SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K/A
Amendment No. 1 to
(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 offices) (Address of principal executive offices)
94177 94105
(Zip Code) (Zip Code)
(415) 973-7000 (415) 267-7000
(Registrant's telephone number, including area code) (Registrant's telephone number, 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 Securities, American Stock Exchange and
Series A (liquidation preference $25), issued by PG&E Pacific Exchange
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 shares held by sub)
Pacific Gas and Electric Company: Wholly owned by PG&E Corporation
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)
INTRODUCTORY NOTE
PG&E Corporation has previously disclosed that its subsidiary, PG&E
National Energy Group, Inc (PG&E NEG), has used "synthetic leases" in connection
with some of its power plant projects and turbine acquisition commitments.
Subsequent to the issuance of PG&E Corporation's 1999 and 2000 consolidated
financial statements, management determined that the assets and liabilities
associated with these leases should have been consolidated. This Amendment No. 1
to PG&E Corporation's and Pacific Gas and Electric Company's joint Annual Report
on Form 10-K for the year ended December 31, 2000, contains revised consolidated
financial statements for PG&E Corporation for the years ended December 31, 1999
and 2000. To reflect the revisions, this Amendment No. 1 hereby amends:
Part I, Item 1. Business (by correcting the statement of the amount of PG&E
Corporation's assets for the year ended December 31, 2000 that appears on page 2
of the original filing)
Part I, Items 2 through 4 - unchanged
Part II, Item 5. Market for Registrant's Common Equity and Related Stockholder
Matters (references are to amended 2000 Annual Report to Shareholders)
Part II, Item 6. Selected Financial Data (references are to amended 2000 Annual
Report to Shareholders)
Part II, Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations, (references are to amended 2000 Annual Report to
Shareholders)
Part II, Item 7A. Quantitative and Qualitative Disclosures About Market Risk
(references are to amended 2000 Annual Report to Shareholders)
Part II, Item 8. Financial Statements and Supplementary Data (references are to
amended 2000 Annual Report to Shareholders)
Part III, Items 10 through 13 - unchanged
Part IV, Item 14. Exhibits, Financial Statement Schedules, and Reports on Form
8-K (amended to file herewith amended Exhibit 13 - portions of the amended 2000
Annual Report to Shareholders, Exhibit 23.1 - Independent Auditors' Consent
(Deloitte & Touche LLP), and Exhibit 23.2 - Consent of Arthur Andersen LLP. All
other exhibits that were filed with the original filing have not been re-filed
with this amendment but instead have been incorporated by reference to the
original filing.)
Although the full text of the amended Form 10-K is contained herein, this
Amendment No. 1 does not update any other disclosures to reflect developments
since the original date of filing.
i
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 ............................................................................... 4
Regulation of Pacific Gas and Electric Company ............................................................... 5
Federal Regulation ........................................................................................ 5
State Regulation .......................................................................................... 5
Licenses and Permits ...................................................................................... 6
Regulation of PG&E National Energy Group, Inc. Businesses .................................................... 6
Federal Regulation ........................................................................................ 6
State and Other Regulations ............................................................................... 7
UTILITY OPERATIONS ........................................................................................... 8
Ratemaking Mechanisms ........................................................................................ 8
General Rate Case ....................................................................................... 8
Cost of Capital ......................................................................................... 8
Electric and Gas Distribution Performance-Based Ratemaking (PBR) ........................................ 8
Electric Ratemaking ....................................................................................... 9
Rate Stabilization Plan Proceeding ...................................................................... 9
General Rate Case ....................................................................................... 10
2001 Attrition Rate Adjustment Request .................................................................. 11
Revenue Adjustment Proceeding ........................................................................... 11
Annual Transition Cost Proceeding ....................................................................... 11
Electric Industry Restructuring Implementation Costs .................................................... 11
Electric Restructuring Costs Account (ERCA) ............................................................. 11
Revenues from Must-Run Contracts ........................................................................ 12
FERC Transmission Owner Rate Case ....................................................................... 12
AB 1890 Electric Base Revenue Increase .................................................................. 12
Electric Transmission Rates ............................................................................. 13
Post-Transition Period Ratemaking Proceeding ............................................................ 13
Gas Ratemaking ............................................................................................ 13
Gas Accord .............................................................................................. 13
General Rate Case ....................................................................................... 13
Gas Procurement Costs ................................................................................... 13
The Biennial Cost Allocation Proceeding (BCAP) .......................................................... 13
Public Purpose Programs ...................................................................................... 14
Electric Utility Operations .................................................................................. 15
Electric Industry Restructuring ........................................................................... 15
California Power Crisis ................................................................................. 15
FERC Order .............................................................................................. 15
The California Independent System Operator and the California Power Exchange ............................ 16
New California Legislation .............................................................................. 17
ii
Page
