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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year Ended December 31, 1998
OR
[_] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
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Commission Exact Name of Registrant IRS Employer
File as specified in its State of Identification
Number charter Incorporation Number
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<C> <S> <C> <C> <C>
1-12609 PG&E CORPORATION California 94-3234914
1-2348 PACIFIC GAS AND ELECTRIC California 94-0742640
COMPANY
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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
(Zip Code)
94177
(Zip Code) (415) 267-7000
(Registrant's telephone number,
(415) 973-7000 including area code)
(Registrant's telephone number,
including area code)
Securities registered pursuant to Section 12(b) of the Act:
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Name of Each Exchange on
Title of Each Class Which Registered
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PG&E Corporation
Common Stock, no par value New York Stock Exchange and
Pacific Exchange
Pacific Gas and Electric Company
First Preferred Stock, cumulative, American Stock Exchange and
par value $25 per share: Pacific Exchange
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Redeemable: 7.04%, 5% Series A, 5%, 4.80%, 4.50%, 4.36%.
Mandatorily Redeemable: 6.57%, 6.30%
Nonredeemable: 6%, 5.50%, 5%
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7.90% Cumulative Quarterly Income Preferred American Stock Exchange and
Securities, Series A (liquidation preference Pacific Exchange
$25), issued by PG&E Capital I and guaranteed
by Pacific Gas and Electric Company
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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 22, 1999:
PG&E Corporation Common Stock $11,810 million
Pacific Gas and Electric Company First Preferred Stock $422 million
Common Stock outstanding as of February 22, 1999:
PG&E Corporation: 382,964,605
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.
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(1) Designated portions of the combined
Annual Report to Shareholders for the year
ended December 31, 1998................... Part II (Items 5, 6, 7.7A and 8)
Part IV (Item 14)
(2) Designated portions of the Joint Proxy
Statement relating to the 1999 Annual
Meetings of Shareholders.................. Part III (Items 10, 11, 12 and 13)
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TABLE OF CONTENTS
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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..................................................... 4
Regulation of Pacific Gas and Electric Company................... 5
State Regulation................................................. 5
Federal Regulation............................................... 6
Licenses and Permits............................................. 6
Regulation of PG&E Corporation and Other Subsidiaries............ 6
PG&E Corporation................................................. 6
Wholesale Operations of Affiliates............................... 7
Capital Requirements and Financing Programs...................... 9
Price Risk Management Programs................................... 10
Year 2000 Matters................................................ 10
UTILITY OPERATIONS............................................... 11
California Ratemaking Mechanisms................................. 11
Electric Ratemaking.............................................. 12
Gas Ratemaking................................................... 13
Electric Utility Operations...................................... 14
Implementation of Electric Industry Restructuring................ 14
Independent System Operator and Power Exchange................... 14
Voluntary Generation Asset Divestiture........................... 15
Direct Access.................................................... 16
Electric Base Revenue Increase................................... 16
Rate Levels and Rate Reduction Bonds............................. 17
Recovery of Transition Costs..................................... 17
Public Purpose Programs.......................................... 18
Electric Operating Statistics.................................... 19
Electric Generating Capacity..................................... 20
Diablo Canyon.................................................... 21
Diablo Canyon Operations......................................... 21
Diablo Canyon Ratemaking......................................... 21
Nuclear Fuel Supply and Disposal................................. 22
Insurance........................................................ 23
Decommissioning.................................................. 23
Other Electric Resources......................................... 24
QF Generation and Other Power-Purchase Contracts................. 24
Geothermal Generation............................................ 25
Electric Transmission and Distribution........................... 25
Gas Utility Operations........................................... 26
Gas Operating Statistics......................................... 27
Natural Gas Supplies............................................. 28
Gas Regulatory Framework......................................... 28
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TABLE OF CONTENTS--(Continued)
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Transportation Commitments.................................... 29
Core Procurement Incentive Mechanism.......................... 30
PGT/Pacific Gas and Electric Company Pipeline Expansion....... 30
WHOLESALE OPERATIONS OF AFFILIATES............................ 31
Gas Transmission Operations................................... 31
Independent Power Generation.................................. 31
Portfolio of Operating Generating Plants...................... 34
Energy Trading................................................ 35
RETAIL OPERATIONS OF AFFILIATES............................... 35
Energy Services............................................... 35
ENVIRONMENTAL MATTERS......................................... 36
Environmental Matters......................................... 36
Environmental Protection Measures............................. 36
Air Quality................................................... 36
Water Quality................................................. 37
Hazardous Waste Compliance and Remediation.................... 38
Potential Recovery of Hazardous Waste Compliance and
Remediation Costs............................................. 39
Compressor Station Litigation................................. 40
Electric and Magnetic Fields.................................. 40
Low Emission Vehicle Programs................................. 41
Item 2. Properties.................................................... 41
Item 3. Legal Proceedings............................................. 41
Compressor Station Chromium Litigation........................ 41
Texas Franchise Fee Litigation................................ 42
Item 4. Submission of Matters to a Vote of Security Holders........... 44
EXECUTIVE OFFICERS OF THE REGISTRANTS......................... 45
PART II
Item 5. Market for the Registrant's Common Equity and Related
Stockholder Matters........................................... 48
Item 6. Selected Financial Data....................................... 48
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations..................................... 48
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.... 48
Item 8. Financial Statements and Supplementary Data................... 49
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure...................................... 49
PART III
Item 10. Directors and Executive Officers of the Registrant............ 49
Item 11. Executive Compensation........................................ 49
Item 12. Security Ownership of Certain Beneficial Owners and
Management.................................................... 49
Item 13. Certain Relationships and Related Transactions................ 49
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form
8-K........................................................... 50
Signatures.................................................... 54
Report of Independent Public Accountants...................... 55
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GLOSSARY OF TERMS
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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
ATCP.............. Annual Transition Cost Proceeding
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
CARE.............. California Alternate Rates for Energy
CCAA.............. California Clean Air Act
CEC............... California Energy Commission
CEMA.............. Catastrophic Emergency Memorandum Account
Central Coast
Board............ Central Coast Regional Water Quality Control Board
CERCLA............ Comprehensive Environmental Response, Compensation, and
Liability Act
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
EDRA.............. Electric Deferred Refund Account
El Paso........... El Paso Natural Gas Company
EMF............... electric and magnetic fields
EPA............... United States Environmental Protection Agency
FERC.............. Federal Energy Regulatory Commission
Gas Accord........ Gas Accord Settlement
Geysers........... The Geysers Power Plant
GRC............... General Rate Case
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
IPP............... Independent power producer
ISO............... Independent System Operator
ITCBA............. Interim Transition Cost Balancing Account
ITCS.............. Interstate Transition Cost Surcharge
kV................ kilovolts
kVa............... kilovolt-amperes
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kW................ kilowatts
kWh............... kilowatt-hour
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, a division of the California
Public Utilities Commission
PBR............... performance-based ratemaking
PG&E Expansion.... the Pacific Gas and Electric Company portion of the
Pipeline Expansion
PG&E 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 GTT.......... PG&E Gas Transmission, Texas Corporation
PG&E ET........... PG&E Corporation's energy commodities activities, PG&E
Energy Trading or PG&E ET
PGT Expansion..... 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
SOS............... Standard Offer Service
Teco.............. Teco Pipeline Company
TRA............... Transition Revenue Account
transition the period during which electric rates are frozen at 1996
period........... 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
USGen............. U.S. Generating Company, LLC and its affiliates
USGenNE........... USGen New England, Inc.
USOSC............. U.S. Operating Services Company
Valero............ Valero Energy Corporation
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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 North America. Effective January 1,
1997, Pacific Gas and Electric Company (sometimes referred to herein as the
"Company") and its subsidiaries became subsidiaries of PG&E Corporation, which
was incorporated in 1995. Pacific Gas and Electric Company, incorporated in
California in 1905, is an operating public utility primarily regulated by the
California Public Utilities Commission (CPUC) and engaged principally in the
business of providing electric and natural gas services throughout most of
Northern and Central California. 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. Because PG&E Corporation did not become the
holding company for Pacific Gas and Electric Company until January 1, 1997,
the 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 its
telephone number is (415) 267-7000. The principal executive offices of Pacific
Gas and Electric Company are located at 77 Beale Street, P.O. Box 770000, San
Francisco, California 94177, and its telephone number is (415) 973-7000.
As of December 31, 1998, PG&E Corporation had $33.2 billion in assets. PG&E
Corporation generated $19.9 billion in operating revenues for 1998. As of
December 31, 1998, PG&E Corporation and its subsidiaries and affiliates had
approximately 23,300 employees. As of December 31, 1998, Pacific Gas and
Electric Company had $23 billion in assets. The Company generated $8.9 billion
in operating revenues for 1998. As of December 31, 1998, Pacific Gas and
Electric Company had approximately 19,800 employees.
In addition to the regulated utility business of Pacific Gas and Electric
Company, PG&E Corporation's other affiliated businesses include the ownership
and operation of natural gas pipelines, natural gas storage facilities, and
natural gas processing plants, primarily in the Pacific Northwest and Texas,
through various subsidiaries of PG&E Corporation (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,
LLC and its affiliates (USGen); 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). On
September 1, 1998, PG&E Corporation, through its indirect subsidiary, USGen
New England, Inc. (USGenNE), completed the acquisition of a portfolio of
electric generating assets and power supply contracts from the New England
Electric System (NEES) for approximately $1.59 billion plus $85 million for
certain employee-related costs. See "Wholesale Operations of Affiliates--
Independent Power Generation" below.
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The gas and electric utility operations of Pacific Gas and Electric Company
represent the principal component of PG&E Corporation's business, contributing
45% of PG&E Corporation's total revenues in 1998. Pacific Gas and Electric
Company's utility operations contributed $1.82 of PG&E Corporation's total
1998 earnings per share of $1.88.
Pacific Gas and Electric Company's utility service territory covers 70,000
square miles with an estimated population of approximately 13 million and
includes all or portions of 48 of California's 58 counties. The area's diverse
economy includes aerospace, electronics, financial services, food processing,
petroleum refining, agriculture, and tourism.
At December 31, 1998, Pacific Gas and Electric Company served approximately
4.6 million electric customers. In 1998, 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, on July 1, 1998, the Company sold three fossil-fueled power
plants which included six steam units and three combustion turbines. In late
1998 and in January 1999, the Company entered into agreements to sell three of
its five remaining fossil-fueled power plants, which include 10 steam units
and three combustion turbines, and its geothermal facilities. The sales are
expected to be completed in 1999. See "Utility Operations--Electric Utility
Operations--Implementation of Electric Industry Restructuring" below.) The
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, the 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 3.8 million gas
customers at December 31, 1998. Most of these customers continue to obtain gas
supplies from the Company under regulated tariff rates. To ensure a diverse
and competitive mix of natural gas supplies to serve customers that choose the
Company as its supplier, the Company directly purchases gas from producers and
marketers in both Canada and the United States. In 1998, about 68% of the
Company's gas supply was purchased in Canada, about 4% was purchased in
California, and about 28% was purchased in the U.S. Southwest.
In 1998, California became one of the first states in the nation to
implement an electric industry restructuring plan. (The framework of this plan
was established by Assembly Bill 1890 (AB 1890) passed by the California
Legislature and signed by the Governor in 1996.) In California, electric
customers may choose to purchase their electricity from investor-owned
utilities (such as Pacific Gas and Electric Company), unregulated retail
electricity providers (such as marketers, including PG&E Energy Services,
brokers, and aggregators), or unregulated power generators, on a competitive
basis (i.e., "direct access"). The California restructuring plan contemplates
that the investor-owned utilities (such as Pacific Gas and Electric Company)
will continue to provide distribution services to substantially all customers
within their service territories. In November 1998, the California voters
defeated Proposition 9, a voter initiative which would have overturned major
portions of AB 1890 if it had been approved. See "Utility Operations--Electric
Utility Operations--Implementation of Electric Industry Restructuring" below.
The following information includes forward-looking statements about the
future that involve a number of risks and uncertainties. Words such as
"estimates," "expects," "intends," "anticipates," and "plans," and similar
expressions identify those statements which are forward-looking. These
forward-looking statements are based on management's beliefs and assumptions
and on information currently available to management. Actual results could
differ materially from those contemplated by the forward-looking statements.
Some of the factors that could cause actual results to differ materially from
those contemplated in the forward-looking statements include, but are not
limited to, the pace and extent of the ongoing restructuring of the electric
and gas industries across the United States; the outcome of regulatory and
legislative proceedings and operational changes related to industry
restructuring; any changes in the amount Pacific Gas and Electric Company is
allowed to collect
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(recover) from its customers for certain costs which prove to be uneconomic
under the new competitive market (called transition costs) in accordance with
the Company's plan for recovering those costs; the successful integration and
performance of recently acquired assets; the Corporation's ability to
successfully compete outside of the traditional regulated markets; the ability
to lessen the risk of the impact of the Year 2000 on internal and external
computer and software systems; the outcome of ongoing regulatory proceedings,
including Pacific Gas and Electric Company's pending General Rate Case which
will determine whether the Company will have the opportunity to earn its
authorized rate of return, the Cost of Capital proceeding, which will
determine the amount of return the Company will be authorized to earn on its
assets and recover from ratepayers, the Company's proposal to adopt
performance-based ratemaking, the Company's electric transmission rate case
applications, and the CPUC's proceeding relating to the Company's affiliate
transactions; fluctuations in commodity gas and electric prices and the
ability to successfully manage such price fluctuations; and the pace and
extent of competition in the California generation market and its impact on
the Company's costs and resulting collection of transition costs. As the
ultimate impacts of these and other factors is uncertain, these and other
factors may cause future results to differ materially from results or outcomes
currently expected or sought by PG&E Corporation.
Competition and the Changing Regulatory Environment
The electric and gas industries are 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 traditional regulatory framework
to one in which competition is allowed in certain segments of the gas and
electric industries.
In 1998, a significant portion of Pacific Gas and Electric Company's
business was transformed from the traditional monopoly structure to a
competitive operation. The return on Diablo Canyon and certain other
generation assets continued to be significantly lower in 1998 than historical
levels and will remain at this lower level throughout the transition period.
See "Utility Operations--Electric Utility Operations--Diablo Canyon--Diablo
Canyon Ratemaking" below. The new competitive environment and the regulatory
decisions made in the context of electric and gas industry restructuring will
continue to affect PG&E Corporation's financial results and may result in
greater earnings volatility. The changes in both the electric and gas
industries, as described below, require the Company to develop and implement
changes to its business processes and systems, including customer information
and billing systems, to accommodate electric and gas industry restructuring.
To the extent the Company is unable to successfully and timely develop and
implement such changes, there could be an adverse impact on the Company's
future results of operations.
Electric Industry
In 1998, California became one of the first states in the nation to
implement an electric industry restructuring plan, the framework of which was
established by AB 1890. Pursuant to AB 1890, on January 1, 1997, electric
rates were frozen, at the levels in effect on June 10, 1996, until the earlier
of March 31, 2002, or when the particular utility has recovered its
generation-related transition costs (the transition period). The following key
features of AB 1890 have been implemented:
--Mandatory unbundling of transmission, distribution, and generation
services, although the utilities must continue to offer bundled electric
service to customers who wish to continue receiving it from the utility.
--Commencement of operations of the California Power Exchange (PX) which
provides a competitive auction process to establish a transparent market
clearing price for electricity in California.
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--Relinquishment of control (but not ownership or maintenance) of the
utilities' transmission facilities to the California Independent System
Operator (ISO).
--Commencement of operations of the ISO which ensures system reliability
and provides electric market participants with open and comparable access
to transmission services.
--A 10% reduction in the previously frozen rates, effective January 1,
1998, through the end of the transition period, for residential and small
commercial customers.
--The issuance of rate reduction bonds in December 1997 to finance the 10%
rate reduction.
--Collection of a nonbypassable charge (the competition transition charge
or CTC) to provide the opportunity for utilities to recover their
transition costs.
--Accelerated recovery of transition costs associated with utility-owned
generation facilities.
--Commencement of direct access to competitive generation resources for all
retail electric customers on March 31, 1998.
--Commencement of the market valuation process for utility-owned non-
nuclear generation assets, to be completed by 2001.
For more information about California electric industry restructuring, see
"Utility Operations--Electric Utility Operations--Implementation of Electric
Industry Restructuring" below.
Other states also have moved forward with their electric industry
restructuring plans to increase competition. PG&E Corporation's national
energy strategy includes active pursuit of opportunities created by the
gradual deregulation of the electric industry across the nation. PG&E
Corporation's ability to anticipate and capture profitable business
opportunities created by deregulation will have a significant impact on the
Corporation's future operating results.
Additional information concerning electric industry restructuring and the
financial impact of these changes on PG&E Corporation is provided in
"Management's Discussion and Analysis" in the 1998 Annual Report to
Shareholders, beginning on page 18, and in Note 2 of the "Notes to
Consolidated Financial Statements" beginning on page 49 of the 1998 Annual
Report to Shareholders.
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.
Regulators and legislators are using "unbundling" (separating the various
services and the pricing of those services) to increase competition for non-
monopoly energy services and to increase choices for customers. In the gas
industry, Federal Energy Regulatory Commission (FERC) Order 636 required
interstate pipeline companies to divide their services into separate sales,
transportation, and storage services. Under Order 636, interstate pipelines
must provide transportation service regardless of whether the customer
(typically a local gas distribution company) buys the gas commodity from the
pipeline.
During 1998, the California gas industry continued to be restructured
pursuant to the Gas Accord Settlement, a multi-party agreement approved by the
CPUC in 1997 (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.
Pacific Gas and Electric Company's customers may buy gas directly from
competing suppliers and purchase transmission-only and distribution-only
services from Pacific Gas and Electric Company. The Company's
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transmission and distribution services historically have 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.
The Gas Accord increases opportunities for Pacific Gas and Electric
Company's core customers to purchase gas from competing suppliers and,
therefore, may 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, Pacific Gas and Electric Company's core gas
procurement costs for the period 1994 to 2002 are recoverable under a core
procurement incentive mechanism (CPIM), a form of incentive regulation. The
CPIM provides the Company with a direct financial incentive to procure gas and
transportation services at the lowest reasonable costs by comparing all
procurement costs to an aggregate market-based benchmark. If costs fall within
a range (tolerance band) around the benchmark, costs are deemed reasonable and
fully recoverable from ratepayers. If the Company's actual core procurement
costs fall outside the tolerance band, the Company's ratepayers and
shareholders share savings or costs, respectively.
The Gas Accord also established gas transmission and storage rates for the
period from March 1, 1998, through December 31, 2002. During this 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 rulemaking 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. In August 1998,
the Governor of California signed Senate Bill 1602, allowing the CPUC to
investigate issues associated with the further restructuring of natural gas
services. If the CPUC determines that further changes are in the public
interest, it is required to submit its findings to the Legislature. Senate
Bill 1602 prohibits the CPUC from adopting any decisions regarding gas
industry restructuring until January 1, 2000. The CPUC has completed hearings
dealing with market conditions and has indicated that it will issue a decision
identfiying the most promising structural changes for further study. The CPUC
will hold hearings in the future on safety issues associated with gas revenue
cycle service unbundling and the costs and benefits associated with the most
promising options. The CPUC then intends to conduct open public comment
meetings, develop consumer protection rules, and submit a report to the
Legislature setting forth its recommendations.
Additional information concerning gas industry restructuring, and the
financial impact of these changes on PG&E Corporation, is provided in
"Management's Discussion and Analysis" in the 1998 Annual Report to
Shareholders, beginning on page 18.
Regulation of Pacific Gas and Electric Company
State Regulation
The CPUC consists of five members appointed by the Governor (although there
are currently two vacancies) 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, in order to
determine its future policies.
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The California Energy Commission (CEC) has the responsibility to make
electric-demand forecasts for the state and for specific service territories.
Based upon these forecasts, the CEC determines the need for additional energy
sources and for conservation programs. The CEC sponsors alternative-energy
research and development projects, promotes energy conservation programs, and
maintains a statewide plan of action in case of energy shortages. In addition,
the CEC certifies power-plant sites and related facilities within California.
The CEC also administers funding for public purpose research and development,
and renewable technologies programs. The funding will be collected from
ratepayers through a nonbypassable public benefits charge. See "Utility
Operations--Electric Utility Operations--Implementation of Electric Industry
Restructuring--Public Purpose Programs" below.
Federal Regulation
The Federal Energy Regulatory Commission (FERC) regulates electric
transmission rates and access, operation of the California Independent System
Operator and the California Power Exchange, compliance with the uniform
systems of accounts, and electric contracts involving sales of electricity for
resale. The FERC also has jurisdiction over Pacific Gas and Electric Company's
electric transmission revenue requirements and 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 and the nuclear generating unit at Humboldt Bay Power Plant
(Unit 3). NRC regulations require extensive monitoring and review of the
safety, radiological, and environmental aspects of these facilities.
Licenses and Permits
Pacific Gas and Electric Company obtains a number of permits,
authorizations, and licenses in connection with the construction and operation
of its generating plants 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 being imposed by the
granting agency.
Regulation of PG&E Corporation and Other Subsidiaries
PG&E Corporation
PG&E Corporation and its subsidiaries are exempt from all provisions, except
Section 9(a)(2), of the federal 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
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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 if 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 has responded to the
audit report, and the CPUC held hearings in 1998 to determine if the
additional recommended conditions should be imposed on the holding company. On
February 23, 1999, a CPUC administrative law judge (ALJ) issued a proposed
decision which declines to adopt most of the recommended conditions, including
all of the financial conditions contested by the Company. Instead, the ALJ's
proposed decision directs the CPUC staff to prepare for the CPUC's
consideration a draft CPUC order to institute a generic proceeding to
determine whether the recommended financial conditions, or other appropriate
financial conditions, should be imposed on all California electric and gas
utilities within the CPUC's jurisdiction with respect to their holding company
operations. The ALJ's proposed decision also proposes to require Pacific Gas
and Electric Company to establish and maintain various accounting and internal
control practices and systems with respect to affiliate transactions. 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, the non-regulated energy marketing subsidiary of PG&E Corporation)
to compete in the affiliated utility's service territory, and also to use the
name and logo of their affiliated utility, provided that in California the
affiliate includes certain designated disclaimer language which emphasizes the
separateness of the entities and that the affiliate is not regulated by the
CPUC. The decision adopts complex and detailed rules requiring the separation
of regulated utilities and their non-regulated affiliates, and also contains
rules regarding information exchange 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 and
on September 17, 1998, the CPUC approved parts of the plan and ordered that
other parts be resubmitted. The Company has resubmitted its plan and expects
the CPUC to act on the plan in early 1999.
On December 17, 1998, the CPUC issued a decision establishing specific
penalties and enforcement procedures for affiliate rules violations. The
decision included a new requirement that utilities self-report for affiliate
rules violations, provided for an experimental advisory ruling process to be
established, and established an informal inquiry and a formal complaint
process.
Wholesale Operations of Affiliates
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. The FERC also regulates certain
transportation transactions on the intrastate pipelines pursuant to Section
311 of the Natural Gas Policy Act of 1978.
The Railroad Commission of Texas (RRC) regulates gas utilities, including
those owned by PG&E Corporation through PG&E Gas Transmission, Texas
Corporation, (PG&E GTT), PG&E Gas Transmission Teco, Inc., and other
affiliates operating in Texas. The RRC's gas proration rules govern the
wellhead production and purchase of gas. Intrastate pipelines can provide
intrastate gas transportation at negotiated rates which are
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presumed just and reasonable. If the criteria for negotiated rates cannot be
met, the RRC may assess a cost-of-service-based rate. The RRC also may
regulate certain sales of gas. Currently, the price of natural gas sold under
a majority of PG&E GTT's gas sales contracts is not regulated by the RRC. All
transportation and gathering of gas is subject to the RRC Code of Conduct
which prohibits undue discrimination among similarly situated shippers.
Further, all transportation of gas, processing of gas, and transportation of
natural gas liquids are subject to safety regulations enforced by the RRC and
the Texas Natural Resource Conservation Commission.
In addition, the power generation projects that USGen 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 Holding Company Act. EWG status is granted
by the FERC upon application by the project. Some projects have received
authority from the FERC to charge market-based rates for the power they sell,
rather than traditional cost-based rates. Many of USGen's affiliated projects
are qualifying facilities (QFs) 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.
PG&E Corporation's indirect subsidiary, USGen New England, Inc. (USGenNE),
acquired the electric generating facilities of the New England Electric System
(NEES) in September 1998. USGenNE also is subject to numerous federal, state,
and local statutes and regulations. USGenNE sells at wholesale all of the
electricity it generates, as well as electricity it purchases from third
parties under existing power sales agreements. Under the Federal Power Act
("FPA"), the FERC regulates these wholesale sales. The FERC has approved
USGenNE's rate schedule as a market-based schedule and, accordingly, the FERC
granted USGenNE waivers of certain other requirements that otherwise are
imposed on utilities with cost-based rate schedules. In addition, USGenNE owns
and operates a number of hydroelectric and pumped-storage projects that are
licensed by the FERC. These licenses expire periodically and the projects must
be relicensed at that time. USGenNE's licenses for these hydroelectric
projects expire over a period from 2001 to 2020. Prior to the expiration of
any one of the hydroelectric licenses, there is an opportunity for the
existing licensee (as well as others interested in owning and operating the
project) to apply for, and obtain, a new license.
USGenNE also is subject to limited regulation by certain state public
utility commissions located in states where USGenNE owns and operates electric
generating facilities. This regulation does not extend to its rates, which are
regulated exclusively by the FERC, and the scope of this regulation has been
substantially limited by various legislative initiatives.
Other regulatory matters are described throughout this report.
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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 $1,633 million for 1998. New investments totaled $1,779 million
in 1998.
The following table sets forth estimated capital expenditures, as well as
amounts for maturing debt and sinking funds, for PG&E Corporation subsidiaries
for the years 1999 through 2001. The amount of capital expenditures for
Pacific Gas and Electric Company (other than estimated capital expenditures
for Diablo Canyon) include estimates prepared for the Company's GRC
application now pending at the CPUC, excluding capital expenditures for
divested fossil and geothermal power plants. The amount of capital
expenditures for Pacific Gas and Electric Company shown in the table will be
reduced if the CPUC authorizes base revenues significantly lower than those
requested by the Company in its GRC filing.
<TABLE>
<CAPTION>
1999 2000 2001
------ ------ ------
(in millions)
<S> <C> <C> <C>
Utility Capital Expenditures(1)........................ $1,598 $1,666 $1,681
Other Capital Expenditures(2).......................... 364 205 157
Maturing Debt and Sinking Funds........................ 628 988 771
------ ------ ------
Total Capital Requirements........................... $2,590 $2,859 $2,609
====== ====== ======
</TABLE>
- --------
(1) Utility capital expenditures include the estimates prepared for Pacific
Gas and Electric Company's GRC but exclude capital expenditures for
divested fossil and geothermal power plants. These numbers 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.
Most of the estimated capital expenditures for Pacific Gas and Electric
Company for 1999 through 2001 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 proposed expenditures to maintain and improve safety and
reliability of Pacific Gas and Electric Company's electric transmission and
distribution system, as well as proposed expenditures for major projects
associated with customer service improvements.
PG&E Corporation estimates that its total capital requirements for the years
1999 through 2001 will include approximately $2.4 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 1999-2001 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 amounts shown
in the table above are forward-looking statements based on a number of
assumptions and which are subject to various uncertainties. Actual amounts may
differ materially based upon a number of factors, including the outcome of
Pacific Gas and Electric Company's GRC filing, changes in assumptions about
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.
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<PAGE>
Price Risk Management Programs
PG&E Corporation has an officer-level Price Risk Management Committee and
has adopted a Risk Management Policy, approved by the Board of Directors of
PG&E Corporation, for trading and risk management activities. The 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.
The Risk Management Policy allows derivatives to be used for both hedging
and non-hedging purposes. (A derivative is a contract whose value is dependent
on or derived from the value of some underlying asset.) PG&E Corporation uses
derivatives for hedging purposes primarily to offset underlying commodity
price risks. PG&E Corporation also participates in markets using derivatives
to create liquidity and maintain a market presence. Such derivatives include
forward contracts, futures, swaps, and options. The Risk Management Policy and
the trading and risk management policies of PG&E Corporation's subsidiaries
prohibit the use of derivatives whose payment formula includes a multiple of
some underlying asset. PG&E Corporation also monitors the trading and risk
management of PG&E ET, consistent with PG&E Corporation's Risk Management
Policy. See "Wholesale Operations of Affiliates--Energy Trading."
In 1998, the CPUC granted authority to Pacific Gas and Electric Company to
trade natural gas-based financial instruments to manage the influence of
natural gas prices on the cost of electricity purchased under existing power-
purchase contracts and to manage price and revenue risks associated with its
natural gas transmission and storage assets, subject to certain conditions.
The CPUC had previously granted authority to Pacific Gas and Electric Company
to trade natural gas-based financial instruments to hedge the gas commodity
price swings in serving core gas customers.
Additional information concerning price risk management activities and the
financial impact of price risk management activities on PG&E Corporation and
Pacific Gas and Electric Company is provided in "Management's Discussion and
Analysis" in the 1998 Annual Report to Shareholders, beginning on page 18 and
in Notes 1, 3, and 4 of the "Notes to Consolidated Financial Statements"
beginning on page 46 of the 1998 Annual Report to Shareholders.
Year 2000 Matters
PG&E Corporation's Year 2000 compliance program generally is proceeding on
schedule. However, if PG&E Corporation or third parties with whom PG&E
Corporation or Pacific Gas and Electric Company have significant business
relationships fail to achieve Year 2000 readiness with respect to mission-
critical systems, there could be a material adverse impact on PG&E Corporation
and Pacific Gas and Electric Company's financial position, results of
operations, and cash flow.
Additional information concerning Year 2000 matters and the financial impact
of Year 2000 matters on PG&E Corporation and Pacific Gas and Electric Company
is provided in "Management's Discussion and Analysis" in the 1998 Annual
Report to Shareholders, beginning on page 18.
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UTILITY OPERATIONS
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. 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 the
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. The Company's current GRC application
pending at the CPUC is discussed below.
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 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
GRC-adopted expenses), and actual fuel expenses. A reduced rate of return on
common equity of 6.77% applies to these facilities. This alternative revenue
requirement mechanism will be in place through 2001, unless the CPUC
determines otherwise.
Each year, Pacific Gas and Electric Company files an application with the
CPUC to determine the authorized rate of return that the Company may earn on
its assets (subject to the rates of return established for Diablo Canyon and
non-nuclear generation-related assets discussed in the previous paragraph) and
recover from ratepayers. On May 8, 1998, the Company filed its 1999 Cost of
Capital application. Since (i) the CPUC separately reduced the rate of return
on the Company's generation-related assets including Diablo Canyon, (ii) the
FERC will authorize the rate of return for electric transmission assets at a
later date (see discussion below), and (iii) gas transmission and storage
rates have been set in the Gas Accord, the rate of return adopted in the 1999
Cost of Capital Proceeding only applies to the Company's electric and gas
distribution assets. The Company has requested an increase in the rate of
return on common equity to 12.10% and an overall utility return on rate base
of 9.53% compared to the 1998 authorized returns of 11.20% and 9.17%,
respectively. No request was made to change the capital structure for the
Company, which continues to be composed of 48.00% common equity, 5.80%
preferred stock, and 46.20% long-term debt. Other parties have recommended
lower rates of return than the amounts requested. If the Company's requested
increase is approved, the authorized cost of capital will increase 1999
authorized electric and gas revenue by $49.7 million and $15.5 million,
respectively.
In November 1998, Pacific Gas and Electric Company filed an application with
the CPUC to establish performance-based ratemaking (PBR) for electric and gas
distribution services. If approved, the distribution PBR will establish
electric and gas distribution revenue requirements for the years 2000 to 2004.
The Company has proposed that the revenue requirement for the year 2000 be
determined by applying a formula, based principally on inflation and
productivity factors, to the 1999 GRC authorized revenue requirement. In
subsequent years, the formula would be applied to the previous year's
authorized revenue requirement. The proposed PBR also includes a sharing
mechanism for earnings that are significantly above or below the authorized
cost of capital, and a framework for rewards and penalties based upon the
achievement of various performance measures. As the CPUC has indicated that a
decision will not be issued until as late as May 2000, in February 1999, the
Company requested interim relief to be effective starting January 2000.
The 1998 Annual Earnings Assessment Proceeding (AEAP), which determines
shareholder incentives earned for Pacific Gas and Electric Company's 1996 and
1997 demand side management (DSM) programs, was submitted in May 1998. In the
1998 AEAP, the Company has requested an incentive payment of approximately
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$39.8 million for the Company's 1997 DSM programs, to be trued-up and
collected in installments over a 10-year period. After consolidating the
adjusted incentive payment installments from prior years, the net revenue
change in 1999 from DSM shareholder incentives should be an electric decrease
of approximately $14.3 million and a gas decrease of approximately $2.5
million. A final CPUC decision is expected during the first quarter of 1999.
On January 7, 1999, Pacific Gas and Electric Company filed an application
with the CPUC in its first Catastrophic Event Memorandum Account (CEMA)
requesting increases in electric and gas revenue requirements of $60.1 million
and $15.8 million, respectively, for costs incurred for several emergencies,
including the 1997 storms. The Company has requested that these costs be
included in rates effective January 1, 2000.
Electric Ratemaking
During 1998, the CPUC issued many decisions to implement electric industry
restructuring and the new market structure, including decisions related to
unbundling of rates, the recovery of transition costs, performance-based
ratemaking (PBR), and other activities that affect rates and revenue
requirements. Because electric rates are frozen, any change in Pacific Gas and
Electric Company's electric revenue requirements (the amount of revenue
required to pay certain costs) resulting from the items discussed below will
not change electric customer rates. Under the electric rate freeze, the
portion of total actual revenue that exceeds authorized base revenues and
certain other authorized revenue requirements is available to recover
transition costs. Therefore, increases in base revenues would reduce the
amount of revenue available to recover transition costs. Conversely, decreases
in base revenues would increase revenue available from frozen rates for
recovery of transition costs.
General Rate Case. In Pacific Gas and Electric Company's GRC now pending
before the CPUC, the Company is requesting increases in electric base revenues
of $445 million over electric base revenues authorized in 1998 to reflect
increasing levels of electric demand as well as customer growth in the service
territory, the costs of continued and enhanced maintenance activities, and
increased capital expenditures. 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 and maintenance, a continuation of tree-trimming
programs, and enhanced customer service and information technology systems.
Since the FERC authorizes the rates collected from customers for electric
transmission services, the GRC application does not seek approval of base
revenues to recover the cost of transmission services. In December 1998, the
CPUC issued a decision granting the requested increases on an interim basis
effective January 1, 1999. This interim decision will be in effect until the
CPUC issues its final decision, expected in June 1999. The interim decision
allows the Company to reflect the increased revenue requirements in its
balancing accounts to permit the Company to track the differences between
actual revenue requirements in effect on January 1, 1999, and the requested
revenue requirements. The interim decision did not increase electric rates.
Recovery of Transition Costs. On January 1, 1998, the Transition Revenue
Account (TRA) was established. Within the TRA, revenue from frozen rates
collected from ratepayers are allocated to transmission costs, distribution
costs, the costs of public purpose programs, nuclear decommissioning costs,
and energy procurement costs. Remaining revenues, if any, are transferred to
the Transition Cost Balancing Account (TCBA) to offset transition costs. The
CPUC established a separate annual proceeding, the Revenue Adjustment
Proceeding (RAP), to review, track, and compare each electric utility's
authorized revenue requirements with the actual recorded revenues, and to make
any necessary adjustments to reflect the authorized revenues that are approved
in other proceedings. The RAP is a consolidation proceeding to verify that the
outcomes from other proceedings are properly reflected and that the utilities
accurately calculate the amount of revenues available to transfer to the TCBA
to offset transition costs. On July 1, 1998, Pacific Gas and Electric Company
filed an application with the CPUC in its first RAP requesting CPUC approval
of entries made into the TRA from January 1 through May 31, 1998, and
requesting approval of the Company's accounting, revenue allocation, and rate
design proposals. On September 1, 1998, Pacific Gas and Electric Company also
filed an application in its first Annual Transition Cost Proceeding (ATCP)
requesting recovery of transition costs recorded in the TCBA from January 1
through June 30, 1998. This 1998 ATCP will verify the accounting and recording
of costs and revenues in the TCBA and ensure that only eligible transition
costs have been entered. Transition costs will receive a limited
"reasonableness" review.
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<PAGE>
Electric Industry Restructuring Implementation Costs. Under AB 1890, certain
electric industry restructuring implementation costs, that are found
reasonable by the CPUC may be recovered from ratepayers. Eligible costs
include FERC-authorized start-up and development costs of the ISO and PX, CPUC
approved consumer education programs, and the costs of implementing direct
access and demand PX billing and settlement systems. A multiparty settlement
agreement filed with the CPUC on November 13, 1998, proposes that Pacific Gas
and Electric Company would recover $40 million in 1997 and 1998 restructuring
implementation costs during the rate freeze (on a revenue requirements basis).
If recovery of these restructuring implementation costs during the rate freeze
displaces recovery of transition costs, the settlement agreement proposes that
Pacific Gas and Electric Company may recover up to $95 million of such
displaced transition costs after the rate freeze. A proposed CPUC decision is
expected in June 1999.
Revenues from Must-Run Contracts. The ISO has designated certain units at
electric generation facilities as necessary to remain available and
operational to maintain the reliability of the electric transmission system.
These units are called "must-run" units. In general, the ISO dispatches these
units under cost-based rate schedules that allow the owners to recover sunk
costs and ongoing operating costs of the must-run units. Although still
subject to FERC approval, the owners of must-run units choose among three
forms of must-run rate schedules, all of which are premised upon a different
mix of cost-based payments and revenues earned in the market.
Electric Transmission Revenues. Beginning in 1998, the FERC obtained
jurisdiction to determine the annual amount of Pacific Gas and Electric
Company's authorized revenue for transmission services that it may collect
from customers. The Company expects to file an application with the FERC in
March 1999 requesting 1999 electric transmission revenues of approximately
$425 million, an increase of approximately 8% over transmission revenues
sought by the Company and accepted, subject to refund, by the FERC in 1998.
Electric Deferred Refund Account (EDRA). In December 1996, the CPUC issued a
decision establishing an 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 gas disallowances
ordered by the CPUC or the FERC, and amounts resulting from reasonableness
disputes or fuel-related cost refunds made to Pacific Gas and Electric Company
based on regulatory agency decisions, plus interest charges. The Company
requested, and the CPUC approved, an early refund of amounts accrued in EDRA
in 1998. In 1998, the Company refunded approximately $36.4 million of EDRA
refunds to customers.
Post-Rate Freeze Ratemaking Mechanisms. On January 15, 1999, Pacific Gas and
Electric Company filed an application with the CPUC to determine the
ratemaking mechanisms to be in effect after the end of the electric rate
freeze period.
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" in the
1998 Annual Report to Shareholders, beginning on page 18, and in Note 2 of the
"Notes to Consolidated Financial Statements" beginning on page 49 of the 1998
Annual Report to Shareholders.
Gas Ratemaking
Gas Accord. As noted above (see "General--Competition and the Changing
Regulatory Environment--Gas Industry"), the CPUC approved the Gas Accord in
1997. As part of the Gas Accord, the CPUC's traditional reasonableness reviews
of Pacific Gas and Electric Company's core gas costs have been replaced with a
CPIM (which also is discussed below in "Utility Operations--Gas Utility
Operations--Core Procurement Incentive Mechanism") for the period from June 1,
1994, through 2002. Additional information concerning the potential financial
impact of the Gas Accord is provided in "Management's Discussion and Analysis"
in the 1998 Annual Report to Shareholders, beginning on page 18.
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General Rate Case. The Company is requesting an increase in gas base
revenues of $377 million, over base revenues authorized in 1998. The requested
increase in base revenues reflects increasing levels of gas demand as well as
customer growth in the service territory, the costs of continued and enhanced
maintenance activities, and increased capital expenditures. 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. In December 1998, the CPUC issued a decision granting the requested
increase on an interim basis effective January 1, 1999. This interim decision
will be in effect until the CPUC issues its final decision, expected in June
1999. The interim decision allows the Company to reflect the increased revenue
requirements in its balancing accounts to permit the Company to track the
differences between actual revenue requirements in effect on January 1, 1999,
and the requested revenue requirements. The interim decision did not increase
gas rates. However, gas customers would experience an increase in gas
distribution rates if the CPUC approves the requested gas base revenue
increase. 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.
The Biennial Cost Allocation Proceeding (BCAP). The BCAP remains the
proceeding in which distribution costs and balancing account balances are
allocated to customers. The BCAP normally occurs every two years and is
updated in the interim year for purposes of amortizing any accumulation in the
balancing accounts. Balancing accounts for natural gas costs accumulate
differences between the actual recovery of gas costs and the revenues designed
for recovery of such costs. Balancing accounts for sales volumes accumulate
differences between authorized and actual base revenues. In 1997, Pacific Gas
and Electric Company filed its 1998 BCAP application. In June 1998, the CPUC
adopted a decision in the 1998 BCAP granting an annual $97.8 million revenue
requirement decrease effective September 1, 1998, compared to revenues
established by the Gas Accord on March 1, 1998. The overall annual revenue
requirement for the two-year BCAP period (September 1, 1998, through August
31, 2000) is approximately $1.5 billion, of which an annual average of
approximately $102 million is allocated for the collection of balancing
accounts. The previous annual revenue requirement was approximately $1.8
billion, of which approximately $303 million was allocated for the collection
of balancing accounts.
Electric Utility Operations
Implementation of Electric Industry Restructuring
In 1998, electric industry restructuring in California became effective with
the commencement of operations of the California Independent System Operator
(ISO) and the California Power Exchange (PX) on March 31, 1998.
Independent System Operator and Power Exchange
The ISO operates and controls most of the state's electric transmission
facilities (which continue to be owned and maintained by the California
utilities) and provides comparable open access to electric transmission
service. The ISO accepts balanced supply and load schedules from market
participants and manages the availability of electric transmission on a
statewide basis for these transactions. The ISO also purchases necessary
generation and ancillary services to maintain grid reliability.
In 1998, California's three largest investor-owned utilities relinquished
operational 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.
The PX provides a competitive auction process to establish transparent
market clearing prices for electricity in the markets operated by the PX. The
three largest investor-owned utilities in California are required to sell into
the PX all of their generated electric power. "Must-take" generation
resources, such as nuclear generation,
14
<PAGE>
electric power generated by QFs which the utilities are required to purchase
under existing contractual commitments, are also scheduled through the PX. The
utilities must then purchase all electric power for their retail customers
through the PX. Customers who buy power directly from non-regulated suppliers
pay for that generation based upon negotiated contracts. The PX sets a market
clearing price for electricity by matching all demand load bids with supply
bids ranked from lowest to highest. The highest-accepted generation supply bid
used to serve load sets the PX market clearing price for electricity.
The FERC has jurisdiction over both the ISO and the PX. In October 1997, the
FERC granted authority for the ISO and the PX to commence operations and
approved the initial structure, rates, terms and conditions applicable to the
new market structure. The ISO and PX both have made numerous tariff amendment
filings with the FERC to address issues which arose after the commencement of
ISO and PX operations. The FERC has acted on several of these filings and
several remain pending.
The ISO and PX, California public benefit non-profit corporations, each has
a Governing Board that includes representatives of investor-owned utility
transmission systems, publicly-owned utility transmission systems, non-utility
electricity sellers, public buyers and sellers, private buyers and sellers,
industrial end-users, commercial end-users, residential end-users,
agricultural end-users, public interest groups, and non-market participant
representatives. The ISO and PX currently are overseen by a five-member
Electricity Oversight Board which appoints the members of the ISO and PX
Governing Boards. However, this appointment power has been rejected by the
FERC and new bylaws for the ISO and the PX have been filed with the FERC
which, if approved by the FERC, would eliminate this role of the Electricity
Oversight Board.
Voluntary Generation Asset Divestiture
As part of the electric industry restructuring plan to promote a competitive
electric generation market, California utilities, including Pacific Gas and
Electric Company, have voluntarily begun divestiture of some of their
generation assets. On July 1, 1998, Pacific Gas and Electric Company sold
three electric generating plants with a combined capacity of 2,645 megawatts
(MW): 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 aggregate sale price for these three fossil-
fueled plants was $501 million and the combined book value for these three
plants was approximately $346 million as of July 1, 1998. Pacific Gas and
Electric Company has retained liability for required environmental remediation
of any preclosing soil or groundwater contamination at these plants.
In late 1998 and in January 1999, Pacific Gas and Electric Company agreed to
sell three fossil-fueled generating facilities (the Pittsburg and Contra Costa
power plants located in Contra Costa County, and the Potrero power plant in
San Francisco) and its geothermal generating facilities (The Geysers Power
Plant located in Lake and Sonoma Counties) for a combined sale price of $1.014
billion compared to their combined book value of approximately $523 million
(as of December 31, 1998). The aggregate purchase price of the fossil-fueled
power plants is $801 million. The purchase price for the Geysers geothermal
facilities is $213 million. The sales are subject to approval by various
regulatory agencies, including the CPUC, and are conditioned upon the transfer
of various permits and licenses. The transactions are expected to close by the
first half of 1999.
Together, the seven power plants represent 91% of Pacific Gas and Electric
Company's fossil-fueled generating capacity and all of its geothermal
generating capacity. The facilities generated approximately 31% of Pacific Gas
and Electric Company's total electric energy production. The gain from the
sale of these power plants will 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, under two-year operations and
maintenance agreements with the new owners, will continue to operate and
maintain the power plants that are sold. To the extent that payments to the
Company under these agreements exceed the Company's cost of operating the
plants, the Company would offset other transition costs. Conversely, to the
extent the Company's operating costs exceed the revenues from these
agreements, the Company would have lower earnings.
15
<PAGE>
In May 1998, Pacific Gas and Electric Company notified the CPUC that its
non-nuclear generating facilities, including the hydroelectric facilities,
will not be retained by the Company. In July 1998, the Company reached an
agreement with the City and County of San Francisco regarding the Hunters
Point fossil-fueled power plant, which the ISO has designated as a "must run"
facility. The agreement expresses the Company's intention to retire the plant
when it is no longer needed by the ISO. In December 1998, the Company asked
the CPUC to allow it to hire appraisers to determine the market value of the
hydroelectric system. Under the Company's proposal, the Company would have the
option of accepting the appraised value and transferring the assets to another
unit of PG&E Corporation or rejecting the appraised value and auctioning the
assets. The Company expects the CPUC to issue a decision on the appraisal
process in 1999.
Direct Access
Although the restructuring legislation contemplated that direct access would
begin on January 1, 1998, the ISO and PX delayed the commencement of
operations until March 31, 1998. Customers participating in direct access may
purchase their electric power directly either through (1) competing non-
utility retail electric providers such as brokers, marketers, aggregators, or
other retailers, or (2) direct negotiated contracts with electric generators.
All customers (with limited exceptions), whether they choose direct access or
not, must pay the nonbypassable CTC, which will be collected by their
distribution utility in connection with recovery of the utilities' transition
costs. Utilities began accepting requests for direct access in November 1997
to become effective after direct access began. As of February 24, 1999,
Pacific Gas and Electric Company had transferred 53,990 customers to direct
access. The CPUC requires that electric customers with an electricity demand,
or load, of 50 kilowatts (kW) or more must have meters that are capable of
providing hourly data in order to participate in direct access. Those
customers with a load less than 50 kW may participate in direct access either
through "load profiling" or by installing an hourly meter. (Load profiling
approximates the pattern of electricity usage for a given customer class and
provides the equivalent of hourly meter reads.) The customer is responsible
for the cost of the meter and the meter installation.
Energy service providers supplying the direct access market may choose one
of three billing options: (1) consolidated energy supplier billing, under
which the utility bills the energy supplier for the services provided directly
by the utility to the customer, and the supplier, in turn, provides a
consolidated bill to the customer, (2) consolidated distribution company
billing, under which the utility places the supplier's energy charge on a
distribution bill, or (3) dual billing, under which the energy supplier and
the utility bill separately for their own services. Since 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.
During 1998, Pacific Gas and Electric Company continued its efforts to
develop and implement changes to its business processes and systems, including
customer information and billing systems, to accommodate direct access. To the
extent the Company is unable to successfully and timely develop and implement
such changes, there could be an adverse impact on the Company's future results
of operations.
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. The CPUC authorized a 1997 base
revenue increase of $164 million. For 1998, the CPUC authorized an additional
base revenue increase of $77 million, for a total authorized base revenue
increase for 1997 and 1998 of $406 million. The recovery of these amounts from
ratepayers is subject to a reasonableness review by the CPUC. In May 1998, the
Company filed its report on 1997 expenditures with the CPUC seeking review of
approximately $183 million for costs incurred in 1997 for safety and system
reliability enhancements, which exceeded the 1997 authorized revenue
requirement by approximately $19 million. On January 29, 1999, the ORA issued
its report on the claimed expenditures and recommended that a total of
approximately $50 million, including the $19 million amount overspent, be
disallowed, for a net recommended disallowance of $31 million. Under AB 1890,
the
16
<PAGE>
disallowance or underspending of the 1997 revenue requirement, if adopted by
the CPUC, would be credited as an expense against the 1998 authorized revenue
requirement. To the extent that 1998 expenditures (including any amounts
carried over from 1997) exceed the 1998 authorized revenue requirement, the
amount overspent would not be recoverable from ratepayers. The Company plans
to file its report on 1998 expenditures seeking review of its 1997 and 1998
costs for safety and system reliability enhancements in March 1999.
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 10 months to 10 years, and bearing interest at rates ranging from
5.94% to 6.48%. Pacific Gas and Electric Company is collecting 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.
In November 1998, the California voters defeated a voter initiative known as
Proposition 9. If it had passed, Proposition 9 would have, among other things,
(i) required investor-owned California utilities to provide an additional 10%
rate reduction to residential and small commercial customers, (ii) eliminated
transition cost recovery for nuclear investments by utilities (other than
reasonable decommissioning costs), (iii) restricted transition cost recovery
for non-nuclear investments (other than costs associated with QFs), unless the
CPUC found that the utility would be deprived of the opportunity to earn a
fair rate of return, and (iv) prohibited the collection of any customer
charges for rate reduction bonds, or alternatively, required the utility to
offset such charges with an equal credit to customers.
Recovery of Transition Costs
Under electric industry restructuring, utilities are authorized 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 December 31, 2001, although
certain transition costs may be recovered after December 31, 2001. These costs
include certain employee-related transition costs, costs 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.
17
<PAGE>
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. In
1998, the value of four of the Company's remaining power plants and its
geothermal facilities also has been established by the auction process,
subject to CPUC approval. In October 1998, the CPUC ruled that the market
value of the Hunters Point power plant is zero. In December 1998, the Company
filed an application with the CPUC requesting approval for the Company to hire
appraisers to establish a market value for the Company's hydroelectric
facilities.
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 May 1998, the CPUC approved $53
million in 1996 non-nuclear generation capital additions as eligible for
recovery as transition costs. Further, a multiparty settlement agreement filed
with the CPUC on January 8, 1999, proposes that Pacific Gas and Electric
Company would recover approximately $128.5 million of its $133 million request
for recovery of 1997 and first quarter 1998 capital additions. A CPUC decision
on the 1997 and first quarter 1998 capital additions is expected in 1999.
In 1997, to reflect the accelerated recovery of transition costs related to
non-nuclear generation-related assets, including hydroelectric and geothermal
facilities, and for Diablo Canyon, the CPUC reduced the authorized rate of
return on common equity for these assets to 6.77%. The reduced rate of return
will be effective for the duration of the transition period.
During 1998, proceedings commenced at the CPUC to review, track, and compare
each electric utility's authorized revenue requirements with the actual
recorded revenues, and to make any necessary adjustments to reflect the
authorized revenues that are approved in other proceedings. An annual
proceeding also was established to verify the accounting and recording of
transition costs and revenues available for recovery of transition costs and
to ensure that only eligible transition costs have been entered. In this
proceeding, transition costs will receive a limited "reasonableness" review.
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, and low-income energy
efficiency programs at not less than $14 million per year. The California
Alternative Rates for Energy (CARE) low-income discount rate, a rate subsidy
paid for by the Company's other customers, is currently about $31 million per
year.
The California Energy Commission (CEC) administers the public interest
research and development program and the renewable program. The CPUC has set
up public member boards to advise the CPUC on public purpose programs related
to energy efficiency and low-income programs. Initially, these boards also
were
18
<PAGE>
assigned to solicit competitive bids to determine who will administer the
programs in place of the utility's interim administration. However, the CPUC
appointed Pacific Gas and Electric Company as interim administrator of energy
efficiency and low-income programs for 1999. The CPUC recently has issued a
draft decision which, if adopted, would continue the Company's interim
administration of these programs through the end of the transition period.
Additional information concerning AB 1890 and its financial impact on PG&E
Corporation is provided in "Management's Discussion and Analysis" in the 1998
Annual Report to Shareholders, beginning on page 18, and in Note 2 of the
"Notes to Consolidated Financial Statements" beginning on page 49 of the 1998
Annual Report to Shareholders.
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.
<TABLE>
<CAPTION>
Years Ended December 31
----------------------------------------------------------
1998 1997 1996 1995 1994
---------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C>
Customers (average for
the year):
Residential............ 3,962,318 3,915,370 3,874,223 3,825,413 3,788,044
Commercial............. 469,136 465,461 459,001 454,718 452,049
Industrial............. 1,093 1,121 1,248 1,253 1,260
Agricultural........... 85,429 86,359 87,250 88,546 90,520
Public street and
highway lighting...... 18,351 17,955 17,583 17,089 16,709
Other electric
utilities............. 14 47 28 35 29
---------- ---------- ---------- ---------- ----------
Total............... 4,536,341 4,486,313 4,439,333 4,387,054 4,348,611
========== ========== ========== ========== ==========
Sales-kWh (in millions):
Residential............ 26,846 25,946 25,458 24,391 24,326
Commercial............. 28,839 28,887 27,868 27,014 26,195
Industrial............. 16,327 16,876 15,786 16,879 16,010
Agricultural........... 3,069 3,932 3,631 3,478 4,426
Public street and
highway lighting...... 445 446 438 425 418
Other electric
utilities............. 2,358 3,291 1,213 3,172 4,246
---------- ---------- ---------- ---------- ----------
Total energy
delivered.......... 77,884 79,378 74,394 75,359 75,621
========== ========== ========== ========== ==========
Revenues (in thousands):
Residential............ $2,891,424 $3,082,013 $3,033,613 $2,979,590 $2,980,966
Commercial............. 2,793,336 2,932,560 2,840,101 2,964,568 2,892,302
Industrial............. 933,316 1,028,378 1,005,694 1,160,938 1,128,561
Agricultural........... 350,445 413,711 396,469 395,531 477,330
Public street and
highway lighting...... 51,195 53,183 55,372 56,154 55,545
Other electric
utilities............. 50,166 118,781 81,855 133,566 201,133
---------- ---------- ---------- ---------- ----------
Revenues from energy
deliveries......... 7,069,882 7,628,626 7,413,104 7,690,347 7,735,837
Miscellaneous.......... 161,156 (9,439) 112,303 92,538 142,771
Regulatory balancing
accounts.............. (40,408) 71,441 (365,192) (396,578) 142,939
---------- ---------- ---------- ---------- ----------
Operating revenues.. $7,190,630 $7,690,628 $7,160,215 $7,386,307 $8,021,547
========== ========== ========== ========== ==========
</TABLE>
19
<PAGE>
The following table shows certain customer information:
<TABLE>
<S> <C> <C> <C> <C> <C>
Selected Statistics:
Total customers (at year-
end)....................... 4,565,000 4,500,000 4,500,000 4,400,000 4,400,000
Average annual residential
usage (kWh)................ 6,776 6,627 6,571 6,377 6,422
Average billed revenues per
kWh (cents per kWh):
Residential............... 10.77 11.88 11.92 12.22 12.25
Commercial................ 9.69 10.15 10.19 10.97 11.04
Industrial................ 5.72 6.09 6.37 6.88 7.05
Agricultural................ 11.42 10.52 10.92 11.37 10.78
Net plant investment per
customer ($)............... 2,705 3,027 3,198 3,228 3,362
</TABLE>
Electric Generating Capacity
As described above in "Implementation of Electric Industry Restructuring--
Voluntary Generation Asset Divestiture," in 1998, Pacific Gas and Electric
Company sold three fossil-fueled power plants and entered into agreements for
the sale of an additional four fossil-fueled power plants and its geothermal
facilities. Except as otherwise noted below, as of December 31, 1998, Pacific
Gas and Electric Company owned and operated the following generating plants,
all located in California, listed by energy source:
<TABLE>
<CAPTION>
Net
Number Operating
of Capacity
Generation Type County Location Units kW
--------------- --------------- ------ ----------
<S> <C> <C> <C>
Hydroelectric:
Conventional Plants.............. 16 counties in Northern and
Central California 109 2,698,100
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.................... San Francisco 3 377,000
Pittsburg(1)..................... Contra Costa 7 2,022,000
Potrero(1)....................... San Francisco 1 207,000
--- ----------
Steam Subtotal................... 15 3,391,000
--- ----------
Combustion Turbines:
Hunters Point.................... San Francisco 1 52,000
Potrero(1)....................... San Francisco 3 156,000
Mobile Turbines(2)............... Humboldt and Mendocino 3 45,000
--- ----------
Combustion Turbines Subtotal..... 7 253,000
--- ----------
Geothermal:
The Geysers Power Plant(1)(3).... Sonoma and Lake 14 1,224,000
Nuclear:
Diablo Canyon.................... San Luis Obispo 2 2,160,000
--- ----------
Thermal Subtotal............... 38 7,028,000
--- ----------
Total......................... 150 10,938,100
=== ==========
</TABLE>
- --------
(1) In 1998, Pacific Gas and Electric Company entered into agreements to sell
these power plants and its geothermal facilities in connection with
electric industry restructuring.
(2) Listed to show capability; subject to relocation within the system as
required.
(3) The Geysers Power Plant net operating capacity is based on adequate
geothermal steam supply conditions. (Present steam conditions prevent the
units from operating at full operating capacity.)
20
<PAGE>
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, 1998, Diablo Canyon Units 1 and 2 had achieved lifetime
capacity factors of 81.4% and 82.9%, respectively.
The table below outlines Diablo Canyon's refueling schedule for the next
five years. Diablo Canyon refueling outages typically are scheduled every 19
to 21 months. Pacific Gas and Electric Company has been seeking NRC licensing
authority to schedule such outages once every 24 months. Though nominal 20-
month cycles are firm, achieving a 24-month cycle is uncertain and its
implementation could be delayed. The schedule below assumes that a refueling
outage for a unit will last approximately five 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.
<TABLE>
<CAPTION>
1999 2000 2001 2002 2003
-------- -------- ---- ---- --------
<S> <C> <C> <C> <C> <C>
Unit 1
Refueling............................ February October May
Startup.............................. March November June
Unit 2
Refueling............................ October May February
Startup.............................. November June March
</TABLE>
Diablo Canyon Ratemaking
Effective January 1, 1997, Pacific Gas and Electric Company's sunk costs in
Diablo Canyon are recovered from ratepayers through a sunk cost revenue
requirement, at a reduced return on common equity equal to 6.77% that will
remain in effect through the end of the transition period. (Sunk costs are
costs associated with the facility that are fixed and unavoidable and
currently included in customers' electric rates.) Also effective January 1,
1997, a performance-based Incremental Cost Incentive Price (ICIP) mechanism
was established to recover Diablo Canyon's variable and other operating costs
and capital addition costs. The ICIP mechanism establishes a rate per kWh
generated by the facility. This rate is based upon a fixed forecast of ongoing
costs, capital additions, and capacity factors for the period 1997 through
2001. The fixed forecast of ICIP for 1999-2001 is shown below. The revenues
are based on an assumed capacity factor of 83.6%.
Incremental Cost Incentive Prices and Estimated
Total CPUC Revenue Requirement
<TABLE>
<CAPTION>
Estimated Total
Revenue Requirement
--------------------
1999 2000 2001
------ ------ ------
<S> <C> <C> <C>
ICIP (cents per kWh)................................. 3.37 3.43 3.49
Sunk Cost Recovery ($ in millions)................... $1,259 $1,197 $1,135
ICIP Revenues ($ in millions)........................ 532 542 552
------ ------ ------
Total Revenue Requirement ($ in millions)............ $1,791 $1,739 $1,687
</TABLE>
The CPUC decision adopting the ratemaking mechanism 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.
21
<PAGE>
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. On August 31, 1998, an independent accounting firm retained by the
CPUC completed its financial verification audit of Diablo Canyon plant
accounts at December 31, 1996. The audit resulted in the issuance of an
unqualified opinion. The audit verified that Diablo Canyon sunk costs at
December 31, 1996, were $3.3 billion of the total $7.1 billion construction
costs. The independent accounting firm also issued an agreed-upon special
procedures report, requested by the CPUC, which questioned $200 million of the
$3.3 billion sunk costs. The CPUC will review the results of the audit and may
seek to make adjustments to Diablo Canyon sunk costs subject to transition
cost recovery. At this time, the amount of transition cost disallowances, if
any, cannot be predicted.
Additional information concerning the financial impact of Diablo Canyon
ratemaking is included in "Management's Discussion and Analysis" in the 1998
Annual Report to Shareholders, beginning on page 18, and in Note 2 of the
"Notes to Consolidated Financial Statements" beginning on page 49 of the 1998
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 2002, 2000, and 2002, respectively. The fuel fabrication
contract for the two units will supply their requirements for the next seven
operating cycles of each unit. These contracts are intended to ensure long-
term fuel supply, but permit 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 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 been unable to meet its
contract commitment to begin accepting spent fuel by January 1998. Further,
under the DOE's current estimated acceptance schedule for spent fuel, Diablo
Canyon's spent fuel may not be accepted by the DOE for interim or permanent
storage before 2010, at the earliest. At the projected level of operation for
Diablo Canyon, 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 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 nuclear generating unit
(Unit 3) at Humboldt Bay Power Plant (Humboldt) at Humboldt prior to
ultimately decommissioning the unit. The Company has agreed to remove all
spent fuel when the federal disposal site is available.
22
<PAGE>
Insurance
Pacific Gas and Electric Company has insurance coverage for property damage
and business interruption losses as a member of Nuclear Electric Insurance
Limited (NEIL). NEIL, which is owned by utilities with nuclear generating
facilities, provides insurance coverage against property damage,
decontamination, decommissioning, and business interruption and/or extra
expenses during prolonged accidental outages for reactor units in commercial
operation. Under these insurance policies, if the nuclear generating facility
of a member utility suffers a loss due to a prolonged accidental outage, the
Company may be subject to maximum retrospective premium assessments of $17
million (property damage) and $5 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 $9.6 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 $176 million per incident, with
payments in each year limited to a maximum of $20 million per incident.
Decommissioning
Pacific Gas and Electric Company's estimated total obligation to
decommission and dismantle its nuclear power facilities is $1.5 billion in
1998 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 and dismantling the nuclear facilities. The
trust funds maintain substantially all of their investments in debt and equity
securities. All earnings on the trust fund, net of authorized disbursements
from the trusts and management and administrative fees, are reinvested. Monies
may not be released from the external trust funds until authorized by the
CPUC. In December 1997, the CPUC granted Pacific Gas and Electric Company's
request for authority to disburse up to $15.7 million from the Humboldt Bay
Power Plant decommissioning trust funds to finance three partial nuclear
decommissioning projects at Humboldt Bay Power Plant Unit 3. Accordingly, as
of December 31, 1998, $7.2 million (net of taxes) was disbursed from the
Humboldt Bay Power Plant Unit 3 non-tax-qualified trust to reimburse the
Company for nuclear decommissioning expenses associated with the partial
decommissioning projects.
In its 1999 GRC, Pacific Gas and Electric Company is seeking approval from
the CPUC to use the tax savings resulting from the payment of tax-deductible
nuclear decommissioning expenses from the Humboldt Bay Power Plant Unit 3 non-
tax-qualified trust to fund nuclear decommissioning work. If the CPUC rejects
the Company's request, an additional $4.9 million will be disbursed from the
trust to reimburse the Company for the full amount of the 1998 nuclear
decommissioning expenses of $12.1 million. A mechanism to flow the realized
tax savings of $4.9 million associated with $12.1 million tax-deductible
nuclear decommissioning expenses to ratepayers will be established.
As of December 31, 1998, Pacific Gas and Electric Company had accumulated
external trust funds with an estimated fair value of $1.2 billion, based on
quoted market prices and net of deferred taxes on unrealized gains, to be used
for the decommissioning of the Company's nuclear facilities.
The amount recovered in rates for nuclear decommissioning costs is
authorized by the CPUC as part of the GRC. The CPUC considers the trusts'
asset levels, together with revised earnings and decommissioning cost
23
<PAGE>
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, 1998, nuclear
decommissioning costs recovered in rates were $33 million.
Beginning January 1, 1998, nuclear decommissioning costs, which are not
transition costs, were 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. The CPUC has established a Nuclear Decommissioning Costs Triennial
Proceeding to determine the decommissioning costs and to establish the annual
revenue requirement and attrition factors over subsequent three-year periods
when and if GRCs are discontinued.
Other Electric Resources
QF Generation and Other Power-Purchase Contracts
By federal law, Pacific Gas and Electric Company is required to purchase
electric energy and capacity provided by independent power producers. 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
1999 through 2001. Total capacity payments are expected to remain at current
levels during this period. Deliveries from these power producers account for
approximately 23% of Pacific Gas and Electric Company's 1998 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, 1998, the total discounted future
payments remaining under early termination or suspension contracts is $48
million.
Pacific Gas and Electric Company also has contracts with various irrigation
districts and water agencies to purchase hydroelectric power. Under these
contracts, the 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 incurred by the suppliers. These contracts expire on various dates from
2004 to 2031. The total cost of these payments is recoverable in rates. At
December 31, 1998, the undiscounted future minimum payments under these
contracts are $32 million for each of the years 1999 through 2003 and a total
of $280 million for periods thereafter. Irrigation district and water agency
deliveries in the aggregate account for approximately 7.5% of Pacific Gas and
Electric Company's 1998 electric energy requirements.
The amount of energy received and the total payments made under all these
power-purchase contracts were:
<TABLE>
<CAPTION>
1998 1997 1996
------ ------ ------
(in millions)
<S> <C> <C> <C>
Kilowatt-hours received.............................. 25,994 24,389 26,056
Energy payments...................................... $ 943 $1,157 $1,136
Capacity payments.................................... $ 529 $ 538 $ 521
Irrigation district and water agency payments........ $ 53 $ 56 $ 52
</TABLE>
As of December 31, 1998, Pacific Gas and Electric Company had commitments to
purchase approximately 5,200 MW of capacity under CPUC-mandated power-purchase
agreements. Of the 5,200 MW, approximately
24
<PAGE>
4,400 MW were operational. Development of the majority of the balance is
uncertain and it is estimated that very few of the remaining contracts will
become operational. The 4,400 MW of operational capacity consists of 2,800 MW
from cogeneration projects, 600 MW from wind projects, and 1,000 MW from other
projects, including biomass, waste-to-energy, geothermal, solar, and
hydroelectric.
Geothermal Generation
In late 1998 and January 1999, Pacific Gas and Electric Company entered into
agreements to sell its geothermal units at The Geysers Power Plant located in
Lake and Sonoma counties (Geysers) for a total of $213 million. The sale is
subject to final approval by the CPUC and other regulatory agencies, and the
transaction is expected to close by the first half of 1999. See "Electric
Utility Operations--Implementation of Electric Industry Restructuring--
Voluntary Generation Asset Divestiture" above.
The 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. The Company's
agreements with several of its steam suppliers permit the Company to curtail
generation at the Geysers at the Company's discretion. The 1999 consolidated
Geysers capacity factor through the expected close of sale is forecast to be
approximately 38% of installed capacity in 1999, which includes economic
curtailments, forced outages, scheduled overhauls, and projected steam
shortage curtailments, as compared to the actual Geysers capacity factor of
44% in 1998.
Electric Transmission and Distribution
To transport energy to load centers, Pacific Gas and Electric Company as of
December 31, 1998, owned and operated approximately 18,624 circuit miles of
interconnected transmission lines of 60 kilovolts (kV) to 500 kV and
transmission substations having a capacity of approximately 39,565,906
kilovolt-amperes (kVa), including spares, excluding power plant
interconnection facilities. Energy is distributed to customers through
approximately 112,080 circuit miles of distribution system and distribution
substations having a capacity of approximately 23,575,800 kVa.
In 1998, the utilities relinquished control, but not ownership, of their
transmission facilities to the ISO. The ISO commenced operations on March 31,
1998. The ISO, regulated by the FERC, controls the operation of the
transmission system and provides open access transmission service on a
nondiscriminatory basis. In 1998, the FERC approved the various forms of
agreements for must-run facilities that have been entered into between the
utilities and the ISO to ensure grid reliability.
The FERC 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.
On December 17, 1998, the CPUC opened a rulemaking proceeding to consider
whether it should pursue further reforms in the structure and regulatory
framework governing electricity distribution service. The CPUC will solicit
comments and proposals regarding the scope and substance of issues, possible
policy options, and procedural steps the CPUC could pursue in considering
distributed generation and competition in electric distribution service. The
rulemaking was opened, in part, in response to a request from Pacific Gas and
Electric Company for a comprehensive review of distribution competition.
Initial comments are due to the CPUC on March 17, 1999.
On December 8, 1998, Pacific Gas and Electric Company lost power on all its
115 kV transmission lines from the San Mateo Substation to San Francisco, and
the two San Francisco power plants tripped off line, leaving more than 456,000
customers without power. The Company immediately notified the ISO of the
outage. Only the approximately 13,000 customers served from the 230 kV
transmission line maintained power. Six hours later, the Company had restored
service to all but 27,000 customers. Within the next two hours, all customers
had power.
