SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year Ended December 31, 1999
OR
[_] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
IRS Employer
Commission Exact Name of Registrant State of Identification
File Number as specified in its charter Incorporation Number
----------- --------------------------- ------------- --------------
1-12609 PG&E CORPORATION California 94-3234914
1-2348 PACIFIC GAS AND ELECTRIC COMPANY California 94-0742640
Pacific Gas and Electric Company PG&E Corporation
77 Beale Street One Market, Spear Tower
P.O. Box 770000 Suite 2400
San Francisco, California San Francisco, California
(Address of principal executive (Address of principal executive
offices) offices)
94177 94105
(Zip Code) (Zip Code)
(415) 973-7000 (415) 267-7000
(Registrant's telephone number, (Registrant's telephone number,
including area code) including area code)
Securities registered pursuant to Section 12(b) of the Act:
Name of Each Exchange on
Title of Each Class Which Registered
------------------- ---------------------------
PG&E Corporation
Common Stock, no par value New York Stock Exchange and
Pacific Exchange
Pacific Gas and Electric Company
First Preferred Stock, cumulative, American Stock Exchange and
par value $25 per share: Pacific Exchange
Redeemable: 7.04%, 5% Series A, 5%, 4.80%,
4.50%, 4.36%
Mandatorily Redeemable: 6.57%, 6.30%
Nonredeemable: 6%, 5.50%, 5%
7.90% Cumulative Quarterly Income Preferred American Stock Exchange and
Securities, Series A (liquidation preference Pacific Exchange
$25), issued by PG&E Capital I and guaranteed by
Pacific Gas and Electric Company
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days.
Yes [X] No [_]
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to
the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [_]
Aggregate market value of the voting stock held by non-affiliates of the
registrant as of February 22, 2000:
PG&E Corporation Common Stock $8,095 million
Pacific Gas and Electric Company First Preferred Stock $331 million
Common Stock outstanding as of February 22, 2000:
PG&E Corporation: 384,825,799
Pacific Gas and Electric Company: Wholly owned by PG&E Corporation
The market values of certain series of First Preferred Stock, for which
market prices as of a date within 60 days prior to the date of filing were not
available, were derived by dividing the annual dividend rate of each such
series of stock by the average yield of all of Pacific Gas and Electric
Company's Preferred Stock outstanding for which market prices were available.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the documents listed below have been incorporated by reference
into the indicated parts of this report, as specified in the responses to the
item numbers involved.
(1) Designated portions of the combined Annual Report to
Shareholders for the year ended December 31, 1999..... 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 2000 Annual Meetings of Shareholders.. Part III (Items 10, 11, 12, and 13)
TABLE OF CONTENTS
Page
----
Glossary of Terms.............................................. iii
PART I
Item 1. Business....................................................... 1
GENERAL........................................................ 1
Corporate Structure and Business............................... 1
Competition and the Changing Regulatory Environment............ 2
Regulation of PG&E Corporation................................. 3
Regulation of Pacific Gas and Electric Company................. 4
State Regulation............................................. 4
Federal Regulation........................................... 4
Licenses and Permits......................................... 4
Regulation of the National Energy Group........................ 4
Risk Management Programs....................................... 5
UTILITY OPERATIONS............................................. 7
Ratemaking Mechanisms.......................................... 7
Electric Ratemaking.......................................... 8
Gas Ratemaking............................................... 11
Electric Utility Operations.................................... 12
California Electric Industry Restructuring................... 12
The California Independent System Operator and the
California Power Exchange................................. 12
Voluntary Generation Asset Divestiture..................... 13
Recovery of Transition Costs............................... 14
Retail Direct Access....................................... 14
Rate Levels and Rate Reduction Bonds....................... 15
Public Purpose Programs.................................... 15
Distributed Generation and Electric Distribution
Competition............................................... 15
Electric Operating Statistics.................................. 16
Electric Generating Capacity................................... 17
Diablo Canyon.................................................. 18
Diablo Canyon Operations..................................... 18
Diablo Canyon Ratemaking..................................... 19
Nuclear Fuel Supply and Disposal............................. 19
Insurance.................................................... 20
Decommissioning.............................................. 20
Other Electric Resources....................................... 21
QF Generation and Other Power Purchase Contracts............. 21
Electric Transmission and Distribution......................... 22
Gas Utility Operations......................................... 23
Gas Operating Statistics....................................... 24
Natural Gas Supplies........................................... 25
Gas Regulatory Framework....................................... 25
Transportation Commitments..................................... 26
Core Procurement Incentive Mechanism........................... 27
NATIONAL ENERGY GROUP.......................................... 28
Gas Transmission Operations.................................... 28
i
TABLE OF CONTENTS--(Continued)
Page
----
PG&E Gas Transmission, Texas................................ 28
PG&E GT-Northwest........................................... 29
Independent Power Generation.................................. 30
New England Operations...................................... 30
Portfolio of Operating Generating Plants...................... 31
Generation Development Projects............................. 32
Energy Trading................................................ 32
Energy Services............................................... 33
ENVIRONMENTAL MATTERS......................................... 34
Environmental Matters......................................... 34
Environmental Protection Measures........................... 34
Air Quality................................................. 34
Water Quality............................................... 35
Hazardous Waste Compliance and Remediation.................. 36
Potential Recovery of Hazardous Waste Compliance and
Remediation Costs.......................................... 37
Compressor Station Litigation............................... 38
Electric and Magnetic Fields................................ 38
Low Emission Vehicle Programs............................... 38
Item 2. Properties.................................................... 39
Item 3. Legal Proceedings............................................. 39
Compressor Station Chromium Litigation........................ 39
Texas Franchise Fee Litigation................................ 40
Item 4. Submission of Matters to a Vote of Security Holders........... 42
EXECUTIVE OFFICERS OF THE REGISTRANTS......................... 43
PART II
Item 5. Market for the Registrant's Common Equity and Related
Stockholder Matters.......................................... 46
Item 6. Selected Financial Data....................................... 46
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations.................................... 46
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.... 46
Item 8. Financial Statements and Supplementary Data................... 46
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure..................................... 47
PART III
Item 10. Directors and Executive Officers of the Registrant............ 47
Item 11. Executive Compensation........................................ 47
Item 12. Security Ownership of Certain Beneficial Owners and
Management................................................... 47
Item 13. Certain Relationships and Related Transactions................ 47
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form
8-K.......................................................... 48
Signatures.................................................... 52
Independent Auditors' Report (Deloitte & Touche LLP).......... 53
Independent Auditors' Report (Arthur Andersen LLP)............ 54
Report of Independent Public Accountants (Arthur Andersen
LLP)......................................................... 55
ii
GLOSSARY OF TERMS
AB 1890.................... Assembly Bill 1890, the California electric industry restructuring legislation
AEAP....................... Annual Earnings Assessment Proceeding
ATCP....................... Annual Transition Cost Proceeding
BCAP....................... Biennial Cost Allocation Proceeding
bcf........................ billion cubic feet
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
CERCLA..................... Comprehensive Environmental Response, Compensation, and Liability Act
core customers............. residential and smaller commercial gas customers
core subscription
customers................. noncore customers who choose bundled service
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
EDRA....................... Electric Deferred Refund Account
El Paso.................... El Paso Natural Gas Company
EMF........................ electric and magnetic fields
EPA........................ United States Environmental Protection Agency
ERCA....................... Electric Restructuring Costs Account
FERC....................... Federal Energy Regulatory Commission
Gas Accord................. Gas Accord Settlement
Geysers.................... The Geysers Power Plant
GRC........................ General Rate Case
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
IPP........................ Independent power producer
ISO........................ Independent System Operator
kV......................... kilovolts
kVa........................ kilovolt-amperes
kW......................... kilowatts
kWh........................ kilowatt-hour
LEV........................ low emission vehicle
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
iii
GLOSSARY OF TERMS--(Continued)
NGL........................ natural gas liquids
noncore customers.......... industrial and larger commercial gas customers
NOx........................ oxides of nitrogen
NRC........................ Nuclear Regulatory Commission
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
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 GT-Northwest.......... PG&E Gas Transmission, Northwest Corporation formerly known as
Pacific Gas Transmission Company
PG&E GT NW Expansion....... PG&E Gas Transmission, Northwest Corporation's portion of the Pipeline
Expansion
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
PRP........................ potentially responsible party
PURPA...................... Public Utility Regulatory Policies Act of 1978
PX......................... California Power Exchange
QF......................... qualifying facility
RAP........................ Revenue Adjustment Proceeding
RRC........................ The Railroad Commission of Texas
SEC........................ Securities and Exchange Commission
SOS........................ Standard Offer Service
Teco....................... Teco Pipeline Company
TCBA....................... Transition Cost Balancing Account
TRA........................ Transition Revenue Account
Transwestern............... Transwestern Pipeline Company
USGenNE.................... US Gen New England, Inc.
Utility.................... Pacific Gas and Electric Company and it subsidiaries
Valero..................... Valero Energy Corporation
iv
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.
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.
In addition to the regulated utility business of Pacific Gas and Electric
Company, PG&E Corporation's National Energy Group provides energy products and
services throughout North America. The National Energy Group businesses
develop, construct, operate, own, and manage independent power generation
facilities that serve wholesale and industrial customers through PG&E
Generating Company, LLC (formerly U.S. Generating Company, LLC) and its
affiliates (collectively, PG&E Gen); own and operate natural gas pipelines,
natural gas storage facilities, and natural gas processing plants, primarily
in the Pacific Northwest and Texas, through various subsidiaries of PG&E
Corporation (collectively, PG&E Gas Transmission or PG&E GT); purchase and
sell energy commodities and provide risk management services to customers in
major North American markets, including the National Energy Group's non-
utility businesses, unaffiliated utilities, marketers, municipalities, and
large end-use customers through PG&E Energy Trading--Gas Corporation, PG&E
Energy Trading--Power, L.P., and their affiliates (collectively, PG&E Energy
Trading or PG&E ET); and provide competitively priced electricity, natural
gas, and related services to industrial, commercial, and institutional
customers through PG&E Energy Services Corporation (PG&E Energy Services or
PG&E ES). In the fourth quarter of 1999, PG&E Corporation's Board of Directors
approved a plan for the divestiture of PG&E Corporation's Texas natural gas
and natural gas liquids business. Also in the fourth quarter of 1999, PG&E
Corporation's Board of Directors approved a plan for the divestiture of PG&E
Corporation's retail energy services. See "National Energy Group--Gas
Transmission Operations" and "National Energy Group--Energy Services" below.
As of December 31, 1999, PG&E Corporation had $29.7 billion in assets. PG&E
Corporation generated $20.8 billion in operating revenues for 1999. As of
December 31, 1999, PG&E Corporation and its subsidiaries and affiliates had
22,433 employees. As of December 31, 1999, Pacific Gas and Electric Company
had $21.4 billion in assets. The Utility generated $9.2 billion in operating
revenues for 1999. As of December 31, 1999, the Utility had 18,935 employees.
The gas and electric utility operations of Pacific Gas and Electric Company
represent the largest component of PG&E Corporation's business, contributing
44% of PG&E Corporation's total revenues in 1999.
1
PG&E Corporation has identified four reportable operating segments. The
Utility is one reportable operating segment and the other three are part of
PG&E Corporation's National Energy Group (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 1999 Annual Report to
Shareholders and in Note 17 of the "Notes to Consolidated Financial
Statements" beginning on page 63 of PG&E Corporation's 1999 Annual Report to
Shareholders, portions of which are filed as Exhibit 13 to this report.
The following report includes forward-looking statements about the future
that involve a number of risks and uncertainties. These statements are based
on 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 pace and extent of the ongoing restructuring of the
electric and natural gas industries across the United States; operational
changes related to industry restructuring, including changes to the Utility's
business processes and systems; the method and timing of disposition and
valuation of the Utility's hydroelectric generation assets; the timing of the
completion of the Utility's transition cost recovery and the consequent end of
the current electric rate freeze in California; any changes in the amount the
Utility is allowed to collect (recover) from its customers for certain costs
which prove to be uneconomic under the new competitive market (called
transition costs); future operating performance at the Utility's Diablo Canyon
Nuclear Power Plant (Diablo Canyon); the method adopted by the CPUC for
sharing the net benefits of operating Diablo Canyon with ratepayers and the
timing of the implementation of the adopted method; the extent of anticipated
growth of transmission and distribution services in the Utility's service
territory; future market prices for electricity; future fuel prices; the
success of management's strategies to maximize shareholder value in PG&E
Corporation's National Energy Group which may include acquisitions or
dispositions of assets or internal restructuring; the extent to which current
or planned generation development projects are completed and the pace and cost
of such completion; generating capacity expansion and retirements by others;
the successful integration and performance of acquired assets; the outcome of
the Utility's various regulatory proceedings, including the the proposal to
auction the Utility's hydroelectric generation assets, the electric
transmission rate case applications, and post-transition period ratemaking
proceedings; fluctuations in commodity gas, natural gas liquid, and
electricity prices and the ability to successfully manage such price
fluctuations; and the pace and extent of competition in the California
generation market and its impact on the Utility's costs and resulting
collection of transition costs. As the ultimate impact of these and other
factors is uncertain, these and other factors may cause future results to
differ materially from results or outcomes currently expected or sought by
PG&E Corporation.
Competition and the Changing Regulatory Environment
The electric and gas industries are continuing to undergo significant
change. 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 1998, California became one of the first states in the country to
implement electric industry restructuring and establish a competitive market
framework for electric generation. Today, most Californians may continue to
purchase their electricity from investor-owned utilities (such as Pacific Gas
and Electric Company) or they may choose to purchase electricity from
alternative generation providers (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, continue to be the generation providers. 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. The framework for electric industry
restructuring was established in Assembly
2
Bill 1890 (AB 1890) passed by the California Legislature and signed by the
Governor in 1996. For information about California electric industry
restructuring, see "Utility Operations--Electric Utility Operations--
California Electric Industry Restructuring" below.
Although the initial stages of restructuring have focussed on competition
among suppliers of generation, the CPUC also is studying the effect of
distributed generation (where the electric energy source is located in close
proximity to electric demand) in the California generation market and possible
changes in the electric distribution function of traditional utilities. See
"Utility Operations--Electric Utility Operations--California Electric Industry
Restructuring--Distributed Generation and Electric Distribution Competition"
below.
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. 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.
Additional information concerning competition and the changing regulatory
environment is provided in "Management's Discussion and Analysis" in the 1999
Annual Report to Shareholders, beginning on page 5, and in Note 2 of the
"Notes to Consolidated Financial Statements" beginning on page 40 of the 1999
Annual Report to Shareholders, which information is hereby incorporated by
reference.
Regulation of PG&E Corporation
PG&E Corporation and its subsidiaries are exempt from all provisions,
except Section 9(a)(2), of the Public Utility Holding Company Act of 1935
(Holding Company Act). At present, PG&E Corporation has no expectation of
becoming a registered holding company under the Holding Company Act.
PG&E Corporation is not a public utility under the laws of California and
is not subject to regulation as such by the CPUC. However, the CPUC approval
authorizing Pacific Gas and Electric Company to form a holding company was
granted subject to various conditions related to finance, human resources,
records and bookkeeping, and the transfer of customer information. The
financial conditions provide that the Utility is precluded from guaranteeing
any obligations of PG&E Corporation without prior written consent from the
CPUC, the Utility's dividend policy shall continue to be established by the
Utility's Board of Directors as though Pacific Gas and Electric Company were a
stand-alone utility company, and the capital requirements of the Utility, as
determined to be necessary to meet the Utility's service obligations, shall be
given first priority by the Boards of Directors of PG&E Corporation and
Pacific Gas and Electric Company. The conditions also provide that the Utility
shall maintain on average its CPUC-authorized utility capital structure,
although it shall have an opportunity to request a waiver of this condition if
an adverse financial event reduces the Utility's equity ratio by 1% or more.
The CPUC also has adopted complex and detailed rules governing transactions
between California's natural gas local distribution and electric utility
companies and their non-regulated affiliates. The rules permit non-regulated
affiliates of regulated utilities (such as PG&E Energy Services, the non-
regulated energy marketing subsidiary of PG&E Corporation) 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
3
exchange among the affiliates. The rules prohibit the utilities from engaging
in certain practices, which 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.
Regulation of Pacific Gas and Electric Company
State Regulation
The CPUC has jurisdiction to regulate the following utility functions
within California: electric distribution service, gas distribution service,
and gas transmission service. The CPUC regulates Pacific Gas and Electric
Company's rates and conditions of service, sales of securities, dispositions
of utility property, rates of return, rates of depreciation, and long-term
resource procurement. The CPUC also conducts various reviews of utility
performance and conducts investigations into various matters, such as
deregulation, competition, and the environment, in order to determine its
future policies. The CPUC consists of five members appointed by the Governor
and confirmed by the State Senate for six-year terms.
The California Energy Commission (CEC) has the responsibility to make
electric-demand forecasts for the state and for specific service territories.
Based upon these forecasts, the CEC determines the need for additional energy
sources and for conservation programs. The CEC sponsors alternative-energy
research and development projects, promotes energy conservation programs, and
maintains a statewide plan of action in case of energy shortages. In addition,
the CEC certifies power plant sites and related facilities within California.
The CEC also administers funding for public purpose research and development,
and renewable technologies programs.
Federal Regulation
The FERC regulates electric transmission rates and access, operation of the
California Independent System Operator (ISO) and the California Power Exchange
(PX), uniform systems of accounts, and electric contracts involving sales of
electricity for resale. The FERC also 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.
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.
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. Pacific Gas and Electric
Company currently has ten hydroelectric projects and one transmission line
project undergoing FERC license renewal.
Regulation of the National Energy Group
In addition to Pacific Gas and Electric Company, certain of PG&E
Corporation's other subsidiaries that conduct interstate gas transmission and
storage and electric wholesale power marketing operations are subject to
4
FERC jurisdiction. The FERC also has authority to regulate rates for natural
gas transportation and storage in interstate commerce. The FERC also regulates
certain transportation and storage transactions on the intrastate pipelines
pursuant to Section 311 of the Natural Gas Policy Act of 1978.
