December 31, 1997 (File No. 1-12609),
Exhibit No. 10.13)
*10.19 PG&E Corporation Long-Term Incentive Program, as amended
February 16, 2000, including the PG&E Corporation Stock Option
Plan, Performance Unit Plan, and Non-Employee Director Stock
Incentive Plan (incorporated by reference to incorporated by
reference to PG&E Corporation Form 10-K for the year ended
December 31, 1999, (File No. 1-12609), Exhibit No. 10.12)
*10.20 PG&E Corporation Executive Stock Ownership Program, amended as
of September 19, 2000
*10.21 PG&E Corporation Officer Severance Policy, amended as of July
21, 1999 (incorporated by reference to PG&E Corporation's Form
10-Q for the quarter ended September 30, 1999 (File No. 1-
12609), Exhibit 10.1)
*10.22 PG&E Corporation Director Grantor Trust Agreement dated April
1, 1998 (incorporated by reference to PG&E Corporation's Form
10-Q for the quarter ended March 31, 1998 (File No. 1-12609),
Exhibit 10.1)
*10.23 PG&E Corporation Officer Grantor Trust Agreement dated April 1,
1998 (incorporated by reference to PG&E Corporation's Form 10-Q
for the quarter ended March 31, 1998 (File No. 1-12609),
Exhibit 10.2)
11. Computation of Earnings Per Common Share
12.1 Computation of Ratios of Earnings to Fixed Charges for Pacific
Gas and Electric Company
12.2 Computation of Ratios of Earnings to Combined Fixed Charges and
Preferred Stock Dividends for Pacific Gas and Electric Company
13. 2000 Annual Report to Shareholders of PG&E Corporation and
Pacific Gas and Electric Company--portions of the Report to
Shareholders under the headings "Selected Financial Data,"
"Management's Discussion and Analysis," "Independent Auditors'
Report," "Responsibility for Consolidated Financial
Statements," financial statements of PG&E Corporation entitled
"Statement of Consolidated Operations," "Consolidated Balance
Sheet," "Statement of Consolidated Cash Flows," "Statement of
Consolidated Common Stock Equity," financial statements of
Pacific Gas and Electric Company entitled "Statement of
Consolidated Operations," "Consolidated Balance Sheet,"
"Statement of Consolidated Cash Flows," "Statement of
Consolidated Stockholders' Equity," "Notes to Consolidated
Financial Statements" and "Quarterly Consolidated Financial
Data (Unaudited)" are included only (Except for those portions
that are expressly incorporated herein by reference, such
Report to Shareholders is furnished for the information of the
Commission and is not deemed to be "filed" herein.)
21. Subsidiaries of the Registrant
23.1 Independent Auditors' Consent (Deloitte & Touche LLP)
23.2 Consent of Arthur Andersen LLP
64
24.1 Resolutions of the Boards of Directors of PG&E Corporation and
Pacific Gas and Electric Company authorizing the execution of
the Form 10-K
24.2 Powers of Attorney
- --------
* Management contract or compensatory plan or arrangement required to be
filed as an exhibit to this report pursuant to Item 14(c) of Form 10-K.
The exhibits filed herewith are attached hereto (except as noted) and those
indicated above which are not filed herewith were previously filed with the
Commission and are hereby incorporated by reference. All exhibits filed
herewith or incorporated by reference are filed with respect to both PG&E
Corporation (File No. 1-12609) and Pacific Gas and Electric Company (File No.
1-2348), unless otherwise noted. Exhibits will be furnished to security
holders of PG&E Corporation or Pacific Gas and Electric Company upon written
request and payment of a fee of $0.30 per page, which fee covers only the
registrants' reasonable expenses in furnishing such exhibits. The registrants
agree to furnish to the Commission upon request a copy of any instrument
defining the rights of long-term debt holders not otherwise required to be
filed hereunder.
