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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, 1997
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
---------- ------------------------ ------------- --------------
<C> <S> <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
94177 (ZIP CODE)
(ZIP CODE)
(415) 973-7000
(REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE)
SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:
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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 Stock Exchange
PACIFIC GAS AND ELECTRIC COMPANY
First Preferred Stock, cumulative, American Stock Exchange and
par value $25 per share: Pacific Stock Exchange
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Redeemable: 7.04%, 6 7/8, 5% Series A, 5%, 4.80%, 4.50%, 4.36%.
Mandatorily Redeemable: 6.57%, 6.30%
Nonredeemable: 6%, 5 1/2%, 5%
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7.90% Cumulative Quarterly Income Preferred
Securities,
Series A (liquidation preference $25), issued by
PG&E
Capital I and guaranteed by Pacific Gas and
Electric American Stock Exchange and
Company Pacific Stock Exchange
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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 17, 1998:
PG&E Corporation Common Stock $11,426 million
Pacific Gas and Electric Company First Preferred Stock $463 million
COMMON STOCK OUTSTANDING AS OF FEBRUARY 17, 1998:
PG&E Corporation: 381,010,366
Pacific Gas and Electric Company: Wholly owned by PG&E Corporation
The market values of certain series of First Preferred Stock, for which
market prices as of a date within 60 days prior to the date of filing were not
available, were derived by dividing the annual dividend rate of each such
series of stock by the average yield of all of Pacific Gas and Electric
Company's Preferred Stock outstanding for which market prices were available.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the documents listed below have been incorporated by reference
into the indicated parts of this report, as specified in the responses to the
item numbers involved.
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(1) Designated portions of the combined
Annual Report to Shareholders for the year
ended Part II (Items 5, 6, 7 and 8)
December 31, 1997......................... Part IV (Item 14)
(2) Designated portions of the Joint Proxy
Statement relating to the 1998 Annual
Meetings of Shareholders.................. Part III (Items 10, 11, 12 and 13)
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TABLE OF CONTENTS
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PAGE
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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..................................................... 5
Regulation of Pacific Gas and Electric Company................... 6
State Regulation................................................. 6
Federal Regulation............................................... 6
Licenses and Permits............................................. 6
Regulation of PG&E Corporation and Other Subsidiaries............ 7
Pacific Gas and Electric Company Rate Matters.................... 8
California Ratemaking Mechanisms................................. 8
Electric Ratemaking.............................................. 9
Gas Ratemaking................................................... 11
1998 Revenues.................................................... 11
Capital Requirements and Financing Programs...................... 12
Price Risk Management Programs................................... 13
ELECTRIC UTILITY OPERATIONS...................................... 15
Electric Industry Restructuring Legislation...................... 15
Independent System Operator and Power Exchange................... 15
Voluntary Generation Asset Divestiture........................... 15
Direct Access.................................................... 16
Rate Levels and Rate Reduction Bonds............................. 17
Recovery of Transition Costs..................................... 17
Public Purpose Programs.......................................... 18
Electric Operating Statistics.................................... 20
Electric Generating and Transmission Capacity.................... 22
Diablo Canyon.................................................... 23
Diablo Canyon Operations......................................... 23
Diablo Canyon Ratemaking......................................... 24
Nuclear Fuel Supply and Disposal................................. 25
Insurance........................................................ 26
Decommissioning.................................................. 26
Other Electric Resources......................................... 27
QF Generation and Other Power-Purchase Contracts................. 27
Geothermal Generation............................................ 28
Helms Pumped Storage Plant....................................... 28
Electric Transmission and Distribution........................... 28
GAS UTILITY OPERATIONS........................................... 30
Gas Operations................................................... 30
Gas Operating Statistics......................................... 31
Natural Gas Supplies............................................. 32
Gas Regulatory Framework......................................... 32
Transportation Commitments....................................... 33
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i
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TABLE OF CONTENTS--(CONTINUED)
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Gas Reasonableness Proceedings................................. 34
1988-1990 Canadian Gas Procurement Activities.................. 34
PGT/Pacific Gas and Electric Company Pipeline Expansion........ 34
PG&E CORPORATION'S GAS TRANSMISSION OPERATIONS................. 36
PG&E CORPORATION'S INDEPENDENT POWER GENERATION OPERATIONS..... 37
PG&E CORPORATION'S ENERGY SERVICES AND COMMODITIES............. 39
ENVIRONMENTAL MATTERS.......................................... 40
Environmental Matters.......................................... 40
Environmental Protection Measures.............................. 40
Air Quality.................................................... 40
Water Quality.................................................. 41
Hazardous Waste Compliance and Remediation..................... 41
Potential Recovery of Hazardous Waste Compliance and
Remediation Costs.............................................. 43
Compressor Station Litigation.................................. 43
Electric and Magnetic Fields................................... 43
Low Emission Vehicle Programs.................................. 44
Item 2. Properties..................................................... 44
Item 3. Legal Proceedings.............................................. 44
Compressor Station Chromium Litigation......................... 45
Texas Franchise Fee Litigation................................. 46
Item 4. Submission of Matters to a Vote of Security Holders............ 49
EXECUTIVE OFFICERS OF THE REGISTRANTS.......................... 50
PART II
Market for the Registrant's Common Equity and Related
Item 5. Stockholder Matters............................................ 53
Item 6. Selected Financial Data........................................ 53
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations.......................................... 53
Item 7A. Quantitative and Qualitative Disclosures About Market Risk..... 53
Item 8. Financial Statements and Supplementary Data.................... 53
Changes in and Disagreements with Accountants on Accounting and
Item 9. Financial Disclosure........................................... 54
PART III
Item 10. Directors and Executive Officers of the Registrant............. 54
Item 11. Executive Compensation......................................... 54
Item 12. Security Ownership of Certain Beneficial Owners and Management. 54
Item 13. Certain Relationships and Related Transactions................. 54
PART IV
Exhibits, Financial Statement Schedules, and Reports on Form 8-
Item 14. K.............................................................. 54
Signatures..................................................... 59
Report of Independent Public Accountants....................... 60
Financial Statement Schedules.................................. 61
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ii
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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
Bechtel........... Bechtel Enterprises, Inc.
Betz.............. Betz Laboratories, Inc. and affiliated entities
BCAP.............. Biennial Cost Allocation Proceeding
bcf............... billion cubic feet
BRPU.............. Biennial Resource Plan Update
BTA............... best technology available
Btu............... British thermal unit
California
Superfund........ California Hazardous Substance Account Act
CARE.............. California Alternate Rates for Energy
CCAA.............. California Clean Air Act
CEC............... California Energy Commission
Central Coast
Board............ Central Coast Regional Water Quality Control Board
CERCLA............ Comprehensive Environmental Response, Compensation, and
Liability Act
CFCA.............. Core Fixed Cost Account
CIG............... customer identified gas program
Company........... Pacific Gas and Electric Company and its subsidiaries
core customers.... residential and smaller commercial gas customers
core subscription
customers........ noncore customers who choose bundled service
CPIM.............. core procurement incentive mechanism
CPUC.............. California Public Utilities Commission
CTC............... competition transition charge
Diablo Canyon..... Diablo Canyon Nuclear Power Plant
DOE............... United States Department of Energy
DSM............... Demand Side Management
Duke Energy....... Duke Energy Power Services, Inc.
ECAC.............. Energy Cost Adjustment Clause
EDRA.............. electric deferred refund account
El Paso........... El Paso Natural Gas Company
EMF............... electric and magnetic fields
Enterprises....... PG&E Enterprises
EPA............... United States Environmental Protection Agency
ERAM.............. Electric Revenue Adjustment Mechanism
FERC.............. Federal Energy Regulatory Commission
Gas Accord........ Gas Accord Settlement
Geysers........... The Geysers Power Plant
GRC............... General Rate Case
GTT............... PG&E Gas Transmission, Texas Corporation
HCP............... Habitat Conservation Plan
Helms............. Helms hydroelectric pumped storage plant
Holding Company
Act.............. Public Utility Holding Company Act of 1935
Humboldt.......... Humboldt Bay Power Plant
HWRC.............. hazardous waste remediation costs
ICIP.............. Incremental Cost Incentive Price
InterGen.......... International Generating Company, Ltd.
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ISO............... Independent System Operator
ITCBA............. Interim Transition Cost Balancing Account
ITCS.............. Interstate Transition Cost Surcharge
kV................ kilovolts
kVa............... kilovolt-amperes
kW................ kilowatts
kWh............... kilowatt-hour
LDC............... local distribution company
LEV............... low emission vehicle
Mcf............... thousand cubic feet
MMcf.............. million cubic feet
MMcf/d............ million cubic feet per day
MW................ megawatts
MWh............... megawatt-hour
NEES.............. New England Electric System
NEIL.............. Nuclear Electric Insurance Limited
NGL............... natural gas liquids
noncore
customers........ industrial and larger commercial gas customers
NOx............... oxides of nitrogen
NRC............... Nuclear Regulatory Commission
Nuclear Waste
Act.............. Nuclear Waste Policy Act of 1982
ORA............... Office of Ratepayer Advocates, formerly known as the
Division of Ratepayer Advocates
PBR............... performance-based ratemaking
PEPR.............. Pipeline Expansion Project Reasonableness case
PG&E Expansion.... the Pacific Gas and Electric Company portion of the
Pipeline Expansion
PG&E ES........... PG&E Corporation's energy services operations, PG&E Energy
Services or PG&E ES
PG&E GT........... PG&E Corporation's gas transmission operations, PG&E Gas
Transmission or PG&E GT
PG&E ET........... PG&E Corporation's energy commodities activities, PG&E
Energy Trading or PG&E ET
PGT............... Pacific Gas Transmission Company, now known as PG&E Gas
Transmission, Northwest Corporation
PGT Expansion..... the Pacific Gas Transmission Company (now known as PG&E Gas
Transmission, Northwest Corporation) portion of the
Pipeline Expansion
Pipeline
Expansion........ PGT/Pacific Gas and Electric Company Pipeline Expansion
PPPs.............. public purpose programs
PRP............... potentially responsible party
PX................ California Power Exchange
QF................ qualifying facility
RAP............... Revenue Adjustment Proceeding
RRC............... The Railroad Commission of Texas
SEC............... Securities and Exchange Commission
Teco.............. Teco Pipeline Company
TRA............... Transition Revenue Account
transition period. the period during which electric rates are frozen at 1996
levels, which extends until the earlier of March 31, 2002
or the point in time when Pacific Gas and Electric Company
has recovered its transition costs
Transwestern...... Transwestern Pipeline Company
TURN.............. The Utility Reform Network
USGen............. U.S. Generating Company
USOSC............. U.S. Operating Services Company
Vantus............ Vantus Energy Corporation
Valero............ Valero Energy Corporation
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<PAGE>
PART I
ITEM 1. BUSINESS.
GENERAL
CORPORATE STRUCTURE AND BUSINESS
PG&E Corporation is a holding company, based in San Francisco, California,
which provides energy services throughout the United States and in Australia.
Effective January 1, 1997, Pacific Gas and Electric Company and its
subsidiaries became subsidiaries of PG&E Corporation, which was incorporated
in 1995. In the holding company reorganization, Pacific Gas and Electric
Company's outstanding common stock was converted on a share-for-share basis
into PG&E Corporation common stock. Pacific Gas and Electric Company's debt
securities and preferred stock were unaffected and remain securities of
Pacific Gas and Electric Company. The consolidated financial statements of
PG&E Corporation incorporated herein include the accounts of PG&E Corporation
and its wholly owned and controlled subsidiaries (collectively, PG&E
Corporation). The consolidated financial statements of Pacific Gas and
Electric Company incorporated herein include the accounts of Pacific Gas and
Electric Company and its wholly owned and controlled subsidiaries (sometimes
referred to in this report as the "Company"). Because PG&E Corporation did not
become the holding company for Pacific Gas and Electric Company until January
1, 1997, the 1995 and 1996 consolidated financial statements represent the
accounts of Pacific Gas and Electric Company on a consolidated basis as
predecessor of PG&E Corporation.
The principal executive offices of PG&E Corporation are located at One
Market, Spear Tower, Suite 2400, San Francisco, California 94105, and the
principal executive offices of Pacific Gas and Electric Company are located at
77 Beale Street, P.O. Box 770000, San Francisco, California 94177, and their
telephone number is (415) 973-7000.
As of December 31, 1997, PG&E Corporation had $30.6 billion in assets. PG&E
Corporation generated $15.4 billion in operating revenues for 1997. As of
December 31, 1997, PG&E Corporation and its subsidiaries and affiliates had
approximately 23,500 employees.
During 1997, PG&E Corporation expanded its energy-related business
activities, which now include the gas and electric utility operations of
Pacific Gas and Electric Company; the ownership and operation of natural gas
pipelines, natural gas storage facilities, and natural gas processing plants,
primarily in the Pacific Northwest, Texas and Australia, through various
subsidiaries of PG&E Corporation (PG&E Gas Transmission or PG&E GT); the
development, construction, operation, ownership, and management of independent
power generation facilities through U.S. Generating Company and its
affiliates; the purchase and sale of energy commodities and financial
instruments to PG&E Corporation's other businesses, unaffiliated utilities,
marketers, municipalities, cooperatives, independent power producers, and
large end-use customers through PG&E Energy Trading Corporation and its
affiliates (PG&E Energy Trading or PG&E ET); and the provision to customers
nationwide with competitively priced natural gas and electricity and services
to manage and make more efficient their energy consumption through PG&E Energy
Services Corporation (PG&E Energy Services or PG&E ES).
Pacific Gas and Electric Company, incorporated in California in 1905, is an
operating public utility engaged principally in the business of providing
electric and natural gas services throughout most of Northern and Central
California. As of December 31, 1997, Pacific Gas and Electric Company had
$25.1 billion in assets. The Company generated $9.5 billion in operating
revenues for 1997. As of December 31, 1997, Pacific Gas and Electric Company
had approximately 21,000 employees.
The gas and electric utility operations of Pacific Gas and Electric Company
represent the principal component of PG&E Corporation's business, contributing
62% of PG&E Corporation's total revenues in 1997. Pacific Gas and Electric
Company's utility operations contributed $1.77 of PG&E Corporation's total
1997 earnings per share of $1.75. (Pacific Gas and Electric Company's earnings
were offset by losses at some of PG&E Corporation's other businesses: PG&E
Energy Services, PG&E Energy Trading, and U.S. Generating Company.)
1
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Pacific Gas and Electric Company's utility service territory covers 70,000
square miles with an estimated population of approximately 12 million and
includes all or portions of 48 of California's 58 counties. The area's diverse
economy includes aerospace, electronics, financial services, food processing,
petroleum refining, agriculture, and tourism.
At December 31, 1997, Pacific Gas and Electric Company served approximately
4.5 million electric customers. In 1997, Pacific Gas and Electric Company
served its electric customers with power generated by seven primarily natural
gas-fueled steam power plants with 21 units, ten combustion turbines, two
nuclear power reactor units at Diablo Canyon Nuclear Power Plant (Diablo
Canyon), 68 hydroelectric powerhouses with 109 units, the Helms hydroelectric
pumped storage plant (Helms) with three units, and a geothermal energy complex
of 14 units. (In connection with the ongoing California electric industry
restructuring, Pacific Gas and Electric Company has entered into agreements to
sell three fossil-fueled power plants and has announced plans to sell an
additional four power plants plus its geothermal facilities in 1998. See
"Electric Utility Operations--Electric Industry Restructuring Legislation"
below.) Pacific Gas and Electric Company also purchases power produced by
other generating entities that use a wide array of resources and technologies,
including hydroelectric, wind, solar, biomass, geothermal, and cogeneration.
In addition, Pacific Gas and Electric Company is interconnected with electric
power systems in 14 western states and British Columbia, Canada, for the
purposes of buying, selling, and transmitting power.
Pacific Gas and Electric Company served approximately 3.7 million gas
customers at December 31, 1997. To ensure a diverse and competitive mix of
natural gas supplies, Pacific Gas and Electric Company purchases gas from both
Canadian and United States suppliers. In 1997, about 66% of Pacific Gas and
Electric Company's gas supply came from fields in Canada, about 3% came from
fields in California, and about 31% came from fields in other states
(substantially all from the U.S. Southwest). In 1997, the CPUC approved the
Gas Accord Settlement (Gas Accord), a comprehensive multi-party settlement
agreement to restructure Pacific Gas and Electric Company's gas services and
its role in the gas market, establish gas transmission rates for the period
from March 1, 1998 through December 2002, and resolve various gas regulatory
issues.
On July 31, 1997, a wholly owned subsidiary of PG&E Corporation merged with
Valero Energy Corporation, (Valero) in Texas (now known as PG&E Gas
Transmission, Texas Corporation). As a result of the merger, PG&E Corporation
acquired Valero's natural gas and natural gas liquids pipelines, natural gas
storage facilities, natural gas processing plants, and various gas marketing
companies. Through its January 1997 acquisition of Teco Pipeline Company
(Teco) in Texas (now known as PG&E Gas Transmission, Teco, Inc.), PG&E
Corporation also acquired interests in various natural gas pipelines, natural
gas processing facilities, and an operation in Houston, Texas, involved in the
purchase and sale of energy commodities and related financial instruments.
PG&E Gas Transmission, Northwest Corporation (formerly Pacific Gas
Transmission Company or PGT) owns and operates an interstate natural gas
pipeline in the Pacific Northwest. See "PG&E Corporation's Gas Transmission
Operations" below.
Also in 1997, PG&E Corporation established PG&E Energy Services Corporation
(formerly Vantus Energy Corporation) to compete in the direct access market in
California and to provide customers nationwide with competitively priced
natural gas and electricity services to manage and make more efficient their
energy consumption. See "PG&E Corporation's Energy Services and Commodities"
below. Although the direct access market was scheduled to begin in California
on January 1, 1998, in late December 1997, the Independent System Operator
(ISO) and the Power Exchange (PX) announced that there would be a delay in the
commencement of a direct access market until certain operational and
logistical issues are resolved, and that they expected direct access to begin
by March 31, 1998. The ISO is the corporation proposed by California electric
industry restructuring legislation to operate and control the state's electric
transmission facilities and to provide comparable open access to electric
transmission service. The PX is the corporation proposed by the California
Public Utilities Commission (CPUC) to provide a competitive auction process to
establish the price of electricity. See "Electric Utility Operations--Electric
Industry Restructuring Legislation" below.
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In August 1997, PG&E Corporation announced plans to acquire, through
affiliates of U.S. Generating Company (USGen), a portfolio of electric
generating assets and power supply contracts from the New England Electric
System for approximately $1.59 billion plus $85 million for certain employee-
related costs. In September 1997, PG&E Corporation acquired full ownership of
USGen, originally formed as a joint venture with Bechtel Enterprises, Inc.
(Bechtel). PG&E Corporation also acquired full ownership of certain other
partnerships affiliated with USGen, as well as all or a portion of Bechtel's
interests in various power projects affiliated with USGen. See "PG&E
Corporation's Independent Power Generation Operations" below.
The following information includes forward-looking statements that involve a
number of risks, uncertainties, and assumptions. Words such as "estimates,"
"expects," "intends," "anticipates," "plans," and similar expressions identify
those statements which are forward-looking. A number of factors that could
cause actual results to differ materially from those indicated in the forward-
looking statements include, but are not limited to, the ongoing restructuring
of the electric and gas industries and the outcome of regulatory proceedings
related to that restructuring, and other factors which are described in more
detail below. The ultimate impacts of both increased competition and the
changing regulatory environment on future results are uncertain, but are
expected to fundamentally change how PG&E Corporation's utility operations are
conducted. The outcome of these changes and other matters discussed below may
cause future results to differ materially from historic results, or from
results or outcomes currently expected or sought by PG&E Corporation.
COMPETITION AND THE CHANGING REGULATORY ENVIRONMENT
The electric and gas industries are undergoing significant change. Under
traditional regulation, utilities were provided the opportunity to earn a fair
return on their invested capital in exchange for a commitment to serve all
customers within a designated service territory. The objective of this
regulatory policy was to provide universal access to safe and reliable utility
services. Regulation was designed in part to take the place of competition and
ensure that these services were provided at fair prices.
Today, competitive pressures and emerging market forces are exerting an
increasing influence over the structure of the gas and electric industries.
Other companies have challenged the utilities' exclusive relationship with
their customers and have sought to replace certain utility functions with
their own. Customers, too, have asked for choice in their energy provider.
These pressures have caused a move from the existing regulatory framework to a
framework under which competition is allowed in certain segments of the gas
and electric industries.
For several years, Pacific Gas and Electric Company has been working with
its regulators to achieve an orderly transition to competition and to ensure
that the Company has an opportunity to recover investments made under
traditional regulatory policies. Beginning in 1998, a significant portion of
Pacific Gas and Electric Company's business will be transformed from the
current utility monopoly to a competitive operation. During the transition
period, the return on Diablo Canyon and certain other generation assets will
be significantly lower than historical levels. See "Electric Utility
Operations--Diablo Canyon--Diablo Canyon Ratemaking" below. These changes will
affect PG&E Corporation's financial results and may result in greater earnings
volatility.
ELECTRIC INDUSTRY
In 1995, the CPUC issued a decision that provides a plan to restructure
California's electric industry. The decision acknowledges that much of
utilities' current costs and commitments result from past CPUC decisions and
that, in a competitive generation market, utilities would not recover some of
these costs through market-based revenues. To assure the continued financial
integrity of California utilities, the CPUC authorized recovery of these
above-market costs, called transition costs, through a nonbypassable charge,
called the competition transition charge or CTC, to be collected over a period
of years.
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In 1996, legislation adressing electric industry restructuring, Assembly Bill
1890 (AB 1890), was signed into law in California. AB 1890 adopts the basic
tenets of the CPUC's restructuring decision and establishes the operating
framework for a competitive electric generation market. Key features of AB
1890 include:
--mandatory unbundling of transmission, distribution, and generation
services;
--formation of the PX to provide a competitive auction process to establish
the price of electricity in California;
--establishment of the ISO to ensure system reliability and provide
electric generators and energy service providers with open and comparable
access to transmission services;
--an electric rate freeze at 1996 levels until the earlier of March 31,
2002, or when the particular utility has recovered its generation-related
transition costs (the transition period);
--a 10% rate reduction on January 1, 1998, for residential and small
commercial customers, financed through "rate reduction bonds;"
--nonbypassable charges (the competition transition charge or CTC) to
provide the opportunity for utilities to recover their transition costs
and accelerated recovery of transition costs associated with utility-
owned generation facilities;
--direct access to competitive generation resources for all retail electric
customers to start no later than January 1, 1998;
--market valuation for utility-owned fossil generation assets by 2001,
followed by an end to cost-of-service ratemaking for most plants; and
--continued support for renewable generation resources, conservation, and
other public purpose programs.
Under AB 1890, Pacific Gas and Electric Company and other utilities will
continue to own transmission and distribution facilities and must continue to
offer bundled electric service to customers who wish to continue receiving it.
Although ownership of transmission facilities will be retained, utilities will
relinquish control of the facilities to the ISO.
As required by AB 1890, electric rates were frozen on January 1, 1997 at
1996 levels, and on January 1, 1998, rates for residential and small
commercial customers were reduced by 10% and will be held at the reduced
level. The rate freeze will continue until the end of the transition period.
During 1997, the CPUC issued many decisions to establish the ratemaking and
accounting mechanisms necessary to implement AB 1890. Many of the key features
of AB 1890 were implemented by January 1, 1998, such as the rate freeze, the
10% rate reduction for residential and small commercial customers, formation
of the ISO and PX, and commencement of the market valuation process. However,
direct access for all retail electric customers has been delayed. In December
1997, the ISO and the PX announced that they were unable to commence
operations on January 1, 1998, and that they expected to be operational by
March 31, 1998, at which time direct access would begin. See "Electric Utility
Operations--Electric Industry Restructuring Legislation" below.
At the federal level, the ISO is regulated by the Federal Energy Regulatory
Commission (FERC). In October 1997, the FERC granted conditional authority for
the California ISO to commence operations and for the California PX to charge
market-based rates for electricity. See "Electric Utility Operations--Electric
Transmission" below.
Additional information concerning electric industry restructuring, the
expected operating framework for a competitive generation market, and the
financial impact of these changes on PG&E Corporation is provided in
"Management's Discussion and Analysis of Consolidated Results of Operations
and Financial Condition" in the 1997 Annual Report to Shareholders, beginning
on page 20, and in Note 2 of the "Notes to Consolidated Financial Statements"
beginning on page 43 of the 1997 Annual Report to Shareholders.
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GAS INDUSTRY
Restructuring of the natural gas industry on both the national and state
levels has given customers greater options in meeting their gas supply needs.
Currently, Pacific Gas and Electric Company's customers may buy gas directly
from competing suppliers and purchase transmission- and distribution-only
services from Pacific Gas and Electric Company. Pacific Gas and Electric
Company's transmission and distribution services have historically been
"bundled," or sold together at a combined rate, within California. Most of
Pacific Gas and Electric Company's industrial and larger commercial (noncore)
customers now purchase their gas from marketers and brokers. Substantially all
residential and smaller commercial (core) customers buy gas as well as
transmission and distribution services from Pacific Gas and Electric Company
as a bundled service. Customer rates for gas are updated on a monthly basis in
order to reflect changes in Pacific Gas and Electric Company's gas procurement
costs.
In 1995 and 1996, Pacific Gas and Electric Company actively pursued changes
in the California gas industry in an effort to promote competition and
increase options for all customers, as well as to position the Company for the
competitive marketplace. In 1996, Pacific Gas and Electric Company submitted
to the CPUC the Gas Accord, a multi-party settlement agreement which resulted
from an extensive negotiation process begun in 1995 among a broad coalition of
customer groups and industry participants. On August 1, 1997, the CPUC
unanimously approved the Gas Accord.
The Gas Accord separates, or "unbundles," Pacific Gas and Electric Company's
gas transmission services from its distribution services and changes the terms
of service and rate structure for gas transportation. Unbundling gives noncore
customers the opportunity to select from a menu of services offered by Pacific
Gas and Electric Company and enables them to pay only for the services they
use. Unbundling also makes access to the transmission system possible for all
gas marketers and shippers, as well as noncore end-users. As a result, the
transmission system is now more accessible to a greater number of customers.
The Gas Accord increases opportunities for Pacific Gas and Electric
Company's core customers to purchase gas from competing suppliers and,
therefore, will reduce the Company's role in procuring gas for such customers.
However, Pacific Gas and Electric Company will continue to procure gas as a
regulated utility supplier for those customers who do not obtain gas supplies
from an alternative provider.
Under the Gas Accord, the CPUC's traditional after-the-fact reasonableness
review of Pacific Gas and Electric Company's core gas procurement costs for
the period 1994 to 2002 are replaced by a core procurement incentive mechanism
(CPIM), a form of incentive regulation. Under the CPIM, Pacific Gas and
Electric Company is able to recover its gas commodity and interstate
transportation costs and receives benefits or incurs penalties depending on
whether its actual core procurement costs are within, below, or above a
"tolerance band" constructed around market benchmarks. Actual core procurement
costs measured for the period June 1, 1994, through December 31, 1997, have
generally been within the CPIM "tolerance band."
The Gas Accord establishes gas transmission and storage rates for the period
from March 1, 1998, through December 2002. During the Gas Accord period,
Pacific Gas and Electric Company is at risk for revenue fluctuations resulting
from variances in demand for noncore gas transmission throughput. Rates for
distribution service continue to be set by the CPUC and are designed to
provide the Company an opportunity to recover its costs of service and include
a return on investment.
In January 1998, the CPUC opened a rule-making proceeding to expand market-
oriented policies in the natural gas industry, including the further
unbundling of services to promote competition, streamlining regulation for
noncompetitive services, mitigating the potential for anti-competitive
behavior, and establishing appropriate consumer protections. The CPUC will be
studying various new alternative market structures for the California natural
gas industry with the goal of encouraging competition and customer choice,
while maintaining a high standard of consumer protection.
5
<PAGE>
Additional information concerning gas industry restructuring, and the
financial impact of these changes on PG&E Corporation, is provided in
"Management's Discussion and Analysis of Consolidated Results of Operations
and Financial Condition" in the 1997 Annual Report to Shareholders, beginning
on page 24, and in Note 3 of the "Notes to Consolidated Financial Statements"
beginning on page 46 of the 1997 Annual Report to Shareholders.
REGULATION OF PACIFIC GAS AND ELECTRIC COMPANY
STATE REGULATION
The CPUC consists of five members appointed by the Governor and confirmed by
the State Senate for six-year terms. The CPUC regulates Pacific Gas and
Electric Company's rates and conditions of service, sales of securities,
dispositions of utility property, rate of return, rates of depreciation,
uniform systems of accounts, long-term resource procurement, and transactions
between Pacific Gas and Electric Company and its subsidiaries and affiliates.
The CPUC also conducts various reviews of utility performance and conducts
investigations into various matters, such as deregulation, competition, and
the environment, to determine its future policies.
The California Energy Commission (CEC) has the responsibility to make
electric-demand forecasts for the state and for specific service territories.
Based upon these forecasts, the CEC determines the need for additional energy
sources and for conservation programs. The CEC sponsors alternative-energy
research and development projects, promotes energy conservation programs, and
maintains a state-wide plan of action in case of energy shortages. In
addition, the CEC certifies power-plant sites and related facilities within
California. Under electric industry restructuring legislation, the CEC also
administers funding for public purpose research and development, and renewable
technologies programs. The funding will be collected from ratepayers through a
nonbypassable public benefits charge. See "Electric Utility Operations--
Electric Industry Restructuring Legislation--Public Purpose Programs" below.
FEDERAL REGULATION
The FERC regulates electric transmission rates and access, compliance with
the uniform systems of accounts, and electric contracts involving sales of
electricity for resale. After the ISO and PX commence operations, the FERC
will have jurisdiction over Pacific Gas and Electric Company's electric
transmission revenue requirements and rates, which previously were included in
CPUC-authorized bundled rates. The FERC also regulates the interstate
transportation of natural gas. Further, most of Pacific Gas and Electric
Company's hydroelectric facilities are subject to licenses issued by the FERC.
The Nuclear Regulatory Commission (NRC) oversees the licensing,
construction, operation, and decommissioning of nuclear facilities, including
Diablo Canyon. NRC regulations require extensive monitoring and review of the
safety, radiological, and environmental aspects of these facilities.
LICENSES AND PERMITS
Pacific Gas and Electric Company obtains a number of permits,
authorizations, and licenses in connection with the construction and operation
of its generating plants and gas compressor station facilities. Discharge
permits, various Air Pollution Control District permits, FERC hydroelectric
facility licenses, and NRC licenses are the most significant examples. Some
licenses and permits may be revoked or modified by the granting agency if
facts develop or events occur that differ significantly from the facts and
projections assumed in granting the approval. Furthermore, discharge permits
and other approvals and licenses are granted for a term less than the expected
life of the associated facility. Licenses and permits may require periodic
renewal, which may result in additional requirements imposed by the granting
agency.
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REGULATION OF PG&E CORPORATION AND OTHER SUBSIDIARIES
PG&E Corporation and its subsidiaries are exempt from all provisions, except
Section 9(a)(2), of the Public Utility Holding Company Act of 1935 (Holding
Company Act) on the basis that PG&E Corporation and Pacific Gas and Electric
Company are incorporated in the same state and their business is predominantly
intrastate in character and carried on substantially in the state of
incorporation. At present, PG&E Corporation has no expectation of becoming a
registered holding company under the Holding Company Act.
PG&E Corporation is not a public utility under the laws of California and is
not subject to regulation as such by the CPUC. However, the CPUC approval
authorizing Pacific Gas and Electric Company to form a holding company was
granted subject to various conditions related to finance, human resources,
records and bookkeeping, and the transfer of customer information. The
financial conditions provide that Pacific Gas and Electric Company is
precluded from guaranteeing any obligations of PG&E Corporation without prior
written consent from the CPUC, Pacific Gas and Electric Company's dividend
policy shall continue to be established by Pacific Gas and Electric Company's
Board of Directors as though Pacific Gas and Electric Company were a
comparable stand-alone utility company, and the capital requirements of
Pacific Gas and Electric Company, as determined to be necessary to meet
Pacific Gas and Electric Company's service obligations, shall be given first
priority by the Boards of Directors of PG&E Corporation and Pacific Gas and
Electric Company. The conditions also provide that Pacific Gas and Electric
Company shall maintain on average its CPUC-authorized utility capital
structure, although it shall have an opportunity to request a waiver of this
condition in the event an adverse financial event reduces the utility's equity
ratio by 1% or more.
A further condition of the CPUC's approval of the holding company formation
was that an audit of affiliate transactions from 1994 to 1996 be conducted and
supervised by the CPUC's Office of Ratepayer Advocates (ORA). The audit
report, completed in November 1997, was critical of Pacific Gas and Electric
Company's affiliate transaction internal controls and compliance. The report
contained numerous recommendations for additional conditions to be imposed on
the holding company. Pacific Gas and Electric Company will be responding to
the audit report, and the CPUC will hold hearings to determine if the
additional recommended conditions should be imposed on the holding company. A
final CPUC decision is expected in early 1999.
On December 16, 1997, the CPUC issued a decision that adopted rules
governing transactions between California's natural gas local distribution and
electric utility companies and their non-regulated affiliates. This decision
permits non-regulated affiliates of regulated utilities (such as PG&E Energy
Services Corporation, the non-regulated energy marketing subsidiary of PG&E
Corporation) to compete in the affiliated utility's service territory. The
decision permits non-regulated affiliates to use the same name and logo of
their affiliated utility, provided that in California the affiliate includes
certain designated disclaimer language which emphasizes the separateness of
the entities and that the affiliate is not regulated by the CPUC.
The decision also adopts complex and detailed rules requiring the separation
of regulated utilities and their non-regulated affiliates, through the
maintenance of separate books and records, physical separation of facilities,
and the separation of certain functions, such as energy-related purchases and
sales, and marketing, among others. The decision also contains rules regarding
disclosure and use of information among the affiliates and prohibits the
utility from engaging in certain practices which would discriminate against
energy service providers which compete with the utility's non-regulated
affiliates. As required by the decision, Pacific Gas and Electric Company
filed a comprehensive plan to comply with the affiliate transaction rules on
December 31, 1997.
In addition to Pacific Gas and Electric Company, certain of PG&E
Corporation's other subsidiaries which conduct interstate gas transmission and
electric wholesale power marketing operations are subject to FERC
jurisdiction. The FERC also has authority to regulate rates for natural gas
transportation in interstate commerce.
In addition, the power generation projects that USGen and its affiliates
develop, manage or own, are subject to differing types of federal regulation
depending on the regulatory status of the particular project. Some of these
projects are exempt wholesale generators (EWG) under the National Energy
Policy Act of 1992, which status exempts the project from the Public Utility
Holding Company Act of 1935. EWG status is granted by FERC upon application by
the project. Some projects have received authority from FERC to charge market-
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<PAGE>
based rates for the power they sell, rather than traditional cost-based rates.
Many of USGen's affiliated projects are qualifying facilities (QF) under the
Public Utility Regulatory Policies Act of 1978. QF status exempts the project
from regulation under various federal and state laws concerning the electric
industry. USGen's projects are also subject to various federal, state, and
local regulations concerning siting and environmental matters.
The Railroad Commission of Texas (RRC) regulates gas utilities including
those owned by PG&E Corporation through PG&E Gas Transmission, Texas
Corporation, PG&E Gas Transmission Teco, Inc., and other affiliates operating
in Texas. The RRC gas proration rules govern the wellhead production and
purchase of gas. Intrastate pipelines can provide intrastate gas
transportation at negotiated rates which are presumed just and reasonable. If
the criteria for negotiated rates cannot be met, the RRC may assess a cost-of-
service-based rate. The RRC may also regulate certain sales of gas. Currently,
the price of natural gas sold under a majority of PG&E Gas Transmission, Texas
Corporation's gas sales contracts is not regulated by the RRC. All
transportation and gathering of gas is subject to the RRC Code of Conduct
which prohibits undue discrimination among similarly situated shippers.
Further, all transportation of gas, processing of gas, and transportation of
natural gas liquids are subject to safety regulations enforced by the RRC and
the Texas Natural Resource Conservation Commission.
Other regulatory matters are described throughout this report.
PACIFIC GAS AND ELECTRIC COMPANY RATE MATTERS
CALIFORNIA RATEMAKING MECHANISMS
The CPUC authorizes an amount, known as "base revenues," to be collected
from ratepayers to recover Pacific Gas and Electric Company's basic business
and operational costs for its gas and electric operations. Base revenues,
which include non-fuel-related operating and maintenance costs, depreciation,
taxes, and a return on invested capital, are currently authorized by the CPUC
in general rate case (GRC) proceedings before the CPUC. Pacific Gas and
Electric Company's next scheduled GRC will establish base revenues effective
January 1, 1999.
During the GRC, which occurs every three years, the CPUC examines Pacific
Gas and Electric Company's costs and operations to determine the amount of
base revenue requirement Pacific Gas and Electric Company is authorized to
collect from customers through base revenues. The revenue requirement is
forecasted on the basis of a specified test year. (The return component of
Pacific Gas and Electric Company's revenue requirement is computed using the
overall cost of capital authorized in other proceedings.) Following the
revenue requirement phase of a GRC, the CPUC conducts a rate design phase,
which allocates revenue requirements and establishes rate levels for the
different classes of customers.
On December 12, 1997, Pacific Gas and Electric Company filed its Test Year
1999 GRC application with the CPUC, requesting increases in electric and gas
base revenues of $693 million and $501 million, respectively, over base
revenues authorized in 1997. The requested increase in base revenues reflects
increasing levels of electric and gas demand as well as customer growth in the
service territory, the costs of continued and enhanced maintenance activities,
and increased capital expenditures. If granted by the CPUC, the requested
increase would be effective January 1, 1999.
The requested increase of $693 million in electric base revenues as compared
to 1997 will not increase customer electric rates because these rates will
continue to be frozen. Under the frozen electric rates, the portion of total
actual revenue which exceeds authorized base revenues and certain other
authorized revenue requirements is available to recover transition costs.
Therefore, increases in base revenues would reduce the amount of revenue
available to recover transition costs.
The GRC electric revenue request includes proposed funding for distribution
services, including system reliability and safety projects, increased
distribution capacity (poles, wires, substations, etc.), equipment inspection
8
<PAGE>
and maintenance, a continuation of tree-trimming programs, and enhanced
customer service and information technology systems. Since the FERC will
authorize the rates to be collected from customers for electric transmission
services once direct access begins, the GRC application does not seek approval
of base revenues to recover the cost of transmission services. The requested
increase in electric base revenues is in addition to increases for system
safety and reliability provided by AB 1890, as discussed in "1998 Revenues"
below.
Gas customers would experience an increase in gas distribution rates if the
CPUC approves the requested gas base revenue increase. The GRC gas base
revenue request includes proposed funding for distribution system safety and
reliability improvements, increased depreciation costs of the gas pipeline
system, expanded customer service, and expanded customer and other information
systems. The requested increase in gas base revenues will not result in an
increase in customer gas transmission and storage rates, since the Gas Accord
has set gas transmission and storage rates for the period from implementation
of the Gas Accord through December 2002.
ELECTRIC RATEMAKING
In 1996, the CPUC issued a "roadmap" decision outlining the necessary steps
to accomplish electric industry restructuring. During 1997, the CPUC issued
many decisions to implement AB 1890 and the new market structure beginning in
1998, including decisions related to unbundling of rates, transition costs,
performance based ratemaking (PBR), and other activities that affect rates and
revenue requirements.
In its roadmap decision, the CPUC established a separate annual proceeding
to consider ratemaking issues related to each electric utility's revenues,
which will consolidate all pending revenue changes and track utility revenues
at present rate levels for the purpose of comparison with authorized amounts.
Beginning in 1998, this annual Revenue Adjustment Proceeding (RAP) will
review, track, and compare each electric utility's authorized revenue
requirements with the actual recorded revenues, and will make any necessary
adjustments or updates due to authorized revenues for alternative ratemaking
mechanisms, various power purchase contracts, public purpose programs, nuclear
facilities, nuclear decommissioning, transition costs, and other proceedings.
Pacific Gas and Electric Company has filed numerous regulatory applications
and proposals that detail its transition cost recovery plan during the
transition period. Pacific Gas and Electric Company's recovery plan includes
(1) separating or unbundling of its previously approved cost-of-service
revenue requirement for its electric operations into distribution,
transmission, public purpose programs (PPPs), and generation, (2) determining
revenues available to recover transition costs, and (3) development of a
ratemaking mechanism to track and match revenues and cost recovery during the
transition period.
In August 1997, the CPUC adopted Pacific Gas and Electric Company's proposed
unbundling of its 1998 authorized electric revenue requirements with some
exceptions. The decision enables Pacific Gas and Electric Company to separate
revenues provided by frozen rates into transmission, distribution, PPPs, and
generation based upon their respective costs of service. The generation
category includes energy costs, generation operating costs, nuclear
decommissioning costs, and transition costs. When direct access begins, bills
for all customers will describe what portion of the bill is attributable to
transmission, distribution, PPPs, energy, and transition costs and other
nonbypassable charges.
Under the restructuring legislation, most transition costs must be recovered
by March 31, 2002. The CPUC believes that the shorter amortization period
reduces risks associated with recovery of generation facilities, including
Diablo Canyon. As a result, in November 1997 (but retroactive to July 28,
1997), the CPUC reduced the authorized rate of return on common equity for
Pacific Gas and Electric Company's non-nuclear electric generation-related
assets including hydroelectric and geothermal facilities, to 90% of the
Company's embedded cost of debt, for a reduced rate of return on common equity
equal to 6.77%, as compared to the previously authorized 1997 rate of return
on common equity of 11.6%. Effective January 1, 1997, the rate of return on
common equity on Diablo Canyon was reduced to 90% of Pacific Gas and Electric
Company's embedded cost of long-term debt, for a return on common equity of
6.77%. See "Electric Utility Operations--Diablo Canyon--Diablo Canyon
Ratemaking" below. The reduced rate of return for the Company's non-nuclear
electric generation-related assets and for Diablo Canyon will be in effect for
the duration of the transition period.
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Before 1998, the Electric Revenue Adjustment Mechanism (ERAM) allowed rate
adjustments to offset the effect on base revenues of differences between
actual electric sales volumes and the forecasted volumes used to set electric
rates. The ERAM eliminated the impact on earnings of sales fluctuations,
including those resulting from conservation and weather conditions. Base
revenue differences resulting from the disparity between actual and forecasted
electric sales accumulated in a balancing account, with interest. In
connection with electric industry restructuring, the CPUC eliminated the ERAM
effective January 1, 1998. Until direct access begins, ERAM-related revenues
will be recorded in a separate memorandum account established in connection
with the delay of direct access.
Before 1998, most of Pacific Gas and Electric Company's fuel, purchased-
power, and energy-related costs of providing electric service, as well as
revenues attributable to Diablo Canyon generation, were recovered through a
balancing account mechanism called the Energy Cost Adjustment Clause (ECAC).
Under the ECAC balancing account procedure, actual costs were compared with
revenues designated for recovery of such costs, and the difference was
recorded as either an undercollection or overcollection. In prior years, rates
would be adjusted such that the amount of overcollections would be returned to
ratepayers through lower rates and undercollections would be recovered through
higher rates. However, as part of the electric industry restructuring, the
CPUC eliminated the ECAC balancing account effective January 1, 1998.
In December 1996, the CPUC issued a decision establishing an electric
deferred refund account (EDRA). The CPUC ordered Pacific Gas and Electric
Company to place into the EDRA credits for CPUC-ordered electric
disallowances, the utility electric generation share of CPUC-ordered gas
disallowances, amounts resulting from reasonableness disputes, and fuel-
related cost refunds made to Pacific Gas and Electric Company based on
regulatory agency decisions, plus interest charges. The CPUC ordered Pacific
Gas and Electric Company to file advice letters by January 31 of each year,
setting forth its annual refund plans for directly refunding to electric
customers the amounts accumulated in the EDRA. The CPUC also ordered Pacific
Gas and Electric Company to include initially in the EDRA any such credits
already recorded in ECAC and ERAM but not yet amortized in rates. The effect
of this was to reduce the amount available to offset Pacific Gas and Electric
Company's transition costs by approximately $75 million. In February 1998,
Pacific Gas and Electric Company refunded approximately $61 million of EDRA
funds to customers.
The ISO will designate certain electric generation facilities as necessary
to remain available and operational to maintain the reliability of the
electric transmission system. These facilities are called "must-run"
facilities. In general, sunk costs and on-going operating costs of must-run
facilities are recoverable through different types of FERC-authorized
contracts between must-run facilities and the ISO and, in some cases, also
through PX revenues. For an initial three-month period, all must-run
facilities will be under the same type of contract. Thereafter, the type of
contract for a particular must-run facility may change based upon the ISO's
evaluation of facility operating factors and system reliability needs. Subject
to CPUC approval, the type of contract and generation (i.e., fossil,
hydroelectric, or geothermal) will determine whether (1) all of the facility's
sunk costs and ongoing operating costs are eligible for transition cost
recovery, (2) the portion of the facility's sunk costs and ongoing operating
costs, which are not recovered through ISO or PX revenues, are eligible for
transition cost recovery, (3) differences between authorized and actual
revenues for the facility will be included in the transition cost recovery
mechanism, and (4) the facility may participate in the PX.
In December 1997, the CPUC adopted a cost-of-service based ratemaking
mechanism for determining Pacific Gas and Electric Company's revenue
requirement for its hydroelectric and geothermal generation facilities. Under
this mechanism, the revenue requirements for these facilities (including the
Helms pumped storage facility) will be calculated as the sum of the capital-
related revenue requirement (based on recorded capital costs), the expense
revenue requirement (based on the current General Rate Case adopted expenses),
and actual fuel expenses. A reduced rate of return on common equity of 6.77%
will apply to these facilities. This alternative revenue requirement mechanism
will be in place through 2001, unless the CPUC determines otherwise.
Additional information concerning Pacific Gas and Electric Company's
transition cost recovery plan, and the financial impact of electric industry
restructuring is provided in "Management's Discussion and Analysis of
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Consolidated Results of Operations and Financial Condition" in the 1997 Annual
Report to Shareholders, beginning on page 20, and in Note 2 of the "Notes to
Consolidated Financial Statements" beginning on page 43 of the 1997 Annual
Report to Shareholders.
GAS RATEMAKING
As noted above (see "Competition and the Changing Regulatory Environment--
Gas Industry"), the CPUC approved the Gas Accord in 1997. Additional
information concerning the potential financial impact of the Gas Accord is
provided in "Management's Discussion and Analysis of Consolidated Results of
Operations and Financial Condition" in the 1997 Annual Report to Shareholders,
beginning on page 24, and in Note 3 of the "Notes to Consolidated Financial
Statements" beginning on page 46 of the 1997 Annual Report to Shareholders.
As part of the Gas Accord, the CPUC's traditional reasonableness reviews of
Pacific Gas and Electric Company's core gas costs have been be replaced with a
CPIM (which is also discussed above in "Competition and the Changing
Regulatory Environment-Gas Industry") for the period June 1, 1994, through
2002.
The Biennial Cost Allocation Proceeding (BCAP) remains the proceeding in
which distribution costs and balancing account balances are allocated to
customers. The BCAP normally occurs every two years and is updated in the
interim year for purposes of amortizing any accumulation in the balancing
accounts. Balancing accounts for natural gas costs accumulate differences
between the actual recovery of gas costs and the revenues designed for
recovery of such costs. Balancing accounts for sales volumes accumulate
differences between authorized and actual base revenues.
In 1997, the CPUC also authorized Pacific Gas and Electric Company to set
its natural gas rates for core customers each month rather than annually.
Because Pacific Gas and Electric Company's gas costs are passed through to
customers, this change will better align customer prices with actual gas
costs.
1998 REVENUES
Under frozen rates, any change in Pacific Gas and Electric Company's
electric revenue requirements resulting from the items discussed below will
not change electric customer rates. Decreases in electric revenue requirements
will increase revenue from frozen rates available for collection from
customers as the competition transition charge (CTC) for recovery of
transition costs. Conversely, increases in electric revenue requirements will
decrease revenue from frozen rates available for collection from customers as
CTC for recovery of transition costs.
AB 1890-Electric Base Revenue Increase. AB 1890 provides for an increase in
Pacific Gas and Electric Company's electric base revenues for 1997 and 1998,
for enhancement of transmission and distribution system safety and
reliability. In January 1998, the CPUC authorized a 1998 base revenue increase
of $86 million in addition to the 1997 authorized base revenue increase of
$164 million.
Recovery of Transition Costs. In June 1997, the CPUC issued a decision
adopting CTC ratemaking and accounting mechanisms to enable the utilities to
measure their transition costs and track the recovery of transition costs.
Revenues collected under frozen electric rates will be allocated to
distribution, transmission, and generation services and PPPs based upon their
respective cost-of-service, and to nuclear decommissioning, rate reduction
bond debt service (for residential and small commercial customers), and
transition cost recovery at levels authorized by the CPUC.
Elimination of ECAC and ERAM. Effective January 1, 1998, the ECAC and ERAM
balancing accounts were eliminated and the December 31, 1997, balances in
these accounts were transferred to the Interim Transition Cost Balancing
Account (ITCBA). The ECAC was undercollected by $468 million, and the ERAM was
overcollected by $309 million. On January 1, 1998, the ITCBA balance of $160
million undercollection was transferred to the Transition Cost Balancing
Account (TCBA). Until direct access begins, fuel and fuel-related costs which
would otherwise have been included in an ECAC adjustment will be recorded in a
memorandum account to be later transferred to the ITCBA. Costs recorded in the
ITCBA are subject to a subsequent
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reasonableness review, in which the CPUC determines whether those costs were
reasonably incurred. Costs found to be unreasonable may be disallowed, or
deducted, from the amount to be recovered in rates. When direct access begins,
costs will be recovered from the market price, the TCBA, the Transition
Revenue Account (TRA), or any other cost recovery mechanism approved by the
CPUC.
Cost of Capital. The CPUC's decision in the 1998 Cost of Capital proceeding
authorized a utility return on common equity of 11.20%, a decrease from the
1997 level of 11.60%. The decision authorizes a utility capital structure for
Pacific Gas and Electric Company of 48.00% common equity, 5.80% preferred
stock, and 46.20% long-term debt. The combined authorized costs of debt,
preferred stock, and the 11.20% return on common equity result in an overall
return on utility rate base of 9.17%, a decrease from the 9.45% authorized for
1997. Since (i) the CPUC separately reduced the rate of return on Pacific Gas
and Electric Company generation-related
assets including Diablo Canyon, (ii) the FERC will authorize the rate of
return for electric transmission assets at a later date, and (iii)
transmission and storage rates have been set in the Gas Accord, the reduced
rate of return of 11.20% adopted in the 1998 Cost of Capital Proceeding only
applies to Pacific Gas and Electric Company's electric and gas distribution
assets. The authorized cost of capital will decrease 1998 authorized electric
and gas revenue by $25 million and $9 million, respectively. Pacific Gas and
Electric Company has requested a rehearing of this decision.
BCAP. In 1997, Pacific Gas and Electric Company filed its 1998 BCAP
application. The Company is requesting an overall annual revenue requirement
for the two-year BCAP period of approximately $1.5 billion of which
approximately $107 million will be allocated for the collection of balancing
accounts. The current annual revenue requirement is approximately $1.8 billion
of which approximately $303 million has been allocated for the collection of
balancing accounts. No rate changes resulting from the BCAP are expected to be
implemented before August 1, 1998.
AEAP. The 1997 Annual Earnings Assessment Proceeding (AEAP), which
determines shareholder incentives earned for Pacific Gas and Electric
Company's demand side management (DSM) programs, was submitted in December
1997. All of the parties to the proceeding agree that Pacific Gas and Electric
Company is entitled to an incentive payment of approximately $32 million for
Pacific Gas and Electric Company's 1996 DSM programs, to be collected in
installments over a 10-year period. After consolidating the adjusted incentive
payment installments from prior years, the net revenue change in 1998 from DSM
shareholder incentives should be an electric decrease of approximately $4
million and a gas decrease of approximately $2 million. A CPUC decision
adopting the shareholder incentives is expected during the first quarter of
1998.
Electric Transmission Revenues. Prior to 1998, most electric transmission
revenues were authorized by the CPUC as part of the GRC. In 1998, electric
transmission revenues are expected to be authorized by the FERC. In 1997,
Pacific Gas and Electric Company filed an application with the FERC requesting
electric transmission revenues of $305 million. This requested revenue
requirement is comparable to electric transmission revenues in CPUC-authorized
1997 electric rates.
CAPITAL REQUIREMENTS AND FINANCING PROGRAMS
PG&E Corporation and Pacific Gas and Electric Company continue to require
capital for improvements to facilities to enhance their efficiency and
reliability, to extend their useful lives, and to comply with environmental
laws and regulations. PG&E Corporation's expenditures for these purposes,
including the allowance for funds used during construction (AFUDC), were
approximately $1,829 million for 1997. New investments totaled $41 million in
1997.
The following table sets forth PG&E Corporation's estimated total capital
requirements, consisting of capital expenditures for Pacific Gas and Electric
Company's utility functions, including Diablo Canyon, as well as capital
requirements for PG&E Corporation's other lines of business, and amounts for
maturing debt and sinking funds for the years 1998 through 2000. These are
forward-looking statements which involve a number of assumptions and
uncertainties. Actual amounts may differ materially from the estimated amounts
shown below.
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PG&E CORPORATION CAPITAL REQUIREMENTS
(IN MILLIONS)
<TABLE>
<CAPTION>
1998 1999 2000
------ ------ ------
<S> <C> <C> <C>
Utility Capital Requirements (1).......................... $1,835 $1,739 $1,617
Other Capital Requirements (2)............................ 2,091 246 192
Maturing Debt and Sinking Funds........................... 784 559 740
------ ------ ------
Total Capital Requirements............................ $4,710 $2,544 $2,549
====== ====== ======
</TABLE>
- --------
(1) Utility expenditures including Pacific Gas and Electric Company's electric
and gas operations, are shown net of reimbursed capital, and include
AFUDC.
(2) Other expenditures include those of PG&E GT, PG&E ES, PG&E ET, and USGen.
In August 1997, PG&E Corporation announced plans to acquire, through
USGen, a portfolio of electric generating assets and power supply
contracts from the New England Electric System for $1.59 billion.
Including fuel and other inventories and transaction costs, financing
requirements are expected to total approximately $1.75 billion, which
amount is included in the table above.
Most of the capital expenditures for Pacific Gas and Electric Company for
1998 through 2000 are associated with short lead time, capital expenditure
projects aimed at the replacement and enhancement of existing facilities, and
compliance with environmental laws and regulations. Also included are
expenditures to improve the safety and reliability of Pacific Gas and Electric
Company's electric transmission and distribution system consistent with AB
1890, as well as major projects associated with customer service improvements.
PG&E Corporation estimates that its total capital requirements for the years
1998 through 2000 will include approximately $2 billion for payment at
maturity of outstanding long-term debt and for meeting sinking fund
requirements for debt, as indicated above.
The funds necessary for 1998-2000 capital requirements of PG&E Corporation
and its subsidiaries will be obtained from (i) internal sources, principally
net income before noncash charges for depreciation and deferred income taxes,
and (ii) external sources, including short-term financing, such as bank loans
and the sale of short-term notes, and long-term financing, such as sales of
equity and long-term debt securities, when and as required.
PG&E Corporation and its subsidiaries and affiliates conduct a continuing
review of their capital expenditures and financing programs. The programs and
estimates above are subject to revision and actual amounts may vary based upon
changes in assumptions as to system load growth, rates of inflation, receipt
of adequate and timely rate relief, availability and timing of regulatory
approvals, total cost of major projects, availability and cost of suitable
nonregulated investments, and availability and cost of external sources of
capital, as well as the outcome of the ongoing restructuring in both the
electric and gas industries.
In January 1997, PG&E Corporation acquired Teco and its subsidiaries for
approximately $378 million, consisting of the purchase of a $61 million note,
and $317 million of PG&E Corporation common stock. On July 31, 1997, PG&E
Corporation acquired Valero's natural gas and natural gas liquids business. In
the Valero acquisition, approximately 31 million shares of PG&E Corporation
common stock were issued and approximately $780 million in long term debt was
assumed.
PRICE RISK MANAGEMENT PROGRAMS
PG&E Corporation established an officer-level price risk management
committee, and adopted a price risk management policy approved by the PG&E
Corporation Board of Directors, for trading and risk management activities.
The price risk management committee oversees implementation of the policy,
approves the trading and price risk management policies of subsidiaries, and
monitors compliance with the policy.
13
<PAGE>
The price risk management policy allows derivatives to be used for both
hedging and non-hedging purposes. (A derivative is a contract whose value is
dependent on or derived from the value of some underlying asset.) PG&E
Corporation uses derivatives for hedging purposes primarily to offset
underlying commodity price risks. PG&E Corporation also participates in
markets using derivatives to create liquidity, and maintain a market presence.
Such derivatives include forward contracts, futures, swaps, and options. The
price risk management policy and the trading and risk management policies of
PG&E Corporation's subsidiaries prohibit the use of derivatives whose payment
formula includes a multiple of some underlying asset.
In 1997, PG&E Corporation approved and implemented trading and risk
management policies for PG&E ET, and continued to seek approval from the CPUC
to manage commodity price risks in Pacific Gas and Electric Company's
business.
The fair value of the market risk sensitive instruments (which includes the
hedging and non-hedging instruments described above) as of December 31, 1997,
is immaterial for financial instruments subject to commodity price risk.
Additionally, as of December 31, 1997, PG&E Corporation calculated value-at-
risk based on a 95 percent confidence level using five-day holding periods.
Using this methodology, the potential for near-term losses in future earnings,
fair values, and cash flows from reasonably possible near-term changes in
market prices for financial instruments subject to commodity price risk is
immaterial.
PG&E Corporation anticipates an increase in the level of trading and risk
management activity in 1998 due to expected growth in its national energy
businesses and a continuing effort to manage anticipated price risks in
Pacific Gas and Electric Company's business. Pacific Gas and Electric Company
manages price risk independently from the activities of PG&E Corporation's
other subsidiaries.
14
<PAGE>
ELECTRIC UTILITY OPERATIONS
ELECTRIC INDUSTRY RESTRUCTURING LEGISLATION
In 1997, the relevant regulatory authorities took steps to implement AB
1890, including establishing the ISO and PX, and implementing direct access.
AB 1890 also provides for the financing of the 10 percent rate reduction
through rate reduction bonds, recovery of transition costs, and the funding of
public purpose programs.
INDEPENDENT SYSTEM OPERATOR AND POWER EXCHANGE
AB 1890 requires the CPUC to facilitate the development of an ISO and a PX,
and establishes a five-member Oversight Board to oversee the ISO and PX and
appoint the members of the ISO and PX Governing Boards. In May 1997, the ISO
and PX were formed as California non-profit corporations. The ISO and PX
Governing Boards include representatives of investor-owned utility
transmission systems, publicly owned utility transmission systems, non-utility
electricity sellers, public buyers and sellers, private buyers and sellers,
industrial end-users, commercial end-users, residential end-users,
agricultural end-users, public interest groups, and non-market participant
representatives. In March 1997, the trustee for the development of the ISO and
PX, filed the documents with FERC that explained the structure, rates, terms
and conditions applicable to the new market structure. While those documents
have been subsequently revised and clarified in more recent filings by the
duly constituted governing boards of the ISO and PX, on October 30, 1997, the
FERC granted conditional authority for the ISO to begin operations and for the
PX to charge market-based rates for electricity.
Under AB 1890, it is intended that both California's investor-owned
utilities and its publicly owned utilities relinquish control, but not
ownership, of their transmission facilities to the ISO. The ISO is required to
ensure reliable transmission services consistent with planning and operating
reserve criteria no less stringent than those established by the Western
Systems Coordinating Council and the North American Electric Reliability
Council. Oversight responsibility for reliability of utility distribution
systems remains with the CPUC. In December 1997, the ISO announced a delay of
its operations and its formal assumption of control of the utilities'
transmission systems. The PX also announced a delay in the commencement of its
operations. Both the ISO and the PX announced that they expected to begin
operations by March 31, 1998, at which time direct access will begin. The FERC
requires that it be given at least 15 days notice before ISO and PX operations
commence.
VOLUNTARY GENERATION ASSET DIVESTITURE
In 1997, California utilities produced a significant portion of the state's
electric generation needs. In a competitive market, the CPUC is concerned that
this level of generation may give existing utilities undue influence on the PX
price. To alleviate this concern, Pacific Gas and Electric Company has
indicated that it is willing to proceed with voluntary economic divestiture of
at least 98% of its fossil-fueled power plants and all of its geothermal
facilities. In December 1997, the CPUC approved Pacific Gas and Electric
Company's sale of three electric generating plants with a combined capacity of
2,645 megawatts (MW) to Duke Energy Power Services, Inc. (Duke Energy) in
Pacific Gas and Electric Company's first power plant auction. The aggregate
bid was $501 million for these three fossil-fueled plants: the Morro Bay Power
Plant located in San Luis Obispo County, the Moss Landing Power Plant located
in Monterey County, and the Oakland Power Plant located in Alameda County. The
combined book value for these three fossil-fueled plants is approximately $370
million as of December 31, 1997. Pacific Gas and Electric Company will retain
liability for required environmental remediation of any preclosing soil or
groundwater contamination at these plants. Subject to various conditions,
including regulatory approval of the transfer of various permits and licenses,
and the commencement of direct access, Pacific Gas and Electric Company
expects the sale to close in 1998.
In 1997 Pacific Gas and Electric Company announced plans to conduct the
second auction of four of its five remaining fossil-fueled power plants (the
Hunters Point and Potrero Power Plants, both located in San Francisco County,
and the Contra Costa and Pittsburg Power Plants, both located in Contra Costa
County) and all of its geothermal facilities (The Geysers located in Lake and
Sonoma counties) in 1998, subject to CPUC approval. These
15
<PAGE>
plants have a combined generating capacity of 4,718 MW and a combined book
value at December 31, 1997 of approximately $790 million. In January 1998,
Pacific Gas and Electric Company filed its application to seek CPUC approval
for the sale of these plants. In its application, Pacific Gas and Electric
Company indicated that the auction for these plants would begin on March 16,
1998.