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Recovery of Transition Costs, Wholesale Power Purchase Costs, and End of Rate Freeze .... 18
Retail Direct Access .................................................................... 19
Electric Operating Statistics ................................................................ 20
Electric Resources ........................................................................... 21
Generating Capacity .......................................................................... 21
Hydroelectric Generation Assets ........................................................... 22
Diablo Canyon Nuclear Power Plant ......................................................... 22
Diablo Canyon Ratemaking ................................................................ 23
Nuclear Fuel Supply and Disposal ........................................................ 23
Insurance ............................................................................... 24
Decommissioning ......................................................................... 24
Other Electric Resources ..................................................................... 25
QF Generation and Other Power Purchase Contracts ........................................ 25
Bilateral Agreements .................................................................... 26
Electric Transmission and Distribution ....................................................... 27
Gas Utility Operations ....................................................................... 28
Gas Operating Statistics ................................................................ 29
Natural Gas Supplies .................................................................... 30
Gas Regulatory Framework ................................................................ 31
Transportation Commitments .............................................................. 32
PG&E NATIONAL ENERGY GROUP, INC. ............................................................. 32
Integrated Power Generation, and Energy Trading and Marketing Business ....................... 33
Ownership and Operation of Generating Facilities .......................................... 33
New Power Plant Development and Construction .............................................. 33
Contractual Control of Generating Capacity ................................................ 34
Energy Marketing and Trading .............................................................. 34
Description of Generating Facilities ...................................................... 37
Competition ............................................................................... 37
Natural Gas Transmission Business ............................................................ 38
PG&E GT-Northwest (PG&E GTN) ............................................................ 38
North Baja Pipeline ..................................................................... 39
Competition ............................................................................. 39
ENVIRONMENTAL MATTERS ........................................................................ 40
Environmental Matters ........................................................................ 40
Environmental Protection Measures ......................................................... 40
Air Quality ............................................................................... 40
Water Quality ............................................................................. 42
Hazardous Waste Compliance and Remediation ................................................ 43
Potential Recovery of Hazardous Waste Compliance and Remediation Costs .................... 44
Compressor Station Litigation ............................................................. 45
Electric and Magnetic Fields .............................................................. 45
Low Emission Vehicle Programs ............................................................. 45
Item 2. Properties ................................................................................... 45
Item 3. Legal Proceedings ............................................................................ 46
Pacific Gas and Electric Company Bankruptcy .................................................. 46
Pacific Gas and Electric Company vs. California Public Utilities Commissioners ............... 46
Wilson vs. PG&E Corporation and Pacific Gas and Electric Company ............................. 46
Moss Landing Power Plant ..................................................................... 47
iii
Page
----
Compressor Station Chromium Litigation ...................................................... 48
Texas Franchise Fee Litigation .............................................................. 49
Item 4. Submission of Matters to a Vote of Security Holders ......................................... 49
EXECUTIVE OFFICERS OF THE REGISTRANTS ....................................................... 50
PART II
Item 5. Market for the Registrant's Common Equity and Related Stockholder Matters ................... 53
Item 6. Selected Financial Data ..................................................................... 53
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations ....... 53
Item 7A. Quantitative and Qualitative Disclosures About Market Risk .................................. 53
Item 8. Financial Statements and Supplementary Data ................................................. 53
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure ........ 54
PART III
Item 10. Directors and Executive Officers of the Registrant .......................................... 54
Item 11. Executive Compensation ...................................................................... 54
Item 12. Security Ownership of Certain Beneficial Owners and Management .............................. 54
Item 13. Certain Relationships and Related Transactions .............................................. 54
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K ............................ 55
Signatures .................................................................................. 63
Independent Auditors' Report (Deloitte & Touche LLP) ........................................ 64
Report of Independent Public Accountants (Arthur Andersen LLP) .............................. 65
Report of Independent Public Accountants (Arthur Andersen LLP) .............................. 66
iv
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
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
ICIP ......................... Incremental Cost Incentive Price
v
GLOSSARY OF TERMS--(Continued)
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
RAP .................................... Revenue Adjustment Proceeding
vi
GLOSSARY OF TERMS--(Continued)
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.
vii
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 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
1
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 $36.2 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;
. 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
2
. 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.