25
<PAGE>
Pacific Gas and Electric Company immediately began an internal investigation
of the outage. On December 17, 1998, the CPUC issued an Order Instituting
Investigation concerning the power outage. The order required Pacific Gas and
Electric Company to file a report by January 25, 1999 to address various
issues arising from the outage, including chronology, cause, response,
mitigation, prevention, and handling of claims.
On January 25, 1999, the Company completed its internal investigation and
filed a report with the CPUC detailing the results of its investigation. The
Company's internal investigation confirmed that the outage resulted when a
construction crew working on an equipment upgrade project at the San Mateo
Substation failed to follow established procedures and practices, and failed
to remove temporary protective grounds. Separately, a transmission operator at
the substation then energized the substation bus, but failed to engage the
protective relays associated with the bus. (A "bus" refers to a collection
point for connecting transmission lines and flowing power out from a
substation.) Without the local protective system in place, the electric
current was sent to ground, and the system took a half second to isolate the
fault instead of the one-tenth of a second that would normally be required.
This delay resulted in a sharp drop in transmission line voltages, and the
transmission system into San Francisco then experienced large power
fluctuations. As they are designed to do, protective systems at other
substations and at the Hunters Point and Potrero power plants separated from
the transmission system to make sure that the fluctuations did not extend to
other parts of the Company's system, and that no damage occurred to equipment
in San Francisco's electric facilities that could have delayed restoration of
operations.
Pacific Gas and Electric Company is taking actions to strengthen and adjust
its grounding and switching procedures as preventative measures to minimize
the risk that such an initiating event could occur in the future. The
Company's internal investigation found that the transmission system design is
consistent with the requirements of the North American Electric Reliability
Council and the Western Systems Coordinating Council, and performed as
designed given the initiating event that occurred. As a result of this
finding, the Company is not proposing modifications to the system design.
Finally, the Company and the ISO are using the lessons learned in this event
to strengthen their communications.
Gas Utility Operations
Pacific Gas and Electric Company owns and operates an integrated gas
transmission, storage, and distribution system in California. At December 31,
1998, Pacific Gas and Electric Company's system, including the PG&E Expansion
(Line 401), consisted of approximately 5,706 miles of transmission pipelines,
three gas storage facilities, and approximately 37,023 miles of gas
distribution lines.
Pacific Gas and Electric Company's peak day send-out of gas on its
integrated system in California during the year ended December 31, 1998, was
4,300 million cubic feet (MMcf). The total volume of gas throughput during
1998 was approximately 850,000 MMcf, of which 295,000 MMcf was sold to direct
end-use or resale customers, 158,000 MMcf was used by Pacific Gas and Electric
Company primarily for its fossil-fueled electric generating plants, and
397,000 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 1998 California Gas Report updates Pacific Gas and Electric Company's
annual gas requirements forecast (excluding bypass volumes) for the years 1998
through 2015, forecasting average annual growth in gas throughput served by
the Company of approximately 1%. The gas requirements forecast is subject to
many uncertainties and there are many factors that can influence the demand
for natural gas, including weather conditions, level of utility electric
generation, fuel switching, and new technology. In addition, some large
customers, mostly in the industrial and enhanced oil recovery sectors, may
have the ability to use unregulated private pipelines or interstate pipelines,
bypassing the Company's system entirely. The 1998 California Gas Report
forecasts a total bypass volume of 133,600 MMcf for 1999.
26
<PAGE>
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.
<TABLE>
<CAPTION>
Years Ended December 31
----------------------------------------------------------
1998 1997 1996 1995 1994
---------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C>
Customers (average for
the year):
Residential............ 3,536,089 3,491,963 3,455,086 3,417,556 3,372,768
Commercial............. 200,620 198,453 198,071 197,939 196,509
Industrial............. 1,610 1,650 1,500 1,500 1,400
Other gas utilities.... 5 3 2 2 2
---------- ---------- ---------- ---------- ----------
Total.............. 3,738,324 3,692,069 3,654,659 3,616,997 3,570,679
========== ========== ========== ========== ==========
Gas supply--thousand
cubic feet (Mcf) (in
thousands):
Purchased from
suppliers in:
Canada............... 298,125 280,084 253,209 261,800 319,453
California........... 17,724 10,655 28,130 31,158 31,757
Other states......... 122,342 131,074 110,604 117,538 249,733
---------- ---------- ---------- ---------- ----------
Total purchased.... 438,191 421,813 391,943 410,496 600,943
Net from storage (to
storage).............. 14,468 14,160 6,871 (10,921) 3,591
---------- ---------- ---------- ---------- ----------
Total.............. 452,659 435,973 398,814 399,575 604,534
Pacific Gas and
Electric Company use,
losses, etc.(1)....... 158,241 173,789 134,375 129,671 297,604
---------- ---------- ---------- ---------- ----------
Net gas for sales.. 294,418 262,184 264,439 269,904 306,930
========== ========== ========== ========== ==========
Bundled gas sales and
transportation
service--Mcf (in
thousands):
Residential............ 223,706 191,327 190,246 191,724 214,358
Commercial............. 66,082 60,803 62,178 64,135 72,183
Industrial............. 4,616 10,054 12,015 14,045 19,495
Other gas utilities.... 14 0 0 0 894
---------- ---------- ---------- ---------- ----------
Total.............. 294,418 262,184 264,439 269,904 306,930
========== ========== ========== ========== ==========
Transportation service
only--Mcf (in
thousands):
Vintage system
(Substantially all
Industrial)(2)........ 319,099 218,660 189,695 143,921 142,393
PG&E Expansion (Line
401).................. 77,773 233,269 237,776 240,506 200,755
---------- ---------- ---------- ---------- ----------
Total.............. 396,872 451,929 427,471 384,427 343,148
========== ========== ========== ========== ==========
Revenues (in thousands):
Bundled gas sales and
transportation
service:
Residential.......... $1,414,313 $1,170,135 $1,109,463 $1,205,223 $1,268,966
Commercial........... 426,299 374,084 362,819 421,397 444,805
Industrial........... 24,634 46,592 42,520 42,106 57,297
Other gas utilities.. 1,072 3,701 510 0 2,371
---------- ---------- ---------- ---------- ----------
Bundled gas
revenues.......... 1,866,318 1,594,512 1,515,312 1,668,726 1,773,439
Transportation only
revenue:
Vintage system
(Substantially all
Industrial)......... 232,038 207,160 180,197 167,325 132,509
PG&E Expansion (Line
401)................ 42,194 90,180 85,144 82,904 58,442
---------- ---------- ---------- ---------- ----------
Transportation service
only revenue.......... 274,232 297,340 265,341 250,229 190,951
Miscellaneous.......... 41,364 50,295 (9,271) (18,018) 40,427
Regulatory balancing
accounts.............. (448,351) (137,787) 57,864 (43,771) (101,443)
Subsidiaries(3)........ 0 0 210,556 201,951 177,688
---------- ---------- ---------- ---------- ----------
Operating
revenues.......... $1,733,563 $1,804,360 $2,039,802 $2,059,117 $2,081,062
========== ========== ========== ========== ==========
</TABLE>
- --------
(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 34,169 MMcf, 72,958 MMcf, 78,552 MMcf, 100,207 MMcf, and
79,749 MMcf, for 1998, 1997, 1996, 1995, and 1994, 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.
27
<PAGE>
<TABLE>
<CAPTION>
Years Ended December 31
-------------------------------------------------
1998 1997 1996 1995 1994
--------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C>
Selected Statistics:
Total customers (at year-
end)....................... 3,766,000 3,700,000 3,700,000 3,600,000 3,500,000
Average annual residential
usage (Mcf)................ 63 55 55 56 64
Heating temperature--% of
normal(1).................. 93.0 71.7 75.7 75.3 104.4
Average billed bundled gas
sales revenues per Mcf:
Residential................. $6.32 $6.12 $5.83 $6.29 $5.92
Commercial.................. 6.45 6.15 5.84 6.57 6.16
Industrial.................. 5.36 4.63 3.54 3.00 2.94
Average billed
transportation only revenue
per Mcf:
Vintage system.............. 0.66 0.71 0.67 0.69 0.60
PG&E Expansion (Line 401)... 0.54 0.39 0.36 0.34 0.29
Net plant investment per
customer (2)............... $1,040 $1,031 $1,378 $1,315 $1,340
</TABLE>
- --------
(1) Over 100% indicates colder than normal.
(2) The net plant investment per customer figures for 1997 and 1998 are lower
than in previous years because they exclude 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, 1998, approximately 68% of the 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 4% was purchased in
California; and approximately 28% was purchased in the U.S. Southwest and
transported by the El Paso Natural Gas Company or Transwestern Pipeline
Company pipelines. California purchases include both purchases from various
California producers and purchases of gas transported to California by others.
The following table shows the total 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.
<TABLE>
<CAPTION>
Years Ended December 31
----------------------------------------------------------------------------------------------
1998 1997 1996 1995 1994
------------------ ------------------ ------------------ ------------------ ------------------
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)
--------- -------- --------- -------- --------- -------- --------- -------- --------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Canada................. 298,125 $2.00 280,084 $1.77 253,209 $1.57 261,800 $1.34 319,453 $1.94
California............. 17,724 2.44 10,655 2.12 28,130 1.90 31,158 1.32 31,757 1.55
Other states...........
(substantially all
U.S Southwest)....... 122,342 2.62 131,074 3.75 110,604 3.72 117,538 2.64 249,733 2.41
------- ----- ------- ----- ------- ----- ------- ----- ------- -----
Total/Weighted
Average............... 438,191 $2.19 421,813 $2.39 391,943 $2.21 410,496 $1.71 600,943 $2.12
======= ===== ======= ===== ======= ===== ======= ===== ======= =====
</TABLE>
- --------
(1) The average prices for Canadian and U.S. Southwest gas include the
commodity gas prices, interstate pipeline demand or reservation charges,
transportation charges, and other pipeline assessments, including direct
bills allocated over the quantities received at the California border.
Beginning March 1, 1998, the average price for gas also includes
intrastate pipeline demand and reservation charges. These costs were
previously bundled in gas rates.
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 "General--Competition and the Changing Regulatory
Environment--Gas Industry"), the Gas Accord separates, or "unbundles," the
rates for Pacific Gas
28
<PAGE>
and Electric Company's gas transmission services from its distribution
services, increases the opportunities for core customers 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 "General--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 $113 million in
1998. This amount includes payments made to PG&E Gas Transmission,
Northwest Corporation (PG&E GT-Northwest) of approximately $49 million in
1998, but which 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 GT-Northwest 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 GT-Northwest
system to support its core and core subscription customers. The Company has
been able to broker its unused capacity on PG&E GT-Northwest's system, when
not needed for core and core subscription customers.
In 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 GT-Northwest and El
Paso Natural Gas Company (El Paso). (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 $26 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
29
<PAGE>
of capacity for 1992. It indicated that it would disallow costs through the
term of the contract unless Pacific Gas 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.
Core Procurement Incentive Mechanism
Pacific Gas and Electric Company's core gas procurement costs for the period
June 1994 to 2002 are recoverable under a core procurement incentive mechanism
(CPIM), a form of incentive regulation established by the Gas Accord. The CPIM
provides the Company with a direct financial incentive to procure gas and
transportation services at the lowest reasonable costs by comparing all
procurement costs to an aggregate market-based benchmark. If costs fall within
a range (tolerance band) around the benchmark, costs are deemed reasonable and
fully recoverable from ratepayers. If procurement costs fall outside the
tolerance band, the Company's ratepayers and shareholders share savings or
costs, respectively. In January 1999, the Company filed a performance report
with the ORA of the CPUC, recommending a shareholder award of $190,766, for
the period January 1, 1998 through October 31, 1998. During 1998, the Company
submitted a similar report to the ORA for its January 1997 through December
1997 performance, recommending a shareholder award of approximately $1.8
million. After ORA comments on the Company's performance reports, the Company
will seek CPUC approval for all gas procurement costs for both periods,
including the Company's shareholder awards.
PGT/Pacific Gas and Electric Company Pipeline Expansion
In November 1993, PG&E GT-Northwest (then known as 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 the 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 GT-
Northwest (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 is at risk for
recovery of all gas transmission costs, including costs of the PG&E Expansion,
through rates; however, a portion of the PG&E Expansion will be combined with
other transmission assets (specifically, a portion of the 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.
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WHOLESALE OPERATIONS OF AFFILIATES
Gas Transmission Operations
PG&E Corporation participates in the "midstream" portion of the gas business
through PG&E GTT, PG&E Gas Transmission Teco, Inc. and PG&E GT-Northwest. The
"midstream" gas business includes (1) gas gathering, processing, and storage,
and transportation of natural gas and natural gas liquids (NGLs); (2) the
marketing of natural gas to gas distribution companies, electric utilities,
municipalities, marketers, independent power producers, and end-use customers;
(3) the transportation of natural gas for these customers, producers, and
other pipelines; and (4) the marketing and transportation of NGLs to various
customers, including end-use customers.
PG&E GTT and PG&E Gas Transmission Teco, Inc. own and operate gas gathering,
transportation, and processing facilities, and NGL pipelines. The NGL business
includes the gathering of natural gas, the extraction of NGLs from natural
gas, the fractionation of mixed NGLs into component products (e.g., ethane,
propane, butane, and natural gasoline), and the transportation and marketing
of NGLs. The Texas operations include approximately 6,600 miles of natural gas
pipelines and joint ownership or leasehold interests in approximately 1,900
miles of pipelines, including pipelines from Waha in west Texas to the Katy
area near Houston, Texas. These pipeline systems have the capacity to
transport more than 3 billion cubic feet (bcf) of gas per day. Other Texas
assets include a long-term lease of 7.2 bcf of storage capacity, approximately
536 miles of NGL pipelines and nine natural gas processing plants with a
combined capacity of approximately 1.6 bcf per day of gas throughput, capable
of producing approximately over 100,000 barrels per day of NGLs.
PG&E GT-Northwest owns and operates gas transmission pipelines and
associated facilities which extend over 612 miles from the Canada-U.S. border
to the Oregon-California border and are capable of transporting 2.4 bcf per
day of natural gas. It also owns two smaller diameter pipeline extensions
within Oregon, totaling 106 miles. In July 1998, PG&E Corporation sold its
natural gas pipeline in Australia as part of its strategy to focus on the
domestic market.
In September 1996, the FERC approved a settlement of PG&E GT-Northwest's
1994 rate case. The major issue in this proceeding was whether PG&E GT-
Northwest'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 "Utility Operations--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%.
In 1998, petitions filed by various parties for rehearing of the FERC order
approving the settlement were denied. Some parties have appealed the FERC's
denial of these rehearing petitions to the U.S. Court of Appeals for the
District of Columbia Circuit, but PG&E GT-Northwest currently expects the
settlement to be upheld.
Independent Power Generation
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. USGen is headquartered in Bethesda, Maryland.
In 1998, PG&E Corporation, through its indirect subsidiary, USGen New
England, Inc. (USGenNE), completed the acquisition of a portfolio of electric
generating assets and power supply contracts from NEES for
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$1.59 billion, plus $85 million for early retirement and severance costs
previously committed to by NEES. Including fuel and other inventories and
transaction costs, PG&E Corporation's financing requirements were
approximately $1.8 billion, funded through $1.3 billion of debt, a $425
million equity contribution, and $70 million from cash on hand and other
sources. The debt was raised through revolving credit facilities established
at both the USGen and the USGenNE levels. Specifically, a $1.1 billion credit
facility was established at the USGen level, and $575 million credit facility
was established at the USGenNE level. In December 1998, USGenNE canceled $475
million of this $575 million facility through a sale-leaseback transaction
involving the pumped storage facility acquired from NEES.
The acquired NEES facilities consist of two conventional hydroelectric
systems with 14 stations, three fossil-fuel stations (coal, oil, and natural
gas) with 11 units, and a pumped storage facility, with a combined generating
capacity of approximately 4,000 MW. In addition, USGenNE assumed the purchase
obligations under 27 multi-year power-purchase agreements between NEES's
subsidiary, New England Power, and other utility and non-utility wholesale
suppliers representing an additional 1,100 MW of production capacity.
Subsequently, several of the power-purchase agreements expired and/or were
transferred, thereby reducing the total capacity to the current level of
approximately 800 MW. USGenNE entered into agreements with NEES as part of the
acquisition, which (1) provide that NEES shall make annual support payments
through early 2008 to offset the cost of power associated with these above-
market contracts, and (2) require that USGenNE provide electricity to NEES
under supply agreements that expire over the next six to 11 years.
Three of the four states in which the acquired assets are located
(Massachusetts, Rhode Island, and New Hampshire) were also among the first
states in the country to introduce retail competition. (A referendum in
Massachusetts reaffirming electric industry restructuring was approved by the
voters in November 1998.) Connecticut also has passed retail competition
legislation.
The acquired assets are located within the New England Power Pool (NEPOOL).
The wholesale electricity market in New England features a bid-based, real-
time pricing structure. Traditionally, NEPOOL has operated as a "tight power
pool," one in which the utilities within the pool dedicate their generation
resources to be centrally dispatched. Dispatch starts with the lowest-cost
generation and ends with the highest-cost generation. In 1998, an independent
system operator for the New England states (ISO-NE) began to provide central
dispatch service and to operate the power pool as a competitive wholesale
marketplace.
As a result, the NEPOOL market is in the midst of transitioning to a
competitive market. The duties of the ISO-NE include scheduling the operations
of the regional transmission systems and, importantly, operating a power
exchange for seven generation products (the "Interchange"). These products are
energy, installed (monthly) capacity and operable (hourly) capacity, three
types of reserves and automatic generation control (adjustment of generators
to meet the second-to-second changes in electric load). The installed capacity
market began operations on April 1, 1998. The balance of the Interchange is
anticipated to begin operations on April 1, 1999, although this date is
subject to final implementation by the ISO-NE.
In these New England states, the utility companies providing service to
retail customers are required to provide Standard Offer Service (SOS) to those
customers. The SOS is intended to provide consumers with a price benefit (the
commodity electric price offered to the retail customer is expected to be less
than the market price) for the first several years, followed by a price
disincentive that is intended to stimulate the retail market.
Retail customers may continue to receive SOS through June 30, 2002, in New
Hampshire (subject to early termination on December 31, 2000, at the
discretion of the New Hampshire Public Service Commission); through December
31, 2004, in Massachusetts; and through December 31, 2009, in Rhode Island.
However, if any customer elects to have their electricity provided by an
alternate supplier, they are precluded from returning to the SOS. In
connection with the purchase of the NEES generation assets, PG&E Corporation,
through USGenNE, entered into agreements to supply the electric capacity and
energy requirements necessary for NEES to meet its SOS obligations. In
December 1998, NEES's New Hampshire utility subsidiary, Granite State Electric
Co., reached an agreement with Constellation Power Source, Inc. under which
Constellation Power Source, Inc. will
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provide the SOS for Granite State Electric Co.'s customers. USGenNE retains
its supply obligations for Massachusetts Electric Company and Narrangansett
Electric Company, two utility subsidiaries of NEES located in Massachusetts
and Rhode Island, respectively. NEES is responsible for passing on to PG&E
Corporation the revenues generated from the SOS.
Initially, approximately 90% of the operating capacity acquired from NEES,
including capacity and energy generated by independent power producers (IPPs)
under the assumed power-purchase agreements, has been dedicated to providing
SOS. To the extent that customers eligible to receive SOS choose alternate
suppliers this percentage will decrease.
Like California utilities, the New England utilities have entered into
agreements with IPPs to provide energy and capacity at prices which are
anticipated to be in excess of market prices. As described above, USGenNE
assumed NEES's contractual rights and duties under certain power-purchase
agreements with IPPs, which in the aggregate provide for approximately 800 MW
of capacity. In connection with the acquisition of NEES's generating assets,
USGenNE is required to pay NEES amounts due from NEES to the IPPs in
accordance with their power-purchase agreements. These payment obligations are
reduced by monthly support payments that NEES pays USGenNE.
Finally, in connection with the NEES acquisition, USGenNE obtained the right
to purchase NEES's nuclear generated electric energy, capacity, and associated
products at market prices up to the entire amount available. This right
terminates automatically with respect to any nuclear facility that is sold or
ceases operation for any reason, and if not terminated earlier, expires at
termination of the SOS.
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 SOS 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.
As of December 31, 1998, USGen affiliates had ownership interests in 30
operating plants (including the assets acquired from NEES) in 10 states. The
total generating capacity of these 30 plants is approximately 6,560 MW. PG&E
Corporation's combined net equity ownership and leased interest in these
plants as of December 31, 1998, represented approximately 5,300 MW. The plants
were financed largely with a combination of equity or equity commitments from
the project sponsors and non-recourse debt. (For a description of the
financing of the NEES acquisition, see above.) 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 8,600 MW in 8 states. USGen and its
affiliated or managed facilities sold 22,242,949 million megawatt-hours (MWh)
of electricity in 1998, including sales of electricity from the generating
facilities acquired from NEES on September 1, 1998.
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The following table sets forth information regarding the operating
generating plants in which USGen affiliates have ownership or leasehold
interests. The table also notes the operating plants which USGen affiliates
manage or operate, or both manage and operate, power plant operations.
Portfolio of Operating Generating Plants
<TABLE>
<CAPTION>
Date Placed in
Commercial
Plant MWs Fuel Location Service
----- --- ---- -------- --------------
<C> <C> <C> <C> <S>
Bear Swamp Facility(1),(2)
Pumped Storage 2 Units........... 588 Water Massachusetts 1974
Fife Brook....................... 10 Water 1974
Brayton Point Station (2)
Unit Nos. 1, 2 and 3............. 1,130 Coal Massachusetts 1963, '64, '69
Unit No. 4....................... 446 Oil/Gas 1974
Diesel Generators................ 10 Diesel Oil N/A
Carneys Point....................... 260 Coal New Jersey 1994
Cedar Bay........................... 250 Coal Florida 1994
Connecticut River (2)
Hydroelectric 26 Units........... 484 Water New Hampshire/Vermont 1909-1957
Deerfield River (2)
Hydroelectric 15 Units........... 84 Water Massachusetts/Vermont 1912-1927
Hermiston........................... 474 Natural Gas Oregon 1996
Indiantown.......................... 330 Coal Florida 1995
Logan............................... 225 Coal New Jersey 1995
Manchester St. Station (2)
3 Combined Cycle Units........... 495 Natural Gas Rhode Island 1995
MASSPOWER........................... 240 Natural Gas Massachusetts 1993
Northampton......................... 110 Waste Coal Pennsylvania 1995
Pittsfield.......................... 165 Natural Gas Massachusetts 1990
Salem Harbor Station (2)
Unit Nos. 1, 2 and 3............. 314 Coal Massachusetts 1952, '52, '58
Unit No. 4....................... 400 Oil 1972
Scrubgrass.......................... 83 Waste Coal Pennsylvania 1993
Selkirk............................. 345 Natural Gas New York 1994
-----
Total MWs/Operating Plants... 6,443
USGen Affiliate Investments
Colstrip (3)........................ 37 Waste Coal Montana 1990
Panther Creek (3)................... 83 Waste Coal Pennsylvania 1992
-----
Total MWs from Investments... 120
=====
Total MWs in Operation (4)... 6,563
</TABLE>
- --------
(1) Unlike other operating facilities in which USGen affiliates have ownership
and management interests, the Bear Swamp Facility is owned by a third
party through a single-investor lease arrangement. USGen maintains full
management and operating responsibility for the facility.
(2) Acquired from NEES on September 1, 1998.
(3) USGen affiliates have an ownership or leasehold interest in these plants,
but do not manage power plant operations.
(4) Of the total of 6,563 megawatts, USGen's net equity ownership and leased
percentage is 5,282 megawatts.
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<PAGE>
Energy Trading
PG&E Energy Trading-Gas Corporation and PG&E Energy Trading-Power, L.P.
(collectively referred to as PG&E Energy Trading), headquartered in Houston,
Texas, purchase bulk volumes of power and natural gas from PG&E Corporation
affiliates and the wholesale market. PG&E Energy Trading then schedules,
transports, and resells these commodities, either directly to third parties or
to other PG&E Corporation affiliates. 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 provides PG&E Energy Services Corporation with a broad
portfolio of energy products and services for the retail market. For more
information, see "General--Price Risk Management Programs" above.
Additional information concerning the wholesale operations of PG&E
Corporation's affiliates is provided in "Management's Discussion and Analysis"
in the 1998 Annual Report to Shareholders, beginning on page 18, and in Note
16 of the "Notes to Consolidated Financial Statements" beginning on page 67 of
the 1998 Annual Report to Shareholders.
RETAIL OPERATIONS OF AFFILIATES
Energy Services
PG&E Energy Services (PG&E ES), headquartered in San Francisco, California,
provides retail gas and electric commodities nationwide, where permitted under
applicable laws, and provides energy related value-added services, including
billing and information management services, energy efficiency and other
energy management services, regulatory and rate analysis, and power quality
solutions. PG&E ES targets primarily industrial, commercial, and institutional
customers, offering comprehensive energy management solutions to reduce their
energy costs and improve their productivity. PG&E ES has 20 offices nationwide
to support its sales activities. PG&E ES currently competes with other non-
utility electric retailers in California for direct access customers. See
"Utility Operations--Electric Utility Operations--Implementation of Electric
Industry Restructuring" above.
Additional information concerning the retail operations of PG&E ES is
provided in "Management's Discussion and Analysis" in the 1998 Annual Report
to Shareholders, beginning on page 18, and in Note 16 of the "Notes to
Consolidated Financial Statements" beginning on page 67 of the 1998 Annual
Report to Shareholders.
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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 below
reflects 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 the
facility owner'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, U.S. Generating Company
and its affiliates (including USGen New England, Inc. (USGenNE) which holds
the electric generating facilities acquired from NEES in September 1998), 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 generally have been recovered in rates.
Environmental Protection Measures
The estimated expenditures of PG&E Corporation's subsidiaries for
environmental protection are subject to periodic review and revision to
reflect changing technology and evolving regulatory requirements. It is likely
that the stringency of environmental regulations will increase in the future.
With Pacific Gas and Electric Company's 1998 sale of its Morro Bay, Moss
Landing, and Oakland power plants, and the upcoming sale of the Company's
Contra Costa, Pittsburg, Potrero, and Geysers power plants (expected to close
in 1999), the Company's oxides of nitrogen (NOx) emission reduction compliance
costs will be reduced significantly. See "Utility Operations--Electric Utility
Operations--Implementation of Electric Industry Restructuring--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
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Company's other natural gas compressor stations in California. Eventually the
rules are likely to require NOx reductions of up to 80% at many of these
natural gas compressor stations. Pacific Gas and Electric Company currently
estimates that the total cost of complying with these various NOx rules will
be up to $51.9 million over four years.
USGen's compliance with certain future regulatory requirements limiting the
total amount of NOx emissions from its fossil-fueled power plants is expected
to be achieved by installing additional controls, fuel switching and
purchasing of NOx allowances. USGenNE has agreed to be bound by a number of
state and regional initiatives that will require it to achieve significant
reductions of sulfur dioxide (SO/2/) and NOx emissions by the time its older
fossil-fueled power plants have been in operation for 40 years or by 2010,
whichever comes first. It is expected that USGenNE can meet these requirements
through the utilization of allowances it currently owns, installation of
additional controls or through the purchase of additional allowances. (SO/2/
allowances are emission credits that are traded in a national market under the
United States Environmental Protection Agency's (EPA) Acid Rain Program. NOx
allowances are emission credits that are traded in a regional market
consisting of seven Northeast states known as the Ozone Transport Region.) It
is estimated that USGenNE's total cost of complying with these requirements
will be up to $6 million through the year 2000.
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. A comprehensive
statistical analysis of Diablo Canyon's thermal effects was submitted to the
Central Coast Board in December 1997 and a regulatory assessment was submitted
in November 1998. 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. The 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. The 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 (the Contra Costa and Pittsburgh fossil-fueled power plants). To
address the impacts of operation and maintenance activities at the Delta
plants on sensitive species, the 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"
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<PAGE>
(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.
USGen's existing power plants, including USGenNE facilities, are subject to
federal and state water quality standards with respect to discharge
constituents and thermal effluents. Two of the fossil-fueled plants owned and
operated by USGenNE are operating in compliance with National Pollutant
Discharge Elimination System (NPDES) permits that have expired and the NPDES
permit for a third facility is scheduled to expire in 1999. As to the
facilities for which the NPDES permit has expired, new permit applications are
pending and it is anticipated that all three facilities should be able to
continue to operate under existing terms and conditions until new permits are
issued. USGenNE has submitted a permit renewal application and is negotiating
with EPA on ongoing studies and permit conditions. It is estimated that
USGenNE's cost to comply with these conditions could be as much as $4 million
through the year 2000.
Hazardous Waste Compliance and Remediation
PG&E Corporation subsidiaries assess, on an ongoing basis, measures that may
need to be taken to comply with laws and regulations related to hazardous
materials and hazardous waste compliance and remediation activities. Pacific
Gas and Electric Company has a comprehensive program to comply with many
hazardous waste storage, handling, and disposal requirements promulgated by
the EPA under the Resource Conservation and Recovery Act (RCRA) and the
Comprehensive Environmental Response, Compensation, and Liability Act
(CERCLA), along with other state hazardous waste laws and other environmental
requirements.
One part of this program is aimed at assessing whether and to what extent
remedial action may be necessary to mitigate potential hazards posed by
certain disposal sites and retired manufactured gas plant sites. During their
operation, manufactured gas plants produced lampblack and tar residues,
byproducts of a process that Pacific Gas and Electric Company, its predecessor
companies, and other utilities used as early as the 1850s to manufacture gas
from coal and oil. As natural gas became widely available (beginning about
1930), Pacific Gas 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. The Company has identified
and reported to federal and California environmental agencies 96 manufactured
gas plant sites which operated in the Company's service territory. The Company
owns all or a portion of 30 of these manufactured gas plant sites. The 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. It is estimated that the Company's
program may result in expenditures of approximately $8 million in 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.
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
potentially responsible party (PRP) under CERCLA (the federal Superfund law)
with respect to the Purity Oil Sales site in Malaga, California, the
Industrial Waste Processing site near Fresno, California, and the Lorentz
Barrel and Drum site in San Jose, California. With respect to the Casmalia
site near Santa Maria, California, the 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 the 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 the Company and
other parties to initiate measures with respect to the study and remediation
of that site.
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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 the 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, 1998, of $296
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 $487 million
if, among other things, other PRPs are not financially able to contribute to
these costs or further investigation indicates that the extent of
contamination or necessary remediation is greater than anticipated at sites
for which the Company is responsible. This upper limit of the range of costs
was estimated using assumptions least favorable to the Company based upon a
range of reasonably possible outcomes. Costs may be higher if the Company is
found to be responsible for cleanup costs at additional sites or identifiable
possible outcomes change.
USGen acquired the onsite environmental liability associated with USGenNE's
acquisition of electric generating facilities from NEES, but did not acquire
any offsite pollution liability associated with the past disposal practices at
the acquired facilities. USGen has obtained pollution liability and
environmental remediation insurance coverage to limit the financial risk
associated with the onsite pollution liability at all of its facilities.
Potential Recovery of Hazardous Waste Compliance and Remediation Costs
In 1994, the CPUC established a ratemaking mechanism for hazardous waste
remediation costs (HWRC). That mechanism assigns 90% of the includable
hazardous substance cleanup costs to utility ratepayers and 10% to utility
shareholders, without a reasonableness review of such costs or of underlying
activities. However, utilities will have the opportunity to recover the
shareholder portion of the cleanup costs from insurance carriers. Under the
HWRC, 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. The Company can seek to recover hazardous substance
cleanup costs under the HWRC in the rate proceeding it deems most appropriate.
In connection with electric industry restructuring, the HWRC mechanism may no
longer be used to recover electric generation-related clean-up costs for
contamination caused by events occurring after January 1, 1998.
Pacific Gas and Electric Company retains 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. As each generation facility is divested, the
Company is required to prepare a forecast of environmental remediation costs
for that plant and to use the forecast to adjust the current plant
decommissioning cost estimate, eventually to be recovered through the
Transition Cost Balancing Account (TCBA). (For ratemaking purposes, estimates
of environmental remediation costs are discounted to present value, whereas
for accounting purposes the nominal value of estimated remediation costs is
used.) The discounted environmental liability associated with the Morro Bay,
Moss Landing, and Oakland power plants (which were sold on July 1, 1998) and
approved by the CPUC is $31.6 million. (The buyer of these plants has assumed
the decommissioning liability for the purchased plants.) As of July 1, 1998,
the Company had recovered $66 million from ratepayers for both the
environmental and non-environmental decommissioning accrual related to the
Morro Bay, Moss Landing, and Oakland power plants. The excess recovery related
to these plants in the amount of $34.5 million ($66 million minus $31.6
million) resulted in a net credit to the sunk cost of the remaining plants
(the Contra Costa, Pittsburgh, and Potrero power plants, and the Geysers
geothermal facilities) reducing the amount of sunk costs to be amortized over
the transition period, offsetting other transition costs.
On October 23, 1998, Pacific Gas and Electric Company requested that the
CPUC approve a total of $88.6 million of estimated costs of environmental
remediation liability that the Company will retain for the Contra Costa,
Pittsburg, and Potrero power plants, and the Geysers geothermal facilities.
(The buyers will assume
39
<PAGE>
the decommissioning liability.) The Company also requested that the CPUC
approve similar accounting and ratemaking treatment of environmental
remediation and non-environmental decommissioning for these plants as the CPUC
approved for the first group of plants sold. As of December 31, 1998, Pacific
Gas and Electric Company has recovered from ratepayers approximately $141
million for environmental and non-environmental decommissioning accrual
related to these plants. After the plant sales are completed, the excess
recovery of approximately $48.5 million (as adjusted for decommissioning costs
that will continue to be accrued) would reduce the amount of generation-
related sunk costs to be amortized over the transition period, offsetting
other transition costs.
Pacific Gas and Electric Company expects to recover $160 million of the $296
million accrued liability, discussed above, in future rates. The liability
also includes $76 million related to power plant decommissioning for
environmental clean-up, which is recovered through depreciation. Additionally,
the 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. The Company previously had
notified its insurance carriers that it seeks coverage under its comprehensive
general liability policies to recover costs incurred at certain specified
sites. In general, the Company's carriers neither admitted nor denied
coverage, but requested additional information from the Company. Although the
Company has received some amounts in settlements with certain of its insurers
(approximately $49.6 million through December 31, 1998), 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
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. The 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 is not currently involved in third party
litigation concerning EMF. In August 1996, the California Supreme Court held
that homeowners are barred from suing utilities for alleged property value
losses caused by fear of EMF from power lines. The Court expressly limited its
holding to
40
<PAGE>
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 was a defendant in civil litigation in which
plaintiffs alleged personal injuries resulting from exposure to EMF. In
January 1998, the appeals court in this matter held that the CPUC has
exclusive jurisdiction over personal injury and wrongful death claims arising
from allegations of harmful exposure to EMF and barred plaintiffs' personal
injury claims. Plaintiffs filed an appeal of this decision with the California
Supreme Court. The California Supreme Court declined to hear the case.
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 $42 million in funding for
Pacific Gas and Electric Company's LEV program for the six-year period
beginning in 1996. The CPUC's decision on electric industry restructuring
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 heading of
this report entitled "Wholesale Operations of Affiliates."
ITEM 3. Legal Proceedings.
See Item 1, Business, for other proceedings pending before governmental and
administrative bodies. In addition to the following legal proceedings, PG&E
Corporation and Pacific Gas and Electric Company are subject to routine
litigation incidental to their business.
Compressor Station Chromium Litigation
Pacific Gas and Electric Company is a defendant in five civil actions
pending in California courts on behalf of approximately 2,300 plaintiffs.
These cases are (1) Aguayo v. Pacific Gas and Electric Company, filed
March 15, 1995, in Los Angeles County Superior Court; (2) Aguilar v. Pacific
Gas and Electric Company, filed October 4, 1996 in Los Angeles County Superior
Court; (3) Acosta, et al. v. Betz Laboratories, Inc., et al., filed November
27, 1996, in Los Angeles Superior Court; (4) Little and Mustafa v. Pacific Gas
and Electric Company and PG&E Corporation, filed September 10, 1997, in San
Bernardino Superior Court; and (5) Whipple, et al. v. Pacific Gas and Electric
Company and PG&E Corporation, et al., filed September 10, 1997, in San
Bernardino Superior Court. (Plaintiffs have agreed to dismiss PG&E Corporation
in these last two suits.) These cases are collectively referred to as the
"Aguayo Litigation."
Each of the complaints in the Aguayo Litigation, except the Little case
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
41
<PAGE>
Kettleman, Hinkley, and Topock, California. The plaintiffs in the Aguayo
Litigation include current and former Pacific Gas and Electric Company
employees, relatives of current and former Company employees, residents in the
vicinity of the compressor stations, and persons who visited the gas
compressor stations. The plaintiffs also include spouses or children of these
plaintiffs who claim only loss of consortium or injury through the alleged
exposure of their spouses or parents.
In the Whipple case, pending in San Bernardino Superior Court, the
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.
In June 1998, a Los Angeles Superior Court judge found that preconception
claims are not recognizable under California law and ordered the dismissal of
235 plaintiffs with such claims from the Aguayo Litigation. Judgment was
entered against these plaintiffs in December 1998. During September and
October 1998, the court made similar rulings in the Acosta and Aguilar cases.
The Company expects that plaintiffs may appeal these rulings.
All discovery and discovery motion practice in three of the cases brought in
Los Angeles Superior Court (Acosta v. Betz, Aguilar v. Pacific Gas and
Electric Company, and Aguayo v. Pacific Gas and Electric Company) has been
referred by the judge to a discovery referee. The court ordered that those
plaintiffs who did not respond to written discovery requests served by Pacific
Gas and Electric Company by November 15, 1998, would be dismissed. The Company
has submitted stipulations to dismiss approximately 630 plaintiffs who failed
to respond to discovery requests. It is not anticipated that these plaintiffs
will appeal.
After the entry of the dismissal of plaintiffs with preconception claims and
those plaintiffs who failed to respond to discovery requests, there will be
approximately 1,650 plaintiffs remaining in the Aguayo Litigation.
On September 16, 1998, a discovery referee set the procedures for selecting
20 trial test plaintiffs and two alternates in the Aguayo, Acosta, and Aguilar
cases. Ten of these trial test plaintiffs and one alternate were selected by
plaintiffs, six plaintiffs and one alternate were selected by defendants, and
four plaintiffs were selected at random (by selecting seven plaintiffs at
random and allowing each party -- plaintiffs, Pacific Gas and Electric
Company, and Betz to strike one). A trial date has been set for November 16,
1999. The Company has filed a motion to transfer venue to Fresno County
Superior Court which is scheduled to be heard on March 22, 1999.
Pacific Gas and Electric Company is responding to the complaints and
asserting affirmative defenses. The 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. The 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
On July 31, 1997, PG&E Corporation acquired Valero Energy Corporation
(Valero), now known as PG&E Gas Transmission, Texas Corporation or PG&E GTT.
PG&E GTT succeeded to the eight cases described below
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<PAGE>
which were pending at the time of the acquisition against Valero and its
affiliates (collectively referred to as the "Texas Franchise Fees
Litigation"). These actions were brought by various cities in Texas arising
out of several Texas statutes and city ordinances involving the following: (a)
what rights, if any, Texas cities may have to require companies engaged in the
gathering, production, distribution, transmission, and/or sale of natural gas
(gas business) to obtain consent from, and pay fees to, the cities within
which such activities are being conducted, (b) what form any such consent, if
required, must take, (c) what constitutes "use" of city property, and (d) what
types of charges, if any, a Texas city properly can assess against gas
pipeline and marketing companies for use of that city's property.
These seven cases pending against Valero entities at the time of the
acquisition are: (1) City of Edinburg v. Rio Grande Valley Gas Co. (RGVG),
Valero Energy Corporation (now known as PG&E GTT), Valero Transmission Company
(now known as PG&E Texas Pipeline Company), Valero Natural Gas Company (now
known as PG&E Texas Natural Gas Company), Reata Industrial Gas Company (now
known as PG&E Energy Trading Holdings Corporation), Valero Transmission, L.P.
(now known as PG&E Texas Pipeline, L.P.), and Reata Industrial Gas, L.P. (now
known as PG&E Reata Energy, L.P.), Southern Union Gas Co., and Mercado Gas
Services, Inc., filed August 31, 1995, in the 92nd State District Court,
Hidalgo County, Texas; (2) Cities of San Benito, Primera, and Port Isabel v.
RGVG, Valero Energy Corporation (now known as PG&E GTT), Southern Union
Company, et al., filed December 31, 1996, in the 107th State District Court,
Cameron County, Texas; (3) City of Mercedes v. Reata Industrial Gas L.P. (now
known as PG&E Reata Energy, L.P.), and Reata Industrial Gas Company (now known
as PG&E Energy Trading Holdings Corporation), filed April 16, 1997, in the
92nd State District Court in Hidalgo County, Texas; (4) Cities of Alton and
Dana v. Rio Grande Valley Gas Co., Valero Energy Corporation (now known as
PG&E GTT), Valero Transmission Company (now known as PG&E Texas Pipeline
Company), Valero Natural Gas Company (now known as PG&E Texas Natural Gas
Company), Reata Industrial Gas Company (now known as PG&E Energy Trading
Holdings Corporation), Valero Transmission, L.P. (now known as PG&E Texas
Pipeline, L.P.), and Reata Industrial Gas, L.P. (now known as PG&E Reata
Energy, L.P.), Southern Union Gas Co., and Mercado Gas Services, Inc., filed
July 18, 1996, in the 92nd State District Court, Hidalgo County, Texas; (5)
City of La Joya v. Rio Grande Valley Gas Company, Valero Energy Corporation
(now known as PG&E GTT), Southern Union Company, et al., filed December 27,
1996, in the 92nd State District Court, Hidalgo County, Texas; (6) 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 (now known as PG&E
GTT), Southern Union Company, et al., filed December 27, 1996, in the 93rd
State District Court, Hidalgo County, Texas; and (7) City of Weslaco v. Valero
Natural Gas Company (now known as PG&E Texas Natural Gas Company), Reata
Industrial Gas Company (now known as PG&E Energy Trading Holdings Corporation)
and Reata Industrial Gas, L.P. (now known as PG&E Reata Energy L.P.) filed
April 17, 1997, in the 92nd State District Court, Hidalgo County, Texas.
The trial in the City of Edinburg case began on June 15, 1998. On August 14,
1998, a jury returned a verdict in favor of the City of Edinburg, and awarded
damages in the approximate aggregate amount of $9.8 million, plus attorneys'
fees of approximately $3.5 million, against PG&E GTT, Southern Union Gas
Company and various affiliates of PG&E GTT. The jury refused to award punitive
damages against the PG&E GTT defendants. On December 1, 1998, based on the
jury verdict, the court entered a judgment in the City's favor, and awarded
damages of $5.3 million, attorneys' fees of up to $3.5 million (to the extent
that the City is successful on appeal), prejudgment interest of $1.6 million
and post-judgment interest at the rate of 10 percent per year, compounded
annually, from December 1, 1998. The court found that various PG&E GTT and
Southern Union defendants were jointly and severally liable for $3.3 million
of the damages, prejudgment interest in the amount of $1.1 million, and all
the attorneys' fees. Certain PG&E GTT subsidiaries were found solely liable
for $1.4 million of the damages and prejudgment interest of $440,000. The
court did not clearly indicate the extent to which the PG&E GTT defendants
could be found liable for the remaining damages. The judgment also decreed
that (1) certain pipelines owned by PG&E GTT subsidiaries encroached on the
City's property without the City's consent and (2) based on certain jury
findings, PG&E GTT was vicariously liable for certain conduct of the local
distribution company, RGVG, from October 1, 1985, to September 30, 1993 (the
date Valero, PG&E GTT's predecessor, sold RGVG to Southern Union). The PG&E
GTT defendants are appealing the judgment.
43
<PAGE>
On November 4, 1997, the lawsuit filed in Cameron County, Texas, by the
cities of San Benito, Primera, and Port Isabel was amended to name as
defendants PG&E GTT and all of its subsidiaries (excluding its Canadian gas
trading and power trading company), PG&E Gas Transmission Teco, Inc. and its
subsidiaries, and PG&E Energy Trading Corporation (now known as PG&E Energy
Trading--Gas Corporation), and to dismiss the Southern Union defendants. In
connection with the certification of a class in this case, the court ordered
notice to be sent to all potential class members and setting an opt-out
deadline of December 31, 1997. Notices were mailed to approximately 159 Texas
cities. Fewer than 20 cities opted out by the deadline. Some of the cities
opting out include Austin, Brownsville, Houston, Pharr, and San Antonio.
Defendants' motion to transfer venue of this case to Bexar County, Texas, is
currently pending.
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, also is
currently pending.
In July 1996, the lawsuits brought by the cities of Alton and Dana were
originally brought as intervening actions in the City of Edinburg case, but
were severed from the Edinburg lawsuit. The claims asserted by the cities of
Alton and Dana are substantially similar to the Edinburg litigation claims.
Damages are not quantified. Defendants' motion to transfer venue of both cases
to Bexar County, Texas, also is currently pending.
On September 4, 1997, the City of Mercedes amended its petition to include
class action claims and requested to be named as class representative for a
statewide class consisting of all Texas municipal corporations,
municipalities, towns, and villages, excluding the cities of Edinburg and
Weslaco (both of which filed separate actions), in which any of the defendants
have sold or supplied gas, or used public rights-of-way to transport gas. The
City of Mercedes has requested a damage award, but has not specified an
amount. On November 26, 1997, defendants' motion to recuse the presiding judge
was granted. Plaintiffs' request for class certification is still pending. If
a class is certified, defendants anticipate that they will challenge such
certification. Defendants' motion to transfer venue to Bexar County, Texas,
also is still pending.
The causes of action alleged in the case brought by the city of Weslaco are
identical to those alleged in the City of Mercedes case. Defendants' motion to
transfer venue to Bexar County, Texas, is currently pending. Defendants also
have filed a motion to disqualify or recuse the presiding judge (the same
judge that was recused in the Mercedes case) which is also pending.
In addition to the seven cases described above, a lawsuit was filed on April
3, 1996, in the 92nd State District Court, Hidalgo County, Texas, by the City
of Pharr against Southern Union Company, et al., and RGVG. On June 24, 1996,
the court certified the case as a class action and named Pharr as the class
representative for the class consisting of those Texas cities, excluding
Edinburg and McAllen, that have, or had natural gas franchises with RGVG. The
Pharr class was certified as to two claims: breach of contract and declaratory
relief dealing with the rights, status, and legal relationship between
plaintiff, the class members, and the local distribution company regarding
payment of franchise fees and use of granted easements. Plaintiffs' original
petition also sought injunctive relief, but the class order does not include
injunctive relief. Plaintiffs seek actual damages, exemplary damages,
attorneys' fees, costs, and pre- and post-judgment interest, but have not
specified any amounts. The court records show that a pleading was allegedly
filed on December 12, 1997, but not docketed until mid-February 1998, that
purports to add as defendants the same 29 PG&E Corporation entities that are
parties in the San Benito class action. These PG&E Corporation entities have
not been served in this litigation. On December 30, 1997, in affirming the
Pharr class certification, the appellate court specifically found that the
PG&E Corporation-related entities were not parties to the class action.
PG&E Corporation believes that the ultimate outcome of the Texas franchise
fee cases described above could have a material adverse impact on its
financial position or results of operation.
ITEM 4. Submission of Matters to a Vote of Security Holders.
Not applicable.
44
<PAGE>
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:
<TABLE>
<CAPTION>
Age at
December 31,
Name 1998 Position
---- ------------ --------
<C> <C> <S>
R. D. Glynn, Jr. ....... 56 Chairman of the Board, Chief Executive
Officer, and President
S. W. Gebhardt.......... 47 Senior Vice President; President and
Chief Executive Officer, PG&E Energy
Services Corporation
T. W. High.............. 51 Senior Vice President, Administration
and External Relations
P. C. Iribe............. 48 Senior Vice President; President and
Chief Operating Officer, U.S.
Generating Company
T. B. King.............. 37 Senior Vice President; President and
Chief Operating Officer, PG&E Gas
Transmission Corporation
L. E. Maddox............ 43 Senior Vice President, President and
Chief Executive Officer, PG&E Energy
Trading Corporation
M. E. Rescoe............ 46 Senior Vice President, Chief Financial
Officer, and Treasurer
G. R. Smith............. 50 Senior Vice President; President and
Chief Executive Officer, Pacific Gas
and Electric Company
G. B. Stanley........... 52 Senior Vice President, Human Resources
B. R. Worthington....... 49 Senior Vice President and General
Counsel
</TABLE>
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.
<TABLE>
<CAPTION>
Name Position Period Held Office
---- -------- ------------------
<C> <S> <C>
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
</TABLE>
45
<PAGE>
<TABLE>
<CAPTION>
Name Position Period Held Office
---- -------- ------------------
<C> <S> <C>
P. C. Iribe.......... Senior Vice President January 1, 1999, to current
President and Chief November 1, 1998, to current
Operating Officer, U.S.
Generating Company
Executive Vice President September 1, 1997, to October 31, 1998
and Chief Operating
Officer, U.S.
Generating Company
Executive Vice May 1994 to September 1, 1997
President, Marketing,
Development, and Asset
Management, U.S.
Generating Company
Senior Vice President, September 1990 to May 1994
U.S. Generating Company
T. B. King........... Senior Vice President January 1, 1999, to current
President and Chief November 23, 1998, to current
Operating Officer, PG&E
Gas Transmission
Corporation
President and Chief February 14, 1997, to November 22, 1998
Operating Officer,
Kinder Morgan
Energy Partners, L.P.
Vice President, July 1, 1995, to February 14, 1997
Commercial Operations--
Midwest Region, Enron
Liquid Services
Corporation
Vice President, July 1994 to July 1, 1995
Gathering Services,
Northern Natural Gas
Company and
Transwestern Pipeline
Company
Vice President, September 1993 to July 1994
Transportation
Marketing Northern
Natural Gas 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.......... Senior Vice President January 1, 1999, to current
(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)
B. R. Worthington.... Senior Vice President June 1, 1997, to current
and General Counsel
General Counsel December 18, 1996, to May 31, 1997
Senior Vice President June 1, 1995, to June 30, 1997
and General Counsel,
Pacific Gas and
Electric Company
Vice President and December 21, 1994, to May 31, 1996
General Counsel,
Pacific Gas and
Electric Company
Chief Counsel-Corporate, January 10, 1991, to December 20, 1994
Pacific Gas and
Electric Company
</TABLE>
46
<PAGE>
"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:
<TABLE>
<CAPTION>
Age at
December 31,
Name 1998 Position
---- ------------ --------
<C> <C> <S>
G. R. Smith............. 50 President and Chief Executive Officer
K. M. Harvey............ 40 Senior Vice President, Treasurer and
Chief Financial Officer
E. J. Macias............ 44 Senior Vice President and General
Manager, Generation, Transmission,
and Supply Business Unit
R. J. Peters............ 48 Senior Vice President and General
Counsel
J. K. Randolph.......... 54 Senior Vice President and General
Manager, Distribution and Customer
Service Business Unit
D. D. Richard, Jr. ..... 48 Senior Vice President, Governmental
and Regulatory Relations
G. M. Rueger............ 48 Senior Vice President and General
Manager, Nuclear Power Generation
Business Unit
</TABLE>
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.
<TABLE>
<CAPTION>
Name Position Period Held Office
---- -------- ------------------
<C> <S> <C>
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
</TABLE>
47
<PAGE>
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 69 under the heading
"Quarterly Consolidated Financial Data (Unaudited)" in the 1998 Annual Report
to Shareholders, which information is hereby incorporated by reference and
filed as part of Exhibit 13 to this report. As of February 22, 1999, there
were 162,261 holders of record of PG&E Corporation common stock.
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 Pipeline
Company (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 17 under the heading "Selected Financial Data" in the 1998
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, 1998, was 3.02. Pacific Gas and Electric Company's
earnings to combined fixed charges and preferred stock dividends ratio for the
year ended December 31, 1998, was 2.85. The statement of the foregoing ratios,
together with the statements of the computation of the foregoing ratios filed
as Exhibits 12.1 and 12.2 hereto, are included herein for the purpose of
incorporating such information and exhibits into Registration Statement Nos.
33-62488, 33-64136, 33-50707, and 33-61959 relating to Pacific Gas and
Electric Company's various classes of debt and first preferred stock
outstanding.
ITEM 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations.
A discussion of PG&E Corporation's and Pacific Gas and Electric Company's
consolidated results of operations and financial condition is set forth on
pages 18 through 35 under the heading "Management's Discussion and Analysis"
in the 1998 Annual Report to Shareholders, which discussion is hereby
incorporated by reference and filed as part of Exhibit 13 to this report.
ITEM 7A. Quantitative and Qualitative Disclosures About Market Risk.
Information responding to Item 7A appears in the 1998 Annual Report to
Shareholders on page 32 under the heading "Management's Discussion and
Analysis--Debt Obligations and Rate Reduction Bonds," on pages 34 and 35 under
the heading "Management's Discussion and Analysis--Price Risk Management
Activities," and on pages 47, 48, 53, and 54 under Notes 1, 3, and 4 of the
"Notes to Consolidated Financial Statements" of the 1998 Annual Report to
Shareholders, which information is hereby incorporated by reference and filed
as part of Exhibit 13 to this report.
48
<PAGE>
ITEM 8. Financial Statements and Supplementary Data.
Information responding to Item 8 appears on pages 36 through 70 of the 1998
Annual Report to Shareholders under the following headings for PG&E
Corporation: "Statement of Consolidated Income," "Consolidated Balance Sheet,"
"Statement of Consolidated Cash Flows," and "Statement of Consolidated Common
Stock Equity;" under the following headings for Pacific Gas and Electric
Company: "Statement of Consolidated Income," "Consolidated Balance Sheet,"
"Statement of Consolidated Cash Flows," and "Statement of Consolidated Common
Stock Equity, Preferred Stock, and Preferred Securities;" and under the
following headings for PG&E Corporation and Pacific Gas and Electric Company
jointly: "Notes to Consolidated Financial Statements," "Quarterly Consolidated
Financial Data (Unaudited)," 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.
Information responding to Item 9 has been previously reported by PG&E
Corporation and Pacific Gas and Electric Company in a current report on Form
8-K dated February 17, 1999 and filed on February 23, 1999.
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 45 through 47 in Part I of this
report. Other information responding to Item 10 is included on pages 3 through
6 under the heading "Item No. 1: Election of Directors of PG&E Corporation and
Pacific Gas and Electric Company" and page 43 under the heading "Section 16(a)
Beneficial Ownership Reporting Compliance" in the 1999 Joint Proxy Statement
relating to the 1999 Annual Meetings of Shareholders, which information is
hereby incorporated by reference.
ITEM 11. Executive Compensation.
Information responding to Item 11, for each of PG&E Corporation and Pacific
Gas and Electric Company, is included on pages 9 and 10 under the heading
"Compensation of Directors" and on pages 36 through 41 under the headings
"Summary Compensation Table," "Option/SAR Grants in 1998," "Aggregated
Option/SAR Exercises in 1998 and Year-End Option/SAR Values," "Long-Term
Incentive Plan--Awards in 1998," "Retirement Benefits," and "Termination of
Employment and Change In Control Provisions" in the 1999 Joint Proxy Statement
relating to the 1999 Annual Meetings of Shareholders, which information is
hereby incorporated by reference.
ITEM 12. Security Ownership of Certain Beneficial Owners and Management.
Information responding to Item 12, for each of PG&E Corporation and Pacific
Gas and Electric Company, is included on pages 11 and 12 under the heading
"Security Ownership of Management" and on pages 42 and 43 under the heading
"Principal Shareholders" in the 1999 Joint Proxy Statement relating to the
1999 Annual Meetings of Shareholders, which information is hereby incorporated
by reference.
ITEM 13. Certain Relationships and Related Transactions.
Information responding to Item 13, for each of PG&E Corporation and Pacific
Gas and Electric Company, is included on page 10 under the heading "Certain
Relationships and Related Transactions" in the 1999 Joint Proxy Statement
relating to the 1999 Annual Meetings of Shareholders, which information is
hereby incorporated by reference.
49
<PAGE>
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 1998 Annual Report to Shareholders, which have been
incorporated by reference in this report:
Statements of Consolidated Income for the Years Ended December 31,
1998, 1997, and 1996, for each of PG&E Corporation and Pacific Gas
and Electric Company.
Statements of Consolidated Cash Flows for the Years Ended December
31, 1998, 1997, and 1996, for each of PG&E Corporation and Pacific
Gas and Electric Company.
Consolidated Balance Sheets at December 31, 1998, and 1997, for each
of PG&E Corporation and Pacific Gas and Electric Company.
Statement of Consolidated Common Stock Equity for the Years Ended
December 31, 1998, 1997, and 1996, for PG&E Corporation.
Statement of Consolidated Common Stock Equity, Preferred Stock and
Preferred Securities for the Years Ended December 31, 1998, 1997,
and 1996, for 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 55 of this
Form 10-K.
3. Consolidated financial statement schedules:
I --Condensed Financial Information of Parent for the Years Ended
December 31, 1998 and 1997.
II--Consolidated Valuation and Qualifying Accounts for each of PG&E
Corporation and Pacific Gas and Electric Company for the Years
Ended December 31, 1998, 1997 and 1996.
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:
<TABLE>
<C> <S>
3.1 Restated Articles of Incorporation of PG&E Corporation effective
as of December 19, 1996 (PG&E Corporation's Form 8-B (File No. 1-
12609), Exhibit 3.1).
3.2 By-Laws of PG&E Corporation amended as of January 27, 1999.
3.3 Restated Articles of Incorporation of Pacific Gas and Electric
Company effective as of May 6, 1998 (Pacific Gas and Electric
Company's Form 10-Q for the quarter ended March 31, 1998 (File No.
1-2348), Exhibit 3.1).
3.4 By-Laws of Pacific Gas and Electric Company amended as of January
27, 1999.
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
</TABLE>
50
<PAGE>
<TABLE>
<C> <S>
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. (PG&E Corporation and
Pacific Gas and Electric Company's Form 10-K for the year ended
December 31, 1997 (File No. 1-12609 and File No. 1-2348), Exhibit
No. 10.2.)
*10.3 PG&E Corporation Deferred Compensation Plan for Non-Employee
Directors, as amended and restated effective as of July 22, 1998.
(PG&E Corporation's Form 10-Q for the quarter ended September 30,
1998 (File No. 1-12609), Exhibit 10.2).
*10.4 PG&E Corporation Deferred Compensation Plan for Officers, as
amended and restated effective as of October 21, 1998.
*10.5 Description of Short-Term Incentive Plan for Officers of PG&E
Corporation and its subsidiaries, effective January 1, 1998.
*10.6 Description of Short-Term Incentive Plan for Officers of PG&E
Corporation and its subsidiaries, effective January 1, 1999.
*10.7 Supplemental Executive Retirement Plan of the Pacific Gas and
Electric Company, effective January 1, 1998.
*10.8 PG&E Corporation Supplemental Executive Retirement Savings Plan,
effective January 1, 1998.
*10.9 Pacific Gas and Electric Company Relocation Assistance Program
for Officers (Pacific Gas and Electric Company's Form 10-K for
fiscal year 1989 (File No. 1-2348), Exhibit 10.16).
*10.10 Postretirement Life Insurance Plan of the Pacific Gas and
Electric Company (Pacific Gas and Electric Company's Form 10-K
for fiscal year 1991 (File No. 1-2348), Exhibit 10.16).
*10.11 PG&E Corporation Retirement Plan for Non-Employee Directors, as
amended and terminated January 1, 1998. (PG&E Corporation Form
10-K for the year ended December 31, 1997, (File No. 1-12609),
Exhibit No. 10.13.)
*10.12 PG&E Corporation Long-Term Incentive Program, as amended and
restated effective as of October 21, 1998, including the PG&E
Corporation Stock Option Plan, Performance Unit Plan, and Non-
Employee Director Stock Incentive Plan.
*10.13 PG&E Corporation Executive Stock Ownership Program, effective
January 1, 1998, as amended October 21, 1998.
*10.14 PG&E Corporation Officer Severance Policy, effective as of
December 16, 1998.
*10.15 PG&E Corporation Director Grantor Trust Agreement dated April 1,
1998 (PG&E Corporation's Form 10-Q for the quarter ended March
31, 1998 (File No. 1-12609), Exhibit 10.1).
*10.16 PG&E Corporation Officer Grantor Trust Agreement dated April 1,
1998 (PG&E Corporation's Form 10-Q for the quarter ended March
31, 1998 (File No. 1-12609), Exhibit 10.2).
</TABLE>
51
<PAGE>
<TABLE>
<C> <S>
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. 1998 Annual Report to Shareholders of PG&E Corporation and Pacific
Gas and Electric Company--portions of the 1998 Annual Report to
Shareholders under the headings "Selected Financial Data,"
"Management's Discussion and Analysis," "Report of Independent
Public Accountants," financial statements of PG&E Corporation
entitled "Statement of Consolidated Income," "Consolidated Balance
Sheet," "Statement of Consolidated Cash Flows," "Statement of
Consolidated Common Stock Equity," financial statements of Pacific
Gas and Electric Company entitled "Statement of Consolidated
Income," "Consolidated Balance Sheet," "Statement of Consolidated
Cash Flows," "Statement of Consolidated Common Stock Equity,
Preferred Stock and Preferred Securities," "Notes to Consolidated
Financial Statements" and "Quarterly Consolidated Financial Data
(Unaudited)" are included only. (Except for those portions which
are expressly incorporated herein by reference, such 1998 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 Company Act of 1935 under Rule 2
by filing Form U-3A-2 dated March 1, 1999, pages 1 through 34).
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, 1998, for
PG&E Corporation.
27.2 Financial Data Schedule for the year ended December 31, 1998, for
Pacific Gas and Electric Company.
</TABLE>
- --------
* Management contract or compensatory plan or arrangement required to be
filed as an exhibit to this report pursuant to Item 14(c) of Form 10-K.
The exhibits filed herewith are attached hereto (except as noted) and those
indicated above which are not filed herewith were previously filed with the
Commission and are hereby incorporated by reference. All exhibits filed
herewith or incorporated by reference are filed with respect to both PG&E
Corporation (File No. 1-12609) and Pacific Gas and Electric Company (File No.
1-2348), unless otherwise noted. Exhibits will be furnished to security
holders of PG&E Corporation or Pacific Gas and Electric Company upon written
request and payment of a fee of $0.30 per page, which fee covers only the
registrants' reasonable expenses in furnishing such exhibits. The registrants
agree to furnish to the Commission upon request a copy of any instrument
defining the rights of long-term debt holders not otherwise required to be
filed hereunder.
52
<PAGE>
(b) Reports on Form 8-K
Reports on Form 8-K(/1/) during the quarter ended December 31, 1998, and
through the date hereof:
1. October 21, 1998
Item 5. Other Events
-- Year-to-Date Financial Results
2. November 4, 1998
Item 5. Other Events
A. Electric Industry Restructuring
3. November 25, 1998
Item 5. Other Events
A. Electric Industry Restructuring
4. January 20, 1999
Item 5. Other Events
A. 1998 Consolidated Earnings (unaudited)
B.1999 Outlook
C.Share Repurchase Program
5. February 17, 1999
Item 4. Changes in Registrant's Certifying Accountant
Item 5. Other Events
-- Share 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)
53
<PAGE>
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, 1999.
PG&E CORPORATION PACIFIC GAS AND ELECTRIC COMPANY
(Registrant) (Registrant)
By /s/ Gary P. Encinas By /s/ Gary P. Encinas
--------------------------------- ---------------------------------
(Gary P. Encinas, Attorney-in-Fact) (Gary P. Encinas, Attorney-in-Fact)
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrants and in the capacities and on the dates indicated.
<TABLE>
<CAPTION>
Signature Title Date
--------- ----- ----
<C> <S> <C>
A. Principal Executive Officers
*ROBERT D. GLYNN, JR. Chairman of the Board, Chief March 5, 1999
Executive Officer, and President
(PG&E Corporation)
*GORDON R. SMITH President and Chief Executive Officer
(Pacific Gas and Electric Company)
B. Principal Financial Officers
*MICHAEL E. RESCOE Senior Vice President, Chief March 5, 1999
Financial Officer, and Treasurer
(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, 1999
(PG&E Corporation)
Vice President and Controller
(Pacific Gas and Electric Company)
D. Directors
*RICHARD A. CLARKE
*DAVID A. COULTER
*C. LEE COX
*WILLIAM S. DAVILA
*ROBERT D. GLYNN, JR.
*DAVID M. LAWRENCE Directors of PG&E Corporation and March 5, 1999
*RICHARD B. MADDEN Pacific Gas and Electric Company,
*MARY S. METZ except as noted
*REBECCA Q. MORGAN
*JOHN C. SAWHILL
*GORDON R. SMITH
(Director of Pacific Gas and
Electric Company, only)
*BARRY LAWSON WILLIAMS
</TABLE>
*By /s/ Gary P. Encinas
----------------------------
(Gary P. Encinas, Attorney-in-Fact)
54
<PAGE>
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 Form 10-K, and have issued our report thereon dated February
8, 1999. Our audits were made for the purpose of forming an opinion on those
statements taken as a whole. The schedules listed in Part IV, Item 14. (a)(3)
in this Form 10-K are the responsibility of the management of PG&E Corporation
and of Pacific Gas and Electric Company and are presented for purposes of
complying with the Securities and Exchange Commission's rules and are not part
of the consolidated financial statements. These schedules have been subjected
to the auditing procedures applied in the audits of the consolidated financial
statements and, in our opinion, fairly state in all material respects the
financial data required to be set forth therein in relation to the
consolidated financial statements taken as a whole.
/s/ ARTHUR ANDERSEN LLP
San Francisco, California
February 8, 1999
55
<PAGE>
SCHEDULE I--CONDENSED FINANCIAL INFORMATION OF PARENT
CONDENSED BALANCE SHEET
<TABLE>
<CAPTION>
December 31,
--------------
1998 1997
------ ------
(in millions)
<S> <C> <C>
Assets:
Cash and cash equivalents.................................... $ 9 $ 1
Accounts Receivable
Related parties............................................ 448 149
Other current assets......................................... 2 --
------ ------
Total current assets..................................... 459 150
Property, plant, and equipment............................... 6 --
Construction work in progress................................ 2 --
------ ------
Total property, plant, and equipment......................... 8 --
Accumulated depreciation and decommissioning................. (1) --
------ ------
Net property, plant, and equipment........................... 7 --
Investments in subsidiaries.................................. 8,780 9,556
Other noncurrent assets...................................... 41 --
Other deferred charges....................................... 1 1
------ ------
Total Assets............................................. $9,288 $9,707
====== ======
Liabilities and Stockholders' Equity:
Current Liabilities
Short-term borrowings...................................... $ 683 $ --
Accounts payable
Related parties........................................... 221 635
Other..................................................... 9 10
Accrued taxes.............................................. 155 46
Dividends payable.......................................... 115 118
Other...................................................... 16 --
------ ------
Total current liabilities.................................. 1,199 809
Noncurrent Liabilities
Deferred income taxes...................................... 19 --
Other...................................................... 4 1
------ ------
Total noncurrent liabilities............................... 23 1
Stockholder's Equity
Common stock............................................... 5,862 6,366
Reinvested earnings........................................ 2,204 2,531
------ ------
Total stockholders' equity................................. 8,066 8,897
------ ------
Total Liabilities and Stockholders' Equity............... $9,288 $9,707
====== ======
</TABLE>
<PAGE>
SCHEDULE I--CONDENSED FINANCIAL INFORMATION FOR PARENT--(Continued)
CONDENSED STATEMENTS OF INCOME
For the years ended December 31, 1998 and 1997
<TABLE>
<CAPTION>
1998 1997
------- -------
(in millions,
except per
share amounts)
<S> <C> <C>
Equity in earnings of subsidiaries......................... $ 684 $ 743
Operating expenses......................................... 1 (21)
Interest expense........................................... (52) (23)
Other income............................................... 5 --
------- -------
Income Before Income Taxes................................. 638 699
Less: Income taxes......................................... (83) (17)
------- -------
Net Income................................................. $ 721 $ 716
Elimination of intercompany profit......................... (2) --
------- -------
Income Available for Common Stock.......................... $ 719 $ 716
======= =======
Weighted Average Common Shares Outstanding................. 382 410
Earnings Per Common Share.................................. $ 1.88 $ 1.75
======= =======
</TABLE>
CONDENSED STATEMENTS OF CASH FLOWS
For the years ended December 31, 1998 and 1997
<TABLE>
<CAPTION>
1998 1997
------- -------
(in millions)
<S> <C> <C>
Cash Flows From Operating Activities
Net income............................................... $ 721 $ 716
Adjustments to reconcile net income to net cash provided
by operating activities:
Dividends received from consolidated subsidiaries...... 445 763
Other--net............................................. (1,291) (167)
------- -------
Net cash provided by operating activities................ $ (125) $ 1,312
Cash Flows From Investing Activities
Capital expenditures................................... (8) --
Investments in unregulated projects.................... (575) (150)
Repurchase of Utility stock holdings by parent......... 1,600 --
------- -------
Net cash provided by investing activities................ $ 1,017 $ (150)
Cash Flows From Financing Activities
Common stock repurchased............................... (1,158) (804)
Short-term debt issued--net............................ 683 --
Dividends paid......................................... (470) (367)
Other--net............................................. 61 10
------- -------
Net cash used by financing activities.................... (884) (1,161)
Net Change in Cash and Cash Equivalents.................. 8 1
Cash and Cash Equivalents at January 1................... 1 --
------- -------
Cash and Cash Equivalents at December 31................. $ 9 $ 1
======= =======
</TABLE>
<PAGE>
PG&E CORPORATION
SCHEDULE II--CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
For the years ended December 31, 1998, 1997, and 1996
<TABLE>
<CAPTION>
Column A Column B Column C Column D Column E
Additions
---------------------
Balance
Balance at Charged Charged at end
beginning to costs to other of
Description of period and expenses accounts Deductions period
----------- ---------- ------------ -------- ---------- --------
(in thousands)
<S> <C> <C> <C> <C> <C>
Valuation and qualifying
accounts deducted from
assets:
1998:
Allowance for
uncollectible
accounts............. $72,912 $10,978 $(2,893) $22,420(2) $58,577
======= ======= ======= ======= =======
1997:
Allowance for
uncollectible
accounts............. $57,904 $42,500 $ -- $27,492(2) $72,912
======= ======= ======= ======= =======
1996:
Reserve for deferred
project costs........ $ 5,710 $ -- $ -- $ 5,710(1) $ --
======= ======= ======= ======= =======
Allowance for
uncollectible
accounts............. $35,520 $55,566 $ 1,836 $35,018(2) $57,904
======= ======= ======= ======= =======
Reserve for land
costs................ $ 4,444 $ -- $ -- $ 4,444(1) $ --
======= ======= ======= ======= =======
</TABLE>
- --------
(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.