Together, the eight power plants represent 98% of Pacific Gas and Electric
Company's fossil-fueled generating capacity and all of its geothermal
generating capacity. The facilities generate approximately 22% of Pacific Gas
and Electric Company's total electric energy sold to customers. Pacific Gas
and Electric Company is evaluating its options related to its remaining
generation facilities and may decide not to retain its economic investments in
those facilities. Any gain from the sale of power plants would be used to
offset Pacific Gas and Electric Company's transition costs.
As required by the California electric industry restructuring legislation,
Pacific Gas and Electric Company employees will continue to operate and
maintain the power plants that are sold under a two-year operations and
maintenance agreement with the new owner. To the extent that payments to
Pacific Gas and Electric Company under these agreements exceed the Company's
cost of operating the plants, the Company would offset other transition costs.
Conversely, to the extent Pacific Gas and Electric Company's operating costs
exceed the revenues from these agreements, the Company would have lower
earnings.
DIRECT ACCESS
AB 1890 authorizes direct transactions between electricity suppliers and
customers, beginning January 1, 1998. As described above, direct access has
been delayed due to the delay in the start of operations of the ISO and PX.
The ISO and PX expect to commence operations by March 31, 1998.
In May 1997, the CPUC issued a decision which authorizes full implementation
of direct access for all electric customers. In October 1997, the CPUC
approved implementing tariffs, rate schedules, and service agreements.
Customers participating in direct access would purchase their electric power
directly either through (1) competing non-utility retail electric providers
such as brokers, marketers, aggregators, or other retailers, or (2) direct
negotiated contracts with electric generators. All customers (with limited
exceptions), whether they choose direct access or not, must pay the
nonbypassable CTC, which will be collected by their distribution utility in
connection with recovery of the utilities' transition costs. Utilities began
accepting requests for direct access in November 1997, to become effective
after direct access begins. As of February 19, 1998 Pacific Gas and Electric
Company had accepted over 11,781 direct access requests. The CPUC requires
that electric customers with an electricity demand, or load, of 50 kilowatts
(kW) or more must have meters that are capable of providing hourly data in
order to participate in direct access. Those customers with a load less than
50 kW may participate in direct access either through "load profiling" or by
installing an hourly meter. (Load profiling approximates the pattern of
electricity usage for a given customer class.) The customer will be
responsible for the cost of the meter and the meter installation.
Also in May 1997, the CPUC issued a decision addressing the separation, or
unbundling, of utility revenue cycle services, which include metering and
billing. Under this decision, when direct access begins, energy service
providers supplying the direct access market will be able to choose one of
three billing options: (1) consolidated energy supplier billing, under which
the utility would bill the energy supplier for the services provided directly
by the utility to the customer and the supplier, in turn, would provide a
consolidated bill to the customer; (2) Consolidated distribution company
billing, under which the utility would place the supplier's energy charge on a
distribution bill; or (3) dual billing, under which the energy supplier and
the utility would bill separately for their own services. In December 1997,
the CPUC adopted procedures and standards for non-utility performance of
unbundled metering and meter data management services. Beginning January 1,
1998, energy service providers have been allowed to provide metering services
to their customers with a demand greater than 20 kW, and beginning January 1,
1999, energy service providers may provide metering to all of their customers.
16
<PAGE>
RATE LEVELS AND RATE REDUCTION BONDS
To achieve the 10% rate reduction for residential and eligible small
commercial customers, effective January 1, 1998, AB 1890 authorized utilities
to finance a portion of their transition costs with "rate reduction bonds." On
December 8, 1997, a special purpose entity established by the California
Infrastructure and Economic Development Bank issued $2.9 billion of rate
reduction bonds on behalf of a wholly owned subsidiary of Pacific Gas and
Electric Company. The bonds were issued in eight classes with maturities
ranging from ten months to ten years, and bearing interest at rates ranging
from 5.94% to 6.48%. Pacific Gas and Electric Company will collect a separate
nonbypassable charge on behalf of the bondholders to recover principal,
interest, and related costs over the life of the bonds from residential and
small commercial customers. The bond proceeds were used by the wholly owned
subsidiary to purchase from Pacific Gas and Electric Company the right to be
paid the revenues from this separate charge. The bonds are secured by the
future revenue from the separate charge and not by Pacific Gas and Electric
Company's assets. While the bonds are reflected as long-term debt on Pacific
Gas and Electric Company's balance sheet, creditors of Pacific Gas and
Electric Company do not have any recourse to the revenues from the separate
charge.
Various consumer groups filed a voter initiative with the California
Attorney General which seeks among other things, to (i) require investor-owned
California utilities to provide an additional 10% rate reduction to
residential and small commercial customers; (ii) eliminate transition cost
recovery for nuclear investments by utilities (other than reasonable
decommissioning costs); (iii) restrict transition cost recovery for non-
nuclear investments (other than costs associated with QFs), unless the CPUC
finds that the utility would be deprived of the opportunity to earn a fair
rate of return; (iv) and prohibit the collection of any customer charges for
rate reduction bonds, or alternatively, require the utility to offset such
charges with an equal credit to customers. In February 1998, the California
Secretary of State released the title and summary prepared for the proposed
initiative by the California Attorney General's office. The sponsors of the
initiative are now seeking sufficient signatures to qualify the initiative for
the November 1998, statewide ballot. If the proposed initiative were voted
into law, costly and time-consuming litigation may ensue. The Company believes
that under applicable federal and state constitutional principles relating to
the impairment of contracts, the State of California through such an
initiative, could not repeal or amend the Company's authorization to collect
principal, interest, and related costs for the rate reduction bonds if such
repeal or amendment would substantially impair the rights of the bondholders.
RECOVERY OF TRANSITION COSTS
AB 1890 authorizes utilities to recover their transition costs--the
utilities' costs of their generation-related assets and obligations which
prove to be uneconomic in the new competitive framework. Costs eligible for
recovery as transition costs, as determined by the CPUC, include (1) above-
market sunk costs (sunk costs are costs associated with utility generating
facilities that are fixed and unavoidable and currently included in customer
rates), and future sunk costs, such as costs related to plant removal, (2)
costs associated with long-term contracts to purchase power at above-market
prices from QFs and other power suppliers, and (3) generation-related
regulatory assets and obligations. (In general, regulatory assets are expenses
deferred in the current or prior periods to be included in rates in subsequent
periods). Transition costs are eligible for recovery from all customers (with
certain exceptions) through a nonbypassable competition transition charge or
CTC included as part of rates. Transition costs that are disallowed by the
CPUC for collection from customers will be written off.
As a prerequisite to any consumer obtaining direct access services, the
consumer must agree to pay its applicable nonbypassable CTC. Further, nuclear
decommissioning costs are being recovered through a separate CPUC-authorized
charge. Most transition costs must be recovered by March 31, 2002, although
certain transition costs may be recovered after March 31, 2002. These costs
include certain employee-related transition costs, costs
17
<PAGE>
that are unrecovered as result of the implementation of direct access and
creation of the PX and ISO, and above-market costs associated with power-
purchase agreements. In addition, costs financed by the issuance of rate
reduction bonds are expected to be recovered over the term of the bonds.
The total amount of sunk costs to be included as transition costs will be
based on the aggregate of above-market and below-market values of utility-
owned generation assets and obligations. Under AB 1890, valuation of
generation-related assets through appraisal or sale must be completed by
December 31, 2001. In 1997, the value of three of Pacific Gas and Electric
Company's electric facilities was established through the auction process.
Pacific Gas and Electric Company has also announced plans to conduct the
second auction of four of its five remaining fossil-fueled power plants and
its geothermal facilities in 1998, subject to CPUC approval.
In September 1997, the CPUC adopted a decision addressing transition cost
recovery for capital additions to Pacific Gas and Electric Company's non-
nuclear generating facilities. The decision allows Pacific Gas and Electric
Company to recover costs of capital additions made in 1996 and 1997 (and in
1998 for fossil-fueled plants completely divested by March 31, 1998) based
upon an after-the-fact reasonableness review. All capital additions found
reasonable by the CPUC through this process will be recoverable as transition
costs. Capital additions made in 1998 and thereafter to non-nuclear
generation-related assets and capital additions made to fossil-fueled
generating assets which are not completely divested by March 31, 1998, must be
recovered either through revenues from the ISO agreements for "must-run"
plants or from sales of electricity to the PX. The CPUC decision allows
Pacific Gas and Electric Company to seek an after-the-fact reasonableness
review of post 1997 capital addition expenditures for collection as transition
costs in certain limited circumstances.
In November and December 1997, the CPUC issued two decisions confirming the
eligibility of Pacific Gas and Electric Company's various categories of non-
nuclear generation-related costs for accelerated recovery as transition costs
and adopting tariffs associated with enforcement of the nonbypassable CTC. The
CPUC reduced the authorized rate of return on common equity to 6.77% for all
Pacific Gas and Electric Company's non-nuclear generation-related assets,
including hydroelectric and geothermal facilities, for a total rate of return
of 7.13% for these assets. The reduced rate of return was retroactive to July
28, 1997, and will be effective for the duration of the transition period.
The CPUC has ordered the utilities to file applications by June 1, 1998, to
request recovery of transition costs in 1999. The annual transition cost
proceeding will be used to develop a record to establish the guidelines for
computing the transition costs on an ongoing basis and a mechanism for
tracking the amount of transition costs and revenues recovered each year for
the nuclear facilities based on actual recorded data. This proceeding will
establish the reasonableness of accelerating recovery of transition costs and
of estimating the market value of the assets subject to market valuation, and
review actual employee transition costs, review all costs and revenues related
to the PX and ISO revenues, and transition cost balancing account entries. In
February 1998, Pacific Gas and Electric Company, along with the other
California utilities, requested that the June 1, 1998, filing date be
postponed to September 1, 1998, to reflect the delay of the commencement of
direct access.
PUBLIC PURPOSE PROGRAMS
On January 1, 1998, and continuing through December 31, 2001, energy
efficiency, research and development, and low-income programs are being funded
through a separate nonbypassable charge included in frozen electric rates, in
compliance with AB 1890. Low-income programs are funded at the level of need,
but are not to be funded at less than the 1996 level of expenditures. Under
this provision of AB 1890, Pacific Gas and Electric Company is obligated to
fund through electric rates energy efficiency and conservation programs in an
amount not less than $106 million per year, public interest research and
development programs at not less than $30 million per year, renewable
technologies at not less than $48 million per year, low-income energy
efficiency programs at not less than $14 million per year, and the low-income
rate discount program at approximately $38 million per year.
In February 1997, the CPUC adopted a decision that turns over administration
of the funding for public interest research and development, and renewable
technologies programs to the CEC, beginning January 1, 1998.
18
<PAGE>
The decision also changed the way some programs are administered. Before 1998,
Pacific Gas and Electric Company and other utilities administered public
purpose programs for energy efficiency and conservation, and low-income
customer assistance. Under the CPUC's decision, the CPUC will appoint
independent boards to oversee energy efficiency and low-income assistance
programs. These boards will solicit competitive bids to determine who will
administer the programs from January 1, 1998, through 2001. In December 1997,
the CPUC approved Pacific Gas and Electric Company's continuing to act as
interim administrator of energy efficiency programs until October 1, 1998.
Thereafter, an open-bidding process is expected to be completed to select
energy efficiency program administrators.
Additional information concerning AB 1890 and its financial impact on PG&E
Corporation is provided in "Management's Discussion and Analysis of
Consolidated Results of Operations and Financial Condition" in the 1997 Annual
Report to Shareholders, beginning on page 20, and in Note 2 of the "Notes to
Consolidated Financial Statements" beginning on page 43 of the 1997 Annual
Report to Shareholders.
19
<PAGE>
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
---------------------------------------------------------
1997 1996 1995 1994 1993
---------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C>
CUSTOMERS (AVERAGE FOR
THE YEAR):
Residential............ 3,915,370 3,874,223 3,825,413 3,788,044 3,748,831
Commercial............. 465,461 459,001 454,718 452,049 449,619
Industrial............. 1,121 1,248 1,253 1,260 1,243
Agricultural........... 86,359 87,250 88,546 90,520 91,376
Public street and
highway lighting...... 17,955 17,583 17,089 16,709 16,096
Other electric
utilities............. 47 28 35 29 28
---------- ---------- ---------- ---------- ----------
Total............... 4,486,313 4,439,333 4,387,054 4,348,611 4,307,193
========== ========== ========== ========== ==========
GENERATED, RECEIVED AND
SOLD--KWH (IN
MILLIONS):
Generated:
Hydroelectric plants.. 13,549 15,158 16,608 7,791 14,403
Thermal-electric
plants:
Fossil fueled........ 14,655 11,620 13,729 29,543 19,070
Geothermal........... 4,829 4,514 4,001 6,024 6,491
Nuclear.............. 17,071 16,720 16,269 15,265 16,816
---------- ---------- ---------- ---------- ----------
Total thermal-
electric plants.... 36,555 32,854 33,999 50,832 42,377
Wind and solar plants. 1 2 1 1 --
Received from other
sources: (1).......... 55,745 57,134 54,935 47,199 48,859
---------- ---------- ---------- ---------- ----------
Total gross system
output(2).......... 105,850 105,148 105,543 105,823 105,639
Less:
Delivered for
interchange or
exchange.............. 3,000 4,000 4,261 3,275 8,848
Delivered for the
account of others(1).. 16,611 19,356 18,946 18,622 13,726
Helms pumpback
energy(3)............. 661 898 937 467 452
Company use, losses,
etc.(4)............... 6,200 6,500 6,040 7,838 6,960
---------- ---------- ---------- ---------- ----------
Total energy sold... 79,378 74,394 75,359 75,621 75,653
========== ========== ========== ========== ==========
POWER PLANT FUEL SUPPLY
(IN THOUSANDS):
Natural gas (equivalent
barrels).............. 23,983 20,193 23,143 44,119 28,791
Fuel oil............... 0 686 756 2,395 2,080
Nuclear (equivalent
barrels).............. 29,152 28,574 27,814 26,135 28,724
---------- ---------- ---------- ---------- ----------
Total............... 53,135 49,453 51,713 72,649 59,595
========== ========== ========== ========== ==========
POWER PLANT FUEL COSTS
(AVERAGE COST PER
MILLION BTU'S):
Natural gas............ $ 2.87 $ 1.83 $ 2.06 $ 2.19 $ 2.86
Fuel oil............... $ 0 $ 2.66 $ 1.28 $ 2.83 $ 3.49
Weighted average....... $ 2.87 $ 1.92 $ 2.03 $ 2.23 $ 2.90
SALES--KWH (IN
MILLIONS):
Residential............ 25,946 25,458 24,391 24,326 24,111
Commercial............. 28,887 27,868 27,014 26,195 26,258
Industrial............. 16,876 15,786 16,879 16,010 16,492
Agricultural........... 3,932 3,631 3,478 4,426 3,672
Public street and
highway lighting...... 446 438 425 418 419
Other electric
utilities............. 3,291 1,213 3,172 4,246 4,701
---------- ---------- ---------- ---------- ----------
Total energy sold... 79,378 74,394 75,359 75,621 75,653
========== ========== ========== ========== ==========
REVENUES (IN THOUSANDS):
Residential............ $3,082,013 $3,033,613 $2,979,590 $2,980,966 $2,952,893
Commercial............. 2,932,560 2,840,101 2,964,568 2,892,302 2,914,855
Industrial............. 1,028,378 1,005,694 1,160,938 1,128,561 1,183,728
Agricultural........... 413,711 396,469 395,531 477,330 419,628
Public street and
highway lighting...... 53,183 55,372 56,154 55,545 55,976
Other electric
utilities............. 118,781 81,855 133,566 201,133 242,433
---------- ---------- ---------- ---------- ----------
Revenues from energy
sales.............. 7,628,626 7,413,104 7,690,347 7,735,837 7,769,513
Miscellaneous.......... (9,439) 112,303 92,538 142,771 87,991
Regulatory balancing
accounts.............. 71,441 (365,192) (396,578) 142,939 19,421
---------- ---------- ---------- ---------- ----------
Operating revenues.. $7,690,628 $7,160,215 $7,386,307 $8,021,547 $7,876,925
========== ========== ========== ========== ==========
</TABLE>
- --------
(1) Includes energy supplied through Pacific Gas and Electric Company's system
by the City and County of San Francisco for San Francisco's own use and
for sale by San Francisco to its customers, by the Department of Energy
for government use and sale to its customers, and by the State of
California for California Water Project pumping, as well as energy
supplied by QFs and purchases from other utilities.
(2) Includes energy output from Modesto and Turlock Irrigation Districts' own
resources.
(3) Represents energy required for pumping operations.
(4) Includes use by business units other than the electric utility business
units.
20
<PAGE>
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31
-------------------------------------------------
1997 1996 1995 1994 1993
--------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C>
SELECTED STATISTICS:
Total customers (at year-
end)........................ 4,500,000 4,500,000 4,400,000 4,400,000 4,400,000
Average annual residential
usage (kWh)................. 6,627 6,571 6,377 6,422 6,431
Average billed revenues per
kWh (c):
Residential................. 11.88 11.92 12.22 12.25 12.25
Commercial.................. 10.15 10.19 10.97 11.04 11.10
Industrial.................. 6.09 6.37 6.88 7.05 7.18
Agricultural................ 10.52 10.92 11.37 10.78 11.43
Net plant investment per
customer ($)................ 3,027 3,198 3,228 3,362 3,436
Electric control area
capability(megawatts)(1).... 23,157 22,724 22,099 21,851 23,009
Electric net control area
peak demand(megawatts)(2)... 21,862 21,437 20,317 19,118 19,607
</TABLE>
- --------
(1) Area net capability at time of annual peak, based on actual water
conditions.
(2) Net control area peak demand includes demand served by Modesto and Turlock
Irrigation Districts' own resources.
21
<PAGE>
ELECTRIC GENERATING AND TRANSMISSION CAPACITY
As described above in "Electric Industry Restructuring Legislation--
Voluntary Generation Asset Divestiture," in 1997, Pacific Gas and Electric
Company entered into an agreement for the sale of three fossil-fueled power
plants and announced plans to sell an additional four fossil-fueled power
plants and its geothermal facilities. As of December 31, 1997, Pacific Gas and
Electric Company owned and operated the following generating plants, all
located in California, listed by energy source:
<TABLE>
<CAPTION>
NET
OPERATING
NUMBER CAPACITY
GENERATION TYPE COUNTY LOCATION OF UNITS KW
--------------- --------------- -------- ----------
<S> <C> <C> <C>
Hydroelectric:
Conventional Plants....... 16 counties in Northern and 109 2,698,100
Central California
Helms Pumped Storage
Plant.................... Fresno 3 1,212,000
--- ----------
Hydroelectric Subtotal.. 112 3,910,100
--- ----------
Steam Plants:
Contra Costa(1)........... Contra Costa 2 680,000
Humboldt Bay.............. Humboldt 2 105,000
Hunters Point(1).......... San Francisco 3 377,000
Morro Bay(2).............. San Luis Obispo 4 1,002,000
Moss Landing(2)........... Monterey 2 1,478,000
Pittsburg(1).............. Contra Costa 7 2,022,000
Potrero(1)................ San Francisco 1 207,000
--- ----------
Steam Subtotal............ 21 5,871,000
--- ----------
Combustion Turbines:
Hunters Point(1).......... San Francisco 1 52,000
Oakland(2)................ Alameda 3 165,000
Potrero(1)................ San Francisco 3 156,000
Mobile Turbines(3)........ Humboldt and Mendocino 3 45,000
--- ----------
Combustion Turbines
Subtotal................. 10 418,000
--- ----------
Geothermal:
The Geysers Power
Plant(1)(4).............. Sonoma and Lake 14 1,224,000
Nuclear:
Diablo Canyon............. San Luis Obispo 2 2,160,000
--- ----------
Thermal Subtotal........ 47 9,673,000
--- ----------
Total.............................................. 159 13,583,100
=== ==========
</TABLE>
- --------
(1) In 1997, Pacific Gas and Electric Company announced plans to sell these
power plants and its geothermal facilities in connection with electric
industry restructuring.
(2) In 1997, Pacific Gas and Electric Company entered into an agreement to
sell these power plants in connection with electric industry
restructuring.
(3) Listed to show capability; subject to relocation within the system as
required.
(4) The Geysers Power Plant net operating capacity is based on adequate
geothermal steam supply conditions. Any decrease in capacity, at peak, is
included as unavailable capacity in the control area net capacity table
below.
22
<PAGE>
The following table sets forth the available capacity for the control area
(the area served by Pacific Gas and Electric Company and various publicly
owned systems in Northern California) at the date of peak (including reduction
for scheduled and forced outages and based on actual water conditions) by
various sources of generation available to the control area and the total
amount of generation provided by these sources during the year ended December
31, 1997.
<TABLE>
<CAPTION>
CONTROL AREA
NET CAPACITY
(AT DATE OF 1997 PEAK)
----------------------
KW %
-------------- ----------
<S> <C> <C>
Sources of
Electric
Generation:
Company-Owned
Plants:
Fossil Fueled.... 6,289,000 48
Geothermal....... 1,224,000 9
Nuclear.......... 2,160,000 17
-------------- -------
Total Thermal... 9,673,000 74
Hydroelectric
(available)..... 3,326,000 26
Solar............ 0 0
-------------- -------
Total Company-
Owned Capacity.. 12,999,000 100
============== =======
Less Unavailable
Capacity........ (1,906,200)
--------------
Total Company
Available
Capacity........ 11,092,800 48
Capacity Received
from Others:
QF Producers
(available)..... 2,948,800 13
Area Producers &
Imports......... 9,115,400 39
-------------- -------
Capacity from
Others.......... 12,064,200 52
-------------- -------
Total Available
Capacity........ 23,157,000 100
============== =======
Total Area
Demand(1)(2)..... 21,862,000
==============
</TABLE>
<TABLE>
<CAPTION>
GENERATION
YEAR ENDED
DECEMBER 31, 1997(3)
--------------------
KWH
THOUSANDS %
-------------- ------
<S> <C> <C>
Electric
Generation:
Company-Owned
Plants:
Fossil Fueled.... 14,654,952 14
Geothermal....... 4,829,743 5
Nuclear.......... 17,070,798 17
-------------- ------
Total Thermal... 36,555,493 36
Hydroelectric.... 13,549,123 13
Solar............ 1,164 0
-------------- ------
Total Company
Generation...... 50,105,780 49
Helms Pumpback
Energy.......... (661) 0
-------------- ------
Net Company
Generation...... 50,105,119 49
============== ======
Generation
Received from
Others:
QF Producers..... 19,700,000 19
Area Producers &
Imports......... 33,194,881 32
-------------- ------
Generation from
Others......... 52,894,881 51
============== ======
Total Area
Generation...... 103,000,000 100
============== ======
</TABLE>
- --------
(1) The maximum control area peak demand to date was 21,862,000 kW which
occurred in August 1997.
(2) The reserve capacity margin at the time of the 1996 control area peak,
taking into account short-term firm capacity purchases from utilities
located outside Pacific Gas and Electric Company's service area: Pacific
Gas and Electric Company's load responsibility for spinning reserve
(capability already connected to the system and ready to meet
instantaneous changes in demand) to the control area peak was 6.4% of the
peak demand and total reserve (spinning reserve and capability available
within a short period of time) was 7.4%.
(3) Represents actual year net generation from sources shown. Generation
received from others is based on the best available information at the
publication date of this document.
DIABLO CANYON
DIABLO CANYON OPERATIONS
Diablo Canyon consists of two nuclear power reactor units, each capable of
generating up to approximately 26 million kilowatt-hours (kWh) of electricity
per day. Diablo Canyon Units 1 and 2 began commercial operation in May 1985
and March 1986, respectively. The operating license expiration dates for
Diablo Canyon Units 1 and 2 are September 2021 and April 2025, respectively.
As of December 31, 1997, Diablo Canyon Units 1 and 2 had achieved lifetime
capacity factors of 80.3% and 82.7%, respectively.
The table below outlines Diablo Canyon's refueling schedule for the next
five years. In the past, Diablo Canyon refueling outages typically have
occurred every 18 months. Beginning in 1996, Pacific Gas and Electric Company
schedules refueling outages every 20 to 21 months, and it has been seeking NRC
licensing authority to schedule such outages once every 24 months beginning in
2001. Though nominal 20-month cycles are firm, achieving a 24-month cycle is
uncertain and its implementation could be delayed. The schedule below assumes
23
<PAGE>
that a refueling outage for a unit will last approximately six weeks,
depending on the scope of the work required for a particular outage. The
schedule is subject to change in the event of unscheduled plant outages or
changes in the length of the fuel cycle.
<TABLE>
<CAPTION>
1998 1999 2000 2001 2002
-------- --------- --------- ----- -----
<S> <C> <C> <C> <C> <C>
Unit 1
Refueling............................. January September March
Startup............................... March November May
Unit 2
Refueling............................. February September April
Startup............................... March November May
</TABLE>
DIABLO CANYON RATEMAKING
Prior to 1997, ratemaking for Diablo Canyon was determined by basing
revenues primarily on the amount of electricity generated by the plant, rather
than on traditional cost-based ratemaking. Under the prior ratemaking
treatment, revenues were based on a pre-established price per kWh of
electricity generated by the plant. That price consisted of a fixed component
(3.15 cents per kWh) and a separate component that declined until 2000, at
which point the variable component would have begun to escalate. For example,
the total price per kWh for the year 1996 was 10.50 cents. Under this
"performance-based" approach, Pacific Gas and Electric Company assumed a
significant portion of the operating risk of the plant because the extent and
timing of the recovery of actual operating costs, depreciation, and a return
on the investment in the plant primarily depended on the amount of power
produced and the level of costs incurred. Pacific Gas and Electric Company's
earnings were affected directly by plant performance and costs incurred. Under
this ratemaking treatment, earnings relating to Diablo Canyon could fluctuate
significantly as a result of refueling or other extended plant outages, plant
expenses, and the effects of a peak-period pricing mechanism.
In connection with electric industry restructuring, in 1996, Pacific Gas and
Electric Company proposed to price electric generation from Diablo Canyon at
market prices and to complete recovery of its investment in Diablo Canyon by
the end of 2001. Pacific Gas and Electric Company proposed to replace the
Diablo Canyon performance-based ratemaking mechanism described above with: (1)
a sunk cost revenue requirement to recover net investment in plant, including
a return on this net investment, and (2) a performance-based Incremental Cost
Incentive Price (ICIP) mechanism to recover the facility's variable and other
operating costs and capital addition costs. As proposed by Pacific Gas and
Electric Company, the sunk cost revenue requirement would be set to accelerate
recovery of Diablo Canyon sunk costs from a period ending in 2016 to a five-
year period ending in 2001. The related return on common equity associated
with Diablo Canyon sunk costs would be reduced to 90 percent of Pacific Gas
and Electric Company's long-term cost of debt. Pacific Gas and Electric
Company's proposed ICIP mechanism would establish a rate per kWh generated by
the facility. This rate would be based upon a fixed forecast of ongoing costs,
capital additions, and capacity factors for the period 1997 through 2001.
In May 1997, the CPUC issued a decision on Pacific Gas and Electric
Company's proposal with an effective date of January 1, 1997. Under the
decision, Pacific Gas and Electric Company's sunk costs will be recovered
through a sunk cost revenue requirement, at a reduced return on common equity
equal to 90 percent of Pacific Gas and Electric Company's embedded cost of
debt, for a reduced total return of 7.17% which will be effective through
2001. The CPUC decision substantially reduces the level of Pacific Gas and
Electric Company's proposed ICIP pricing through which ongoing operating costs
and capital additions will be recovered.
The CPUC decision adopts a fixed forecast of ICIP for 1997-2001, as shown
below. The revenues are based on an assumed capacity factor of 83.6 percent.
24
<PAGE>
INCREMENTAL COST INCENTIVE PRICES AND ESTIMATED
TOTAL CPUC REVENUE REQUIREMENT
<TABLE>
<CAPTION>
ESTIMATED TOTAL REVENUE
REQUIREMENT
----------------------------------
1997 1998 1999 2000 2001
------ ------ ------ ------ ------
($ IN MILLIONS)
<S> <C> <C> <C> <C> <C>
ICIP (cents per kWh)...................... 3.26 3.31 3.37 3.43 3.49
Sunk Cost Recovery........................ $1,385 $1,322 $1,259 $1,197 $1,135
ICIP Revenues............................. 515 523 532 542 552
------ ------ ------ ------ ------
Total Revenue Requirement................. $1,900 $1,845 $1,791 $1,739 $1,687
</TABLE>
The CPUC decision excluded several items totaling $160 million from the sunk
cost revenue requirement, including out-of-core fuel inventory, materials and
supplies inventory, and prepaid insurance expenses. The CPUC decision requires
that the costs of materials, supplies and nuclear fuel be recovered through
the ICIP mechanism as these items are used. The CPUC also disallowed about $70
million in plant costs from the sunk cost revenue requirement. Pacific Gas and
Electric Company has sought a rehearing of the CPUC decision.
The CPUC decision also ordered that a financial verification audit of Diablo
Canyon plant accounts be performed by an independent accounting firm, and that
the CPUC hold a proceeding to review the results of the audit, including any
proposed adjustments to Diablo Canyon accounts, following the completion of
the audit.
More information concerning the financial impact of Diablo Canyon ratemaking
is included in "Management's Discussion and Analysis of Consolidated Results
of Operations and Financial Condition" in the 1997 Annual Report to
Shareholders, beginning on page 20, and in Note 2 of the "Notes to
Consolidated Financial Statements" beginning on page 43 of the 1997 Annual
Report to Shareholders.
NUCLEAR FUEL SUPPLY AND DISPOSAL
Pacific Gas and Electric Company has purchase contracts for, and inventories
of, uranium concentrates, uranium hexaflouride, and enriched uranium, as well
as one contract for fuel fabrication. Based on current operations forecasts,
Diablo Canyon's requirements for uranium supply, the conversion of uranium to
uranium hexaflouride, and the enrichment of the uranium hexaflouride to
enriched uranium will be satisfied by a combination of existing contracts and
inventories through 2000, 1999, and 2002, respectively. The fuel fabrication
contract for the two units will supply their requirements for the next eight
operating cycles of each unit. These contracts are intended to ensure long-
term fuel supply, but permit Pacific Gas and Electric Company the flexibility
to take advantage of short-term supply opportunities. In most cases, Pacific
Gas and Electric Company's nuclear fuel contracts are requirements-based, with
the Company's obligations linked to the continued operation of Diablo Canyon.
Under the Nuclear Waste Policy Act of 1982 (Nuclear Waste Act), the U.S.
Department of Energy (DOE) is responsible for the transportation and ultimate
long-term disposal of spent nuclear fuel and high-level radioactive waste.
Under the Nuclear Waste Act, utilities are required to provide interim storage
facilities until permanent storage facilities are provided by the federal
government. The Nuclear Waste Act mandates that one or more such permanent
disposal sites be in operation by 1998. Consistent with the law, Pacific Gas
and Electric Company has signed a contract with the DOE providing for the
disposal of the spent nuclear fuel and high-level radioactive waste from the
Company's nuclear power facilities beginning not later than January 1998.
However, due to delays in identifying a storage site, the DOE has officially
acknowledged that it will not be able to meet its contract commitment to begin
accepting spent fuel by January 1998. Further, under the DOE's current
estimated acceptance schedule for spent fuel, Diablo Canyon's spent fuel may
not be accepted by the DOE for interim or permanent storage before 2012, at
the earliest. At the projected level of operation for Diablo Canyon, Pacific
Gas and Electric Company's facilities are sufficient to store on-site all
spent fuel produced through approximately 2006 while maintaining the
capability for a full-core off-load. It is likely that an interim or
25
<PAGE>
permanent DOE storage facility will not be available for Diablo Canyon's spent
fuel by 2006. Pacific Gas and Electric Company is examining options for
providing additional temporary spent fuel storage at Diablo Canyon or other
facilities, pending disposal or storage at a DOE facility.
In July 1988, the NRC gave final approval to Pacific Gas and Electric
Company's plan to store radioactive waste from the Humboldt Bay Power Plant
(Humboldt) at Humboldt for 20 to 30 years and, ultimately, to decommission the
unit. The license amendment issued by the NRC allows storage of spent fuel
rods at Humboldt until a federal repository is established. Pacific Gas and
Electric Company has agreed to remove all nuclear waste as soon as possible
after the federal disposal site is available.
INSURANCE
Pacific Gas and Electric Company has insurance coverage for property damage
and business interruption losses as a member of Nuclear Electric Insurance
Limited (NEIL). The company, which is owned by utilities with nuclear
generating facilities, provides insurance coverage against property damage,
decontamination, decommissioning, and business interruption and/or extra
expenses during prolonged accidental outages for reactor units in commercial
operation. Under Pacific Gas and Electric Company's policies, if the nuclear
generating facility of a member utility suffers a loss due to a prolonged
accidental outage, the Company may be subject to maximum retrospective premium
assessments of $23 million (property damage) and $7 million (business
interruption), in each case per one-year policy period, if losses exceed the
resources of NEIL.
Pacific Gas and Electric Company has purchased primary insurance of $200
million for public liability claims resulting from a nuclear incident. An
additional $8.7 billion of coverage is provided by secondary financial
protection required by federal law and provides for loss sharing among
utilities owning nuclear generating facilities if a costly incident occurs. If
a nuclear incident results in claims in excess of $200 million, Pacific Gas
and Electric Company may be assessed up to $159 million per incident, with
payments in each year limited to a maximum of $20 million per incident.
DECOMMISSIONING
Pacific Gas and Electric Company's estimated total obligation to
decommission and dismantle its nuclear power facilities is $1.4 billion in
1997 dollars ($5.1 billion in future dollars). This estimate, which includes
labor, materials, waste disposal charges, and other costs, is based on a 1997
decommissioning cost study. A contingency to capture engineering, regulatory,
and business environment changes is included in the total estimated
obligation. Actual decommissioning costs are expected to vary from this
estimate because of changes in the assumed dates of decommissioning,
regulatory requirements, and technology, as well as differences in the amount
of labor, materials, and equipment needed to complete decommissioning. The
estimated total obligation needed to complete decommissioning is recognized
proportionately over the license term of each facility.
Nuclear decommissioning costs recovered in rates are placed in external
trust funds. These funds, along with accumulated earnings, will be used
exclusively for decommissioning. The trust funds maintain substantially all of
their investments in debt and equity securities. All earnings on the trust
fund are reinvested. Monies may not be released from the external trust funds
until authorized by the CPUC. As of December 31, 1997, Pacific Gas and
Electric Company had accumulated external trust funds with an estimated fair
value of $1 billion, based on quoted market prices, to be used for the
decommissioning of the Company's nuclear facilities.
In the past, the amount recovered in rates for nuclear decommissioning costs
through an annual allowance has been reviewed by the CPUC as part of the GRC.
The CPUC considers the trusts' asset levels, together with revised earnings
and decommissioning cost assumptions, to determine the amount of
decommissioning costs it will authorize in rates for contribution to the
trusts. The monies contributed to the decommissioning trusts, together with
existing trust fund balances and projected earnings, are intended to satisfy
the estimated future obligation for decommissioning costs. For the year ended
December 31, 1997, nuclear decommissioning costs recovered in rates were $33
million.
26
<PAGE>
In compliance with AB 1890, effective on January 1, 1998, nuclear
decommissioning costs, which are not transition costs, are being recovered
through a nonbypassable charge which will continue until those costs are fully
recovered. Recovery of decommissioning costs may be accelerated to the extent
possible under the rate freeze. In its roadmap decision, the CPUC established
a Nuclear Decommissioning Costs Triennial Proceeding to determine the
decommissioning costs and establish the annual revenue requirement and
attrition factors over three-year periods when and if GRCs are discontinued.
OTHER ELECTRIC RESOURCES
QF GENERATION AND OTHER POWER-PURCHASE CONTRACTS
By federal law, Pacific Gas and Electric Company is required to purchase
electric energy and capacity provided by independent power producers. The CPUC
established a series of power-purchase contracts and set the applicable terms,
conditions, price options, and eligibility requirements.
Under these contracts, Pacific Gas and Electric Company is required to make
payments only when energy is supplied or when capacity commitments are met.
The total cost of these payments is recoverable in rates. Pacific Gas and
Electric Company's contracts with these power producers expire on various
dates through 2028. Total energy payments are expected to decline in the years
1998 through 2001. Total capacity payments are expected to remain at current
levels during this period. Deliveries from these power producers accounted for
approximately 18% of Pacific Gas and Electric Company's 1997 electric energy
requirements and no single contract accounted for more than 5% of the
Company's energy needs.
Pacific Gas and Electric Company has negotiated early termination or
suspension of certain power-purchase contracts. These amounts are expected to
be recovered in rates and as such are reflected as deferred charges on the
Company's balance sheet. At December 31, 1997, the total discounted future
payments remaining under early termination or suspension contracts is $53
million.
Pacific Gas and Electric Company also has contracts with various irrigation
districts and water agencies to purchase hydroelectric power. Under these
contracts, Pacific Gas and Electric Company must make specified semi-annual
minimum payments whether or not any energy is supplied (subject to the
provider's retention of the FERC's authorization) and variable payments for
operation and maintenance costs are incurred by the providers. These contracts
expire on various dates from 2004 to 2031. The total cost of these payments is
recoverable in rates. At December 31, 1997, the undiscounted future minimum
payments under these contracts are $34 million for each of the years 1998
through 2002 and a total of $349 million for periods thereafter. Irrigation
district and water agency deliveries in the aggregate account for
approximately 4% of Pacific Gas and Electric Company's 1997 electric energy
requirements.
The amount of energy received and the total payments made under all these
power-purchase contracts were:
<TABLE>
<CAPTION>
1997 1996 1995
------ ------ ------
(IN MILLIONS)
<S> <C> <C> <C>
Kilowatt-hours received................................ 24,389 26,056 26,468
Energy payments........................................ $1,157 $1,136 $1,140
Capacity payments...................................... $ 538 $ 521 $ 484
Irrigation district and water agency payments.......... $ 56 $ 52 $ 50
</TABLE>
As of December 31, 1997, Pacific Gas and Electric Company had commitments to
purchase approximately 5,400 megawatts (MW) of capacity under CPUC-mandated
power-purchase agreements. Of the 5,400 MW, approximately 4,600 MW were
operational. Development of the balance is uncertain and it is estimated that
very few of the remaining contracts will become operational. The 4,600 MW of
operational capacity consists of 2,900 MW from cogeneration projects, 700 MW
from wind projects, and 1,000 MW from other projects, including biomass,
waste-to-energy, geothermal, solar, and hydroelectric.
27
<PAGE>
GEOTHERMAL GENERATION
Pacific Gas and Electric Company's geothermal units at The Geysers Power
Plant (Geysers) are forecast to operate at reduced capacities because of
declining geothermal steam supplies and curtailment of the Geysers due to the
existence of more economic sources of electric generation. Pacific Gas and
Electric Company's agreements with several of its steam suppliers permit the
Company to curtail generation at The Geysers at the Company's discretion. The
consolidated Geysers capacity factor is forecast to be approximately 48% of
installed capacity in 1998, which includes economic curtailments, forced
outages, scheduled overhauls, and projected steam shortage curtailments, as
compared to the actual Geysers capacity factor of 45% in 1997.
In connection with electric industry restructuring, in January 1998, Pacific
Gas and Electric Company filed an application with the CPUC seeking approval
to sell The Geysers, subject to CPUC and other regulatory approvals. See
"Electric Utility Operations--Electric Industry Restructuring Legislation--
Voluntary Generation Asset Divestiture" above.
HELMS PUMPED STORAGE PLANT
Helms is a three-unit hydroelectric combined generating and pumped storage
facility, completion of which was delayed due to a water conduit rupture in
September 1982 and various start-up problems related to the plant's
generators. Helms became commercially operable in June 1984. As a result of
the damage caused by the rupture and the delay in the operational date,
Pacific Gas and Electric Company incurred additional costs which were not
initially included in rate base, and lost revenues during the period the plant
was under repair. In September 1996, the CPUC approved a settlement resolving
the treatment of remaining unrecovered Helms costs.
As part of the 1996 GRC decision issued in December 1995, the CPUC directed
Pacific Gas and Electric Company to perform a cost-effectiveness study of
Helms. The CPUC indicated the study should consider changes in rate recovery
for the plant including, among other things, the option of retirement with
recovery of the investment without a return. The cost-effectiveness study
submitted by Pacific Gas and Electric Company in July 1996 concluded that the
continued operation of Helms is cost-effective. Pacific Gas and Electric
Company recommended that the CPUC take no action based on the study, but
address Helms along with other generating plants in the context of electric
industry restructuring. Pacific Gas and Electric Company's net investment in
Helms at December 31, 1997 was $691 million. Under electric industry
restructuring, the uneconomic above-market portion of the Company's net
investment in Helms is eligible for recovery as a transition cost. However,
Pacific Gas and Electric Company will be placed at risk to recover its future
operating costs in the newly restructured electric generation market. Because
the CPUC has not specifically addressed the cost-effectiveness study, Pacific
Gas and Electric Company is currently unable to predict whether there will be
further changes in rate recovery resulting from the study. See "Pacific Gas
and Electric Company Rate Matters--Electric Ratemaking" above.
ELECTRIC TRANSMISSION AND DISTRIBUTION
To transport energy to load centers, Pacific Gas and Electric Company as of
December 31, 1997, owned and operated approximately 18,516 circuit miles of
interconnected transmission lines of 60 kilovolts (kV) to 500 kV and
transmission substations having a capacity of approximately 33,814,855
kilovolt-amperes (kVa), excluding power plant interconnection facilities.
Energy is distributed to customers through approximately 108,170 circuit miles
of distribution system and distribution substations having a capacity of
approximately 23,000,000 kVa.
Under AB 1890, it is intended that California's investor-owned utilities and
its publicly owned utilities relinquish control, but not ownership, of their
transmission facilities to the ISO. In 1997, the FERC issued various decisions
to implement the formation and operation of the ISO and the PX as contemplated
by AB 1890. The ISO will control the operation of the transmission system and
provide open access transmission service on a nondiscriminatory basis. The
FERC approved the various forms of agreements for must-run facilities that
will be entered into between the utilities and the ISO to ensure grid
reliability. The FERC also granted conditional
28
<PAGE>
authority for operation of the ISO and the PX. After the ISO and the PX
announced a delay in commencement of their operations, the FERC issued an
order requiring the ISO and the PX to provide the FERC 15 days notice before
the intended commencement date of operations and the ISO's assumption of
operational control of certain transmission facilities.
The FERC has also approved a proposal from Pacific Gas and Electric Company
and the other California utilities that distinguishes between local
distribution facilities and transmission facilities. The order defines
jurisdiction for the CPUC over local distribution and retail power customers.
The FERC will have jurisdiction over the transmission facilities as defined in
the order and over the transmission aspects of retail direct access. Most of
Pacific Gas and Electric Company's distribution services will remain subject
to CPUC jurisdiction.
29
<PAGE>
GAS UTILITY OPERATIONS
Pacific Gas and Electric Company owns and operates an integrated gas
transmission, storage, and distribution system in California. At December 31,
1997, Pacific Gas and Electric Company's system, including the PG&E Expansion
(Line 401), consisted of approximately 5,700 miles of transmission pipelines,
three gas storage facilities, and approximately 36,700 miles of gas
distribution lines.
GAS OPERATIONS
Pacific Gas and Electric Company's peak day send-out of gas on its
integrated system in California during the year ended December 31, 1997, was
4,145 million cubic feet (MMcf). The total volume of gas throughput during
1997 was approximately 888,000 MMcf, of which 262,000 MMcf was sold to direct
end-use or resale customers, 173,000 MMcf was used by Pacific Gas and Electric
Company primarily for its fossil-fueled electric generating plants, and
452,000 MMcf was transported as customer-owned gas.
The California Gas Report, which presents the outlook for natural gas
requirements and supplies for California over a long-term planning horizon, is
prepared annually by the California electric and gas utilities as a result of
a CPUC order. A comprehensive biennial report is prepared in even-numbered
years with a supplemental report in intervening odd-numbered years.
The 1997 Supplemental Report updates Pacific Gas and Electric Company's
annual gas requirements forecast (excluding bypass volumes) for the years 1997
through 2010 forcasting growth in gas throughput served by Pacific Gas and
Electric Company of 2% per year. The gas requirements forecast is subject to
many uncertainties and there are many factors that can influence the demand
for natural gas, including weather conditions, level of utility electric
generation, fuel switching, and new technology. In addition, some large
customers, mostly in the industrial and enhanced oil recovery sectors, may
have the ability to use unregulated private pipelines or interstate pipelines,
bypassing Pacific Gas and Electric Company's system entirely. The 1997
Supplemental Report forecasts a total bypass volume of 133,600 MMcf for 1998.
30
<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
----------------------------------------------------------
1997 1996 1995 1994 1993
---------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C>
CUSTOMERS (AVERAGE FOR
THE YEAR):
Residential............ 3,491,963 3,455,086 3,417,556 3,372,768 3,339,859
Commercial............. 198,453 198,071 197,939 196,509 195,815
Industrial............. 1,650 1,500 1,500 1,400 1,265
Other gas utilities.... 3 2 2 2 4
---------- ---------- ---------- ---------- ----------
Total............... 3,692,069 3,654,659 3,616,997 3,570,679 3,536,943
========== ========== ========== ========== ==========
GAS SUPPLY--THOUSAND
CUBIC FEET (MCF) (IN
THOUSANDS):
Purchased:
From Canada........... 280,084 253,209 261,800 319,453 329,693
From California....... 10,655 28,130 31,158 31,757 32,096
From other states..... 131,074 110,604 117,538 249,733 243,058
---------- ---------- ---------- ---------- ----------
Total purchased..... 421,813 391,943 410,496 600,943 604,847
Net from storage (to
storage).............. 14,160 6,871 (10,921) 3,591 (12,234)
---------- ---------- ---------- ---------- ----------
Total............... 435,973 398,814 399,575 604,534 592,613
Pacific Gas and
Electric Company use,
losses, etc.(1)....... 173,789 134,375 129,671 297,604 161,895
---------- ---------- ---------- ---------- ----------
Net gas for sales... 262,184 264,439 269,904 306,930 430,718
========== ========== ========== ========== ==========
BUNDLED GAS SALES AND
TRANSPORTATION
SERVICE--MCF (IN
THOUSANDS):
Residential............ 191,327 190,246 191,724 214,358 206,053
Commercial............. 60,803 62,178 64,135 72,183 82,048
Industrial............. 10,054 12,015 14,045 19,495 133,178
Other gas utilities.... 0 0 0 894 9,439
---------- ---------- ---------- ---------- ----------
Total............... 262,184 264,439 269,904 306,930 430,718
========== ========== ========== ========== ==========
TRANSPORTATION SERVICE
ONLY--MCF (IN THOU-
SANDS):
Vintage system
(Substantially all
Industrial)(2)........ 218,660 189,695 143,921 142,393 101,888
PG&E Expansion (Line
401).................. 233,269 237,776 240,506 200,755 20,513
---------- ---------- ---------- ---------- ----------
Total............... 451,929 427,471 384,427 343,148 122,401
========== ========== ========== ========== ==========
REVENUES (IN THOUSANDS):
Bundled gas sales and
transportation
service:
Residential........... $1,170,135 $1,109,463 $1,205,223 $1,268,966 $1,152,494
Commercial............ 374,084 362,819 421,397 444,805 467,962
Industrial............ 46,592 42,520 42,106 57,297 367,221
Other gas utilities... 3,701 510 0 2,371 25,654
---------- ---------- ---------- ---------- ----------
Bundled gas
revenues........... 1,594,512 1,515,312 1,668,726 1,773,439 2,013,331
Transportation only
revenue:
Vintage system
(Substantially all
Industrial).......... 207,160 180,197 167,325 132,509 56,733
PG&E Expansion (Line
401)................. 90,180 85,144 82,904 58,442 8,097
---------- ---------- ---------- ---------- ----------
Transportation service
only revenue.......... 297,340 265,341 250,229 190,951 64,830
Miscellaneous.......... 50,295 (9,271) (18,018) 40,427 (16,692)
Regulatory balancing
accounts.............. (137,787) 57,864 (43,771) (101,443) 95,339
Subsidiaries(3)........ 0 210,556 201,951 177,688 264,925
---------- ---------- ---------- ---------- ----------
Operating revenues.. $1,804,360 $2,039,802 $2,059,117 $2,081,062 $2,421,733
========== ========== ========== ========== ==========
</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 72,958 MMcf, 78,552 MMcf, 100,207 MMcf, 79,749 MMcf, and
7,205 MMcf for 1997, 1996, 1995, 1994 and 1993, respectively.
(3) In January 1997, a Pacific Gas and Electric Company subsidiary--Pacific
Gas Transmission Company (PGT) became a subsidiary of PG&E Corporation and
is now known as PG&E Gas Transmission, Northwest Corporation.
31
<PAGE>
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31
-------------------------------------------------
1997 1996 1995 1994 1993
--------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C>
SELECTED STATISTICS:
Total customers (at year-
end)....................... 3,700,000 3,700,000 3,600,000 3,500,000 3,600,000
Average annual residential
usage (Mcf)................ 55 55 56 64 62
Heating temperature -- % of
normal(1).................. 71.7 75.7 75.3 104.4 89.9
Average billed bundled gas
sales revenues per Mcf:
Residential................ 6.12 $5.83 $6.29 $5.92 $5.59
Commercial................. 6.15 5.84 6.57 6.16 5.70
Industrial................. 4.63 3.54 3.00 2.94 2.76
Average billed
transportation only revenue
per Mcf:
Vintage system............. 0.71 0.67 0.69 0.60 0.52
PG&E Expansion (Line 401).. 0.39 0.36 0.34 0.29 0.39
Net plant investment per
customer (2)............... $1,031 $1,378 $1,315 $1,340 $1,339
</TABLE>
- --------
(1) Over 100% indicates colder than normal.
(2) The net plant investment per customer figure for 1997 is lower than in
previous years because it excludes subsidiaries.
NATURAL GAS SUPPLIES
The objective of Pacific Gas and Electric Company's gas supply planning is
to maintain a balanced supply portfolio which provides supply reliability and
contract flexibility, minimizes costs, and fosters competition among
suppliers.
Under current CPUC regulations, Pacific Gas and Electric Company purchases
natural gas from its various suppliers based on economic considerations,
consistent with regulatory, contractual, and operational constraints. During
the year ended December 31, 1997, approximately 66% of Pacific Gas and
Electric Company's total purchases of natural gas consisted of Canadian gas
purchased from various Canadian producers and transported by Canadian pipeline
companies and PG&E Gas Transmission, Northwest Corporation; approximately 3%
was purchased from various California producers; and approximately 31% was
purchased in other states (substantially all from U.S. Southwest sources and
transported by the El Paso Natural Gas Company or Transwestern Pipeline
Company pipelines). The following table shows the volume and average price of
gas in dollars per thousand cubic feet (Mcf) purchased by Pacific Gas and
Electric Company from these sources during each of the last five years.
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31
----------------------------------------------------------------------------------------------
1997 1996 1995 1994 1993
------------------ ------------------ ------------------ ------------------ ------------------
THOUSANDS AVG. THOUSANDS AVG. THOUSANDS AVG. THOUSANDS AVG. THOUSANDS AVG.
OF MCF PRICE(1) OF MCF PRICE(1) OF MCF PRICE(1) OF MCF PRICE(1) OF MCF PRICE(1)
--------- -------- --------- -------- --------- -------- --------- -------- --------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Canada................. 280,084 $ 1.77 253,209 $ 1.57 261,800 $ 1.34 319,453 $ 1.94 329,693 $ 2.26
California............. 10,655 2.12 28,130 $ 1.90 31,158 $ 1.32 31,757 1.55 32,096 1.65
Other states
(substantially all
U.S. Southwest)....... 131,074 3.75 110,604 $3.72 117,538 $2.64 249,733 2.41 243,058 2.84
-------- ------ -------- ------ -------- ------ -------- ------ -------- ------
Total/Weighted Average. 421,813 $2.39 391,943 $2.21 410,496 $1.71 600,943 $2.12 604,847 $2.46
======== ====== ======== ====== ======== ====== ======== ====== ======== ======
</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. The
average prices for California gas include only commodity gas prices
delivered to Pacific Gas and Electric Company's gas system.
GAS REGULATORY FRAMEWORK
In August 1997, the CPUC approved the Gas Accord which restructures Pacific
Gas and Electric Company's gas services and its role in the gas market. As
discussed above (see "Competition and the Changing Regulatory Environment--Gas
Industry"), the Gas Accord separates, or "unbundles," the rates for Pacific
Gas and Electric Company's gas transmission services from its distribution
services, increases the opportunities for core customers
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<PAGE>
to purchase gas from competing suppliers, establishes a form of incentive
regulation to measure the reasonableness of core procurement costs, and
establishes gas transmission and storage rates from March 1998 through
December 2002. The Gas Accord also settled various issues pending in certain
regulatory proceedings.
The CPUC is considering further changes in California's natural gas
industry. See "Competition and the Changing Regulatory Environment--Gas
Industry" above.
TRANSPORTATION COMMITMENTS
Pacific Gas and Electric Company has gas transportation service agreements
with various Canadian and interstate pipeline companies. These agreements
include provisions for payment of fixed demand charges for reserving firm
capacity on the pipelines. The total demand charges that Pacific Gas and
Electric Company will pay each year may change due to changes in tariff rates.
The total demand and volumetric transportation charges paid by Pacific Gas and
Electric Company under these agreements were approximately $255 million in
1997. This amount includes payments made to PG&E Gas Transmission, Northwest
Corporation of approximately $49 million in 1997, which payments are
eliminated in the consolidated financial statements of PG&E Corporation.
As a result of regulatory changes, Pacific Gas and Electric Company no
longer procures gas for most of its noncore customers, resulting in a decrease
in the Company's need for firm transportation capacity for its gas purchases.
Pacific Gas and Electric Company continues to procure gas for almost all of
its core customers and those noncore customers who choose bundled service
(core subscription customers). Pacific Gas and Electric Company is continuing
its efforts to broker or assign any of its remaining contracted-for but unused
interstate transportation capacity, including unused capacity held for its
core and core subscription customers.
Under a firm transportation agreement with PG&E Gas Transmission, Northwest
Corporation that runs through October 31, 2005, Pacific Gas and Electric
Company currently retains approximately 600 million cubic feet per day
(MMcf/d) on the PG&E Gas Transmission, Northwest Corporation system to support
its core and core subscription customers. Although this capacity commitment
exceeds the amount needed to support Pacific Gas and Electric Company's core
and core subscription customers, the Company has been able to assign
substantially all of its unused capacity on PG&E Gas Transmission, Northwest
Corporation's system to other shippers.
In general, any shortfall resulting from the difference between the fixed
demand charges Pacific Gas and Electric Company pays under gas transportation
contracts with interstate pipeline companies for the reservation of interstate
pipeline capacity that the Company no longer uses to serve noncore customers,
and the revenues Pacific Gas and Electric Company obtains from brokering that
capacity, is eligible for rate recovery through the Interstate Transition Cost
Surcharge (ITCS), subject to a reasonableness review. Various groups had
challenged Pacific Gas and Electric Company's recovery of these amounts,
including amounts which arose in connection with firm transportation
commitments that the Company had entered into with PG&E Gas Transmission,
Northwest Corporation and El Paso Natural Gas Company. (The agreement with El
Paso terminated as of December 31, 1997.) Under the Gas Accord, these
challenges were resolved through Pacific Gas and Electric Company's agreement
to forgo recovery of 100 percent and 50 percent of the ITCS amounts allocated
for collection from its core and noncore customers, respectively.
In 1992, Pacific Gas and Electric Company entered into a firm transportation
agreement with Transwestern Pipeline Company (Transwestern), which expires in
2007, to meet core gas sales demands and electric generation needs. The demand
charges associated with the entire Transwestern capacity are currently
approximately $29 million per year. Pacific Gas and Electric Company was not
permitted to include any Transwestern firm capacity demand charges in rates or
in the ITCS account, although the Company was authorized to record costs
associated with its Transwestern capacity in a balancing account, with
recovery of such costs subject to reasonableness review proceedings. In 1995,
the CPUC determined that it was unreasonable for Pacific Gas and Electric
Company to commit to transportation capacity with Transwestern and disallowed
recovery of the costs of capacity for 1992. It indicated that it would
disallow costs through the term of the contract unless Pacific Gas
33
<PAGE>
and Electric Company could demonstrate on an annual basis that the benefit of
the commitment outweighed the costs in a particular year. As part of the Gas
Accord, Pacific Gas and Electric Company agreed to resolve this issue by
forgoing the recovery of costs associated with capacity originally subscribed
to in order to serve core customers through 1997 and to limit its recovery of
demand charges through the CPIM during the period 1998 through 2002.
GAS REASONABLENESS PROCEEDINGS
Recovery of gas costs through Pacific Gas and Electric Company's regulatory
balancing account mechanisms is subject to a CPUC determination that such
costs were incurred reasonably. Before June 1, 1994, annual reasonableness
proceedings were conducted by the CPUC on a historic calendar year basis. As
discussed above (see "Competition and the Changing Regulatory, Environment--
Gas Industry"), the annual reasonableness proceedings have been replaced by
the CPIM.
1988-1990 CANADIAN GAS PROCUREMENT ACTIVITIES
In March 1994, the CPUC issued a final decision on Pacific Gas and Electric
Company's Canadian gas procurement activities during 1988 through 1990. The
CPUC found that Pacific Gas and Electric Company could have saved its
customers money if it had bargained more aggressively with its existing
Canadian suppliers or bought less expensive gas from other Canadian sources.
The decision ordered a disallowance of $90 million of gas costs, plus accrued
interest estimated at approximately $25 million through December 31, 1993.
Although Pacific Gas and Electric Company had challenged this decision by the
CPUC in federal court, as part of the Gas Accord, the Company has agreed to
forgo recovery of the $90 million disallowance ordered in the 1988-1990
reasonableness proceeding. In November 1997, Pacific Gas and Electric
Company's federal lawsuit was dismissed with prejudice.
PGT/PACIFIC GAS AND ELECTRIC COMPANY PIPELINE EXPANSION
In November 1993, PG&E Gas Transmission, Northwest Corporation (formerly
Pacific Gas Transmission Company or PGT) and Pacific Gas and Electric Company
placed in service the Pipeline Expansion, an expansion of their interconnected
natural gas transmission systems from the Canadian border into California. The
840-mile combined Pipeline Expansion provides an additional 148 MMcf/d of firm
capacity to the Pacific Northwest and an additional 851 MMcf/d of capacity to
Northern and Southern California.
The conditions of the CPUC's approval of the construction of Pacific Gas and
Electric Company's portion of the Pipeline Expansion (PG&E Expansion or Line
401) placed Pacific Gas and Electric Company at risk for its decision to
construct based on its assessment of market demand and for undersubscription
and underutilization of the facility. The CPUC required the application of a
"cross-over" ban under which volumes delivered from the incremental portion
owned by PG&E Gas Transmission, Northwest Corporation (PGT Expansion) of the
Pipeline Expansion must be transported at an incremental PG&E Expansion rate.
The costs of PG&E Expansion operations were recovered only from PG&E Expansion
customers, through rates established in separate PG&E Expansion rate
proceedings.
Under the Gas Accord, Pacific Gas and Electric Company remains at risk for
cost recovery of the PG&E Expansion through rates; however, a portion of the
PG&E Expansion will be combined with other Pacific Gas and Electric Company
transmission assets (specifically, a portion of Pacific Gas and Electric
Company's Line 400) for ratemaking purposes. This new ratemaking treatment for
gas transmission assets allows all shippers supplying noncore customers to
transport Canadian gas in California at a single rate, and obviates the need
for the "cross-over" ban, which was eliminated under the Gas Accord. Further,
in the Gas Accord, the CPUC adopted a rule under which Pacific Gas and
Electric Company is required, whenever it discounts service for a shipper on
its Line 400/401 delivering primarily Canadian gas within the Company's
service territory, to contemporaneously offer a commensurate discount to all
shippers delivering Southwest or California source gas on Line 300 within the
Company's service territory.
34
<PAGE>
In 1994, Pacific Gas and Electric Company filed its application in the
Pipeline Expansion Project Reasonableness case (PEPR) requesting that the CPUC
find reasonable the full capital costs of the PG&E Expansion (estimated to be
$810 million). In that proceeding, the ORA recommended a minimum of $100
million in capital costs be disallowed, while two intervenors jointly
recommended a $237 million disallowance or reallocation of costs among
customers. In addition, in 1996, a CPUC administrative law judge (ALJ) ordered
consolidation of the market impact phase of the PEPR and the ITCS proceeding
described above. An ALJ also ordered reopening of the 1993 PG&E Pipeline
Expansion Rate Case to allow reconsideration of issues regarding the decision
to construct the PG&E Expansion. The CPUC's 1997 decision approving the Gas
Accord affirms the CPUC's 1994 finding that the decision to construct the PG&E
Expansion was reasonable based on Pacific Gas and Electric Company
management's knowledge at the time. The Gas Accord decision accepts the Gas
Accord's proposal to set rates for Line 401 during the Gas Accord period based
on total capital costs of $736 million.
35
<PAGE>
PG&E CORPORATION'S GAS TRANSMISSION OPERATIONS
During 1997, PG&E Corporation expanded its operations in the "midstream"
portion of the gas business, which includes (1) the gas gathering, processing,
storage, and transportation of natural gas, (2) the marketing of natural gas
to gas distribution companies, electric utilities, municipalities, marketers,
independent power producers, and end-use customers, and (3) the transportation
of natural gas for these customers, producers and other pipelines.
Through its January 1997 acquisition of Teco in Texas (now known as PG&E Gas
Transmission Teco, Inc.), PG&E Corporation acquired various interests in
natural gas pipeline systems in Texas, various investments in gas gathering
and processing facilities, and a gas marketing operation in Houston, Texas.