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.
3
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 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.
4
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 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
5
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
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
6
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
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.
7
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.
8
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 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
9
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, 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.
10
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.
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
11
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 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.
12
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.
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
13
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.
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.
14
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 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.
15
. 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.
. 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.
16
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 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-
17
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 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.
18
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 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.
19
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 $7,160,215
========== =========== ========== ========== ==========
The following table shows certain customer information:
Selected Statistics: 2000 1999 1998 1997 1996
---- ---- ---- ---- ----
Average annual residential usage (kWh) .................. 7,062 6,905 6,776 6,627 6,571
Average billed revenues per kWh (cents per kWh):
Residential ........................................... 10.46 10.68 10.77 11.88 11.92
Commercial ............................................ 8.48 9.32 9.69 10.15 10.19
Industrial(1) ......................................... 3.02 5.17 5.72 6.09 6.37
Agricultural(1) ....................................... 10.11 10.48 11.42 10.52 10.92
Net plant investment per customer ($) ................... 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.
20
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:
Net
Number Operating
Generation Type County Location of 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.
21
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.
22
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 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.
23
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.
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.
24
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.
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.
25
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 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
26
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 PUC 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 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.
27
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.
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.
28
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.
29
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 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.
30
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)."
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.
31
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.
32
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 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.
33
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.
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.
34
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.
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.
35
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.
36
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 Commercial
Generating Facility State MW MW(1) Structure Fuel Primary Output Sales 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.
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
37
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.
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
38
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.
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.
39
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.
40
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.
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.
41
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 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.
42
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.
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.
43
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 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.
44
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.
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.
45
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 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
46
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.
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.
47
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 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.
48
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.
49
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, Jr. ..... Chairman of the Board, Chief Executive Officer, and January 1, 1998 to present
President
Chairman of the Board, Pacific Gas and January 1, 1998 to present
Electric Company
President and Chief Executive Officer June 1, 1997 to present
President and Chief Operating Officer December 18, 1996 to May 31, 1997
President and Chief Operating Officer, Pacific Gas June 1, 1995 to May 31, 1997
and Electric Company
T. G. Boren .......... Executive Vice President August 1, 1999 to present
Chairman, President, and Chief Executive July 1, 2000 to present
Officer, PG&E National Energy Group, Inc.
President, and Chief Executive Officer, PG&E
National Energy Group, Inc. August 1, 1999 to June 30, 2000
President and Chief Executive Officer, February 18, 1992 to July 31, 1999
Southern Energy, Inc.
Executive Vice President, Southern Company June 1, 1999 to July 31, 1999
Senior Vice President, Southern Company February 16, 1998 to May 31, 1999
Vice President, Southern Company July 17, 1995 to February 15, 1998
P. A. Darbee .......... Senior Vice President, Chief Financial Officer, September 20, 1999 to present
and Treasurer
Vice President and Chief Financial Officer, June 30, 1997 to September 19, 1999
Advance Fibre Communications, Inc.
Vice President, Chief Financial Officer, and January 10, 1994 to June 30, 1997
Controller, Pacific Bell
50
Name Position Period Held Office
----- --------- ------------------
T. W. High ............... Senior Vice President, Administration and June 1, 1997 to present
External Relations
Senior Vice President, Corporate Services, June 1, 1995 to May 31, 1997
Pacific Gas and Electric Company
P. C. Iribe .............. Senior Vice President January 1, 1999 to present
President and Chief Operating Officer, East April 6, 2000 to present
Region, PG&E National Energy Group, Inc.
President and Chief Operating Officer, November 1, 1998 to April 5, 2000
PG&E Generating Company (formerly
known as U.S. Generating Company)
Executive Vice President and Chief September 1, 1997 to October 31, 1998
Operating Officer, U.S. Generating Company
Executive Vice President, Marketing, May 17, 1994 to September 1, 1997
Development, and Asset Management,
U.S. Generating Company
T. B. King ............... Senior Vice President January 1, 1999 to present
President and Chief Operating Office, West April 6, 2000 to present
Region, PG&E National Energy Group, Inc.