The Railroad Commission of Texas (RRC) regulates gas utilities, including
those owned by PG&E Corporation through PG&E Gas Transmission, Texas
Corporation (PG&E GTT), PG&E Gas Transmission Teco, Inc., and other affiliates
operating in Texas. The RRC's gas proration rules govern the wellhead
production and purchase of gas. Intrastate pipelines can provide intrastate
gas transportation at negotiated rates that are presumed just and reasonable.
If the criteria for negotiated rates cannot be met, the RRC may assess a cost-
of-service-based rate. The RRC also may regulate certain sales of gas.
Currently, the price of natural gas sold under a majority of PG&E GTT's gas
sales contracts is not regulated by the RRC. All transportation and gathering
of gas is subject to the RRC Code of Conduct which prohibits undue
discrimination among similarly situated shippers. Further, all transportation
of gas, processing of gas, and transportation of natural gas liquids is
subject to safety regulations enforced by the RRC and the Texas Natural
Resource Conservation Commission.
In addition, the power generation projects that PG&E Gen develops, manages,
or owns are subject to differing types of federal regulation depending on the
regulatory status of the particular project. Some of these projects are exempt
wholesale generators (EWG) under the National Energy Policy Act of 1992, which
status exempts the project from regulation under the Holding Company Act. EWG
status is granted by the FERC upon application by the project. Some projects
have received authority from the FERC to charge market-based rates for the
power they sell, rather than traditional cost-based rates. Many of PG&E Gen's
affiliated projects are qualifying facilities (QFs) under the Public Utility
Regulatory Policies Act of 1978 (PURPA). QF status exempts the project from
regulation under various federal and state laws concerning the electric
industry. PG&E Gen's projects are also subject to various federal, state, and
local regulations concerning siting and environmental matters.
PG&E Corporation's indirect subsidiary USGen New England, Inc. (USGenNE)
acquired the electric generating facilities of the New England Electric System
(NEES) in September 1998. USGenNE also is subject to numerous federal, state,
and local statutes and regulations. USGenNE sells at wholesale all of the
electricity it generates, as well as electricity it purchases from third
parties under existing power sales agreements. Under the Federal Power Act
(FPA), the FERC regulates these wholesale sales. The FERC has approved
USGenNE's rate schedule as a market-based schedule and, accordingly, the FERC
granted USGenNE waivers of certain other requirements that otherwise are
imposed on utilities with cost-based rate schedules. In addition, USGenNE owns
and operates a number of hydroelectric and pumped storage projects that are
licensed by the FERC. These licenses expire periodically and the projects must
be relicensed at that time. USGenNE's licenses for these hydroelectric
projects expire over a period from 2001 to 2020. Before expiration of any one
of the hydroelectric licenses, there is an opportunity for the existing
licensee (as well as others interested in owning and operating the project) to
apply for, and obtain, a new license.
USGenNE also is subject to limited regulation by certain state public
utility commissions located in states where USGenNE owns and operates electric
generating facilities. This regulation does not extend to its rates, which are
regulated exclusively by the FERC, and the scope of this regulation has been
substantially limited by various legislative initiatives.
Other regulatory matters are described throughout this report.
Risk Management Programs
PG&E Corporation has an officer-level Risk Management Committee and has
adopted a Risk Management Policy, approved by the Board of Directors of PG&E
Corporation, for trading and risk management activities. The Risk Management
Committee oversees implementation of the policy, approves the trading and risk
management policies of subsidiaries, and monitors compliance with the policy.
5
The Risk Management Policy allows derivatives to be used for both hedging
and non-hedging purposes. (A derivative is a contract whose value is dependent
on or derived from the value of some underlying asset.) PG&E Corporation uses
derivatives for hedging purposes primarily to offset underlying commodity
price risks. PG&E Corporation also participates in markets using derivatives
to gather market intelligence, create liquidity, maintain a market presence,
and take a market view. Such derivatives include forward contracts, futures,
swaps, and options. The Risk Management Policy and the trading and risk
management policies of PG&E Corporation's subsidiaries prohibit the use of
derivatives whose payment formula includes a multiple of some underlying
asset. The Risk Management Committee also monitors the trading and risk
management of PG&E ET, consistent with PG&E Corporation's Risk Management
Policy. See "National Energy Group--Energy Trading."
The CPUC has authorized Pacific Gas and Electric Company to trade natural
gas-based financial instruments to manage price and revenue risks associated
with its natural gas transmission and storage assets, subject to certain
conditions. The CPUC also has authorized the Utility to trade natural gas-
based financial instruments to hedge the gas commodity price swings in serving
core gas customers. In May 1999, the PX obtained FERC approval to operate the
"block forward market" which offers parties the ability to buy and sell
contracts to purchase electricity in the future at prices set in the
contracts. The Utility sought and obtained CPUC authority to participate in
the PX block forward market for contracts that call for delivery of the
purchased electricity by October 31, 2000, as well as to recover costs (such
as gain/losses and transaction fees) associated with its participation in this
market.
Additional information concerning risk management activities and the
financial impact of risk management activities on PG&E Corporation and Pacific
Gas and Electric Company is provided in "Management's Discussion and Analysis"
in the 1999 Annual Report to Shareholders, beginning on page 5 and in Notes 1,
3, and 4 of the "Notes to Consolidated Financial Statements" beginning on pages
36, 45, and 47, respectively, of the 1999 Annual Report to Shareholders, which
information is hereby incorporated by reference.
6
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, financial services, food processing, petroleum refining,
agriculture, and tourism.
Ratemaking Mechanisms
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 Pacific Gas and Electric Company'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. On February 17, 2000, the CPUC issued
a decision in the Utility's GRC for the period 1999-2001, further discussed
below. The decision also orders that the Utility file a 2002 GRC, so that the
revenue requirements established in the 2002 GRC will be the starting point
for a future performance based ratemaking (PBR) mechanism (discussed below)
that is intended to eventually replace the GRC mechanism and cost of capital
proceedings.
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. In November
1999, the Utility filed its 2000 cost of capital application. To reflect
increasing interest rates, the Utility has requested a return on equity (ROE)
of 12.5% and an overall rate of return of 9.76% as compared to its 1999
authorized rates of 10.6% ROE and 8.75% overall rate of return. The Utility
has not requested any change in its current authorized capital structure of
46.2% long-term debt, 5.8% preferred stock, and 48% common equity. If granted,
the requested ROE would increase electric distribution revenues by
approximately $36.6 million and natural gas distribution revenues by
approximately $127.8 million based upon the rate base authorized in the 1999
GRC. The Utility requested that a final CPUC decision be issued in June 2000.
On February 17, 2000, the CPUC issued a decision to allow the final CPUC
decision, when it is adopted, to be effective retroactively to February 17,
2000. The return on the Utility's electric transmission-related assets will be
determined by the FERC in 2000. 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. The authorized
ROE for the Utility's remaining generation assets, including Diablo Canyon, is
6.77% throughout the transition period.
Electric and Gas Distribution Performance-Based Ratemaking. In November
1998, the Utility filed an application with the CPUC to establish performance-
based ratemaking (PBR) for electric and gas distribution services. The
proposed distribution PBR would establish electric and gas distribution
revenue requirements for the year in which PBR is approved to 2004 taking the
place of the GRC and cost of capital proceedings for these years. The Utility
proposed that the revenue requirement for the year 2000 be determined by
applying a formula, based principally on inflation and productivity factors,
to the 1999 GRC authorized revenue requirement. In subsequent years, the
formula would be applied to the previous year's authorized revenue
requirement. The proposed PBR also includes a sharing mechanism for earnings
that are significantly above or below the authorized cost of capital, and a
framework for rewards and penalties based upon the achievement of various
performance measures.
7
The final decision in the GRC requires the Utility to go forward with the
performance rewards/penalties framework of its PBR proposal, but it requires a
2002 GRC before implementing the PBR mechanism that determines future revenue
requirements based principally on inflation and productivity factors. The
starting point for the PBR mechanism will be the revenue requirements
established in the required 2002 GRC. In any event, after the transition
period, the Utility's earnings from its electric distribution operations will
be subject to volatility as a result of sales fluctuations.
Annual Earnings Assessment Proceeding. The Annual Earnings Assessment
Proceeding (AEAP) determines shareholder incentives to be earned for Pacific
Gas and Electric Company's demand side management (DSM) programs. The Utility
was authorized to collect $15.9 million in incentive payments during 1999. The
Utility has filed an application seeking $28.7 million in incentive payments
relating to 1998 energy efficiency and low-income assistance programs, and DSM
programs from other years to be paid in 2000. After consolidating the adjusted
incentive payment installments from prior years, the net revenue change in
2000 from DSM shareholder incentives should be an electric increase of
approximately $2.47 million and a gas decrease of approximately $0.75 million
assuming the Utility's incentive claims are approved. The 1999 AEAP decision
is expected in the second quarter of 2000.
Catastrophic Event Memorandum Account. The Catastrophic Event Memorandum
Account (CEMA) allows Pacific Gas and Electric Company to track costs incurred
in connection with catastrophic events. On January 7, 1999, the Utility filed
an application with the CPUC in its first CEMA proceeding requesting increases
in electric and gas revenue requirements of $60.1 million and $15.8 million,
respectively, for costs incurred for several emergencies, including the 1991
Oakland Hills Fire and 1998 storms. In September 1999, the Utility entered
into a settlement agreement providing for a $59 million increase in electric
distribution revenue requirement and a $11 million increase in gas
distribution revenue requirement effective January 1, 2000. A CPUC decision is
expected in early 2000.
Electric Ratemaking
The California electric industry restructuring legislation provided for a
transition period during which electric customer rates remain frozen. Any
change in the Utility's electric revenue requirements resulting from the items
discussed below will not change electric customer rates. Under the electric
rate freeze, the portion of total actual revenue that exceeds authorized base
revenues and certain other authorized revenue requirements and costs is
available to recover transition costs during the transition period. Transition
costs are certain generation-related costs that prove to be uneconomic under
the new competitive generation market. (See "Electric Utility Operations--
California Electric Industry Restructuring--Recovery of Transition Costs.")
Therefore, increases in base revenues would reduce the amount of revenue
available to recover transition costs. Conversely, decreases in base revenues
would increase revenue available from frozen rates for recovery of transition
costs. The transition period will end the earlier of December 31, 2001, or
when the Utility has recovered its eligible transition costs. The electric
rate freeze will end the earlier of March 31, 2002, or when the Utility has
recovered its eligible transition costs.
General Rate Case. On February 17, 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 increases in base revenues for the Utility's
electric distribution function of $377 million over base revenues authorized
in 1996.
Revenue Adjustment Proceeding. On January 1, 1998, the Transition Revenue
Account (TRA) was established. The TRA 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) to offset transition costs. The CPUC established a separate
annual proceeding, the Revenue Adjustment Proceeding (RAP), to review and
verify the amounts recorded in
8
the 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. In June 1999, the
CPUC issued a decision in the Utility's first RAP that, among other things,
adopted an agreement between the Utility and the CPUC's Office of Ratepayer
Advocates (ORA) that resolved several rate allocation and rate design issues,
eliminated certain balancing and memorandum accounts, and allows the recovery
of entries made into the TRA from January 1 through May 31, 1998 and certain
other balancing accounts, subject to CPUC audit. On August 9, 1999, the
Utility filed its application in the 1999 RAP addressing revenues and costs
recorded in the TRA from June 1, 1998 through June 30, 1999. A CPUC decision
on this application is expected in late 2000.
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 September 1, 1998, the Utility filed its application in the 1998
ATCP requesting that $1.8 billion of costs recorded in the TCBA from January 1
through June 30, 1998 be approved as eligible for recovery as transition
costs. In July 1999, PG&E and ORA filed a joint motion with the CPUC for
approval of a settlement that recommends that the CPUC approve substantially
all costs requested by the Utility. On February 17, 2000, the CPUC issued a
decision which accepts the settlement in its entirety, and decides most of the
other issues in the case in the Utility's favor. Under the final decision, on
a prospective basis, the utilities are required to assess the estimated market
value of their remaining non-nuclear generating assets, including the land
associated with those assets, on an aggregate basis at a value not less than
the net book value of those assets and to credit the TCBA with the estimated
value. The decision encourages the utilities to base such estimates on
realistic assessments of the market value of the assets. The final decision
did not adopt a recommendation contained in a previously issued proposed
decision to establish a new regulatory asset account that would allow a true-
up when the estimated market value is greater than actual market value.
However, the decision states that crediting the TCBA with the aggregate net
book value of the remaining non-nuclear generating assets is a conservative
approach and remedies any concerns regarding the lack of a true-up. The
decision provides that if the estimated market valuation is less than book
value for any individual asset, accelerated amortization of the associated
transition costs will continue until final market valuation of the asset
occurs through sale, appraisal, or other divestiture. If the final value of
the assets, determined through sale, appraisal or other divestiture, is higher
than the estimate, the excess amount would be used to pay remaining transition
costs, if any. The utilities are required to file the adjusted entries to
their respective TCBA based on the estimated market values with the CPUC by
March 9, 2000. The filing will become effective after appropriate review by
the CPUC's Energy Division and the TCBA entries are subject to review in the
next ATCP. On September 1, 1999, the Utility filed its 1999 ATCP application
requesting that $2.6 billion recorded in the TCBA from July 1, 1998, through
June 30, 1999, be approved as eligible for recovery as transition costs.
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.
As part of the settlement agreement, the CPUC also 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
9
from the CPUC or the FERC, and certain other costs. The reasonableness of the
entries made in the ERCA and the recovery of these costs will be made through
a separate application by the Utility in 2000.
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) and three of its hydroelectric generation
facilities are under must-run contracts. The form of must-run contract chosen
for all of these facilities (except Hunters Point) is the one that does not
limit market participation. The Utility currently receives approximately $100
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 when the ISO has not dispatched the
plant. The Utility has filed an application with the CPUC to determine the
market value of its hydroelectric generation facilities and related assets
through an open competitive auction.
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, 1999, the Utility has recorded approximately $39 million of these
scheduling coordinator costs in the TRBA. (The Utility has also disputed
approximately $22.5 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.). On September 1, 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 2000. On January 11, 2000, the FERC accepted a
proposal by the Utility to establish the Scheduled Coordinator Services (SCS)
Tariff which 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. The CPUC's
Office of Ratepayer Advocate (ORA) has recommended that $88.4 million in
expenditures for 1997 and 1998 be disallowed. The Utility Reform Network
(TURN) has 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. A proposed decision is not expected until the first quarter of
2000. Any proposed decision would be subject to comment by the parties and
change by the CPUC before a final decision is issued.
10
Electric Transmission Revenues. Since April 1998, all electric transmission
revenues are authorized by the FERC. During 1998 and 1999, the FERC issued
orders that put into effect various rates to recover electric transmission
costs from the Utility's former bundled rate transmission customers. All 1998
and 1999 rates are subject to refund, pending final decisions. In April 1999,
the Utility filed a settlement with the FERC which, if approved, would allow
the Utility to recover $345 million for the period of April 1998 through May
1999. In May 1999, the FERC accepted, subject to refund, the Utility's March
1999 request to begin recovering, as of May 31, 1999, $324 million annually.
In October 1999, the FERC accepted, subject to refund, the Utility's September
1999 request to increase revenues to $370 million annually beginning in April
2000.
Electric Deferred Refund Account (EDRA). In December 1996, the CPUC issued
a decision establishing an EDRA. The CPUC ordered the Utility to place into
the EDRA credits for CPUC-ordered electric disallowances, the utility electric
generation share of gas disallowances ordered by the CPUC or the FERC, and
amounts resulting from reasonableness disputes or fuel-related cost refunds
made to the Utility based on regulatory agency decisions, plus interest
charges. In February 2000, the Utility refunded approximately $25 million of
EDRA refunds to customers, which included a refund of unspent research,
development, and demonstration funds.
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 addresses the mechanisms
for ending the current electric rate freeze and for establishing post-
transition period accounting mechanisms and rates. The decision prohibits the
Utility from collecting after the rate freeze any electric 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 under-collected accounting balances relating to power purchases. The
decision also requires the discontinuance of Diablo Canyon's performance-based
ratemaking, the incremental cost incentive price (ICIP) mechanism, at the end
of the transition period. Instead, after the transition period, Diablo Canyon
generation must be sold at the prevailing market price for power. The Utility
has filed an application for rehearing of the CPUC's decision.
In the 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. The CPUC intends to explore other ratemaking issues,
including whether dollar-for-dollar recovery of energy costs is appropriate,
in the second phase of the post-transition electric ratemaking proceeding.
There are three primary options for the future regulatory framework for
utility electric energy procurement cost recovery after the rate freeze: (1) a
CPUC-defined procurement practice, that if followed by the Utility, would pass
through costs without the need for reasonableness reviews, (2) a pass through
of costs subject to after-the-fact reasonableness reviews, or (3) a
procurement incentive mechanisms with rewards and penalties determined based
on the Utility's energy purchasing performance compared to a benchmark. The
Utility proposed adoption of either a defined procurement practice or a
procurement incentive mechanism, neither of which would involve reasonableness
reviews. The volatility of earnings and risk exposure of the Utility related
to post-transition period purchases of electricity is dependent on which of
these options, or some other approach, is adopted.
A decision in the second phase of the proceeding is expected in the first
quarter 2000, addressing certain other post-transition period ratemaking
issues including, among others, incentive mechanisms for commodity purchases
and the allocation of certain transition costs that are recoverable after the
transition period.
Additional information about the financial impact of the end of the rate
freeze and the end of the transition period on the Utility and PG&E
Corporation is provided in "Management's Discussion and Analysis" in the 1999
Annual Report to Shareholders, beginning on page 5.
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
11
mechanism to measure the reasonableness of core procurement costs, and
established gas transmission and storage rates through 2002. Additional
information about the Gas Accord is provided below in "Utility Operations--Gas
Utility Operations" and in "Management's Discussion and Analysis" in the 1999
Annual Report to Shareholders, beginning on page 5.
General Rate Case. On February 17, 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 increases in base revenues for the Utility's gas
distribution function of approximately $93 million over base revenues
authorized in 1996.