(b) Reports on Form 8-K
Reports on Form 8-K(1) during the quarter ended December 31, 2000 and
through the date hereof:
1. October 25, 2000
Item 5. Other Events--
B. Third Quarter 2000 Consolidated Earnings
C. Pacific Gas and Electric Company's Wholesale Power Purchase
Costs
D. Transition Cost Recovery
E. Earnings Outlook
2. November 22, 2000
Item 5. Other Events--
A. Valuation and Disposition of Pacific Gas and Electric Company's
Hydroelectric Generating Assets
B. Recovery of Wholesale Power Purchase Costs
C. Pacific Gas and Electric Company's Rate Stabilization Plan
D. Federal Energy Regulatory Commission Order
E. Pacific Gas and Electric Company's Federal Complaint
3. December 8, 2000
Item 5. Other Events--
A. Valuation and Disposition of Pacific Gas and Electric Company's
Hydroelectric Generating Assets
B. Pacific Gas and Electric Company's Rate Stabilization Plan
C. CPUC's Post-transition Period Ratemaking Decision
4. December 18, 2000
Item 5. Other Events--
A. Recent Regulatory Actions Addressing the California Energy
Market
B. Pacific Gas and Electric Company's Wholesale Power Purchase
Costs
C. Liquidity and Financial Impacts
65
5. December 22, 2000
Item 5. Other Events--
A. California Energy Crisis
B. PG&E Corporation Shareholder Rights Plan
6. December 29, 2000
Item 5. Other Events--California Energy Crisis
7. January 4, 2001
Item 5. Other Events--California Energy Crisis
8. January 5, 2001
Item 5. Other Events--
California Public Utilities Commission Decision Issued
9. January 10, 2001
Item 5. Other Events--
A. Current Financial Condition
B. Impending Natural Gas Shortage
C. ISO's Requested Tariff Amendment to Creditworthiness Standards
10. January 10, 2001
Item 5. Other Events--Suspension of PG&E Corporation and Pacific Gas
and Electric Company Dividends
11. January 17, 2001
Item 5. Other Events--
A. Ratings Downgrades
B. Liquidity Impacts and Financial Condition
12. February 1, 2001
Item 5. Other Events--
A. Wholesale Power Payments
B. Liquidity Impacts and Financial Condition
C. Federal Lawsuit
D. Rate Stabilization Plan Proceeding
E. Consulting Report
F. CPUC Emergency Action
13. February 14, 2001
Item 5. Other Events--
A. Assembly Bill 1X
B. Liquidity Impacts and Financial Condition
C. Federal Lawsuit
14. February 28, 2001
Item 5. Other Events--
A. Recent Regulatory Action
B. Liquidity
C. Wilson vs. PG&E Corporation and Pacific Gas and Electric
Company
66
15. March 2, 2001--Filed by PG&E Corporation only
Item 5. Other Events--PG&E Corporation debt restructure
16. March 9, 2001
Item 5. Other Events
A. Recent Regulatory Action
B. 2001 Cost of Capital Proceeding
17. March 16, 2001
Item 5. Other Events--Liquidity and Financial Condition
18. March 23, 2001
Item 5. Other Events
A. Recent Legislative and Regulatory Actions
B. Accounting Treatment
C. Bank Forbearance Agreement
19. March 30, 2001
Item 5. Other Events
A. Recent Regulatory Actions
B. Accounting Treatment
C. Liquidity and Financial Condition
20. April 6, 2001 (as amended)--Filed by PG&E Corporation only
Item 5. Other Events--Pacific Gas and Electric Company Bankruptcy
21. April 6, 2001 (as amended)--Filed by Pacific Gas and Electric
Company only
Item 3. Other Events--Bankruptcy or Receivership.
- --------
(1) Unless otherwise noted, all reports were filed under Commission File
Number 1-2348 (Pacific Gas and Electric Company) and Commission File
Number 1-12609 (PG&E Corporation).
67
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrants have duly caused this report to be signed
on their behalf by the undersigned, thereunto duly authorized, in the City and
County of San Francisco, on the 16th day of April, 2001.