President and Chief Operating Officer, November 23, 1998 to present
PG&E Gas Transmission Corporation
President and Chief Operating Officer, February 14, 1997 to November 22, 1998
Kinder Morgan Energy Partners, L.P.
Vice President, Commercial Operations-- July 1, 1995 to February 14, 1997
Midwest Region, Enron Liquid Services
Corporation
L. E. Maddox ............. Senior Vice President June 1, 1997 to present
President and Chief Operating Officer, April 6, 2000 to present
Trading, PG&E National Energy Group, Inc.
President and Chief Executive Officer, May 12, 1997 to April 5, 2000
PG&E Energy Trading-Gas Corporation
President, PennUnion Energy Services, L.L.C. May 1995 to May 1997
G. R. Smith .............. Senior Vice President (Please refer to January 1, 1999 to present
description of business experience for
executive officers of Pacific Gas and
Electric Company below.)
G. B. Stanley ............ Senior Vice President, Human Resources January 1, 1998 to present
Vice President, Human Resources June 1, 1997 to December 31, 1997
Vice President, Human Resources, Pacific July 1, 1996 to May 31, 1997
Gas and Electric Company
B. R. Worthington ........ Senior Vice President and General Counsel June 1, 1997 to present
General Counsel December 18, 1996 to May 31, 1997
Senior Vice President and General June 1, 1995 to June 30, 1997
Counsel, Pacific Gas and Electric Company
51
"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, Position
---- ------------------- --------
2000
----
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, Jr. ......... 50 Senior Vice President, Public 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 Executive Officer June 1, 1997 to present
Chief Financial Officer, PG&E Corporation December 18, 1996 to May 31, 1997
Senior Vice President and Chief Financial June 1, 1995 to May 31, 1997
Officer
Vice President and Chief Financial Officer November 1, 1991 to May 31, 1995
K. M. Harvey ............... Senior Vice President, Chief Financial Officer, November 1, 2000 to present
and Treasurer
Senior Vice President, Chief Financial Officer, January 1, 2000 to October 31, 2000
Controller, and Treasurer
Senior Vice President, Chief Financial Officer, July 1, 1997 to December 31, 1999
and Treasurer
Vice President and Treasurer June 1, 1995 to June 30, 1997
R. J. Peters ............... Senior Vice President and General Counsel January 1, 1999 to present
Vice President and General Counsel July 1, 1997 to December 31, 1998
Chief Counsel, Regulatory January 1, 1993 to June 30, 1997
J. K. Randolph ............. Senior Vice President and Chief of Utility April 6, 2000 to present
Operations
Senior Vice President and General Manager, July 1, 1997 to April 5, 2000
Transmission, Distribution and
Customer Service Business Unit
Vice President and General Manager, Power January 1, 1997 to June 30, 1997
Generation, Business Unit
Vice President, Power Generation November 1, 1991 to December 31, 1996
D. D. Richard, Jr. ......... Senior Vice President, Public Affairs May 1, 1998 to present
Senior Vice President, Governmental and July 1, 1997 to April 30, 1998
Regulatory Relations
Senior Vice President, Public Affairs, October 18, 2000 to present
PG&E Corporation
Vice President, Governmental Relations, July 1, 1997 October 17, 2000
PG&E Corporation
Vice President, Governmental Relations January 1, 1997 to June 30, 1997
Executive Vice President and Principal, January 1993 to December 1996
Morse, Richard, Weisenmiller & Assoc., Inc.
(energy, project finance, and
environmental consulting)
G. M. Rueger ............... Senior Vice President, Generation and chief April 6, 2000 to present
Nuclear Officer
Senior Vice President and General Manager, November 1, 1991 to April 5, 2000
Nuclear Power Generation Business Unit
52
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 amended 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 under the heading "Selected Financial Data" in the amended 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 under
the heading "Management's Discussion and Analysis" in the amended 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 under the heading "Management's Discussion and
Analysis--Quantitative and Qualitative Disclosures about Market Risk," and under
Notes 1, 4, 8 and 9 of the "Notes to the Consolidated Financial Statements" of
the amended 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 in the amended 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 "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
53
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.