The Biennial Cost Allocation Proceeding (BCAP). The BCAP remains the
proceeding in which distribution costs and balancing account balances are
allocated to customers. The BCAP normally occurs every two years and is
updated in the interim year for purposes of amortizing any accumulation in the
balancing accounts. Balancing accounts for natural gas costs accumulate
differences between the actual recovery of gas costs and the revenues designed
for recovery of such costs. Balancing accounts for sales volumes accumulate
differences between authorized and actual base revenues. In June 1998, the
CPUC adopted a decision in the 1998 BCAP granting an annual $97.8 million
revenue requirement decrease effective September 1, 1998, compared to revenues
established by the Gas Accord on March 1, 1998. The overall annual revenue
requirement for the two-year BCAP period (September 1, 1998, through August
31, 2000) is approximately $1.5 billion, of which an annual average of
approximately $102 million is allocated for the collection of balancing
accounts. The Utility plans to file its 2000 BCAP application in the first
half of 2000.
Electric Utility Operations
California Electric Industry Restructuring
As a result of California electric industry restructuring, the electric
generation function of traditional utilities has been opened up to
competition, giving electric customers of investor-owned utilities (such as
Pacific Gas and Electric Company) the choice of continuing to purchase
electricity from investor-owned utilities or purchasing electricity from
alternative providers (including unregulated power generators and unregulated
retail electricity providers such as marketers, brokers, and aggregators).
Purchasing electricity from an alternative generation provider is called
"direct access." For those customers who have not chosen an alternative
generation provider, investor-owned utilities continue to be the generation
provider. Investor-owned utilities continue to provide distribution services
to substantially all customers within their service territories, including
those customers who choose direct access.
The California Independent System Operator and the California Power
Exchange. To create a competitive generation market, the PX and the ISO were
established and began operating on March 31, 1998. The FERC has jurisdiction
over both the ISO and the PX.
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 supply and load schedules from 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 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.
The PX provides a competitive auction process to establish transparent
market clearing prices for electricity in the markets operated by the PX.
During the transition period, the Utility is required to sell into the PX all
of its 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, also are scheduled through the PX. During the
transition period, the Utility must purchase all
12
electric power for its retail customers through the PX. Customers who buy
power directly from non-regulated suppliers pay for that generation based upon
negotiated contracts. The PX sets a market-clearing price for electricity by
matching all demand load bids with supply bids ranked from lowest to highest.
The highest-accepted generation supply bid used to serve load sets the PX
market-clearing price for electricity.
After the transition period, the Utility may continue to schedule its must-
take generation resources into the PX. It is unsettled whether the Utility
will be required to continue purchasing its electric power for its retail
customers through the PX after the transition period. The Utility expects that
the CPUC will address the issue of whether the purchase obligation will
continue through December 31, 2001, if the Utility's rate freeze ends before
that date, in the second phase of the Utility's post-transition period
ratemaking proceeding in the first quarter of 2000. Some parties have argued
that the utilities' purchase obligation may need to continue beyond
December 31, 2001, depending on market conditions. See "Ratemaking
Mechanisms--Electric Ratemaking--Post-Transition Period Ratemaking Proceeding"
above.
The ISO and PX are California public benefit non-profit corporations. Each
has a Governing Board that includes representatives of investor-owned utility
transmission systems, publicly owned utility transmission systems, non-utility
electricity sellers, public buyers and sellers, private buyers and sellers,
industrial end-users, commercial end-users, residential end-users,
agricultural end-users, public interest groups, and non-market participant
representatives. The ISO and PX currently are overseen by a five-member
Electricity Oversight Board (EOB) that appoints the members of the ISO and PX
Governing Boards. However, this appointment power was rejected by the FERC.
Subsequently the California Legislature passed, and the Governor signed,
Senate Bill (SB) 96 which redefined the relationship between the EOB and the
ISO and PX. SB 96 limits the EOB's appointment power to representatives of
those classes that represent California consumers' interests. The ISO or PX
Governing Boards confirm all other appointments. SB 96 has been accepted in
principle by the FERC. Bylaw amendments implementing SB 96 are pending before
the FERC for the PX and the ISO currently is circulating draft bylaw
amendments among its stakeholders.
Voluntary Generation Asset Divestiture. California utilities, including
Pacific Gas and Electric Company, have voluntarily begun divesting some of
their generation assets. In 1998, the Utility sold three of its fossil-fueled
electric generating plants located at Morro Bay, Moss Landing, and Oakland,
California. In 1999, the Utility also sold three fossil-fueled generating
facilities (the Pittsburg and Contra Costa power plants located in Contra
Costa County, and the Potrero power plant in San Francisco) and its geothermal
generating facilities (The Geysers Power Plant located in Lake and Sonoma
Counties). The Utility has retained liability for required environmental
remediation of any pre-closing soil or groundwater contamination at these
plants.
In September 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. The Utility
proposes to use an auction process similar to the one previously used in the
sale of the Utility's fossil fueled and geothermal plants. Under the process
proposed in the application. PG&E Gen would be permitted to participate in the
auction on the same basis as other bidders. The sale of the hydroelectric
facilities would be subject to certain conditions, including the transfer or
re-issuance of various permits and licenses by the FERC and other agencies. On
January 13, 2000, the CPUC issued a ruling which separates the proceeding into
two concurrent phases: one to review the potential environmental impacts of
the proposed auction under the California Environmental Quality Act (CEQA) and
a second to determine whether the Utility's auction proposal, or some other
alternative to the proposal, is in the public interest. The ruling sets a
procedural schedule which calls for a final CPUC decision on the Utility's
auction proposal by October 19, 2000, and a final environmental impact report
published in November 2000. The schedule calls for the auction, if approved,
to begin in early November 2000 and end in early January 2001. The schedule
anticipates that the divestiture process would be closed by June 1, 2001.
Finally, the ruling prohibits the Utility from withdrawing its application
without express CPUC authority. It is uncertain whether the CPUC will
ultimately approve the Utility's auction proposal. Additional information
about the potential financial impact of the proposed auction on the Utility
and PG&E Corporation is provided in "Management's Discussion and Analysis" in
the 1999 Annual Report to Shareholders, beginning on page 5.
13
As required by AB 1890, Utility employees, under two-year operations and
maintenance agreements with the new owners, will continue to operate and
maintain the power plants that have been sold. To the extent that payments to
the Utility under these agreements exceed the Utility's cost of operating the
plants, the additional revenue would be given to ratepayers. Conversely, to
the extent the Utility's operating costs exceed the revenues from these
agreements, the Utility absorbs these losses in earnings.
Recovery of Transition Costs. As market-based revenues may not be
sufficient to recover certain of the Utility's generation costs, AB 1890
provides the investor-owned utilities the opportunity to recover such
uneconomic generation costs (called transition costs) for a certain period of
time (the transition period). 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.) Transition costs are
eligible for recovery from all customers (with certain exceptions) through a
nonbypassable competition transition charge, or CTC, included as part of
rates. Transition costs that are disallowed by the CPUC for collection from
customers will be written off.
As a prerequisite to any consumer obtaining direct access services, the
consumer must agree to pay its applicable nonbypassable CTC. Most transition
costs must be recovered by December 31, 2001, although certain transition
costs may be recovered after December 31, 2001. These costs include (1)
certain employee-related transition costs, (2) above-market payments under
existing long-term contracts to purchase power, (3) up to $95 million of
transition costs to the extent that the recovery of such costs during the
transition period was displaced by the recovery of electric industry
restructuring implementation costs, and (4) transition costs financed by the
issuance of rate reduction bonds. In addition, nuclear decommissioning costs
are being recovered through a CPUC-authorized charge, which will extend until
sufficient funds exist to decommission the nuclear facility.
The total amount of sunk costs to be included as transition costs will be
based on the aggregate of above-market and below-market values of utility-
owned generation assets and obligations. Under AB 1890, valuation of
generation-related assets through appraisal, sale, or other divestiture must
be completed by December 31, 2001. The value of seven of the Utility's power
plants was established when these facilities were sold to third parties. In
October 1998, the CPUC ruled that the market value of the Hunters Point power
plant is zero. In September 1999, the Utility filed an application with the
CPUC to determine the market value of the Utility's hydroelectric generating
facilities and related costs through an open competitive auction.
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. All
customers (with limited exceptions), whether they choose direct access or not,
must pay the nonbypassable CTC, which will be collected by their distribution
utility in connection with recovery of the utilities' transition costs.
Utilities began accepting requests for direct access in November 1997 to
become effective after direct access began. As of February 17, 2000, Pacific
Gas and Electric Company had transferred 94,454 customers to direct access.
The CPUC requires that electric customers with an electricity demand, or load,
of 50 kilowatts (kW) or more must have meters that are capable of providing
hourly data in order to participate in direct access. Those customers with a
load less than 50 kW may participate in direct access either through "load
profiling" or by installing an hourly meter. (Load profiling approximates the
pattern of electricity usage for a given customer class and provides the
equivalent of hourly meter reads.) The customer is responsible for the cost of
the meter and the meter installation.
Energy service providers supplying the direct access market may choose one
of 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
14
distribution bill, or (3) dual billing, under which the energy supplier and
the utility bill separately for their own services. Since January 1, 1999,
energy service providers may provide metering to all of their customers.
During 1999, the Utility continued its efforts to develop and implement
changes to its business processes and systems, including customer information
and billing systems, to accommodate direct access. To the extent the Utility
is unable to successfully and timely develop and implement such changes, there
could be an adverse impact on PG&E Corporation's and the Utility's future
results of operations.
Rate Levels and Rate Reduction Bonds. As required by AB 1890, electric
rates for all customers have been 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 electric rate
freeze and electric rate reduction will continue throughout the transition
period. In 1997, the Utility refinanced the expected 10% rate reduction with
the proceeds from rate reduction bonds. On December 8, 1997, a special purpose
entity established by the California Infrastructure and Economic Development
Bank issued $2.9 billion (the expected revenue reduction from the rate
decrease) of rate reduction bonds on behalf of a wholly owned subsidiary of
the Utility. The bonds were issued in eight classes with maturities ranging
from 10 months to 10 years, and bearing interest at rates ranging from 5.94%
to 6.48%. The Utility is collecting from residential and small commercial
customers a separate nonbypassable charge on behalf of the bondholders to
recover principal, interest, and related costs over the life of the bonds. The
bond proceeds were used by the wholly owned subsidiary to purchase from the
Utility the right to be paid the revenues from this separate charge. The bonds
are secured by the future revenue from the separate charge and not by the
Utility's assets. While the bonds are reflected as long-term debt on the
Utility's balance sheet, the Utility's creditors do not have any recourse to
the revenues from the separate charge. The bonds allow for the rate reduction
by lowering the carrying cost on a portion of the transition costs and by
deferring recovery of a portion of these transition costs until after the
transition period. During the rate freeze, the rate reduction bond debt
service will not increase the Utility customers' electric rates. 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.
Public Purpose Programs. Under AB 1890, 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. Under this
provision of AB 1890, 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. 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. In accordance with AB 1890, 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.
Distributed Generation and Electric Distribution Competition. In October
1999, the CPUC issued a decision outlining how the CPUC, in cooperation with
other regulatory agencies and the California Legislature,
15
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 close proximity to the electric demand (referred to
as "load"). 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. With respect to electric distribution competition, the CPUC
directed its staff to deliver a report by April 21, 2000 on the different
policy options that the CPUC, in cooperation with the California Legislature,
can pursue. Following the issuance of the report, the CPUC expects to open one
or more new proceedings to address electric distribution competition and
competition in the retail electric market.
Electric Operating Statistics
At December 31, 1999, Pacific Gas and Electric Company served approximately
4.6 million electric distribution customers.
During the transition period, the Utility is 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. The following table shows
the Utility's operating statistics (excluding subsidiaries) for electric
energy, including the classification of sales and revenues by type of service.
1999 1998 1997 1996 1995
---------- ---------- ---------- ---------- ----------
Customers (average for
the year):
Residential............ 4,017,428 3,962,318 3,915,370 3,874,223 3,825,413
Commercial............. 474,710 469,136 465,461 459,001 454,718
Industrial............. 1,151 1,093 1,121 1,248 1,253
Agricultural........... 85,131 85,429 86,359 87,250 88,546
Public street and
highway lighting...... 20,806 18,351 17,955 17,583 17,089
Other electric
utilities............. 0 14 47 28 35
---------- ---------- ---------- ---------- ----------
Total................ 4,599,226 4,536,341 4,486,313 4,439,333 4,387,054
========== ========== ========== ========== ==========
Sales-kWh (in millions):
Residential............ 27,739 26,846 25,946 25,458 24,391
Commercial............. 30,426 28,839 28,887 27,868 27,014
Industrial(1).......... 16,722 16,327 16,876 15,786 16,879
Agricultural(1)........ 3,739 3,069 3,932 3,631 3,478
Public street and
highway lighting...... 437 445 446 438 425
Other electric
utilities............. 167 2,358 3,291 1,213 3,172
---------- ---------- ---------- ---------- ----------
Total energy
delivered........... 79,230 77,884 79,378 74,394 75,359
========== ========== ========== ========== ==========
Revenues (in thousands):
Residential............ $2,961,788 $2,891,424 $3,082,013 $3,033,613 $2,979,590
Commercial............. 2,837,111 2,793,336 2,932,560 2,840,101 2,964,568
Industrial............. 863,951 933,316 1,028,378 1,005,694 1,160,938
Agricultural........... 391,876 350,445 413,711 396,469 395,531
Public street and
highway lighting...... 49,209 51,195 53,183 55,372 56,154
Other electric
utilities............. 16,501 50,166 118,781 81,855 133,566
Revenues from energy
deliveries.......... 7,120,436 7,069,882 7,628,626 7,413,104 7,690,347
Miscellaneous.......... 162,105 161,156 (9,439) 112,303 92,538
Regulatory balancing
accounts.............. (50,780) (40,408) 71,441 (365,192) (396,578)
---------- ---------- ---------- ---------- ----------
Operating revenues... $7,231,761 $7,190,630 $7,690,628 $7,160,215 $7,386,307
========== ========== ========== ========== ==========
16
The following table shows certain customer information:
1999 1998 1997 1996 1995
Selected Statistics: ----- ----- ----- ----- -----
Average annual residential usage (kWh)........... 6,905 6,776 6,627 6,571 6,377
Average billed revenues per kWh (cents per kWh):
Residential..................................... 10.68 10.77 11.88 11.92 12.22
Commercial...................................... 9.32 9.69 10.15 10.19 10.97
Industrial(1)................................... 5.17 5.72 6.09 6.37 6.88
Agricultural(1)................................. 10.48 11.42 10.52 10.92 11.37
Net plant investment per customer ($)............ 2,388 2,705 3,027 3,198 3,228
- --------
(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.
Electric Generating Capacity
At the beginning of 1999, the Utility's electric generation facilities
included five primarily natural gas-fueled steam power plants with 15 units,
four combustion turbines, two nuclear power reactor units at Diablo Canyon, 67
hydroelectric powerhouses with 107 units, and the Helms hydroelectric pumped
storage plant (Helms) with three units. In 1998, the Utility sold three of its
fossil-fueled power plants. In April and May 1999, the Utility sold three of
its five remaining fossil-fueled power plants, which include 10 steam units
and three combustion turbines, and its geothermal energy complex of 14 units.
Together, the seven divested power plants represented 91% of the Utility's
fossil-fueled generating capacity and all of its geothermal generating
capacity. The facilities generated approximately 31% of the Utility's total
electric energy production.
The Utility is committed under long-term contracts to purchase power
produced by other generating entities that use a wide array of resources and
technologies, including hydroelectric, wind, solar, biomass, geothermal, and
cogeneration. In addition, the Utility is interconnected with electric power
systems in 14 western states and British Columbia, Canada, for the purposes of
buying, selling, and transmitting power.
During the transition period, the Utility is required to bid or schedule
into the PX and ISO markets all of the electricity generated by its power
plants and electricity acquired under contractual agreements with unregulated
generators.
17
Except as otherwise noted below, as of December 31, 1999, Pacific Gas and
Electric Company owned and operated the following generating plants, all
located in California, listed by energy source:
Number
of Net Operating
Generation Type County Location Units Capacity kW
--------------- --------------- ------ -------------
Hydroelectric:
Conventional Plants(1)....... 16 counties in Northern and
Central California 107 2,684,100
Helms Pumped Storage
Plant(1).................... Fresno 3 1,212,000
--- ---------
Hydroelectric Subtotal..... 110 3,896,100
--- ---------
Steam Plants:
Humboldt Bay................. Humboldt 2 105,000
Hunters Point(2)............. San Francisco 3 377,000
--- ---------
Steam Subtotal............. 5 482,000
--- ---------
Combustion Turbines:
Hunters Point(2)............. San Francisco 1 52,000
Mobile Turbines(3)........... Humboldt and Mendocino 3 45,000
--- ---------
Combustion Turbines
Subtotal.................. 4 97,000
--- ---------
Nuclear:
Diablo Canyon................ San Luis Obispo 2 2,160,000
--- ---------
Total...................... 121 6,635,100
=== =========
- --------
(1) In September 1999, the Utility filed an application with the CPUC to
determine the market value of the Utility's hydroelectric generating
facilities and related assets through an open competitive auction. (See
"Utility Operations--Electric Utility Operations--California Electric
Industry Restructuring" above.)
(2) 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.
(3) Listed to show capability; subject to relocation within the system as
required.
Diablo Canyon
Diablo Canyon Operations
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, 1999, Diablo Canyon Units 1 and 2 had achieved lifetime
capacity factors of 82% and 83%, respectively.
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 thirty 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.
2000 2001 2002 2003 2004
---- ---- ---- ---- ----
Unit 1
Refueling..................... October May February
Startup....................... November June March
Unit 2
Refueling..................... May February October
Startup....................... June March November
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Diablo Canyon Ratemaking
Since January 1, 1997, the Utility's sunk costs in Diablo Canyon are
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. On August 31, 1998, an
independent accounting firm retained by the CPUC completed its financial
verification audit of the December 31, 1996 Diablo Canyon plant accounts. The
audit resulted in the issuance of an unqualified opinion. The audit verified
that Diablo Canyon sunk costs at December 31, 1996, were $3.3 billion of the
total $7.1 billion construction costs. The independent accounting firm also
issued an agreed-upon special procedures report, requested by the CPUC, which
questioned $200 million of the $3.3 billion sunk costs. The CPUC will review
the results of the audit and may seek to make adjustments to Diablo Canyon
sunk costs subject to transition cost recovery. At this time, what action the
CPUC may take regarding the audit, if any, cannot be predicted.