PG&E CORPORATION PACIFIC GAS AND ELECTRIC COMPANY
(Registrant) (Registrant)
/s/ Gary P. Encinas /s/ Gary P. Encinas
By ______________________________________ By ______________________________________
(Gary P. Encinas, Attorney-in-Fact) (Gary P. Encinas, Attorney-in-Fact)
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrants and in the capacities and on the dates indicated.
Signature Title Date
--------- ----- ----
A. Principal Executive Officers
*ROBERT D. GLYNN, JR. Chairman of the Board, April 16, 2001
Chief Executive Officer,
and President
(PG&E Corporation)
*GORDON R. SMITH President and Chief April 16, 2001
Executive Officer
(Pacific Gas and
Electric Company)
B. Principal Financial Officers
*PETER A. DARBEE Senior Vice President, April 16, 2001
Chief Financial Officer,
and Treasurer
(PG&E Corporation)
*KENT M. HARVEY Senior Vice President, April 16, 2001
Chief Financial Officer,
and Treasurer
(Pacific Gas and Electric
Company)
C. Principal Accounting Officers
*CHRISTOPHER P. JOHNS Vice President and April 16, 2001
Controller
(PG&E Corporation)
*DINYAR B. MISTRY Vice President-Controller April 16, 2001
(Pacific Gas and Electric
Company)
D. Directors
*DAVID ANDREWS
*DAVID A. COULTER
*C. LEE COX
*WILLIAM S. DAVILA
*ROBERT D. GLYNN, JR. Directors of PG&E
*DAVID M. LAWRENCE, M.D. Corporation and
*MARY S. METZ Pacific Gas and Electric April 16, 2001
*CARL E. REICHARDT Company,
*GORDON R. SMITH except as noted
(Director of Pacific Gas and
Electric Company only)
*BARRY LAWSON WILLIAMS
/s/ Gary P. Encinas
*By __________________________________
(Gary P. Encinas, Attorney-in-Fact)
68
INDEPENDENT AUDITORS' REPORT
To the Shareholders and the Boards of Directors of
PG&E Corporation and Pacific Gas and Electric Company:
We have audited the consolidated financial statements of PG&E Corporation and
subsidiaries and Pacific Gas and Electric Company and subsidiaries as of and
for the years ended December 31, 2000 and 1999 and have issued our report
thereon dated April 6, 2001, which report includes an explanatory paragraph
concerning the ability of Pacific Gas and Electric Company to continue as a
going concern; such consolidated financial statements are included in your
2000 Annual Report to shareholders and are incorporated herein by reference.
Our audits also included the financial statement schedules of PG&E Corporation
and Pacific Gas and Electric Company, listed in Item 14(a)5. These financial
statement schedules are the responsibility of the management of PG&E
Corporation and Pacific Gas and Electric Company. Our responsibility is to
express an opinion based on our audits. In our opinion, such financial
statement schedules, when considered in relation to the basic financial
statements taken as a whole, present fairly in all material respects the
information set forth therein.
DELOITTE & TOUCHE LLP
San Francisco, California
April 6, 2001
69
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Shareholders and Board of Directors of
PG&E Corporation and Pacific Gas and Electric Company:
We have audited in accordance with generally accepted auditing standards, the
consolidated financial statements for the year ended December 31, 1998
included in the PG&E Corporation and Pacific Gas and Electric Company Annual
Report to Shareholders incorporated by reference in this Form 10-K, and have
issued our report thereon dated February 8, 1999. Our audits were made for the
purpose of forming an opinion on the basic consolidated financial statements
taken as a whole. The Condensed Financial Information of Parent for the Year
Ended December 31, 1998 and the Consolidated Valuation and Qualifying Accounts
for each of PG&E Corporation and Pacific Gas and Electric Company for the Year
Ended December 31, 1998 are the responsibility of the management of PG&E
Corporation and of Pacific Gas and Electric Company. These schedules are for
purposes of complying with the Securities and Exchange Commission's rules and
are not part of the basic consolidated financial statements. These schedules
have been subjected to the auditing procedures applied in the audits of the
basic consolidated financial statements and, in our opinion, fairly state in
all material respects the financial data required to be set forth therein in
relation to the basic consolidated financial statements taken as a whole.