On July 31, 1997, PG&E Corporation completed its acquisition of Valero's
natural gas and related businesses, including its gas gathering,
transportation, and storage facilities, and its facilities relating to the
processing, transportation, and marketing of natural gas liquids (NGLs).
Valero's NGL business includes the gathering of natural gas, the extraction of
NGLs from natural gas, the fractionation of mixed NGLs into component products
(e.g., ethane, propane, butane, and natural gasoline), and the transportation
and marketing of NGLs. PG&E Corporation acquired approximately 6,400 miles of
natural gas pipeline and Valero's joint ownership or leasehold interests in
approximately 1,100 miles of pipeline, including the Valero-Teco West Texas
pipeline from Waha in west Texas to the San Antonio area. This pipeline system
has the capacity to transport more than 3 bcf of gas per day. PG&E Corporation
acquired a long-term lease of 7.2 bcf of storage capacity, approximately 536
miles of NGL pipelines and eight natural gas processing plants with a combined
capacity of approximately 1.5 bcf per day of gas throughput, capable of
producing approximately 93,000 barrels per day of NGLs.
PG&E Gas Transmission, Northwest Corporation (formerly Pacific Gas
Transmission Company or PGT) owns and operates gas transmission pipelines and
associated facilities which extend over 612 miles from the Canada-U.S. border
to the Oregon-California border and are capable of transporting 2.4 billion
cubic feet (bcf) per day of natural gas. It also owns two smaller diameter
pipeline extensions within Oregon, totaling 106 miles. A subsidiary of PG&E
Corporation also owns the PG&E Queensland Gas Pipeline, an approximately 389-
mile of mostly 12-inch pipeline in Queensland, Australia, which provides
natural gas transportation service to customers in the vicinity of the
pipeline.
In September 1996, the FERC approved a settlement of PG&E Gas Transmission,
Northwest Corporation's 1994 rate case. The major issue in this proceeding was
whether PG&E Gas Transmission, Northwest Corporation's mainline transportation
rates should be equalized through the use of rolled-in cost allocations, or
whether they should continue to reflect the use of incremental cost allocation
to determine the rates to be paid by firm shippers. (Under incremental rates,
a pipeline would generally charge higher rates to shippers contracting for
capacity on newly-added expansion facilities as compared to shippers using
depreciated pre-expansion facilities.) The settlement provides for rolled-in
rates effective November 1996. To mitigate the impact of the higher rolled-in
rates on shippers who were paying lower rates under contracts executed prior
to construction of the PGT Expansion, most of the firm shippers who took
service prior to such time receive a reduction from the rolled-in rate for a
six-year period, while PGT Expansion firm shippers pay a surcharge in addition
to the rolled-in rates to offset the effect of the mitigation. See "Gas
Utility Operations--PGT/Pacific Gas and Electric Company Pipeline Expansion"
above. The settlement also provides for rates based on a return on equity of
12.2%. Several parties are seeking rehearing of the FERC order approving the
settlement, but PG&E Gas Transmission, Northwest Corporation currently expects
the settlement to be upheld.
36
<PAGE>
PG&E CORPORATION'S INDEPENDENT POWER GENERATION OPERATIONS
Through USGen and its affiliates, PG&E Corporation participates in the
development, construction, operation, ownership, and management of non-utility
electric generating facilities that compete in the United States power
generation market. As of December 31, 1997, USGen, headquartered in Bethesda,
Maryland, and its affiliates had ownership interests in 15 operating plants in
eight states. The total generating capacity of these 15 plants is 3,249 MW.
PG&E Corporation's combined net equity ownership in these plants as of
December 31, 1997, represented 1,457 MW. The plants were largely financed with
a combination of equity or equity commitments from the project sponsors and
non-recourse debt. USGen, through its affiliate, U.S. Operating Services
Company (USOSC), provides contract operations and maintenance services to many
of these facilities. Nationwide, USGen's power plant development activities
exceed 4,400 MW in eight states. Together with its power marketing affiliate,
USGen Power Services, L.P. (now PG&E Energy Trading--Power, L.P.), USGen and
its affiliated or managed facilities sold 38.4 million megawatt-hours (MWh) of
electricity into the wholesale electric market in 1997.
In a series of transactions commencing in September 1997 and ending in
January 1998, subsidiaries of PG&E Corporation acquired Bechtel Enterprises'
interests in USGen, USOSC, and USGen Power Services, L.P. (now PG&E Energy
Trading--Power, L.P.). PG&E Corporation also acquired all or a portion of
Bechtel's interests in six independent power generating facilities which were
jointly owned by PG&E Corporation and Bechtel, or by PG&E Corporation,
Bechtel, and various third parties.
On August 6, 1997, PG&E Corporation announced that it had agreed to acquire
a portfolio of non-nuclear electric generating assets and power supply
contracts from the New England Electric System (NEES) for $1.59 billion. These
assets will be held by an affiliate of USGen. The $1.59 billion purchase price
includes $225 million to be paid to NEES when customer choice of energy power
suppliers is broadly available in New England. This amount will decline in
accordance with a prorated schedule if the implementation of customer choice
of energy power suppliers in New England occurs after January 1, 1999. In
addition to the purchase price, NEES will also receive $85 million from USGen
or its affiliates to pay for employee retraining, early retirement, and
severance for NEES' employees affected by industry restructuring. USGen or one
of its affiliates will also assume certain existing collective bargaining
agreements between NEES and its labor unions.
Including fuel and other inventories and transaction costs, financing
requirements are expected to reach approximately $1.75 billion, of which
approximately $1 billion will be funded through a combination of project level
debt as well as debt of affiliates of USGen. In addition, up to $750 million
of equity will be contributed over two years and will be financed initially
using short-term debt of PG&E Corporation.
The NEES facilities to be acquired consist of two hydroelectric systems with
14 stations, three fossil-fuel stations with 11units, and a pumped storage
facility, with a combined generating capacity of approximately 4,000 MW. USGen
or its affiliates will also assume the purchase obligations under 23 multi-
year power purchase agreements between NEES' subsidiary, New England Power,
and other utility and non-utility wholesale suppliers representing an
additional 1,100 MW of production capacity. The terms of the acquisition call
for New England Power to make annual support payments ranging approximately
from $150 million to $170 million through early 2008 to offset the cost of
power associated with these above-market contracts. The annual payment is a
fixed obligation and is not dependent on the actual costs under the
agreements, market prices, or NEES' regulatory status.
As part of the electric industry deregulation in Massachusetts and Rhode
Island, NEES' retail customers in those states may choose to continue
receiving power from NEES (the "Standard Offer") at a fixed price or may
choose a new power supplier. NEES' retail customers may make this choice
through the year 2004 in Massachusetts and through the year 2009 in Rhode
Island. It is expected that in the first half of 1998 NEES will auction its
wholesale supply obligations under the Standard Offer to third parties. NEES'
remaining supply obligation for these customers will be assigned to USGen, or
one or more of its affiliates.
37
<PAGE>
NEES will also assign to USGen or one or more of its affiliates its rights
to supply power under several long-term power supply agreements, totaling
approximately 100 MW. The acquisition also includes 100 million cubic feet per
day of long-term natural gas supply and pipeline commitments, as well as a
twelve-year lease on a self-unloading coal transportation vessel.
PG&E Corporation's acquisition of NEES' assets, which is expected to be
completed in 1998, is subject to a number of conditions, including approval of
the FERC and state regulators.
NEES' sale of these generating facilities and power supply contracts was
prompted, in part, by the anticipated deregulation of the electric industry in
several New England states. In Massachusetts, electric industry restructuring
legislation took effect on March 1, 1998. A referendum will be voted on in
November 1998, to repeal this legislation.
The financial impact of the acquisition of the NEES assets on PG&E
Corporation is subject to a number of risks and uncertainties, including
future market prices of power in the region where the NEES assets are located,
future fuel prices, the development of a competitive market in the states in
which the NEES assets are located, the extent to which operating efficiencies
at the NEES plants can be attained, changes in legislation affecting electric
industry restructuring and in the regulatory environment in the states where
the NEES assets are located, the extent of the obligation to provide
electricity under the Standard Offer at prices below cost or market, the
extent to which a liquid, well-structured trading market develops for
wholesale electric power in the states in which the NEES assets are located,
and generating capacity expansion and retirements by others.
In the second quarter of 1997, Bechtel acquired PG&E Corporation's
partnership interest in International Generating Company, Ltd. (InterGen), a
company formed to develop, own, and operate international electric generation
projects. PG&E Corporation realized an after-tax gain of $120 million on the
sale.
38
<PAGE>
PG&E CORPORATION'S ENERGY SERVICES AND COMMODITIES
PG&E Energy Services Corporation provides gas and electric energy services
and commodities nationwide where permitted under applicable laws. PG&E Energy
Services also provides commercial, industrial, and institutional customers
with a wide range of services, including competitively priced electric and gas
commodities, billing and information management services, energy management
services, regulatory and rate analysis, and power quality solutions. PG&E
Energy Services targets primarily industrial, commercial, and institutional
customers. In 1997, PG&E Energy Services embarked on an aggressive campaign to
open new offices in the United States, primarily to support its direct sales
efforts and to establish a presence and market its services in emerging energy
markets. It now has over 20 offices nationwide.
PG&E Energy Services will compete with other non-utility electric retailers
in California when direct access begins. See "Electric Utility Operations--
Electric Industry Restructuring Legislation" above.
PG&E Energy Trading, headquartered in Houston, Texas, purchases bulk volumes
of power and natural gas from PG&E Corporation affiliates; USGen and PG&E Gas
Transmission, and from the wholesale market. PG&E Energy Trading then
schedules, transports, and resells these commodities, either directly or
through PG&E Energy Services--repackaging them to meet customers' individual
delivery, price, and reliability needs. PG&E Energy Trading also provides
price risk management services to PG&E Corporation's other businesses (except
Pacific Gas and Electric Company) and to wholesale customers. Additionally,
PG&E Energy Trading supports PG&E Energy Services Corporation with a broad
portfolio of energy products and services for the retail market.
For more information, see "Price Risk Management Programs" above.
39
<PAGE>
ENVIRONMENTAL MATTERS
ENVIRONMENTAL MATTERS
The following discussion includes certain forward-looking information
relating to estimated expenditures for environmental protection and the
possible future impact of environmental compliance. This information reflects
Pacific Gas and Electric Company's current estimates which are periodically
evaluated and revised. These estimates are subject to a number of assumptions
and uncertainties, including changing laws and regulations, the ultimate
outcome of complex factual investigations, evolving technologies, selection of
compliance alternatives, the nature and extent of required remediation, the
extent of Pacific Gas and Electric Company's responsibility, and the
availability of recoveries or contributions from third parties. Future
estimates and actual results may differ materially from those indicated below.
PG&E Corporation, Pacific Gas and Electric Company, and other PG&E
Corporation subsidiaries and affiliates, are subject to a number of federal,
state, and local laws and regulations designed to protect human health and the
environment by imposing stringent controls with regard to planning and
construction activities, land use, and air and water pollution, and, in recent
years, by governing the use, treatment, storage, and disposal of hazardous or
toxic materials. These laws and regulations affect future planning and
existing operations, including environmental protection and remediation
activities. Pacific Gas and Electric Company has undertaken major compliance
efforts with specific emphasis on its purchase, use, and disposal of hazardous
materials, the cleanup or mitigation of historic waste spill and disposal
activities, and the upgrading or replacement of the Company's bulk waste
handling and storage facilities. The costs of compliance with environmental
laws and regulations have generally been recovered in rates.
ENVIRONMENTAL PROTECTION MEASURES
Pacific Gas and Electric Company's estimated expenditures for environmental
protection are subject to periodic review and revision to reflect changing
technology and evolving regulatory requirements.With the sale of the Morro
Bay, Moss Landing, and Oakland power plants, and the planned sale of the
Contra Costa, Pittsburg, Hunters Point, Potrero, and Geysers power plants,
Pacific Gas and Electric Company no longer expects to incur significant oxides
of nitrogen (NOx) emission reduction compliance costs. See "Electric Utility
Operations--Electric Industry Restructuring Legislation--Voluntary Generation
Asset Divestiture" above.
AIR QUALITY
Pacific Gas and Electric Company's thermal electric generating plants are
subject to numerous air pollution control laws, including the California Clean
Air Act (CCAA) with respect to emissions. Pursuant to the CCAA and the Federal
Clean Air Act, three of the local air districts in which Pacific Gas and
Electric Company operates fossil-fueled generating plants have adopted final
rules that require a reduction in NOx emissions from the power plants of
approximately 90% by 2004 (with numerous interim compliance deadlines).
Following divestiture of the Company's fossil-fueled generating plants in
connection with electric industry restructuring, the new owners will bear NOx
retrofit costs. Under AB 1890, NOx retrofit costs would be eligible for
recovery as transition costs but only to the extent that those costs are found
by the CPUC to be both reasonable and necessary to maintain the unit in
operation through 2001.
The Gas Accord authorizes $42 million to be included in rates through 2002,
for gas NOx retrofit projects related to natural gas compressor stations on
Pacific Gas and Electric Company's Line 300 which delivers Southwest gas.
Other air districts are considering NOx rules which would apply to Pacific Gas
and Electric Company's other natural gas compressor stations in California.
Eventually the rules are likely to require NOx reductions of up to 80% at
these natural gas compressor stations. Pacific Gas and Electric Company
currently estimates that the total cost of complying with these rules will be
up to $34 million over four years.
40
<PAGE>
WATER QUALITY
Pacific Gas and Electric Company's existing power plants, including Diablo
Canyon, are subject to federal and state water quality standards with respect
to discharge constituents and thermal effluents. Pacific Gas and Electric
Company's fossil-fueled power plants comply in all material respects with the
discharge constituents standards and either comply in all material respects
with or are exempt from the thermal standards. A thermal effects study at
Diablo Canyon was completed in May 1988, and was reviewed by the Central Coast
Regional Water Quality Control Board (Central Coast Board). The Central Coast
Board did not make a final decision on the report and requested that Pacific
Gas and Electric Company continue its thermal effects monitoring program. In
1995, the Central Coast Board requested that Pacific Gas and Electric Company
prepare an updated comprehensive assessment of Diablo Canyon's thermal effects
and approved a reduced environmental monitoring program. The new comprehensive
assessment is scheduled for submission to the Central Coast Board in the first
quarter of 1998. In the unlikely event that the Central Coast Board finds that
Diablo Canyon's existing thermal limits are not protective of beneficial uses
of the marine waters and that major modifications are required (e.g., cooling
towers), significant additional construction expenses could be required.
Pursuant to the federal Clean Water Act, Pacific Gas and Electric Company is
required to demonstrate that the location, design, construction, and capacity
of power plant cooling water intake structures reflect the best technology
available (BTA) for minimizing adverse environmental impacts at all existing
water-cooled thermal plants. Pacific Gas and Electric Company has submitted
detailed studies of each power plant's intake structure to various
governmental agencies. Each plant's existing water intake structure was found
to meet the BTA requirements. Pacific Gas and Electric Company is currently
preparing a new study for Diablo Canyon. The study is scheduled to be
submitted to the Central Coast Board for review in 1999. In the event that the
Central Coast Board finds that Diablo Canyon's cooling water intake structure
does not meet the BTA requirements, significant additional expenses for
construction or mitigation could be required. In addition, the promulgation or
modification of statutes, regulations, or water quality control plans, at the
federal, state, or regional level may impose increasingly stringent cooling
water discharge requirements on Pacific Gas and Electric Company power plants
in the future. Costs to comply with renewed permit conditions required to meet
any more stringent requirements that might be imposed cannot be estimated at
the present time.
Several fish species listed or proposed for listing as endangered species
may be found in the waters near Pacific Gas and Electric Company's Delta power
plants. To address the impacts of operation and maintenance activities at the
Delta plants on sensitive species, Pacific Gas and Electric Company has
developed a Habitat Conservation Plan (HCP) pursuant to the requirements of
Section 10(a) of the federal Endangered Species Act. The HCP is designed to
minimize and mitigate any incidental "take" (e.g., harassing, wounding, or
killing) of listed species that may occur from the operation, maintenance, and
repair of the power plants, in order to support the issuance of a Section
10(a) incidental take permit necessary for continued operation of the plants.
HAZARDOUS WASTE COMPLIANCE AND REMEDIATION
Pacific Gas and Electric Company assesses, on an ongoing basis, measures
that may need to be taken to comply with laws and regulations related to
hazardous materials and hazardous waste compliance and remediation activities.
Pacific Gas and Electric Company has a comprehensive program to comply with
the many hazardous waste storage, handling, and disposal requirements
promulgated by the United States Environmental Protection Agency (EPA) under
the Resource Conservation and Recovery Act and the Comprehensive Environmental
Response, Compensation, and Liability Act (CERCLA), along with California's
hazardous waste laws and other environmental requirements.
One part of this program is aimed at assessing whether and to what extent
remedial action may be necessary to mitigate potential hazards posed by
certain disposal sites and retired manufactured gas plant sites. During their
operation, manufactured gas plants produced lampblack and tar residues,
byproducts of a process that Pacific Gas and Electric Company, its predecessor
companies, and other utilities used as early as the 1850s to manufacture gas
from coal and oil. As natural gas became widely available (beginning about
1930), Pacific Gas
41
<PAGE>
and Electric Company's manufactured gas plants were removed from service. The
residues which may remain at some sites contain chemical compounds which now
are classified as hazardous. Pacific Gas and Electric Company has identified
and reported to federal and California environmental agencies 96 manufactured
gas plant sites which operated in Pacific Gas and Electric Company's service
territory. Pacific Gas and Electric Company owns all or a portion of 29 of
these manufactured gas plant sites. Pacific Gas and Electric Company has a
program, in cooperation with environmental agencies, to evaluate and take
appropriate action to mitigate any potential health or environmental hazards
at sites which the Company owns. Pacific Gas and Electric Company currently
estimates that this program may result in expenditures of approximately $8
million to $11 million over the period 1998 through 1999. The full long-term
costs of the program cannot be determined accurately until a closer study of
each site has been completed. It is expected that expenses will increase as
remedial actions related to these sites are approved by regulatory agencies or
if Pacific Gas and Electric Company is found to be responsible for cleanup at
sites it does not currently own.
Pacific Gas and Electric Company has been designated as a potentially
responsible party (PRP) under the California Hazardous Substance Account Act
(California Superfund) with respect to several manufactured gas plant sites.
In addition to the manufactured gas plant sites, Pacific Gas and Electric
Company may be required to take remedial action at certain other disposal
sites if they are determined to present a significant threat to human health
and the environment because of an actual or potential release of hazardous
substances. Pacific Gas and Electric Company has been designated as a PRP
under CERCLA (the federal Superfund law) with respect to the Purity Oil Sales
site in Malaga, California, the Jibboom Junkyard site in Sacramento,
California, the Industrial Waste Processing site near Fresno, California, and
the Lorentz Barrel and Drum site in San Jose, California. The Purity Oil Sales
site is a former used oil recycling facility at which Pacific Gas and Electric
Company is one of nine PRPs named in an EPA order requiring groundwater
remediation at the site. Pacific Gas and Electric Company has also entered
into an Administrative Order with the EPA to address soil contamination at the
site. With respect to the Casmalia site near Santa Maria, California, Pacific
Gas and Electric Company and several other generators of waste sent to the
site have entered into a court-approved agreement with the EPA that requires
these generators to perform certain site investigation and mitigation
measures, and provides a release from liability for certain other site cleanup
obligations. Although Pacific Gas and Electric Company has not been formally
designated a PRP with respect to the Geothermal Incorporated site in Lake
County, California, the Central Valley Regional Water Quality Control Board
and the California Attorney General's office have directed Pacific Gas and
Electric Company and other parties to initiate measures with respect to the
study and remediation of that site.
In addition to the sites discussed above, Pacific Gas and Electric Company
has also been identified as a PRP at certain disposal sites under the
California Superfund. Pacific Gas and Electric Company has also been sued for
reimbursement of cleanup costs incurred by the State of California at Pacific
Gas and Electric Company's former Jibboom Street Station B power plant in
Sacramento, California. In addition, Pacific Gas and Electric Company has been
named as a defendant in several civil lawsuits in which plaintiffs allege that
the Company is responsible for performing or paying for remedial action at
sites the Company no longer owns or never owned.
The cost of hazardous substance remediation ultimately undertaken by Pacific
Gas and Electric Company is difficult to estimate. It is reasonably possible
that a change in the estimate will occur in the near term due to uncertainty
concerning Pacific Gas and Electric Company's responsibility, the complexity
of environmental laws and regulations, and the selection of compliance
alternatives. Pacific Gas and Electric Company had an accrued liability at
December 31, 1997, of $232 million for hazardous waste remediation costs at
those sites, including fossil-fueled power plants, where such costs are
probable and quantifiable. Environmental remediation at identified sites may
be as much as $442 million if, among other things, other PRPs are not
financially able to contribute to these costs or further investigation
indicates that the extent of contamination or necessary remediation is greater
than anticipated at sites for which Pacific Gas and Electric Company is
responsible. This upper limit of the range of costs was estimated using
assumptions least favorable to Pacific Gas and Electric
42
<PAGE>
Company based upon a range of reasonably possible, outcomes. Costs may be
higher if Pacific Gas and Electric Company is found to be responsible for
cleanup costs at additional sites or identifiable possible outcomes change.
POTENTIAL RECOVERY OF HAZARDOUS WASTE COMPLIANCE AND REMEDIATION COSTS
In 1994, the CPUC established a ratemaking mechanism for hazardous waste
remediation costs (HWRC). That mechanism assigns 90% of the includable
hazardous substance cleanup costs to utility ratepayers and 10% to utility
shareholders, without a reasonableness review of such costs or of underlying
activities. However, under the proposed mechanism, utilities will have the
opportunity to recover the shareholder portion of the cleanup costs from
insurance carriers. Under the mechanism, 70% of the ratepayer portion of
Pacific Gas and Electric Company's cleanup costs is attributed to its gas
department and 30% is attributed to its electric department. Pacific Gas and
Electric Company can seek to recover hazardous substance cleanup costs under
the new mechanism in the rate proceeding it deems most appropriate.
In connection with electric industry restructuring, the HWRC mechanism may
no longer be used to recover electric generation-related clean-up costs for
contamination caused by events occurring after January 1, 1998.
Pacific Gas and Electric Company will retain liability for certain required
environmental remediation of pre-closing soil or groundwater contamination for
fossil and geothermal generation facilities which are sold in connection with
electric industry restructuring. In 1997, the CPUC approved Pacific Gas and
Electric Company's proposal, with respect to certain generation plants to be
divested, to prepare a forecast of environmental remediation costs for plants
to be divested and use the forecast to adjust the current plant
decommissioning cost estimate which will be recovered through the CTC
ratemaking mechanism. Pacific Gas and Electric Company's revised estimate of
costs to remediate environmental contamination for which it will remain liable
at the Morro Bay, Moss Landing, and Oakland power plant is $39 million.
Pacific Gas and Electric Company expects to recover $157 million of the $232
million accrued liability, discussed above, in future rates. The liability
also includes $58 million related to power plant decommissioning for
environmental clean-up, which is recovered through depreciation. Additionally,
Pacific Gas and Electric Company is seeking recovery of costs from insurance
carriers and from other third parties.
In 1992, Pacific Gas and Electric Company filed a complaint in San Francisco
County Superior Court against more than 100 of its domestic and foreign
insurers, seeking damages and declaratory relief for remediation and other
costs associated with hazardous waste mitigation. Pacific Gas and Electric
Company had previously notified its insurance carriers that it seeks coverage
under its comprehensive general liability policies to recover costs incurred
at certain specified sites. In general, Pacific Gas and Electric Company's
carriers neither admitted nor denied coverage, but requested additional
information from the Company. Although Pacific Gas and Electric Company has
received some amounts in settlements with certain of its insurers
(approximately $55 million through December 31, 1997), the ultimate amount of
recovery from insurance coverage, either in the aggregate or with respect to a
particular site, cannot be quantified at this time.
COMPRESSOR STATION LITIGATION
Several cases have been brought against Pacific Gas and Electric Company
seeking damages from alleged chromium contamination at the Company's Hinkley,
Topock, and Kettleman Compressor Stations. See Item 3, "Legal Proceedings--
Compressor Station Chromium Litigation" below, for a description of the
pending litigation.
ELECTRIC AND MAGNETIC FIELDS
In January 1991, the CPUC opened an investigation into potential interim
policy actions to address increasing public concern, especially with respect
to schools, regarding potential health risks which may be associated with
electric and magnetic fields (EMF) from utility facilities. In its order
instituting the investigation, the CPUC acknowledged that the scientific
community has not reached consensus on the nature of any health impacts from
43
<PAGE>
contact with EMF but went on to state that a body of evidence has been
compiled which raises the question of whether adverse health impacts might
exist.
In November 1993, the CPUC adopted an interim EMF policy for California
energy utilities which, among other things, requires California energy
utilities to take no-cost and low-cost steps to reduce EMF from new and
upgraded utility facilities. California energy utilities are required to fund
a $1.5 million EMF education program and a $5.6 million EMF research program
managed by the California Department of Health Services.
As part of its effort to educate the public about EMF, Pacific Gas and
Electric Company provides interested customers with information regarding the
EMF exposure issue. Pacific Gas and Electric Company also provides a free
field measurement service to inform customers about EMF levels at different
locations in and around their residences or commercial buildings.
Pacific Gas and Electric Company and other utilities are involved in
litigation concerning EMF. In August 1996, the California Supreme Court held
that homeowners are barred from suing utilities for alleged property value
losses caused by fear of EMF from power lines. The Court expressly limited its
holding to property value issues, leaving open the question as to whether
lawsuits for alleged personal injury resulting from exposure to EMF are
similarly barred. Pacific Gas and Electric Company is a defendant in civil
litigation in which plaintiffs allege personal injuries resulting from
exposure to EMF. In January 1998, the appeals court in this matter held that
the CPUC has exclusive jurisdiction over personal injury and wrongful death
claims arising from allegations of harmful exposure to EMF, and barring
plaintiffs' personal injury claims. Plaintiffs have filed an appeal of this
decision with the California Supreme Court.
In the event that the scientific community reaches a consensus that EMF
presents a health hazard and further determines that the impact of utility-
related EMF exposures can be isolated from other exposures, Pacific Gas and
Electric Company may be required to take mitigation measures at its
facilities. The costs of such mitigation measures cannot be estimated with any
certainty at this time. However, such costs could be significant depending on
the particular mitigation measures undertaken, especially if relocation of
existing power lines is ultimately required.
LOW EMISSION VEHICLE PROGRAMS
In December 1995, the CPUC issued its decision in the Low Emission Vehicle
(LEV) proceeding which approved approximately $36 million in funding for
Pacific Gas and Electric Company's LEV program for the six-year period
beginning in 1996. The CPUC's decision on electric industry restructuring
finds that the costs of utility LEV programs should continue to be collected
by the utility for the duration of the six-year period. Pacific Gas and
Electric Company continues to run its LEV program as funded.
ITEM 2. PROPERTIES.
Information concerning Pacific Gas and Electric Company's electric
generation units, gas transmission facilities, and electric and gas
distribution facilities is included in response to Item 1. All real properties
and substantially all personal properties of Pacific Gas and Electric Company
are subject to the lien of an indenture which provides security to the holders
of Pacific Gas and Electric Company's First and Refunding Mortgage Bonds.
Information concerning properties and facilities owned by other PG&E
Corporation subsidiaries is included in the discussion under the headings of
this report entitled "PG&E Corporation's Gas Transmission Operations," "PG&E
Corporation's Independent Power Generation Operations," and "PG&E
Corporation's Energy Services and Commodities."
ITEM 3. LEGAL PROCEEDINGS.
See Item 1, Business, for other proceedings pending before governmental and
administrative bodies. In addition to the following legal proceedings, PG&E
Corporation and Pacific Gas and Electric Company are subject to routine
litigation incidental to their business.
44
<PAGE>
COMPRESSOR STATION CHROMIUM LITIGATION
Pacific Gas and Electric Company has been named as a defendant in several
civil actions filed in California courts on behalf of more than 3,000
plaintiffs, and claims by approximately 2,800 plaintiffs are still pending.
These cases are Aguayo v. Betz, Pacific Gas and Electric Company, et al.,
filed March 15, 1995, in Los Angeles County Superior Court; Aguilar v. Pacific
Gas and Electric Company, Betz, et al., filed October 4, 1996, in Los Angeles
County Superior Court; Adams v. Betz, filed September 21, 1994, in Los Angeles
County Superior Court; Acosta, et al. v. Betz, Pacific Gas and Electric
Company, et al., filed November 27, 1996, in Los Angeles Superior Court; Riep,
et al. v. Pacific Gas and Electric Company, Betz, et al., filed February 14,
1997, in San Francisco Superior Court; Petitt, et al. v. Pacific Gas and
Electric Company, Betz, et al., filed May 6, 1997, in Los Angeles Superior
Court; Little and Mustafa v. Pacific Gas and Electric Company and PG&E
Corporation, filed September 10, 1997, in San Bernardino Superior Court; and
Whipple, et al. v. Pacific Gas and Electric Company and PG&E Corporation,
filed September 10, 1997, in San Bernardino Superior Court. (Plaintiffs have
agreed to dismiss PG&E Corporation in these last two suits.) These eight cases
are collectively referred to as the "Aguayo Litigation."
Each of the complaints in the Aguayo Litigation, except Little described
below, alleges personal injuries and seeks compensatory and punitive damages
in an unspecified amount arising out of alleged exposure to chromium
contamination in the vicinity of Pacific Gas and Electric Company's gas
compressor stations at Kettleman, Hinkley and Topock, California. The
plaintiffs in the Aguayo Litigation include Pacific Gas and Electric Company
employees, former Pacific Gas and Electric Company employees, relatives of
Pacific Gas and Electric Company employees or former employees, residents in
the vicinity of the compressor stations, and persons who visited the gas
compressor stations, alleging exposure to chromium at or near the compressor
stations. The plaintiffs also include spouses or children of these plaintiffs
who claim only loss of consortium or injury through the alleged exposure of
their parents.
In the Adams case, the claims remaining against Pacific Gas and Electric
Company arise from a cross-claim filed by Betz Chemical Company, the supplier
of water treatment products containing chromium used at the gas compressor
stations.
In the Whipple case, pending in San Bernardino Superior Court, plaintiffs,
four members of one family, allege personal injuries, injury to a business
enterprise, and injury to real property based upon causes of action for (1)
actual fraud and deceit, (2) negligence, (3) negligence per se, (4) strict
liability, (5) battery, (6) intentional misrepresentation, (7) negligent
misrepresentation, (8) fraudulent concealment, and (9) intentional spoliation
of evidence. In the Little case, also pending in San Bernardino Superior
Court, two plaintiffs allege injury to real property based upon causes of
action for (1) actual fraud and deceit, (2) negligence, and (3) negligence per
se. Plaintiffs in each action are seeking unspecified compensatory and
punitive damages, as well as civil penalties pursuant to Proposition 65.
All discovery and discovery motion practice in four of the five cases
brought in Los Angeles Superior Court (Acosta v. Betz, Aguilar v. Pacific Gas
and Electric Company, Aguayo v. Pacific Gas and Electric Company, and Adams v.
Betz) has been referred by the judge to a discovery referee. Test plaintiffs
have been chosen in the Aguayo matter, and discovery is ongoing. During 1997,
more than 300 plaintiffs were dismissed from Aguayo v. Pacific Gas and
Electric Company for failure to respond to discovery or otherwise pursue their
claims. Discovery is beginning in the Acosta and Aguilar matters. Pacific Gas
and Electric Company has a motion for good faith settlement pending in the
Adams matter, as that case involves the same plaintiffs as a matter that
Pacific Gas and Electric Company previously settled. The fifth case brought in
Los Angeles Superior Court by eight plaintiffs (Pettit v. Pacific Gas and
Electric Company) was not served on Pacific Gas and Electric Company until
December 1997, and Pacific Gas and Electric Company filed an answer in January
1998.
In Riep v. Pacific Gas and Electric Company, pending in San Francisco
Superior Court, a trial date has been set for August 3, 1998.
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Pacific Gas and Electric Company is responding to the complaints and
asserting affirmative defenses. Pacific Gas and Electric Company will pursue
appropriate legal defenses including statute of limitations, inability of
certain plaintiffs to state a claim for alleged preconception exposure, or
exclusivity of workers' compensation laws, and factual defenses including lack
of exposure to chromium and the inability of chromium to cause certain of the
illnesses alleged. At this stage of the proceedings, there is substantial
uncertainty concerning the claims alleged, and Pacific Gas and Electric
Company is attempting to gather information concerning the alleged type and
duration of exposure, the nature of injuries alleged by individual plaintiffs,
and the additional facts necessary to support its legal defenses, in order to
better evaluate and defend this litigation.
PG&E Corporation believes that the ultimate outcome of this matter will not
have a material adverse impact on its or Pacific Gas and Electric Company's
financial position or results of operations.
TEXAS FRANCHISE FEE LITIGATION
In connection with PG&E Corporation's acquisition of Valero Energy
Corporation, now known as PG&E Gas Transmission, Texas Corporation (GTT), PG&E
Corporation entities succeeded to the litigation described below.
City of San Benito, City of Primera, and City of Port Isabel v. Rio Grande
Valley Gas Company, Valero Energy Corporation (now known as GTT), Southern
Union Company, et al., 107th State District Court, Cameron County, Texas.
On December 31, 1996, a petition was filed by the Texas cities of San
Benito, Primera, and Port Isabel against Rio Grande Valley Gas Company (RGVG),
Valero (now known as PG&E Gas Transmission, Texas Corporation), Valero Natural
Gas Company (now known as PG&E Texas Natural Gas Company), Reata Industrial
Gas Company (now known as Valero Gas Marketing Company), Reata Industrial Gas
L.P. (now known as PG&E Reata Energy, L.P.), Valero Transmission L.P. (now
known as PG&E Texas Pipeline, L.P.), and Valero Transmission Company (now
known as VT Company), and two Southern Union entities: Southern Union Company
("SU") and Mercado Gas Services, Inc. On November 4, 1997, the cities of San
Benito, Primera, and Port Isabel filed an amended petition and an amended
motion for class action certification, and dismissed RGVG and the other SU
entities. The amended petition named as defendants PG&E Gas Transmission,
Texas Corporation and most of its subsidiaries (excluding the Canadian gas
trading company and power trading company), PG&E Gas Transmission Teco, Inc.
and most of its subsidiaries, and PG&E Energy Trading Corporation.
In the amended petition, plaintiffs allege, among other things, that (1) the
defendants that own or operate pipelines (in their capacities as merchants or
transporters) have occupied city property and conducted pipeline operations
without the cities' consent and without compensating the cities for use of the
cities' properties and (2) the defendants that are gas marketers have failed
to pay cities for accessing and utilizing pipelines located in the cities to
flow gas under city streets to end-use gas customers. The petition also
alleges various tort and statutory claims against defendants for failure to
secure the consents.
On November 5, 1997, orders were signed certifying a class, setting an opt
out deadline of December 31, 1997, and ordering notice to all potential class
members. The class certified consists of every incorporated municipality in
Texas (excepting the cities of Edinburg, Mercedes, and Weslaco, which have
filed separate actions) where any of the defendants engaged in business
activities related to natural gas or natural gas liquids. The court named the
cities of San Benito, Primera, and Port Isabel as class representatives. Fewer
than 20 cities had opted out by the deadline. Some of the cities which opted
out include Austin, Brownsville, Houston, Pharr, and San Antonio. One
purported class member has filed a notice to vacate the class certified.
Defendants' motion to transfer venue of this case to Bexar County, Texas, is
currently pending.
City of Edinburg v. Rio Grande Valley Gas Co., Valero Energy Corporation
(now known as GTT), Valero Natural Gas Company (now known as PG&E Texas
Natural Gas Company), Southern Union Gas Co., and Southern Union Gas Co., 92nd
State District Court, Hidalgo County, Texas.
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<PAGE>
On August 31, 1995, the City of Edinburg (City) filed a lawsuit against
certain Valero and Southern Union companies. The City's pleadings assert
various contract and tort actions, but all such claims are based on the theory
that when Rio Grande Valley Gas Company (RGVG), as the local distribution
company (LDC), was granted a franchise to sell gas and construct, maintain,
own, and operate gas pipelines in city streets, such authorization extended to
RGVG only and to no other entity. (On September 30, 1993, Valero sold the
common stock of RGVG to Southern Union.) The City seeks monetary damages and
injunctive relief on the theory that non-LDC owned pipelines were not
authorized under the franchise with RGVG and were otherwise unlawful without
the consent of, and the payment of compensation to, the City. The City also
claims that when RGVG began to operate pipelines it did not own, such
activities were not within the franchise and not otherwise consented to by the
City. Consequently, the City contends that all non-LDC owned pipelines (which
includes all of Valero Transmission, L.P.'s (now known as PG&E Texas Pipeline,
L.P.) transmission and gathering lines in City rights-of-way) are
"trespassing," and the Valero defendants must agree to a franchise or face
removal by injunction.
Further, the City contends that it is entitled to compensation for the past
presence of such pipelines in city property without consent, and for the use
of such pipelines to facilitate the past and present sales of gas, both for
resale and to direct end-users, by any person or entity other than the LDC.
Additionally, the City contends that RGVG has breached the franchise agreement
by failing to pay all franchise fees owed because it did not include in the
"gross sales" figure such incidental revenues as bad check fees, late payment
charges, hook-up and disconnect fees, and transportation revenues. The City
seeks to assert against the Valero defendants derivative liability for all of
RGVG's acts and omissions.
The latest pleading seeks actual damages in excess of $15 million,
unspecified punitive damages, and injunctive relief against six Valero
entities: Valero Energy Corporation (now known as GTT), Valero Transmission
Company (now known as PG&E Texas Pipeline Company), Valero Natural Gas Company
(now known as PG&E Natural Gas Company), Reata Industrial Gas Company (now
known as Valero Gas Marketing Company), Valero Transmission, L.P. (now known
as PG&E Texas Pipeline, L.P.), and Reata Industrial Gas, L.P. (now known as
PG&E Reata Energy, L.P.), and two SU entities.
Trial was originally set in the Edinburg matter for September 9, 1996, but
did not commence due to the disqualification on August 21, 1996, of the
original judge. The new judge has set a jury trial for June 15, 1998.
City of Mercedes v. Reata Industrial Gas, L.P. (now known as PG&E Reata
Energy, L.P.) and Reata Industrial Gas Company (now known as Valero Gas
Marketing Company), 92nd State District Court of Hidalgo County, Texas.
A lawsuit filed by the City of Mercedes on April 16, 1997, is currently
pending against Valero Gas Marketing Company and Reata Industrial Gas, L.P.
(now known as PG&E Reata Energy, L.P.). On September 4, 1997, Mercedes amended
its petition to include class action claims and requested to be named as class
representative for a statewide class consisting of all Texas municipal
corporations, municipalities, towns, and villages, excluding the cities of
Edinburg and Weslaco (both of which filed separate actions), in which any of
the defendants have sold or supplied gas, or used public rights-of-way to
transport gas.
The defendants, gas marketers, have never owned or operated any pipelines.
Plaintiff asserts these marketing companies have operated as "ghost pipelines"
that have "used" public property without consent or franchise from the cities
in which the defendants have sold gas. Plaintiff alleges that state law
requires the defendants to have specific prior city consent by ordinance in
order to transact business within or through city limits. The plaintiff
alleges various tort and statutory claims against the defendants for failure
to secure such consent. Plaintiff has requested a damage award, but has not
specified an amount.
Defendants' motion to transfer venue to Bexar County, Texas, is currently
pending. On September 10, 1997, defendants also filed a motion to disqualify
or recuse the presiding judge of the 92nd State District Court. This motion
was granted on November 26, 1997. A new judge has not been appointed yet. If a
class is certified, defendants anticipate that they will challenge such
certification.
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Other Texas Franchise Fee Litigation
In addition to the three cases described above, involving the cities of
Edinburg, Mercedes, San Benito, Primera, and Port Isabel, there are five
lawsuits involving claims of a similar nature.
In 1996, the South Texas cities of Alton and Donna also independently
intervened as plaintiffs in the Edinburg lawsuit filed in the 92nd State
District Court in Hidalgo County. Subsequently, in July 1996, these lawsuits
were severed from the Edinburg lawsuit. The claims asserted by the cities of
Alton and Donna are substantially similar to the Edinburg litigation claims.
Damages are not quantified.
In December 1996, two additional lawsuits were filed in South Texas making
allegations substantially similar to those in the City of Edinburg litigation:
City of La Joya v. Rio Grande Valley Gas Company, Valero Energy Corporation,
Southern Union Company, et al., 92nd State District Court, Hidalgo County,
Texas (filed December 27, 1996), and City of San Juan, City of La Villa, City
of Penitas, City of Edcouch, and City of Palmview v. Rio Grande Valley Gas
Company, Valero Energy Corporation, Southern Union Company, et al., 93rd State
District Court, Hidalgo County, Texas (filed December 27, 1996).
The City of La Joya filed its lawsuit on its own behalf and as a putative
class representative on behalf of all similarly situated cities against the
same defendants sued in the Edinburg case. The same Southern Union entities in
the Edinburg suit have also been named in this suit.
The factual allegations and claims asserted in the lawsuit filed by the city
of La Joya, and in the lawsuit filed by the cities of San Juan, Lavilla,
Penitas, Edcouch, and Palmview, are similar to the claims made in the lawsuit
filed by the cities of San Benito, Primera, and Port Isabel. Defendants'
motion to transfer venue of both cases to Bexar County, Texas, is also
currently pending.
Finally, on April 17, 1997, a petition was filed by the South Texas city of
Weslaco. (City of Weslaco v. Reata Industrial Gas, L.P., et al., 92nd State
District Court, Hidalgo County, Texas). Weslaco sued Valero Natural Gas
Company (now known as PG&E Texas Natural Gas Company), Reata Industrial Gas
Company (now known as Valero Gas Marketing Company), and Reata Industrial Gas,
L.P. (now known as PG&E Reata Energy L.P.) The causes of action alleged are
identical to those alleged in the City of Mercedes case. Defendants' motion to
transfer venue to Bexar County, Texas is currently pending. Defendants have
also filed a motion to disqualify or recuse the presiding judge, which is also
pending.
In 1996, the Texas city of Pharr sought and obtained class certification in
a lawsuit styled City of Pharr, on behalf of itself and other Similarly
Situated Entities v. Rio Grande Valley Gas Company, et al, 92nd Judicial
District Court, Hidalgo County, Texas. By definition, the Pharr class consists
only of those Texas cities, excluding Edinburg and McAllen, that have, or have
had, natural gas franchises with RGVG or SU. The Pharr class was certified as
to only two claims: breach of contract and declaratory relief dealing with the
rights, status and legal relationship between plaintiff, the class members and
the LDC regarding payment of franchise fees and use of granted easements. On
December 30, 1997, the Pharr class certification order was affirmed on
interlocutory appeal. In conjunction with this appeal, the appellate court
specifically considered whether any of the Valero entities (now PG&E Gas
Transmission, Texas Corporation entities) is a party to the Pharr class action
and expressly found that such entities are not parties to that class action.
Recently, however, Pharr class counsel has represented to various Texas courts
that these entities were added to the Pharr class action as of December 9,
1997. As of February 25, 1998, none of these entities has been formally served
in the Pharr class action, nor has counsel to these entities been furnished
with a copy of the pleadings. However, the court's docket sheet shows a
supplemental pleading was filed on or about December 12, 1997, which purports
to add as defendants to the Pharr class action the same twenty-nine PG&E
Corporation entities that are defendants in the San Benito litigation
described above. The PG&E Corporation entities intend to defend vigorously
against any attempt to add them as defendants in the Pharr class action, as
well as against any attempt to modify the Pharr class definition in an effort
to assert claims against the PG&E Corporation entities.
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PG&E Corporation believes that the ultimate outcome of the Texas franchise
fee cases described above will not have a material adverse impact on its
financial position.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
Not applicable.
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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 1997 POSITION
---- ------------ --------
<C> <C> <S>
R. D. Glynn, Jr...... 55 Chairman of the Board, Chief Executive
Officer, and President
S. W. Gebhardt....... 46 Senior Vice President, President and
Chief Executive Officer, PG&E Energy
Services Corporation
T. W. High........... 50 Senior Vice President, Administration and
External Relations
J. F. Jenkins-Stark.. 46 Senior Vice President, President and
Chief Executive Officer, PG&E Gas
Transmission Corporation
J. P Kearney......... 49 Senior Vice President, President and
Chief Executive Officer, U.S. Generating
Company
L. E. Maddox......... 42 Senior Vice President, President and
Chief Executive Officer, PG&E Energy
Trading Corporation
M. E. Rescoe......... 45 Senior Vice President, Chief Financial
Officer, and Treasurer
G. R. Smith.......... 49 President and Chief Executive Officer,
Pacific Gas and Electric Company
G. B. Stanley........ 51 Senior Vice President, Human Resources
B. R. Worthington.... 48 Senior Vice President and General Counsel
</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
J. F. Jenkins-Stark.. Senior Vice President June 1, 1997 to current
President and Chief June 1, 1997 to current
Executive Officer, PG&E
Gas Transmission
Corporation
</TABLE>
50
<PAGE>
<TABLE>
<CAPTION>
NAME POSITION PERIOD HELD OFFICE
---- -------- ------------------
<C> <S> <C>
Senior Vice President August 1, 1993 to May 30, 1997
and General Manager,
Gas Supply Business
Unit, Pacific Gas and
Electric Company
Vice President and January 15, 1992 to July 31, 1993
Treasurer, Pacific Gas
and Electric Company
J. P. Kearney........ Senior Vice President September 1997 to current
President and Chief February 1989 to current
Executive Officer, U.S.
Generating Company
L. E. Maddox......... Senior Vice President June 1, 1997 to current
President and Chief June 1, 1997 to current
Executive Officer, PG&E
Energy Trading
Corporation
President, PennUnion May 1995 to May 1997
Energy Services, L.L.C.
President, Brooklyn January 1993 to May 1995
Interstate Natural Gas
Corp.
M. E. Rescoe......... Senior Vice President, January 1, 1998 to current
Chief Financial
Officer, and Treasurer
Senior Vice President September 1, 1997 to December 31, 1997
and Chief Financial
Officer
Executive Vice August 11, 1997 to August 31, 1997
President, Strategic
Planning and Corporate
Development, Texas
Utilities Company
Senior Vice President, July 1995 to August 10, 1997
Chief Financial
Officer, Enserch Corp.
(gas and power)
Senior Managing July 1992 to July 1995
Director, Bear, Stearns
& Co., Inc. (investment
bankers)
G. R. Smith.......... (Please refer to
description of business
experience for
executive officers of
Pacific Gas and
Electric Company,
below.)
G. B. Stanley........ Senior Vice President, January 1, 1998 to current
Human Resources
Vice President, Human June 1, 1997 to December 31, 1997
Resources
Vice President, Human July 1, 1996 to May 31, 1997
Resources, Pacific Gas
and Electric Company
Self-employed (human January 1995 to June 1996
resources consultant)
Senior Vice President, January 1992 to December 1994
Human Resources, The
Gap, Inc. (retail
clothing)
Senior Vice President
B. R. Worthington.... and General Counsel June 1, 1997 to current
General Counsel December 18, 1996 to May 31, 1997
Senior Vice President
and General Counsel,
Pacific Gas and
Electric Company June 1, 1995 to June 30, 1997
Vice President and
General Counsel,
Pacific Gas and
Electric Company December 21, 1994 to May 31, 1995
Chief Counsel-Corporate,
Pacific Gas and
Electric Company January 10, 1991 to December 20, 1994
</TABLE>
"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 1997 POSITION
---- ------------ --------
<C> <C> <S>
G. R. Smith.......... 49 President and Chief Executive Officer
K. M. Harvey......... 39 Senior Vice President, Chief Financial
Officer and Treasurer
E. J. Macias......... 43 Senior Vice President and General
Manager, Generation, Transmission, and
Supply Business Unit
R. J. Peters......... 47 Vice President and General Counsel
J. K. Randolph....... 53 Senior Vice President and General
Manager, Distribution and Customer
Service Business Unit
D. D. Richard, Jr.... 47 Senior Vice President, Governmental and
Regulatory Relations
G. M. Rueger......... 47 Senior Vice President and General
Manager, Nuclear Power Generation
Business Unit
</TABLE>
51
<PAGE>
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>
52
<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 60 under the heading
"Quarterly Consolidated Financial Data (Unaudited)" in the 1997 Annual Report
to Shareholders, which information is hereby incorporated by reference and
filed as part of Exhibit 13 to this report.
Pacific Gas and Electric Company has made no sales of unregistered equity
securities in the last three years. PG&E Corporation has made the following
sales of unregistered equity securities during such period:
On January 27, 1997, PG&E Corporation issued 14,607,143 shares of common
stock. The shares were issued to nine former shareholders of Teco in
connection with the acquisition of Teco by PG&E Corporation. PG&E
Corporation owns all the outstanding shares of Teco as a result of the
acquisition. The shares were issued in reliance upon the exemption from
registration under the Securities Act of 1933, as amended, pursuant to
Section 4(2) thereof and Rule 506 of Regulation D thereunder. All of the
former shareholders of Teco represented that they were "accredited
investors" as defined in Rule 501(a) under the Securities Act of 1933 and
made other representations establishing the basis for the exemption. A
legend as provided for by Rule 501(d)(3) was placed on each of the stock
certificates representing the shares of PG&E Corporation common stock
received by the former shareholders of Teco.
ITEM 6. SELECTED FINANCIAL DATA.
A summary of selected financial information for each of PG&E Corporation and
Pacific Gas and Electric Company for each of the last five fiscal years is set
forth on page 16 under the heading "Selected Financial Data" in the 1997
Annual Report to Shareholders, which information is hereby incorporated by
reference and filed as part of Exhibit 13 to this report.
Pacific Gas and Electric Company's earnings to fixed charges ratio for the
year ended December 31, 1997, was 3.19. Pacific Gas and Electric Company's
earnings to combined fixed charges and preferred stock dividends ratio for the
year ended December 31, 1997, was 2.96. The statement of the foregoing ratios,
together with the statements of the computation of the foregoing ratios filed
as Exhibits 12.1 and 12.2 hereto, are included herein for the purpose of
incorporating such information and exhibits into Registration Statement Nos.
33-62488, 33-64136, 33-50707, and 33-61959, relating Pacific Gas and Electric
Company's various classes of debt and first preferred stock outstanding.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS.
A discussion of PG&E Corporation's and Pacific Gas and Electric Company's
consolidated results of operations and financial condition is set forth on
pages 17 through 30 under the heading "Management's Discussion and Analysis of
Consolidated Results of Operations and Financial Condition" in the 1997 Annual
Report to Shareholders, which discussion is hereby incorporated by reference
and filed as part of Exhibit 13 to this report.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
Information concerning PG&E Corporation's and Pacific Gas and Electric
Company's market risk is set forth on page 28 in the table providing
information about debt obligations and rate reduction bonds under the heading
"Cash Flows From Financing Activities--Utility," and on page 30 under the
heading "Price Risk Management" in the 1997 Annual Report to Shareholders,
which discussion is hereby incorporated by reference and filed as part of
Exhibit 13 to this report.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
Information responding to Item 8 is contained in the 1997 Annual Report to
Shareholders on pages 31 through 61 under the respective headings for each of
PG&E Corporation and Pacific Gas and Electric Company, "Statement of
Consolidated Income," "Consolidated Balance Sheet," "Statement of Consolidated
Cash Flows," "Statement
53
<PAGE>
of Consolidated Common Stock Equity, Preferred Stock, and Preferred
Securities," "Notes to Consolidated Financial Statements," "Quarterly
Consolidated Financial Data (Unaudited)," and "Report of Independent Public
Accountants," which information is hereby incorporated by reference and filed
as part of Exhibit 13 to this report.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE.
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
Information regarding executive officers of PG&E Corporation and Pacific Gas
and Electric Company is included in a separate item captioned "Executive
Officers of the Registrant" contained on pages 50 through 52 in Part I of this
report. Other information responding to Item 10 is included on pages 2 through
5 under the heading "Election of Directors of PG&E Corporation and Pacific Gas
and Electric Company" and page 35 under the heading "Section 16(a) Beneficial
Ownership Reporting Compliance" in the 1998 Joint Proxy Statement relating to
the 1998 Annual Meetings of Shareholders, which information is hereby
incorporated by reference.
ITEM 11. EXECUTIVE COMPENSATION.
Information responding to Item 11, for each of PG&E Corporation and Pacific
Gas and Electric Company, is included on page 8 under the heading
"Compensation of Directors" and on pages 28 through 33 under the heading
"Executive Compensation" (excluding the sections thereunder entitled
"Nominating and Compensation Committee Report on Compensation," "Comparison of
One-Year Total Shareholder Return," and "Comparison of Five-Year Cumulative
Total Shareholder Return") in the 1998 Joint Proxy Statement relating to the
1998 Annual Meetings of Shareholders, which information is hereby incorporated
by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
Information responding to Item 12, for each of PG&E Corporation and Pacific
Gas and Electric Company, is included on pages 10 and 11 under the heading
"Security Ownership of Management" and on page 34 under the heading "Principal
Shareholders" in the 1998 Joint Proxy Statement relating to the 1998 Annual
Meetings of Shareholders, which information is hereby incorporated by
reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
Information responding to Item 13, for each of PG&E Corporation and Pacific
Gas and Electric Company, is included on page 9 under the heading "Certain
Relationships and Related Transactions" in the 1998 Joint Proxy Statement
relating to the 1998 Annual Meetings of Shareholders, which information is
hereby incorporated by reference.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K.
(A) THE FOLLOWING DOCUMENTS ARE FILED AS A PART OF THIS REPORT:
1. The following consolidated financial statements, supplemental
information, and report of independent public accountants contained
in the 1997 Annual Report to Shareholders, are incorporated by
reference in this report:
Statements of Consolidated Income for the Years Ended December 31,
1997, 1996, and 1995, for each of PG&E Corporation and Pacific Gas
and Electric Company.
54
<PAGE>
Statements of Consolidated Cash Flows for the Years Ended December
31, 1997, 1996, and 1995, for each of PG&E Corporation and Pacific
Gas and Electric Company.
Consolidated Balance Sheets at December 31, 1997, and 1996, for each
of PG&E Corporation and Pacific Gas and Electric Company.
Statements of Consolidated Common Stock Equity, Preferred Stock and
Preferred Securities for the Years Ended December 31, 1997, 1996,
and 1995, for each of PG&E Corporation and Pacific Gas and Electric
Company.
Notes to Consolidated Financial Statements.
Quarterly Consolidated Financial Data (Unaudited).
Report of Independent Public Accountants.
2. Report of Independent Public Accountants included at page 60 of this
Form 10-K.
3. Consolidated financial statement schedules:
I--Condensed Financial Information of Parent for the Year Ended
December 31, 1997.
II--Consolidated Valuation and Qualifying Accounts of PG&E
Corporation and Pacific Gas and Electric Company for the Years
Ended December 31, 1997, 1996 and 1995.
Schedules not included are omitted because of the absence of conditions
under which they are required or because the required information is provided
in the consolidated financial statements including the notes thereto.
4. Exhibits required to be filed by Item 601 of Regulation S-K:
3.1 Restated Articles of Incorporation of PG&E Corporation
effective as of December 19, 1996 (PG&E Corporation's Form 8-B
(File No. 1-12609), Exhibit 3.1).
3.2 By-Laws of PG&E Corporation effective as of January 1, 1998.
3.3 Restated Articles of Incorporation of Pacific Gas and Electric
Company effective as of April 28, 1997 (Pacific Gas and
Electric Company's Form 10-Q for quarter ended June 30, 1997
(File No. 1-2348), Exhibit 3.1).
3.4 By-Laws of Pacific Gas and Electric Company as of January 1,
1998.
4. First and Refunding Mortgage of Pacific Gas and Electric
Company dated December 1, 1920, and supplements thereto dated
April 23, 1925, October 1, 1931, March 1, 1941, September 1,
1947, May 15, 1950, May 1, 1954, May 21, 1958, November 1,
1964, July 1, 1965, July 1, 1969, January 1, 1975, June 1,
1979, August 1, 1983, and December 1, 1988 (Registration No. 2-
1324, Exhibits B-1, B-2, B-3; Registration No. 2-4676, Exhibit
B-22; Registration No. 2-7203, Exhibit B-23; Registration No.
2-8475, Exhibit B-24; Registration No. 2-10874, Exhibit 4B;
Registration No. 2-14144, Exhibit 4B; Registration No. 2-22910,
Exhibit 2B; Registration No. 2-23759, Exhibit 2B; Registration
No. 2-35106, Exhibit 2B; Registration No. 2-54302, Exhibit 2C;
Registration No. 2-64313, Exhibit 2C; Registration No. 2-86849,
Exhibit 4.3; Pacific Gas and Electric Company's Form 8-K dated
January 18, 1989 (File No. 1-2348), Exhibit 4.2).
10.1 Asset Purchase Agreement by and among New England Power
Company, The Narragansett Electric Company, and USGen
Acquisition Corporation, dated as of August 5, 1997 (PG&E
Corporation's Form 10-Q for the quarter ended September 30,
1997 (File No. 1-12609, Exhibit No. 10.1). Filed only as an
exhibit to the Annual Report on Form 10-K filed by PG&E
Corporation under Commission File Number 1-12609.
10.2 The Gas Accord Settlement Agreement, together with accompanying
tables, adopted by the California Public Utilities Commission
on August 1, 1997, in Decision 97-08-055.
55
<PAGE>
*10.3 Agreement regarding certain payments between U.S. Generating
Company and Joseph Kearney. (PG&E Corporation's Form 10-Q for
the quarter ended September 30, 1997 (File No. 1-12609),
Exhibit 10.2.) Filed only as an exhibit to the Annual Report
on Form 10-K filed by PG&E Corporation under Commission File
Number 1-12609. Confidential treatment of information omitted
from this exhibit has been granted by the Commission until
December 31, 1999. Omitted information has been filed
separately with the Commission.
*10.4 PG&E Corporation Deferred Compensation Plan for Directors.
*10.5 PG&E Corporation Deferred Compensation Plan for Officers.
*10.6 The Pacific Gas and Electric Company Savings Fund Plan for
Non-Union Employees, as amended and restated effective as of
October 1, 1997.
*10.7 Short-Term Incentive Plan for Officers of Pacific Gas and
Electric Company, effective January 1, 1996 (Pacific Gas and
Electric Company's Form 10-K for fiscal year 1995 (File No. 1-
2348), Exhibit 10.7).
*10.8 The Pacific Gas and Electric Company Retirement Plan
applicable to non-union employees, as amended October 15,
1997, effective January 1, 1998.
*10.9 Supplemental Executive Retirement Plan of the Pacific Gas and
Electric Company, as amended through October 16, 1991 (Pacific
Gas and Electric Company's Form 10-K for fiscal year 1991
(File No. 1-2348), Exhibit 10.11).
*10.10 Pacific Gas and Electric Company Relocation Assistance
Program for Officers (Pacific Gas and Electric Company's Form
10-K for fiscal year 1989 (File No. 1-2348), Exhibit 10.16).
*10.11 Pacific Gas and Electric Company Executive Flexible
Perquisites Program (Pacific Gas and Electric Company's Form
10-K for fiscal year 1993 (File No. 1-2348), Exhibit 10.16).
*10.12 The Postretirement Life Insurance Plan of the Pacific Gas and
Electric Company (Pacific Gas and Electric Company's Form 10-
K for fiscal year 1991 (File No. 1-2348), Exhibit 10.16).
*10.13 PG&E Corporation Retirement Plan for Non-Employee Directors,
as amended and terminated January 1, 1998.
*10.14 Executive Compensation Insurance Indemnity in respect of
Deferred Compensation Plan for Directors, Deferred
Compensation Plan for Officers, Supplemental Executive
Retirement Plan and Retirement Plan for Non-Employee
Directors (Pacific Gas and Electric Company's Form 10-K for
fiscal year 1991 (File No. 1-2348), Exhibit 10.19).
*10.15 PG&E Corporation Long-Term Incentive Program, as amended and
restated effective as of January 1, 1998, including the PG&E
Corporation Stock Option Plan, Performance Unit Plan, and
Non-Employee Director Stock Incentive Plan.
*10.16 PG&E Corporation Executive Stock Ownership Program, effective
January 1, 1998.
- --------
* Management contract or compensatory plan or arrangement required to be
filed as an exhibit to this report pursuant to Item 14(c) of Form 10-K.
56
<PAGE>
11. Computation of Earnings Per Common Share.
12.1 Computation of Ratios of Earnings to Fixed Charges for Pacific
Gas and Electric Company.
12.2 Computation of Ratios of Earnings to Combined Fixed Charges and
Preferred Stock Dividends for Pacific Gas and Electric Company.
13. 1997 Annual Report to Shareholders of PG&E Corporation and
Pacific Gas and Electric Company (portions of the 1997 Annual
Report to Shareholders under the headings "Selected Financial
Data," "Management's Discussion and Analysis of Consolidated
Results of Operations and Financial Condition," "Report of
Independent Public Accountants," and for each of PG&E
Corporation and Pacific Gas and Electric Company, "Statement of
Consolidated Income," "Consolidated Balance Sheet," "Statement
of Consolidated Cash Flows," "Statement of Consolidated Common
Stock
Equity, Preferred Stock and Preferred Securities," "Notes to
Consolidated Financial Statements" and "Quarterly Consolidated
Financial Data (Unaudited)" included only) (except for those
portions which are expressly incorporated herein by reference,
such 1997 Annual Report to Shareholders is furnished for the
information of the Commission and is not deemed to be "filed"
herein).
21. Subsidiaries of the Registrant (incorporated by reference from
PG&E Corporation's Statement by Holding Company Claiming
Exemption from the Public Utility Holding Act of 1935 under Rule
2 by filing Form U-3A-2 dated February 27, 1998, pages 1 through
33 (File No. 1-12609).
