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, 1997
OR
[_] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM TO
COMMISSION EXACT NAME OF REGISTRANT IRS EMPLOYER
FILE AS SPECIFIED IN ITS STATE OF IDENTIFICATION
NUMBER CHARTER INCORPORATION NUMBER
---------- ------------------------ ------------- --------------
1-12609 PG&E CORPORATION California 94-3234914
1-2348 PACIFIC GAS AND ELECTRIC California 94-0742640
COMPANY
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)
94105
94177 (ZIP CODE)
(ZIP CODE)
(415) 973-7000
(REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE)
SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:
NAME OF EACH EXCHANGE ON
TITLE OF EACH CLASS WHICH REGISTERED
- ------------------- ---------------------------
PG&E CORPORATION
Common Stock, no par value New York Stock Exchange and
Pacific Stock Exchange
PACIFIC GAS AND ELECTRIC COMPANY
First Preferred Stock, cumulative, American Stock Exchange and
par value $25 per share: Pacific Stock Exchange
Redeemable: 7.04%, 6 7/8, 5% Series A, 5%, 4.80%, 4.50%, 4.36%.
Mandatorily Redeemable: 6.57%, 6.30%
Nonredeemable: 6%, 5 1/2%, 5%
7.90% Cumulative Quarterly Income Preferred
Securities,
Series A (liquidation preference $25), issued by
PG&E
Capital I and guaranteed by Pacific Gas and
Electric American Stock Exchange and
Company Pacific Stock Exchange
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. [X]
AGGREGATE MARKET VALUE OF THE VOTING STOCK HELD BY NON-AFFILIATES OF THE
REGISTRANT AS OF FEBRUARY 17, 1998:
PG&E Corporation Common Stock $11,426 million
Pacific Gas and Electric Company First Preferred Stock $463 million
COMMON STOCK OUTSTANDING AS OF FEBRUARY 17, 1998:
PG&E Corporation: 381,010,366
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 Part II (Items 5, 6, 7 and 8)
December 31, 1997......................... Part IV (Item 14)
(2) Designated portions of the Joint Proxy
Statement relating to the 1998 Annual
Meetings of Shareholders.................. Part III (Items 10, 11, 12 and 13)
TABLE OF CONTENTS
PAGE
----
Glossary of Terms
PART I
Item 1. Business......................................................... 1
GENERAL.......................................................... 1
Corporate Structure and Business................................. 1
Competition and the Changing Regulatory Environment.............. 3
Electric Industry................................................ 3
Gas Industry..................................................... 5
Regulation of Pacific Gas and Electric Company................... 6
State Regulation................................................. 6
Federal Regulation............................................... 6
Licenses and Permits............................................. 6
Regulation of PG&E Corporation and Other Subsidiaries............ 7
Pacific Gas and Electric Company Rate Matters.................... 8
California Ratemaking Mechanisms................................. 8
Electric Ratemaking.............................................. 9
Gas Ratemaking................................................... 11
1998 Revenues.................................................... 11
Capital Requirements and Financing Programs...................... 12
Price Risk Management Programs................................... 13
ELECTRIC UTILITY OPERATIONS...................................... 15
Electric Industry Restructuring Legislation...................... 15
Independent System Operator and Power Exchange................... 15
Voluntary Generation Asset Divestiture........................... 15
Direct Access.................................................... 16
Rate Levels and Rate Reduction Bonds............................. 17
Recovery of Transition Costs..................................... 17
Public Purpose Programs.......................................... 18
Electric Operating Statistics.................................... 20
Electric Generating and Transmission Capacity.................... 22
Diablo Canyon.................................................... 23
Diablo Canyon Operations......................................... 23
Diablo Canyon Ratemaking......................................... 24
Nuclear Fuel Supply and Disposal................................. 25
Insurance........................................................ 26
Decommissioning.................................................. 26
Other Electric Resources......................................... 27
QF Generation and Other Power-Purchase Contracts................. 27
Geothermal Generation............................................ 28
Helms Pumped Storage Plant....................................... 28
Electric Transmission and Distribution........................... 28
GAS UTILITY OPERATIONS........................................... 30
Gas Operations................................................... 30
Gas Operating Statistics......................................... 31
Natural Gas Supplies............................................. 32
Gas Regulatory Framework......................................... 32
Transportation Commitments....................................... 33
i
TABLE OF CONTENTS--(CONTINUED)
PAGE
----
Gas Reasonableness Proceedings................................. 34
1988-1990 Canadian Gas Procurement Activities.................. 34
PGT/Pacific Gas and Electric Company Pipeline Expansion........ 34
PG&E CORPORATION'S GAS TRANSMISSION OPERATIONS................. 36
PG&E CORPORATION'S INDEPENDENT POWER GENERATION OPERATIONS..... 37
PG&E CORPORATION'S ENERGY SERVICES AND COMMODITIES............. 39
ENVIRONMENTAL MATTERS.......................................... 40
Environmental Matters.......................................... 40
Environmental Protection Measures.............................. 40
Air Quality.................................................... 40
Water Quality.................................................. 41
Hazardous Waste Compliance and Remediation..................... 41
Potential Recovery of Hazardous Waste Compliance and
Remediation Costs.............................................. 43
Compressor Station Litigation.................................. 43
Electric and Magnetic Fields................................... 43
Low Emission Vehicle Programs.................................. 44
Item 2. Properties..................................................... 44
Item 3. Legal Proceedings.............................................. 44
Compressor Station Chromium Litigation......................... 45
Texas Franchise Fee Litigation................................. 46
Item 4. Submission of Matters to a Vote of Security Holders............ 49
EXECUTIVE OFFICERS OF THE REGISTRANTS.......................... 50
PART II
Market for the Registrant's Common Equity and Related
Item 5. Stockholder Matters............................................ 53
Item 6. Selected Financial Data........................................ 53
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations.......................................... 53
Item 7A. Quantitative and Qualitative Disclosures About Market Risk..... 53
Item 8. Financial Statements and Supplementary Data.................... 53
Changes in and Disagreements with Accountants on Accounting and
Item 9. Financial Disclosure........................................... 54
PART III
Item 10. Directors and Executive Officers of the Registrant............. 54
Item 11. Executive Compensation......................................... 54
Item 12. Security Ownership of Certain Beneficial Owners and Management. 54
Item 13. Certain Relationships and Related Transactions................. 54
PART IV
Exhibits, Financial Statement Schedules, and Reports on Form 8-
Item 14. K.............................................................. 54
Signatures..................................................... 59
Report of Independent Public Accountants....................... 60
Financial Statement Schedules.................................. 61
ii
GLOSSARY OF TERMS
AB 1890........... Assembly Bill 1890, the California electric industry
restructuring legislation
AEAP.............. Annual Earnings Assessment Proceeding
AER............... Annual Energy Rate
AFUDC............. allowance for funds used during construction
ALJ............... Administrative Law Judge
Bechtel........... Bechtel Enterprises, Inc.
Betz.............. Betz Laboratories, Inc. and affiliated entities
BCAP.............. Biennial Cost Allocation Proceeding
bcf............... billion cubic feet
BRPU.............. Biennial Resource Plan Update
BTA............... best technology available
Btu............... British thermal unit
California
Superfund........ California Hazardous Substance Account Act
CARE.............. California Alternate Rates for Energy
CCAA.............. California Clean Air Act
CEC............... California Energy Commission
Central Coast
Board............ Central Coast Regional Water Quality Control Board
CERCLA............ Comprehensive Environmental Response, Compensation, and
Liability Act
CFCA.............. Core Fixed Cost Account
CIG............... customer identified gas program
Company........... Pacific Gas and Electric Company and its subsidiaries
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
Duke Energy....... Duke Energy Power Services, Inc.
ECAC.............. Energy Cost Adjustment Clause
EDRA.............. electric deferred refund account
El Paso........... El Paso Natural Gas Company
EMF............... electric and magnetic fields
Enterprises....... PG&E Enterprises
EPA............... United States Environmental Protection Agency
ERAM.............. Electric Revenue Adjustment Mechanism
FERC.............. Federal Energy Regulatory Commission
Gas Accord........ Gas Accord Settlement
Geysers........... The Geysers Power Plant
GRC............... General Rate Case
GTT............... PG&E Gas Transmission, Texas Corporation
HCP............... Habitat Conservation Plan
Helms............. Helms hydroelectric pumped storage plant
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
InterGen.......... International Generating Company, Ltd.
ISO............... Independent System Operator
ITCBA............. Interim Transition Cost Balancing Account
ITCS.............. Interstate Transition Cost Surcharge
kV................ kilovolts
kVa............... kilovolt-amperes
kW................ kilowatts
kWh............... kilowatt-hour
LDC............... local distribution company
LEV............... low emission vehicle
Mcf............... thousand cubic feet
MMcf.............. million cubic feet
MMcf/d............ million cubic feet per day
MW................ megawatts
MWh............... megawatt-hour
NEES.............. New England Electric System
NEIL.............. Nuclear Electric Insurance Limited
NGL............... natural gas liquids
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, formerly known as the
Division of Ratepayer Advocates
PBR............... performance-based ratemaking
PEPR.............. Pipeline Expansion Project Reasonableness case
PG&E Expansion.... the Pacific Gas and Electric Company portion of the
Pipeline Expansion
PG&E ES........... PG&E Corporation's energy services operations, PG&E Energy
Services or PG&E ES
PG&E GT........... PG&E Corporation's gas transmission operations, PG&E Gas
Transmission or PG&E GT
PG&E ET........... PG&E Corporation's energy commodities activities, PG&E
Energy Trading or PG&E ET
PGT............... Pacific Gas Transmission Company, now known as PG&E Gas
Transmission, Northwest Corporation
PGT Expansion..... the Pacific Gas Transmission Company (now known as PG&E Gas
Transmission, Northwest Corporation) portion of the
Pipeline Expansion
Pipeline
Expansion........ PGT/Pacific Gas and Electric Company Pipeline Expansion
PPPs.............. public purpose programs
PRP............... potentially responsible party
PX................ California Power Exchange
QF................ qualifying facility
RAP............... Revenue Adjustment Proceeding
RRC............... The Railroad Commission of Texas
SEC............... Securities and Exchange Commission
Teco.............. Teco Pipeline Company
TRA............... Transition Revenue Account
transition period. the period during which electric rates are frozen at 1996
levels, which extends until the earlier of March 31, 2002
or the point in time when Pacific Gas and Electric Company
has recovered its transition costs
Transwestern...... Transwestern Pipeline Company
TURN.............. The Utility Reform Network
USGen............. U.S. Generating Company
USOSC............. U.S. Operating Services Company
Vantus............ Vantus Energy Corporation
Valero............ Valero Energy Corporation
PART I
ITEM 1. BUSINESS.
GENERAL
CORPORATE STRUCTURE AND BUSINESS
PG&E Corporation is a holding company, based in San Francisco, California,
which provides energy services throughout the United States and in Australia.
Effective January 1, 1997, Pacific Gas and Electric Company and its
subsidiaries became subsidiaries of PG&E Corporation, which was incorporated
in 1995. 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 (sometimes
referred to in this report as the "Company"). Because PG&E Corporation did not
become the holding company for Pacific Gas and Electric Company until January
1, 1997, the 1995 and 1996 consolidated financial statements represent the
accounts of Pacific Gas and Electric Company on a consolidated basis as
predecessor of PG&E Corporation.
The principal executive offices of PG&E Corporation are located at One
Market, Spear Tower, Suite 2400, San Francisco, California 94105, and 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 their
telephone number is (415) 973-7000.
As of December 31, 1997, PG&E Corporation had $30.6 billion in assets. PG&E
Corporation generated $15.4 billion in operating revenues for 1997. As of
December 31, 1997, PG&E Corporation and its subsidiaries and affiliates had
approximately 23,500 employees.
During 1997, PG&E Corporation expanded its energy-related business
activities, which now include the gas and electric utility operations of
Pacific Gas and Electric Company; the ownership and operation of natural gas
pipelines, natural gas storage facilities, and natural gas processing plants,
primarily in the Pacific Northwest, Texas and Australia, through various
subsidiaries of PG&E Corporation (PG&E Gas Transmission or PG&E GT); the
development, construction, operation, ownership, and management of independent
power generation facilities through U.S. Generating Company and its
affiliates; the purchase and sale of energy commodities and financial
instruments to PG&E Corporation's other businesses, unaffiliated utilities,
marketers, municipalities, cooperatives, independent power producers, and
large end-use customers through PG&E Energy Trading Corporation and its
affiliates (PG&E Energy Trading or PG&E ET); and the provision to customers
nationwide with competitively priced natural gas and electricity and services
to manage and make more efficient their energy consumption through PG&E Energy
Services Corporation (PG&E Energy Services or PG&E ES).
Pacific Gas and Electric Company, incorporated in California in 1905, is an
operating public utility engaged principally in the business of providing
electric and natural gas services throughout most of Northern and Central
California. As of December 31, 1997, Pacific Gas and Electric Company had
$25.1 billion in assets. The Company generated $9.5 billion in operating
revenues for 1997. As of December 31, 1997, Pacific Gas and Electric Company
had approximately 21,000 employees.
The gas and electric utility operations of Pacific Gas and Electric Company
represent the principal component of PG&E Corporation's business, contributing
62% of PG&E Corporation's total revenues in 1997. Pacific Gas and Electric
Company's utility operations contributed $1.77 of PG&E Corporation's total
1997 earnings per share of $1.75. (Pacific Gas and Electric Company's earnings
were offset by losses at some of PG&E Corporation's other businesses: PG&E
Energy Services, PG&E Energy Trading, and U.S. Generating Company.)
1
Pacific Gas and Electric Company's utility service territory covers 70,000
square miles with an estimated population of approximately 12 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.
At December 31, 1997, Pacific Gas and Electric Company served approximately
4.5 million electric customers. In 1997, Pacific Gas and Electric Company
served its electric customers with power generated by seven primarily natural
gas-fueled steam power plants with 21 units, ten combustion turbines, two
nuclear power reactor units at Diablo Canyon Nuclear Power Plant (Diablo
Canyon), 68 hydroelectric powerhouses with 109 units, the Helms hydroelectric
pumped storage plant (Helms) with three units, and a geothermal energy complex
of 14 units. (In connection with the ongoing California electric industry
restructuring, Pacific Gas and Electric Company has entered into agreements to
sell three fossil-fueled power plants and has announced plans to sell an
additional four power plants plus its geothermal facilities in 1998. See
"Electric Utility Operations--Electric Industry Restructuring Legislation"
below.) Pacific Gas and Electric Company also purchases 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, Pacific Gas and Electric Company is interconnected with electric
power systems in 14 western states and British Columbia, Canada, for the
purposes of buying, selling, and transmitting power.
Pacific Gas and Electric Company served approximately 3.7 million gas
customers at December 31, 1997. To ensure a diverse and competitive mix of
natural gas supplies, Pacific Gas and Electric Company purchases gas from both
Canadian and United States suppliers. In 1997, about 66% of Pacific Gas and
Electric Company's gas supply came from fields in Canada, about 3% came from
fields in California, and about 31% came from fields in other states
(substantially all from the U.S. Southwest). In 1997, the CPUC approved the
Gas Accord Settlement (Gas Accord), a comprehensive multi-party settlement
agreement to restructure Pacific Gas and Electric Company's gas services and
its role in the gas market, establish gas transmission rates for the period
from March 1, 1998 through December 2002, and resolve various gas regulatory
issues.
On July 31, 1997, a wholly owned subsidiary of PG&E Corporation merged with
Valero Energy Corporation, (Valero) in Texas (now known as PG&E Gas
Transmission, Texas Corporation). As a result of the merger, PG&E Corporation
acquired Valero's natural gas and natural gas liquids pipelines, natural gas
storage facilities, natural gas processing plants, and various gas marketing
companies. Through its January 1997 acquisition of Teco Pipeline Company
(Teco) in Texas (now known as PG&E Gas Transmission, Teco, Inc.), PG&E
Corporation also acquired interests in various natural gas pipelines, natural
gas processing facilities, and an operation in Houston, Texas, involved in the
purchase and sale of energy commodities and related financial instruments.
PG&E Gas Transmission, Northwest Corporation (formerly Pacific Gas
Transmission Company or PGT) owns and operates an interstate natural gas
pipeline in the Pacific Northwest. See "PG&E Corporation's Gas Transmission
Operations" below.
Also in 1997, PG&E Corporation established PG&E Energy Services Corporation
(formerly Vantus Energy Corporation) to compete in the direct access market in
California and to provide customers nationwide with competitively priced
natural gas and electricity services to manage and make more efficient their
energy consumption. See "PG&E Corporation's Energy Services and Commodities"
below. Although the direct access market was scheduled to begin in California
on January 1, 1998, in late December 1997, the Independent System Operator
(ISO) and the Power Exchange (PX) announced that there would be a delay in the
commencement of a direct access market until certain operational and
logistical issues are resolved, and that they expected direct access to begin
by March 31, 1998. The ISO is the corporation proposed by California electric
industry restructuring legislation to operate and control the state's electric
transmission facilities and to provide comparable open access to electric
transmission service. The PX is the corporation proposed by the California
Public Utilities Commission (CPUC) to provide a competitive auction process to
establish the price of electricity. See "Electric Utility Operations--Electric
Industry Restructuring Legislation" below.
2
In August 1997, PG&E Corporation announced plans to acquire, through
affiliates of U.S. Generating Company (USGen), a portfolio of electric
generating assets and power supply contracts from the New England Electric
System for approximately $1.59 billion plus $85 million for certain employee-
related costs. In September 1997, PG&E Corporation acquired full ownership of
USGen, originally formed as a joint venture with Bechtel Enterprises, Inc.
(Bechtel). PG&E Corporation also acquired full ownership of certain other
partnerships affiliated with USGen, as well as all or a portion of Bechtel's
interests in various power projects affiliated with USGen. See "PG&E
Corporation's Independent Power Generation Operations" below.
The following information includes forward-looking statements that involve a
number of risks, uncertainties, and assumptions. Words such as "estimates,"
"expects," "intends," "anticipates," "plans," and similar expressions identify
those statements which are forward-looking. A number of factors that could
cause actual results to differ materially from those indicated in the forward-
looking statements include, but are not limited to, the ongoing restructuring
of the electric and gas industries and the outcome of regulatory proceedings
related to that restructuring, and other factors which are described in more
detail below. The ultimate impacts of both increased competition and the
changing regulatory environment on future results are uncertain, but are
expected to fundamentally change how PG&E Corporation's utility operations are
conducted. The outcome of these changes and other matters discussed below may
cause future results to differ materially from historic results, or from
results or outcomes currently expected or sought by PG&E Corporation.
COMPETITION AND THE CHANGING REGULATORY ENVIRONMENT
The electric and gas industries are undergoing 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.
Today, competitive pressures and emerging market forces are exerting an
increasing influence over the structure of the gas and electric industries.
Other companies have challenged the utilities' exclusive relationship with
their customers and have sought to replace certain utility functions with
their own. Customers, too, have asked for choice in their energy provider.
These pressures have caused a move from the existing regulatory framework to a
framework under which competition is allowed in certain segments of the gas
and electric industries.
For several years, Pacific Gas and Electric Company has been working with
its regulators to achieve an orderly transition to competition and to ensure
that the Company has an opportunity to recover investments made under
traditional regulatory policies. Beginning in 1998, a significant portion of
Pacific Gas and Electric Company's business will be transformed from the
current utility monopoly to a competitive operation. During the transition
period, the return on Diablo Canyon and certain other generation assets will
be significantly lower than historical levels. See "Electric Utility
Operations--Diablo Canyon--Diablo Canyon Ratemaking" below. These changes will
affect PG&E Corporation's financial results and may result in greater earnings
volatility.
ELECTRIC INDUSTRY
In 1995, the CPUC issued a decision that provides a plan to restructure
California's electric industry. The decision acknowledges that much of
utilities' current costs and commitments result from past CPUC decisions and
that, in a competitive generation market, utilities would not recover some of
these costs through market-based revenues. To assure the continued financial
integrity of California utilities, the CPUC authorized recovery of these
above-market costs, called transition costs, through a nonbypassable charge,
called the competition transition charge or CTC, to be collected over a period
of years.
3
In 1996, legislation adressing electric industry restructuring, Assembly Bill
1890 (AB 1890), was signed into law in California. AB 1890 adopts the basic
tenets of the CPUC's restructuring decision and establishes the operating
framework for a competitive electric generation market. Key features of AB
1890 include:
--mandatory unbundling of transmission, distribution, and generation
services;
--formation of the PX to provide a competitive auction process to establish
the price of electricity in California;
--establishment of the ISO to ensure system reliability and provide
electric generators and energy service providers with open and comparable
access to transmission services;
--an electric rate freeze at 1996 levels until the earlier of March 31,
2002, or when the particular utility has recovered its generation-related
transition costs (the transition period);
--a 10% rate reduction on January 1, 1998, for residential and small
commercial customers, financed through "rate reduction bonds;"
--nonbypassable charges (the competition transition charge or CTC) to
provide the opportunity for utilities to recover their transition costs
and accelerated recovery of transition costs associated with utility-
owned generation facilities;
--direct access to competitive generation resources for all retail electric
customers to start no later than January 1, 1998;
--market valuation for utility-owned fossil generation assets by 2001,
followed by an end to cost-of-service ratemaking for most plants; and
--continued support for renewable generation resources, conservation, and
other public purpose programs.
Under AB 1890, Pacific Gas and Electric Company and other utilities will
continue to own transmission and distribution facilities and must continue to
offer bundled electric service to customers who wish to continue receiving it.
Although ownership of transmission facilities will be retained, utilities will
relinquish control of the facilities to the ISO.
As required by AB 1890, electric rates were frozen on January 1, 1997 at
1996 levels, and on January 1, 1998, rates for residential and small
commercial customers were reduced by 10% and will be held at the reduced
level. The rate freeze will continue until the end of the transition period.
During 1997, the CPUC issued many decisions to establish the ratemaking and
accounting mechanisms necessary to implement AB 1890. Many of the key features
of AB 1890 were implemented by January 1, 1998, such as the rate freeze, the
10% rate reduction for residential and small commercial customers, formation
of the ISO and PX, and commencement of the market valuation process. However,
direct access for all retail electric customers has been delayed. In December
1997, the ISO and the PX announced that they were unable to commence
operations on January 1, 1998, and that they expected to be operational by
March 31, 1998, at which time direct access would begin. See "Electric Utility
Operations--Electric Industry Restructuring Legislation" below.