Also since January 1, 1997, a performance-based Incremental Cost Incentive
Price (ICIP) mechanism has been used to recover Diablo Canyon's operating
costs and the cost of capital additions incurred after December 31, 1996. The
ICIP mechanism establishes a rate per kWh generated by the facility for the
period 1997 through 2001. The CPUC-authorized ICIP prices and revenue
requirement for Diablo Canyon for 2000 and 2001 are shown below. The ICIP
revenues are based on an assumed capacity factor of 83.6%.
Estimated Total
Revenue Requirement
-------------------
2000 2001
--------- ---------
ICIP (cents per kWh).................................. 3.43 3.49
Sunk Cost Recovery ($ in millions).................... $ 1,197 $ 1,135
ICIP Revenues ($ in millions)......................... 542 552
--------- ---------
Total Revenue Requirement ($ in millions)............. $ 1,739 $ 1,687
========= =========
Any variance between ICIP revenues and related costs is reflected in
earnings. In October 1999, the CPUC issued a decision that will discontinue
the ICIP mechanism after the transition period. After the transition period,
Diablo Canyon generation must be sold at the prevailing market price for
power. The Utility has filed an application for rehearing of this decision.
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 January 1, 2002. The CPUC may interpret a
more recent CPUC decision to require sharing to begin at the end of the
transition period. The Utility is required to file an application with the
CPUC in July 2000 with its proposal for the methods to be used in the
valuation of the benefits associated with the operation of Diablo Canyon and
the mechanism to be used to share these benefits with ratepayers. (See
"Utility Operations--Ratemaking Mechanisms--Electric Ratemaking--Post-
Transition Period Ratemaking Mechanisms" above.)
Additional information concerning the financial impact of Diablo Canyon
ratemaking is included in "Management's Discussion and Analysis" in the 1999
Annual Report to Shareholders, beginning on page 5, and in Note 2 of the
"Notes to Consolidated Financial Statements" beginning on page 40 of the 1999
Annual Report to Shareholders.
Nuclear Fuel Supply and Disposal
Pacific Gas and Electric Company 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
19
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.
Under the Nuclear Waste Policy Act of 1982 (Nuclear Waste Act), the U.S.
Department of Energy (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
Pacific Gas and Electric Company 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 $15
million (property damage) and $4 million (business interruption), in each case
per one-year policy period, if losses exceed the resources of NEIL.
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
Pacific Gas and Electric Company's estimated total obligation to
decommission and dismantle its nuclear power facilities is $1.6 billion in
1999 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
20
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
trust funds. These funds, along with accumulated earnings, will be used
exclusively for decommissioning and dismantling the nuclear facilities. The
trust funds maintain substantially all of their investments in debt and equity
securities. All earnings on the trust fund, net of authorized disbursements
from the trusts and management and administrative fees, are reinvested. Monies
may not be released from the external trust funds 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 trust funds to finance three partial nuclear decommissioning
projects at Humboldt Bay Power Plant Unit 3. Accordingly, as of December 31,
1999, $9.3 million (net of taxes) has been disbursed from the Humboldt Bay
Power Plant 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 is expected to
be funded with associated tax savings.
In its 1999 GRC, Pacific Gas and Electric Company sought approval from the
CPUC to use the tax savings resulting from the payment of tax-deductible
nuclear decommissioning expenses from the Humboldt Bay Power Plant Unit 3 non-
tax-qualified trust to fund nuclear decommissioning work. The CPUC found that
the Utility's recommended approach of using the tax benefit to fund
decommissioning activity was reasonable and approved the Utility's request.
As of December 31, 1999, the Utility had accumulated external trust funds
with an estimated fair value of $1.3 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, 1999, annual
nuclear decommissioning trust contributions collected in rates were
$26.47 million.
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 when and
if GRCs are discontinued.
Other Electric Resources
QF Generation and Other Power Purchase Contracts
By federal law, Pacific Gas and Electric Company is required 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 established a series of QF long-term power purchase
contracts and set the applicable terms, conditions, price options, and
eligibility requirements. Under these contracts, the Utility is required to
make payments only when energy is supplied (an "energy payment") or when
capacity commitments are met (a "capacity payment"). 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. The
Utility's contracts with these power producers expire on various dates through
2028. Deliveries from these power producers account for approximately 23% of
the Utility's 1999 electric energy requirements and no single contract
accounted for more than 5% of the Utility's energy needs.
21
The Utility has negotiated with several QFs for early termination of their
power purchase contracts. For other contracts, the Utility has negotiated with
QFs to refrain from producing energy during the remaining term of the higher
fixed energy price period under their contract (a "buy-down") or to curtail
energy production for shorter periods of time (a "curtailment"). At December
31, 1999, the total discounted future payments due under the renegotiated
contracts that are subject to early termination, buy-down or curtailment, was
$16 million. Of the $16 million, the Utility has recovered $6.6 million in
rates and expects to recover the remaining $9.4 million in future rates.
As of December 31, 1999, the Utility had commitments to purchase
approximately 5,200 MW of capacity under CPUC-mandated power purchase
agreements. Of the 5,200 MW, approximately 4,500 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 4,500 MW
of operational capacity consists of 2,800 MW from co-generation 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, 1999, the undiscounted future minimum payments under
these contracts are approximately $32.7 million for each of the years 2000
through 2004 and a total of $280 million for periods thereafter. Irrigation
district and water agency deliveries in the aggregate account for
approximately 5.8% of the Utility's 1999 electric energy requirements.
The amount of energy received and the total payments made under all these
power purchase contracts were:
1999 1998 1997
------ ------ ------
(in millions)
Kilowatt-hours received.............................. 25,910 25,994 24,389
Energy payments...................................... $ 837 $ 943 $1,157
Capacity payments.................................... $ 539 $ 529 $ 538
Irrigation district and water agency payments........ $ 60 $ 53 $ 56
Electric Transmission and Distribution
To transport energy to load centers, Pacific Gas and Electric Company as of
December 31, 1999, owned approximately 18,624 circuit miles of interconnected
transmission lines of 60 kilovolts (kV) to 500 kV and transmission substations
having a capacity of approximately 42,106,600 kilovolt-amperes (kVa),
including spares, excluding power plant interconnection facilities. Energy is
distributed to customers through approximately 113,289 circuit miles of
distribution system and distribution substations having a capacity of
approximately 23,773,000 kVa.
In 1998, the utilities relinquished control, but not ownership, of their
transmission facilities to the ISO. 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. In 1998, the FERC approved the various forms of
agreements for must-run facilities that have been entered into between the
utilities and the ISO to ensure grid reliability.
The FERC also has approved a proposal from Pacific Gas and Electric Company
and the other California utilities that distinguishes between local
distribution facilities and transmission facilities. The FERC will have
jurisdiction over the transmission facilities as defined in the order and over
the transmission aspects of direct access. Most of the Utility's distribution
services remain subject to CPUC jurisdiction.
22
The CPUC is considering whether it should pursue further reforms in the
structure and regulatory framework governing electricity distribution service.
See "Utility Operations--Electric Utility Operations--California Electric
Industry Restructuring" above.
During 1999, the Utility and various other parties, including the ISO and
the CPUC, issued reports on their investigation into the power outage that
occurred on December 8, 1998, in the San Francisco Bay area. In March 1999,
the ISO issued its report on the outage that concluded that the Utility's
system was designed in accordance with industry standards and responded as
expected under the circumstances. The ISO's report identified a number of
measures for the Utility to undertake to minimize the likelihood of a similar
event occurring in the future. Reports by other parties, including the CPUC,
have also recommended corrective measures. Since the outage, the Utility has
revised its grounding and switching procedures as preventive measures to
minimize the risk that the type of initiating event that caused the outage
could occur in the future. On October 20, 1999, the Utility submitted a report
to the CPUC describing how its corrective actions implements the ISO's
recommendations, and responds to the other parties' recommendations. The CPUC
is currently holding workshops to address the issues in the proceeding. After
the conclusion of the workshops, the CPUC plans to convene another prehearing
conference to discuss how to address any remaining issues.
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, 1999. Most of
these customers continue to obtain gas supplies from the Utility under
regulated tariff rates.
At December 31, 1999, the Utility's system, including the PG&E Expansion
(Line 401), consisted of approximately 6,225 miles of transmission pipelines,
three gas storage facilities, and approximately 37,487 miles of gas
distribution lines. The PG&E Expansion is the Utility's portion of an
expansion of the interconnected natural gas transmission systems of the
Utility and PG&E Gas Transmission, Northwest Corporation (PG&E GT-Northwest)
which extends from the Canadian border into California (Pipeline Expansion).
Including the portion owned by PG&E GT-Northwest (PG&E GT-NW Expansion), the
840-mile combined Pipeline Expansion provides an additional 148 million cubic
feet per day (MMcf/d) of firm capacity to the Pacific Northwest and an
additional 851 MMcf/d of capacity to Northern and Southern California. The Gas
Accord resolved various issues concerning the PG&E Expansion and also
established certain rules for ratemaking and terms of service applicable to
the PG&E Expansion.
The Utility's peak day send-out of gas on its integrated system in
California during the year ended December 31, 1999, was 3,503 million cubic
feet (MMcf). The total volume of gas throughput during 1999 was approximately
840,000 MMcf, of which 309,000 MMcf was sold to direct end-use or resale
customers, 47,000 MMcf was used by the Utility primarily for its fossil-fueled
electric generating plants, and 484,000 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 as a result of
a CPUC order. 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 1998 California Gas Report updates the Utility's annual gas
requirements forecast (excluding bypass volumes) for the years 1999 through
2015, forecasting average annual growth in gas throughput served by the
Utility of approximately 1.5%. 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.
23
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,
----------------------------------------------------------
1999 1998 1997 1996 1995
---------- ---------- ---------- ---------- ----------
Customers (average for
the year):
Residential............ 3,593,355 3,536,089 3,491,963 3,455,086 3,417,556
Commercial............. 203,342 200,620 198,453 198,071 197,939
Industrial............. 1,625 1,610 1,650 1,500 1,500
Other gas utilities.... 4 5 3 2 2
---------- ---------- ---------- ---------- ----------
Total.............. 3,798,326 3,738,324 3,692,069 3,654,659 3,616,997
========== ========== ========== ========== ==========
Gas supply--thousand
cubic feet (Mcf) (in
thousands):
Purchased from
suppliers in:
Canada............... 230,808 298,125 280,084 253,209 261,800
California........... 18,956 17,724 10,655 28,130 31,158
Other states......... 107,226 122,342 131,074 110,604 117,538
---------- ---------- ---------- ---------- ----------
Total purchased.... 356,990 438,191 421,813 391,943 410,496
Net (to storage) from
storage............... (980) (14,468) 14,160 6,871 (10,921)
---------- ---------- ---------- ---------- ----------
Total.............. 356,010 423,723 435,973 398,814 399,575
Pacific Gas and
Electric Company use,
losses, etc.(1)....... 47,152 129,305 173,789 134,375 129,671
---------- ---------- ---------- ---------- ----------
Net gas for sales.. 308,858 294,418 262,184 264,439 269,904
========== ========== ========== ========== ==========
Bundled gas sales and
transportation
service--Mcf (in
thousands):
Residential............ 233,482 223,706 191,327 190,246 191,724
Commercial............. 70,093 66,082 60,803 62,178 64,135
Industrial............. 5,255 4,616 10,054 12,015 14,045
Other gas utilities.... 28 14 0 0 0
---------- ---------- ---------- ---------- ----------
Total.............. 308,858 294,418 262,184 264,439 269,904
========== ========== ========== ========== ==========
Transportation service
only--Mcf (in
thousands):
Vintage system
(Substantially all
Industrial)(2)........ 447,867 319,099 218,660 189,695 143,921
PG&E Expansion (Line
401).................. 36,351 77,773 233,269 237,776 240,506
---------- ---------- ---------- ---------- ----------
Total.............. 484,218 396,872 451,929 427,471 384,427
========== ========== ========== ========== ==========
Revenues (in thousands):
Bundled gas sales and
transportation
service:
Residential.......... $1,542,705 $1,414,313 $1,170,135 $1,109,463 $1,205,223
Commercial........... 448,655 426,299 374,084 362,819 421,397
Industrial........... 24,638 24,634 46,592 42,520 42,106
Other gas utilities.. 77 1,072 3,701 510 0
---------- ---------- ---------- ---------- ----------
Bundled gas
revenues.......... 2,016,075 1,866,318 1,594,512 1,515,312 1,668,726
Transportation only
revenue:
Vintage system
(Substantially all
Industrial)......... 267,544 232,038 207,160 180,197 167,325
PG&E Expansion (Line
401)................ 19,091 42,194 90,180 85,144 82,904
---------- ---------- ---------- ---------- ----------
Transportation service
only revenue.......... 286,635 274,232 297,340 265,341 250,229
Miscellaneous.......... (47,311) 41,364 50,295 (9,271) (18,018)
Regulatory balancing
accounts.............. (259,648) (448,351) (137,787) 57,864 (43,771)
---------- ---------- ---------- ---------- ----------
Operating
revenues.......... $1,995,751 $1,733,563 $1,804,360 $1,829,246 $1,856,499
========== ========== ========== ========== ==========
- --------
(1) Primarily 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 1,251 MMcf, 34,169 MMcf, 72,958 MMcf, 78,552 MMcf, and
100,207 MMcf for 1999, 1998, 1997, 1996, and 1995, respectively.
24
Years Ended December 31,
----------------------------------
1999 1998 1997 1996 1995
------ ------ ------ ------ ------
Selected Statistics:
Average annual residential usage (Mcf)...................... 65 63 55 55 56
Heating temperature--% of normal (1)........................ 108.5 93.0 71.7 75.7 75.3
Average billed bundled gas sales revenues per Mcf:
Residential................................................ $ 6.61 $ 6.32 $ 6.12 $ 5.83 $ 6.29
Commercial................................................. 6.40 6.45 6.15 5.84 6.57
Industrial................................................. 4.69 5.36 4.63 3.54 3.00
Average billed transportation only revenue per Mcf:
Vintage system............................................. 0.66 0.66 0.71 0.67 0.69
PG&E Expansion (Line 401).................................. 0.53 0.54 0.39 0.36 0.34
Net plant investment per customer (2)...................... $1,011 $1,040 $1,031 $1,061 $1,025
- --------
(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 supplies to serve the Utility's customers, the Utility purchases
gas directly from producers and marketers in both Canada and the United States.
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,
1999, approximately 65% of the Utility's total purchases of natural gas
consisted of Canadian-sourced gas transported by Canadian pipeline companies
and PG&E GT-Northwest and Rocky Mountain-sourced gas transported by PG&E GT-
Northwest, approximately 5% was purchased in California, approximately 22% 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 8% 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.
1999 1998 1997 1996 1995
------------------ ------------------ ------------------ ------------------ ------------------
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................. 230,808 $2.50 298,125 $2.00 280,084 $1.77 253,209 $1.57 261,800 $1.34
California............. 18,956 2.45 17,724 2.44 10,655 2.12 28,130 1.90 31,158 1.32
Other states
(substantially all
U.S. Southwest)....... 107,227 2.42 122,342 2.62 131,074 3.75 110,604 3.72 117,538 2.64
------- ----- ------- ----- ------- ----- ------- ----- ------- -----
Total/Weighted
Average............... 356,991 $2.47 438,191 $2.19 421,813 $2.39 391,943 $2.21 410,496 $1.71
======= ===== ======= ===== ======= ===== ======= ===== ======= =====
- --------
(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 Pacific
Gas and Electric Company'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
25
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 established an incentive mechanism (the core procurement incentive
mechanism or CPIM) for recovery of the Utility's core gas procurement costs as
described below.
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)."
The CPUC is considering further changes in California's natural gas
industry. Additional information concerning gas industry restructuring, and
the financial impact of these changes on PG&E Corporation, is provided in
"Management's Discussion and Analysis" in the 1999 Annual Report to
Shareholders, beginning on page 5.
Transportation Commitments
Pacific Gas and Electric Company 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 $97 million in 1999. This amount includes payments made to
PG&E GT-Northwest of approximately $47 million in 1999, 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 those noncore
customers who choose bundled service (core subscription 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 GT-Northwest that runs
through October 31, 2005, the Utility currently retains capacity of
approximately 600 MMcf/d on the PG&E GT-Northwest system to support its core
and core-subscription customers. The Utility has been able to broker its
unused capacity on PG&E GT-Northwest's system, when not needed for core and
core-subscription customers.
In 1992, the Utility entered into a firm transportation agreement with
Transwestern Pipeline Company (Transwestern), which expires in 2007, to hold
capacity to meet core gas sales demands and electric generation needs. Since
the Utility has sold most of its fossil-fueled generating plants in connection
with electric industry restructuring and no longer needs natural gas for
electric generation, the Utility permanently released 50 MMcf/d of firm
capacity under this contract. As a result, the demand charges associated with
the entire Transwestern capacity currently approximate $22 million per year.
The Utility may recover demand charges through the CPIM and through brokering
activities.
26
Core Procurement Incentive Mechanism
The Utility's core gas procurement costs through 2002 are recoverable in
rates under the CPIM, which 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.
Under the Gas Accord and CPIM mechanism, all Utility procurement costs from
June 1, 1994 to October 31, 1998, were approved by the CPUC as reasonable. For
the period from December 1, 1997 to October 31, 1998, the CPUC, with ORA
support, has recognized savings outside of the tolerance band, and for that
period has awarded approximately $2 million of the savings to shareholders. In
January 2000, the Utility filed a CPIM performance report for the period of
November 1, 1998, through October 31, 1999. The report determined that all gas
commodity and transportation costs for the period were within the tolerance
band, and therefore should be deemed reasonable and recoverable in full from
ratepayers.