<PAGE>
PACIFIC GAS AND ELECTRIC COMPANY
SCHEDULE II--CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
For the years ended December 31, 1998, 1997, and 1996
<TABLE>
<CAPTION>
Column A Column B Column C Column D Column E
Additions
---------------------
Balance
Balance at Charged Charged at end
beginning to costs to other of
Description of period and expenses accounts Deductions period
----------- ---------- ------------ -------- ---------- --------
(in thousands)
<S> <C> <C> <C> <C> <C>
Valuation and qualifying
accounts deducted from
assets:
1998:
Allowance for
uncollectible
accounts............. $59,608 $10,007 $ 152 $22,420(2) $47,347
======= ======= ======= ======= =======
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) $ --
======= ======= ======= ======= =======
Allowance for
uncollectible
accounts............. $35,520 $55,566 $ 1,836 $35,018(2) $57,904
======= ======= ======= ======= =======
Reserve for land
costs................ $ 4,444 $ -- $ -- $ 4,444(1) $ --
======= ======= ======= ======= =======
</TABLE>
- --------
(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.
<PAGE>
EXHIBIT INDEX
<TABLE>
<CAPTION>
Exhibit
No. Description
------- -----------
<C> <S>
3.1 Restated Articles of Incorporation of PG&E Corporation effective as of
December 19, 1996 (PG&E Corporation's Form 8-B (File No. 1-12609),
Exhibit 3.1).
3.2 By-Laws of PG&E Corporation amended as of January 27, 1999.
3.3 Restated Articles of Incorporation of Pacific Gas and Electric Company
effective as of May 6, 1998 (Pacific Gas and Electric Company's Form
10-Q for the quarter ended March 31, 1998 (File No. 1-2348), Exhibit
3.1).
3.4 By-Laws of Pacific Gas and Electric Company amended as of January 27,
1999.
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. (PG&E Corporation and Pacific
Gas and Electric Company's Form 10-K for the year ended December 31,
1997, (File No. 1-12609 and File No. 1-2348), Exhibit No. 10.2.)
*10.3 PG&E Corporation Deferred Compensation Plan for Non-Employee
Directors, as amended and restated effective as of July 22, 1998.
(PG&E Corporation's Form 10-Q for the quarter ended September 30,
1998 (File No. 1-12609), Exhibit 10.2).
*10.4 PG&E Corporation Deferred Compensation Plan for Officers, as amended
and restated effective as of October 21, 1998.
*10.5 Description of Short-Term Incentive Plan for Officers of PG&E
Corporation and its subsidiaries, effective January 1, 1998.
*10.6 Description of Short-Term Incentive Plan for Officers of PG&E
Corporation and its subsidiaries, effective January 1, 1999.
*10.7 Supplemental Executive Retirement Plan of the Pacific Gas and Electric
Company, effective January 1, 1998.
*10.8 PG&E Corporation Supplemental Executive Retirement Savings Plan,
effective January 1, 1998.
*10.9 Pacific Gas and Electric Company Relocation Assistance Program for
Officers (Pacific Gas and Electric Company's Form 10-K for fiscal
year 1989 (File No. 1-2348), Exhibit 10.16).
*10.10 Postretirement Life Insurance Plan of the Pacific Gas and Electric
Company (Pacific Gas and Electric Company's Form 10-K for fiscal year
1991 (File No. 1-2348), Exhibit 10.16).
*10.11 PG&E Corporation Retirement Plan for Non-Employee Directors, as
amended and terminated January 1, 1998. (PG&E Corporation Form 10-K
for the year ended December 31, 1997, (File No. 1-12609), Exhibit No.
10.13.)
</TABLE>
56
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT
NO. DESCRIPTION
------- -----------
<C> <S>
*10.12 PG&E Corporation Long-Term Incentive Program, as amended and restated
effective as of October 21, 1998, including the PG&E Corporation
Stock Option Plan, Performance Unit Plan, and Non-Employee Director
Stock Incentive Plan.
*10.13 PG&E Corporation Executive Stock Ownership Program, effective January
1, 1998, as amended October 21, 1998.
*10.14 PG&E Corporation Officer Severance Policy, effective as of December
16, 1998.
*10.15 PG&E Corporation Director Grantor Trust Agreement dated April 1, 1998
(PG&E Corporation's Form 10-Q for the quarter ended March 31, 1998
(File No. 1-12609), Exhibit 10.1).
*10.16 PG&E Corporation Officer Grantor Trust Agreement dated April 1, 1998
(PG&E Corporation's Form 10-Q for the quarter ended March 31, 1998
(File No. 1-12609), Exhibit 10.2).
11. Computation of Earnings Per Common Share.
12.1 Computation of Ratios of Earnings to Fixed Charges for Pacific Gas and
Electric Company.
12.2 Computation of Ratios of Earnings to Combined Fixed Charges and
Preferred Stock Dividends for Pacific Gas and Electric Company.
13. 1998 Annual Report to Shareholders of PG&E Corporation and Pacific Gas
and Electric Company--portions of the 1998 Annual Report to
Shareholders under the headings "Selected Financial Data,"
"Management's Discussion and Analysis," "Report of Independent Public
Accountants," financial statements of PG&E Corporation entitled
"Statement of Consolidated Income," "Consolidated Balance Sheet,"
"Statement of Consolidated Cash Flows," "Statement of Consolidated
Common Stock Equity," financial statements of Pacific Gas and
Electric Company entitled "Statement of Consolidated Income,"
"Consolidated Balance Sheet," "Statement of Consolidated Cash Flows,"
"Statement of Consolidated Common Stock Equity, Preferred Stock and
Preferred Securities," "Notes to Consolidated Financial Statements"
and "Quarterly Consolidated Financial Data (Unaudited)" are included
only. (Except for those portions which are expressly incorporated
herein by reference, such 1998 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 Company Act of 1935 under Rule 2 by filing
Form U-3A-2 dated March 1, 1999, pages 1 through 34).
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, 1998, for PG&E
Corporation.
27.2 Financial Data Schedule for the year ended December 31, 1998, for
Pacific Gas and Electric Company.
</TABLE>
The exhibits filed herewith are attached hereto (except as noted) and those
indicated above which are not filed herewith were previously filed with the
Commission and are hereby incorporated by reference. All exhibits filed
herewith or incorporated by reference are filed with respect to both PG&E
Corporation (File No. 1-12609) and Pacific Gas and Electric Company (File No.
1-2348), unless otherwise noted. Exhibits will be furnished to security
holders of PG&E Corporation or Pacific Gas and Electric Company upon written
request and payment of a fee of $0.30 per page, which fee covers only the
registrants' reasonable expenses in furnishing such exhibits. The registrants
agree to furnish to the Commission upon request a copy of any instrument
defining the rights of long-term debt holders not otherwise required to be
filed hereunder.
- --------
* 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.
57
<PAGE>
EXHIBIT 3.2
Bylaws
of
PG&E Corporation
amended as of January 27, 1999
------------------------------
Article I.
SHAREHOLDERS.
1. Place of Meeting. All meetings of the shareholders shall be held
at the office of the Corporation in the City and County of San Francisco, State
of California, or at such other place within the State of California as may be
designated by the Board of Directors.
2. Annual Meetings. The annual meeting of shareholders shall be
held each year on a date and at a time designated by the Board of Directors.
Written notice of the annual meeting shall be given not less than ten (or, if
sent by third-class mail, thirty) nor more than sixty days prior to the date of
the meeting to each shareholder entitled to vote thereat. The notice shall
state the place, day, and hour of such meeting, and those matters which the
Board, at the time of mailing, intends to present for action by the
shareholders.
Notice of any meeting of the shareholders shall be given by mail or
telegraphic or other written communication, postage prepaid, to each holder of
record of the stock entitled to vote thereat, at his address, as it appears on
the books of the Corporation.
3. Special Meetings. Special meetings of the shareholders shall be
called by the Corporate Secretary or an Assistant Corporate Secretary at any
time on order of the Board of Directors, the Chairman of the Board, the Vice
Chairman of the Board, the Chairman of the Executive Committee, or the
President. Special meetings of the shareholders shall also be called by the
Corporate Secretary or an Assistant Corporate Secretary upon the written request
of holders of shares entitled to cast not less than ten percent of the votes at
the meeting. Such request shall state the purposes of the meeting, and shall be
delivered to the Chairman of the Board, the Vice Chairman of the Board, the
Chairman of the Executive Committee, the President, or the Corporate Secretary.
A special meeting so requested shall be held on the date requested, but not
less than thirty-five nor more than sixty days after the date of the original
request. Written notice of each special meeting of shareholders, stating the
place, day, and hour of such meeting and the business proposed to be transacted
thereat, shall be given in the
<PAGE>
manner stipulated in Article I, Section 2, Paragraph 3 of these Bylaws within
twenty days after receipt of the written request.
4. Attendance at Meetings. At any meeting of the shareholders, each
holder of record of stock entitled to vote thereat may attend in person or may
designate an agent or a reasonable number of agents, not to exceed three to
attend the meeting and cast votes for his or her shares. The authority of
agents must be evidenced by a written proxy signed by the shareholder
designating the agents authorized to attend the meeting and be delivered to the
Corporate Secretary of the Corporation prior to the commencement of the meeting.
Article II.
DIRECTORS.
1. Number. As stated in Section I of Article Third of this Corporation's
Articles of Incorporation, the authorized number of directors of this
Corporation can be no less than nine (9) nor more than seventeen (17), with the
exact number within the range determined by this Corporation's Board of
Directors. The exact number of directors within the range shall be thirteen
(13), unless and until the Board of Directors fixes a different number within
the range through amendment of these Bylaws which amendment may be adopted
solely by the Board of Directors.
2. Powers. The Board of Directors shall exercise all the powers of
the Corporation except those which are by law, or by the Articles of
Incorporation of this Corporation, or by the Bylaws conferred upon or reserved
to the shareholders.
3. Executive Committee. There shall be an Executive Committee of the
Board of Directors consisting of the Chairman of the Committee, the Chairman of
the Board, if these offices be filled, the President, and four Directors who are
not officers of the Corporation. The members of the Committee shall be elected,
and may at any time be removed, by a two-thirds vote of the whole Board.
The Executive Committee, subject to the provisions of law, may exercise any of
the powers and perform any of the duties of the Board of Directors; but the
Board may by an affirmative vote of a majority of its members withdraw or limit
any of the powers of the Executive Committee.
The Executive Committee, by a vote of a majority of its members, shall fix its
own time and place of meeting, and shall prescribe its own rules of procedure.
A quorum of the Committee for the transaction of business shall consist of three
members.
2
<PAGE>
4. Time and Place of Directors' Meetings. Regular meetings of the
Board of Directors shall be held on such days and at such times and at such
locations as shall be fixed by resolution of the Board, or designated by the
Chairman of the Board or, in his absence, the Vice Chairman of the Board, or the
President of the Corporation and contained in the notice of any such meeting.
Notice of meetings shall be delivered personally or sent by mail or telegram at
least seven days in advance.
5. Special Meetings. The Chairman of the Board, the Vice Chairman
of the Board, the Chairman of the Executive Committee, the President, or any
five directors may call a special meeting of the Board of Directors at any time.
Notice of the time and place of special meetings shall be given to each Director
by the Corporate Secretary. Such notice shall be delivered personally or by
telephone to each Director at least four hours in advance of such meeting, or
sent by first-class mail or telegram, postage prepaid, at least two days in
advance of such meeting.
6. Quorum. A quorum for the transaction of business at any meeting
of the Board of Directors shall consist of six members.
7. Action by Consent. Any action required or permitted to be taken
by the Board of Directors may be taken without a meeting if all Directors
individually or collectively consent in writing to such action. Such written
consent or consents shall be filed with the minutes of the proceedings of the
Board of Directors.
8. Meetings by Conference Telephone. Any meeting, regular or
special, of the Board of Directors or of any committee of the Board of
Directors, may be held by conference telephone or similar communication
equipment, provided that all Directors participating in the meeting can hear one
another.
Article III.
OFFICERS.
1. Officers. The officers of the Corporation shall be a Chairman of
the Board, a Vice Chairman of the Board, a Chairman of the Executive Committee
(whenever the Board of Directors in its discretion fills these offices), a
President, a Chief Financial Officer, a General Counsel, one or more Vice
Presidents, a Corporate Secretary and one or more Assistant Corporate
Secretaries, a Treasurer and one or more Assistant Treasurers, and a Controller,
all of whom shall be elected by the Board of Directors. The Chairman of the
Board, the Vice Chairman of the Board, the Chairman of the Executive Committee,
and the President shall be members of the Board of Directors.
3
<PAGE>
2. Chairman of the Board. The Chairman of the Board, if that office
be filled, shall preside at all meetings of the shareholders and of the
Directors, and shall preside at all meetings of the Executive Committee in the
absence of the Chairman of that Committee. He shall be the chief executive
officer of the Corporation if so designated by the Board of Directors. He shall
have such duties and responsibilities as may be prescribed by the Board of
Directors or the Bylaws. The Chairman of the Board shall have authority to sign
on behalf of the Corporation agreements and instruments of every character, and,
in the absence or disability of the President, shall exercise the President's
duties and responsibilities.
3. Vice Chairman of the Board. The Vice Chairman of the Board, if
that office be filled, shall have such duties and responsibilities as may be
prescribed by the Board of Directors, the Chairman of the Board, or the Bylaws.
He shall be the chief executive officer of the Corporation if so designated by
the Board of Directors. In the absence of the Chairman of the Board, he shall
preside at all meetings of the Board of Directors and of the shareholders; and,
in the absence of the Chairman of the Executive Committee and the Chairman of
the Board, he shall preside at all meetings of the Executive Committee. The
Vice Chairman of the Board shall have authority to sign on behalf of the
Corporation agreements and instruments of every character.
4. Chairman of the Executive Committee. The Chairman of the Executive
Committee, if that office be filled, shall preside at all meetings of the
Executive Committee. He shall aid and assist the other officers in the
performance of their duties and shall have such other duties as may be
prescribed by the Board of Directors or the Bylaws.
5. President. The President shall have such duties and responsibilities as
may be prescribed by the Board of Directors, the Chairman of the Board, or the
Bylaws. He shall be the chief executive officer of the Corporation if so
designated by the Board of Directors. If there be no Chairman of the Board, the
President shall also exercise the duties and responsibilities of that office.
The President shall have authority to sign on behalf of the Corporation
agreements and instruments of every character.
6. Chief Financial Officer. The Chief Financial Officer shall be
responsible for the overall management of the financial affairs of the
Corporation. He shall render a statement of the Corporation's financial
condition and an account of all transactions whenever requested by the Board of
Directors, the Chairman of the Board, the Vice Chairman of the Board, or the
President.
The Chief Financial Officer shall have such other duties as may from time to
time be prescribed by the Board of Directors, the Chairman of the Board, the
Vice Chairman of the Board, the President, or the Bylaws.
4
<PAGE>
7. General Counsel. The General Counsel shall be responsible for
handling on behalf of the Corporation all proceedings and matters of a legal
nature. He shall render advice and legal counsel to the Board of Directors,
officers, and employees of the Corporation, as necessary to the proper conduct
of the business. He shall keep the management of the Corporation informed of
all significant developments of a legal nature affecting the interests of the
Corporation.
The General Counsel shall have such other duties as may from time to time be
prescribed by the Board of Directors, the Chairman of the Board, the Vice
Chairman of the Board, the President, or the Bylaws.
8. Vice Presidents. Each Vice President, if those offices are filled, shall
have such duties and responsibilities as may be prescribed by the Board of
Directors, the Chairman of the Board, the Vice Chairman of the Board, the
President, or the Bylaws. Each Vice President's authority to sign agreements and
instruments on behalf of the Corporation shall be as prescribed by the Board of
Directors. The Board of Directors, the Chairman of the Board, the Vice Chairman
of the Board, or the President may confer a special title upon any Vice
President.
9. Corporate Secretary. The Corporate Secretary shall attend all
meetings of the Board of Directors and the Executive Committee, and all meetings
of the shareholders, and he shall record the minutes of all proceedings in books
to be kept for that purpose. He shall be responsible for maintaining a proper
share register and stock transfer books for all classes of shares issued by the
Corporation. He shall give, or cause to be given, all notices required either
by law or the Bylaws. He shall keep the seal of the Corporation in safe
custody, and shall affix the seal of the Corporation to any instrument requiring
it and shall attest the same by his signature.
The Corporate Secretary shall have such other duties as may be prescribed by
the Board of Directors, the Chairman of the Board, the Vice Chairman of the
Board, the President, or the Bylaws.
The Assistant Corporate Secretaries shall perform such duties as may be
assigned from time to time by the Board of Directors, the Chairman of the Board,
the Vice Chairman of the Board, the President, or the Corporate Secretary. In
the absence or disability of the Corporate Secretary, his duties shall be
performed by an Assistant Corporate Secretary.
10. Treasurer. The Treasurer shall have custody of all moneys and
funds of the Corporation, and shall cause to be kept full and accurate records
of receipts and disbursements of the Corporation. He shall deposit all moneys
and other valuables of the Corporation in the name and to the credit of the
Corporation in such depositaries as may be designated by the Board of Directors
or any employee of the Corporation
5
<PAGE>
designated by the Board of Directors. He shall disburse such funds of the
Corporation as have been duly approved for disbursement.
The Treasurer shall perform such other duties as may from time to time be
prescribed by the Board of Directors, the Chairman of the Board, the Vice
Chairman of the Board, the President, the Chief Financial Officer, or the
Bylaws.
The Assistant Treasurers shall perform such duties as may be assigned from
time to time by the Board of Directors, the Chairman of the Board, the Vice
Chairman of the Board, the President, the Chief Financial Officer, or the
Treasurer. In the absence or disability of the Treasurer, his duties shall be
performed by an Assistant Treasurer.
11. Controller. The Controller shall be responsible for maintaining
the accounting records of the Corporation and for preparing necessary financial
reports and statements, and he shall properly account for all moneys and
obligations due the Corporation and all properties, assets, and liabilities of
the Corporation. He shall render to the officers such periodic reports covering
the result of operations of the Corporation as may be required by them or any
one of them.
The Controller shall have such other duties as may from time to time be
prescribed by the Board of Directors, the Chairman of the Board, the Vice
Chairman of the Board, the President, the Chief Financial Officer, or the
Bylaws. He shall be the principal accounting officer of the Corporation, unless
another individual shall be so designated by the Board of Directors.
Article IV.
MISCELLANEOUS.
1. Record Date. The Board of Directors may fix a time in the future
as a record date for the determination of the shareholders entitled to notice of
and to vote at any meeting of shareholders, or entitled to receive any dividend
or distribution, or allotment of rights, or to exercise rights in respect to any
change, conversion, or exchange of shares. The record date so fixed shall be
not more than sixty nor less than ten days prior to the date of such meeting nor
more than sixty days prior to any other action for the purposes for which it is
so fixed. When a record date is so fixed, only shareholders of record on that
date are entitled to notice of and to vote at the meeting, or entitled to
receive any dividend or distribution, or allotment of rights, or to exercise the
rights, as the case may be.
2. Transfers of Stock. Upon surrender to the Corporate Secretary or
Transfer Agent of the Corporation of a certificate for shares duly endorsed or
accompanied by proper evidence of succession, assignment, or authority to
transfer,
6
<PAGE>
and payment of transfer taxes, the Corporation shall issue a new certificate to
the person entitled thereto, cancel the old certificate, and record the
transaction upon its books. Subject to the foregoing, the Board of Directors
shall have power and authority to make such rules and regulations as it shall
deem necessary or appropriate concerning the issue, transfer, and registration
of certificates for shares of stock of the Corporation, and to appoint and
remove Transfer Agents and Registrars of transfers.
3. Lost Certificates. Any person claiming a certificate of stock to
be lost, stolen, mislaid, or destroyed shall make an affidavit or affirmation of
that fact and verify the same in such manner as the Board of Directors may
require, and shall, if the Board of Directors so requires, give the Corporation,
its Transfer Agents, Registrars, and/or other agents a bond of indemnity in form
approved by counsel, and in amount and with such sureties as may be satisfactory
to the Corporate Secretary of the Corporation, before a new certificate may be
issued of the same tenor and for the same number of shares as the one alleged to
have been lost, stolen, mislaid, or destroyed.
Article V.
AMENDMENTS.
1. Amendment by Shareholders. Except as otherwise provided by law,
these Bylaws, or any of them, may be amended or repealed or new Bylaws adopted
by the affirmative vote of a majority of the outstanding shares entitled to vote
at any regular or special meeting of the shareholders.
2. Amendment by Directors. To the extent provided by law, these
Bylaws, or any of them, may be amended or repealed or new Bylaws adopted by
resolution adopted by a majority of the members of the Board of Directors.
7
<PAGE>
EXHIBIT 3.4
Bylaws
of
Pacific Gas and Electric Company
amended as of January 27, 1999
-------------------------------
Article I.
SHAREHOLDERS.
1. Place of Meeting. All meetings of the shareholders shall be held at
the office of the Corporation in the City and County of San Francisco, State of
California, or at such other place within the State of California as may be
designated by the Board of Directors.
2. Annual Meetings. The annual meeting of shareholders shall be held each
year on a date and at a time designated by the Board of Directors.
Written notice of the annual meeting shall be given not less than ten (or,
if sent by third-class mail, thirty) nor more than sixty days prior to the date
of the meeting to each shareholder entitled to vote thereat. The notice shall
state the place, day, and hour of such meeting, and those matters which the
Board, at the time of mailing, intends to present for action by the
shareholders.
Notice of any meeting of the shareholders shall be given by mail or
telegraphic or other written communication, postage prepaid, to each holder of
record of the stock entitled to vote thereat, at his address, as it appears on
the books of the Corporation.
3. Special Meetings. Special meetings of the shareholders shall be called
by the Secretary or an Assistant Secretary at any time on order of the Board of
Directors, the Chairman of the Board, the Vice Chairman of the Board, the
Chairman of the Executive Committee, or the President. Special meetings of the
shareholders shall also be called by the Secretary or an Assistant Secretary
upon the written request of holders of shares entitled to cast not less than ten
percent of the votes at the meeting. Such request shall state the purposes of
the meeting, and shall be delivered to the Chairman of the Board, the Vice
Chairman of the Board, the Chairman of the Executive Committee, the President or
the Secretary.
[1]
<PAGE>
A special meeting so requested shall be held on the date requested, but not
less than thirty-five nor more than sixty days after the date of the original
request. Written notice of each special meeting of shareholders, stating the
place, day, and hour of such meeting and the business proposed to be transacted
thereat, shall be given in the manner stipulated in Article I, Section 2,
Paragraph 3 of these Bylaws within twenty days after receipt of the written
request.
4. Attendance at Meetings. At any meeting of the shareholders, each
holder of record of stock entitled to vote thereat may attend in person or may
designate an agent or a reasonable number of agents, not to exceed three to
attend the meeting and cast votes for his shares. The authority of agents must
be evidenced by a written proxy signed by the shareholder designating the agents
authorized to attend the meeting and be delivered to the Secretary of the
Corporation prior to the commencement of the meeting.
5. No Cumulative Voting. No shareholder of the Corporation shall be
entitled to cumulate his or her voting power.
Article II.
DIRECTORS.
1. Number. The Board of Directors of this corporation shall consist of
such number of directors, not less than nine (9) nor more than seventeen (17),
and the exact number of directors shall be fourteen (14) until changed, within
the limits specified above, by an amendment to this Bylaw duly adopted by the
Board of Directors or the shareholders.
2. Powers. The Board of Directors shall exercise all the powers of the
Corporation except those which are by law, or by the Articles of Incorporation
of this Corporation, or by the Bylaws conferred upon or reserved to the
shareholders.
3. Executive Committee. There shall be an Executive Committee of the
Board of Directors consisting of the Chairman of the Committee, the Chairman of
the Board, if these offices be filled, the President, and four Directors who are
not officers of the Corporation. The members of the Committee shall be elected,
and may at any time be removed, by a two-thirds vote of the whole Board.
The Executive Committee, subject to the provisions of law, may exercise any
of the powers and perform any of the duties of the Board of Directors; but the
Board may by an affirmative vote of a majority of its members withdraw or limit
any of the powers of the Executive Committee.
The Executive Committee, by a vote of a majority of its members, shall fix
its own time and place of meeting, and shall prescribe its own rules of
procedure. A quorum of the Committee for the transaction of business shall
consist of three members.
4. Time and Place of Directors' Meetings. Regular meetings of the Board
of Directors shall be held on such days and at such times and at such locations
as shall be fixed by resolution of the Board, or designated by the Chairman of
the Board or, in his absence, the
<PAGE>
Vice Chairman of the Board, or the President of the Corporation and contained
in the notice of any such meeting. Notice of meetings shall be delivered
personally or sent by mail or telegram at least seven days in advance.
5. Special Meetings. The Chairman of the Board, the Vice Chairman of the
Board, the Chairman of the Executive Committee, the President, or any five
directors may call a special meeting of the Board of Directors at any time.
Notice of the time and place of special meetings shall be given to each Director
by the Secretary. Such notice shall be delivered personally or by telephone to
each Director at least four hours in advance of such meeting, or sent by first-
class mail or telegram, postage prepaid, at least two days in advance of such
meeting.
6. Quorum. A quorum for the transaction of business at any meeting of the
Board of Directors shall consist of six members.
7. Action by Consent. Any action required or permitted to be taken by the
Board of Directors may be taken without a meeting if all Directors individually
or collectively consent in writing to such action. Such written consent or
consents shall be filed with the minutes of the proceedings of the Board of
Directors.
8. Meetings by Conference Telephone. Any meeting, regular or special, of
the Board of Directors or of any committee of the Board of Directors, may be
held by conference telephone or similar communication equipment, provided that
all Directors participating in the meeting can hear one another.
Article III.
OFFICERS.
1. Officers. The officers of the Corporation shall be a Chairman of the
Board, a Vice Chairman of the Board, a Chairman of the Executive Committee
(whenever the Board of Directors in its discretion fills these offices), a
President, one or more Vice Presidents, a Secretary and one or more Assistant
Secretaries, a Treasurer and one or more Assistant Treasurers, a General
Counsel, a General Attorney (whenever the Board of Directors in its discretion
fills this office), and a Controller, all of whom shall be elected by the Board
of Directors. The Chairman of the Board, the Vice Chairman of the Board, the
Chairman of the Executive Committee, and the President shall be members of the
Board of Directors.
2. Chairman of the Board. The Chairman of the Board, if that office be
filled, shall preside at all meetings of the shareholders, of the Directors, and
of the Executive Committee in the absence of the Chairman of that Committee. He
shall be the chief executive officer of the Corporation if so designated by the
Board of Directors. He shall have such duties and responsibilities as may be
prescribed by the Board of Directors or the Bylaws. The Chairman of the Board
shall have authority to sign on behalf of the Corporation agreements and
instruments of every character, and in the absence or disability of the
President, shall exercise his duties and responsibilities.
<PAGE>
3. Vice Chairman of the Board. The Vice Chairman of the Board, if that
office be filled, shall have such duties and responsibilities as may be
prescribed by the Board of Directors, the Chairman of the Board, or the Bylaws.
He shall be the chief executive officer of the Corporation if so designated by
the Board of Directors. In the absence of the Chairman of the Board, he shall
preside at all meetings of the Board of Directors and of the shareholders; and,
in the absence of the Chairman of the Executive Committee and the Chairman of
the Board, he shall preside at all meetings of the Executive Committee. The
Vice Chairman of the Board shall have authority to sign on behalf of the
Corporation agreements and instruments of every character.
4. Chairman of the Executive Committee. The Chairman of the Executive
Committee, if that office be filled, shall preside at all meetings of the
Executive Committee. He shall aid and assist the other officers in the
performance of their duties and shall have such other duties as may be
prescribed by the Board of Directors or the Bylaws.
5. President. The President shall have such duties and responsibilities as
may be prescribed by the Board of Directors, the Chairman of the Board, or the
Bylaws. He shall be the chief executive officer of the Corporation if so
designated by the Board of Directors. If there be no Chairman of the Board, the
President shall also exercise the duties and responsibilities of that office.
The President shall have authority to sign on behalf of the Corporation
agreements and instruments of every character.
6. Vice Presidents. Each Vice President shall have such duties and
responsibilities as may be prescribed by the Board of Directors, the Chairman of
the Board, the Vice Chairman of the Board, the President, or the Bylaws. Each
Vice President's authority to sign agreements and instruments on behalf of the
Corporation shall be as prescribed by the Board of Directors. The Board of
Directors, the Chairman of the Board, the Vice Chairman of the Board, or the
President may confer a special title upon any Vice President.
7. Secretary. The Secretary shall attend all meetings of the Board of
Directors and the Executive Committee, and all meetings of the shareholders, and
he shall record the minutes of all proceedings in books to be kept for that
purpose. He shall be responsible for maintaining a proper share register and
stock transfer books for all classes of shares issued by the Corporation. He
shall give, or cause to be given, all notices required either by law or the
Bylaws. He shall keep the seal of the Corporation in safe custody, and shall
affix the seal of the Corporation to any instrument requiring it and shall
attest the same by his signature.
The Secretary shall have such other duties as may be prescribed by the Board
of Directors, the Chairman of the Board, the Vice Chairman of the Board, the
President, or the Bylaws.
The Assistant Secretaries shall perform such duties as may be assigned from
time to time by the Board of Directors, the Chairman of the Board, the Vice
Chairman of the Board, the President, or the Secretary. In the absence or
disability of the Secretary, his duties shall be performed by an Assistant
Secretary.
8. Treasurer. The Treasurer shall have custody of all moneys and funds of
the Corporation, and shall cause to be kept full and accurate records of
receipts and disbursements of the Corporation. He shall deposit all moneys and
other valuables of the Corporation in the
<PAGE>
name and to the credit of the Corporation in such depositaries as may be
designated by the Board of Directors or any employee of the Corporation
designated by the Board of Directors. He shall disburse such funds of the
Corporation as have been duly approved for disbursement.
The Treasurer shall perform such other duties as may from time to time be
prescribed by the Board of Directors, the Chairman of the Board, the Vice
Chairman of the Board, the President, or the Bylaws.
The Assistant Treasurer shall perform such duties as may be assigned from
time to time by the Board of Directors, the Chairman of the Board, the Vice
Chairman of the Board, the President, or the Treasurer. In the absence or
disability of the Treasurer, his duties shall be performed by an Assistant
Treasurer.
9. General Counsel. The General Counsel shall be responsible for handling
on behalf of the Corporation all proceedings and matters of a legal nature. He
shall render advice and legal counsel to the Board of Directors, officers, and
employees of the Corporation, as necessary to the proper conduct of the
business. He shall keep the management of the Corporation informed of all
significant developments of a legal nature affecting the interests of the
Corporation.
The General Counsel shall have such other duties as may from time to time be
prescribed by the Board of Directors, the Chairman of the Board, the Vice
Chairman of the Board, the President, or the Bylaws.
10. Controller. The Controller shall be responsible for maintaining the
accounting records of the Corporation and for preparing necessary financial
reports and statements, and he shall properly account for all moneys and
obligations due the Corporation and all properties, assets, and liabilities of
the Corporation. He shall render to the officers such periodic reports covering
the result of operations of the Corporation as may be required by them or any
one of them.
The Controller shall have such other duties as may from time to time be
prescribed by the Board of Directors, the Chairman of the Board, the Vice
Chairman of the Board, the President, or the Bylaws. He shall be the principal
accounting officer of the Corporation, unless another individual shall be so
designated by the Board of Directors.
Article IV.
MISCELLANEOUS.
1. Record Date. The Board of Directors may fix a time in the future as a
record date for the determination of the shareholders entitled to notice of and
to vote at any meeting of shareholders, or entitled to receive any dividend or
distribution, or allotment of rights, or to exercise rights in respect to any
change, conversion, or exchange of shares. The record date so fixed shall be
not more than sixty nor less than ten days prior to the date of such meeting nor
more than sixty days prior to any other action for the purposes for which it is
so fixed. When a record date is so fixed, only shareholders of record on that
date are entitled to notice of and to
<PAGE>
vote at the meeting, or entitled to receive any dividend or distribution, or
allotment of rights, or to exercise the rights, as the case may be.
2. Transfers of Stock. Upon surrender to the Secretary or Transfer Agent
of the Corporation of a certificate for shares duly endorsed or accompanied by
proper evidence of succession, assignment, or authority to transfer, and payment
of transfer taxes, the Corporation shall issue a new certificate to the person
entitled thereto, cancel the old certificate, and record the transaction upon
its books. Subject to the foregoing, the Board of Directors shall have power
and authority to make such rules and regulations as it shall deem necessary or
appropriate concerning the issue, transfer, and registration of certificates for
shares of stock of the Corporation, and to appoint and remove Transfer Agents
and Registrars of transfers.
3. Lost Certificates. Any person claiming a certificate of stock to be
lost, stolen, mislaid, or destroyed shall make an affidavit or affirmation of
that fact and verify the same in such manner as the Board of Directors may
require, and shall, if the Board of Directors so requires, give the Corporation,
its Transfer Agents, Registrars, and/or other agents a bond of indemnity in form
approved by counsel, and in amount and with such sureties as may be satisfactory
to the Secretary of the Corporation, before a new certificate may be issued of
the same tenor and for the same number of shares as the one alleged to have been
lost, stolen, mislaid, or destroyed.
Article V.
AMENDMENTS.
1. Amendment by Shareholders. Except as otherwise provided by law, these
Bylaws, or any of them, may be amended or repealed or new Bylaws adopted by the
affirmative vote of a majority of the outstanding shares entitled to vote at any
regular or special meeting of the shareholders.
2. Amendment by Directors. To the extent provided by law, these Bylaws,
or any of them, may be amended or repealed or new Bylaws adopted by resolution
adopted by a majority of the members of the Board of Directors.
<PAGE>
EXHIBIT 10.4
PG&E CORPORATION
DEFERRED COMPENSATION PLAN
FOR OFFICERS
(As amended and restated effective as of October 21, 1998)
1. Purpose
-------
This is the controlling and definitive statement of the PG&E Corporation
Deferred Compensation Plan for Officers ("PLAN")./1/ The PLAN which became
effective on November 5, 1997, takes the place of and assumes the existing
benefits accrued under the Deferred Compensation Plan of the Pacific Gas
and Electric Company. The PLAN provides an opportunity for OFFICERS and
other designated key employees of the CORPORATION and its subsidiaries and
affiliates to defer payment of (1) part of their salaries, (2) all or part
of their INCENTIVE PLAN AWARDS, (3) all of their SAVINGS FUND PLAN EXCESS
BENEFITS, (4) PERQUISITE ALLOWANCES under the Executive Flexible
Perquisites Program, (5) all or a portion of their PERFORMANCE UNITS under
the Performance Unit Plan, and (6) such other payments, awards, allowances,
or benefits as the COMMITTEE may in the future determine appropriate.
SPECIAL INCENTIVE STOCK OWNERSHIP PREMIUMS are automatically credited to
participant accounts maintained by the PLAN.
2. Definitions
-----------
(a) "BENEFICIARY" means the person, persons, or entity designated by the
PLAN participant on the DEFERRAL ELECTION FORM to receive payment of
the participant's DEFERRED COMPENSATION ACCOUNT in the event of the
death of the participant.
(b) "BOARD" and "BOARD OF DIRECTORS" means the BOARD OF DIRECTORS of the
CORPORATION or, when appropriate, any committee of the BOARD which
has been delegated authority to take action with respect to the PLAN.
(c) "COMMITTEE" means the Nominating and Compensation Committee of the
BOARD.
(d) "CORPORATION" means PG&E Corporation, a California corporation.
(e) "DEFERRAL ELECTION FORM" means a participation form to be supplied by
the Human Resources Department of the CORPORATION.
(f) "DEFERRED COMPENSATION ACCOUNT" means the bookkeeping account
established pursuant to Section 6 on behalf of each ELIGIBLE EMPLOYEE
who elects to participate in the PLAN.
- ------------------------
/1/ Words in all capitals are defined in Section 2.
<PAGE>
(g) "ELIGIBLE EMPLOYEE" means an OFFICER and such other key employees as
may be designated by the PLAN ADMINISTRATOR as eligible to participate
in the PLAN.
(h) "INCENTIVE PLAN AWARD" means a monetary award payable under the annual
short-term performance incentive plan maintained by the CORPORATION,
or any of its subsidiaries or affiliates.
(i) "OFFICER" means all OFFICERS of the CORPORATION and its subsidiaries
and affiliates in Officer Band 6 and above.
(j) "PERFORMANCE UNITS" means the amounts which are payable as a result
of units earned under the CORPORATION'S Performance Unit Plan, as may
be revised thereafter from time to time.
(k) "PERQUISITE ALLOWANCE" means the amounts which an OFFICER can use for
the reimbursement of certain designated expenses under the
CORPORATION'S Executive Flexible Perquisites Program.
(l) "PLAN" means the PG&E Corporation Deferred Compensation Plan for
Officers.
(m) "PLAN ADMINISTRATOR" shall mean the senior Human Resources officer of
the CORPORATION.
(n) "SALARY" means the amount of compensation payable by the CORPORATION
or by any of its subsidiaries or affiliates to an ELIGIBLE EMPLOYEE
for his or her duties. It does not include any amount payable with
respect to services rendered prior to an ELIGIBLE EMPLOYEE'S election
to defer according to Section 5 of this PLAN.
(o) "SAVINGS FUND PLAN EXCESS BENEFITS" means amounts payable to OFFICERS
under the SAVINGS FUND PLAN EXCESS BENEFITS arrangement as originally
adopted on December 20, 1989, and as may be revised thereafter from
time to time.
(p) "SPECIAL INCENTIVE STOCK OWNERSHIP PREMIUMS" means the special
premiums awarded to eligible OFFICERS under the Executive Stock
Ownership Guidelines approved by the COMMITTEE on October 15, 1997,
as amended on July 22, 1998, and as may hereafter be amended from
time to time.
(q) "TERMINATION DATE" means the last day on which the PLAN participant
is an employee of the CORPORATION, one of its subsidiaries, or of an
association affiliated with the CORPORATION.
(r) "YEAR" means the calendar YEAR.
3. Eligibility
-----------
Each OFFICER who receives a SALARY for service as an OFFICER of the
CORPORATION shall be eligible to participate in the PLAN. Any other
-2-
<PAGE>
ELIGIBLE EMPLOYEE shall be eligible to participate in the PLAN consistent
with the terms set by the PLAN ADMINISTRATOR in its designation of such key
employee as an ELIGIBLE EMPLOYEE.
4. Participation
-------------
In order to commence participation in the PLAN, a participant must file a
DEFERRAL ELECTION FORM with the PLAN ADMINISTRATOR. An election to defer
(i) an INCENTIVE PLAN AWARD, (ii) PERFORMANCE UNITS or (iii) SALARY must be
filed prior to the beginning of the YEAR in which said amounts are paid. An
election to defer SAVINGS FUND PLAN EXCESS BENEFITS must be filed prior to
the beginning of the Savings Fund Plan YEAR to which the Excess Benefits
are attributable. An election to defer PERQUISITE ALLOWANCES must be filed
prior to the beginning of the YEAR in which said amounts are granted.
SPECIAL INCENTIVE STOCK OWNERSHIP PREMIUMS are automatically deferred into
the PLAN immediately upon grant. Notwithstanding the foregoing, upon first
becoming an ELIGIBLE EMPLOYEE, an election to participate shall be
effective for the month following the filing of a DEFERRAL ELECTION FORM,
provided said Form is filed within 60 days following the date when the
employee first becomes an ELIGIBLE EMPLOYEE.
(a) Deferral of SALARY
------------------
A participant may defer from 5 percent to 30 percent of his or her
monthly SALARY.
(b) Deferral of INCENTIVE PLAN AWARDS
---------------------------------
A participant may defer all or part of his or her INCENTIVE PLAN
AWARDS.
(c) Deferral of SAVINGS FUND PLAN EXCESS BENEFITS
---------------------------------------------
A participant may defer all amounts which would otherwise be paid in
cash under the SAVINGS FUND PLAN EXCESS BENEFITS arrangement. Partial
deferrals of SAVINGS FUND PLAN EXCESS BENEFITS are not permitted.
(d) Deferral of PERQUISITE ALLOWANCES
---------------------------------
A participant may elect to defer any portion of his or her flexible
PERQUISITE ALLOWANCE.
(e) Deferral of PERFORMANCE UNITS
-----------------------------
A participant may elect to defer all or part of his or her PERFORMANCE
UNITS.
(f) Deferral of SPECIAL INCENTIVE STOCK OWNERSHIP PREMIUMS.
------------------------------------------------------
All of an OFFICER'S SPECIAL INCENTIVE STOCK OWNERSHIP PREMIUMS are
automatically deferred to the PLAN immediately upon
-3-
<PAGE>
grant and converted into units representing shares of PG&E Corporation
common stock. The units attributable to SPECIAL INCENTIVE STOCK
OWNERSHIP PREMIUMS and any additional units resulting from the
conversion of dividend equivalents thereon remain unvested until the
earlier of the third anniversary of the date on which the SPECIAL
INCENTIVE STOCK OWNERSHIP PREMIUMS are credited to an OFFICER'S
DEFERRED COMPENSATION ACCOUNT (provided the OFFICER continues to be
employed on such date), death, disability, or retirement of the
participant, or upon a Change in Control as defined in the PG&E
Corporation Long-Term Incentive Program (LTIP). (The term "disability"
shall, for purposes of the PLAN, have the same meaning as in Section
22(e)(3) of the Internal Revenue Code.) Unvested units attributable to
SPECIAL INCENTIVE STOCK OWNERSHIP PREMIUMS and any additional units
resulting from the conversion of dividend equivalents thereon shall be
forfeited upon termination of the OFFICER'S employment unless
otherwise provided in the PG&E Corporation Officer Severance Policy,
or if an OFFICER'S stock ownership falls below the levels set forth in
the Executive Stock Ownership Program.
The phantom stock units attributable to the award of SPECIAL INCENTIVE
STOCK OWNERSHIP PREMIUMS under the Executive Stock Ownership
Guidelines, and additional units acquired upon the conversion of
dividend equivalents thereon, constitute Incentive Awards under the
LTIP. An such units are credited to a participant's account, an equal
number of shares of PG&E Corporation common stock shall be reserved
from the pool of shares authorized for issuance under the LTIP. Upon
forfeiture of such units, a number of shares equal to the number of
forfeited units shall again become available for issuance under the
LTIP.
5. Deferral Election
-----------------
An ELIGIBLE EMPLOYEE who elects to participate in the PLAN shall file an
executed DEFERRAL ELECTION FORM with the PLAN ADMINISTRATOR which (i)
indicates the percentage of SALARY and applicable pay periods, and the
amount of any INCENTIVE PLAN AWARD, PERFORMANCE UNITS, SAVINGS FUND PLAN
EXCESS BENEFITS, PERQUISITE ALLOWANCES, and such other eligible payments,
awards, allowances, or benefits to be deferred under the PLAN; and (ii)
specifies the time and form of distribution and designates a BENEFICIARY. A
participant may not elect to defer the receipt of SALARY, any INCENTIVE
PLAN AWARD, PERFORMANCE UNITS, or SAVINGS FUND PLAN EXCESS BENEFITS, for
less than three years, subject to earlier distribution following
termination of employment in accordance with Section 9.
The participant's deferral election of SALARY shall continue from YEAR to
YEAR until terminated or modified by written notice to the PLAN
ADMINISTRATOR. Notice of termination of SALARY deferrals shall not become
effective until the first day of the month following the month in which
such written notice is received by the PLAN ADMINISTRATOR. A participant
who terminates SALARY deferrals shall not be permitted to elect future
SALARY deferrals earlier than the first day of the following YEAR. A
participant may modify a prior deferral election of SALARY only by
delivering a
-4-
<PAGE>
new DEFERRAL ELECTION FORM to the PLAN ADMINISTRATOR to be effective as of
the first day of the following YEAR. In no event shall any termination or
modification of deferrals affect amounts deferred prior to the effective
date of such termination or modification.
Deferral elections of INCENTIVE PLAN AWARDS, PERFORMANCE UNITS, SAVINGS
FUND PLAN EXCESS BENEFITS, and PERQUISITE ALLOWANCES, only are effective
for the YEAR following the YEAR in which the executed DEFERRAL ELECTION
FORM is filed with the PLAN ADMINISTRATOR. Thereafter, a new DEFERRAL
ELECTION FORM must be filed with the PLAN ADMINISTRATOR in order to
maintain deferrals in subsequent years. All deferral elections of
INCENTIVE PLAN AWARDS, PERFORMANCE UNITS, SAVINGS FUND PLAN EXCESS
BENEFITS, and PERQUISITE ALLOWANCES may be revoked prior to the beginning
of the YEAR in which INCENTIVE PLAN AWARDS, PERFORMANCE UNITS, and
PERQUISITE ALLOWANCES would otherwise be paid, and thereafter shall be
irrevocable. All deferral elections of SAVINGS FUND PLAN EXCESS BENEFITS
may be revoked prior to the beginning of the Savings Fund Plan YEAR to
which the Excess Benefits are attributable.
Notwithstanding the foregoing, the participant's designation as to time and
form of distribution to the participant may not be revoked or modified by
the participant as to amounts already deferred, except as permitted by the
PLAN ADMINISTRATOR pursuant to Section 10 in the case of hardship
withdrawals.
6. Credits to DEFERRED COMPENSATION ACCOUNT
----------------------------------------
Upon receipt of a completed DEFERRAL ELECTION FORM, the CORPORATION shall
establish a DEFERRED COMPENSATION ACCOUNT to which shall be credited such
amounts as the participant has elected to defer under the terms of the
PLAN.
SALARY which is deferred shall be credited to the participant's DEFERRED
COMPENSATION ACCOUNT as of each payroll period. SAVINGS FUND PLAN EXCESS
BENEFITS which are deferred shall be credited to the participant's DEFERRED
COMPENSATION ACCOUNT as of the first business day following the end of the
YEAR to which such Excess Benefits are attributable. PERQUISITE ALLOWANCES
which are deferred shall be credited to the participant's DEFERRED
COMPENSATION ACCOUNT on the date of grant. PERFORMANCE UNITS and INCENTIVE
PLAN AWARDS which are deferred shall be credited to the participant's
DEFERRED COMPENSATION ACCOUNT as of the date such amounts would otherwise
have been paid.
SPECIAL INCENTIVE STOCK OWNERSHIP PREMIUMS shall be credited to the
participant's DEFERRED COMPENSATION ACCOUNT immediately upon the date of
grant and converted into units (including fractions computed to three
decimal places) representing shares of PG&E Corporation common stock. The
initial value of a SPECIAL INCENTIVE STOCK OWNERSHIP PREMIUM unit shall be
the average of the daily high and low price of a share of PG&E Corporation
common stock as traded on the New York Stock Exchange for the 30 trading
days preceding the date that the SPECIAL INCENTIVE STOCK OWNERSHIP PREMIUM
is credited to a participant's DEFERRED COMPENSATION ACCOUNT. Thereafter,
the value of a SPECIAL
-5-
<PAGE>
INCENTIVE STOCK OWNERSHIP PREMIUM unit shall fluctuate with the closing
price of a share of PG&E Corporation common stock. Whenever dividends are
declared with respect to the Corporation's common stock, additional
SPECIAL INCENTIVE STOCK OWNERSHIP PREMIUM units (including fractions
computed to three decimal places) shall be credited to a participant's
account on the dividend payment date in an amount determined by dividing
(i) the aggregate amount of dividends, i.e., the dividend multiplied by
the number of SPECIAL INCENTIVE STOCK OWNERSHIP PREMIUM units credited to
the participant's account as of the dividend record date, by (ii) the
closing price of PG&E Corporation common stock on the New York Stock
Exchange on the dividend payment date.
7. Earnings During Deferral Period
-------------------------------
At such time as participant elects to participate in the PLAN, he shall
also elect to have his account balances allocated to the Utility Bond Fund
or to the PG&E Corporation Phantom Stock Fund. Participant shall make such
elections and in such percentages as the PLAN ADMINISTRATOR shall
prescribe. Participant shall be able to reallocate account balances
between the funds and reallocate new deferrals at such time and in such
manner as the PLAN ADMINISTRATOR shall prescribe; provided, however, that
units attributable to SPECIAL INCENTIVE STOCK OWNERSHIP PREMIUMS and
additional units resulting from the conversion of dividend equivalents
thereon may not be reallocated. Anything to the contrary herein
notwithstanding, a participant may not reallocate account balances between
funds if such reallocation would result in a non-exempt Discretionary
Transaction as defined in Rule 16b-3 of the Securities Exchange Act of
1934, as amended, or any successor to Rule 16b-3, as in effect when the
reallocation is requested.
(a) Utility Bond Fund
-----------------
On the first business day of each calendar quarter, interest shall be
credited on the balance in each participant's DEFERRED COMPENSATION
ACCOUNT as of the last day of the immediately preceding calendar quarter
and prorated based on the number of days in the quarter that the balance
was allocated to the Utility Bond Fund. Such interest shall be at a rate
equal to the AA Utility Bond Yield reported in Moody's Public Utility,
----------------------
published in the issue of Moody's Investors Service immediately preceding
-------------------------
the first day of the calendar quarter in which the interest is to be
credited. Such interest shall become a part of the DEFERRED COMPENSATION
ACCOUNT and shall be paid at the same time or times as the balance of the
DEFERRED COMPENSATION ACCOUNT. Notwithstanding the above, if a participant
has requested that his account balance be reallocated to the PG&E
Corporation Phantom Stock Fund before the end of the quarter, prorated
interest on the participant's account balance shall be calculated at a rate
equal to the AA Utility Bond Yield reported in Moody's Public Utility,
----------------------
published in the issue of Moody's Investors Service immediately preceding
-------------------------
the date of reallocation, shall be credited to the participant's account on
the date of reallocation, and shall be subject to the reallocation request.
(b) PG&E Corporation Phantom Stock Fund
-----------------------------------
Deferrals credited to the PG&E Corporation Phantom Stock Fund shall be
converted into units (including fractions computed to three decimal places)
each
-6-
<PAGE>
representing share of PG&E Corporation common stock. The value of a unit
for purposes of determining the number of units to credit upon initial
deferral or reallocation from the Utility Bond Fund, and for determining
the dollar value of the aggregate number of units to be reallocated from
the PG&E Corporation Phantom Stock Fund to the Utility Bond Fund, shall
be the average of the daily high and low price of a share of PG&E
Corporation common stock as traded on the New York Stock Exchange for the
30 trading days preceding (i) the date that deferrals and reallocations
are credited to a participant's account in the PG&E Corporation Phantom
Stock Fund in the case of new deferrals and reallocations from the
Utility Bond Fund, and (ii) the date the PLAN ADMINISTRATOR receives a
reallocation request, in the case of reallocations. Thereafter, the value
of a unit shall fluctuate in accordance with the closing price of PG&E
Corporation common stock on the New York Stock Exchange.
Whenever dividends are paid with respect to the Corporation's common stock,
additional units (including fractions computed to three decimal places)
shall be credited to a participant's account on the dividend payment date
in an amount determined by dividing (i) the aggregate amount of dividends,
i.e,. the dividend multiplied by the number of units credited to the
participant's account as of the dividend record date, by (ii) the closing
price of PG&E Corporation common stock on the New York Stock Exchange on
the dividend payment date. If, after the record date but before the
dividend payment date, a participant's balance in the PG&E Corporation
Phantom Stock Fund has been reallocated to the Utility Bond Fund, or has
been paid to the participant or the participant's beneficiary, then an
amount equal to the aggregate dividend shall be credited to the
participant's account in the Utility Bond Fund, or paid directly to the
participant or the participant's beneficiary, whichever is applicable.
8. Effect of Deferral on Qualified Benefit PLANS
---------------------------------------------
A participant who participates in this PLAN shall continue to be eligible
to participate in all CORPORATION benefit PLANS. However, no amount
deferred under this PLAN shall be deemed to be covered compensation or
SALARY for the purposes of computing percentage of participation and
benefits to which the OFFICER may be entitled under the CORPORATION
Retirement and Savings Fund Plans and any other CORPORATION benefit plans
which are qualified under Section 401(a) of the Internal Revenue Code of
1986, as amended.
9. Form and Time of Payment to a Participant of DEFERRED COMPENSATION ACCOUNT
--------------------------------------------------------------------------
Payment to the participant of deferred compensation allocated to the
Utility Bond Fund or the PG&E Corporation Phantom Stock Fund shall be made
in the form of cash. At the election of the participant, the cash may be
paid in a lump sum or in a series of ten or less approximately equal annual
installments. Payment to the participant shall be made at such time and in
such form as the participant has specified on the DEFERRAL ELECTION FORM(s)
previously filed with the PLAN ADMINISTRATOR; provided however, that
payments shall commence (either as a lump sum or as the first of a series
of ten or less approximately equal annual installments) no later than
January of the YEAR following the YEAR in which the participant's
employment terminated. Payment to a participant of his or her DEFERRED
COMPENSATION ACCOUNT shall be made in January of
-7-
<PAGE>
each YEAR in which payment is to be made in accordance with the
participant's DEFERAL ELECTION FORM. All payments from the DEFERRED
COMPENSATION ACCOUNT shall be subject to all tax withholdings or other
reductions which may be required by law. In accordance with Section 11 of
the LTIP with respect to Incentive Awards, a participant may elect
(unless the Committee determines otherwise) to have PG&E Corporation
withhold a sufficient number of shares of PG&E Corporation common stock
from the shares otherwise due upon settlement of the phantom stock units
attributable to SPECIAL INCENTIVE STOCK OWNERSHIP PREMIUMS (and dividend
equivalents with respect thereto), to satisfy applicable withholding
taxes. The value of the shares withheld shall be calculated in the same
manner as the value of the shares distributed to the participant for tax
reporting purposes.
For purposes of this Section 9 and Sections 10 and 11 below, the amount of
cash to be distributed upon settlement of units credited to a participant's
account in the PG&E Corporation Phantom Stock Fund shall be equal to the
number of credited units, or fraction thereof, multiplied by the average of
the high and low price of a share of PG&E Corporation common stock as
traded on the New York Stock Exchange for the 30 trading days preceding the
date of distribution.
Notwithstanding the foregoing, following a participant's termination of
employment, deferrals attributable to SPECIAL INCENTIVE STOCK OWNERSHIP
PREMIUMS shall only be distributed in January of the YEAR following
termination in the form of one or more certificates for a number of shares
of PG&E Corporation common stock equal to the number of vested SPECIAL
INCENTIVE STOCK OWNERSHIP PREMIUM units, rounded down to the nearest whole
share.
10. Distribution Due to Unforeseeable Emergency
-------------------------------------------
A participant may request a distribution due to an Unforeseeable Emergency
by submitting a written request to the Plan Administrator accompanied by
evidence to demonstrate that the circumstances being experienced qualify as
an Unforeseeable Emergency. The Plan Administrator shall have the
authority to require such evidence as it deems necessary to determine if a
distribution is warranted. If an application for a hardship distribution
due to an Unforeseeable Emergency is approved, the distribution is limited
to the amount sufficient to meet the emergency. The allowed distribution
shall be payable in a method determined by the Plan Administrator as soon
as possible after approval of such distribution. A participant who has
commenced receiving installment payments under the Plan may request
acceleration of such payments in the event of an Unforeseeable Emergency.
The Administrator may permit accelerated payments to the extent such
accelerated payment does not exceed the amount necessary to meet the
emergency.
For purposes of this Section 10, an "Unforeseeable Emergency " means a
severe financial hardship to the participant resulting from a sudden and
unexpected illness or accident of the participant or of a dependent of the
participant, loss of the participant's property due to casualty, or other
similar extraordinary and unforeseeable circumstances arising as a result
of events beyond the control of the participant. The circumstances that
will constitute an "Unforeseeable Emergency" would depend upon the facts in
each case, but, in any case, payment may not be made in the event that such
hardship is or may be relieved (i) through prompt
-8-
<PAGE>
reimbursement or compensation by insurance or otherwise, (ii) by
liquidation of the participant's assets, to the extent that liquidation
of such assets would not itself cause severe financial hardship, or (iii)
by cessation of deferrals under the Plan. The need to send a
participant's child to college or the desire to purchase a home shall not
be an Unforeseeable Emergency.
11. Effect of Death of Participant
------------------------------
Upon the death of a participant who participated in the PLAN, all amounts,
if any, remaining in his or her DEFERRED COMPENSATION ACCOUNT shall be
distributed to the BENEFICIARY designated by the participant. Payment to
the beneficiary shall be made at such time and in such form as the
participant has previously specified in a form previously filed with the
PLAN ADMINISTRATOR; provided however, that payments shall commence (either
as a lump sum or as the first of a series of ten or less approximately
equal annual installments) no later than January of the YEAR following the
YEAR in which the participant's death occurred.
Earnings, as determined under Section 7 of the PLAN, shall be credited to
the date of distribution. Any shares of PG&E Corporation common stock to
be issued in settlement of the deceased participant's SPECIAL INCENTIVE
STOCK OWNERSHIP PREMIUM units shall be issued in the name of the
participant's designated beneficiary. If the designated BENEFICIARY does
not survive the participant or dies before receiving payment in full of the
participant's DEFERRED COMPENSATION ACCOUNT, a lump sum payment of the
remaining balance (and a distribution of the shares of PG&E Corporation
common stock issuable in settlement of the deceased participant's SPECIAL
INCENTIVE STOCK OWNERSHIP PREMIUM units) shall be made as soon as
practicable to the estate of whoever dies last, the participant or the
designated BENEFICIARY. All BENEFICIARY designations may be changed by the
participant at any time without the consent of a BENEFICIARY. The
participant shall notify the PLAN ADMINISTRATOR in writing of any such
change of BENEFICIARY.
12. Participant's Rights Unsecured
------------------------------
The interest under the PLAN of any participant and such participant's right
to receive a distribution of his or her DEFERRED COMPENSATION ACCOUNT shall
be an unsecured claim against the general assets of the CORPORATION. The
DEFERRED COMPENSATION ACCOUNT shall consist of bookkeeping entries only,
and this PLAN does not create an interest in, nor permit a claim against,
any specific asset of the CORPORATION pursuant to the PLAN.
13. Annual Statement of DEFERRED COMPENSATION ACCOUNT
-------------------------------------------------
As soon as practicable after the close of each YEAR, each participant shall
be provided with a statement describing the status of his or her DEFERRED
COMPENSATION ACCOUNT as of the end of the preceding YEAR. The statement
shall reflect the totals of amounts deferred during the YEAR, the amount of
interest credited, the amount of PG&E Corporation Phantom Stock Fund
units, the amount of SPECIAL INCENTIVE STOCK OWNERSHIP
-9-
<PAGE>
PREMIUMS (if any), the amount of payments made during the YEAR, if any,
and the net balance remaining in the account at the end of the YEAR.
14. Nonassignability of Interests
-----------------------------
The interest and property rights of any participant under the PLAN shall
not be assignable either by voluntary or involuntary assignment or by
operation of law, including (without limitation) bankruptcy, garnishment,
attachment or other creditor's process, and any act in violation of this
Section 14 shall be void.
15. Administration of the PLAN
--------------------------
The PLAN shall be administered by the PLAN ADMINISTRATOR. The PLAN
ADMINISTRATOR shall have full power and authority to administer and
interpret the PLAN, to establish procedures for administering the PLAN, and
to take any and all necessary action in connection therewith. The PLAN
ADMINISTRATOR's interpretation and construction of the PLAN shall be
conclusive and binding on all persons.
16. Amendment or Termination of the PLAN
------------------------------------
The CORPORATION may amend, suspend, or terminate the PLAN at any time. In
the event of such termination, the DEFERRED COMPENSATION ACCOUNTS of
participants shall be paid in accordance with the participant's deferral
election.
-10-
<PAGE>
Exhibit 10.5
Description of Short-Term Incentive Plan for Officers of PG&E Corporation and
its subsidiaries, effective January 1, 1998.
Executive Summary
-----------------
Background
- ----------
In October of this year, the Nominating and Compensation Committee reviewed and
approved a general short-term incentive plan (STIP) structure for officers of
the Corporation and each subsidiary.
Recommendation
- --------------
It is recommended that the Nominating and Compensation Committee approve a STIP
structure for officers which ties a significant portion (a minimum of 75%) of
all officers'(1) short-term incentives to earnings per share (EPS) objective as
measured by earnings from operations. The remainder of each officers' STIP will
be linked to either additional financial measures or operational measures as
defined by the respective head of each subsidiary.
The EPS performance scale will be constructed and presented to the Committee for
its approval in January 1998, based on actual 1997 earnings from operations.
(1) Excludes PG&E Energy Services officers (see page 3).
1
<PAGE>
Background
----------
Short-Term Incentive Plan Structure
- -----------------------------------
In October of this year, the Nominating and Compensation Committee reviewed and
approved the following general STIP structure for officers of the Corporation
and each subsidiary:
<TABLE>
<CAPTION>
Officer Group Award Components Weight
- ------------- ---------------- -------
<S> <C> <C>
PG&E Corporation Corporate Financial Performance 75%
Subsidiary Performance (1) 25%
Subsidiary CEO's Corporate Financial Performance 25%
Subsidiary Performance (2) 75%
PG&E Company Subsidiary Financial Performance 25-100%
Subsidiary Operational Performance Remainder of
weighting
PG&E Energy Services Subsidiary Financial Performance 25-100%
Subsidiary Operational Performance Remainder of
weighting
PG&E US Generating Subsidiary Financial Performance 25-100%
Subsidiary Operational Performance Remainder of
weighting
PG&E Energy Trading Subsidiary Financial Performance 25-100%
Subsidiary Operational Performance Remainder of
weighting
PG&E Gas Transmissions Subsidiary Financial Performance 25-100%
Subsidiary Operational Performance Remainder of
weighting
</TABLE>
(1) Simple average of the STIP performance ratings of the five
subsidiaries.
(2) STIP performance rating of respective subsidiary.
2
<PAGE>
Recommendation
--------------
It is recommended that the Nominating and Compensation Committee approve the
following officer STIP structures and associated Corporate financial performance
measure.
<TABLE>
<CAPTION>
Short-Term Incentive Plan Structures
- ------------------------------------
Officer Group Award Component Weight Performance Measure
- ------------- --------------- ------ -------------------
<S> <C> <C> <C>
PG&E Corporation Corporate Financial Performance 75% Corporate EPS from operations
Subsidiary Performance 25% Average STIP rating of five
subsidiary officer groups
Subsidiary CEO's Corporate Financial Performance 25% Corporate EPS from operations
Subsidiary Performance 75% Average STIP rating of
respective subsidiary
PG&E Company Subsidiary Financial Performance 75% Subsidiary contribution to
PG&E Gas Transmission corporate EPS from operations
PG&E Energy Trading Subsidiary Operational 25% Financial, operating, and
PG&E US Generating Performance service measures determined by
subsidiary CEO
PG&E Energy Services Subsidiary Financial Performance 40% Financial measures (12%) are
net income and gross margin.
Non-financial measures (28%)
are sales momentum, product
development, staffing,
regulatory relations, and
effective relationships with
other PG&E subsidiaries
Individual Officer Performance 60% Subjective evaluation of each
individual's contribution to
company performance approved
by Corporation CEO
</TABLE>
3
<PAGE>
Recommendation (continued)
--------------
Corporate Financial Performance Measure
- ---------------------------------------
The Corporate financial measure will be earnings per share (EPS).
The 1998 EPS performance scale will be presented to the Committee for approval
in January 1998. The scale will be designed so that (1) there will be no payout
unless 1998 EPS exceeds inflation-adjusted 1997 EPS from operations, and (2)
target payout will occur only if 1998 EPS exceeds the 1998 budget (in the past,
target has been pegged to the budget).
EPS Performance Level STIP Payout Level
--------------------- -----------------
9.0% Above 1997 EPS Maximum 2.00
1998 EPS Budget 0.75
Inflation-Adjusted 1997 EPS Threshold 0.50
See Appendix A for an example of the EPS Scale.
The 1997 EPS used to calculate the performance scale will be the EPS from
operations used to determine the 1997 STIP payout. The 1998 EPS used to measure
the achievement of the 1998 STIP will be EPS from operations resulting from
implementing the 1998 business plan and budget. As with past STIPs, unbudgeted
one-time charges for items such as changes in accounting methods, workforce
restructuring, and similar one-time occurrences will be excluded, and the
Committee will continue to retain full discretion to determine final awards to
officers.
4
<PAGE>
EXHIBIT 10.6
Description of Short-Term Incentive Plan for Officers of PG&E Corporation and
its subsidiaries, effective January 1, 1999.
Recommendation
--------------
It is recommended that the Nominating and Compensation Committee approve the
following methodology for establishing the scale for the corporate EPS
performance measure.
TARGET (1.0) payout will occur at budgeted financial performance of $2.15 per
share. This is estimated to represent a 13% increase over 1998 EPS from
operations.
THRESHOLD (0.5) payout will occur at 1999 EPS from operations of 5% over actual
1998 EPS from operations(1).
MAXIMUM (2.0) payout will occur at 1999 EPS from operations of 17.5% over actual
1998 EPS from operations(1).
Each of these payout targets represents a significant stretch from 1998 and
prior years as illustrated in the table below. Appendix B shows an example of
this scale based on a current forecast of 1998 EPS from operations performance.
<TABLE>
<CAPTION>
EPS Performance Level STIP Payout Level
--------------------- -----------------
1999 1998
---- ----
<S> <C> <C>
17.50 Above 1998 EPS 11.65% Above 1997 EPS Maximum 2.00
13.16% Above 1998 EPS 7.51% Above 1997 EPS Target 1.00
5.00% Above 1998 EPS 0.00% Above 1997 EPS Threshold 0.50
</TABLE>
The 1998 EPS used to calculate the performance scale will be the EPS from
operations used to determine the 1998 STIP payout. The 1999 EPS used to measure
the achievement of the 1999 STIP will be EPS from operations resulting from
implementing the 1999 business plan and budget. As with past STIPs, unbudgeted
one-time charges for items such as changes in accounting methods, workforce
restructuring, and similar one-time occurrences will be excluded, and the
Committee will continue to retain full discretion to determine final awards to
officers.
(1) This actual value will be presented to the Committee in January 1999 when
actual 1998 EPS from operations are available.
1
<PAGE>
Background
----------
Short-Term Incentive Plan Structure
- -----------------------------------
At its meeting on October 21, 1998, the Nominating and Compensation Committee
reviewed and approved the 1999 Short-Term Incentive Plan (STIP) structure for
officers of the Corporation and each subsidiary. The structure (see Appendix A)
established the weighting of corporate earnings per share (EPS), subsidiary EPS,
and other performance factors for officers. The structure requires an
implementing methodology to link the EPS performance levels to threshold,
minimum, and maximum incentive payout levels, which is contained in this
document.
2
<PAGE>
EXHIBIT 10.7
SUPPLEMENTAL EXECUTIVE RETIREMENT PLAN
OF
THE PACIFIC GAS AND ELECTRIC COMPANY
----------------------------------------------
This is the controlling and definitive statement of the Supplemental
Executive Retirement Plan ("PLAN"/1/) for ELIGIBLE EMPLOYEES of Pacific Gas and
Electric Company ("COMPANY") and such other companies, affiliates, subsidiaries,
or associations as the BOARD OF DIRECTORS may designate from time to time. The
PLAN was first adopted by the BOARD OF DIRECTORS in 1984 and was effective
January 1, 1985. It has since been amended from time to time. Except as
expressly stated by any amendment to this PLAN, benefits of ELIGIBLE EMPLOYEES
who retire, terminate from employment, or cease to be ELIGIBLE EMPLOYEES prior
to the effective date of any amendment shall not be affected by any such
amendment. The amended PLAN as contained herein is effective January 1, 1998.
ARTICLE I
DEFINITIONS
-----------
1.01 Basic SERP Benefit shall mean the benefit described in Section 2.01.
------------------
1.02 Beneficiary shall mean the person, persons, or entity designated by
-----------
the ELIGIBLE EMPLOYEE to receive payments under any optional form of benefit
elected pursuant to Section 2.03 c. or Section 2.03 d., payable or owed but
unpaid at the time of the ELIGIBLE EMPLOYEE's death. An ELIGIBLE EMPLOYEE shall
designate a BENEFICIARY on a form provided by the PLAN ADMINISTRATOR and kept on
file in the PLAN ADMINISTRATOR's office. An ELIGIBLE EMPLOYEE may change a
BENEFICIARY at any time by filing a new beneficiary form with the PLAN
ADMINISTRATOR.
1.03 Board or Board of Directors shall mean the BOARD OF DIRECTORS of the
----- ------------------
COMPANY or, when appropriate, any committee of the BOARD which has been
delegated the authority to take action with respect to the PLAN.