At the federal level, the ISO is regulated by the Federal Energy Regulatory
Commission (FERC). In October 1997, the FERC granted conditional authority for
the California ISO to commence operations and for the California PX to charge
market-based rates for electricity. See "Electric Utility Operations--Electric
Transmission" below.
Additional information concerning electric industry restructuring, the
expected operating framework for a competitive generation market, and the
financial impact of these changes on PG&E Corporation is provided in
"Management's Discussion and Analysis of Consolidated Results of Operations
and Financial Condition" in the 1997 Annual Report to Shareholders, beginning
on page 20, and in Note 2 of the "Notes to Consolidated Financial Statements"
beginning on page 43 of the 1997 Annual Report to Shareholders.
4
GAS INDUSTRY
Restructuring of the natural gas industry on both the national and state
levels has given customers greater options in meeting their gas supply needs.
Currently, Pacific Gas and Electric Company's customers may buy gas directly
from competing suppliers and purchase transmission- and distribution-only
services from Pacific Gas and Electric Company. Pacific Gas and Electric
Company's transmission and distribution services have historically been
"bundled," or sold together at a combined rate, within California. Most of
Pacific Gas and Electric Company's industrial and larger commercial (noncore)
customers now purchase their gas from marketers and brokers. Substantially all
residential and smaller commercial (core) customers buy gas as well as
transmission and distribution services from Pacific Gas and Electric Company
as a bundled service. Customer rates for gas are updated on a monthly basis in
order to reflect changes in Pacific Gas and Electric Company's gas procurement
costs.
In 1995 and 1996, Pacific Gas and Electric Company actively pursued changes
in the California gas industry in an effort to promote competition and
increase options for all customers, as well as to position the Company for the
competitive marketplace. In 1996, Pacific Gas and Electric Company submitted
to the CPUC the Gas Accord, a multi-party settlement agreement which resulted
from an extensive negotiation process begun in 1995 among a broad coalition of
customer groups and industry participants. On August 1, 1997, the CPUC
unanimously approved the Gas Accord.
The Gas Accord separates, or "unbundles," Pacific Gas and Electric Company's
gas transmission services from its distribution services and changes the terms
of service and rate structure for gas transportation. Unbundling gives noncore
customers the opportunity to select from a menu of services offered by Pacific
Gas and Electric Company and enables them to pay only for the services they
use. Unbundling also makes access to the transmission system possible for all
gas marketers and shippers, as well as noncore end-users. As a result, the
transmission system is now more accessible to a greater number of customers.
The Gas Accord increases opportunities for Pacific Gas and Electric
Company's core customers to purchase gas from competing suppliers and,
therefore, will reduce the Company's role in procuring gas for such customers.
However, Pacific Gas and Electric Company will continue to procure gas as a
regulated utility supplier for those customers who do not obtain gas supplies
from an alternative provider.
Under the Gas Accord, the CPUC's traditional after-the-fact reasonableness
review of Pacific Gas and Electric Company's core gas procurement costs for
the period 1994 to 2002 are replaced by a core procurement incentive mechanism
(CPIM), a form of incentive regulation. Under the CPIM, Pacific Gas and
Electric Company is able to recover its gas commodity and interstate
transportation costs and receives benefits or incurs penalties depending on
whether its actual core procurement costs are within, below, or above a
"tolerance band" constructed around market benchmarks. Actual core procurement
costs measured for the period June 1, 1994, through December 31, 1997, have
generally been within the CPIM "tolerance band."
The Gas Accord establishes gas transmission and storage rates for the period
from March 1, 1998, through December 2002. During the Gas Accord period,
Pacific Gas and Electric Company is at risk for revenue fluctuations resulting
from variances in demand for noncore gas transmission throughput. Rates for
distribution service continue to be set by the CPUC and are designed to
provide the Company an opportunity to recover its costs of service and include
a return on investment.
In January 1998, the CPUC opened a rule-making proceeding to expand market-
oriented policies in the natural gas industry, including the further
unbundling of services to promote competition, streamlining regulation for
noncompetitive services, mitigating the potential for anti-competitive
behavior, and establishing appropriate consumer protections. The CPUC will be
studying various new alternative market structures for the California natural
gas industry with the goal of encouraging competition and customer choice,
while maintaining a high standard of consumer protection.
5
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 of Consolidated Results of Operations
and Financial Condition" in the 1997 Annual Report to Shareholders, beginning
on page 24, and in Note 3 of the "Notes to Consolidated Financial Statements"
beginning on page 46 of the 1997 Annual Report to Shareholders.
REGULATION OF PACIFIC GAS AND ELECTRIC COMPANY
STATE REGULATION
The CPUC consists of five members appointed by the Governor and confirmed by
the State Senate for six-year terms. The CPUC regulates Pacific Gas and
Electric Company's rates and conditions of service, sales of securities,
dispositions of utility property, rate of return, rates of depreciation,
uniform systems of accounts, long-term resource procurement, and transactions
between Pacific Gas and Electric Company and its subsidiaries and affiliates.
The CPUC also conducts various reviews of utility performance and conducts
investigations into various matters, such as deregulation, competition, and
the environment, to determine its future policies.
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 state-wide plan of action in case of energy shortages. In
addition, the CEC certifies power-plant sites and related facilities within
California. Under electric industry restructuring legislation, the CEC also
administers funding for public purpose research and development, and renewable
technologies programs. The funding will be collected from ratepayers through a
nonbypassable public benefits charge. See "Electric Utility Operations--
Electric Industry Restructuring Legislation--Public Purpose Programs" below.
FEDERAL REGULATION
The FERC regulates electric transmission rates and access, compliance with
the uniform systems of accounts, and electric contracts involving sales of
electricity for resale. After the ISO and PX commence operations, the FERC
will have jurisdiction over Pacific Gas and Electric Company's electric
transmission revenue requirements and rates, which previously were included in
CPUC-authorized bundled rates. The FERC also regulates the interstate
transportation of natural gas. Further, most of Pacific Gas and Electric
Company'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. 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 and gas compressor station facilities. Discharge
permits, various Air Pollution Control District permits, FERC hydroelectric
facility 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 imposed by the granting
agency.
6
REGULATION OF PG&E CORPORATION AND OTHER SUBSIDIARIES
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) on the basis that PG&E Corporation and Pacific Gas and Electric
Company are incorporated in the same state and their business is predominantly
intrastate in character and carried on substantially in the state of
incorporation. 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 Pacific Gas and Electric Company is
precluded from guaranteeing any obligations of PG&E Corporation without prior
written consent from the CPUC, Pacific Gas and Electric Company's dividend
policy shall continue to be established by Pacific Gas and Electric Company's
Board of Directors as though Pacific Gas and Electric Company were a
comparable stand-alone utility company, and the capital requirements of
Pacific Gas and Electric Company, as determined to be necessary to meet
Pacific Gas and Electric Company'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 Pacific Gas and Electric
Company shall maintain on average its CPUC-authorized utility capital
structure, although it shall have an opportunity to request a waiver of this
condition in the event an adverse financial event reduces the utility's equity
ratio by 1% or more.
A further condition of the CPUC's approval of the holding company formation
was that an audit of affiliate transactions from 1994 to 1996 be conducted and
supervised by the CPUC's Office of Ratepayer Advocates (ORA). The audit
report, completed in November 1997, was critical of Pacific Gas and Electric
Company's affiliate transaction internal controls and compliance. The report
contained numerous recommendations for additional conditions to be imposed on
the holding company. Pacific Gas and Electric Company will be responding to
the audit report, and the CPUC will hold hearings to determine if the
additional recommended conditions should be imposed on the holding company. A
final CPUC decision is expected in early 1999.
On December 16, 1997, the CPUC issued a decision that adopted rules
governing transactions between California's natural gas local distribution and
electric utility companies and their non-regulated affiliates. This decision
permits non-regulated affiliates of regulated utilities (such as PG&E Energy
Services Corporation, the non-regulated energy marketing subsidiary of PG&E
Corporation) to compete in the affiliated utility's service territory. The
decision permits non-regulated affiliates to use the same 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 decision also adopts complex and detailed rules requiring the separation
of regulated utilities and their non-regulated affiliates, through the
maintenance of separate books and records, physical separation of facilities,
and the separation of certain functions, such as energy-related purchases and
sales, and marketing, among others. The decision also contains rules regarding
disclosure and use of information among the affiliates and prohibits the
utility from engaging in certain practices which would discriminate against
energy service providers which compete with the utility's non-regulated
affiliates. As required by the decision, Pacific Gas and Electric Company
filed a comprehensive plan to comply with the affiliate transaction rules on
December 31, 1997.
In addition to Pacific Gas and Electric Company, certain of PG&E
Corporation's other subsidiaries which conduct interstate gas transmission and
electric wholesale power marketing operations are subject to FERC
jurisdiction. The FERC also has authority to regulate rates for natural gas
transportation in interstate commerce.
In addition, the power generation projects that USGen and its affiliates
develop, manage or own, 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 the Public Utility
Holding Company Act of 1935. EWG status is granted by FERC upon application by
the project. Some projects have received authority from FERC to charge market-
7
based rates for the power they sell, rather than traditional cost-based rates.
Many of USGen's affiliated projects are qualifying facilities (QF) under the
Public Utility Regulatory Policies Act of 1978. QF status exempts the project
from regulation under various federal and state laws concerning the electric
industry. USGen's projects are also subject to various federal, state, and
local regulations concerning siting and environmental matters.
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 Gas Transmission Teco, Inc., and other affiliates operating
in Texas. The RRC gas proration rules govern the wellhead production and
purchase of gas. Intrastate pipelines can provide intrastate gas
transportation at negotiated rates which 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 may also regulate certain sales of gas. Currently,
the price of natural gas sold under a majority of PG&E Gas Transmission, Texas
Corporation'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 are subject to safety regulations enforced by the RRC and
the Texas Natural Resource Conservation Commission.
Other regulatory matters are described throughout this report.
PACIFIC GAS AND ELECTRIC COMPANY RATE MATTERS
CALIFORNIA RATEMAKING MECHANISMS
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 operations. Base revenues,
which include non-fuel-related operating and maintenance costs, depreciation,
taxes, and a return on invested capital, are currently authorized by the CPUC
in general rate case (GRC) proceedings before the CPUC. Pacific Gas and
Electric Company's next scheduled GRC will establish base revenues effective
January 1, 1999.
During the GRC, which occurs every three years, the CPUC examines Pacific
Gas and Electric Company's costs and operations to determine the amount of
base revenue requirement Pacific Gas and Electric Company 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
Pacific Gas and Electric Company'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 December 12, 1997, Pacific Gas and Electric Company filed its Test Year
1999 GRC application with the CPUC, requesting increases in electric and gas
base revenues of $693 million and $501 million, respectively, over base
revenues authorized in 1997. The requested increase in base revenues reflects
increasing levels of electric and gas demand as well as customer growth in the
service territory, the costs of continued and enhanced maintenance activities,
and increased capital expenditures. If granted by the CPUC, the requested
increase would be effective January 1, 1999.
The requested increase of $693 million in electric base revenues as compared
to 1997 will not increase customer electric rates because these rates will
continue to be frozen. Under the frozen electric rates, the portion of total
actual revenue which exceeds authorized base revenues and certain other
authorized revenue requirements is available to recover transition costs.
Therefore, increases in base revenues would reduce the amount of revenue
available to recover transition costs.
The GRC electric revenue request includes proposed funding for distribution
services, including system reliability and safety projects, increased
distribution capacity (poles, wires, substations, etc.), equipment inspection
8
and maintenance, a continuation of tree-trimming programs, and enhanced
customer service and information technology systems. Since the FERC will
authorize the rates to be collected from customers for electric transmission
services once direct access begins, the GRC application does not seek approval
of base revenues to recover the cost of transmission services. The requested
increase in electric base revenues is in addition to increases for system
safety and reliability provided by AB 1890, as discussed in "1998 Revenues"
below.
Gas customers would experience an increase in gas distribution rates if the
CPUC approves the requested gas base revenue increase. The GRC gas base
revenue request includes proposed funding for distribution system safety and
reliability improvements, increased depreciation costs of the gas pipeline
system, expanded customer service, and expanded customer and other information
systems. The requested increase in gas base revenues will not result in an
increase in customer gas transmission and storage rates, since the Gas Accord
has set gas transmission and storage rates for the period from implementation
of the Gas Accord through December 2002.
ELECTRIC RATEMAKING
In 1996, the CPUC issued a "roadmap" decision outlining the necessary steps
to accomplish electric industry restructuring. During 1997, the CPUC issued
many decisions to implement AB 1890 and the new market structure beginning in
1998, including decisions related to unbundling of rates, transition costs,
performance based ratemaking (PBR), and other activities that affect rates and
revenue requirements.
In its roadmap decision, the CPUC established a separate annual proceeding
to consider ratemaking issues related to each electric utility's revenues,
which will consolidate all pending revenue changes and track utility revenues
at present rate levels for the purpose of comparison with authorized amounts.
Beginning in 1998, this annual Revenue Adjustment Proceeding (RAP) will
review, track, and compare each electric utility's authorized revenue
requirements with the actual recorded revenues, and will make any necessary
adjustments or updates due to authorized revenues for alternative ratemaking
mechanisms, various power purchase contracts, public purpose programs, nuclear
facilities, nuclear decommissioning, transition costs, and other proceedings.
Pacific Gas and Electric Company has filed numerous regulatory applications
and proposals that detail its transition cost recovery plan during the
transition period. Pacific Gas and Electric Company's recovery plan includes
(1) separating or unbundling of its previously approved cost-of-service
revenue requirement for its electric operations into distribution,
transmission, public purpose programs (PPPs), and generation, (2) determining
revenues available to recover transition costs, and (3) development of a
ratemaking mechanism to track and match revenues and cost recovery during the
transition period.
In August 1997, the CPUC adopted Pacific Gas and Electric Company's proposed
unbundling of its 1998 authorized electric revenue requirements with some
exceptions. The decision enables Pacific Gas and Electric Company to separate
revenues provided by frozen rates into transmission, distribution, PPPs, and
generation based upon their respective costs of service. The generation
category includes energy costs, generation operating costs, nuclear
decommissioning costs, and transition costs. When direct access begins, bills
for all customers will describe what portion of the bill is attributable to
transmission, distribution, PPPs, energy, and transition costs and other
nonbypassable charges.
Under the restructuring legislation, most transition costs must be recovered
by March 31, 2002. The CPUC believes that the shorter amortization period
reduces risks associated with recovery of generation facilities, including
Diablo Canyon. As a result, in November 1997 (but retroactive to July 28,
1997), the CPUC reduced the authorized rate of return on common equity for
Pacific Gas and Electric Company's non-nuclear electric generation-related
assets including hydroelectric and geothermal facilities, to 90% of the
Company's embedded cost of debt, for a reduced rate of return on common equity
equal to 6.77%, as compared to the previously authorized 1997 rate of return
on common equity of 11.6%. Effective January 1, 1997, the rate of return on
common equity on Diablo Canyon was reduced to 90% of Pacific Gas and Electric
Company's embedded cost of long-term debt, for a return on common equity of
6.77%. See "Electric Utility Operations--Diablo Canyon--Diablo Canyon
Ratemaking" below. The reduced rate of return for the Company's non-nuclear
electric generation-related assets and for Diablo Canyon will be in effect for
the duration of the transition period.
9
Before 1998, the Electric Revenue Adjustment Mechanism (ERAM) allowed rate
adjustments to offset the effect on base revenues of differences between
actual electric sales volumes and the forecasted volumes used to set electric
rates. The ERAM eliminated the impact on earnings of sales fluctuations,
including those resulting from conservation and weather conditions. Base
revenue differences resulting from the disparity between actual and forecasted
electric sales accumulated in a balancing account, with interest. In
connection with electric industry restructuring, the CPUC eliminated the ERAM
effective January 1, 1998. Until direct access begins, ERAM-related revenues
will be recorded in a separate memorandum account established in connection
with the delay of direct access.
Before 1998, most of Pacific Gas and Electric Company's fuel, purchased-
power, and energy-related costs of providing electric service, as well as
revenues attributable to Diablo Canyon generation, were recovered through a
balancing account mechanism called the Energy Cost Adjustment Clause (ECAC).
Under the ECAC balancing account procedure, actual costs were compared with
revenues designated for recovery of such costs, and the difference was
recorded as either an undercollection or overcollection. In prior years, rates
would be adjusted such that the amount of overcollections would be returned to
ratepayers through lower rates and undercollections would be recovered through
higher rates. However, as part of the electric industry restructuring, the
CPUC eliminated the ECAC balancing account effective January 1, 1998.
In December 1996, the CPUC issued a decision establishing an electric
deferred refund account (EDRA). The CPUC ordered Pacific Gas and Electric
Company to place into the EDRA credits for CPUC-ordered electric
disallowances, the utility electric generation share of CPUC-ordered gas
disallowances, amounts resulting from reasonableness disputes, and fuel-
related cost refunds made to Pacific Gas and Electric Company based on
regulatory agency decisions, plus interest charges. The CPUC ordered Pacific
Gas and Electric Company to file advice letters by January 31 of each year,
setting forth its annual refund plans for directly refunding to electric
customers the amounts accumulated in the EDRA. The CPUC also ordered Pacific
Gas and Electric Company to include initially in the EDRA any such credits
already recorded in ECAC and ERAM but not yet amortized in rates. The effect
of this was to reduce the amount available to offset Pacific Gas and Electric
Company's transition costs by approximately $75 million. In February 1998,
Pacific Gas and Electric Company refunded approximately $61 million of EDRA
funds to customers.
The ISO will designate certain electric generation facilities as necessary
to remain available and operational to maintain the reliability of the
electric transmission system. These facilities are called "must-run"
facilities. In general, sunk costs and on-going operating costs of must-run
facilities are recoverable through different types of FERC-authorized
contracts between must-run facilities and the ISO and, in some cases, also
through PX revenues. For an initial three-month period, all must-run
facilities will be under the same type of contract. Thereafter, the type of
contract for a particular must-run facility may change based upon the ISO's
evaluation of facility operating factors and system reliability needs. Subject
to CPUC approval, the type of contract and generation (i.e., fossil,
hydroelectric, or geothermal) will determine whether (1) all of the facility's
sunk costs and ongoing operating costs are eligible for transition cost
recovery, (2) the portion of the facility's sunk costs and ongoing operating
costs, which are not recovered through ISO or PX revenues, are eligible for
transition cost recovery, (3) differences between authorized and actual
revenues for the facility will be included in the transition cost recovery
mechanism, and (4) the facility may participate in the PX.
In December 1997, the CPUC adopted a cost-of-service based ratemaking
mechanism for determining Pacific Gas and Electric Company's revenue
requirement for its hydroelectric and geothermal generation facilities. Under
this mechanism, the revenue requirements for these facilities (including the
Helms pumped storage facility) will be calculated as the sum of the capital-
related revenue requirement (based on recorded capital costs), the expense
revenue requirement (based on the current General Rate Case adopted expenses),
and actual fuel expenses. A reduced rate of return on common equity of 6.77%
will apply to these facilities. This alternative revenue requirement mechanism
will be in place through 2001, unless the CPUC determines otherwise.
Additional information concerning Pacific Gas and Electric Company's
transition cost recovery plan, and the financial impact of electric industry
restructuring is provided in "Management's Discussion and Analysis of
10
Consolidated Results of Operations and Financial Condition" in the 1997 Annual
Report to Shareholders, beginning on page 20, and in Note 2 of the "Notes to
Consolidated Financial Statements" beginning on page 43 of the 1997 Annual
Report to Shareholders.
GAS RATEMAKING
As noted above (see "Competition and the Changing Regulatory Environment--
Gas Industry"), the CPUC approved the Gas Accord in 1997. Additional
information concerning the potential financial impact of the Gas Accord is
provided in "Management's Discussion and Analysis of Consolidated Results of
Operations and Financial Condition" in the 1997 Annual Report to Shareholders,
beginning on page 24, and in Note 3 of the "Notes to Consolidated Financial
Statements" beginning on page 46 of the 1997 Annual Report to Shareholders.
As part of the Gas Accord, the CPUC's traditional reasonableness reviews of
Pacific Gas and Electric Company's core gas costs have been be replaced with a
CPIM (which is also discussed above in "Competition and the Changing
Regulatory Environment-Gas Industry") for the period June 1, 1994, through
2002.
The Biennial Cost Allocation Proceeding (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 1997, the CPUC also authorized Pacific Gas and Electric Company to set
its natural gas rates for core customers each month rather than annually.
Because Pacific Gas and Electric Company's gas costs are passed through to
customers, this change will better align customer prices with actual gas
costs.
1998 REVENUES
Under frozen rates, any change in Pacific Gas and Electric Company's
electric revenue requirements resulting from the items discussed below will
not change electric customer rates. Decreases in electric revenue requirements
will increase revenue from frozen rates available for collection from
customers as the competition transition charge (CTC) for recovery of
transition costs. Conversely, increases in electric revenue requirements will
decrease revenue from frozen rates available for collection from customers as
CTC for recovery of transition costs.
AB 1890-Electric Base Revenue Increase. AB 1890 provides for an increase in
Pacific Gas and Electric Company's electric base revenues for 1997 and 1998,
for enhancement of transmission and distribution system safety and
reliability. In January 1998, the CPUC authorized a 1998 base revenue increase
of $86 million in addition to the 1997 authorized base revenue increase of
$164 million.
Recovery of Transition Costs. In June 1997, the CPUC issued a decision
adopting CTC ratemaking and accounting mechanisms to enable the utilities to
measure their transition costs and track the recovery of transition costs.
Revenues collected under frozen electric rates will be allocated to
distribution, transmission, and generation services and PPPs based upon their
respective cost-of-service, and to nuclear decommissioning, rate reduction
bond debt service (for residential and small commercial customers), and
transition cost recovery at levels authorized by the CPUC.
Elimination of ECAC and ERAM. Effective January 1, 1998, the ECAC and ERAM
balancing accounts were eliminated and the December 31, 1997, balances in
these accounts were transferred to the Interim Transition Cost Balancing
Account (ITCBA). The ECAC was undercollected by $468 million, and the ERAM was
overcollected by $309 million. On January 1, 1998, the ITCBA balance of $160
million undercollection was transferred to the Transition Cost Balancing
Account (TCBA). Until direct access begins, fuel and fuel-related costs which
would otherwise have been included in an ECAC adjustment will be recorded in a
memorandum account to be later transferred to the ITCBA. Costs recorded in the
ITCBA are subject to a subsequent
11
reasonableness review, in which the CPUC determines whether those costs were
reasonably incurred. Costs found to be unreasonable may be disallowed, or
deducted, from the amount to be recovered in rates. When direct access begins,
costs will be recovered from the market price, the TCBA, the Transition
Revenue Account (TRA), or any other cost recovery mechanism approved by the
CPUC.