ARTHUR ANDERSEN LLP
San Francisco, California
February 8, 1999
70
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Shareholders and the Board of Directors of PG&E Corporation
and Pacific Gas and Electric Company:
We have audited the accompanying statements of consolidated operations, cash
flows, and common stock equity of PG&E Corporation (a California corporation)
and subsidiaries and the statements of consolidated operations, cash flows,
and stockholders' equity of Pacific Gas and Electric Company (a California
corporation) and subsidiaries for the year ended December 31, 1998. These
financial statements are the responsibility of the management of PG&E
Corporation and Pacific Gas and Electric Company. Our responsibility is to
express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the results of operations and cash flows of PG&E
Corporation and subsidiaries and Pacific Gas and Electric and subsidiaries for
the year ended December 31, 1998, in conformity with generally accepted
accounting principles.
ARTHUR ANDERSEN LLP
San Francisco, California
February 8, 1999
71
SCHEDULE I--CONDENSED FINANCIAL INFORMATION OF PARENT
CONDENSED BALANCE SHEETS
December 31,
----------------
2000 1999
------- -------
(in millions)
Assets:
Cash and cash equivalents..................................... $ 351 $ 155
Advances to affiliates........................................ 295 299
Note receivable from subsidiary............................... 308 --
Other current assets.......................................... 6 --
------- -------
Total current assets....................................... 960 454
Equipment..................................................... 15 16
Accumulated depreciation...................................... (6) (3)
------- -------
Net equipment................................................. 9 13
Investments in subsidiaries................................... 3,439 6,931
Other investments............................................. 64 52
Deferred income taxes......................................... -- 396
Other deferred charges........................................ 1 --
------- -------
Total Assets............................................... $ 4,473 $ 7,846
======= =======
Liabilities and Stockholders' Equity:
Current Liabilities:
Short-term borrowings........................................ $ 931 $ 526
Accounts payable--related parties............................ 59 76
Accounts payable--trade...................................... 13 10
Note payable to subsidiary................................... 75 --
Accrued taxes................................................ 108 117
Dividends payable............................................ 109 110
Other........................................................ 25 112
------- -------
Total current liabilities.................................. 1,320 951
Noncurrent Liabilities:
Deferred income taxes........................................ 9 --
Other........................................................ 10 5
------- -------
Total noncurrent liabilities............................... 19 5
Stockholders' Equity:
Common stock................................................. 5,971 5,906
Common stock held by subsidiary.............................. (690) (690)
Reinvested earnings.......................................... (2,147) 1,674
------- -------
Total stockholders' equity................................. 3,134 6,890
------- -------
Total Liabilities and Stockholders' Equity................. $ 4,473 $ 7,846
======= =======
72
SCHEDULE I--CONDENSED FINANCIAL INFORMATION OF PARENT--(Continued)
CONDENSED STATEMENTS OF INCOME
For the Years Ended December 31, 2000, 1999, and 1998
2000 1999 1998
-------- ------- ------
(in millions except per
share amounts)
Administrative service revenue .................... $ 111 $ 82 $ 64
Equity in earnings (losses) of subsidiaries........ (3,316) 853 736
Operating expenses................................. (111) (86) (63)
Loss on assets held for sale....................... -- (1,275) --
Interest expense................................... (27) (30) (52)
Other income....................................... 22 16 5
-------- ------- ------
Income (Loss) Before Income Taxes.................. (3,321) (440) 690
Less: Income Taxes................................. (4) (447) (83)
-------- ------- ------
Income (Loss) from continuing operations........... (3,317) 7 773
Discontinued operations............................ (40) (98) (52)
Cumulative effect of a change in an accounting
principle......................................... -- 12 --
-------- ------- ------
Net income (loss) before intercompany elimination.. (3,357) (79) 721
Eliminations of intercompany (profit) loss......... (7) 6 (2)
-------- ------- ------
Net income (loss).................................. $ (3,364) $ (73) $ 719
======== ======= ======
Weighted Average Common Shares Outstanding, Basic