1.04 Company shall mean the Pacific Gas and Electric Company, a California
-------
corporation.
- -----------------------------
/1/ Words in all capitals are defined in Article I.
<PAGE>
1.05 Eligible Employee shall mean (1) employees of the COMPANY, or (2)
-----------------
with respect to PG&E Corporation and PG&E Corporation Support Services, Inc.,
employees who were transferred to PG&E Corporation or PG&E Corporation Support
Services, Inc., from the COMPANY before January 1, 2000, (3) who are officers at
the vice presidential level or above, the corporate secretary, the controller,
and the treasurer of the COMPANY, and (4) such other employees of the COMPANY,
or such other companies, affiliates, subsidiaries, or associations as may be
designated by the Nominating and Compensation Committee.
1.06 STIP Payment shall mean amounts received by an ELIGIBLE EMPLOYEE
------------
under the Short-Term Incentive Plan maintained by PG&E Corporation.
1.07 Plan shall mean the Supplemental Executive Retirement Plan ("SERP")
----
as set forth herein and as may be amended from time to time.
1.08 Plan Administrator shall mean the Employee Benefit Administrative
------------------
Committee or such individual or individuals as that Committee may appoint to
handle the day-to-day affairs of the PLAN.
1.09 Retirement Plan shall mean the Pacific Gas and Electric Company
---------------
Retirement Plan for Management Employees.
1.10 Salary shall mean the base salary received by an ELIGIBLE EMPLOYEE.
------
SALARY shall not include amounts received by an employee after such employee
ceases to be an ELIGIBLE EMPLOYEE. For purposes of calculating benefits under
the PLAN, SALARY shall not be reduced to reflect amounts which have been
deferred under the Pacific Gas and Electric Company Deferred Compensation Plan
or under the PG&E Corporation Deferred Compensation Plan which became effective
November 5, 1997.
1.11 Service shall mean "credited service" as that term is defined in the
-------
RETIREMENT PLAN or, if the Nominating and Compensation Committee of the BOARD
OF DIRECTORS has granted an adjusted service date for an ELIGIBLE EMPLOYEE,
"credited service" as calculated from such adjusted service date. In no event,
however, shall SERVICE include periods of time after which an officer has ceased
to be an ELIGIBLE EMPLOYEE.
ARTICLE II
SERP BENEFITS
-------------
2.01 The BASIC SERP BENEFIT payable from the PLAN shall be a monthly
annuity commencing on the first of the month following the month in which the
ELIGIBLE
2
<PAGE>
EMPLOYEE (i) attains his 65th birthday or (ii) ceases to be an employee
of the COMPANY, whichever is later. The monthly amount of the BASIC SERP
BENEFIT shall be equal to the product of:
1.6% x [average of three highest calendar years' combination of SALARY
and STIP PAYMENT for the last ten years of SERVICE] x SERVICE x 1/12.
In computing a year's combination of SALARY and STIP PAYMENT, the year's
amount shall be the sum of the SALARY and STIP PAYMENT, if any, paid or payable
in the same calendar year. If an ELIGIBLE EMPLOYEE has fewer than three years'
SALARY, the average shall be the combination of SALARY and STIP PAYMENT for such
shorter time, divided by the number of years and partial years during which such
employee was an ELIGIBLE EMPLOYEE.
The BASIC SERP BENEFIT is further reduced by any amounts paid or payable
from the RETIREMENT PLAN, calculated before adjustments for marital or joint
pension option elections.
2.02 For ELIGIBLE EMPLOYEES of the COMPANY, PG&E Corporation, or PG&E
Corporation Support Services, Inc., who transfer from any of said companies to
another subsidiary or affiliate, the principles of Section 10 of the RETIREMENT
PLAN shall govern the calculation of benefits under this PLAN. An ELIGIBLE
EMPLOYEE who ceases to be an employee of the COMPANY and who is also not
employed by any of its subsidiaries, affiliates, or related associations shall
be entitled to receive a benefit payable from the PLAN at any time after his
55th birthday. The amount of the benefit payable shall be reduced by the
appropriate age and service factors contained in the RETIREMENT PLAN applicable
to such employee. For such calculations, the service factor shall be SERVICE as
defined in the PLAN.
In computing amounts payable from the RETIREMENT PLAN as an offset to the
benefit payable from this PLAN, the RETIREMENT PLAN benefit shall be calculated
as though the ELIGIBLE EMPLOYEE elected to receive a pension from the RETIREMENT
PLAN commencing on the same date as benefits from this PLAN.
2.03 An ELIGIBLE EMPLOYEE may elect to have his BASIC SERP BENEFIT paid in
any one of the following forms:
a. BASIC SERP BENEFIT, or a reduced BASIC SERP BENEFIT as calculated
under Section 2.02, paid as a monthly annuity for the life of the
ELIGIBLE EMPLOYEE with no survivor's benefit.
b. A monthly annuity payable for the life of the ELIGIBLE EMPLOYEE
with a survivor's option payable to the ELIGIBLE EMPLOYEE's joint
annuitant beginning on the first of the month following the
ELIGIBLE EMPLOYEE'S
3
<PAGE>
death. The factors to be applied to reduce the BASIC SERP BENEFIT
to provide for a survivor's benefit shall be the factors which
are contained in the RETIREMENT PLAN and which are appropriate
given the type of joint pension elected and the ages and marital
status of the joint annuitants.
c. A five-year or ten-year certain annuity, with equal annual
installment payments beginning on January 1 of the year following
the year in which payments of the BASIC SERP BENEFIT would
otherwise have commenced and continuing every January 1
thereafter until all payments are made. In determining the amount
of the annuity payments, the present value of the BASIC SERP
BENEFIT shall be computed using the appropriate mortality factors
contained in the RETIREMENT PLAN for single life annuities and
the interest rate set by the Pension Benefit Guaranty Corporation
as of the first day of the year in which annuity payments begin.
d. A lump sum payment of the actuarial present value of the BASIC
SERP BENEFIT which would have been payable to the ELIGIBLE
EMPLOYEE under Section 2.03 a. In determining the actuarial
present value of the BASIC SERP BENEFIT, the PLAN ADMINISTRATOR
shall apply the appropriate mortality factors used in calculating
lump sum payments under the RETIREMENT PLAN for single life
annuities and the interest rate set by the Pension Benefit
Guaranty Corporation as of the first day of the year in which the
lump sum payment is made.
2.04 Annuities payable to an ELIGIBLE EMPLOYEE who is receiving a (i)
BASIC SERP BENEFIT, (ii) a BASIC SERP BENEFIT reduced to provide a survivor's
benefit to a joint annuitant, or (iii) a joint annuitant who is receiving a
survivor's benefit shall be decreased by any additional amounts which can be
paid from the RETIREMENT PLAN where such additional amounts are due to increases
in the limits placed on benefits payable from qualified pension plans under
Section 4l5 of the Internal Revenue Code. The amount of any such decrease shall
be adjusted to reflect the type of pension elected by an ELIGIBLE EMPLOYEE under
the RETIREMENT PLAN and this PLAN. Decreases under this Section 2.04 shall not
be applied to decrease benefits payable under the lump sum or the five-year or
ten-year certain annuity options.
ARTICLE III
DEATH BENEFITS
--------------
3.01 For an ELIGIBLE EMPLOYEE who has elected to receive his PLAN benefits
in one of the optional forms described in Section 2.03 c. or 2.03 d. and who
dies before receiving the total number of payments selected under the optional
form of benefit, the PLAN
4
<PAGE>
ADMINISTRATOR shall continue to make the scheduled benefit payments to the
BENEFICIARY designated by the ELIGIBLE EMPLOYEE. If the ELIGIBLE EMPLOYEE has
failed to designate a BENEFICIARY or if there is no designated BENEFICIARY
surviving at the time of the ELIGIBLE EMPLOYEE'S death, the PLAN ADMINISTRATOR
shall make the remaining payments to the estate of the ELIGIBLE EMPLOYEE.
3.02 In the event that an ELIGIBLE EMPLOYEE who has accrued a benefit
under this PLAN dies prior to the date that a BASIC SERP BENEFIT would otherwise
commence and the ELIGIBLE EMPLOYEE is married at the time of the ELIGIBLE
EMPLOYEE's death, the PLAN ADMINISTRATOR shall pay a spouse's benefit to the
ELIGIBLE EMPLOYEE's surviving spouse:
a. If the sum of the age and SERVICE of the ELIGIBLE EMPLOYEE at the
time of death equaled 70 (69.5 or more is rounded to 70) or if
the ELIGIBLE EMPLOYEE was age 55 at the time of death, the
spouse's benefit shall be a monthly annuity commencing on the
first of the month following the month in which the ELIGIBLE
EMPLOYEE dies and shall be payable for the life of the surviving
spouse. The amount of the monthly benefit shall be one-half of
the monthly BASIC SERP BENEFIT which would have been paid to the
ELIGIBLE EMPLOYEE calculated:
1) as if he had elected to receive a BASIC SERP BENEFIT, without
survivor's option;
2) the monthly annuity starting date was the first of the month
following the month in which the ELIGIBLE EMPLOYEE died; and
3) without the application of early retirement reduction
factors.
b. If the ELIGIBLE EMPLOYEE is less than 55 years of age or had
fewer than 70 points (as calculated under Section 3.02(a)) at the
time of death, the surviving spouse will be entitled to receive a
monthly annuity commencing on the first of the month following
the month in which the ELIGIBLE EMPLOYEE would have become age 55
if he had survived. The amount of the monthly annuity payable to
the surviving spouse shall be equal to the BASIC SERP BENEFIT
converted to a marital joint annuity providing for a 50 percent
survivor's benefit, calculated as if: 1) the ELIGIBLE EMPLOYEE
had terminated employment at the date of death, 2) had lived
until age 55, 3) had begun to receive PENSION payments, and 4)
had subsequently died.
c. If a former ELIGIBLE EMPLOYEE was age 55 or older at the time of
his death and not yet receiving a SERP BENEFIT under the PLAN,
the surviving spouse
5
<PAGE>
will be entitled to receive a monthly annuity in an amount equal
to the BASIC SERP BENEFIT converted to a marital joint annuity
providing for a 50 percent survivor's benefit, calculated as if
the former ELIGIBLE EMPLOYEE had begun receiving the converted
SERP BENEFIT immediately prior to his death.
d. If a former ELIGIBLE EMPLOYEE was younger than age 55 or had
fewer than 70 points (as calculated under Section 3.02(a)) at the
time of his death, the surviving spouse will be entitled to
receive a monthly annuity in an amount equal to the BASIC SERP
BENEFIT converted to a marital joint annuity providing for a 50
percent survivor's benefit, calculated as if: 1) the former
ELIGIBLE EMPLOYEE had survived until age 55, 2) had begun
receiving the converted SERP BENEFIT, and 3) had subsequently
died.
3.03 A surviving spouse who is entitled to receive a spouse's benefit
under Section 3.02 shall not be entitled to receive any other benefit under the
PLAN.
ARTICLE IV
ADMINISTRATIVE PROVISIONS
-------------------------
4.01 Administration. The PLAN shall be administered by the PLAN
--------------
ADMINISTRATOR who shall have the authority to interpret the PLAN and make such
rules as it deems appropriate. The PLAN ADMINISTRATOR shall have the duty and
responsibility of maintaining records, making the requisite calculations, and
disbursing payments hereunder. The PLAN ADMINISTRATOR's interpretations,
determinations, rules, and calculations shall be final and binding on all
persons and parties concerned.
4.02 Amendment and Termination. The COMPANY may amend or terminate the
-------------------------
PLAN at any time, provided, however, that no such amendment or termination shall
adversely affect an accrued benefit which an ELIGIBLE EMPLOYEE has earned prior
to the date of such amendment or termination, nor shall any amendment or
termination adversely affect a benefit which is being provided to an ELIGIBLE
EMPLOYEE, surviving spouse, joint annuitant, or beneficiary under Article II or
Article III on the date of such amendment or termination. Anything in this
Section 4.02 to the contrary notwithstanding, the COMPANY may reduce or
terminate any benefit to which an ELIGIBLE EMPLOYEE, surviving spouse, joint
annuitant, or BENEFICIARY is or may become entitled provided that such ELIGIBLE
EMPLOYEE, surviving spouse, joint annuitant, or BENEFICIARY is or becomes
entitled to an amount equal to such benefit under another plan, practice, or
arrangement of the COMPANY.
6
<PAGE>
4.03 Nonassignability of Benefits. The benefits payable under this PLAN
----------------------------
or the right to receive future benefits under this PLAN may not be anticipated,
alienated, pledged, encumbered, or subject to any charge or legal process, and
if any attempt is made to do so, or a person eligible for any benefits becomes
bankrupt, the interest under the PLAN of the person affected may be terminated
by the PLAN ADMINISTRATOR which, in its sole discretion, may cause the same to
be held if applied for the benefit of one or more of the dependents of such
person or make any other disposition of such benefits that it deems appropriate.
4.04 Nonguarantee of Employment. Nothing contained in this PLAN shall be
--------------------------
construed as a contract of employment between the COMPANY or the ELIGIBLE
EMPLOYEE, or as a right of the ELIGIBLE EMPLOYEE to be continued in the employ
of the COMPANY, to remain as an officer of the COMPANY, or as a limitation on
the right of the COMPANY to discharge any of its employees, with or without
cause.
4.05 Benefits Unfunded and Unsecured. The benefits under this PLAN are
-------------------------------
unfunded, and the interest under this PLAN of any ELIGIBLE EMPLOYEE and such
ELIGIBLE EMPLOYEE's right to receive a distribution of benefits under this PLAN
shall be an unsecured claim against the general assets of the COMPANY.
4.06 Applicable Law. All questions pertaining to the construction,
--------------
validity, and effect of the PLAN shall be determined in accordance with the laws
of the United States, and to the extent not preempted by such laws, by the laws
of the State of California.
Adopted pursuant to the delegation contained in the Resolution of the Board of
Directors of Pacific Gas and Electric Company dated June 18, 1997.
By: /s/ Gordon R. Smith
----------------------------------------
Gordon R. Smith
President and Chief Executive Officer
Pacific Gas and Electric Company
7
<PAGE>
EXHIBIT 10.8
PG&E CORPORATION
SUPPLEMENTAL EXECUTIVE RETIREMENT SAVINGS PLAN
<PAGE>
TABLE OF CONTENTS
-----------------
<TABLE>
<CAPTION>
Page
----
<S> <C>
1. Purpose of Plan....................................................... 1
2. Definitions........................................................... 1
3. Employer Contributions................................................ 3
4. Accounting............................................................ 6
5. Distributions......................................................... 7
6. Domestic Relations Orders............................................. 9
7. Vesting............................................................... 10
8. Administration Of The Plan............................................ 10
9. Funding............................................................... 10
10. Modification Or Termination Of Plan................................... 11
11. General Provisions.................................................... 11
Execution.................................................................. 12
Appendix A................................................................. 13
</TABLE>
<PAGE>
PG&E CORPORATION
SUPPLEMENTAL EXECUTIVE RETIREMENT SAVINGS PLAN
PG&E CORPORATION ("PG&E CORP") hereby establishes the PG&E Corporation
Supplemental Executive Retirement Savings Plan (the "Plan"), effective as of
January 1, 1997, with respect to all individuals who were Eligible Employees as
of such date, other than Eligible Employees of U.S. Generating Company, Pacific
Gas and Electric Company, and PG&E CORP, with respect to whom this Plan is
effective as of January 1, 1998.
1. Purpose of the Plan
-------------------
The Plan is established and is maintained for the benefit of a select group
of management and highly compensated employees of PG&E CORP and its
Participating Subsidiaries in order to provide such employees with certain
deferred compensation benefits. The Plan is an unfunded deferred
compensation plan that is intended to qualify for the exemptions provided
in Sections 201, 301, and 401 of ERISA.
2. Definitions
-----------
The following words and phrases shall have the following meanings unless a
different meaning is plainly required by the context:
(a) "Applicable Plan" shall mean, with respect to any Eligible Employee,
---------------
the plan in which such Eligible Employee is an active participant that
is sponsored by an Employer and that is a defined contribution plan
intended to be qualified under Code Section 401(a).
(b) "Board of Directors" shall mean the Board of Directors of PG&E CORP,
------------------
as from time to time constituted.
(c) "Code" shall mean the Internal Revenue Code of 1986, as amended.
----
Reference to a specific section of the Code shall include such
section, any valid regulation promulgated thereunder, and any
comparable provision of any future legislation amending,
supplementing, or superseding such section.
(d) "Committee" shall mean the Nominating and Compensation Committee of
---------
the Board, as it may be constituted from time to time.
(e) "Compensation" shall mean an Eligible Employee's base compensation,
and, with respect to an Eligible Employee whose Employer does not
sponsor a defined benefit pension plan intended to be qualified under
Code Section 401(a), such Eligible Employee's short-term incentive
payments, before any deductions to such Eligible Employee's
compensation deferrals elected by such Eligible Employee under the
PG&E Corporation Deferred Compensation Plan for Officers and before
any deductions for contributions to a plan qualifying under Section
401(k) of the Code as salary reduction contributions or to a cafeteria
plan under Section 125 of the Code. An Eligible Employee's
Compensation for purposes of this Plan shall not be subject to the
dollar limitation of Section 401(a)(17) of the Code (e.g., $160,000
----
for 1998).
<PAGE>
(f) "Eligible Employee" shall mean an Employee who:
-----------------
(1) Is an officer of PG&E CORP or any Participating Subsidiary and
who is in Officer Band 5 or above; or
(2) Is a key employee of PG&E CORP or any Participating Subsidiary
and who is designated by the Committee as eligible to participate
in the Plan.
(g) "Eligible Employee's Account" or "Account" shall mean as to any
--------------------------- -------
Eligible Employee, the separate account maintained on the books of
PG&E CORP in accordance with Section 4(a) in order to reflect his or
her interest under the Plan.
(h) "Employee" shall mean an individual who is treated in the records of
--------
an Employer as an employee of the Employer and who is not covered by a
collective bargaining agreement; provided, however, such term shall
not mean an individual who is a "leased employee" or who has entered
into a written contract or agreement with an Employer which explicitly
excludes such individual from participation in an Employer's benefit
plans. The provisions of this definition shall govern, whether or not
it is determined that an individual otherwise meets the definition of
"common law" employee.
(i) "Employers" shall mean PG&E CORP and the Participating Subsidiaries
---------
designated by the Employee Benefit Committee of PG&E CORP. An initial
list of the Participating Subsidiaries is contained in Appendix A to
this Plan.
(j) "Employer Contributions" shall mean the amounts credited to Eligible
----------------------
Employees' Accounts under the Plan by the Employers, in accordance
with Section 3(d).
(k) "Employer Matching Contributions" shall mean the amounts credited to
-------------------------------
Eligible Employees' Accounts under the Plan by the Employers, in
accordance with Section 3(b).
(l) "ERISA" shall mean the Employee Retirement Income Security Act of
-----
1974, as amended. Reference to a specific section of ERISA shall
include such section, any valid regulation promulgated thereunder, and
any comparable provision of any future legislation amending,
supplementing, or superseding such section.
(m) "Investment Funds" shall mean (i) the PG&E CORP Phantom Stock Fund,
----------------
(ii) the AA Utility Bond Fund, and (iii) the S&P 500 Index Fund. The
Investment Funds shall be used for tracking phantom investment results
under the Plan.
2
<PAGE>
(n) "Participating Subsidiary" shall mean a subsidiary of PG&E CORP, which
------------------------
has been designated by the Chief Executive Officer of PG&E CORP as a
Participating Subsidiary under this Plan. At such times and under such
conditions as the Committee may direct, one or more other subsidiaries
of PG&E CORP may become Participating Subsidiaries or a Participating
Subsidiary may be withdrawn from the Plan. An initial list of the
Participating Subsidiaries is contained in Appendix A to this Plan.
(o) "Plan" shall mean the PG&E Corporation Supplemental Executive
----
Retirement Savings Plan, as set forth in this instrument and as
heretofore and hereafter amended from time to time.
(p) "Plan Year" shall mean the calendar year.
---------
(q) "Retirement" or "Retire" shall mean an Eligible Employee's "separation
---------- ------
from service" within the meaning of Section 401(k) of the Code.
(r) "PG&E CORP" shall mean PG&E Corporation, a California corporation.
---------
(s) "Valuation Date" shall mean:
--------------
(1) For purposes of valuing Plan assets and Eligible Employees'
Accounts for periodic reports and statements, the date as of
which such reports or statements are made; and
(2) For purposes of determining the amount of assets actually
distributed to the Eligible Employee, his or her beneficiary, or
an Alternate Payee (or available for withdrawal), a date that
shall not be more than seven business days prior to the date the
check is issued to the Eligible Employee.
In any other case, the Valuation Date shall be the date designated by
the Plan Administrator (in its discretion) or the date otherwise set
forth in this Plan. In all cases, the Plan Administrator (in its
discretion) may change the Valuation Date, on a uniform and
nondiscriminatory basis, as is necessary or appropriate.
Notwithstanding the foregoing, the Valuation Date shall occur at least
annually.
3. Employer Contributions
----------------------
(a) Employer Matching Contributions. Subject to the provisions of
-------------------------------
Section 10, the Employer Account of each Eligible Employee shall be
credited for each Plan Year with an additional Employer Matching
Contribution, calculated in the manner provided in Sections 3(a) (1),
(2), and (3) below:
(1) First, an amount shall be calculated equal to the maximum
matching contribution that would be made under the terms of the
Applicable Plan, taking into account for such Plan Year the
amount of pre-tax deferrals and after-tax contributions the
Eligible Employee elected under the Applicable Plan. For purposes
of this calculation, amounts deferred under the PG&E Corporation
Deferred Compensation Plan for Officers shall be treated as pre-
tax deferrals under the Applicable Plan.
3
<PAGE>
(2) The calculation made in accordance with this Section 3(a) (1)
above shall be made without regard to any limitation on such
amounts under the Applicable Plan resulting from the application
of any of the limitations under Code Sections 401(m), 401(a)(17),
or 415.
(3) The Employer Matching Contribution to be credited to the Account
of an Eligible Employee for any Plan Year shall equal the amount
calculated in accordance with Sections 3(a) (1) and (2) above,
reduced by the amount of matching contribution made to such
Eligible Employee's account for such Plan Year under the
Applicable Plan.
(b) Crediting of Employer Matching Contributions. Employer Matching
--------------------------------------------
Contributions shall be credited to the Eligible Employee's Account at
the end of each calendar year and shall be credited only if the
Eligible Employee is an Employee on the last day of such calendar
year.
(c) Employer Contributions. Subject to the provisions of Section 10, the
----------------------
Account of each Eligible Employee shall be credited for each Plan Year
with an additional Employer Contribution, calculated in the manner
provided in Sections 3(c) (1), (2), and (3) below:
(1) First, an amount shall be calculated equal to the maximum profit-
sharing contribution that would be made under the terms of the
Applicable Plan, taking into account for such Plan Year the
Eligible Employee's Compensation for such Plan Year.
(2) The calculation made in accordance with this Section 3(c) (1)
above shall be made without regard to any limitation on such
amounts under the Applicable Plan resulting from the application
of any of the limitations under Code Sections 401(a)(4),
401(a)(17), or 415.
(3) The Employer Contribution to be credited to the Account of an
Eligible Employee for any Plan Year shall equal the amount
calculated in accordance with Sections 3(c) (1) and (2) above,
reduced by the amount of profit-sharing contributions made to
such Eligible Employee's account for such Plan Year under the
Applicable Plan.
(d) Crediting of Employer Contributions. The Employer Contributions made
-----------------------------------
in respect of an Eligible Employee shall be credited to the Eligible
Employee's Account at the end of each calendar years and shall be
credited only if the Eligible Employee is an Employee on the last day
of such calendar year.
4
<PAGE>
(e) Investment Return on Accounts. Although no assets will be segregated
-----------------------------
or otherwise set aside with respect to an Eligible Employee's Account,
the amount that is ultimately payable to the Eligible Employee with
respect to such Account shall be determined as if such Account had
been invested in some or all of the Investment Funds. The Plan
Administrator, in its sole discretion, shall adopt (and modify from
time to time) such rules and procedures as it deems necessary or
appropriate to implement the deemed investment of the Eligible
Employees' Accounts. Such procedures generally shall provide that an
Eligible Employee's Account shall be deemed to be invested among the
three Investment Funds in the manner elected by the Eligible Employee
in such percentages and manner as prescribed by the Plan
Administrator. Eligible Employees shall be able to reallocate their
Accounts between the Investment Funds and reallocate amounts newly
credited to their Accounts at such time and in such manner as the Plan
Administrator shall prescribe. Anything to the contrary herein
notwithstanding, an Eligible Employee may not reallocate Account
balances between Investment Funds if such reallocation would result in
a non-exempt Discretionary Transaction as defined in Rule 16b-3 of the
Securities Exchange Act of 1934, as amended, or any successor to Rule
16b-3, as in effect when the reallocation is requested.
(1) AA Utility Bond Fund. Amounts credited to the AA Utility Bond
Fund shall be credited with interest as of the last business day
of the immediately preceding calendar quarter and prorated based
on the number of days in the quarter that the balance was
allocated to the AAA Utility Bond Fund. Such interest shall be at
a rate equal to the AA Utility Bond Yield reported in Moody's
-------
Public Utility, published in the issue of Moody's Investors
-------------- -----------------
Service immediately preceding the first day of the calendar
-------
quarter in which the interest is to be credited. Such interest
shall become a part of the Eligible Employee's Account and shall
be paid at the same time or times as the balance of the Eligible
Employee's Account. Notwithstanding the above, if before the end
of the quarter an Eligible Employee has requested that his or her
Account balance be reallocated to another Investment Fund(s) or
the Eligible Employee's Account balance has been paid to the
Eligible Employee or to the Eligible Employee's beneficiary,
prorated interest on the Eligible Employee's Account balance
shall be calculated at a rate equal to the AA Utility Bond Yield
reported in Moody's Public Utility, published in the issue of
----------------------
Moody's Investors Service immediately preceding the date of such
-------------------------
reallocation or payment and shall be credited to the Eligible
Employee's Account in such other Investment Fund(s) on the date
of reallocation or paid directly to the Eligible Employee or the
Eligible Employee's beneficiary, whichever is applicable.
5
<PAGE>
(2) PG&E CORP Phantom Stock Fund. Amounts credited to the PG&E CORP
Phantom Stock Fund shall be converted into units (including
fractions computed to three decimal places) each representing a
share of PG&E CORP common stock. The value of a unit for purposes
of determining the number of units to credit upon initial
allocation or upon reallocation from another Investment Fund, and
for determining the dollar value of the aggregate number of units
to be reallocated from the PG&E CORP Phantom Stock Fund to
another Investment Fund, shall be the average of the daily high
and low price of a share of PG&E CORP common stock as traded on
the New York Stock Exchange for the 30 trading days preceding the
date that (i) amounts are credited to an Eligible Employee's
Account in the PG&E CORP Phantom Stock Fund, or (ii) the Plan
Administrator receives a reallocation request, in the case of
reallocations. Thereafter, the value of a unit shall fluctuate in
accordance with the closing price of PG&E CORP common stock on
the New York Stock Exchange. Each time that PG&E CORP pays a
dividend on its common stock, an amount equal to such dividend
payable with respect to each share of PG&E CORP common stock,
multiplied by the number of units credited to an Eligible
Employee's Account, shall be credited to the Eligible Employee's
Account and converted into additional units. The number of
additional units shall be calculated by dividing the aggregate
amount of credited dividends, i.e. the dividend multiplied by the
number of units credited to the Eligible Employee's Account as of
the dividend record date, by the closing price of a share of PG&E
CORP common stock on the New York Stock Exchange on the dividend
payment date. If, after the record date but before the dividend
payment date, an Eligible Employee's balance in the PG&E CORP
Phantom Stock Fund has been reallocated to another Investment
Fund(s) or has been paid to the Eligible Employee or to the
Eligible Employee's beneficiary, then an amount equal to the
aggregated dividend shall be credited to the Eligible Employee's
Account in such other Investment Fund(s) or paid directly to the
Eligible Employee or the Eligible Employee's beneficiary,
whichever is applicable.
(3) S&P 500 Index Fund. Amounts credited to the S&P 500 Index Fund
shall be valued based on the difference between the value of the
S&P 500 Index as reported in the Wall Street Journal on the date
amounts are credited to an Eligible Employee's Account and the
value of the S&P 500 Index as reported in the Wall Street Journal
on the relevant Valuation Date, assuming reinvestment of all
dividends under the S&P 500 Index Fund during the relevant
period.
4. Accounting
----------
(a) Eligible Employees' Accounts. At the direction of the Plan
----------------------------
Administrator, there shall be established and maintained on the books
of the Employer, a separate account for each Eligible Employee in
order to reflect his or her interest under the Plan.
6
<PAGE>
(b) Investment Earnings. Each Eligible Employee's Account shall initially
-------------------
reflect the value of his or her Account's interest in each of the
Investment Funds, deemed acquired with the amounts credited thereto.
Each Eligible Employee's Account shall also be credited (or debited)
as of the end of each day with the net appreciation (or depreciation),
earnings and gains (or losses) with respect to the investments deemed
made by his or her Account. Any such net earnings or gains deemed
realized with respect to any investment of any Eligible Employee's
Account shall be deemed reinvested in additional amounts of the same
investment and credited to the Eligible Employee's Account.
(c) Accounting Methods. The accounting methods or formulae to be used
------------------
under the Plan for the purpose of maintaining the Eligible Employees'
Accounts shall be determined by the Plan Administrator. The accounting
methods or formulae selected by the Plan Administrator may be revised
from time to time but shall conform to the extent practicable with the
accounting methods used under the Applicable Plan.
(d) Valuations and Reports. The fair market value of each Eligible
----------------------
Employee's Account shall be determined as of each Valuation Date. In
making such determinations and in crediting net deemed earnings and
gains (or losses) in the Investment Funds to the Eligible Employees'
Accounts, the Plan Administrator (in its discretion) may employ such
accounting methods as the Plan Administrator (in its discretion) may
deem appropriate in order to fairly reflect the fair market values of
the Investment Funds and each Eligible Employee's Account. For this
purpose, the Plan Administrator may rely upon information provided by
the Plan Administrator or other persons believed by the Plan
Administrator to be competent.
(e) Statements of Eligible Employee's Accounts. Each Eligible Employee
------------------------------------------
shall be furnished with periodic statements of his or her interest in
the Plan, at least annually.
5. Distributions
-------------
(a) Events Permitting Distribution. Subject to Sections 5(g) and 10(c),
------------------------------
distribution of the balance credited to an Eligible Employee's Account
shall be made only in the following circumstances:
(1) Upon the Eligible Employee's Retirement; or
(2) In the case of an Alternate Payee (as defined in Section 6(a), as
directed in a domestic relations order which the Plan
Administrator determines is a QDRO (as defined in Section 6(a),
but only as to the portion of the Eligible Employee's Account
which the QDRO states is payable to the Alternate Payee.
(b) Time and Form of Termination and Retirement Distributions.
---------------------------------------------------------
Distributions following an Eligible Employee's Retirement shall be
made in a lump sum cash payment within 30 days after his or her
Retirement.
7
<PAGE>
(c) Death Distributions. If an Eligible Employee dies before the entire
-------------------
balance of his or her Account has been distributed (whether or not the
Eligible Employee had previously terminated employment and whether or
not installment payments had previously commenced), the remaining
balance of the Eligible Employee's Account shall be distributed to the
beneficiary designated or otherwise determined in accordance with
Section 5(f), as soon as practicable after the date of death.
(d) Effect of Change in Eligible Employee Status. If an Eligible Employee
--------------------------------------------
ceases to be an Eligible Employee, the balance credited to his or her
Account shall continue to be credited (or debited) with appreciation,
depreciation, earnings, gains or losses under the terms of the Plan
and shall be distributed to him or her at the time and in the manner
set forth in this Section 5; provided, however, that the Plan
Administrator, in its sole discretion, may authorize an accelerated
distribution of the balance credited to his or her Account in the form
of a lump sum cash payment as of any earlier date.
(e) Payments to Incompetents. If any individual to whom a benefit is
------------------------
payable under the Plan is a minor or if the Plan Administrator
determines that any individual to whom a benefit is payable under the
Plan is incompetent to receive such payment or to give a valid release
therefor, payment shall be made to the guardian, committee, or other
representative of the estate of such individual which has been duly
appointed by a court of competent jurisdiction. If no guardian,
committee, or other representative has been appointed, payment may be
made to any person as custodian for such individual under the
California Uniform Transfers to Minors Act (or similar law of another
state) or may be made to or applied to or for the benefit of the minor
or incompetent, the incompetent's spouse, children or other
dependents, the institution or persons maintaining the minor or
incompetent, or any of them, in such proportions as the Plan
Administrator from time to time shall determine; and the release of
the person or institution receiving the payment shall be a valid and
complete discharge of any liability of PG&E CORP with respect to any
benefit so paid.
(f) Beneficiary Designations. Each Eligible Employee may designate, in a
------------------------
signed writing delivered to the Plan Administrator, on such form as it
may prescribe, one or more beneficiaries to receive any distribution
which may become payable under the Plan as the result of the Eligible
Employee's death.
(1) Changes and Failed Designations. An Eligible Employee may
designate different beneficiaries at any time by delivering a new
designation in like manner. Any designation shall become
effective only upon its receipt by the Plan Administrator, and
the last effective designation received by the Plan Administrator
shall supersede all prior designations. If an Eligible Employee
dies without having designated a beneficiary or if no beneficiary
survives the Eligible Employee, the Eligible Employee's Account
shall be payable to the beneficiary or beneficiaries designated
or otherwise determined under such Eligible Employee's Applicable
Plan.
8
<PAGE>
(g) Undistributable Accounts. Each Eligible Employee and (in the event of
------------------------
death) his or her beneficiary shall keep the Plan Administrator
advised of his or her current address. If the Plan Administrator is
unable to locate the Eligible Employee or beneficiary to whom an
Eligible Employee's Account is payable under this Section 5, the
Eligible Employee's Account shall be frozen as of the date on which
distribution would have been completed in accordance with this Section
5, and no further appreciation, depreciation, earnings, gains or
losses shall be credited (or debited) thereto. PG&E CORP shall have
the right to assign or transfer the liability for payment of any
undistributable Account to the Eligible Employee's former Employer (or
any successor thereto).
(h) Plan Administrator Discretion. Within the specific time periods
-----------------------------
described in this Section 5, the Plan Administrator shall have sole
discretion to determine the specific timing of the payment of any
Account balance under the Plan.
6. Domestic Relations Orders
-------------------------
(a) Qualified Domestic Relations Orders. The Plan Administrator shall
-----------------------------------
establish written procedures for determining whether a domestic
relations order purporting to dispose of any portion of an Eligible
Employee's Account is a qualified domestic relations order (within the
meaning of Section 414(p) of the Code) (a "QDRO").
----
(1) No Payment Unless a QDRO. No payment shall be made to any person
designated in a domestic relations order (an "Alternate Payee")
---------------
until the Plan Administrator (or a court of competent
jurisdiction reversing an initial adverse determination by the
Plan Administrator) determines that the order is a QDRO. Payment
shall be made to each Alternate Payee as specified in the QDRO.
(2) Time of Payment. Payment may be made to an Alternate Payee in the
form of a lump sum, at the time specified in the QDRO, but no
earlier than as soon as practicable following the date the QDRO
determination is made.
(3) Hold Procedures. Notwithstanding any contrary Plan provision,
prior to the receipt of a domestic relations order, the Plan
Administrator may, in its sole discretion, place a hold upon all
or a portion of an Eligible Employee's Account for a reasonable
period of time (as determined by the Plan Administrator) if the
Plan Administrator receives notice that (a) a domestic relations
order is being sought by the Eligible Employee, his or her
spouse, former spouse, child or other dependent, and (b) the
Eligible Employee's Account is a source of the payment under such
domestic relations order. For purposes of this Section 6(a) (3),
a "hold" means that no withdrawals, distributions, or investment
----
transfers may be made with respect to an Eligible Employee's
Account. If the Plan Administrator places a hold upon an Eligible
Employee's Account pursuant to this Section 6(a) (3), it shall
inform the Eligible Employee of such fact.
9
<PAGE>
7. Vesting
-------
(a) Percent Vesting. An Eligible Employee's interest in his or her Account
---------------
at all times shall be 100 percent vested and nonforfeitable. Upon the
Eligible Employee's Retirement, the balance credited to his or her
Account shall be distributable to him or her in the manner and at the
times set forth in Section 5.
8. Administration Of The Plan
--------------------------
(a) Plan Administrator. The Employee Benefit Committee of PG&E CORP is
------------------
hereby designated as the administrator of the Plan (within the meaning
of Section 3(16)(A) of ERISA). The Plan Administrator delegates to the
Senior Human Resource officer for PG&E CORP, or his or her designee,
the authority to carry out all duties and responsibilities of the Plan
Administrator under the Plan. The Plan Administrator shall have the
authority to control and manage the operation and administration of
the Plan.
(b) Powers of Plan Administrator. The Plan Administrator shall have all
----------------------------
discretion and powers necessary to supervise the administration of the
Plan and to control its operation in accordance with its terms,
including, but not by way of limitation, the power to interpret the
provisions of the Plan and to determine, in its sole discretion, any
question arising under, or in connection with the administration or
operation of, the Plan.
(c) Decisions of Plan Administrator. All decisions of the Plan
-------------------------------
Administrator and any action taken by it in respect of the Plan and
within the powers granted to it under the Plan shall be conclusive and
binding on all persons and shall be given the maximum deference
permitted by law.
9. Funding
-------
(a) Unfunded Plan. All amounts credited to an Eligible Employee's Account
-------------
under the Plan shall continue for all purposes to be a part of the
general assets of PG&E CORP. The interest of the Eligible Employee in
his or her Account, including his or her right to distribution
thereof, shall be an unsecured claim against the general assets of
PG&E CORP. While PG&E CORP may choose to invest a portion of its
general assets in investments identical or similar to those selected
by Eligible Employees for purposes of determining the amounts to be
credited (or debited) to their Accounts, nothing contained in the Plan
shall give any Eligible Employee or beneficiary any interest in or
claim against any specific assets of PG&E CORP.
10
<PAGE>
10. Modification Or Termination Of Plan
-----------------------------------
(a) Employers' Obligations Limited. The Plan is voluntary on the part of
------------------------------
the Employers, and the Employers do not guarantee to continue the
Plan. PG&E CORP at any time may, by appropriate amendment of the Plan,
suspend Employer Matching Contributions and/or Employer Contributions
or may discontinue Employer Matching Contributions and/or Employer
Contributions, with or without cause.
(b) Right to Amend or Terminate. The Board of Directors, acting through
---------------------------
its Nominating and Compensation Committee, reserves the right to
alter, amend, or terminate the Plan, or any part thereof, in such
manner as it may determine, for any reason whatsoever.
(1) Limitations. Any alteration, amendment, or termination shall take
effect upon the date indicated in the document embodying such
alteration, amendment, or termination, provided that no such
alteration or amendment shall divest any portion of an Account
that is then vested under the Plan.
(c) Effect of Termination. If the Plan is terminated, the balances
---------------------
credited to the Accounts of the Eligible Employees affected by such
termination shall be distributed to them at the time and in the manner
set forth in Section 5; provided, however, that the Plan
Administrator, in its sole discretion, may authorize accelerated
distribution of Eligible Employees' Accounts as of any earlier date.
11. General Provisions
------------------
(a) Inalienability. Except to the extent otherwise directed by a domestic
--------------
relations order which the Plan Administrator determines is a QDRO (as
defined in Section 6(a) or mandated by applicable law, in no event may
either an Eligible Employee, a former Eligible Employee or his or her
spouse, beneficiary or estate sell, transfer, anticipate, assign,
hypothecate, or otherwise dispose of any right or interest under the
Plan; and such rights and interests shall not at any time be subject
to the claims of creditors nor be liable to attachment, execution, or
other legal process.
(b) Rights and Duties. Neither the Employers nor the Plan Administrator
-----------------
shall be subject to any liability or duty under the Plan except as
expressly provided in the Plan, or for any action taken, omitted, or
suffered in good faith.
(c) No Enlargement of Employment Rights. Neither the establishment or
-----------------------------------
maintenance of the Plan, the making of any Employer Matching
Contributions, nor any action of any Employer or Plan Administrator,
shall be held or construed to confer upon any individual any right to
be continued as an Employee nor, upon dismissal, any right or interest
in any specific assets of the Employers other than as provided in the
Plan. Each Employer expressly reserves the right to discharge any
Employee at any time, with or without cause or advance notice.
11
<PAGE>
(d) Apportionment of Costs and Duties. All acts required of the Employers
---------------------------------
under the Plan may be performed by PG&E CORP for itself and its
Participating Subsidiaries, and the costs of the Plan may be equitably
apportioned by the Plan Administrator among PG&E CORP and the other
Employers. Whenever an Employer is permitted or required under the
terms of the Plan to do or perform any act, matter or thing, it shall
be done and performed by any officer or employee of the Employer who
is thereunto duly authorized by the board of directors of the
Employer.
(e) Applicable Law. The provisions of the Plan shall be construed,
--------------
administered, and enforced in accordance with the laws of the State of
California and, to the extent applicable, ERISA.
(f) Severability. If any provision of the Plan is held invalid or
------------
unenforceable, its invalidity or unenforceability shall not affect any
other provisions of the Plan, and the Plan shall be construed and
enforced as if such provision had not been included.
(g) Captions. The captions contained in and the table of contents prefixed
--------
to the Plan are inserted only as a matter of convenience and for
reference and in no way define, limit, enlarge, or describe the scope
or intent of the Plan nor in any way shall affect the construction of
any provision of the Plan.
Execution
---------
IN WITNESS WHEREOF, PG&E CORP, by its duly authorized officer, has executed
this Plan on the date indicated below.
PG&E CORPORATION
Dated: _______________ By:_____________________________
Title: _________________________
12
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APPENDIX A
PARTICIPATING SUBSIDIARIES
Participating Subsidiaries as of January 1, 1997
------------------------------------------------
- PG&E Gas Transmission Corporation
- PG&E Gas Transmission, Texas Corporation
- PG&E Gas Transmission TECO, Inc.
- PG&E Energy Trading-Gas Corporation
- PG&E Energy Services Corporation
- And the U.S. subsidiaries of each of the above-named corporations.
Additional Participating Subsidiaries as of January 1, 1998
-----------------------------------------------------------
- PG&E Corporation
- Pacific Gas and Electric Company
- PG&E Generating Company
- PG&E Corporation Support Services, Inc.
- And the U.S. subsidiaries of each of the above-named corporations.
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EXHIBIT 10.12
PG&E CORPORATION
LONG-TERM INCENTIVE PROGRAM
(As amended and restated effective as of October 21, 1998)
1. Purpose of the Program
----------------------
This is the controlling and definitive statement of the PG&E Corporation
Long-Term Incentive Program, as amended and restated herein (hereinafter
called the PROGRAM/1/). The purpose of the PROGRAM is to advance the
interests of the CORPORATION by providing ELIGIBLE PARTICIPANTS with
financial incentives to promote the success of its long-term (five to ten
years) business objectives, and to increase their proprietary interest in
the success of the CORPORATION. It is the intent of the CORPORATION to
reward those ELIGIBLE PARTICIPANTS who have a significant impact on
improved long-term corporate achievements. Inasmuch as the PROGRAM is
designed to encourage financial performance and to improve the value of
shareholders' investment in PG&E CORPORATION, the costs of the PROGRAM will
be funded from corporate earnings.
2. Program Administration
----------------------
The PROGRAM shall be administered by the COMMITTEE, except that the BOARD
OF DIRECTORS shall administer the PROGRAM with respect to grants of
INCENTIVE AWARDS TO NON-EMPLOYEE DIRECTORS. The BOARD OF DIRECTORS may at
any time revest authority to administer the PROGRAM in all respects in the
BOARD OF DIRECTORS. Subject to the provisions of the PROGRAM, the COMMITTEE
or the BOARD OF DIRECTORS, as the case may be, shall have full and final
authority, in its sole discretion:
(a) to determine the ELIGIBLE PARTICIPANTS to whom INCENTIVE AWARDS shall
be granted and the number of shares of COMMON STOCK to be awarded
under each INCENTIVE AWARD, based on the recommendation of the CHIEF
EXECUTIVE OFFICER (except that awards to the CHIEF EXECUTIVE OFFICER
shall be based on the recommendation of the BOARD OF DIRECTORS and
awards to NON-EMPLOYEE DIRECTORS shall be based on the recommendation
of the COMMITTEE);
(b) to determine the time or times at which INCENTIVE AWARDS shall be
granted;
- --------------
/1/ Capitalized words are defined in Section 20 hereof.
<PAGE>
(c) to designate the types of INCENTIVE AWARD being granted;
(d) to vary the OPTION vesting schedule described in the STOCK OPTION
PLAN;
(e) to determine the terms and conditions, not inconsistent with the terms
of the PROGRAM, of any INCENTIVE AWARD granted hereunder (including,
but not limited to, the consideration and method of payment for shares
purchased upon the exercise of an INCENTIVE AWARD, and any vesting
acceleration or exercisability provisions in the event of a CHANGE IN
CONTROL or TERMINATION), based in each case on such factors as the
COMMITTEE or BOARD OF DIRECTORS shall deem appropriate;
(f) to approve forms of agreement for use under the PROGRAM;
(g) to construe and interpret the PROGRAM and any related INCENTIVE AWARD
agreement and to define the terms employed herein and therein;
(h) except as provided in Section 18 hereof, to modify or amend any
INCENTIVE AWARD or to waive any restrictions or conditions applicable
to any INCENTIVE AWARD or the exercise or realization thereof;
(i) except as provided in Section 18 hereof, to prescribe, amend and
rescind rules, regulations and policies relating to the administration
of the PROGRAM;
(j) except as provided in Section 18 hereof, to suspend, terminate, modify
or amend the PROGRAM;
(k) to delegate to one or more agents such administrative duties as the
COMMITTEE or BOARD OF DIRECTORS may deem advisable, to the extent
permitted by applicable law; and
(l) to make all other determinations and take such other action with
respect to the PROGRAM and any INCENTIVE AWARD granted hereunder as
the COMMITTEE may deem advisable, to the extent permitted by
applicable law.
Notwithstanding the provisions contained in the foregoing paragraph, the
CHIEF EXECUTIVE OFFICER shall have the authority, in his sole discretion:
(a) to grant INCENTIVE AWARDS to any ELIGIBLE PARTICIPANT who, at the time
of the INCENTIVE AWARD grant, (i) is not an officer of the CORPORATION or a
DIRECTOR, and (ii) if such ELIGIBLE PARTICIPANT is an EMPLOYEE, is
receiving an annual salary which is below the level which
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requires approval by the COMMITTEE; (b) to determine the time or times at
which INCENTIVE AWARDS shall be granted to such ELIGIBLE PARTICIPANTS; (c)
to designate the types of INCENTIVE AWARD being granted to such ELIGIBLE
PARTICIPANTS; and (d) to vary the OPTION vesting schedule described in the
STOCK OPTION PLAN for the OPTIONS granted to such ELIGIBLE PARTICIPANTS;
provided, however, that all grants of INCENTIVE AWARDS by the CHIEF
EXECUTIVE OFFICER shall conform to the guidelines previously approved by
the COMMITTEE.
3. Shares of Stock Subject to the Program
--------------------------------------
There shall be reserved for use under the PROGRAM (subject to the
provisions of Section 13 hereof) a total of 23,389,230 shares of COMMON
STOCK, which shares may be authorized but unissued shares of COMMON STOCK
or issued shares of COMMON STOCK which shall have been reacquired by PG&E
CORPORATION. Such shares consist of (i) 13,000,000 shares of COMMON STOCK
originally reserved for use under the PROGRAM at the time it first became
effective on January 1, 1992, (ii) 389,230 shares of COMMON STOCK remaining
under the 1986 OPTION PLAN and carried over to the PROGRAM, and (iii)
10,000,000 shares of COMMON STOCK added to the PROGRAM effective as of
January 1, 1996.
If (i) any INCENTIVE AWARD expires or terminates for any reason without
having been exercised or purchased in full, (ii) an INCENTIVE AWARD is
surrendered in exchange for one or more other INCENTIVE AWARDS, or (iii)
any RESTRICTED STOCK is forfeited, then, in each such case, any
unexercised, unpurchased, surrendered or forfeited shares which were
subject to such INCENTIVE AWARD (except shares as to which a related TANDEM
SAR has been exercised) shall again be available for the future grant of
INCENTIVE AWARDS under the PROGRAM (unless the PROGRAM has terminated). In
addition, shares may be reused or added back to the PROGRAM to the extent
permitted by applicable law.
4. Eligibility
-----------
INCENTIVE AWARDS will be granted only to ELIGIBLE PARTICIPANTS. ISOS will
be granted only to EMPLOYEES. The COMMITTEE, in its sole discretion, may
grant INCENTIVE AWARDS to an ELIGIBLE PARTICIPANT who is a resident or
citizen of a foreign country, with such modifications as the COMMITTEE may
deem advisable to reflect the laws, tax policy or customs of such foreign
country.
The PROGRAM shall not confer upon any RECIPIENT any right to continuation
of employment, service as a DIRECTOR or consulting relationship with the
CORPORATION; nor shall it interfere in any way with the right of the
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RECIPIENT or the CORPORATION to terminate such employment, service as a
DIRECTOR or consulting relationship at any time, with or without cause.
5. Designation of Incentive Awards
-------------------------------
At the time of the grant of each INCENTIVE AWARD under the Program, the
COMMITTEE (or the CHIEF EXECUTIVE OFFICER, in the case of INCENTIVE AWARDS
granted by the CHIEF EXECUTIVE OFFICER to certain ELIGIBLE PARTICIPANTS
pursuant to Section 2 hereof, or the BOARD OF DIRECTORS, in the case of
INCENTIVE AWARDS granted by the BOARD OF DIRECTORS to NON-EMPLOYEE
DIRECTORS) shall determine whether such INCENTIVE AWARD is to be designated
as an ISO, NON-QUALIFIED STOCK OPTION, SAR, DIVIDEND EQUIVALENT,
PERFORMANCE UNIT, stock grant, RESTRICTED STOCK, LSAR, PHANTOM STOCK or
other STOCK-BASED AWARD; provided, however, that ISOS may be granted only
to EMPLOYEES.
Notwithstanding such designation, to the extent that the aggregate FAIR
MARKET VALUE (determined for each share as of the date of grant of the
OPTION covering each share) of the shares with respect to which OPTIONS
designated as ISOS become exercisable for the first time by any RECIPIENT
during any calendar year exceeds $100,000, such OPTIONS shall be treated as
NON-QUALIFIED STOCK OPTIONS.
Any INCENTIVE AWARD may be granted alone, contingent upon, in addition to
or in TANDEM with one or more other INCENTIVE AWARDS granted under the
PROGRAM. In addition, except as provided in Section 12 hereof, any
INCENTIVE AWARD may be granted in exchange for one or more other INCENTIVE
AWARDS.
6. Stock Options, Tandem Stock Appreciation Rights and Tandem Dividend
-------------------------------------------------------------------
Equivalents
-----------
Except as provided in Section 9 below (relating to grants of INCENTIVE
AWARDS to NON-EMPLOYEE DIRECTORS), the COMMITTEE, in its sole discretion,
may grant ISOS, NON-QUALIFIED STOCK OPTIONS, TANDEM SARS and TANDEM
DIVIDEND EQUIVALENTS to ELIGIBLE PARTICIPANTS, subject to the terms and
conditions set forth in the STOCK OPTION PLAN attached hereto as Exhibit A.
7. Performance Units
-----------------
Except as provided in Section 9 below (relating to grants of INCENTIVE
AWARDS to NON-EMPLOYEE DIRECTORS), the COMMITTEE, in its sole discretion,
may grant PERFORMANCE UNITS to ELIGIBLE PARTICIPANTS,
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subject to the terms and conditions set forth in the PERFORMANCE UNIT PLAN
attached hereto as Exhibit B.
8. Other Incentive Awards
----------------------
Except as provided in Section 9 below (relating to grants of INCENTIVE
AWARDS to NON-EMPLOYEE DIRECTORS), the COMMITTEE, in its sole discretion,
may grant other INCENTIVE AWARDS (including, but not limited to, SARS
granted without OPTIONS, DIVIDEND EQUIVALENTS granted without OPTIONS,
stock grants, RESTRICTED STOCK, LSARS, PHANTOM STOCK or other STOCK-BASED
AWARDS) to ELIGIBLE PARTICIPANTS, subject to such terms and conditions as
the COMMITTEE shall deem appropriate.
9. Grants of Incentive Awards to Non-Employee Directors
----------------------------------------------------
NON-EMPLOYEE DIRECTORS will only be eligible to be granted DIRECTOR
RESTRICTED STOCK, PHANTOM STOCK and NON-QUALIFIED STOCKOPTIONS in
accordance with, and subject to the terms and conditions contained in, the
NON-EMPLOYEE DIRECTOR STOCK INCENTIVE PLAN RULES attached hereto as Exhibit
C.
10. Termination of Employment or Relationship with the CORPORATION
--------------------------------------------------------------
The COMMITTEE may, in its sole discretion, establish terms and conditions
pertaining to the effect of TERMINATION on INCENTIVE AWARDS granted to a
RECIPIENT prior to TERMINATION, to the extent permitted by applicable law.
11. Tax Withholding
---------------
When a RECIPIENT incurs tax liability in connection with the exercise of an
INCENTIVE AWARD or the receipt of shares of COMMON STOCK pursuant to an
INCENTIVE AWARD, which tax liability is subject to tax withholding under
applicable tax laws, and the RECIPIENT is obligated to pay the CORPORATION
an amount required to be withheld under applicable tax laws, the RECIPIENT
may satisfy the withholding tax obligation by (i) electing to have the
CORPORATION withhold such amount from his or her current compensation
through payroll deductions, or (ii) making a direct payment to the
CORPORATION in cash or by check.
The COMMITTEE may, in its sole discretion, permit a RECIPIENT to satisfy
all or part of his or her withholding tax obligations by having the
CORPORATION withhold from the shares to be issued to the RECIPIENT that
number of shares having a FAIR MARKET VALUE equal to the amount required to
be withheld
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determined on the date when taxes otherwise would be withheld in cash. The
payment of withholding taxes in this manner, if permitted by the COMMITTEE,
shall be subject to such restrictions as the COMMITTEE may impose,
including any restrictions required by rules of the Securities and Exchange
Commission.
12. Replacement of Grants
---------------------
The COMMITTEE may, in its sole discretion, offer a RECIPIENT (other than
NON-EMPLOYEE DIRECTORS) the option of surrendering an unexercised OPTION or
other INCENTIVE AWARD in exchange for another INCENTIVE AWARD of the same
type or for a different type of INCENTIVE AWARD; provided, however, that no
OPTION or INCENTIVE AWARD may be exchanged for a new OPTION or INCENTIVE
AWARD having an OPTION PRICE or purchase price that is lower than the
OPTION PRICE or purchase price of the original OPTION or INCENTIVE AWARD.
13. Deferral of Payments
--------------------
The COMMITTEE may, in its sole discretion, approve a RECIPIENT'S deferral
of any cash payments which may become due under the PROGRAM. Such deferrals
shall be subject to any conditions, restrictions or requirements as the
COMMITTEE may determine.
14. Adjustments Upon Changes in Number or Value of Shares of Common Stock
---------------------------------------------------------------------
If there are any changes in the number or value of shares of COMMON STOCK
by reason of stock dividends, stock splits, reverse stock splits,
recapitalizations, mergers, consolidations or other events that materially
increase or decrease the number or value of issued and outstanding shares
of COMMON STOCK, the COMMITTEE may make such adjustments as it shall deem
appropriate, in order to prevent dilution or enlargement of rights.
15. Non-Transferability of Incentive Awards
---------------------------------------
An INCENTIVE AWARD shall not be transferable by the RECIPIENT otherwise
than by will or the laws of descent and distribution, or pursuant to a
qualified domestic relations order as defined by the CODE, Title I of ERISA
or the rules thereunder. During the lifetime of the RECIPIENT, an INCENTIVE
AWARD may be exercised only by the RECIPIENT or by an alternate payee under
a qualified domestic relations order.
16. Change in Control
-------------------
Upon the occurrence of a CHANGE IN CONTROL (as defined below):
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(a) Any time periods relating to the exercise or realization of any
INCENTIVE AWARD granted hereunder shall be accelerated so that such
INCENTIVE AWARD may be immediately exercised or realized in full;
(b) All shares of RESTRICTED STOCK granted hereunder shall immediately
cease to be forfeitable; and
(c) All conditions relating to the realization of any STOCK-BASED AWARD
granted hereunder shall immediately terminate.
A "CHANGE IN CONTROL" shall be deemed to have occurred if:
(a) any "person" (as such term is used in Sections 13(d) and 14(d)(2) of
the EXCHANGE ACT, but excluding any benefit plan for EMPLOYEES or any
trustee, agent or other fiduciary for any such plan acting in such
person's capacity as such fiduciary), directly or indirectly, becomes
the beneficial owner of securities of the CORPORATION representing
twenty percent (20%) or more of the combined voting power of the
CORPORATION's then outstanding securities;
(b) during any two consecutive years, individuals who at the beginning of
such a period constitute the BOARD OF DIRECTORS cease for any reason
to constitute at least a majority of the BOARD OF DIRECTORS, unless
the election, or the nomination for election by the shareholders of
the CORPORATION, of each new DIRECTOR was approved by a vote of at
least two-thirds (2/3) of the DIRECTORS then still in office who were
DIRECTORS at the beginning of the period; or
(c) the shareholders of the CORPORATION shall have approved (i) any
consolidation or merger of the CORPORATION other than a merger or
consolidation which would result in the voting securities of the
CORPORATION outstanding immediately prior thereto continuing to
represent (either by remaining outstanding or by being converted into
voting securities of the surviving entity or any parent of such
surviving entity) at least 70 percent of the Combined Voting Power of
the CORPORATION, such surviving entity or the parent of such surviving
entity outstanding immediately after the merger or consolidation; (ii)
any sale, lease, exchange or other transfer (in one transaction or a
series of related transactions) of all or substantially all of the
assets of the CORPORATION, or (iii) any plan or proposal for the
liquidation or dissolution of the CORPORATION. For purposes of this
paragraph, the term Combined Voting Power shall mean the combined
voting power of the CORPORATION's or other relevant entity's then
outstanding voting securities.
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17. Listing and Registration of Shares
----------------------------------
Each INCENTIVE AWARD shall be subject to the requirement that if at any
time the COMMITTEE shall determine, in its discretion, that the listing,
registration or qualification of the shares covered thereby under any
securities exchange or under any state or federal law or the consent or
approval of any governmental regulatory body, including the California
Public Utilities Commission, is necessary or desirable as a condition of,
or in connection with, the granting of such INCENTIVE AWARD or the issue or
purchase of shares thereunder, such INCENTIVE AWARD may not be exercised in
whole or in part unless and until such listing, registration,
qualification, consent or approval shall have been effected or obtained
free of any conditions not acceptable to the COMMITTEE.
18. Amendment and Termination of the Program and Incentive Awards
-------------------------------------------------------------
The BOARD OF DIRECTORS or the COMMITTEE may at any time suspend, terminate,
modify or amend the PROGRAM in any respect; provided, however, that to the
extent necessary and desirable to comply with Section 422 of the CODE (or
any other applicable law or regulation, including the requirements of any
stock exchange on which the COMMON STOCK is listed or quoted), shareholder
approval of any PROGRAM amendment shall be obtained in such a manner and to
such a degree as is required by the applicable law or regulation.
No suspension, termination, modification or amendment of the PROGRAM may,
without the consent of the RECIPIENT, adversely affect his or her rights
under INCENTIVE AWARDS theretofore granted to such RECIPIENT. In the event
of amendments to the CODE or applicable rules or regulations relating to
ISOS subsequent to the date hereof, the CORPORATION may amend the PROGRAM,
and the CORPORATION and RECIPIENTS holding OPTION agreements may agree to
amend outstanding OPTION agreements, to conform to such amendments.
The BOARD OF DIRECTORS or COMMITTEE may make such amendments or
modifications in the terms and conditions of any INCENTIVE AWARD as it may
deem advisable, or cancel or annul any grant of an INCENTIVE AWARD;
provided, however, that no such amendment, modification, cancellation or
annulment may, without the consent of the RECIPIENT, adversely affect his
or her rights under such INCENTIVE AWARD; and provided further the BOARD OF
DIRECTORS or COMMITTEE may not reduce the OPTION PRICE or purchase price of
any OPTION or INCENTIVE AWARD below the original OPTION PRICE or purchase
price.
Notwithstanding the foregoing, the BOARD OF DIRECTORS or COMMITTEE reserves
the right, in its sole discretion, to (i) convert any outstanding ISOS to
NON-QUALIFIED STOCK OPTIONS, (ii) to require a RECIPIENT to forfeit any
unexercised or unpurchased INCENTIVE AWARDS, any shares received or
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purchased pursuant to an INCENTIVE AWARD, or any gains realized by virtue
of the receipt of an INCENTIVE AWARD in the event that such RECIPIENT
competes against the CORPORATION, and (iii) to cancel or annul any grant of
an INCENTIVE AWARD in the event of a RECIPIENT'S TERMINATION FOR CAUSE. For
purposes of the PROGRAM, "TERMINATION FOR CAUSE" shall include, but not be
limited to, termination because of dishonesty, criminal offense or
violation of a work rule, and shall be determined by, and in the sole
discretion of, the BOARD OF DIRECTORS or COMMITTEE.
19. Effective Date of the Program and Duration
------------------------------------------
The Program first became effective as of January 1, 1992. The first
amendment and restatement of the PROGRAM as of January 1, 1996, was
approved by the shareholders of Pacific Gas and Electric Company at its
Annual Meeting on April 17, 1996. Effective January 1, 1997, the PROGRAM
was assumed by PG&E CORPORATION. At its meeting on December 17, 1997, the
BOARD OF DIRECTORS amended and restated the PROGRAM effective January 1,
1998, to (i) reflect the adoption of new RULE 16B-3 which became effective
November 1, 1996, and (ii) provide automatic formula awards of NON-
QUALIFIED STOCK OPTIONS and PHANTOM STOCK to NON-EMPLOYEE DIRECTORS within
the limits of the PROGRAM as previously approved by shareholders in 1996.
The COMMITTEE amended Section 16 of the PROGRAM to revise the definition of
CHANGE IN CONTROL on October 21, 1998. Unless terminated sooner pursuant to
Section 16 hereof, the PROGRAM shall terminate on December 31, 2005.
20. Definitions
-----------
(a) BOARD OF DIRECTORS means the Board of Directors of PG&E CORPORATION.
------------------
(b) CHANGE IN CONTROL has the meaning set forth in Section 16 hereof.
-----------------
(c) CHIEF EXECUTIVE OFFICER means the Chief Executive Officer of PG&E
-----------------------
CORPORATION.
(d) CODE means the Internal Revenue Code of 1986, as amended from time to
----
time.
(e) COMMITTEE means the Nominating and Compensation Committee of the BOARD
---------
OF DIRECTORS or any successor to such committee.
(f) COMMON STOCK means common shares of PG&E CORPORATION with no par value
------------
and any class of common shares into which such common shares hereafter
may be converted.
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(g) CONSULTANT means any person, including an advisor, who is engaged by
----------
the CORPORATION to render services.
(h) CORPORATION means PG&E CORPORATION, and any parent corporation (as
-----------
defined in Section 424(e) of the CODE) or subsidiary corporation (as
defined in Section 424(f) of the CODE).
(i) DIRECTOR means any person who is a member of the BOARD OF DIRECTORS or
--------
the Board of Directors of any parent corporation (as defined in
Section 424(e) of the CODE) which may hereafter be established,
including an advisory, emeritus or honorary director.
(j) DIRECTOR RESTRICTED STOCK means RESTRICTED STOCK granted to a NON-
-------------------------
EMPLOYEE DIRECTOR under the NON-EMPLOYEE DIRECTOR STOCK INCENTIVE
PLAN.
(k) DIVIDEND EQUIVALENT means a right that entitles the RECIPIENT to
-------------------
receive cash or COMMON STOCK based on the dividends declared on the
COMMON STOCK covered by such right.
(l) ELIGIBLE PARTICIPANT means any KEY EMPLOYEE. It also means, if so
--------------------
identified by the COMMITTEE (or by the CHIEF EXECUTIVE OFFICER, in the
case of INCENTIVE AWARDS granted by the CHIEF EXECUTIVE OFFICER to
certain ELIGIBLE PARTICIPANTS pursuant to Section 2 hereof), other
EMPLOYEES, DIRECTORS, CONSULTANTS, employees or consultants of any
affiliates of PG&E CORPORATION, and other persons whose participation
in the PROGRAM is deemed by the COMMITTEE (or by the CHIEF EXECUTIVE
OFFICER, in the case of INCENTIVE AWARDS granted by the CHIEF
EXECUTIVE OFFICER to certain ELIGIBLE PARTICIPANTS pursuant to Section
2 hereof) to be in the best interests of the CORPORATION.
(m) EMPLOYEE means any person who is employed by the CORPORATION. The
--------
payment of a director's fee or consulting fee by the CORPORATION shall
not be sufficient to constitute "employment" by the CORPORATION.
(n) ERISA means the Employee Retirement Income Security Act of 1974, as
-----
amended.
(o) EXCHANGE ACT means the Securities Exchange Act of 1934, as amended.
------------
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(p) FAIR MARKET VALUE means the closing price of the COMMON STOCK reported
-----------------
on the New York Stock Exchange Composite Transactions for the date
specified for determining such value.
(q) INCENTIVE AWARD means any ISO, NON-QUALIFIED STOCK OPTION, SAR,
---------------
DIVIDEND EQUIVALENT, PERFORMANCE UNIT or other STOCK-BASED AWARD
granted under the PROGRAM.
(r) ISO means an OPTION intended to qualify as an incentive stock option
---
under Section 422 of the CODE.
(s) KEY EMPLOYEE means the Corporate Secretary, Treasurer, Vice Presidents
------------
and other executive officers of PG&E CORPORATION above the rank of
Vice President. It also means, if so identified by the COMMITTEE (or
by the CHIEF EXECUTIVE OFFICER, in the case of INCENTIVE AWARDS
granted by the CHIEF EXECUTIVE OFFICER to certain ELIGIBLE
PARTICIPANTS pursuant to Section 2 hereof), executive officers of
wholly-owned subsidiaries of PG&E CORPORATION (including subsidiaries
which become such after adoption of the PROGRAM) and any other key
management employee of PG&E CORPORATION or any wholly-owned subsidiary
of PG&E CORPORATION.
(t) LSAR means a limited stock appreciation right which is exercisable
----
only in the event of a CHANGE IN CONTROL.
(u) 1986 OPTION PLAN means the Pacific Gas and Electric Company 1986
----------------
Stock Option Plan, as amended to date.
(v) NON-EMPLOYEE DIRECTOR means a DIRECTOR who is not an EMPLOYEE.
--------------------
(w) NON-EMPLOYEE DIRECTOR STOCK INCENTIVE PLAN RULES means the Non-
------------------------------------------------
Employee Director Stock Incentive Plan attached hereto as Exhibit C or
any successor rules which the BOARD OF DIRECTORS may adopt from time
to time with respect to the grant of INCENTIVE AWARDS to NON-EMPLOYEE
DIRECTORS under the PROGRAM.
(x) NON-QUALIFIED STOCK OPTION means any OPTION which is not an ISO.
--------------------------
(y) OPTION means an option to purchase shares of COMMON STOCK granted
------
under the STOCK OPTION PLAN.
(z) OPTION PRICE means the purchase price for the COMMON STOCK upon
------------
exercise of an OPTION.
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(aa) PERFORMANCE UNIT means a performance unit granted under the
----------------
PERFORMANCE UNIT PLAN.
(bb) PERFORMANCE UNIT PLAN means the Performance Unit Plan Rules attached
---------------------
hereto as Exhibit B or any successor rules which the COMMITTEE may
adopt from time to time with respect to the grant of PERFORMANCE UNITS
under the PROGRAM.
(cc) PG&E CORPORATION means PG&E CORPORATION, a California corporation.
----------------
(dd) PHANTOM STOCK means allocated hypothetical shares of COMMON STOCK that
-------------
can be converted at a future date into cash or stock.
(ee) PROGRAM means the PG&E Corporation Long-Term Incentive Program as
-------
amended and restated herein and as may be amended from time to time.
(ff) RECIPIENT means the ELIGIBLE PARTICIPANT receiving the INCENTIVE
---------
AWARD, or his or her legal representative, legatees, distributees or
alternate payees, as the case may be.
(gg) RESTRICTED STOCK means COMMON STOCK that is subject to forfeiture by
----------------
the RECIPIENT to the CORPORATION under such circumstances as may be
specified by the COMMITTEE in its sole discretion.
(hh) RETIREMENT means the Actual Retirement Date under the Pacific Gas and
----------
Electric Company Retirement Plan.
(ii) RULE 16b-3 means Rule 16b-3 under the EXCHANGE ACT or any successor to
----------
Rule 16b-3, as in effect when discretion is being exercised with
respect to the Plan.
(jj) SAR means a stock appreciation right whose value is based on the
---
increase in the FAIR MARKET VALUE of the COMMON STOCK covered by such
right.
(kk) SECTION 16 OFFICER means any person who is designated by the BOARD OF
------------------
DIRECTORS as an executive officer of PG&E CORPORATION and any other
person who is designated as an officer of PG&E CORPORATION for
purposes of Section 16 of the EXCHANGE ACT.
(ll) STOCK-BASED AWARD means any award that is valued in whole or in part
-----------------
by reference to, or is otherwise based on, the COMMON STOCK,
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including, but not limited to, stock grants, RESTRICTED STOCK, LSARS
and PHANTOM STOCK.