23. Consent of Arthur Andersen LLP.
24.1 Resolutions of the Boards of Directors of PG&E Corporation and
Pacific Gas and Electric Company authorizing the execution of
the Form 10-K.
24.2 Powers of Attorney.
27.1 Financial Data Schedule for the year ended December 31, 1997,
for PG&E Corporation.
27.2 Financial Data Schedule for the year ended December 31, 1997,
for Pacific Gas and Electric Company.
The exhibits filed herewith are attached hereto (except as noted) and those
indicated above which are not filed herewith were previously filed with the
Commission as indicated and are hereby incorporated by reference. All exhibits
filed herewith or incorporated by reference are filed with respect to both
PG&E Corporation (File No. 1-12609) and Pacific Gas and Electric Company (File
No. 1-2348), unless otherwise noted. Exhibits will be furnished to security
holders of PG&E Corporation or Pacific Gas and Electric Company upon written
request and payment of a fee of $0.30 per page, which fee covers only the
registrants' reasonable expenses in furnishing such exhibits. The registrants
agree to furnish to the Commission upon request a copy of any instrument
defining the rights of long-term debt holders not otherwise required to be
filed hereunder.
(B) REPORTS ON FORM 8-K
Reports on Form 8-K(/1/) during the quarter ended December 31, 1997, and
through the date hereof:
1. October 16, 1997
Item 5. Other Events
-- Performance Incentive Plan--Year-to-Date Financial Results
57
<PAGE>
2. November 24, 1997
Item 5. Other Events
A. Electric Industry Restructuring
B. Gas Accord
3. December 19, 1997
Item 5. Other Events
A. Electric Industry Restructuring
B. CPUC Regulatory Proceedings
C. Common Stock Repurchase Authorization
4. January 22, 1998 (As amended by Form 8-K/A dated February 5, 1998.)
Item 5. Other Events
A. Performance Incentive Plan--Year-to-Date Financial Results
B. 1997 Consolidated Earnings (unaudited)
C. Accelerated Stock Repurchase Program
- --------
(1) Unless otherwise noted, all reports were filed under Commission File
Number 1-2348 (Pacific Gas and Electric Company) and Commission File
Number 1-12609 (PG&E Corporation)
58
<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, 1998.
PG&E CORPORATION PACIFIC GAS AND ELECTRIC COMPANY
(Registrant) (Registrant)
/s/ GARY P. ENCINAS /s/ GARY P. ENCINAS
By _________________________________ By _________________________________
(Gary P. Encinas, Attorney-in-Fact) (Gary P. Encinas, Attorney-in-
Fact)
PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS
REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE
REGISTRANTS AND IN THE CAPACITIES AND ON THE DATES INDICATED.
<TABLE>
<CAPTION>
SIGNATURE TITLE DATE
--------- ----- ----
<S> <C> <C>
A. PRINCIPAL EXECUTIVE
OFFICERS
*ROBERT D. GLYNN Chairman of the Board of March 5, 1998
Directors,
Chief Executive Officer, and
*GORDON R. SMITH President
(PG&E Corporation)
President and Chief Executive
Officer
(Pacific Gas and Electric
Company)
B. PRINCIPAL FINANCIAL
OFFICERS
MICHAEL E. RESCOE /s/ MICHAEL E. RESCOE March 5, 1998
Senior Vice President, Treasurer,
and
Chief Financial Officer
(PG&E Corporation)
*KENT M. HARVEY Senior Vice President, Treasurer,
and
Chief Financial Officer
(Pacific Gas and Electric
Company)
C. PRINCIPAL ACCOUNTING
OFFICER
*CHRISTOPHER P. JOHNS Vice President and Controller March 5, 1998
(PG&E Corporation)
Vice President and Controller
(Pacific Gas and Electric
Company)
D. DIRECTORS
*RICHARD A. CLARKE
*H. M. CONGER
*DAVID A. COULTER
*C. LEE COX
*WILLIAM S. DAVILA
*ROBERT D. GLYNN, JR.
*DAVID M. LAWRENCE
*RICHARD B. MADDEN
*MARY S. METZ Directors of PG&E Corporation and
*REBECCA Q. MORGAN Pacific Gas and Electric March 5, 1998
Company,
*CARL E. REICHARDT except as noted
*JOHN C. SAWHILL
*GORDON R. SMITH
(Director of Pacific Gas
and
Electric Company, only)
*BARRY LAWSON WILLIAMS
</TABLE>
/s/ GARY P. ENCINAS
*By ________________________________
(Gary P. Encinas, Attorney-in-Fact)
59
<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 Annual Report on Form 10-K, and have issued our report
thereon dated February 9, 1998. Our audits were made for the purpose of
forming an opinion on those statements taken as a whole. The schedules listed
in Part IV, Item 14. (a)(3) of this Annual Report on Form 10-K are the
responsibility of the management of PG&E Corporation and of Pacific Gas and
Electric Company and are presented for purposes of complying with the
Securities and Exchange Commission's rules and are not part of the basic
consolidated financial statements. These schedules have been subjected to the
auditing procedures applied in the audits of the basic consolidated financial
statements and, in our opinion, fairly state in all material respects the
financial data required to be set forth therein in relation to the basic
consolidated financial statements taken as a whole.
/s/ ARTHUR ANDERSEN LLP
_______________________
ARTHUR ANDERSEN LLP
San Francisco, California
February 9, 1998
60
<PAGE>
<TABLE>
<CAPTION>
SCHEDULE I - CONDENSED FINANCIAL
INFORMATION OF PARENT
CONDENSED BALANCE SHEET
December 31,
1997
-------------
(In millions)
<S> <C>
Assets:
Cash and cash equivalents................................ $ 1
Other current assets..................................... 149
------
Total current assets................................. 150
Investments in subsidiaries.............................. 9,600
Other deferred charges................................... 1
------
Total Assets......................................... $9,751
======
Liabilities and Stockholders' Equity:
Current Liabilities
Accounts payable
Related parties.................................... $ 635
Other.............................................. 10
Accrued taxes........................................ 46
Dividends payable.................................... 118
------
Total current liabilities............................ 809
Noncurrent Liabilities................................... 1
Stockholders' Equity
Common stock......................................... 6,366
Reinvested earnings.................................. 2,575
------
Total stockholders' equity........................... 8,941
------
Total Liabilities and Stockholders' Equity........... $9,751
======
<CAPTION>
CONDENSED STATEMENT OF INCOME
FOR THE YEAR ENDED DECEMBER 31, 1997
1997
----------
(In millions, except per share amounts)
<S> <C>
Equity in earnings of subsidiaries....................... $ 743
Operating expenses....................................... (21)
Interest expense......................................... (23)
------
Income Before Income Taxes............................... 699
Income taxes............................................. (17)
------
Net Income............................................... $ 716
======
Weighted Average Common Shares Outstanding............... 410
Earnings Per Common Share................................ $ 1.75
======
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF PARENT (CONTINUED)
CONDENSED STATEMENT OF CASH FLOWS
FOR THE YEAR ENDED DECEMBER 31, 1997
1997
----------
(in millions)
<S> <C>
Cash Flows From Operating Activities
Net income............................................... $ 716
Adjustments to reconcile net income to net cash
provided by operating activities:
Dividends received from consolidated subsidiaries.. 763
Other-net.......................................... (167)
-------
Net cash provided by operating activities................ $ 1,312
Cash Flows From Investing Activities..................... (150)
Cash Flows From Financing Activities
Common stock repurchased........................... (804)
Dividends paid..................................... (367)
Other-net.......................................... 10
-------
Net cash used by financing activities.................... (1,161)
Net Change in Cash and Cash Equivalents.................. 1
Cash and Cash Equivalents at January 1................... 0
-------
Cash and Cash Equivalents at December 31................. $ 1
=======
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
PG&E CORPORATION
SCHEDULE II -- CONSOLIDATED VALUATION AND
QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 1997, 1996, AND 1995
Column A Column B Column C Column D Column E
Additions
---------------------
Balance Charged
at to Costs Charged Balance
Beginning and to Other at End of
Description of Period Expenses Accounts Deductions Period
------------ --------- ---------- --------- ------------ ---------
(in thousands)
<S> <C> <C> <C> <C> <C>
VALUATION AND QUALIFYING ACCOUNTS
DEDUCTED FROM ASSETS:
1997:
Allowance for uncollectible accounts............... $57,904 $42,500 $ 0 $ 27,492(2) $72,912
======= ======= ======= ========= =======
1996:
Reserve for deferred project costs................. $ 5,710 $ -- $ -- $ 5,710(1) $ 0
======= ======= ======= ========= =======
Allowance for uncollectible accounts............... $35,520 $55,566 $ 1,836 $ 35,018(2) $57,904
======= ======= ======= ========= =======
Reserve for land costs............................. $ 4,444 $ -- $ -- $ 4,444(1) $ 0
======= ======= ======= ========= =======
1995:
Reserve for impairment of oil and gas
properties....................................... $ 4,341 $ -- $ -- $ 4,341(3) $ 0
======= ======= ======= ========= =======
Reserve for deferred project costs................. $25,800 $ -- $ -- $ 20,090(1) $ 5,710
======= ======= ======= ========= =======
Allowance for uncollectible accounts............... $29,769 $50,327 $ -- $ 44,576(2) $35,520
======= ======= ======= ========= =======
Reserve for land costs............................. $ 5,960 $ -- $ -- $ 1,516(1) $ 4,444
======= ======= ======= ========= =======
</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 noncurrents assets.
(2) Deductions consist principally of write-offs, net of collections of
receivables previously written off.
(3) Deductions consist principally of write-offs of expired leaseholds on
reserved property. Deduction in 1995 results from sale of oil and gas
properties.
<PAGE>
PACIFIC GAS AND ELECTRIC COMPANY
SCHEDULE II -- CONSOLIDATED VALUATION AND
QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 1997, 1996, AND 1995
<TABLE>
<CAPTION>
Column A Column B Column C Column D Column E
Additions
---------------------
Balance Charged
at to Costs Charged Balance
Beginning and to Other at End of
Description of Period Expenses Accounts Deductions Period
------------ --------- ---------- --------- ------------ ---------
(in thousands)
<S> <C> <C> <C> <C> <C>
VALUATION AND QUALIFYING ACCOUNTS
DEDUCTED FROM ASSETS:
1997:
Allowance for uncollectible accounts............... $57,904 $30,718 ($ 1,836) $ 27,178(2) $59,608
======= ======= ======= ========= =======
1996:
Reserve for deferred project costs................. $ 5,710 $ -- $ -- $ 5,710(1) $ 0
======= ======= ======= ========= =======
Allowance for uncollectible accounts............... $35,520 $55,566 $ 1,836 $ 35,018(2) $57,904
======= ======= ======= ========= =======
Reserve for land costs............................. $ 4,444 $ -- $ -- $ 4,444(1) $ 0
======= ======= ======= ========= =======
1995:
Reserve for impairment of oil and gas
properties....................................... $ 4,341 $ -- $ -- $ 4,341(3) $ 0
======= ======= ======= ========= =======
Reserve for deferred project costs................. $25,800 $ -- $ -- $ 20,090(1) $ 5,710
======= ======= ======= ========= =======
Allowance for uncollectible accounts............... $29,769 $50,327 $ -- $ 44,576(2) $35,520
======= ======= ======= ========= =======
Reserve for land costs............................. $ 5,960 $ -- $ -- $ 1,516(1) $ 4,444
======= ======= ======= ========= =======
</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.
(3) Deductions consist principally of write-offs of expired leaseholds on
reserved property. Deduction in 1995 results from sale of oil and gas
properties.
<PAGE>
EXHIBIT INDEX
3.1 Restated Articles of Incorporation of PG&E Corporation
effective as of December 19, 1996 (PG&E Corporation's Form 8-B
(File No. 1-12609), Exhibit 3.1).
3.2 By-Laws of PG&E Corporation effective as of January 1, 1998.
3.3 Restated Articles of Incorporation of Pacific Gas and Electric
Company effective as of April 28, 1997 (Pacific Gas and
Electric Company's Form 10-Q for quarter ended June 30, 1997
(File No. 1-2348), Exhibit 3.1).
3.4 By-Laws of Pacific Gas and Electric Company as of January 1,
1998.
4. First and Refunding Mortgage of Pacific Gas and Electric
Company dated December 1, 1920, and supplements thereto dated
April 23, 1925, October 1, 1931, March 1, 1941, September 1,
1947, May 15, 1950, May 1, 1954, May 21, 1958, November 1,
1964, July 1, 1965, July 1, 1969, January 1, 1975, June 1,
1979, August 1, 1983, and December 1, 1988 (Registration No. 2-
1324, Exhibits B-1, B-2, B-3; Registration No. 2-4676, Exhibit
B-22; Registration No. 2-7203, Exhibit B-23; Registration No.
2-8475, Exhibit B-24; Registration No. 2-10874, Exhibit 4B;
Registration No. 2-14144, Exhibit 4B; Registration No. 2-22910,
Exhibit 2B; Registration No. 2-23759, Exhibit 2B; Registration
No. 2-35106, Exhibit 2B; Registration No. 2-54302, Exhibit 2C;
Registration No. 2-64313, Exhibit 2C; Registration No. 2-86849,
Exhibit 4.3; Pacific Gas and Electric Company's Form 8-K dated
January 18, 1989 (File No. 1-2348), Exhibit 4.2).
10.1 Asset Purchase Agreement by and among New England Power
Company, The Narragansett Electric Company, and USGen
Acquisition Corporation, dated as of August 5, 1997 (PG&E
Corporation's Form 10-Q for the quarter ended September 30,
1997 (File No. 1-12609, Exhibit No. 10.1). Filed only as an
exhibit to the Annual Report on Form 10-K filed by PG&E
Corporation under Commission File Number 1-12609.
10.2 The Gas Accord Settlement Agreement, together with accompanying
tables, adopted by the California Public Utilities Commission
on August 1, 1997, in Decision 97-08-055.
1
<PAGE>
*10.3 Agreement regarding certain payments between U.S. Generating
Company and Joseph Kearney. (PG&E Corporation's Form 10-Q for
the quarter ended September 30, 1997 (File No. 1-12609),
Exhibit 10.2.) Filed only as an exhibit to the Annual Report
on Form 10-K filed by PG&E Corporation under Commission File
Number 1-12609. Confidential treatment of information omitted
from this exhibit has been granted by the Commission until
December 31, 1999. Omitted information has been filed
separately with the Commission.
*10.4 PG&E Corporation Deferred Compensation Plan for Directors.
*10.5 PG&E Corporation Deferred Compensation Plan for Officers.
*10.6 The Pacific Gas and Electric Company Savings Fund Plan for
Non-Union Employees, as amended and restated effective as of
October 1, 1997.
*10.7 Short-Term Incentive Plan for Officers of Pacific Gas and
Electric Company, effective January 1, 1996 (Pacific Gas and
Electric Company's Form 10-K for fiscal year 1995 (File No. 1-
2348), Exhibit 10.7).
*10.8 The Pacific Gas and Electric Company Retirement Plan
applicable to non-union employees, as amended October 15,
1997, effective January 1, 1998.
*10.9 Supplemental Executive Retirement Plan of the Pacific Gas and
Electric Company, as amended through October 16, 1991 (Pacific
Gas and Electric Company's Form 10-K for fiscal year 1991
(File No. 1-2348), Exhibit 10.11).
*10.10 Pacific Gas and Electric Company Relocation Assistance
Program for Officers (Pacific Gas and Electric Company's Form
10-K for fiscal year 1989 (File No. 1-2348), Exhibit 10.16).
*10.11 Pacific Gas and Electric Company Executive Flexible
Perquisites Program (Pacific Gas and Electric Company's Form
10-K for fiscal year 1993 (File No. 1-2348), Exhibit 10.16).
*10.12 The Postretirement Life Insurance Plan of the Pacific Gas and
Electric Company (Pacific Gas and Electric Company's Form 10-
K for fiscal year 1991 (File No. 1-2348), Exhibit 10.16).
*10.13 PG&E Corporation Retirement Plan for Non-Employee Directors,
as amended and terminated January 1, 1998.
*10.14 Executive Compensation Insurance Indemnity in respect of
Deferred Compensation Plan for Directors, Deferred
Compensation Plan for Officers, Supplemental Executive
Retirement Plan and Retirement Plan for Non-Employee
Directors (Pacific Gas and Electric Company's Form 10-K for
fiscal year 1991 (File No. 1-2348), Exhibit 10.19).
*10.15 PG&E Corporation Long-Term Incentive Program, as amended and
restated effective as of January 1, 1998, including the PG&E
Corporation Stock Option Plan, Performance Unit Plan, and
Non-Employee Director Stock Incentive Plan.
*10.16 PG&E Corporation Executive Stock Ownership Program, effective
January 1, 1998.
- --------
* Management contract or compensatory plan or arrangement required to be
filed as an exhibit to this report pursuant to Item 14(c) of Form 10-K.
2
<PAGE>
11. Computation of Earnings Per Common Share.
12.1 Computation of Ratios of Earnings to Fixed Charges for Pacific
Gas and Electric Company.
12.2 Computation of Ratios of Earnings to Combined Fixed Charges and
Preferred Stock Dividends for Pacific Gas and Electric Company.
13. 1997 Annual Report to Shareholders of PG&E Corporation and
Pacific Gas and Electric Company (portions of the 1997 Annual
Report to Shareholders under the headings "Selected Financial
Data," "Management's Discussion and Analysis of Consolidated
Results of Operations and Financial Condition," "Report of
Independent Public Accountants," and for each of PG&E
Corporation and Pacific Gas and Electric Company, "Statement of
Consolidated Income," "Consolidated Balance Sheet," "Statement
of Consolidated Cash Flows," "Statement of Consolidated Common
Stock
Equity, Preferred Stock and Preferred Securities," "Notes to
Consolidated Financial Statements" and "Quarterly Consolidated
Financial Data (Unaudited)" included only) (except for those
portions which are expressly incorporated herein by reference,
such 1997 Annual Report to Shareholders is furnished for the
information of the Commission and is not deemed to be "filed"
herein).
21. Subsidiaries of the Registrant (incorporated by reference from
PG&E Corporation's Statement by Holding Company Claiming
Exemption from the Public Utility Holding Act of 1935 under Rule
2 by filing Form U-3A-2 dated February 27, 1998, pages 1 through
33 (File No. 1-12609).
23. Consent of Arthur Andersen LLP.
24.1 Resolutions of the Boards of Directors of PG&E Corporation and
Pacific Gas and Electric Company authorizing the execution of
the Form 10-K.
24.2 Powers of Attorney.
27.1 Financial Data Schedule for the year ended December 31, 1997,
for PG&E Corporation.
27.2 Financial Data Schedule for the year ended December 31, 1997,
for Pacific Gas and Electric Company.
The exhibits filed herewith are attached hereto (except as noted) and those
indicated above which are not filed herewith were previously filed with the
Commission as indicated and are hereby incorporated by reference. All exhibits
filed herewith or incorporated by reference are filed with respect to both
PG&E Corporation (File No. 1-12609) and Pacific Gas and Electric Company (File
No. 1-2348), unless otherwise noted. Exhibits will be furnished to security
holders of PG&E Corporation or Pacific Gas and Electric Company upon written
request and payment of a fee of $0.30 per page, which fee covers only the
registrants' reasonable expenses in furnishing such exhibits. The registrants
agree to furnish to the Commission upon request a copy of any instrument
defining the rights of long-term debt holders not otherwise required to be
filed hereunder.
(B) REPORTS ON FORM 8-K
Reports on Form 8-K(/1/) during the quarter ended December 31, 1997, and
through the date hereof:
1. October 16, 1997
Item 5. Other Events
-- Performance Incentive Plan--Year-to-Date Financial Results
3
<PAGE>
EXHIBIT 3.2
BYLAWS
OF
PG&E CORPORATION
AMENDED AS OF JANUARY 1, 1998
-----------------------------
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. The Board of Directors shall consist of fourteen (14)
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.
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.
2
<PAGE>
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.
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
3
<PAGE>
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.
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.
4
<PAGE>
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 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.
5
<PAGE>
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, 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.
6
<PAGE>
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 1, 1998
-----------------------------
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 shall consist of fifteen (15)
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.
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.
[2]
<PAGE>
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.
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
[3]
<PAGE>
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 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.
[4]
<PAGE>
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 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
[5]
<PAGE>
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.
[6]
<PAGE>
EXHIBIT 10.2
===============================================================================
Subject to Rule 51 of the CPUC Rules of Practice and Procedure, Rule 601 et
seq. of the FERC Rules of Practice, Rule 408 of the Federal Rules of Evidence,
and Section 1152 of the California Evidence Code
===============================================================================
[GAS ACCORD LOGO]
THE GAS ACCORD SETTLEMENT AGREEMENT
------------------------------------
I. INTRODUCTION
A. PROPOSAL FOR A NEW GAS MARKET STRUCTURE FOR NORTHERN CALIFORNIA
The Gas Accord is a proposal to significantly restructure the way PG&E
provides natural gas service to California consumers by increasing
competition and customer choice. In part, the Gas Accord is a response to
signals from regulators and the market that the time has come for such
changes. The Gas Accord is also a vision of how the natural gas industry
in northern California should be structured as we enter the next century.
The Gas Accord consists of three broad initiatives. First, the Accord
unbundles PG&E's gas transmission and a portion of storage services, places
PG&E at risk for these costs, and changes the terms of service and the rate
structure for gas transportation so that customers' rates more accurately
reflect the facilities used to serve them. PG&E's service area is served by
an integrated high-pressure transmission system that resembles an
interstate pipeline system more than a typical local distribution company
(LDC) system. The Accord unbundles the transmission system, and requires
PG&E to operate and provide service on that system similar to an interstate
pipeline. PG&E will continue to provide distribution service, much as it
does today.
Second, the Accord changes PG&E's role in procuring gas supplies for core
customers in order to increase customer choice. It reduces PG&E's role in
core procurement, and reduces PG&E's holdings of interstate transportation
capacity. It also provides for negotiations between PG&E and California gas
producers for a mutual release of supply contracts with PG&E. PG&E's core
procurement department will continue to hold a portion of storage capacity
to ensure system reliability and a defined standard of customer service
reliability, but customers will be free to seek commodity and transmission
services from alternative suppliers. As part of this Agreement, the Core
Procurement Incentive Mechanism agreed to by PG&E and DRA in 1996 must be
implemented for an initial period through 1997, followed by the revised
incentive mechanism described in the Gas Accord for the period thereafter.
The Gas Accord period will extend from the date of implementation, which
PG&E is asking to be July 1, 1997, through December 31, 2002.
Third, the Gas Accord settles all major outstanding gas regulatory issues.
Neither PG&E, the CPUC, nor market participants can expend the energy and
resources to proceed with the Gas Accord while at the same time arguing
about whether PG&E acted reasonably under the old rules.
<PAGE>
The changes proposed herein are reasonable and bold responses to several
forces for change that have manifested themselves since gas restructuring
began in California, about ten years ago. On the regulatory side, the CPUC
has initiated programs to segment the noncore from the core market, with
rights accorded to noncore customers to obtain transmission service and
commodity supplies separately from bundled PG&E service. Core customer
representatives are now advocating an increase in the competitive choices
available to them. In addition, the CPUC has changed the way it regulates
both Southern California gas utilities, approving performance-based
regulation for each utility's gas procurement. The CPUC also has called for
an OII/OIR for the purpose of further restructuring the California natural
gas industry on at least two occasions, most recently in a decision (D.94-
02-042) approving interim rates for PG&E's Pipeline Expansion Project.
The market, too, has signaled a desire for change. Customers have sought
more options for natural gas transportation and sources of supply.
Marketers and producers have stated there are obstacles to selling directly
to core customers, and there have been proposals to build competitive
pipelines into PG&E's service area. All of these demonstrate that PG&E's
current transportation and service structure is outdated.
For these reasons, further changes are inevitable. PG&E could resist and
watch these changes occur piecemeal, to the possible disadvantage of its
customers and shareholders; however, this Gas Accord, negotiated with the
market participants, offers a better prospect for a rational result. All
participants in the Accord process -- market participants, the CPUC, and
PG&E -- have significant interests in the process of change. It is vital
that this process result in a fair resolution of past issues and a fair
opportunity to compete in the new world of unbundled competitive gas
markets.
Unbundling of services will increase market participation. Each competitive
market -- transmission, procurement, and other services --inevitably will
lead to the development of new services and increased choices for
consumers. As these markets become contested by new service providers, the
freedom to compete in each on an equal basis must be granted to all
parties, including PG&E. The Accord will move PG&E and the marketplace
toward this vision.
The Accord is a negotiated compromise on a number of issues related to many
proceedings. If not accepted by the Commission, the Accord shall not be
admissible in evidence in this or any other proceeding. Nothing contained
herein shall be deemed to constitute an admission or an acceptance by any
party of any fact, principle, or position contained herein.
The Accord is to be treated as an entire package and not as a collection of
separate agreements on discrete proceedings, nor is the restructuring
proposal separable from the resolution of past issues. To accommodate the
interests of different parties on diverse issues, changes, concessions, or
compromises in one section of the Accord necessitated changes, concessions,
or compromises in other sections.
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<PAGE>
In an August 16, 1995, Assigned Commissioner's Ruling on the Gas Accord
process, Assigned Commissioner Fessler stated:
I encourage all affected parties to participate in settlement
discussions, and I encourage PG&E to include all gas market
participants in its negotiations. I look with disfavor on parties that
decline fair opportunities to participate in settlement discussions,
then criticize agreements reached in their absence. (August 16, 1995,
ACR, p. 5).
The Gas Accord negotiations have met the Assigned Commissioner's standard
for wide participation, and the Accord presents a new, more competitive
structure for the natural gas marketplace in northern California that is
broadly supported by the market participants. The settling parties
encourage the Commission to adopt and implement the Gas Accord.
B. ELEMENTS OF THE AGREEMENT
1. Unbundle the rates and service options for transmission system service
from distribution system service. The transmission system is defined as
PG&E's backbone and local gas transmission lines, including gathering
and Stanpac facilities. The local transmission system includes
distribution feeder mains (DFMs). A map of PG&E's system is included at
the end of this Section.
2. Charge transmission, storage, and distribution rates to those customers
who use these facilities pursuant to contractually-defined terms of
service.
3. Provide balancing service through a single integrated gas system for
both transmission level and distribution level customers. PG&E proposes
initially to continue a monthly balancing service, with imbalance
trading, tighter tolerance bands and monthly cash-out provisions.
4. Establish transmission system services that eliminate the crossover ban
and the backbone credit.
5. Offer various paths over the transmission system. Each path requires a
separate contract. See Section II for more information on the
definition of the paths and applicable delivery and receipt points.
These paths include:
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<PAGE>
a. Malin to On-system for the Core;
b. Malin to On-system;
c. Topock to On-system;
d. California Production and Storage to On-system;
e. Malin to Off-system;
f. Topock to Off-system;
g. California Production, Storage, Market Center/Hub Services, and On-
system Delivery Points to Off-system; and
h. G-XF Firm Service.
On-system is defined as any point at which deliveries are made to, or
for ultimate delivery to, PG&E's distribution facilities, PG&E's
storage facilities, a third party's storage facilities located in
PG&E's service territory, or end-use or wholesale loads located in
PG&E's service territory. Off-system is defined as any point of
interconnection for delivery outside of PG&E's service territory.
6. Provide new services over these paths using (a) Line 300 capacity, and
(b) capacity consisting of that portion of Line 400 capacity not
reserved for the core and that portion of Line 401 capacity not
reserved under long-term firm contracts with existing firm Expansion
shippers. This combined Malin capacity is to be redesignated by the
Commission as non-Expansion capacity, which shall be subject to phased-
in rates and shall not be subject to the tariff or contract provisions
and rights that apply to the Line 401 capacity reserved under long-term
Expansion contracts.
7. For ratemaking purposes, phase-in the embedded cost of 375 MMcf/d (381
Mdth/d) of Line 401 capacity into the Line 400 capacity not reserved
for the core over the period from 1997 through 2002. The phase-in will
begin at 200 MMcf/d (203 Mdth/d). This phase-in schedule is consistent
with historical Line 401 on-system usage and projected on-system
noncore demand growth. This will determine the Malin to on-system path
costs. (See Section II.I.3 for the complete phase-in schedule.)
8. Provide to the retail core 600 MMcf/d (609 Mdth/d) and to core
wholesale 6.5 MMcf/d (6.6 Mdth/d) of Malin to on-system vintage firm
capacity, at Line 400 embedded cost (vintaged rates). Any additional
capacity from Malin used by the retail core or wholesale customers must
be on the Malin to on-system path.
9. Honor the service commitments set forth in existing long-term
transmission service agreements for the period of the Accord or the
remaining term of each such
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<PAGE>
agreement, whichever applies. These commitments are addressed below in
Section II.F.
10. Provide parking and lending services at all interstate interconnection
points and at Kern River Station. These services shall be provided
using transmission and storage capacity as it becomes available.
11. Continue operational integration of PG&E's gas storage facilities with
PG&E's transmission facilities. PG&E will reserve firm storage capacity
for pipeline balancing services and PG&E's Core Procurement Department
will contract for a major portion of PG&E firm storage capacity on
behalf of the retail core. The remaining storage capacity will be
marketed in an unbundled storage program.
12. Unless otherwise stated in this document, the principles and specific
elements of the Accord, the resulting Accord rates (and their
underlying assumptions) and the revenue treatment for Accord services
are fixed and not subject to challenge or change in any regulatory
forum during the Gas Accord period. Consequently, the parties will not
challenge any assumption that is set by this Accord, and that if
altered, would result in a shift of revenue responsibility between core
and noncore customers and/or between customers and PG&E shareholders.
Furthermore, any issue settled as part of the Gas Accord described in
Section V, Litigation Resolution, will not be subject to litigation in
any regulatory forum.
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<PAGE>
This page left deliberately blank for the map to be inserted
-6-
<PAGE>
II. TRANSMISSION AND STORAGE SERVICES
A. NEW TRANSMISSION SERVICES
The services offered over the backbone portions of the new transmission
paths (paths a through g, listed in Section I.B.5 above) are described
below. Contracts will set the terms of service, including service
priority. Local transmission costs are included in a separate local
transmission charge, which will be collected from all on-system end-
users. The pre-existing transmission services are described in Section
II.B, below.
The following five transmission services will have all terms and
conditions set by tariff.
1. Firm Annual On-system (AFT)
a. Definition: Firm service on the transmission system with
deliveries on-system.
b. Minimum Term: One year.
c. Rate: Straight Fixed Variable (SFV) or Modified Fixed Variable
(MFV), at the shipper's option for the backbone component. See
rates in Section VI. No discounts.
2. Firm Seasonal (SFT)
a. Definition: Firm seasonal service on the transmission system.
b. Conditions: Paths to on-system destinations only. Maximum term
limited to two years.
c. Minimum Term: Three consecutive months in one season.
d. Winter Season: November through March.
e. Summer Season: April through October.
f. Rate: SFV or MFV, at the shipper's option for the backbone
component. See rates in Section VI. No discounts.
3. As-available On-system (AA)
a. Definition: As-available service on the transmission system
with deliveries on-system.
b. Minimum Term: One day.
c. Rate: Volumetric for the backbone component. See rates in
Section VI. No discounts.
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<PAGE>
4. Firm Annual Off-system (AFT-Off)
a. Definition: Firm service on the transmission system with
deliveries off-system.
b. Minimum Term: One year.
c. Rate: Straight Fixed Variable (SFV) or Modified Fixed Variable
(MFV), at the shipper's option for the backbone component. If a
shipper elects SFV rate design, the shipper can also specify an
alternate delivery point on-system. If a shipper elects MFV,
delivery must be off-system only. See rates in Section VI. No
discounts .
5. As-available Off-system (AA-Off)
a. Definition: As-available service on the transmission system
with deliveries off-system.
b. Minimum Term: One day.
c. Rate: Volumetric for the backbone component. See rates in
Section VI. No discounts.
The following four transmission services are negotiable, as indicated.
6. Negotiated Firm Service On-system (NFT)
a. Definition: Firm service on the transmission system with
deliveries on-system.
b. Minimum Term: Negotiable.
c. Rate: Negotiable, above a marginal-cost-based floor consistent
with negotiated term. Maximum rate for the backbone component
of each path is 120 percent of the firm annual rate for that
path.
d. Take Requirement: Negotiable.
e. Sections IX and X of General Order No. 96-A are waived by the
Commission.
7. Negotiated As-available On-system (NAA)
a. Definition: As-available service on the transmission system
with deliveries on-system.
b. Minimum Term: Negotiable.
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<PAGE>
c. Rate: Negotiable, above a marginal-cost-based floor consistent
with the negotiated term. Maximum rate for the backbone
component of each path is 120 percent of the As-available rate
for that path.
d. Take Requirement: Negotiable.
e. Sections IX and X of General Order No. 96-A are waived by the
Commission.
8. Negotiated Firm Service Off-system (NFT-Off)
a. Definition: Firm service on the transmission system with
deliveries off-system.
b. Minimum Term: Negotiable.
c. Rate: Negotiable, above a marginal-cost-based floor consistent
with negotiated term. Maximum rate for the backbone component
of each path is 120 percent of the firm annual rate for that
path.
d. Take Requirement: Negotiable.
e. Sections IX and X of General Order No. 96-A are waived by the
Commission.
9. Negotiated As-available Off-system (NAA-Off)
a. Definition: As-available service on the transmission system
with deliveries off-system.
b. Minimum Term: Negotiable.
c. Rate: Negotiable, above a marginal-cost-based floor consistent
with the negotiated term. Maximum rate for the backbone
component of each path is 120 percent of the As-available rate
for that path.
d. Take Requirement: Negotiable.
e. Sections IX and X of General Order No. 96-A are waived by the
Commission.
10. PG&E may also offer other customer-specific negotiated contracts.
Negotiated transmission service contracts under NFT and NAA will
not require submission to the CPUC for approval; however, any other
negotiated transmission service contracts will require submission
to the CPUC for approval.
-9-
<PAGE>
11. The following table summarizes which new transmission services are
available to the transmission paths described in Section I.B.5.
<TABLE>
<CAPTION>
Available
Path Services
---- ---------
<S> <C>
a. Malin to On-system for Core AFT
b. Malin to On-system AFT, SFT, AA, NFT,
NAA
c. Topock to On-system AFT, SFT, AA, NFT,
NAA,
d. California Production and AFT, SFT, AA, NFT,
Storage to On-system NAA,
e. Malin to Off-system AFT-Off, AA-Off,
NFT-Off, NAA-Off
f. Topock to Off-system AFT-Off, AA-Off,
NFT-Off, NAA-Off
g. California Production, Storage, AFT-Off, AA-Off, Services and
Market Center/Hub On-system NFT-Off, NAA-Off
Delivery Points to Off-system
</TABLE>
B. PRE-EXISTING TRANSMISSION SERVICES
1. G-XF Firm Service
a. Definition: Firm service on Line 401 under the G-XF rate.
b. Minimum Term: Thirty years.
c. Rate: Incremental rates based on a capital cost for Line 401 of
$736 million, using utility capital structure and the operating
expenses and cost allocation methodologies set forth in PG&E's PEPR
Application.
d. Take Requirement: As negotiated.
e. Other terms and conditions: Delivery point as set forth in Exhibit
A to each firm contract; Uniform Terms of Service rights apply only
to firm G-XF service; backbone credit and crossover ban are
eliminated.
f. Sections IX and X of General Order No. 96-A may apply.
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<PAGE>
2. Expedited Application Docket (EAD) Agreements
a. Definition: Firm service on Line 300 and from California gas
production to the burnertip, under individually negotiated
contracts approved by the CPUC under the provisions of Decision 92-
11-052.
b. Minimum Term: As set forth in each contract.
c. Rate: Volumetric negotiated rate, as set forth in each contract.
d. Take Requirement: As set forth in each contract.
e. Other terms and conditions: As set forth in each contract.
f. Sections IX and X of General Order No. 96-A may apply.
3. Enhanced Oil Recovery (EOR) Agreements
a. Definition: Interruptible service for Enhanced Oil Recovery
customers pursuant to Decisions 85-12-102 and 87-05-046.
b. Minimum Term: As set forth in each contract.
c. Rate: Volumetric negotiated rate, as set forth in each contract.
d. Take Requirement: None
e. Other terms and conditions: As set forth in each contract.
f. Sections IX and X of General Order No. 96-A apply.
4. Expedited Direct Connection Docket (EDCD) Agreements
a. Definition: Agreements for direct connection service on PG&E's Line
401 approved pursuant to the CPUC's Expedited Direct Connection
Docket.
b. Term: The remaining term of the direct connection agreement.
c. Rate: The rate established in the direct connection agreement. If
this agreement does not specify a rate, then the rate will be
established under one of the new transmission service rates.
d. Other terms and conditions: Per the direct connection agreement, or
if unspecified in that agreement, the applicable Gas Accord
tariffs.
5. Other Existing Agreements
a. Negotiable Interruptible Agreements
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PG&E has a number of negotiable interruptible transportation
agreements with terms that may extend into the Accord period. PG&E
will continue to honor the terms and conditions, including the
rate, negotiated for the original term of these contracts.
b. Crockett Cogeneration
Crockett cogeneration has a negotiated contract which provides for
transportation service at volumetric rates. PG&E will continue to
honor the terms and conditions, including the rate, negotiated for
the original term of this contract. If any terms and conditions are
unspecified by the existing contract agreement, then the applicable
Gas Accord tariffs will apply.
C. STORAGE SERVICES
1. Storage Capacity Allocated To Core Customers, Including Core Transport
Customers
a. Core service is allocated a portion of storage capacity to support
the obligation to maintain highly reliable service under cold
conditions. See Section II.E.5 for allocations.
b. Core aggregators, on behalf of their core transport customers, will
be allocated a pro rata share of the total core reservation based
on the winter season throughput of their core customers.
c. Costs for storage allocated to core customers, including core
transport customers, will remain bundled in all core rates.
d. Any storage capacity that is not needed for core reliability may be
brokered.
e. PG&E and core aggregators, on behalf of core customers, may elect
to purchase more storage through the unbundled storage program.
2. Storage Capacity Allocated to Pipeline Balancing Services
a. A portion of storage capacity is needed to support the balancing
services. See Section II.E.5 for the allocation.
b. Storage costs allocated to balancing services remain bundled in
transmission rates.
3. Unbundled Storage Program
a. PG&E will offer storage services to the market from its integrated
storage facilities through the unbundled storage program. The
storage services will be
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<PAGE>
offered from the capacity remaining, after the allocations for
balancing provisions and storage for the core market.
b. Firm Storage Service (FS)
i. Definition: Firm storage service.
ii. Minimum Term: One year
iii. Rate: Sub-functions are capacity (combined injection and inventory)
and withdrawal. Each sub-function is further divided into a
reservation charge (fixed) component and a volumetric charge
(variable) component.
iv. Conditions: Requires injection during the defined summer storage
season.
v. Features: Imbalance trading and inventory transfers are available.
c. Negotiated Firm Storage Service (NFS)
i. Definition: Firm storage service; customers may purchase inventory,
injection, and withdrawal separately.
ii. Minimum Term: One month
iii. Rate: The flexibility inherent in this storage offer could result
in stranded facilities and PG&E requires the opportunity to collect
the value of its storage services. Rates are negotiable above a
short-run marginal price floor and capped at the price which will
collect 100 percent of PG&E's total revenue requirement for the
unbundled storage program for each of the three storage
subfunctions (e.g., inventory, injection, or withdrawal).
iv. Features: Imbalance trading, inventory transfers, and counter-
cyclical operations are available.
v. Sections IX and X of General Order No. 96-A are waived by the
Commission.
d. Negotiated As-available Storage Injection and Withdrawal Service (NAS)
i. Definition: As-available storage service only available to
customers with firm storage inventory.
ii. Minimum Term: One day
iii. Rate: Volumetric only rate design. The flexibility inherent in this
storage offer could result in stranded facilities and PG&E requires
the opportunity to collect the value of its storage services. Rates
are negotiable above a marginal price floor and capped at the price
which will collect 100 percent of PG&E's
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<PAGE>
total revenue requirement for the unbundled storage program for
each of the three storage subfunctions (e.g., inventory, injection,
or withdrawal).
iv. Sections IX and X of General Order No. 96-A are waived by the
Commission.
4. PG&E may also offer other customer-specific negotiated contracts.
Negotiated storage service contracts under NFS and NAS will not require
submission to the CPUC for approval; however, any other negotiated
storage service contracts will require submission to the CPUC for
approval.
5. Depending on market interest, PG&E is free to develop and offer
additional storage services in the future.
D. OTHER SERVICES
1. Parking (PARK) Services offered are identical to those approved by the
CPUC on June 26, 1996 (Advice 1949-G).
a. Definition: As-available short-term parking service, using PG&E's
transmission and storage system.
b. Term: One day to one year.
c. Rate: Negotiable, above a minimum transaction fee and capped at the
daily and/or annual cost to cycle gas using Firm Storage Service.
d. Terms and Conditions: Gas is parked and unparked at the same
location.
e. Priority: Lowest priority As-available service.
2. Lending (LEND) Services offered are identical to those approved by the
CPUC on June 26, 1996 (Advice 1949-G).
a. Definition: As-available short-term loan of gas using PG&E's
transmission and storage system.
b. Term: One day to one year.
c. Rate: Negotiable, above a minimum transaction fee and capped at the
daily and/or annual cost to cycle gas using Firm Storage Service.
d. Terms and Conditions: Gas is loaned and repaid at the same
location.
e. Priority: Lowest priority As-available service.
3. PG&E may also offer other customer-specific negotiated contracts.
Negotiated service contracts under PARK and LEND will not require
submission to the CPUC
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<PAGE>
for approval; however, any other negotiated service contracts will
require submission to the CPUC for approval.
4. Other
Depending on market interest, PG&E is free to develop and offer various
additional services in the future.
E. GENERAL TERMS AND CONDITIONS
1. These general terms and conditions will apply to PG&E's intrastate
transmission and storage systems, and to third party storage providers
located in PG&E's service territory who have an operating agreement and
who have inter-connecting facilities with PG&E. Subscription to these
services does not, in itself, subject the subscriber to CPUC
jurisdiction.
2. With the unbundling of transmission services, the crossover ban and the
backbone credit are eliminated. The following sections in PG&E's
existing tariffs are removed along with other references and
definitions as may be applicable: Rule 21, Section H, "Scheduling
Priority at Malin, Oregon"; Rule 21, Section I, "Self Identification of
Malin, Oregon Receipts"; and Rule 22, "Backbone Credit Eligibility
Criteria."
-15-
<PAGE>
3. Receipt Points By Path
a. The receipt points by path are as follows:
<TABLE>
<CAPTION>
Path Receipt Points
- ----- --------------
<S> <C>
Malin to On-system for the Core Malin
Malin to On-system Malin
Topock to On-system Topock, Daggett, and Kern River Station
California Production and Storage to On-system PG&E interconnections with California gas
production within PG&E's service territory,
PG&E's storage facilities, or a third
party's storage facilities located in
PG&E's service territory.
Malin to Off-system Malin
Topock to Off-system Topock, Daggett, and Kern River Station
California Production, Storage, Market Center/Hub PG&E interconnections with California gas
Services, and On-system Delivery Point Pools to production within PG&E's service territory,
Off-system PG&E's storage facilities, a third party's
storage facilities located in PG&E's
service territory, PG&E's Market Center/Hub
Services, or on-system delivery point pools.
G-XF Firm Service Malin
</TABLE>
b. Alternate Receipt Points
Alternate receipt points are allowed only within the transmission path
contracted for by a shipper.
c. New Receipt Points
New receipt points may be requested from time to time by shippers.
4. Delivery Points
a. On-system Deliveries
On-system is defined as any point at which deliveries are made to, or
for ultimate delivery to, PG&E's distribution facilities, PG&E's
storage facilities, a third party's storage facilities located in
PG&E's service territory, or end-use or wholesale loads located in
PG&E's service territory.
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<PAGE>
b. Off-system Deliveries
Any interconnection for delivery outside of PG&E's service territory,
including Topock, Daggett, Kern River Station, Malin, etc.
c. G-XF Firm Service
Delivery points are as specified in each shipper's FTSA (Exhibit A).
5. Initial Allocation of Firm Intrastate Transmission Capacity
a. Total intrastate capacity currently available for firm transmission
services is:
<TABLE>
<CAPTION>
MMcf/d Mdth/d
------------------ ------------------
<S> <C> <C>
Malin: 1,803 1,830
Topock: 1,140 1,174
CaliGas 200 192
</TABLE>
The Malin capacity consists of 990 MMcf/d (1,005 Mdth/d) from Line 400
and 813 MMcf/d (825 Mdth/d) from Line 401.
b. PG&E's retail core initially will be allocated the following quantities
of firm transmission capacity:
<TABLE>
<CAPTION>
Malin to Topock to
On-system On-system California
--------- --------- ----------
<S> <C> <C> <C> <C>
Annual MMcf/d 600 150 50
Mdth/d 609 155 48
</TABLE>
c. PG&E's retail core will also hold additional seasonal winter capacity
as follows:
<TABLE>
<CAPTION>
Malin to Topock to
On-system On-system California
--------- --------- ----------
<S> <C> <C> <C>
November and March
MMcf/d 0 150 0
Mdth/d 0 155 0
December to February
MMcf/d 0 450 0
Mdth/d 0 464 0
</TABLE>
d. The retail core capacity reservation on the Topock to on-system path
(Line 300) and the California production path can be modified in
ensuing BCAPs to account for changes in core requirements due to
factors such as core aggregation, the termination of PG&E's California
gas contracts, and the migration of core
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<PAGE>
customers to noncore status. These modifications will not take place
prior to 2000.
e. Capacity of up to 6.5 MMcf/d (6.6 Mdth/d) is available on the Malin to
on-system path for existing wholesale customers on behalf of their core
load.
f. New services over the Malin 517 Mdth/d) not reserved under paths will
use capacity long-term firm contracts with consisting of that portion
of existing firm Expansion Line 400 capacity (383.5 shippers. This
combined MMcf/d; 389 Mdth/d) not capacity is to be redesignated
reserved for the core, by the Commission as including wholesale, and
that non-Expansion capacity, which portion of Line 401 capacity shall
be subject to "phased-in" (509 MMcf/d; rates and shall not be subject
to the tariff or contract provisions and rights (including but not
limited to the firm Expansion shippers' "Uniform Terms of Service"
rights) that apply to the Line 401 Expansion capacity reserved under
long-term contracts.
g. PG&E will conduct an open season among all creditworthy parties to
award remaining intrastate firm transmission service for at least the
minimum term and at the full tariff rate under the AFT, AFT-Off, or SFT
service. Firm capacity will first be awarded under the AFT and AFT-Off
service. Any remaining firm capacity will then be awarded under the SFT
service.
h. If a particular path is oversubscribed in the open season, PG&E will
award available firm capacity based on PG&E's determination of the
highest economic value of each bid to PG&E's gas transmission
department, as determined by PG&E.
6. Allocation of Storage Capacity
a. The following quantities of firm storage capacity will be allocated to
PG&E's retail core customers, including core transport:
<TABLE>
<CAPTION>
Inventory Injection Withdrawal
--------- ---------- ----------
<S> <C> <C>
32.Bcf 93 - 209 MMcf/d 951 - 1,228 MMcf/d
33.5 MMdth 95 - 213 Mdth/d 970 - 1,253 Mdth/d
</TABLE>
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<PAGE>
b. The following quantities of firm storage capacity will be allocated to
system load balancing:
<TABLE>
<CAPTION>
Inventory Injection Withdrawal
--------- --------- -----------
<S> <C> <C>
2.2 Bcf 50 MMcf/d 70 MMcf/d
2.24 MMdth 51 Mdth/d 71 Mdth/d
</TABLE>
c. The following quantities of storage capacity will be allocated to the
unbundled storage program:
<TABLE>
<CAPTION>
Inventory Injection Withdrawal
--------- --------- ----------
<S> <C> <C>
4.7 Bcf 13 - 30 MMcf/d 136 - 175 MMcf/d
4.79 MMdth 13 - 30 Mdth/d 139 - 179 Mdth/d
</TABLE>
Volumes are subject to change pursuant to operating conditions. Future
fluctuations or changes in PG&E's injection and/or withdrawal
capabilities during the Gas Accord period will be assigned or absorbed
by the unbundled storage program, except for changes in storage
capabilities required on behalf of core customers served by PG&E.
d. PG&E will conduct an open season among all creditworthy parties to
award remaining firm storage service for at least the minimum term and
at the full tariff rate for Firm Storage Service.
e. If Firm Storage Service is oversubscribed in the open season, PG&E will
award available firm storage capacity based on PG&E's determination of
the highest economic value of each bid to PG&E's gas transmission
department, as determined by PG&E.
7. Subsequent Allocation of Intrastate Transmission and Storage Capacity
a. After the open season for transmission and storage capacity, any
remaining capacity will be available for subscription under the Firm,
Negotiated Firm, or As-available services on an on-going basis.
b. Customers may request negotiated rates at less than maximum rates. PG&E
will not be required to sell capacity to any shipper at less than the
full tariff rate; however, at PG&E's sole option, capacity may be
awarded based on offers that represent the highest economic value to
PG&E, as determined by PG&E.
8. Contract Assignment
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<PAGE>
a. Unless the shipper's contract states otherwise, all transmission and
storage contracts are assignable. Such assignments may consist of all
or part of the shipper's contract quantity and all or part of the
shipper's remaining contract term.
b. Contract assignments are subject to the following requirements:
i. Assignors must notify PG&E in advance of their assignments.
ii. The assignee must satisfy PG&E's creditworthiness requirements
described in Section II.E.9. Alternatively, the assignor may, at
its option, waive the creditworthiness requirements applicable to
the assignee, in which case the assignor shall be secondarily
liable for non-performance by the assignee. If an assignor
exercises this option, it must demonstrate to PG&E's satisfaction
that it remains creditworthy itself.
c. To encourage assignments and development of an active secondary market,
PG&E will maintain a posting board similar to PG&E's existing "Energy
Marketplace" that contract holders may use, at their option. PG&E is
willing to work with others to establish new or modify existing
mechanisms, including electronic bulletin boards, that encourage
development of an active secondary market.
9. Creditworthiness
a. An entity requesting service must demonstrate creditworthiness before
receiving service. Additionally, an entity receiving service under a
long-term (one year or longer) contract may be subject to periodic re-
evaluations of its creditworthiness.
b. An entity requesting service must provide the following to PG&E in
order for PG&E to evaluate its creditworthiness:
i. Most recent annual report;
ii. Most recent SEC Form 10-K;
iii. If SEC Form 10-K is unavailable, substitute audited annual
financial statements (including a balance sheet, income statement,
and cash flow statement), o r
iv. If audited financial statements are unavailable, substitute
unaudited financial statements (including a balance sheet, income
statement, and cash flow statement) accompanied by an attestation
by the providing entity's Chief Financial Officer that the
information reflected in the unaudited statements is true and
correct and a fair representation of the entity's financial
condition;
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<PAGE>
v. Most recent quarterly or monthly financial statements (including a
balance sheet, income statement, cash flow statement, and
contingencies).
c. PG&E will use the items above, in conjunction with the entity's service
request or service level, to determine the maximum amount of credit
PG&E can offer the entity.
d. If an entity is unable to demonstrate creditworthiness through the
materials listed in Section b, PG&E may request additional evidence of
creditworthiness, in which event the entity may elect to provide one of
the following:
i. an irrevocable letter of credit in form, substance and amount
satisfactory to PG&E;
ii. a guarantee, in form and substance satisfactory to PG&E, executed
by a person PG&E deems to be creditworthy, of the entity's
performance of its obligations to PG&E; or
iii.such other form of security as the entity may agree to provide and
as may be acceptable to PG&E.
e. PG&E will treat all financial statements provided to it as
confidential.
f. PG&E will continue to oversee aggregators' creditworthiness, pursuant
to PG&E's Gas Rule 23 - Gas Aggregation Service for Core Transport
Customers.
10. Priority of Service
a. The current Receipt Point Capacity Allocation rules will change to
reflect the following priorities.
b. Scheduling Priority at Transmission Receipt Points (in the following
order)
i. Firm Intrastate Transmission: All firm service at all receipt
points on a defined transmission path is treated equally (pro rata
allocation of nominations if necessary).
ii. As-available Intrastate Transmission: Scheduled according to
contract price.
c. Scheduling Priority at Transmission Delivery Points (in the following
order):
i. Firm Intrastate Transmission: All firm service at a given delivery
point is treated equally (pro rata allocation of nominations if
necessary).
ii. As-available Intrastate Transmission: Scheduled according to
contract price.
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<PAGE>
d. Scheduling Priority To Storage for Injection
i. Transportation priority to storage is determined by the underlying
intrastate transmission contract.
ii. Injection priority at PG&E's storage interconnection is determined
by the storage contract:
* PG&E Firm Storage Service: All firm service treated equally (pro
rata allocation of nominations if necessary).
* PG&E As-available Storage Service: Scheduled according to
contract price.
e. Scheduling Priority From Storage for Withdrawal
i. Transportation priority from storage to the delivery point is
determined by the underlying intrastate transportation contract.
ii. Withdrawal priority at PG&E's storage interconnection is determined
by the storage contract.
* PG&E Firm Storage Service: All firm service treated equally (pro
rata allocation of nominations if necessary).
* PG&E As-available Storage Service: Scheduled according to
contract price.
f. Over-Nomination Provision
PG&E will develop a tariff provision to discourage nominations in
excess of actual available supply (over-nomination) at a constrained
receipt or delivery point.
11. Local Constraints
a. PG&E will take whatever steps it determines are operationally necessary
in the event a constraint on local transmission or distribution
threatens service to customers. This includes curtailment of noncore
customers.
b. To the extent feasible, PG&E will use the transmission system diversion
procedures to prioritize noncore customers in the affected service
area.
c. In the event of an Emergency Flow Order (EFO) due to a local
constraint, EFO penalties may apply, but involuntary diversion
penalties will not apply.
12. Service Reliability and Diversion Procedures
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<PAGE>
a. When operational conditions exist such that supply is insufficient to
meet demand and delivery to end-users is threatened, the diversion of
supply may be used to ensure continued gas delivery to core end-users.
EFO provisions will apply under these conditions (see Section II.E.13).
If a noncore end-user's supply is diverted, either voluntarily or
involuntarily, then that end-user must curtail its use of natural gas.
If a core end-user's supply is diverted, then that customer must pay
any penalties if it continues to use gas, as referenced later in this
Section.
b. The following diversion procedures will apply to ensure service
reliability to core end-users. PG&E's core procurement department and
core aggregators, on behalf of core customers, will use:
i. their own firm capacity, to the extent possible;
ii. any available As-available capacity on the system at any receipt
point; and
iii.available voluntary diversion of supply from noncore end-users or
other transmission system shippers, at prices not to exceed the
cost of involuntary diversion.
c. Involuntary diversion of gas supply on the transmission system will be
used as a last resort to ensure service reliability for core end-users.
Firm transportation to off-system is not subject to diversion.
Diversion will occur in the following order:
i. Noncore supply scheduled under As-available transportation is
diverted in order of contract transmission price and on a pro rata
basis for all volumes with the same price. However, scheduled
deliveries from storage using As-available transmission will be
treated as the highest priority noncore firm transmission.
ii. Firm transportation to on-system noncore end-users.
d. Those receiving involuntarily diverted supply will be assessed a
$50/Dth diversion usage charge in addition to a $50/Dth EFO curtailment
noncompliance penalty, for a total noncompliance charge of $100/Dth.
These revenues will be used first to pay diversion credits to those
whose gas supply is involuntarily diverted. The remaining revenues will
be returned to all customers in the customer class charge.
e. Firm transportation service customers whose gas supply is involuntarily
diverted will receive a $50/Dth diversion credit.
f. As-available transmission service customers whose gas supply is
involuntarily diverted will receive a diversion credit based on the
current market price of the diverted supply.
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<PAGE>
13. Balancing Service
a. Basic Service
i. Balancing service will be provided on a monthly basis through a
single integrated gas system for both transmission-level and
distribution-level customers.
ii. All customers shall exercise best efforts to have daily gas
receipts match daily gas usage.
iii.Monthly imbalances can be carried forward one month, not to exceed
plus or minus five percent of the usage in the month in which the
imbalance occurred, except as noted in items a.iv and d, below.
iv. If at any time the aggregate imbalance on PG&E's system (excluding
the operation of the storage reserved for balancing) has exceeded
plus or minus three percent of that month's aggregate deliveries
(excluding gas scheduled for subsequent delivery off-system) for
two months in the preceding 12 month period, then the imbalance
carry-over allowance will be decreased one percent after a minimum
of 30 days notice to the market. This provision can be used to
lower the imbalance carry-over allowance no more than once in any
12 month period. The carry-over allowance will not be set below
three percent without CPUC approval. All references in the Gas
Accord to a five percent carry-over allowance and to the tiers for
monthly imbalance cash-outs are intended and understood to be
subject to change by operation of this provision.
v. Operational Flow Order (OFO) and Emergency Flow Order (EFO)
provisions will be used to manage operational imbalances when
necessary.
b. Customer Imbalances
i. Imbalances generally will be maintained at the delivery point. For
deliveries made to on-system end-users, the end-user will be
responsible for imbalances. For deliveries to storage and to off-
system points, the transmission shipper will be responsible for
imbalances.
ii. End-user imbalance accounts may be assigned to a third party.
iii.A third party may aggregate imbalance accounts.
c. Imbalance Trading
i. Monthly imbalance quantities may be traded with another entity.
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<PAGE>
ii. Imbalance quantities can only be traded with other imbalance
quantities that occurred during the same calendar month. Trading
between on- and off-system imbalances is not allowed.
iii.Any imbalance trade must move the trader's imbalance quantity
toward zero, unless the imbalance resulting from the trade is
within the range of plus or minus three percent.
iv. Imbalance trading into and out of storage will be available. Firm
storage customers may use a PG&E (or other on-system storage
provider's storage account subject to having an appropriate
operational balancing agreement between PG&E and the other storage
provider) to trade transportation imbalances, during the imbalance
trading period, within operational limits.
d. Imbalance Charges and Cash-Out
i. Automatic cash-out of all commodity and transmission imbalances
outside of allowed carry-forward quantity each month will occur.
In-kind imbalance deliveries will not be included. Imbalance cash
-outs will have a commodity and a transmission component. Monthly
imbalance cash-out occurs after imbalance trading for the month is
complete.
ii. Commodity cash-out prices for each month for each interconnect are
based on the higher (for under-deliveries) or lower (for over-
deliveries) of the following gas price indexes at PG&E
interconnects (e.g. Malin, Topock) from public sources (e.g.
Bloomberg, Gas Daily):
* Monthly index price;
* Under-deliveries: average of the five highest daily index prices
during the month;
* Over-deliveries: average of the five lowest daily index prices
during the month.
iii.The commodity cash-out index price for imbalances less than or
equal to ten percent will weight the appropriate interconnect
indices by the supply mix of all gas received by PG&E for on-system
customers during the month in which the imbalance occurred.
Imbalances greater than ten percent will be cashed-out based upon
an index equal to the highest interconnect index price for under-
deliveries and the lowest interconnect index price for over-
deliveries, regardless of PG&E's supply mix.
iv. The commodity cash-out index price will be adjusted by the
following percentages, according to the level of the actual monthly
imbalance:
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<PAGE>
<TABLE>
<CAPTION>
Monthly Imbalance Over-delivery (OD) Under-delivery (UD)
Level Purchase Dollars Sale Dollars
- ----- ---------------- ------------
<S> <C> <C>
+/-5% to +/-10% 95% weighted OD index 105% weighted UD index
>+/-10% 50% lowest index 150% highest index
</TABLE>
v. Transmission service cash-out prices are based on the volumetric
component of PG&E's standard tariff firm (MFV) and As-available
transmission services. Over-deliveries will receive a transmission
service credit based on the volumetric component of the appropriate
firm transportation rate. Under-deliveries will be charged the
appropriate rate for As-available service. The appropriate rate is
determined by weighting the path specific rates by the supply mix
of all gas received by PG&E for on-system customers during the
month.
vi. PG&E gas purchases and/or sales associated with cash-outs will be
accounted for separately from the core portfolio purchases.
vii.The intent of imbalance cash-outs is to create an economic
disincentive for incurring cash-out imbalances. PG&E will file to
revise the imbalance charges and cash-out options if the Gas Accord
provisions do not accomplish this.
e. Operational Flow Order Provisions
i. System-wide, local, or customer-specific OFO provisions may be
called to order out-of-tolerance customers to balance supply and
demand daily, when operationally necessary. OFO provisions will
require daily balancing and impose penalties for noncompliance.
ii. OFOs may be called if pipeline inventory exceeds or is forecast to
exceed desired pipeline inventory by 200 MMcf/d, or is below or is
forecast to be below desired pipeline inventory by 150 MMcf/d.
Desired pipeline inventory in the winter is typically 4.2 Bcf and
in the summer is typically 4.15 Bcf.
iii.PG&E will use multi-stage OFO provisions, which would provide a
daily tolerance band ranging from plus or minus 25 percent to zero
percent of actual daily usage.
iv. Multi-stage OFO non-compliance penalty provisions would range from
$1/Dth to $25/Dth. The amount of the penalty will be announced
prior to the enactment of each stage. The penalty will start at
$1/Dth and only increase during an event if the response to the OFO
is inadequate. Subsequent levels will be $5/Dth and $25/Dth, as
needed to maintain pipeline system integrity. A specific customer
may start at an elevated penalty level if that customer has a
history of non-compliance.