27
NATIONAL ENERGY GROUP
PG&E Corporation's National Energy Group has been formed to pursue
opportunities created by the gradual deregulation of the energy industry
across the nation. The National Energy Group integrates PG&E Corporation's
national power generation, gas transmission, and energy trading and services
businesses. The National Energy Group contemplates increasing PG&E
Corporation's national market presence through a balanced program of
acquisition and development of energy assets and businesses, while at the same
time undertaking ongoing portfolio management of its assets and businesses.
PG&E Corporation'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.
Gas Transmission Operations
PG&E Corporation participates in the "midstream" portion of the gas
business through PG&E GT. PG&E GT consists of three principal entities: PG&E
Gas Transmission, Texas Corporation, PG&E Gas Transmission Teco, Inc., and
PG&E GT-Northwest. PG&E Gas Transmission, Texas Corporation and PG&E Gas
Transmission Teco, Inc. are referred to collectively as PG&E Gas Transmission,
Texas (PG&E GTT). The "midstream" gas business includes (1) gas gathering,
processing, storage, and transportation of natural gas and natural gas liquids
(NGLs), and (2) the marketing of natural gas and NGLs. PG&E GT's gas
transmission facilities are operated through offices in various cities,
including Houston and San Antonio, Texas and Portland, Oregon.
PG&E GT competes with, among others, major interstate and intrastate
pipeline companies in the transportation of natural gas and NGLs. The
principal elements of competition among pipeline companies are rates, terms of
service, flexibility, and reliability of service. Natural gas competes with
other forms of energy available to PG&E GT's customers and end-users,
including electricity, coal, and fuel oils. A significant competitive factor
is price. Changes in the availability or price of natural gas and other forms
of energy, the level of business activity, conservation, legislation, and
governmental regulations, the capability to convert to alternative fuels, and
other factors, including weather, affect the demand for natural gas.
PG&E GT also competes with, among others, major integrated energy
companies, the marketing affiliates of the major interstate and intrastate
pipelines, national and local gas gatherers, brokers, marketers, and
distributors for natural gas supplies, in gathering and processing natural gas
and in marketing natural gas and NGLs. Competition for natural gas supplies is
based on a number of factors, including flexibility in contract terms and
conditions, reliability, availability of transportation, and price for the
natural gas and NGLs. Competition for sales customers is based upon, among
other factors, flexibility of contract terms and conditions, reliability and
price of delivered natural gas and NGLs.
PG&E Gas Transmission, Texas
PG&E GTT owns and operates gas gathering, transportation, and processing
facilities, and NGL pipelines. The NGL business includes the gathering of
natural gas, the extraction of NGLs from natural gas, the fractionation of
mixed NGLs into component products (e.g., ethane, propane, butane, and natural
gasoline), and the transportation and marketing of NGLs. The Texas operations
include approximately 6,700 miles of natural gas pipelines and joint ownership
or leasehold interests in approximately 1,300 miles of pipelines, including
pipelines from Waha in west Texas to the Katy area near Houston, Texas. These
pipeline systems have the capacity to transport more than 3 billion cubic feet
(bcf) of gas per day. The Texas assets also include approximately 536 miles of
NGL pipelines and nine natural gas processing plants with a combined capacity
of approximately 1.6 bcf per day of gas throughput, capable of producing
approximately 100,000 barrels per day of NGLs, and a long-term lease of 7.2
bcf of storage capacity. PG&E GTT participates in all areas of the midstream
portion of the gas business. PG&E GTT markets gas to gas distribution
companies, electric utilities, municipalities, marketers, independent power
producers, and end-use customers. It also transports natural gas for these
customers, producers, and other pipelines, and markets and transports NGLs to
various customers, including end-use customers.
28
On January 27, 2000, PG&E Corporation's National Energy Group signed a
definitive agreement with El Paso Field Services Company providing for the
sale to El Paso Field Services Company, a subsidiary of El Paso Energy
Corporation, of the stock of PG&E Gas Transmission, Texas Corporation and PG&E
Gas Transmission Teco, Inc. (collectively PG&E GTT). Closing of the sale,
which is expected near the end of the first half of 2000, is subject to
approval under the Hart Scott Rodino Act.
Additional information concerning the sale of PG&E GTT is provided in
"Management's Discussion and Analysis" in the 1999 Annual Report to
Shareholders, beginning on page 5, and in Note 5 of the "Notes to Consolidated
Financial Statements" beginning on page 47 of the 1999 Annual Report to
Shareholders.
PG&E GT-Northwest
PG&E GT-Northwest owns and operates gas transmission pipelines and
associated facilities which extend over 612 miles from the Canada-U.S. border
to the Oregon-California border. PG&E GT-Northwest participates in the
midstream portion of the gas business by providing firm and interruptible
transportation services to third party shippers on an open access,
nondiscriminatory basis. Its customers are principally retail gas distribution
utilities, electric utilities that use natural gas to generate electricity,
natural gas marketing companies, natural gas producers, and industrial
companies. PG&E GT-Northwest's largest customer in 1999 was Pacific Gas and
Electric Company, accounting for approximately $49 million, or 23.5% of its
transportation revenues.
PG&E GT-Northwest's mainline system is composed of two parallel pipelines
with 12 compressor stations totaling approximately 408,660 International
Standards Organization (ISO) installed horsepower and ancillary facilities,
including metering, regulating facilities, and a communications system. The
dual pipeline system consists of approximately 639 miles of 36-inch diameter
gas transmission line (612 miles of single 36-inch diameter pipe and 27 miles
of 36-inch diameter pipeline looping) and approximately 590 miles of 42-inch
diameter pipe. In addition, in 1995, PG&E GT-Northwest constructed two lateral
pipeline extensions, adding approximately 84 miles of 12-inch diameter pipe,
and 22 miles of 16-inch diameter pipe to serve its customers on those
laterals.
PG&E GT-Northwest's total transportation quantities for 1995 through 1999
are set forth in the following table.
Quantities
(in thousand
decatherms
Year (MDt))
---- ------------
1995.......................................................... 885,186
1996.......................................................... 934,029
1997.......................................................... 969,257
1998.......................................................... 1,003,266
1999.......................................................... 839,778
PG&E GT-Northwest's current rates were set in a rate settlement approved by
the FERC in September 1996. In 1998, petitions filed by various parties for
rehearing of the FERC order approving the settlement were denied. Three
parties have appealed the FERC's denial of these rehearing petitions to the
U.S. Court of Appeals for the District of Columbia Circuit. On February 1,
2000, the appellate court denied the petitions for review and reaffirmed the
FERC settlement.
Additional information concerning PG&E Corporation's gas transmission
operations is provided in "Management's Discussion and Analysis" in the 1999
Annual Report to Shareholders, beginning on page 5, and in Note 17 of the "Notes
to Consolidated Financial Statements" beginning on page 63 of the 1999 Annual
Report to Shareholders.
29
Independent Power Generation
Through PG&E Gen and its affiliates, PG&E Corporation participates in the
development, construction, operation, ownership, and management of non-utility
electric generating facilities that compete in the United States power
generation market. PG&E Gen is headquartered in Bethesda, Maryland.
As of December 31, 1999, PG&E Gen affiliates had ownership interests in 30
operating plants in 10 states. The total generating capacity of these 30
plants is approximately 6,560 MW. Ten of these plants operate as QFs with a
combined capacity of 2,128 MW which is sold at fixed prices under long-term
power purchase agreements. The remaining plants with a combined capacity of
4,435 MW are operated as merchant power plants that sell their power directly
to wholesale customers (including other PG&E Corporation affiliates) at
prevailing market prices. PG&E Corporation's combined net equity ownership and
leased interest in these plants as of December 31, 1999, represented
approximately 5,200 MW. The plants were financed largely with a combination of
non-recourse debt and equity or equity commitments from the project sponsors.
PG&E Gen, through its affiliate, PG&E Operating Services Company (PG&E OSC),
provides contract operations and maintenance services to many of these
facilities. PG&E Gen also manages power purchase agreements with an aggregate
of 789 MW of capacity. PG&E Gen and its affiliated or managed facilities sold
29,187,905 megawatt-hours (MWh) of electricity in 1999. PG&E Gen also is
engaged in the "greenfield" development of new merchant power plants, as
discussed below.
PG&E Gen competes with unaffiliated utilities and other independent power
producers.
New England Operations
In 1998, PG&E Corporation, through its indirect subsidiary, USGenNE,
purchased from the New England Electric System (NEES) a portfolio of electric
generating assets with a combined generating capacity of about 4,000 MW. In
addition, USGenNE assumed NEES' obligations to purchase power from various
independent power producers (IPPs). As of December 31, 1999 these power
purchase obligations represented an additional 470 MW of production capacity.
NEES is required to make annual support payments to USGenNE through early 2008
to offset the cost of power associated with these above-market contracts.
Finally, in connection with the NEES acquisition, USGenNE obtained the right
to purchase NEES's nuclear generated electric energy, capacity, and associated
products at market prices up to the entire amount available. In December 1999,
USGenNE sold these nuclear entitlements.
Three of the four states in which USGenNE operates generation facilities
(Massachusetts, Rhode Island, and New Hampshire) were, like California, among
the first states in the country to introduce retail competition. As part of
electric industry restructuring in these New England states, local utility
companies were required to offer standard offer service (SOS) to their retail
customers. Retail customers may select alternate suppliers at any time. The
SOS is intended to provide customers with a price benefit (the commodity
electric price offered to the retail customer under SOS is expected to be less
than the market price for the first several years), followed by a price
disincentive that is intended to stimulate the retail market. Connecticut also
has passed retail competition legislation.
The New England assets are located within the New England Power Pool
(NEPOOL). The wholesale electricity market in New England features a bid-
based, real-time pricing structure. Traditionally, NEPOOL has operated as a
"tight power pool," one in which the utilities within the pool dedicate their
generation resources to be centrally dispatched. Dispatch starts with the
lowest-cost generation and ends with the highest-cost generation. An
independent system operator for the New England states (ISO-NE) provides
central dispatch service and operates the power pool as a competitive
wholesale marketplace. The duties of the ISO-NE include scheduling the
operations of the regional transmission systems and, importantly, operating a
power exchange for seven generation products (the "Interchange"). These
products are energy, installed (monthly) capacity and operable (hourly)
capacity, three types of reserves, and automatic generation control
(adjustment of generators to meet the second-to-second changes in electric
load).
30
Additional information concerning the New England electricity market and
the Corporation's New England operations is provided in "Management's
Discussion and Analysis" in the 1999 Annual Report to Shareholders, beginning
on page 5.
Portfolio of Operating Generating Plants
The following table sets forth information regarding the operating
generating plants in which PG&E Gen affiliates have an ownership or leasehold
interest. Except as otherwise noted, PG&E Gen affiliates also manage or
operate, or both manage and operate, power plant operations.
Date Placed in
Commercial
Plant MWs Fuel Location Service
----- --- ---- -------- --------------
Bear Swamp Facility(1),(2)
Pumped Storage 2 Units.......... 588 Hydro Massachusetts 1974
Fife Brook...................... 10 Hydro 1974
Brayton Point Station(2)
Unit Nos. 1, 2, and 3........... 1,130 Coal Massachusetts 1963, '64, '69
Unit No. 4...................... 446 Oil/Gas 1974
Diesel Generators.................. 10 Diesel Oil N/A
Carneys Point...................... 260 Coal New Jersey 1994
Cedar Bay.......................... 250 Coal Florida 1994
Connecticut River(2)
Hydroelectric 26 Units.......... 484 Hydro New Hampshire/Vermont 1909-1957
Deerfield River(2)
Hydroelectric 15 Units.......... 84 Hydro Massachusetts/Vermont 1912-1927
Hermiston.......................... 474 Natural Gas Oregon 1996
Indiantown......................... 330 Coal Florida 1995
Logan.............................. 225 Coal New Jersey 1995
Manchester St. Station(2)
3 Combined Cycle Units.......... 495 Natural Gas Rhode Island 1995
MASSPOWER.......................... 240 Natural Gas Massachusetts 1993
Northampton........................ 110 Waste Coal Pennsylvania 1995
Pittsfield(1)...................... 165 Natural Gas Massachusetts 1990
Salem Harbor Station(2)
Unit Nos. 1, 2, and 3........... 314 Coal Massachusetts 1952, '52, '58
Unit No. 4...................... 400 Oil 1972
Scrubgrass......................... 83 Waste Coal Pennsylvania 1993
Selkirk............................ 345 Natural Gas New York 1992, '94
-----
Total MWs/Operating Plants.. 6,443
PG&E Gen Affiliate Investments:
Colstrip(3)........................ 37 Waste Coal Montana 1990
Panther Creek(3)................... 83 Waste Coal Pennsylvania 1992
-----
Total MWs from Investments.. 120
-----
Total MWs in Operation(4)... 6,563
=====
- --------
(1) Unlike other operating facilities in which PG&E Gen affiliates have
ownership and management interests, the Bear Swamp Facility and the
Pittsfield plant are owned by third parties through a single-investor
lease arrangement. PG&E Gen maintains full management and operating
responsibility for the facilities and is entitled to the output.
(2) Acquired from NEES on September 1, 1998.
(3) PG&E Gen affiliates have an ownership or leasehold interest in these
plants, but do not manage power plant operations.
(4) Of the total of 6,563 megawatts in operation, PG&E Gen's net equity
ownership and leased percentage interest in the total is 5,225 megawatts.
31
Generation Development Projects
Nationwide, PG&E Gen's greenfield power plant development activities exceed
10,000 MW in 9 states. The table below lists PG&E Gen's development projects.
The Millennium Project in Charlton, Massachusetts (360 MW) and the Lake Road
Project in Killingly, Connecticut (792 MW) are under construction. The La
Paloma Project in McKittrick, California (1,048 MW) has been approved by PG&E
Corporation's Board of Directors and the California Energy Commission. The
other development projects listed below are in the early stages of the
development process. The completion of these planned projects is subject to
many factors, including but not limited to various regulatory and
environmental approvals, adequate financing on satisfactory terms, competitive
conditions including the expansion and retirement plans of others, market
prices for electricity, and future fuel prices.
Estimated
start of
commercial
Plant MW Fuel Location service
----- -- ---- -------- ----------
Millennium.................... 360 Natural gas Massachusetts 4Q 2000
Lake Road..................... 792 Natural gas Connecticut 2Q 2001
La Paloma..................... 1,048 Natural gas California 1Q 2002
Madison....................... 12 Wind New York 3Q 2000
Brayton V..................... 800 Natural gas Massachusetts 4Q 2002
Athens........................ 1,080 Natural gas New York 1Q 2002
Covert........................ 1,022 Natural gas Michigan 3Q 2002
Badger........................ 1,022 Natural gas Wisconsin 3Q 2002
Liberty....................... 1,048 Natural gas New Jersey 3Q 2002
Mantua Creek.................. 800 Natural gas New Jersey 1Q 2002
Otay Mesa..................... 510 Natural gas California 3Q 2002
Harquahala.................... 1,000 Natural gas Arizona 3Q 2003
Okeechobee.................... 550 Natural gas Florida 2Q 2004
Energy Trading
PG&E Energy Trading-Gas Corporation and PG&E Energy Trading-Power, L.P.
(also collectively referred to as PG&E ET), headquartered in Houston, Texas,
purchase electric power from PG&E Corporation affiliates and the wholesale
market and natural gas from producers, marketers, and other parties. PG&E ET
then schedules, transports, and resells these commodities, either to third
parties or to other PG&E Corporation affiliates (except the Utility). PG&E ET
also provides risk management services to PG&E Corporation's other businesses
(except the Utiltiy) and to unaffiliated wholesale customers. For more
information, see "General--Risk Management Programs" above.
PG&E ET competes with, among others, major integrated energy companies,
marketing affiliates of major interstate pipelines, brokers, gas marketers,
and gas distributors for natural gas supplies and/or in marketing natural gas.
In addition, PG&E ET competes with unaffiliated electric utilities, marketers,
and other entities in purchasing and selling electric power and other energy
commodities. Competition in the energy marketing business is driven by various
factors, including the price of commodities and services delivered along with
quality and reliability of services delivered.
Additional information concerning the wholesale operations of PG&E
Corporation's affiliates is provided in "Management's Discussion and Analysis"
in the 1999 Annual Report to Shareholders, beginning on page 5, and in Note 17
of the "Notes to Consolidated Financial Statements" beginning on page 63 of
the 1999 Annual Report to Shareholders.
32
Energy Services
PG&E Energy Services (PG&E ES), headquartered in San Francisco, California,
provides retail gas and electric commodities nationwide, where permitted under
applicable laws, and provides energy-related value-added services, including
billing and information management services, energy efficiency and other
energy management services, regulatory and rate analysis, and power quality
solutions. PG&E ES targets primarily industrial, commercial, and institutional
customers, offering comprehensive energy management solutions to reduce their
energy costs and improve their productivity. PG&E ES has 20 offices nationwide
to support its sales activities. PG&E ES currently competes with other non-
utility electric retailers in California for direct access customers. See
"Utility Operations--Electric Utility Operations--California Electric Industry
Restructuring" above.
In December 1999, PG&E Corporation's Board of Directors approved a plan to
dispose of PG&E ES, its wholly owned subsidiary, through a sale. The intended
disposal has been accounted for as a discontinued operation in PG&E
Corporation's 1999 financial statements. While there is no definitive sales
agreement, it is expected that the disposition will be completed by June 2000.
Additional information concerning PG&E ES is provided in "Management's
Discussion and Analysis" in the 1999 Annual Report to Shareholders, beginning
on page 5, and in Notes 5 and 17 of the "Notes to Consolidated Financial
Statements" beginning on pages 47 and 63, respectively, of the 1999 Annual
Report to Shareholders.
33
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, PG&E Gen and its affiliates (including
USGenNE), and other PG&E Corporation subsidiaries and affiliates 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 $51 million
over three years. Substantially all of these costs will be capital costs.
34
PG&E Gen's compliance 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 (SO\\2\\) 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. (SO\\2\\
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.) It
is estimated that USGenNE's total cost of complying with these requirements
will be up to $4 million through the year 2001.