Cost of Capital. The CPUC's decision in the 1998 Cost of Capital proceeding
authorized a utility return on common equity of 11.20%, a decrease from the
1997 level of 11.60%. The decision authorizes a utility capital structure for
Pacific Gas and Electric Company of 48.00% common equity, 5.80% preferred
stock, and 46.20% long-term debt. The combined authorized costs of debt,
preferred stock, and the 11.20% return on common equity result in an overall
return on utility rate base of 9.17%, a decrease from the 9.45% authorized for
1997. Since (i) the CPUC separately reduced the rate of return on Pacific Gas
and Electric Company generation-related
assets including Diablo Canyon, (ii) the FERC will authorize the rate of
return for electric transmission assets at a later date, and (iii)
transmission and storage rates have been set in the Gas Accord, the reduced
rate of return of 11.20% adopted in the 1998 Cost of Capital Proceeding only
applies to Pacific Gas and Electric Company's electric and gas distribution
assets. The authorized cost of capital will decrease 1998 authorized electric
and gas revenue by $25 million and $9 million, respectively. Pacific Gas and
Electric Company has requested a rehearing of this decision.
BCAP. In 1997, Pacific Gas and Electric Company filed its 1998 BCAP
application. The Company is requesting an overall annual revenue requirement
for the two-year BCAP period of approximately $1.5 billion of which
approximately $107 million will be allocated for the collection of balancing
accounts. The current annual revenue requirement is approximately $1.8 billion
of which approximately $303 million has been allocated for the collection of
balancing accounts. No rate changes resulting from the BCAP are expected to be
implemented before August 1, 1998.
AEAP. The 1997 Annual Earnings Assessment Proceeding (AEAP), which
determines shareholder incentives earned for Pacific Gas and Electric
Company's demand side management (DSM) programs, was submitted in December
1997. All of the parties to the proceeding agree that Pacific Gas and Electric
Company is entitled to an incentive payment of approximately $32 million for
Pacific Gas and Electric Company's 1996 DSM programs, to be collected in
installments over a 10-year period. After consolidating the adjusted incentive
payment installments from prior years, the net revenue change in 1998 from DSM
shareholder incentives should be an electric decrease of approximately $4
million and a gas decrease of approximately $2 million. A CPUC decision
adopting the shareholder incentives is expected during the first quarter of
1998.
Electric Transmission Revenues. Prior to 1998, most electric transmission
revenues were authorized by the CPUC as part of the GRC. In 1998, electric
transmission revenues are expected to be authorized by the FERC. In 1997,
Pacific Gas and Electric Company filed an application with the FERC requesting
electric transmission revenues of $305 million. This requested revenue
requirement is comparable to electric transmission revenues in CPUC-authorized
1997 electric rates.
CAPITAL REQUIREMENTS AND FINANCING PROGRAMS
PG&E Corporation and Pacific Gas and Electric Company continue to require
capital for improvements to facilities to enhance their efficiency and
reliability, to extend their useful lives, and to comply with environmental
laws and regulations. PG&E Corporation's expenditures for these purposes,
including the allowance for funds used during construction (AFUDC), were
approximately $1,829 million for 1997. New investments totaled $41 million in
1997.
The following table sets forth PG&E Corporation's estimated total capital
requirements, consisting of capital expenditures for Pacific Gas and Electric
Company's utility functions, including Diablo Canyon, as well as capital
requirements for PG&E Corporation's other lines of business, and amounts for
maturing debt and sinking funds for the years 1998 through 2000. These are
forward-looking statements which involve a number of assumptions and
uncertainties. Actual amounts may differ materially from the estimated amounts
shown below.
12
PG&E CORPORATION CAPITAL REQUIREMENTS
(IN MILLIONS)
1998 1999 2000
------ ------ ------
Utility Capital Requirements (1).......................... $1,835 $1,739 $1,617
Other Capital Requirements (2)............................ 2,091 246 192
Maturing Debt and Sinking Funds........................... 784 559 740
------ ------ ------
Total Capital Requirements............................ $4,710 $2,544 $2,549
====== ====== ======
- --------
(1) Utility expenditures including Pacific Gas and Electric Company's electric
and gas operations, are shown net of reimbursed capital, and include
AFUDC.
(2) Other expenditures include those of PG&E GT, PG&E ES, PG&E ET, and USGen.
In August 1997, PG&E Corporation announced plans to acquire, through
USGen, a portfolio of electric generating assets and power supply
contracts from the New England Electric System for $1.59 billion.
Including fuel and other inventories and transaction costs, financing
requirements are expected to total approximately $1.75 billion, which
amount is included in the table above.
Most of the capital expenditures for Pacific Gas and Electric Company for
1998 through 2000 are associated with short lead time, capital expenditure
projects aimed at the replacement and enhancement of existing facilities, and
compliance with environmental laws and regulations. Also included are
expenditures to improve the safety and reliability of Pacific Gas and Electric
Company's electric transmission and distribution system consistent with AB
1890, as well as major projects associated with customer service improvements.
PG&E Corporation estimates that its total capital requirements for the years
1998 through 2000 will include approximately $2 billion for payment at
maturity of outstanding long-term debt and for meeting sinking fund
requirements for debt, as indicated above.
The funds necessary for 1998-2000 capital requirements of PG&E Corporation
and its subsidiaries will be obtained from (i) internal sources, principally
net income before noncash charges for depreciation and deferred income taxes,
and (ii) external sources, including short-term financing, such as bank loans
and the sale of short-term notes, and long-term financing, such as sales of
equity and long-term debt securities, when and as required.
PG&E Corporation and its subsidiaries and affiliates conduct a continuing
review of their capital expenditures and financing programs. The programs and
estimates above are subject to revision and actual amounts may vary based upon
changes in assumptions as to system load growth, rates of inflation, receipt
of adequate and timely rate relief, availability and timing of regulatory
approvals, total cost of major projects, availability and cost of suitable
nonregulated investments, and availability and cost of external sources of
capital, as well as the outcome of the ongoing restructuring in both the
electric and gas industries.
In January 1997, PG&E Corporation acquired Teco and its subsidiaries for
approximately $378 million, consisting of the purchase of a $61 million note,
and $317 million of PG&E Corporation common stock. On July 31, 1997, PG&E
Corporation acquired Valero's natural gas and natural gas liquids business. In
the Valero acquisition, approximately 31 million shares of PG&E Corporation
common stock were issued and approximately $780 million in long term debt was
assumed.
PRICE RISK MANAGEMENT PROGRAMS
PG&E Corporation established an officer-level price risk management
committee, and adopted a price risk management policy approved by the PG&E
Corporation Board of Directors, for trading and risk management activities.
The price risk management committee oversees implementation of the policy,
approves the trading and price risk management policies of subsidiaries, and
monitors compliance with the policy.
13
The price 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 create liquidity, and maintain a market presence.
Such derivatives include forward contracts, futures, swaps, and options. The
price 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.
In 1997, PG&E Corporation approved and implemented trading and risk
management policies for PG&E ET, and continued to seek approval from the CPUC
to manage commodity price risks in Pacific Gas and Electric Company's
business.
The fair value of the market risk sensitive instruments (which includes the
hedging and non-hedging instruments described above) as of December 31, 1997,
is immaterial for financial instruments subject to commodity price risk.
Additionally, as of December 31, 1997, PG&E Corporation calculated value-at-
risk based on a 95 percent confidence level using five-day holding periods.
Using this methodology, the potential for near-term losses in future earnings,
fair values, and cash flows from reasonably possible near-term changes in
market prices for financial instruments subject to commodity price risk is
immaterial.
PG&E Corporation anticipates an increase in the level of trading and risk
management activity in 1998 due to expected growth in its national energy
businesses and a continuing effort to manage anticipated price risks in
Pacific Gas and Electric Company's business. Pacific Gas and Electric Company
manages price risk independently from the activities of PG&E Corporation's
other subsidiaries.
14
ELECTRIC UTILITY OPERATIONS
ELECTRIC INDUSTRY RESTRUCTURING LEGISLATION
In 1997, the relevant regulatory authorities took steps to implement AB
1890, including establishing the ISO and PX, and implementing direct access.
AB 1890 also provides for the financing of the 10 percent rate reduction
through rate reduction bonds, recovery of transition costs, and the funding of
public purpose programs.
INDEPENDENT SYSTEM OPERATOR AND POWER EXCHANGE
AB 1890 requires the CPUC to facilitate the development of an ISO and a PX,
and establishes a five-member Oversight Board to oversee the ISO and PX and
appoint the members of the ISO and PX Governing Boards. In May 1997, the ISO
and PX were formed as California non-profit corporations. The ISO and PX
Governing Boards include 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. In March 1997, the trustee for the development of the ISO and
PX, filed the documents with FERC that explained the structure, rates, terms
and conditions applicable to the new market structure. While those documents
have been subsequently revised and clarified in more recent filings by the
duly constituted governing boards of the ISO and PX, on October 30, 1997, the
FERC granted conditional authority for the ISO to begin operations and for the
PX to charge market-based rates for electricity.
Under AB 1890, it is intended that both California's investor-owned
utilities and its publicly owned utilities relinquish control, but not
ownership, of their transmission facilities to the ISO. 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 responsibility for reliability of utility distribution
systems remains with the CPUC. In December 1997, the ISO announced a delay of
its operations and its formal assumption of control of the utilities'
transmission systems. The PX also announced a delay in the commencement of its
operations. Both the ISO and the PX announced that they expected to begin
operations by March 31, 1998, at which time direct access will begin. The FERC
requires that it be given at least 15 days notice before ISO and PX operations
commence.
VOLUNTARY GENERATION ASSET DIVESTITURE
In 1997, California utilities produced a significant portion of the state's
electric generation needs. In a competitive market, the CPUC is concerned that
this level of generation may give existing utilities undue influence on the PX
price. To alleviate this concern, Pacific Gas and Electric Company has
indicated that it is willing to proceed with voluntary economic divestiture of
at least 98% of its fossil-fueled power plants and all of its geothermal
facilities. In December 1997, the CPUC approved Pacific Gas and Electric
Company's sale of three electric generating plants with a combined capacity of
2,645 megawatts (MW) to Duke Energy Power Services, Inc. (Duke Energy) in
Pacific Gas and Electric Company's first power plant auction. The aggregate
bid was $501 million for these three fossil-fueled plants: the Morro Bay Power
Plant located in San Luis Obispo County, the Moss Landing Power Plant located
in Monterey County, and the Oakland Power Plant located in Alameda County. The
combined book value for these three fossil-fueled plants is approximately $370
million as of December 31, 1997. Pacific Gas and Electric Company will retain
liability for required environmental remediation of any preclosing soil or
groundwater contamination at these plants. Subject to various conditions,
including regulatory approval of the transfer of various permits and licenses,
and the commencement of direct access, Pacific Gas and Electric Company
expects the sale to close in 1998.
In 1997 Pacific Gas and Electric Company announced plans to conduct the
second auction of four of its five remaining fossil-fueled power plants (the
Hunters Point and Potrero Power Plants, both located in San Francisco County,
and the Contra Costa and Pittsburg Power Plants, both located in Contra Costa
County) and all of its geothermal facilities (The Geysers located in Lake and
Sonoma counties) in 1998, subject to CPUC approval. These
15
plants have a combined generating capacity of 4,718 MW and a combined book
value at December 31, 1997 of approximately $790 million. In January 1998,
Pacific Gas and Electric Company filed its application to seek CPUC approval
for the sale of these plants. In its application, Pacific Gas and Electric
Company indicated that the auction for these plants would begin on March 16,
1998.
Together, the eight power plants represent 98% of Pacific Gas and Electric
Company's fossil-fueled generating capacity and all of its geothermal
generating capacity. The facilities generate approximately 22% of Pacific Gas
and Electric Company's total electric energy sold to customers. Pacific Gas
and Electric Company is evaluating its options related to its remaining
generation facilities and may decide not to retain its economic investments in
those facilities. Any gain from the sale of power plants would be used to
offset Pacific Gas and Electric Company's transition costs.
As required by the California electric industry restructuring legislation,
Pacific Gas and Electric Company employees will continue to operate and
maintain the power plants that are sold under a two-year operations and
maintenance agreement with the new owner. To the extent that payments to
Pacific Gas and Electric Company under these agreements exceed the Company's
cost of operating the plants, the Company would offset other transition costs.
Conversely, to the extent Pacific Gas and Electric Company's operating costs
exceed the revenues from these agreements, the Company would have lower
earnings.
DIRECT ACCESS
AB 1890 authorizes direct transactions between electricity suppliers and
customers, beginning January 1, 1998. As described above, direct access has
been delayed due to the delay in the start of operations of the ISO and PX.
The ISO and PX expect to commence operations by March 31, 1998.
In May 1997, the CPUC issued a decision which authorizes full implementation
of direct access for all electric customers. In October 1997, the CPUC
approved implementing tariffs, rate schedules, and service agreements.
Customers participating in direct access would 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 begins. As of February 19, 1998 Pacific Gas and Electric
Company had accepted over 11,781 direct access requests. 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.) The customer will be
responsible for the cost of the meter and the meter installation.
Also in May 1997, the CPUC issued a decision addressing the separation, or
unbundling, of utility revenue cycle services, which include metering and
billing. Under this decision, when direct access begins, energy service
providers supplying the direct access market will be able to choose one of
three billing options: (1) consolidated energy supplier billing, under which
the utility would bill the energy supplier for the services provided directly
by the utility to the customer and the supplier, in turn, would provide a
consolidated bill to the customer; (2) Consolidated distribution company
billing, under which the utility would place the supplier's energy charge on a
distribution bill; or (3) dual billing, under which the energy supplier and
the utility would bill separately for their own services. In December 1997,
the CPUC adopted procedures and standards for non-utility performance of
unbundled metering and meter data management services. Beginning January 1,
1998, energy service providers have been allowed to provide metering services
to their customers with a demand greater than 20 kW, and beginning January 1,
1999, energy service providers may provide metering to all of their customers.
16
RATE LEVELS AND RATE REDUCTION BONDS
To achieve the 10% rate reduction for residential and eligible small
commercial customers, effective January 1, 1998, AB 1890 authorized utilities
to finance a portion of their transition costs with "rate reduction bonds." On
December 8, 1997, a special purpose entity established by the California
Infrastructure and Economic Development Bank issued $2.9 billion of rate
reduction bonds on behalf of a wholly owned subsidiary of Pacific Gas and
Electric Company. The bonds were issued in eight classes with maturities
ranging from ten months to ten years, and bearing interest at rates ranging
from 5.94% to 6.48%. Pacific Gas and Electric Company will collect a separate
nonbypassable charge on behalf of the bondholders to recover principal,
interest, and related costs over the life of the bonds from residential and
small commercial customers. The bond proceeds were used by the wholly owned
subsidiary to purchase from Pacific Gas and Electric Company 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 Pacific Gas and Electric
Company's assets. While the bonds are reflected as long-term debt on Pacific
Gas and Electric Company's balance sheet, creditors of Pacific Gas and
Electric Company do not have any recourse to the revenues from the separate
charge.
Various consumer groups filed a voter initiative with the California
Attorney General which seeks among other things, to (i) require investor-owned
California utilities to provide an additional 10% rate reduction to
residential and small commercial customers; (ii) eliminate transition cost
recovery for nuclear investments by utilities (other than reasonable
decommissioning costs); (iii) restrict transition cost recovery for non-
nuclear investments (other than costs associated with QFs), unless the CPUC
finds that the utility would be deprived of the opportunity to earn a fair
rate of return; (iv) and prohibit the collection of any customer charges for
rate reduction bonds, or alternatively, require the utility to offset such
charges with an equal credit to customers. In February 1998, the California
Secretary of State released the title and summary prepared for the proposed
initiative by the California Attorney General's office. The sponsors of the
initiative are now seeking sufficient signatures to qualify the initiative for
the November 1998, statewide ballot. If the proposed initiative were voted
into law, costly and time-consuming litigation may ensue. The Company believes
that under applicable federal and state constitutional principles relating to
the impairment of contracts, the State of California through such an
initiative, could not repeal or amend the Company's authorization to collect
principal, interest, and related costs for the rate reduction bonds if such
repeal or amendment would substantially impair the rights of the bondholders.
RECOVERY OF TRANSITION COSTS
AB 1890 authorizes utilities to recover their transition costs--the
utilities' costs of their generation-related assets and obligations which
prove to be uneconomic in the new competitive framework. Costs eligible for
recovery as transition costs, as determined by the CPUC, include (1) above-
market sunk costs (sunk costs are costs associated with utility generating
facilities that are fixed and unavoidable and currently included in customer
rates), 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. Further, nuclear
decommissioning costs are being recovered through a separate CPUC-authorized
charge. Most transition costs must be recovered by March 31, 2002, although
certain transition costs may be recovered after March 31, 2002. These costs
include certain employee-related transition costs, costs
17
that are unrecovered as result of the implementation of direct access and
creation of the PX and ISO, and above-market costs associated with power-
purchase agreements. In addition, costs financed by the issuance of rate
reduction bonds are expected to be recovered over the term of the bonds.
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 or sale must be completed by
December 31, 2001. In 1997, the value of three of Pacific Gas and Electric
Company's electric facilities was established through the auction process.
Pacific Gas and Electric Company has also announced plans to conduct the
second auction of four of its five remaining fossil-fueled power plants and
its geothermal facilities in 1998, subject to CPUC approval.
In September 1997, the CPUC adopted a decision addressing transition cost
recovery for capital additions to Pacific Gas and Electric Company's non-
nuclear generating facilities. The decision allows Pacific Gas and Electric
Company to recover costs of capital additions made in 1996 and 1997 (and in
1998 for fossil-fueled plants completely divested by March 31, 1998) based
upon an after-the-fact reasonableness review. All capital additions found
reasonable by the CPUC through this process will be recoverable as transition
costs. Capital additions made in 1998 and thereafter to non-nuclear
generation-related assets and capital additions made to fossil-fueled
generating assets which are not completely divested by March 31, 1998, must be
recovered either through revenues from the ISO agreements for "must-run"
plants or from sales of electricity to the PX. The CPUC decision allows
Pacific Gas and Electric Company to seek an after-the-fact reasonableness
review of post 1997 capital addition expenditures for collection as transition
costs in certain limited circumstances.
In November and December 1997, the CPUC issued two decisions confirming the
eligibility of Pacific Gas and Electric Company's various categories of non-
nuclear generation-related costs for accelerated recovery as transition costs
and adopting tariffs associated with enforcement of the nonbypassable CTC. The
CPUC reduced the authorized rate of return on common equity to 6.77% for all
Pacific Gas and Electric Company's non-nuclear generation-related assets,
including hydroelectric and geothermal facilities, for a total rate of return
of 7.13% for these assets. The reduced rate of return was retroactive to July
28, 1997, and will be effective for the duration of the transition period.
The CPUC has ordered the utilities to file applications by June 1, 1998, to
request recovery of transition costs in 1999. The annual transition cost
proceeding will be used to develop a record to establish the guidelines for
computing the transition costs on an ongoing basis and a mechanism for
tracking the amount of transition costs and revenues recovered each year for
the nuclear facilities based on actual recorded data. This proceeding will
establish the reasonableness of accelerating recovery of transition costs and
of estimating the market value of the assets subject to market valuation, and
review actual employee transition costs, review all costs and revenues related
to the PX and ISO revenues, and transition cost balancing account entries. In
February 1998, Pacific Gas and Electric Company, along with the other
California utilities, requested that the June 1, 1998, filing date be
postponed to September 1, 1998, to reflect the delay of the commencement of
direct access.
PUBLIC PURPOSE PROGRAMS
On January 1, 1998, and continuing through December 31, 2001, energy
efficiency, research and development, and low-income programs are being funded
through a separate nonbypassable charge included in frozen electric rates, in
compliance with AB 1890. Low-income 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, Pacific Gas and Electric Company 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
technologies at not less than $48 million per year, low-income energy
efficiency programs at not less than $14 million per year, and the low-income
rate discount program at approximately $38 million per year.
In February 1997, the CPUC adopted a decision that turns over administration
of the funding for public interest research and development, and renewable
technologies programs to the CEC, beginning January 1, 1998.
18
The decision also changed the way some programs are administered. Before 1998,
Pacific Gas and Electric Company and other utilities administered public
purpose programs for energy efficiency and conservation, and low-income
customer assistance. Under the CPUC's decision, the CPUC will appoint
independent boards to oversee energy efficiency and low-income assistance
programs. These boards will solicit competitive bids to determine who will
administer the programs from January 1, 1998, through 2001. In December 1997,
the CPUC approved Pacific Gas and Electric Company's continuing to act as
interim administrator of energy efficiency programs until October 1, 1998.
Thereafter, an open-bidding process is expected to be completed to select
energy efficiency program administrators.
Additional information concerning AB 1890 and its financial impact on PG&E
Corporation is provided in "Management's Discussion and Analysis of
Consolidated Results of Operations and Financial Condition" in the 1997 Annual
Report to Shareholders, beginning on page 20, and in Note 2 of the "Notes to
Consolidated Financial Statements" beginning on page 43 of the 1997 Annual
Report to Shareholders.
19
ELECTRIC OPERATING STATISTICS
The following table shows Pacific Gas and Electric Company's operating
statistics (excluding subsidiaries except where indicated) for electric
energy, including the classification of sales and revenues by type of service.