54
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 amended report on
Form 10-K:
1. The following consolidated financial statements, supplemental
information, and report of independent public accountants
contained in the amended 2000 Annual 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 64 of this amended report on Form 10-K.
3. Report of Independent Public Accountants (Arthur Andersen LLP)
included at page 65 of this amended report on Form 10-K.
4. Report of Independent Public Accountants (Arthur Andersen LLP)
included at page 66 of this amended report on Form 10-K.
5. Financial statement schedules (these schedules are the same as the
schedules filed with the original filing):
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 (incorporated by
reference to PG&E Corporation's Form 10-K for the year ended
December 31, 2000 (File No.1-12609), Exhibit 3.2)
3.3 By-Laws of PG&E Corporation amended as of February 21, 2001
(incorporated by reference to PG&E Corporation's Form 10-K
for the year ended December 31, 2000 (File No. 1-12609),
Exhibit 3.3)
55
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 (incorporated by reference to Pacific Gas and
Electric Company's Form 10-K for the year ended December 31,
2000 (File No. 1-2348), Exhibit 3.5)
First and Refunding Mortgage of Pacific Gas and Electric
4.1 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
Form of Rights Agreement dated as of December 22, 2000 between
4.2 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 (incorporated by reference to PG&E
Corporation's Form 10-K for the year ended December 31, 2000
(File No. 1-12609), Exhibit 4.2)
The Gas Accord Settlement Agreement, together with accompanying
10. 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
(incorporated by reference to Form 10-K filed by PG&E
Corporation and Pacific Gas and Electric Company for the year
ended December 31, 2000 (File No. 1-12609 and File No. 1-2348),
Exhibit 10)
Stock Purchase Agreement By and Between PG&E National Energy
10.1 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)
Credit Agreement between PG&E Corporation, General Electric
10.2 Capital Corporation and Lehman Commercial Paper, Inc. dated
March 1, 2001 (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)
*10.3 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, 1999
(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)
56
*10.6 Letter regarding Compensation Arrangement between PG&E
Corporation and Thomas B. King dated November 4, 1998
(incorporated by reference to PG&E Corporation's Form 10-K
for the year ended December 31, 2000 (File No. 1-12609),
Exhibit 10.6)
*10.7 Letter regarding Compensation Arrangement between PG&E
Corporation and Lyn E. Maddox dated April 25, 1997
(incorporated by reference to PG&E Corporation's Form 10-K
for the year ended December 31, 2000 (File No. 1-12609),
Exhibit 10.7)
*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 (incorporated by reference to
PG&E Corporation's Form 10-K for the year ended December
31, 2000 (File No. 1-12609), Exhibit 10.9)
*10.10 PG&E Corporation Senior Executive Officer Retention Program
approved December 20, 2000 (incorporated by reference to
PG&E Corporation's Form 10-K for the year ended December
31, 2000 (File No. 1-12609), Exhibit 10.10)
*10.10.1 Letter regarding retention award to Robert D. Glynn, Jr.
dated January 22, 2001 (incorporated by reference to PG&E
Corporation's Form 10-K for the year ended December 31,
2000 (File No. 1-12609), Exhibit 10.10.1)
*10.10.2 Letter regarding retention award to Gordon R. Smith dated
January 22, 2001 (incorporated by reference to PG&E
Corporation's Form 10-K for the year ended December 31,
2000 (File No. 1-12609), Exhibit 10.10.2)
*10.10.3 Letter regarding retention award to Peter A. Darbee dated
January 22, 2001 (incorporated by reference to PG&E
Corporation's Form 10-K for the year ended December 31,
2000 (File No. 1-12609), Exhibit 10.10.3.)