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 either comply in all material respects with or are exempt from
the thermal standards. A thermal effects study at Diablo Canyon was completed
in May 1988, and was reviewed by the Central Coast Regional Water Quality
Control Board (Central Coast Board). The Central Coast Board did not make a
final decision on the report and requested that the Utility continue its
thermal effects monitoring program. In 1995, the Central Coast Board requested
that the Utility prepare an updated comprehensive assessment of Diablo
Canyon's thermal effects and approved a reduced environmental monitoring
program. A comprehensive statistical analysis of Diablo Canyon's thermal
effects was submitted to the Central Coast Board in December 1997 and a
regulatory assessment was submitted in November 1998. If the Central Coast
Board finds that Diablo Canyon's existing thermal limits are not protective of
beneficial uses of the marine waters, major modifications (e.g., cooling
towers) resulting in additional construction expenditures, or reduced power
operation, could be required.
Pursuant to 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. Each plant's
existing water intake structure was found to meet the BTA requirements. The
Utility currently is completing a new study for Diablo Canyon. The study is
scheduled to be submitted to the Central Coast Board for review in 2000. If
the Central Coast Board finds that Diablo Canyon's cooling water intake
structure does not meet the BTA requirements, additional expenses for
construction or mitigation could be required. In addition, 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 remaining power plants in the
future. Costs to comply with renewed permit conditions required to meet any
more stringent requirements that might be imposed cannot be estimated at the
present time.
In December 1999, the Utility was notified by the purchaser of its former
Moss Landing power plant that that it had identified a cleaning procedure used
at the plant that released heated water 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 Board. The
purchaser notified the Central Coast Board of its findings and the Central
Coast Board requested additional information from the purchaser. The Utility
has initiated an investigation of these activities during the time it owned
the plant. The Central Coast Board has been notified of the investigation and
the results will be presented to the Central Coast Board when the
investigation is complete. If the identified procedure was performed during
the Utility's ownership and was beyond the scope of the relevant NPDES
permits, the Central Coast Board may choose to initiate an enforcement action.
If so, the Utility could be subject to significant penalties. Until the
investigation is complete and the results discussed with the Central Coast
Board, it is not possible to determine whether the Utility will suffer a loss
in connection with this matter or to provide a more detailed estimate of such
liability.
35
PG&E Gen'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 in compliance with NPDES permits that
have expired. As to the facilities for which the NPDES permit has expired, new
permit 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. USGenNE has submitted a permit
renewal application and is negotiating with EPA on ongoing studies and permit
conditions. It is estimated that USGenNE's cost to comply with these
conditions could be as much as $5 million through the year 2001.
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 many hazardous waste
storage, handling, and disposal requirements promulgated by the EPA under the
Resource Conservation and Recovery Act (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 2000. 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. The Utility
has been designated as a potentially responsible party (PRP) under CERCLA (the
federal Superfund law) with respect to the PRC Patterson site in Patterson,
California, and the Industrial Waste Processing site near Fresno, California.
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. Although
the Utility has not been formally designated a 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
36
uncertainty concerning the Utility's responsibility, the complexity of
environmental laws and regulations, and the selection of compliance
alternatives. At December 31, 1999, the Utility expects to spend $300 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 $271 million at December 31,
1999, representing the discounted value of these costs. Environmental
remediation at identified sites may be as much as $486 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.
PG&E Gen acquired the onsite environmental liability associated with
USGenNE's acquisition of electric generating facilities from NEES, but did not
acquire any offsite liability associated with the past disposal practices at
the acquired facilities. PG&E Gen has obtained pollution liability and
environmental remediation insurance coverage to limit the financial risk
associated with the onsite pollution liability at all of its facilities.
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 are 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,
1999, 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.
Of the $271 million accrued liability, discussed above, the Utility has
recovered $148 million through rates, including $34 million through
depreciation, and expects to recover $95 million in future rates.
Additionally, the Utility is mitigating its costs by seeking recovery 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
37
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 $71 million through
December 31, 1999), 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.
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
38
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.
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 other PG&E
Corporation subsidiaries is included in the discussion under the heading of
this report entitled "National Energy Group."
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.
Compressor Station Chromium Litigation
Pacific Gas and Electric Company is currently a defendant in three 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, and (3) Acosta, et al. v. Betz
Laboratories, Inc., Pacific Gas and Electric Company, et al., filed November
27, 1996, in Los Angeles County Superior Court. These cases are collectively
referred to as the "Aguayo Litigation." There are approximately 900 plaintiffs
in the Aguayo Litigation.
Each of the complaints in the Aguayo Litigation alleges personal injuries
and seeks 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 at Kettleman, Hinkley, and Topock,
California. The plaintiffs in the Aguayo Litigation include current and former
Utility employees, relatives of current and former employees, 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.
All discovery and discovery motion practice in the Aguayo Litigation have
been referred by the judge to a discovery referee. The discovery referee has
set the procedures for selecting 18 trial test plaintiffs and two alternates
in the Aguayo Litigation. Ten of these trial test plaintiffs were selected by
plaintiffs, seven trial test plaintiffs were selected by defendants, and one
trial test plaintiff and two alternates were selected at random. The trial
date has been set for November 17, 2000 in Los Angeles Superior Court.
The Utility is responding to the complaints and asserting affirmative
defenses. The Utility will pursue appropriate legal defenses, including
statute of limitations or exclusivity of workers' compensation laws, and
factual defenses including lack of exposure to chromium and the inability of
chromium to cause certain of the illnesses alleged. At this stage of the
proceedings, there is substantial uncertainty concerning the claims alleged.
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.
PG&E Corporation believes that the ultimate outcome of this matter will not
have a material adverse impact on its or Pacific Gas and Electric Company's
financial position or results of operations.
39
Texas Franchise Fee Litigation
On July 31, 1997, PG&E Corporation acquired Valero Energy Corporation
(Valero), now known as PG&E Gas Transmission, Texas Corporation. PG&E Gas
Transmission, Texas Corporation and its affiliates (PG&E GTT) succeeded to the
cases described below, which were pending at the time of the acquisition
against Valero and its affiliates. A lawsuit was also pending at such time
that had been filed by the City of Pharr, but no PG&E GTT entity has been
served in this case. These cases are collectively referred to as the "Texas
Franchise Fees Litigation." These actions were brought by various cities in
Texas arising out of several Texas statutes and city ordinances involving the
following: (a) what rights, if any, Texas cities may have to require companies
engaged in the gathering, production, distribution, transmission, and/or sale
of natural gas to obtain consent from, and pay fees to, the cities within
which such activities are being conducted, (b) what form any such consent, if
required, must take, (c) what constitutes "use" of city property, and (d) what
types of charges, if any, a Texas city properly can assess against gas
pipeline and marketing companies for use of that city's property.
There were seven cases pending against Valero entities at the time of the
acquisition: (1) City of Edinburg v. Rio Grande Valley Gas Co. (RGVG), Valero
Energy Corporation (now known as PG&E GTT), Valero Transmission Company (now
known as PG&E Texas Pipeline Company), Valero Natural Gas Company (now known
as PG&E Texas Natural Gas Company), Reata Industrial Gas Company a/k/a Valero
Gas Marketing Company (now known as PG&E Energy Trading Holdings Corporation),
Valero Transmission, L.P. (now known as PG&E Texas Pipeline, L.P.), and Reata
Industrial Gas, L.P. (now known as PG&E Reata Energy, L.P.), Southern Union
Company and its unincorporated division, Southern Union Gas Co. (Southern
Union), and Mercado Gas Services, Inc., filed August 31, 1995, in the 92nd
State District Court, Hidalgo County, Texas, (2) Cities of San Benito,
Primera, and Port Isabel v. RGVG, Valero Energy Corporation (now known as PG&E
GTT), Southern Union, et al., filed December 31, 1996, in the 107th State
District Court, Cameron County, Texas, (3) City of Mercedes v. Reata
Industrial Gas, L.P. (now known as PG&E Reata Energy, L.P.), and Valero Gas
Marketing Company (now known as PG&E Energy Trading Holdings Corporation),
filed April 16, 1997, in the 92nd State District Court in Hidalgo County,
Texas, (4) Cities of Alton and Donna v. RGVG, Valero Energy Corporation (now
known as PG&E Gas Transmission, Texas Corporation), Valero Transmission
Company (now known as PG&E Texas Pipeline Company), Valero Natural Gas Company
(now known as PG&E Texas Natural Gas Company), Reata Industrial Gas Company
(now known as PG&E Energy Trading Holdings Corporation), Valero Transmission,
L.P. (now known as PG&E Texas Pipeline, L.P.), and Reata Industrial Gas, L.P.
(now known as PG&E Reata Energy, L.P.), Southern Union Gas Co., and Mercado
Gas Services, Inc., filed July 18, 1996, in the 92nd State District Court,
Hidalgo County, Texas, (5) City of La Joya v. RGVG, Valero Energy Corporation
(now known as PG&E GTT), Southern Union Company, et al., filed December 27,
1996, in the 92nd State District Court, Hidalgo County, Texas, (6) Cities of
San Juan, La Villa, Penitas, Edcouch, and Palmview v. RGVG, Valero Energy
Corporation (now known as PG&E Gas Transmission, Texas Corporation), Southern
Union Company, et al., filed December 27, 1996, in the 93rd State District
Court, Hidalgo County, Texas, and (7) City of Weslaco v. Valero Natural Gas
Company (now known as PG&E Texas Natural Gas Company), Valero Gas Marketing
Co. (now known as PG&E Energy Trading Holdings Corporation), and Reata
Industrial Gas, L.P. (now known as PG&E Reata Energy L.P.) filed April 17,
1997, in the 92nd State District Court, Hidalgo County, Texas. The lawsuits
involving the City of La Joya (item number 5 above) and the Cities of San
Juan, La Villa, Penitas, Edcouch, and Palmview (item number 6 above) were
voluntarily dismissed on July 13, 1999, and February 23, 2000, respectively.
However, all of these cities are class members in the San Benito class action
(item number 5 above) as are the Cities of Alton and Donna.
The trial in the City of Edinburg case began on June 15, 1998. On August
14, 1998, a jury returned a verdict in favor of the City of Edinburg, and
awarded damages in the approximate aggregate amount of $9.8 million, plus
attorneys' fees of approximately $3.5 million, against PG&E GTT, Southern
Union and various affiliates of PG&E GTT and Southern Union. The jury refused
to award punitive damages against the PG&E GTT defendants. On December 1,
1998, based on the jury verdict, the court entered a judgment in the City's
favor, and awarded damages of $5.3 million, attorneys' fees of up to $3.5
million (to the extent that the City is successful on appeal), prejudgment
interest of $1.6 million, and post-judgment interest at the rate of 10% per
year, compounded annually, from December 1, 1998. The court found that various
PG&E GTT and Southern
40
Union defendants were jointly and severally liable for $3.3 million of the
damages, prejudgment interest in the amount of $1.1 million, and all the
attorneys' fees. Certain PG&E GTT subsidiaries were found solely liable for
$1.4 million of the damages and prejudgment interest of $440,000. The court
did not clearly indicate the extent to which the PG&E GTT defendants could be
found liable for the remaining damages. The judgment also decreed that (1)
certain pipelines owned by PG&E Texas Pipeline, L.P. (formerly known as Valero
Transmission, L.P.) encroached on the City's property without the City's
consent and (2) based on certain jury findings, PG&E GTT was vicariously
liable for certain conduct of the local distribution company, RGVG, from
October 1, 1985, to September 30, 1993 (the date Valero, PG&E GTT's
predecessor, sold RGVG to Southern Union). The PG&E GTT defendants are
appealing the judgment.
On November 4, 1997, the lawsuit filed in Cameron County, Texas, by the
cities of San Benito, Primera, and Port Isabel was amended to name as
defendants PG&E GTT and all of its subsidiaries (excluding its Canadian gas
trading and power trading subsidiaries), PG&E Gas Transmission Teco, Inc. and
its subsidiaries, and PG&E Energy Trading Corporation (now known as PG&E
Energy Trading--Gas Corporation) (collectively these defendants are referred
to as the "PG&E Corporation Texas defendants"). In November 1997, the court
ordered a state-wide class certified and granted plaintiffs' request to
dismiss RGVG and the Southern Union defendants. In connection with the
certification of a class in this case, the court ordered notice to be sent to
all potential class members and setting an opt-out deadline of December 31,
1997. Notices were mailed to approximately 159 Texas cities. Fewer than 20
cities opted out by the deadline. Some of the cities opting out include
Austin, Brownsville, Houston, and San Antonio. The city of Los Indios has been
severed from the class and its claims separately docketed in Cameron County,
Texas. On November 22, 1999, the court signed an order dismissing from the
class 42 cities because it determined there was no pipeline presence and no
past or present sales activity in such cities, leaving 106 cities in the
class. The parties are negotiating the terms of a final settlement agreement.
The settlement proposal contemplates, among other things, that the PG&E
Corporation Texas defendants would pay a total of not more than $12.2 million
to the settling class cities, inclusive of attorney fees and expenses, which
amount may be reduced by amounts attributable to certain opt-out cities. The
defendants retain the right to reject the settlement if the settlement
proposal is not approved by certain key cities and by 80% of the overall
plaintiff class. Although a significant number of the 106 cities in the
plaintiff class already have either approved the settlement by enacting the
consent ordinance or have adopted resolutions to pass the ordinance, certain
key cities have not yet approved the settlement. The settlement is also
subject to final court approval. On January 27, 2000, the court approved the
settlement proposal and established a 14-day period for the cities to decide
whether to accept the negotiated settlement terms or opt out of the
settlement. The court also stated that if the City of Corpus Christi does not
accept the settlement proposal, it will be placed in a single city sub-class
and its claims will not be finalized as part of the settlement approval.
Corpus Christi has the right to opt out of this subclass. Although the 14-day
period expired on February 11, 2000, certain cities have requested and
received additional time to decide whether to opt out.
In July 1996, the lawsuits originally filed by the cities of Alton and
Donna as intervening actions in the City of Edinburg case were severed from
the Edinburg lawsuit. The claims asserted by the cities of Alton and Donna are
substantially similar to the San Benito litigation claims, except that no
class claims are asserted. Damages are not quantified. Defendants' motion to
transfer venue of both cases to Bexar County, Texas, is currently pending. The
Cities of Alton and Donna are also members of the San Benito class, and will
be required to dismiss their claims against PG&E GTT in this separate lawsuit
if they agree to accept the settlement of the San Benito class action.
On September 4, 1997, the City of Mercedes amended its petition to include
class action claims and requested to be named as class representative for a
statewide class consisting of all Texas municipal corporations,
municipalities, towns, and villages, excluding the cities of Edinburg and
Weslaco (both of which have filed separate actions), in which any of the
defendants have sold or supplied gas, or used public rights-of-way to
transport gas. The City of Mercedes has requested a damage award, but has not
specified an amount. On November 26, 1997, defendants' motion to recuse the
presiding judge was granted. Plaintiffs' request for class certification is
still pending.
41
The causes of action alleged in the case brought by the City of Weslaco are
identical to those alleged in the City of Mercedes case, except that no class
claims are asserted. Damages are not quantified. A motion similar to the
motion filed in Mercedes, seeking to recuse the judge of the 92nd State
District Court, was filed but not ruled upon. On May 12, 1999, this case was
transferred to the 370th State District Court of Hidalgo County, Texas.
Defendants' motion to transfer venue to Bexar County, Texas, is currently
pending.
In addition to the cases described above, during May 1996, a petition in
intervention was filed in the Edinburg case by the City of Pharr. On June 24,
1996, the court severed Pharr from the Edinburg case, certified the severed
case as a class action against Southern Union Company and RGVG, and named
Pharr as class representative for a class consisting of those Texas cities,
excluding Edinburg and McAllen, that have or had natural gas franchise
agreements with RGVG or Southern Union. The Pharr class was certified as to
two claims: breach of contract and declaratory relief dealing with the rights,
status, and legal relationship between plaintiff, the class members, and the
local distribution company regarding payment of franchise fees and use of
granted easements. Plaintiffs' original petition also sought injunctive
relief, but the class order does not include injunctive relief. Plaintiffs
seek actual damages, exemplary damages, attorneys' fees, costs, and pre- and
post-judgment interest, but have not specified any amounts. On January 26,
1998, the court added the Cities of Mercedes and Weslaco as class
representatives. None of the PG&E Corporation Texas entities have ever been
served in the Pharr litigation. On December 30, 1997, in affirming the Pharr
class certification, the appellate court specifically found that the PG&E GTT
entities were not parties to the Pharr class action. However, the same 29 PG&E
Corporation Texas entities that are class defendants in the San Benito
litigation have subsequently been named and served as defendants in two
ancillary suits brought during 1998 by the Pharr class plaintiffs. These
ancillary suits seek only injunctive relief, for the stated purpose of
"protecting" the Pharr class from alleged interference by the San Benito
class.
PG&E Corporation believes that the ultimate outcome of this matter will not
have a material adverse impact on its financial position or results of
operations. As discussed above under "Item 1--National Energy Group-- Gas
Transmission Operations," in January 2000, PG&E Corporation's National Energy
Group signed a definitive agreement to sell the stock of PG&E Gas
Transmission, Texas Corporation and PG&E Gas Transmission Teco, Inc., the
National Energy Group subsidiaries which conduct gas transmission operations
in Texas. The buyer will assume all liabilities associated with the cases
described above.
ITEM 4. Submission of Matters to a Vote of Security Holders.
Not applicable.
42
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 1999 Position
---- ------------ --------
R. D. Glynn, Jr. ....... 57 Chairman of the Board, Chief Executive
Officer, and President
T. G. Boren............. 50 Executive Vice President; President
and Chief Executive Officer, PG&E
National Energy Group, Inc.