YEARS ENDED DECEMBER 31
---------------------------------------------------------
1997 1996 1995 1994 1993
---------- ---------- ---------- ---------- ----------
CUSTOMERS (AVERAGE FOR
THE YEAR):
Residential............ 3,915,370 3,874,223 3,825,413 3,788,044 3,748,831
Commercial............. 465,461 459,001 454,718 452,049 449,619
Industrial............. 1,121 1,248 1,253 1,260 1,243
Agricultural........... 86,359 87,250 88,546 90,520 91,376
Public street and
highway lighting...... 17,955 17,583 17,089 16,709 16,096
Other electric
utilities............. 47 28 35 29 28
---------- ---------- ---------- ---------- ----------
Total............... 4,486,313 4,439,333 4,387,054 4,348,611 4,307,193
========== ========== ========== ========== ==========
GENERATED, RECEIVED AND
SOLD--KWH (IN
MILLIONS):
Generated:
Hydroelectric plants.. 13,549 15,158 16,608 7,791 14,403
Thermal-electric
plants:
Fossil fueled........ 14,655 11,620 13,729 29,543 19,070
Geothermal........... 4,829 4,514 4,001 6,024 6,491
Nuclear.............. 17,071 16,720 16,269 15,265 16,816
---------- ---------- ---------- ---------- ----------
Total thermal-
electric plants.... 36,555 32,854 33,999 50,832 42,377
Wind and solar plants. 1 2 1 1 --
Received from other
sources: (1).......... 55,745 57,134 54,935 47,199 48,859
---------- ---------- ---------- ---------- ----------
Total gross system
output(2).......... 105,850 105,148 105,543 105,823 105,639
Less:
Delivered for
interchange or
exchange.............. 3,000 4,000 4,261 3,275 8,848
Delivered for the
account of others(1).. 16,611 19,356 18,946 18,622 13,726
Helms pumpback
energy(3)............. 661 898 937 467 452
Company use, losses,
etc.(4)............... 6,200 6,500 6,040 7,838 6,960
---------- ---------- ---------- ---------- ----------
Total energy sold... 79,378 74,394 75,359 75,621 75,653
========== ========== ========== ========== ==========
POWER PLANT FUEL SUPPLY
(IN THOUSANDS):
Natural gas (equivalent
barrels).............. 23,983 20,193 23,143 44,119 28,791
Fuel oil............... 0 686 756 2,395 2,080
Nuclear (equivalent
barrels).............. 29,152 28,574 27,814 26,135 28,724
---------- ---------- ---------- ---------- ----------
Total............... 53,135 49,453 51,713 72,649 59,595
========== ========== ========== ========== ==========
POWER PLANT FUEL COSTS
(AVERAGE COST PER
MILLION BTU'S):
Natural gas............ $ 2.87 $ 1.83 $ 2.06 $ 2.19 $ 2.86
Fuel oil............... $ 0 $ 2.66 $ 1.28 $ 2.83 $ 3.49
Weighted average....... $ 2.87 $ 1.92 $ 2.03 $ 2.23 $ 2.90
SALES--KWH (IN
MILLIONS):
Residential............ 25,946 25,458 24,391 24,326 24,111
Commercial............. 28,887 27,868 27,014 26,195 26,258
Industrial............. 16,876 15,786 16,879 16,010 16,492
Agricultural........... 3,932 3,631 3,478 4,426 3,672
Public street and
highway lighting...... 446 438 425 418 419
Other electric
utilities............. 3,291 1,213 3,172 4,246 4,701
---------- ---------- ---------- ---------- ----------
Total energy sold... 79,378 74,394 75,359 75,621 75,653
========== ========== ========== ========== ==========
REVENUES (IN THOUSANDS):
Residential............ $3,082,013 $3,033,613 $2,979,590 $2,980,966 $2,952,893
Commercial............. 2,932,560 2,840,101 2,964,568 2,892,302 2,914,855
Industrial............. 1,028,378 1,005,694 1,160,938 1,128,561 1,183,728
Agricultural........... 413,711 396,469 395,531 477,330 419,628
Public street and
highway lighting...... 53,183 55,372 56,154 55,545 55,976
Other electric
utilities............. 118,781 81,855 133,566 201,133 242,433
---------- ---------- ---------- ---------- ----------
Revenues from energy
sales.............. 7,628,626 7,413,104 7,690,347 7,735,837 7,769,513
Miscellaneous.......... (9,439) 112,303 92,538 142,771 87,991
Regulatory balancing
accounts.............. 71,441 (365,192) (396,578) 142,939 19,421
---------- ---------- ---------- ---------- ----------
Operating revenues.. $7,690,628 $7,160,215 $7,386,307 $8,021,547 $7,876,925
========== ========== ========== ========== ==========
- --------
(1) Includes energy supplied through Pacific Gas and Electric Company's system
by the City and County of San Francisco for San Francisco's own use and
for sale by San Francisco to its customers, by the Department of Energy
for government use and sale to its customers, and by the State of
California for California Water Project pumping, as well as energy
supplied by QFs and purchases from other utilities.
(2) Includes energy output from Modesto and Turlock Irrigation Districts' own
resources.
(3) Represents energy required for pumping operations.
(4) Includes use by business units other than the electric utility business
units.
20
YEARS ENDED DECEMBER 31
-------------------------------------------------
1997 1996 1995 1994 1993
--------- --------- --------- --------- ---------
SELECTED STATISTICS:
Total customers (at year-
end)........................ 4,500,000 4,500,000 4,400,000 4,400,000 4,400,000
Average annual residential
usage (kWh)................. 6,627 6,571 6,377 6,422 6,431
Average billed revenues per
kWh (c):
Residential................. 11.88 11.92 12.22 12.25 12.25
Commercial.................. 10.15 10.19 10.97 11.04 11.10
Industrial.................. 6.09 6.37 6.88 7.05 7.18
Agricultural................ 10.52 10.92 11.37 10.78 11.43
Net plant investment per
customer ($)................ 3,027 3,198 3,228 3,362 3,436
Electric control area
capability(megawatts)(1).... 23,157 22,724 22,099 21,851 23,009
Electric net control area
peak demand(megawatts)(2)... 21,862 21,437 20,317 19,118 19,607
- --------
(1) Area net capability at time of annual peak, based on actual water
conditions.
(2) Net control area peak demand includes demand served by Modesto and Turlock
Irrigation Districts' own resources.
21
ELECTRIC GENERATING AND TRANSMISSION CAPACITY
As described above in "Electric Industry Restructuring Legislation--
Voluntary Generation Asset Divestiture," in 1997, Pacific Gas and Electric
Company entered into an agreement for the sale of three fossil-fueled power
plants and announced plans to sell an additional four fossil-fueled power
plants and its geothermal facilities. As of December 31, 1997, Pacific Gas and
Electric Company owned and operated the following generating plants, all
located in California, listed by energy source:
NET
OPERATING
NUMBER CAPACITY
GENERATION TYPE COUNTY LOCATION OF UNITS KW
--------------- --------------- -------- ----------
Hydroelectric:
Conventional Plants....... 16 counties in Northern and 109 2,698,100
Central California
Helms Pumped Storage
Plant.................... Fresno 3 1,212,000
--- ----------
Hydroelectric Subtotal.. 112 3,910,100
--- ----------
Steam Plants:
Contra Costa(1)........... Contra Costa 2 680,000
Humboldt Bay.............. Humboldt 2 105,000
Hunters Point(1).......... San Francisco 3 377,000
Morro Bay(2).............. San Luis Obispo 4 1,002,000
Moss Landing(2)........... Monterey 2 1,478,000
Pittsburg(1).............. Contra Costa 7 2,022,000
Potrero(1)................ San Francisco 1 207,000
--- ----------
Steam Subtotal............ 21 5,871,000
--- ----------
Combustion Turbines:
Hunters Point(1).......... San Francisco 1 52,000
Oakland(2)................ Alameda 3 165,000
Potrero(1)................ San Francisco 3 156,000
Mobile Turbines(3)........ Humboldt and Mendocino 3 45,000
--- ----------
Combustion Turbines
Subtotal................. 10 418,000
--- ----------
Geothermal:
The Geysers Power
Plant(1)(4).............. Sonoma and Lake 14 1,224,000
Nuclear:
Diablo Canyon............. San Luis Obispo 2 2,160,000
--- ----------
Thermal Subtotal........ 47 9,673,000
--- ----------
Total.............................................. 159 13,583,100
=== ==========
- --------
(1) In 1997, Pacific Gas and Electric Company announced plans to sell these
power plants and its geothermal facilities in connection with electric
industry restructuring.
(2) In 1997, Pacific Gas and Electric Company entered into an agreement to
sell these power plants in connection with electric industry
restructuring.
(3) Listed to show capability; subject to relocation within the system as
required.
(4) The Geysers Power Plant net operating capacity is based on adequate
geothermal steam supply conditions. Any decrease in capacity, at peak, is
included as unavailable capacity in the control area net capacity table
below.
22
The following table sets forth the available capacity for the control area
(the area served by Pacific Gas and Electric Company and various publicly
owned systems in Northern California) at the date of peak (including reduction
for scheduled and forced outages and based on actual water conditions) by
various sources of generation available to the control area and the total
amount of generation provided by these sources during the year ended December
31, 1997.
CONTROL AREA
NET CAPACITY
(AT DATE OF 1997 PEAK)
----------------------
KW %
-------------- ----------
Sources of
Electric
Generation:
Company-Owned
Plants:
Fossil Fueled.... 6,289,000 48
Geothermal....... 1,224,000 9
Nuclear.......... 2,160,000 17
-------------- -------
Total Thermal... 9,673,000 74
Hydroelectric
(available)..... 3,326,000 26
Solar............ 0 0
-------------- -------
Total Company-
Owned Capacity.. 12,999,000 100
============== =======
Less Unavailable
Capacity........ (1,906,200)
--------------
Total Company
Available
Capacity........ 11,092,800 48
Capacity Received
from Others:
QF Producers
(available)..... 2,948,800 13
Area Producers &
Imports......... 9,115,400 39
-------------- -------
Capacity from
Others.......... 12,064,200 52
-------------- -------
Total Available
Capacity........ 23,157,000 100
============== =======
Total Area
Demand(1)(2)..... 21,862,000
==============
GENERATION
YEAR ENDED
DECEMBER 31, 1997(3)
--------------------
KWH
THOUSANDS %
-------------- ------
Electric
Generation:
Company-Owned
Plants:
Fossil Fueled.... 14,654,952 14
Geothermal....... 4,829,743 5
Nuclear.......... 17,070,798 17
-------------- ------
Total Thermal... 36,555,493 36
Hydroelectric.... 13,549,123 13
Solar............ 1,164 0
-------------- ------
Total Company
Generation...... 50,105,780 49
Helms Pumpback
Energy.......... (661) 0
-------------- ------
Net Company
Generation...... 50,105,119 49
============== ======
Generation
Received from
Others:
QF Producers..... 19,700,000 19
Area Producers &
Imports......... 33,194,881 32
-------------- ------
Generation from
Others......... 52,894,881 51
============== ======
Total Area
Generation...... 103,000,000 100
============== ======
- --------
(1) The maximum control area peak demand to date was 21,862,000 kW which
occurred in August 1997.
(2) The reserve capacity margin at the time of the 1996 control area peak,
taking into account short-term firm capacity purchases from utilities
located outside Pacific Gas and Electric Company's service area: Pacific
Gas and Electric Company's load responsibility for spinning reserve
(capability already connected to the system and ready to meet
instantaneous changes in demand) to the control area peak was 6.4% of the
peak demand and total reserve (spinning reserve and capability available
within a short period of time) was 7.4%.
(3) Represents actual year net generation from sources shown. Generation
received from others is based on the best available information at the
publication date of this document.
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, 1997, Diablo Canyon Units 1 and 2 had achieved lifetime
capacity factors of 80.3% and 82.7%, respectively.
The table below outlines Diablo Canyon's refueling schedule for the next
five years. In the past, Diablo Canyon refueling outages typically have
occurred every 18 months. Beginning in 1996, Pacific Gas and Electric Company
schedules refueling outages every 20 to 21 months, and it has been seeking NRC
licensing authority to schedule such outages once every 24 months beginning in
2001. Though nominal 20-month cycles are firm, achieving a 24-month cycle is
uncertain and its implementation could be delayed. The schedule below assumes
23
that a refueling outage for a unit will last approximately six weeks,
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 or
changes in the length of the fuel cycle.
1998 1999 2000 2001 2002
-------- --------- --------- ----- -----
Unit 1
Refueling............................. January September March
Startup............................... March November May
Unit 2
Refueling............................. February September April
Startup............................... March November May
DIABLO CANYON RATEMAKING
Prior to 1997, ratemaking for Diablo Canyon was determined by basing
revenues primarily on the amount of electricity generated by the plant, rather
than on traditional cost-based ratemaking. Under the prior ratemaking
treatment, revenues were based on a pre-established price per kWh of
electricity generated by the plant. That price consisted of a fixed component
(3.15 cents per kWh) and a separate component that declined until 2000, at
which point the variable component would have begun to escalate. For example,
the total price per kWh for the year 1996 was 10.50 cents. Under this
"performance-based" approach, Pacific Gas and Electric Company assumed a
significant portion of the operating risk of the plant because the extent and
timing of the recovery of actual operating costs, depreciation, and a return
on the investment in the plant primarily depended on the amount of power
produced and the level of costs incurred. Pacific Gas and Electric Company's
earnings were affected directly by plant performance and costs incurred. Under
this ratemaking treatment, earnings relating to Diablo Canyon could fluctuate
significantly as a result of refueling or other extended plant outages, plant
expenses, and the effects of a peak-period pricing mechanism.
In connection with electric industry restructuring, in 1996, Pacific Gas and
Electric Company proposed to price electric generation from Diablo Canyon at
market prices and to complete recovery of its investment in Diablo Canyon by
the end of 2001. Pacific Gas and Electric Company proposed to replace the
Diablo Canyon performance-based ratemaking mechanism described above with: (1)
a sunk cost revenue requirement to recover net investment in plant, including
a return on this net investment, and (2) a performance-based Incremental Cost
Incentive Price (ICIP) mechanism to recover the facility's variable and other
operating costs and capital addition costs. As proposed by Pacific Gas and
Electric Company, the sunk cost revenue requirement would be set to accelerate
recovery of Diablo Canyon sunk costs from a period ending in 2016 to a five-
year period ending in 2001. The related return on common equity associated
with Diablo Canyon sunk costs would be reduced to 90 percent of Pacific Gas
and Electric Company's long-term cost of debt. Pacific Gas and Electric
Company's proposed ICIP mechanism would establish a rate per kWh generated by
the facility. This rate would be based upon a fixed forecast of ongoing costs,
capital additions, and capacity factors for the period 1997 through 2001.
In May 1997, the CPUC issued a decision on Pacific Gas and Electric
Company's proposal with an effective date of January 1, 1997. Under the
decision, Pacific Gas and Electric Company's sunk costs will be recovered
through a sunk cost revenue requirement, at a reduced return on common equity
equal to 90 percent of Pacific Gas and Electric Company's embedded cost of
debt, for a reduced total return of 7.17% which will be effective through
2001. The CPUC decision substantially reduces the level of Pacific Gas and
Electric Company's proposed ICIP pricing through which ongoing operating costs
and capital additions will be recovered.
The CPUC decision adopts a fixed forecast of ICIP for 1997-2001, as shown
below. The revenues are based on an assumed capacity factor of 83.6 percent.
24
INCREMENTAL COST INCENTIVE PRICES AND ESTIMATED
TOTAL CPUC REVENUE REQUIREMENT
ESTIMATED TOTAL REVENUE
REQUIREMENT
----------------------------------
1997 1998 1999 2000 2001
------ ------ ------ ------ ------
($ IN MILLIONS)
ICIP (cents per kWh)...................... 3.26 3.31 3.37 3.43 3.49
Sunk Cost Recovery........................ $1,385 $1,322 $1,259 $1,197 $1,135
ICIP Revenues............................. 515 523 532 542 552
------ ------ ------ ------ ------
Total Revenue Requirement................. $1,900 $1,845 $1,791 $1,739 $1,687
The CPUC decision excluded several items totaling $160 million from the sunk
cost revenue requirement, including out-of-core fuel inventory, materials and
supplies inventory, and prepaid insurance expenses. The CPUC decision requires
that the costs of materials, supplies and nuclear fuel be recovered through
the ICIP mechanism as these items are used. The CPUC also disallowed about $70
million in plant costs from the sunk cost revenue requirement. Pacific Gas and
Electric Company has sought a rehearing of the CPUC decision.
The CPUC decision also 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.
More information concerning the financial impact of Diablo Canyon ratemaking
is included in "Management's Discussion and Analysis of Consolidated Results
of Operations and Financial Condition" in the 1997 Annual Report to
Shareholders, beginning on page 20, and in Note 2 of the "Notes to
Consolidated Financial Statements" beginning on page 43 of the 1997 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 operations forecasts,
Diablo Canyon's requirements for uranium supply, the conversion of uranium to
uranium hexaflouride, and the enrichment of the uranium hexaflouride to
enriched uranium will be satisfied by a combination of existing contracts and
inventories through 2000, 1999, and 2002, respectively. The fuel fabrication
contract for the two units will supply their requirements for the next eight
operating cycles of each unit. These contracts are intended to ensure long-
term fuel supply, but permit Pacific Gas and Electric Company the flexibility
to take advantage of short-term supply opportunities. In most cases, Pacific
Gas and Electric Company's nuclear fuel contracts are requirements-based, with
the Company'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 has signed a contract with the DOE providing for the
disposal of the spent nuclear fuel and high-level radioactive waste from the
Company's nuclear power facilities beginning not later than January 1998.
However, due to delays in identifying a storage site, the DOE has officially
acknowledged that it will not be able 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 2012, at
the earliest. At the projected level of operation for Diablo Canyon, Pacific
Gas and Electric Company'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
25
permanent DOE storage facility will not be available for Diablo Canyon's spent
fuel by 2006. Pacific Gas and Electric Company 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 Pacific Gas and Electric
Company's plan to store radioactive waste from the Humboldt Bay Power Plant
(Humboldt) at Humboldt for 20 to 30 years and, ultimately, to decommission the
unit. The license amendment issued by the NRC allows storage of spent fuel
rods at Humboldt until a federal repository is established. Pacific Gas and
Electric Company has agreed to remove all nuclear waste as soon as possible
after 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). The company, 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 Pacific Gas and Electric Company's policies, if the nuclear
generating facility of a member utility suffers a loss due to a prolonged
accidental outage, the Company may be subject to maximum retrospective premium
assessments of $23 million (property damage) and $7 million (business
interruption), in each case per one-year policy period, if losses exceed the
resources of NEIL.
Pacific Gas and Electric Company has purchased primary insurance of $200
million for public liability claims resulting from a nuclear incident. An
additional $8.7 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, Pacific Gas
and Electric Company may be assessed up to $159 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 $1.4 billion in
1997 dollars ($5.1 billion in future dollars). This estimate, which includes
labor, materials, waste disposal charges, and other costs, is based on a 1997
decommissioning cost study. A contingency to capture engineering, regulatory,
and business environment changes is included in the total estimated
obligation. Actual decommissioning costs are expected to vary from this
estimate because of changes in the assumed dates of decommissioning,
regulatory requirements, and technology, as well as differences in the amount
of labor, materials, and equipment needed to complete decommissioning. The
estimated total obligation needed to complete decommissioning is recognized
proportionately over the license term of each facility.
Nuclear decommissioning costs recovered in rates are placed in external
trust funds. These funds, along with accumulated earnings, will be used
exclusively for decommissioning. The trust funds maintain substantially all of
their investments in debt and equity securities. All earnings on the trust
fund are reinvested. Monies may not be released from the external trust funds
until authorized by the CPUC. As of December 31, 1997, Pacific Gas and
Electric Company had accumulated external trust funds with an estimated fair
value of $1 billion, based on quoted market prices, to be used for the
decommissioning of the Company's nuclear facilities.
In the past, the amount recovered in rates for nuclear decommissioning costs
through an annual allowance has been reviewed 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, 1997, nuclear decommissioning costs recovered in rates were $33
million.
26
In compliance with AB 1890, effective on January 1, 1998, nuclear
decommissioning costs, which are not transition costs, are being recovered
through a nonbypassable charge which will continue until those costs are fully
recovered. Recovery of decommissioning costs may be accelerated to the extent
possible under the rate freeze. In its roadmap decision, the CPUC established
a Nuclear Decommissioning Costs Triennial Proceeding to determine the
decommissioning costs and establish the annual revenue requirement and
attrition factors over 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. The CPUC
established a series of power-purchase contracts and set the applicable terms,
conditions, price options, and eligibility requirements.
Under these contracts, Pacific Gas and Electric Company is required to make
payments only when energy is supplied or when capacity commitments are met.
The total cost of these payments is recoverable in rates. Pacific Gas and
Electric Company's contracts with these power producers expire on various
dates through 2028. Total energy payments are expected to decline in the years
1998 through 2001. Total capacity payments are expected to remain at current
levels during this period. Deliveries from these power producers accounted for
approximately 18% of Pacific Gas and Electric Company's 1997 electric energy
requirements and no single contract accounted for more than 5% of the
Company's energy needs.
Pacific Gas and Electric Company has negotiated early termination or
suspension of certain power-purchase contracts. These amounts are expected to
be recovered in rates and as such are reflected as deferred charges on the
Company's balance sheet. At December 31, 1997, the total discounted future
payments remaining under early termination or suspension contracts is $53
million.
Pacific Gas and Electric Company also has contracts with various irrigation
districts and water agencies to purchase hydroelectric power. Under these
contracts, Pacific Gas and Electric Company must make specified semi-annual
minimum payments whether or not any energy is supplied (subject to the
provider's retention of the FERC's authorization) and variable payments for
operation and maintenance costs are incurred by the providers. These contracts
expire on various dates from 2004 to 2031. The total cost of these payments is
recoverable in rates. At December 31, 1997, the undiscounted future minimum
payments under these contracts are $34 million for each of the years 1998
through 2002 and a total of $349 million for periods thereafter. Irrigation
district and water agency deliveries in the aggregate account for
approximately 4% of Pacific Gas and Electric Company's 1997 electric energy
requirements.
The amount of energy received and the total payments made under all these
power-purchase contracts were:
1997 1996 1995
------ ------ ------
(IN MILLIONS)
Kilowatt-hours received................................ 24,389 26,056 26,468
Energy payments........................................ $1,157 $1,136 $1,140
Capacity payments...................................... $ 538 $ 521 $ 484
Irrigation district and water agency payments.......... $ 56 $ 52 $ 50
As of December 31, 1997, Pacific Gas and Electric Company had commitments to
purchase approximately 5,400 megawatts (MW) of capacity under CPUC-mandated
power-purchase agreements. Of the 5,400 MW, approximately 4,600 MW were
operational. Development of the balance is uncertain and it is estimated that
very few of the remaining contracts will become operational. The 4,600 MW of
operational capacity consists of 2,900 MW from cogeneration projects, 700 MW
from wind projects, and 1,000 MW from other projects, including biomass,
waste-to-energy, geothermal, solar, and hydroelectric.