*10.10.4 Letter regarding retention award to Bruce R. Worthington
dated January 22, 2001 (incorporated by reference to PG&E
Corporation's Form 10-K for the year ended December 31,
2000 (File No. 1-12609), Exhibit 10.10.4)
*10.10.5 Letter regarding retention award to G. Brent Stanley dated
January 22, 2001 (incorporated by reference to PG&E
Corporation's Form 10-K for the year ended December 31,
2000 (File No. 1-12609), Exhibit 10.10.5)
*10.10.6 Letter regarding retention award to Daniel D. Richard dated
January 22, 2001 (incorporated by reference to PG&E
Corporation's Form 10-K for the year ended December 31,
2000 (File No. 1-12609), Exhibit 10.10.6)
*10.10.7 Letter regarding retention award to James K. Randolph dated
February 27, 2001 (incorporated by reference to Pacific Gas
and Electric Company's Form 10-K for the year ended
December 31, 2000 (File No. 1-2348), Exhibit 10.10.7)
*10.10.8 Letter regarding retention award to Gregory M. Rueger dated
February 27, 2001 (incorporated by reference to Pacific Gas
and Electric Company's Form 10-K for the year ended
December 31, 2000 (File No. 1-2348), Exhibit 10.10.8)
*10.10.9 Letter regarding retention award to Kent Harvey dated
February 27, 2001 (incorporated by reference to Pacific Gas
and Electric Company's Form 10-K for the year ended
December 31, 2000 (File No. 1-2348), Exhibit 10.10.9)
*10.10.10 Letter regarding retention award to Roger J. Peters dated
February 27, 2001 (incorporated by reference to Pacific Gas
and Electric Company's Form 10-K for the year ended
December 31, 2000 (File No. 1-2348), Exhibit 10.10.10)
57
*10.10.11 Letter regarding retention award to Thomas G. Boren dated
February 27, 2001 (incorporated by reference to PG&E
Corporation's Form 10-K for the year ended December 31,
2000 (File No. 1-12609), Exhibit 10.10.11)
*10.10.12 Letter regarding retention award to Lyn E. Maddox dated
February 27, 2001 (incorporated by reference to PG&E
Corporation's Form 10-K for the year ended December 31,
2000 (File No. 1-12609), Exhibit 10.10.12)
*10.10.13 Letter regarding retention award to P. Chrisman Iribe dated
February 27, 2001 (incorporated by reference to PG&E
Corporation's Form 10-K for the year ended December 31,
2000 (File No. 1-12609), Exhibit 10.10.13)
*10.10.14 Letter regarding retention award to Thomas B. King dated
February 27, 2001 (incorporated by reference to PG&E
Corporation's Form 10-K for the year ended December 31,
2000 (File No. 1-12609), Exhibit 10.10.14)
*10.11 Agreement and Release between PG&E Corporation and Thomas
W. High dated December 8, 2000 (incorporated by reference
to PG&E Corporation's Form 10-K for the year ended December
31, 2000 (File No. 1-12609), Exhibit 10.11)
*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 (incorporated by reference to PG&E Corporation's Form
10-K for the year ended December 31, 2000 (File No.
1-12609), Exhibit 10.14)
*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)
*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 (incorporated by reference to
PG&E Corporation's Form 10-K for the year ended December
31, 2000 (File No. 1-12609), Exhibit 10.20)
*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)
58
*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 (incorporated by
reference to PG&E Corporation's Form 10-K for the year
ended December 31, 2000 (File No. 1-12609), Exhibit 11)
12.1 Computation of Ratios of Earnings to Fixed Charges for
Pacific Gas and Electric Company (incorporated by
reference to Pacific Gas and Electric Company's Form 10-K
for the year ended December 31, 2000, Exhibit 12.1)
12.2 Computation of Ratios of Earnings to Combined Fixed Charges
and Preferred Stock Dividends for Pacific Gas and
Electric Company (incorporated by reference to Pacific
Gas and Electric Company's Form 10-K for the year ended
December 31, 2000, Exhibit 12.2)
13. 2000 Amended 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 Registrants (incorporated by reference
to Form 10-K filed by PG&E Corporation and Pacific Gas
and Electric Company for the year ended December 31,
2000, Exhibit 21)
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 (incorporated by reference to
Form 10-K filed by PG&E Corporation and Pacific Gas and
Electric Company for the year ended December 31, 2000,
Exhibit 24.1)
24.2 Powers of Attorney (incorporated by reference to Form 10-K
filed by PG&E Corporation and Pacific Gas and Electric
Company for the year ended December 31, 2000, Exhibit
24.2)
____________
* 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:
59
1. October 25, 2000
Item 5. Other Events--
A. Third Quarter 2000 Consolidated Earnings
B. Pacific Gas and Electric Company's Wholesale Power Purchase Costs
C. Transition Cost Recovery
D. 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
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
60
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
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
61
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).