P. A. Darbee............ 47 Senior Vice President, Chief Financial
Officer, and Treasurer
S. W. Gebhardt.......... 48 Senior Vice President; President and
Chief Executive Officer, PG&E Energy
Services Corporation
T. W. High.............. 52 Senior Vice President, Administration
and External Relations
P. C. Iribe............. 49 Senior Vice President; President and
Chief Operating Officer, PG&E
Generating Company
T. B. King.............. 38 Senior Vice President; President and
Chief Operating Officer, PG&E Gas
Transmission Corporation
L. E. Maddox............ 44 Senior Vice President; President and
Chief Executive Officer, PG&E Energy
Trading Corporation
G. R. Smith............. 51 Senior Vice President; President and
Chief Executive Officer, Pacific Gas
and Electric Company
G. B. Stanley........... 53 Senior Vice President, Human Resources
B. R. Worthington....... 50 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 January 1, 1998, to present
Executive Officer, and
President
Chairman of the Board of January 1, 1998, to present
Directors, Pacific Gas and
Electric Company
President and Chief Executive June 1, 1997, to present
Officer
President and Chief Operating December 18, 1996, to May 31, 1997
Officer
President and Chief Operating June 1, 1995, to May 31, 1997
Officer, Pacific Gas and
Electric Company
Executive Vice President, July 1, 1994, to May 31, 1995
Pacific Gas and Electric
Company
T. G. Boren............. Executive Vice President August 1, 1999, to present
President and Chief Executive August 1, 1999, to present
Officer, PG&E National Energy
Group, Inc.
President and Chief Executive February 18, 1992, to July 31, 1999
Officer, Southern Energy,
Inc.
Executive Vice President, June 1, 1999, to July 31, 1999
Southern Company
Senior Vice President, February 16, 1998, to May 31, 1999
Southern Company
Vice President, Southern July 17, 1995, to February 15, 1998
Company
P. A. Darbee............ Senior Vice President, Chief September 20, 1999, to present
Financial Officer, and
Treasurer
Vice President and Chief June 30, 1997, to September 19, 1999
Financial Officer, Advance
Fibre Communications, Inc.
Vice President, Chief January 10, 1994, to June 30, 1997
Financial Officer, and
Controller, Pacific Bell
S. W. Gebhardt.......... Senior Vice President April 1, 1997, to present
President and Chief Executive April 1, 1997, to present
Officer, PG&E Energy Services
Corporation
Executive Vice President, April 1, 1996, to March 28, 1997
PennUnion Energy Services
Vice President, Enron Capital January 1, 1993, to December 31, 1995
& Trade Resources
43
Name Position Period Held Office
---- -------- ------------------
T. W. High.............. Senior Vice President, June 1, 1997, to present
Administration and External
Relations
Senior Vice President, June 1, 1995, to May 31, 1997
Corporate Services, Pacific
Gas and Electric Company
Vice President and Assistant July 1, 1994, to May 31, 1995
to the Chief Executive
Officer, Pacific Gas and
Electric Company
P. C. Iribe............. Senior Vice President January 1, 1999, to present
President and Chief November 1, 1998, to present
Operating Officer, PG&E
Generating Company
(formerly known as U.S.
Generating Company)
Executive Vice President and September 1, 1997, to October 31, 1998
Chief Operating Officer,
U.S. Generating Company
Executive Vice President, May 17, 1994, to September 1, 1997
Marketing, Development, and
Asset Management, U.S.
Generating Company
T. B. King.............. Senior Vice President January 1, 1999, to present
President and Chief November 23, 1998, to present
Operating Officer, PG&E Gas
Transmission Corporation
President and Chief February 14, 1997, to November 22, 1998
Operating Officer, Kinder
Morgan Energy Partners,
L.P.
Vice President, Commercial July 1, 1995, to February 14, 1997
Operations--Midwest Region,
Enron Liquid Services
Corporation
Vice President, Gathering July 1994, to July 1, 1995
Services, Northern Natural
Gas Company and
Transwestern Pipeline
Company
L. E. Maddox............ Senior Vice President June 1, 1997, to present
President and Chief May 12, 1997, to present
Executive Officer, PG&E
Energy Trading Corporation
President, PennUnion Energys May 1995 to May 1997
Services, L.L.C.
President, Brooklyn January 1993 to May 1995
Interstate Natural Gas
Corp.
G. R. Smith............. Senior Vice President January 1, 1999, to present
(Please refer to
description of business
experience for executive
officers of Pacific Gas and
Electric Company below.)
G. B. Stanley........... Senior Vice President, Human January 1, 1998, to present
Resources
Vice President, Human June 1, 1997, to December 31, 1997
Resources
Vice President, Human July 1, 1996, to May 31, 1997
Resources, Pacific Gas and
Electric Company
Self-employed (human January 1995, to June 1996
resources consultant)
B. R. Worthington....... Senior Vice President and June 1, 1997, to present
General Counsel
General Counsel December 18, 1996, to May 31, 1997
Senior Vice President and June 1, 1995, to June 30, 1997
General Counsel, Pacific
Gas and Electric Company
Vice President and General December 21, 1994, to May 31, 1995
Counsel, Pacific Gas and
Electric Company
44
"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:
Age at
December 31,
Name 1999 Position
---- ------------ --------
G. R. Smith............. 51 President and Chief Executive Officer
K. M. Harvey............ 41 Senior Vice President, Chief Financial
Officer, Controller, and Treasurer
R. J. Peters............ 45 Senior Vice President and General
Counsel
J. K. Randolph.......... 55 Senior Vice President and General
Manager, Transmission, Distribution
and Customer Service Business Unit
D. D. Richard, Jr....... 49 Senior Vice President, Governmental
and Regulatory Relations
G. M. Rueger............ 49 Senior Vice President and General
Manager, Nuclear Power Generation
Business Unit
All officers of Pacific Gas and Electric Company serve at the pleasure of
the Board of Directors. During the past five years, the executive officers of
Pacific Gas and Electric Company had the following business experience. Except
as otherwise noted, all positions have been held at Pacific Gas and Electric
Company.
Name Position Period Held Office
---- -------- ------------------
G. R. Smith............. President and Chief June 1, 1997, to present
Executive Officer
Chief Financial Officer, December 18, 1996, to May 31, 1997
PG&E Corporation
Senior Vice President and June 1, 1995, to May 31, 1997
Chief Financial Officer
Vice President and Chief November 1, 1991, to May 31, 1995
Financial Officer
K. M. Harvey............ Senior Vice President, Chief January 1, 2000, to present
Financial Officer,
Controller, and Treasurer
Senior Vice President, Chief July 1, 1997, to December 31, 1999
Financial Officer, and
Treasurer
Vice President and Treasurer June 1, 1995, to June 30, 1997
Treasurer August 1, 1993, to May 31, 1995
R. J. Peters............ Senior Vice President and January 1, 1999, to present
General Counsel
Vice President and General July 1, 1997, to December 31, 1998
Counsel
Chief Counsel, Regulatory January 1, 1993, to June 30, 1997
J. K. Randolph.......... Senior Vice President and July 1, 1997, to present
General Manager,
Transmission, Distribution
and Customer Service
Business Unit
Vice President and General January 1, 1997, to June 30, 1997
Manager, Power Generation,
Business Unit
Vice President, Power November 1, 1991, to December 31, 1996
Generation
D. D. Richard, Jr....... Senior Vice President, July 1, 1997, to present
Governmental and Regulatory
Relations
Vice President, Governmental July 1, 1997, to present
Relations, PG&E Corporation
Vice President, Governmental January 1, 1997, to June 30, 1997
Relations
Executive Vice President and January 1993, to December 1996
Principal, Morse, Richard,
Weisenmiller & Assoc., Inc.
(energy, project finance,
and environmental
consulting)
G. M. Rueger............ Senior Vice President and November 1, 1991, to present
General Manager, Nuclear
Power Generation Business
Unit
45
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 67 under the heading
"Quarterly Consolidated Financial Data (Unaudited)" in the 1999 Annual Report
to Shareholders, which information is hereby incorporated by reference and
filed as part of Exhibit 13 to this report. As of February 22, 2000, there
were 149,708 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 1999 Annual Report to Shareholders.
Neither Pacific Gas and Electric Company nor PG&E Corporation made any
sales of unregistered equity securities during 1999, the period covered by
this report.
ITEM 6. Selected Financial Data.
A summary of selected financial information for each of PG&E Corporation
and Pacific Gas and Electric Company for each of the last five fiscal years is
set forth on page 4 under the heading "Selected Financial Data" in the 1999
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, 1999, was 3.25. Pacific Gas and Electric Company's
ratio of earnings to combined fixed charges and preferred stock dividends for
the year ended December 31, 1999, was 3.08. The statement of the foregoing
ratios, together with the statements of the computation of the foregoing
ratios filed as Exhibits 12.1 and 12.2 hereto, are included herein for the
purpose of incorporating such information and exhibits into Registration
Statement Nos. 33-62488, 33-64136, 33-50707, and 33-61959 relating to Pacific
Gas and Electric Company's various classes of debt and first preferred stock
outstanding.
ITEM 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations.
A discussion of PG&E Corporation's and Pacific Gas and Electric Company's
consolidated results of operations and financial condition is set forth on
pages 5 through 25 under the heading "Management's Discussion and Analysis"
in the 1999 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 1999 Annual Report to
Shareholders on page 23 under the heading "Management's Discussion and
Analysis--Debt Obligations and Rate Reduction Bonds," on pages 24 and 25 under
the heading "Management's Discussion and Analysis--Price Risk Management
Activities," and on pages 37, 38, 45, and 47 under Notes 1, 3, and 4 of the
"Notes to Consolidated Financial Statements" of the 1999 Annual Report to
Shareholders, which information is hereby incorporated by reference and filed
as part of Exhibit 13 to this report.
ITEM 8. Financial Statements and Supplementary Data.
Information responding to Item 8 appears on pages 26 through 69 of the 1999
Annual Report to Shareholders under the following headings for PG&E
Corporation: "Statement of Consolidated Income," "Consolidated Balance Sheet,"
"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 Income," "Consolidated Balance Sheet,"
"Statement of Consolidated Cash Flows," and
46
"Statement of Consolidated Stockholders' Equity;" and under the following
headings for PG&E Corporation and Pacific Gas and Electric Company jointly:
"Notes to Consolidated Financial Statements," "Quarterly Consolidated Financial
Data (Unaudited)," "Report of Independent Public Accountants," and
"Responsibility for 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.
Information responding to Item 9 has been previously reported by PG&E
Corporation and Pacific Gas and Electric Company in a current report on Form
8-K dated February 17, 1999, and filed on February 23, 1999, as amended by a
Current Report on Form 8-K/A filed on June 11, 1999.
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 43 through 45 in Part I of this
report. Other information responding to Item 10 is included on pages 3 through
6 under the heading "Item No. 1: Election of Directors of PG&E Corporation and
Pacific Gas and Electric Company" and page 38 under the heading "Section 16(a)
Beneficial Ownership Reporting Compliance" in the 2000 Joint Proxy Statement
relating to the 2000 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 9 and 10 under the heading
"Compensation of Directors" and on pages 30 through 35 under the headings
"Summary Compensation Table," "Option/SAR Grants in 1999," "Aggregated
Option/SAR Exercises in 1999 and Year-End Option/SAR Values," "Long-Term
Incentive Plan--Awards in 1999," "Retirement Benefits," and "Termination of
Employment and Change In Control Provisions" in the 2000 Joint Proxy Statement
relating to the 2000 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 11 and 12 under the heading
"Security Ownership of Management" and on page 38 under the heading "Principal
Shareholders" in the 2000 Joint Proxy Statement relating to the 2000 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 10 under the heading "Certain
Relationships and Related Transactions" in the 2000 Joint Proxy Statement
relating to the 2000 Annual Meetings of Shareholders, which information is
hereby incorporated by reference.
47
PART IV
ITEM 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K.
(a) The following documents are filed as a part of this report:
1. The following consolidated financial statements, supplemental
information, and report of independent public accountants contained
in the 1999 Annual Report to Shareholders, which have been
incorporated by reference in this report:
Statements of Consolidated Income for the Years Ended December
31, 1999, 1998, and 1997, for each of PG&E Corporation and
Pacific Gas and Electric Company.
Statements of Consolidated Cash Flows for the Years Ended
December 31, 1999, 1998, and 1997, for each of PG&E Corporation
and Pacific Gas and Electric Company.
Consolidated Balance Sheets at December 31, 1999, and 1998 for
each of PG&E Corporation and Pacific Gas and Electric Company.
Statement of Consolidated Common Stock Equity for the Years
Ended December 31, 1999, 1998, and 1997, for PG&E Corporation.
Statement of Consolidated Stockholders' Equity for the Years
Ended December 31, 1999, 1998, and 1997, 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 53 of this Form 10-K.
3. Report of Independent Public Accountants (Arthur Andersen LLP)
included at page 54 of this Form 10-K.
4. Report of Independent Public Accountants (Arthur Andersen LLP)
included at page 55 of this Form 10-K.
5. Financial statement schedules:
I--Condensed Financial Information of Parent for the Years Ended
December 31, 1999 and 1998.
II--Consolidated Valuation and Qualifying Accounts for each of
PG&E Corporation and Pacific Gas and Electric Company for the
Years Ended December 31, 1999, 1998 and 1997.
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 December 19, 1996 (PG&E Corporation's Form 8-B (File No. 1-
12609), Exhibit 3.1).
3.2 By-Laws of PG&E Corporation amended as of February 16, 2000.
3.3 Restated Articles of Incorporation of Pacific Gas and Electric
Company effective as of May 6, 1998 (Pacific Gas and Electric
Company's Form 10-Q for the quarter ended March 31, 1998 (File No.
1-2348), Exhibit 3.1).
3.4 By-Laws of Pacific Gas and Electric Company amended as of February
16, 2000.
4. First and Refunding Mortgage of Pacific Gas and Electric Company
dated December 1, 1920, and supplements thereto dated April 23,
1925, October 1, 1931, March 1, 1941, September 1, 1947, May 15,
1950, May 1, 1954, May 21, 1958, November 1, 1964, July 1, 1965,
July 1, 1969, January 1, 1975, June 1, 1979, August 1, 1983, and
48
December 1, 1988 (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).
10. The Gas Accord Settlement Agreement, together with accompanying
tables, adopted by the California Public Utilities Commission on
August 1, 1997, in Decision 97-08-055. (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).
10.1 Stock Purchase Agreement By and Between PG&E National Energy
Group, Inc. and El Paso Field Services Company, dated as of
January 27, 2000.
*10.2 PG&E Corporation Supplemental Retirement Savings Plan dated as of
January 1, 2000.
*10.3 Description of Compensation Arrangement between PG&E Corporation
and Thomas G. Boren. (PG&E Corporation's Form 10-Q for the
quarter ended September 30, 1999 (File No. 1-12609), Exhibit
10.2).
*10.4 Description of Compensation Arrangement between PG&E Corporation
and Peter Darbee. (PG&E Corporation's Form 10-Q for the quarter
ended September 30, 1999 (File No. 1-12609), Exhibit 10.3).
*10.5 PG&E Corporation Deferred Compensation Plan for Non-Employee
Directors, as amended and restated effective as of July 22, 1998.
(PG&E Corporation's Form 10-Q for the quarter ended September 30,
1998 (File No. 1-12609), Exhibit 10.2).
*10.6 Description of Short-Term Incentive Plan for Officers of PG&E
Corporation and its subsidiaries, effective January 1, 1999.
(PG&E Corporation's Form 10-K for the year ended December 31,
1998 (File No. 1-12609), Exhibit 10.6).
*10.7 Description of Short-Term Incentive Plan for Officers of PG&E
Corporation and its subsidiaries, effective January 1, 2000.
*10.8 Supplemental Executive Retirement Plan of the Pacific Gas and
Electric Company, effective January 1, 1998 (PG&E Corporation's
Form 10-K for the year ended December 31, 1998 (File No. 1-
12609), Exhibit 10.7).
*10.9 Pacific Gas and Electric Company Relocation Assistance Program
for Officers (Pacific Gas and Electric Company's Form 10-K for
fiscal year 1989 (File No. 1-2348), Exhibit 10.16).
*10.10 Postretirement Life Insurance Plan of the Pacific Gas and
Electric Company (Pacific Gas and Electric Company's Form 10-K
for fiscal year 1991 (File No. 1-2348), Exhibit 10.16).
*10.11 PG&E Corporation Retirement Plan for Non-Employee Directors, as
amended and terminated January 1, 1998. (PG&E Corporation Form
10-K for the year ended December 31, 1997, (File No. 1-12609),
Exhibit No. 10.13).
*10.12 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.
49
*10.13 PG&E Corporation Executive Stock Ownership Program, amended as of
February 16, 2000.
*10.14 PG&E Corporation Officer Severance Policy, amended as of July 21,
1999. (PG&E Corporation's Form 10-Q for the quarter ended
September 30, 1999 (File No. 1-12609), Exhibit 10.1).
*10.15 PG&E Corporation Director Grantor Trust Agreement dated April 1,
1998 (PG&E Corporation's Form 10-Q for the quarter ended March
31, 1998 (File No. 1-12609), Exhibit 10.1).
*10.16 PG&E Corporation Officer Grantor Trust Agreement dated April 1,
1998 (PG&E Corporation's Form 10-Q for the quarter ended March
31, 1998 (File No. 1-12609), Exhibit 10.2).
11. Computation of Earnings Per Common Share.
12.1 Computation of Ratios of Earnings to Fixed Charges for Pacific
Gas and Electric Company.
12.2 Computation of Ratios of Earnings to Combined Fixed Charges and
Preferred Stock Dividends for Pacific Gas and Electric Company.
13. 1999 Annual Report to Shareholders of PG&E Corporation and
Pacific Gas and Electric Company--portions of the 1999 Annual
Report to Shareholders under the headings "Selected Financial
Data," "Management's Discussion and Analysis," "Independent
Auditors' Report," "Responsibility for Consolidated Financial
Statements," financial statements of PG&E Corporation entitled
"Statement of Consolidated Income," "Consolidated Balance Sheet,"
"Statement of Consolidated Cash Flows," "Statement of
Consolidated Common Stock Equity," financial statements of
Pacific Gas and Electric Company entitled "Statement of
Consolidated Income," "Consolidated Balance Sheet," "Statement of
Consolidated Cash Flows," "Statement of Consolidated
Stockholders' Equity," "Notes to Consolidated Financial
Statements" and "Quarterly Consolidated Financial Data
(Unaudited)" are included only. (Except for those portions that
are expressly incorporated herein by reference, such 1999 Annual
Report to Shareholders is furnished for the information of the
Commission and is not deemed to be "filed" herein.)