27
GEOTHERMAL GENERATION
Pacific Gas and Electric Company's geothermal units at The Geysers Power
Plant (Geysers) are forecast to operate at reduced capacities because of
declining geothermal steam supplies and curtailment of the Geysers due to the
existence of more economic sources of electric generation. Pacific Gas and
Electric Company's agreements with several of its steam suppliers permit the
Company to curtail generation at The Geysers at the Company's discretion. The
consolidated Geysers capacity factor is forecast to be approximately 48% of
installed capacity in 1998, which includes economic curtailments, forced
outages, scheduled overhauls, and projected steam shortage curtailments, as
compared to the actual Geysers capacity factor of 45% in 1997.
In connection with electric industry restructuring, in January 1998, Pacific
Gas and Electric Company filed an application with the CPUC seeking approval
to sell The Geysers, subject to CPUC and other regulatory approvals. See
"Electric Utility Operations--Electric Industry Restructuring Legislation--
Voluntary Generation Asset Divestiture" above.
HELMS PUMPED STORAGE PLANT
Helms is a three-unit hydroelectric combined generating and pumped storage
facility, completion of which was delayed due to a water conduit rupture in
September 1982 and various start-up problems related to the plant's
generators. Helms became commercially operable in June 1984. As a result of
the damage caused by the rupture and the delay in the operational date,
Pacific Gas and Electric Company incurred additional costs which were not
initially included in rate base, and lost revenues during the period the plant
was under repair. In September 1996, the CPUC approved a settlement resolving
the treatment of remaining unrecovered Helms costs.
As part of the 1996 GRC decision issued in December 1995, the CPUC directed
Pacific Gas and Electric Company to perform a cost-effectiveness study of
Helms. The CPUC indicated the study should consider changes in rate recovery
for the plant including, among other things, the option of retirement with
recovery of the investment without a return. The cost-effectiveness study
submitted by Pacific Gas and Electric Company in July 1996 concluded that the
continued operation of Helms is cost-effective. Pacific Gas and Electric
Company recommended that the CPUC take no action based on the study, but
address Helms along with other generating plants in the context of electric
industry restructuring. Pacific Gas and Electric Company's net investment in
Helms at December 31, 1997 was $691 million. Under electric industry
restructuring, the uneconomic above-market portion of the Company's net
investment in Helms is eligible for recovery as a transition cost. However,
Pacific Gas and Electric Company will be placed at risk to recover its future
operating costs in the newly restructured electric generation market. Because
the CPUC has not specifically addressed the cost-effectiveness study, Pacific
Gas and Electric Company is currently unable to predict whether there will be
further changes in rate recovery resulting from the study. See "Pacific Gas
and Electric Company Rate Matters--Electric Ratemaking" above.
ELECTRIC TRANSMISSION AND DISTRIBUTION
To transport energy to load centers, Pacific Gas and Electric Company as of
December 31, 1997, owned and operated approximately 18,516 circuit miles of
interconnected transmission lines of 60 kilovolts (kV) to 500 kV and
transmission substations having a capacity of approximately 33,814,855
kilovolt-amperes (kVa), excluding power plant interconnection facilities.
Energy is distributed to customers through approximately 108,170 circuit miles
of distribution system and distribution substations having a capacity of
approximately 23,000,000 kVa.
Under AB 1890, it is intended that California's investor-owned utilities and
its publicly owned utilities relinquish control, but not ownership, of their
transmission facilities to the ISO. In 1997, the FERC issued various decisions
to implement the formation and operation of the ISO and the PX as contemplated
by AB 1890. The ISO will control the operation of the transmission system and
provide open access transmission service on a nondiscriminatory basis. The
FERC approved the various forms of agreements for must-run facilities that
will be entered into between the utilities and the ISO to ensure grid
reliability. The FERC also granted conditional
28
authority for operation of the ISO and the PX. After the ISO and the PX
announced a delay in commencement of their operations, the FERC issued an
order requiring the ISO and the PX to provide the FERC 15 days notice before
the intended commencement date of operations and the ISO's assumption of
operational control of certain transmission facilities.
The FERC has also approved a proposal from Pacific Gas and Electric Company
and the other California utilities that distinguishes between local
distribution facilities and transmission facilities. The order defines
jurisdiction for the CPUC over local distribution and retail power customers.
The FERC will have jurisdiction over the transmission facilities as defined in
the order and over the transmission aspects of retail direct access. Most of
Pacific Gas and Electric Company's distribution services will remain subject
to CPUC jurisdiction.
29
GAS UTILITY OPERATIONS
Pacific Gas and Electric Company owns and operates an integrated gas
transmission, storage, and distribution system in California. At December 31,
1997, Pacific Gas and Electric Company's system, including the PG&E Expansion
(Line 401), consisted of approximately 5,700 miles of transmission pipelines,
three gas storage facilities, and approximately 36,700 miles of gas
distribution lines.
GAS OPERATIONS
Pacific Gas and Electric Company's peak day send-out of gas on its
integrated system in California during the year ended December 31, 1997, was
4,145 million cubic feet (MMcf). The total volume of gas throughput during
1997 was approximately 888,000 MMcf, of which 262,000 MMcf was sold to direct
end-use or resale customers, 173,000 MMcf was used by Pacific Gas and Electric
Company primarily for its fossil-fueled electric generating plants, and
452,000 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.
The 1997 Supplemental Report updates Pacific Gas and Electric Company's
annual gas requirements forecast (excluding bypass volumes) for the years 1997
through 2010 forcasting growth in gas throughput served by Pacific Gas and
Electric Company of 2% per year. 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 Pacific Gas and Electric Company's system entirely. The 1997
Supplemental Report forecasts a total bypass volume of 133,600 MMcf for 1998.
30
GAS OPERATING STATISTICS
The following table shows Pacific Gas and Electric Company's operating
statistics (excluding subsidiaries except where indicated) for gas, including
the classification of sales and revenues by type of service.
YEARS ENDED DECEMBER 31
----------------------------------------------------------
1997 1996 1995 1994 1993
---------- ---------- ---------- ---------- ----------
CUSTOMERS (AVERAGE FOR
THE YEAR):
Residential............ 3,491,963 3,455,086 3,417,556 3,372,768 3,339,859
Commercial............. 198,453 198,071 197,939 196,509 195,815
Industrial............. 1,650 1,500 1,500 1,400 1,265
Other gas utilities.... 3 2 2 2 4
---------- ---------- ---------- ---------- ----------
Total............... 3,692,069 3,654,659 3,616,997 3,570,679 3,536,943
========== ========== ========== ========== ==========
GAS SUPPLY--THOUSAND
CUBIC FEET (MCF) (IN
THOUSANDS):
Purchased:
From Canada........... 280,084 253,209 261,800 319,453 329,693
From California....... 10,655 28,130 31,158 31,757 32,096
From other states..... 131,074 110,604 117,538 249,733 243,058
---------- ---------- ---------- ---------- ----------
Total purchased..... 421,813 391,943 410,496 600,943 604,847
Net from storage (to
storage).............. 14,160 6,871 (10,921) 3,591 (12,234)
---------- ---------- ---------- ---------- ----------
Total............... 435,973 398,814 399,575 604,534 592,613
Pacific Gas and
Electric Company use,
losses, etc.(1)....... 173,789 134,375 129,671 297,604 161,895
---------- ---------- ---------- ---------- ----------
Net gas for sales... 262,184 264,439 269,904 306,930 430,718
========== ========== ========== ========== ==========
BUNDLED GAS SALES AND
TRANSPORTATION
SERVICE--MCF (IN
THOUSANDS):
Residential............ 191,327 190,246 191,724 214,358 206,053
Commercial............. 60,803 62,178 64,135 72,183 82,048
Industrial............. 10,054 12,015 14,045 19,495 133,178
Other gas utilities.... 0 0 0 894 9,439
---------- ---------- ---------- ---------- ----------
Total............... 262,184 264,439 269,904 306,930 430,718
========== ========== ========== ========== ==========
TRANSPORTATION SERVICE
ONLY--MCF (IN THOU-
SANDS):
Vintage system
(Substantially all
Industrial)(2)........ 218,660 189,695 143,921 142,393 101,888
PG&E Expansion (Line
401).................. 233,269 237,776 240,506 200,755 20,513
---------- ---------- ---------- ---------- ----------
Total............... 451,929 427,471 384,427 343,148 122,401
========== ========== ========== ========== ==========
REVENUES (IN THOUSANDS):
Bundled gas sales and
transportation
service:
Residential........... $1,170,135 $1,109,463 $1,205,223 $1,268,966 $1,152,494
Commercial............ 374,084 362,819 421,397 444,805 467,962
Industrial............ 46,592 42,520 42,106 57,297 367,221
Other gas utilities... 3,701 510 0 2,371 25,654
---------- ---------- ---------- ---------- ----------
Bundled gas
revenues........... 1,594,512 1,515,312 1,668,726 1,773,439 2,013,331
Transportation only
revenue:
Vintage system
(Substantially all
Industrial).......... 207,160 180,197 167,325 132,509 56,733
PG&E Expansion (Line
401)................. 90,180 85,144 82,904 58,442 8,097
---------- ---------- ---------- ---------- ----------
Transportation service
only revenue.......... 297,340 265,341 250,229 190,951 64,830
Miscellaneous.......... 50,295 (9,271) (18,018) 40,427 (16,692)
Regulatory balancing
accounts.............. (137,787) 57,864 (43,771) (101,443) 95,339
Subsidiaries(3)........ 0 210,556 201,951 177,688 264,925
---------- ---------- ---------- ---------- ----------
Operating revenues.. $1,804,360 $2,039,802 $2,059,117 $2,081,062 $2,421,733
========== ========== ========== ========== ==========
- --------
(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 72,958 MMcf, 78,552 MMcf, 100,207 MMcf, 79,749 MMcf, and
7,205 MMcf for 1997, 1996, 1995, 1994 and 1993, respectively.
(3) In January 1997, a Pacific Gas and Electric Company subsidiary--Pacific
Gas Transmission Company (PGT) became a subsidiary of PG&E Corporation and
is now known as PG&E Gas Transmission, Northwest Corporation.
31
YEARS ENDED DECEMBER 31
-------------------------------------------------
1997 1996 1995 1994 1993
--------- --------- --------- --------- ---------
SELECTED STATISTICS:
Total customers (at year-
end)....................... 3,700,000 3,700,000 3,600,000 3,500,000 3,600,000
Average annual residential
usage (Mcf)................ 55 55 56 64 62
Heating temperature -- % of
normal(1).................. 71.7 75.7 75.3 104.4 89.9
Average billed bundled gas
sales revenues per Mcf:
Residential................ 6.12 $5.83 $6.29 $5.92 $5.59
Commercial................. 6.15 5.84 6.57 6.16 5.70
Industrial................. 4.63 3.54 3.00 2.94 2.76
Average billed
transportation only revenue
per Mcf:
Vintage system............. 0.71 0.67 0.69 0.60 0.52
PG&E Expansion (Line 401).. 0.39 0.36 0.34 0.29 0.39
Net plant investment per
customer (2)............... $1,031 $1,378 $1,315 $1,340 $1,339
- --------
(1) Over 100% indicates colder than normal.
(2) The net plant investment per customer figure for 1997 is lower than in
previous years because it excludes subsidiaries.
NATURAL GAS SUPPLIES
The objective of Pacific Gas and Electric Company's gas supply planning is
to maintain a balanced supply portfolio which provides supply reliability and
contract flexibility, minimizes costs, and fosters competition among
suppliers.
Under current CPUC regulations, Pacific Gas and Electric Company purchases
natural gas from its various suppliers based on economic considerations,
consistent with regulatory, contractual, and operational constraints. During
the year ended December 31, 1997, approximately 66% of Pacific Gas and
Electric Company's total purchases of natural gas consisted of Canadian gas
purchased from various Canadian producers and transported by Canadian pipeline
companies and PG&E Gas Transmission, Northwest Corporation; approximately 3%
was purchased from various California producers; and approximately 31% was
purchased in other states (substantially all from U.S. Southwest sources and
transported by the El Paso Natural Gas Company or Transwestern Pipeline
Company pipelines). The following table shows the volume and average price of
gas in dollars per thousand cubic feet (Mcf) purchased by Pacific Gas and
Electric Company from these sources during each of the last five years.
YEARS ENDED DECEMBER 31
----------------------------------------------------------------------------------------------
1997 1996 1995 1994 1993
------------------ ------------------ ------------------ ------------------ ------------------
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................. 280,084 $ 1.77 253,209 $ 1.57 261,800 $ 1.34 319,453 $ 1.94 329,693 $ 2.26
California............. 10,655 2.12 28,130 $ 1.90 31,158 $ 1.32 31,757 1.55 32,096 1.65
Other states
(substantially all
U.S. Southwest)....... 131,074 3.75 110,604 $3.72 117,538 $2.64 249,733 2.41 243,058 2.84
-------- ------ -------- ------ -------- ------ -------- ------ -------- ------
Total/Weighted Average. 421,813 $2.39 391,943 $2.21 410,496 $1.71 600,943 $2.12 604,847 $2.46
======== ====== ======== ====== ======== ====== ======== ====== ======== ======
- --------
(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. The
average prices for California gas include only commodity gas prices
delivered to Pacific Gas and Electric Company's gas system.
GAS REGULATORY FRAMEWORK
In August 1997, the CPUC approved the Gas Accord which restructures Pacific
Gas and Electric Company's gas services and its role in the gas market. As
discussed above (see "Competition and the Changing Regulatory Environment--Gas
Industry"), the Gas Accord separates, or "unbundles," the rates for Pacific
Gas and Electric Company's gas transmission services from its distribution
services, increases the opportunities for core customers
32
to purchase gas from competing suppliers, establishes a form of incentive
regulation to measure the reasonableness of core procurement costs, and
establishes gas transmission and storage rates from March 1998 through
December 2002. The Gas Accord also settled various issues pending in certain
regulatory proceedings.
The CPUC is considering further changes in California's natural gas
industry. See "Competition and the Changing Regulatory Environment--Gas
Industry" above.
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 Pacific Gas and
Electric Company will pay each year may change due to changes in tariff rates.
The total demand and volumetric transportation charges paid by Pacific Gas and
Electric Company under these agreements were approximately $255 million in
1997. This amount includes payments made to PG&E Gas Transmission, Northwest
Corporation of approximately $49 million in 1997, which payments are
eliminated in the consolidated financial statements of PG&E Corporation.
As a result of regulatory changes, Pacific Gas and Electric Company no
longer procures gas for most of its noncore customers, resulting in a decrease
in the Company's need for firm transportation capacity for its gas purchases.
Pacific Gas and Electric Company continues to procure gas for almost all of
its core customers and those noncore customers who choose bundled service
(core subscription customers). Pacific Gas and Electric Company is continuing
its efforts to broker or assign any of its remaining contracted-for but unused
interstate transportation capacity, including unused capacity held for its
core and core subscription customers.
Under a firm transportation agreement with PG&E Gas Transmission, Northwest
Corporation that runs through October 31, 2005, Pacific Gas and Electric
Company currently retains approximately 600 million cubic feet per day
(MMcf/d) on the PG&E Gas Transmission, Northwest Corporation system to support
its core and core subscription customers. Although this capacity commitment
exceeds the amount needed to support Pacific Gas and Electric Company's core
and core subscription customers, the Company has been able to assign
substantially all of its unused capacity on PG&E Gas Transmission, Northwest
Corporation's system to other shippers.
In general, any shortfall resulting from the difference between the fixed
demand charges Pacific Gas and Electric Company pays under gas transportation
contracts with interstate pipeline companies for the reservation of interstate
pipeline capacity that the Company no longer uses to serve noncore customers,
and the revenues Pacific Gas and Electric Company obtains from brokering that
capacity, is eligible for rate recovery through the Interstate Transition Cost
Surcharge (ITCS), subject to a reasonableness review. Various groups had
challenged Pacific Gas and Electric Company's recovery of these amounts,
including amounts which arose in connection with firm transportation
commitments that the Company had entered into with PG&E Gas Transmission,
Northwest Corporation and El Paso Natural Gas Company. (The agreement with El
Paso terminated as of December 31, 1997.) Under the Gas Accord, these
challenges were resolved through Pacific Gas and Electric Company's agreement
to forgo recovery of 100 percent and 50 percent of the ITCS amounts allocated
for collection from its core and noncore customers, respectively.
In 1992, Pacific Gas and Electric Company entered into a firm transportation
agreement with Transwestern Pipeline Company (Transwestern), which expires in
2007, to meet core gas sales demands and electric generation needs. The demand
charges associated with the entire Transwestern capacity are currently
approximately $29 million per year. Pacific Gas and Electric Company was not
permitted to include any Transwestern firm capacity demand charges in rates or
in the ITCS account, although the Company was authorized to record costs
associated with its Transwestern capacity in a balancing account, with
recovery of such costs subject to reasonableness review proceedings. In 1995,
the CPUC determined that it was unreasonable for Pacific Gas and Electric
Company to commit to transportation capacity with Transwestern and disallowed
recovery of the costs of capacity for 1992. It indicated that it would
disallow costs through the term of the contract unless Pacific Gas
33
and Electric Company could demonstrate on an annual basis that the benefit of
the commitment outweighed the costs in a particular year. As part of the Gas
Accord, Pacific Gas and Electric Company agreed to resolve this issue by
forgoing the recovery of costs associated with capacity originally subscribed
to in order to serve core customers through 1997 and to limit its recovery of
demand charges through the CPIM during the period 1998 through 2002.
GAS REASONABLENESS PROCEEDINGS
Recovery of gas costs through Pacific Gas and Electric Company's regulatory
balancing account mechanisms is subject to a CPUC determination that such
costs were incurred reasonably. Before June 1, 1994, annual reasonableness
proceedings were conducted by the CPUC on a historic calendar year basis. As
discussed above (see "Competition and the Changing Regulatory, Environment--
Gas Industry"), the annual reasonableness proceedings have been replaced by
the CPIM.
1988-1990 CANADIAN GAS PROCUREMENT ACTIVITIES
In March 1994, the CPUC issued a final decision on Pacific Gas and Electric
Company's Canadian gas procurement activities during 1988 through 1990. The
CPUC found that Pacific Gas and Electric Company could have saved its
customers money if it had bargained more aggressively with its existing
Canadian suppliers or bought less expensive gas from other Canadian sources.
The decision ordered a disallowance of $90 million of gas costs, plus accrued
interest estimated at approximately $25 million through December 31, 1993.
Although Pacific Gas and Electric Company had challenged this decision by the
CPUC in federal court, as part of the Gas Accord, the Company has agreed to
forgo recovery of the $90 million disallowance ordered in the 1988-1990
reasonableness proceeding. In November 1997, Pacific Gas and Electric
Company's federal lawsuit was dismissed with prejudice.
PGT/PACIFIC GAS AND ELECTRIC COMPANY PIPELINE EXPANSION
In November 1993, PG&E Gas Transmission, Northwest Corporation (formerly
Pacific Gas Transmission Company or PGT) and Pacific Gas and Electric Company
placed in service the Pipeline Expansion, an expansion of their interconnected
natural gas transmission systems from the Canadian border into California. The
840-mile combined Pipeline Expansion provides an additional 148 MMcf/d of firm
capacity to the Pacific Northwest and an additional 851 MMcf/d of capacity to
Northern and Southern California.
The conditions of the CPUC's approval of the construction of Pacific Gas and
Electric Company's portion of the Pipeline Expansion (PG&E Expansion or Line
401) placed Pacific Gas and Electric Company at risk for its decision to
construct based on its assessment of market demand and for undersubscription
and underutilization of the facility. The CPUC required the application of a
"cross-over" ban under which volumes delivered from the incremental portion
owned by PG&E Gas Transmission, Northwest Corporation (PGT Expansion) of the
Pipeline Expansion must be transported at an incremental PG&E Expansion rate.
The costs of PG&E Expansion operations were recovered only from PG&E Expansion
customers, through rates established in separate PG&E Expansion rate
proceedings.
Under the Gas Accord, Pacific Gas and Electric Company remains at risk for
cost recovery of the PG&E Expansion through rates; however, a portion of the
PG&E Expansion will be combined with other Pacific Gas and Electric Company
transmission assets (specifically, a portion of Pacific Gas and Electric
Company's Line 400) for ratemaking purposes. This new ratemaking treatment for
gas transmission assets allows all shippers supplying noncore customers to
transport Canadian gas in California at a single rate, and obviates the need
for the "cross-over" ban, which was eliminated under the Gas Accord. Further,
in the Gas Accord, the CPUC adopted a rule under which Pacific Gas and
Electric Company is required, whenever it discounts service for a shipper on
its Line 400/401 delivering primarily Canadian gas within the Company's
service territory, to contemporaneously offer a commensurate discount to all
shippers delivering Southwest or California source gas on Line 300 within the
Company's service territory.
34
In 1994, Pacific Gas and Electric Company filed its application in the
Pipeline Expansion Project Reasonableness case (PEPR) requesting that the CPUC
find reasonable the full capital costs of the PG&E Expansion (estimated to be
$810 million). In that proceeding, the ORA recommended a minimum of $100
million in capital costs be disallowed, while two intervenors jointly
recommended a $237 million disallowance or reallocation of costs among
customers. In addition, in 1996, a CPUC administrative law judge (ALJ) ordered
consolidation of the market impact phase of the PEPR and the ITCS proceeding
described above. An ALJ also ordered reopening of the 1993 PG&E Pipeline
Expansion Rate Case to allow reconsideration of issues regarding the decision
to construct the PG&E Expansion. The CPUC's 1997 decision approving the Gas
Accord affirms the CPUC's 1994 finding that the decision to construct the PG&E
Expansion was reasonable based on Pacific Gas and Electric Company
management's knowledge at the time. The Gas Accord decision accepts the Gas
Accord's proposal to set rates for Line 401 during the Gas Accord period based
on total capital costs of $736 million.
35
PG&E CORPORATION'S GAS TRANSMISSION OPERATIONS
During 1997, PG&E Corporation expanded its operations in the "midstream"
portion of the gas business, which includes (1) the gas gathering, processing,
storage, and transportation of natural gas, (2) the marketing of natural gas
to gas distribution companies, electric utilities, municipalities, marketers,
independent power producers, and end-use customers, and (3) the transportation
of natural gas for these customers, producers and other pipelines.
Through its January 1997 acquisition of Teco in Texas (now known as PG&E Gas
Transmission Teco, Inc.), PG&E Corporation acquired various interests in
natural gas pipeline systems in Texas, various investments in gas gathering
and processing facilities, and a gas marketing operation in Houston, Texas.
On July 31, 1997, PG&E Corporation completed its acquisition of Valero's
natural gas and related businesses, including its gas gathering,
transportation, and storage facilities, and its facilities relating to the
processing, transportation, and marketing of natural gas liquids (NGLs).