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<PAGE>
v. An OFO will normally be ordered with at least twelve hours notice
prior to the beginning of the gas day, or as necessary as dictated
by operating conditions. Penalties will not be imposed with less
than twelve hours notice.
vi. For each noncore end-user without telemetering, compliance with an
OFO will be determined by comparing the end-user's supply against a
5:00 p.m. day-before PG&E forecast of the end-user's usage.
f. Emergency Flow Order Provisions
i. Emergency Flow Order conditions are defined to exist when a
forecast or actual supply and/or capacity shortage threatens to
affect the delivery to end-users.
ii. EFOs will have a zero percent tolerance (supply must be greater
than or equal to usage) and a $50/Dth noncompliance penalty.
iii.For each noncore end-user without telemetering, compliance with an
EFO will be determined by comparing the end-user's supply against a
5:00 p.m. day-before PG&E forecast of the end-user's usage.
iv. If an involuntary supply diversion is called in conjunction with an
EFO, an additional $50/Dth diversion usage charge will apply for a
total potential noncompliance penalty of $100/Dth.
v. An EFO would normally be ordered following an OFO, but could also
occur under an emergency operational condition. There is no
required notice period for EFOs, however, PG&E will attempt to
provide as much notification to customers as possible.
vi. PG&E reserves the right to implement other measures to ensure
system integrity should the EFO actions not alleviate the emergency
condition.
g. Other Operational Balancing Issues
i. Transmission-level end-users and distribution-level noncore end-
users will be required to have daily metering.
ii. Telemetering will be installed on noncore customers' meters where
it is cost-effective. These costs will not change the rates
established by the Gas Accord.
iii.PG&E reserves the right to propose other measures to ensure system
integrity should the OFO and/or EFO provisions not prove to be
adequate.
iv. A load profile modeling tool will be developed to determine daily
usage for PG&E's core procurement customers and core transport
customers served by
-27-
<PAGE>
core aggregators in order to remove PG&E's core portfolio from
providing a system balancing function, and to be able to hold
PG&E's core procurement department to the same balancing and OFO
provisions to which others are held.
v. The normal nomination deadline will be shifted to one day prior to
gas flow at all receipt points where the upstream operator(s) will
accommodate the shift.
vi. PG&E will allow same-day nominations, if necessary, and if upstream
and downstream operator(s) are able to accommodate the practice.
14. Transmission Level End-Use Service
a. To be eligible for transmission-level end-use service, an end-user
must:
i. Be a noncore customer;
ii. Be physically connected to the transmission system or have an
annual load in excess of 3 million therms/year; and
iii.Elect to receive transmission level end-use service.
b. All on-system transmission-level end-users must pay local transmission
charges.
c. All other end-users will be served at distribution tariff rates.
d. The definition of a noncore customer may be revisited in BCAPs during
the Accord period.
15. Negotiated Contracts
a. Standard tariff rates and terms are available to all customers.
b. PG&E may distinguish between parties in offering negotiated rates by
evaluating differences in circumstances and conditions, including but
not limited to differences occurring upstream, downstream or at the
customer's location, affecting either cost of service or the entities'
market alternatives. Such negotiations will be conducted without undue
preference or undue discrimination.
c. Negotiated rates for transmission and storage service shall not be less
than PG&E's short-run marginal cost of providing the service.
Negotiated transmission rates under NFT and NAA will be capped at 120
percent of the tariffed rate for the particular service on the
particular path. Negotiated storage rates (NFS and NAS) will be capped
at the price which will provide PG&E the opportunity to recover its
total embedded cost revenue requirement for the unbundled storage
program for each of the three storage subfunctions (e.g., inventory,
injection, or withdrawal).
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<PAGE>
d. To the extent that PG&E negotiates a transmission contract for its
Malin to on-system path with an on-system end-user, and the negotiated
backbone rate component offered is below the analogous Topock to on-
system path rate, e.g., seasonal firm, PG&E agrees to offer to that
end-user the same negotiated rate for a Topock to on-system path
contract, to the extent that capacity is available .
e. Negotiated rates for parking and lending services shall not be less
than PG&E's short-run marginal cost of providing the service. These
rates will be capped at a daily and/or annual cost to cycle gas using
firm storage service.
f. PG&E will issue monthly reports to CPUC covering all negotiated
contracts, including those negotiated under NFT, NAA, NFS, and NAS, but
excluding PARK and LEND. PG&E will make the report available upon
request. Customer names, including PG&E's affiliates and other
departments, will not be disclosed in the report. However, the report
will indicate whether a particular transaction was with an affiliate.
The report will show the negotiated contract rates.
g. The CPUC's complaint procedure will be available to address any undue
discrimination claims.
h. PG&E may also offer other customer-specific negotiated contracts.
Negotiated transmission and storage service contracts under NFT, NAA,
NFS, and NAS will not require submission to the CPUC for approval;
however, any other negotiated transmission or storage service contracts
will require submission to the CPUC for approval.
16. Affiliate and Intracompany Transactions
a. PG&E will treat PG&E's affiliates and core procurement and UEG
departments without undue preference or undue discrimination.
b. PG&E will not disclose specific shipper information to PG&E's
affiliates or core procurement and UEG departments without that
shipper's permission, except as needed to serve the shipper.
c. PG&E will provide nonpublic information about the intrastate
transmission system to all entities, including PG&E's affiliates and
core procurement and UEG departments, without undue preference or undue
discrimination.
d. PG&E will develop specific standards of conduct for affiliate
transactions to be included in its Accord tariffs.
F. SPECIAL AGREEMENTS
1. Firm Expansion Agreements
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a. As set forth in Section I.B.6, the 304 MMcf/d of Line 401 capacity
remains initially dedicated to firm G-XF service, consistent with the
Firm Transportation Service Agreements (FTSAs) previously approved by
the CPUC for service to the firm Expansion shippers. The G-XF rate will
continue to apply to this capacity and to service provided to these
shippers for the remainder of the 30-year term of these agreements, as
set forth in part (b.ii), below, except that each shipper may elect one
of the options set forth in parts (b.i) and (c), below, and, by virtue
of that election, alter the rate, term, and terms and conditions of
service. The other 509 MMcf/d of Line 401 firm capacity is redesignated
as firm capacity available for subscription under the new transmission
services described in Section II.A.
b. Options for Service: Firm Expansion shippers may elect
--------------------
one of the following options for restructuring their contractual
commitments. The shippers may elect either of the following two options
at any time up to 45 calendar days following CPUC approval of this
Settlement Agreement.
i. Accord Service: A shipper may convert its firm Expansion
---------------
contract to Firm Annual Off-System service (AFT-Off) under the
Accord for Malin to off-system service. The rate, terms and
conditions of this service are delineated in Section II.A.4. These
include a Line 401 capital cost of $736 million, and an on-system
delivery option if the shipper elects SFV rate design. Features
specially applicable to converting Expansion shippers are the
following:
* the term of the replacement contract is the full
remainder of the shipper's 30-year term under its FTSA;
* UTS and all other Expansion-related contract and tariff
rights must be irrevocably waived;
* the contract for new service is pro forma (no negotiated
agreements) and service is henceforth provided under AFT-Off and
superseding tariff(s);
* the shipper's capacity is redesignated as non-Expansion
capacity, as discussed in Section I.B.6; and
* PG&E will offer consideration as payment for the
shipper's waiver of UTS rights.
ii. G-XF Firm Service: Those firm Expansion shippers that do
------------------
not elect one of the other options set forth herein will continue
to receive service under G-XF, as described below:
* Rates are based on a $736 million capital cost, using PG&E's
proposed cost of capital and utility capital structure;
* Rates remain incremental and are based on the operating expenses
and cost allocation methodologies proposed by PG&E in its PEPR
Application;
* The G-XF firm service continues to apply, but is modified to
reflect the revenue requirement assumptions above, and the
backbone credit and crossover ban are eliminated;
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<PAGE>
* UTS and all other contract rights remain applicable only to firm
G-XF service; and
* Delivery points are as set forth in Exhibit A to each shipper's
FTSA.
c. Other Options: PG&E is also offering the following three options to
-------------
firm Expansion shippers. The following descriptions set forth PG&E's
vision of these options, but each option will be negotiated with any
interested shipper, and specific terms and conditions may vary as a
result of those negotiations. The shippers may elect one of these
options by executing the appropriate agreement with PG&E on or before
the earlier of (1) December 1, 1996, or (2) the date the CPUC approves
this Accord Settlement Agreement.
i. Negotiated Contract Amendments: A shipper may elect either a
------------------------------
discounted rate (to be negotiated with PG&E), which is fixed for
the term of the Gas Accord, or a market index rate, which would
fluctuate during the term of the Gas Accord within a negotiated
floor and ceiling based on differentials between Southwest and
Canadian prices. Service under either rate option, once agreed to,
will be provided under G-XF, as modified by the Gas Accord. At the
end of the Gas Accord term, and for the remainder of the shipper's
30-year contract term, rates will be set based on a Line 401
capital cost of $736 million. Beginning on the date the contract
amendment is executed, the shipper must waive its UTS provision
for the remainder of its 30-year contract term.
ii. Contract buyout: A shipper may terminate its contract
---------------
obligations either by making a single payment to PG&E or
accelerating payment of demand charges by means of a higher
negotiated rate for a specified negotiated term. In either case,
PG&E intends that the payment shall be of a sum less than the full
NPV of the remainder of the shipper's 30-year contract term. Upon
payment of the full negotiated buyout amount, the shipper's
contract with PG&E for Expansion transportation service, and all
rights and obligations under that contract, shall terminate, and
the capacity released thereby shall be redesignated as non-
Expansion capacity and shall become part of the pool of capacity
used to provide Accord transmission services. If a shipper elects
the accelerated payment option, service for the term of such
payment will be provided under G-XF, as modified by the Gas
Accord, and the shipper must waive its UTS provision immediately.
iii. Equity Purchase: A shipper may convert its firm service to an
---------------
equity interest in Line 401 at a purchase price to be negotiated
with PG&E. Under this option, the shipper would purchase a share
of Line 401 at least equal to the firm Maximum Daily Quantity
(MDQ) set forth in Exhibit A to the shipper's FTSA.
2. EAD Contracts
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<PAGE>
The EAD contracts provide the equivalent of contract rights as firm
transportation service (AFT) on the Topock to on-system path, but at the
contract volumetric rate. The EAD customers will have the option of
continuing to receive the same bundled transportation service, or taking
service under a Gas Accord contract. Service under Gas Accord contracts will
contribute to any use-or-pay obligations under the EAD contract. Because of
the unique terms and conditions in the various EAD contracts, individual
discussions are needed as to how specific contract provisions will be
implemented in the Gas Accord contract environment.
3. EOR Contracts
In Decisions 85-12-102 and 87-05-046, the Commission established a long-term
transportation program and set the criteria for Enhanced Oil Recovery (EOR)
contracts. Existing EOR contracts will be treated based on the Commission's
decisions during the Accord period, or until the expiration date of such
contracts, whichever is earlier. Future EOR service will be provided based
on the terms and conditions of Accord services.
4. EDCD Agreements
In Decision 94-12-061, the Commission established the Expedited Direct
Connection Docket (EDCD) for case-by-case approval of direct connection
service on PG&E's Line 401. PG&E has one EDCD application (A.96-04-007)
pending before the Commission and may file additional applications. To the
extent these applications are approved before the Gas Accord is implemented,
the underlying agreements shall continue in effect during the Gas Accord
until they expire. Otherwise, new services are provided consistent with the
Accord services.
5. Other Existing Agreements
a. Negotiated Interruptible Agreements
PG&E has a number of negotiable interruptible transportation agreements
with terms that may extend into the Accord period. PG&E will continue to
honor the terms and conditions, including the rate, negotiated for the
original term of these contracts. Because the underlying tariff (G-ITS)
will be eliminated upon Accord implementation, these terms and
conditions will be carried out through an NAA contract.
b. Crockett Cogeneration
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<PAGE>
Crockett cogeneration has a negotiated contract which provides for
transportation service at volumetric rates. PG&E will continue to honor
the terms and conditions, including the rate, negotiated for the
original term of this contract. If any terms and conditions are
unspecified by the existing contract agreement, then the applicable Gas
Accord tariffs will apply.
6. SMUD
a. Background
Sacramento Municipal Utility District (SMUD), as the largest municipal
utility in the state, is in a unique position and the Accord proposes a
unique solution to meet its needs. PG&E and SMUD have agreed, subject to
completing definitive agreements and obtaining CPUC approval, that PG&E
will sell to SMUD a qualified equity interest in Line 300 and Line 401
backbone facilities.
This transaction along with the Interim and Contingent Rate discussed
below, would settle SMUD's BCAP Phase II issues. The details of the
transaction will be part of a Section 851 filing seeking CPUC approval
of the asset sale.
b. Interim and Contingent Rate
Should the above asset transfers not occur before the Gas Accord becomes
effective, there will be an interim rate, which is also a contingent
rate in the event that the Section 851 filing is not approved as filed.
This rate will include a $0.123 per Dth discount (escalated for
inflation over time) from the local transmission charge component of the
otherwise applicable tariff rates for gas delivered and received by SMUD
or its affiliate to support its electric utility operations. This rate
treatment will terminate upon closing of SMUD's purchase of a qualified,
equity interest in Lines 300 and 401.
G. GENERAL DESCRIPTION OF TRANSMISSION AND UNBUNDLED STORAGE PROGRAM RATES
1. Unbundle transmission and a portion of storage from distribution services.
2. Establish transmission, distribution, and storage rates based on cost of
service.
3. Make transmission and storage service available to all entities,
including end-users, shippers, producers and marketers.
4. Collect social, environmental, and transition costs and balancing
accounts from on-system end-use volumes.
5. Backbone rates associated with service to storage are paid upon
injection. For on-system deliveries, the remaining transmission rates
are paid upon withdrawal.
6. New Transmission Rates
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a. Differentiate transmission rates by path to reflect facilities used
to provide service.
b. Establish two-part firm rates (reservation and usage charges) and
one-part As-available rates (volumetric or usage charges).
c. Establish a customer access charge to cover the costs of meters and
service drops, meter reading, billing and payment processing where
applicable.
7. Pre-existing Transmission Rates
For those services with pre-existing contracts discussed in Section II.F,
charge the rates shown in Section II.B.
8. Storage Rates for the Unbundled Storage Program
a. Establish two-part (reservation and volumetric) rates for both the
capacity (injection and inventory) and withdrawal subfunctions for
Firm Storage Service.
b. Negotiated storage rates may be based on three subfunctions
(inventory, injection, and withdrawal) and may be either one-part or
two-part rates.
H. TRANSMISSION AND UNBUNDLED STORAGE PROGRAM RATES
1. New Transmission Rates
a. Four rate components will be applicable to on-system transmission
service. A backbone transmission charge, a local transmission
charge, a customer class charge, and a customer access charge.
Shippers delivering on-system will be charged the backbone
transmission charge, and corresponding end-users will be charged the
local transmission charge, the customer class charge and customer
access charge.
b. The backbone transmission charge, the local transmission charge, and
the transmission-level customer access charge, will not change from
the rate set forth in this Accord, except pursuant to the z-factor.
c. New off-system transmission service under the Accord includes a
backbone transmission charge, and a customer access charge where
applicable. The backbone transmission and customer access charges
are guaranteed except for the z-factor.
d. Backbone Transmission Charge
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<PAGE>
i. The backbone transmission charge is designed to collect backbone
transmission revenues and is applicable to all transmission
customers.
ii. The retail core market receives 600 MMcf/d (609 Mdth/d) and the
core wholesale market receives up to 6.5 MMcf/d (6.6 Mdth/d) of
Malin to on-system firm intrastate capacity at vintaged rates.
iii. The Malin to on-system rate is based on an intrastate capacity
phase-in, over the period from 1997 through 2002 of 375 MMcf/d
(381 Mdth/d) of Line 401 and the portion of Line 400 embedded
costs not allocated to the retail core and core wholesale.
e. The local transmission charge collects local transmission costs and
is applicable to all on-system end-users.
f. The customer class charge includes social, environmental and
transition costs, balancing account balances and all other non-base
revenue requirements. Some of the costs included in this charge are
CARE, CEE programs, hazardous substance, and ITCS costs. It is
generally applicable to all on-system end-users.
g. The customer access charge includes the cost of meters and service
drops, meter reading, billing and payment processing, and is
applicable to the customers to whom PG&E provides these services
(see Section II.I.10).
h. Transmission rates for AFT, SFT, and AA are shown in Section VI.
2. Pre-existing Transmission Rates
Pre-existing services and contracts are discussed in Sections II.B and
II.F.
3. Storage Rates for the Unbundled Storage Program
a. Rates for storage services are based on the costs of storage
injection, inventory and withdrawal.
b. Firm Storage
i. Rates are subfunctionalized by a capacity (combined injection and
inventory) charge and withdrawal charge.
ii. Capacity and withdrawal charges are recovered through a
reservation (fixed) and volumetric (variable) component.
c. Negotiated Firm and As-available services are negotiable above a
price floor representing PG&E's short-run marginal cost of providing
the service.
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<PAGE>
d. Negotiated Firm rates can be recovered through a volumetric-only
charge or a reservation and volumetric charge.
e. Negotiated As-available Storage Injection and Withdrawal rates are
recovered through a volumetric charge only.
f. Negotiated storage rates (NFS and NAS) are capped at the price which
will collect 100 percent of PG&E's total embedded cost revenue
requirement for the unbundled storage program for each of the three
storage subfunctions (e.g., inventory, injection, or withdrawal).
The flexibility inherent in this storage offer could result in
stranded facilities and PG&E requires the opportunity to collect the
value of its storage services.
g. Firm storage rates for the unbundled storage program are shown in
Section VI.
I. COST BASIS AND RATE DESIGN
1. The Backbone Component of New Transmission Path Rates
a. Except for certain services and contracts described in Section II.F,
all on-system rates include a backbone transmission component that
varies by path, and a common backbone component. The common backbone
component includes the costs of backbone facilities used by all on-
system paths, and gathering mains.
b. The incremental Line 401 costs used in developing the Malin to on-
and off-system rates are based on the Pipeline Expansion assumptions
shown in Section II.I.3. Off-system rates do not include any common
backbone component.
c. Malin to on-system rates for the core (including core wholesale) are
based on a prorated portion of vintaged Line 400 and Line 2, and the
common backbone component.
d. Malin to on-system rates for all customers except retail core and
core wholesale include the cost of the portions of Line 400 and Line
2 not reserved for the core, the common backbone component, and a
phased-in portion of Line 401 costs as described in Section II.I.3.
e. Both the Topock to on-system and the Topock to off-system rates
include the cost of Line 300 and the common backbone component.
Capital costs of $42 million for NOx-related retrofits needed to
meet NOx emission standards are included in the Line 300 revenue
requirement. To the extent PG&E's expenditures exceed the $42
million, PG&E will be at risk for recovery of these expenditures
during the Gas Accord period, but does not waive the right to seek
recovery after that.
f. California production to on-system rates include 40 percent of the
average backbone transmission costs and the common backbone
component. California
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<PAGE>
production to off-system rates assume Line 401 will be used, and the
rate is equal to the Line 401 to off-system rate.
g. The on-system and off-system rates are guaranteed for the Accord
period, subject to change pursuant only to the z-factor provision of
Section II.I.7.
2. The Storage Costs in the Unbundled Storage Program
a. The storage costs allocated to the unbundled storage program
represent 12.5 percent of the inventory, injection, and withdrawal
storage costs remaining after the allocation for load balancing
requirements.
b. The maximum rates for Negotiated Firm Storage and Negotiated As-
available Storage are based on a rate design assuming an average
injection period of 30 days and an average withdrawal period of
seven days. The rates assume full collection of the total unbundled
storage program revenue requirement in each individual subfunction.
c. The minimum rates for Negotiated Firm Storage and Negotiated
As-available Storage are based on the marginal price floor to provide
the service.
3. Revenue Requirement Assumptions
a. Gas Department (excluding Pipeline Expansion)
i. Initial base revenue requirements for calculating 1997 rates
match PG&E's 1996 GRC.
ii. Cost of capital and capital structure are based on the 1996 Cost
of Capital proceeding's authorized cost of capital for the gas
department.
iii. Gas department common costs are allocated to backbone
transmission, local transmission and distribution based on plant
and labor.
b. Development of the Line 401 Revenue Requirement
i. Base revenue requirements are calculated using the proposed
litigation resolution figure of $736 million of capital costs
discussed in Section V. Operating expenses and the methods used
to allocate costs and calculate taxes and the revenue
requirement match PG&E's current position in the Pipeline
Expansion Project Reasonableness (PEPR) Case.
ii. Cost of capital and capital structure matches PG&E's gas
department cost of capital as authorized in the 1996 Cost of
Capital Decision 95-11-062, with no premium on the return on
equity.
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iii. No common costs, except those included in the PEPR Case, are
included. The cost allocation methods match those used in the
PEPR Case. The allocation of original facilities to the
Expansion increases to the amount proposed by PG&E in the PEPR
Case.
c. Line 401 Cost Phase-in to On-system Rates
Each year a portion of the Line 401 revenue requirement will be
included in the Malin to on-system rate. The portion is calculated
using the firm Expansion capacity of 813 MMcf/d (825 Mdth/d). The
Line 401 revenue requirement phased-in each year will be based on
depreciated plant. The following table summarizes the amount of
capacity used to determine the phased-in costs:
<TABLE>
<CAPTION>
Capacity 1997 1998 1999 2000 2001 2002
---- ---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C> <C>
Incremental 200 50 50 25 25 25
(MMcf/d)
Cumulative 200 250 300 325 350 375
(MMcf/d)
Cumulative 208 254 305 330 355 381
(Mdth/d)
</TABLE>
4. Load Factor and Rate Cap Assumptions
a. Firm annual on-system backbone transmission charges are based on an
annual average capacity factor of 87.5 percent. Malin to on-system
capacity increases each year consistent with the cost phase-in.
Seasonal firm and As-available rates are set at 120 percent of the
annual firm rates. As-available rates are set at 110 percent of the
annual firm rates through March 31, 1998, and at 120 percent
thereafter. The load factors used in setting backbone transmission
rates remain constant through the Gas Accord period. The core's Topock
to On-system path charge for firm seasonal capacity will be calculated
at 110 percent of the firm annual price for the period through March
1998.
b. The Malin to off-system firm rates are calculated using incremental
Line 401 costs and a 95 percent load factor. The Malin to off-system
As-available rates are set at 110 percent of firm rates through March
31, 1998, and at 120 percent thereafter.
c. On-system California production and storage to off-system rates are
equal to the Malin to off-system rates.
5. Balancing Account Treatment
a. There will be no balancing account treatment for backbone or local
transmission revenues, or for parking or lending service revenues.
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b. The current storage program has a contractual operating period from
April 1 through March 31. Therefore, PG&E will not offer firm storage
service until April 1, 1998, and PG&E will continue to honor storage
contracts for the 1997/1998 storage season. PG&E may begin offering
as-available storage service upon implementation of all other
services if capacity is available. Balancing account treatment for
the current storage program will continue through March 31, 1998.
Any outstanding balance plus interest will be allocated to core and
noncore customers on an equal cents per therm basis. PG&E will
absorb 100 percent of the core share.
6. Shrinkage (compressor fuel, and lost and unaccounted for gas)
In-kind shrinkage will be charged to all gas shipped on the PG&E
transmission system on a postage-stamp basis. Additional shrinkage will be
charged for distribution service, also on a postage-stamp basis. The Malin
to off-system shrinkage rate is the rate adopted in Decision 94-02-042.
The shrinkage rate for all other transmission paths is developed using
rates authorized in PG&E's BCAP Decision 95-12-053 and is subject to
change in subsequent BCAPs. Transmission shrinkage will be charged for all
deliveries into storage, but not for deliveries out of storage.
Path Shrinkage Rate
---- --------------
Malin to Off-system 1.11%
All Other Transmission Paths 1.72%
7. Rate Adjustments
a. The Line 400 component of Malin rates escalates at 2.5 percent
annually.
b. Line 401 costs used to establish the phase-in component of the Malin
to on-system rates and the Malin to off-system rates are adjusted in
accordance with PG&E's Pipeline Expansion Rate Case methodology and
the litigation resolution agreement in Section V.
c. Line 300 rates escalate at 2.5 percent annually, plus the revenue
requirement associated with the $42 million of capital cost additions
for NOx-related retrofits needed to meet NOx emission standards.
d. Storage and parking and lending rates escalate at 2.5 percent
annually.
e. The guaranteed rates may be adjusted by a z-factor to reflect
extraordinary costs or savings. The z-factor is limited to known
changes due to governmental action. An example of a government action
would include changes to the federal or state income tax rate. The z-
factor mechanism would not replace either the current CEMA or the
Hazardous Substance incentive mechanism, both of which would remain in
effect.
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f. The following z-factor sharing mechanism (costs or savings) is
adopted for cost responsibility per each extraordinary event:
<TABLE>
<CAPTION>
z-Factor Cost (Savings) Cost
Per Event Responsibility
----------------------- --------------
<S> <C>
$0 - $5 million 100% PG&E
(greater than) $5 - $10 million 50/50 sharing
(greater than) $10 million 100% customers
</TABLE>
8. Local Transmission Charge
a. The charge includes the cost of local transmission facilities.
b. The local transmission charge is paid by all on-system end-users.
This charge is non-bypassable.
c. The local transmission charge varies by core and noncore customer
class. Local transmission costs are allocated to core and noncore
based on LRMC methodology from PG&E's BCAP Decision 95-12-053.
d. Local transmission rates escalate at 2.5 percent annually.
e. The local transmission charge will have no balancing account
protection.
f. The rates are guaranteed for the Accord period, subject only to the
z-factor provisions of Section II.I.7.
g. Local transmission rates are shown in Section VI.
9. Customer Class Charge
a. The customer class charge is designed to collect social, environmental
and transition costs, balancing account balances, and all other non-
base revenue requirements. Some of the costs included in this charge
are CARE, CEE programs, hazardous substance, and ITCS costs.
b. The core customer class charge does not include ITCS. PG&E will absorb
all of the core portion of the ITCS charges as defined herein, less
brokering revenues, plus interest, from the beginning of the ITCS
account, as part of the litigation resolution described in Section V.
The customer class charge includes a "true-up" of ITCS costs collected
from core customers prior to Accord implementation.
c. The noncore customer class charge includes only 50 percent of the
noncore ITCS costs, less brokering revenues, plus interest, from the
beginning of the ITCS account. PG&E will absorb the remaining 50
percent of the noncore ITCS costs, as part of the litigation
resolution described in Section V.
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d. The customer class charge does not include any component for recovery
of the backbone credit. PG&E will absorb 100 percent of the Backbone
Credit Account. PG&E will not provide any shipper with a backbone
credit after the Gas Accord is approved, as part of the litigation
resolution described in Section V.
e. Initial customer class charges have been allocated to customer classes
and will be collected in rates as determined in PG&E's 1996 GRC and
PG&E's BCAP Decision 95-12-053. These charges will be periodically
adjusted based on the regulatory proceedings associated with each
account and continue to be subject to balancing account treatment.
f. PG&E will collect the existing balance in the Noncore Fixed Cost
Account (NFCA), but will not record any activity to the account other
than amortization revenue and interest after implementation of the Gas
Accord.
g. Customer class charges will be paid by on-system end-users only.
However, loads subject to Line 401 direct connect agreements or EOR
contracts will neither pay, nor be allocated, customer class charges
while the direct connect agreements or contracts are in effect.
h. Forecast customer class charges are shown in Section VI.
10. Customer Access Charge
a. End-users who are directly connected to the transmission system will
pay a customer access charge each month. The purpose of the customer
access charge is to assess the end-user a fee for the cost of
providing and maintaining the individual end-user's service connection
to the transmission system.
b. For industrial end-users, the customer access charges will be the same
as the current industrial customer charge. With the current industrial
customer charge, each end-user is placed in one of six tiers depending
on the end-user's specific annual volumetric usage. There is a
specific monthly charge associated with each tier. Distribution
industrial customers will have the same initial customer access charge
as part of their distribution rates.
c. The UEG and cogenerator customer access charges will be based on the
annual scaled marginal customer cost revenues adopted in BCAP Decision
95-12-053. For UEG, the customer access charge is a monthly charge.
For cogeneration end-users, the customer access charge will be a
volumetric adder, calculated such that the UEG-cogeneration rate
parity is maintained. For cogeneration end-users currently on Schedule
G-CGS, the volumetric adder will equal UEG customer access charges for
twelve months divided by the UEG average annual forecasted throughput
adopted in BCAP Decision 95-12-053. For cogeneration end-users
currently on Schedule G-EPO, the volumetric adder will equal the UEG
monthly
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<PAGE>
customer charge divided by UEG actual monthly throughput, lagged by
sixty days.
d. For wholesale customers, the customer access charge for each month of
1997 will equal the scaled annual marginal customer cost revenues
adopted in BCAP Decision 95-12-053 for each specific wholesale
customer divided by twelve.
e. Customer access charges escalate at 2.5 percent per year annually.
f. Current customer access charges are shown in Section VI.
g. Customer access charges for transmission level customers are
guaranteed for the Accord period, subject only to z-factor changes
described in Section II.I.7.
11. Cogeneration Rate Parity
a. On-system cogeneration tariff transmission rates will be available to
all cogenerators, including EPO3 cogenerators, from PG&E's
transmission department. For each path and service, cogenerator rates
will be set equal to the average Utility Electric Generation (UEG)
rate for that path and service. UEG negotiated rates received from
PG&E's transmission department will be included in the rate
calculations on a weighted average,/1/ path specific, service-
-
specific/2/ basis. PG&E will develop, in cooperation with
-
cogenerators, a-mechanism to incorporate UEG negotiated rates into
cogeneration rates.
b. In the event that the current methodology used to determine payments
to EPO3 cogenerators changes so that it is no longer based on actual
UEG natural gas costs, PG&E will negotiate with EPO3 customers in good
faith to develop a method for calculating EPO3 natural gas
transmission service rates which maintains the linkage between EPO3
cogenerators' transmission rates and their electricity payments. Such
resulting rates would be subject to CPUC approval and will apply only
until the expiration of the EPO3 payment option.
- -------------------
/1/ That is, the firm service rate for cogenerators will be calculated using
-
any-negotiated rates for firm service for UEG weighted by volume; similarly, the
As-available service rate for cogenerators will be calculated using any
negotiated rates for As-available service for UEG weighted by volume.
/2/ For purposes of this paragraph, the term "service specific" shall refer
-
to-either firm service or As-available service (including negotiable rate, non-
negotiable rate and other variations of such service) and indicates the
distinction between firm and As-available as separate services.
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<PAGE>
c. Transportation services provided to the UEG by entities other than
PG&E's transmission department will not be included in the
cogeneration rate calculations. The UEG includes only PG&E-owned
utility fossil-fired generation facilities. If the UEG does not take
any service from PG&E's transmission department on a particular path
for a particular service, the on-system cogeneration tariff rates for
that path and service will equal the otherwise-applicable cogeneration
tariff rates for that path and service.
d. On-system cogeneration transmission rates will be available only to
cogeneration end-users for their own usage up to the authorized
cogenerator gas allowance./3/ If the cogeneration rate parity statute
-
(Public Utilities Code Section 454.4) is amended or repealed so that
"rate parity" is no longer required by statute,/4/ and if the CPUC
-
for whatever reason no longer requires such rate parity, then there
will be no separate transmission tariff rates applicable to
cogeneration end-users. For purposes of this paragraph, PG&E shall be
free at any time (following the amendment or repeal of the
cogeneration rate parity statute so that "rate parity" is no longer
required by statute) to file a superseding tariff for cogenerators
with the CPUC, which filing may be the occasion for the CPUC to
reevaluate the requirement for such rate parity. Cogenerators
expressly retain the right to oppose such a filing by PG&E./5/
-
e. An on-system cogenerator's monthly bill for non-discounted tariff
service provided by PG&E's transmission department shall be the
minimum of the bill calculated using the transmission rates described
above, and the bill calculated using the otherwise-applicable tariff
transmission rates for that path and service.
f. During open seasons for intrastate transmission capacity, PG&E will
notify on-system cogenerators of UEG's elections for service from
PG&E's transmission department three business days prior to the date
that cogenerators must make their service elections. PG&E will also
notify on-system cogenerators of UEG's other elections for service
from PG&E's transmission department as they may occur
- -----------------------
/3/ The cogenerator gas allowance is not to be determined by the Gas Accord,
-
except that it will remain within 10 percent of 0.09683 th/kWh.
/4/ The Gas Accord does not restrict either PG&E or cogenerators from seeking
-
legislative changes to P.U. Code Section 454.4, but the parties shall support
the provisions of the Gas Accord before the CPUC.
/5/ The provisions of this section are not intended to limit parties'
-
abilities to address before the CPUC any issue they think appropriate dealing
with the divestiture of PG&E generation units. This could include discussion of
any cogeneration rate parity topics as they might relate in any way to divested
units.
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<PAGE>
from time to time. This will apply only to UEG service agreements
whose durations are more than 30 days.
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<PAGE>
III. DISTRIBUTION SERVICES
A. SERVICES FOR NONCORE END-USERS
1. Distribution transportation service: Noncore customers connected to
PG&E's distribution system may arrange for transmission, storage,
and supply services separately. These customers receive noncore
distribution service from PG&E.
2. Core subscription: Noncore customers may have PG&E arrange for
their supply and transmission service under core subscription
service, described in Section IV.M.
3. Residual load service: PG&E will propose a residual load service in
the next BCAP.
B. SERVICE FOR CORE END-USERS
1. PG&E will continue to provide bundled service for coreend-users.
See Section IV for changes that may affect core service.
2. PG&E will also provide core transport service for core end-users.
See Section IV for a discussion of core aggregation.
C. RATES AND COST ALLOCATION
1. Distribution Revenue Requirement Assumptions
a. The initial natural gas distribution revenue requirement will
match PG&E's 1996 GRC Decision 95-12-055, consistent with the
transfer of DFMs to local transmission. Customer access charges
for transmission-level end-users have been moved from the
distribution revenue requirement to the customer access charge.
b. The distribution revenue requirement in future years of the Gas
Accord will be based on cost of service or Performance Based
Regulation (PBR), whichever is applicable. For the purposes of
calculating the illustrative rates shown in Table 16 in Section
VI, the revenue requirement escalates at 2.5 percent per year.
2. Distribution Cost Allocation
a. The initial distribution revenue requirement will be allocated to
end-users on an Equal Percent of Marginal Cost (EPMC) basis, using
distribution and customer marginal cost revenues consistent with
PG&E's BCAP Decision 95-12-053.
b. PG&E will continue to have BCAPs and GRCs or successor proceedings
to update the allocations of costs. The methodology for allocating
the distribution revenue requirement between core and noncore will
not be changed for the term of the Gas Accord, although the
allocation itself may change due to, among other
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<PAGE>
things, changes to throughput forecasts or marginal costs. The
allocation of revenues within the core will be addressed in
future BCAPs.
3. Distribution Throughput
a. Distribution throughput for noncore end-users has been modified to
reflect loads served directly from the transmission system, as
well as end-users connected to the distribution system but
classified as transmission customers.
b. Core and noncore throughput forecasts will be addressed in future
BCAPs or PBRs.
4. Balancing Account Treatment
a. PG&E's core procurement department's cost of intrastate backbone
and local transmission service for the core will receive 100
percent balancing account treatment for the costs incurred, either
through the Core Fixed Cost Account (CFCA) or the Purchased Gas
Account (PGA).
b. The core distribution revenue requirement will continue to
receive 100 percent balancing account treatment.
c. Balancing account treatment (Noncore Fixed Cost Account) for
prospective noncore distribution revenues will be eliminated.
5. Shrinkage
a. Noncore customers and core transport customers will continue to
deliver in-kind shrinkage. Bundled core end-users and core
subscription customers will continue to pay shrinkage as part of
their procurement rate.
b. Shrinkage will be charged on the distribution system on a postage-
stamp basis for all gas deliveries. Distribution shrinkage is in
addition to any shrinkage applied on the transmission system.
c. Distribution shrinkage is calculated using percentages authorized
in PG&E's most recent BCAP Decision 95-12-053, as follows: the
core distribution shrinkage rate (including core transport) is
3.31 percent, and the noncore distribution shrinkage rate is 0.21
percent. These percentages are subject to change in future BCAPs.
The core shrinkage subaccount will continue as currently
authorized.
6. Distribution Rates and Rate Design
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<PAGE>
a. Forecast distribution rates and illustrative intrastate bundled
core transportation rates are shown in Section VI.
b. The initial core commercial winter distribution rate component
will remain at 135 percent of the summer distribution rate
component. For core commercial customers taking bundled service
from PG&E, intrastate transmission costs will be allocated into
the season in which they are incurred, and storage costs will be
included in winter season rates only. Commodity costs will not be
included in any seasonal rate differential calculation.
c. The initial noncore winter distribution rate component will be
135 percent of the summer distribution rate component.
d. Future distribution rate design, rates, residential tier
differentials, and core deaveraging, among other things, will be
determined in future BCAPs. Parties also reserve the right to
propose other cost-based core cost allocation and rate design
changes in future BCAPs.
7. Cogeneration Rate Parity
a. Consistent with the CPUC's cogeneration rate parity policy,
distribution level cogenerators will not have a distribution
component in their rate. The resulting "cogeneration shortfall"
will be a part of the customer class charge, and will be collected
from cogeneration and UEG end-users, for their own usage up to the
authorized cogenerator gas allowance.
b. If the cogeneration rate parity statute is amended or repealed so
that "rate parity" is no longer required by statute, and if the
CPUC for whatever reason no longer requires such rate parity, then
distribution level cogenerators will be served under the otherwise
applicable distribution rate, and there will be no separate
cogeneration class.
c. PG&E shall be free at any time (following the amendment or repeal
of the cogeneration rate parity statute so that "rate parity" is
no longer required by statute) to file a superseding tariff for
cogenerators with the CPUC, which filing may be the occasion for
the CPUC to reevaluate the requirement for such rate parity.
Cogenerators expressly retain the right to oppose such a filing by
PG&E.
8. Discounting
a. Distribution service may be discounted to prevent uneconomic
bypass of PG&E's distribution system and to encourage business
retention and business attraction.
b. PG&E may negotiate discounts with distribution-level noncore end-
users to prevent uneconomic bypass of PG&E's distribution and
transmission systems, and to encourage business retention and
business attraction.
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<PAGE>
c. Any negotiated discounts with core end-users for distribution
service will require CPUC approval prior to going into effect.
d. If the purpose of a noncore discount negotiation is to attract or
retain both transmission and distribution load, any discount will
be "split" between transmission and distribution services
proportional to the revenue to each system at full tariff prices.
The noncore end-use customer would receive the transmission
portion of the discount in a bill credit, or through local
transmission or customer access charges.
e. If a negotiated distribution service benefits only the
distribution system, any discount will be reflected only in
distribution rates.
f. PG&E will have the option in BCAP proceedings of demonstrating the
reasonableness of any discounted distribution contracts that will
continue into the prospective period. If the Commission finds the
discounts to be reasonable, PG&E will be allowed to recover the
forecasted revenue shortfalls during the prospective period.
g. Negotiated contracts and affiliate transactions rules which will
apply to transmission services will also apply to distribution
services. (See Sections II.E.15 and II.E.16.)
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<PAGE>
IV. PG&E'S FUTURE ROLE IN CORE PROCUREMENT
A. OVERVIEW
PG&E proposes to reduce costs to customers and to expand core customer
choices by:
1. Encouraging greater customer choice among gas suppliers;
2. Reducing PG&E's regulated sales of gas to core customers;
3. Reducing PG&E's interstate pipeline capacity holdings for the core;
4. Establishing operational principles that provide market flexibility
while ensuring safe and reliable service;
5. Implementing appropriate incentive mechanisms; and
6. Negotiating with California producers for a mutual release of PG&E's
gas purchase contracts and reducing gas gathering costs through the
disposal of assets.
B. CORE PROCUREMENT ADVISORY GROUP
1. Significantly reducing PG&E's role in the core procurement market
requires significant expansion of the current core gas transportation
program. This program now serves only about three percent of the core
load in PG&E's service area, and well under one percent of core
customers.
2. To determine the changes that should be made to the program, PG&E
invited all Gas Accord parties to participate in the Core Procurement
Advisory Group (CPAG). The focus of the CPAG was the development of
recommendations that would accomplish two primary objectives:
a. Make the program consistent with the proposed Gas Accord
framework; and
b. Remove barriers, from both the customers' and aggregators'
perspectives, to increasing program participation.
3. Approximately 50 parties joined PG&E and identified over 40 separate
issues that needed to be resolved. Two working groups were
established to conduct the detailed negotiations necessary to resolve
these issues and balance the widely diverse interests of the parties.
4. After the initial package of recommendations was developed, three
new CPAG working groups were established to facilitate
implementation of the CPAG recommendations:
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<PAGE>
a. Market Test: The Market Test work group will participate in the
-----------
development and performance of market research and affinity-
group marketing field tests that are required to enhance core
aggregation in PG&E's service area.
b. Tariff Revisions: The Tariff Revision work group will assist as
----------------
PG&E's tariffs are revised to incorporate the CPAG
recommendations that are ultimately approved in the Gas Accord
proceeding.
c. Load Forecast and Determination Model: The Load Forecast and
-------------------------------------
Determination Model work group will participate in the
development of a model that will be used for core load balancing
purposes.
5. The agreements below reflect the approved package of CPAG
recommendations. The core aggregation agreements are intended to
apply to PG&E's service area. They are not intended to set precedents
for any other utility service area, or for noncore service.
Additional information about the detail behind these proposals can be
found in the CPAG agreement.
C. PG&E'S AND AGGREGATORS' ROLES IN THE CHANGING CORE GAS SALES MARKET
1. As part of its compliance filing following approval of the Gas
Accord, PG&E will file tariffs to lift the ten percent cap on PG&E's
core gas aggregation program.
2. Aggregators have the obligation to make and pay for all necessary
arrangements to deliver gas to PG&E to match the use of their
customers.
3. PG&E has the obligation to operate the gas system safely and
efficiently and to purchase gas supplies for customers not served by
aggregators.
4. PG&E's remaining core gas procurement role will be as a regulated
utility supplier within PG&E's service area during the Gas Accord
period.
5. The CPAG will explore, through market research efforts, several ways
to attract small and highly seasonal customers to core transportation
service and to reduce transaction costs for aggregators to serve
them.
6. PG&E and the aggregators will each be responsible for dealing with
their own customers' payment problems. The allocation of costs to
serve slow- and non-paying customers will be reexamined when PG&E's
core gas sales market share drops to 80 percent.
7. The costs of social and environmental programs such as CARE, clean
air vehicles and customer energy efficiency will continue to be
recovered from all on-system end-users through the customer class
charge component of the transportation rates.
8. CARE core transportation customers will receive the full CARE
benefits regardless of their choice of gas supplier.
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<PAGE>
D. REDUCING PG&E'S INTERSTATE PIPELINE CAPACITY
PG&E will adjust its core capacity holdings of firm interstate pipeline
capacity as follows:
1. PG&E's contract with El Paso will terminate at the end of 1997. As
part of the current El Paso general rate case (FERC Docket Nos. RP95-
363-000, et al.), PG&E's termination of this contract, as well as
other utility contract step-downs and the related costs, are
addressed in a settlement filed with the FERC on March 15, 1996. The
parties agree that any costs paid by PG&E resulting from the FERC-
approved settlement will be treated as one component of the overall
interstate pipeline reservation charges; and therefore, will be
allocated to core and noncore customers using the allocation
methodology for interstate pipeline reservation charges adopted in
PG&E's BCAP Decision 95-12-053.
2. PG&E reserves the right to subscribe to additional interstate
capacity in the future, with costs assigned to PG&E's core
procurement customers.
3. Other reductions may be made by PG&E (as allowed by PG&E's
interstate capacity contracts) as core aggregators' share of the
core market increases.
E. PG&E'S CORE PROCUREMENT DEPARTMENT INTRASTATE PIPELINE AND STORAGE
CAPACITY
1. PG&E's core procurement department will hold intrastate
transportation capacity on behalf of its core and core subscription
customers. The following initial firm reservation of intrastate
transportation capacity will be made for the retail core:
a. PG&E's retail core initially will be allocated the following
quantities of firm transmission capacity:
<TABLE>
<CAPTION>
Malin to Topock to
On-system On-system California
--------- ---------- ----------
<S> <C> <C> <C>
Annual MMcf/d 600 150 50
Mdth/d 609 155 48
</TABLE>
b. PG&E's retail core will also hold additional seasonal winter
capacity as follows:
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<PAGE>
<TABLE>
<CAPTION>
Malin to Topock to
On-system On-system California
--------- --------- ----------
<S> <C> <C> <C>
November and March
MMcf/d 0 150 0
Mdth/d 0 155 0
December to February
MMcf/d 0 450 0
Mdth/d 0 464 0
</TABLE>
2. The initial firm allocation of Malin capacity for the retail core
will be priced at vintaged rates.
3. PG&E's core procurement department will continue to be allocated firm
rights to a portion of storage capacity on behalf of the core market,
as specified in Section II.E.5. The core's storage and other costs
related to maintaining the safe and reliable operation of the gas
system will be included in core rates.
F. CORE AGGREGATORS' HOLDINGS OF INTERSTATE CAPACITY
1. PG&E will make two filings to unbundle interstate transmission costs
from core transport rates within 30 days after a comprehensive Gas
Accord agreement is signed.
a. The first filing will address unbundling prior to January 1,
1998. This filing will:
i. unbundle PGT and El Paso capacity;
ii. impose a surcharge on core transport rates until January 1,
1998, not to exceed $0.19/Dth, to cover any resulting
transition costs;
iii. continue the present treatment of ANG and NOVA costs; and
iv. implement the rate credit described in Section IV.G.6.
b. The second filing will address unbundling after January 1, 1998,
when PG&E's El Paso contract will expire. This filing will:
i. continue unbundling of PGT capacity; and
ii. provide that, once the core transport share of PGT core
capacity exceeds the point where PG&E's remaining PGT core
capacity matches its upstream rights on ANG and NOVA,
approximately 40 MMcf/d, core aggregators taking a share of
PGT core capacity will have the right, but not the
obligation, to accept a proportionate share of ANG and NOVA
capacity, to the extent it is available, for additional PGT
capacity reservations.
iii. provide that, to the extent that core aggregators taking a
share of PGT core capacity choose not to take a
proportionate share of ANG and NOVA
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<PAGE>
capacity, PG&E will have the right to offer to assign the
capacity to other shippers for one month up to the duration
of PG&E's contracts with ANG and NOVA. This may result in
core aggregator's not having access to this capacity in the
future. If PG&E chooses not to make such an offer, or is not
successful in finding shippers for the full amount offered,
PG&E will broker the capacity.
iv. provide that, 50 percent of the difference between the cost
of PG&E's contractual obligations for the proportionate
share of ANG and NOVA capacity offered to, but not taken, by
core aggregators, and the revenues collected by PG&E as a
result of brokering efforts for that capacity will be
allocated to the transportation rates paid by PG&E's core
transport customers. PG&E's shareholders will be at risk for
the remaining 50 percent.
2. Core aggregators will choose their own interstate pipeline capacity
mix. Each month, core aggregators will have a preferential right
(but not the obligation) to acquire a portion of PG&E's interstate
capacity holdings to serve their core customers.
3. If core aggregators choose not to acquire PG&E's firm capacity
rights, or if this capacity is marketed at less than as-billed rates,
unrecovered pipeline reservation fees will become a transition cost,
subject to the $0.19/Dth cap in Section IV.F.1.a.ii above until
January 1, 1998.
4. Beginning January 1, 1998, any pipeline transition costs resulting
from existing PGT commitments on behalf of core transport customers
will be allocated to all core customers for the term of the Gas
Accord. This provision will be reexamined if transition costs exceed
$5 million per year.
G. CORE AGGREGATORS' HOLDINGS OF INTRASTATE CAPACITY AND STORAGE
1. Intrastate transmission costs will be unbundled from core
aggregation customers' rates effective with the Accord.
2. For the initial two years of the Gas Accord, aggregators must hold
firm intrastate transmission capacity rights during the winter season
equal to a proportional share of PG&E's initial core reservation
during the five winter months, excluding the California on-system
reservation. Thereafter, aggregators who perform reliably will have
no firm requirements.
3. Aggregators may choose the transmission path of their reservation.
They are entitled, though not obligated, to subscribe to a
proportional share of the vintage-priced Malin to on-system core
reservation and/or a proportional share of the Topock to on-system
reservation.
4. Aggregators may also use the following alternatives to meet their
firm intrastate transmission requirements:
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<PAGE>
a. Standard agreements to use other firm holders' rights when
needed;
b. California gas supplies; or
c. Firm storage capacity in addition to their assigned capacity, if
available.
5. Aggregators will continue to be assigned a proportional share of
PG&E's core storage reservation based on the winter season throughput
of the core transport customers (consistent with CPUC Decision 95-07-
048), with the obligation to fill it and maintain minimum inventory
levels for reliability purposes. However, to the extent possible
without compromising the reliability functions of storage for core
customers, aggregators will have the right to use storage balances
above each aggregator's minimum level described in PG&E's G-CT tariff
to cure imbalances, to make same-day injection and withdrawal
nominations, and to sell or trade gas in storage.
6. Within three years after the Gas Accord is implemented, PG&E will
file with the CPUC an examination of storage unbundling for core
transportation customers in light of the then-existing market.
7. In recognition of the fact that aggregators have settled for less
service unbundling than they preferred, and to encourage
participation in the core transportation program, PG&E's shareholders
will fund a $0.095/Dth credit to core transport rates until January
1, 1998.
H. CORE AGGREGATION REGULATORY ISSUES
1. The PG&E core procurement brokerage fee will be set at $0.024/Dth and
will be subject to balancing-account recovery. This fee will be
reviewed when PG&E's market share drops to 80 percent.
2. In compliance with the provisions of California Public Utilities Code
Sections 6350 - 6354, PG&E will continue to collect city/county
franchise fees for service provided by aggregators based on its own
weighted-average cost of gas (WACOG). PG&E will seek legislative
changes to allow similar treatment for utility users' taxes.
3. Billing and metering costs will remain bundled. PG&E will install
additional metering at the request/expense of aggregators and their
customers, and will provide a credit if PG&E equipment can be removed
as a result.
4. PG&E will continue to oversee aggregators' creditworthiness,
pursuant to PG&E's Gas Rule 23, Gas Aggregation Service for Core
Transport Customers.
5. Aggregators will continue to be required to sign a core transport
agreement with PG&E. Aggregator-customer contracts are strictly
between the parties.
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<PAGE>
6. Customers must sign a PG&E agreement for service from an aggregator
for an initial term of 12 months. PG&E will conduct market research
to see if this requirement is a significant barrier to program
participation.
7. In order to prevent slamming (unauthorized switching of a customer
from one aggregator to another), written consent will continue to be
required from customers who want to change their gas aggregators.
8. Aggregators may obtain PG&E customer information required to select
and serve their customers (such as balances owed and customer-service
details) when authorization is given by the customer.
9. PG&E will provide aggregators with a list of qualified gas-supply
businesses owned by minorities, women, and disabled veterans that may
be used when purchasing gas supplies. PG&E will also provide gas-
supply businesses owned by minorities, women, and disabled veterans
with a list of qualified core aggregators and other information
needed to participate in PG&E's core gas transportation program.
10. The minimum size for a core transport group will be lowered from
250,000 therms per year to 120,000 therms per year.
11. After three years, PG&E will file a core transport program status
report with the CPUC, and PG&E will hold a workshop to address any
difficulties that have arisen with respect to PG&E's core gas
transportation program.
12. The modifications for core aggregation are designed so that they do
not have a significant adverse impact on PG&E's remaining core
procurement customers.
I. CORE AGGREGATION AND CUSTOMER INFORMATION
1. Customers of aggregators may continue to select a consolidated
payment option, where aggregators in compliance with PG&E's Gas Rule
23 creditworthiness standards collect and forward to PG&E appropriate
transportation revenues from their customers, as long as the payments
to PG&E are on time.
2. PG&E and the aggregators will work together to develop a common
Electronic Data Interface (EDI) protocol, which all aggregators will
then be required to use, to streamline data and monetary transfers
necessary to serve their customers.
3. PG&E will continue to promote the core transportation program to
customers through periodic bill inserts and provision of aggregator
lists upon customer request. PG&E will also promote the core
transportation program to its own employees through an internal
education program.
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<PAGE>
4. PG&E will conduct a market test to see if outreach efforts through
affinity groups (e.g., city governments, schools, churches) are
effective in increasing program knowledge and participation and
reducing aggregators' transaction costs.
5. PG&E call centers will be equipped to handle calls about the core
transportation program.
6. PG&E will provide aggregators with a bill insert that they may use to
ensure that their customers know to call PG&E for service- or safety-
related questions. Aggregators will refer all such calls that they
receive from their customers to PG&E.
J. CUSTOMER AGGREGATION SERVICE AND OPERATIONAL ISSUES
1. PG&E will provide aggregators with a new Core Load Forecasting and
Determination Service. This service will feature 24- and 48-hour
forecasts and day-after estimated ("determined") use, based on each
aggregator's customer mix.
2. The sum of the daily determined use figures will be used to calculate
monthly imbalance volumes and penalties.
3. The difference between the monthly sum of the daily determined use
figures and the prorated monthly metered use for each aggregator's
customers will be the "operating imbalance." The operating imbalance
will be disposed of during the next month. However, operating
imbalances of more than 10 percent of monthly use can be disposed of
over two months.
4. By 5:00 p.m. on the day before an Operational Flow Order or Emergency
Flow Order, PG&E will provide an additional forecast to aggregators
for their customers' next-day usage. Aggregators will be required to
balance against that forecast during the OFO or EFO.
5. When an aggregator collects PG&E transportation revenue from
customers under the "consolidated payment" option, PG&E will hold the
aggregator responsible for late payment or non-payment to PG&E if the
customer can demonstrate that it has paid the aggregator in full and
on time. PG&E will not hold the customer responsible .
6. The following recommendations were made in order to provide clear,
prompt, and responsive information to address customer concerns:
a. PG&E and the aggregators will negotiate the establishment of
joint communications protocols, to allow seamless call and
information transfers.
b. PG&E and the aggregators will negotiate an industry "decision
tree" for screening customer inquiries, to determine the party
responsible for responding to the customer.
K. CORE WHOLESALE CUSTOMERS
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1. Wholesale customers have the obligation to plan to meet their own
core loads.
2. Existing wholesale customers, Palo Alto and Coalinga, will have a
one-time option at the implementation of the Gas Accord to
subscribe, on behalf of their core customers, for up to 6.5 MMcf/d
(6.6 Mdth/d) of firm capacity on the Malin to on-system path at
vintaged rates.
3. Existing wholesale customers will have the right to a share of
storage capacity. They will get first priority from the storage
capacity allocated to the Unbundled Storage Program, equal to their
proportional share of the core load. They must reserve inventory,
injection, and withdrawal proportionately together and they will pay
the equivalent core rate for storage. Any storage cost will be added
to the wholesale customer's transportation rate. They will have the
same storage rights as other entities serving core customers and they
may contract for storage through the Unbundled Storage Program to
serve their noncore customers.
L. PROCUREMENT INCENTIVE MECHANISMS
1. For the period June 1, 1994, through December 31, 1997, PG&E will
recover procurement and transportation costs consistent with the
revised CPIM mechanism negotiated with DRA in 1996, and submitted as
testimony by PG&E on April 23, 1996, in Application 94-12-039. As a
result, this will resolve core procurement reasonableness for such
period. Further, as part of such testimony, PG&E will forego its
right to seek recovery of the reservation charges associated with the
150 MMcf/d Transwestern core reservation for the periods 1992-1997.
2. A post-1997 procurement incentive mechanism will be based on the
following parameters:
a. The pre-1998 CPIM agreement with DRA will be used as a model
for the new incentive mechanism.
b. The mechanism will be modified to include intrastate core
capacity use (both firm and as-available).
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<PAGE>
c. The mechanism will be modified to allow for the opportunity to
recover the cost of Transwestern reservation charges for 150
MMcf/d, as well as other Southwest interstate capacity
requirements that the core may require.
d. PG&E will develop a procedure to recover the costs associated
with diversion and balancing penalties in rates that may occur
under extreme weather or other extraordinary circumstances.
e. Based on the above parameters, PG&E and DRA will agree on the
detailed substance of their post-1997 mechanism and amend this
Gas Accord Settlement filing with the CPUC.
M. CORE SUBSCRIPTION
1. Operations
a. Core and core subscription customers will be served by PG&E
through a single supply portfolio.
b. Capacity reservations, nominations, and balancing will take place
for the portfolio as a whole.
c. Core subscription customers will be assumed to use a
proportional share of reserved interstate, Canadian and
intrastate capacity.
d. Core subscription customers will be assumed to use a
proportional share of the core portfolio's flowing supplies.
e. Transmission service priority for core subscription customers
under emergency conditions will be the same as the priority of
firm intrastate transmission service.
2. Pricing
a. Core subscription rates will be volumetric.
b. The intrastate transmission capacity charges for core
subscription will be based on the transmission rates for the
noncore market. That is, core subscription will not receive
vintaged Malin to on-system prices. Core subscription revenues
above the core subscription's proportionate share of the core
portfolio's intrastate capacity costs will be returned to core
customers served from the portfolio.
c. The PGT capacity costs for core subscription will be set at a
weighted average (based on the available capacity) of the FTS-1
"Noncore" and the FTS-1 "Expansion Shipper" reservation rates, as
specified in PGT's FERC-approved tariffs. Core subscription
revenues above the core subscription's proportionate share of the
core portfolio's PGT capacity costs will be returned to core
customers served from the portfolio.
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d. The cost of southwest pipeline capacity for core subscription is
set at its cost.
e. The Canadian capacity charges for core subscription will be at
the as-billed rate.
f. There will be a surcharge on core subscription rates of $0.07/Dth
beginning January 1, 1998, to fund activities associated with
program phase-out. Unspent revenues from the surcharge remaining
after the core subscription program is discontinued will be
returned to the core subscription customers which initially paid
the surcharge.
g. Each core subscription customer will be responsible for any
customer-specific penalties for failing to curtail use when
requested by PG&E under the involuntary diversion provisions.
Core subscription customers will not be responsible for any
involuntary diversion penalties incurred by the core portfolio.
h. Except as just described, the core subscription rate will include
core subscription's pro rata share of all core portfolio costs.
Among other things, this includes Southwest interstate and
Canadian capacity costs, as well as any imbalance charges,
voluntary diversion payments, and costs or credits associated
with the risk-sharing provisions of the core procurement
incentive mechanism.
i. The core subscription rate will be set monthly based on a
forecast of the core portfolio costs.
j. The core subscription monthly commodity price will be set at the
forecasted average cost of core portfolio flowing supplies (no
gas out of storage), adjusted as necessary to reflect any prior
months' forecast error in the core portfolio commodity cost.
k. The core subscription rate will also be adjusted as necessary to
reflect any prior period forecast errors associated with
Canadian, interstate and intrastate capacity (net of brokering
revenues).
l. Adopted shrinkage costs will be collected from core subscription
customers.
m. Balancing account treatment for core subscription commodity,
interstate and Canadian capacity, and shrinkage will be
eliminated prospectively.
n. The core subscription rate will include a component to amortize
the accrued balances from the current balancing accounts.
o. PG&E's noncore brokerage fee will remain at $0.0382 per
decatherm, with balancing account treatment. Balances will
continue to be allocated equal cents per therm to all noncore
customers.
3. Eligibility for Core Subscription Service
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Any noncore customer on PG&E's system, excluding UEG, is eligible for
core subscription service.
4. Core Subscription Service Phaseout
a. Core subscription service is to expire within three years after
implementation of the Gas Accord. At that time, customers wishing
to remain PG&E procurement customers must elect to become core
customers.
b. Parties may propose cost-based rate design changes in a future
BCAP to mitigate the price impact on such customers who choose
core status.
c. PG&E will conduct a marketing campaign to ensure that core
subscription customers are aware of the competitive procurement
alternatives available to them. The cost of the marketing
campaign will be offset against the revenues from the $0.07/Dth
surcharge.
5. Contract Terms
a. One-year term.
b. Current contracts will remain in effect until their expiration on
July 1, 1997, except that current core subscription customers
will be allowed to change suppliers before the expirations of
their current contracts.
c. If the core subscription program participation (numbers of
customers or contracted load) increases by more than ten percent
(35 customers or 4 MMcf/d), the parties will confer to consider
possible responses.
N. CHANGING PG&E'S ROLE IN NORTHERN CALIFORNIA GAS PRODUCTION
1. PG&E has had a strong presence in the northern California gas
production industry both as the largest purchaser of gas and the
largest gas gatherer. The Gas Accord proposes to reshape that role
and seeks approval of the principles advocated here. Many of the
implementation details that underlie these changes will of necessity
be part of separate proceeding(s).
PG&E and California producers intend to provide for efficient
operation of the facilities used to bring California gas to market
and to extend the economic life of California gas production.
2. PG&E proposes several principles that would apply to northern
California gas production. They are:
a. The mutual release of all California production gas procurement
contracts held by PG&E.
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b. PG&E will support the formation of a non-utility cooperative run
and managed by an association of producers (the Cooperative) or
of a utility corporation run and managed by an association of
producers (the Utility) to purchase and operate the gas gathering
system. The Utility or Cooperative shall protect producer
interests through an opportunity to participate in ownership and
in governance; to have access to information; and to participate
in profits, if any. PG&E's support is limited to a gas gathering
entity. PG&E will not seek to spin-down the gathering facilities
to an unregulated affiliate.
c. The sale of as many of the gas gathering facilities as possible
to the Cooperative or the Utility, or to individual producers who
are served by those facilities. Assets presently designated as
gathering that are needed to provide safe and reliable
transmission or distribution service will be retained and
redesignated. PG&E will identify and connect producers on
redesignated portions of the gathering system to the
Utility/Cooperative gathering system(s) to assure access to
market.
d. Should the Cooperative or the Utility not be formed or not
purchase all the facilities, PG&E shall divest as many facilities
as possible to producers where those facilities are only used by
those producers.
e. If gathering facilities cannot be divested at a fair market
price, PG&E will continue to own and maintain those facilities
while recovering the ongoing costs of such facilities directly
from producers that use them through a gathering charge. The
level of the gathering charges will not exceed the difference
between the California path rate and the lowest noncore
transmission path connected to interstate gas supplies.
f. Where the Utility, the Cooperative, or individual producers
acquire or provide their own gathering, the California path rate
will be reduced by a cost-based credit. The cost-based credit
shall be volumetric and shall be afforded to producers on a basis
that reflects facilities acquired and costs avoided.
g. Approval of the sale of gas gathering facilities is pursuant to
Section 851 of the California Public Utilities Code, on such
terms and conditions as are mutually acceptable to the parties.