62
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrants have duly caused this Amendment No. 1 to
the their Annual Report on Form 10-K/A for the year ended December 31, 2000 to
be signed on their behalf by the undersigned, thereunto duly authorized, in the
City and County of San Francisco, on the 5th day of March, 2002.
PG&E CORPORATION PACIFIC GAS AND ELECTRIC COMPANY
(Registrant) (Registrant)
By /s/ Gary P. Encinas By /s/ Gary P. Encinas
------------------------------------ --------------------------------------
(Gary P. Encinas, Attorney-in-Fact) (Gary P. Encinas, Attorney-in-Fact)
63
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, February 26, 2002 as to Note 17, which report includes
explanatory paragraphs concerning the ability of Pacific Gas and Electric
Company to continue as a going concern and the revision of PG&E Corporation's
1999 and 2000 financial statements to consolidate the assets and liabilities
associated with certain leases; 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, February 26, 2002 as to Note 17
64
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
65
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
66
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
======= =======
67
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
======= ======= =======
68
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."
69
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."
70
EXHIBIT INDEX
-------------
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 (incorporated by
reference to PG&E Corporation's Form 10-K for the year ended
December 31, 2000 (File No. 1-12609), Exhibit 3.2)
3.3 By-Laws of PG&E Corporation amended as of February 21, 2001
(incorporated by reference to PG&E Corporation's Form 10-K for
the year ended December 31, 2000 (File No. 1-12609), Exhibit
3.3)
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 (incorporated by reference to Pacific Gas and
Electric Company's Form 10-K for the year ended December 31,
2000 (File No. 1-2348), Exhibit 3.5)
First and Refunding Mortgage of Pacific Gas and Electric
4.1 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
Form of Rights Agreement dated as of December 22, 2000 between
4.2 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 (incorporated by reference to PG&E
Corporation's Form 10-K for the year ended December 31, 2000
(File No. 1-12609), Exhibit 4.2)
The Gas Accord Settlement Agreement, together with accompanying
10. 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
(incorporated by reference to Form 10-K filed by PG&E
Corporation and Pacific Gas and Electric Company for the year
ended December 31, 2000 (File No. 1-12609 and File No. 1-2348),
Exhibit 10)
Stock Purchase Agreement By and Between PG&E National Energy
10.1 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)
Credit Agreement between PG&E Corporation, General Electric
10.2 Capital Corporation and Lehman Commercial Paper, Inc. dated
March 1, 2001 (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)
*10.3 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, 1999
(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
(incorporated by reference to PG&E Corporation's Form 10-K
for the year ended December 31, 2000 (File No. 1-12609),
Exhibit 10.6)
*10.7 Letter regarding Compensation Arrangement between PG&E
Corporation and Lyn E. Maddox dated April 25, 1997
(incorporated by reference to PG&E Corporation's Form 10-K
for the year ended December 31, 2000 (File No. 1-12609),
Exhibit 10.7)
*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 (incorporated by reference to
PG&E Corporation's Form 10-K for the year ended December 31,
2000 (File No. 1-12609), Exhibit 10.9)
*10.10 PG&E Corporation Senior Executive Officer Retention Program
approved December 20, 2000 (incorporated by reference to
PG&E Corporation's Form 10-K for the year ended December 31,
2000 (File No. 1-12609), Exhibit 10.10)
*10.10.1 Letter regarding retention award to Robert D. Glynn, Jr.
dated January 22, 2001 (incorporated by reference to PG&E
Corporation's Form 10-K for the year ended December 31, 2000
(File No. 1-12609), Exhibit 10.10.1)
*10.10.2 Letter regarding retention award to Gordon R. Smith dated
January 22, 2001 (incorporated by reference to PG&E
Corporation's Form 10-K for the year ended December 31, 2000
(File No. 1-12609), Exhibit 10.10.2)
*10.10.3 Letter regarding retention award to Peter A. Darbee dated
January 22, 2001 (incorporated by reference to PG&E
Corporation's Form 10-K for the year ended December 31, 2000
(File No. 1-12609), Exhibit 10.10.3.)