Valero's 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. PG&E Corporation acquired approximately 6,400 miles of
natural gas pipeline and Valero's joint ownership or leasehold interests in
approximately 1,100 miles of pipeline, including the Valero-Teco West Texas
pipeline from Waha in west Texas to the San Antonio area. This pipeline system
has the capacity to transport more than 3 bcf of gas per day. PG&E Corporation
acquired a long-term lease of 7.2 bcf of storage capacity, approximately 536
miles of NGL pipelines and eight natural gas processing plants with a combined
capacity of approximately 1.5 bcf per day of gas throughput, capable of
producing approximately 93,000 barrels per day of NGLs.
PG&E Gas Transmission, Northwest Corporation (formerly Pacific Gas
Transmission Company or PGT) 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 and are capable of transporting 2.4 billion
cubic feet (bcf) per day of natural gas. It also owns two smaller diameter
pipeline extensions within Oregon, totaling 106 miles. A subsidiary of PG&E
Corporation also owns the PG&E Queensland Gas Pipeline, an approximately 389-
mile of mostly 12-inch pipeline in Queensland, Australia, which provides
natural gas transportation service to customers in the vicinity of the
pipeline.
In September 1996, the FERC approved a settlement of PG&E Gas Transmission,
Northwest Corporation's 1994 rate case. The major issue in this proceeding was
whether PG&E Gas Transmission, Northwest Corporation's mainline transportation
rates should be equalized through the use of rolled-in cost allocations, or
whether they should continue to reflect the use of incremental cost allocation
to determine the rates to be paid by firm shippers. (Under incremental rates,
a pipeline would generally charge higher rates to shippers contracting for
capacity on newly-added expansion facilities as compared to shippers using
depreciated pre-expansion facilities.) The settlement provides for rolled-in
rates effective November 1996. To mitigate the impact of the higher rolled-in
rates on shippers who were paying lower rates under contracts executed prior
to construction of the PGT Expansion, most of the firm shippers who took
service prior to such time receive a reduction from the rolled-in rate for a
six-year period, while PGT Expansion firm shippers pay a surcharge in addition
to the rolled-in rates to offset the effect of the mitigation. See "Gas
Utility Operations--PGT/Pacific Gas and Electric Company Pipeline Expansion"
above. The settlement also provides for rates based on a return on equity of
12.2%. Several parties are seeking rehearing of the FERC order approving the
settlement, but PG&E Gas Transmission, Northwest Corporation currently expects
the settlement to be upheld.
36
PG&E CORPORATION'S INDEPENDENT POWER GENERATION OPERATIONS
Through USGen 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. As of December 31, 1997, USGen, headquartered in Bethesda,
Maryland, and its affiliates had ownership interests in 15 operating plants in
eight states. The total generating capacity of these 15 plants is 3,249 MW.
PG&E Corporation's combined net equity ownership in these plants as of
December 31, 1997, represented 1,457 MW. The plants were largely financed with
a combination of equity or equity commitments from the project sponsors and
non-recourse debt. USGen, through its affiliate, U.S. Operating Services
Company (USOSC), provides contract operations and maintenance services to many
of these facilities. Nationwide, USGen's power plant development activities
exceed 4,400 MW in eight states. Together with its power marketing affiliate,
USGen Power Services, L.P. (now PG&E Energy Trading--Power, L.P.), USGen and
its affiliated or managed facilities sold 38.4 million megawatt-hours (MWh) of
electricity into the wholesale electric market in 1997.
In a series of transactions commencing in September 1997 and ending in
January 1998, subsidiaries of PG&E Corporation acquired Bechtel Enterprises'
interests in USGen, USOSC, and USGen Power Services, L.P. (now PG&E Energy
Trading--Power, L.P.). PG&E Corporation also acquired all or a portion of
Bechtel's interests in six independent power generating facilities which were
jointly owned by PG&E Corporation and Bechtel, or by PG&E Corporation,
Bechtel, and various third parties.
On August 6, 1997, PG&E Corporation announced that it had agreed to acquire
a portfolio of non-nuclear electric generating assets and power supply
contracts from the New England Electric System (NEES) for $1.59 billion. These
assets will be held by an affiliate of USGen. The $1.59 billion purchase price
includes $225 million to be paid to NEES when customer choice of energy power
suppliers is broadly available in New England. This amount will decline in
accordance with a prorated schedule if the implementation of customer choice
of energy power suppliers in New England occurs after January 1, 1999. In
addition to the purchase price, NEES will also receive $85 million from USGen
or its affiliates to pay for employee retraining, early retirement, and
severance for NEES' employees affected by industry restructuring. USGen or one
of its affiliates will also assume certain existing collective bargaining
agreements between NEES and its labor unions.
Including fuel and other inventories and transaction costs, financing
requirements are expected to reach approximately $1.75 billion, of which
approximately $1 billion will be funded through a combination of project level
debt as well as debt of affiliates of USGen. In addition, up to $750 million
of equity will be contributed over two years and will be financed initially
using short-term debt of PG&E Corporation.
The NEES facilities to be acquired consist of two hydroelectric systems with
14 stations, three fossil-fuel stations with 11units, and a pumped storage
facility, with a combined generating capacity of approximately 4,000 MW. USGen
or its affiliates will also assume the purchase obligations under 23 multi-
year power purchase agreements between NEES' subsidiary, New England Power,
and other utility and non-utility wholesale suppliers representing an
additional 1,100 MW of production capacity. The terms of the acquisition call
for New England Power to make annual support payments ranging approximately
from $150 million to $170 million through early 2008 to offset the cost of
power associated with these above-market contracts. The annual payment is a
fixed obligation and is not dependent on the actual costs under the
agreements, market prices, or NEES' regulatory status.
As part of the electric industry deregulation in Massachusetts and Rhode
Island, NEES' retail customers in those states may choose to continue
receiving power from NEES (the "Standard Offer") at a fixed price or may
choose a new power supplier. NEES' retail customers may make this choice
through the year 2004 in Massachusetts and through the year 2009 in Rhode
Island. It is expected that in the first half of 1998 NEES will auction its
wholesale supply obligations under the Standard Offer to third parties. NEES'
remaining supply obligation for these customers will be assigned to USGen, or
one or more of its affiliates.
37
NEES will also assign to USGen or one or more of its affiliates its rights
to supply power under several long-term power supply agreements, totaling
approximately 100 MW. The acquisition also includes 100 million cubic feet per
day of long-term natural gas supply and pipeline commitments, as well as a
twelve-year lease on a self-unloading coal transportation vessel.
PG&E Corporation's acquisition of NEES' assets, which is expected to be
completed in 1998, is subject to a number of conditions, including approval of
the FERC and state regulators.
NEES' sale of these generating facilities and power supply contracts was
prompted, in part, by the anticipated deregulation of the electric industry in
several New England states. In Massachusetts, electric industry restructuring
legislation took effect on March 1, 1998. A referendum will be voted on in
November 1998, to repeal this legislation.
The financial impact of the acquisition of the NEES assets on PG&E
Corporation is subject to a number of risks and uncertainties, including
future market prices of power in the region where the NEES assets are located,
future fuel prices, the development of a competitive market in the states in
which the NEES assets are located, the extent to which operating efficiencies
at the NEES plants can be attained, changes in legislation affecting electric
industry restructuring and in the regulatory environment in the states where
the NEES assets are located, the extent of the obligation to provide
electricity under the Standard Offer at prices below cost or market, the
extent to which a liquid, well-structured trading market develops for
wholesale electric power in the states in which the NEES assets are located,
and generating capacity expansion and retirements by others.
In the second quarter of 1997, Bechtel acquired PG&E Corporation's
partnership interest in International Generating Company, Ltd. (InterGen), a
company formed to develop, own, and operate international electric generation
projects. PG&E Corporation realized an after-tax gain of $120 million on the
sale.
38
PG&E CORPORATION'S ENERGY SERVICES AND COMMODITIES
PG&E Energy Services Corporation provides gas and electric energy services
and commodities nationwide where permitted under applicable laws. PG&E Energy
Services also provides commercial, industrial, and institutional customers
with a wide range of services, including competitively priced electric and gas
commodities, billing and information management services, energy management
services, regulatory and rate analysis, and power quality solutions. PG&E
Energy Services targets primarily industrial, commercial, and institutional
customers. In 1997, PG&E Energy Services embarked on an aggressive campaign to
open new offices in the United States, primarily to support its direct sales
efforts and to establish a presence and market its services in emerging energy
markets. It now has over 20 offices nationwide.
PG&E Energy Services will compete with other non-utility electric retailers
in California when direct access begins. See "Electric Utility Operations--
Electric Industry Restructuring Legislation" above.
PG&E Energy Trading, headquartered in Houston, Texas, purchases bulk volumes
of power and natural gas from PG&E Corporation affiliates; USGen and PG&E Gas
Transmission, and from the wholesale market. PG&E Energy Trading then
schedules, transports, and resells these commodities, either directly or
through PG&E Energy Services--repackaging them to meet customers' individual
delivery, price, and reliability needs. PG&E Energy Trading also provides
price risk management services to PG&E Corporation's other businesses (except
Pacific Gas and Electric Company) and to wholesale customers. Additionally,
PG&E Energy Trading supports PG&E Energy Services Corporation with a broad
portfolio of energy products and services for the retail market.
For more information, see "Price Risk Management Programs" above.
39
ENVIRONMENTAL MATTERS
ENVIRONMENTAL MATTERS
The following discussion includes certain forward-looking information
relating to estimated expenditures for environmental protection and the
possible future impact of environmental compliance. This information reflects
Pacific Gas and Electric Company's current estimates which are periodically
evaluated and revised. 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 Pacific Gas and Electric Company's responsibility, and the
availability of recoveries or contributions from third parties. Future
estimates and actual results may differ materially from those indicated below.
PG&E Corporation, Pacific Gas and Electric Company, 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, and air and water pollution, and, in recent
years, by governing the use, 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. Pacific Gas and Electric Company has undertaken major 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 Company's bulk waste
handling and storage facilities. The costs of compliance with environmental
laws and regulations have generally been recovered in rates.
ENVIRONMENTAL PROTECTION MEASURES
Pacific Gas and Electric Company's estimated expenditures for environmental
protection are subject to periodic review and revision to reflect changing
technology and evolving regulatory requirements.With the sale of the Morro
Bay, Moss Landing, and Oakland power plants, and the planned sale of the
Contra Costa, Pittsburg, Hunters Point, Potrero, and Geysers power plants,
Pacific Gas and Electric Company no longer expects to incur significant oxides
of nitrogen (NOx) emission reduction compliance costs. See "Electric Utility
Operations--Electric Industry Restructuring Legislation--Voluntary Generation
Asset Divestiture" above.
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, three of the local air districts in which Pacific Gas and
Electric Company 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).
Following divestiture of the Company's fossil-fueled generating plants in
connection with electric industry restructuring, the new owners will bear NOx
retrofit costs. Under AB 1890, NOx retrofit costs would be eligible for
recovery as transition costs but only to the extent that those costs are found
by the CPUC to be both reasonable and necessary to maintain the unit in
operation through 2001.
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 Southwest gas.
Other air districts are considering NOx rules which would apply to Pacific Gas
and Electric Company's other natural gas compressor stations in California.
Eventually the rules are likely to require NOx reductions of up to 80% at
these natural gas compressor stations. Pacific Gas and Electric Company
currently estimates that the total cost of complying with these rules will be
up to $34 million over four years.
40
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. Pacific Gas and Electric
Company'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 Pacific
Gas and Electric Company continue its thermal effects monitoring program. In
1995, the Central Coast Board requested that Pacific Gas and Electric Company
prepare an updated comprehensive assessment of Diablo Canyon's thermal effects
and approved a reduced environmental monitoring program. The new comprehensive
assessment is scheduled for submission to the Central Coast Board in the first
quarter of 1998. In the unlikely event that the Central Coast Board finds that
Diablo Canyon's existing thermal limits are not protective of beneficial uses
of the marine waters and that major modifications are required (e.g., cooling
towers), significant additional construction expenses could be required.
Pursuant to the federal Clean Water Act, Pacific Gas and Electric Company 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 all existing
water-cooled thermal plants. Pacific Gas and Electric Company 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. Pacific Gas and Electric Company is currently
preparing a new study for Diablo Canyon. The study is scheduled to be
submitted to the Central Coast Board for review in 1999. In the event that the
Central Coast Board finds that Diablo Canyon's cooling water intake structure
does not meet the BTA requirements, significant 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 Pacific Gas and Electric Company 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.
Several fish species listed or proposed for listing as endangered species
may be found in the waters near Pacific Gas and Electric Company's Delta power
plants. To address the impacts of operation and maintenance activities at the
Delta plants on sensitive species, Pacific Gas and Electric Company has
developed a Habitat Conservation Plan (HCP) pursuant to the requirements of
Section 10(a) of the federal Endangered Species Act. The HCP is designed to
minimize and mitigate any incidental "take" (e.g., harassing, wounding, or
killing) of listed species that may occur from the operation, maintenance, and
repair of the power plants, in order to support the issuance of a Section
10(a) incidental take permit necessary for continued operation of the plants.
HAZARDOUS WASTE COMPLIANCE AND REMEDIATION
Pacific Gas and Electric Company assesses, 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.
Pacific Gas and Electric Company has a comprehensive program to comply with
the many hazardous waste storage, handling, and disposal requirements
promulgated by the United States Environmental Protection Agency (EPA) under
the Resource Conservation and Recovery Act and the Comprehensive Environmental
Response, Compensation, and Liability Act (CERCLA), along with California's
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), Pacific Gas
41
and Electric Company's manufactured gas plants were removed from service. The
residues which may remain at some sites contain chemical compounds which now
are classified as hazardous. Pacific Gas and Electric Company has identified
and reported to federal and California environmental agencies 96 manufactured
gas plant sites which operated in Pacific Gas and Electric Company's service
territory. Pacific Gas and Electric Company owns all or a portion of 29 of
these manufactured gas plant sites. Pacific Gas and Electric Company has a
program, in cooperation with environmental agencies, to evaluate and take
appropriate action to mitigate any potential health or environmental hazards
at sites which the Company owns. Pacific Gas and Electric Company currently
estimates that this program may result in expenditures of approximately $8
million to $11 million over the period 1998 through 1999. 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 Pacific Gas and Electric Company is found to be responsible for cleanup at
sites it does not currently own.
Pacific Gas and Electric Company has been designated as a potentially
responsible party (PRP) under the California Hazardous Substance Account Act
(California Superfund) with respect to several manufactured gas plant sites.
In addition to the manufactured gas plant sites, Pacific Gas and Electric
Company 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. Pacific Gas and Electric Company has been designated as a PRP
under CERCLA (the federal Superfund law) with respect to the Purity Oil Sales
site in Malaga, California, the Jibboom Junkyard site in Sacramento,
California, the Industrial Waste Processing site near Fresno, California, and
the Lorentz Barrel and Drum site in San Jose, California. The Purity Oil Sales
site is a former used oil recycling facility at which Pacific Gas and Electric
Company is one of nine PRPs named in an EPA order requiring groundwater
remediation at the site. Pacific Gas and Electric Company has also entered
into an Administrative Order with the EPA to address soil contamination at the
site. With respect to the Casmalia site near Santa Maria, California, Pacific
Gas and Electric Company 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 Pacific Gas and Electric Company 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 Pacific Gas and
Electric Company and other parties to initiate measures with respect to the
study and remediation of that site.
In addition to the sites discussed above, Pacific Gas and Electric Company
has also been identified as a PRP at certain disposal sites under the
California Superfund. Pacific Gas and Electric Company has also been sued for
reimbursement of cleanup costs incurred by the State of California at Pacific
Gas and Electric Company's former Jibboom Street Station B power plant in
Sacramento, California. In addition, Pacific Gas and Electric Company has been
named as a defendant in several civil lawsuits in which plaintiffs allege that
the Company is responsible for performing or paying for remedial action at
sites the Company 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 will occur in the near term due to uncertainty
concerning Pacific Gas and Electric Company's responsibility, the complexity
of environmental laws and regulations, and the selection of compliance
alternatives. Pacific Gas and Electric Company had an accrued liability at
December 31, 1997, of $232 million for hazardous waste remediation costs at
those sites, including fossil-fueled power plants, where such costs are
probable and quantifiable. Environmental remediation at identified sites may
be as much as $442 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 Pacific Gas and Electric Company is
responsible. This upper limit of the range of costs was estimated using
assumptions least favorable to Pacific Gas and Electric
42
Company based upon a range of reasonably possible, outcomes. Costs may be
higher if Pacific Gas and Electric Company is found to be responsible for
cleanup costs at additional sites or identifiable possible outcomes change.
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. However, under the proposed mechanism, utilities will have the
opportunity to recover the shareholder portion of the cleanup costs from
insurance carriers. Under the 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. Pacific Gas and
Electric Company can seek to recover hazardous substance cleanup costs under
the new mechanism 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 clean-up costs for
contamination caused by events occurring after January 1, 1998.
Pacific Gas and Electric Company will retain liability for certain required
environmental remediation of pre-closing soil or groundwater contamination for
fossil and geothermal generation facilities which are sold in connection with
electric industry restructuring. In 1997, the CPUC approved Pacific Gas and
Electric Company's proposal, with respect to certain generation plants to be
divested, to prepare a forecast of environmental remediation costs for plants
to be divested and use the forecast to adjust the current plant
decommissioning cost estimate which will be recovered through the CTC
ratemaking mechanism. Pacific Gas and Electric Company's revised estimate of
costs to remediate environmental contamination for which it will remain liable
at the Morro Bay, Moss Landing, and Oakland power plant is $39 million.
Pacific Gas and Electric Company expects to recover $157 million of the $232
million accrued liability, discussed above, in future rates. The liability
also includes $58 million related to power plant decommissioning for
environmental clean-up, which is recovered through depreciation. Additionally,
Pacific Gas and Electric Company is seeking recovery of costs from insurance
carriers and from other third parties.
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. Pacific Gas and Electric
Company had previously notified its insurance carriers that it seeks coverage
under its comprehensive general liability policies to recover costs incurred
at certain specified sites. In general, Pacific Gas and Electric Company's
carriers neither admitted nor denied coverage, but requested additional
information from the Company. Although Pacific Gas and Electric Company has
received some amounts in settlements with certain of its insurers
(approximately $55 million through December 31, 1997), 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 Company'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 which 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
43
contact with EMF but went on to state that a body of evidence has been
compiled which raises the question of whether adverse health impacts might
exist.
In November 1993, the CPUC adopted an interim EMF policy for California
energy utilities which, 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.
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. Pacific Gas and Electric Company also provides a free
field measurement service to inform customers about EMF levels at different
locations in and around their residences or commercial buildings.
Pacific Gas and Electric Company and other utilities are involved in
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. Pacific Gas and Electric Company is a defendant in civil
litigation in which plaintiffs allege 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 barring
plaintiffs' personal injury claims. Plaintiffs have filed an appeal of this
decision with the California Supreme Court.
In the event that 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, Pacific Gas and
Electric Company 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 is ultimately required.
LOW EMISSION VEHICLE PROGRAMS
In December 1995, the CPUC issued its decision in the Low Emission Vehicle
(LEV) proceeding which approved approximately $36 million in funding for
Pacific Gas and Electric Company's LEV program for the six-year period
beginning in 1996. The CPUC's decision on electric industry restructuring
finds that the costs of utility LEV programs should continue to be collected
by the utility for the duration of the six-year period. Pacific Gas and
Electric Company continues to run its LEV program as funded.
ITEM 2. PROPERTIES.
Information concerning Pacific Gas and Electric Company's electric
generation units, gas transmission facilities, and electric and gas
distribution facilities is included in response to Item 1. All real properties
and substantially all personal properties of Pacific Gas and Electric Company
are subject to the lien of an indenture which provides security to the holders
of Pacific Gas and Electric Company'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 headings of
this report entitled "PG&E Corporation's Gas Transmission Operations," "PG&E
Corporation's Independent Power Generation Operations," and "PG&E
Corporation's Energy Services and Commodities."
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.
44
COMPRESSOR STATION CHROMIUM LITIGATION
Pacific Gas and Electric Company has been named as a defendant in several
civil actions filed in California courts on behalf of more than 3,000
plaintiffs, and claims by approximately 2,800 plaintiffs are still pending.
These cases are Aguayo v. Betz, Pacific Gas and Electric Company, et al.,
filed March 15, 1995, in Los Angeles County Superior Court; Aguilar v. Pacific
Gas and Electric Company, Betz, et al., filed October 4, 1996, in Los Angeles
County Superior Court; Adams v. Betz, filed September 21, 1994, in Los Angeles
County Superior Court; Acosta, et al. v. Betz, Pacific Gas and Electric
Company, et al., filed November 27, 1996, in Los Angeles Superior Court; Riep,
et al. v. Pacific Gas and Electric Company, Betz, et al., filed February 14,
1997, in San Francisco Superior Court; Petitt, et al. v. Pacific Gas and
Electric Company, Betz, et al., filed May 6, 1997, in Los Angeles Superior
Court; Little and Mustafa v. Pacific Gas and Electric Company and PG&E
Corporation, filed September 10, 1997, in San Bernardino Superior Court; and
Whipple, et al. v. Pacific Gas and Electric Company and PG&E Corporation,
filed September 10, 1997, in San Bernardino Superior Court. (Plaintiffs have
agreed to dismiss PG&E Corporation in these last two suits.) These eight cases
are collectively referred to as the "Aguayo Litigation."
Each of the complaints in the Aguayo Litigation, except Little described
below, 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 Pacific Gas and Electric Company's gas
compressor stations at Kettleman, Hinkley and Topock, California. The
plaintiffs in the Aguayo Litigation include Pacific Gas and Electric Company
employees, former Pacific Gas and Electric Company employees, relatives of
Pacific Gas and Electric Company employees or former employees, residents in
the vicinity of the compressor stations, and persons who visited the gas
compressor stations, alleging exposure to chromium at or near the compressor
stations. The plaintiffs also include spouses or children of these plaintiffs
who claim only loss of consortium or injury through the alleged exposure of
their parents.
In the Adams case, the claims remaining against Pacific Gas and Electric
Company arise from a cross-claim filed by Betz Chemical Company, the supplier
of water treatment products containing chromium used at the gas compressor
stations.