To the extent there is a gain-on-sale related to the disposition
of gathering facilities, the gains will be shared 95 percent
ratepayer and 5 percent shareholder. To the extent there is a
loss-on-sale, PG&E's shareholders will absorb 100 percent of the
losses. In determining whether or not a gain- or loss-on-sale has
occurred, PG&E will use a net book value based on the
depreciation methodology outlined in Decision 89-12-016, the gas
gathering decision. Gains would be included in an interest
bearing balancing account, reflected in rates in the appropriate
rate proceeding. Any environmental clean-up necessary for the
sale will be recoverable via the Hazardous Substance Mechanism
balancing account or through the appropriate mechanism as may be
authorized by the Commission.
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h. Approval and implementation of a standard California Production
Balancing Agreement to meet one of PG&E's goals of improving the
efficient use of its gas transportation system by reducing delays
caused by adjustments when wellhead meter data do not match
scheduled volumes. This will be effected by filing a pro forma
agreement in an advice filing, subject to protest by producers.
i. Cooperate with the California gas producer community to develop
options that will allow gas gatherers access to pipeline pressure
data to maximize gathering system operational flexibility and to
assist with the management of production imbalances.
j. Approval and implementation of a standard California Production
Interconnection and Operating Agreement to apply consistent
requirements whenever facilities owned by producers, by the
Utility, or by the Cooperative are interconnected with PG&E's
system for the purpose of gas transportation and authorization of
an operations and maintenance fee, where applicable. Both will be
effected through an advice filing, subject to protest by
producers.
k. Any California-produced gas that PG&E buys outside of its
existing contracts will meet the same quality standards as all
other transported California-produced gas. PG&E will endeavor to
continue its historic practice of transporting low-Btu gas to the
extent physically possible, based on historical volumes.
California produced gas that does not meet PG&E's minimum heating
value requirement and/or gas quality specifications as set forth
in PG&E's Rule 21 that is sold directly to end-use customers of
PG&E is exempt from the residual load service tariff.
l. Should the Utility form for the purpose of acquiring and
operating the gas gathering system, PG&E will support a filing
for "light-handed" regulation for the Utility by the commission.
"Light-handed regulation" shall be consistent with protecting
producer interests through the provision of gathering services at
the lowest reasonable cost; participation in ownership;
participation in governance; access to information; assurances
against discrimination; and participation in profits. PG&E's
support for "light-handed" regulation is limited to a gas
gathering entity.
3. The implementation of the Gas Accord could affect the employees of
PG&E. With respect to PG&E's International Brotherhood of Electrical
Workers (IBEW) workforce, PG&E will work with the IBEW to minimize
the impact on employees. In the event that PG&E sells gas gathering
facilities, as discussed above, and the sale results in the need to
reduce the workforce, PG&E may offer a Voluntary Severance Incentive,
a Voluntary Retirement Incentive, retraining, and other employee
options, subject to negotiation with the IBEW local 1245.
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<PAGE>
V. LITIGATION RESOLUTION
A. OBJECTIVES
To resolve the outstanding proceedings relating to PG&E's natural
gas operations as a means of transitioning to a restructured, more
competitive gas business. Settlement of all these cases and the
outstanding issues in these cases pursuant to the provisions below is a
prerequisite to implementation of the Gas Accord.
B. REGULATORY CASES ADDRESSED BY THE ACCORD
1. The Gas Accord settles and resolves the outstanding gas issues in the
following proceedings, except as otherwise noted in this document:
a. PG&E's 1992 through 1995 gas reasonableness cases, Applications
93-04-011, 94-04-002, 95-04-002, and 96-04-001;
b. All issues in Phases 1, 2, and 3 of the combined Pipeline
Expansion Project Reasonableness/Interstate Transition Cost
Surcharge proceeding, and also the alleged Rule 1 violation,
covered in Applications 92-12-043, 93-03-038, 94-05-035, 94-06-
034, 94-09-056, and 94-06-044;
c. All issues regarding the reasonableness of noncore capacity
brokering from January 1, 1996, through December 31, 1997.
(Noncore and core capacity brokering for 1993-1994 is addressed
in 1.b above. Noncore capacity brokering for 1995 is addressed in
1.a above. Core capacity brokering practices from June 1, 1994,
to December 31, 1997, are addressed through PG&E's revised CPIM);
d. All issues in the Core Procurement Incentive Mechanism case,
Application 94-12-039;
e. The EAD shortfall issues addressed in Applications 92-07-047,
92-07-049, 95-02-008, and 95-02-010;
f. Phase 2 of PG&E's BCAP Application 94-11-015; and
g. All issues pertaining to the reasonableness, restructuring, and
revision of PG&E's transmission, storage, and core procurement
practices, rates, and services in various statewide rulemaking
and investigation dockets, R.88-08-018, R.90-02-008, R.92-12-016,
and I.92-12-017.
2. PG&E has omitted the Canadian procurement (including the effects on
northwest, geothermal and QF purchases), Canadian Decontracting and
Restructuring, ANG and NOVA capacity, Affiliate Investigations, CIG
sequencing, UEG curtailment, and Southwest procurement (including the
Satrap investigation) issues in the 1991-1994 gas reasonableness
cases from the list of financial concessions. These issues have
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<PAGE>
been settled separately through May 1994, and the settlements have
been filed with the CPUC. Therefore, they are not included in the
financial concessions being considered as part of the Gas Accord.
C. SETTLEMENT OF REGULATORY CASES AND PG&E FINANCIAL CONCESSIONS
1. Transwestern Pipeline Capacity Charges - Core 150 MMcf/d Contract
-----------------------------------------------------------------
(A.93-04-011, 94-04-002, 94-12-039, 95-04-002, 96-04-001, and PG&E's
application covering reasonableness for 1996 and 1997, when filed)
PG&E will not seek to recover any pipeline demand charges associated
with the core portion of the Transwestern contract from the
initiation of the contract through December 31, 1997, consistent with
PG&E's revised CPIM submitted on April 23, 1996. (See Section IV.L.)
For the period after 1997, PG&E will recover Transwestern demand
charges for the balance of the Transwestern contract term in
accordance with a successor CPIM which will be implemented January 1,
1998. Accordingly, if the Gas Accord, including PG&E's revised CPIM,
is approved, PG&E will withdraw any appeal of Decision 95-12-046.
2. ANG and NOVA Pipeline Capacity Charges
--------------------------------------
(A.94-12-039, 95-04-002, 96-04-001, and PG&E's application covering
reasonableness for 1996 and 1997, when filed)
For the period from June 1, 1994, through December 31, 1997, PG&E
will recover core ANG and NOVA capacity demand charges in accordance
with PG&E's revised CPIM. (See Section IV.L.) For the period after
1997, PG&E will recover ANG and NOVA demand charges for the balance
of the ANG and NOVA contract terms at full ABR in accordance with a
successor CPIM which will be implemented January 1, 1998.
3. Transwestern Pipeline Capacity -- UEG 50 MMcf/d Contract
--------------------------------------------------------
(A.93-04-011, 94-04-002, 95-04-002, and 96-04-001)
PG&E agrees to resolve the UEG Transwestern Capacity of 50 Mdth/d as
follows: PG&E will not seek to recover from ratepayers the
reservation charges associated with the 50 Mdth/d of UEG Transwestern
capacity incurred through July 31, 1993. Recovery of reservation
charges from August 1993 through implementation of the Power Exchange
(PX) will be determined by comparing UEG's monthly commodity and
volumetric interstate transportation costs associated with UEG's 50
Mdth/d of Transwestern capacity contract to a market benchmark based
on California border indices. The benchmark will be calculated by
multiplying an average of Topock gas price indices by the volumes
transported by UEG for the month on the 50 Mdth/d of Transwestern
capacity. The difference between the benchmark and the UEG commodity
and the volumetric interstate transportation costs will be the amount
of Transwestern reservation costs PG&E will be allowed to recover.
The average border price will be determined by a simple average of 30
day Topock gas price indices from the following publications: Gas
Daily, Natural Gas Weekly and Natural Gas Intelligence Gas Price
Index. Recovery of reservation charges after implementation
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<PAGE>
of the PX will not be through the proposed Competitive Transition
Charge (CTC) mechanism.
PG&E is entitled to all revenue from brokering UEG Transwestern
capacity generated through the period of the contract.
For the period prior to December 31, 1995, PG&E would recover $3.7
million of its total Transwestern capacity costs plus brokering
revenues. The appropriate adjustments will be made to PG&E's ECAC
balancing account to reflect this agreement. It is further agreed
that this agreement will set no precedent for the treatment of other
capacity reservations that the UEG may incur from time to time.
4. Pipeline Expansion Project Reasonableness (PEPR)/Interstate
-----------------------------------------------------------
Transition Cost Surcharge (ITCS) Proceeding
-------------------------------------------
(A.92-12-043, 93-03-038, 94-05-035, 94-06-034, 94-09-056, 94-06-044,
and 96-04-001)
Implementation of the terms and agreements of the Gas Accord, as
proposed, settles all contested issues associated with Phases 1, 2,
and 3, of the PEPR/ITCS case, and also Rule 1 allegations.
a. ITCS Account (Core portion)
---------------------------
PG&E will absorb 100 percent of the core portion of ITCS charges
as currently defined, less brokering revenues, plus interest,
from the inception of the ITCS account. Any ITCS costs that were
recovered in rates from the core will be returned to the core.
Consequently:
i. PG&E will not be responsible for any proposed additional
Northern California ITCS costs or other penalties or remedies
alleged in the PEPR/ITCS proceeding for the period addressed
in such proceeding or subsequent periods; and
ii. No other ITCS, capacity assignments, revenue requirements, or
similar "stranded costs" or penalties should be shifted to
Northern California ratepayers or PG&E shareholders from
Southern California, as alleged in the PEPR/ITCS proceeding,
the SoCalGas BCAP (Application 96-03-031), and other
proceedings.
b. ITCS Account (Noncore portion)
------------------------------
PG&E will absorb 50 percent of the noncore portion of ITCS
charges as currently defined, less brokering revenues, plus
interest, from the inception of the ITCS account. PG&E's
liability is limited to 50 percent, and therefore, includes any
rate reduction approved by the CPUC in response to Advice Letter
1952-G
Consequently:
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<PAGE>
i. PG&E will not be responsible for any proposed additional
Northern California ITCS costs or other penalties or
remedies alleged in the PEPR/ITCS proceeding for the period
addressed in such proceeding or subsequent periods;
ii. No other ITCS, capacity assignments, revenue requirements,
or similar "stranded costs" or penalties should be shifted
to Northern California ratepayers or PG&E shareholders from
Southern California, as alleged in the PEPR/ITCS
proceeding, the SoCalGas BCAP (Application 96-03-031), and
other proceedings.
iii. PG&E shall be entitled to recovery of 50 percent of ITCS
charges through gas transportation rates. No ITCS charges
shall be recovered through electric rates except those paid
by PG&E's UEG as a noncore gas customer.
c. Pipeline Expansion Rates
------------------------
PG&E agrees that, for ratemaking purposes, the initial capital
cost of the PG&E portion of the PG&E/PGT Pipeline Expansion
Project will be $736 million. In recalculating rates using the
lower Line 401 capital costs, PG&E will use the Company's utility
corporate cost of capital and capital structure. The rates and
terms of service for the Malin to on- and off-system paths, which
include a Line 401 component, and the major assumptions used in
deriving the Line 401 component, are as specified in Sections
II.I and IV. The rates and terms of service for G-XF firm service
are as specified in Section II.B.1. Other options available to
firm Expansion shippers are described in Section II.F.1.c.
d. Backbone Credit
---------------
PG&E agrees not to collect in future rates the balance of the
Backbone Credit Memorandum Account. As of the date the Gas Accord
is approved by the CPUC, PG&E will not provide a backbone credit
to any shipper and will remove the backbone crediting provisions
from its tariffs. The Backbone Credit Memorandum Account will be
terminated as of the date the Gas Accord is approved.
5. EAD Contracts
-------------
(A.92-07-047, 92-07-049, 95-02-008, and 95-02-010) For the period
from the contracts' inception dates until the date the Gas Accord
rate structure is implemented, PG&E will collect 75 percent of EAD
revenue shortfalls by operation of the Noncore Fixed Cost Account.
This covers all EAD contracts, except those with Gaylord and Posco,
approved in Decisions 95-06-022 and 95-06-023, respectively. With
respect to those contracts, PG&E will be at risk for 100 percent of
EAD shortfall revenue. During the Gas Accord period, PG&E will not
collect any EAD revenue shortfalls in rates. The Commission will not
take any further action in and will close this consolidated
proceeding.
6. BCAP Phase II
-------------
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<PAGE>
(A.94-11-015)
In PG&E's 1995 BCAP, SMUD proposed an unbundled backbone transmission
rate. Decision 95-12-053, recognizing that there were issues that
needed to be addressed prior to adopting such a rate, established a
second phase in the BCAP. The Decision also recognized that these
issues could potentially be resolved in the Accord, and therefore
encouraged parties to enter into negotiations as part of the Accord
process. Subsequent to the issuance of Decision 95-12-053, PG&E and
SMUD have reached preliminary agreement for service that better meets
SMUD's needs, as discussed in Section II.F.6. Subject to timely
completing the definitive agreements and securing CPUC approval, this
arrangement will resolve SMUD's Phase II BCAP issues. The Gas Accord
provides the framework necessary for PG&E to negotiate to resolve any
remaining concerns of other parties.
7. Remaining Reasonableness Issues
-------------------------------
(A.93-04-011, 94-04-002, 95-04-002, and 96-04-001)
All core procurement cost recovery after May 1994 shall be in
accordance with PG&E's revised CPIM. All other issues outstanding in
reasonableness proceedings are deemed settled and no party shall seek
or recommend any disallowance, sanction, or penalty associated any
gas reasonableness issue, named or unnamed for years 1992 through
1995.
8. 1988 - 1990 Gas Reasonableness Issues
-------------------------------------
(A.91-04-003)
If the Gas Accord Settlement is finally adopted by the Commission, or
adopted with modifications acceptable to PG&E and DRA, PG&E will
permanently forego recovering from its ratepayers any of the
disallowance ordered by Decision 94-03-050, which has been (or will
be) refunded to ratepayers, notwithstanding the outcome of its
pending lawsuit in Federal District court (Civil No. C-94-4381 WHO).
In the event the Federal District Court issues a decision prior to a
Commission decision on the Gas Accord, PG&E will not execute any
court judgment or otherwise seek recovery of the disallowance and
associated refunds ordered as a result of Decision 94-03-050, unless
in PG&E's reasonable judgment, failure to do so would prejudice
PG&E's right to said recovery. In the event PG&E seeks recovery of a
refund in order to preserve its rights pending a Commission decision
on the Accord, PG&E agrees to once again refund the disallowance to
ratepayers upon final approval of the Gas Accord Settlement.
The UEG and noncore will receive their portion of the 1988-1990
disallowance ordered by Decision 94-03-050 upon approval of the
refund plan pending before the Commission. The UEG's portion of the
1988-1990 disallowance ordered by Decision 94-03-050 will be credited
directly to the ECAC balancing account and will not be refunded to
electric customers directly. This treatment will not have an effect
on PG&E's electric rate freeze, and will be subject to the same
provisions as other ECAC balances.
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As part of the overall Gas Accord Settlement, the remaining phase III
C issues in Application 91-04-003 associated with the 1988-1990
disallowance (BCAP Phase II) are resolved for $3.7 million inclusive
of any interest through 1995. PG&E will credit its ECAC balancing
account $3.7 million effective December 31, 1995. Interest would
accrue from that date forward. This treatment will not have an effect
on PG&E's electric rate freeze, and will be subject to the same
provisions as other ECAC balances.
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VI. VI. ACCORD RATES
TABLE 1
ILLUSTRATIVE RATE PROJECTIONS UNDER THE GAS ACCORD -- ON-SYSTEM
($/DTH)
<TABLE>
<CAPTION>
1997 1998 1999 2000 2001 2002 AVG (1997-02)
<S> <C> <C> <C> <C> <C> <C> <C>
Core (Bundled)
- ---------------------------
Residential 5.61 5.62 5.75 5.79 5.93 6.07 5.79
Small Commercial 5.65 5.66 5.80 5.83 5.97 6.11 5.84
Large Commercial 3.93 3.92 4.02 4.01 4.11 4.21 4.03
Noncore (Firm Topock)
- ---------------------------
Distribution 1.14 1.11 1.11 1.10 1.12 1.15 1.12
Transmission 0.48 0.45 0.43 0.40 0.41 0.42 0.43
UEG 0.42 0.39 0.38 0.36 0.36 0.37 0.38
COG 0.42 0.39 0.38 0.36 0.36 0.37 0.38
Coalinga 0.47 0.44 0.43 0.41 0.42 0.42 0.43
Palo Alto 0.42 0.40 0.38 0.36 0.37 0.38 0.39
Noncore (Firm Malin)
- ---------------------------
Distribution 1.23 1.21 1.21 1.20 1.22 1.24 1.22
Transmission 0.57 0.54 0.53 0.50 0.51 0.51 0.53
UEG 0.51 0.49 0.48 0.45 0.46 0.46 0.48
COG 0.51 0.49 0.48 0.45 0.46 0.46 0.48
Coalinga 0.56 0.54 0.53 0.51 0.51 0.52 0.53
Palo Alto 0.52 0.49 0.48 0.46 0.47 0.47 0.48
Noncore (Firm California Gas)
- ---------------------------
Distribution 1.10 1.06 1.06 1.04 1.07 1.09 1.07
Transmission 0.44 0.40 0.38 0.35 0.35 0.36 0.38
UEG 0.37 0.34 0.32 0.30 0.31 0.31 0.33
COG 0.37 0.34 0.32 0.30 0.31 0.31 0.33
Coalinga 0.43 0.39 0.37 0.35 0.36 0.37 0.38
Palo Alto 0.38 0.35 0.33 0.31 0.31 0.32 0.33
</TABLE>
Notes:
a) Some portions of these rates are guaranteed.
b) Core rates are bundled and include average backbone transmission costs, local
transmission, distribution, storage, customer class charge, and a forecast of
procurement and interstate pipeline demand charges.
c) Noncore rates include backbone transmission, local transmission, customer
class charges, customer access charges and distribution charges.
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<PAGE>
TABLE 2
FIRM BACKBONE CHARGE -- ANNUAL RATES (AFT)
MFV RATE DESIGN
ON-SYSTEM DELIVERIES
<TABLE>
<CAPTION>
1997 1998 1999 2000 2001 2002
<S> <C> <C> <C> <C> <C> <C> <C>
Malin to On-System - Core
- -----------------------
Reservation Charge ($/Dth/mo) 2.20 2.23 2.27 2.32 2.36 2.41
Usage Charge ($/Dth) 0.041 0.042 0.043 0.043 0.044 0.045
Total ($/Dth@Full 0.113 0.115 0.118 0.119 0.122 0.124
Contract)
Malin to On-System
- -----------------------
Reservation Charge ($/Dth/mo) 3.95 4.21 4.43 4.52 4.61 4.69
Usage Charge ($/Dth) 0.108 0.114 0.119 0.118 0.117 0.115
Total ($/Dth@Full 0.238 0.253 0.265 0.267 0.269 0.269
Contract)
Topock to On-System
- -----------------------
Reservation Charge ($/Dth/mo) 3.16 3.45 3.69 3.81 3.86 3.91
Usage Charge ($/Dth) 0.041 0.042 0.043 0.044 0.045 0.046
Total ($/Dth@Full 0.145 0.155 0.164 0.169 0.172 0.175
Contract)
California Gas and On-System Storage to On-System
- -----------------------
Reservation Charge ($/Dth/mo) 2.00 2.11 2.20 2.26 2.29 2.33
Usage Charge ($/Dth) 0.036 0.038 0.039 0.039 0.039 0.039
Total ($/Dth@Full 0.102 0.107 0.111 0.113 0.114 0.116
Contract)
</TABLE>
Notes:
a) These rates are only the backbone transmission charge component of the
transmission service. They exclude local transmission charges, customer class
charges, customer access charges, distribution charges, storage charges, and
shrinkage charges.
b) On-system backbone transmission charges are based on an 87.5% load factor.
c) The "Total" rows represent the average backbone transmission charge incurred
by a firm shipper that uses its full contract quantity at a 100% load factor.
d) Customers delivering gas to storage facilities pay the applicable backbone
transmission on-system rate from Malin, Topock or California production.
e) Core and core wholesale are assigned 606.5 MMcf/d (615.6 Mdth/d) of capacity
on Line 400 at vintaged rates. These rates are shown under "Malin to On-System -
Core". Any additional usage from Malin by core or core wholesale must be on the
"Malin to on-system path".
f) These rates are subject to change during the Accord period pursuant only to
the z-factor provisions of Section II.I.7. Malin to on-system charges include a
phase-in of Line 401 costs as described in Section II.I.3.
g) Gathering facilities are assumed to be fully depreciated by January 1, 1997.
Gathering O&M expenses are included as part of the common backbone component.
AFT continued next page
-70-
<PAGE>
TABLE 3
FIRM BACKBONE TRANSPORTATION -- ANNUAL RATES (AFT)
SFV RATE DESIGN
ON-SYSTEM DELIVERIES
<TABLE>
<CAPTION>
1997 1998 1999 2000 2001 2002
<S> <C> <C> <C> <C> <C> <C> <C>
Malin to On-System Core
- ----------------------
Reservation Charge ($/Dth/mo) 3.19 3.24 3.30 3.37 3.44 3.52
Usage Charge ($/Dth) 0.008 0.008 0.009 0.009 0.009 0.009
Total ($/Dth@Full 0.113 0.115 0.117 0.120 0.122 0.125
Contract)
Malin to On-System
- ----------------------
Reservation Charge ($/Dth/mo) 7.01 7.48 7.83 7.90 7.95 7.96
Usage Charge ($/Dth) 0.007 0.007 0.007 0.007 0.007 0.007
Total ($/Dth@Full 0.237 0.253 0.264 0.267 0.268 0.269
Contract)
Topock to On-System
- ----------------------
Reservation Charge ($/Dth/mo) 4.31 4.63 4.89 5.03 5.11 5.19
Usage Charge ($/Dth) 0.004 0.004 0.004 0.004 0.004 0.004
Total ($/Dth@Full 0.146 0.156 0.165 0.169 0.172 0.175
Contract)
California Gas and On-System
Storage to On-System
- ----------------------
Reservation Charge ($/Dth/mo) 3.02 3.18 3.30 3.36 3.39 3.43
Usage Charge ($/Dth) 0.003 0.003 0.003 0.003 0.003 0.003
Total ($/Dth@Full 0.102 0.107 0.112 0.113 0.115 0.116
Contract)
</TABLE>
Notes:
a) These rates are only the backbone transmission charge component of the
transmission service. They exclude local transmission charges, customer class
charges, customer access charges, distribution charges, storage charges, and
shrinkage charges.
b) On-system backbone transmission charges are based on an 87.5% load factor.
c) The "Total" rows represent the average backbone transmission charge incurred
by a firm shipper that uses its full contract quantity at a 100% load factor.
d) Customers delivering gas to storage facilities pay the applicable backbone
transmission on-system rate from Malin, Topock or California production.
e) Core and core wholesale are assigned 606.5 MMcf/d (615.6 Mdth/d) of capacity
on Line 400 at vintage rates. Any additional usage from Malin by core or core
wholesale must be on the Malin to on-system path.
f) These rates are subject to change during the Accord period pursuant only to
the z-factor provisions of Section II.I.7. Malin to on-system charges include a
phase-in of Line 401 costs as described in Section II.I.3.
g) Gathering facilities are assumed to be fully depreciated by January 1, 1997.
Gathering O&M expenses are included as part of the common backbone component.
-71-
<PAGE>
TABLE 4
FIRM BACKBONE TRANSPORTATION CHARGES -- SEASONAL RATES (SFT)
MFV RATE DESIGN
ON-SYSTEM DELIVERIES
<TABLE>
<CAPTION>
1997 1998 1999 2000 2001 2002
<S> <C> <C> <C> <C> <C> <C> <C>
Malin to On-System
- ----------------------
Reservation Charge ($/Dth/mo) 4.74 5.06 5.31 5.43 5.53 5.63
Usage Charge ($/Dth) 0.129 0.137 0.143 0.142 0.140 0.138
Total ($/Dth@Full Contract) 0.285 0.303 0.318 0.320 0.322 0.323
Topock to On-System
- ----------------------
Reservation Charge ($/Dth/mo) 3.79 4.14 4.42 4.57 4.63 4.69
Usage Charge ($/Dth) 0.050 0.051 0.052 0.053 0.054 0.055
Total ($/Dth@Full Contract) 0.175 0.187 0.197 0.203 0.206 0.209
California Gas and On-System Storage to On-System
- ----------------------
Reservation Charge ($/Dth/mo) 2.40 2.53 2.64 2.71 2.75 2.79
Usage Charge ($/Dth) 0.044 0.046 0.047 0.047 0.047 0.047
Total ($/Dth@Full Contract) 0.123 0.129 0.134 0.136 0.137 0.139
</TABLE>
Notes:
a) Firm Seasonal rates are 120% of Firm Annual rates.
b) These rates are only the backbone transmission charge component of the
transmission service. They exclude local transmission charges, customer class
charges, customer access charges, distribution charges, storage charges, and
shrinkage charges.
c) The "Total" rows represent the average backbone transmission cost incurred by
a firm shipper that uses its full contract quantity at a 100% load factor.
d) Customers delivering gas to storage facilities pay the applicable backbone
transmission on-system rate from Malin, Topock or California production.
e) These rates are subject to change during the Accord period pursuant only to
the z-factor provisions of Section II.I.7. Malin to on-system rates include
phase-in of Line 401 costs as described in Section II.I.3.
f) Gathering facilities are assumed to be fully depreciated by January 1, 1997.
Gathering O&M expenses are included as part of the common backbone component.
g) For the period July 1997 through March 1998, core will receive seasonal
service (SFT) from Topock at a rate that is 110% of annual firm rates (AFT).
SFT continued next page
-72-
<PAGE>
TABLE 5
FIRM BACKBONE TRANSPORTATION CHARGES -- SEASONAL RATES (SFT)
SFV RATE DESIGN
ON-SYSTEM DELIVERIES
<TABLE>
<CAPTION>
1997 1998 1999 2000 2001 2002
<S> <C> <C> <C> <C> <C> <C> <C>
Malin to On-System
- ----------------------
Reservation Charge ($/Dth/mo) 8.41 8.97 9.39 9.48 9.53 9.55
Usage Charge ($/Dth) 0.008 0.008 0.008 0.009 0.009 0.009
Total ($/Dth@Full Contract) 0.285 0.303 0.317 0.321 0.322 0.323
Topock to On-System
- ----------------------
Reservation Charge ($/Dth/mo) 5.17 5.55 5.86 6.04 6.13 6.23
Usage Charge ($/Dth) 0.004 0.004 0.004 0.004 0.005 0.005
Total ($/Dth@Full Contract) 0.174 0.187 0.197 0.203 0.207 0.210
California Gas and On-System Storage
to On-System
- ----------------------
Reservation Charge ($/Dth/mo) 3.62 3.81 3.96 4.03 4.07 4.11
Usage Charge ($/Dth) 0.004 0.004 0.004 0.004 0.004 0.004
Total ($/Dth@Full Contract) 0.123 0.129 0.134 0.136 0.138 0.139
</TABLE>
Notes:
a) Firm Seasonal rates are 120% of Firm Annual rates.
b) These rates are only the backbone transmission charge component of the
transmission service. They exclude local transmission charges, customer
class charges, customer access charges, distribution charges, storage
charges, and shrinkage charges.
c) The "Total" rows represent the average backbone transmission cost incurred
by a firm shipper that uses its full contract quantity at a 100% load
factor.
d) Customers delivering gas to storage facilities pay the applicable backbone
transmission on-system rate from Malin, Topock or California production.
e) These rates are subject to change during the Accord period pursuant only to
the z-factor provisions of Section II.I.7. Malin to on-system rates include
a phase-in of Line 401 costs described in Section II.I.3.
f) Gathering facilities are assumed to be fully depreciated by January 1, 1997.
Gathering O&M expenses are included as part of the common backbone
component.
g) For the period July 1997 through March 1998, core will receive seasonal
service (SFT) from Topock at a rate that is 110% of annual firm rates (AFT).
-73-
<PAGE>
TABLE 6
AS-AVAILABLE BACKBONE TRANSPORTATION (AA)
ON-SYSTEM DELIVERIES
<TABLE>
<CAPTION>
1997 1998 1998 1999 2000 2001 2002
1/1-3/31 4/1-12/31
<S> <C> <C> <C> <C> <C> <C> <C>
Malin to On-System
- -----------------
Usage Charge ($/Dth) 0.261 0.278 0.303 0.317 0.320 0.322 0.323
Topock to On-System
- -----------------
Usage Charge ($/Dth) 0.160 0.171 0.187 0.197 0.203 0.206 0.209
California Gas to On-System
- -----------------
Usage Charge ($/Dth) 0.112 0.118 0.129 0.134 0.136 0.138 0.139
On-System Storage to On-System
- -----------------
Usage Charge ($/Dth) 0.000 0.000 0.000 0.000 0.000 0.000 0.000
</TABLE>
Notes:
a) As-Available rates are 110% of Firm-Annual rates through March 31, 1998, and
120% thereafter.
b) These rates are only the backbone transmission charge component of the
transmission service. They exclude local transmission charges, customer class
charges, customer access charges, distribution charges, storage charges, and
shrinkage charges.
c) Customers delivering gas to storage facilities pay the applicable backbone
transmission on-system rate from Malin, Topock or California production.
d) Consistent with current CPUC rules, there will not be a transmission charge
for transmission from storage unless firm transmission capacity is required to
schedule the movement of the natural gas from the storage facility.
e) These rates are subject to change during the Accord period pursuant only to
the z-factor provisions of Section II.I.7. Malin to on-system rates include a
phase-in of Line 401 costs described in Section II.I.3.
f) Gathering facilities are assumed to be fully depreciated by January 1, 1997.
Gathering O&M expenses are included as part of the common backbone component.
-74-
<PAGE>
TABLE 7
FIRM BACKBONE TRANSPORTATION CHARGES -- ANNUAL RATES (AFT-OFF)
MFV RATE DESIGN
OFF-SYSTEM DELIVERIES
<TABLE>
<CAPTION>
1997 1998 1999 2000 2001 2002
<S> <C> <C> <C> <C> <C> <C> <C>
Malin to Off-System
- ----------------------
Reservation Charge ($/Dth/mo) 5.52 5.46 5.39 5.32 5.25 5.18
Usage Charge ($/Dth) 0.216 0.205 0.195 0.185 0.175 0.165
Total ($/Dth@Full 0.397 0.384 0.372 0.360 0.348 0.335
Contract)
Topock to Off-System
- ----------------------
Reservation Charge ($/Dth/mo) 3.16 3.45 3.69 3.81 3.86 3.91
Usage Charge ($/Dth) 0.041 0.042 0.043 0.044 0.045 0.046
Total ($/Dth@Full 0.145 0.155 0.164 0.169 0.172 0.175
Contract)
California Gas and On-System Storage to Off-System
- ----------------------
Reservation Charge ($/Dth/mo) 5.52 5.46 5.39 5.32 5.25 5.18
Usage Charge ($/Dth) 0.216 0.205 0.195 0.185 0.175 0.165
Total ($/Dth@Full 0.397 0.384 0.372 0.360 0.348 0.335
Contract)
</TABLE>
Notes:
a) These rates are only the backbone transmission charge component of the
transmission service. They exclude local transmission charges, customer class
charges, customer access charges, distribution charges, storage charges, and
shrinkage charges.
b) Except for Malin to off-system, and California gas to off-system, backbone
transmission rates are based on an 87.5% load factor.
c) The "Total" rows represent the average backbone transmission cost incurred by
a firm shipper that uses its full contract quantity at a 100% load factor.
d) Malin to off-system charges are based on Line 401's embedded costs and a 95%
load factor.
e) These rates are subject to change during the Accord period pursuant only to
the z-factor provisions of Section II.I.7.
f) Gathering facilities are assumed to be fully depreciated by January 1, 1997.
Gathering O&M expenses are included as part of the common backbone component.
g) California gas and storage to off-system are assumed to flow on Line 401, and
are priced at the Line 401 rate.
AFT-Off continued next page
-75-
<PAGE>
TABLE 8
FIRM BACKBONE TRANSPORTATION CHARGES -- ANNUAL RATES (AFT-OFF)
SFV RATE DESIGN
OFF-SYSTEM DELIVERIES
<TABLE>
<CAPTION>
1997 1998 1999 2000 2001 2002
<S> <C> <C> <C> <C> <C> <C> <C>
Malin to Off-System
- ----------------------
Reservation Charge ($/Dth/mo) 11.66 11.28 10.91 10.55 10.19 9.83
Usage Charge ($/Dth) 0.004 0.004 0.004 0.004 0.004 0.004
Total ($/Dth@Full 0.387 0.375 0.363 0.351 0.339 0.327
Contract)
Topock to Off-System
- ----------------------
Reservation Charge ($/Dth/mo) 4.31 4.63 4.89 5.03 5.11 5.19
Usage Charge ($/Dth) 0.004 0.004 0.004 0.004 0.004 0.004
Total ($/Dth@Full 0.146 0.156 0.165 0.169 0.172 0.175
Contract)
California Gas and On-System Storage to
Off-System
- ----------------------
Reservation Charge ($/Dth/mo) 11.66 11.28 10.91 10.55 10.19 9.83
Usage Charge ($/Dth) 0.004 0.004 0.004 0.004 0.004 0.004
Total ($/Dth@Full 0.387 0.375 0.363 0.351 0.339 0.327
Contract)
</TABLE>
Notes:
a) These rates are only the backbone transmission charge component of the
transmission service. They exclude local transmission charges, customer class
charges, customer access charges, distribution charges, storage charges, and
shrinkage charges.
b) Except for Malin to off-system, and California gas to off-system, backbone
transmission rates are based on an 87.5% load factor.
c) The "Total" rows represent the average backbone transmission cost incurred by
a firm shipper that uses its full contract quantity at a 100% load factor.
d) Malin to off-system charges are based on the embedded cost of Line 401 and a
95% load factor.
e) These rates are subject to change during the Accord period pursuant only to
the z-factor provisions of Section II.I.7.
f) Gathering facilities are assumed to be fully depreciated by January 1, 1997.
Gathering O&M expenses are included as part of the common backbone component.
g) California gas and storage to off-system are assumed to flow on Line 401, and
are priced at the Line 401 rate.
-76-
<PAGE>
TABLE 9
AS-AVAILABLE BACKBONE TRANSPORTATION (AA-OFF)
OFF-SYSTEM DELIVERIES
<TABLE>
<CAPTION>
1997 1998 1998 1999 2000 2001 2002
1/1-3/31 4/1-12/31
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Malin to Off-System
- -----------------
Usage Charge ($/Dth) 0.437 0.424 0.462 0.447 0.433 0.418 0.403
Topock to Off-System
- -----------------
Usage Charge ($/Dth) 0.160 0.171 0.187 0.197 0.203 0.206 0.209
California Gas and On-System
Storage to Off-System
- -----------------
Usage Charge ($/Dth) 0.437 0.424 0.462 0.447 0.433 0.418 0.403
</TABLE>
Notes:
a) These rates are only the backbone transmission charge component of the
transmission service. They exclude local transmission charges, customer class
charges, customer access charges, distribution charges, storage charges, and
shrinkage charges.
b) As-Available rates are 110% of Firm-Annual rates through March 31, 1998, and
120% thereafter.
c) Gathering facilities are assumed to be fully depreciated by January 1, 1997.
Gathering O&M expenses are included as part of the common backbone component.
d) California gas and storage to off-system is assumed to flow on Line 401, and
is priced at the Line 401 rate.
-77-
<PAGE>
TABLE 10
FIRM TRANSPORTATION -- EXPANSION SHIPPERS -- ANNUAL RATES (G-XF)
MFV RATE DESIGN
OFF-SYSTEM DELIVERIES
<TABLE>
<CAPTION>
1997 1998 1999 2000 2001 2002
<S> <C> <C> <C> <C> <C> <C> <C>
Malin to Off-System
- ----------------------
Reservation Charge ($/Dth/mo) 5.52 5.46 5.39 5.32 5.25 5.18
Usage Charge ($/Dth) 0.216 0.205 0.195 0.185 0.175 0.165
Total ($/Dth@Full 0.397 0.384 0.372 0.360 0.348 0.335
Contract)
</TABLE>
Notes:
a) These rates are only the backbone transmission charge component of the
transmission service. They exclude local transmission charges, customer class
charges, customer access charges, distribution charges, storage charges, and
shrinkage charges.
b) The "Total" rows represent the average backbone transmission cost incurred by
a firm shipper that uses its full contract quantity at a 100% load factor.
c) G-XF charges are based on the embedded cost of Line 401 and a 95% load
factor.
d) These rates are subject to change during the Accord period pursuant only to
the z-factor provisions of Section II.I.7.
-78-
<PAGE>
TABLE 11
FIRM TRANSPORTATION -- EXPANSION SHIPPERS -- ANNUAL RATES (G-XF)
SFV RATE DESIGN
OFF-SYSTEM DELIVERIES
<TABLE>
<CAPTION>
1997 1998 1999 2000 2001 2002
<S> <C> <C> <C> <C> <C> <C> <C>
Malin to Off-System
- ----------------------
Reservation Charge ($/Dth/mo) 11.66 11.28 10.91 10.55 10.19 9.83
Usage Charge ($/Dth) 0.004 0.004 0.004 0.004 0.004 0.004
Total ($/Dth@Full 0.387 0.375 0.363 0.351 0.339 0.327
Contract)
</TABLE>
Notes:
a) These rates are only the backbone transmission charge component of the
transmission service. They exclude local transmission charges, customer class
charges, customer access charges, distribution charges, storage charges, and
shrinkage charges.
b) The "Total" rows represent the average backbone transmission cost incurred by
a firm shipper that uses its full contract quantity at a 100% load factor.
c) G-XF charges are based on the embedded cost of Line 401 and a 95% load
factor.
d) These rates are subject to change during the Accord period pursuant only to
the z-factor provisions of Section II.I.7.
-79-
<PAGE>
TABLE 12
STORAGE RATES
<TABLE>
<CAPTION>
FIRM STORAGE SERVICE (FS) CAPACITY Withdrawal
------------- -----------------
<S> <C> <C> <C>
RESERVATION CHARGES
Annual Reservation Charge $0.746/Dth $9.651/Dth/day
VARIABLE CHARGES
Variable Charge $0.039/Dth $0.039/Dth
NEGOTIATED FIRM STORAGE (NFS) INJECTION INVENTORY Withdrawal
------------- ------------ ---------------
MAXIMUM RATE
Volumetric Rate 8.149/Dth $1.144/Dth $4.923/Dth
NEGOTIATED AS-AVAILABLE STORAGE (NAS)
MAXIMUM RATE
Volumetric Rate $8.149/Dth $4.923/Dth
</TABLE>
Notes:
a) Rates for storage services are based on the costs of storage injection,
inventory and withdrawal.
b) Firm Storage rates are subfunctionalized by a capacity (combined injection
and inventory) charge and withdrawal charge. The capacity charge is calculated
assuming recovery of both the injection and inventory revenue requirement over
the annual inventory design capacity allocated to the unbundled storage program.
The withdrawal charge is calculated based on recovery of the withdrawal revenue
requirement over the daily withdrawal design capacity allocated to the unbundled
storage program.
c) Firm Storage capacity and withdrawal charges are recovered through a
reservation (fixed) and volumetric (variable) component.
d) Negotiated Firm rates may be one-part rates (volumetric) or two-part rates
(reservation and variable), as negotiated between parties. The volumetric
equivalent is shown above.
e) Negotiated As-available Storage Injection and Withdrawal rates are recovered
through a volumetric charge only.
f) The flexibility inherent in this storage offer could result in stranded
facilities and PG&E requires the opportunity to collect the value of the storage
services. Negotiated rates (NFS and NAS) are capped at the price which will
collect 100 percent of PG&E's total revenue requirement for the unbundled
storage program under all three subfunctions (e.g. inventory, injection, or
withdrawal.) The maximum rates are based on a rate design assuming an average
injection period of 30 days and an average withdrawal period of 7 days.
g) Negotiated Firm and As-available services are negotiable above a price floor
representing PG&E's marginal cost of providing the service.
h) Rates will be implemented for the unbundled storage program in April 1,1998.
i) The maximum annual charge for parking and lending is based on the annual cost
of cycling one Dth of Firm Storage Gas assuming the full 214 day injection
season and 151 day withdrawal season. The annual cycle cost is $0.89 per Dth.
-80-
<PAGE>
TABLE 13
LOCAL TRANSMISSION RATES
($/DTH)
<TABLE>
<CAPTION>
1997 1998 1999 2000 2001 2002
<S> <C> <C> <C> <C> <C> <C>
Core .254 .260 .267 .273 .280 .287
Noncore .131 .135 .138 .141 .145 .149
</TABLE>
Notes:
a) These rates are subject to change during the Accord period pursuant only to
the z-factor provisions of Section II.I.7.
b) Rates for 1998-2002 escalate at 2.5 percent.
c) First year rates are based on 1996 GRC revenue requirement, 1995 BCAP cost
allocation and throughput, and 57.8% of BCAP adopted APD adjustment.
-81-
<PAGE>
TABLE 14
ILLUSTRATIVE CUSTOMER CLASS CHARGES
($/DTH)
<TABLE>
<CAPTION>
1997 1998 1999 2000 2001 2002
<S> <C> <C> <C> <C> <C> <C>
Residential .353 .224 .223 .121 .119 .118
Small Commercial .404 .276 .276 .174 .175 .175
Large Commercial .300 .200 .201 .099 .099 .100
Industrial
Distribution .207 .149 .122 .083 .084 .085
Industrial
Transmission .174 .127 .100 .061 .062 .062
UEG .132 .093 .066 .039 .039 .039
Cogeneration .132 .093 .066 .039 .039 .039
Wholesale
Coalinga .145 .100 .072 .045 .045 .045
Palo Alto .136 .094 .066 .039 .039 .039
</TABLE>
Notes:
a) Customer class charges include no ITCS for core, and 50% of ITCS for noncore,
as described in Section IV.B.4. Core rates include a refund of ITCS costs
recovered prior to 1997.
b) Rates for 1997 consistent with 1995 BCAP decision. Rates for 1998-2002 do not
escalate at 2.5%. Instead they represent forecasts of individual balancing
accounts. Actual rates will be determined in BCAPs or successor proceedings.
c) The UEG and cogeneration customer class charges include costs associated with
cogeneration rate parity. See section III.C.5.
-82-
<PAGE>
TABLE 15 (REVISED--9/11/96)
1997 CUSTOMER ACCESS CHARGE
FOR ON-SYSTEM CUSTOMERS DIRECTLY CONNECTED
TO THE TRANSMISSION SYSTEM
($/MONTH)
<TABLE>
<CAPTION>
1997 1998 1999 2000 2001 2002
<S> <C> <C> <C> <C> <C> <C> <C>
Industrial (Therms/Month)
- ------------
10.49 10.75 11.02 11.30 11.58 11.87
Tier 1 0 to 5,000
82.66 84.73 86.84 89.02 91.24 93.52
Tier 2 5,001 to 10,000
313.58 321.42 329.45 337.69 346.13 354.79
Tier 3 10,001 to 50,000
826.61 847.28 868.46 890.17 912.42 935.23
Tier 4 50,001 to 200,000
1,183.50 1,213.09 1,243.41 1,274.50 1,306.36 1,339.02
Tier 5 200,001 to 1,000,000
3,440.30 3,526.31 3,614.47 3,704.83 3,797.45 3,892.38
Tier 6 1,000,001 and above
113,083 115,910 118,808 121,778 124,822 127,943
UEG
Cogeneration ($/Dth) .00710 .00728 .00746 .00765 .00784 .00803
WHOLESALE
- ------------
908.67 931.39 954.67 978.54 1,003.00 1,028.08
Coalinga
3,882.42 3, 979.48 4,078.96 4,180.94 4,285.46 4,392.60
Palo Alto
</TABLE>
Notes:
a) Customer access charges escalate at 2.5% per year.
-83-
<PAGE>
TABLE 16
FORECAST DISTRIBUTION RATES
($/DTH)
<TABLE>
<CAPTION>
1997 1998 1999 2000 2001 2002
<S> <C> <C> <C> <C> <C> <C>
Residential 2.53 2.59 2.66 2.72 2.79 2.86
Small Commercial 2.53 2.59 2.66 2.72 2.79 2.86
Large Commercial .94 .96 .99 1.01 1.04 1.06
Industrial .656 .672 .689 .706 .724 .742
Distribution
</TABLE>
Notes:
a) Core and noncore rates are distribution only.
b) Commercial and industrial rates shown are average distribution rates.
Commercial and industrial distribution rates will be seasonally differentiated
and include a monthly customer charge.
c) Illustrative rates, based on 2.5% escalation, are shown. Actual rates will be
determined in BCAPs or successor proceedings.
d) There is no cogeneration rate shown, since cogenerators receive rate parity
with UEG, which is transmission level service.
e) All rates exclude procurement and interstate transmission.
-84-
<PAGE>
TABLE 17
ILLUSTRATIVE BUNDLED
1997 CORE TRANSPORTATION RATES
($/DTH)
<TABLE>
<CAPTION>
LARGE
RESIDENTIAL SMALL COMMERCIAL COMMERCIAL AVERAGE CORE
<S> <C> <C> <C> <C>
Intrastate Backbone .148 .148 .130 .147
Transmission
Intrastate Local .254 .254 .254 .254
Transmission
Customer class charge .353 .404 .300 .363
Distribution 2.53 2.53 .945 2.45
Storage .115 .115 .102 .115
Procurement 1.92 1.92 1.92 1.92
Interstate Transmission .292 .281 .281 .289
-------------------------------------------------------------------------------------
Total 5.61 5.65 3.93 5.53
</TABLE>
Note:
a) Average backbone transmission rate based on expected core deliveries from
Line 400, Line 300 and California gas production, based on the capacity
assignments discussed in Section I.E.
b) Average core storage rates are based on core capacity reservations set forth
in Section II.E.
-85-
<PAGE>
TABLE 18 (REVISED--9/11/96)
1997 SEASONAL VOLUMETRIC RATES FOR DISTRIBUTION SERVICE CUSTOMERS
($/th)
<TABLE>
<CAPTION>
SUMMER VOLUMETRIC WINTER AVERAGE WINTER TO
RATE VOLUMETRIC RATE VOLUMETRIC RATE SUMMER RATIO
<S> <C> <C> <C> <C>
Small Commercial $.166 $.250 $.212 1.50
Large Commercial $.065 $.110 $.089 1.70
Industrial $.048 $.064 $.056 1.35
Distribution
</TABLE>
Notes:
a) Rates exclude monthly customer charge.
-86-
<PAGE>
EXHIBIT 10.4
PG&E CORPORATION
DEFERRED COMPENSATION PLAN
FOR NON-EMPLOYEE DIRECTORS
(As Amended and Restated Effective as of December 17, 1997)
1. Establishment and Purpose
-------------------------
The is the controlling and definitive statement of the PG&E Corporation
Deferred Compensation Plan for Non-Employee Directors ("Plan"). The Plan
was originally adopted on December 18, 1996, by the Board of Directors of
PG&E Corporation to provide Directors of PG&E Corporation an opportunity to
defer payment of their Meeting Fees and Retainer Fees. The Plan is also
intended to establish a method of paying Meeting Fees and Retainer Fees
which will assist the Corporation in attracting and retaining persons of
outstanding achievement and ability as members of the Board of Directors of
the Corporation.
2. Definitions
-----------
(a) "Beneficiary" means the person, persons, or entity designated by the
Director to receive payment of the Director's Deferred Compensation
Account in the event of the death of the Director.
(b) "Board" and "Board of Directors" means the Board of Directors of the
Corporation.
(c) "Committee" shall mean the Nominating and Compensation Committee of
the Board.
(d) "Corporation" means PG&E Corporation, a California corporation.
(e) "Deferred Compensation Account" means the bookkeeping account
established pursuant to Section 6 on behalf of each Director who
elects to participate in the Plan.
(f) "Deferred Election Form" means a participation form to be supplied
by the Secretary of the Corporation.
(g) "Director" means a member of the Board of Directors who is not an
employee of the Corporation or any subsidiary thereof.
(h) "Director's Termination Date" shall mean the effective date of the
Director's resignation from the Board of Directors of the
Corporation.
(i) "Meeting Fee" means the amount of compensation paid by the
Corporation to a Director for his or her attendance and services at
a meeting of the Board of Directors or any committee thereof. A
Meeting Fee shall not include (i) any Retainer Fee, (ii) any
reimbursement by the Corporation of expenses incurred by a Director
incidental to attendance at a meeting of the Board of Directors or
of a committee thereof or of any other expense incurred on behalf of
the Corporation, or (iii) any amount payable with respect to
services rendered prior to January 1, 1997.
<PAGE>
(j) "Plan" shall mean the PG&E Corporation Deferred Compensation Plan
for Non-Employee Directors.
(k) "Retainer Fee" means the amount of compensation paid by the
Corporation to a Director for retaining his or her services during a
calendar quarter. A Retainer Fee shall not include (i) any Meeting
Fee, (ii) any reimbursement by the Corporation of expenses incurred
by a Director incidental to attendance at a meeting of the Board of
Directors or of a committee thereof or of any other expense incurred
on behalf of the Corporation, or (iii) any amount payable with
respect to services rendered prior to January 1, 1997.
(l) "Year" shall mean the calendar year.
3. Eligibility
-----------
Each Director who receives a Meeting Fee or Retainer Fee for service on the
Board of Directors shall be eligible to participate in the Plan.
4. Participation
-------------
In order to commence participation in the Plan in 1997, a Director must
file a deferral election with the Secretary of the Corporation prior to
January 1, 1997. In order to commence participation in the Plan for
calendar quarters commencing on or after April 1, 1997, a Director must
file a Deferral Election Form with the Secretary of the Corporation prior
to the first day of the calendar quarter for which participation is to
become effective. Notwithstanding the foregoing, in the case of a newly
elected Director, an election to participate shall be effective for the
calendar quarter in which the Director is first elected if it is filed
before the date the Director first receives a Meeting Fee or Retainer Fee
(but in no event later than one month following the date of election).
A participating Director may defer:
(a) All Retainer Fees only; or
(b) All Meeting Fees only; or
(c) All Retainer Fees and all Meeting Fees.
The Retainer Fees and Meeting Fees deferred under (a), (b), or (c), above,
shall be net of any amounts which a Director has authorized the Corporate
Secretary to transmit to the Corporation's Dividend Reinvestment and Common
Stock Purchase Plan. Partial deferral of Retainer Fees or Meeting Fees is
not permitted.
Payment to the Director of deferred compensation may, at the election of
the participating Director, be paid in a lump sum or in a series of ten or
less approximately equal annual installments. Payment to the Director may
commence in the Year following the Director's Termination Date or in such
earlier year as the Director may specify on the Deferral Election Form.
2
<PAGE>
5. Deferral Election
-----------------
A Director who elects to participate in the Plan shall file an executed
Deferral Election Form with the Secretary of the Corporation indicating the
compensation to be deferred, the time and form of distribution, and the
Beneficiary designations described in Section 9.
The Director's deferral election shall become effective and apply with
respect to Meeting Fees and Retainer Fees earned for the first calendar
quarter after the Deferral Election Form is filed with the Secretary of the
Corporation and all subsequent calendar quarters until revoked (by electing
not to further defer either Meeting Fees or Retainer Fees) or modified by
the Director. The Director shall notify the Secretary of the Corporation
in writing of any such revocation or modification, which shall apply solely
to amounts deferred with respect to calendar quarters following the
calendar quarter in which the revocation or modification is received by the
Secretary of the Corporation.
Notwithstanding the foregoing, the Director's designation as to time and
form of distribution to the Director of deferred compensation may not be
revoked or modified by the Director either as to amounts already deferred
or as to amounts to be deferred in the future.
6. Credits to Deferred Compensation Account
----------------------------------------
Upon receipt of a duly filed Deferral Election Form, the Corporation shall
establish a Deferred Compensation Account to which shall be credited an
amount equal to the Meeting Fees and/or Retainer Fees which would have been
payable currently to the Director but for the terms of the deferral
election.
Retainer Fees and Meeting Fees shall be credited to the Director's Deferred
Compensation Account as of the following dates:
(a) The deferred Retainer Fee for each calendar quarter shall be
credited to such Account as of the first day of such calendar
quarter; and
(b) The deferred Meeting Fee shall be credited to such Account as of the
first business day following the date of the meeting for which the
Meeting Fee was earned.
7. Interest During Deferral Period
-------------------------------
At such time as participant elects to participate in the Plan, he shall
also elect to have his account balances credited to the Utility Bond Fund
or to the PG&E 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 a participant may
not reallocate Phantom Stock Fund units and the earnings thereon which were
credited to a participant's Deferred Compensation Account in connection
with the termination of the PG&E Corporation Retirement Plan for Non-
Employee Directors. 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 under
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.
3
<PAGE>
(a) Utility Bond Fund
-----------------
On the first 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. 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 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 Phantom Stock Fund
-----------------------
Deferrals and transfers into this Fund shall be converted into units
representing a share of PG&E Corporation stock, where the value of a
unit is 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-day period preceding the date of deferral or transfer into this
Fund. Thereafter, the value of a unit shall fluctuate with the value
of a share of PG&E Corporation common stock. Each time that the
Corporation pays a dividend on its stock, an amount equal to such
dividend, multiplied by the number of PG&E Phantom Stock Fund units
held in a participant's account, shall be credited to a participant's
account and converted into additional units.
8. Form and Time of Payment to a Director of Deferred Compensation Account
-----------------------------------------------------------------------
Payment to a Director of his or her Deferred Compensation Account shall be
made in cash prior to January 31 in each Year in which payment is to be
made in accordance with the Director's deferral election; provided,
however, that amounts attributable to Phantom Stock Fund units and the
earnings thereon which were credited to a participant's Deferred
Compensation Account in connection with the termination of the PG&E
Corporation Retirement Plan for Non-Employee Directors may not be
distributed from the Plan until the latter of the participant's retirement
from the Board, or age 65.
9. Effect of Death of Participant
------------------------------
Upon the death of a Director 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 Director. Such
distribution shall be made at the time or times specified as part of the
Beneficiary designation of the Director's deferral election (but, in no
event shall such distribution be made later than ten years after the death
of the Director or in more than ten approximately equal annual
installments). The Committee, however, reserves the right to determine in
its sole discretion that payment shall be made at a different time or times
(but no later than ten years after the death of the Director). If the
designated Beneficiary does not survive the Director or dies before
receiving payment in full of the Director's Deferred Compensation Account,
payment of the remaining balance shall be made as soon as practicable in a
lump sum to the estate of the last to die of the Director or the designated
Beneficiary. All Beneficiary designations (including selection of the
timing and manner of payments to any Beneficiary) may be revoked or
modified at the Director's option. The Director shall notify the Secretary
of the Corporation in writing of any such revocation or modification.
4
<PAGE>
10. Participant's Rights Unsecured
------------------------------
The interest under the Plan of any participating Director and such
Director'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 no Director shall have an interest in or
claim against any specific asset of the Corporation pursuant to the Plan.
11. Statement of Deferred Compensation Account
------------------------------------------
The Secretary of the Corporation shall provide to each participating
Director an annual statement of his or her Deferred Compensation Account no
later than January 31 each year.
12. Nonassignability of Interests
-----------------------------
The interests and property rights of any Director 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 12
shall be void.
13. Administration of the Plan
--------------------------
The Plan shall be administered by the Committee. In addition to the powers
and duties otherwise set forth in the Plan, the Committee 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 Committee's interpretation and
construction of the Plan shall be conclusive and binding on all persons.
14. Amendment or Termination of the Plan
------------------------------------
The Board of Directors may amend, suspend, or terminate the Plan at any
time. In the event of such termination, the Deferred Compensation Accounts
of participating Directors shall be paid at such times and in such forms as
shall be determined pursuant to Section 8, unless the Board of Directors
shall prescribe a different time or times for payments of such Accounts.
5
<PAGE>
EXHIBIT 10.5
PG&E CORPORATION
DEFERRED COMPENSATION PLAN
FOR OFFICERS
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) unused 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 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) SALARY, or (iii) PERFORMANCE UNITS 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 unused PERQUISITE ALLOWANCES may be
filed at any time. 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 unused 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 grant. SPECIAL
INCENTIVE STOCK OWNERSHIP PREMIUMS and
-3-
<PAGE>
any dividends earned thereon remain unvested until the third
anniversary of the date on which they are credited to an OFFICER'S
DEFERRED COMPENSATION ACCOUNT. Unvested SPECIAL INCENTIVE STOCK
OWNERSHIP PREMIUMS and any dividends earned thereon shall be forfeited
if an OFFICER'S stock ownership falls below the levels set forth in
the Executive Stock Ownership Guidelines.
Upon retirement or death of a participant, unvested SPECIAL INCENTIVE
STOCK OWNERSHIP PREMIUMS and any dividends credited thereon shall
immediately vest and shall be payable in accordance with the terms of
the PLAN.
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, unused 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.
The participant's deferral election of SALARY shall continue from YEAR to
YEAR until terminated or modified by written notice to the PLAN
ADMINISTRATOR. Deferral elections of INCENTIVE PLAN AWARDS, PERFORMANCE
UNITS, SAVINGS FUND PLAN EXCESS BENEFITS, and unused 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. Notice of termination or
modification of SALARY, INCENTIVE PLAN AWARDS, and/or PERFORMANCE UNITS
deferral 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. In no event shall any notice of termination or modification
affect amounts deferred prior to the effective date of such notice.
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.
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. Deferred INCENTIVE PLAN
AWARDS shall be credited to the participant's DEFERRED
-4-
<PAGE>
COMPENSATION ACCOUNT on the first of the month following the announcement
of the granting of the participant's individual INCENTIVE PLAN AWARD.
SAVINGS FUND PLAN EXCESS BENEFITS shall be credited to the participant's
DEFERRED COMPENSATION ACCOUNT as of January 1 following the YEAR to which
such Excess Benefits are attributable. PERQUISITE ALLOWANCES shall be
credited to the participant's DEFERRED COMPENSATION ACCOUNT as soon as
practicable after receipt of a DEFERRAL ELECTION FORM specifying the dollar
amount to be deferred. PERFORMANCE UNITS and INCENTIVE PLAN AWARDS shall be
credited to the participant's DEFERRED COMPENSATION ACCOUNT as of the first
business day following the date of payment.
SPECIAL INCENTIVE STOCK OWNERSHIP PREMIUMS shall be credited to the
participant's DEFERRED COMPENSATION ACCOUNT immediately upon the date of
grant. Each SPECIAL INCENTIVE STOCK OWNERSHIP PREMIUM shall be equal to a
share of PG&E Corporation common stock. The initial value of a SPECIAL
INCENTIVE STOCK OWNERSHIP PREMIUM 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-day period preceding the date that the
SPECIAL INCENTIVE STOCK OWNERSHIP PREMIUM is credited to a participant's
DEFERRED COMPENSATION ACCOUNT. Each time that the CORPORATION pays a
dividend on its stock, an amount equal to such dividend, multiplied by the
number of a participant's SPECIAL INCENTIVE STOCK OWNERSHIP PREMIUMS shall
be credited to the participant's account and converted into additional
SPECIAL INCENTIVE STOCK OWNERSHIP PREMIUMS. The number of additional
SPECIAL INCENTIVE STOCK OWNERSHIP PREMIUMS shall be calculated by dividing
the aggregate amount of credited dividends by 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 a period of five trading days ending on the
eight day of the month, or, if such day is not a business day, on the
business day next preceding the eighth. Thereafter, the value of a SPECIAL
INCENTIVE STOCK OWNERSHIP PREMIUM shall fluctuate with the value of a share
of PG&E Corporation common stock.
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 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 SPECIAL INCENTIVE
STOCK OWNERSHIP PREMIUMS and earnings and dividends 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.
-5-
<PAGE>
(a) Utility Bond Fund
-----------------
On the first 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 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 Phantom Stock Fund
-----------------------
Deferrals and reallocations from the Utility Bond Fund to the PG&E Phantom
Stock Fund shall be converted into units representing a share of PG&E
Corporation common stock. The initial value of a 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-day period preceding
the date that (i) deferrals are credited to a participant's account in the
PG&E Phantom Stock Fund, or (ii) the PLAN ADMINISTRATOR receives a
reallocation request. Each time that the CORPORATION pays a dividend on
its stock, an amount equal to such dividend, multiplied by the number of
units credited to a participant's account, shall be credited to the
participant's account and converted into additional units. The number of
additional units shall be calculated by dividing the aggregate amount of
credited dividends by 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 a period of five trading days ending on the eight day of the
month, or, if such day is not a business day, on the business day next
preceding the eighth. Thereafter, the value of a unit shall fluctuate with
the value of a share of PG&E Corporation common stock.
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
1954, as amended.
-6-
<PAGE>
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 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.
Notwithstanding the foregoing, deferrals attributable to SPECIAL INCENTIVE
STOCK OWNERSHIP PREMIUMS shall only be paid 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 PREMIUMS
following a participant's retirement or, if earlier, death or termination
of employment.
Payment to a participant of his or her DEFERRED COMPENSATION ACCOUNT shall
be made in January of each YEAR in which payment is to be made in
accordance with the participant's deferral election. All payments from the
DEFERRED COMPENSATION ACCOUNT shall be subject to all tax withholdings or
other reductions which may be required by law.