(mm) STOCK OPTION PLAN means the Stock Option Plan Rules attached hereto as
-----------------
Exhibit A or any successor rules which the COMMITTEE may adopt from
time to time with respect to the grant of OPTIONS under the PROGRAM.
(nn) TANDEM refers to an INCENTIVE AWARD granted in conjunction with
------
another INCENTIVE AWARD.
(oo) TERMINATION occurs when an EMPLOYEE ceases to be employed by the
-----------
CORPORATION as a common law employee, when a DIRECTOR ceases to be a
member of the BOARD OF DIRECTORS or the Board of Directors of any
parent corporation which may hereafter be established (as the case may
be), or when the relationship between the CORPORATION and a CONSULTANT
or other ELIGIBLE PARTICIPANT terminates, as the case may be.
(pp) TERMINATION FOR CAUSE has the meaning set forth in Section 18 hereof.
---------------------
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EXHIBIT A
PG&E CORPORATION
STOCK OPTION PLAN
(As amended and restated effective as of October 21, 1998)
1. Purpose of the Plan
-------------------
This is the controlling and definitive statement of the PG&E Corporation
Stock Option Plan, as amended and restated herein (hereinafter called the
PLAN/2/). The purpose of the PLAN is to advance the interests of the
CORPORATION by providing ELIGIBLE PARTICIPANTS with financial incentives to
promote the success of its long-term (five to ten years) business
objectives, and to increase their proprietary interest in the success of
the CORPORATION. It is the intent of the CORPORATION to reward those
ELIGIBLE PARTICIPANTS who have a significant impact on improved long-term
corporate achievements. Inasmuch as the PLAN is designed to encourage
financial performance and to improve the value of shareholders' investment
in PG&E CORPORATION, the costs of the PLAN will be funded from corporate
earnings.
2. Plan Administration
-------------------
The PLAN shall be administered by the COMMITTEE, which shall be constituted
in such a manner as to comply with the rules governing a plan intended to
qualify as a discretionary plan under RULE 16b-3.
Subject to the provisions of the PLAN, the COMMITTEE shall have full and
final authority, in its sole discretion:
(a) to determine the ELIGIBLE PARTICIPANTS to whom OPTIONS shall be
granted and the number of shares of COMMON STOCK to be awarded under
each OPTION, based on the recommendation of the CHIEF EXECUTIVE
OFFICER (except that awards to the CHIEF EXECUTIVE OFFICER shall be
shall be based on the recommendation of the BOARD OF DIRECTORS);
provided, however, that the number of shares of COMMON STOCK to be
awarded under each OPTION shall be subject to the limitations
specified in Section 5 hereof;
(b) to determine the time or times at which OPTIONS shall be granted;
- --------------------------
/2/ Capitalized words are defined in Section 20 hereof.
14
<PAGE>
(c) to designate the OPTIONS being granted as ISOS or NON-QUALIFIED STOCK
OPTIONS;
(d) to vary the OPTION vesting schedule described in Section 11 hereof;
(e) to determine the terms and conditions, not inconsistent with the terms
of the PLAN, of any OPTION granted hereunder (including, but not
limited to, the consideration and method of payment for shares
purchased upon the exercise of an OPTION, and any vesting acceleration
or exercisability provisions in the event of a CHANGE IN CONTROL or
TERMINATION), based in each case on such factors as the COMMITTEE
shall deem appropriate;
(f) to approve forms of agreement for use under the PLAN;
(g) to construe and interpret the PLAN and any related OPTION agreement
and to define the terms employed herein and therein;
(h) except as provided in Section 18 hereof, to modify or amend any OPTION
or to waive any restrictions or conditions applicable to any OPTION or
the exercise thereof;
(i) except as provided in Section 18 hereof, to prescribe, amend and
rescind rules, regulations and policies relating to the administration
of the PLAN;
(j) except as provided in Section 18 hereof, to suspend, terminate, modify
or amend the PLAN;
(k) to delegate to one or more agents such administrative duties as the
COMMITTEE may deem advisable, to the extent permitted by applicable
law; and
(l) to make all other determinations and take such other action with
respect to the PLAN and any OPTION granted hereunder as the COMMITTEE
may deem advisable, to the extent permitted by applicable law.
Notwithstanding the provisions contained in the foregoing paragraph, the
CHIEF EXECUTIVE OFFICER shall have the authority, in his sole discretion:
(a) to grant OPTIONS to any ELIGIBLE PARTICIPANT who, at the time of the
OPTION grant, (i) is not an officer of the CORPORATION or a DIRECTOR, and
(ii) if such ELIGIBLE PARTICIPANT is an EMPLOYEE, is receiving an annual
salary which is below the level which requires approval by the COMMITTEE;
(b) to determine the time or times at which OPTIONS shall be granted to
such ELIGIBLE PARTICIPANTS; (c) to designate the OPTIONS being granted to
such ELIGIBLE PARTICIPANTS as ISOS or NON-QUALIFIED STOCK
15
<PAGE>
OPTIONS; and (d) to vary the OPTION vesting schedule described in Section
11 hereof for the OPTIONS granted to such ELIGIBLE PARTICIPANTS; provided,
however, that (x) all grants of OPTIONS by the CHIEF EXECUTIVE OFFICER
shall conform to the guidelines previously approved by the COMMITTEE, and
(y) the number of shares of COMMON STOCK to be awarded under each OPTION
shall be subject to the limitations specified in Section 5 hereof.
3. Shares of Stock Subject to the Plan
-----------------------------------
There shall be reserved for use under the PLAN and for the grant of any
other incentive awards pursuant to the PROGRAM (subject to the provisions
of Section 14 hereof) a total of 23,389,230 shares of COMMON STOCK, which
shares may be authorized but unissued shares of COMMON STOCK or issued
shares of COMMON STOCK which shall have been reacquired by PG&E
CORPORATION.
If any OPTION expires or terminates for any reason without having been
exercised in full, then any unexercised, shares which were subject to such
OPTION (except shares as to which a related TANDEM SAR has been exercised)
shall again be available for the future grant of OPTIONS under the PLAN
(unless the PLAN has terminated). In addition, shares may be reused or
added back to the PLAN to the extent permitted by applicable law.
4. Eligibility
-----------
OPTIONS will be granted only to ELIGIBLE PARTICIPANTS. ISOS will be
granted only to EMPLOYEES. The COMMITTEE, in its sole discretion, may
grant OPTIONS to an ELIGIBLE PARTICIPANT who is a resident or citizen of a
foreign country, with such modifications as the COMMITTEE may deem
advisable to reflect the laws, tax policy or customs of such foreign
country.
The PLAN shall not confer upon any OPTIONEE any right to continuation of
employment, service as a DIRECTOR or consulting relationship with the
CORPORATION; nor shall it interfere in any way with the right of the
OPTIONEE or the CORPORATION to terminate such employment, service as a
DIRECTOR or consulting relationship at any time, with or without cause.
5. Limitation on Options and SARs Awarded to Any Eligible Participant
------------------------------------------------------------------
The aggregate number of shares of COMMON STOCK with respect to which any
ELIGIBLE PARTICIPANT may be granted OPTIONS and SARS under the PLAN during
any calendar year shall in no event exceed two percent (2%) of the total
number of shares reserved for use under the PLAN.
16
<PAGE>
6. Designation of Options
----------------------
At the time of the grant of each OPTION under the PLAN, the COMMITTEE (or
the CHIEF EXECUTIVE OFFICER, in the case of OPTIONS granted by the CHIEF
EXECUTIVE OFFICER to certain ELIGIBLE PARTICIPANTS pursuant to Section 2
hereof) shall determine whether such OPTION is to be designated as an ISO
or a NON-QUALIFIED STOCK OPTION; provided, however, that ISOS may be
granted only to EMPLOYEES.
Notwithstanding such designation, to the extent that the aggregate FAIR
MARKET VALUE (determined for each share as of the date of grant of the
OPTION covering each share) of the shares with respect to which OPTIONS
designated as ISOS become exercisable for the first time by any OPTIONEE
during any calendar year exceeds $100,000, such OPTIONS shall be treated as
NON-QUALIFIED STOCK OPTIONS.
7. Option Price
------------
The OPTION PRICE of the COMMON STOCK under each OPTION issued shall be the
FAIR MARKET VALUE of the COMMON STOCK on the date of grant.
8. Stock Appreciation Rights
-------------------------
At the discretion of the COMMITTEE, an OPTION may be granted with or
without a TANDEM SAR which permits the OPTIONEE to surrender unexercised an
OPTION or portion thereof and to receive in exchange a payment having a
value equal to the difference between (x) the FAIR MARKET VALUE of the
COMMON STOCK covered by the surrendered portion of the OPTION on the date
the SAR is exercised and (y) the OPTION PRICE for such COMMON STOCK. The
SAR is subject to the same terms and conditions as the related OPTION,
except that (i) the SAR may be exercised only when there is a positive
spread (i.e., when the FAIR MARKET VALUE of the COMMON STOCK subject to the
OPTION exceeds the OPTION PRICE), (ii) in accordance with Section 9 hereof,
payment of the DEA (if any) to the OPTIONEE may be restricted, and (iii) if
the OPTIONEE is a SECTION 16 OFFICER, DIRECTOR or other person whose
transactions in the COMMON STOCK are subject to Section 16(b) of the
EXCHANGE ACT, the SAR may be exercised only during the period beginning on
the third (3rd) business day following the date of release of the
CORPORATION's quarterly or annual statement of earnings and ending on the
twelfth (12th) business day following such date. Upon the exercise of a
SAR, the number of shares subject to exercise under the related OPTION
shall be automatically reduced by the number of shares represented by the
OPTION or portion thereof surrendered. No payment will be required from
the OPTIONEE
17
<PAGE>
upon the exercise of a SAR, except that any amount necessary to satisfy
applicable federal, state or local tax requirements shall be withheld.
9. Dividend Equivalent Account
---------------------------
At the discretion of the COMMITTEE, an OPTION may be granted with or
without TANDEM DIVIDEND EQUIVALENTS. When an OPTION is granted with TANDEM
DIVIDEND EQUIVALENTS, a Dividend Equivalent Account ("DEA") shall be
established for the OPTIONEE. This DEA shall be credited quarterly on each
dividend record date with dividends which would have been paid on the
COMMON STOCK subject to the unexercised portion of the OPTION (including
any portion which has not yet vested on the record date), if such portion
had been exercised. Except as provided in Section 12(d) hereof, at the
time the OPTION or any related SAR is exercised, the OPTIONEE shall receive
all funds which have accumulated in the DEA with respect to the shares of
COMMON STOCK for which the OPTION or SAR is being exercised; provided,
however, that if the OPTIONEE exercises a SAR, such DEA funds shall only be
paid to the OPTIONEE if (i) the percentage increase in the FAIR MARKET
VALUE of the COMMON STOCK over the OPTION PRICE averages at least five
percent (5%) per year for the first five (5) years after the grant, or (ii)
in the case of OPTIONS held for longer than five (5) years from the date of
grant, such FAIR MARKET VALUE has increased by at least twenty-five percent
(25%) over the OPTION PRICE.
10. Terms of Options
----------------
The term of each ISO shall be for ten (10) years from the date of grant,
subject to earlier termination as provided in Section 12 hereof. The term
of each NON-QUALIFIED STOCK OPTION shall be ten (10) years and one (1) day
from the date of grant, subject to earlier termination as provided in
Section 12 hereof. Any provision of the PROGRAM to the contrary
notwithstanding, no OPTION shall be exercised after the time limitations
stated in this Section 10.
11. Limitations on Exercise
-----------------------
(a) Each OPTION granted under the PROGRAM shall become exercisable and
vested only to the following extent: (i) up to one-third (1/3) of the
OPTIONS granted may be exercised on or after the second (2nd)
anniversary of the date of grant; (ii) up to two-thirds (2/3) of the
OPTIONS granted may be exercised on or after the third (3rd)
anniversary of the date of grant; and (iii) up to one hundred percent
(100%) of the OPTIONS granted may be exercised on or after the fourth
(4th) anniversary of the date of grant.
18
<PAGE>
(b) No OPTION under the PROGRAM designated by the COMMITTEE as an ISO and
granted before January 1, 1987 may be exercised while there is
outstanding in the hands of the OPTIONEE any ISO which was granted
before the granting of the ISO hereunder sought to be exercised. For
this purpose an ISO shall be treated as outstanding until such OPTION
is (i) exercised in full, (ii) surrendered in full by exercising SARS
pursuant to Section 8 hereof, or (iii) rendered void by reason of
lapse of time.
12. Termination of Employment or Relationship with the CORPORATION
--------------------------------------------------------------
(a) In the event of a TERMINATION by reason of a discharge or TERMINATION
FOR CAUSE, any unexercised OPTIONS theretofore granted to an OPTIONEE
under the PROGRAM shall forthwith terminate.
(b) In the event of a TERMINATION by reason of RETIREMENT, all OPTIONS
held by the OPTIONEE, to the extent that such OPTIONS have not
previously expired or been exercised, shall become fully exercisable
and vested, notwithstanding the provisions of Section 11(a) hereof,
and the OPTIONEE shall have the right to exercise such OPTIONS in full
at any time within their respective terms or within five (5) years
after such RETIREMENT, whichever is shorter. This five-year period
shall be extended if an OPTIONEE remains on the BOARD OF DIRECTORS
after RETIREMENT. In such case, the OPTIONS may be exercised as long
as the OPTIONEE remains a DIRECTOR and for a period of six (6) months
thereafter, or within five (5) years after RETIREMENT, whichever is
longer; provided, however, that no OPTION may be exercised after the
expiration of its term. To the extent any ISO held by the OPTIONEE is
exercised after the expiration of three (3) months after such
TERMINATION, the exercise will be deemed to involve the exercise of a
NON-QUALIFIED STOCK OPTION.
(c) In the event of a TERMINATION by reason of disability or death, all
OPTIONS held by the OPTIONEE, to the extent that such OPTIONS have not
previously expired or been exercised, shall become fully exercisable
and vested, notwithstanding the provisions of Section 11(a) hereof,
and the OPTIONEE (or the OPTIONEE'S estate or a person who acquired
the right to exercise such OPTIONS by bequest or inheritance) shall
have the right to exercise such OPTIONS at any time within their
respective terms or within one (1) year after the date of such
TERMINATION, whichever is shorter. The term "disability" shall, for
the purposes of the PLAN, be defined in Section 22(e)(3) of the CODE.
(d) In the event of a TERMINATION by reason of a divestiture or change in
control of a subsidiary of PG&E CORPORATION, which divestiture or
change in control results in such subsidiary no longer qualifying as
a
19
<PAGE>
subsidiary corporation under Section 424(f) of the CODE, all OPTIONS
held by the OPTIONEE, to the extent that such OPTIONS have not
previously expired or been exercised, shall become fully exercisable
and vested, notwithstanding the provisions of Section 11(a) hereof,
and the OPTIONEE shall have the right to exercise such OPTIONS in full
at any time within their respective terms or within three (3) years
after such TERMINATION, whichever is shorter. This three-year period
shall be extended if an OPTIONEE remains on the BOARD OF DIRECTORS
after such TERMINATION. In such case, the OPTIONS may be exercised as
long as the OPTIONEE remains a DIRECTOR and for a period of six (6)
months thereafter, or within three (3) years after such TERMINATION,
whichever is longer; provided, however, that no OPTION may be
exercised after the expiration of its term. To the extent any ISO held
by the OPTIONEE is exercised after the expiration of three (3) months
after such TERMINATION, the exercise will be deemed to involve the
exercise of a NON-QUALIFIED STOCK OPTION.
(e) In the event of a TERMINATION within one year after a CHANGE IN
CONTROL of the CORPORATION (other than a TERMINATION covered by
clauses (a), (b), or (c) above), OPTIONEE shall have the right to
exercise OPTIONS which OPTIONEE then holds (which OPTIONS will have
been accelerated previously in accordance with Section 16 below), to
the extent that such OPTIONS have not previously expired or been
exercised, in full at any time within their respective terms or within
three (3) years after such TERMINATION, whichever is shorter. This
three-year period shall be extended if an OPTIONEE remains on the
BOARD OF DIRECTORS after such TERMINATION. In such case, the OPTIONS
may be exercised as long as the OPTIONEE remains a DIRECTOR and for a
period of six (6) months thereafter, or within three (3) years after
such TERMINATION, whichever is longer; provided, however, that no
OPTION may be exercised after the expiration of its term. To the
extent any ISO held by the OPTIONEE is exercised after the expiration
of three (3) months after such TERMINATION, the exercise will be
deemed to involve the exercise of a NON-QUALIFIED STOCK OPTION.
(f) In the event of a TERMINATION for any reason other than those
specified in subparagraphs (a) through (e) above, (i) any unexercised
OPTION or OPTIONS granted under the PROGRAM shall be deemed canceled
and terminated forthwith, except that the OPTIONEE may exercise any
unexercised OPTIONS theretofore granted which are otherwise
exercisable and vested within the provisions of Section 11(a) hereof,
during the balance of their respective terms or within thirty (30)
days of such TERMINATION, whichever is shorter, and (ii) the DEA (if
20
<PAGE>
any) shall not be credited with any dividends paid after the date of
such TERMINATION.
(g) Notwithstanding the provisions of subparagraphs (a) through (f) above,
the COMMITTEE may, in its sole discretion, establish different terms
and conditions pertaining to the effect of TERMINATION, to the extent
permitted by applicable federal and state law.
13. Payment for Shares Upon Exercise of Options
-------------------------------------------
The exercise of any OPTION shall be contingent upon receipt by the
CORPORATION of (i) cash (including any DEA funds payable to the OPTIONEE in
connection with the exercise of such OPTION), (ii) check, (iii) shares of
COMMON STOCK, (iv) an executed exercise notice together with irrevocable
instructions to a broker to either sell the shares subject to the OPTION or
hold such shares as collateral for a margin loan and to promptly deliver to
the CORPORATION the amount of sale or loan proceeds required to pay the
OPTION PRICE, (v) any combination of the foregoing in an amount equal to
the full OPTION PRICE of the shares being purchased, or (vi) such other
consideration and method of payment, other than a note from the OPTIONEE,
as the COMMITTEE, in its sole discretion, may allow (which, in the case of
an ISO shall be determined at the time of grant), to the extent permitted
by applicable law. For purposes of this paragraph, shares of COMMON STOCK
that are delivered in payment of the OPTION PRICE must have been previously
owned by the OPTIONEE for a minimum of one year, and shall be valued at
their FAIR MARKET VALUE as of the date of the exercise of the OPTION. The
CORPORATION shall not make loans to any OPTIONEE for the purpose of
exercising OPTIONS.
14. Adjustments Upon Changes in Number or Value of Shares of Common Stock
---------------------------------------------------------------------
If there are any changes in the number or value of shares of COMMON STOCK
by reason of stock dividends, stock splits, reverse stock splits,
recapitalizations, mergers, consolidations or other events that materially
increase or decrease the number or value of issued and outstanding shares
of COMMON STOCK, the COMMITTEE may make such adjustments as it shall deem
appropriate, in order to prevent dilution or enlargement of rights.
15. Non-Transferability of Options
------------------------------
An OPTION shall not be transferable by the OPTIONEE otherwise than by will
or the laws of descent and distribution, or pursuant to a qualified
domestic relations order as defined by the CODE, Title I of ERISA or the
rules thereunder. During the lifetime of the OPTIONEE, an OPTION may be
exercised only by the OPTIONEE or by an alternate payee under a qualified
domestic relations order.
21
<PAGE>
16. Change in Control
-----------------
Upon the occurrence of a CHANGE IN CONTROL (as defined below), any time
periods relating to the exercise of any OPTION granted hereunder shall be
accelerated so that such OPTION may be immediately exercised in full.
A "CHANGE IN CONTROL" shall be deemed to have occurred if:
(a) any "person" (as such term is used in Sections 13(d) and 14(d)(2) of
the EXCHANGE ACT, but excluding any benefit plan for EMPLOYEES or any
trustee, agent or other fiduciary for any such plan acting in such
person's capacity as such fiduciary), directly or indirectly, becomes
the beneficial owner of securities of PG&E CORPORATION representing
twenty percent (20%) or more of the combined voting power of the
CORPORATION's then outstanding securities;
(b) during any two consecutive years, individuals who at the beginning of
such a period constitute the BOARD OF DIRECTORS cease for any reason
to constitute at least a majority of the BOARD OF DIRECTORS, unless
the election, or the nomination for election by the shareholders of
the CORPORATION, of each new DIRECTOR was approved by a vote of at
least two-thirds (2/3) of the DIRECTORS then still in office who were
DIRECTORS at the beginning of the period; or
(c) the shareholders of the CORPORATION shall have approved (i) any
consolidation or merger of the CORPORATION other than a merger or
consolidation which would result in the voting securities of the
CORPORATION outstanding immediately prior thereto continuing to
represent (either by remaining outstanding or by being converted into
voting securities of the surviving entity or any parent of such
surviving entity) at least 70 percent of the Combined Voting Power of
the CORPORATION, such surviving entity or the parent of such surviving
entity outstanding immediately after the merger or consolidation; (ii)
any sale, lease, exchange or other transfer (in one transaction or a
series of related transactions) of all or substantially all of the
assets of the CORPORATION, or (iii) any plan or proposal for the
liquidation or dissolution of the CORPORATION. For purposes of this
paragraph, the term Combined Voting Power shall mean the combined
voting power of the CORPORATION's or other relevant entity's then
outstanding voting securities.
22
<PAGE>
17. Listing and Registration of Shares
----------------------------------
Each OPTION shall be subject to the requirement that if at any time the
COMMITTEE shall determine, in its discretion, that the listing,
registration or qualification of the shares covered thereby under any
securities exchange or under any state or federal law or the consent or
approval of any governmental regulatory body, including the California
Public Utilities Commission, is necessary or desirable as a condition of,
or in connection with, the granting of such OPTION or the issue or purchase
of shares thereunder, such OPTION may not be exercised in whole or in part
unless and until such listing, registration, qualification, consent or
approval shall have been effected or obtained free of any conditions not
acceptable to the COMMITTEE.
18. Amendment and Termination of the Plan and Options
-------------------------------------------------
The BOARD OF DIRECTORS or the COMMITTEE may at any time suspend, terminate,
modify or amend the PLAN in any respect; provided, however, that, to the
extent necessary and desirable to comply with Section 422 of the CODE (or
any other applicable law or regulation, including the requirements of any
stock exchange on which the COMMON STOCK is listed or quoted), shareholder
approval of any PLAN amendment shall be obtained in such a manner and to
such a degree as is required by the applicable law or regulation.
No suspension, termination, modification or amendment of the PLAN may,
without the consent of the OPTIONEE, adversely affect his or her rights
under OPTIONS theretofore granted to such OPTIONEE. In the event of
amendments to the CODE or applicable rules or regulations relating to ISOS
subsequent to the date hereof, the CORPORATION may amend the PLAN, and the
CORPORATION and OPTIONEES holding OPTION agreements may agree to amend
outstanding OPTION agreements, to conform to such amendments.
The COMMITTEE may make such amendments or modifications in the terms and
conditions of any OPTION as it may deem advisable, or cancel or annul any
grant of an OPTION; provided, however, that no such amendment,
modification, cancellation or annulment may, without the consent of the
OPTIONEE, adversely affect his or her rights under such OPTION; and
provided further the COMMITTEE may not reduce the OPTION PRICE or purchase
price of any OPTION or OPTION below the original OPTION PRICE or purchase
price.
Notwithstanding the foregoing, the COMMITTEE reserves the right, in its
sole discretion, to (i) convert any outstanding ISOS to NON-QUALIFIED STOCK
OPTIONS, (ii) to require a OPTIONEE to forfeit any unexercised or
unpurchased OPTIONS, any shares received or purchased pursuant to an
OPTION, or any gains realized by virtue of the receipt of an OPTION in the
event that such OPTIONEE competes against the CORPORATION, and (iii) to
cancel or annul
23
<PAGE>
any grant of an OPTION in the event of a OPTIONEE'S TERMINATION FOR CAUSE.
For purposes of the PROGRAM, "TERMINATION FOR CAUSE" shall include, but not
be limited to, termination because of dishonesty, criminal offense or
violation of a work rule, and shall be determined by, and in the sole
discretion of, the COMMITTEE.
19. Effective Date of the Plan and Duration
---------------------------------------
The PLAN first became effective as of January 1, 1992. It has since been
amended and restated. The amended and restated PLAN became effective as of
January 1, 1996, upon approval by the shareholders of Pacific Gas and
Electric Company at its Annual Meeting on April 17, 1996. Effective
January 1, 1997, the PLAN was assumed by PG&E CORPORATION. The COMMITTEE
amended and restated the PLAN effective October 21, 1998. Unless
terminated sooner pursuant to Section 18 hereof, the PLAN shall terminate
on December 31, 2005.
20. Definitions
-----------
(a) BOARD OF DIRECTORS means the Board of Directors of PG&E CORPORATION.
------------------
(b) CHANGE IN CONTROL has the meaning set forth in Section 16 hereof.
-----------------
(c) CHIEF EXECUTIVE OFFICER means the Chief Executive Officer of PG&E
-----------------------
CORPORATION.
(d) CODE means the Internal Revenue Code of 1986, as amended from time to
----
time.
(e) COMMITTEE means the Nominating and Compensation Committee of the BOARD
---------
OF DIRECTORS or any successor to such committee.
(f) COMMON STOCK means common shares of PG&E CORPORATION with no par value
------------
and any class of common shares into which such common shares hereafter
may be converted.
(g) CONSULTANT means any person, including an advisor, who is engaged by
----------
the CORPORATION to render services.
(h) CORPORATION means PG&E CORPORATION, and any parent corporation (as
-----------
defined in Section 424(e) of the CODE) or subsidiary corporation (as
defined in Section 424(f) of the CODE).
(i) DEA means a Dividend Equivalent Account described in Section 9 hereof.
---
24
<PAGE>
(j) DIRECTOR means any person who is a member of the BOARD OF DIRECTORS or
--------
the Board of Directors of any parent corporation (as defined in
Section 424(e) of the CODE) which may hereafter be established,
including an advisory, emeritus or honorary director.
(k) DIVIDEND EQUIVALENT means a right that entitles the OPTIONEE to
-------------------
receive cash or COMMON STOCK based on the dividends declared on the
COMMON STOCK covered by such right.
(l) ELIGIBLE PARTICIPANT means any KEY EMPLOYEE. It also means, if so
--------------------
identified by the COMMITTEE (or by the CHIEF EXECUTIVE OFFICER, in the
case of OPTIONS granted by the CHIEF EXECUTIVE OFFICER to certain
ELIGIBLE PARTICIPANTS pursuant to Section 2 hereof), other EMPLOYEES,
DIRECTORS, CONSULTANTS, employees or consultants of any affiliates of
PG&E CORPORATION, and other persons whose participation in the PROGRAM
is deemed by the COMMITTEE (or by the CHIEF EXECUTIVE OFFICER, in the
case of OPTIONS granted by the CHIEF EXECUTIVE OFFICER to certain
ELIGIBLE PARTICIPANTS pursuant to Section 2 hereof) to be in the best
interests of the CORPORATION; provided, however, that DIRECTORS who
are not EMPLOYEES shall not be ELIGIBLE PARTICIPANTS for purposes of
the PLAN.
(m) EMPLOYEE means any person who is employed by the CORPORATION. The
--------
payment of a director's fee or consulting fee by the CORPORATION shall
not be sufficient to constitute "employment" by the CORPORATION.
(n) ERISA means the Employee Retirement Income Security Act of 1974, as
-----
amended.
(o) EXCHANGE ACT means the Securities Exchange Act of 1934, as amended.
------------
(p) FAIR MARKET VALUE means the closing price of the COMMON STOCK reported
-----------------
on the New York Stock Exchange Composite Transactions for the date
specified for determining such value.
(q) ISO means an OPTION intended to qualify as an incentive stock option
---
under Section 422 of the CODE.
(r) KEY EMPLOYEE means the Corporate Secretary, Treasurer, Vice Presidents
------------
and other executive officers of PG&E CORPORATION above the rank of
Vice President. It also means, if so identified by the COMMITTEE (or
by the CHIEF EXECUTIVE OFFICER, in the case of
25
<PAGE>
OPTIONS granted by the CHIEF EXECUTIVE OFFICER to certain ELIGIBLE
PARTICIPANTS pursuant to Section 2 hereof), executive officers of
wholly-owned subsidiaries of PG&E CORPORATION (including subsidiaries
which become such after adoption of the PROGRAM) and any other key
management employee of PG&E CORPORATION or any wholly-owned subsidiary
of PG&E CORPORATION.
(s) NON-EMPLOYEE DIRECTOR means a DIRECTOR who is not an EMPLOYEE.
---------------------
(t) NON-QUALIFIED STOCK OPTION means any OPTION which is not an ISO.
--------------------------
(u) OPTION means an option to purchase shares of COMMON STOCK granted
------
under the PLAN.
(v) OPTIONEE means the ELIGIBLE PARTICIPANT receiving the OPTION, or his
--------
or her legal representative, legatees, distributees or alternate
payees, as the case may be.
(w) OPTION PRICE means the purchase price for the COMMON STOCK upon
------------
exercise of an OPTION.
(x) PG&E CORPORATION means PG&E CORPORATION, a California corporation.
----------------
(y) PLAN means this Stock Option Plan as amended and restated herein and
----
as may be amended from time to time, or any successor plan which the
COMMITTEE may adopt from time to time with respect to the grant of
OPTIONS under the PROGRAM.
(z) PROGRAM means the PG&E Corporation Long-Term Incentive Program, as
-------
amended and restated effective as of January 1, 1997, and as may be
amended from time to time, pursuant to which the PLAN is adopted.
(aa) RETIREMENT means the Actual Retirement Date under the Pacific Gas and
----------
Electric Company Retirement Plan.
(bb) RULE 16b-3 means Rule 16b-3 under the EXCHANGE ACT or any successor to
----------
Rule 16b-3, as in effect when discretion is being exercised with
respect to the PLAN.
26
<PAGE>
(cc) SAR means a stock appreciation right whose value is based on the
---
increase in the FAIR MARKET VALUE of the COMMON STOCK covered by such
right.
(dd) SECTION 16 OFFICER means any person who is designated by the BOARD OF
------------------
DIRECTORS as an executive officer of PG&E CORPORATION and any other
person who is designated as an officer of PG&E CORPORATION for
purposes of Section 16 of the EXCHANGE ACT.
(ee) TANDEM refers to a DIVIDEND EQUIVALENT or SAR (as the case may be)
------
granted in conjunction with an OPTION.
(ff) TERMINATION occurs when an EMPLOYEE ceases to be employed by the
-----------
CORPORATION as a common law employee, when a DIRECTOR ceases to be a
member of the BOARD OF DIRECTORS or the Board of Directors of any
parent corporation which may hereafter be established (as the case may
be), or when the relationship between the CORPORATION and a CONSULTANT
or other ELIGIBLE PARTICIPANT terminates, as the case may be.
(gg) TERMINATION FOR CAUSE has the meaning set forth in Section 12 hereof.
---------------------
27
<PAGE>
EXHIBIT B
PG&E CORPORATION
PERFORMANCE UNIT PLAN
(As amended and restated effective as of October 21, 1998)
This is the controlling and definitive statement of the Performance
Unit Plan ("PLAN"/3/) for ELIGIBLE EMPLOYEES of PG&E CORPORATION ("CORPORATION")
and such other companies, affiliates, subsidiaries, or associations as the BOARD
OF DIRECTORS may designate from time to time. The PLAN was first adopted by the
BOARD in 1989 and was effective January 1, 1990. It has since been amended from
time to time.
ARTICLE I
DEFINITIONS
-----------
1.01 Board of Directors or Board shall mean the BOARD OF DIRECTORS of
------------------
the CORPORATION or, when appropriate, any committee of the BOARD which has been
delegated the authority to take action with respect to the PLAN.
1.02 Committee shall mean the Nominating and Compensation Committee
---------
of the BOARD OF DIRECTORS.
1.03 Corporation shall mean PG&E CORPORATION, a California
-----------
corporation.
1.04 Eligible Employee shall mean employees of the CORPORATION who
-----------------
are officers at the vice presidential level or above, the corporate secretary,
the controller, and the treasurer of the CORPORATION, and such other employees
of the CORPORATION, other companies, affiliates, subsidiaries, or associations
as may be designated by the COMMITTEE.
1.05 Performance Targets shall mean the annual CORPORATION financial
-------------------
and operational goals adopted by the COMMITTEE to be used in determining awards
under the PLAN.
1.06 Plan shall mean the Performance Unit Plan ("PUP") as set forth
----
herein and as may be amended from time to time.
- ------------
/3/ Words in all capitals are defined in Article I.
28
<PAGE>
1.07 Plan Administrator shall mean the COMMITTEE or such individual
------------------
or individuals as that COMMITTEE may appoint to handle the day-to-day affairs of
the PLAN.
1.08 Price shall mean the average market price of STOCK for the last
-----
30-day period of the YEAR preceding the YEAR in which UNITS are payable.
1.09 PUP Units shall mean the units granted to ELIGIBLE EMPLOYEES who
---------
participate in the PLAN. A PUP UNIT has the equivalent value of the current
market price of a share of STOCK at the time of grant.
1.10 Stock shall mean the common stock of the CORPORATION and any
-----
class of common shares into which such STOCK hereafter may be converted.
1.11 Vesting Period shall mean the three calendar YEARS commencing
--------------
with the YEAR in which PUP UNITS are granted.
1.12 Year shall mean a calendar year.
----
ARTICLE II
2.01 Prior to the beginning of each YEAR, the COMMITTEE shall
determine whether PUP UNITS will be granted for such YEAR, the ELIGIBLE
EMPLOYEES to whom PUP UNITS will be granted, and the number of PUP UNITS to be
granted to each ELIGIBLE EMPLOYEE. Employees who become ELIGIBLE EMPLOYEES
after the beginning of a YEAR shall be entitled to a prorata grant of PUP UNITS.
2.02 At the same time that the COMMITTEE makes its determination as
to the granting of PUP UNITS, it shall also establish PERFORMANCE TARGETS.
Although it is intended that PERFORMANCE TARGETS will not change in the course
of the YEAR, the COMMITTEE reserves the right to modify or adjust a previously
set PERFORMANCE TARGET if, in its sole discretion, extraordinary events warrant
such modification or adjustment; provided, however, that no such modification or
adjustment shall increase the amount of any payment that would otherwise be due
based upon performance as measured against the original PERFORMANCE TARGET.
2.03 Each grant of PUP UNITS shall have its own VESTING PERIOD.
Subject to modification as measured against a given YEAR's applicable
PERFORMANCE TARGET, each grant of PUP UNITS shall be payable as follows:
a. One-third after the end of the first YEAR of the VESTING PERIOD;
29
<PAGE>
b. One-third after the end of the second YEAR of the VESTING PERIOD;
and
c. One-third after the end of the third YEAR of the VESTING PERIOD.
2.04 To determine the number of PUP UNITS earned, the applicable
PERFORMANCE TARGET shall be the PERFORMANCE TARGET for the YEAR in which the PUP
UNITS vest. Performance as measured against the applicable PERFORMANCE TARGET
for a YEAR shall modify all PUP UNITS that vest at the end of such YEAR. The
PERFORMANCE TARGETS established by the COMMITTEE may modify the number of UNITS
earned from 0% to 200% of the number of vested UNITS.
2.05 ELIGIBLE EMPLOYEES shall receive a cash payment as soon as
practicable following the YEAR PUP UNITS vest pursuant to the schedule set forth
in Section 2.03. The amount of the payment shall be equal to the product of the
number of PUP UNITS earned multiplied by the PRICE of STOCK.
2.06 Each time that the CORPORATION declares a dividend on its STOCK,
an amount equal to the dividend multiplied by an ELIGIBLE EMPLOYEE's
outstanding, but unearned PUP UNITS, shall be accrued on behalf of each ELIGIBLE
EMPLOYEE. As soon as practicable following the end of each YEAR, ELIGIBLE
EMPLOYEES shall receive a cash payment of the dividends accrued for that YEAR,
modified by performance for that YEAR as measured under Section 2.04.
2.07 An ELIGIBLE EMPLOYEE may elect to defer the payment of PUP UNITS
and/or dividends paid on PUP UNITS by making a timely election under the
Deferred Compensation Plan. Deferrals of benefits payable under this Plan shall
be subject to the rules contained in the Deferred Compensation Plan governing
elections to defer and receipt of deferred amounts.
ARTICLE III
3.01 Retirement. Upon retirement under the terms of Pacific Gas and
----------
Electric Company's Retirement Plan, all outstanding PUP UNITS continue to be
payable according to the terms of the PLAN. Thus, the number of UNITS
eventually earned by a retired employee is still subject to modification
depending on the extent to which applicable PERFORMANCE TARGETS are met during
the YEAR preceding the January in which UNITS become payable under the schedule
of Section 2.03. A retired employee is not entitled to receive grants of PUP
UNITS after normal or early retirement date, as those terms are defined under
Pacific Gas and Electric Company's Retirement Plan.
30
<PAGE>
3.02 Disability. If an ELIGIBLE EMPLOYEE is both disabled and
----------
entitled to receive benefits under Pacific Gas and Electric Company's Long Term
Disability Plan, UNITS granted prior to the date of disability shall continue to
be payable according to the terms of this PLAN. An ELIGIBLE EMPLOYEE is not
entitled to receive grants of PUP UNITS after the date of disability as
determined under the provisions of the Long Term Disability Plan. If an
ELIGIBLE EMPLOYEE ceases to be an ELIGIBLE EMPLOYEE because of disability and is
not entitled to receive benefits under Pacific Gas and Electric Company's Long
Term Disability Plan, all outstanding grants of PUP UNITS become vested and
payable as soon as practicable in the YEAR following the YEAR in which the
ELIGIBLE EMPLOYEE ceases to be an ELIGIBLE EMPLOYEE. All of the UNITS payable
shall be subject to modification based upon performance as measured against the
PERFORMANCE TARGET for the YEAR in which the ELIGIBLE EMPLOYEE ceases to be an
ELIGIBLE EMPLOYEE.
3.03 Death. In the event of the death of an ELIGIBLE EMPLOYEE, all
-----
outstanding grants of PUP UNITS held by the ELIGIBLE EMPLOYEE at the date of
death shall become vested and payable as soon as practicable in the YEAR
following the YEAR of death. All of the UNITS payable after an ELIGIBLE
EMPLOYEE's death shall be subject to modification based upon performance as
measured against the PERFORMANCE TARGET for the YEAR in which the death of the
ELIGIBLE EMPLOYEE occurs.
3.04 Termination. If an ELIGIBLE EMPLOYEE ceases to be an ELIGIBLE
-----------
EMPLOYEE for any reason other than retirement as defined under Pacific Gas and
Electric Company's Retirement Plan, disability, or death, all outstanding grants
of PUP UNITS shall be canceled as of the date that the ELIGIBLE EMPLOYEE ceases
to be an ELIGIBLE EMPLOYEE unless otherwise provided in the PG&E Corporation
Officer Severance Policy.
3.05 Change in Control. Upon a Change in Control as defined in the
-----------------
PG&E Corporation Long Term Incentive Program (Program), all PUP UNITS shall
become vested and payable as soon as practicable in the YEAR following the
Change in Control in accordance with Section 16 of the Program.
ARTICLE IV
ADMINISTRATIVE PROVISIONS
-------------------------
4.01 Administration. The PLAN shall be administered by the PLAN
--------------
ADMINISTRATOR who shall have the authority to interpret the PLAN and make such
rules as it deems appropriate. The PLAN ADMINISTRATOR shall have the duty and
responsibility of maintaining records, making the requisite calculations, and
disbursing payments hereunder. The PLAN ADMINISTRATOR's interpretations,
determinations, rules, and calculations shall be final and binding on all
persons and parties concerned.
31
<PAGE>
4.02 Amendment and Termination. The CORPORATION may amend or
-------------------------
terminate the PLAN at any time, provided, however, that no such amendment or
termination shall adversely affect PUP UNITS which an ELIGIBLE EMPLOYEE has
earned prior to the date of such amendment or termination. PUP UNITS
outstanding but unearned at the date of any such amendment or termination may,
in the sole discretion of the CORPORATION, be canceled, and the CORPORATION
shall have no obligation to provide a substitute benefit of lesser, equal, or
greater value.
4.03 Nonassignability of Benefits. The benefits payable under this
----------------------------
PLAN or the right to receive future benefits under this PLAN may not be
anticipated, alienated, pledged, encumbered, or subject to any charge or legal
process, and if any attempt is made to do so, or a person eligible for any
benefits becomes bankrupt, the interest under the PLAN of the person affected
may be terminated by the PLAN ADMINISTRATOR which, in its sole discretion, may
cause the same to be held if applied for the benefit of one or more of the
dependents of such person or make any other disposition of such benefits that it
deems appropriate.
4.04 No Guarantee of Employment. Nothing contained in this PLAN
--------------------------
shall be construed as a contract of employment between the CORPORATION or the
ELIGIBLE EMPLOYEE, or as a right of the ELIGIBLE EMPLOYEE to be continued in the
employ of the CORPORATION, to remain as an officer of the CORPORATION, or as a
limitation on the right of the CORPORATION to discharge any of its employees,
with or without cause.
4.05 Benefits Unfunded and Unsecured. The benefits under this PLAN
-------------------------------
are unfunded, and the interest under this PLAN of any ELIGIBLE EMPLOYEE and such
ELIGIBLE EMPLOYEE's right to receive a distribution of benefits under this PLAN
shall be an unsecured claim against the general assets of the CORPORATION.
4.06 Applicable Law. All questions pertaining to the construction,
--------------
validity, and effect of the PLAN shall be determined in accordance with the laws
of the United States, and to the extent not preempted by such laws, by the laws
of the State of California.
32
<PAGE>
EXHIBIT C
PG&E CORPORATION
NON-EMPLOYEE DIRECTOR STOCK INCENTIVE PLAN
(As amended and restated effective as of October 21, 1998)
1. Purpose of the Plan
-------------------
This is the controlling and definitive statement of the PG&E Corporation
Non-Employee Director Stock Incentive Plan (hereinafter called the
PLAN/3/). The purpose of the PLAN is to advance the interests of the
CORPORATION by providing NON-EMPLOYEE DIRECTORS with financial incentives
to promote the success of its long-term (five to ten years) business
objectives, and to increase their proprietary interest in the success of
the CORPORATION. Inasmuch as the PLAN is designed to encourage financial
performance and to improve the value of shareholders' investment in PG&E
CORPORATION, the costs of the PLAN will be funded from corporate earnings.
2. Formula Awards of Director Restricted Stock, Non-Qualified Stock Options
------------------------------------------------------------------------
and Phantom Stock to Non-Employee Directors
-------------------------------------------
All awards of DIRECTOR RESTRICTED STOCK, NON-QUALIFIED STOCK OPTIONS and
PHANTOM STOCK under the PLAN shall be automatic and non-discretionary, and
shall be made strictly in accordance with the provisions contained herein.
No person shall have any discretion to select which NON-EMPLOYEE DIRECTORS
shall be granted DIRECTOR RESTRICTED STOCK, NON-QUALIFIED STOCK OPTIONS or
PHANTOM STOCK. Further, no person shall have any discretion to determine
the number of shares of DIRECTOR RESTRICTED STOCK awarded to a NON-EMPLOYEE
DIRECTOR, and, except as otherwise provided in Section 4 with respect to a
NON-EMPLOYEE DIRECTOR'S election to allocate formula awards between NON-
QUALIFIED STOCK OPTIONS and PHANTOM STOCK, no person shall have any
discretion to determine the number of shares underlying NON-QUALIFIED STOCK
OPTIONS and PHANTOM STOCK awarded to a NON-EMPLOYEE DIRECTOR.
3. Awards of Director Restricted Stock
-----------------------------------
(a) On the first business day of each calendar year beginning on January
1, 1998, during the duration of the PLAN, each person who is a NON-
EMPLOYEE DIRECTOR on the first business day of the applicable calendar
year shall receive a grant of DIRECTOR RESTRICTED STOCK in an amount
to be determined in accordance with the formula set forth in this
Section 3(a). The number of shares of DIRECTOR RESTRICTED
- --------------
/4/ Capitalized words are defined in Section 15 hereof.
33
<PAGE>
STOCK to be granted to each NON-EMPLOYEE DIRECTOR each calendar year
shall be determined by (i) dividing ten thousand dollars ($10,000) by
the FAIR MARKET VALUE of the COMMON STOCK on the first business day of
the applicable calendar year, and (ii) rounding the resulting number
down to the nearest whole share. No person shall receive more than one
(1) grant of DIRECTOR RESTRICTED STOCK during any calendar year.
(b) Shares of DIRECTOR RESTRICTED STOCK shall vest cumulatively as
follows: (i) twenty percent (20%) of such shares on the first
anniversary of the date of grant; (ii) forty percent (40%) of such
shares on the second anniversary of the date of grant; (iii) sixty
percent (60%) of such shares on the third anniversary of the date of
grant; (iv) eighty percent (80%) of such shares on the fourth
anniversary of the date of grant; and (v) one hundred percent (100%)
of such shares on the fifth anniversary of the date of grant. Shares
of DIRECTOR RESTRICTED STOCK may not be resold or otherwise
transferred by a GRANTEE until such shares are vested in accordance
with the provisions of this Section 3(b).
4. Annual Election to Receive Non-Qualified Stock Options and Phantom Stock
-------------------------------------------------------------------------
By June 30 of each calendar year during the term of the Plan, each person
who is then a NON-EMPLOYEE DIRECTOR shall deliver to the Corporate
Secretary a written election to receive either NON-QUALIFIED STOCK OPTIONS
or PHANTOM STOCK, or both, with an aggregate value of $20,000, on the first
business day of the following calendar year, provided the person continues
to be a NON-EMPLOYEE DIRECTOR on the date the award would otherwise be
made. A NON-EMPLOYEE DIRECTOR may allocate between NON-QUALIFIED STOCK
OPTIONS and PHANTOM STOCK in minimum increments with a value equal to
$5,000, as determined in accordance with Section 5 below with respect to
NON-QUALIFIFED STOCK OPTIONS, and Section 6 below, with respect to PHANTOM
STOCK. All awards of NON-QUALIFIED STOCK OPTIONS and PHANTOM STOCK made to
NON-EMPLOYEE DIRECTORS shall comply with Section 5 and Section 6 below,
respectively. A NON-EMPLOYEE DIRECTOR who has failed to make a timely
election or who became a NON-EMPLOYEE DIRECTOR after June 30 shall be
awarded NON-QUALIFIED STOCK OPTIONS and PHANTOM STOCK, each with a value of
$10,000 as determined in accordance with Section 5 and Section 6,
respectively, provided that the NON-EMPLOYEE DIRECTOR continues to be a
NON-EMPLOYEE DIRECTOR on the on the first business day of the following
calendar year. Notwithstanding the foregoing, elections for calendar year
1998 must be received by December 31, 1997, to be effective on the first
business day of calendar year 1998.
34
<PAGE>
5. Grant of Non-Qualified Stock Options to Non-Employee Directors
--------------------------------------------------------------
(a) On the first business day of each calendar year beginning on January
1, 1998, during the duration of the PLAN, each person who is then a
NON-EMPLOYEE DIRECTOR and who has elected to receive an award of NON-
QUALIFIED STOCK OPTIONS in accordance with Section 4, shall receive a
grant of NON-QUALIFIED STOCK OPTIONS with an aggregate value equal to
$5,000, $10,000, $15,000, or $20,000, as previously elected by the
NON-EMPLOYEE DIRECTOR (or $10,000 in the case of a NON-EMPLOYEE
DIRECTOR who has failed to make a timely election in accordance with
Section 4 or who became a NON-EMPLOYEE DIRECTOR after June 30) (the
"Elected Option Value"). The number of shares subject to the NON-
QUALIFIED STOCK OPTIONS shall be determined by dividing the Elected
Option Value by the value of a NON-QUALIFIED STOCK OPTION to purchase
a single share of PG&E Corporation common stock as of the first
business day of the applicable calendar year. The per stock option
value shall be calculated in accordance with the Black-Scholes stock
option valuation method using the average preceding November closing
price of PG&E Corporation stock and reducing the per option value so
calculated by twenty percent. The resulting number of NON-QUALIFIED
STOCK OPTIONS shall be rounded down to the nearest whole share. No
person shall receive more than one grant of NON-QUALIFIED STOCK
OPTIONS during any calendar year.
(b) The OPTION PRICE of the COMMON STOCK subject under each NON-QUALIFIED
STOCK OPTION shall be the FAIR MARKET VALUE of the COMMON STOCK on the
date of grant. The exercise of any NON-QUALIFIED STOCK OPTION shall be
contingent upon receipt by the CORPORATION of (i) cash, (ii) check,
(iii) shares of COMMON STOCK, (iv) an executed exercise notice
together with irrevocable instructions to a broker to either sell the
shares subject to the NON-QUALIFIED STOCK OPTION or hold such shares
as collateral for a margin loan and to promptly deliver to the
CORPORATION the amount of sale or loan proceeds required to pay the
OPTION PRICE, or (v) any combination of the foregoing in an amount
equal to the full OPTION PRICE of the shares being purchased. For
purposes of this paragraph, shares of COMMON STOCK that are delivered
in payment of the OPTION PRICE must have been previously owned by the
GRANTEE for a minimum of one year, and shall be valued at their FAIR
MARKET VALUE as of the date of the exercise of the NON-QUALIFIED STOCK
OPTION. The CORPORATION shall not make loans to any GRANTEE for the
purpose of exercising NON-QUALIFIED STOCK OPTIONS.
35
<PAGE>
(c) Each NON-QUALIFIED STOCK OPTION granted under the Plan shall become
exercisable and vested cumulatively as follows: (i) up to thirty-three
percent (33%) of the NON-QUALIFIED STOCK OPTION may be exercised on or
after the second anniversary of the date of grant; (ii) up to sixty-
six percent (66%) of the NON-QUALIFIED STOCK OPTION may be exercised
on or after the third anniversary of the date of grant; and (iii) up
to one hundred percent (100%) of the NON-QUALIFIED STOCK OPTION may be
exercised on or after the fourth anniversary of the date of grant.
(d) The term of each NON-QUALIFIED STOCK OPTION shall be ten years and one
day from the date of grant, subject to earlier termination as provided
in Section 9 hereof. Any provision of the PLAN to the contrary
notwithstanding, no NON-QUALIFIED STOCK OPTION shall be exercised
after the time limitations stated in this Section 5(d).
6. Awards of Phantom Stock to Non-Employee Directors
-------------------------------------------------
(a) On the first business day of each calendar year beginning on January
1, 1998, during the duration of the PLAN, each person who is then a
NON-EMPLOYEE DIRECTOR and who has elected to receive an award of
PHANTOM STOCK in accordance with Section 4, shall be credited with an
amount of PHANTOM STOCK with a value (as determined by the FAIR MARKET
VALUE of the COMMON STOCK on the first business day of the applicable
calendar year) equal to $5,000, $10,000, $15,000, or $20,000, as
previously elected by the NON-EMPLOYEE DIRECTOR (the "Elected Phantom
Stock Value"). The number of shares of PHANTOM STOCK (including
fractions computed to three decimal places) to be granted to each NON-
EMPLOYEE DIRECTOR each calendar year shall be determined by dividing
the Elected Phantom Stock Value (or $10,000 in the case of a NON-
EMPLOYEE DIRECTOR who has failed to make a timely election in
accordance with Section 4 or who became a NON-EMPLOYEE DIRECTOR after
June 30) by the FAIR MARKET VALUE of the COMMON STOCK on the first
business day of the applicable calendar year. No person shall receive
more than one grant of PHANTOM STOCK during any calendar year. The
shares of PHANTOM STOCK awarded to a NON-EMPLOYEE DIRECTOR shall be
credited to a newly established PHANTOM STOCK account for the NON-
EMPLOYEE DIRECTOR. Each share of PHANTOM STOCK shall be deemed to be
equal to one share (or fraction thereof) of COMMON STOCK on the date
of grant, and shall thereafter flucuate in value in accordance with
the FAIR MARKET VALUE of the COMMON STOCK.
(b) Each NON-EMPLOYEE DIRECTOR'S PHANTOM STOCK account shall be credited
quarterly on each dividend payment date with additional
36
<PAGE>
shares of PHANTOM STOCK (including fractions computed to three decimal
places) determined by dividing (i) the aggregate amount of dividends,
i.e,. the dividend multiplied by the number of shares of PHANTOM STOCK
credited to the participant's account as of the dividend record date,
by (ii) by the FAIR MARKET VALUE of the COMMON STOCK on the dividend
payment date.
(c) Payment of the shares of PHANTOM STOCK credited to a NON-EMPLOYEE
DIRECTOR'S PHANTOM STOCK account shall only be made after the NON-
EMPLOYEE DIRECTOR'S RETIREMENT or MANDATORY RETIREMENT from the BOARD
OF DIRECTORS. Payment shall be made only in the form of shares of
COMMON STOCK equal to the number of shares of PHANTOM STOCK credited
to the NON-EMPLOYEE DIRECTOR'S PHANTOM STOCK account on the date of
distribution, rounded down to the nearest whole share. The NON-
EMPLOYEE DIRECTOR may elect to receive the number of shares of COMMON
STOCK to which he is entitled in a lump sum distribution of the entire
amount or in a series of ten or less approximately equal annual
installments, provided that distribution shall commence no later than
January of the year following the year in which the NON-EMPLOYEE
DIRECTOR'S RETIREMENT or MANDATORY RETIREMENT occurred.
7. Shares of Stock Subject to the Plan
-----------------------------------
There shall be reserved for use under the PLAN and for the grant of any
other INCENTIVE AWARDS pursuant to the PROGRAM (subject to the provisions
of Section 10 hereof) a total of 23,289,230 shares of COMMON STOCK, which
shares may be authorized but unissued shares of COMMON STOCK or issued
shares of COMMON STOCK which shall have been reacquired by PG&E
CORPORATION.
8. Dividend, Voting and Other Shareholder Rights
---------------------------------------------
Except as otherwise provided in the PLAN, each GRANTEE shall have all of
the rights of a shareholder of PG&E CORPORATION with respect to all
outstanding shares of DIRECTOR RESTRICTED STOCK registered in his or her
name, whether or not such shares are vested, including the right to receive
dividends and other distributions paid or made with respect to such shares
and the right to vote such shares. No GRANTEE shall have any of the rights
of a shareholder of PG&E CORPORATION with respect to a NON-QUALIFIED STOCK
OPTION until the shares acquired upon exercise of such NON-QUALIFIED STOCK
OPTION have been issued and registered in his or her name. No GRANTEE shall
have any of the rights of a shareholder of PG&E CORPORATION with respect to
37
<PAGE>
PHANTOM STOCK credited to the NON-EMPLOYEE DIRECTOR'S PHANTOM STOCK account
under the Plan.
9. Termination of Status as a Non-Employee Director
------------------------------------------------
(a) In the event of a TERMINATION by reason of disability or death, (i)
all shares of DIRECTOR RESTRICTED STOCK held by the GRANTEE shall
become fully vested, notwithstanding the provisions of Section 3(b)
hereof, and the GRANTEE (or the GRANTEE'S estate or a person who
acquired the shares of DIRECTOR RESTRICTED STOCK by bequest or
inheritance) shall have the right to resell or transfer such shares at
any time, (ii) all NON-QUALIFIED STOCK OPTIONS held by the GRANTEE, to
the extent that such NON-QUALIFIED STOCK OPTIONS have not previously
expired or been exercised, shall become fully vested and exercisable,
notwithstanding the provisions of Section 5(c) hereof, and the GRANTEE
(or the GRANTEE'S estate or a person who acquired the right to
exercise the NON-QUALIFIED STOCK OPTION by bequest or inheritance)
shall have the right to exercise the NON-QUALIFIED STOCK OPTIONS at
any time within their respective terms or within one (1) year after
the date of the GRANTEE'S death or disability, whichever is shorter,
and (iii) all shares of PHANTOM STOCK credited to the NON-EMPLOYEE
DIRECTOR'S PHANTOM STOCK account shall immediately become payable to
the GRANTEE (or the GRANTEE'S estate or a person who acquired the
shares of PHANTOM STOCK by bequest or inheritance) in the form of a
number of shares of COMMON STOCK equal to the number of shares of
PHANTOM STOCK credited to the NON-EMPLOYEE DIRECTOR'S PHANTOM STOCK
account, rounded down to the nearest whole share. The term
"disability" shall, for the purposes of the PLAN, be defined in
Section 22(e)(3) of the CODE.
(b) In the event of a TERMINATION by reason of MANDATORY RETIREMENT, (i)
all shares of DIRECTOR RESTRICTED STOCK held by the GRANTEE shall
become fully vested, notwithstanding the provisions of Section 3(b)
hereof, and the GRANTEE shall have the right to resell or transfer
such shares at any time, (ii) the NON-QUALIFIED STOCK OPTIONS then
held by the GRANTEE, to the extent that such NON-QUALIFIED STOCK
OPTIONS have not previously expired or been exercised, shall become
fully vested and exercisable, notwithstanding the provisions of
Section 5(c) hereof, and the GRANTEE shall have the right to exercise
the NON-QUALIFIED STOCK OPTIONS at any time within their respective
terms or within five (5) years after such MANDATORY RETIREMENT,
whichever is shorter; and (iii) all shares of PHANTOM STOCK credited
to the NON-EMPLOYEE DIRECTOR'S PHANTOM STOCK account shall become
payable to the GRANTEE in accordance with Section 6(c) hereof.
38
<PAGE>
(c) In the event of a TERMINATION for any reason other than those
specified in subparagraphs (a) and (b) above, (i) any unvested shares
of DIRECTOR RESTRICTED STOCK granted hereunder shall be forfeited and
the GRANTEE shall return to the CORPORATION for cancellation any stock
certificates representing such forfeited shares which forfeited shares
shall be deemed to be canceled and no longer outstanding as of the
date of TERMINATION; and from and after the date of TERMINATION, the
GRANTEE shall cease to be a shareholder with respect to such forfeited
shares and shall have no dividend, voting or other rights with respect
thereto, (ii) any NON-QUALIFIED STOCK OPTIONS granted hereunder that
have not yet vested and become exercisable shall terminate, (iii) the
GRANTEE shall have the right to exercise NON-QUALIFIED STOCK OPTIONS,
to the extent that such NON-QUALIFIED STOCK OPTIONS have vested and
become exercisable as of the date of TERMINATION, at any time within
their respective terms or within three months after such TERMINATION,
whichever is shorter, after which the NON-QUALIFIED STOCK OPTIONS
shall terminate, and (iv) all shares of PHANTOM STOCK credited to the
NON-EMPLOYEE DIRECTOR'S PHANTOM STOCK account shall be forfeited on
the date of TERMINATION; provided, however, that if the TERMINATION
results from the NON-EMPLOYEE DIRECTOR'S RETIREMENT, then the PHANTOM
STOCK credited to the NON-EMPLOYEE DIRECTOR'S PHANTOM STOCK account
shall become payable in accordance with Section 6(c) hereof.
(d) Notwithstanding the provisions of subparagraphs (a) through (c) above,
the BOARD OF DIRECTORS may, in its sole discretion, establish
different terms and conditions pertaining to the effect of
TERMINATION, to the extent permitted by applicable federal and state
law.
10. Adjustments Upon Changes in Number or Value of Shares of Common Stock
---------------------------------------------------------------------
If there are any changes in the number or value of shares of COMMON STOCK
by reason of stock dividends, stock splits, reverse stock splits,
recapitalizations, mergers, consolidations or other events that materially
increase or decrease the number or value of issued and outstanding shares
of COMMON STOCK, the BOARD OF DIRECTORS or COMMITTEE may make such
adjustments as it shall deem appropriate, in order to prevent dilution or
enlargement of rights.
11. Non-Transferability
-------------------
NON-QUALIFIED STOCK OPTIONS, PHANTOM STOCK, and shares of DIRECTOR
RESTRICTED STOCK that have not vested in accordance with the provisions of
Section 3(b) hereof, shall not be transferable by the GRANTEE otherwise
than by will or the laws of descent and distribution, or pursuant to a
39
<PAGE>
qualified domestic relations order as defined by the CODE, Title I of ERISA
or the rules thereunder.
12. Change in Control
-----------------
Upon the occurrence of a CHANGE IN CONTROL (as defined below), (i) any time
periods relating to the vesting of any shares of DIRECTOR RESTRICTED STOCK
granted hereunder shall be accelerated so that all such shares immediately
become fully vested, (ii) any time periods relating to the vesting of NON-
QUALIFIED STOCK OPTIONS granted hereunder shall be accelerated so that all
such NON-QUALIFIED STOCK OPTIONS immediately become fully vested and
exercisable for the remainder of their terms, and (iii) all shares of
PHANTOM STOCK credited to the NON-EMPLOYEE DIRECTORS' PHANTOM STOCK
accounts shall become payable in accordance with Section 6(c) hereof as if
the CHANGE IN CONTROL constituted a RETIREMENT.
A "CHANGE IN CONTROL" shall be deemed to have occurred if:
(a) any "person" (as such term is used in Sections 13(d) and 14(d)(2) of
the EXCHANGE ACT, but excluding any benefit plan for EMPLOYEES or any
trustee, agent or other fiduciary for any such plan acting in such
person's capacity as such fiduciary), directly or indirectly, becomes
the beneficial owner of securities of PG&E CORPORATION representing
twenty percent (20%) or more of the combined voting power of PG&E
CORPORATION's then outstanding securities;
(b) during any two consecutive years, individuals who at the beginning of
such a period constitute the BOARD OF DIRECTORS cease for any reason
to constitute at least a majority of the BOARD OF DIRECTORS, unless
the election, or the nomination for election by the shareholders of
PG&E CORPORATION, of each new DIRECTOR was approved by a vote of at
least two-thirds (2/3) of the DIRECTORS then still in office who were
DIRECTORS at the beginning of the period; or
the shareholders of the CORPORATION shall have approved (i) any
consolidation or merger of the CORPORATION other than a merger or
consolidation which would result in the voting securities of the
CORPORATION outstanding immediately prior thereto continuing to represent
(either by remaining outstanding or by being converted into voting
securities of the surviving entity or any parent of such surviving entity)
at least 70 percent of the Combined Voting Power of the CORPORATION, such
surviving entity or the parent of such surviving entity outstanding
immediately after the merger or consolidation; (ii) any sale, lease,
exchange or other transfer (in one transaction or a series of related
transactions) of all or substantially all of the assets of the CORPORATION,
or (iii) any plan or proposal for the liquidation or dissolution of the
CORPORATION. For purposes of this paragraph, the term Combined Voting
40
<PAGE>
Power shall mean the combined voting power of the CORPORATION's or other
relevant entity's then outstanding voting securities.
13. Amendment and Termination of the Plan
-------------------------------------
The BOARD OF DIRECTORS or the COMMITTEE may at any time suspend, terminate,
modify or amend the PLAN in any respect; provided, however, that, to the
extent necessary and desirable to comply with the CODE (or any other
applicable law or regulation, including the requirements of any stock
exchange on which the COMMON STOCK is listed or quoted), shareholder
approval of any PLAN amendment shall be obtained in such a manner and to
such a degree as is required by the applicable law or regulation.
No suspension, termination, modification or amendment of the PLAN may,
without the consent of the GRANTEE, adversely affect his or her rights with
respect to DIRECTOR RESTRICTED STOCK, NON-QUALIFIED STOCK OPTIONS or
PHANTOM STOCK theretofore granted to such GRANTEE.
Except as provided in Section 2 hereof, the BOARD OF DIRECTORS or COMMITTEE
may make such amendments or modifications in the terms and conditions of
any grant of DIRECTOR RESTRICTED STOCK, NON-QUALIFIED STOCK OPTIONS or
PHANTOM STOCK as it may deem advisable, or cancel or annul any grant of
DIRECTOR RESTRICTED STOCK, NON-QUALIFIED STOCK OPTIONS or PHANTOM STOCK;
provided, however, that no such amendment, modification, cancellation or
annulment may, without the consent of the GRANTEE, adversely affect his or
her rights with respect to such grant.
14. Effective Date of the Plan and Duration
---------------------------------------
This PLAN became effective as of January 1, 1996, upon approval by the
shareholders of Pacific Gas and Electric Company at its Annual Meeting on
April 17, 1996. Effective January 1, 1997, the PLAN was assumed by PG&E
CORPORATION. At its meeting on December 17, 1997, the BOARD OF DIRECTORS
amended and restated the PLAN effective January 1, 1998, to (i) reflect
the adoption of new RULE 16B-3 which became effective November 1, 1996, and
(ii) provide automatic formula awards of NON-QUALIFIED STOCK OPTIONS and
PHANTOM STOCK to NON-EMPLOYEE DIRECTORS within the limits of the PROGRAM as
previously approved by shareholders in 1996. The COMMITTEE amended Section
12 of the PLAN effective October 21, 1998. Unless terminated sooner
pursuant to Section 13 hereof, the PLAN shall terminate on December 31,
2005.
41
<PAGE>
15. Definitions
-----------
(a) BOARD OF DIRECTORS means the Board of Directors of PG&E CORPORATION.
------------------
(b) CHANGE IN CONTROL has the meaning set forth in Section 12 hereof.
-----------------
(c) CODE means the Internal Revenue Code of 1986, as amended from time to
----
time.
(d) COMMITTEE means the Nominating and Compensation Committee of the BOARD
---------
OF DIRECTORS or any successor to such committee.
(e) COMMON STOCK means common shares of PG&E CORPORATION with no par value
------------
and any class of common shares into which such common shares hereafter
may be converted.
(f) CORPORATION means PG&E CORPORATION, and any parent corporation (as
-----------
defined in Section 424(e) of the CODE) or subsidiary corporation (as
defined in Section 424(f) of the CODE).
(g) DIRECTOR means any person who is a member of the BOARD OF DIRECTORS or
--------
the Board of Directors of any parent corporation (as defined in
Section 424(e) of the CODE) which may hereafter be established,
including an advisory, emeritus or honorary director.
(h) DIRECTOR RESTRICTED STOCK means RESTRICTED STOCK granted to a NON-
-------------------------
EMPLOYEE DIRECTOR under the PLAN.
(i) EMPLOYEE means any person who is employed by the CORPORATION. The
--------
payment of a director's fee or consulting fee by the CORPORATION shall
not be sufficient to constitute "employment" by the CORPORATION.
(j) ERISA means the Employee Retirement Income Security Act of 1974, as
-----
amended.
(k) EXCHANGE ACT means the Securities Exchange Act of 1934, as amended.
------------
(l) FAIR MARKET VALUE means the closing price of the COMMON STOCK reported
-----------------
on the New York Stock Exchange Composite Transactions for the date
specified for determining such value.
(m) GRANTEE means the NON-EMPLOYEE DIRECTOR receiving the DIRECTOR
-------
RESTRICTED STOCK, NON-QUALIFIED STOCK
42
<PAGE>
OPTIONS and PHANTOM STOCK or his or her legal representative,
legatees, distributees or alternate payees, as the case may be.
(n) MANDATORY RETIREMENT means retirement as a DIRECTOR at age 70 or at
--------------------
such other age as may be specified in the retirement policy for the
BOARD OF DIRECTORS or the Board of Directors of any parent corporation
which may hereafter be established (as the case may be), as in effect
at the time of a NON-EMPLOYEE DIRECTOR'S TERMINATION.
(o) NON-EMPLOYEE DIRECTOR means a DIRECTOR who is not an EMPLOYEE.
---------------------
(p) NON-QUALIFIED STOCK OPTION means a option to purchase shares of COMMON
--------------------------
STOCK which is not intended to qualify as an incentive stock option
under Section 422 of the CODE.
(q) PG&E CORPORATION means PG&E CORPORATION, a California corporation.
----------------
(r) PHANTOM STOCK means allocated hypothetical shares of COMMON STOCK that
-------------
can be converted at a future date into stock.
(s) PLAN means this Non-Employee Director Stock Incentive Plan, as may be
----
amended from time to time, or any successor plan which the COMMITTEE
or BOARD OF DIRECTORS may adopt from time to time with respect to the
grant of DIRECTOR RESTRICTED STOCK, NON-QUALIFIED STOCK OPTIONS,
PHANTOM STOCK or other stock-based incentive awards under the PROGRAM.
(t) PROGRAM means the PG&E Corporation Long-Term Incentive Program, as
-------
amended and restated effective as of January 1, 1998, and as may be
amended from time to time, pursuant to which this PLAN is adopted.
(u) RESTRICTED STOCK means COMMON STOCK that is subject to forfeiture by
----------------
the GRANTEE to the CORPORATION under such circumstances as may be
specified by the COMMITTEE.
(v) RETIREMENT means TERMINATION of service on the BOARD OF DIRECTORS
----------
after serving continuously for five consecutive years.
(w) RULE 16b-3 means Rule 16b-3 under the EXCHANGE ACT or any successor to
----------
Rule 16b-3, as in effect when discretion is being exercised with
respect to the PLAN.
43
<PAGE>
(x) TERMINATION occurs when a NON-EMPLOYEE DIRECTOR ceases to be a member
-----------
of the BOARD OF DIRECTORS or the Board of Directors of any parent
corporation which may hereafter be established (as the case may be).
44
<PAGE>
EXHIBIT 10.13
PG&E CORPORATION
EXECUTIVE STOCK OWNERSHIP PROGRAM
Administrative Guidelines
-------------------------
(As amended October 21, 1998)
1. Description. The Executive Stock Ownership Program ("Program") was approved
-----------
by the Nominating and Compensation Committee of the Board of Directors on
October 15, 1997. The Program is an important element of the Committee's
compensation policy of aligning executive interests with those of the
Corporation's shareholders. As an integral part of the Program, the
Committee also authorized the use of Special Incentive Stock Ownership
Premiums ("SISOPs") which are designed to provide incentives to Eligible
Executives to assist in achieving minimum stock ownership targets
established by the Committee. These Guidelines were originally adopted by
the Committee on November 19, 1997, amended by the Committee on July 22,
1998, and subsequently amended on October 21, 1998. These amended
Guidelines, along with the written materials provided to the Committee on
October 15, 1997, describe the Program which became effective on January 1,
1998. The Program is administered by the Corporation's Senior Human
Resources Officer.