and Diluted....................................... 362 368 382
Earnings (Loss) Per Common Share, Basic and
Diluted........................................... $ (9.29) $ (0.20) $ 1.88
======== ======= ======
CONDENSED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2000, 1999, and 1998
2000 1999 1998
-------- ------- ------
(in millions)
Cash Flows From Operating Activities:
Net income (loss).................................. $ (3,364) $ (73) $ 719
Adjustments to reconcile net income (loss) to net
cash provided by operating activities:
Equity in earnings of subsidiaries................ 3,316 (853) (736)
Deferred taxes.................................... 20 (415) 19
Loss on assets held for sale...................... -- 1,275 --
Distributions from consolidated subsidiaries...... 475 527 561
Other-net......................................... 232 77 (688)
-------- ------- ------
Net cash provided by operating activities.......... $ 679 $ 538 $ (125)
Cash Flows From Investing Activities:
Capital expenditures.............................. 1 (8) (8)
Investment in subsidiaries........................ (555) (722) (575)
Loans to subsidiaries............................. (308) -- --
Return of capital by Utility (share repurchases).. 275 926 1,600
Other-net......................................... (9) (12) --
-------- ------- ------
Net cash provided (used) by investing activities... $ (596) $ 184 $1,017
Cash Flows From Financing Activities:
Common stock issued............................... 65 54 63
Common stock repurchased.......................... (2) (3) (1,158)
Loans from subsidiary............................. 75 -- --
Short-term debt issued (redeemed)-net............. 405 (157) 683
Dividends paid.................................... (436) (465) (470)
Other-net......................................... 6 (5) (2)
-------- ------- ------
Net cash provided (used) by financing activities... $ 113 $ (576) $ (884)
Net Change in Cash & Cash Equivalents.............. 196 146 8
Cash & Cash Equivalents at January 1............... 155 9 1
-------- ------- ------
Cash & Cash Equivalents at December 31............. $ 351 $ 155 $ 9
======== ======= ======
73
PG&E CORPORATION
SCHEDULE II -- CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 2000, 1999, and 1998
Column A Column B Column C Column D Column E
Additions
-------------------
Balance at Charged to Charged Balance at
Beginning Costs and to Other End of
Description of Period Expenses Accounts Deductions Period
----------- ---------- ---------- -------- ---------- ----------
(in thousands)
Valuation and qualifying
accounts deducted from
assets:
2000:
Allowance for
uncollectible accounts
(2)................... $65,128 $ 47,980 $ 1,484 $44,092(1) $ 70,500
======= ========== ======= ======= ==========
Provision for loss on
generation-related
regulatory assets and
undercollected
purchased power costs
(3)................... $ -- $6,939,000 $ -- $ -- $6,939,000
======= ========== ======= ======= ==========
1999:
Allowance for
uncollectible accounts
(2)................... $58,577 $ 25,243 $ (183) $18,509(1) $ 65,128
======= ========== ======= ======= ==========
1998:
Allowance for
uncollectible accounts
(2)................... $72,912 $ 10,978 $(2,893) $22,420(1) $ 58,577
======= ========== ======= ======= ==========
- --------
(1) Deductions consist principally of write-offs, net of collections of
receivables previously written off.
(2) Allowance for uncollectible accounts are deducted from "Accounts receivable
Customers, net" and "Accounts receivable Energy Marketing."
(3) Provision was deducted from "Regulatory Assets."
74
PACIFIC GAS AND ELECTRIC COMPANY
SCHEDULE II -- CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 2000, 1999, and 1998
Column A Column B Column C Column D Column E
Additions
-------------------
Balance at Charged to Charged Balance at
Beginning Costs and to Other End of
Description of Period Expenses Accounts Deductions Period
----------- ---------- ---------- -------- ---------- ----------
(in thousands)
Valuation and qualifying
accounts deducted from
assets:
2000:
Allowance for
uncollectible accounts
(2)................... $46,421 $ 19,008 $1,484 $15,344(1) $ 51,569
======= ========== ====== ======= ==========
Provision for loss on
generation-related
regulatory assets and
undercollected
purchased power costs
(3)................... $ -- $6,939,000 $ -- $ -- $6,939,000
======= ========== ====== ======= ==========
1999:
Allowance for
uncollectible accounts
(2)................... $47,347 $ 17,011 $ 44 $17,981(1) $ 46,421
======= ========== ====== ======= ==========
1998:
Allowance for
uncollectible accounts
(2)................... $59,608 $ 10,007 $ 152 $22,420(1) $ 47,347
======= ========== ====== ======= ==========
- --------
(1) Deductions consist principally of write-offs, net of collections of
receivables previously written off.