*10.10.4 Letter regarding retention award to Bruce R. Worthington
dated January 22, 2001 (incorporated by reference to PG&E
Corporation's Form 10-K for the year ended December 31,
2000 (File No. 1-12609), Exhibit 10.10.4)
*10.10.5 Letter regarding retention award to G. Brent Stanley dated
January 22, 2001 (incorporated by reference to PG&E
Corporation's Form 10-K for the year ended December 31, 2000
(File No. 1-12609), Exhibit 10.10.5)
*10.10.6 Letter regarding retention award to Daniel D. Richard dated
January 22, 2001 (incorporated by reference to PG&E
Corporation's Form 10-K for the year ended December 31, 2000
(File No. 1-12609), Exhibit 10.10.6)
*10.10.7 Letter regarding retention award to James K. Randolph dated
February 27, 2001 (incorporated by reference to Pacific Gas
and Electric Company's Form 10-K for the year ended December
31, 2000 (File No. 1-2348), Exhibit 10.10.7)
*10.10.8 Letter regarding retention award to Gregory M. Rueger dated
February 27, 2001 (incorporated by reference to Pacific Gas
and Electric Company's Form 10-K for the year ended December
31, 2000 (File No. 1-2348), Exhibit 10.10.8)
*10.10.9 Letter regarding retention award to Kent Harvey dated
February 27, 2001 (incorporated by reference to Pacific Gas
and Electric Company's Form 10-K for the year ended December
31, 2000 (File No. 1-2348), Exhibit 10.10.9)
*10.10.10 Letter regarding retention award to Roger J. Peters dated
February 27, 2001 (incorporated by reference to Pacific Gas
and Electric Company's Form 10-K for the year ended December
31, 2000 (File No. 1-2348), Exhibit 10.10.10)
*10.10.11 Letter regarding retention award to Thomas G. Boren dated
February 27, 2001 (incorporated by reference to PG&E
Corporation's Form 10-K for the year ended December 31, 2000
(File No. 1-12609), Exhibit 10.10.11)
*10.10.12 Letter regarding retention award to Lyn E. Maddox dated
February 27, 2001 (incorporated by reference to PG&E
Corporation's Form 10-K for the year ended December 31, 2000
(File No. 1-12609), Exhibit 10.10.12)
*10.10.13 Letter regarding retention award to P. Chrisman Iribe dated
February 27, 2001 (incorporated by reference to PG&E
Corporation's Form 10-K for the year ended December 31, 2000
(File No. 1-12609), Exhibit 10.10.13)
*10.10.14 Letter regarding retention award to Thomas B. King dated
February 27, 2001 (incorporated by reference to PG&E
Corporation's Form 10-K for the year ended December 31, 2000
(File No. 1-12609), Exhibit 10.10.14)
*10.11 Agreement and Release between PG&E Corporation and Thomas
W. High dated December 8, 2000 (incorporated by reference to
PG&E Corporation's Form 10-K for the year ended December 31,
2000 (File No. 1-12609), Exhibit 10.11)
*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 (incorporated by reference to PG&E Corporation's Form
10-K for the year ended December 31, 2000 (File No.
1-12609), Exhibit 10.14)
*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)
*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 (incorporated by reference to PG&E
Corporation's Form 10-K for the year ended December 31, 2000
(File No. 1-12609), Exhibit 10.20)
*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 (incorporated by
reference to PG&E Corporation's Form 10-K for the year ended
December 31, 2000 (File No. 1-12609), Exhibit 11)
12.1 Computation of Ratios of Earnings to Fixed Charges for
Pacific Gas and Electric Company (incorporated by reference
to Pacific Gas and Electric Company's Form 10-K for the year
ended December 31, 2000, Exhibit 12.1)
12.2 Computation of Ratios of Earnings to Combined Fixed Charges
and Preferred Stock Dividends for Pacific Gas and Electric
Company (incorporated by reference to Pacific Gas and
Electric Company's Form 10-K for the year ended December 31,
2000, Exhibit 12.2)
13. 2000 Amended 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 Registrants (incorporated by reference
to Form 10-K filed by PG&E Corporation and Pacific Gas and
Electric Company for the year ended December 31, 2000,
Exhibit 21)
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 (incorporated by reference to
Form 10-K filed by PG&E Corporation and Pacific Gas and
Electric Company for the year ended December 31, 2000,
Exhibit 24.1)
24.2 Powers of Attorney (incorporated by reference to Form 10-K
filed by PG&E Corporation and Pacific Gas and Electric
Company for the year ended December 31, 2000, Exhibit 24.2)
____________
* 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.