2. Eligible Executives. The Chief Executive Officer shall designate the
-------------------
officers of the Corporation and its affiliates who shall be Eligible
Executives covered by the Program. Initially, the officers covered by the
Guidelines and the applicable stock ownership Target are:
<TABLE>
<CAPTION>
Officer Band Position Stock Ownership Target
-------------------------------------------------------------------------------------
<C> <S> <C>
1 CEO 3 x base salary
-------------------------------------------------------------------------------------
2 Heads of Business Lines, 2 x base salary
CFO, & General Counsel
-------------------------------------------------------------------------------------
3 SVPs of Corp. 1.5 x base salary
-------------------------------------------------------------------------------------
</TABLE>
3. Annual Milestones. Under the Guidelines, stock ownership levels are
-----------------
designed to be achieved by the end of the fifth calendar year following the
calendar year in which an officer first becomes an Eligible Executive
("Target Date"). Annual Milestones have been established as a means of
measuring progress towards achieving Targets and of providing incentives for
Eligible Executives to expeditiously meet their Targets. The Annual
Milestone at the end of the first full calendar year is 20 percent of the
Target, and the Annual Milestone for each succeeding year is an additional
20 percent of the Target. Annual Milestones shall be adjusted to reflect
changes in base salary; provided, however, that in each instance any such
modification shall be amortized over the remaining original five-year term.
Following the Target Date, annual Targets also shall be modified to reflect
changes in base salary.
1
<PAGE>
4. Calculation of Stock Ownership Levels. Stock ownership level is the
---------------------------
dollar value of stock and stock equivalents owned by an Eligible Executive
and calculated as of the last day of the calendar year ("Measurement Date").
The purpose of this calculation is to determine the value of the stock or
stock equivalents owned by the Eligible Executive as compared with the
Annual Milestone or Target for that executive. For purposes of this
calculation, the value per share of stock or stock equivalent ("Measurement
Value") is the average closing price of PG&E Corporation common stock as
traded on the New York Stock Exchange for the last thirty (30) trading days
of the year.
a) The value of stock beneficially owned by the Eligible Executive is
determined by multiplying the number of shares owned beneficially on
the Measurement Date times the Measurement Value.
b) The value of PG&E Corporation phantom stock units credited to the
Eligible Executive's account in the PG&E Corporation Deferred
Compensation Plan for Officers ("DCP") is determined by multiplying the
number of phantom stock units credited to the Eligible Executive's DCP
account on the Measurement Date times the Measurement Value.
c) The value of stock held in the PG&E Corporation stock fund of any
defined contribution plan maintained by PG&E Corporation or any of its
subsidiaries is the value of the Eligible Executive's PG&E Corporation
stock fund on the Measurement Date.
d) The value of vested stock options is the difference between the number
of options multiplied by the Measurement Value minus the number of
options multiplied by the option exercise price (for purposes of this
calculation, any value attributable to dividend equivalents is
excluded).
5. Award of SISOPs. SISOPs are awarded to Eligible Executives who achieve and
---------------
maintain stock ownership levels prior to the end of the third year following
the year in which an officer first became an Eligible Executive. For
purposes of determining awards, the total stock ownership level is
calculated as set forth under paragraph 4, on the Measurement Date. The
amount of a SISOP award shall be equal to:
a) For the first year, 20 percent of the amount of the Eligible Executive's
stock ownership level at the end of the year, up to the Annual
Milestone, plus an additional 30 percent of the amount by which the
stock ownership level exceeds the Annual Milestone up to the target; and
b) For each of the second and third years, 20 percent of the amount up to
the Annual Milestone by which the end of the year stock ownership level
exceeds the beginning of the year stock ownership level, plus an
additional 30 percent of the amount by which the end of the year balance
exceeds the Annual Milestone, up to the Target.
Each time a SISOP award calculation is made, a second calculation also is
made to determine the minimum number of shares which must be retained by
the Eligible Executive to avoid forfeiture of the SISOP award ("Minimum
Ownership Level") as discussed below in paragraph 8. This calculation
converts the dollar value of the stock ownership level used as the basis
for qualifying for SISOPs into a number of shares of stock. It is
calculated by dividing the stock ownership level by the Measurement Value.
2
<PAGE>
Thus, for example, if an Eligible Executive's stock ownership level was
$250,000 and the Measurement Value was $25 per share, then the Minimum
Ownership Level would be 10,000 shares.
For purposes of this calculation, the maximum share ownership level used is
the Eligible Executive's Target. If an Eligible Executive has a share
ownership level higher than his/her Target, the increment over the Target
is not included. Thus, for example, if an Eligible Executive has a Target
of $750,000 and his/her share ownership level is $900,000, then only
$750,000 is used to calculate the Minimum Ownership Level.
6. SISOPs Credited to the Deferred Compensation Plan. Upon award, SISOPs are
--------------------------------------------------
credited to the Eligible Executive's DCP account and converted into units of
phantom stock each equal in value to a share of PG&E Corporation common
stock ("SISOP units") as determined in accordance with paragraph 6 of the
DCP. The SISOP units constitute "incentive awards" authorized to be awarded
by the Committee to Eligible Executives under the PG&E Corporation Long-Term
Incentive Program ("LTIP"). Upon credit of SISOP units to an Eligible
Executive's DCP account, an equal number of shares of PG&E Corporation
common stock shall be reserved for issuance from the pool of shares
authorized for issuance under the LTIP. Once a SISOP unit is credited to the
Eligible Executive's DCP account, it shall be subject to all of the terms
and conditions specifically applicable to SISOP units under the DCP. Once
vested in accordance with paragraph 7 below, SISOP units are distributed in
the form of an equal number of shares of PG&E Corporation common stock as
provided in the DCP.
7. Vesting. SISOPs vest only upon the expiration of three years after the date
--------
of award (provided the Eligible Executive continues to be employed on such
date), or, if earlier, upon an Eligible Executive's death, disability, or
retirement, or upon a Change in Control as defined in the LTIP. An Eligible
Executive's unvested SISOPs will be forfeited upon termination of employment
unless otherwise provided in the PG&E Corporation Officer Severance Policy.
8. Forfeiture of SISOP Units. So long as SISOP units remain unvested, such
-------------------------
units are subject to forfeiture if, on each Measurement Date, the Eligible
Executive's stock ownership is less than the Minimum Ownership Level
established when the SISOPs were granted (see paragraph 5). To determine
forfeiture, the following steps are followed on each Measurement Date:
a) The number of shares and PG&E Corporation phantom stock units credited
to the Eligible Executive's DCP account is determined.
b) The share-equivalent of the value of the vested "in the money" stock
options is determined by dividing the value of such options (computed in
the manner described in 4(d)) by the current Measurement Value (e.g., if
the value of the vested "in the money" options is $100,000 and the
current Measurement Value is $25 per share, then the share equivalent is
4,000 shares).
c) The number of shares, PG&E Corporation phantom stock units, and share-
equivalents of vested "in the money" options is added together. This
total ("Current Holdings") is compared with the Minimum Ownership Level
determined when the SISOPs were granted. If the Current Holdings are
equal to or greater than the Minimum Ownership Level, then no unvested
SISOP units are forfeited. If the Current Holdings are less than the
3
<PAGE>
Minimum Ownership Level, then the unvested SISOP units are forfeited in
the same proportion as the Current Holdings are less than Minimum
Ownership Level (for example, if the Current Holdings are 20 percent
less than the Minimum Ownership Level, then 20 percent of the SISOP
units are forfeited).
9. Failure to Achieve or Maintain Target. Failure to achieve stock ownership
--------------------------------------
levels at Target on the Target Date, or to maintain stock ownership levels
at Target on any Measurement Date thereafter, will result in the deferral
into the PG&E Corporation Phantom Stock Fund of the DCP of annual awards
from the Performance Unit Plan ("PUP") and the Short Term Incentive Plan
("STIP"). As of any Measurement Date, to the extent that stock ownership
levels are below Target, PUP awards shall be converted into PG&E Corporation
Phantom Stock Units and held in the PG&E Corporation Phantom Stock Fund of
the DCP. If, with the addition of the phantom stock units attributable to
the PUP award, the stock ownership level is still below Target for any
Measurement Date, any STIP award above target STIP also shall be converted
into phantom stock units, to the extent necessary to achieve the Target
stock ownership level. Such conversion of PUP and STIP awards shall continue
for successive Measurement Dates, if necessary, until Target is met. Phantom
stock units attributable to PUP and STIP awards described in this paragraph
9 will be paid from the DCP in a lump sum in January of the year following
the year in which the Eligible Executive's employment terminates, or upon
such earlier date as may have been elected by the Eligible Executive within
thirty days after the date of mandatory deferral of PUP and/or STIP awards
which date shall not be earlier than three (3) years after the date of
mandatory deferral.
4
<PAGE>
EXHIBIT 10.14
PG&E CORPORATION
OFFICER SEVERANCE POLICY
1. Purpose
-------
This is the controlling and definitive statement of the Officer Severance
Policy of PG&E Corporation ("Policy"). Since Officers are employed at the
will of PG&E Corporation and its subsidiaries ("Corporation"), their
employment with the Corporation may be terminated at any time, with or
without cause. The Policy, which was first adopted effective November 1,
1998, provides Officers of the Corporation in Officer Compensation Bands I
through V with severance benefits in the event that their employment is
terminated./1/ Severance benefits for officers not covered by this Policy
will be provided under policies or programs developed by the appropriate
lines of business in consultation with and the approval by the Senior Human
Resources Officer of the Corporation.
The purpose of the Policy is to attract and retain senior management by
defining terms and conditions for severance benefits, to provide severance
benefits that are part of a competitive total compensation package, to
provide consistent treatment for all terminated officers, and to minimize
potential litigation costs associated with Officer termination of
employment.
2. Termination of Employment
-------------------------
(a) If Corporation exercises its right to terminate an Officer's employment
without cause, it shall give the Officer thirty (30) days' advance
written notice or pay in lieu thereof. Except as provided in Section
2(b) below, in consideration of the Officer's agreement to the
obligations described in Section 3 below and to the arbitration
provisions described in Section 11 below, Corporation shall also
provide the following payments and benefits to Officer:
(i) The Corporation shall pay Officer a severance payment, equal to
(x) two, for Officers in Officer Bands I, II or III or (y) one
and one-half, for Officers in Officer Bands IV or V times (the
"Severance Multiple") the sum of the Officer's annual base
compensation and the Officer's Short-Term Incentive Plan target
award at the time of his or her termination, to be paid in a
lump sum. Annual base compensation shall mean the Officer's
monthly base pay
- ------------------------
/1/ Severance benefits for Officers who are currently covered by an employment
agreement will continue to be provided solely under such agreements until
their expiration at which time this Policy will become effective for such
Officers.
<PAGE>
for the month in which the Officer is given notice of
termination, multiplied by 12. If Officer is a participant in
the Corporation's Defined Benefit Supplemental Executive
Retirement Plan ("SERP"), Officer may elect to convert any
portion of the amount described in the preceding sentence to
provide for additional years of service and/or additional years
to Officer's age for purposes of calculating a benefit under the
SERP. The value of any amount so converted shall be calculated
using the same actuarial factors used in calculating benefits
under the Retirement Plan for Employees of Pacific Gas and
Electric Company. Any payments made hereunder shall be less
applicable taxes;
(ii) If Officer is a participant in the SERP and if the additional
age resulting from a conversion under Section 2(a)(i) does not
result in an age of 55 or greater, Officer may elect to begin
receiving an immediately payable SERP benefit. If Officer elects
to receive an immediately payable SERP benefit the Administrator
shall use an interest rate and actuarial factors which the
Administrator, in its sole discretion, has determined are
appropriate to reflect the true economic value to the
Corporation of providing an immediately payable SERP benefit;
(iii) The incentive awards granted to Officer under the Corporation's
Long-Term Incentive Program which have not yet vested as of the
date of termination will continue to vest over a period of years
or portion thereof equal to the Severance Multiple after the
date of termination as if the Officer had remained employed for
such period. For vested stock options as of the date of
termination, the Officer shall have the right to exercise such
stock options at any time within their respective terms or
within five years after termination, whichever is shorter. For
stock options that vest during a period of years or portion
thereof equal to the Severance Multiple, the Officer shall have
the right to exercise such options at any time within five years
after termination. Awards under the Performance Unit Plan shall
continue to vest and be payable during a period of years or
portion thereof equal to the Severance Multiple. Any unvested
Performance Unit Plan awards remaining at the end of such period
shall be forfeited;
(iv) For Officers in Officer Bands I, II or III, two thirds of the
unvested Company stock units in the Officer's account in the
Corporation's Deferred Compensation Plan for Officers which were
awarded in connection with the Executive Stock Ownership Program
requirements ("SISOPs") shall vest upon the Officer's
termination and one third shall be forfeited. For Officers in
Officer Bands IV and V, one third of any unvested SISOPs shall
vest upon the Officer's termination and two thirds shall be
forfeited. Unvested stock units attributable to SISOPs which
becomes vested under this provision shall be distributed to
Officer in accordance with the Deferred Compensation Plan after
such stock units vest;
-2-
<PAGE>
(v) For a period of years or portion thereof equal to the Severance
Multiple, the Corporation shall pay the Officer's COBRA
premiums;
(vi) If Officer is terminated after serving consecutively for six
months in a fiscal year, Officer shall be entitled to receive a
prorated bonus under the Corporation's Short-Term Incentive
Plan, at the time such bonus would otherwise be paid, if any;
(vii) To the extent not theretofore paid or provided, the Corporation
shall timely pay or provide to the Officer any other amounts or
benefits required to be paid or provided or which the Officer is
eligible to receive under any plan, contract or agreement of the
Corporation and its affiliated companies; and
(viii) Such career transition services as the Corporation's Senior
Human Resources Officer shall determine is appropriate.
(b) Section 2(a) shall not apply in the event that the Corporation
terminates an Officer's employment "for cause." "For cause" means that
the Corporation, acting in good faith based upon information then known
to it, determines that the Officer has engaged in, committed, or is
responsible for (1) serious misconduct, gross negligence, theft, or
fraud against the Corporation; (2) refusal or unwillingness to perform
his duties; (3) inappropriate conduct in violation of Corporation's
equal employment opportunity policy; (4) conduct which reflects
adversely upon, or making any remarks disparaging of, the Corporation,
its Board of Directors, Officers, or employees, or its affiliates or
subsidiaries; (5) insubordination; (6) any willful act that is likely
to have the effect of injuring the reputation, business, or business
relationship of the Corporation or its subsidiaries or affiliates; (7)
violation of any fiduciary duty; or (8) breach of any duty of loyalty;
or (9) any breach of the restrictive covenants contained in Section 3.
Upon termination "for cause," the Corporation shall have no liability
to the Officer other than for accrued salary, vacation benefits, and
any vested rights the Officer may have under the Corporation's benefit
and compensation plans under the general terms and conditions of the
applicable plan.
3. Obligations of Officer
----------------------
(a) Release of Claims. The Corporation shall have no obligation to
------------------
commence the payment of the amounts and benefits described in Section
2(a) until the latter of (1) the delivery by Officer to the Corporation
a fully executed comprehensive general release of any and all known or
unknown claims that he or she may have against the Corporation and a
covenant not to sue in the form prescribed by the Administrator, and
(2) the expiration of any revocation period associated with the release
to which the Officer may be entitled under law.
-3-
<PAGE>
(b) Covenant Not to Compete. (i) During the period of Officer's employment
-----------------------
with the Corporation or its subsidiaries and for a period of years or
portion thereof equal to the Severance Multiple thereafter (the
"Restricted Period"), Officer shall not, in any county within the State
of California or in any city, county or area outside the State of
California within the United States or in the countries of Canada or
Mexico, directly or indirectly, whether as partner, employee,
consultant, creditor, shareholder, or other similar capacity, promote,
participate, or engage in any activity or other business competitive
with Corporation's business or that of any of its subsidiaries or
affiliates, without the prior written consent of Corporation's Chief
Executive Officer. Notwithstanding the foregoing, Officer may have an
interest in any public company engaged in a competitive business so
long as Officer does not own more than 2 percent of any class of
securities of such company, Officer is not employed by and does not
consult with, or becomes a director of, or otherwise engage in any
activities for, such competing company.
(ii) The Corporation and its subsidiaries presently conduct their
businesses within each county in the State of California and in areas
outside California that are located within the United States, and it is
anticipated that the Corporation and its subsidiaries will also be
conducting business within the countries of Canada and Mexico. Such
covenants are necessary and reasonable in order to protect the
Corporation and its subsidiaries in the conduct of their businesses.
To the extent that the foregoing covenant or any provision of this
Section 3(b)(e) shall be deemed illegal or unenforceable by a court or
other tribunal of competent jurisdiction with respect to (i) any
geographic area, (ii) any part of the time period covered by such
covenant, (iii) any activity or capacity covered by such covenant, or
(iv) any other term or provision of such covenant, such determination
shall not affect such covenant with respect to any other geographic
area, time period, activity or other term or provision covered by or
included in such covenant.
(c) Soliciting Corporation Customers and Employees. During the Restricted
----------------------------------------------
Period, Officer shall not, directly or indirectly, solicit or contact
any customer or any prospective customer of the Corporation for any
commercial pursuit that could be reasonably construed to be in
competition with the Corporation, or induce, or attempt to induce, any
employees, agents or consultants of or to the Corporation or any of its
subsidiaries or affiliates to do anything from which Officer is
restricted by reason of this covenant nor shall Officer, directly or
indirectly, offer or aid to others to offer employment to, or interfere
or attempt to interfere with any employment, consulting or agency
relationship with, any employees, agents or consultants of the
Corporation, its subsidiaries and affiliates, who received compensation
of $75,000 or more during the preceding six (6) months, to work for any
business competitive with any business of the Corporation, its
subsidiaries or affiliates.
(d) Confidentiality. Officer shall not at any time (including after
---------------
termination of employment) divulge to others, use to the detriment of
the Corporation, or use in any business competitive with any business
of the Corporation, any trade secret,
-4-
<PAGE>
confidential or privileged information obtained during his employment
with the Corporation, without first obtaining the written consent of
the Corporation's Chief Executive Officer. This paragraph covers but
is not limited to discoveries, inventions (except as otherwise
provided by California law), improvements, and writings, belonging to
or relating to the affairs of the Corporation or of any of its
subsidiaries or affiliates, or any marketing systems, customer lists
or other marketing data. Officer shall, upon termination of
employment for any reason, deliver to the Corporation all data,
records and communications, and all drawings, models, prototypes or
similar visual or conceptual presentations of any type, and all
copies or duplicates thereof, relating to all matters contemplated by
this paragraph.
(e) Assistance in Legal Proceedings. During the Restricted Period, Officer
-------------------------------
shall, upon reasonable notice from Corporation, furnish information and
proper assistance (including testimony and document production) to
Corporation as may be reasonably required by Corporation in connection
with any legal, administrative or regulatory proceeding in which it or
any of its subsidiaries or affiliates is, or may become, a party, or in
connection with any filing or similar obligation of Corporation imposed
by any taxing, administrative or regulatory authority having
jurisdiction, provided, however, that Corporation shall pay all
reasonable expenses incurred by Officer in complying with this
paragraph.
(f) Remedies. Upon Officer's failure to comply with the provisions of this
---------
Section 3, the Corporation shall have the right to immediately
terminate the payment of the amounts and benefits described in Section
2(a) to Officer and Corporation shall have no further obligations under
this Policy. As damages for breach or threatened breach of any of the
covenants set forth in this Section 3 will be difficult to determine
and will not afford a full and adequate remedy, the Corporation in
addition to seeking actual damages in connection therewith and ceasing
its obligations hereunder, may seek specific performance of any such
covenant in any court of competent jurisdiction, including without
limitation, by the issuance of a temporary or permanent injunction.
4. Administration
--------------
The Policy shall be administered by the Chief Human Resources Officer of
the Corporation ("Administrator"), who shall have the authority to
interpret the Policy and make and revise such rules as may be reasonably
necessary to administer the Policy. The Administrator shall have the duty
and responsibility of maintaining records, making the requisite
calculations, securing Officer releases, and disbursing payments hereunder.
The Administrator's interpretations, determinations, rules, and
calculations shall be final and binding on all persons and parties
concerned.
-5-
<PAGE>
5. No Mitigation
-------------
Payment of the amounts and benefits under Section 2(a) (except as otherwise
provided in Section 2(a)(iv)) shall not be subject to offset, counterclaim,
recoupment, defense or other claim, right or action which the Corporation
may have, and shall not be subject to a requirement that Officer mitigate
or attempt to mitigate damages resulting from Officer's termination of
employment.
6. Amendment and Termination
-------------------------
The Corporation, acting through its Nominating and Compensation Committee,
reserves the right to amend or terminate the Policy at any time; provided,
however, that any amendment which would reduce the aggregate level of
benefits, or terminate the Policy, shall not become effective prior to the
third anniversary of the Corporation giving notice to Officers of such
amendment or termination.
7. Nonassignability of Benefits
----------------------------
The payments under this Policy or the right to receive future payments
under this Policy may not be anticipated, alienated, pledged, encumbered,
or subject to any charge or legal process, and if any attempt is made to do
so, or a person eligible for payments becomes bankrupt, the payments under
the Policy of the person affected may be terminated by the Administrator
who, in his or her sole discretion, may cause the same to be held if
applied for the benefit of one or more of the dependents of such person or
make any other disposition of such benefits that he or she deems
appropriate.
8. Nonguarantee of Employment
--------------------------
Officers covered by the Policy are at-will employees, and nothing contained
in this Policy shall be construed as a contract of employment between the
Officer and the Corporation (or, where applicable, a subsidiary or
affiliate of the Corporation), or as a right of the Officer to continued
employment, or to remain as an Officer, or as a limitation on the right of
the Corporation (or a subsidiary or affiliate of the Corporation) to
discharge Officer at any time, with or without cause.
9. Benefits Unfunded and Unsecured
-------------------------------
The payments under this Policy are unfunded, and the interest under this
Policy of any Officer and such Officer's right to receive payments under
this Policy shall be an unsecured claim against the general assets of the
Corporation.
-6-
<PAGE>
10. Applicable Law
--------------
All questions pertaining to the construction, validity, and effect of the
Policy shall be determined in accordance with the laws of the United States
and, to the extent not preempted by such laws, by the laws of the state of
California.
11. Arbitration
-----------
With the exception of any request for injunctive or other equitable relief,
any dispute or controversy arising out of this Policy, or out of Officer's
employment with Corporation (or with the employing subsidiary) or
termination thereof, including tort, breach of contract, breach of covenant
of good faith and fair dealing, and discrimination or harassment under
applicable federal, state, or local laws, shall be resolved exclusively
by final and binding arbitration in accordance with the Commercial
Arbitration Rules of the American Arbitration Association then in effect.
Provided, however, that in making its determination, the arbitrator shall
be limited to accepting the position of the Officer or the position of the
Corporation, as the case may be. The only claims not covered by this
Section 11 are claims for benefits under workers' compensation or
unemployment insurance laws; such claims will be resolved under those laws.
The place of arbitration shall be San Francisco, California. Parties may
be represented by legal counsel at the arbitration but must bear their own
fees for such representation. The losing party in any dispute or
controversy shall pay all of the prevailing party's costs, including any
arbitrator or administrative fees and reasonable attorneys' fees. Both the
Officer and the Corporation specifically waive any right to a jury trial on
any dispute or controversy covered by this Section 11. Judgment may be
entered on the arbitrators award in any court having jurisdiction.
-7-
<PAGE>
EXHIBIT 11
PG&E CORPORATION
COMPUTATION OF EARNINGS PER COMMON SHARE
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------------------------------------------
Year ended December 31,
----------------------------------------
(in thousands, except per share amounts) 1998 1997 1996
- --------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
EARNINGS PER COMMON SHARE (EPS) AS SHOWN
IN THE STATEMENT OF CONSOLIDATED INCOME
Earnings available for common stock $ 719,488 $ 715,940 $ 722,096
========== ========== ==========
Average common shares outstanding 381,907 410,040 412,542
========== ========== ==========
Basic EPS $ 1.88 $ 1.75 $ 1.75
========== ========== ==========
DILUTED EPS (1)
Earnings available for common stock $ 719,488 $ 715,940 $ 722,096
========== ========== ==========
Average common shares outstanding 381,907 410,040 412,542
Add exercise of options, reduced by the
number of shares that could have been
purchased with the proceeds from
such exercise (at average market price) 1,198 211 9
---------- ---------- ----------
Average common shares outstanding as
adjusted 383,106 410,251 412,551
========== ========== ==========
Diluted EPS $ 1.88 $ 1.75 $ 1.75
========== ========== ==========
</TABLE>
- -------------------------------------------------------------------------------
(1) This presentation is submitted in accordance with Statement of Financial
Accounting Standards No. 128.
<PAGE>
EXHIBIT 12.1
PACIFIC GAS AND ELECTRIC COMPANY
COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------------------------------
Year ended December 31,
----------------------------------------------------------
(dollars in millions) 1998 1997 1996 1995 1994
- ------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Earnings:
Net income $ 729 $ 768 $ 755 $ 1,339 $ 1,007
Adjustments for minority
interests in losses of
less than 100% owned
affiliates and the
Company's equity in
undistributed losses
(income) of less than
50% owned affiliates - - 3 4 (3)
Income tax expense 629 609 555 895 837
Net fixed charges 673 628 683 716 729
------- -------- -------- -------- --------
Total Earnings $ 2,031 $ 2,005 $ 1,996 $ 2,954 $ 2,570
======= ======== ======== ======== ========
Fixed Charges:
Interest on long-
term debt, net $ 585 $ 485 $ 574 $ 616 $ 639
Interest on short-
term borrowings 50 101 75 83 77
Interest on capital leases 2 2 3 3 2
AFUDC debt 12 17 8 11 13
Earnings required to
cover the preferred stock
dividend and preferred
security distribution
requirements of majority
owned trust 24 24 24 3 -
------- -------- -------- -------- --------
Total Fixed Charges $ 673 $ 629 $ 684 $ 716 $ 731
======= ======== ======== ======== ========
Ratios of Earnings to
Fixed Charges 3.02 3.19 2.92 4.13 3.52
- ------------------------------------------------------------------------------------------------------
</TABLE>
Note: For the purpose of computing Pacific Gas and Electric Company's ratios
of earnings to fixed charges, "earnings" represent net income adjusted
for the minority interest in losses of less than 100% owned affiliates,
cash distributions from and equity in undistributed income or loss of
Pacific Gas and Electric Company's less than 50% owned affiliates,
income taxes and fixed charges (excluding capitalized interest). "Fixed
charges" include interest on long-term debt and short-term borrowings
(including a representative portion of rental expense), amortization of
bond premium, discount and expense, interest of subordinated debentures
held by trust, interest on capital leases, and earnings required to
cover the preferred stock dividend requirements.
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT 12.2
PACIFIC GAS AND ELECTRIC COMPANY
COMPUTATION OF RATIOS OF EARNINGS TO COMBINED FIXED CHARGES AND PREFERRED STOCK DIVIDENDS
- ----------------------------------------------------------------------------------------------------
Year ended December 31,
-------------------------------------------------------
(dollars in millions) 1998 1997 1996 1995 1994
- ----------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Earnings:
Net income $ 729 $ 768 $ 755 $ 1,339 $ 1,007
Adjustments for minority
interests in losses of
less than 100% owned
affiliates and the
Company's equity in
undistributed losses
(income) of less than
50% owned affiliates - - 3 4 (3)
Income tax expense 629 609 555 895 837
Net fixed charges 673 628 683 716 729
-------- -------- -------- -------- --------
Total Earnings $ 2,031 $ 2,005 $ 1,996 $ 2,954 $ 2,570
======== ======== ======== ======== ========
Fixed Charges:
Interest on long-
term debt, net $ 585 $ 485 $ 574 $ 616 $ 639
Interest on short-
term borrowings 50 101 75 83 77
Interest on capital leases 2 2 3 3 2
AFUDC debt 12 17 8 11 13
Earnings required to
cover the preferred stock
dividend and preferred
security distribution
requirements of majority
owned trust 24 24 24 3 -
-------- -------- -------- -------- --------
Total Fixed Charges $ 673 $ 629 $ 684 $ 716 $ 731
-------- -------- -------- -------- --------
Preferred Stock Dividends:
Tax deductible dividends $ 9 $ 10 $ 10 $ 11 $ 5
Pretax earnings required
to cover non-tax
deductible preferred
stock dividend
requirements 31 39 39 100 96
-------- -------- -------- -------- --------
Total Preferred
Stock Dividends $ 40 $ 49 $ 49 $ 111 $ 101
-------- -------- -------- -------- --------
Total Combined Fixed
Charges and Preferred
Stock Dividends $ 713 $ 678 $ 733 $ 827 $ 832
======== ======== ======== ======== ========
Ratios of Earnings to
Combined Fixed Charges and
Preferred Stock Dividends 2.85 2.96 2.72 3.57 3.09
- ----------------------------------------------------------------------------------------------------
</TABLE>
Note: For the purpose of computing Pacific Gas and Electric Company's ratios
of earnings to combined fixed charges and preferred stock dividends,
"earnings" represent net income adjusted for the minority interest in
losses of less than 100% owned affiliates, cash distributions from and
equity in undistributed income or loss of Pacific Gas and Electric
Company's less than 50% owned affiliates, income taxes and fixed
charges (excluding capitalized interest). "Fixed charges" include
interest on long-term debt and short-term borrowings (including a
representative portion of rental expense), amortization of bond
premium, discount and expense, interest on capital leases, interest of
subordinated debentures held by trust, and earnings required to cover
the preferred stock dividend requirements of majority owned
subsidiaries. "Preferred stock dividends" represent pretax earnings
which would be required to cover such dividend requirements.
<PAGE>
EXHIBIT 13
SELECTED FINANCIAL DATA
<TABLE>
<CAPTION>
(in millions, except per share amounts) 1998 1997 1996 1995 1994
<S> <C> <C> <C> <C> <C>
PG&E CORPORATION(1)
- -------------------
For the Year
Operating revenues $19,942 $15,400 $ 9,610 $ 9,622 $10,350
Operating income 2,007 1,728 1,896 2,763 2,424
Net income 719 716 722 1,269 950
Earnings per common share 1.88 1.75 1.75 2.99 2.21
Dividends declared per common share 1.20 1.20 1.77 1.96 1.96
At Year-End
Book value per common share $ 21.08 $ 21.30 $ 20.73 $ 20.77 $ 20.07
Common stock price per share 31.50 30.31 21.00 28.38 24.38
Total assets 33,234 31,115 26,237 26,871 27,738
Long-term debt (excluding current portions) 7,422 7,659 7,770 8,049 8,676
Rate reduction bonds (excluding current portions) 2,321 2,611 -- -- --
Redeemable preferred stock and securities of
subsidiaries (excluding current portions) 635 750 694 694 725
PACIFIC GAS AND ELECTRIC COMPANY
- --------------------------------
For the Year
Operating revenues $ 8,924 $ 9,495 $ 9,610 $ 9,622 $10,350
Operating income 1,876 1,831 1,896 2,763 2,424
Income available for common stock 702 735 722 1,269 950
At Year-End
Total assets $22,950 $25,147 $26,237 $26,871 $27,738
Long-term debt (excluding current portions) 5,444 6,218 7,770 8,049 8,676
Rate reduction bonds (excluding current portions) 2,321 2,611 -- -- --
Redeemable preferred stock and securities
(excluding current portions) 579 694 694 694 725
</TABLE>
- ---------------
(1) PG&E Corporation became the holding company for Pacific Gas and Electric
Company on January 1, 1997. The Selected Financial Data of PG&E Corporation
and Pacific Gas and Electric Company (the Utility) for the years 1994
through 1996 are identical because they reflect the accounts of the Utility
as the predecessor of PG&E Corporation. Matters relating to certain data
above are discussed in Management's Discussion and Analysis and in Notes to
the Consolidated Financial Statements.
17
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS
PG&E Corporation is an energy-based holding company headquartered in San
Francisco, California. PG&E Corporation's businesses provide energy services
throughout North America. PG&E Corporation's Northern and Central California
energy utility subsidiary, Pacific Gas and Electric Company (the Utility),
provides natural gas and electric service to one of every 20 Americans. PG&E
Corporation's four unregulated businesses provide a wide range of energy
products and services through its wholesale and retail unregulated business
operations.
PG&E Corporation's wholesale unregulated business operations consist
of U.S. Generating Company (USGen) which develops, builds, operates, owns,
and manages power generation facilities that serve wholesale and industrial
customers; PG&E Gas Transmission (PG&E GT) which operates approximately 9,000
miles of natural gas pipelines, natural gas storage facilities, and natural
gas processing plants in the Pacific Northwest (PG&EGTNW) and Texas (PG&E
GTT); and PG&E Energy Trading (PG&E ET) which purchases and resells energy
commodities and related financial instruments in major North American
markets, serving PG&E Corporation's other unregulated businesses,
unaffiliated utilities, and large end-use customers.
PG&E Corporation's retail unregulated business operations consist of
PG&E Energy Services (PG&E ES) which provides competitively priced
electricity, natural gas, and related services to lower overall energy costs
for industrial, commercial, and institutional customers.
This is a combined annual report of PG&E Corporation and Pacific Gas
and Electric Company. It includes separate consolidated financial statements for
each entity. The consolidated financial statements of PG&E Corporation reflect
the accounts of PG&E Corporation, the Utility, and PG&E Corporation's other
wholly owned and controlled subsidiaries. The consolidated financial statements
of the Utility reflect the accounts of the Utility and its wholly owned
subsidiaries.
PG&E Corporation was formed in 1997 as the parent holding company for the
Utility and the unregulated businesses. Information for 1996 in PG&E
Corporation's consolidated financial statements is identical to information in
the Utility's consolidated financial statements because they represent the
accounts of Utility as the predecessor of PG&E Corporation.
This combined annual report, including our Letter to Shareholders and
this Management's Discussion and Analysis (MD&A), contains forward-looking
statements about the future that are necessarily subject to various risks and
uncertainties. These statements are based on the beliefs and assumptions of
management and on information currently available to management. These
forward-looking statements are identified by words such as "estimates,"
"expects," "anticipates," "plans," "believes," and other similar expressions.
Factors that could cause future results to differ materially from
those expressed in or implied by the forward-looking statements or historical
results include the impact or outcome of:
* the pace and extent of the ongoing restructuring of the electric and gas
industries across the United States;
* the outcome of regulatory and legislative proceedings and operational changes
related to industry restructuring;
* any changes in the amount the Utility is allowed to collect (recover) from its
customers for certain costs which prove to be uneconomic under the new
competitive market (called transition costs) in accordance with the Utility's
plan for recovering those costs;
* the successful integration and performance of our recently acquired assets;
* our ability to successfully compete outside our traditional regulated markets;
* internal and external Year 2000 software and hardware issues;
* the outcome of ongoing regulatory proceedings, including: the Utility's cost
of capital proceeding; the Utility's 1999 general rate case; the Utility's
proposal to adopt performance based ratemaking (PBR); the Utility's
transmission rate case applications; and the California Public Utilities
Commission's (CPUC) regulatory proceedings including its audit of the
Utility's affiliate transactions;
* fluctuations in commodity gas and electric prices and our ability to
successfully manage such price fluctuations; and
* the pace and extent of competition in the California generation market and its
impact on the Utility's costs and resulting collection of transition costs.
18
<PAGE>
Although the ultimate impacts of the above factors are uncertain, these and
other factors may cause future earnings to differ materially from results or
outcomes we currently seek or expect. Each of these factors is discussed in
greater detail in this MD&A.
In this MD&A, we first discuss our competitive and regulatory environment. We
then discuss earnings and changes in our results of operations for 1998, 1997,
and 1996. Finally, we discuss liquidity and financial resources, various
uncertainties that could affect future earnings, and our risk management
activities. Our MD&A applies to both PG&E Corporation and the Utility. The MD&A
should be read in conjunction with the associated consolidated financial
statements of both PG&E Corporation and the Utility.
Competitive and Regulatory Environment
This section provides a discussion of the competitive environment in the
evolving energy industry, the California transition plans, the New England
electricity market, and regulatory matters.
The Competitive Environment in the Evolving Energy Industry
Historically, energy utilities operated as regulated monopolies within
specific service territories where they were essentially the sole suppliers
of natural gas and electricity services. Under this model, the energy utilities
owned and operated all of the businesses necessary to procure, generate,
transport, and distribute energy. These services were priced on a combined
(bundled) basis, with rates charged by the energy companies designed to include
all of the costs of providing these services. Now, energy utilities face
intensifying pressures to make competitive those activities that are not natural
monopoly services. The most significant of these services are electricity
generation and natural gas supply.
The driving forces behind these competitive pressures are customers
who believe they can obtain energy at lower unit prices and competitors who
want access to those customers. Regulators and legislators are responding to
those customers and competitors by providing more competition in the energy
industry. Regulators and legislators are requiring utilities to "unbundle"
rates (separate their various energy services and the prices of those
services). This allows customers to compare unit prices of the Utility and
other pro-viders when selecting their energy service provider.
In the natural gas industry, Federal Energy Regulatory Commission
(FERC) Order 636 required interstate pipeline companies to divide their
services into separate gas commodity sales, transportation, and storage
services. Under Order 636, interstate gas pipelines must provide transportation
service regardless of whether the customer (typically a local gas distribution
company) buys the gas commodity from the pipeline.
In the electric industry, the Public Utilities Regulatory Policies
Act of 1978 specifically provided that unregulated companies could become
wholesale generators of electricity and that utilities were required to
purchase and use power generated by these unregulated companies in meeting their
customers' needs. The National Energy Policy Act of 1992 was designed to
increase competition in the wholesale unregulated generation market by requiring
access to electric utility transmission systems by all wholesale unregulated
generators, sellers, and buyers of electricity. Now, an increasing number of
states throughout the country have either implemented plans or are considering
proposals to separate the generation from the transmission and distribution of
electricity through some form of electric industry restructuring.
To date, the states, not the federal government, have taken the initiative on
electric industry restructuring at the retail level. While at least five bills
mandating deregulation of the electric industry were introduced in the U.S.
Congress over the past two years, none have been passed. As a result, the pace,
extent, and methods for restructuring the electric industry vary widely
throughout the country. For instance, California, Illinois, Pennsylvania, and
several New England states have passed electric industry restructuring
legislation. Other states are considering restructuring proposals. There are
also some states that have passed legislation precluding or significantly
slowing down deregulation. Differences in how individual states view electric
industry restructuring often relate to the existing unit cost of energy supplies
within each state. Generally, states having higher energy unit costs are moving
more quickly to deregulate energy supply markets.
Implementation of our national energy strategy depends, in part, upon
the opening of energy markets to provide customer choice of supplier. Undue
delays
19
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS
by states or federal legislation to deregulate the electric generation and
natural gas supply business could impact the pace of growth of our retail
unregulated business operations.
California Transition Plans
The Electric Business:
In 1998, California became one of the first states in the country to implement
an electric industry restructuring plan. Today, many Californians may choose to
purchase their electricity from (1) investor-owned utilities such as Pacific Gas
and Electric Company, or (2) unregulated retail electricity suppliers (for
example, marketers, including PG&E Energy Services, brokers, and aggregators).
The restructuring plan contemplates that the investor-owned utilities, including
the Utility, will continue to provide distribution services to substantially all
customers within their service territories, including providing electricity to
customers who choose not to be served by another service provider. California
electric industry restructuring has two major components: the competitive market
framework and the electric transition plan, which are discussed below.
Competitive Market Framework:
To create a competitive generation market, a Power Exchange (PX) and an
Independent System Operator (ISO) began operating in 1998. The Utility is
required to sell to the PX all of the electricity generated by its power plants
and electricity acquired under contract with unregulated generators. Also, the
Utility is required to buy from the PX all electricity needed to provide service
to retail customers that continue to choose the Utility as their electricity
supplier. The ISO schedules delivery of electrici ty for all market participants
to the transmission system. The Utility continues to own and maintain a portion
of the transmission system, but the ISO controls the operation of the system.
During 1998, the Utility continued its efforts to develop and implement
changes to its business processes and systems, including the customer
information and billing system, to accommodate electric industry restructuring.
To the extent that the Utility is unable to develop and implement such changes
in a successful and timely manner, there could be an adverse impact on the
Utility's or PG&E Corporation's future results of operations.
Electric Transition Plan:
Market-based revenues, determined by the market through sales to the PX, may
not be sufficient to recover (that is, to collect from customers) all of the
Utility's generation costs. To allow California investor-owned utilities the
opportunity to recover their transition costs (generation costs that would
not be recovered through market-based revenues) and to ensure a smooth
transition to a competitive market, the California legislature developed a
transition plan in the form of state legislation that was passed in 1996. The
transition plan will remain in effect until the earlier of December 31, 2001, or
when the Utility has recovered its authorized transition costs as determined by
the CPUC, with provisions that certain transition costs can be recovered after
the transition period. At the conclusion of the transition period, the Utility
will be at risk to recover any of its remaining generation costs through market-
based revenues. The transition plan contains three principal elements: (1) an
electric rate freeze and rate reduction, (2) the recovery of transition costs,
and (3) divestiture of utility-owned generation facilities. Each element is
discussed below.
Rate Freeze and Rate Reduction: The first element of the transition plan is
an electric rate freeze and an electric rate reduction. In 1997 and 1998, the
Utility held rates for its larger customers at 1996 levels, and it will hold
their rates at that level until the end of the transition period. On January
1, 1998, the Utility reduced electric rates for its residential and small
commercial customers by 10 percent from 1996 levels, and it will hold their
rates at that level until the end of the transition period. Collectively, these
actions are called a rate freeze.
To pay for the 10 percent rate reduction, the Utility refinanced $2.9
billion of its transition costs with the proceeds of rate reduction bonds
(see Note 9 of Notes to Consolidated Financial Statements). The bonds allow
for the rate reduction by lowering the carrying cost on a portion of the
transition costs and by deferring recovery of a portion of these transition
costs until after the transition period.
20
<PAGE>
Transition costs are being recovered from all Utility distribution
customers through a nonbypassable charge regardless of the customer's choice
of electricity supplier. As the customer charge for transition costs is
nonbypassable, the Utility believes that the availability of choice to its
customers will not have a material impact on its ability to recover
transition costs.
Revenues from frozen electric rates provide for the recovery of authorized
Utility costs, including transmission and distribution service, public purpose
programs, and nuclear decommissioning. To the extent the revenues from frozen
rates exceed authorized Utility costs, the remaining revenues constitute the
competitive transition charge (CTC) which recovers the transition costs. These
CTC revenues are subject to seasonal fluctuations in the Utility's sales volumes
and certain other factors.
Transition Cost Recovery: Transition costs consist of: (1) above-market sunk
costs (sunk costs are costs associated with Utility-owned generation assets
that are fixed and unavoidable and currently included in the Utility customers'
electric rates) and future costs, such as costs related to plant removal of
Utility-owned generation facilities, (2) costs associated with the Utility's
long-term contracts to purchase power at above-market prices from qualifying
facilities 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.)
Above-market sunk costs result when the book value of a facility is
in excess of its market value. Conversely, below-market sunk costs result
when the market value of a facility is in excess of its book value. The total
amount of generation facility costs to be included as transition costs will
be based on the aggregate of above-market and below-market values. The
above-market portion of these costs is eligible for recovery as a transition
cost. The below-market portion of these costs will reduce other unrecovered
transition costs. A valuation of a Utility-owned generation facility where
the market value exceeds the book value could result in a material charge to
Utility earnings if the valuation of the facility is determined based upon any
method other than a sale of the facility to a third party. This is because any
excess of market value over book value would be used to reduce other transition
costs.
The Utility will not be able to determine the exact amount of
above-market non-nuclear sunk costs that will be recoverable as transition
costs until a market valuation process (appraisal, spin, sale, or other
valuation method) is completed for each of its generation facilities. Several
of these valuations occurred in 1997 and 1998, when the Utility agreed to
sell seven of its electric plants. The market value of these facilities
determined by these sales exceeded the book value and will therefore reduce the
amount of transition costs to be recovered. In addition, in December 1998, the
Utility requested that the CPUC allow it to hire appraisers to set the value of
its hydroelectric generation system. (See Generation Divestiture below.) The
remainder of the valuation process is expected to be completed by December 31,
2001. Nuclear sunk costs were separately determined through a CPUC proceeding
and were subject to a final verification audit. This audit was completed in
August 1998, the results of which are currently under review. (See Regulatory
Matters below for further details.)
Costs associated with the Utility's long-term contracts to purchase
electric power at above-market prices are included as transition costs. Over
the remaining life of these contracts, the Utility estimates that it will
purchase 322 million megawatt-hours. To the extent that the individual
contract prices are above the market price, the Utility will be able to
collect the difference between the contract price and the market price from
customers, as a transition cost, over the term of the contract. The contracts
expire at various dates through 2028. During 1998, the average price paid per
kilowatt-hour (kWh) under the Utility's long-term contracts for electric
power was 7.4 cents per kWh. The average cost of electric energy for energy
purchased at market rates from the PX for the period from April 1, 1998, to
December 31, 1998, was 3.2 cents per kWh.
Generation-related regulatory assets and obligations (net generation-related
regulatory assets) are included as transition costs. These net regulatory assets
consist of those created prior to the transition period and those created during
the transition period. In 1998, the staff of the Securities and Exchange
Commission (SEC) issued interpretive guidance related to assets which are being
transitioned to a deregulated environment. The
21
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS
guidance states that an impairment analysis should be performed for such
assets and that the impairment analysis should exclude transition cost
revenues. The Utility has determined that certain of its generation
facilities are considered impaired under the SEC's interpretive guidance.
Because the Utility expects to recover the impaired assets as a transition cost,
it recorded a regulatory asset for the impaired amounts as required. As a
result, in 1998, $3.9 billion was reclassified from property, plant, and
equipment to regulatory assets on the Utility's balance sheet. Prior year
amounts were also reclassified. The Utility's generation-related regulatory
assets total $5.4 billion at December 31, 1998.
Under the transition plan, most transition costs can be recovered until
December 31, 2001. This recovery period is significantly shorter than the
recovery period of the generation assets prior to restructuring and is referred
to as accelerated recovery. Accordingly, the Utility is amortizing its
transition costs, including most generation-related regulatory assets over the
transition period. The CPUC believes that the transition plan reduces risks
associated with recovery of all the Utility's generation assets, including the
Diablo Canyon Nuclear Power Plant (Diablo Canyon) and the hydroelectric
facilities. As a result, during the transition period, the Utility is receiving
a reduced return on common equity for all of its generation assets, including
those generation assets reclassified to regulatory assets. In 1998, the reduced
return on common equity was 6.77 percent as compared to an authorized return on
common equity of 11.20 percent. The reduced return on common equity related to
generation assets will be in effect throughout the transition period.
Certain transition costs can be included in a nonbypassable charge to
distribution customers after the transition period. These costs include: (1)
certain employee-related transition costs, (2) above-market payments under
existing long-term contracts to purchase power, discussed above, and (3)
unrecovered electric industry restructuring implementation costs. In addition,
transition costs financed by the issuance of rate reduction bonds are expected
to be recovered over the term of the bonds. Further, the Utility's nuclear
decommissioning costs are being recovered through a CPUC-authorized charge,
which will extend until sufficient funds exist to decommission our nuclear
facility. During the rate freeze, this charge and the rate reduction bond debt
service will not increase the Utility customers' electric rates. Excluding these
exceptions, the Utility will write-off any transition costs not recovered during
the transition period.
Under the terms of the transition plan, revenues provided for the
recovery of most non-nuclear transition costs are based upon the acceleration
of such costs within the transition period. For nuclear transition costs,
revenues provided for transition cost recovery are based on: (1) an established
incremental cost incentive price per kWh generated by Diablo Canyon to recover
certain ongoing costs and capital additions, and (2) the accelerated recovery of
the investment in Diablo Canyon from a period ending in 2016 to a five-year
period ending December 31, 2001.
The Utility is amortizing its eligible transition costs, including
generation-related regulatory assets, over the transition period in conjunction
with the available CTC revenues. Effective January 1, 1998, the Utility started
collecting these eligible transition costs through the nonbypassable CTC. During
1998, regulatory assets related to electric utility restructuring decreased by
$609 million. This decrease reflects the recovery of eligible transition costs
of $486 million through accelerated amortization and $123 million through the
gain on the sale of generating plants.
During the transition period, the CPUC will review the Utility's compliance
with the accounting methods used by the Utility to recover transition costs and
the amount of transition costs requested for recovery. The CPUC is currently
reviewing non-nuclear transition costs amortized during the first six months of
1998. The Utility expects the CPUC to issue decisions regarding this review in
the second half of 1999. Transition costs that are disallowed by the CPUC for
collection from the Utility customers will be written off.
Generation Divestiture: In 1998, the Utility completed the sale of three
fossil-fueled generation plants for $501 million. These three fossil-fueled
plants had a combined book value at the time of the sale of
$346 million and had a combined capacity of 2,645 megawatts (MW).
22
<PAGE>
Also in 1998, the Utility agreed to sell three other fossil-fueled
generation plants and its complex of geothermal generation facilities. The
winning bids total $1,014 million. As of December 31, 1998, these four plants
had a combined book value of $523 million and had a combined capacity of
4,289 MW. The sales are subject to the approval of regulatory agencies,
including the CPUC, and conditioned upon the transfer of various permits and
licenses. The Utility expects to complete the sale of these four plants in
1999.
The Utility will retain a liability for required environmental
remediation related to all of its fossil-fueled and geothermal generation plants
of any pre-closing soil or groundwater contamination at the plants it has or
will sell. The Utility records its estimated liability for the retained
environmental remediation obligation as part of the determination of the gain or
loss on the sale of each plant.
Any net gains from the sale of our Utility-owned generation plants will be
used to offset other transition costs. As a result, we do not believe sales of
any generation facilities to a third party will have a material impact on our
results of operations.
The Utility is currently evaluating its options related to its remaining non-
nuclear generation facilities, primarily the hydroelectric generation system. In
May 1998, the Utility notified the CPUC that it does not plan to retain the
hydroelectric assets as part of the Utility. In December 1998, the Utility filed
with the CPUC its proposed appraisal process for valuing generation assets,
primarily the hydroelectric system. The Utility expects to receive a response to
this request in 1999.
At December 31, 1998, the book value of the Utility's net investment in
hydroelectric generation assets was $1.4 billion. If the Utility decides to
dispose of the hydroelectric generation assets by any method other than a sale
of the assets to a third party, a material charge could result to the extent
that the market value of the assets exceeds their book value. The market value
of the hydroelectric assets is expected to exceed their book value by a material
amount.
Financial Impact: The Utility's ability to continue recovering its transition
costs will be dependent on several factors including: (1) the continued
application of the regulatory framework established by the CPUC and state
legislation, (2) the amount of transition costs ultimately approved for recovery
by the CPUC, (3) the market value of the remaining Utility-owned generation
facilities, (4) future Utility sales levels, (5) future Utility fuel and
operating costs, (6) the extent to which the Utility's authorized revenues to
recover distribution costs are increased or decreased (see Regulatory Matters),
and (7) the market price of electricity. Given our current evaluation of these
factors, we believe that the Utility will recover its transition costs under the
terms of the approved transition plan. However, a change in one or more of these
factors could affect the probability of recovery of transition costs and result
in a material charge.
The Gas Business:
Restructuring of the natural gas industry on both the national and the state
level has given choices to California utility customers to meet their gas
supply needs. The Gas Accord Settlement (Accord), a multi-party settlement
approved by the CPUC in 1997, continues the process of restructuring the gas
industry in California. The Accord was implemented in 1998, and has four
principal elements:
1. The Accord separates or "unbundles" the rates for the Utility's gas
transportation system. The Utility now offers transmission, distribution, and
storage services as separate and distinct services to its noncore customers.
Unbundling gives these customers the opportunity to select from a menu of
services offered by the Utility and enables them to pay only for the services
that 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 Accord makes the Utility's transmission system more accessible
to a greater number of customers.
2. The Accord increases the opportunity for the Utility's core customers to
select the commodity gas supplier of their choice. Greater customer choice
increases competition among suppliers providing gas to core customers and
reduces the Utility's role in purchasing gas for such customers. Despite
these changes, the Utility continues to purchase gas as a regulated supplier
for those who request it, serving a majority of core customers in its service
territory.
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MANAGEMENT'S DISCUSSION AND ANALYSIS
3. The Accord changes the way in which the Utility's costs of purchasing gas for
core customers through 2002 are regulated. The Accord replaces CPUC
reasonableness reviews with the core procurement incentive mechanism (CPIM),
a form of incentive ratemaking that provides the Utility a direct financial
incentive to procure gas and transportation services at the lowest reasonable
costs by comparing all procurement costs to an aggregate market-based
benchmark. If costs fall within a range (tolerance band) around the
benchmark, costs are considered reasonable and fully recoverable from
ratepayers. If procurement costs fall outside the tolerance band, ratepayers
and shareholders share savings or costs, respectively. The CPIM results for
1997 and 1998 had an immaterial impact on the Utility's results of
operations.
4. The Accord settled various regulatory issues involving the Utility and
various other parties. Resolution of these issues did not have a material
adverse impact on the Utility's or our financial position or results of
operations.
The Accord also establishes gas transmission rates within California for the
period from March 1998 through December 2002 for the Utility's core and noncore
customers and eliminates regulatory protection for variations in sales volumes
for noncore transmission revenues. As a result, the Utility is at risk for
variations between actual and forecasted noncore transmission throughput
volumes. However, we do not expect these variations to have a material adverse
impact on the Utility's or our financial position or results of operations.
Rates for gas distribution services will continue to be set by the CPUC and
designed to provide the Utility an opportunity to recover its costs of service
and include a return on its investment. The regulatory mechanisms for setting
gas distribution rates are discussed below under Regulatory Matters.
New England Electricity Market
Three New England states where our unregulated businesses operate electric
generation facilities (Massachusetts, New Hampshire, and Rhode Island) were,
like California, among the first states in the country to introduce electric
industry restructuring. Connecticut also has passed electric industry
restructuring legislation. As a result of this restructuring, the wholesale
unregulated electricity market in New England features a bid-based market and
an independent system operator.
In September 1998, PG&E Corporation, through its indirect subsidiary USGen
New England, Inc., completed the acquisition of a portfolio of electric
generation assets and power supply contracts from New England Electric System
(NEES). (See Note 5 of Notes to Consolidated Financial Statements.) The NEES
assets include hydroelectric, coal, oil, and natural gas generation facilities
with a combined generating capacity of about 4,000 MW.
Including fuel and other inventories and transaction costs, the financing
requirements for this transaction were approximately $1.8 billion, funded
through $1.3 billion of USGen debt and a $425 million equity contribution from
PG&E Corporation. The net purchase price has been allocated as follows: (1)
electric generating assets of $2.3 billion, (2) receivable for support payments
of $0.8 billion, and (3) contractual obligations of $1.3 billion.
As part of the New England electric industry restructuring, the local utility
companies providing service to retail customers were required to offer Standard
Offer Service (SOS) to their customers. Retail customers may select alternative
suppliers at any time. The SOS is intended to provide customers with a price
benefit (the commodity electric price offered to the retail customer is expected
to be less than the market price) for the first several years, followed by a
price disincentive that is intended to stimulate the retail market.
Retail customers may continue to receive SOS through June 30, 2002, in New
Hampshire (subject to early termination on December 31, 2000, at the discretion
of the New Hampshire Public Service Commission), through December 31, 2004, in
Massachusetts, and through December 31, 2009, in Rhode Island. However, if any
customers elect to have their electricity provided by an alternate supplier,
they are precluded from going back to the SOS.
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<PAGE>
In connection with the purchase of the generation assets, we entered into
agreements to supply the electric capacity and energy requirements necessary for
NEES to meet its SOS obligations. NEES is responsible for passing on to us the
revenues generated from the SOS.
Like California utilities, the New England utilities entered into agreements
with unregulated companies to provide energy and capacity at prices which are
anticipated to be in excess of market prices. We assumed NEES's contractual
rights and duties under several of these power-purchase agreements, which in
aggregate provide for 800 MW of capacity. However, NEES will make support
payments to us toward the cost of these agreements. The support payments by NEES
total $1.1 billion in the aggregate (undiscounted) and are due in monthly
installments from September 1998 through January 2008. In certain circumstances,
with our consent, NEES may make a full or partial lump sum accelerated payment.
Initially, approximately 90 percent of the acquired operating capacity,
including capacity and energy generated by other companies and provided to us
under power-purchase agreements, is dedicated to providing services to customers
receiving SOS.
Regulatory Matters
The Utility is the only subsidiary with significant regulatory activity at
this time. Items affecting future Utility authorized revenues include: the
1999 general rate case, the 1999 cost of capital proceeding, the distribution
performance based ratemaking application, and the CPUC's gas strategy order
instituting rulemaking. These items are discussed below. Any requested change
in authorized revenues resulting from any of these proceedings would not
impact the Utility's customer electric rates through the transition period
because these rates are frozen in accordance with the electric transition plan.
However, the amount of remaining revenues providing for the recovery of
transition costs would be affected.
The Utility's 1999 General Rate Case (GRC):
In December 1997, the Utility filed its 1999 GRC application with the CPUC.
During the GRC process, the CPUC examines the Utility's distribution costs to
determine the amount we can charge customers. The Utility has requested rate
increases to maintain and improve gas and electric distribution reliability,
safety, and customer service. The requested revenues, as updated, include an
increase of $445 million in electric base revenues and an increase of $377
million in gas base revenues over authorized 1998 revenues. The Office of
Ratepayer Advocates (ORA) branch of the CPUC has recommended a decrease of $80
million in electric revenues and an increase of $104 million in gas base
revenues. However, recommendations by the ORA do not represent the positions of
the CPUC.
In December 1998, the CPUC issued a decision on interim rate relief
in the GRC. The decision granted the Utility's request to increase its
electric revenues by $445 million and its gas revenues by $377 million on an
interim basis pending a decision in the GRC. The decision allows the Utility
to reflect the revenue increases, resulting from the Utility request, in
regulatory assets recorded under regulatory adjustment mechanisms approved by
the CPUC. The decision does not increase any electric or gas rates charged to
customers on an interim basis. The regulatory assets will be adjusted to
reflect the final decision of the CPUC in the 1999 GRC when the decision is
issued. We cannot predict the amount of revenue increase or decrease the CPUC
ultimately will approve. If the CPUC issues an unfavorable decision for the
Utility, the ability of the Utility to earn its authorized rate of return, at
the current service levels, for the years 1999 through 2001 could be
adversely affected. The current procedural schedule provides for a final CPUC
decision in March 1999.
The 1999 GRC will not affect the authorized revenues of electric and gas
transmission services or gas storage services. The authorized revenues for gas
transmission and storage services are determined through the Gas Accord and
electric transmission revenues are determined by the FERC as described below.
Electric Transmission:
Since April 1, 1998, all electric transmission revenues are authorized by the
FERC. In December 1997, the FERC issued an order which put into effect,
subject to refund, rates to recover annual electric transmission revenues of
$301 million from the Utility's former
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<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS
bundled rate transmission customers. These rates became effective on April 1,
1998, the operational date of the ISO and PX. In May 1998, the FERC allowed a
$30 million increase in electric transmission revenues, effective October 30,
1998, also subject to refund.
The Utility's 1999 Cost of Capital Proceeding:
The Utility filed its cost of capital application in May 1998. If approved, the
authorized return on rate base for distribution assets would be 9.53 percent.
The 1999 cost of common equity would be 12.1 percent which is higher than the
11.2 percent authorized in 1998. This request would result in an increase of
$49.7 million in electric distribution revenues and an increase of $15.5 million
in gas distribution revenues over authorized 1998 revenues.
The ORA has recommended an overall return on rate base for electric and gas
distribution operations of 7.85 and 8.17 percent, respectively, and a cost of
common equity of 8.64 and 9.32 percent, respectively. If adopted, the ORA's
recommendation would result in a decrease from authorized 1998 revenues in
electric and gas distribution revenues of $162.5 million and $37.8 million,
respectively. However, recommendations by the ORA do not represent the positions
of the CPUC. We expect a final CPUC decision in early 1999.
The Utility's Distribution Performance Based Ratemaking (PBR) Application:
The Utility filed its distribution PBR proposal in November 1998. If approved
as filed, the distribution PBR will determine the Utility's gas and electric
distribution revenues for the years 2000 through 2004. Under the Utility's
proposal, distribution revenues for the year 2000 would be determined by
multiplying total distribution revenues by a rate formula, based principally
on inflation less a proposed productivity factor of 1.1 percent and 0.82
percent for electric distribution and gas distribution, respectively. These
productivity factors will be fixed for the five year duration of the PBR. The
revenues for years 2000 through 2004 would be determined by multiplying total
distribution revenues by the PBR authorized rate. We have proposed different
formulas for small customers (principally residential and commercial
customers) and large customers.
The proposal also includes a sharing mechanism for earnings that are
significantly above or below the authorized weighted average cost of capital. In
addition, the proposed PBR includes rewards and penalties that will depend upon
the Utility's ability to achieve performance standards for electric distribution
reliability; maintenance, repair, and replacement; customer service; and
employee safety. The Commission will have hearings in the PBR proceeding in
August 1999 to determine adopted values for the PBR formula and sharing
parameters. The final schedule is uncertain, but a Commission decision is
expected after January 1, 2000. In this event, the Utility proposes to implement
the PBR-based distribution component rates retroactively to January 1, 2000.
The CPUC's Gas Strategy Order Instituting Rulemaking (OIR):
In 1998, the Governor of California signed Senate Bill 1602, allowing the CPUC
to investigate issues associated with the further restructuring of natural gas
services. If the CPUC determines that further restructuring for core customers
is in the public interest, it shall submit its findings to the Legislature.
However, Senate Bill 1602 prohibits the CPUC from enacting any such gas industry
restructuring decisions prior to January 1, 2000.
The CPUC's Audit of Affiliate Transactions:
PG&E Corporation became the holding company of the Utility in 1997. At that
time, we transferred the unregulated subsidiaries of the Utility to PG&E
Corporation. A condition of the CPUC's approval of the holding company formation
was that the ORA oversee an audit of transactions between the Utility and its
affiliates for the period 1994 to 1996. The audit was completed in November
1997. The principal claim in the resulting audit report, substantially denied by
the Utility, was that the Utility underbilled affiliates by $35 million during
the period from 1994 to 1996. The auditors recommended the CPUC impose new
conditions, affecting the financing and business structure of PG&E Corporation.
We are opposing the recommended new conditions. A final CPUC decision is
expected during the first quarter of 1999.
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<PAGE>
If the CPUC imposed the recommended financial conditions on PG&E Corporation
without modification, such conditions could have an adverse impact on our
ability to implement our national energy strategy.
The Diablo Canyon Sunk Costs Audit:
In August 1998, an independent accounting firm retained by the CPUC completed
a financial verification audit of the Utility's Diablo Canyon plant accounts
as of December 31, 1996. The audit resulted in the issuance of an unqualified
opinion. The audit verified that Diablo Canyon sunk costs at December 31,
1996, were $3.3 billion of the total $7.1 billion construction costs. (Sunk
costs are costs associated with Utility-owned generating facilities that are
fixed and unavoidable and currently included in the Utility customers' electric
rates.) The independent accounting firm also issued an agreed-upon special
procedures report which questioned $200 million of the $3.3 billion sunk costs.
The CPUC will review any proposed adjustments to Diablo Canyon's recoverable
costs, which resulted from the report. At this time, the Utility cannot predict
what actions, if any, the CPUC may take regarding the audit report.
Results of Operations
In this section, we present the components of our results of operations for
1998, 1997, and 1996. The table below shows for 1998, 1997, and 1996, certain
items from our Statement of Consolidated Income detailed by (1) Utility, (2)
wholesale and (3) retail business operations of PG&E Corporation. (In the
"Total" column, the table shows the combined results of operations for these
three groups.) The information for PG&E Corporation (the "Total" column)
excludes all transactions between its subsidiaries (such as the purchase of
natural gas by the Utility from the unregulated business operations).
Following this table we discuss earnings and explain why the components of
our results of operations varied from the year before for 1998 and 1997.
<TABLE>
<CAPTION>
Wholesale Retail
---------------------------------- ------
PG&E GT
-------------
(In millions) Utility USGen NW Texas PG&E ET PG&E ES Corp./Other Eliminations Total
------- ----- -- ----- ------- ------- ----------- ------------ -----
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
1998
Operating revenues $8,924 $649 $237 $1,941 $8,509 $379 $ 8 $(705) $19,942
Operating expenses 7,048 489 101 1,996 8,528 470 3 (700) 17,935
------ ---- ---- ------ ------ ---- ---- ----- -------
Operating income (loss) 1,876 160 136 (55) (19) (91) 5 (5) 2,007
Other income, net 64
Interest expense 782
Income taxes 570
------ ---- ---- ------ ------ ---- ---- ----- -------
Net income $ 719
=======
1997
Operating revenues $9,495 $148 $233 $1,004 $4,808 $145 $13 $(446) $15,400
Operating expenses 7,664 176 127 1,023 4,840 190 98 (446) 13,672
------ ---- ---- ------ ------ ---- ---- ----- -------
Operating income (loss) 1,831 (28) 106 (19) (32) (45) (85) -- 1,728
Other income, net 201
Interest expense 665
Income taxes 548
------ ---- ---- ------ ------ ---- ---- ----- -------
Net income $ 716
=======
1996
Operating revenues $8,989 $105 $264 $ -- $ 283 $ -- $ 27 $ (58) $ 9,610
Operating expenses 7,179 118 136 -- 283 -- 56 (58) 7,714
------ ---- ---- ------ ------ ---- ---- ----- -------
Operating income (loss) 1,810 (13) 128 -- -- -- (29) -- 1,896
Other income, net 13
Interest expense 632
Income taxes 555
------ ---- ---- ------ ------ ---- ---- ----- -------
Net income $ 722
=======
</TABLE>
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MANAGEMENT'S DISCUSSION AND ANALYSIS
Overall Results:
PG&E Corporation:
Net income increased to $719 million in 1998 from $716 million in 1997. The
increase in 1998 net income was the result of a $279 million increase in
operating income, net of lower returns on the Utility's generation assets. This
increase was offset partially by increased interest costs for the Utility's rate
reduction bonds and debt associated with the recent unregulated wholesale
acquisitions of assets in Texas and New England.
The operating income increase of $279 million was primarily due to the growth
of our wholesale and retail operations which contributed $149 million of the
increase. This operating income increase was achieved despite operating losses
at PG&E ES and PG&E GTT. USGen contributed positively to operating income which
includes income generated from its portfolio management activities.
The operating losses at PG&EES reflect the continued start-up operations and
the impact of the developing retail energy market. At PG&E GTT, the natural gas
liquids operations have been adversely affected by the low price differential
between natural gas liquids (NGLs) prices and the cost of natural gas, which is
used to produce NGLs. In addition, low gas prices and a narrow spread in the
price of gas transported across Texas have reduced PG&E GTT's transportation and
gas sales.
The 1998 net income also includes a loss on the sale of our Australian energy
holdings. The sale represented a significant premium in Australian currency of
PG&E Corporation's 1996 investment in the assets. However, there was a 22
percent currency devaluation of the Australian dollar against the U.S. dollar
during the past two years. The net transaction resulted in a charge of
approximately $23 million in the second quarter of 1998. (See Note 5 of Notes to
Consolidated Financial Statements.)
Net income decreased from $722 million in 1996 to $716 million in 1997. The
1997 net income includes charges of approximately $51 million associated with
the write off of investments in power generation projects at USGen, which were
offset by the gain realized on the sale of our interests in International
Generation Company, Ltd. In April 1997, PG&E Enterprises, a wholly owned
subsidiary of PG&E Corporation, sold its interest in International Generating
Company, Ltd., which resulted in an after-tax gain of $120 million.
Utility:
Net income for the Utility decreased $39 million in 1998 from 1997 due to the
reduced rate of return on generation assets and increased interest expense
associated with the rate reduction bonds, discussed below.
Net income for the Utility increased $13 million in 1997 from 1996. Net
income for 1997 included a gain on the buy out of a long-term gas contract. The
increase in 1997 is also related to the increase in revenues associated with
electric transmission and distribution system reliability, discussed below. This
increase is partially offset by the reduction in returns on the Utility's Diablo
Canyon facility as required by electric industry restructuring legislation and
spending for system reliability and safety.
Operating Revenues:
Utility:
Utility operating revenues decreased $571 million in 1998 from 1997. This
decrease is primarily due to: (1) a $410 million decrease for the 10 percent
electric rate reduction provided to residential and small commercial customers,
which was partially offset by $108 million of higher revenues due to increased
consumption of electricity by these customers; (2) a $151 million decrease in
revenues from medium and large electric customers, many of whom are now
purchasing their electricity directly from unregulated power generators; (3) a
$63 million decrease in sales to commercial and agricultural electric customers
resulting from their lower demand for irrigation water pumping as a result of
heavier rainfall in the current year; and (4) a $100 million decrease for the
termination of the volumetric (ERAM) and energy cost (ECAC) revenue balancing
accounts. The ERAM and ECAC accounts were replaced with the transition cost
balancing account, which affects expenses, rather than revenues.
Utility operating revenues in 1997 increased $506 million from 1996. The
largest portion of the increase was due to electric transition cost recovery,
which began January 1, 1997, with respect to Diablo Canyon. A portion of the
increase is due to increased revenues
28
<PAGE>
associated with electric transmission and distribution system reliability. There
was also an increase in energy cost revenues to recover energy cost increases
and changes in sales volumes provided by the Utility's balancing account
mechanisms in place in 1997 and 1996. Under these mechanisms, energy revenues
generally equal energy costs and, thus, increases in the cost of energy do not
affect operating income.