(2) Allowance for uncollectible accounts are deducted from "Accounts receivable
Customers, net."
(3) Provision was deducted from "Regulatory Assets."
75
EXHIBIT INDEX
Exhibit No. Description of Exhibit
----------- ----------------------
3.1 Restated Articles of Incorporation of PG&E Corporation effective
as of May 5, 2000 (incorporated by reference to PG&E Corporation's
Form 10-Q for the quarter ended March 31, 2001 (File No. 1-12609),
Exhibit 3.1)
3.2 Certificate of Determination for PG&E Corporation Series A
Preferred Stock filed December 22, 2000
3.3 By-Laws of PG&E Corporation amended as of February 21, 2001
3.4 Restated Articles of Incorporation of Pacific Gas and Electric
Company effective as of May 6, 1998 (incorporated by reference to
Pacific Gas and Electric Company's Form 10-Q for the quarter ended
March 31, 1998 (File No. 1-2348), Exhibit 3.1)
3.5 By-Laws of Pacific Gas and Electric Company amended as of February
21, 2001
4.1 First and Refunding Mortgage of Pacific Gas and Electric Company
dated December 1, 1920, and supplements thereto dated April 23,
1925, October 1, 1931, March 1, 1941, September 1, 1947, May 15,
1950, May 1, 1954, May 21, 1958, November 1, 1964, July 1, 1965,
July 1, 1969, January 1, 1975, June 1, 1979, August 1, 1983, and
December 1, 1988 (incorporated by reference to Registration No. 2-
1324, Exhibits B-1, B-2, B-3; Registration No. 2-4676, Exhibit B-
22; Registration No. 2-7203, Exhibit B-23; Registration No. 2-
8475, Exhibit B-24; Registration No. 2-10874, Exhibit 4B;
Registration No. 2-14144, Exhibit 4B; Registration No. 2-22910,
Exhibit 2B; Registration No. 2-23759, Exhibit 2B; Registration No.
2-35106, Exhibit 2B; Registration No. 2-54302, Exhibit 2C;
Registration No. 2-64313, Exhibit 2C; Registration No. 2-86849,
Exhibit 4.3; Pacific Gas and Electric Company's Form 8-K dated
January 18, 1989 (File No. 1-2348), Exhibit 4.2)
In accordance with Item 601(b)(4)(iii) of Regulation S-K, each of
PG&E Corporation or Pacific Gas and Electric Company agrees to
furnish to the Commission any instruments respecting long-term
debt not required to be filed by application of such item
4.2 Form of Rights Agreement dated as of December 22, 2000 between
PG&E Corporation and Mellon Investor Services LLC, including the
Form of Rights Certificate as Exhibit A, the Summary of Rights to
Purchase Preferred Stock as Exhibit B, and the Form of Certificate
of Determination of Preferences for the Preferred Stock as Exhibit
C
10. The Gas Accord Settlement Agreement, together with accompanying
tables, adopted by the California Public Utilities Commission on
August 1, 1997, in Decision 97-08-055 (incorporated by reference
to PG&E Corporation and Pacific Gas and Electric Company's Form
10-K for the year ended December 31, 1997 (File No. 1-12609 and
File No. 1-2348), Exhibit No. 10.2), as amended by Operational
Flow Order (OFO) Settlement Agreement, approved by the California
Public Utilities Commission on February 17, 2000, in Decision 00-
02-050, as amended by Comprehensive Gas OII Settlement Agreement,
approved by the California Public Utilities Commission on May 18,
2000, in Decision 00-05-049
10.1 Stock Purchase Agreement By and Between PG&E National Energy
Group, Inc. and El Paso Field Services Company, dated as of
January 27, 2000 (incorporated by reference to PG&E Corporation's
Form 10-K for the year ended December 31, 1999 (File No. 1-12609),
Exhibit No. 10.1)
10.2 Credit Agreement between PG&E Corporation, General Electric
Capital Corporation and Lehman Commercial Paper, Inc. dated March
1, 2001
*10.3 PG&E Corporation Supplemental Retirement Savings Plan dated as of
January 1, 2000 (incorporated by reference to PG&E Corporation's
Form 10-K for the year ended December 31, 2000 (File No. 1-12609),
Exhibit 10.2)
Exhibit No. Description of Exhibit
----------- ----------------------
*10.4 Description of Compensation Arrangement between PG&E Corporation