18. Letter re change in Accounting Principles.
21. Subsidiaries of the Registrant.
23.1 Consent of Deloitte & Touche LLP.
23.2 Consent of Arthur Andersen LLP.
24.1 Resolutions of the Boards of Directors of PG&E Corporation and
Pacific Gas and Electric Company authorizing the execution of the
Form 10-K.
24.2 Powers of Attorney.
27.1 Financial Data Schedule for the year ended December 31, 1999, for
PG&E Corporation.
27.2 Financial Data Schedule for the year ended December 31, 1999, for
Pacific Gas and Electric Company.
- --------
* 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.
50
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, 1999, and
through the date hereof:
1. October 1, 1999
Item 5. Other Events--Reporting the filing of an application relating to
the proposed auction of Pacific Gas and Electric Company's hydroelectric
generation assets
2. October 20, 1999
Item 5. Other Events--Proposed decision in Pacific Gas and Electric
Company's General Rate Case
3. October 21, 1999--Filed by PG&E Corporation only
Item 5. Other Events--
A. Share Repurchase
B. Proposed amendments to Articles of Incorporation and Bylaw
Amendments
4. November 5, 1999
Item 5. Other Events--
A. Pacific Gas and Electric Company's Post-transition Period
Ratemaking Proceeding
B. Pacific Gas and Electric Company's 2000 Cost of Capital
Proceeding
5. December 1, 1999
Item 5. Other Events--Performance Goals and Implementation Strategy
6. January 21, 2000
Item 5. Other Events--
A. Pacific Gas and Electric Company's General Rate Case Proceeding
B. Proposed Auction of Pacific Gas and Electric Company's
Hydroelectric Generating Assets
C. 1998 Annual Transition Cost Proceeding
7. January 31, 2000
Item 5. Other Events--Sale of Texas Gas Transmission Companies
8. February 23, 2000
Item 5. Other Events--
A. Pacific Gas and Electric Company's General Rate Case Proceeding
B. 1998 Annual Transition Cost Proceeding
C. Disposition of PG&E Energy Services Corporation
- --------
(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)
51
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrants have duly caused this report to be signed
on their behalf by the undersigned, thereunto duly authorized, in the City and
County of San Francisco, on the 6th day of March, 2000.
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)
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrants and in the capacities and on the dates indicated.
Signature Title Date
--------- ----- ----
A. Principal Executive Officers
*ROBERT D. GLYNN, JR. Chairman of the Board, Chief March 6, 2000
Executive Officer, and President
(PG&E Corporation)
*GORDON R. SMITH President and Chief Executive March 6, 2000
Officer
(Pacific Gas and Electric Company)
B. Principal Financial Officers
*PETER A. DARBEE Senior Vice President, Chief March 6, 2000
Financial Officer, and Treasurer
(PG&E Corporation)
*KENT M. HARVEY Senior Vice President, Chief March 6, 2000
Financial Officer, Controller, and
Treasurer
(Pacific Gas and Electric Company)
C. Principal Accounting Officers
*CHRISTOPHER P. JOHNS Vice President and Controller March 6, 2000
(PG&E Corporation)
*KENT M. HARVEY Senior Vice President, Chief March 6, 2000
Financial Officer, Controller, and
Treasurer
(Pacific Gas and Electric Company)
D. Directors
*RICHARD A. CLARKE
*HARRY M. CONGER
*DAVID A. COULTER
*C. LEE COX
*WILLIAM S. DAVILA
*ROBERT D. GLYNN, JR. Directors of PG&E Corporation and
*DAVID M. LAWRENCE, M.D. Pacific Gas and Electric Company, March 6, 2000
*MARY S. METZ except as noted
*CARL E. REICHARDT
*JOHN C. SAWHILL
*GORDON R. SMITH
(Director of Pacific Gas and
Electric Company, only)
*BARRY LAWSON WILLIAMS
*By /s/ Gary P. Encinas
----------------------------
(Gary P. Encinas, Attorney-in-Fact)
52
INDEPENDENT AUDITORS' REPORT
To the Shareholders and the Boards 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 as of and for the year ended December
31, 1999 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 March 3, 2000. Our audits were made for
the purpose of forming an opinion on those statements taken as a whole. The
schedules listed in Part IV, Item 14. (a)(5) in this Form 10-K are the
responsibility of the management of PG&E Corporation and of Pacific Gas and
Electric Company and are presented for purposes of complying with the
Securities and Exchange Commission's rules and are not part of the
consolidated financial statements. These schedules have been subjected to the
auditing procedures applied in the audits of the 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
consolidated financial statements taken as a whole.
Deloitte & Touche LLP
San Francisco, California
March 3, 2000
53
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 in accordance with generally accepted auditing standards,
the consolidated financial statements as of December 31, 1998, and for each of
the two years in the period 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 Years
Ended December 31, 1998 and 1997, 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
54
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 consolidated balance sheets of PG&E
Corporation (a California corporation) and subsidiaries and Pacific Gas and
Electric Company (a California corporation) and subsidiaries as of December
31, 1998, and the related statements of consolidated income, cash flows, and
common stock equity of PG&E Corporation and subsidiaries and the related
statements of consolidated income, cash flows and stockholders' equity of
Pacific Gas and Electric Company and subsidiaries for each of the two years in
the period 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 financial positions of PG&E Corporation and
subsidiaries, and of Pacific Gas and Electric Company and subsidiaries, as of
December 31, 1998, and the results of their operations and their cash flows
for each of the two years in the period ended December 31, 1998, in conformity
with generally accepted accounting principles.
ARTHUR ANDERSEN LLP
San Francisco, California
February 8, 1999
55
SCHEDULE I--CONDENSED FINANCIAL INFORMATION OF PARENT
CONDENSED BALANCE SHEETS
December 31,
--------------
1999 1998
------ ------
(in millions)
Assets:
Cash and cash equivalents.................................... $ 155 $ 9
Advances to affiliates....................................... 299 448
Other current assets......................................... -- 2
------ ------
Total current assets..................................... 454 459
Equipment.................................................... 16 8
Accumulated depreciation..................................... (3) (1)
------ ------
Net equipment................................................ 13 7
Investments in subsidiaries.................................. 7,621 8,780
Other investments............................................ 52 41
Deferred income taxes........................................ 396 --
Other deferred charges....................................... -- 1
------ ------
Total Assets............................................. $8,536 $9,288
====== ======
Liabilities and Stockholders' Equity:
Current Liabilities
Short-term borrowings...................................... $526 $ 683
Accounts payable - related parties......................... 76 221
Accounts payable - trade................................... 10 9
Accrued taxes.............................................. 117 155
Dividends payable.......................................... 110 115
Other...................................................... 112 16
------ ------
Total current liabilities................................ 951 1,199
Noncurrent Liabilities
Deferred income taxes...................................... -- 19
Other...................................................... 5 4
------ ------
Total noncurrent liabilities............................. 5 23
Stockholders' Equity
Common stock............................................... 5,906 5,862
Reinvested earnings........................................ 1,674 2,204
------ ------
Total stockholders' equity............................... 7,580 8,066
------ ------
Total Liabilities and Stockholders' Equity............... $8,536 $9,288
====== ======
SCHEDULE I--CONDENSED FINANCIAL INFORMATION FOR PARENT--(Continued)
CONDENSED STATEMENTS OF INCOME
For the Years Ended December 31, 1999, 1998 and 1997
1999 1998 1997
------- ------- --------
(in millions, except
per share amounts)
Equity in earnings of subsidiaries............. $ 853 $ 736 $ 772
Operating expenses............................. (4) 1 (21)
Loss on assets held for sale................... (1,275) -- --
Interest expense............................... (30) (52) (23)
Other income................................... 16 5 --
------- ------- --------
Income Before Income Taxes..................... (440) 690 728
Less: Income taxes............................. (447) (83) (17)
------- ------- --------
Income from continuing operations.............. $ 7 $ 773 $ 716
Discontinued operations........................ (98) (52) (29)
Cumulative effect of a change in an accounting
principle..................................... 12 -- --
------- ------- --------
Net income (loss) before intercompany
elimination................................... $ (79) $ 721 $ 716
Elimination of intercompany (profit) loss...... 6 (2) --
------- ------- --------
Net income (loss).............................. $ (73) $ 719 $ 716
======= ======= ========
Weighted Average Common Shares Outstanding..... 368 382 410
======= ======= ========
Earnings Per Common Share, Basic and Diluted... $ (.20) $ 1.88 $ 1.75
======= ======= ========
CONDENSED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 1999, 1998 and 1997
1999 1998 1997
------- ------- --------
(in millions)
Cash Flows From Operating Activities
Net income (loss).............................. $ (73) $ 721 $ 716
Adjustments to reconcile net income to net cash
provided by operating activities:
Equity in earnings of subsidiaries........... (853) (736) (772)
Deferred taxes............................... (415) 19 --
Loss on assets held for sale................. 1,275 -- --
Dividends received from consolidated
subsidiaries................................ 527 445 763
Other--net................................... 77 (574) (605)
------- ------- --------
Net cash provided (used) by operating
activities.................................... $ 538 $ (125) $ 1,312
Cash Flows From Investing Activities
Capital expenditures......................... (8) (8) --
Investments in subsidiaries.................. (722) (575) (150)
Return of capital by Utility (share
repurchases)................................ 926 1,600 --
Other--net................................... (12) -- --
------- ------- --------
Net cash provided by investing activities...... $ 184 $ 1,017 $ (150)
Cash Flows From Financing Activities
Common stock issued.......................... 54 63 --
Common stock repurchased..................... (3) (1,158) (804)
Short-term debt issued (redeemed)--net....... (157) 683 --
Dividends paid............................... (465) (470) (367)
Other--net................................... (5) (2) 10
------- ------- --------
Net cash used by financing activities.......... $ (576) $ (884) $ (1,161)
Net Change in Cash and Cash Equivalents........ 146 8 1
Cash and Cash Equivalents at January 1......... 9 1 --
------- ------- --------
Cash and Cash Equivalents at December 31....... $ 155 $ 9 $ 1
======= ======= ========
PG&E CORPORATION
SCHEDULE II--CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 1999, 1998, and 1997
Column A Column B Column C Column D Column E
Additions
---------------------
Balance
Balance at Charged Charged at End
Beginning to Costs to Other of
Description of Period and Expenses Accounts Deductions Period
----------- ---------- ------------ -------- ---------- --------
(in thousands)
Valuation and qualifying
accounts deducted from
assets:
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
======= ======= ======= ======= =======
1997:
Allowance for
uncollectible accounts
(2)................... $57,904 $42,500 $ -- $27,492(1) $72,912
======= ======= ======= ======= =======
- --------
(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."
PACIFIC GAS AND ELECTRIC COMPANY
SCHEDULE II--CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
For the years ended December 31, 1999, 1998, and 1997
Column A Column B Column C Column D Column E
Additions
---------------------
Balance
Balance at Charged Charged at End
Beginning to Costs to Other of
Description of Period and Expenses Accounts Deductions Period
----------- ---------- ------------ -------- ---------- --------
(in thousands)
Valuation and qualifying
accounts deducted from
assets:
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
======= ======= ======= ======= =======
1997:
Allowance for
uncollectible accounts
(2)................... $57,904 $30,718 $(1,836) $27,178(1) $59,608
======= ======= ======= ======= =======
- --------
(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."
EXHIBIT INDEX
Exhibit No. Description of Exhibit
----------- ----------------------
3.1 Restated Articles of Incorporation of PG&E Corporation
effective as of December 19, 1996 (PG&E Corporation's Form
8-B (File No. 1-12609), Exhibit 3.1)......................
3.2 By-Laws of PG&E Corporation amended as of February 16,
2000......................................................
3.3 Restated Articles of Incorporation of Pacific Gas and
Electric Company effective as of May 6, 1998 (Pacific Gas
and Electric Company's Form 10-Q for the quarter ended
March 31, 1998 (File No. 1-2348), Exhibit 3.1)............
3.4 By-Laws of Pacific Gas and Electric Company amended as of
February 16, 2000.........................................
4. First and Refunding Mortgage of Pacific Gas and Electric
Company dated December 1, 1920, and supplements thereto
dated April 23, 1925, October 1, 1931, March 1, 1941,
September 1, 1947, May 15, 1950, May 1, 1954, May 21,
1958, November 1, 1964, July 1, 1965, July 1, 1969,
January 1, 1975, June 1, 1979, August 1, 1983, and
December 1, 1988 (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).................................
10. The Gas Accord Settlement Agreement, together with
accompanying tables, adopted by the California Public
Utilities Commission on August 1, 1997, in Decision 97-08-
055. (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).....................................................
10.1 Stock Purchase Agreement By and Between PG&E National
Energy Group, Inc. and El Paso Field Services Company,
dated as of January 27, 2000..............................
*10.2 PG&E Corporation Supplemental Retirement Savings Plan
dated as of January 1, 2000...............................
*10.3 Description of Compensation Arrangement between PG&E
Corporation and Thomas G. Boren. (PG&E Corporation's Form
10-Q for the quarter ended September 30, 1999 (File No. 1-
12609), Exhibit 10.2).....................................
*10.4 Description of Compensation Arrangement between PG&E
Corporation and Peter Darbee. (PG&E Corporation's Form 10-
Q for the quarter ended September 30, 1999 (File No. 1-
12609), Exhibit 10.3).....................................
*10.5 PG&E Corporation Deferred Compensation Plan for Non-
Employee Directors, as amended and restated effective as
of July 22, 1998. (PG&E Corporation's Form 10-Q for the
quarter ended September 30, 1998 (File No. 1-12609),
Exhibit 10.2).............................................
*10.6 Description of Short-Term Incentive Plan for Officers of
PG&E Corporation and its subsidiaries, effective January
1, 1999. (PG&E Corporation's Form 10-K for the year ended
December 31, 1998 (File No. 1-12609), Exhibit 10.6).......
*10.7 Description of Short-Term Incentive Plan for Officers of
PG&E Corporation and its subsidiaries, effective January
1, 2000...................................................
Exhibit No. Description of Exhibit
----------- ----------------------
*10.8 Supplemental Executive Retirement Plan of the Pacific Gas
and Electric Company, effective January 1, 1998 (PG&E
Corporation's Form 10-K for the year ended December 31,
1998 (File No. 1-12609), Exhibit 10.7)....................
*10.9 Pacific Gas and Electric Company Relocation Assistance
Program for Officers (Pacific Gas and Electric Company's
Form 10-K for fiscal year 1989 (File No. 1-2348),
Exhibit 10.16)............................................
*10.10 Postretirement Life Insurance Plan of the Pacific Gas and
Electric Company (Pacific Gas and Electric Company's Form
10-K for fiscal year 1991 (File No. 1-2348),
Exhibit 10.16)............................................
*10.11 PG&E Corporation Retirement Plan for Non-Employee
Directors, as amended and terminated January 1, 1998.
(PG&E Corporation Form 10-K for the year ended December
31, 1997, (File No. 1-12609), Exhibit No. 10.13)..........
*10.12 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.............................
*10.13 PG&E Corporation Executive Stock Ownership Program,
amended as of February 16, 2000...........................
*10.14 PG&E Corporation Officer Severance Policy, amended as of
July 21, 1999. (PG&E Corporation's Form 10-Q for the
quarter ended September 30, 1999 (File No. 1-12609),
Exhibit 10.1).............................................
*10.15 PG&E Corporation Director Grantor Trust Agreement dated
April 1, 1998 (PG&E Corporation's Form 10-Q for the
quarter ended March 31, 1998 (File No. 1-12609), Exhibit
10.1).....................................................
*10.16 PG&E Corporation Officer Grantor Trust Agreement dated
April 1, 1998 (PG&E Corporation's Form 10-Q for the
quarter ended March 31, 1998 (File No. 1-12609), Exhibit
10.2).....................................................
11. Computation of Earnings Per Common Share..................
12.1 Computation of Ratios of Earnings to Fixed Charges for
Pacific Gas and Electric Company..........................
12.2 Computation of Ratios of Earnings to Combined Fixed
Charges and Preferred Stock Dividends for Pacific Gas and
Electric Company..........................................
13. 1999 Annual Report to Shareholders of PG&E Corporation and
Pacific Gas and Electric Company--portions of the 1999
Annual Report to Shareholders under the headings "Selected
Financial Data," "Management's Discussion and Analysis,"
"Report of Independent Public Accountants,"
"Responsibility for Consolidated Financial Statements,"
financial statements of PG&E Corporation entitled
"Statement of Consolidated Income," "Consolidated Balance
Sheet," "Statement of Consolidated Cash Flows," "Statement
of Consolidated Common Stock Equity," financial statements
of Pacific Gas and Electric Company entitled "Statement of
Consolidated Income," "Consolidated Balance Sheet,"
"Statement of Consolidated Cash Flows," "Statement of
Consolidated Stockholders' Equity," "Notes to Consolidated
Financial Statements" and "Quarterly Consolidated
Financial Data (Unaudited)" are included only. (Except for
those portions that are expressly incorporated herein by
reference, such 1999 Annual Report to Shareholders is
furnished for the information of the Commission and is not
deemed to be "filed" herein.).............................
Exhibit No. Description of Exhibit
----------- ----------------------
18. Letter re change in Accounting Principles....................
21. Subsidiaries of the Registrant...............................
23.1 Consent of Deloitte & Touche LLP.............................
23.2 Consent of Arthur Andersen LLP...............................
24.1 Resolutions of the Boards of Directors of PG&E Corporation
and Pacific Gas and Electric Company authorizing the
execution of the Form 10-K...................................
24.2 Powers of Attorney...........................................
27.1 Financial Data Schedule for the year ended December 31, 1999,
for PG&E Corporation.........................................
27.2 Financial Data Schedule for the year ended December 31, 1999,
for Pacific Gas and Electric Company.........................
- --------
* 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.