Wholesale Unregulated Business Operations:
Operating revenues associated with wholesale unregulated business operations
increased $5,143 million in 1998 from 1997. This was primarily due to revenue
increases of $3,701 million from PG&E ET, $937 million from PG&E GTT and $501
million from USGen. Energy trading volumes grew at PG&E ET as growth of PG&E
Corporation and deregulation of the energy markets continued. PG&E GTT's
revenues increased as a result of twelve months of revenue from the Texas
acquisitions versus seven months in 1997. USGen's revenue increased as a result
of an increase in the portfolio management activity and the acquisition of NEES
in 1998.
Operating revenues associated with wholesale unregulated business operations
increased $5,541 million in 1997 from 1996. This was primarily due to a $4,525
million increase in energy commodities revenues and an increase in revenues
resulting from our 1997 acquisitions.
Retail Unregulated Business Operations:
Retail unregulated business operations contributed $379 million of revenue in
1998, an increase of $234 million from 1997. This increase is primarily due to
deregulation in California and the expansion of our energy services business in
the electric and gas commodity markets.
Operating revenues associated with retail unregulated business operations
totaled $145 million in 1997, the first year of operation.
Operating Expenses:
Utility:
Utility operating expenses in 1998 decreased $616 million from 1997. This
decrease reflects a reduction in the amount of amortization of transition
costs, primarily due to lower revenues from residential and small commercial
customers discussed above in Operating Revenues-Utility. Also contributing to
the decrease in operating expenses was a reduction in gas transportation
demand charges of $134 million, due to the expiration of contracted pipeline
capacity.
Utility operating expenses in 1997 increased $485 million from 1996. The
increase was due primarily to an increase in amortization of Diablo Canyon costs
which are being recovered as a transition cost as discussed above, an increase
in cost of energy, and an increase in expenditures associated with system
reliability. These increases were partially offset by a decrease in expenses
resulting from several charges in 1996 associated with gas transportation
commitments and a litigation reserve.
Wholesale Unregulated Business Operations:
Operating expenses for our wholesale unregulated business operations increased
$4,948 million in 1998 from 1997. This reflects the increase in the volumes of
energy commodities purchased at PG&EETand operating costs associated with our
newly acquired New England assets at USGen and the gas transportation assets at
PG&E GTT.
Wholesale unregulated business operations operating expenses in 1997
increased $5,629 million from 1996, which reflects the increase in the volume of
energy commodities purchased due to our 1997 acquisitions.
Retail Unregulated Business Operations:
Retail unregulated business operations operating expenses increased $280
million in 1998 as compared to 1997. This increase is primarily due to the
expansion of our energy services business.
Retail unregulated business operations operating expenses totaled $190
million in 1997, the first year of operation.
Other Income, Net:
Other income, net was $64 million in 1998 as compared to $201 million in 1997.
The decrease was primarily due to the $23 million loss on the sale of our
Australian holdings, discussed above, and a $120 million gain recorded in 1997.
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<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS
Other income, net increased by $188 million in 1997 as compared to 1996
primarily due to a $120 million gain realized on the sale of interests in
International Generating Company, Ltd.
Interest Expense:
Interest expense increased $117 million in 1998 from 1997. This increase was
primarily a result of increased interest costs for the Utility's rate reduction
bonds and debt for the acquisition of the Texas and New England assets.
Interest expense in 1997 increased $33 million from 1996 primarily due to
interest costs related to the Texas acquisitions.
Income Taxes:
Income taxes in 1998 increased $22 million from 1997. The overall effective
tax rate increased 0.9 percent in 1998 largely due to accelerated book
depreciation and amortization related to electric industry restructuring.
These increases were partially offset by a lowered effective state tax rate
resulting from our expanded business operations.
The effective tax rate decreased slightly in 1997 as compared to 1996,
resulting in a $7 million decrease in 1997 taxes.
Common Stock Dividend:
We base our common stock dividend on a number of financial considerations,
including sustainability, financial flexibility, and competitiveness with
investment opportunities of similar risk. Our current quarterly common stock
dividend is $.30 per common share, which corresponds to an annualized
dividend of $1.20 per common share. We continually review the level of our
common stock dividend taking into consideration the impact of the changing
regulatory environment throughout the nation, the resolution of asset
dispositions, the operating performance of our business units, and our
capital and financial resources in general.
The CPUC requires the Utility to maintain its CPUC-authorized capital
structure, potentially limiting the amount of dividends the Utility may pay
PG&E Corporation. In 1998, the Utility was in compliance with its
CPUC-authorized capital structure. PG&E Corporation and the Utility believe
that the Utility will continue to meet this requirement in the future without
affecting PG&E Corporation's ability to pay common stock dividends.
Liquidity and Financial Resources
Cash Flows from Operating Activities:
Net cash provided by PG&E Corporation's operating activities totaled $2.3
billion, $2.6 billion, and $2.6 billion in 1998, 1997, and 1996, respectively.
Net cash provided by the Utility's operating activities totaled $2.6 billion,
$1.8 billion, and $2.6 billion in 1998, 1997, and 1996, respectively.
Cash Flows from Financing Activities:
PG&E Corporation:
We fund investing activities from cash provided by operations after capital
requirements and, to the extent necessary, external financing. Our policy is
to finance our investments with a capital structure that minimizes financing
costs, maintains financial flexibility, and, with regard to the Utility,
complies with regulatory guidelines. Based on cash provided from operations
and our investing and disposition activities, we may repurchase equity and
long-term debt in order to manage the overall size and balance of our capital
structure.
During 1998, 1997, and 1996, we issued $63 million, $54 million, and
$220 million of common stock, respectively, primarily through the Dividend
Reinvestment Plan, the Stock Option Plan, and the Long-Term Incentive Plan.
During 1997, we also issued $1.1 billion of common stock to acquire the
natural gas assets in Texas. During 1998, 1997, and 1996, we paid dividends
of $470 million, $524 million, and $844 million, respectively.
During 1998, 1997, and 1996, we repurchased $1,158 million, $804 million, and
$455 million, respectively, of our common stock. In February 1999, PG&E
Corporation used the remaining portion of an existing authorization to
repurchase 16.6 million shares at a price of $30.25 per share.
In 1998, our unregulated business operations retired $75 million of
long-term debt and retired the notes used in our acquisition of the
Australian holdings. During 1997, our unregulated business operations issued
$30 million and retired $109 million of long-term debt. Also in 1997, we
assumed $780 million of
30
<PAGE>
long-term debt in connection with the acquisition of the natural gas assets in
Texas. In 1996, we entered into additional loan agreements of $92 million to
finance the acquisition of our energy holdings in Australia.
We maintain a number of credit facilities throughout our organization to
support commercial paper programs, letters of credit, and other short term
liquidity requirements. At PG&E Corporation, we maintain two $500 million
revolving credit facilities, one of which expires in November 1999 and the other
in 2002. The PG&E Corporation credit facilities are used to support the
commerical paper program and other liquidity needs. The facility expiring in
1999 may be extended annually for additional one-year periods upon agreement
between the lending institutions and us. There was $683 million of commercial
paper outstanding at December 31, 1998.
In September 1998, USGen obtained $1,675 million in revolving credit
facilities. Of these, $575 million is specifically related to the New England
operations. Of the New England facility, $475 million was used to execute a sale
leaseback transaction related to the newly acquired New England assets and
subsequently cancelled. No amounts are outstanding under the New England
facilities at December 31, 1998. USGen, itself, maintains two credit facilities
of $550 million each. One agreement expires in August 1999 and the other in
2003. These facilities were used in the acquisition of the New England assets
and for general corporate purposes. The total amount outstanding at December 31,
1998, backed by the facilities, was $540 million in eurodollar loans and $233
million in commercial paper. Of these loans, $550 million is classified as
noncurrent in the consolidated balance sheet.
At December 31, 1998, PG&E GTT had $70 million of outstanding short-term bank
borrowings related to two separate credit facilities. These lines are cancelable
upon demand and bear interest at each respective bank's quoted money market
rate. The borrowings are unsecured and unrestricted as to use.
PG&E GT NW maintains a $200 million revolving credit facility which expires
in the year 2000. At December 31, 1998 and 1997, PG&E GT NW had outstanding
commercial paper balances of $104 million and $80 million, respectively,
supported by this revolving facility. These balances were classified as
noncurrent obligations in the consolidated balance sheet.
Utility:
In 1998, the Utility repurchased $1.6 billion of its common stock from PG&E
Corporation to maintain its authorized capital structure.
The Utility's long-term debt that either matured, was redeemed, or was
repurchased during 1998 totaled $1.4 billion. Of this amount, (1) $249 million
related to the Utility's redemption of its 8% mortgage bonds due October 1,
2025; (2) $252 million related to the Utility's repurchase of various other
mortgage bonds; (3) $397 million related to the maturity of the Utility's 5 3\8%
mortgage bonds; (4) $204 million related to the other scheduled maturities of
long-term debt; and (5) $290 million related to rate reduction bonds maturing.
In 1997 and 1996, the Utility redeemed or repurchased $225 million and $1,113
million, respectively, of long-term debt to manage the overall balance of its
capital structure. In 1997, the Utility replaced $360 million of fixed interest
rate pollution control bonds with the same amount of variable interest rate
pollution control bonds. In 1996, the Utility replaced $988 million of variable
interest rate and fixed interest rate pollution control mortgage bonds and loan
agreements with the same amount of variable interest rate pollution control loan
agreements.
In 1998, the Utility redeemed its Series 7.44% preferred stock with a face
value of $65 million and its Series 6 7\8% preferred stock with a face value of
$43 million. During 1997 and 1996, the Utility did not redeem or repurchase any
of its preferred stock. In December 1997, a subsidiary of the Utility issued
$2.9 billion of rate reduction bonds through a special purpose entity
established by the California Infrastructure and Economic Development Bank. The
proceeds were used by the Utility to retire debt and reduce equity. (See Note 9
of Notes to Consolidated Financial Statements.)
31
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS
The Utility maintains a $1 billion revolving credit facility, which expires
in 2002. The Utility may extend the facility annually for additional one-year
periods upon agreement with the banks. This facility is used to support the
Utility's commercial paper program and other liquidity requirements. At December
31, 1998, the Utility had $567 million of commercial paper and $101 million of
bank notes outstanding. No amounts were outstanding at December 31, 1997.
Debt Obligations and Rate Reduction Bonds:
The table below provides information about our debt obligations and rate
reduction bonds at December 31, 1998:
<TABLE>
<CAPTION>
Expected maturity date 1999 2000 2001 2002 2003 Thereafter Total
- ---------------------- ---- ---- ---- ---- ---- ---------- -----
(dollars in millions)
<S> <C> <C> <C> <C> <C> <C> <C>
Utility:
Long-term debt
Variable rate obligations -- $200 $100 $738 $310 -- $1,348
Fixed rate obligations $260 $266 $274 $382 $372 $2,802 $4,356
Average interest rate 6.2% 6.6% 8.0% 7.8% 6.3% 7.1% 7.1%
Rate reduction bonds $290 $290 $290 $290 $290 $1,161 $2,611
Average interest rate 6.1% 6.2% 6.2% 6.3% 6.4% 6.4% 6.3%
---- ---- ---- ---- ---- ------ ------
Wholesale and Retail Unregulated
Business Operations:
Long-term debt
Variable rate obligations $ 7 $115 $ 12 $ 10 $560 $ 125 $ 829
Fixed rate obligations $ 71 $117 $ 94 $126 $ 46 $ 773 $1,227
Average interest rate 10.4% 9.1% 9.1% 8.7% 9.9% 8.2% 8.6%
---- ---- ---- ---- ---- ------ ------
</TABLE>
Cash Flows from Investing Activities:
The primary uses of cash for investing activities are additions to property,
plant, and equipment; unregulated investments in partnerships; and acquisitions.
The Utility's estimated capital spending for 1999 is $1.7 billion. Utility
capital expenditures are based on estimates prepared for the Utility's GRC, but
exclude capital expenditures for divested fossil and geothermal power plants.
These estimates may be reduced if the CPUC authorized base revenues are
significantly lower than those requested by the Utility in its GRC filing.
In 1998, the Utility had proceeds of $501 million from the sale of
three fossil-fueled generation plants. Also in 1998, PG&E Corporation sold its
Australian energy holdings, for proceeds of approximately $126 million. In 1997,
PG&E Corporation sold its interest in International Generating Company, Ltd.,
resulting in an after-tax gain of approximately $120 million.
Also in 1998, the Utility agreed to sell three other fossil-fueled
generation plants and to sell its complex of geothermal generation
facilities. The winning bids total $1,014 million. As of December 31, 1998,
these four plants had a combined book value of $523 million and had a
combined capacity of 4,289 MW. The sales are subject to the approval of
regulatory agencies, including the CPUC, and conditioned upon the transfer of
various permits and licenses. The Utility expects to complete the sale of
these four plants in 1999.
Environmental Matters:
We are subject to laws and regulations established to both maintain and improve
the quality of the environment. Where our properties contain hazardous
substances, these laws and regulations require us to remove those substances or
remedy effects on the environment.
At December 31, 1998, the Utility expects to spend $296 million over the next
30 years for cleanup costs at identified sites. If other responsible parties
fail to pay or expected outcomes change, then these costs may be as much as $487
million. Of the $296 million, the Utility has recovered $104 million (including
remediation of generation plants divested, discussed above) and expects to
recover another $160 million in future rates. The Utility mitigates its cost by
seeking recovery from insurance carriers and other third parties. (See Note 15
of Notes to Consolidated Financial Statements.)
32
<PAGE>
The cost of the hazardous substance remediation ultimately undertaken
by the Utility is difficult to estimate. A change in the estimate may occur
in the near term due to uncertainty concerning the Utility's responsibility,
the complexity of environmental laws and regulations, and the selection of
compliance alternatives. The Utility estimated costs using assumptions least
favorable to the Utility, based upon a range of reasonably possible outcomes.
Costs may be higher if the Utility is found to be responsible for cleanup
costs at additional sites or expected outcomes change.
Year 2000:
The Year 2000 issue exists because many computer programs use only two digits
to refer to a year, and were developed without considering the impact of the
upcoming change in the century. If PG&E Corporation's computer systems fail
or function incorrectly due to not being made Year 2000 ready, they could
directly and adversely affect our ability to generate or deliver our products
and services or could otherwise affect revenues, safety, or reliability for
such a period of time as to lead to unrecoverable consequences.
Our plan to address the Year 2000 issues focuses on mission-critical systems
whose components are categorized as in-house software, vendor software, embedded
systems, and computer hardware. The four phases of our plan to address these
systems are inventory and assessment, remediation, testing, and certification.
Certification occurs when mission-critical systems are formally determined to be
Year 2000 ready.
Our Year 2000 project is generally proceeding on schedule. The following
table indicates our Year 2000 progress as of January 11, 1999. The percentages
in this table reflect approximations based on a standardized reporting system
that combines subsidiary results to provide a consistent, company-wide view.
Year 2000 Readiness of Mission-Critical Items
Remediation Testing Certification
Complete Complete Complete
----------- -------- -------------
In-house software 94% 91% 11%
Vendor software 53% 26% 2%
Embedded systems 95% 91% 0%
Computer hardware 92% 60% 0%
Changes in company inventories, or issues uncovered in subsequent phases for
an item previously reported as completed, may lead to downward adjustments in
percentages from period to period. Also, the completion of these phases does not
address external interdependencies that could affect the ability of the company
to be Year 2000 ready. Even after systems are certified, we may continue various
kinds of testing through the end of 1999.
Although 91 percent of remediation and testing of embedded systems has been
completed, the remaining 9 percent in this area may require some of the more
challenging work.
In addition to internal systems, we also depend upon external parties,
including customers, suppliers, business partners, gas and electric system
operators, government agencies, and financial institutions to support the
functioning of our business. To the extent that any of these parties are
considered mission-critical to our business and experience Year 2000 problems in
their systems, our mission-critical business functions may be adversely
affected. To deal with this vulnerability, we have another phased approach. The
primary phases for dealing with external parties are: (1) inventory, (2) action
planning, (3) risk assessment, and (4) contingency planning. We have completed
our inventory and action planning phases for mission-critical external parties.
We expect to complete the risk assessment by March 1999 and the contingency
planning phase by July 1999.
Although we expect our efforts and those of our external parties to be
largely successful, we recognize that with the complex interaction of today's
computing and communications systems, we cannot be certain we will be completely
successful. Therefore, contingency plans for Year 2000 readiness are being
developed and tested throughout 1999 to address our external dependencies as
well as any significant schedule delays of mission-critical system work, should
they occur. These plans will take into account possible interruptions of power,
computing, financial, and communications infrastructures. Due to the speculative
nature of contingency planning, however, it is uncertain whether these plans
will be sufficient to remove the risk of material impacts on our operations
resulting from Year 2000 problems.
33
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS
In 1997 and through December 1998, we spent approximately $108 million to
assess and remediate Year 2000 problems. About $64 million of this cost was for
software systems that we replaced for business purposes generally unrelated to
addressing Year 2000 readiness, but whose schedule we advanced to meet Year 2000
requirements. The replacement costs for these accelerated systems were
capitalized. Our estimate of future costs to address mission-critical Year 2000
issues is approximately $140 million. About $60 million of these remaining Year
2000 costs will be capitalized because they relate to the purchase and
installation of systems and equipment for general business purposes and the
remaining $80 million will be expensed.
Based on our current schedule for the completion of Year 2000 tasks, we
expect to secure Year 2000 readiness of our mission-critical systems by the end
of the third quarter of 1999. However, as our current schedule is partially
dependent on the efforts of third parties, their delays may cause our schedule
to change.
If we, or third parties with whom we have significant business relationships,
fail to achieve Year 2000 readiness of mission-critical systems, there could be
a material adverse impact on the Utility's and PG&E Corporation's financial
position, results of operations, and cash flows.
Inflation:
Financial statements, which are prepared in accordance with generally accepted
accounting principles, report operating results in terms of historical costs and
do not evaluate the impact of inflation. Inflation affects our construction
costs, operating expenses, and interest charges. In addition, the Utility's
electric revenues will not reflect the impact of inflation due to the current
electric rate freeze. However, inflation at the levels currently being
experienced is not expected to have a material adverse impact on the Utility's
or our financial position or results of operations.
Price Risk Management Activities:
We have established a price risk management policy which 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).
We use derivatives for hedging purposes primarily to offset underlying commodity
price risks. We also participate in markets using derivatives to gather market
intelligence, create liquidity, and maintain a market presence. Such derivatives
include forward contracts, futures, swaps, and options. Net open positions often
exist or are established due to PG&E Corporation's assessment of its response to
changing market conditions. To the extent that PG&E Corporation has an open
position, it is exposed to the risk that fluctuating market prices may adversely
impact its financial results. Our price risk management policy and the trading
and risk management policies of our subsidiaries prohibit the use of derivatives
whose payment formula includes a multiple of some underlying asset.
PG&E Corporation prepares a daily assessment of its portfolio market risk
exposure using value-at-risk and other methodologies that simulate future price
movements in the energy markets to estimate the size and probability of future
potential losses. The quantification of market risk using value-at-risk provides
a consistent measure of risk across diverse energy markets and products. The use
of this methodology requires a number of important assumptions including the
selection of a confidence level for losses, volatility of prices, market
liquidity, and a holding period.
PG&E Corporation utilizes historical data for calculating the price
volatility of PG&E Corporation's positions and how likely the prices of those
positions will move together. The model includes all derivative and commodity
investments for its trading portfolio and only derivative commodity investments
for its hedging portfolio (but not the related underlying hedged position). PG&E
Corporation expresses value-at-risk as a dollar amount of the potential loss in
the fair value of its portfolio based on a 95 percent confidence level using a
one-day liquidation period. Therefore, there is a 5 percent probability that a
portfolio will incur a loss in one day greater than its value-at-risk. The
value-at-risk is aggregated for PG&E Corporation as a whole by correlating the
daily returns of the portfolios for natural gas, natural gas liquids, and power
for the previous 22 trading days. PG&E Corporation's daily value-at-risk for
commodity price sensitive derivative instruments as of December 31, 1998, is
$6.2 million for trading activities and $0.2 million for non-trading activities.
34
<PAGE>
Value-at-risk has several limitations as a measure of portfolio risk
including, but not limited to, underestimation of the risk of a portfolio with
significant options exposure, inadequate indication of the exposure of a
portfolio to extreme price movements, and the inability to address the risk
resulting from intraday trading activities.
In June 1998, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards (SFAS) No. 133, Accounting for Derivative
Instruments and Hedging Activities, which is required to be adopted in years
beginning after June 15, 1999. The Statement permits early adoption as of the
beginning of any fiscal quarter. PG&E Corporation expects to adopt the new
Statement no later than January 1, 2000. The Statement will require PG&E
Corporation to recognize all derivatives, as defined in the Statement, on the
balance sheet at fair value. Derivatives, or any portion thereof, that are not
effective hedges must be adjusted to fair value through income. If derivatives
are effective hedges, depending on the nature of the hedges, changes in the fair
value of derivatives either will be offset against the change in fair value of
the hedged assets, liabilities, or firm commitments through earnings or will be
recognized in other comprehensive income until the hedged items are recognized
in earnings. PG&E Corporation is currently evaluating what the effect of SFAS
No. 133 will be on the earnings and financial position of PG&E Corporation. PG&E
Corporation uses the mark-to-market method of accounting for its commodity
trading and price risk management activities.
In November 1998, the Emerging Issues Task Force of the Financial Accounting
Standards Board released Issue 98-10, Accounting for Energy Trading and Risk
Management Activities. This Issue states that all energy-related contracts
entered into with the objective of generating profits on or from exposure to
shifts or changes in market prices be marked to market with the gains and losses
reflected in the income statement. The Task Force stipulates implementation for
fiscal years beginning after December 15, 1998. PG&E Corporation does not
believe that the effect of adoption of this standard on earnings or the
financial position of PG&E Corporation will be material.
Legal Matters:
In the normal course of business, both the Utility and PG&E Corporation are
named as parties in a number of claims and lawsuits. (See Note 15 of Notes to
Consolidated Financial Statements for further discussion of significant pending
legal matters.)
35
<PAGE>
PG&E Corporation
STATEMENT OF CONSOLIDATED INCOME
(in millions, except per share amounts) Year ended December 31,
-----------------------------
1998 1997 1996
------- ------- -------
Operating Revenues
Utility $ 8,924 $ 9,495 $ 8,989
Energy commodities and services 11,018 5,905 621
------- ------- -------
Total operating revenues 19,942 15,400 9,610
------- ------- -------
Operating Expenses
Cost of energy for utility 3,029 3,287 3,142
Cost of energy commodities and services 10,194 5,481 356
Operating and maintenance, net 3,103 3,052 2,994
Depreciation, amortization, and
decommissioning 1,609 1,852 1,222
------- ------- -------
Total operating expenses 17,935 13,672 7,714
------- ------- -------
Operating Income 2,007 1,728 1,896
Interest expense, net (782) (665) (632)
Other income, net 64 201 13
------- ------- -------
Income Before Income Taxes 1,289 1,264 1,277
Income taxes 570 548 555
------- ------- -------
Net Income $ 719 $ 716 $ 722
======= ======= =======
Weighted Average Common Shares Outstanding 382 410 413
Earnings Per Common Share, Basic and
Diluted $ 1.88 $ 1.75 $ 1.75
Dividends Declared Per Common Share $ 1.20 $ 1.20 $ 1.77
The accompanying Notes to the Consolidated Financial Statements are an
integral part of this statement.
36
<PAGE>
PG&E Corporation
CONSOLIDATED BALANCE SHEET
(in millions) Balance at December 31, 1998 1997
---- ----
Assets
Current Assets
Cash and cash equivalents $ 286 $ 237
Short-term investments 55 1,160
Accounts receivable
Customers, net 1,856 1,514
Regulatory balancing accounts -- 458
Energy marketing 507 830
Price risk management 1,416 500
Inventories and prepayments 835 626
-------- --------
Total current assets 4,955 5,325
Property, Plant, and Equipment
Utility 23,996 23,764
Wholesale and retail unregulated business
operations
Electric generation 1,967 --
Gas transmission 3,347 3,415
Construction work in progress 407 492
Other 127 55
-------- --------
Total property, plant, and equipment
(at original cost) 29,844 27,726
Accumulated depreciation and decommissioning (12,026) (11,617)
-------- --------
Net property, plant, and equipment 17,818 16,109
Other Noncurrent Assets
Regulatory assets 6,347 6,900
Nuclear decommissioning funds 1,172 1,024
Other 2,942 1,757
-------- --------
Total noncurrent assets 10,461 9,681
-------- --------
Total Assets $ 33,234 $ 31,115
======== ========
37
<PAGE>
PG&E Corporation
CONSOLIDATED BALANCE SHEET
(in millions) Balance at December 31, 1998 1997
---- ----
Liabilities and Equity
Current Liabilities
Short-term borrowings $ 1,644 $ 103
Current portion of long-term debt 338 659
Current portion of rate reduction bonds 290 290
Accounts payable
Trade creditors 1,001 754
Other 443 466
Regulatory balancing accounts 79 --
Energy marketing 381 758
Accrued taxes 103 226
Price risk management 1,412 512
Other 1,064 893
------- -------
Total current liabilities 6,755 4,661
Noncurrent Liabilities
Long-term debt 7,422 7,659
Rate reduction bonds 2,321 2,611
Deferred income taxes 3,861 4,029
Deferred tax credits 283 339
Other 3,746 2,024
------- -------
Total noncurrent liabilities 17,633 16,662
Preferred Stock of Subsidiaries 480 595
Utility Obligated Mandatorily Redeemable
Preferred Securities of Trust Holding
Solely Utility Subordinated Debentures 300 300
Common Stockholders' Equity
Common stock, no par value, authorized
800,000,000 shares, issued and outstanding,
382,603,564 and 417,665,891 5,862 6,366
Reinvested earnings 2,204 2,531
------- -------
Total common stockholders' equity 8,066 8,897
------- -------
Commitments and Contingencies (Notes 1,
2, 3, 4, 5, 14, and 15) -- --
------- -------
Total Liabilities and Stockholders' Equity $33,234 $31,115
======= =======
The accompanying Notes to the Consolidated Financial Statements are an
integral part of this statement
38
<PAGE>
PG&E Corporation
STATEMENT OF CONSOLIDATED CASH FLOWS
(in millions) For the year ended December 31,
-------------------------------
1998 1997 1996
---- ---- ----
Cash Flows From Operating Activities
Net income $ 719 $ 716 $ 722
Adjustments to reconcile net income to
net cash provided by operating activities:
Depreciation, amortization, and
decommissioning 1,609 1,852 1,222
Deferred income taxes and tax credits-net (107) (159) (150)
Other deferred charges and noncurrent
liabilities 18 121 116
Loss (gain) on sale of assets 23 (120) --
Net effect of changes in operating
assets and liabilities:
Accounts receivable -- trade (342) (242) (70)
Regulatory balancing accounts receivable 537 126 302
Inventories and prepayments (161) (4) 32
Price risk management assets and
liabilities, net (16) 12 --
Accounts payable -- trade 247 210 217
Accrued taxes (123) (54) 36
Other working capital 199 (85) (6)
Other-net (302) 245 160
------- ------- -------
Net cash provided by operating activities 2,301 2,618 2,581
------- ------- -------
Cash Flows From Investing Activities
Capital expenditures (1,619) (1,822) (1,230)
Acquisitions and investments in
unregulated projects (1,779) (116) (229)
Proceeds from sale of assets 1,106 146 --
Other-net 48 21 (120)
------- ------- -------
Net cash used by investing activities (2,244) (1,771) (1,579)
------- ------- -------
Cash Flows From Financing Activities
Net borrowings (repayments) under credit
facilities 2,115 (587) (115)
Long-term debt issued -- 386 1,088
Long-term debt matured, redeemed, or
repurchased (1,552) (961) (1,472)
Proceeds from issuance of rate reduction
bonds -- 2,881 --
Preferred stock redeemed or repurchased (108) -- --
Common stock issued 63 54 220
Common stock repurchased (1,158) (804) (455)
Dividends paid (470) (524) (844)
Other-net (3) (39) (14)
------- ------- -------
Net cash used by financing activities (1,113) 406 (1,592)
------- ------- -------
Net Change in Cash and Cash Equivalents (1,056) 1,253 (590)
Cash and Cash Equivalents at January 1 1,397 144 734
------- ------- -------
Cash and Cash Equivalents at December 31 $ 341 $ 1,397 $ 144
======= ======= =======
Supplemental disclosures of cash flow
information
Cash paid for:
Interest (net of amounts capitalized) $ 774 $ 624 $ 598
Income taxes 770 801 640
The accompanying Notes to the Consolidated Financial Statements are an
integral part of this statement.
39
<PAGE>
PG&E CORPORATION
STATEMENT OF CONSOLIDATED COMMON STOCK EQUITY
<TABLE>
<CAPTION>
Total
Additional Common
Common Paid-in Reinvested Stock
Stock Capital Earnings Equity
------ ---------- ---------- -------
(dollars in millions)
<S> <C> <C> <C> <C>
BALANCE DECEMBER 31, 1995 $2,070 $ 3,716 $ 2,813 $ 8,599
------ ------- ------- -------
Net income 722 722
Common stock issued (9,290,102 shares) 47 173 220
Common stock repurchased (19,811,396 shares) (99) (182) (174) (455)
Cash dividends declared
Common stock (729) (729)
Other 3 4 7
------ ------- ------- -------
BALANCE DECEMBER 31, 1996 2,018 3,710 2,636 8,364
------ ------- ------- -------
Net income 716 716
Holding company formation 3,710 (3,710) --
Common stock issued (2,302,544 shares) 54 54
Acquisitions (45,683,005 shares) 1,069 1,069
Common stock repurchased (33,823,950 shares) (496) (308) (804)
Cash dividends declared
Common stock (485) (485)
Other 11 (28) (17)
------ ------- ------- -------
BALANCE DECEMBER 31, 1997 6,366 -- 2,531 8,897
------ ------- ------- -------
Net income 719 719
Common stock issued (2,028,303 shares) 63 63
Common stock repurchased (37,090,630 shares) (565) (593) (1,158)
Cash dividends declared
Common stock (466) (466)
Other (2) 13 11
------ ------- ------- -------
BALANCE DECEMBER 31, 1998 $5,862 $ -- $ 2,204 $ 8,066
====== ======= ======= =======
</TABLE>
The accompanying Notes to the Consolidated Financial Statements are
an integral part of this statement.
40
<PAGE>
Pacific Gas and Electric Company
STATEMENT OF CONSOLIDATED INCOME
<TABLE>
<CAPTION>
1998 1997 1996
-------- -------- --------
(in millions) Year ended December 31,
<S> <C> <C> <C>
Operating Revenues
Electric utility $7,191 $7,691 $7,160
Gas utility 1,733 1,804 1,829
Energy commodities and services -- -- 621
------ ------ ------
Total operating revenues 8,924 9,495 9,610
------ ------ ------
Operating Expenses
Cost of electric energy 2,321 2,501 2,261
Cost of gas 708 786 881
Cost of energy commodities and services -- -- 356
Operating and maintenance, net 2,581 2,629 2,994
Depreciation, amortization, and decommissioning 1,438 1,748 1,222
------ ------ ------
Total operating expenses 7,048 7,664 7,714
------ ------ ------
Operating Income 1,876 1,831 1,896
Interest expense, net (621) (570) (632)
Other income, net 103 116 46
------ ------ ------
Income Before Income Taxes 1,358 1,377 1,310
Income taxes 629 609 555
------ ------ ------
Net Income 729 768 755
------ ------ ------
Preferred dividend requirement 27 33 33
------ ------ ------
Income Available for Common Stock $ 702 $ 735 $ 722
====== ====== ======
</TABLE>
The accompanying Notes to the Consolidated Financial Statements are an
integral part of this statement.
41
<PAGE>
PACIFIC GAS AND ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEET
<TABLE>
<CAPTION>
1998 1997
-------- --------
(in millions) Balance at December 31,
<S> <C> <C>
Assets
Current Assets
Cash and cash equivalents $ 73 $ 80
Short-term investments 17 1,143
Accounts receivable
Customers, net 1,383 1,204
Regulatory balancing accounts -- 458
Related parties 14 459
Inventories
Fuel oil and nuclear fuel 187 207
Gas stored underground 130 102
Materials and supplies 159 189
Prepayments 50 25
-------- --------
Total current assets 2,013 3,867
Property, Plant, and Equipment
Electric 16,924 16,913
Gas 7,072 6,851
Construction work in progress 273 421
-------- --------
Total property, plant, and equipment (at original cost) 24,269 24,185
Accumulated depreciation and decommissioning (11,397) (11,134)
-------- --------
Net property, plant, and equipment 12,872 13,051
Other Noncurrent Assets
Regulatory assets 6,288 6,846
Nuclear decommissioning funds 1,172 1,024
Other 605 359
-------- --------
Total noncurrent assets 8,065 8,229
-------- --------
Total Assets $ 22,950 $ 25,147
======== ========
</TABLE>
42
<PAGE>
PACIFIC GAS AND ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEET
<TABLE>
<CAPTION>
1998 1997
-------- --------
(in millions) Balance at December 31,
<S> <C> <C>
Liabilities and Equity
Current Liabilities
Short-term borrowings $ 668 $ --
Current portion of long-term debt 260 580
Current portion of rate reduction bonds 290 290
Accounts payable
Trade creditors 718 441
Related parties 60 134
Regulatory balancing accounts 79 --
Other 374 424
Accrued taxes 2 229
Deferred income taxes 3 149
Other 558 527
------- -------
Total current liabilities 3,012 2,774
Noncurrent Liabilities
Long-term debt 5,444 6,218
Rate reduction bonds 2,321 2,611
Deferred income taxes 3,060 3,304
Deferred tax credits 283 338
Other 2,045 1,810
------- -------
Total noncurrent liabilities 13,153 14,281
Preferred Stock With Mandatory Redemption Provisions
6.30% and 6.57%, outstanding 5,500,000 shares, due 2002-2009 137 137
Company Obligated Mandatorily Redeemable Preferred Securities of Trust
Holding Solely Utility Subordinated Debentures
7.90%, 12,000,000 shares, due 2025 300 300
Stockholders' Equity
Preferred stock without mandatory redemption provisions
Nonredeemable -- 5% to 6%, outstanding 5,784,825 shares 145 145
Redeemable -- 4.36% to 7.04%, outstanding 5,973,456 shares 142 257
Common stock, $5 par value, authorized 800,000,000 shares;
issued and outstanding, 341,353,455 and 403,504,292 1,707 2,018
Additional paid in capital 2,094 2,564
Reinvested earnings 2,260 2,671
------- -------
Total stockholders' equity 6,348 7,655
Commitments and Contingencies (Notes 1, 2, 3, 4, 5, 14, and 15) -- --
------- -------
Total Liabilities and Stockholders' Equity $22,950 $25,147
======= =======
</TABLE>
The accompanying Notes to the Consolidated Financial Statements are an
integral part of this statement.
43
<PAGE>
PACIFIC GAS AND ELECTRIC COMPANY
STATEMENT OF CONSOLIDATED CASH FLOWS
<TABLE>
<CAPTION>
1998 1997 1996
-------- -------- --------
(in millions) For the year ended December 31,
<S> <C> <C> <C>
Cash Flows From Operating Activities
Net income $ 729 $ 768 $ 755
Adjustments to reconcile net income to net cash provided by
operating activities:
Depreciation, amortization, and decommissioning 1,438 1,748 1,222
Deferred income taxes and tax credits-net (257) (182) (150)
Other deferred charges and noncurrent liabilities 31 133 116
Net effect of changes in operating assets and liabilities:
Accounts receivable 266 (582) (70)
Regulatory balancing accounts receivable 537 126 302
Inventories and prepayments (3) 12 32
Accounts payable -- trade 203 (80) 217
Accrued taxes (227) (62) 36
Other working capital (50) (128) (6)
Other-net (39) 15 127
------- ------ -------
Net cash provided by operating activities 2,628 1,768 2,581
Cash Flows From Investing Activities
Capital expenditures (1,382) (1,522) (1,230)
Acquisitions and investments in unregulated projects -- -- (229)
Proceeds from sale of generation assets 501 -- --
Other-net 22 (117) (120)
------- ------ -------
Net cash used by investing activities (859) (1,639) (1,579)
------- ------ -------
Cash Flows From Financing Activities
Net borrowings (repayments) under credit facilities 668 (681) (115)
Long-term debt issued -- 355 1,088
Long-term debt matured, redeemed, or repurchased (1,413) (852) (1,472)
Proceeds from issuance of rate reduction bonds -- 2,881 --
Preferred stock redeemed (108) -- --
Common stock repurchased (1,600) -- --
Dividends paid (444) (739) (844)
Other-net (5) (14) (249)
------- ------ -------
Net cash used by financing activities (2,902) 950 (1,592)
Net Change in Cash and Cash Equivalents (1,133) 1,079 (590)
Cash and Cash Equivalents at January 1 1,223 144 734
------- ------ -------
Cash and Cash Equivalents at December 31 $ 90 $1,223 $ 144
======= ====== =======
Supplemental disclosures of cash flow information
Cash paid for:
Interest (net of amounts capitalized) $ 600 $ 547 $ 598
Income taxes 1,115 841 640
</TABLE>
The accompanying Notes to the Consolidated Financial Statements are an
integral part of this statement.
44
<PAGE>
PACIFIC GAS AND ELECTRIC COMPANY
STATEMENT OF CONSOLIDATED COMMON STOCK EQUITY,
PREFERRED STOCK, AND PREFERRED SECURITIES
<TABLE>
<CAPTION>
Preferred Preferred Company
Stock Stock Obligated
Total Without With Mandatorily
Additional Common Mandatory Mandatory Redeemable
Common Paid-in Reinvested Stock Redemption Redemption Preferred
(dollars in millions) Stock Capital Earnings Equity Provisions Provisions Securities
- ------------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
Balance December 31, 1995 $ 2,070 $3,716 $ 2,813 $ 8,599 $ 402 $137 $300
- -----------------------------------------------------------------------------------------------------------------------------------
Net income 755 755
Common stock issued
(9,290,102 shares) 47 173 220
Common stock repurchased
(19,811,396 shares) (99) (182) (174) (455)
Cash dividends declared
Preferred stock (33) (33)
Common stock (729) (729)
Other 3 4 7
- -----------------------------------------------------------------------------------------------------------------------------------
Balance December 31, 1996 2,018 3,710 2,636 8,364 402 137 300
- -----------------------------------------------------------------------------------------------------------------------------------
Net income 768 768
Holding company formation (1,146) (1,146)
Cash dividends declared
Preferred stock (33) (33)
Common stock (699) (699)
Other (1) (1)
- -----------------------------------------------------------------------------------------------------------------------------------
Balance December 31, 1997 2,018 2,564 2,671 7,253 402 137 300
- -----------------------------------------------------------------------------------------------------------------------------------
Net income 729 729
Common stock repurchased
(62,150,837 shares) (311) (481) (808) (1,600)
Preferred stock redeemed
(4,323,948 shares) (3) (3) (105)
Cash dividends declared
Preferred stock (28) (28)
Common stock (300) (300)
Other 11 (1) 10 (10)
- -----------------------------------------------------------------------------------------------------------------------------------
Balance December 31, 1998 $ 1,707 $2,094 $ 2,260 $ 6,061 $ 287 $137 $300
====================================================================================
</TABLE>
The accompanying Notes to the Consolidated Financial Statements are an
integral part of this statement.
45
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1: General
Basis of Presentation: PG&E Corporation became the holding company of Pacific
Gas and Electric Company (the Utility) on January 1, 1997. Prior to that time,
the Utility was the predecessor of PG&E Corporation. Effective with PG&E
Corporation's formation, the Utility's interests in its unregulated subsidiaries
were transferred to PG&E Corporation.
This is a combined annual report of PG&E Corporation and the Utility.
Therefore, the Notes to Consolidated Financial Statements apply to both PG&E
Corporation and the Utility. PG&E Corporation's consolidated financial
statements include the accounts of PG&E Corporation, the Utility, and PG&E
Corporation's other wholly owned subsidiaries. The Utility's consolidated
financial statements include its accounts as well as those of its wholly
owned subsidiaries. PG&E Corporation and the Utility have identical 1996
consolidated financial statements because they represent the accounts of the
Utility as predecessor of PG&E Corporation. All significant intercompany
transactions have been eliminated from the consolidated financial statements.
Certain amounts in the prior years' consolidated financial statements have
been reclassified to conform to the 1998 presentation.
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions. These estimates and assumptions affect the reported amounts of
revenues, expenses, assets, and liabilities and the disclosure of contingencies.
Actual results could differ from these estimates.
Accounting principles utilized include those necessary for rate-regulated
enterprises which reflect the ratemaking policies of the California Public
Utilities Commission (CPUC) and the Federal Energy Regulatory Commission (FERC).
Operations: PG&E Corporation is an energy-based holding company headquartered
in San Francisco, California. PG&E Corporation's businesses provide energy
services throughout North America. PG&E Corporation's Northern and Central
California energy utility subsidiary, Pacific Gas and Electric Company,
provides natural gas and electric service to one of every 20 Americans. PG&E
Corporation's four unregulated businesses provide a wide range of energy
products and services through its wholesale and retail unregulated business
operations.
PG&E Corporation's wholesale unregulated business operations consist
of U.S. Generating Company (USGen) which develops, builds, operates, owns,
and manages power generation facilities that serve wholesale and industrial
customers; PG&E Gas Transmission (PG&E GT) which operates approximately 9,000
miles of natural gas pipelines, natural gas storage facilities, and natural gas
processing plants in the Pacific Northwest (PG&EGTNW) and Texas (PG&E GTT); and
PG&E Ener gy Trading (PG&E ET) which purchases and resells energy commodities
and related financial instruments in major North American markets, serving PG&E
Corporation's other unregulated businesses, unaffiliated utilities, and large
end-use customers.
PG&E Corporation's retail unregulated business operations consist of
PG&E Energy Services (PG&E ES) which provides competitively priced
electricity, natural gas, and related services to lower overall energy costs
for industrial, commercial, and institutional customers.
Regulation and Statements of Financial Accounting Standards (SFAS) No. 71: The
Utility is regulated by the CPUC, the FERC, and the Nuclear Regulatory
Commission (NRC) among others. The gas transmission business in the Pacific
Northwest is regulated by the FERC. The gas transmission business in Texas is
regulated by the Texas Railroad Commission.
PG&E Corporation and the Utility account for the financial effects of
regulation in accordance with SFAS No. 71, "Accounting for the Effects of
Certain Types of Regulation." This statement allows for the deferral as a
regulatory asset costs that otherwise would have been expensed if it is probable
that the costs will be recovered in future regulated revenues. In addition, SFAS
No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to be Disposed Of," requires PG&E Corporation and the Utility to write
off regulatory assets when they are no longer probable of recovery. On an
ongoing basis, PG&E Corporation and the Utility review their regulatory
46
<PAGE>
assets and liabilities for the continued applicability of SFAS No. 71 and the
effect of SFAS No. 121.
Regulatory assets and liabilities are comprised of the following:
<TABLE>
<CAPTION>
December 31, 1998 1997
- -------------------------------------------------------------------------------------------------------
<S> <C> <C>
(in millions)
Utility:
Generation-related transition costs/(1)/ $5,355 $5,964
Unamortized loss, net of gain, on
reacquired debt 289 283
Regulatory assets for deferred income tax 293 253
Other (net) 351 346
- -------------------------------------------------------------------------------------------------------
Total Utility $6,288 $6,846
Wholesale 59 54
-------------
Regulatory assets $6,347 $6,900
-------------
Regulatory liabilities $526 $ 477
-------------
</TABLE>
/(1)/ See Note 2 of Notes to Consolidated Financial Statements, for further
discussion.
Regulatory assets and liabilities are amortized over the period that the
costs are reflected in regulated revenues. The majority of the Utility's
regulatory assets are included in generation-related transition costs. The
Utility is amortizing its eligible transition costs, including generation-
related regulatory assets, over the transition period in conjunction with the
available competitive transition charge (CTC) revenues. During 1998, regulatory
assets related to electric utility restructuring decreased by $609 million. This
decrease reflects the recovery of eligible transition costs of $486 million
through accelerated amortization and $123 million through the gain on the sale
of generating plants.
Revenues and Regulatory Balancing Accounts: In connection with electric industry
restructuring, use of the Utility's sales and energy cost balancing accounts for
electric utility revenues has been discontinued in 1998. These balancing
accounts have been replaced with regulatory adjustment mechanisms which impact
expenses instead of revenues. (See Note 2.) For gas utility revenues, sales
balancing accounts accumulate differences between authorized and actual base
revenues. Further, gas cost balancing accounts accumulate differences between
the actual cost of gas and the revenues designated for recovery of such costs.
The regulatory balancing accounts accumulate balances until they are refunded to
or received from Utility customers through authorized rate adjustments. Utility
revenues included amounts for services rendered but unbilled at the end of each
year.
Accounting for Price Risk Management Activities: PG&E Corporation, primarily
through its subsidiaries, engages in price risk management activities for both
non-hedging and hedging purposes. PG&E Corporation conducts non-hedging
activities principally through its unregulated subsidiary, PG&E ET. Derivative
and other financial instruments associated with PG&E Corporation's electric
power, natural gas, natural gas liquids, and related non-hedging activities are
accounted for using the mark-to-market method of accounting.
Under mark-to-market accounting, PG&E Corpo-ration's non-hedging
contracts, including both physical contracts and financial instruments, are
recorded at market value, which approximates fair value. The market prices used
to value these transactions reflect management's best estimates considering
various factors including market quotes, time value, and volatility factors of
the underlying commitments. The values are adjusted to reflect the potential
impact of liquidating a position in an orderly manner over a reasonable period
of time under present market conditions.
Changes in the market value of these contract portfolios, resulting primarily
from newly originated transactions and the impact of commodity price and
interest rate movements, are recognized in operating revenues in the period of
change. Unrealized gains and losses of these contract portfolios are recorded as
assets and liabilities, respectively, from price risk management.
In addition to the non-hedging activities discussed above, PG&E Corporation
may engage in hedging activities using futures, forward contracts, options, and
swaps to hedge the impact of market fluctuations on energy commodity prices,
interest rates, and foreign currencies when there is a high degree of
correlation between price movements in the derivative and the item designated as
being hedged. PG&E Corporation accounts for hedge transactions under the
deferral method. Initially, PG&E Corporation defers unrealized gains and losses
on these transactions and classifies
47
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
them as assets or liabilities. When the hedged transaction occurs, PG&E
Corporation recognizes the gain or loss in operating expense. In instances where
the anticipated correlation of price movements does not occur, hedge accounting
is terminated and future changes in the value of the derivative are recognized
as gains or losses. If the hedged item is sold, the value of the associated
derivative is recognized in income.
For regulatory reasons, the Utility manages price risk independently from the
activities in PG&E Corporation's unregulated business. In the first quarter of
1998, the CPUC granted approval for the Utility to use financial instruments to
manage price volatility of gas purchased for the Utility's electric generation
portfolio. The approval limits the Utility's outstanding financial instruments
to $200 million, with downward adjustments occurring as the Utility divests its
fossil-fueled generation plants. (See Utility Generation Divestiture, below.)
Authority to use these risk management instruments ceases upon the full
divestiture of fossil-fueled generation plants or at the end of the current
electric rate freeze (see Rate Freeze and Rate Reduction, below), whichever
comes first.
In the second quarter of 1998, the CPUC granted conditional authority to the
Utility to use natural gas-based financial instruments to manage the impact of
natural gas prices on the cost of electricity purchased pursuant to existing
power-purchase contracts. Under the authority granted in the CPUC decision, no
natural gas-based financial instruments shall have an expiration date later than
December 31, 2001. Further, if the rate freeze ends before December 31, 2001,
the Utility shall net any outstanding financial instrument contracts through
equal and opposite contracts, within a reasonable amount of time. Also during
the fourth quarter, the CPUC granted conditional authority to the Utility to use
natural gas-based financial instruments to manage price and revenue risks
associated with its natural gas transmission and storage assets.
Property, Plant, and Equipment: Plant additions and replacements are
capitalized. The capitalized costs include labor, materials, construction
overhead, and capitalized interest or an allowance for funds used during
construction (AFUDC). AFUDC is the estimated cost of debt and equity funds used
to finance regulated plant additions. The Utility recovers AFUDC in rates
through depreciation expense over the useful life of the related asset.
The original cost of retired plant and removal costs less salvage value is
charged to accumulated depreciation upon retirement of plant in service for the
Utility and the unregulated businesses that apply SFAS No. 71. For our wholesale
and retail unregulated business operations, the cost and accumulated
depreciation of property, plant, and equipment retired or otherwise disposed of
are removed from related accounts and included in the determination of the gain
or loss on disposition.
Property, plant, and equipment is depreciated using a straight-line
remaining-life method. PG&E Corporation's composite depreciation rates were
4.11 percent, 3.70 percent, and 3.37 percent for the years ended December 31,
1998, 1997, and 1996, respectively. The Utility's composite depreciation rates
were 4.15 percent, 3.52 percent, and 3.37 percent for the years ended December
31, 1998, 1997, and 199 6, respectively.
Gains and Losses on Reacquired Debt: Any gains and losses on reacquired debt
associated with regulated operations that are subject to the provisions of SFAS
No. 71 are deferred and amortized over the remaining original lives of the debt
reacquired, consistent with ratemaking principles. Gains and losses on
reacquired debt associated with unregulated operations are recognized in
earnings at the time such debt is reacquired.
Inventories: Inventories include material and supplies, gas stored underground,
nuclear fuel, and fuel oil. Materials and supplies and gas stored underground
are valued at average cost. Stored nuclear fuel inventory is stated at lower of
average cost or market. Nuclear fuel in the reactor is amortized based on the
amount of energy output. Fuel oil is valued by the last-in-first-out method.
Cash Equivalents and Short-Term Investments: Cash equivalents (stated at cost,
which approximates market) include working funds and consist primarily of
eurodollar time deposits, bankers acceptances, and
48
<PAGE>
some commercial paper with original maturities of three months or less.
Income Taxes: PG&E Corporation uses the liability method of accounting for
income taxes. Income tax expense includes current and deferred income taxes
resulting from operations during the year. Tax credits are amortized over the
life of the related property.
PG&E Corporation files a consolidated federal income tax return that includes
domestic subsidiaries in which its ownership is 80 percent or more. The Utility
and various other subsidiaries are parties to a tax-sharing arrangement with
PG&E Corporation. PG&E Corporation files consolidated state income tax returns
when applicable. The Utility reports taxes on a stand-alone basis.
Related Party Agreements: In accordance with various agreements, the Utility and
other subsidiaries provide and receive various services from their parent, PG&E
Corporation. Services include the Utility's provision of general and
administrative services. The Utility and other subsidiaries receive general and
administrative services and financing from PG&E Corporation. Corporate costs,
such as administrative costs, interest, and income taxes, are allocated to
subsidiaries using a variety of factors including their share of employees,
operating expenses, assets, and other cost causal methods. Also, the Utility
purchases gas transmission services from PG&EGTNW.
Note 2: California Electric Industry Restructuring
In 1998, California became one of the first states in the country to implement
an electric industry restructuring plan. California electric industry
restructuring has two major impacts on the financial statements. The two major
components are the competitive market framework and the electric transition
plan, which are discussed below.
Competitive Market Framework: To create a competitive generation market, a Power
Exchange (PX) and an Independent System Operator (ISO) began operating in 1998.
The Utility is required to sell to the PX all of the electricity generated by
its power plants and electricity acquired under contractual agreements with
unregulated generators. Also, the Utility is required to buy from the PX all
electricity needed to provide service to retail customers that continue to
choose the Utility as their electricity supplier. The ISO schedules delivery of
electricity for all market participants to the transmission system. The Utility
continues to own and maintain a portion of the transmission system, but the ISO
controls the operation of the system.
For the year ended December 31, 1998, the cost of energy for the Utility,
reflected on the Statement of Consolidated Income, is comprised of the cost of
PX purchases, ancillary services (standby power and miscellaneous services)
purchased from the ISO, cost of transmission, and the cost of Utility
generation, net of sales to the PX as follows:
For the year ended December 31, 1998
- ----------------------------------------------------------------------
(in millions)
Cost of fuel for electric generation $2,030
Cost of purchases from the PX 723
Net cost of ancillary services 406
Proceeds from sales to the PX (838)
- ----------------------------------------------------------------------
Cost of electric energy $2,321
- ----------------------------------------------------------------------
The Utility's cost of energy is recovered from retail customers under the
terms of the restructuring plan.
California Transition Plan: Market-based revenues determined by the market
through sales to the PX may not be sufficient to recover (that is, to collect
from customers) all of the Utility's generation costs. To allow California
investor-owned utilities the opportunity to recover their transition costs
(generation costs that would not be recovered through market-based revenues) and
to ensure a smooth transition to a competitive market, the California
legislature developed a transition plan in the form of state legislation that
was passed in 1996. The transition plan will remain in effect until the earlier
of December 31, 2001, or when the Utility has recovered its authorized
transition costs as determined by the CPUC, with provisions that certain
transition costs can be recovered after the transition period. At the conclusion
of the transition period, the Utility will be at risk to recover any of its
remaining generation costs through market-based revenues. The transition plan
contains three principal elements
49
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
consisting of the determination of: (1) an electric rate freeze and rate
reduction, (2) the recovery of transition costs, and (3) divestiture of utility-
owned generation facilities. Each element is discussed below.
* Rate Freeze and Rate Reduction:
The first element of the transition plan is an electric rate freeze and an
electric rate reduction. In 1997 and 1998, the Utility held rates for its larger
customers at 1996 levels, and it will hold their rates at that level until the
end of the transition period. On January 1, 1998, the Utility reduced electric
rates for its residential and small commercial customers by 10 percent from 1996
levels, and it will hold their rates at that level until the end of the
transition period. Collectively, these actions are called a rate freeze.
To pay for the 10 percent rate reduction, the Utility refinanced $2.9 billion
of its transition costs with the proceeds of rate reduction bonds. (See Note 9.)
The bonds allow for the rate reduction by lowering the carrying cost on a
portion of the transition costs and by deferring recovery of a portion of these
transition costs until after the transition period.
The frozen rates include a component for transition cost recovery. Transition
costs are being recovered from all Utility distribution customers through a
nonbypassable charge regardless of the customer's choice of electricity
supplier. As the customer charge for transition costs is nonbypassable, the
Utility does not believe that the availability of choice to its customers will
have a material impact on its ability to recover transition costs.
Revenues from frozen electric rates provide for the recovery of authorized
Utility costs, including transmission and distribution service, public purpose
programs, nuclear decommissioning, and rate reduction bond debt service. To the
extent the revenues from frozen rates exceed authorized Utility costs, the
remaining revenues constitute the CTC which recovers the transition costs. These
CTC revenues are subject to seasonal fluctuations in the Utility's sales volumes
and certain other factors.
* Transition Cost Recovery:
Transition costs consist of: (1) above-market sunk costs (sunk costs are costs
associated with Utility-owned generation assets that are fixed and unavoidable
and currently included in the Utility customers' electric rates) and future
costs, such as costs related to plant removal of Utility-owned generation
facilities, (2) costs associated with the Utility's long-term contracts to
purchase power at above-market prices from qualifying facilities 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.)
Above-market sunk costs result when the book value of a facility is in excess
of its market value. Conversely, below-market sunk costs result when the market
value of a facility is in excess of its book value. The total amount of
generation facility costs to be included as transition costs will be based on
the aggregate of above-market and below-market values. The above-market portion
of these costs is eligible for recovery as a transition cost. The below-market
portion of these costs will reduce other unrecovered transition costs. A
valuation of a Utility-owned generation facility where the market value exceeds
the book value could result in a material charge to Utility earnings if the
valuation of the facility is determined based upon any method other than a sale
of the facility to a third party. This is because any excess of market value
over book value would be used to reduce other transition costs.
The Utility will not be able to determine the exact amount of above-market
non-nuclear sunk costs that will be recoverable as transition costs until a
market valuation process (appraisal, spin, sale, or other valuation method) is
completed for each of its generation facilities. Several of these valuations
occurred in 1997 and 1998, when the Utility agreed to sell seven of its electric
plants. The market value of these facilities determined by these sales exceeded
the book value and will therefore reduce the amount of transition costs to be
recovered. In addition, in December 1998, the Utility requested that the CPUC
allow it to hire appraisers to set the value of its hydroelectric generation
system. (See Generation Divestiture below.) The remainder of the valuation
process is expected to be completed by December 31, 2001. Nuclear sunk costs
were separately determined through a CPUC proceed-
50
<PAGE>
ing and were subject to a final verification audit. This audit was completed in
August 1998, the results of which are currently under review.
The Utility has long-term contracts to purchase electric power at above-
market prices. To the extent that individual contract prices are above market
price, the Utility is collecting the difference between the contract price and
the market price from customers, as a transition cost, over the term of the
contract. The contracts expire at various dates through 2028. The total amount
of the above-market costs under long-term contracts will be based on several
variables, including the capacity factors of the related generating facilities
and future market prices for electricity. During 1998, the average price paid
per kilowatt hour (kWh) under the Utility's long-term contracts for electric
power was 7.4 cents per kWh. The average cost of electric energy for energy
purchased at market rates from the PX (a measure of market prices) for the
period from April 1, 1998, to December 31, 1998, was 3.2 cents per kWh.
Generation-related regulatory assets and obligations (net generation-related
regulatory assets) are included as transition costs. These net regulatory assets
consist of those created prior to the transition period and those created during
the transition period. In 1998, the staff of the Securities and Exchange
Commission (SEC)issued interpretive guidance related to assets which are being
transitioned to a deregulated environment. The guidance states that an
impairment analysis should be performed for such assets and that the impairment
analysis should exclude transition cost revenues. Following this guidance, the
Utility determined that $3.9 billion of its generation assets were impaired. The
Utility has determined that certain of its generation facilities are considered
impaired under the SEC interpretive guidance. Because the Utility expects to
recover the impaired assets as a transition cost, it recorded a regulatory asset
for the impaired amounts as required. As a result, in 1998, $3.9 billion was
reclassified from property, plant, and equipment to regulatory assets on the
Utility's balance sheet. Prior year amounts were also reclassified. The
Utility's generation-related net regulatory assets total $5.4 billion at
December 31, 1998.
Under the transition plan, most transition costs can be recovered until
December 31, 2001. This recovery period is significantly shorter than the
recovery period of the generation assets prior to restructuring and is referred
to as accelerated recovery. Accordingly, the Utility is amortizing its
transition costs, including most generation-related regulatory assets over the
transition period. The CPUC believes that the transition plan reduces risks
associated with recovery of all the Utility's generation assets, including the
Diablo Canyon Nuclear Power Plant (Diablo Canyon) and the hydroelectric
facilities. As a result, during the transition period, the Utility is receiving
a reduced return on common equity for all of its generation assets, including
those generation assets reclassified to regulatory assets. In 1998, the reduced
return on common equity was 6.77 percent as compared to an authorized return on
common equity of 11.20 percent. The reduced return on common equity, related to
generation assets, will be in effect throughout the transition period.
Certain transition costs can be included in a non-bypassable charge to
distribution customers after the transition period. These costs include: (1)
certain employee-related transition costs, (2) above-market payments under
existing long-term contracts to purchase power, discussed above, and (3)
unrecovered electric industry restructuring implementation costs. In addition,
transition costs financed by the issuance of rate reduction bonds are expected
to be recovered over the term of the bonds. Further, the Utility's nuclear
decommissioning costs are being recovered through a CPUC-authorized charge,
which will extend until sufficient funds exist to decommission our nuclear
facility. During the rate freeze, this charge and the rate reduction bond debt
service will not increase the Utility customers' electric rates. Excluding these
exceptions, the Utility will write-off any transition costs not recovered during
the transition period.
Under the terms of the transition plan, revenues provided for the recovery of
most non-nuclear transition costs are based upon the acceleration of such costs
within the transition period. For nuclear transition costs, revenues provided
for transition cost recovery are based on: (1) an established incremental cost
incentive price per kWh generated by Diablo Canyon to recover certain ongoing
costs and capital additions, and (2) the
51
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
accelerated recovery of the investment in Diablo Canyon from a period ending in
2016 to a five-year period ending December 31, 2001.
The Utility is amortizing its eligible transition cost, including generation-
related regulatory assets, over the transition period in conjunction with
available CTC revenues. Effective January 1, 1998, the Utility started
collecting these eligible transition costs through the nonbypassable CTC. During
1998, regulatory assets related to electric utility restructuring decreased by
$609 million. This decrease reflects the recovery of eligible transition costs
of $486 million through accelerated amortization and $123 million through the
gain on the sale of generating plants.
During the transition period, the CPUC will review the Utility's compliance
with the accounting methods used by the Utility to recover transition costs and
the amount of transition costs requested for recovery. The CPUC is currently
reviewing non-nuclear transition costs amortized during the first six months of
1998. The Utility expects the CPUC to issue a decision regarding this review in
the second half of 1999. Transition costs that are disallowed by the CPUC for
collection from the Utility customers will be written off.
In addition, in August 1998, an independent accounting firm retained by the
CPUC completed its financial verification audit of the Utility's Diablo Canyon
plant accounts at December 31, 1996. The audit resulted in the issuance of an
unqualified opinion. The audit verified that Diablo Canyon sunk costs at
December 31, 1996, were $3.3 billion of the total $7.1 billion construction
costs. (Sunk costs are costs associated with Utility-owned generating facilities
that are fixed and unavoidable and currently included in the Utility customers'
electric rates.) The independent accounting firm also issued an agreed-upon
special procedures report, requested by the CPUC, which questioned $200 million
of the $3.3 billion sunk costs. The CPUC will review any proposed adjustments to
Diablo Canyon's recoverable costs, which resulted from the report. At this time,
the Utility cannot predict what actions, if any, the CPUC may take regarding the
audit report.
* Generation Divestiture:
In 1998, the Utility completed the sale of three fossil-fueled generation plants
for $501 million. These three fossil-fueled plants had a combined book value at
the time of the sale of $346 million and had a combined capacity of 2,645
megawatts (MW).
Also in 1998, the Utility agreed to sell three other fossil-fueled generation
plants and its complex of geothermal generation facilities. The winning bids
total $1,014 million. As of December 31, 1998, these four plants had a combined
book value of $523 million and had a combined capacity of 4,289 MW. The sales
are subject to the approval of regulatory agencies, including the CPUC, and
conditioned upon the transfer of various permits and licenses. The Utility
expects to complete the sale of these four plants in 1999.
The Utility will retain a liability for required environmental remediation
related to all of its fossil-fueled generation and geothermal plants of any pre-
closing soil or groundwater contamination at the plants it has or will sell. The
Utility records its estimated liability for the retained environmental
remediation obligation as part of the determination of the gain or loss on the
sale of each plant.
Any net gains from the sale of the Utility-owned generation plants will be
used to offset other transition costs. As a result, PG&E Corporation does not
believe sales of any generation facilities to a third party will have a material
impact on its results of operations.
The Utility is currently evaluating its options related to its remaining non-
nuclear generation facilities, primarily the hydroelectric generation system. In
May 1998, the Utility notified the CPUC that it does not plan to retain the
hydroelectric generation assets as part of the Utility. In December 1998, the
Utility filed with the CPUC its proposed appraisal process for valuing
generation assets, primarily the hydroelectric facilities. The Utility expects
to receive a response to this request in 1999.
At December 31, 1998, the book value of the Utility's net investment in
hydroelectric generation assets was $1.4 billion. If the Utility decides to
dispose of the hydroelectric generation assets by any method other than a sale
of the assets to a third party, a material charge could result to the extent
that the market value of the assets exceeds their book value. The
52
<PAGE>
market value of the hydroelectric assets is expected to exceed their book value
by a material amount.
Financial Impact of Transition Plan: The Utility's ability to continue
recovering its transition costs will be dependent on several factors, including:
(1) the continued application of the regulatory framework established by the
CPUC and state legislation, (2) the amount of transition costs ultimately
approved for recovery by the CPUC, (3) the market value of the remaining
Utility-owned generation facilities, (4) future Utility sales levels, (5) future
Utility fuel and operating costs, (6) the extent to which the Utility's
authorized revenues to recover distribution costs are increased or decreased,
and (7) the market price of electricity. Given the current evaluation of these
factors, PG&E Corporation believes that the Utility will recover its transition
costs under the terms of the approved transition plan. However, a change in one
or more of these factors could affect the probability of recovery of transition
costs and result in a material charge.
Note 3: Price Risk Management and Financial Instruments
The following table is a summary of the contract or notional amounts and
maturities of PG&E Corporation's contracts used for non-hedging activities
related to commodity price risk management as of December 31, 1998. Short and as
of December 31, 1998 are immaterial.
<TABLE>
<CAPTION>
Maximum
Natural Gas and Purchase Sale Term in
Electricity Contracts (Long) (Short) Years
- ------------------------------------------------------------------------------
<S> <C> <C> <C>
(billions of MMBtu equivalents/(a)/)
Non-Hedging Activities
Swaps 6.12 5.94 8
Options 1.39 1.18 5
Futures 0.44 0.46 4
Forward Contracts 3.68 3.53 5
- ------------------------------------------------------------------------------
</TABLE>
/(a)/ One MMBtu is equal to one million British thermal units. PG&E
Corporation's electric power contracts, measured in megawatts, were
converted to MMBtu equivalents using a conversion factor of 10 MMBtu's
per 1 megawatt-hour.
<TABLE>
<CAPTION>
Maximum
Purchase Sale Term in
Natural Gas Liquids Contracts (Long) (Short) Years
- ------------------------------------------------------------------------------
<S> <C> <C> <C>
(millions of barrels)
Non-Hedging Activities
Swaps 15.13 20.96 2
Options 19.24 17.69 1
Futures 24.16 25.18 1
Forward Contracts 5.01 5.29 2
- ------------------------------------------------------------------------------
</TABLE>
Volumes shown for swaps represent notional volumes that are used to calculate
amounts due under the agreements and do not represent volumes exchanged.
Moreover, notional amounts are indicative only of the volume of activity and are
not a measure of market risk.
The following table discloses the estimated fair values of price risk
management assets and liabilities as of December 31, 1998. PG&E Corporation's
net gains and losses on swaps, options, futures, and forward contracts held
during the year for non-hedging purposes were $69 million, $(49) million, $(63)
million, and $101 million, respectively. The ending and average fair values and
associated carrying amounts of derivative contracts used for hedging purposes
are not material as of December 31, 1998.
<TABLE>
<CAPTION>
Average Ending
Fair Value Fair Value
- ------------------------------------------------------------------------------
<S> <C> <C>
(in millions)
Assets
Non-Hedging Activities
Swaps $ 494 $ 947
Options 121 154
Futures 115 150
Forward Contracts 342 499
- ------------------------------------------------------------------------------
Total $1,072 $1,750
--------------------------
Noncurrent portion 334
- ------------------------------------------------------------------------------
Current portion $1,416
-------------
</TABLE>
53
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
Average Ending
Fair Value Fair Value
- ----------------------------------------------------------------------------
<S> <C> <C>
(in millions)
Liabilities
Non-Hedging Activities
Swaps $ 476 $ 908
Options 147 201
Futures 111 186
Forward Contracts 282 398
- ----------------------------------------------------------------------------
Total $1,016 $1,693
-------------------------
Noncurrent portion 281
- ----------------------------------------------------------------------------
Current portion $1,412
-----------
</TABLE>
The impact of price risk management assets and liabilities on PG&E
Corporation's results of operations for fiscal 1997 was immaterial.
In valuing its electric power, natural gas, and natural gas liquids
portfolios, PG&E Corporation considers a number of market risks and estimated
costs and continuously monitors the valuation of identified risks and adjusts
them based on present market conditions. Considerable judgment is required to
develop the estimates of fair value; thus, the estimates provided herein are not
necessarily indicative of the amounts that PG&E Corporation could realize in the
current market.
Generally, exchange-traded futures contracts require deposit of margin cash,
the amount of which is subject to change based on market movement and in
accordance with exchange rules. Margin cash requirements for over-the-counter
financial instruments are specified by the particular instrument and often do
not require margin cash and are settled monthly. Both exchange-traded and over-
the-counter options contracts require payment/receipt of an option premium at
the inception of the contract. Margin cash for commodities futures and cash on
deposit with counterparties was immaterial at December 31, 1998.
Note 4: Concentrations of Market and Credit Risk
Market Risk: Market risk is the risk that changes in market prices will
adversely effect earnings and cash flows. PG&E Corporation is primarily exposed
to the market risk associated with energy commodities such as electric power,
natural gas, and natural gas liquids. Therefore, PG&E Corporation's price risk
management activities primarily involve buying and selling fixed price commodity
commitments into the future. Net open positions often exist or are established
due to PG&E Corporation's assessment of and response to changing market
conditions. To the extent that PG&E Corporation has an open position, it is
exposed to the risk that fluctuating market prices may adversely impact its
financial results.
Credit Risk: The use of financial instruments to manage the risks associated
with changes in energy commodity prices creates exposure resulting from the
possibility of nonperformance by counterparties pursuant to the terms of their
contractual obligation. The counterparties in PG&E Corporation's portfolio
consist primarily of investor owned and municipal utilities, energy trading
companies, financial institutions, and oil and gas production companies. PG&E
Corporation minimizes credit risk by dealing primarily with creditworthy
counterparties in accordance with established credit approval practices and
limits. PG&E Corporation routinely assesses the financial strength of its
counterparties and may require letters of credit or parental guarantees when the
financial strength of a counterparty is not considered sufficient. PG&E
Corporation has experienced no material losses due to the nonperformance of
counterparties in 1998. The credit exposure of the five largest counterparties
comprised approximately $127 million of the total credit exposure associated
with financial instruments used to manage price risk. Counterparties considered
to be investment grade or higher comprise 71 percent of the total credit
exposure.