and Thomas G. Boren (incorporated by reference to PG&E
Corporation's Form 10-Q for the quarter ended September 30, 1999
(File No. 1-12609), Exhibit 10.2)
*10.5 Description of Compensation Arrangement between PG&E Corporation
and Peter Darbee (incorporated by reference to PG&E Corporation's
Form 10-Q for the quarter ended September 30, 1999 (File No. 1-
12609), Exhibit 10.3)
*10.6 Letter regarding Compensation Arrangement between PG&E Corporation
and Thomas B. King dated November 4, 1998
*10.7 Letter regarding Compensation Arrangement between PG&E Corporation
and Lyn E. Maddox dated April 25, 1997
*10.8 Letter Regarding Relocation Arrangement Between PG&E Corporation
and Thomas B. King dated March 16, 2000 (incorporated by reference
to PG&E Corporation's Form 10-Q for the quarter ended March 31,
2000 (File No. 1-12609), Exhibit 10)
*10.9 Description of Relocation Arrangement Between PG&E Corporation and
Lyn E. Maddox
*10.10 PG&E Corporation Senior Executive Officer Retention Program
approved December 20, 2000
*10.10.1 Letter regarding retention award to Robert D. Glynn, Jr. dated
January 22, 2001
*10.10.2 Letter regarding retention award to Gordon R. Smith dated January
22, 2001
*10.10.3 Letter regarding retention award to Peter A. Darbee dated January
22, 2001
*10.10.4 Letter regarding retention award to Bruce R. Worthington dated
January 22, 2001
*10.10.5 Letter regarding retention award to G. Brent Stanley dated January
22, 2001
*10.10.6 Letter regarding retention award to Daniel D. Richard dated
January 22, 2001
*10.10.7 Letter regarding retention award to James K Randolph dated
February 27, 2001
*10.10.8 Letter regarding retention award to Gregory M. Rueger dated
February 27, 2001
*10.10.9 Letter regarding retention award to Kent Harvey dated February 27,
2001
*10.10.10 Letter regarding retention award to Roger J. Peters dated February
27, 2001
*10.10.11 Letter regarding retention award to Thomas G. Boren dated February
27, 2001
*10.10.12 Letter regarding retention award to Lyn E. Maddox dated February
27, 2001
*10.10.13 Letter regarding retention award to P. Chrisman Iribe dated
February 27, 2001
*10.10.14 Letter regarding retention award to Thomas B. King dated February
27, 2001
*10.11 Agreement and Release between PG&E Corporation and Thomas W. High
dated December 8, 2000
*10.12 PG&E Corporation Deferred Compensation Plan for Non-Employee
Directors, as amended and restated effective as of July 22, 1998
(incorporated by reference to PG&E Corporation's Form 10-Q for the
quarter ended September 30, 1998 (File No. 1-12609), Exhibit 10.2)
*10.13 Description of Short-Term Incentive Plan for Officers of PG&E
Corporation and its subsidiaries, effective January 1, 2000
(incorporated by reference to PG&E Corporation's Form 10-K for the
year ended December 31, 1999 (File No. 1-12609), Exhibit 10.7)
*10.14 Description of Short-Term Incentive Plan for Officers of PG&E
Corporation and its subsidiaries, effective January 1, 2001
*10.15 Supplemental Executive Retirement Plan of the Pacific Gas and
Electric Company, effective January 1, 1998 (incorporated by
reference to PG&E Corporation's Form 10-K for the year ended
December 31, 1998 (File No. 1-12609), Exhibit 10.7)
Exhibit No. Description of Exhibit
----------- ----------------------
*10.16 Pacific Gas and Electric Company Relocation Assistance Program for
Officers (incorporated by reference to Pacific Gas and Electric
Company's Form 10-K for fiscal year 1989 (File No. 1-2348),
Exhibit 10.16)
*10.17 Postretirement Life Insurance Plan of the Pacific Gas and Electric
Company (incorporated by reference to Pacific Gas and Electric
Company's Form 10-K for fiscal year 1991 (File No. 1-2348),
Exhibit 10.16)
*10.18 PG&E Corporation Retirement Plan for Non-Employee Directors, as
amended and terminated January 1, 1998 (incorporated by reference
to incorporated by reference to PG&E Corporation Form 10-K for the
year ended December 31, 1997 (File No. 1-12609), Exhibit No.