In the Whipple case, pending in San Bernardino Superior Court, plaintiffs,
four members of one family, allege personal injuries, injury to a business
enterprise, and injury to real property based upon causes of action for (1)
actual fraud and deceit, (2) negligence, (3) negligence per se, (4) strict
liability, (5) battery, (6) intentional misrepresentation, (7) negligent
misrepresentation, (8) fraudulent concealment, and (9) intentional spoliation
of evidence. In the Little case, also pending in San Bernardino Superior
Court, two plaintiffs allege injury to real property based upon causes of
action for (1) actual fraud and deceit, (2) negligence, and (3) negligence per
se. Plaintiffs in each action are seeking unspecified compensatory and
punitive damages, as well as civil penalties pursuant to Proposition 65.
All discovery and discovery motion practice in four of the five cases
brought in Los Angeles Superior Court (Acosta v. Betz, Aguilar v. Pacific Gas
and Electric Company, Aguayo v. Pacific Gas and Electric Company, and Adams v.
Betz) has been referred by the judge to a discovery referee. Test plaintiffs
have been chosen in the Aguayo matter, and discovery is ongoing. During 1997,
more than 300 plaintiffs were dismissed from Aguayo v. Pacific Gas and
Electric Company for failure to respond to discovery or otherwise pursue their
claims. Discovery is beginning in the Acosta and Aguilar matters. Pacific Gas
and Electric Company has a motion for good faith settlement pending in the
Adams matter, as that case involves the same plaintiffs as a matter that
Pacific Gas and Electric Company previously settled. The fifth case brought in
Los Angeles Superior Court by eight plaintiffs (Pettit v. Pacific Gas and
Electric Company) was not served on Pacific Gas and Electric Company until
December 1997, and Pacific Gas and Electric Company filed an answer in January
1998.
In Riep v. Pacific Gas and Electric Company, pending in San Francisco
Superior Court, a trial date has been set for August 3, 1998.
45
Pacific Gas and Electric Company is responding to the complaints and
asserting affirmative defenses. Pacific Gas and Electric Company will pursue
appropriate legal defenses including statute of limitations, inability of
certain plaintiffs to state a claim for alleged preconception exposure, 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, and Pacific Gas and Electric
Company 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.
TEXAS FRANCHISE FEE LITIGATION
In connection with PG&E Corporation's acquisition of Valero Energy
Corporation, now known as PG&E Gas Transmission, Texas Corporation (GTT), PG&E
Corporation entities succeeded to the litigation described below.
City of San Benito, City of Primera, and City of Port Isabel v. Rio Grande
Valley Gas Company, Valero Energy Corporation (now known as GTT), Southern
Union Company, et al., 107th State District Court, Cameron County, Texas.
On December 31, 1996, a petition was filed by the Texas cities of San
Benito, Primera, and Port Isabel against Rio Grande Valley Gas Company (RGVG),
Valero (now known as PG&E Gas Transmission, Texas Corporation), Valero Natural
Gas Company (now known as PG&E Texas Natural Gas Company), Reata Industrial
Gas Company (now known as Valero Gas Marketing Company), Reata Industrial Gas
L.P. (now known as PG&E Reata Energy, L.P.), Valero Transmission L.P. (now
known as PG&E Texas Pipeline, L.P.), and Valero Transmission Company (now
known as VT Company), and two Southern Union entities: Southern Union Company
("SU") and Mercado Gas Services, Inc. On November 4, 1997, the cities of San
Benito, Primera, and Port Isabel filed an amended petition and an amended
motion for class action certification, and dismissed RGVG and the other SU
entities. The amended petition named as defendants PG&E Gas Transmission,
Texas Corporation and most of its subsidiaries (excluding the Canadian gas
trading company and power trading company), PG&E Gas Transmission Teco, Inc.
and most of its subsidiaries, and PG&E Energy Trading Corporation.
In the amended petition, plaintiffs allege, among other things, that (1) the
defendants that own or operate pipelines (in their capacities as merchants or
transporters) have occupied city property and conducted pipeline operations
without the cities' consent and without compensating the cities for use of the
cities' properties and (2) the defendants that are gas marketers have failed
to pay cities for accessing and utilizing pipelines located in the cities to
flow gas under city streets to end-use gas customers. The petition also
alleges various tort and statutory claims against defendants for failure to
secure the consents.
On November 5, 1997, orders were signed certifying a class, setting an opt
out deadline of December 31, 1997, and ordering notice to all potential class
members. The class certified consists of every incorporated municipality in
Texas (excepting the cities of Edinburg, Mercedes, and Weslaco, which have
filed separate actions) where any of the defendants engaged in business
activities related to natural gas or natural gas liquids. The court named the
cities of San Benito, Primera, and Port Isabel as class representatives. Fewer
than 20 cities had opted out by the deadline. Some of the cities which opted
out include Austin, Brownsville, Houston, Pharr, and San Antonio. One
purported class member has filed a notice to vacate the class certified.
Defendants' motion to transfer venue of this case to Bexar County, Texas, is
currently pending.
City of Edinburg v. Rio Grande Valley Gas Co., Valero Energy Corporation
(now known as GTT), Valero Natural Gas Company (now known as PG&E Texas
Natural Gas Company), Southern Union Gas Co., and Southern Union Gas Co., 92nd
State District Court, Hidalgo County, Texas.
46
On August 31, 1995, the City of Edinburg (City) filed a lawsuit against
certain Valero and Southern Union companies. The City's pleadings assert
various contract and tort actions, but all such claims are based on the theory
that when Rio Grande Valley Gas Company (RGVG), as the local distribution
company (LDC), was granted a franchise to sell gas and construct, maintain,
own, and operate gas pipelines in city streets, such authorization extended to
RGVG only and to no other entity. (On September 30, 1993, Valero sold the
common stock of RGVG to Southern Union.) The City seeks monetary damages and
injunctive relief on the theory that non-LDC owned pipelines were not
authorized under the franchise with RGVG and were otherwise unlawful without
the consent of, and the payment of compensation to, the City. The City also
claims that when RGVG began to operate pipelines it did not own, such
activities were not within the franchise and not otherwise consented to by the
City. Consequently, the City contends that all non-LDC owned pipelines (which
includes all of Valero Transmission, L.P.'s (now known as PG&E Texas Pipeline,
L.P.) transmission and gathering lines in City rights-of-way) are
"trespassing," and the Valero defendants must agree to a franchise or face
removal by injunction.
Further, the City contends that it is entitled to compensation for the past
presence of such pipelines in city property without consent, and for the use
of such pipelines to facilitate the past and present sales of gas, both for
resale and to direct end-users, by any person or entity other than the LDC.
Additionally, the City contends that RGVG has breached the franchise agreement
by failing to pay all franchise fees owed because it did not include in the
"gross sales" figure such incidental revenues as bad check fees, late payment
charges, hook-up and disconnect fees, and transportation revenues. The City
seeks to assert against the Valero defendants derivative liability for all of
RGVG's acts and omissions.
The latest pleading seeks actual damages in excess of $15 million,
unspecified punitive damages, and injunctive relief against six Valero
entities: Valero Energy Corporation (now known as GTT), Valero Transmission
Company (now known as PG&E Texas Pipeline Company), Valero Natural Gas Company
(now known as PG&E Natural Gas Company), Reata Industrial Gas Company (now
known as Valero Gas Marketing Company), 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.), and two SU entities.
Trial was originally set in the Edinburg matter for September 9, 1996, but
did not commence due to the disqualification on August 21, 1996, of the
original judge. The new judge has set a jury trial for June 15, 1998.
City of Mercedes v. Reata Industrial Gas, L.P. (now known as PG&E Reata
Energy, L.P.) and Reata Industrial Gas Company (now known as Valero Gas
Marketing Company), 92nd State District Court of Hidalgo County, Texas.
A lawsuit filed by the City of Mercedes on April 16, 1997, is currently
pending against Valero Gas Marketing Company and Reata Industrial Gas, L.P.
(now known as PG&E Reata Energy, L.P.). On September 4, 1997, 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 filed separate actions), in which any of
the defendants have sold or supplied gas, or used public rights-of-way to
transport gas.
The defendants, gas marketers, have never owned or operated any pipelines.
Plaintiff asserts these marketing companies have operated as "ghost pipelines"
that have "used" public property without consent or franchise from the cities
in which the defendants have sold gas. Plaintiff alleges that state law
requires the defendants to have specific prior city consent by ordinance in
order to transact business within or through city limits. The plaintiff
alleges various tort and statutory claims against the defendants for failure
to secure such consent. Plaintiff has requested a damage award, but has not
specified an amount.
Defendants' motion to transfer venue to Bexar County, Texas, is currently
pending. On September 10, 1997, defendants also filed a motion to disqualify
or recuse the presiding judge of the 92nd State District Court. This motion
was granted on November 26, 1997. A new judge has not been appointed yet. If a
class is certified, defendants anticipate that they will challenge such
certification.
47
Other Texas Franchise Fee Litigation
In addition to the three cases described above, involving the cities of
Edinburg, Mercedes, San Benito, Primera, and Port Isabel, there are five
lawsuits involving claims of a similar nature.
In 1996, the South Texas cities of Alton and Donna also independently
intervened as plaintiffs in the Edinburg lawsuit filed in the 92nd State
District Court in Hidalgo County. Subsequently, in July 1996, these lawsuits
were severed from the Edinburg lawsuit. The claims asserted by the cities of
Alton and Donna are substantially similar to the Edinburg litigation claims.
Damages are not quantified.
In December 1996, two additional lawsuits were filed in South Texas making
allegations substantially similar to those in the City of Edinburg litigation:
City of La Joya v. Rio Grande Valley Gas Company, Valero Energy Corporation,
Southern Union Company, et al., 92nd State District Court, Hidalgo County,
Texas (filed December 27, 1996), and City of San Juan, City of La Villa, City
of Penitas, City of Edcouch, and City of Palmview v. Rio Grande Valley Gas
Company, Valero Energy Corporation, Southern Union Company, et al., 93rd State
District Court, Hidalgo County, Texas (filed December 27, 1996).
The City of La Joya filed its lawsuit on its own behalf and as a putative
class representative on behalf of all similarly situated cities against the
same defendants sued in the Edinburg case. The same Southern Union entities in
the Edinburg suit have also been named in this suit.
The factual allegations and claims asserted in the lawsuit filed by the city
of La Joya, and in the lawsuit filed by the cities of San Juan, Lavilla,
Penitas, Edcouch, and Palmview, are similar to the claims made in the lawsuit
filed by the cities of San Benito, Primera, and Port Isabel. Defendants'
motion to transfer venue of both cases to Bexar County, Texas, is also
currently pending.
Finally, on April 17, 1997, a petition was filed by the South Texas city of
Weslaco. (City of Weslaco v. Reata Industrial Gas, L.P., et al., 92nd State
District Court, Hidalgo County, Texas). Weslaco sued Valero Natural Gas
Company (now known as PG&E Texas Natural Gas Company), Reata Industrial Gas
Company (now known as Valero Gas Marketing Company), and Reata Industrial Gas,
L.P. (now known as PG&E Reata Energy L.P.) The causes of action alleged are
identical to those alleged in the City of Mercedes case. Defendants' motion to
transfer venue to Bexar County, Texas is currently pending. Defendants have
also filed a motion to disqualify or recuse the presiding judge, which is also
pending.
In 1996, the Texas city of Pharr sought and obtained class certification in
a lawsuit styled City of Pharr, on behalf of itself and other Similarly
Situated Entities v. Rio Grande Valley Gas Company, et al, 92nd Judicial
District Court, Hidalgo County, Texas. By definition, the Pharr class consists
only of those Texas cities, excluding Edinburg and McAllen, that have, or have
had, natural gas franchises with RGVG or SU. The Pharr class was certified as
to only two claims: breach of contract and declaratory relief dealing with the
rights, status and legal relationship between plaintiff, the class members and
the LDC regarding payment of franchise fees and use of granted easements. On
December 30, 1997, the Pharr class certification order was affirmed on
interlocutory appeal. In conjunction with this appeal, the appellate court
specifically considered whether any of the Valero entities (now PG&E Gas
Transmission, Texas Corporation entities) is a party to the Pharr class action
and expressly found that such entities are not parties to that class action.
Recently, however, Pharr class counsel has represented to various Texas courts
that these entities were added to the Pharr class action as of December 9,
1997. As of February 25, 1998, none of these entities has been formally served
in the Pharr class action, nor has counsel to these entities been furnished
with a copy of the pleadings. However, the court's docket sheet shows a
supplemental pleading was filed on or about December 12, 1997, which purports
to add as defendants to the Pharr class action the same twenty-nine PG&E
Corporation entities that are defendants in the San Benito litigation
described above. The PG&E Corporation entities intend to defend vigorously
against any attempt to add them as defendants in the Pharr class action, as
well as against any attempt to modify the Pharr class definition in an effort
to assert claims against the PG&E Corporation entities.
48
PG&E Corporation believes that the ultimate outcome of the Texas franchise
fee cases described above will not have a material adverse impact on its
financial position.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
Not applicable.
49
EXECUTIVE OFFICERS OF THE REGISTRANTS
"Executive officers," as defined by Rule 3b-7 of the General Rules and
Regulations under the Securities and Exchange Act of 1934, of PG&E Corporation
are as follows:
AGE AT
DECEMBER 31,
NAME 1997 POSITION
---- ------------ --------
R. D. Glynn, Jr...... 55 Chairman of the Board, Chief Executive
Officer, and President
S. W. Gebhardt....... 46 Senior Vice President, President and
Chief Executive Officer, PG&E Energy
Services Corporation
T. W. High........... 50 Senior Vice President, Administration and
External Relations
J. F. Jenkins-Stark.. 46 Senior Vice President, President and
Chief Executive Officer, PG&E Gas
Transmission Corporation
J. P Kearney......... 49 Senior Vice President, President and
Chief Executive Officer, U.S. Generating
Company
L. E. Maddox......... 42 Senior Vice President, President and
Chief Executive Officer, PG&E Energy
Trading Corporation
M. E. Rescoe......... 45 Senior Vice President, Chief Financial
Officer, and Treasurer
G. R. Smith.......... 49 President and Chief Executive Officer,
Pacific Gas and Electric Company
G. B. Stanley........ 51 Senior Vice President, Human Resources
B. R. Worthington.... 48 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, January 1, 1998 to current
Chief Executive
Officer, and President
Chairman of the Board of January 1, 1998 to current
Directors, Pacific Gas
and Electric Company
President and Chief June 1, 1997 to current
Executive Officer
President and Chief December 18, 1996 to May 31, 1997
Operating Officer
President and Chief June 1, 1995 to May 31, 1997
Operating Officer,
Pacific Gas and
Electric Company
Executive Vice July 1, 1994 to May 31, 1995
President, Pacific Gas
and Electric Company
Senior Vice President January 1, 1994 to June 30, 1994
and General Manager,
Customer Energy
Services Business Unit,
Pacific Gas and
Electric Company
Senior Vice President November 1, 1991 to December 31, 1993
and General Manager,
Electric Supply
Business Unit, Pacific
Gas and Electric
Company
S. W. Gebhardt....... Senior Vice President April 1, 1997 to current
President and Chief April 1, 1997 to current
Executive Officer, PG&E
Energy Services
Corporation
Executive Vice April 1, 1996 to March 28, 1997
President, PennUnion
Energy Services
Vice President, Enron January 1, 1993 to December 31, 1995
Capital & Trade
Resources
T. W. High........... Senior Vice President, June 1, 1997 to current
Administration and
External Relations
Senior Vice President, June 1, 1995 to May 31, 1997
Corporate Services,
Pacific Gas and
Electric Company
Vice President and July 1, 1994 to May 31, 1995
Assistant to the Chief
Executive Officer,
Pacific Gas and
Electric Company
Vice President and November 1, 1991 to June 30, 1994
Assistant to the
Chairman of the Board,
Pacific Gas and
Electric Company
J. F. Jenkins-Stark.. Senior Vice President June 1, 1997 to current
President and Chief June 1, 1997 to current
Executive Officer, PG&E
Gas Transmission
Corporation
50
NAME POSITION PERIOD HELD OFFICE
---- -------- ------------------
Senior Vice President August 1, 1993 to May 30, 1997
and General Manager,
Gas Supply Business
Unit, Pacific Gas and
Electric Company
Vice President and January 15, 1992 to July 31, 1993
Treasurer, Pacific Gas
and Electric Company
J. P. Kearney........ Senior Vice President September 1997 to current
President and Chief February 1989 to current
Executive Officer, U.S.
Generating Company
L. E. Maddox......... Senior Vice President June 1, 1997 to current
President and Chief June 1, 1997 to current
Executive Officer, PG&E
Energy Trading
Corporation
President, PennUnion May 1995 to May 1997
Energy Services, L.L.C.
President, Brooklyn January 1993 to May 1995
Interstate Natural Gas
Corp.
M. E. Rescoe......... Senior Vice President, January 1, 1998 to current
Chief Financial
Officer, and Treasurer
Senior Vice President September 1, 1997 to December 31, 1997
and Chief Financial
Officer
Executive Vice August 11, 1997 to August 31, 1997
President, Strategic
Planning and Corporate
Development, Texas
Utilities Company
Senior Vice President, July 1995 to August 10, 1997
Chief Financial
Officer, Enserch Corp.
(gas and power)
Senior Managing July 1992 to July 1995
Director, Bear, Stearns
& Co., Inc. (investment
bankers)
G. R. Smith.......... (Please refer to
description of business
experience for
executive officers of
Pacific Gas and
Electric Company,
below.)
G. B. Stanley........ Senior Vice President, January 1, 1998 to current
Human Resources
Vice President, Human June 1, 1997 to December 31, 1997
Resources
Vice President, Human July 1, 1996 to May 31, 1997
Resources, Pacific Gas
and Electric Company
Self-employed (human January 1995 to June 1996
resources consultant)
Senior Vice President, January 1992 to December 1994
Human Resources, The
Gap, Inc. (retail
clothing)
Senior Vice President
B. R. Worthington.... and General Counsel June 1, 1997 to current
General Counsel December 18, 1996 to May 31, 1997
Senior Vice President
and General Counsel,
Pacific Gas and
Electric Company June 1, 1995 to June 30, 1997
Vice President and
General Counsel,
Pacific Gas and
Electric Company December 21, 1994 to May 31, 1995
Chief Counsel-Corporate,
Pacific Gas and
Electric Company January 10, 1991 to December 20, 1994
"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 1997 POSITION
---- ------------ --------
G. R. Smith.......... 49 President and Chief Executive Officer
K. M. Harvey......... 39 Senior Vice President, Chief Financial
Officer and Treasurer
E. J. Macias......... 43 Senior Vice President and General
Manager, Generation, Transmission, and
Supply Business Unit
R. J. Peters......... 47 Vice President and General Counsel
J. K. Randolph....... 53 Senior Vice President and General
Manager, Distribution and Customer
Service Business Unit
D. D. Richard, Jr.... 47 Senior Vice President, Governmental and
Regulatory Relations
G. M. Rueger......... 47 Senior Vice President and General
Manager, Nuclear Power Generation
Business Unit
51
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 current
Executive Officer
Chief Financial Officer, December 18, 1996 to May 31, 1997
PG&E Corporation
Senior Vice President June 1, 1995 to May 31, 1997
and Chief Financial
Officer
Vice President and Chief November 1, 1991 to May 31, 1995
Financial Officer
K. M. Harvey......... Senior Vice President, July 1, 1997 to current
Chief Financial
Officer, and Treasurer
Vice President and June 1, 1995 to June 30, 1997
Treasurer
Treasurer August 1, 1993 to May 31, 1995
Corporate Secretary November 1, 1991 to July 31, 1993
E. J. Macias......... Senior Vice President July 1, 1997 to current
and General Manager,
Generation,
Transmission and Supply
Business Unit
Vice President and November 15, 1995 to June 30, 1997
General Manager,
Electric Transmission
Vice President, Power December 21, 1994 to November 14, 1995
System
Manager, Power Control March 1993 to December 20, 1994
and System Operation
R. J. Peters......... Vice President and July 1, 1997 to current
General Counsel
Chief Counsel, January 1, 1993 to June 30, 1997
Regulatory
J. K. Randolph....... Senior Vice President July 1, 1997 to current
and General Manager,
Distribution and
Customer Service
Business Unit
Vice President and January 1, 1997 to June 30, 1997
General Manager, Power
Generation
Vice President, Power November 1, 1991 to December 31, 1996
Generation
D. D. Richard, Jr.... Senior Vice President, July 1, 1997 to current
Governmental and
Regulatory Relations
Vice President, July 1, 1997 to current
Governmental Relations,
PG&E Corporation
Vice President, January 1, 1997 to June 30, 1997
Governmental Relations
Executive Vice President January 1993 to December 1996
and Principal, Morse,
Richard, Weisenmiller &
Assoc., Inc. (energy,
project finance, and
environmental
consulting)
G. M. Rueger......... Senior Vice President November 1, 1991 to current
and General Manager,
Nuclear Power
Generation Business
Unit
52
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS.
Information responding to part of Item 5, for each of PG&E Corporation and
Pacific Gas and Electric Company, is set forth on page 60 under the heading
"Quarterly Consolidated Financial Data (Unaudited)" in the 1997 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 has made no sales of unregistered equity
securities in the last three years. PG&E Corporation has made the following
sales of unregistered equity securities during such period:
On January 27, 1997, PG&E Corporation issued 14,607,143 shares of common
stock. The shares were issued to nine former shareholders of Teco in
connection with the acquisition of Teco by PG&E Corporation. PG&E
Corporation owns all the outstanding shares of Teco as a result of the
acquisition. The shares were issued in reliance upon the exemption from
registration under the Securities Act of 1933, as amended, pursuant to
Section 4(2) thereof and Rule 506 of Regulation D thereunder. All of the
former shareholders of Teco represented that they were "accredited
investors" as defined in Rule 501(a) under the Securities Act of 1933 and
made other representations establishing the basis for the exemption. A
legend as provided for by Rule 501(d)(3) was placed on each of the stock
certificates representing the shares of PG&E Corporation common stock
received by the former shareholders of Teco.