Note 5: Acquisitions and Sales
In January 1997, PG&E Corporation acquired Teco Pipeline Company for $378
million, consisting of $317 million of PG&E Corporation common stock and the
purchase of a $61 million note.
In April 1997, through one of its wholly owned subsidiaries, PG&E Corporation
sold its interest in International Generating Company, Ltd., which resulted in
an after-tax gain of approximately $120 million.
54
<PAGE>
In July 1997, PG&E Corporation completed its acquisition of Valero Energy
Corporation's natural gas business and a gas marketing business located in
Texas. PG&E Corporation issued approximately 31 million shares of its common
stock to acquire Valero along with the assumption of $780 million in long-term
debt, equating to a purchase price of approximately $1.5 billion. The
acquisition was accounted for as a purchase and accordingly, the purchase price
has been allocated to the assets acquired and the liabilities assumed based on
estimated fair values.
In September 1997, PG&E Corporation became the sole owner of USGen, an
independent power developer and manager; U.S. Operating Services Company,
USGen's operations and maintenance affiliate; and USGen Power Services, L.P.,
USGen's power marketing affiliate. Additionally, PG&E Corporation has acquired
all or part of interest in several power projects that are affiliated with
USGen.
In July 1998, PG&E Corporation sold its Australian energy holdings. The
sale represents a premium on the price in local currency of PG&E
Corporation's 1996 investment in the assets. However, the transaction
resulted in a non-recurring charge of $.06 per share in the second quarter of
1998. This charge was primarily due to the 22 percent currency devaluation of
the Australian dollar against the U.S. dollar during the past two years.
In September 1998, PG&E Corporation, through its indirect subsidiary USGen
New England, Inc., completed the acquisition of a portfolio of electric
generating assets and power supply contracts from the New England Electric
System (NEES). The acquisition has been accounted for using the purchase method
of accounting. Accordingly, the purchase price has been allocated to the assets
purchased and the liabilities assumed based upon a preliminary assessment of the
fair values at the date of acquisition.
Including fuel and other inventories and transaction costs, PG&E
Corporation's financing requirements were approximately $1.8 billion, funded
through $1.3 billion of USGen debt and a $425 million equity contribution from
PG&ECorporation. The net purchase price has been allocated as follows: (1)
electric generating assets of $2.3 billion classified as property, plant, and
equipment; (2) receivable for support payments of $0.8 billion; and
(3)contractual obligations of $1.3 billion classified as current liabilities and
other noncurrent liabilities. The NEES assets include hydroelectric, coal, oil,
and natural gas generation facilities with a combined generating capacity of
4,000 MW. In addition, USGen assumed 23 multi-year power-purchase agreements
representing an additional 800 MW of production capacity. USGen entered into
agreements with NEES as part of the acquisition, which: (1) provide that NEES
shall make support payments over the next ten years to USGen for the purchase
power agreements; and (2) require that USGen provide electricity to NEES under
contracts that expire over the next six to eleven years.
Note 6: Common Stock
PG&E Corporation: PG&E Corporation has authorized 800 million shares of no-par
common stock of which 382,603,564 and 417,665,891 shares were issued and
outstanding as of December 31, 1998 and 1997, respectively.
As of December 31, 1997, the Board of Directors had authorized the repurchase
of up to $1.7 billion of PG&E Corporation's common stock on the open market or
in negotiated transactions. As part of this authorization, in January 1998, PG&E
Corporation repurchased in a specific transaction 37 million shares of common
stock. As of December 31, 1998, approximately $570 million remains available
under this repurchase authorization. In February 1999, PG&E Corporation used
this remaining authorization to purchase 16.6 million shares at a price of
$30.25 per share. In connection with this transaction, PG&E Corporation has
entered into a forward contract with an investment institution. PG&E Corporation
will retain the risk of increases and the benefit of decreases in the price of
the common shares purchased through the forward contract. This obligation will
not be terminated until the investment institution has replaced the shares sold
to PG&E Corporation through purchases on the open market or through privately
negotiated transactions. The contract is anticipated to expire by year-end.
55
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Utility: All of the Utility's stock outstanding is held by PG&E Corporation. In
connection with the formation of the holding company, all of the Utility's
common stock was converted on a share for share basis to PG&E Corporation common
stock.
The Utility has authorized 800 million shares of $5 par value common stock of
which 341,353,455 and 403,504,292 shares are issued and outstanding at December
31, 1998 and 1997, respectively.
The CPUC requires the Utility to maintain its CPUC-authorized capital
structure, potentially limiting the amount of dividends the Utility may pay PG&E
Corporation. In 1998, the Utility was in compliance with its CPUC-authorized
capital structure.
Note 7: Preferred Stock and Utility Obligated Mandatorily Redeemable Preferred
Securities of Trust Holding Solely Utility Subordinated Debentures
Preferred Stock: The Utility has authorized 75,000,000 shares of $25 par value
preferred stock which may be issued as redeemable or nonredeemable preferred
stock. At December 31, 1998 and 1997, the Utility has issued and outstanding
5,784,825 shares of nonredeemable preferred stock.
At December 31, 1998 and 1997, the Utility has issued and outstanding
5,973,456 and 10,297,404 shares of redeemable preferred stock, respectively. The
Utility's redeemable preferred stock is subject to redemption at the Utility's
option, in whole or in part, if the Utility pays the specified redemption price
plus accumulated and unpaid dividends through the redemption date. Annual
dividends and redemption prices per share at December 31, 1998, range from $1.09
to $1.76 and from $25.00 to $27.25, respectively. In 1998, the Utility redeemed
its Series 7.44% preferred stock with a face value of $65 million. Also in 1998,
the Utility redeemed its Series 6 7\8% preferred stock with a face value of $43
million. During 1997 and 1996, the Utility did not redeem or repurchase any of
its preferred stock.
The Utility's redeemable preferred stock with mandatory redemption provisions
consists of 3 million shares of the 6.57% series and 2.5 million shares of the
6.30% series at December 31, 1998. The 6.57% series and 6.30% series may be
redeemed at the Utility's option beginning in 2002 and 2004, respectively, at
par value plus accumulated and unpaid dividends through the redemption date.
These series of preferred stock are subject to mandatory redemption provisions
entitling them to sinking funds providing for the retirement of stock
outstanding.
Holders of the Utility's nonredeemable preferred stock 5%, 5.5%, and 6%
series have rights to annual dividends per share ranging from $1.25 to $1.50.
Dividends on all preferred stock are cumulative. All shares of preferred
stock have voting rights and equal preference in dividend and liquidation
rights. Upon liquidation or dissolution of the Utility, holders of preferred
stock would be entitled to the par value of such shares plus all accumulated and
unpaid dividends, as specified for the class and series. The estimated fair
value of the Utility's preferred stock with mandatory redemption provisions at
December 31, 1998 and 1997, was $143 million and $146 million, respectively,
based on quoted market prices.
Utility Obligated Mandatorily Redeemable Preferred Securities of Trust Holding
Solely Utility Subordinated Debentures: The Utility, through its wholly owned
subsidiary, PG&E Capital I (Trust), has outstanding 12 million shares of 7.90%
cumulative quarterly income preferred securities (QUIPS), with an aggregate
liquidation value of $300 million. Concurrent with the issuance of the QUIPS,
the Trust issued to the Utility 371,135 shares of common securities with an
aggregate liquidation value of $9 million. The Trust in turn used the net
proceeds from the QUIPS offering and issuance of the common stock securities to
purchase subordinated debentures issued by the Utility with a face value of $309
million, an interest rate of 7.9 percent, and a maturity date of 2025. These
subordinated debentures are the only assets of the Trust. Proceeds from the sale
of the subordinated debentures were used to redeem and repurchase higher-cost
preferred stock.
The Utility's guarantee of the QUIPS, considered together with the other
obligations of the Utility with respect to the QUIPS, constitutes a full and
unconditional guarantee by the Utility of the Trust's contractual obligations
under the QUIPS issued by the Trust.
56
<PAGE>
The subordinated debentures may be redeemed at the Utility's option beginning
in 2000 at par value plus accrued interest through the redemption date. The
proceeds of any redemption will be used by the Trust to redeem QUIPS in
accordance with their terms.
Upon liquidation or dissolution of the Utility, holders of these QUIPS would
be entitled to the liquidation preference of $25 per share plus all accrued and
unpaid dividends thereon to the date of payment. The estimated fair value of the
Utility's QUIPS at December 31, 1998 and 1997, was $303 million and $304
million, respectively, based on quoted market prices.
Note 8: Long-Term Debt
Long-term debt at December 31, 1998 and 1997, consisted of the following:
<TABLE>
<CAPTION>
December 31, 1998 1997
<S> <C> <C>
(in millions)
Utility long-term debt
First and refunding mortgage bonds
Maturity Interest rates
1999-2002 5.500% to 8.75% $ 682 $1,241
2003-2007 5.875% to 6.250% 902 974
2008-2020 6.35% to 8.02% 160 160
2021-2026 5.85% to 8.80% 2,117 2,498
- -----------------------------------------------------------------------
Principal amounts outstanding 3,861 4,873
Unamortized discount net of premium (32) (42)
- -----------------------------------------------------------------------
Total mortgage bonds 3,829 4,831
Pollution control loan agreements,
variable rates, due 2010-2026 1,348 1,348
Unsecured medium-term notes,
5.37% to 8.45%, due 1999-2014 498 587
Other Utility long-term debt 29 32
- -----------------------------------------------------------------------
Total Utility long-term debt 5,704 6,798
Current portion of long-term debt 260 580
- -----------------------------------------------------------------------
Total Utility long-term debt, net of current
portion 5,444 6,218
Long-term debt of wholesale and retail
unregulated business operations
First mortgage notes
10.02% to 11.50%, due 1999-2009 370 409
Senior notes
10.58%, due 1999-2000 69 105
7.10%, due 2005 250 250
Medium term notes
6.61% to 9.29%, due 2000-2012 298 298
Senior debentures
7.80%, due 2025 148 148
Amounts outstanding under credit
facilities (See Note 10) 654 80
Other long-term debt 267 230
- -----------------------------------------------------------------------
Total wholesale and retail unregulated business
operations long-term debt 2,056 1,520
Current portion of long-term debt 78 79
- -----------------------------------------------------------------------
Long-term debt, net of current portion 1,978 1,441
- -----------------------------------------------------------------------
Total long-term debt $7,422 $7,659
========================
</TABLE>
Utility:
* First and Refunding Mortgage Bonds:
First and refunding mortgage bonds are issued in series and bear annual interest
rates ranging from 5.50 percent to 8.80 percent. All real properties and
57
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
substantially all personal properties of the Utility are subject to the lien of
the bonds, and the Utility is required to make semi-annual sinking fund payments
for the retirement of the bonds. Additional bonds may be issued subject to CPUC
approval, up to a maximum total amount outstanding of $10 billion assuming
compliance with indenture covenants for earnings coverage and available property
balances as security.
The Utility redeemed or repurchased $501 million and $167 million of the
bonds in 1998 and 1997, respectively, with interest rates ranging from 6.25
percent to 8.80 percent. These bonds were to mature from 2002 to 2026.
Included in the total of outstanding bonds at December 31, 1998 and 1997, are
$345 million of bonds held in trust for the California Pollution Control
Financing Authority (CPCFA) with interest rates ranging from 5.85 percent to
6.625 percent and maturity dates ranging from 2009 to 2023. In addition to these
bonds, the Utility holds long-term pollution control loan agreements with the
CPCFA as described below.
* Pollution Control Loan Agreements:
Pollution control loan agreements from the CPCFA totaled $1,348 million at
December 31, 1998 and 1997. Interest rates on the loans vary with average annual
interest rates. For 1998 the interest rates ranged from 2.56 percent to 3.68
percent. These loans are subject to redemption by the holder under certain
circumstances. These loans are primarily secured by irrevocable letters of
credit which mature 2000 through 2003.
Wholesale and Retail Unregulated Business Operations: Long-term debt of
wholesale and retail unregulated business operations consists of first mortgage
bonds and other secured and unsecured obligations.
The first mortgage notes are comprised of three series due serially from 1999
to 2009, and are secured by mortgages and security interests in the natural gas
transmission and natural gas processing facilities and other real and personal
property of PG&E GTT. The mortgage indenture requires semi-annual payments with
one-half of each interest payment and one-fourth of each annual principal
payment escrowed quarterly in advance. The mortgage indenture also contains
covenants which restrict the ability of PG&E GTT to incur additional
indebtedness and precludes cash distributions if certain cash flow coverages are
not met.
Other long-term debt consists of project financing associated with
unregulated generation facilities, premiums and other loans.
Repayment Schedule: At December 31, 1998, PG&E Corporation's combined aggregate
amounts of maturing long-term debt and sinking fund requirements, for the years
1999 through 2003, are $338 million, $698 million, $480 million, $1,256 million
and $1,288 million, respectively. The Utility's share of those maturities and
sinking fund requirements is $260 million, $466 million, $374 million, $1,120
million and $682 million, respectively.
Fair Value: The estimated fair value of PG&E Corporation's total long-term debt
at December 31, 1998 and 1997, was $8.1 billion and $8.3 billion, respectively.
The estimated fair value of the Utility's total long-term debt at December 31,
1998 and 1997, was $6.0 billion and $7.0 billion, respectively. The estimated
fair value of long-term debt was determined based on quoted market prices, where
available. Where quoted market prices were not available, the estimated fair
value was determined using other valuation techniques (for example, the present
value of future cash flows).
Note 9: Rate Reduction Bonds
In December 1997, PG&E Funding LLC (SPE), a special-purpose entity wholly owned
by the Utility, issued $2.9 billion of rate reduction bonds to the California
Infrastructure and Economic Development Bank Special Purpose Trust PG&E-1
(Trust), a special-purpose entity. The terms of the bonds generally mirror the
terms of the pass-through certificates issued by the Trust. The proceeds of the
rate reduction bonds were used by the SPE to purchase from the Utility the
right, known as "transition property," to be paid a specified amount from a
nonbypassable tariff levied on residential and small commercial customers which
was authorized by the CPUC pursuant to state legislation.
58
<PAGE>
The rate reduction bonds have maturities ranging from ten months to ten
years, and bear interest at rates ranging from 6.01 percent to 6.48 percent. The
bonds are secured solely by the transition property and there is no recourse to
the Utility or PG&E Corporation.
At December 31, 1998, $2.6 billion of rate reduction bonds were outstanding.
The combined expected principal payments on the rate reduction bonds for the
years 1999 through 2003 are $290 million for each year.
The estimated fair value of the rate reduction bonds was $2.6 billion at
December 31, 1998. The estimated fair value of the bonds was determined based on
quoted market prices.
While the SPE is consolidated with the Utility for purposes of these
financial statements, the SPE is legally separate from the Utility. The assets
of the SPE are not available to creditors of the Utility or PG&E Corporation,
and the transition property is legally not an asset of the Utility or PG&E
Corporation.
Note 10: Credit Facilities
PG&E Corporation: At December 31, 1998 and 1997, PG&E Corporation had borrowed
$2,298 million and $183 million, respectively, under various credit facilities
discussed below. $654 million and $80 million of these borrowings December 31,
1998 and 1997, respectively are classified as long-term debt. (See Note 8.) The
weighted average interest rate on the short-term borrowings was 5.6 percent and
6.9 percent for 1998 and 1997, respectively. The carrying amount of short-term
borrowings approximates fair value.
PG&E Corporation maintains two $500 million revolving credit facilities. One
expires in November 1999 and the other in 2002. The facility expiring in
November 1999 may be extended annually for additional one-year periods upon
agreement between PG&E Corporation and the lending institutions. These credit
facilities are used to support PG&E Corporation's commercial paper program and
other liquidity needs. At December 31, 1998, PG&E Corporation had $683 million
of commercial paperoutstanding supported by these facilities. No amounts were
outstanding at December 31, 1997.
59
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Utility: The Utility maintains a $1 billion revolving credit facility which
expires in 2002. The facility may be extended annually for additional one-year
periods upon agreement between the Utility and the banks. At December 31, 1998,
the Utility had $567 million of commercial paper outstanding and $101 million of
bank notes outstanding. No amounts were outstanding at December 31, 1997.
Wholesale and Retail Unregulated Business Operations: USGen has $1,675 million
in revolving credit facilities, of which $575 million is specifically related to
its New England operations. The $575 million line is comprised of a $100 million
facility, expiring in 2003, and a $475 million facility, used to execute a sale
leaseback transaction and subsequently cancelled. As of December 31, 1998, no
amounts were outstanding under these facilities. The remaining facility is a
$1.1 billion revolving credit agreement comprised of two $550 million
facilities, one of which expires in 2003, and the other of which expires in
August 1999. As of December 31, 1998, the long-term facility has a $540 million
eurodollar loan drawn on it, and it also supports $10 million of outstanding
commercial paper. Both are classified as noncurrent debt in the consolidated
balance sheet. (See Note 8.) As of December 31, 1998, the short-term facility
supported $223 million in outstanding commercial paper, which had a weighted
average rate of 5.6 percent.
PG&E GT NW maintains a $200 million revolving credit facility which expires
in the year 2000. At December 31, 1998 and 1997, PG&E GT NW had outstanding
commercial paper balances of $104 mil-lion and $80 million, respectively,
supported by this revolving facility. These balances were classified as
noncurrent debt in the consolidated balance sheet. (See Note 8.)
PG&E GTThad $70 million and $100 million of outstanding short-term bank
borrowings related to two separate credit facilities at December 31, 1998 and
1997, respectively. These lines are cancelable upon demand and bear interest at
each respective bank's quoted money market rate. The borrowings are unsecured
and unrestricted as to use.
Note 11: Nuclear Decommissioning
Decommissioning of the Utility's nuclear power plants is scheduled to begin
in 2015 with scheduled completion in 2034. Nuclear decommissioning means to
safely remove nuclear facilities from service and reduce residual radioactivity
to a level that permits termination of the Nuclear Regulatory Commission license
and release of the property for unrestricted use.
The estimated total obligation for nuclear decommissioning costs, based on a
1997 site study, is $1.5 billion in 1998 dollars (or $5.1 billion in future
dollars). This estimate assumes after-tax earnings on the tax-qualified and
nontax-qualified decommissioning funds of 6.16 percent and 5.21 percent,
respectively, as well as a future annual escalation rate of 5.5 percent for
decommissioning costs. The decommissioning cost estimates are based on the plant
location and cost characteristics for the Utility's nuclear plants. Actual
decommissioning costs are expected to vary from this estimate because of changes
in assumed dates of decommissioning, regulatory requirements, technology, and
costs of labor, materials, and equipment. The estimated total obligation is
being recognized proportionately over the license of each facility.
For the years ended December 31, 1998, 1997, and 1996, nuclear
decommissioning costs recovered in rates were $33 million per year,
respectively. Based on the 1997 site study, the amount proposed to be recovered
in rates in 1999 and annually, until the commencement of decommissioning, is $33
million. This amount is currently under review in the Utility's 1999 General
Rate Case and will continue to be reviewed in future nuclear decommissioning
cost triennial proceedings.
At December 31, 1998, the total nuclear decommissioning obligation accrued
was $1.2 billion and is included in the balance sheet classification of
accumulated depreciation and decommissioning. Decommissioning costs recovered in
rates are placed in external trust funds. These funds along with accumulated
earnings will be used exclusively for decommissioning and cannot be released
from the trust funds until authorized by the CPUC.
The following table provides a summary of amortized cost and fair value,
based on quoted market prices, of these nuclear decommissioning funds:
<TABLE>
<CAPTION>
Year ended December 31, Maturity Dates 1998 1997
- -----------------------------------------------------------------------
<S> <C> <C> <C>
(in millions)
Amortized cost
U.S. government and
agency issues 1999-2028 $ 379 $ 422
Equity securities -- 246 257
Municipal bonds and other 1999-2030 164 70
Gross unrealized holding gains 394 287
Gross unrealized holding losses (11) (12)
- -----------------------------------------------------------------------
Fair value (net, of tax) $1,172 $1,024
===================
</TABLE>
The proceeds received from sales of securities were $1.4 billion in each year
in 1998 and 1997. The gross realized gains on sales of securities held as
available-for-sale were $52 million and $40 million, in 1998 and 1997,
respectively, and the gross realized losses on sales of securities held as
available-for-sale were $39 million and $24 million, in 1998 and 1997,
respectively. The cost of debt and equity securities sold is determined by
specific identification.
Under the Nuclear Waste Policy Act of 1982, the Department of Energy (DOE) is
responsible for the permanent storage and disposal of spent nuclear fuel. The
Utility has signed a contract with the DOE to provide for the disposal of spent
nuclear fuel and high-level radioactive waste from the Utility's nuclear power
facilities. The DOE's current estimate for an available site to begin accepting
physical possession of the spent nuclear fuel is 2010. At the projected level of
operation for Diablo Canyon, the Utility's facilities are sufficient to store
on-site all spent fuel produced through approximately 2006. It is likely that an
interim or permanent DOE storage facility will not be available for Diablo
Canyon's spent fuel by 2006. The Utility is examining options for providing
additional temporary spent fuel storage at Diablo Canyon or other facilities,
pending disposal or storage at a DOE facility.
60
<PAGE>
Note 12: Employee Benefit Plans
Several of PG&E Corporation's subsidiaries provide noncontributory defined
benefit pension plans for their employees. In addition, these subsidiaries
provide contributory defined benefit medical plans for certain retired employees
and their eligible dependents and noncontributory defined benefit life insurance
plans for certain retired employees (referred to collectively as other
benefits). For both pension and other benefit plans, the Utility's plan
represents substantially all of the plan assets and the benefit obligation.
Therefore, all descriptions and assumptions are based on the Utility's plan. The
schedules below aggregate all of PG&E Corporation's plans.
The following schedule reconciles the plans' funded status (the difference
between fair value of plan assets and the benefit obligation) to the prepaid or
accrued benefit cost recorded on the consolidated balance sheet:
<TABLE>
<CAPTION>
Pension Benefits Other Benefits
------------------ -------------------
December 31, 1998 1997 1998 1997
- ----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
(in millions)
Change in benefit obligation
Benefit obligation at January 1 $(4,457) $(4,231) $(907) $(921)
Service cost for benefits earned (108) (102) (19) (22)
Interest cost (334) (315) (64) (64)
Plan amendments 1 (47) -- --
Special term benefits -- (11) -- (15)
Actuarial gain (loss) (321) 16 (36) 63
Benefits and expenses paid 242 233 77 52
- --------------------------------------------------------------------------------------------------------------------------------
Benefit obligation at December 31 (4,977) (4,457) (949) (907)
Change in plan assets
Fair value of plan assets at January 1 6,419 5,526 823 669
Actual return on plan assets 919 1,139 173 144
Company contributions 27 2 18 48
Plan participant contribution -- -- 13 11
Benefits and expenses paid (261) (248) (76) (49)
- --------------------------------------------------------------------------------------------------------------------------------
Fair value of plan assets at December 31 7,104 6,419 951 823
Plan assets in excess of benefit obligation 2,127 1,962 2 (84)
(Benefit obligation in excess of plan assets)
Unrecognized prior service cost 104 121 19 20
Unrecognized net loss (gain) (2,025) (2,133) (430) (375)
Unrecognized net transition obligation 79 93 366 393
- --------------------------------------------------------------------------------------------------------------------------------
Prepaid (accrued) benefit cost $ 285 $ 43 $(43) $(46)
=========================================
</TABLE>
The Utility's share of the plan's assets in excess of the benefit obligation
for pensions in 1998 and 1997 was $2,134 million and $2,003 million,
respectively. The Utility's share of the prepaid (accrued) benefit cost for the
pensions in 1998 and 1997 was $301 million and $60 million, respectively.
The plan assets of the Utility exceeded its share of the benefit obligation
for other benefits by $24 million in 1998. In 1997, the Utility's share of the
benefit obligation in excess of the plan assets was $64 million. The Utility's
share of the accrued benefit liability for other benefits in 1998 and 1997 was
$26 million and $29 million, respectively.
Unrecognized prior service costs and the net gains are amortized on a
straight-line basis over the average remaining service period of active plan
participants. The transition obligations for pension benefits and other benefits
are being amortized over 17.5 years from 1987.
Net benefit income (cost) was as follows:
61
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
Pension Benefits Other Benefits
-------------------- --------------------
December 31, 1998 1997 1996 1998 1997 1996
- -----------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
(in millions)
Service cost for benefits earned $(108) $(102) $(101) $(19) $(21) $(22)
Interest cost (333) (316) (304) (64) (64) (66)
Expected return on assets 567 486 434 73 60 49
Amortized prior service and transition
cost (26) (22) (23) (28) (28) (28)
Actuarial gain (loss) recognized 114 74 43 22 13 4
- ------------------------------------------------------------------------------------------------
Benefit income (cost) $ 214 $120 $49 $(16) $(40) $(63)
========================================================
</TABLE>
The Utility's share of the net benefit income for pensions in 1998, 1997, and
1996 was $215 million, $123 million, and $49 million, respectively.
The Utility's share of the net benefit cost for other benefits in 1998, 1997,
and 1996 was $12 million, $38 million, and $61 million, respectively.
Net benefit income (cost) is calculated using expected return on plan assets
of 9.0 percent. The difference between actual and expected return on plan assets
is included in net amortization and deferral and is considered in the
determination of future net benefit income (cost). In 1998, 1997, and 1996,
actual return on plan assets exceeded expected return.
In conformity with SFAS No. 71, regulatory adjustments have been recorded in
the income statement and balance sheet of the Utility which reflect the
difference between Utility pension income determined for accounting purposes and
Utility pension income determined for ratemaking, which is based on a funding
approach.
The CPUC has also authorized the Utility to recover the costs associated with
its other benefit plans for 1993 and beyond. Recovery is based on the lesser of
the annual accounting costs or the annual contributions on a tax-deductible
basis to the appropriate trusts.
The following actuarial assumptions were used in determining the plans'
funded status and net benefit income (cost). Year-end assumptions are used to
compute funded status, while prior year-end assumptions are used to compute net
benefit income (cost).
<TABLE>
<CAPTION>
Pension Benefits Other Benefits
---------------------- ----------------------
December 31, 1998 1997 1996 1998 1997 1996
- --------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Discount rate 7.0% 7.5% 7.5% 7.0% 7.5% 7.5%
Rate of future compensation
increases 5.0% 5.0% 5.0% 5.0% 5.0% 5.0%
Expected long-term rate of
return on plan assets 9.0% 9.0% 9.0% 9.0% 9.0% 9.0%
</TABLE>
The assumed health care cost trend rate for 1999 is approximately 9.0
percent, grading down to an ultimate rate in 2005 of approximately 6.0 percent.
The assumed health care cost trend rate can have a significant effect on the
amounts reported for health care plans. A one percentage point change would have
the following effects:
<TABLE>
<CAPTION>
1-Percentage- 1-Percentage-
(in millions) Point Increase Point Decrease
- ----------------------------------------------------------------------------------------------------------------
<S> <C> <C>
Effect on total service and interest
cost components $ 8 $ (7)
Effect on postretirement benefit obligation $ 79 $(72)
</TABLE>
Long-term Incentive Program: PG&E Corporation maintains a Long-term Incentive
Program (Program) which provides for grants of stock options to eligible
participants with or without associated stock appreciation rights and dividend
equivalents. As of December 31, 1998, 24.5 million shares of common stock have
been authorized for award under the program with 10,844,471 shares still
available under this plan. At December 31, 1998, stock options on 11,225,564
shares, granted at option prices ranging from $21.125 to $34.25, were
outstanding, of which 2,440,008 were exercisable. In 1998, 6,367,100 options
were granted at an average option price of $30.52, for an approximate value of
$24,258,651 using the Black-Scholes valuation method.
Outstanding stock options expire ten years and one day after the date of
grant and become exercisable on a
62
<PAGE>
cumulative basis at one-third each year commencing two years from the date of
grant. In 1998, 1997, and 1996, stock options on 710,271; 235,315; and 72,960
shares, respectively, were exercised at option prices ranging from $16.75 to
$34.25. In addition, on January 4, 1999, PG&E Corporation granted 6,173,500
options at $30.9375, the then current market price.
Note 13: Income Taxes
The significant components of income tax expense were:
<TABLE>
<CAPTION>
PG&E Corporation Utility
-------------------- --------------------
Year ended December 31, 1998 1997 1996 1998 1997 1996
- -----------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
(in millions)
Current $677 $ 707 $ 705 $ 886 $ 791 $ 705
Deferred (52) (119) (132) (201) (142) (132)
Tax credits-net (55) (40) (18) (56) (40) (18)
- -----------------------------------------------------------------------------------
Total income tax expense $570 $ 548 $ 555 $ 629 $ 609 $ 555
=================================================
</TABLE>
The significant components of net deferred income tax liabilities were:
<TABLE>
<CAPTION>
PG&E Corporation Utility
December 31, 1998 1997 1998 1997
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
(in millions)
Deferred income tax assets $ 1,219 $1,108 $ 843 $ 96
- -----------------------------------------------------------------------------------------------------------------------------------
Deferred income tax liabilities:
Regulatory balancing accounts 43 311 40 311
Plant in service 3,722 3,621 2,930 3,144
Income tax regulatory asset 391 430 381 420
Other 968 924 555 540
- -----------------------------------------------------------------------------------------------------------------------------------
Total deferred income tax liabilities 5,124 5,286 3,906 4,415
- -----------------------------------------------------------------------------------------------------------------------------------
Total net deferred income taxes $3,905 $4,178 $3,063 $3,453
========================================
Classification of net deferred income taxes:
Included in current liabilities $ 44 $ 149 $ 3 $ 149
Included in noncurrent liabilities 3,861 4,029 3,060 3,304
Total net deferred income taxes $3,905 $4,178 $3,063 $3,453
========================================
</TABLE>
The differences between income taxes and amounts determined by applying the
federal statutory rate to income before income tax expense were:
<TABLE>
<CAPTION>
PG&E Corporation Utility
--------------------------- ----------------------
Year ended December 31, 1998 1997 1996 1998 1997 1996
- -----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Federal statutory income tax rate 35.0% 35.0% 35.0% 35.0% 35.0% 35.0%
Increase (decrease) in income tax rate resulting from:
State income tax (net of federal benefit) 3.3 5.3 3.8 6.6 4.6 3.7
Effect of regulatory treatment of depreciation
differences 10.4 8.1 6.0 9.8 7.5 5.9
Tax credits-net (4.3) (3.2) (1.4) (4.1) (2.9) (1.4)
Effect of foreign earnings at different tax rate .6 (2.2) -- -- -- --
Other-net (.8) .3 -- (1.0) -- (.8)
- ------------------------------------------------------------------------------------------------------------------------
Effective tax rate 44.2% 43.3% 43.4% 46.3% 44.2% 42.4%
=========================================================
</TABLE>
63
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Historically, the benefits of certain temporary differences have been
utilized to reduce the Utility's customers rates. Accordingly, a regulatory
asset has been recorded reflecting the pre-tax amount that will be recovered
from customers as the temporary difference reverses. In connection with the
California electric restructuring plan, the Utility is collecting the regulatory
asset over four years.
Note 14: Commitments
Utility:
* Letters of Credit:
The Utility uses $385 million in standby letters of credit and surety bonds to
secure future workers' compensation liabilities.
* Restructuring Trust Guarantees:
Tax-exempt restructuring trusts have been established to oversee the development
of the operating framework for the competitive generation market in California.
(See Note 2.) The CPUC has authorized California utilities to guarantee bank
loans of up to $300 million to be used by the trusts for this purpose. Under
this authorization, the Utility has guaranteed up to a maximum of $135 million
of these loans. The bank loans will be repaid and the guarantees removed when
the trusts obtain proceeds from permanent financing or rate recovery.
* Power-Purchase Contracts:
By federal law, the Utility is required to purchase electric energy and capacity
provided by cogenerators and small 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, the Utility 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. The Utility's contracts with these power
producers expire on various dates through 2028. Total energy payments are
expected to decline in the years 1999 through 2001. Total capacity payments are
expected to remain at current levels during this period. Deliveries from these
power producers account for approximately 23 percent of the Utility's 1998
electric energy requirements, and no single contract accounted for more than
five percent of the Utility's energy needs.
The Utility 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 in the accompanying balance sheet. At
December 31, 1998, the total discounted future payments remaining under early
termination or suspension contracts is $48 million.
The Utility also has contracts with various irrigation districts and water
agencies to purchase hydroelectric power. Under these contracts, the Utility
must make specified semi-annual minimum payments whether or not any energy is
supplied (subject to the supplier's retention of the FERC's authorization) and
variable payments for operation and maintenance costs incurred by the suppliers.
These contracts expire on various dates from 2004 to 2031. These costs are also
recoverable in rates. At December 31, 1998, the undiscounted future minimum
payments under these contracts are $32 million for each of the years 1999
through 2003 and a total of $280 million for periods thereafter. Irrigation
district and water agency deliveries in the aggregate account for approximately
7.5 percent of the Utility's 1998 electrict energy requirements.
The amount of energy received and the total payments made under all of these
power-purchase contracts were:
<TABLE>
<CAPTION>
Year ended December 31, 1998 1997 1996
- ------------------------------------------------------------
<S> <C> <C> <C>
(in millions)
Kilowatt-hours received 25,994 24,389 26,056
Energy payments 943 1,157 1,136
Capacity payments 529 538 521
Irrigation district and water
agency payments 53 56 52
</TABLE>
* Natural Gas Transportation Commitments:
The Utility has long-term gas transportation service contracts with various
Canadian and interstate pipeline companies. For the duration of these contracts,
the Utility has agreed to pay the pipeline companies an amount each year for
capacity rights on their pipelines. The amount that the Utility pays each year
varies due to changes in the rates of the pipeline companies. The
64
<PAGE>
total amounts the Utility paid under these contracts were $113 million, $255
million, and $269 million in 1998, 1997, and 1996, respectively. These amounts
include payments made by the Utility to PG&E GT of $49 million, $49 million, and
$57 million in 1998, 1997, and 1996, respectively.
The Utility's obligations related to capacity held pursuant to long-term
contracts on various pipelines are as follows:
- --------------------------------------------------------------------
(in millions)
1999 $102
2000 102
2001 99
2002 83
2003 83
Thereafter 188
- --------------------------------------------------------------------
Total $657
=======
As a result of regulatory changes, the Utility no longer procures gas for
most of its industrial and larger commercial (noncore) customers, resulting in a
decrease in the Utility's need for capacity on these pipelines. Despite these
changes, the Utility continues to procure gas for substantially all of its
residential and smaller commercial (core) customers and its noncore customers
who choose bundled service. To the extent that the Utility's current capacity
holdings exceed demand for gas transportation by its customers, the Utility will
continue its efforts to broker such excess capacity.
Wholesale and Retail Unregulated Business Operations:
* Power-Purchase Contracts:
As a part of the acquisition of a portfolio of electric generating assets and
power supply contracts from NEES (See Note 5), NEES transferred to USGen
contractual rights and duties under several power-purchase contracts with third-
party independent power producers, which in the aggregate provide for
approximately 800 MW of capacity. Under the transfer agreement, USGen is
required to pay to NEES amounts due to the third-party power producers under the
power-purchase contracts. USGen's payment obligations to NEES are reduced by
NEES's monthly payment obligation, which equals, in the aggregate, approximately
$1.1 billion, payable in monthly installments from September 1998 through
January 2008. In certain circumstances, NEES, with the consent of USGen, will
make a full or partial lump-sum accelerated payment of the monthly payment
obligation to such party as USGen may direct. The approximate dollar obligations
under these agreements are as follows:
- --------------------------------------------------------------------
(in millions)
1999 $ 261
2000 272
2001 263
2002 238
2003 217
Thereafter 2,024
- --------------------------------------------------------------------
Total $3,275
=========
* Natural Gas Transportation Commitments:
As a part of the acquisition of a portfolio of electric generating assets and
power supply contracts from NEES (See Note 5), NEES transferred to USGen four
natural gas purchase agreements with contract expirations ranging from October
2008 to October 2013, as well as eleven natural gas transportation contracts
with contract expirations ranging from October 2006 to October 2014. The
approximate dollar obligations under the natural gas transportation agreements
are as follows:
(in millions)
1999 $ 58
2000 58
2001 58
2002 58
2003 57
Thereafter 465
- --------------------------------------------------------------------
Total $754
========
* Standard Offer Agreements:
As a part of the acquisition of a portfolio of electric generating assets and
power supply contracts from NEES (See Note 5), USGen entered into agreements to
supply the electric capacity and energy necessary for NEES to meet its
obligations to provide standard offer service. The agreements to provide
standard offer service range in length from 6 to 11 years. The price per MW hour
is standard for all agreements. The approximate dollar obligations under the
agreements are as follows:
65
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- --------------------------------------------------------------------
(in millions)
1999 $ 788
2000 767
2001 712
2002 483
2003 345
Thereafter 302
- --------------------------------------------------------------------
Total $3,397
==========
Note 15: Contingencies
Nuclear Insurance: The Utility has insurance for property damage and business
interruption losses as a member of Nuclear Electric Insurance Limited (NEIL).
Under this insurance, if a nuclear generating facility suffers a loss due to a
prolonged accidental outage, then the Utility may be subject to maximum
retrospective assessments of $17 million (property damage) and $5 million
(business interruption), in each case per policy period, in the event losses
exceed the resources of NEIL.
The Utility has purchased primary insurance of $200 million for public
liability claims resulting from a nuclear incident. The Utility has secondary
financial protection which provides an additional $9.6 billion in coverage,
which is mandated by federal legislation. It 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, then the Utility
may be assessed up to $176 million per incident, with payments in each year
limited to a maximum of $20 million per incident.
Environmental Remediation: The Utility may be required to pay for environmental
remediation at sites where the Utility has been or may be a potentially
responsible party under the Comprehensive Environmental Response, Compensation,
and Liability Act (CERCLA) or the California Hazardous Substance Account Act.
These sites include former manufactured gas plant sites, power plant sites, and
sites used by the Utility for the storage or disposal of potentially hazardous
materials. Under CERCLA, the Utility may be responsible for remediation of
hazardous substances even if the Utility did not deposit those substances on the
site.
The Utility records a liability when site assessments indicate remediation is
probable and a range of reasonably likely cleanup costs can be estimated. The
Utility reviews its remediation liability quarterly for each identified site.
The liability is an estimate of costs for site investigations, remediation,
operations and maintenance, monitoring, and site closure. The remediation costs
also reflect: (1) current technology, (2) enacted laws and regulations, (3)
experience gained at similar sites, and (4) the probable level of involvement
and financial condition of other potentially responsible parties. Unless there
is a better estimate within this range of possible costs, the Utility records
the lower end of this range.
The cost of the hazardous substance remediation ultimately undertaken by the
Utility is difficult to estimate. A change in the estimate may occur in the near
term due to uncertainty concerning the Utility's responsibility, the complexity
of environmental laws and regulations, and the selection of compliance
alternatives. The Utility had an accrued liability of $296 million and $232
million at December 31, 1998 and 1997, respectively, for hazardous waste
remediation costs at identified sites, including divested fossil-fueled power
plants.
Environmental remediation at identified sites may be as much as $487 million
if, among other things, other potentially responsible parties 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. The Utility estimated this upper limit of the range of costs using
assumptions least favorable to the Utility, based upon a range of reasonably
possible outcomes. Costs may be higher if the Utility is found to be responsible
for cleanup costs at additional sites or expected outcomes change.
Of the $296 million liability, discussed above, the Utility has recovered
$104 million and expects to recover another $160 million in future rates.
Additionally, the Utility mitigates its cost by seeking recovery of its costs
from insurance carriers and from other third parties as appropriate.
Legal Matters:
* Chromium Litigation:
Several civil suits are pending against the Utility in California state courts.
The suits seek an unspecified
66
<PAGE>
amount of compensatory and punitive damages for alleged personal injuries and,
in some cases, property damage, resulting from alleged exposure to chromium in
the vicinity of the Utility's gas compressor stations at Hinkley, Kettleman, and
Topock, California. Two of these suits also name PG&E Corporation as a
defendant. Currently, there are claims pending on behalf of approximately 2,300
individuals.
The Utility is responding to the suits and asserting affirmative defenses.
The Utility will pursue appropriate legal defenses, including statute of
limitations or exclusivity of workers' compensation laws, and factual defenses,
including lack of exposure to chromium and the inability of chromium to cause
certain of the illnesses alleged.
PG&E Corporation believes that the ultimate outcome of these matters will not
have a material impact on its or the Utility'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 GTT, PG&E GTT succeeded to the litigation described below.
PG&E GTT and various of its affiliates are defendants in at least two class
action suits and five separate suits filed by various Texas cities. Generally,
these cities allege, among other things, that: (1) owners or operators of
pipelines occupied city property and conducted pipeline operations without the
cities' consent and without compensating the cities; and (2) the gas marketers
failed to pay the cities for accessing and utilizing the pipelines located in
the cities to flow gas under city streets. Plaintiffs also allege various other
claims against the defendants for failure to secure the cities' consent. Damages
are not quantified.
In 1998, a jury trial was held in the separate suit brought by the City of
Edinburg (the City). This suit involved, among other things, a particular
franchise agreement entered into by a former subsidiary of PG&E GTT (now owned
by Southern Union Gas Company (SU)) and the City and certain conduct of the
defendants.
On December 1, 1998, based on the jury verdict, the court entered a judgment
in the City's favor, and awarded damages of $5.3 million, and attorneys' fees of
up to $3.5 million plus interest. The court found that various PG&E GTT and SU
defendants were jointly and severally liable for $3.3 million of the damages and
all the attorneys' fees. Certain PG&E GTT subsidiaries were found solely liable
for $1.4 million of the damages. The court did not clearly indicate the extent
to which the PG&E GTT defendants could be found liable for the remaining
damages. The PG&E GTT defendants intend to appeal the judgment.
PG&E Corporation believes that the ultimate outcome of these matters could
have a material adverse impact on its financial position or results of
operations.
Note 16: Segment Information
PG&E Corporation's reportable operating segments provide different products and
services and are subject to different forms of regulation or jurisdictions. The
accounting policies of the reportable operating segments are the same as those
described in Note 1. PG&E Corporation's reportable segments are des-cribed
below.
Utility: PG&E Corporation's Northern and Central California energy utility
subsidiary, Pacific Gas and Electric Company, provides natural gas and electric
service to one of every 20 Americans.
Wholesale Unregulated Business Operations: PG&E Corporation's wholesale
unregulated business operations consist of USGen which develops, builds,
operates, owns, and manages power generation facilities that serve wholesale and
industrial customers; PG&EGT which operates approximately 9,000 miles of natural
gas pipelines, natural gas storage facilities, and natural gas processing plants
in the Pacific Northwest and Texas; and PG&EET which purchases and resells
energy commodities and related financial instruments in major North American
markets, serving PG&E Corporation's other unregulated businesses, unaffiliated
utilities, and large end-use customers.
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<PAGE>
Retail Unregulated Business Operations: PG&ECorporation's retail unregulated
business operations consist of PG&E ES which provides competitively priced
electricity, natural gas, and related services to lower overall energy costs
Segment information for the years 1998, 1997, and 1996 was as follows:
<TABLE>
<CAPTION>
Wholesale Retail
------------------------------------- ---------
PG&E ET
-------------------- Corp. & Elimi-
Utility USGen/(5)/ NW TEXAS/(5)/ PG&E ET PG&E ES Other/(2)/ nations Total
- ------------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
(in millions)
1998
Operating revenues $ 8,919 $ 645 $ 185 $1,640 $8,183 $365 $ 8 $ (3) $19,942
Intersegment revenues/(1)/ 5 4 52 301 326 14 -- (702) --
- ------------------------------------------------------------------------------------------------------------------------------------
Total operating revenues 8,924 649 237 1,941 8,509 379 8 (705) 19,942
- ------------------------------------------------------------------------------------------------------------------------------------
Depreciation, amortization and
decommissioning 1,438 52 39 65 5 7 3 -- 1,609
Interest expense/(3)/ (621) (43) (43) (77) (7) (1) (30) 40 (782)
Other income (expense) 76 18 3 13 5 (1) (6) (44) 64
Income taxes/(4)/ 629 28 31 (47) (17) (41) (13) -- 570
Net income 702 106 65 (71) (6) (52) (18) (7) 719
Capital expenditures 1,396 98 49 39 12 38 1 -- 1,633
Total assets at year-end $22,950 $3,844 $1,169 $2,655 $2,555 $ 202 $ 601 $(742) $33,234
1997
Operating revenues $ 9,495 $ 148 $ 186 $ 800 $4,613 $ 145 $ 13 $ -- $15,400
Intersegment revenues/(1)/ -- -- 47 204 195 -- -- (446) --
- ------------------------------------------------------------------------------------------------------------------------------------
Total operating revenues 9,495 148 233 1,004 4,808 145 13 (446) 15,400
- ------------------------------------------------------------------------------------------------------------------------------------
Depreciation, amortization and
decommissioning 1,748 19 38 33 3 1 10 -- 1,852
Interest expense/(3)/ (570) (5) (41) (26) (2) (1) (32) 12 (665)
Other income (expense) 83 (25) 1 13 3 -- 138 (12) 201
Income taxes/(4)/ 609 (17) 26 (8) (12) (17) (33) -- 548
Net income 735 (41) 40 (24) (19) (29) 54 -- 716
Capital expenditures 1,529 23 34 45 5 15 50 -- 1,701
Total assets at year-end $25,147 $989 $1,208 $2,800 $1,452 $60 $370 $(911) $31,115
1996
Operating revenues $ 8,989 $105 $ 206 $ -- $ 283 $-- $27 $ -- $ 9,610
Intersegment revenues/(1)/ -- -- 58 -- -- -- -- (58) --
- ------------------------------------------------------------------------------------------------------------------------------------
Total operating revenues 8,989 105 264 -- 283 -- 27 (58) 9,610
- ------------------------------------------------------------------------------------------------------------------------------------
Depreciation, amortization and
decommissioning 1,177 12 32 -- -- -- 1 -- 1,222
Interest expense/(3)/ (600) (7) (45) -- -- -- 20 -- (632)
Other income (expense) 20 9 (4) -- -- -- (12) -- 13
Income taxes/(4)/ 526 (6) 31 -- -- -- 4 -- 555
Net income 706 (6) 50 -- -- -- (28) -- 722
Capital expenditures 1,231 -- 173 -- -- -- -- -- 1,404
Total assets at year-end $23,567 $881 $1,772 $-- $-- $-- $205 $(188) $26,237
</TABLE>
/(1)/ Intersegment electric and gas revenues are recorded at market prices,
which for the Utility and PG&E GT NW are tariffed rates prescribed by the
CPUC and FERC, respectively.
/(2)/ Assets of PG&E Corporation are included in the Other column exclusive of
investment in its subsidiaries.
/(3)/ Net interest expense incurred by PG&E Corporation is allocated to the
segments using specific identification.
/(4)/ Income tax expense for the Utility is computed on a stand-alone basis. The
balance of the consolidated income tax provision is allocated among the
unregulated wholesale and retail segments.
/(5)/ Income from equity-method investees for 1998, 1997, and 1996 was $113
million, $41 million, and $36 million, respectively, for USGen, and $3
million and $2 million, respectively, for PG&E GT Texas.
68
<PAGE>
QUARTERLY CONSOLIDATED FINANCIAL DATA (UNAUDITED)
<TABLE>
<CAPTION>
Quarter ended December 31 September 30 June 30 March 31
- -------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
(in millions, except per share amounts)
1998
PG&E Corporation
Operating revenues $5,495 $5,307 $4,787 $4,353
Operating income 456 529 557 465
Net income 196 210 174 139
Earnings per common share, basic and diluted .51 .55 .46 .36
Dividends declared per common share .30 .30 .30 .30
Common stock price per share
High 35.00 33.38 33.19 33.19
Low 30.44 30.06 30.13 29.38
Utility
Operating revenues $2,218 $2,563 $2,117 $2,026
Operating income 443 513 494 426
Income available for common stock 169 199 186 148
1997
PG&E Corporation
Operating revenues $4,889 $4,063 $3,083 $3,365
Operating income 265 628 371 464
Net income 94 257 193 172
Earnings per common share, basic and diluted .22 .62 .49 .42
Dividends declared per common share .30 .30 .30 .30
Common stock price per share
High 30.94 24.94 25.00 24.25
Low 23.00 22.69 22.38 20.88
Utility
Operating revenues $2,401 $2,541 $2,279 $2,274
Operating income 390 626 370 445
Income available for common stock 180 269 122 164
</TABLE>
69
<PAGE>
REPORT OF INDEPENDENT PUBLIC ACCOUTANTS
To the Shareholders and the Board of Directors of PG&E Corporation and Pacific
Gas and Electric Company:
We have audited the accompanying consolidated balance sheets of PG&E Corporation
(a California corporation) and subsidiaries and Pacific Gas and Electric Company
(a California corporation) and subsidiaries as of December 31, 1998, and 1997,
and the related statements of consolidated income, cash flows, and common stock
equity of PG&E Corporation and subsidiaries and the related statements of
consolidated income, cash flows and common stock equity, preferred stock and
preferred securities of Pacific Gas and Electric Company and subsidiaries for
each of the three years in the period ended December 31, 1998. These financial
statements are the responsibility of the management of PG&E Corporation and
Pacific Gas and Electric Company. Our responsibility is to express an opinion
on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overal l financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial positions of PG&E Corporation and
subsidiaries, and of Pacific Gas and Electric Company and subsidiaries, as of
December 31, 1998, and 1997, and the results of their operations and their cash
flows for each of the three years in the period ended December 31, 1998, in
conformity with generally accepted accounting principles.
ARTHUR ANDERSEN LLP
San Francisco, California
February 8, 1999
RESPONSIBILITY FOR CONSOLIDATED FINANCIAL STATEMENTS
At both PG&E Corporation and Pacific Gas and Electric Company (the Utility)
management is responsible for the integrity of the accompanying consolidated
financial statements. These statements have been prepared in accordance with
generally accepted accounting principles. Management considers materiality and
uses its best judgment to ensure that such statements reflect fairly the
financial position, results of operations, and cash flows of PG&E Corporation
and the Utility.
PG&E Corporation and the Utility maintain systems of internal controls
supported by formal policies and procedures which are communicated throughout
PG&E Corporation and the Utility. These controls are adequate to provide
reasonable assurance that assets are safeguarded from material loss or
unauthorized use and that necessary records are produced for the preparation of
consolidated financial statements. There are limits inherent in all systems of
internal controls, based on recognition that the costs of such systems should
not exceed the benefits to be derived. PG&E Corporation and the Utility believe
that their systems of internal control provide this appropriate balance. PG&E
Corporation management also maintains a staff of internal auditors who evaluate
the adequacy of, and assess the adherence to, these controls, policies, and
procedures for all of PG&E Corporation, including the Utility.
Both PG&E Corporation's and the Utility's consolidated financial statements
have been audited by Arthur Andersen LLP, PG&E Corporation's independent public
accountants. The audit includes a review of the internal accounting controls and
performance of other tests necessary to support an opinion. The auditors' report
contains an independent informed judgment as to the fairness, in all material
respects, of reported results of operations and financial position.
The Audit Committee of the Board of Directors for PG&E Corporation meets
regularly with management, internal auditors, and Arthur Andersen LLP, jointly
and separately, to review internal accounting controls and auditing and
financial reporting matters. The internal auditors and Arthur Andersen LLP have
free access to the Audit Committee, which consists of five outside directors.
The Audit Committee has reviewed the financial data contained in this report.
PG&E Corporation and the Utility are committed to full compliance with all
laws and regulations and to conducting business in accordance with high
standards of ethical conduct. Management has taken the steps necessary to ensure
that all employees and other agents understand and support this commitment.
Guidance for corporate compliance and ethics is provided by an officers' Ethics
Committee and by a Legal Compliance and Business Ethics organization. PG&E
Corporation and the Utility believe that these efforts provide reasonable
assurance that each of their operations is conducted in conformity with
applicable laws and with their commitment to ethical conduct.
70
<PAGE>
EXHIBIT 23
[LETTERHEAD OF ARTHUR ANDERSEN LLP]
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation of our
report dated February 8, 1999, incorporated by reference in this Form 10-K, into
the Company's previously filed registration statements as follows: (1) PG&E
Corporation's Form S-3 Registration Statement File No. 333-16255 (relating to
PG&E Corporation's Dividend Reinvestment Plan); (2) Pacific Gas and Electric
Company's Form S-3 Registration Statement File No. 33-64136 (relating to
$2,000,000,000 aggregate principal amount of Pacific Gas and Electric Company's
First and Refunding Mortgage Bonds and Medium-Term Notes); (3) Pacific Gas and
Electric Company's Form S-3 Registration Statement File No. 33-50707 (relating
to $1,500,000,000 aggregate principal amount of Pacific Gas and Electric
Company's First and Refunding Mortgage Bonds); (4) PG&E Corporation's Form S-8
Registration Statement File No. 33-50601 (relating to the Pacific Gas and
Electric Company Savings Fund Plan for Employees); (5) PG&E Corporation's
Form S-8 Registration Statement File No. 33-23692 (relating to PG&E
Corporation's 1986 Stock Option Plan); (6) Pacific Gas and Electric Company's
Form S-3 Registration Statement File No. 33-62488 (relating to 10,000,000 shares
of Pacific Gas and Electric Company's Redeemable First Preferred Stock); (7)
Form S-3 Registration Statement File No. 33-61959 (relating to $335,000,000)
aggregate liquidation value of Cumulative Quarterly Income Preferred
Securities); (8) PG&E Corporation's Form S-8 Registration Statement File No.
333-16253 (relating to PG&E Corporation's Long-Term Incentive Program), (9) PG&E
Corporation's Form S-3 Registration Statement File No.333-25685 (relating to the
resale of PG&E Corporation shares held by certain shareholders), (10) PG&E
Corporation's Post-Effective Amendment on Form S-8 to Form S-4 Registration
Statement File No. 333-27015 (relating to Valero Energy Corporation Stock Option
Plan No. 4, Valero Energy Corporation Stock Option Plan No. 5, and Valero Energy
Corporation Executive Stock Incentive Plan), (11) PG&E Corporation's Form S-8
Registration Statement File No. 333-33657 (relating to PG&E Gas Transmission,
Texas Corporation Savings Fund Plan), (12) PG&E Corporation's Form S-8
Registration Statement File No. 333-68155 (relating to PG&E Gas Transmission,
Northwest Corporation Savings Fund Plan for Non-Management Employees, PG&E Gas
Transmission, Northwest Corporation Savings Fund Plan for Management Employees,
and (13) PG&E Corporation's Form S-8 Registration Statement File No. 333-69437
(relating to PG&E Energy Services Retirement Plan, U.S. Generating Company
401(k) Profit-Sharing Plan, and U.S. Generating Company 401(k) Profit-Sharing
Plan for Bargaining Unit Employees.
/s/ ARTHUR ANDERSEN LLP
San Francisco, California
March 5, 1999
<PAGE>
Exhibit 24.1
RESOLUTION OF THE
-----------------
BOARD OF DIRECTORS OF
---------------------
PG&E CORPORATION
----------------
February 17, 1999
-----------------
BE IT RESOLVED that each of LESLIE H. EVERETT, LINDA Y.H. CHENG, WONDY S.
LEE, ERIC MONTIZAMBERT, GARY P. ENCINAS, and KATHLEEN HAYES is hereby authorized
to sign on behalf of this corporation and as attorneys in fact for the Chairman
of the Board, President, and Chief Executive Officer, the Senior Vice President,
Chief Financial Officer, and Treasurer, and the Vice President and Controller of
this corporation the Form 10-K Annual Report for the year ended December 31,
1998, required by Section 13 or 15(d) of the Securities Exchange Act of 1934 and
all amendments and other filings or documents related thereto to be filed with
the Securities and Exchange Commission, and to do any and all acts necessary to
satisfy the requirements of the Securities Exchange Act of 1934 and the
regulations of the Securities and Exchange Commission adopted thereunder with
regard to said Form 10-K Annual Report.
<PAGE>
I, LINDA Y.H. CHENG, do hereby certify that I am an Assistant Corporate
Secretary of PG&E CORPORATION, a corporation organized and existing under the
laws of the State of California; that the above and foregoing is a full, true,
and correct copy of a resolution which was duly adopted by the Board of
Directors of said corporation at a meeting of said Board which was duly and
regularly called and held at the office of said corporation on February 17,
1999; and that this resolution has never been amended, revoked, or repealed, but
is still in full force and effect.
WITNESS my hand and the seal of said corporation hereunto affixed this 5th
day of March, 1999.
/s/ Linda Y.H. Cheng
-------------------------------
Linda Y.H. Cheng
Assistant Corporate Secretary
PG&E CORPORATION
C O R P O R A T E
S E A L
<PAGE>
RESOLUTION OF THE
-----------------
BOARD OF DIRECTORS OF
---------------------
PACIFIC GAS AND ELECTRIC COMPANY
--------------------------------
February 17, 1999
-----------------
BE IT RESOLVED that each of LESLIE H. EVERETT, LINDA Y.H. CHENG, WONDY S.
LEE, ERIC MONTIZAMBERT, GARY P. ENCINAS, and KATHLEEN HAYES is hereby authorized
to sign on behalf of this company and as attorneys in fact for the President and
Chief Executive Officer, the Senior Vice President-Treasurer and Chief Financial
Officer, and the Vice President and Controller of this corporation the Form 10-K
Annual Report for the year ended December 31, 1998, required by Section 13 or
15(d) of the Securities Exchange Act of 1934 and all amendments and other
filings or documents related thereto to be filed with the Securities and
Exchange Commission, and to do any and all acts necessary to satisfy the
requirements of the Securities Exchange Act of 1934 and the regulations of the
Securities and Exchange Commission adopted thereunder with regard to said Form
10-K Annual Report.
<PAGE>
I, LINDA Y.H. CHENG, do hereby certify that I am Senior Assistant Corporate
Secretary of PACIFIC GAS AND ELECTRIC COMPANY, a corporation organized and
existing under the laws of the State of California; that the above and foregoing
is a full, true, and correct copy of a resolution which was duly adopted by the
Board of Directors of said corporation at a meeting of said Board which was duly
and regularly called and held at the office of said corporation on February 17,
1999; and that this resolution has never been amended, revoked, or repealed, but
is still in full force and effect.
WITNESS my hand and the seal of said corporation hereunto affixed this
5th day of March, 1999.
/s/ Linda Y.H. Cheng
-------------------------------
Linda Y.H. Cheng
Senior Assistant Corporate Secretary
PACIFIC GAS AND ELECTRIC COMPANY
C O R P O R A T E
S E A L
<PAGE>
Exhibit 24.2
POWER OF ATTORNEY
Each of the undersigned Directors of PG&E Corporation hereby constitutes
and appoints LESLIE H. EVERETT, LINDA Y.H. CHENG, WONDY S. LEE, ERIC
MONTIZAMBERT, GARY P. ENCINAS, and KATHLEEN HAYES, and each of them, as his or
her attorneys in fact with full power of substitution to sign and file with the
Securities and Exchange Commission in his or her capacity as such Director of
said corporation the Form 10-K Annual Report for the year ended December 31,
1998, required by Section 13 or 15(d) of the Securities Exchange Act of 1934 and
any and all amendments and other filings or documents related thereto, and
hereby ratifies all that said attorneys in fact or any of them may do or cause
to be done by virtue hereof.
IN WITNESS WHEREOF, we have signed these presents this 17th day of
February, 1999.
ROBERT D. GLYNN, JR. RICHARD A. CLARKE
- ------------------------------------- --------------------------------------
DAVID A. COULTER REBECCA Q. MORGAN
- ------------------------------------- --------------------------------------
C. LEE COX MARY S. METZ
- ------------------------------------- --------------------------------------
BARRY LAWSON WILLIAMS REBECCA B. MADDEN
- ------------------------------------- --------------------------------------
WILLIAM S. DAVILA
- ------------------------------------- --------------------------------------
DAVID M. LAWRENCE, M.D
- ------------------------------------- --------------------------------------
JOHN C. SAWHILL
- -------------------------------------
<PAGE>
POWER OF ATTORNEY
ROBERT D. GLYNN, JR., the undersigned, Chairman of the Board, Chief
Executive Officer, and President of PG&E Corporation, hereby constitutes and
appoints LESLIE H. EVERETT, LINDA Y.H CHENG, WONDY S. LEE, ERIC MONTIZAMBERT,
GARY P. ENCINAS, and KATHLEEN HAYES, and each of them, as his attorneys in fact
with full power of substitution to sign and file with the Securities and
Exchange Commission in his capacity as Chairman of the Board and Chief Executive
Officer (principal executive officer) of said corporation the Form 10-K Annual
Report for the year ended December 31, 1998, required by Section 13 or 15(d) of
the Securities Exchange Act of 1934 and any and all amendments and other filings
or documents related thereto, and hereby ratifies all that said attorneys in
fact or any of them may do or cause to be done by virtue hereof.
IN WITNESS WHEREOF, I have signed these presents this 17th day of
February, 1999.
/s/ Robert D. Glynn, JR
--------------------------------------------
Robert D. Glynn, Jr.
<PAGE>
POWER OF ATTORNEY
MICHAEL E. RESCOE, the undersigned, Senior Vice President and Chief
Financial Officer of PG&E Corporation, hereby constitutes and appoints LESLIE H.
EVERETT, LINDA Y.H. CHENG, WONDY S. LEE, ERIC MONTIZAMBERT, GARY P. ENCINAS, and
KATHLEEN HAYES, and each of them, as his attorneys in fact with full power of
substitution to sign and file with the Securities and Exchange Commission in his
capacity as Senior Vice President and Chief Financial Officer (principal
financial officer) of said corporation the Form 10-K Annual Report for the year
ended December 31, 1998, required by Section 13 or 15(d) of the Securities
Exchange Act of 1934 and any and all amendments and other filings or documents
related thereto, and hereby ratifies all that said attorneys in fact or any of
them may do or cause to be done by virtue hereof.
IN WITNESS WHEREOF, I have signed these presents this 17th day of
February, 1999.
/s/ Michael E. Rescoe
--------------------------------------------
Michael E. Rescoe
<PAGE>
POWER OF ATTORNEY
CHRISTOPHER P. JOHNS, the undersigned, Vice President and Controller
of PG&E Corporation, hereby constitutes and appoints LESLIE H. EVERETT, LINDA
Y.H. CHENG, WONDY S. LEE, ERIC MONTIZAMBERT, GARY P. ENCINAS, and KATHLEEN
HAYES, and each of them, as his attorneys in fact with full power of
substitution to sign and file with the Securities and Exchange Commission in his
capacity as Vice President and Controller (principal accounting officer) of said
corporation the Form 10 K Annual Report for the year ended December 31, 1998,
required by Section 13 or 15(d) of the Securities Exchange Act of 1934 and any
and all amendments and other filings or documents related thereto, and hereby
ratifies all that said attorneys in fact or any of them may do or cause to be
done by virtue hereof.
IN WITNESS WHEREOF, I have signed these presents this 17th day of
February, 1999.
/S/ Christopher P. Johns
-----------------------------------
Christopher P. Johns
<PAGE>
POWER OF ATTORNEY
Each of the undersigned Directors of Pacific Gas and Electric Company
hereby constitutes and appoints LESLIE H. EVERETT, LINDA Y.H. CHENG, WONDY S.
LEE, ERIC MONTIZAMBERT, GARY P. ENCINAS, and KATHLEEN HAYES, and each of them,
as his or her attorneys in fact with full power of substitution to sign and file
with the Securities and Exchange Commission in his or her capacity as such
Director of said corporation the Form 10-K Annual Report for the year ended
December 31, 1998, required by Section 13 or 15(d) of the Securities Exchange
Act of 1934 and any and all amendments and other filings or documents related
thereto, and hereby ratifies all that said attorneys in fact or any of them may
do or cause to be done by virtue hereof.
IN WITNESS WHEREOF, we have signed these presents this 17th day of
February, 1999.
ROBERT D. GLYNN, JR. RICHARD A. CLARKE
- ---------------------------------- ----------------------------------------
DAVID A. COULTER REBECCA Q. MORGAN
- ---------------------------------- ----------------------------------------
C. LEE COX MARY S. METZ
- ---------------------------------- ----------------------------------------
BARRY LAWSON WILLIAMS RICHARD B. MADDEN
- ---------------------------------- ----------------------------------------
WILLIAM S. DAVILA GORDON R. SMITH
- ---------------------------------- ----------------------------------------
DAVID M. LAWRENCE, MD
- ---------------------------------- ----------------------------------------
JOHN C. SAWHILL
- ---------------------------------- ----------------------------------------
<PAGE>
POWER OF ATTORNEY
GORDON R. SMITH, the undersigned, President and Chief Executive Officer of
Pacific Gas and Electric Company, hereby constitutes and appoints LESLIE H.
EVERETT, LINDA Y.H CHENG, WONDY S. LEE, ERIC MONTIZAMBERT, GARY P. ENCINAS, and
KATHLEEN HAYES, and each of them, as his attorneys in fact with full power of
substitution to sign and file with the Securities and Exchange Commission in his
capacity as President and Chief Executive Officer (principal executive officer)
of said corporation the Form 10-K Annual Report for the year ended December 31,
1998, required by Section 13 or 15(d) of the Securities Exchange Act of 1934 and
any and all amendments and other filings or documents related thereto, and
hereby ratifies all that said attorneys in fact or any of them may do or cause
to be done by virtue hereof.
IN WITNESS WHEREOF, I have signed these presents this 17th day of
February , 1999.
/s/ Gordon R. Smith
---------------------------------------
Gordon R. Smith
<PAGE>
POWER OF ATTORNEY
KENT M. HARVEY, the undersigned, Senior Vice President - Treasurer and
Chief Financial Officer of Pacific Gas and Electric Company, hereby constitutes
and appoints LESLIE H. EVERETT, LINDA Y.H. CHENG, WONDY S. LEE, ERIC
MONTIZAMBERT, GARY P. ENCINAS, and KATHLEEN RUEGER, and each of them, as his
attorneys in fact with full power of substitution to sign and file with the
Securities and Exchange Commission in his capacity as Senior Vice President -
Treasurer and Chief Financial Officer (principal financial officer) of said
corporation the Form 10-K Annual Report for the year ended December 31, 1998,
required by Section 13 or 15(d) of the Securities Exchange Act of 1934 and any
and all amendments and other filings or documents related thereto, and hereby
ratifies all that said attorneys in fact or any of them may do or cause to be
done by virtue hereof.
IN WITNESS WHEREOF, I have signed these presents this 17th day of
February, 1999.
/s/ Kent M. Harvey
---------------------------------------
Kent M. Harvey
<PAGE>
POWER OF ATTORNEY
CHRISTOPHER P. JOHNS, the undersigned, Vice President and Controller
of Pacific Gas and Electric Company, hereby constitutes and appoints LESLIE H.
EVERETT, LINDA Y.H. CHENG, WONDY S. LEE, ERIC MONTIZAMBERT, GARY P. ENCINAS, and
KATHLEEN HAYES, and each of them, as his attorneys in fact with full power of
substitution to sign and file with the Securities and Exchange Commission in his
capacity as Vice President and Controller (principal accounting officer) of said
corporation the Form 10-K Annual Report for the year ended December 31, 1998,
required by Section 13 or 15(d) of the Securities Exchange Act of 1934 and any
and all amendments and other filings or documents related thereto, and hereby
ratifies all that said attorneys in fact or any of them may do or cause to be
done by virtue hereof.
IN WITNESS WHEREOF, I have signed these presents this 17th day of
February, 1999.
/s/ Christopher P. Johns
---------------------------------------
Christopher P. Johns
WARNING: THE EDGAR SYSTEM ENCOUNTERED ERROR(S) WHILE PROCESSING THIS SCHEDULE.
<TABLE> <S> <C>
<PAGE>
<ARTICLE> UT
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM PG&E
CORPORATION AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL
STATEMENTS.
</LEGEND>
<MULTIPLIER> 1,000,000
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-START> JAN-01-1998
<PERIOD-END> DEC-31-1998
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<OTHER-PROPERTY-AND-INVEST> 0
<TOTAL-CURRENT-ASSETS> 4,955
<TOTAL-DEFERRED-CHARGES> 2,998
<OTHER-ASSETS> 7,463
<TOTAL-ASSETS> 33,234
<COMMON> 5,862
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300
480
<LONG-TERM-DEBT-NET> 6,065
<SHORT-TERM-NOTES> 1,644
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 1,357
<LONG-TERM-DEBT-CURRENT-PORT> 338
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
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<OTHER-OPERATING-EXPENSES> 17,935
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<OPERATING-INCOME-LOSS> 2,007
<OTHER-INCOME-NET> 64
<INCOME-BEFORE-INTEREST-EXPEN> 2,071
<TOTAL-INTEREST-EXPENSE> 782
<NET-INCOME> 719
0
<EARNINGS-AVAILABLE-FOR-COMM> 719
<COMMON-STOCK-DIVIDENDS> 466
<TOTAL-INTEREST-ON-BONDS> 340
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<EPS-PRIMARY> $1.88
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</TABLE>
<TABLE> <S> <C>
<PAGE>
<ARTICLE> UT
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM PACIFIC GAS
AND ELECTRIC COMPANY AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH
FINANCIAL STATEMENTS.
</LEGEND>
<MULTIPLIER> 1,000,000
<S> <C>
<PERIOD-TYPE> 12-MOS
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<PERIOD-START> JAN-01-1998
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437
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<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 567
<LONG-TERM-DEBT-CURRENT-PORT> 260
0
<CAPITAL-LEASE-OBLIGATIONS> 0
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<OTHER-OPERATING-EXPENSES> 7,048
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<TOTAL-INTEREST-EXPENSE> 621
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27
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</TABLE>