10.13)
*10.19 PG&E Corporation Long-Term Incentive Program, as amended February
16, 2000, including the PG&E Corporation Stock Option Plan,
Performance Unit Plan, and Non-Employee Director Stock Incentive
Plan (incorporated by reference to incorporated by reference to
PG&E Corporation Form 10-K for the year ended December 31, 1999
(File No. 1-12609), Exhibit No. 10.12)
*10.20 PG&E Corporation Executive Stock Ownership Program, amended as of
September 19, 2000
*10.21 PG&E Corporation Officer Severance Policy, amended as of July 21,
1999 (incorporated by reference to PG&E Corporation's Form 10-Q
for the quarter ended September 30, 1999 (File No. 1-12609),
Exhibit 10.1)
*10.22 PG&E Corporation Director Grantor Trust Agreement dated April 1,
1998 (incorporated by reference to PG&E Corporation's Form 10-Q
for the quarter ended March 31, 1998 (File No. 1-12609), Exhibit
10.1)
*10.23 PG&E Corporation Officer Grantor Trust Agreement dated April 1,
1998 (incorporated by reference to PG&E Corporation's Form 10-Q
for the quarter ended March 31, 1998 (File No. 1-12609), Exhibit
10.2)
11. Computation of Earnings Per Common Share
12.1 Computation of Ratios of Earnings to Fixed Charges for Pacific Gas
and Electric Company
12.2 Computation of Ratios of Earnings to Combined Fixed Charges and
Preferred Stock Dividends for Pacific Gas and Electric Company
13. 2000 Annual Report to Shareholders of PG&E Corporation and Pacific
Gas and Electric Company--portions of the Report to Shareholders
under the headings "Selected Financial Data," "Management's
Discussion and Analysis," "Independent Auditors' Report,"
"Responsibility for Consolidated Financial Statements," financial
statements of PG&E Corporation entitled "Statement of Consolidated
Income," "Consolidated Balance Sheet," "Statement of Consolidated
Cash Flows," "Statement of Consolidated Common Stock Equity,"
financial statements of Pacific Gas and Electric Company entitled
"Statement of Consolidated Income," "Consolidated Balance Sheet,"
"Statement of Consolidated Cash Flows," "Statement of Consolidated
Stockholders' Equity," "Notes to Consolidated Financial
Statements" and "Quarterly Consolidated Financial Data
(Unaudited)" are included only. (Except for those portions that
are expressly incorporated herein by reference, such Report to
Shareholders is furnished for the information of the Commission
and is not deemed to be "filed" herein.)
21. Subsidiaries of the Registrant
23.1 Independent Auditors' Consent (Deloitte & Touche LLP)
23.2 Consent of Arthur Andersen LLP
24.1 Resolutions of the Boards of Directors of PG&E Corporation and
Pacific Gas and Electric Company authorizing the execution of the
Form 10-K
24.2 Powers of Attorney