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 16 under the heading "Selected Financial Data" in the 1997
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 earnings to fixed charges ratio for the
year ended December 31, 1997, was 3.19. Pacific Gas and Electric Company's
earnings to combined fixed charges and preferred stock dividends ratio for the
year ended December 31, 1997, was 2.96. 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 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 17 through 30 under the heading "Management's Discussion and Analysis of
Consolidated Results of Operations and Financial Condition" in the 1997 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 concerning PG&E Corporation's and Pacific Gas and Electric
Company's market risk is set forth on page 28 in the table providing
information about debt obligations and rate reduction bonds under the heading
"Cash Flows From Financing Activities--Utility," and on page 30 under the
heading "Price Risk Management" in the 1997 Annual Report to Shareholders,
which discussion 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 is contained in the 1997 Annual Report to
Shareholders on pages 31 through 61 under the respective headings for each of
PG&E Corporation and Pacific Gas and Electric Company, "Statement of
Consolidated Income," "Consolidated Balance Sheet," "Statement of Consolidated
Cash Flows," "Statement
53
of Consolidated Common Stock Equity, Preferred Stock, and Preferred
Securities," "Notes to Consolidated Financial Statements," "Quarterly
Consolidated Financial Data (Unaudited)," and "Report of Independent Public
Accountants," 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.
None.
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 50 through 52 in Part I of this
report. Other information responding to Item 10 is included on pages 2 through
5 under the heading "Election of Directors of PG&E Corporation and Pacific Gas
and Electric Company" and page 35 under the heading "Section 16(a) Beneficial
Ownership Reporting Compliance" in the 1998 Joint Proxy Statement relating to
the 1998 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 page 8 under the heading
"Compensation of Directors" and on pages 28 through 33 under the heading
"Executive Compensation" (excluding the sections thereunder entitled
"Nominating and Compensation Committee Report on Compensation," "Comparison of
One-Year Total Shareholder Return," and "Comparison of Five-Year Cumulative
Total Shareholder Return") in the 1998 Joint Proxy Statement relating to the
1998 Annual Meetings of Shareholders, which information is hereby incorporated
by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
Information responding to Item 12, for each of PG&E Corporation and Pacific
Gas and Electric Company, is included on pages 10 and 11 under the heading
"Security Ownership of Management" and on page 34 under the heading "Principal
Shareholders" in the 1998 Joint Proxy Statement relating to the 1998 Annual
Meetings of Shareholders, which information is hereby incorporated by
reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
Information responding to Item 13, for each of PG&E Corporation and Pacific
Gas and Electric Company, is included on page 9 under the heading "Certain
Relationships and Related Transactions" in the 1998 Joint Proxy Statement
relating to the 1998 Annual Meetings of Shareholders, which information is
hereby incorporated by reference.
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 1997 Annual Report to Shareholders, are incorporated by
reference in this report:
Statements of Consolidated Income for the Years Ended December 31,
1997, 1996, and 1995, for each of PG&E Corporation and Pacific Gas
and Electric Company.
54
Statements of Consolidated Cash Flows for the Years Ended December
31, 1997, 1996, and 1995, for each of PG&E Corporation and Pacific
Gas and Electric Company.
Consolidated Balance Sheets at December 31, 1997, and 1996, for each
of PG&E Corporation and Pacific Gas and Electric Company.
Statements of Consolidated Common Stock Equity, Preferred Stock and
Preferred Securities for the Years Ended December 31, 1997, 1996,
and 1995, for each of PG&E Corporation and Pacific Gas and Electric
Company.
Notes to Consolidated Financial Statements.
Quarterly Consolidated Financial Data (Unaudited).
Report of Independent Public Accountants.
2. Report of Independent Public Accountants included at page 60 of this
Form 10-K.
3. Consolidated financial statement schedules:
I--Condensed Financial Information of Parent for the Year Ended
December 31, 1997.
II--Consolidated Valuation and Qualifying Accounts of PG&E
Corporation and Pacific Gas and Electric Company for the Years
Ended December 31, 1997, 1996 and 1995.
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.
4. 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 effective as of January 1, 1998.
3.3 Restated Articles of Incorporation of Pacific Gas and Electric
Company effective as of April 28, 1997 (Pacific Gas and
Electric Company's Form 10-Q for quarter ended June 30, 1997
(File No. 1-2348), Exhibit 3.1).
3.4 By-Laws of Pacific Gas and Electric Company as of January 1,
1998.
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).
10.1 Asset Purchase Agreement by and among New England Power
Company, The Narragansett Electric Company, and USGen
Acquisition Corporation, dated as of August 5, 1997 (PG&E
Corporation's Form 10-Q for the quarter ended September 30,
1997 (File No. 1-12609, Exhibit No. 10.1). Filed only as an
exhibit to the Annual Report on Form 10-K filed by PG&E
Corporation under Commission File Number 1-12609.
10.2 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.
55
*10.3 Agreement regarding certain payments between U.S. Generating
Company and Joseph Kearney. (PG&E Corporation's Form 10-Q for
the quarter ended September 30, 1997 (File No. 1-12609),
Exhibit 10.2.) Filed only as an exhibit to the Annual Report
on Form 10-K filed by PG&E Corporation under Commission File
Number 1-12609. Confidential treatment of information omitted
from this exhibit has been granted by the Commission until
December 31, 1999. Omitted information has been filed
separately with the Commission.
*10.4 PG&E Corporation Deferred Compensation Plan for Directors.
*10.5 PG&E Corporation Deferred Compensation Plan for Officers.
*10.6 The Pacific Gas and Electric Company Savings Fund Plan for
Non-Union Employees, as amended and restated effective as of
October 1, 1997.
*10.7 Short-Term Incentive Plan for Officers of Pacific Gas and
Electric Company, effective January 1, 1996 (Pacific Gas and
Electric Company's Form 10-K for fiscal year 1995 (File No. 1-
2348), Exhibit 10.7).
*10.8 The Pacific Gas and Electric Company Retirement Plan
applicable to non-union employees, as amended October 15,
1997, effective January 1, 1998.
*10.9 Supplemental Executive Retirement Plan of the Pacific Gas and
Electric Company, as amended through October 16, 1991 (Pacific
Gas and Electric Company's Form 10-K for fiscal year 1991
(File No. 1-2348), Exhibit 10.11).
*10.10 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).
*10.11 Pacific Gas and Electric Company Executive Flexible
Perquisites Program (Pacific Gas and Electric Company's Form
10-K for fiscal year 1993 (File No. 1-2348), Exhibit 10.16).
*10.12 The 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).
*10.13 PG&E Corporation Retirement Plan for Non-Employee Directors,
as amended and terminated January 1, 1998.
*10.14 Executive Compensation Insurance Indemnity in respect of
Deferred Compensation Plan for Directors, Deferred
Compensation Plan for Officers, Supplemental Executive
Retirement Plan and Retirement Plan for Non-Employee
Directors (Pacific Gas and Electric Company's Form 10-K for
fiscal year 1991 (File No. 1-2348), Exhibit 10.19).
*10.15 PG&E Corporation Long-Term Incentive Program, as amended and
restated effective as of January 1, 1998, including the PG&E
Corporation Stock Option Plan, Performance Unit Plan, and
Non-Employee Director Stock Incentive Plan.
*10.16 PG&E Corporation Executive Stock Ownership Program, effective
January 1, 1998.
- --------
* 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.
56
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. 1997 Annual Report to Shareholders of PG&E Corporation and
Pacific Gas and Electric Company (portions of the 1997 Annual
Report to Shareholders under the headings "Selected Financial
Data," "Management's Discussion and Analysis of Consolidated
Results of Operations and Financial Condition," "Report of
Independent Public Accountants," and for each of PG&E
Corporation and Pacific Gas and Electric Company, "Statement of
Consolidated Income," "Consolidated Balance Sheet," "Statement
of Consolidated Cash Flows," "Statement of Consolidated Common
Stock
Equity, Preferred Stock and Preferred Securities," "Notes to
Consolidated Financial Statements" and "Quarterly Consolidated
Financial Data (Unaudited)" included only) (except for those
portions which are expressly incorporated herein by reference,
such 1997 Annual Report to Shareholders is furnished for the
information of the Commission and is not deemed to be "filed"
herein).
21. Subsidiaries of the Registrant (incorporated by reference from
PG&E Corporation's Statement by Holding Company Claiming
Exemption from the Public Utility Holding Act of 1935 under Rule
2 by filing Form U-3A-2 dated February 27, 1998, pages 1 through
33 (File No. 1-12609).
23. 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, 1997,
for PG&E Corporation.
27.2 Financial Data Schedule for the year ended December 31, 1997,
for Pacific Gas and Electric Company.
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 as indicated 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, 1997, and
through the date hereof:
1. October 16, 1997
Item 5. Other Events
-- Performance Incentive Plan--Year-to-Date Financial Results
57
2. November 24, 1997
Item 5. Other Events
A. Electric Industry Restructuring
B. Gas Accord
3. December 19, 1997
Item 5. Other Events
A. Electric Industry Restructuring
B. CPUC Regulatory Proceedings
C. Common Stock Repurchase Authorization
4. January 22, 1998 (As amended by Form 8-K/A dated February 5, 1998.)
Item 5. Other Events
A. Performance Incentive Plan--Year-to-Date Financial Results
B. 1997 Consolidated Earnings (unaudited)
C. Accelerated Stock Repurchase Program
- --------
(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)
58
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 5TH DAY OF MARCH, 1998.
PG&E CORPORATION PACIFIC GAS AND ELECTRIC COMPANY
(Registrant) (Registrant)
/s/ GARY P. ENCINAS /s/ GARY P. ENCINAS
By _________________________________ By _________________________________
(Gary P. Encinas, Attorney-in-Fact) (Gary P. Encinas, Attorney-in-
Fact)
PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS
REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE
REGISTRANTS AND IN THE CAPACITIES AND ON THE DATES INDICATED.
SIGNATURE TITLE DATE
--------- ----- ----
A. PRINCIPAL EXECUTIVE
OFFICERS
*ROBERT D. GLYNN Chairman of the Board of March 5, 1998
Directors,
Chief Executive Officer, and
*GORDON R. SMITH President
(PG&E Corporation)
President and Chief Executive
Officer
(Pacific Gas and Electric
Company)
B. PRINCIPAL FINANCIAL
OFFICERS
MICHAEL E. RESCOE /s/ MICHAEL E. RESCOE March 5, 1998
Senior Vice President, Treasurer,
and
Chief Financial Officer
(PG&E Corporation)
*KENT M. HARVEY Senior Vice President, Treasurer,
and
Chief Financial Officer
(Pacific Gas and Electric
Company)
C. PRINCIPAL ACCOUNTING
OFFICER
*CHRISTOPHER P. JOHNS Vice President and Controller March 5, 1998
(PG&E Corporation)
Vice President and Controller
(Pacific Gas and Electric
Company)
D. DIRECTORS
*RICHARD A. CLARKE
*H. M. CONGER
*DAVID A. COULTER
*C. LEE COX
*WILLIAM S. DAVILA
*ROBERT D. GLYNN, JR.
*DAVID M. LAWRENCE
*RICHARD B. MADDEN
*MARY S. METZ Directors of PG&E Corporation and
*REBECCA Q. MORGAN Pacific Gas and Electric March 5, 1998
Company,
*CARL E. REICHARDT except as noted
*JOHN C. SAWHILL
*GORDON R. SMITH
(Director of Pacific Gas
and
Electric Company, only)
*BARRY LAWSON WILLIAMS
/s/ GARY P. ENCINAS
*By ________________________________
(Gary P. Encinas, Attorney-in-Fact)
59
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 included in the PG&E Corporation and
Pacific Gas and Electric Company Annual Report to Shareholders incorporated by
reference in this Annual Report on Form 10-K, and have issued our report
thereon dated February 9, 1998. 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)(3) of this Annual Report on 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 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.
/s/ ARTHUR ANDERSEN LLP
_______________________
ARTHUR ANDERSEN LLP
San Francisco, California
February 9, 1998
60
SCHEDULE I - CONDENSED FINANCIAL
INFORMATION OF PARENT
CONDENSED BALANCE SHEET
December 31,
1997
-------------
(In millions)
Assets:
Cash and cash equivalents................................ $ 1
Other current assets..................................... 149
------
Total current assets................................. 150
Investments in subsidiaries.............................. 9,600
Other deferred charges................................... 1
------
Total Assets......................................... $9,751
======
Liabilities and Stockholders' Equity:
Current Liabilities
Accounts payable
Related parties.................................... $ 635
Other.............................................. 10
Accrued taxes........................................ 46
Dividends payable.................................... 118
------
Total current liabilities............................ 809
Noncurrent Liabilities................................... 1
Stockholders' Equity
Common stock......................................... 6,366
Reinvested earnings.................................. 2,575
------
Total stockholders' equity........................... 8,941
------
Total Liabilities and Stockholders' Equity........... $9,751
======
CONDENSED STATEMENT OF INCOME
FOR THE YEAR ENDED DECEMBER 31, 1997
1997
----------
(In millions, except per share amounts)
Equity in earnings of subsidiaries....................... $ 743
Operating expenses....................................... (21)
Interest expense......................................... (23)
------
Income Before Income Taxes............................... 699
Income taxes............................................. (17)
------
Net Income............................................... $ 716
======
Weighted Average Common Shares Outstanding............... 410
Earnings Per Common Share................................ $ 1.75
======
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF PARENT (CONTINUED)
CONDENSED STATEMENT OF CASH FLOWS
FOR THE YEAR ENDED DECEMBER 31, 1997
1997
----------
(in millions)
Cash Flows From Operating Activities
Net income............................................... $ 716
Adjustments to reconcile net income to net cash
provided by operating activities:
Dividends received from consolidated subsidiaries.. 763
Other-net.......................................... (167)
-------
Net cash provided by operating activities................ $ 1,312
Cash Flows From Investing Activities..................... (150)
Cash Flows From Financing Activities
Common stock repurchased........................... (804)
Dividends paid..................................... (367)
Other-net.......................................... 10
-------
Net cash used by financing activities.................... (1,161)
Net Change in Cash and Cash Equivalents.................. 1
Cash and Cash Equivalents at January 1................... 0
-------
Cash and Cash Equivalents at December 31................. $ 1
=======
PG&E CORPORATION
SCHEDULE II -- CONSOLIDATED VALUATION AND
QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 1997, 1996, AND 1995
Column A Column B Column C Column D Column E
Additions
---------------------
Balance Charged
at to Costs Charged Balance
Beginning and to Other at End of
Description of Period Expenses Accounts Deductions Period
------------ --------- ---------- --------- ------------ ---------
(in thousands)
VALUATION AND QUALIFYING ACCOUNTS
DEDUCTED FROM ASSETS:
1997:
Allowance for uncollectible accounts............... $57,904 $42,500 $ 0 $ 27,492(2) $72,912
======= ======= ======= ========= =======
1996:
Reserve for deferred project costs................. $ 5,710 $ -- $ -- $ 5,710(1) $ 0
======= ======= ======= ========= =======
Allowance for uncollectible accounts............... $35,520 $55,566 $ 1,836 $ 35,018(2) $57,904
======= ======= ======= ========= =======
Reserve for land costs............................. $ 4,444 $ -- $ -- $ 4,444(1) $ 0
======= ======= ======= ========= =======
1995:
Reserve for impairment of oil and gas
properties....................................... $ 4,341 $ -- $ -- $ 4,341(3) $ 0
======= ======= ======= ========= =======
Reserve for deferred project costs................. $25,800 $ -- $ -- $ 20,090(1) $ 5,710
======= ======= ======= ========= =======
Allowance for uncollectible accounts............... $29,769 $50,327 $ -- $ 44,576(2) $35,520
======= ======= ======= ========= =======
Reserve for land costs............................. $ 5,960 $ -- $ -- $ 1,516(1) $ 4,444
======= ======= ======= ========= =======
(1) Deductions consist principally of write-offs. Reserve for deferred project
costs and reserve for land costs are classified on the balance sheet
in other noncurrents assets.
(2) Deductions consist principally of write-offs, net of collections of
receivables previously written off.
(3) Deductions consist principally of write-offs of expired leaseholds on
reserved property. Deduction in 1995 results from sale of oil and gas
properties.
PACIFIC GAS AND ELECTRIC COMPANY
SCHEDULE II -- CONSOLIDATED VALUATION AND
QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 1997, 1996, AND 1995
Column A Column B Column C Column D Column E
Additions
---------------------
Balance Charged
at to Costs Charged Balance
Beginning and to Other at End of
Description of Period Expenses Accounts Deductions Period
------------ --------- ---------- --------- ------------ ---------
(in thousands)
VALUATION AND QUALIFYING ACCOUNTS
DEDUCTED FROM ASSETS:
1997:
Allowance for uncollectible accounts............... $57,904 $30,718 ($ 1,836) $ 27,178(2) $59,608
======= ======= ======= ========= =======
1996:
Reserve for deferred project costs................. $ 5,710 $ -- $ -- $ 5,710(1) $ 0
======= ======= ======= ========= =======
Allowance for uncollectible accounts............... $35,520 $55,566 $ 1,836 $ 35,018(2) $57,904
======= ======= ======= ========= =======
Reserve for land costs............................. $ 4,444 $ -- $ -- $ 4,444(1) $ 0
======= ======= ======= ========= =======
1995:
Reserve for impairment of oil and gas
properties....................................... $ 4,341 $ -- $ -- $ 4,341(3) $ 0
======= ======= ======= ========= =======
Reserve for deferred project costs................. $25,800 $ -- $ -- $ 20,090(1) $ 5,710
======= ======= ======= ========= =======
Allowance for uncollectible accounts............... $29,769 $50,327 $ -- $ 44,576(2) $35,520
======= ======= ======= ========= =======
Reserve for land costs............................. $ 5,960 $ -- $ -- $ 1,516(1) $ 4,444
======= ======= ======= ========= =======
(1) Deductions consist principally of write-offs. Reserve for deferred project
costs and reserve for land costs are classified on the balance sheet in
other noncurrent assets.
(2) Deductions consist principally of write-offs, net of collections of
receivables previously written off.
(3) Deductions consist principally of write-offs of expired leaseholds on
reserved property. Deduction in 1995 results from sale of oil and gas
properties.
EXHIBIT INDEX
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 effective as of January 1, 1998.
3.3 Restated Articles of Incorporation of Pacific Gas and Electric
Company effective as of April 28, 1997 (Pacific Gas and
Electric Company's Form 10-Q for quarter ended June 30, 1997
(File No. 1-2348), Exhibit 3.1).
3.4 By-Laws of Pacific Gas and Electric Company as of January 1,
1998.
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).
10.1 Asset Purchase Agreement by and among New England Power
Company, The Narragansett Electric Company, and USGen
Acquisition Corporation, dated as of August 5, 1997 (PG&E
Corporation's Form 10-Q for the quarter ended September 30,
1997 (File No. 1-12609, Exhibit No. 10.1). Filed only as an
exhibit to the Annual Report on Form 10-K filed by PG&E
Corporation under Commission File Number 1-12609.
10.2 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.
1
*10.3 Agreement regarding certain payments between U.S. Generating
Company and Joseph Kearney. (PG&E Corporation's Form 10-Q for
the quarter ended September 30, 1997 (File No. 1-12609),
Exhibit 10.2.) Filed only as an exhibit to the Annual Report
on Form 10-K filed by PG&E Corporation under Commission File
Number 1-12609. Confidential treatment of information omitted
from this exhibit has been granted by the Commission until
December 31, 1999. Omitted information has been filed
separately with the Commission.
*10.4 PG&E Corporation Deferred Compensation Plan for Directors.
*10.5 PG&E Corporation Deferred Compensation Plan for Officers.
*10.6 The Pacific Gas and Electric Company Savings Fund Plan for
Non-Union Employees, as amended and restated effective as of
October 1, 1997.
*10.7 Short-Term Incentive Plan for Officers of Pacific Gas and
Electric Company, effective January 1, 1996 (Pacific Gas and
Electric Company's Form 10-K for fiscal year 1995 (File No. 1-
2348), Exhibit 10.7).
*10.8 The Pacific Gas and Electric Company Retirement Plan
applicable to non-union employees, as amended October 15,
1997, effective January 1, 1998.
*10.9 Supplemental Executive Retirement Plan of the Pacific Gas and
Electric Company, as amended through October 16, 1991 (Pacific
Gas and Electric Company's Form 10-K for fiscal year 1991
(File No. 1-2348), Exhibit 10.11).
*10.10 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).
*10.11 Pacific Gas and Electric Company Executive Flexible
Perquisites Program (Pacific Gas and Electric Company's Form
10-K for fiscal year 1993 (File No. 1-2348), Exhibit 10.16).
*10.12 The 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).
*10.13 PG&E Corporation Retirement Plan for Non-Employee Directors,
as amended and terminated January 1, 1998.
*10.14 Executive Compensation Insurance Indemnity in respect of
Deferred Compensation Plan for Directors, Deferred
Compensation Plan for Officers, Supplemental Executive
Retirement Plan and Retirement Plan for Non-Employee
Directors (Pacific Gas and Electric Company's Form 10-K for
fiscal year 1991 (File No. 1-2348), Exhibit 10.19).
*10.15 PG&E Corporation Long-Term Incentive Program, as amended and
restated effective as of January 1, 1998, including the PG&E
Corporation Stock Option Plan, Performance Unit Plan, and
Non-Employee Director Stock Incentive Plan.
*10.16 PG&E Corporation Executive Stock Ownership Program, effective
January 1, 1998.
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* 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.
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. 1997 Annual Report to Shareholders of PG&E Corporation and
Pacific Gas and Electric Company (portions of the 1997 Annual
Report to Shareholders under the headings "Selected Financial
Data," "Management's Discussion and Analysis of Consolidated
Results of Operations and Financial Condition," "Report of
Independent Public Accountants," and for each of PG&E
Corporation and Pacific Gas and Electric Company, "Statement of
Consolidated Income," "Consolidated Balance Sheet," "Statement
of Consolidated Cash Flows," "Statement of Consolidated Common
Stock
Equity, Preferred Stock and Preferred Securities," "Notes to
Consolidated Financial Statements" and "Quarterly Consolidated
Financial Data (Unaudited)" included only) (except for those
portions which are expressly incorporated herein by reference,
such 1997 Annual Report to Shareholders is furnished for the
information of the Commission and is not deemed to be "filed"
herein).
21. Subsidiaries of the Registrant (incorporated by reference from
PG&E Corporation's Statement by Holding Company Claiming
Exemption from the Public Utility Holding Act of 1935 under Rule
2 by filing Form U-3A-2 dated February 27, 1998, pages 1 through
33 (File No. 1-12609).
23. 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, 1997,
for PG&E Corporation.
27.2 Financial Data Schedule for the year ended December 31, 1997,
for Pacific Gas and Electric Company.
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 as indicated 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, 1997, and
through the date hereof:
1. October 16, 1997
Item 5. Other Events
-- Performance Incentive Plan--Year-to-Date Financial Results
3