10. 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 in a lump sum to the BENEFICIARY designated by the OFFICER on
the DEFERRAL ELECTION FORM. 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 PREMIUMS 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 PREMIUMS) 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.
11. 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
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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.
12. 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 Phantom Stock Fund units, the amount
of SPECIAL INCENTIVE STOCK OWNERSHIP 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.
13. 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 13 shall be void.
14. 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.
15. 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.
Adopted pursuant to the delegation contained in the Resolution of the Board of
Directors of PG&E Corporation dated June 18, 1997.
By: /s/ Robert D. Glynn, Jr.
______________________________
Robert D. Glynn, Jr.
President and Chief Executive Officer
PG&E Corporation
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<PAGE>
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
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<PAGE>
EXHIBIT 10.6
THE PACIFIC GAS AND ELECTRIC COMPANY
SAVINGS FUND PLAN
FOR NON-UNION EMPLOYEES
_________________________________________
This is the controlling and definitive statement of the Pacific Gas and
Electric Company Savings Fund Plan for Non-Union EMPLOYEES /1/ in effect on and
after October 1, 1997. The PLAN, which covers ELIGIBLE EMPLOYEES of the COMPANY
and other EMPLOYERS, is a further revision of the one originally placed in
effect by the COMPANY as of April 1, 1959. It has since been amended from time
to time. The PLAN as amended may be further amended retroactively in order to
meet applicable rules and regulations of the Internal Revenue Service, the
United States Department of Labor and all other applicable rules and
regulations.
The PLAN is maintained for the exclusive benefit of participants or their
BENEFICIARIES, and contributions or benefits under the PLAN do not discriminate
in favor of HIGHLY COMPENSATED EMPLOYEES.
ELIGIBILITY AND PARTICIPATION
-----------------------------
1. Eligibility
-----------
A non-union EMPLOYEE becomes an ELIGIBLE EMPLOYEE upon commencement of
employment. Once eligibility occurs it continues as long as the EMPLOYEE
remains a non-union EMPLOYEE and SERVICE continues.
2. Participation
-------------
To become a participant, an ELIGIBLE EMPLOYEE must provide NOTICE to the
PLAN ADMINISTRATOR of the ELIGIBLE EMPLOYEE'S election to participate and
to be bound by the terms of the PLAN. Through such NOTICE, the ELIGIBLE
EMPLOYEE shall:
(a) authorize the EMPLOYER to reduce his COVERED COMPENSATION by a
stated percentage and to contribute such amount to the PLAN as a
SECTION 401(k)
(b) elect to make NON-SECTION 401(k) CONTRIBUTIONS, if any, to the PLAN;
and
(c) instruct the PLAN ADMINISTRATOR as to the manner in which EMPLOYEE
contributions and matching EMPLOYER CONTRIBUTIONS are to be invested.
- ------------------
/1/ Words in all capitals are defined in Section 30.
<PAGE>
CONTRIBUTIONS
-------------
3. EMPLOYEE Contributions
----------------------
To become a contributing participant, an ELIGIBLE EMPLOYEE must make
SECTION 401(k) CONTRIBUTIONS, NON-SECTION 401(k) CONTRIBUTIONS, or a
combination of both to the PLAN through payroll deduction.
All contributions withheld by the EMPLOYER from COVERED COMPENSATION are
paid over to the TRUSTEE, unconditionally credited to the participant's
account and invested in accordance with the participant's instructions.
(a) SECTION 401(k) CONTRIBUTIONS. A SECTION 401(k) CONTRIBUTION is an
election to defer the receipt of a specified whole percentage of
COVERED COMPENSATION which would otherwise be currently payable to a
participant. The EMPLOYER shall reduce the participant's COVERED
COMPENSATION by an amount equal to the percentage of the SECTION
401(k) CONTRIBUTION elected by the participant. Under current law,
SECTION 401(k) CONTRIBUTIONS deferred by a participant under the
PLAN are not subject to federal or state income tax until actually
withdrawn or distributed from the PLAN.
(b) FLEXDOLLARS. By giving NOTICE, a participant in the COMPANY'S Flex
Plan may elect to have any unused FLEXDOLLARS contributed to this
PLAN. Any FLEXDOLLARS contributed to this PLAN shall be deemed
SECTION 401(k) CONTRIBUTIONS and shall be subject to all
restrictions and limitations applicable to SECTION 401(k)
CONTRIBUTIONS. FLEXDOLLAR contributions shall not be eligible for
matching EMPLOYER CONTRIBUTIONS as described in Section 4.
(c) NON-SECTION 401(k) CONTRIBUTIONS. NON-SECTION 401(k) CONTRIBUTIONS
differ from SECTION 401(k) CONTRIBUTIONS in that a participant has
already paid taxes on the amounts contributed to the PLAN. All
EMPLOYEE Contributions made to the PLAN as it existed prior to
October 1, 1984, are considered to be NON-SECTION 401(k)
CONTRIBUTIONS and are so recorded in the accounts maintained by the
PLAN ADMINISTRATOR.
NON-SECTION 401(k) CONTRIBUTIONS must be made in whole percentages of
COVERED COMPENSATION, and the sum of all SECTION 401(k)
CONTRIBUTIONS and NON-SECTION 401(k) CONTRIBUTIONS made by a
participant may not exceed 15 percent of the participant's COVERED
COMPENSATION.
(d) CHANGING CONTRIBUTIONS. By giving NOTICE to the PLAN ADMINISTRATOR,
a participant may direct the PLAN ADMINISTRATOR to cease or resume
making contributions, or to change the rate of contributions. Any
such change shall become effective within 30 days of receipt by the
PLAN ADMINISTRATOR of such NOTICE.
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<PAGE>
4. Employer Contributions
----------------------
(a) Each and every time that participants make Section 401(k) or non-
section 401(K) CONTRIBUTIONS to the PLAN eligible for matching
EMPLOYER CONTRIBUTIONS, the COMPANY shall make a matching EMPLOYER
CONTRIBUTION to the PLAN in cash or in whole shares of COMMON STOCK,
or partly in both. Matching EMPLOYER CONTRIBUTIONS shall be limited
to an amount equal to three-quarters of the aggregate participant
contributions eligible for matching EMPLOYER CONTRIBUTIONS under the
provisions of Subsection 4(a)(1). The COMPANY shall charge to each
EMPLOYER its appropriate share of matching EMPLOYER CONTRIBUTIONS.
(1) SECTION 401(k) and NON-SECTION 401(k) CONTRIBUTIONS Eligible
for Matching EMPLOYER CONTRIBUTIONS. Although a participant may
elect to defer up to 15 percent of COVERED COMPENSATION to the
PLAN, the maximum amount of a participant's contributions
eligible for matching EMPLOYER CONTRIBUTIONS shall be one of
the following percentages of COVERED COMPENSATION:
a) up to 3 percent, with at least one but less than three
years of SERVICE; or
b) up to 6 percent, with at least three years of SERVICE.
c) for a participant who is absent from work and receiving
temporary compensation under any state Worker's
Compensation Law or under the COMPANY'S LONG TERM
DISABILITY PLAN, the larger of:
i) the maximum percentage calculated under (a) or (b),
whichever is applicable; or
ii) the dollar amount which was eligible for matching
EMPLOYER CONTRIBUTIONS immediately before the
participant's absence began.
(b) Investment of EMPLOYER CONTRIBUTIONS. All EMPLOYER CONTRIBUTIONS
made to the PLAN shall be invested by the TRUSTEE in accordance with
a participant's INVESTMENT FUND directions.
5. Rollover Contributions
----------------------
(a) With the approval of the Plan Administrator, an Eligible Employee
may make a rollover to the Plan in cash an amount which constitutes
all or part of an eligible rollover distribution (as defined in
Section 402(c)(4) of the Code). However, a direct or indirect
transfer to this Plan from another qualified plan will not be
permitted if such transfer would subject this Plan to the qualified
joint and survivor rules of Code Section 401(a)(11)
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<PAGE>
(b) The Employer, the Plan Administrator and the Trustee have no
responsibility for determining the propriety of, proper amount or
time of, or status as a tax-free transaction of any transfer under
Subsection (a) above.
(c) The Plan administrator shall develop such procedures, and may
require such information from the individual who is requesting to
make a rollover to the Plan, as necessary or desirable in order to
determine that the proposed rollover will meet the requirements of
this Section 5.
(d) A rollover will be credited to the participant's account and will be
recorded separately as a Rollover Contribution by the Plan
Administrator as soon as practicable following the receipt thereof
by the Trustee.
(e) The Plan Administrator in its discretion may direct the return to
the participant (or the transfer to another trustee or custodian
designated by the participant) of any Rollover Contribution and any
earnings thereon to the extent the Plan Administrator determines
that such return may be necessary to insure the continued
qualification of this Plan under Section 401(a) of the Code.
(f) Rollover Contributions shall not be eligible for matching Employer
Contributions as described in Section 4.
6. Limitations
-----------
(a) Average Deferral Percentage Limitation. In any PLAN YEAR, the
average rate of SECTION 401(k) CONTRIBUTIONS as a percentage of
compensation for all participating HIGHLY COMPENSATED ELIGIBLE
EMPLOYEES shall not exceed the larger of:
(1) the average rate of SECTION 401(k) CONTRIBUTIONS as a
percentage of compensation for all other participating ELIGIBLE
EMPLOYEES multiplied by 1.25 percent; or
(2) the lesser of:
a) the average rate of SECTION 401(k) CONTRIBUTIONS as a
percentage of compensation for all other participating
ELIGIBLE EMPLOYEES multiplied by 2; or
b) the average rate of SECTION 401(k) CONTRIBUTIONS as a
percentage of compensation for all other participating
ELIGIBLE EMPLOYEES plus 2 percentage points, or such lesser
amount as the Secretary of the Treasury may prescribe in
order to prevent the multiple use of this alternative
limitation with respect to any HIGHLY COMPENSATED
participant. If multiple use of the alternative limitation
occurs with respect to the Average Deferral Percentage
Limitation and Average Contribution Percentage Limitation
in this PLAN, it will be corrected by reducing the actual
contribution percentage of HIGHLY COMPENSATED participants
in the manner described in Section 6(c), below.
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<PAGE>
The average rate of SECTION 401(k) CONTRIBUTIONS for a PLAN YEAR for a
designated group of ELIGIBLE EMPLOYEES shall be the average of the
ratios, calculated separately for each participating ELIGIBLE EMPLOYEE
in the group, of the amount of SECTION 401(k) CONTRIBUTIONS made by
each EMPLOYEE for the PLAN YEAR, to the EMPLOYEE'S compensation for
such PLAN YEAR. As used in this subsection, compensation shall mean
compensation paid by an EMPLOYER to the participant during the PLAN
YEAR which is required to be reported as wages on the participant's
form W-2 and shall also include compensation which is not currently
includable in the participant's gross income by reason of the
application of CODE Sections 125 and 402(e)(3).
For purposes of this subsection, the ratio of the amount of SECTION
401(k) CONTRIBUTIONS to a participant's compensation for any
participant who is HIGHLY COMPENSATED for the PLAN YEAR and who is
eligible to have elective deferrals or qualified employer deferral
contributions allocated to his account under two or more plans or
arrangements described in Section 401(k) of the CODE that are
maintained by an employer or affiliated employer shall be determined
as if all such SECTION 401(k) CONTRIBUTIONS, elective deferrals and
qualified employer deferral contributions were made under a single
arrangement.
For purposes of determining the ratio of the amount of SECTION 401(k)
CONTRIBUTIONS to a participant's compensation for a participant who is
HIGHLY COMPENSATED by reason of being one of the ten highest-paid
EMPLOYEES or a 5 percent owner of the controlled group of
corporations, as defined in Section 414 of the CODE, the SECTION
401(k) CONTRIBUTIONS and compensation of such participant shall
include the SECTION 401(k) CONTRIBUTIONS and compensation of the
participant's family members, as defined in Section 414 of the CODE,
and such family members shall be disregarded in determining the
average rate of SECTION 401(k) CONTRIBUTIONS for non-HIGHLY
COMPENSATED participants.
The determination and treatment of SECTION 401(k) CONTRIBUTIONS of any
participant shall satisfy such other requirements as may be prescribed
by the Secretary of the Treasury.
(b) Average Contribution Percentage Limitation. In any PLAN YEAR, the
average rate of NON-SECTION 401(k) CONTRIBUTIONS and EMPLOYER
CONTRIBUTIONS as a percentage of compensation for all participating
HIGHLY COMPENSATED ELIGIBLE EMPLOYEES shall not exceed the larger
of:
(1) the average rate of NON-SECTION 401(k) CONTRIBUTIONS and
EMPLOYER CONTRIBUTIONS as a percentage of compensation for all
other participating ELIGIBLE EMPLOYEES multiplied by 1.25; or
(2) the lesser of:
a) the average rate of NON-SECTION 401(k) CONTRIBUTIONS and
EMPLOYER CONTRIBUTIONS as a percentage of compensation for
all other participating ELIGIBLE EMPLOYEES multiplied by 2;
or
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<PAGE>
b) the average rate of NON-SECTION 401(k) CONTRIBUTIONS and
EMPLOYER CONTRIBUTIONS for all other participating ELIGIBLE
EMPLOYEES plus 2 percentage points, or such lesser amount
as the Secretary of the Treasury may prescribe in order to
prevent the multiple use of this alternative limitation
with respect to any HIGHLY COMPENSATED participant. If
multiple use of the alternative limitation occurs with
respect to the Average Deferral Percentage Limitation and
Average Contribution Percentage Limitation in this PLAN, it
will be corrected by reducing the actual contribution
percentage of HIGHLY COMPENSATED participants in the manner
described in Section 6(c), below.
The average rate of NON-SECTION 401(k) CONTRIBUTIONS and EMPLOYER
CONTRIBUTIONS for a PLAN YEAR for a designated group of ELIGIBLE
EMPLOYEES shall be the average of the ratios, calculated separately
for each participating ELIGIBLE EMPLOYEE in the group, of the amount
of NON-SECTION 401(k) CONTRIBUTIONS and EMPLOYER CONTRIBUTIONS made
by and on behalf of each EMPLOYEE for the PLAN YEAR, to the
EMPLOYEE'S compensation for such PLAN YEAR. As used in this
subsection, compensation shall mean compensation paid by an EMPLOYER
to the participant during the PLAN YEAR which is required to be
reported as wages on the participant's form W-2 and shall also
include compensation which is not currently includable in the
participant's gross income by reason of the application of CODE
Sections 125 and 402(e)(3).
For purposes of this subsection, the ratio of the amount of NON-
SECTION 401(k) CONTRIBUTIONS and EMPLOYER CONTRIBUTIONS to a
participant's compensation for any participant who is HIGHLY
COMPENSATED for the PLAN YEAR and who is eligible to have elective
deferrals or qualified employer deferral contributions allocated to
his account under two or more plans or arrangements described in
Section 401(k) of the CODE that are maintained by an employer or
affiliated employer shall be determined as if all such NON-SECTION
401(k) CONTRIBUTIONS and EMPLOYER CONTRIBUTIONS, elective deferrals
and qualified employer deferral contributions were made under a
single arrangement.
For purposes of determining the ratio of the amount of NON-SECTION
401(k) CONTRIBUTIONS and EMPLOYER CONTRIBUTIONS to a participant's
compensation for a participant who is HIGHLY COMPENSATED by reason
of being one of the ten highest-paid EMPLOYEES or a 5 percent owner
of the controlled group of corporations, as defined in Section 414
of the CODE, the NON-SECTION 401(k) CONTRIBUTIONS and EMPLOYER
CONTRIBUTIONS and compensation of such participant shall include the
NON-SECTION 401(k) CONTRIBUTIONS and EMPLOYER CONTRIBUTIONS and
compensation of the participant's family members, as defined in
Section 414 of the CODE, and such family members shall be
disregarded in determining the average rate of NON-SECTION 401(k)
CONTRIBUTIONS and EMPLOYER CONTRIBUTIONS for non-HIGHLY COMPENSATED
participants.
The determination and treatment of NON-SECTION 401(k) CONTRIBUTIONS
and EMPLOYER CONTRIBUTIONS of any participant shall satisfy such
other requirements as may be prescribed by the Secretary of the
Treasury.
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<PAGE>
(c) In the event that the EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE, in
its sole and absolute discretion, determines that the rate of
SECTION 401(k) CONTRIBUTIONS, and/or the rate of NON-SECTION 401(k)
CONTRIBUTIONS and EMPLOYER CONTRIBUTIONS will exceed either or both
of the maximum limitations contained in subsections 6(a) and 6(b),
the EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE shall instruct the
PLAN ADMINISTRATOR to reduce the rate of contributions made by
HIGHLY COMPENSATED participants so that the limitations will be met.
The PLAN ADMINISTRATOR shall first determine the maximum average rate
of contributions which can be made by the HIGHLY COMPENSATED
participants. The contributions made by HIGHLY COMPENSATED
participants shall then be reduced, on a prospective basis, until the
limitations are met. Any necessary reduction shall be made by first
reducing the highest rate of SECTION 401(k) CONTRIBUTIONS or NON-
SECTION 401(k) CONTRIBUTIONS and EMPLOYER CONTRIBUTIONS as may be
appropriate, currently authorized by participants, with such rate to
be reduced in one percent increments until the maximum permissible
average rate of contributions is met.
Notwithstanding any other provision of the PLAN, if, as of the end of
a PLAN YEAR, the PLAN fails to meet either or both of the tests
described in subsections 6(a) or 6(b), the PLAN ADMINISTRATOR shall,
on or before December 31 of the following PLAN YEAR distribute to each
HIGHLY COMPENSATED participant, beginning with the participant having
the higher ratio, such excess portion of the participant's SECTION
401(k) CONTRIBUTIONS, and/or NON-SECTION 401(k) CONTRIBUTIONS and
EMPLOYER CONTRIBUTIONS (and any income allocable to such portion),
until the PLAN satisfies both of the tests. Distributions made to
satisfy the limitations described in subsection 6(b) shall include
both NON-SECTION 401(k) CONTRIBUTIONS and related matching EMPLOYER
CONTRIBUTIONS in accordance with the requirements of Treasury
Regulation SECTION 1.401(m)-l(e)(4). If there is a loss allocable to
such excess amount, the amount of the distribution shall in no event
be less than the lesser of the (i) participant's account or (ii) the
participant's SECTION 401(k) CONTRIBUTIONS, or NON-SECTION 401(k)
CONTRIBUTIONS and EMPLOYER CONTRIBUTIONS, as appropriate, for the
PLAN YEAR.
For the PLAN YEARS 1987, 1988, 1989, 1990 and 1991 only, the PLAN
ADMINISTRATOR may elect to make qualified non-elective employer
contributions within the meaning of Section 401(m)(4)(c) of the CODE,
on behalf of such non-HIGHLY COMPENSATED participants who are
EMPLOYEES of Pacific Service Employees Association as will cause the
PLAN to meet the appropriate limits set forth in subsections 6(a)
and 6(b). For purposes of PLAN withdrawals qualified non-elective
employer contributions shall be treated as SECTION 401(k)
CONTRIBUTIONS.
For purposes of determining whether the PLAN meets either or both of
the limits set forth in subsections 6(a) and 6(b), the PLAN
ADMINISTRATOR may elect to make the look-back year calculation as
provided in Regulation 1.414(q)-ITA-14(b)(1) for any determination
year on the basis of the calendar year ending with the applicable
determination year.
-7-
<PAGE>
(d) Annual Section 401(k) Limitation. Effective as of January 1, 1987,
no participant shall be permitted to make Section 401(k)
CONTRIBUTIONS to the PLAN during any PLAN YEAR in excess of $7,000,
multiplied by the adjustment factor prescribed by the Secretary of
the Treasury under Section 415(d) of the CODE for years beginning
after December 31, 1987, as applied to elective deferrals. A
participant who is unable to make SECTION 401(k) CONTRIBUTIONS which
would have been eligible for matching EMPLOYER CONTRIBUTIONS because
of the limitation contained in this subsection 6(d), shall be
entitled to make NON-SECTION 401(k) CONTRIBUTIONS in an amount equal
to the amount of SECTION 401(k) CONTRIBUTIONS that could have been
made but for the subsection 6(d) limitation. Such NON-SECTION 401(k)
CONTRIBUTIONS shall be eligible for matching EMPLOYER CONTRIBUTIONS
as though they were SECTION 401(k) CONTRIBUTIONS, subject to the
limitations contained in Section 6.
(e) Section 415 Limitation. Anything herein to the contrary
notwithstanding, in no event shall the annual additions to a
participant's accounts in a YEAR exceed the lesser of (1) 25 percent
of the participant's compensation (as defined in subparagraph
6(e)(1), below) for the YEAR or (2) $30,000, or, if greater, one-
fourth of the defined benefit dollar limitation set forth in Section
415(b)(1) of the CODE as in effect for the PLAN YEAR. For purposes
of applying the limitations of Section 415 of the CODE, the annual
additions which must be kept within the limits set forth above,
shall mean the sum credited to a participant's account for any PLAN
YEAR of (i) EMPLOYER CONTRIBUTIONS and SECTION 401(k) CONTRIBUTIONS,
(ii) NON-SECTION 401(k) CONTRIBUTIONS, and (iii) any amounts
allocated to an individual medical account, as defined in Sections
415(l)(2) and 419A(d)(2) of the CODE. The compensation limitation
percentage referred to above shall not apply to (i) any contribution
for medical benefits, as defined in Section 419A(f)(2) of the CODE,
after a participant's separation from SERVICE which is otherwise
treated as an annual addition, or (ii) any amount which is otherwise
treated as an annual addition under Section 415(l)(1) of the CODE.
(1) Solely for purposes of applying the Section 415 limitations,
compensation shall include all of a participant's wages,
salaries, fees for professional service, and other amounts
received for personal services actually rendered in the course
of employment with an EMPLOYER (including, but not limited to,
commissions paid to salesmen, compensation for services on the
basis of a percentage of profits, commissions on insurance
premiums, tips, and bonuses). For purposes of applying the
Section 415 limitations, compensation shall not include any of
the following:
a) Contributions made by an EMPLOYER to a plan of deferred
compensation to the extent that, before the application of
the Section 415 limitations to that plan, the contributions
are not includable in the gross income of the participant
for the taxable year in which contributed. Any
distributions from a plan of deferred compensation are not
considered as compensation for Section 415 purposes,
regardless of whether such amounts are includable in the
gross income of the EMPLOYEE when distributed. However, any
amounts received by a participant pursuant to an unfunded,
nonqualified plan may be considered as
-8-
<PAGE>
compensation for Section 415 purposes in the year such
income is includable in the gross income of the EMPLOYEE.
b) Amounts realized from the exercise of a nonqualified stock
option, or when restricted stock (or property) held by a
participant either becomes freely transferable or is no
longer subject to a substantial risk of forfeiture.
c) Amounts realized from the sale, exchange, or other
disposition of stock acquired under a qualified stock
option.
d) Other amounts which receive special tax benefits such as
premiums for group term life insurance (but only to the
extent that the premiums are not includable in the gross
income of the participant).
In the event that the annual additions to a participant's
accounts would exceed the Section 415 Limitations, the PLAN
ADMINISTRATOR shall first reduce the participant's NON-
SECTION 401(k) CONTRIBUTIONS until the Section 415
limitations are met.
(f) If a participant of this PLAN is also a participant in the COMPANY'S
RETIREMENT PLAN, Section 415 of the CODE imposes a combined benefit
limitation. Contributions to this PLAN will nevertheless be
permitted to the maximum extent permitted by Section 415 of the CODE
and the terms of the PLAN. If the combined maximum benefit permitted
would be exceeded, the benefit from the COMPANY'S RETIREMENT PLAN
shall be reduced so that the limitation will be met. The combined
maximum benefit for a participant shall be determined pursuant to
the provisions of Section 415(e) of the CODE.
At the election of the PLAN ADMINISTRATOR, special transitional rules
may apply for both the defined benefit fraction and the defined
contribution fraction for EMPLOYEES who were participants as of
December 31, 1982.
(g) Top Heavy Provisions. In the event that the PLAN is or becomes "Top
Heavy", as that term is defined in Section 416(g) of the CODE, the
provision contained in Special Provision A shall supersede any
conflicting provision of the PLAN.
(h) For purposes of determining all benefits under the PLAN, for PLAN
YEARS beginning after 1988 and before 1994, the maximum compensation
of each EMPLOYEE that may be taken into account each PLAN YEAR shall
not exceed $200,000 (as adjusted by the Secretary of the Treasury
under Section 401(a)(17) of the CODE. For purposes of determining
all benefits under the PLAN, for PLAN YEARS beginning after 1993,
the maximum compensation of each EMPLOYEE that may be taken into
account each PLAN YEAR shall not exceed $150,000 (as adjusted by the
Secretary of the Treasury under Section 401(a)(17) of the CODE). In
determining the compensation of a HIGHLY COMPENSATED EMPLOYEE for
purposes of this limitation, the rules of Section 414(q)(6) of the
CODE shall apply, except that the term "family" shall include only
the spouse of the EMPLOYEE and any lineal descendants of the
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<PAGE>
EMPLOYEE who have not attained age 19 before the close of the YEAR.
If the aggregate compensation of family members exceeds the
applicable compensation limit of compensation as limited by Section
401(a)(17) of the CODE, then the amount of compensation considered
under the PLAN for each family member is proportionately reduced so
that the total equals the applicable compensation limitation under
Section 401(a)(17) of the CODE.
SELECTION OF INVESTMENT FUNDS
-----------------------------
7.
(a) SECTION 401(k) CONTRIBUTIONS, NON-SECTION 401(k) CONTRIBUTIONS, and
EMPLOYER CONTRIBUTIONS. By giving NOTICE, a participant shall
instruct the PLAN ADMINISTRATOR to invest his SECTION 401(k)
CONTRIBUTIONS, NON-SECTION 401(k) CONTRIBUTIONS, and EMPLOYER
CONTRIBUTIONS in one or more INVESTMENT FUNDS. The minimum amount
which can be invested in any single INVESTMENT FUND shall be one
percent of a participant's current contributions to the PLAN. A
participant may elect to invest more than the minimum amount in any
INVESTMENT FUND, provided that any such increase must be in
increments of one percent.
(b) CHANGE OF INVESTMENT FUND ALLOCATIONS. By giving NOTICE to the PLAN
ADMINISTRATOR, a participant may (1) change the percentage levels of
future contributions which are to be allocated to any INVESTMENT FUND
or FUNDS or, (2) change the INVESTMENT FUNDS in which his future
contributions are to be invested. Each election regarding investment
of future contributions shall be effective with the next deposit of
contributions.
THE INVESTMENT FUNDS
--------------------
8. PG&E Corporation Common Stock Fund
----------------------------------
This FUND is invested primarily in common stock of PG&E Corporation/2/,
with a small portion invested in cash or cash equivalents. The FUND also
holds COMMON STOCK and the earnings thereon attributable to EMPLOYER
CONTRIBUTIONS and participant contributions made to the Basic Fund of the
PLAN as it existed prior to April 1, 1983, as well as all COMMON STOCK
which has been transferred to this PLAN from the TRASOP and PAYSOP Plan.
All cash dividends received by the TRUSTEE on COMMON STOCK are reinvested
in the FUND.
(a) Investment Generally. Whenever the TRUSTEE invests cash in COMMON
STOCK, the EMPLOYEE BENEFIT FINANCE COMMITTEE shall direct the
- ------------------
/2/ Prior to January 1, 1997, this FUND was invested primarily in the common
stock of the Pacific Gas and Electric Company. Effective January 1, 1997,
all PG&E common stock was converted to common stock of PG&E Corporation by
operation of the formation of PG&E Corporation.
-10-
<PAGE>
TRUSTEE to purchase the COMMON STOCK either (i) at a public sale on
a recognized stock exchange, (ii) directly from PG&E Corporation at
a price equal to that day's closing price for COMMON STOCK on the
New York Stock Exchange, or (iii) from a private source at a price
no higher than the price that would have been payable under (i).
(b) Voting of COMMON STOCK. Each and every time common shareholders of
PG&E Corporation who are not participants in the PLAN are entitled
to vote COMMON STOCK, participants shall have an absolute right to
vote COMMON STOCK. Whenever participants are given the opportunity
to vote COMMON STOCK, the TRUSTEE shall inform each participant of
all relevant material received by the TRUSTEE with a written request
for confidential voting instructions. The TRUSTEE is required to
vote the COMMON STOCK credited to a participant's account as the
participant directs. If the participant does not give such
instructions within the required time, the TRUSTEE may not vote any
---
COMMON STOCK credited to a participant's account.
(c) Cost of UNITS. The cost of a UNIT shall be the current value of a
UNIT as determined by the TRUSTEE as of the valuation date
immediately preceding the date that the TRUSTEE invests
contributions in the COMMON STOCK FUND.
(d) Value of UNITS. The value of a UNIT is the value of the COMMON STOCK
held in the FUND at the closing price on the New York Stock Exchange
plus the cash held in the FUND, as determined by the TRUSTEE each
BUSINESS DAY, less any fees or other expenses which are charged to
the FUND which shall reduce the earnings of that fund, divided by
the number of UNITS. Each payment into the COMMON STOCK FUND of
contributions shall increase, and each payment out of the COMMON
STOCK FUND shall decrease, the number of UNITS by a number equal to
the amount of the payment divided by the last UNIT value
determination immediately preceding the date of payment.
9. United States Bond Fund
-----------------------
This FUND was maintained for the purpose of investing EMPLOYEE
contributions in United States BONDS. This FUND also holds all BONDS
attributable to participant contributions made to the Basic Fund of the
PLAN as it existed prior to April 1, 1983. Income from BONDS is reflected
in the greater redemption values of the BONDS. BONDS held in this FUND
cannot be transferred to another INVESTMENT FUND under the transfer
provisions of Section 18.
Effective July 1, 1991, the U.S. BOND FUND no longer accepts EMPLOYEE
contributions. BONDS purchased to date with EMPLOYEE contributions will
continue to be held in the PLAN until a distribution is requested by the
EMPLOYEE in accordance with current PLAN provisions.
10. Large Company Stock Index Fund (LCSF)
------------------------------
This FUND is maintained for the purpose of investing in a diversified
portfolio consisting principally of common stock of large US companies and
securities convertible into
-11-
<PAGE>
common stock. However, at no time shall the LCSF be invested in
securities issued or guaranteed by the COMPANY or any of its
subsidiaries, except to the extent that any such securities are held in a
commingled account invested in by the LCSF INVESTMENT MANAGER.
The LCSF INVESTMENT MANAGER directs the day-to-day investment of the FUND.
Contributions to this FUND are paid over to the TRUSTEE and invested in
accordance with instructions received from the LCSF INVESTMENT MANAGER. A
participant's account is credited with the number of LCSF UNITS purchased
with contributions allocated to his account.
(a) Cost of LCSF UNITS. The cost of a LCSF UNIT shall be the current
value of a UNIT as determined by the TRUSTEE as of the valuation
date immediately preceding the date that the TRUSTEE invests
contributions in the LCSF.
(b) Value of LCSF UNITS. The value of a LCSF UNIT is the value of the
FUND assets, as determined each BUSINESS DAY by the TRUSTEE, less
any liabilities (other than the interests of participants in the
FUND), divided by the number of LCSF UNITS. Each payment into the
FUND of contributions shall increase, and each payment out of the
FUND shall decrease, the number of FUND UNITS by a number equal to
the amount of the payment divided by the last UNIT value
determination immediately preceding the date of the payment.
11. Small Company Stock Index Fund (SCSF)
-------------------------------------
This FUND is maintained for the purpose of investing in a diversified
portfolio consisting principally of common stock of small capitalization US
companies and securities convertible into common stock. However, at no
time shall the SCSF be invested in securities issued or guaranteed by the
COMPANY or any of its subsidiaries, except to the extent that any such
securities are held in a commingled account invested in by the SCSF
INVESTMENT MANAGER.
The SCSF INVESTMENT MANAGER directs the day-to-day investment of the FUND.
Contributions to this FUND are paid over to the TRUSTEE and invested in
accordance with instructions received from the SCSF INVESTMENT MANAGER. A
participant's account is credited with the number of SCSF UNITS purchased
with contributions allocated to his account.
(a) Cost of SCSF UNITS. The cost of a SCSF UNIT shall be the current
value of a UNIT as determined by the TRUSTEE as of the valuation
date immediately preceding the date that the TRUSTEE invests
contributions in the SCSF.
(b) Value of SCSF UNITS. The value of a SCSF UNIT is the value of the
FUND assets, as determined each BUSINESS DAY by the TRUSTEE, less
any liabilities (other than the interests of participants in the
FUND), divided by the number of SCSF UNITS. Each payment into the
FUND of contributions shall increase, and each payment out of the
FUND shall decrease, the number of FUND UNITS by a number equal to
the amount of the payment divided by the last UNIT value
determination immediately preceding the date of the payment.
-12-
<PAGE>
12. International Stock Index Fund (ISF)
------------------------------------
This FUND is maintained for the purpose of investing in a diversified
portfolio consisting principally of non-US common stock and securities
convertible into common stock. However, at no time shall the ISF be
invested in securities issued or guaranteed by the COMPANY or any of its
subsidiaries, except to the extent that any such securities are held in a
commingled account invested in by the ISF INVESTMENT MANAGER.
The ISF INVESTMENT MANAGER directs the day-to-day investment of the FUND.
Contributions to this FUND are paid over to the TRUSTEE and invested in
accordance with instructions received from the ISF INVESTMENT MANAGER. A
participant's account is credited with the number of ISF UNITS purchased
with contributions allocated to his account.
(a) Cost of ISF UNITS. The cost of a ISF UNIT shall be the current
value of a UNIT as determined by the TRUSTEE as of the valuation
date immediately preceding the date that the TRUSTEE invests
contributions in the ISF.
(b) Value of ISF UNITS. The value of a ISF UNIT is the value of the
FUND assets, as determined each BUSINESS DAY by the TRUSTEE, less
any liabilities (other than the interests of participants in the
FUND), divided by the number of ISF UNITS. Each payment into the
FUND of contributions shall increase, and each payment out the FUND
shall decrease, the number of FUND UNITS by a number equal to the
amount of the payment divided by the last UNIT value determination
immediately preceding the date of the payment.
13. Stable Value Fund (SVF)
-----------------------
This FUND is designed to provide participants with preservation of
principal while earning a stable and consistent rate of return. The FUND
is made up of investment contracts with a diversified group of insurance
companies, banks, and other financial institutions which provide for
credited interest rates and terms that are negotiated at the time of
purchase.
Contributions made to the SVF are invested in a portfolio of investment
contracts. The SVF INVESTMENT MANAGER directs the day-to-day investment of
the FUND. The blended interest earned on all contracts held in the
portfolio is posted daily to the participant's account.
(a) COST OF SVF UNITS. The cost of a SVF UNIT shall be the current
value of a UNIT as determined by the TRUSTEE as of the valuation
date immediately preceding the date that the TRUSTEE invests
contributions in the SVF.
(b) VALUE OF SVF UNITS. The value of a SVF UNIT is the value of the SVF
assets, as determined each BUSINESS DAY by the TRUSTEE, less any
liabilities (other than the interests of participants in the SVF),
divided by the number of SVF UNITS. Each payment into the SVF of
contributions shall increase, and payments out of the SVF shall
decrease, the number of SVF UNITS by a number equal to the amount of
the payment divided by the last UNIT value determination immediately
preceding the date of payment.
-13-
<PAGE>
14. Bond Index Fund (BIF)
---------------
The BIF is maintained for the purpose of investing in a diversified
portfolio consisting principally of marketable fixed-income securities. At
no time shall the BIF be invested in securities issued or guaranteed by the
COMPANY or any of its subsidiaries, except to the extent that any such
securities are held in a commingled account invested in by the BIF
INVESTMENT MANAGER. The BIF INVESTMENT MANAGER directs the day-to-day
investment of the BIF.
Contributions to the BIF are paid over to the TRUSTEE and invested in
accordance with instructions received from the BIF INVESTMENT MANAGER. A
participant's account is credited with the number of BIF UNITS purchased
with contributions allocated to his account.
(a) Cost of BIF UNITS. The cost of a BIF UNIT shall be the current value
of a UNIT as determined by the TRUSTEE as of the valuation date
immediately preceding the date that the TRUSTEE invests
contributions in the FUND.
(b) Value of BIF UNITS. The value of a BIF UNIT is the value of the BIF
assets, as determined each BUSINESS DAY by the TRUSTEE, less any
liabilities (other than the interests of participants in the BIF),
divided by the number of BIF UNITS. Each payment into the BIF of
contributions shall increase, and each payment out of the BIF shall
decrease, the number of BIF UNITS by a number equal to the amount of
the payment divided by the last UNIT value determination immediately
preceding the date of payment.
15. Conservative Asset Allocation Fund (CAAF)
-----------------------------------------
The FUND is maintained for the purpose of investing in a diversified
portfolio with a primary emphasis on bonds and a secondary emphasis on
stocks. This Fund has an allocation to each of the following Funds: the
Small Company Stock Index Fund (SCSF), the Large Company Stock Index Fund
(LCSF), the International Stock Index Fund (ISF), and the Bond Index Fund
(BIF). At no time shall the CAAF be invested in securities issued or
guaranteed by the COMPANY or any of its subsidiaries, except to the extent
that any such securities are held in a commingled account invested in by
the CAAF INVESTMENT MANAGER.
The CAAF INVESTMENT MANAGER directs the day-to-day investment of the FUND.
Contributions to this FUND are paid over to the TRUSTEE and invested in
accordance with instructions from the CAAF INVESTMENT MANAGER. A
participant's account is credited with the number of CAAF UNITS purchased
with contributions allocated to his account.
(a) Cost of CAAF UNITS. The cost of an CAAF UNIT shall be the current
value of a UNIT as determined by the TRUSTEE as of the valuation
date immediately preceding the date that the TRUSTEE invests
contributions in the CAAF.
(b) Value of CAAF UNITS. The value of a CAAF UNIT is the value of the
FUND assets, as determined each BUSINESS DAY by the TRUSTEE, less
any liabilities (other than the interests of participants in the
FUND), divided by the number of
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<PAGE>
CAAF UNITS. Each payment into the FUND of contributions shall
increase, and each payment out of the FUND shall decrease, the
number of FUND UNITS by a number equal to the amount of the payment
divided by the last UNIT value determination immediately preceding
the date of payment.
16. Moderate Asset Allocation Fund (MAAF)
-------------------------------------
The FUND is maintained for the purpose of investing in a diversified
portfolio with an emphasis on stocks and bonds. This Fund has an
allocation to each of the following Funds: the Small Company Stock Index
Fund (SCSF), the Large Company Stock Index Fund (LCSF), the International
Stock Index Fund (ISF), and the Bond Index Fund (BIF). However, at no time
shall the MAAF be invested in securities issued or guaranteed by the
COMPANY or any of its subsidiaries, except to the extent that any such
securities are held in a commingled account invested in by the MAAF
INVESTMENT MANAGER.
The MAAF INVESTMENT MANAGER directs the day-to-day investment of the FUND.
Contributions to this FUND are paid over to the TRUSTEE and invested in
accordance with instructions from the MAAF INVESTMENT MANAGER. A
participant's account is credited with the number of MAAF UNITS purchased
with contributions allocated to his account.
(a) Cost of MAAF UNITS. The cost of an MAAF UNIT shall be the current
value of a UNIT as determined by the TRUSTEE as of the valuation
date immediately preceding the date that the TRUSTEE invests
contributions in the MAAF.
(b) Value of MAAF UNITS. The value of a MAAF UNIT is the value of the
FUND assets, as determined each BUSINESS DAY by the TRUSTEE, less
any liabilities (other than the interests of participants in the
FUND), divided by the number of MAAF UNITS. Each payment into the
FUND of contributions shall increase, and each payment out of the
FUND shall decrease, the number of FUND UNITS by a number equal to
the amount of the payment divided by the last UNIT value
determination immediately preceding the date of payment.
17. Aggressive Asset Allocation Fund (AAAF)
---------------------------------------
The FUND is maintained for the purpose of investing in a diversified
portfolio with a primary emphasis on stocks and a secondary emphasis on
bonds. This Fund has an allocation to each of the following Funds: the
Small Company Stock Index Fund (SCSF), the Large Company Stock Index Fund
(LCSF), the International Stock Index Fund (ISF), and the Bond Index Fund
(BIF). However, at no time shall the AAAF be invested in securities issued
or guaranteed by the COMPANY or any of its subsidiaries, except to the
extent that any such securities are held in a commingled account invested
in by the AAAF INVESTMENT MANAGER.
The AAAF INVESTMENT MANAGER directs the day-to-day investment of the FUND.
Contributions to this FUND are paid over to the TRUSTEE and invested in
accordance with instructions from the AAAF INVESTMENT MANAGER. A
participant's account is credited with the number of AAAF UNITS purchased
with contributions allocated to his account.
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<PAGE>
(a) Cost of AAAF UNITS. The cost of an AAAF UNIT shall be the current
value of a UNIT as determined by the TRUSTEE as of the valuation
date immediately preceding the date that the TRUSTEE invests
contributions in the AAAF.
(b) Value of AAAF UNITS. The value of a AAAF UNIT is the value of the
FUND assets, as determined each BUSINESS DAY by the TRUSTEE, less
any liabilities (other than the interests of participants in the
FUND), divided by the number of AAAF UNITS. Each payment into the
FUND of contributions shall increase, and each payment out of the
FUND shall decrease, the number of FUND UNITS by a number equal to
the amount of the payment divided by the last UNIT value
determination immediately preceding the date of payment.
18. Transfer of Investment Fund Balances
------------------------------------
(a) By giving NOTICE to the PLAN ADMINISTRATOR, a participant may elect
to transfer any portion of the contributions held in his account,
plus the earnings thereon, from any INVESTMENT FUND to another
INVESTMENT FUND or FUNDS. A transfer shall be effective and shall be
valued on the day it is made, if such day is a BUSINESS DAY, and the
participant provides NOTICE of such transfer prior to the closing
time of the New York Stock Exchange. All other transfers shall be
effective and valued as of the next BUSINESS DAY.
Upon receipt of a transfer NOTICE, the TRUSTEE shall value the UNITS
to be transferred from the FUND and convert the UNITS to cash. The
FUND account of the participant shall be debited with the number of
UNITS transferred from that FUND and the TRUSTEE shall purchase with
the cash proceeds realized from the converted UNITS, UNITS in the
appropriate FUND or FUNDS, as designated by the participant. The cost
of the UNITS purchased shall be the value of the FUND UNITS as
determined on the date of transfer, and the number of UNITS purchased
shall be credited to the appropriate INVESTMENT FUND account of the
participant.
(b) COMMON STOCK FUND -- Overall Limitation. Anything herein to the
contrary notwithstanding, if, as of any single month, the TRUSTEE is
required, as a result of the transfer provisions of this Section 18,
to sell on the open market more than one percent of the number of
outstanding shares of COMMON STOCK, then the TRUSTEE shall
immediately so advise the EMPLOYEE BENEFIT FINANCE COMMITTEE. The
EMPLOYEE BENEFIT FINANCE COMMITTEE may, in its sole discretion,
limit, prorate, or temporarily suspend further sales of COMMON STOCK
by the PLAN or take whatever steps necessary to ensure an orderly
market in COMMON STOCK. The percentage limitation set forth in this
subsection shall be applied to the excess of shares sold on the open
market less shares purchased to meet Section 18 requirements for the
applicable period.
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<PAGE>
PARTICIPANT'S INTEREST IN THE PLAN
----------------------------------
19. Participant Accounts
--------------------
The PLAN ADMINISTRATOR maintains a separate account for each PLAN
participant which records the participant's interest in each of the
INVESTMENT FUNDS, together with EMPLOYER CONTRIBUTIONS made on his behalf.
Each account is charged with participant transfers and withdrawals and
credited with its appropriate share of FUND income. The account maintained
by the PLAN ADMINISTRATOR for each participant also records separately the
participant's SECTION 401(k) CONTRIBUTIONS and NON-SECTION 401(k)
CONTRIBUTIONS, the UNITS purchased therewith, and the earnings thereon.
All Basic Contributions and Supplemental Contributions made to the PLAN
as it existed prior to October 1, 1984, are recorded as NON-SECTION
401(k) CONTRIBUTIONS on the records maintained by the PLAN ADMINISTRATOR.
Whenever UNITS attributable to a participant's SECTION 401(k)
CONTRIBUTIONS are transferred to another FUND OR FUNDS, the resulting
UNITS are also recorded as attributable to SECTION 401(k) CONTRIBUTIONS.
Similarly, UNITS attributable to NON-SECTION 401(k) CONTRIBUTIONS which
are transferred to another FUND or FUNDS are also recorded as NON-SECTION
401(k) CONTRIBUTIONS. A participant is at all times fully vested in his
own contributions and all EMPLOYER CONTRIBUTIONS credited to his account,
together with income attributable thereto.
20. Account Statements
------------------
As soon as practicable after the end of each CALENDAR QUARTER, all
participants will receive from the ADMINISTRATOR a statement of their
interest in the PLAN.
PLAN WITHDRAWALS
----------------
21. Withdrawal During Service
-------------------------
Except as provided in this Section, withdrawals of any part of a
participant's interest in the PLAN are not permitted as long as SERVICE
continues. A participant may never replace in the TRUST FUND any UNITS or
cash which have been withdrawn. By submitting a withdrawal Form, a
participant may make withdrawals as provided below.
(a) SECTION 401(k) CONTRIBUTIONS.
(1) A participant may withdraw all or part of the UNITS, including
income thereon and including additional UNITS attributable
thereto, bought with the participant's SECTION 401(k)
CONTRIBUTIONS upon the occurrence of any of the following
events:
a) the participant is disabled and is receiving benefits under
the LONG TERM DISABILITY PLAN; or
b) the participant has attained age 59 1/2.
-17-
<PAGE>
(2) A participant may withdraw an amount equal to his SECTION
401(k) CONTRIBUTIONS, as we ll as any income and UNITS
attributable to income accrued thereon prior to January 1,
1989, upon receipt of satisfactory proof by the PLAN
ADMINISTRATOR that the withdrawal is required to meet immediate
and heavy financial needs of the participant which constitute a
valid hardship as defined under the CODE and regulations issued
by the Secretary of the Treasury. A request for a withdrawal
for one of the following reasons will be deemed to be on
account of a valid hardship:
a) To cover medical expenses (as defined in Section 213(d) of
the CODE) of the participant, the participant's spouse or
dependents (as defined in Section 152 of the CODE);
b) The purchase of a participant's principal place of
residence, but not including mortgage payments;
c) To meet tuition payments for the next semester or quarter
of post-secondary education for the participant, his
spouse, children or dependents; or
d) To prevent the eviction of the participant from his
principal place of residence, or to prevent a foreclosure
of the mortgage on the participant's principal place of
residence.
A request for a withdrawal under this subsection 21(a)(2) will
not be deemed to be for immediate and heavy financial needs
unless the participant represents that the need cannot be met
from the following resources:
a) through reimbursement or compensation by insurance or
otherwise,
b) by reasonable liquidation of the participant's resources,
c) by cessation of contributions to the PLAN, or
d) by other distributions, withdrawals or nontaxable loans from
any plans maintained by an EMPLOYER, or by borrowing from
commercial sources on reasonable commercial terms.
For purposes of this Subsection 21(a)(2), a participant's
resources shall be deemed to include any assets of his spouse and
minor children that are reasonably available to the participant.
In addition, withdrawals under Subsection 21(a)(2) may not exceed
the amount actually required to meet the participant's immediate
financial needs.
(3) A participant who withdraws UNITS under Subsection 21(a) will
automatically be suspended from the PLAN and will not be
permitted to resume making contributions to the PLAN for six
months following the date upon which the withdrawal Form is
processed by the PLAN ADMIN-
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<PAGE>
ISTRATOR. After suspension ends, contributions may be resumed
by giving NOTICE to the PLAN ADMINISTRATOR.
(b) NON-SECTION 401(k) CONTRIBUTIONS. A participant may at any time
elect to withdraw all or any part of the UNITS including income
thereon and including additional UNITS attributable thereto, bought
with the participant's NON-SECTION 401(k) CONTRIBUTIONS to the
PLAN. Such an election will not cause suspension from the PLAN.
(c) EMPLOYER CONTRIBUTIONS.
(1) A participant may withdraw all or any part of the UNITS,
including the income attributable thereto, bought with
EMPLOYER CONTRIBUTIONS which were made to the PLAN at anytime
prior to the second YEAR preceding the current YEAR. For
example, UNITS, including the income attributable thereto,
purchased with EMPLOYER CONTRIBUTIONS made in 1981 and prior
years may be withdrawn in 1984 or anytime thereafter. Such an
election will not cause suspension from the PLAN.
(2) UNITS, including the income attributable thereto, bought with
EMPLOYER CONTRIBUTIONS which would not be withdrawable under
Subsection 21(c)(1), shall nonetheless be withdrawable upon
the occurrence of any of the following events:
a) the participant is disabled and is receiving benefits under
the LONG TERM DISABILITY PLAN;
b) the participant attains 59-1/2; or
c) the participant has requested and is entitled to receive a
hardship distribution which meets the requirements of
Subsection 21(a)(2) but only if all amounts distributable
under Subsection 21(a) have been exhausted.
Anything herein to the contrary notwithstanding, if as of any single
month, the TRUSTEE is required as a result of the withdrawal
provisions of this Subsection 21(c), to sell on the open market more
than one percent of the outstanding shares of COMMON STOCK, then the
TRUSTEE shall immediately so advise the EMPLOYEE BENEFIT FINANCE
COMMITTEE. The EMPLOYEE BENEFIT FINANCE COMMITTEE may, in its sole
discretion, limit, prorate, or temporarily suspend further sales of
COMMON STOCK by the PLAN or take whatever steps necessary to ensure an
orderly market in COMMON STOCK.
A participant shall submit the appropriate Form to the SAVINGS FUND
PLAN directing the PLAN ADMINISTRATOR as to the amount of the
withdrawal. Distribution will be made as soon as practicable after
receipt of the withdrawal Form. Upon each withdrawal, the UNITS
credited to the appropriate FUND or FUNDS will be reduced by the
number of UNITS withdrawn. Withdrawals from the BOND FUND can only be
made in United States BONDS. Withdrawals from the COMMON STOCK FUND
may be made in cash or whole shares of stock at the
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<PAGE>
election of the participant. Withdrawals of LCSF, SCSF, ISF, SVF,
BIF, CAAF, MAAF or AAAF UNITS will be made in cash at the then
current value of the UNITS; or, at the election of the participant,
the UNITS will be transferred to the COMMON STOCK FUND pursuant to
Section 18 and distribution will be made in whole shares of COMMON
STOCK.
(d) ROLLOVER CONTRIBUTIONS. A participant may at any time elect to
withdraw all or any part of the UNITS including income thereon
bought with the participant's Rollover Contributions to the PLAN.
Such an election will not cause suspension from the PLAN.
(e) ORDERING OF WITHDRAWALS. Whenever the PLAN ADMINISTRATOR is required
to make a distribution under this Section 21 or Section 22, the PLAN
ADMINISTRATOR shall first withdraw UNITS and earnings thereon
attributable to a participant's NON-SECTION 401(k) CONTRIBUTIONS
made prior to 1987, followed by UNITS and earnings thereon
attributable to NON-SECTION 401(k) CONTRIBUTIONS made after 1986,
followed by Units and earnings thereon attributable to Rollover
Contributions, followed by UNITS withdrawable under Subsection
21(c)(1) followed by UNITS withdrawable under Subsection 21(c)(2),
but only if available for withdrawal under that subsection, followed
by UNITS and earnings thereon attributable to a participant's
SECTION 401(k) CONTRIBUTIONS, but only to the extent that such UNITS
can be withdrawn by the participant under Subsection 21(a).
22. Termination of Participation
----------------------------
Participation in the PLAN ends as of the date that a participant ceases to
be an ELIGIBLE EMPLOYEE. Although a former participant may elect to have
an account balance held in the PLAN under Section 23 after participation
ends, a former participant may not contribute to the PLAN, except that
contributions to the PLAN will be accepted with respect to retroactive wage
payments. A former participant who has an account balance in the PLAN may
make withdrawals from the account balance, and transfer from one or more
FUNDS to another FUND or FUNDS pursuant to the terms of the PLAN.
Upon the death of a participant, the PLAN ADMINISTRATOR shall distribute
the participant's account balance to the participant's BENEFICIARY within a
reasonable time but not later than 60 days after receipt of a completed
withdrawal form or 180 days after the PLAN ADMINISTRATOR receives NOTICE of
the participant's death. If the BENEFICIARY does not complete a withdrawal
form within the time periods set forth above, the distribution shall be in
cash and paid directly to the BENEFICIARY.
23. Distribution of Plan Benefits
-----------------------------
(a) Upon termination of participation, a distribution shall be made of
the balances allocated to a participant's accounts if the value of
the participant's account is $3,500 or less. Such distribution shall
be made no later than the 60th day following the close of the PLAN
YEAR in which participation terminates, unless the participant
elects to receive distribution at an earlier date. If the value of a
participant's account exceeds $3,500, distribution will be made upon
receipt by
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<PAGE>
the PLAN ADMINISTRATOR of the written distribution request of the
participant. Distribution will therefore be made within 60 days of
the receipt of such distribution request. Any provision of the PLAN
notwithstanding, if participation continues beyond the end of the
YEAR in which the participant attains age 70-1/2, distribution of
the participant's entire interest in the PLAN shall be made no later
than April 1 of the YEAR following the YEAR in which the participant
attains age 70-1/2.
All distributions due under the PLAN shall be payable only out of the
PLAN's assets as directed by the ADMINISTRATOR. Unless a cash
distribution is requested the TRUSTEE will distribute a certificate
for the whole shares of COMMON STOCK, the United States BONDS, and the
TRUSTEE'S check for the then current value of all other UNITS credited
to the participant's account, plus any uninvested cash.
Alternatively, at the direction of the participant, FUND UNITS other
than U.S. SAVINGS BONDS UNITS may be transferred to the COMMON STOCK
FUND pursuant to Section 18 and distribution will be made in whole
shares of COMMON STOCK.
If a participant elects a cash distribution, upon receipt of the
appropriate Form requesting such distribution, the TRUSTEE will
distribute the then current value of the INVESTMENT FUND UNITS and
uninvested cash. Until the TRUSTEE converts INVESTMENT FUND UNITS to
cash, all UNITS shall continue to share in investment gains and
losses. Distributions from the BOND FUND can only be made in United
States BONDS.
(b) Any provision of the PLAN notwithstanding:
Unless the participant otherwise elects, distribution to such
participant shall be made (or shall commence) not later than the 60th
day after the close of the PLAN YEAR in which occurs the latest of the
following events:
(1) The participant attains age 65;
(2) The participant attains the 10th anniversary of the date on
which he or she became a participant under the PLAN; or
(3) The participant's termination of employment with the EMPLOYER.
(c) Distributions hereunder will be made in accordance with Section
401(a)(9) of the CODE and the regulations thereunder, including
Treasury regulation Section 1.401(a)(9)-2, which are incorporated by
reference herein.
24. Direct Rollovers
----------------
Notwithstanding any provision of the PLAN to the contrary that would
otherwise limit a participant's election under this section, effective
January 1, 1993, a participant or BENEFICIARY who is a surviving spouse may
elect, at the time and in the manner prescribed by the PLAN ADMINISTRATOR,
to have any portion of an eligible rollover distribution, as defined below,
paid directly to an eligible retirement plan, as defined below, specified
by the participant or BENEFICIARY who is a surviving spouse in a direct
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rollover. Any taxable portion of an eligible rollover distribution that is
not transferred directly to an eligible retirement plan will be subject to
mandatory federal income tax withholding.
(a) An eligible rollover distribution shall mean any distribution of all
or any portion of the balance to the credit of the participant,
except that an eligible rollover distribution does not include any
distribution that is one of a series of substantially equal periodic
payments (not less frequently than annually) made for the life (or
life expectancy) of the participant or the joint lives (joint life
expectancies) of the participant and his or her designated
BENEFICIARY, or for a specified period of 10 years or more; any
distribution to the extent such distribution is required under
Section 401(a)(9) of the CODE; and the portion of any distribution
that is not includable in gross income (determined without regard to
the exclusion for net unrealized appreciation with respect to
employer securities).
(b) An eligible retirement plan shall mean an individual retirement
account described in Section 408(a) of the CODE, an individual
retirement annuity described in Section 408(b) of the CODE, an
annuity plan described in Section 403(a) of the CODE, or a qualified
trust described in Section 401(a) of the CODE, that accepts the
participant's eligible rollover distribution. However, in the case
of an eligible rollover distribution to the surviving spouse, an
eligible retirement plan is an individual retirement account or
individual retirement annuity.
ADMINISTRATIVE PROVISIONS
-------------------------
25. Company's Powers and Duties
---------------------------
The COMPANY, acting through its BOARD OF DIRECTORS or Executive Committee,
reserves to itself the exclusive power to amend, suspend or terminate the
PLAN as provided below and to appoint and remove from time to time:
(a) The individuals comprising the EMPLOYEE BENEFIT FINANCE COMMITTEE;
(b) The individuals comprising the EMPLOYEE BENEFIT ADMINISTRATIVE
COMMITTEE; and
(c) The EMPLOYERS whose EMPLOYEES may participate in the PLAN.
All powers and duties not reserved to the COMPANY are delegated to the
EMPLOYEE BENEFIT FINANCE COMMITTEE and to the EMPLOYEE BENEFIT
ADMINISTRATIVE COMMITTEE. Action of either committee shall be by vote of a
majority of the members of the committee at a meeting, or in writing
without a meeting and evidenced by the signature of any member who is so
authorized by the committee. The COMPANY indemnifies each member of each
committee against any personal liability or expense arising out of any
action or inaction of the committee or of any member of the committee or of
such individual, except that due to his own willful misconduct.
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26. Funding and Investment Provisions
---------------------------------
The EMPLOYEE BENEFIT FINANCE COMMITTEE appointed by the COMPANY'S BOARD OF
DIRECTORS to serve at its pleasure has the express powers and duties
described in this section.
(a) Appointments. The EMPLOYEE BENEFIT FINANCE COMMITTEE has the sole
power and duty from time to time to appoint and remove the TRUSTEE,
the INVESTMENT MANAGER, actuaries, accountants and such other
advisors and consultants as may be needed for the proper financial
administration and investment of the assets of the PLAN.
Supplementing such appointments, the EMPLOYEE BENEFIT FINANCE
COMMITTEE may enter into appropriate agreements with each TRUSTEE,
INVESTMENT MANAGER or other advisors appointed under this paragraph
and delegate to them appropriate powers and duties. The EMPLOYEE
BENEFIT FINANCE COMMITTEE may appoint and delegate to one or more
individuals the power and duty to handle the day-to-day financial
administration of the PLAN. Such individuals need not be members of
the committee and shall serve at the pleasure of the committee.
(b) Investment Policy. The funding policy is set forth in Sections 3 and
4. The EMPLOYEE BENEFIT FINANCE COMMITTEE has the sole power and
duty to establish the investment policy and to review and revise it
from time to time as the committee shall determine in its sole
discretion. A copy of the current investment policy will be
available for participants' review in the ADMINISTRATOR'S office.
Any revision of the investment policy shall not be an amendment of
the PLAN.
27. Administration
--------------
The EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE, appointed by the COMPANY'S
BOARD OF DIRECTORS to serve at its pleasure, is the ADMINISTRATOR of the
PLAN and is responsible for the overall administration of the PLAN. The
ADMINISTRATOR has the sole power and duty to establish, and from time to
time revise, such rules and regulations as may be necessary to administer
the PLAN in a nondiscriminatory manner for the exclusive benefit of
participants and all other persons entitled to benefits under the PLAN.
The ADMINISTRATOR shall also maintain such records and make such
computations, interpretations and decisions as may be necessary or
desirable for the proper administration of the PLAN. The ADMINISTRATOR
shall maintain for participants' inspection copies of the PLAN, TRUST
AGREEMENT, investment policy, each agreement with an INVESTMENT MANAGER,
the latest annual report, PLAN description and summary description and any
amendments or changes in any of these documents. On written request,
participants may obtain from the ADMINISTRATOR a copy of any of these
documents at a cost established by the ADMINISTRATOR from time to time.
The ADMINISTRATOR may appoint and delegate to one or more individuals the
power and duty to handle the day-to-day administration of the PLAN. Such
individuals need not be members of the committee and shall serve at the
pleasure of the committee.
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<PAGE>
The EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE shall serve as the final
review committee under the PLAN, to determine conclusively for all parties
any and all questions arising from the administration of the PLAN and shall
have sole and complete discretionary authority and control to manage the
operation and administration of the PLAN, including, but not limited to,
the determination of all questions relating to eligibility for
participation and benefits, interpretation of all PLAN provisions,
determination of the amount and kind of benefits payable to any participant
or BENEFICIARY, and construction of disputed or doubtful terms. Such
decisions shall be conclusive and binding on all parties and not subject to
further review.
28. Claims and Appeals Procedure
----------------------------
If a claim is denied in whole or in part, the ADMINISTRATOR shall furnish
to the claimant a written notice setting forth:
(a) Specific reason(s) for the denial,
(b) The PLAN provision(s) on which the denial is based,
(c) A description of any material or information, if any, necessary for
the claimant to perfect the claim, and an explanation of why such
material or information is necessary, and
(d) Information concerning the steps to be taken if claimant wishes to
submit a claim for review.
The above information shall be furnished to the claimant within 90 days
after the claim is received by the ADMINISTRATOR.
If a claimant is not satisfied with the written NOTICE described in the
preceding paragraph, such claimant may request a full and fair review by so
notifying the ADMINISTRATOR in writing within 90 days after receiving such
notice. If a review is requested the claimant shall also be entitled, upon
written request, to review pertinent documents and to submit issues and
comments in writing. The EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE shall
furnish the claimant with a written final decision within 60 days after
receipt of the request for review.
29. Qualified Domestic Relations Orders
-----------------------------------
The EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE shall apply the provisions of
this section with regard to a Domestic Relations Order (as defined below)
to the extent not inconsistent with Section 414(p) of the CODE.
The EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE shall establish procedures,
consistent with Section 414(p) of the CODE, to determine the qualified
status of any Domestic Relations Order, to administer distributions under
any Qualified Domestic Relations Order (as defined below), and to provide
to the Participant and the Alternate Payee(s) (as defined below) all
notices required under Section 414(p) of the CODE with respect to any
Domestic Relations Order.
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<PAGE>
Within a reasonable period of time after the receipt of a Domestic
Relations Order (or any modification thereof), the EMPLOYEE BENEFIT
ADMINISTRATIVE COMMITTEE shall determine whether such order is a Qualified
Domestic Relations Order.
For purposes of this section:
(a) Alternate Payee shall mean any spouse, former spouse, child, or
other dependent of a participant who is recognized by a Domestic
Relations Order as having a right to receive all, or a portion of,
the benefits payable under the PLAN with respect to such
Participant.
(b) Domestic Relations Order shall mean any judgment, decree, or order
(including approval of a property settlement agreement) which:
(1) relates to the provision of child support, alimony payments, or
marital property rights to a spouse, former spouse, child, or
other dependent of a participant; and
(2) is made pursuant to a state domestic relations law (including a
community property law).
(c) Qualified Domestic Relations Order shall mean a Domestic Relations
Order which meets the requirements of Section 414(p)(1) of the CODE.
30. Lost Participant or Beneficiary
-------------------------------
If, after three years, the ADMINISTRATOR cannot locate a participant or
BENEFICIARY who is entitled to a distribution from an account, the UNITS,
cash or COMMON STOCK in the account shall be applied to reduce the amount
of future EMPLOYER CONTRIBUTIONS payable to the PLAN. A participant or
BENEFICIARY who is entitled to a distribution from an account which has
previously been applied to reduce EMPLOYER CONTRIBUTIONS under this Section
30 shall, upon filing a written claim, have the account reinstated in full
and upon such reinstatement shall receive a distribution of the balance in
the reinstated account, with interest at the prevailing legal rate accrued
from the date his account was applied to reduce EMPLOYER CONTRIBUTIONS.
31. Benefits Are Not Assignable
---------------------------
Except as may be required by law, a participant's interest in the PLAN and
that of a participant's BENEFICIARY or spouse shall not be subject in any
manner to assignment, anticipation, alienation, sale, transfer, pledge,
encumbrance or charge, whether voluntary or involuntary, and any attempt to
so assign, anticipate, sell, transfer, pledge, encumber or charge the same
shall be void.
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<PAGE>
32. Facility of Payment
-------------------
If the ADMINISTRATOR determines that any individual entitled to any payment
under the PLAN is physically or mentally incompetent and no guardian or
conservator has been appointed to receive such payment, the ADMINISTRATOR
may cause all payments thereafter becoming due to such individual to be
applied for and on behalf of and for the benefit of such individual.
Payments made pursuant to this provision shall completely discharge the
EMPLOYER, the ADMINISTRATOR, the TRUSTEE and all fiduciaries of all further
responsibility with respect to such individual.
33. Future of the Plan
------------------
If participation in the PLAN is ended because a substantial portion of an
EMPLOYER'S property is sold or otherwise disposed of or because an EMPLOYER
withdraws from the PLAN, a participant's interest is determined in
accordance with the provisions of the next paragraphs as if the PLAN itself
has been terminated.
The COMPANY hopes and expects to continue this PLAN indefinitely, but
because future conditions cannot be foreseen, its BOARD OF DIRECTORS
necessarily reserves the right to amend or terminate the PLAN at any time.
However, no amendment, merger or consolidation of the PLAN may be made
which would reduce the right that any individual may then have with respect
to the PLAN's assets then being held under the PLAN or permit any funds to
revert to an EMPLOYER or to be used for any purpose except for the
exclusive benefit of participants, spouses and BENEFICIARIES.
If the PLAN is terminated, all contributions to the PLAN shall cease but
the PLAN shall continue to operate in all other respects until all of the
TRUST assets have been distributed in accordance with the provisions of the
PLAN in effect on the date of its termination. In the event of a merger or
consolidation with, or transfer of assets or liabilities to any other plan,
if such other plan is then terminated, participant shall receive a benefit
immediately after such merger, consolidation, or transfer which is equal to
or greater than the benefit which participant would have received had the
PLAN terminated immediately prior to such merger, consolidation, or
transfer.
34. Definitions
-----------
AAAF: The Aggressive Asset Allocation
----- Fund.
Aggressive Asset Allocation Fund: A fund invested in a diversified
--------------------------------- portfolio with a primary emphasis
on stocks and a secondary emphasis
on bonds. (See Section 17)
Administrator: Employee Benefit Administrative
-------------- Committee, Market Street, 3d
Floor, Mail Code N3X, P.O. Box
770000, San Francisco, California
94177
BIF: The Bond Index Fund.
----
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<PAGE>
Beneficiary: The person or persons entitled to
------------ receive any distribution due under
the Plan in the event of a
participant's death. For a married
participant, the participant's
spouse shall automatically be the
Beneficiary unless the
participant, with the written
consent of his spouse, elects to
designate another person or
persons to be Beneficiary. The
consent of the spouse shall be in
writing, shall acknowledge the
effect of the consent, and shall
be witnessed by a notary public or
Plan representative. A participant
designates a Beneficiary on a
Designation of Beneficiary Form
available from the Plan
Administrator. In the event an
unmarried participant does not
designate a Beneficiary, the
participant's estate shall be
deemed to be the Beneficiary.
Board of Directors: The Board of Directors of Pacific
------------------- Gas and Electric Company.
Bond Fund: A fund invested in United States
---------- Savings Bonds. (See Section 9)
Bond Index Fund: A fund invested in marketable
---------------- fixed-income securities. (See
Section 14)
Bonds: Series "EE" Savings Bonds issued
------ by the United States Treasury. If
the issuance of Series "EE" Bonds
is discontinued, Bonds will refer
to any other Bond issued by the
United States Treasury which the
Employee Benefit Finance Committee
selects for purchase under the
Plan.
Business Day: Any day that the New York Stock
------------- Exchange is open for business.
CAAF: The Conservative Asset Allocation
----- Fund.
Calendar Quarter: The three month period commencing
----------------- on January 1, April 1, July 1 or
October 1.
Code: The Internal Revenue Code of 1986,
----- as amended from time to time.
Company: Pacific Gas and Electric Company.
--------
Common Stock: The common stock issued by PG&E
------------- Corporation.
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<PAGE>
Common Stock Fund: A fund invested in the common stock
------------------ issued by PG&E Corporation.
(See Section 8)
Conservative Asset Allocation Fund: A fund invested in a diversified
----------------------------------- portfolio with a primary emphasis
on bonds and a secondary emphasis
on stocks. (See Section 15)
Covered Compensation: Earnings from an Employer, including
--------------------- straight-time pay for hours
worked, shift and nuclear premiums
at the straight-time rate,
straight-time pay for temporary
upgrades, vacation pay (including
vacation pay upon retirement),
inclement weather pay, sick leave
pay, holiday pay, differential pay
for military training, pay for
other time off with permission
carrying full pay, temporary
compensation under any state
Worker's Compensation Law,
payments under the Long Term
Disability Plan, or supplemental
benefits for industrial injury.
Covered Compensation shall not
include pay or shift and nuclear
premiums for more than 40 hours
per week, overtime bonuses,
vacation or holiday pay requests
other special fees or allowances,
per diem allowances, payments,
other than temporary compensation,
made under any Workers'
Compensation Law, voluntary wage
benefit or state disability plans,
or any other benefit plan. For
Plan Years beginning after 1988
and before 1994, the maximum
Covered Compensation of each
Employee that may be taken into
account each Plan Year shall not
exceed $200,000 (as adjusted by
the Secretary of the Treasury
under Section 401(a)(17) of the
Code. For Plan Years beginning
after 1993, the maximum Covered
Compensation of each Employee that
may be taken into account each
Plan Year shall not exceed
$150,000 (as adjusted by the
Secretary of the Treasury under
Section 401(a)(17) of the Code).
In determining the Covered
Compensation of a Highly
Compensated Employee for purposes
of this limitation, the rules of
Section 414(q)(6) of the Code
shall apply, except that the term
"family" shall include only the
spouse of the Employee and any
lineal descendants of the Employee
who have not attained age 19
before the close of the Year. If
the aggregate Covered Compensation
of family members exceeds the
applicable compensation limit as
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<PAGE>
limited by Section 401(a)(17) of
the Code, then the amount of
Covered Compensation considered
under the Plan for each family
member is proportionately reduced
so that the total equals the
applicable compensation limitation
under Section 401(a)(17) of the
Code.
Eligible Employee: One entitled to become a
------------------ contributing participant,
provided, however, a "leased
employee," as defined in Section
414(n)(2) of the Code shall not be
entitled to become an Eligible
Employee
Employee: An Employee of an Employer who is
--------- not represented by a union.
Employee Benefit Administrative
Committee: The Employee Benefit
------------------------------- Administrative Committee referred
to in Section 27.
Employee Benefit Finance Committee: The Employee Benefit Finance
----------------------------------- Committee referred to in Section 26.
Employer: Pacific Gas and Electric Company,
--------- Pacific Service Employees
Association, and any other
company, association, or credit
union designated by the Board of
Directors as eligible to
participate in this Plan as an
Employer.
Employer Contributions: Any contributions to the Plan by
----------------------- Company.
FlexDollars: Amounts which a participant elects
------------ pursuant to the Company's Flex
Plan to contribute as Section
401(k) Contributions. Rules
governing FlexDollars are
contained in the Company's Flex
Plan; rules governing the
treatment of FlexDollars under
this Plan are contained in
Subsection 3(b).
Fund: The Company Stock Fund, The Bond
----- Fund, the Bond Index Fund, the
Large Company Stock Index Fund,
the Small Company Stock Index
Fund, the International Stock
Index Fund, the Stable Value Fund,
the Conservative Asset Allocation
Fund, the Moderate Asset
Allocation Fund and the Aggressive
Asset Allocation Fund or any of
them.
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<PAGE>
Highly Compensated: Whether an Eligible Employee is
------------------- Highly Compensated shall be
determined using the simplified
method under Code Section
414(q)(12) as described in
applicable Treasury regulations or
other guidance issued by the
Internal Revenue Service.
Investment Fund: The Company Stock Fund, The Bond
---------------- Fund, the Bond Index Fund, the
Large Company Stock Index Fund,
the Small Company Stock Index
Fund, the International Stock
Index Fund, the Stable Value Fund,
the Conservative Asset Allocation
Fund, the Moderate Asset
Allocation Fund and the Aggressive
Asset Allocation Fund or any of
them.
Investment Manager: STABLE VALUE FUND. PRIMCO Capital
------------------- Management, Inc., 101 South Fifth
Street, Louisville, Kentucky
40202, or such other firm or
individual as may be selected from
time to time by the Employee
Benefit Finance Committee.
BOND INDEX FUND. State Street Bank
and Trust, Two International
Place, Boston, MA 02110, or such
other firm or individual as may be
selected from time to time by the
Employee Benefit Finance
Committee.
LARGE COMPANY STOCK INDEX FUND.
State Street Bank and Trust, Two
International Place, Boston, MA
02110, or such other firm or
individual as may be selected from
time to time by the Employee
Benefit Finance Committee.
SMALL COMPANY STOCK INDEX FUND.
State Street Bank and Trust, Two
International Place, Boston, MA
02110, or such other firm or
individual as may be selected from
time to time by the Employee
Benefit Finance Committee.
INTERNATIONAL STOCK INDEX FUND.
State Street Bank and Trust, Two
International Place, Boston, MA
02110, or such other firm or
individual as may be selected from
time to time by the Employee
Benefit Finance Committee.
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<PAGE>
CONSERVATIVE ASSET ALLOCATION
FUND. State Street Bank and Trust,
Two International Place, Boston,
MA 02110, or such other firm or
individual as may be selected from
time to time by the Employee
Benefit Finance Committee.
MODERATE ASSET ALLOCATION FUND.
State Street Bank and Trust, Two
International Place, Boston, MA
02110, or such other firm or
individual as may be selected from
time to time by the Employee
Benefit Finance Committee.
AGGRESSIVE ASSET ALLOCATION FUND.
Stat Street Bank and Trust, Two
International Place, Boston, MA
02110, or such other firm or
individual as may be selected from
time to time by the Employee
Benefit Finance Committee.
Long Term Disability Plan: Part B of the Group Life Insurance
-------------------------- and Long term Disability Plan of
Pacific Gas and Electric Company
as amended January 1, 1991.
MAAF: The Moderate Asset Allocation Fund.
-----
Moderate Asset Allocation Fund: A fund invested in a diversified
------------------------------- portfolio with an emphasis on
stocks and bonds. (See Section 16)
Non-Section 401(k) Contributions: Employee contributions to the Plan
--------------------------------- as described in Subsection 3(c)
and all Employee Contributions
made prior to October 1, 1984. Non-
Section 401(k) Contributions are
made with after-tax dollars.
Notice: Any method of communication, whether
------- electronic, telephonic, written or
other, provided that the Plan
Administrator has communicated in
writing to participants any such
method and its format as
appropriate and acceptable.
Plan: This Company's Savings Fund Plan for
----- Non-Union Employees, as amended,
revised and set forth herein.
Retirement Plan: The Company's Retirement Plan as
---------------- revised from time to time.
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<PAGE>
Rollover Contribution: An amount contributed by a
---------------------- participant which originated from
another employer's qualified plan
which is eligible for rollover
under Section 402(c)(4) of the
Code.
Savings Fund Plan Office: 245 Market Street, 3d Floor
------------------------- Mail Code N3X
P.O. Box 770000
San Francisco, CA 94177
Section 401(k) Contributions: Amounts deferred from a
----------------------------- Participant's Covered Compensation
as described in Subsection 3(a).
Section 401(k) Contributions are
made with pre-tax dollars.
Service: The period of time commencing with
-------- the first day of employment or
reemployment for an Employer and
ending on participant's Severance
from Service Date. If an Employee
with less than one year of Service
is rehired after a period of
severance which extends for 12
months or more, the Employee shall
be treated as a new Employee for
all purposes, and the Service and
compensation before the Severance
from Service Date shall not be
recognized for any purpose of the
Plan. Participants who have a
period of severance after they
have completed at least one year
of Service and who are later
rehired, immediately become
Eligible Employees entitled to
contribute in accordance with
their total years of Service.
Service shall also include all
years of Service with:
(a) Any corporation which is a
member of the same controlled
group of corporations as the
Company or of any other
Employer (within the meaning
of Section 414(b) of the
Code);
(b) Any trade or business under
the common control of the
Company or of any other
Employer (within the meaning
of Section 414(c) of the
Code);
(c) Any service organization which
is a member of the same
affiliated service group as
the Company or of any other
Employer (within the meaning
of
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<PAGE>
Section 414(m) of the Code).
Severance From Service Date: A. The date on which an Employee
---------------------------- quits, retires, is discharged
or dies; or
B. The first anniversary of the
first date of a period in
which a participant remains
absent from work for an
Employer for any reason other
than resignation, retirement,
discharge, or death.
C. For the purpose of determining
the Severance from Service
Date, the following periods
shall not be considered as
absences from work for an
Employer:
(1) Absence on a leave of
absence authorized by an
Employer.
(2) Absence because of
illness or injury as long
as the participant is
entitled to receive sick
leave pay or is entitled
to receive benefits under
the provisions of the
Voluntary Wage Benefit
Plan, a state disability
plan, the Long Term
Disability Plan, or a
Workers' Compensation
Law.
(3) Absence for military
service or service in the
Merchant Marines so long
as reemployment rights
are protected by law.
(4) Absence caused by layoff
for lack of work of less
than 12 continuous months
for a Participant who has
less than five years of
service, or 24 continuous
months for a Participant
who has five or more
years of service.
Stable Value Fund: A fund invested in fixed rate,
------------------ fixed term investment contracts.
(See Section 13)
SVF: The Stable Value Fund.
----
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<PAGE>
Trust: The Trust into which all
------ contributions are deposited and
from which all distributions are
made.
Trustee: State Street Bank and Trust
-------- Company, 225 Franklin Street,
Boston, Massachusetts 02101, or
such other bank or trust company
selected by the Employee Benefit
Finance Committee which agrees to
act as Trustee or successor
Trustee of the Trust pursuant to
the Trust Agreement.
Trust Agreement: The agreement between the Company
---------------- and the Trustee.
Unit: A measurement of participant's
----- interest in the Investment Funds.
For purposes of the Bond Fund, a
unit shall be a United States
Bond.
Year: The calendar year beginning
----- January 1 and ending December 31.
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SPECIAL PROVISION A
TOP HEAVY PROVISIONS
--------------------
(a) General Rule
------------
For any PLAN YEAR for which this PLAN is a "top-heavy plan" as defined in
subsection (g) below, any other provisions of this PLAN to the contrary
notwithstanding, this PLAN shall be subject to the following provisions:
(1) The minimum contribution provisions of subsection (b).
(2) The limitation on contribution set by subsection (d).
(b) Minimum Contribution Provisions
-------------------------------
Each participant who (i) is a non-key EMPLOYEE (as defined in subsection
(i) below) and (ii) is employed on the last day of the PLAN YEAR, even if
such individual is excluded from the PLAN for failing to make mandatory
contributions to the PLAN, shall be entitled to have contributions
allocated to his account of not less than three percent (the "minimum
contribution percentage") of the participant's compensation (within the
meaning of Section 415 of the CODE). In determining the minimum
contribution percentage to be allocated to an EMPLOYEE'S account, a key
EMPLOYEE'S SECTION 401(k) CONTRIBUTIONS shall be considered as an EMPLOYER
CONTRIBUTION. However, SECTION 401(k) CONTRIBUTIONS on behalf of EMPLOYEES
other than key EMPLOYEES will not be considered as EMPLOYER CONTRIBUTIONS.
The minimum contribution percentage set forth above shall be reduced for
any PLAN YEAR in which the percentage at which contributions are made (or
required to be made) under the PLAN for the PLAN YEAR for the key EMPLOYEE
for whom such percentage is the highest for such PLAN YEAR is less than
three percent. For this purpose, the percentage with respect to a key
EMPLOYEE (as defined in subsection (g) below) shall be determined by
dividing the contributions (including forfeitures and SECTION 401(k)
CONTRIBUTIONS) made for such key EMPLOYEES by so much of his total
compensation for the PLAN YEAR.
Contributions taken into account under the immediately preceding sentence
shall include contributions under this PLAN and under all other defined
contribution plans required to be included in an aggregation group (as
defined in subsection (f)(2) below) but shall not include any plan required
to be included in such aggregation group if such plan enables a defined
contribution plan required to be included in such group to meet the
requirements of the CODE prohibiting discrimination as to contributions or
benefits in favor of EMPLOYEES who are officers, shareholders or the
highly-compensated or prescribing the minimum participation standards.
Contributions taken into account under this subsection (b) shall not
include any contributions under the Social Security Act or any other
Federal or State law.
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<PAGE>
(c) Limitations on Contributions
----------------------------
In the event that the EMPLOYER also maintains a defined benefit PLAN
providing benefits on behalf of participants in this PLAN, one of the two
following provisions shall apply:
(1) If for the PLAN YEAR this PLAN would not be a "top-heavy PLAN" as
defined in subsection (a)(2) above if "90 percent" were substituted
for "60 percent," then subsection (b) shall apply for such PLAN YEAR
as if amended so that "four percent" were substituted for "three
percent".
(2) If for the PLAN YEAR this PLAN would continue to be a "top-heavy PLAN"
as defined in subsection (f) below if "90 percent" were substituted
for "60 percent," then the denominator of both the defined
contribution PLAN fraction and the defined benefit PLAN fraction shall
be calculated as set forth in Section 415 (e) of the CODE for the
limitation year ending in such PLAN YEAR by substituting "1.0" for
"1.25" in each place such figure appears, except with respect to any
individual for whom there are no EMPLOYER CONTRIBUTIONS allocated or
any accruals for such individual under the defined benefit PLAN.
Furthermore, the transitional rule set forth in Section 415 (e) of the
CODE shall be applied by substituting "$41,500" for "$51,875".
(d) Coordination with Other Plans
-----------------------------
In the event that another defined contribution or defined benefit plan
maintained by the EMPLOYER provides contributions or benefits on behalf of
participants in this PLAN, such other plan shall be treated as a part of
this PLAN pursuant to applicable principles (such as Rev. Rul. 81-202 or
any successor ruling or regulations) in determining whether this PLAN
satisfies the requirements of subsection (b), (c) and (d). Such
determination shall be made upon the advice of counsel by the EMPLOYEE
BENEFIT ADMINISTRATIVE COMMITTEE.
(e) Top-Heavy Plan Definition
-------------------------
This PLAN shall be a "top-heavy plan" for any PLAN YEAR if, as of the
determination date (as defined in subsection (f)(1) below), the aggregate
of the accounts under the PLAN and any required aggregation group or
permissive aggregation group of plans for participants (including former
participants) who are key EMPLOYEES (as defined in subsection (g) below but
not including accounts of individuals excluded under section 416(g)(4)(E)
of the CODE) exceeds 60 percent of the present value of the aggregate of
the accounts for all participants, excluding former key EMPLOYEES, or if
this PLAN is required to be in an aggregate group (as defined in subsection
(f)(3) below) which for such PLAN YEAR is a top-heavy group (as defined in
subsection (f)(4) below).
(1) "Determination date" means for any PLAN YEAR the last day of the
immediately preceding PLAN YEAR.
(2) "Valuation date" means the last day of each PLAN YEAR.
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<PAGE>
(3) "Aggregation group" means the group of plans, if any, that includes
both the group of plans that are required to be aggregated and the
group of plans that are permitted to be aggregated.
(A) The group of plans that are required to be aggregated (the
"required aggregation group") includes
(i) Each plan of the EMPLOYER (as defined in subsection (i)
below) in which a key EMPLOYEE is a participant, including
collectively-bargained plans, and
(ii) Each other plan, including collectively-bargained plans of
the EMPLOYER (as defined in subsection (i) below) which
enables a plan in which a key EMPLOYEE is a participant to
meet the requirements of the CODE prohibiting discrimination
as to contributions or benefits in favor of EMPLOYEES who
are officers, shareholders or the highly-compensated or
prescribing the minimum participation standards.
(B) The group of plans that are permitted to be aggregated (the
"permissive aggregation group") includes the required aggregation
group plus one or more plans of the EMPLOYER (as defined in
subsection (i) below) that is not part of the required
aggregation group and that the EMPLOYEE BENEFIT ADMINISTRATIVE
COMMITTEE certifies as constituting a plan within the permissive
aggregation group. Such plan or plans may be added to the
permissive aggregation group only if, after the addition, the
aggregation group as a whole continues not to discriminate as to
contributions or benefits in favor of officers, shareholders or
the highly-compensated and to meet the minimum participation
standards under the CODE.
(4) "Top-heavy group" means the aggregation group, if as of the applicable
determination date, the sum of the present value of the cumulative
accrued benefits for key EMPLOYEES under all defined benefit plans
included in the aggregation group plus the aggregate of the accounts
of key EMPLOYEES under all defined contribution plans included in the
aggregation group exceeds 60% of the sum of the present value of the
cumulative accrued benefits for all EMPLOYEES, excluding former key
EMPLOYEES, under all such defined benefit plans plus the aggregate
accounts for all EMPLOYEES, excluding former key EMPLOYEES, under such
defined contribution plans. If the aggregation group that is a top-
heavy group is a required aggregation group, each plan in the group
will be top heavy. If the aggregation group that is a top-heavy group
is a permissive aggregation group, only those plans that are part of
the required aggregation group will be treated as top-heavy. If the
aggregation group is not a top-heavy group, no plan within such group
will be top-heavy.
(5) In determining whether this PLAN constitutes a "top-heavy plan," the
EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE (or its agent) shall make
the following adjustments in connection therewith:
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<PAGE>
(A) When more than one plan is aggregated, the EMPLOYEE BENEFIT
ADMINISTRATIVE COMMITTEE shall determine separately for each plan
as of each plan's determination date the present value of the
accrued benefits or account balance. The results shall then be
aggregated separately by adding the results of each plan as of
the determination dates for such plans that fall with the same
calendar year.
(B) In determining the present value of the cumulative accrued
benefit or the amount of the account of any EMPLOYEE, such
present value or account shall include the amount in dollar value
of the aggregate distributions made to such EMPLOYEE under the
applicable plan during the five-year period ending on the
determination date, unless reflected in the value of the accrued
benefit or account balance as of the most recent valuation date.
Such amounts shall include distributions to EMPLOYEES which
represented the entire amount credited to their accounts under
the applicable plan.
(C) Further, in making such determination, in any case where an
individual is a "non-key EMPLOYEE" as defined in subsection (h)
below, with respect to an applicable plan, but was a key EMPLOYEE
with respect to such plan for any prior PLAN YEAR, any accrued
benefit and any account of such EMPLOYEE shall be altogether
disregarded. For this purpose, to the extent that a key EMPLOYEE
is deemed to be a key EMPLOYEE if he or she met the definition of
key EMPLOYEE within any of the four preceding PLAN YEARS, this
provision shall apply following the end of such period of time.
(f) Key EMPLOYEE
------------
The term "key EMPLOYEE" means any EMPLOYEE or former EMPLOYEE under this
PLAN who, at any time during the PLAN YEAR containing the determination
date or during any of the four preceding PLAN YEARS, is or was one of the
following:
(1) An officer of the EMPLOYER having an annual compensation greater than
50 percent of the amount in effect under Section 415(b)(1)(A) of the
CODE for such PLAN YEAR. Whether an individual is an officer shall be
determined by the EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE on the
basis of all the facts and circumstances, such as an individual's
authority, duties and term of office, not on the mere fact that the
individual has the title of officer. For any such PLAN YEAR, these
shall be treated as officers no more than the lesser of:
(A) 50 EMPLOYEES, or
(B) the greater of three EMPLOYEES or 10 percent of the EMPLOYEES.
For this purpose, if there are more than 50 officers, the 50 highest-
paid officers shall be the key EMPLOYEES.
(2) One of the ten EMPLOYEES owning (or considered as owning, within the
meaning of the constructive ownership rules of the CODE) the largest
interests in the EMPLOYER (as defined in subsection (i)). An EMPLOYEE
who has some ownership interest is considered to be one of the top ten
owners unless at least ten other EMPLOYEES own a greater interest than
that EMPLOYEE. However, an
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<PAGE>
EMPLOYEE will not be considered a top ten owner for a PLAN YEAR if
the EMPLOYEE earns an amount equal to or less than the maximum
dollar limitation on contributions and other annual additions to a
participant's account in a defined contribution PLAN under the CODE
as in effect for the calendar year in which the determination date
falls.
(3) Any person who owns (or is considered as owning within the meaning of
the constructive ownership rules of the CODE) more than five percent
of the outstanding stock of the EMPLOYER or stock possessing more than
five percent of the combined total voting power of all stock of the
EMPLOYER.
(4) A one percent owner of the EMPLOYER having an annual compensation from
the EMPLOYER of more than $150,000, and who owns more than one percent
of the outstanding stock of the EMPLOYER or stock possessing more than
one percent of the combined total voting power of all stock of the
EMPLOYER. For purposes of this subsection, compensation means all
items includable as compensation for purposes of applying the
limitations on contributions and other annual additions to a
participant's account in a defined contribution plan and the maximum
benefit payable under a defined benefit plan under the CODE.
For purposes of parts (1), (2), (3) and (4) of this definition, a
BENEFICIARY of a key EMPLOYEE shall be treated as a key EMPLOYEE. For
purposes of parts (3) and (4), each EMPLOYER is treated separately
(without regard to the definition in subsection (i)) in determining
ownership percentages; but, in determining the amount of compensation,
the definition of EMPLOYER in subsection (i) is taken into account.
(g) Non-key EMPLOYEE
----------------
The term "non-key EMPLOYEE" means any EMPLOYEE (and any beneficiary or an
EMPLOYEE) who is not a key EMPLOYEE.
(h) Employer
--------
The term "employer" as defined in Section 34 of this PLAN.
-39-
<PAGE>
-------------------------
I, Leslie H. Everett, do hereby certify that I am the Vice President and
Corporate Secretary of the PACIFIC GAS AND ELECTRIC COMPANY, a corporation
organized and existing under the laws of the State of California, and that the
above and foregoing is a full, true and correct copy of the Pacific Gas and
Electric Company SAVINGS FUND PLAN FOR NON-UNION EMPLOYEES as the same exists at
the date of this certification.
WITNESS my hand and the seal of the said corporation hereunto affixed this
day of
Leslie H. Everett
Vice President and Corporate Secretary of
PACIFIC GAS AND ELECTRIC COMPANY
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<PAGE>
EXHIBIT 10.8
THE PACIFIC GAS AND ELECTRIC COMPANY
RETIREMENT PLAN
<PAGE>
PART I
------
TABLE OF CONTENTS
-----------------
RETIREMENT PLAN
---------------
<TABLE>
<CAPTION>
Page
----
<S> <C>
1. INTRODUCTION...................................................1
2. ELIGIBILITY AND PARTICIPATION..................................2
3. SERVICE........................................................2
4. BREAK IN SERVICE AND REEMPLOYMENT..............................2
5. NORMAL RETIREMENT DATE.........................................3
6. BASIC PENSION BENEFIT FORMULA..................................3
7. EARLY RETIREMENT PENSION BENEFIT FORMULA.......................4
8. PENSIONS WHERE EMPLOYMENT ENDS BEFORE AGE 55...................5
9. DEFERRED RETIREMENT............................................5
10. FORMS OF PENSION...............................................6
11. SPOUSE'S PENSION...............................................7
12. WITHDRAWAL OF PARTICIPANT CONTRIBUTIONS ON TERMINATION OF
EMPLOYMENT..................................................9
13. DEATH BENEFITS.................................................9
14. FACILITY OF PAYMENT............................................9
15. BENEFITS ARE NOT ASSIGNABLE...................................10
16. EMPLOYER CONTRIBUTIONS........................................10
17. COMPANY'S POWERS AND DUTIES...................................10
18. FUNDING AND INVESTMENT PROVISIONS.............................11
19. ADMINISTRATION................................................11
20. CLAIMS PROCEDURE..............................................12
21. QUALIFIED DOMESTIC RELATIONS ORDERS...........................12
22. AMENDMENT, TERMINATION, AND MERGER............................13
23. DEFINITIONS AND CROSS-REFERENCES..............................13
SPECIAL PROVISIONS A, B, C, D, E, F, G, H, I, J, K, L, M AND N..20-76
</TABLE>
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<PAGE>
RETIREMENT PLAN
---------------
1. Introduction
------------
This is the controlling and definitive statement of the Pacific Gas and
Electric Company Retirement PLAN /1/ which, with certain exceptions, is
effective on and after January 1, 1996, for EMPLOYEES who are employed by
Pacific Gas and Electric Company and other EMPLOYERS.
This PLAN is a further revision of the PLAN, originally placed in effect by
the COMPANY January 1, 1937, which has been amended from time to time in
the intervening years. Rights of PARTICIPANTS in this PLAN will not be
less than rights of PARTICIPANTS under COMPANY'S PLAN as it existed before
1996.
The purpose of this PLAN is to distribute the corpus and income of
accumulated PENSION trust funds in accordance with the PLAN. Under no
circumstances shall contributions or benefits under this PLAN discriminate
in favor of a "highly compensated EMPLOYEE," as that term is defined using
the simplified method under CODE Section 414(q)(12) as described in
applicable Treasury regulations or other guidance issued by the Internal
Revenue Service. Forfeitures of nonvested accrued benefits under the PLAN
shall not be applied to increase benefits any EMPLOYEE could otherwise
receive under the terms of the PLAN.
Except for pension adjustments provided for in Special Provision G,
PARTICIPANTS who retire or terminate employment before the effective date
of any amendment are not affected or benefited by such amendments.
Since final regulations governing many statutory requirements of the
Employee Retirement Income Security Act of 1974 (ERISA) have not yet been
issued, the COMPANY reserves the right to retroactively modify the final
language of the revised PLAN to conform to these requirements.
As provided for in Section 414(f) of the CODE, the PLAN has elected to be
treated as a single employer plan.
This PLAN consists of Part I and Part II. Part I applies solely to
EMPLOYEES not covered by a collective bargaining agreement, and Part II
applies solely to EMPLOYEES whose benefits are the subject of collective
bargaining with a union representing EMPLOYEES of the COMPANY. /2/
- ---------------------------
/1/ Words in all capitals are defined in Section 23.
/2/ For PLAN YEARS prior to January 1, 1995, only management EMPLOYEES were
PARTICIPANTS in Part I of the PLAN; prior to January 1, 1995, weekly-paid,
non-union EMPLOYEES participated in Part II.
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<PAGE>
PART I
------
2. Eligibility and Participation
-----------------------------
An EMPLOYEE automatically becomes a PARTICIPANT in the PLAN on the first
day of work for an EMPLOYER, and participation continues until the
PARTICIPANT's SERVICE is terminated.
3. Service
-------
(a) The SERVICE of a PARTICIPANT on any date shall consist of the sum of
the following:
(1) Any CREDITED SERVICE as of December 31, 1975, as defined under
the PLAN prior to the January 1, 1976, amendment and reproduced
in Special Provision F, and
(2) The elapsed time from the first day of employment with an
EMPLOYER (but not earlier than January 1, 1976) to the
PARTICIPANT's SEVERANCE FROM SERVICE DATE, excluding any periods
of BREAK IN SERVICE and any SERVICE cancelled by the operation of
Sections 4 and 13.
(b) For EMPLOYEES who attain PART-TIME status at any time on or after
January 1, 1991, service benefit accruals will be based on the
following SERVICE:
(1) Paragraph (a) of this Section will apply to all SERVICE prior to
January 1, 1991;
(2) All SERVICE after December 31, 1990 in which the EMPLOYEE is
designated as a PART-TIME EMPLOYEE shall be prorated for
purposes of benefit accruals based on the ratio of actual
straight-time hours worked in the calendar year to the full-time
hourly equivalent (2,080 per calendar year) rounded to the
nearest month.
4. Break in Service and Reemployment
---------------------------------
Upon reemployment with an EMPLOYER after a BREAK IN SERVICE, prior SERVICE
earned under the PLAN will be treated for eligibility, vesting and/or
benefit accrual as follows:
(a) If a PARTICIPANT has a BREAK IN SERVICE starting on or after January
1, 1989, the SERVICE of such PARTICIPANT prior to the BREAK IN SERVICE
will be cancelled unless such prior SERVICE was at least five years
or, in the event that such prior SERVICE was less than five years, if
the period of the BREAK IN SERVICE was less than the prior SERVICE.
(b) If a PARTICIPANT has a BREAK IN SERVICE starting on or after January
1, 1985, but before January 1, 1989, the SERVICE of such PARTICIPANT
prior to the BREAK IN SERVICE will be cancelled unless such prior
SERVICE was at least 10 years or, in the event that such prior
SERVICE was less than 10 years, such prior SERVICE will be cancelled
if the period of the BREAK IN SERVICE is equal to or exceeds the
greater of (i) five years or (ii) the period of SERVICE prior to the
BREAK IN SERVICE.
(c) If a PARTICIPANT has a BREAK IN SERVICE starting on or after January
1, 1976, but before January 1, 1985, the SERVICE of such PARTICIPANT
prior to the BREAK IN SERVICE will be cancelled unless such prior
SERVICE was at least 10 years or, in the event that such prior
SERVICE was less than 10 years, if the period of the BREAK IN SERVICE
was less than the prior SERVICE. If the PARTICIPANT's contributions
to the PLAN have been withdrawn,
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<PAGE>
restoration of the PARTICIPANT's prior SERVICE will be in accordance
with the provisions of Section 12.
(d) EMPLOYEES who were PARTICIPANTS in the PLAN prior to January 1, 1976,
and whose prior SERVICE would not be restored under the provisions of
(a) of this Section, but would have been restored under the
provisions of the PLAN prior to the January 1, 1976, amendment, shall
continue to be eligible to have their prior SERVICE restored under
the rules of the PLAN prior to the January 1, 1976, amendment. Such
rules are set forth in Special Provision E.
5. Normal Retirement Date
----------------------
NORMAL RETIREMENT DATE is the first day of the month following a
PARTICIPANT's 65th birthday.
6. Basic Pension Benefit Formula
-----------------------------
A PARTICIPANT whose SERVICE continues to NORMAL RETIREMENT DATE or
beyond/3/ is entitled to a BASIC PENSION payable on ACTUAL RETIREMENT DATE
and on the first day of each month thereafter as long as the PARTICIPANT
lives./4/
(a) The monthly amount of the BASIC PENSION for a PARTICIPANT whose entire
SERVICE is accrued as a PARTICIPANT in Part I of this PLAN shall be a
monthly amount equal to 1.6 percent of the PARTICIPANT's average BASIC
MONTHLY SALARY for the final 36 consecutive months of SERVICE,/5/
multiplied by the number of whole and fractional years of SERVICE. The
amount so determined shall take the place of all other retirement
income to which a PARTICIPANT might otherwise have been entitled under
any suspended plan of an EMPLOYER or predecessor company.
(b) The monthly amount of the BASIC PENSION for a PARTICIPANT whose
classification is changed and who has accrued SERVICE under both Part
I and Part II of this PLAN shall be the larger of (1) or (2) below:
(1) The amount produced by computing all years of SERVICE pursuant to
the applicable formula for the new classification.
(2) The amount equal to the sum of (i) a pension benefit for SERVICE
prior to the change in classification, computed pursuant to the
applicable formula for the PARTICIPANT's old classification in
effect at the time of the change in classification; and (ii) a
pension benefit for SERVICE after the change in classification,
computed pursuant to the formula applicable for the PARTICIPANT's
new job classification. Each portion of the BASIC PENSION
calculated under (i) and (ii) above shall be subject to all the
applicable reductions imposed in PART I and PART II with respect
to age and early retirement, joint pensions, marital pensions,
and the election of an alternative spouse's pension.
- ---------------------------
/3/ See Section 9 for the conditions under which this may occur.
/4/ See Section 10 for the conditions under which other forms of pension may be
substituted for the BASIC PENSION.
/5/ A married PARTICIPANT'S EARLY RETIREMENT PENSION shall be in the form of a
MARITAL PENSION, computed as provided in Section 10b. In lieu of a MARITAL
PENSION, a PARTICIPANT may elect any of the alternative forms of the EARLY
RETIREMENT PENSION described in Section 10b. and subject to the rules
contained therein.
-3-
<PAGE>
(c) The monthly amount of the BASIC PENSION for a PARTICIPANT receiving
LONG TERM DISABILITY PLAN benefits on ACTUAL RETIREMENT DATE shall be
computed under (1) or (2) below, as applicable:
(1) For EMPLOYEES receiving LONG TERM DISABILITY PLAN benefits on
January 1, 1988, a monthly benefit equal to 1.6 percent of the
larger of (i) the PARTICIPANT'S BASIC MONTHLY SALARY for the last
month of active SERVICE or (ii) the PARTICIPANT'S LONG TERM
DISABILITY PLAN benefit for the month immediately preceding
ACTUAL RETIREMENT DATE. The result obtained in (i) or (ii) shall
be multiplied by the number of whole or fractional years of
SERVICE.
(2) For EMPLOYEES who start receiving LONG TERM DISABILITY PLAN
benefits after January 1, 1988, a monthly benefit equal to 1.6
percent of the larger of (i) the average BASIC MONTHLY SALARY for
the final consecutive 36 months of active SERVICE or (ii) the
PARTICIPANT'S LONG TERM DISABILITY PLAN benefit for the month
immediately preceding ACTUAL RETIREMENT DATE. The result obtained
in (a) or (b) shall be multiplied by the number of whole and
fractional years of SERVICE.
7. Early Retirement Pension Benefit Formula
----------------------------------------
If a PARTICIPANT's SERVICE ends after the first day of the month following
said PARTICIPANT's 55th birthday, and before NORMAL RETIREMENT DATE or
death, the PARTICIPANT shall elect to receive either:
(a) A BASIC PENSION computed as provided in Section 6, or a MARITAL
PENSION computed as provided in Section 10b., whichever is applicable,
payable beginning with NORMAL RETIREMENT DATE; or
(b) An EARLY RETIREMENT PENSION with payments to begin on the
PARTICIPANT's EARLY RETIREMENT DATE and to continue on the first day
of each month thereafter so long as PARTICIPANT lives. EARLY
RETIREMENT DATE is the date selected by the PARTICIPANT for
commencement of payment of retirement benefits. This date must be the
first day of any month after the termination of SERVICE and before the
PARTICIPANT's 65th birthday. To elect an EARLY RETIREMENT PENSION,
PARTICIPANT must notify the EMPLOYER in writing at least 30 days
before the EARLY RETIREMENT DATE the PARTICIPANT selects. The monthly
amount of the PARTICIPANT's EARLY RETIREMENT PENSION/6/ will be as
follows:
(1) If PARTICIPANT has less than 15 years of SERVICE on the EARLY
RETIREMENT DATE, the amount of the BASIC PENSION shall be reduced
by one-fourth of one percent for each month (three percent per
year) between PARTICIPANT's NORMAL RETIREMENT DATE and
PARTICIPANT's EARLY RETIREMENT DATE; or
(2) If PARTICIPANT has at least 15 but less than 30 years of SERVICE
and is 62 years of age or older on the EARLY RETIREMENT DATE, the
amount shall be the PARTICIPANT's BASIC PENSION computed to the
PARTICIPANT's EARLY RETIREMENT DATE; or
- ---------------------------
/6/ A married PARTICIPANT'S EARLY RETIREMENT PENSION shall be in the form of a
MARITAL PENSION, computed as provided in Section 10b and Section 7. In lieu
of a MARITAL PENSION, a PARTICIPANT may elect any of the alternative forms
of the EARLY RETIREMENT PENSION described in Section 10b. and subject to
the rules contained therein.
-4-
<PAGE>
(3) If PARTICIPANT has at least 15 but less than 25 years of SERVICE
and is less than 62 years of age on the EARLY RETIREMENT DATE,
the amount of the BASIC PENSION shall be reduced by one-fourth of
one percent for each month (three percent per year) by which
PARTICIPANT's EARLY RETIREMENT DATE precedes PARTICIPANT's 62nd
birthday, and further reduced by 1/12th of one percent for each
month (one percent per year) by which PARTICIPANT's EARLY
RETIREMENT DATE precedes PARTICIPANT's 60th birthday; or
(4) If PARTICIPANT has at least 25 but less than 30 years of SERVICE
and is less than 62 years of age on the EARLY RETIREMENT DATE,
the amount of the BASIC PENSION shall be reduced by one-fourth of
one percent for each month (three percent per year) by which
PARTICIPANT's EARLY RETIREMENT DATE precedes PARTICIPANT's 62nd
birthday; or
(5) If a PARTICIPANT has at least 30 years of SERVICE and is less
than 60 years of age on the EARLY RETIREMENT DATE, the amount of
the BASIC PENSION shall be reduced by one- half of one percent
for each month (up to a maximum of 12 months or six percent) by
which PARTICIPANT'S EARLY RETIREMENT DATE precedes PARTICIPANT's
60th birthday, and further reduced by one-fourth of one percent
for each month (three percent per year) by which PARTICIPANT'S
EARLY RETIREMENT DATE precedes PARTICIPANT's 59th birthday; or
(6) If PARTICIPANT has at least 30 years of SERVICE and is 60 years
of age or older on the EARLY RETIREMENT DATE, the amount shall be
the PARTICIPANT's BASIC PENSION computed to the PARTICIPANT's
EARLY RETIREMENT DATE.
(7) If a PARTICIPANT has at least 35 years of SERVICE and is 55 years
of age or older on EARLY RETIREMENT DATE, and such PARTICIPANT
was formerly a PARTICIPANT on December 31, 1994, in Part II of
the PLAN, the amount shall be the PARTICIPANT'S BASIC PENSION
computed to the PARTICIPANT'S EARLY RETIREMENT DATE.
See Special Provision B for a table of EARLY RETIREMENT reductions.
8. Pensions Where Employment Ends Before Age 55
--------------------------------------------
Until January 1, 1989, a PARTICIPANT with at least 10 years of SERVICE will
be designated as a former EMPLOYEE rather than a retired EMPLOYEE if such
PARTICIPANT's SERVICE ends before the first day of the month which follows
the PARTICIPANT's 55th birthday. Effective January 1, 1989, any
PARTICIPANT with at least five years of SERVICE will be designated as a
former EMPLOYEE if such PARTICIPANT's SERVICE ends before the first day of
the month which follows the PARTICIPANT's 55th birthday. Such former
EMPLOYEE has a vested right to receive a PENSION with the same rights of
election and in the same amounts as provided in Section 7, provided that
the earliest election date for commencement of PENSION payments is the
first day of the month after the PARTICIPANT's 55th birthday and the latest
shall be April 1 of the year following the year in which the PARTICIPANT
attains age 70 1/2. Such a PARTICIPANT is also entitled to the elections
provided in Sections 10 (Forms of Pension), 12 (Withdrawal of Participant
Contributions on Termination of Employment), 13 (Death Benefits in Certain
Cases), and 15 (Facility of Payment).
9. Deferred Retirement
-------------------
An EMPLOYEE may continue in employment beyond the NORMAL RETIREMENT DATE
only at the request of an EMPLOYER or as may be required by law. A
PARTICIPANT whose employment continues
-5-
<PAGE>
beyond NORMAL RETIREMENT DATE shall not be entitled to a pension until
PARTICIPANT's ACTUAL RETIREMENT DATE. Any provision of the PLAN
notwithstanding, distributions from the PLAN shall comply with the
requirements of CODE Section 401(a)(9) and the regulations thereunder. The
amount of the PENSION payable shall be the PENSION benefit accrued as of
the April 1 following the end of the year in which the EMPLOYEE attains age
70 1/2, adjusted for any elections made by the PARTICIPANT and any forms of
PENSION required under Section 10.
Pursuant to CODE Section 401(a)(9)(A)(ii), if an EMPLOYEE continues
employment beyond the end of the year in which the EMPLOYEE attains age 70
1/2, a PENSION shall be distributed, commencing not later than April 1 of
the calendar year following the calendar year in which the EMPLOYEE attains
age 70 1/2, over the life of the EMPLOYEE or over the joint lives of the
EMPLOYEE and the EMPLOYEE'S SPOUSE or other JOINT PENSIONER.
If an EMPLOYEE dies after the distribution of the EMPLOYEE'S interest in
the PLAN has begun, then, in accordance with CODE Section 401(a)(9)(B)(i),
the remaining portion of the EMPLOYEE'S accrued PENSION benefit, if any,
will be distributed at least as rapidly as under the method of
distributions being used as of the date of his or her death. If an
EMPLOYEE dies before the ACTUAL RETIREMENT DATE, then the EMPLOYEE'S SPOUSE
may elect to postpone receiving distributions under the SPOUSE'S PENSION,
but postponement of receipt of benefits shall not extend beyond the date
that the EMPLOYEE would have attained age 70 1/2. Death benefits provided
under the PLAN shall be no more than incidental, within the meaning of the
CODE, to the PLAN'S primary purpose of providing retirement benefits to
EMPLOYEES.
10. Forms of Pension
----------------
(a) Joint Pension With Non-Spouse
-----------------------------
For a PARTICIPANT who is unmarried on the ACTUAL RETIREMENT DATE, the
normal form of a PENSION shall be a BASIC PENSION or an EARLY
RETIREMENT PENSION which terminates on the PARTICIPANT'S death. A
MARITAL PENSION, as described in 10(b) below, is the normal form of
PENSION for PARTICIPANTS who are married on the ACTUAL RETIREMENT
DATE. However, any PARTICIPANT, whether married or unmarried, who
wishes to have the PENSION continued in whole or in part after the
PARTICIPANT'S death for the life of a non-spouse JOINT PENSIONER, may
elect to have the applicable normal form of PENSION paid as a JOINT
PENSION by giving the EMPLOYER at least 30 days' advance written
notice prior to the PARTICIPANT'S ACTUAL RETIREMENT DATE.
If such an election is made, the PARTICIPANT will receive a reduced
BASIC or EARLY RETIREMENT PENSION for life and, upon the PARTICIPANT'S
death, the non-spouse JOINT PENSIONER designated by the PARTICIPANT
will receive that proportion of such reduced PENSION, up to 100
percent, which the PARTICIPANT has elected, for the remainder of the
JOINT PENSIONER'S life.
Non-spouse JOINT PENSIONS shall be determined in accordance with an
actuarial formula which is set forth in Special Provision C.
(b) Joint Pension With Spouse
-------------------------
For a PARTICIPANT who is married on the ACTUAL RETIREMENT DATE, the
normal form of PENSION shall be a MARITAL PENSION, reducing the amount
of the PARTICIPANT'S BASIC PENSION and providing that on the
PARTICIPANT'S death one-half of such MARITAL PENSION will be continued
to the SPOUSE for the remainder of the SPOUSE'S life.
-6-
<PAGE>
In lieu of the MARITAL PENSION, a married PARTICIPANT, by making a
QUALIFIED ELECTION prior to ACTUAL RETIREMENT DATE, may elect one of
the following options:
(1) a JOINT PENSION with SPOUSE which provides that an amount equal
to either 25, 75 or 100 percent of a reduced BASIC or EARLY
RETIREMENT PENSION will, upon the PARTICIPANT'S death, be
continued for the remainder of the SPOUSE'S life, or
(2) a SPECIAL JOINT PENSION with SPOUSE which provides an amount of
one-half or 100 percent of a reduced BASIC or EARLY RETIREMENT
PENSION that, upon the PARTICIPANT'S death, will be continued for
the remainder of the SPOUSE'S life. However, if the SPOUSE
predeceases the PARTICIPANT, future PENSION payments will be
restored to the amount of the full BASIC or EARLY RETIREMENT
PENSION that the PARTICIPANT would be entitled to receive if no
SPECIAL JOINT PENSION with SPOUSE had been elected.
MARITAL PENSIONS and JOINT PENSIONS with SPOUSE shall be determined in
accordance with an actuarial formula which is set forth in Special
Provision D. Special Provision D also includes tables of factors
which apply to typical options which may be elected.
SPECIAL JOINT PENSIONS with SPOUSE shall also be determined in
accordance with the actuarial formula which is set forth in Special
Provision D, but actuarially adjusted further to reflect the value of
the restoration feature. Provision D also includes tables of the
factors which apply to SPECIAL JOINT PENSION options that may be
elected.
(c) Basic or Early Retirement Pension Terminating Upon The Death Of The
-------------------------------------------------------------------
Participant
-----------
Under this option, no additional PENSION payments are made to anyone
after the PARTICIPANT'S death.
(d) Conditions Applicable To All Forms Of Pensions
----------------------------------------------
The CONSENT of the SPOUSE is required whenever a QUALIFIED ELECTION is
made which would provide benefits to a surviving SPOUSE less than
those provided by a MARITAL PENSION.
The SPOUSE of a PARTICIPANT may not receive a benefit under any
provisions of this Section if a larger SPOUSE'S PENSION is payable
under Section 11.
11. Spouse's Pension
----------------
(a) If a married PARTICIPANT dies while employed by an EMPLOYER and prior
to the ACTUAL RETIREMENT DATE, or within 30 days thereafter, the
PARTICIPANT's surviving SPOUSE will be eligible to receive a SPOUSE's
PENSION if, at the time of the PARTICIPANT'S death, (i) the
PARTICIPANT was at least 55 years of age, or (ii) the sum of the
PARTICIPANT's age and years of SERVICE equaled 70 or more. (69.5 or
more is rounded to 70.)
The amount of the SPOUSE's PENSION is one-half of the PENSION that the
PARTICIPANT would have been entitled to receive, and will be
calculated as if:
(1) the PARTICIPANT had elected a BASIC PENSION under Section
10(b)(3),
(2) the first day of the month following the PARTICIPANT's death had
been the PARTICIPANT's ACTUAL RETIREMENT DATE, and
-7-
<PAGE>
(3) The PARTICIPANT had in fact retired on that date without
reduction for early retirement. However, if the SPOUSE is more
than 10 years younger than the PARTICIPANT, the amount of the
SPOUSE's PENSION shall be reduced 1/20th of one percent for each
full month in excess of 120 months' difference in their ages,
except that such reduction shall not result in a SPOUSE's PENSION
lower than would have been payable if the PARTICIPANT had retired
as of the date of death and elected an optional form providing
for continuation of 50 percent to a named JOINT PENSIONER with
SPOUSE the same sex and age of the SPOUSE, under the provisions
of Section 10(b)(1). The SPOUSE's PENSION is payable to the
PARTICIPANT's surviving SPOUSE on the first day of the month
following the PARTICIPANT's death and the first day of each month
thereafter so long as the SPOUSE lives.
(b) The surviving SPOUSE of a PARTICIPANT or of a former EMPLOYEE who dies
prior to actual retirement date shall be entitled to receive a
SPOUSE's PENSION under this Section 11(b) if, at the time of the death
of the PARTICIPANT or former EMPLOYEE, (i) the PARTICIPANT or former
EMPLOYEE had at least five years of SERVICE, and (ii) the surviving
SPOUSE does not qualify for a SPOUSE's PENSION under Section 11(a),
above.
A SPOUSE's PENSION under this Section 11(b) shall be payable on the
first day of the month following the later of (i) the date of death or
(ii) the month in which the deceased PARTICIPANT or former EMPLOYEE
would have attained his 55th birthday. By submitting an election form
to the PLAN ADMINISTRATOR, a SPOUSE may elect to begin receiving a
SPOUSE's PENSION at a specified later date.
Unless a vested PARTICIPANT or vested former EMPLOYEE and his or her
SPOUSE have elected otherwise pursuant to a QUALIFIED ELECTION, if a
PARTICIPANT dies on or before age 55, the PARTICIPANT'S or FORMER
EMPLOYEE'S surviving SPOUSE (if any) will receive the same benefit
that would have been payable if the PARTICIPANT or former EMPLOYEE
had:
(1) separated from SERVICE on the date of death (or date of
separation from SERVICE, if earlier),
(2) survived to age 55,
(3) retired with a MARITAL PENSION at age 55,
(4) died on the day of retirement, and begun to receive benefit
payments at the date as of which the PARTICIPANT or former
EMPLOYEE would have attained age 55.
Unless a surviving SPOUSE elects otherwise, the surviving SPOUSE will
begin to receive payments at the date as of which the PARTICIPANT or
former EMPLOYEE would have attained age 55. Benefits commencing after
this date will be the ACTUARIAL EQUIVALENT of the benefit to which the
surviving SPOUSE would have been entitled if benefits had commenced at
this date.
A PARTICIPANT's SPOUSE may not receive both a SPOUSE's PENSION under this
Section and a MARITAL or JOINT PENSION under Section 10. If the
PARTICIPANT dies within 30 days after the PARTICIPANT's ACTUAL RETIREMENT
DATE, the SPOUSE will receive the larger of the monthly Pensions under this
Section and Section 3.10, but not both.
-8-
<PAGE>
12. Withdrawal of Participant Contributions on Termination of Employment
--------------------------------------------------------------------
A PARTICIPANT's contributions to the PLAN may not be withdrawn prior to
ACTUAL RETIREMENT DATE or other termination of SERVICE. After a
PARTICIPANT's SERVICE is terminated, the PARTICIPANT, by written notice to
the PARTICIPANT's EMPLOYER at least 30 days before the date the PENSION
begins, may elect to have such CONTRIBUTIONS PLUS INTEREST returned.
If a PARTICIPANT elects to withdraw such CONTRIBUTIONS PLUS INTEREST, the
PENSION the PARTICIPANT would otherwise be entitled to at the NORMAL or
EARLY RETIREMENT DATE shall be reduced by an amount that reflects the
actuarial value of the contributions withdrawn. The factors used to reduce
the PENSION of a PARTICIPANT who has withdrawn his contributions shall
comply with CODE Sections 411(a)(7)(D) and 411(c)(2)(B) and are contained
in the table set forth in Special Provision I.
13. Death Benefits
--------------
If a PARTICIPANT with contributions on deposit in the PLAN dies before
receiving payments from the PLAN equal to the amount of the PARTICIPANT's
CONTRIBUTIONS PLUS INTEREST, the difference between the payments made and
the CONTRIBUTIONS PLUS INTEREST will be paid to the named BENEFICIARY,
unless a PENSION is payable to the PARTICIPANT's surviving SPOUSE or JOINT
PENSIONER. If a PENSION is payable after such PARTICIPANT's death, and if
upon the death of the SPOUSE or JOINT PENSIONER the total combined amount
paid to the PARTICIPANT and the SPOUSE or JOINT PENSIONER does not equal
the amount of the PARTICIPANT's CONTRIBUTIONS PLUS INTEREST, the difference
between the total amount paid and the PARTICIPANT's CONTRIBUTIONS PLUS
INTEREST will be paid to the BENEFICIARY of the SPOUSE or JOINT PENSIONER.
14. Facility of Payment
-------------------
(a) If the present value of all PENSION benefits payable under the PLAN to
any individual is less than $3,500.00 as of the date of SEVERANCE FROM
SERVICE or ACTUAL RETIREMENT DATE, the equivalent value shall be paid
in a lump sum, as directed by the ADMINISTRATOR. For PARTICIPANTS
terminating before age 55, present value means the ACTUARIAL
EQUIVALENT of the normal retirement benefit commencing at NORMAL
RETIREMENT DATE. For PARTICIPANTS retiring at or after age 55, present
value means the ACTUARIAL EQUIVALENT of the early, normal or deferred
retirement benefit commencing at ACTUAL RETIREMENT DATE. In
determining the present value, the PLAN ADMINISTRATOR shall use the
Unisex Mortality Table for 1984 (UP-84) and the interest rates set, as
of the first day of the PLAN YEAR in which the lump sum payment is
made, by the Pension Benefit Guaranty Corporation for the purpose of
determining the present value of a lump sum distribution on PLAN
termination.
(b) If the ADMINISTRATOR determines that any individual entitled to any
payment under the PLAN is physically or mentally incompetent to handle
the payment and no guardian or conservator has been appointed to
receive such payment, the ADMINISTRATOR may cause all payments
thereafter becoming due to such individual to be applied for and on
behalf of and for the benefit of such individual. Payments made
pursuant to this provision shall completely discharge the EMPLOYER,
the ADMINISTRATOR, the Trustee, and all fiduciaries of all further
responsibility with respect to such individual.
(c) If the distributee of any eligible rollover distribution (as defined
below) elects to have the distribution paid directly to an eligible
retirement plan (as defined below), and if the distributee specified,
according to the manner specified by the PLAN, the eligible retirement
plan to which such distribution is to be paid, then the distribution
shall be made in the form of a direct trustee-to-
-9-
<PAGE>
trustee transfer to the eligible retirement plan specified by the
distributee. The trustee-to-trustee transfer shall be made available
only if the distribution from the PLAN would be subject to federal
income taxation.
The term "eligible rollover distribution" shall mean any distribution to a
PARTICIPANT or former EMPLOYEE of all or part of the balance to the credit
of the PARTICIPANT or former EMPLOYEE in the PLAN. The term shall not,
however, include any distribution which is one of a series of
"substantially equal periodic payments" (as defined at CODE Section
402(c)(4)(A), or any distribution that is required under CODE Section
401(a)(9).
The term "eligible retirement plan" means an individual retirement account
described in CODE Section 408(a), an individual retirement annuity
described in CODE Section 408(b) (other than an endowment contract), an
annuity plan described in CODE Section 403(a), or a qualified defined
contribution plan, the terms of which permit the acceptance of rollover
distributions.
15. Benefits Are Not Assignable
---------------------------
Except as may be required by law, a PARTICIPANT's interest in the PLAN,
either before or after retirement, and that of a PARTICIPANT's SPOUSE,
JOINT PENSIONER, or BENEFICIARY shall not be subject to assignment,
anticipation, sale, transfer, pledge, encumbrance, or charge, whether
voluntary or involuntary, and any attempt to so assign, anticipate, sell,
transfer, pledge, encumber, or charge shall be void.
16. Employer Contributions
----------------------
The COMPANY shall contribute to the PLAN such amount of EMPLOYER
CONTRIBUTIONS as the EMPLOYEE BENEFIT FINANCE COMMITTEE, with the advice of
the actuary, shall determine is necessary to keep the PLAN funded in
accordance with the Funding Policy and to satisfy any minimum funding
standard required by the Internal Revenue SERVICE or the Department of
Labor. The EMPLOYEE BENEFIT FINANCE COMMITTEE shall determine and charge
to each EMPLOYER its share of the EMPLOYER contributions made by the
COMPANY.
17. Company's Powers and Duties
---------------------------
The COMPANY, acting through its Board of Directors or Executive Committee,
reserves to itself the exclusive power to amend, suspend, or terminate the
PLAN as provided below and to appoint and remove from time to time:
(a) The individuals comprising the EMPLOYEE BENEFIT FINANCE COMMITTEE;
(b) The individuals comprising the EMPLOYEE BENEFIT ADMINISTRATIVE
COMMITTEE;
(c) The EMPLOYERS whose EMPLOYEES may participate in the PLAN.
(d) Except as provided in Section 20, the appropriate committees
established by the COMPANY shall serve as the final review committees,
under the PLAN, to determine conclusively for all parties any and all
questions arising from the administration of the PLAN and shall have
sole and complete discretionary authority and control to manage the
operation and administration of the PLAN, including, but not limited
to, the determination of all questions relating to eligibility for
participation and benefits, interpretation of all PLAN provisions,
determination of the amount and kind of benefits payable to any
PARTICIPANT, SPOUSE or beneficiary, and construction of
-10-
<PAGE>
disputed or doubtful terms. Such decisions shall be conclusive and
binding on all parties and not subject to further review.
All powers and duties not reserved to the COMPANY are delegated to the
EMPLOYEE BENEFIT FINANCE COMMITTEE and to the EMPLOYEE BENEFIT
ADMINISTRATIVE COMMITTEE. Action of either committee shall be by vote of a
majority of the members of the committee at a meeting, or in writing
without a meeting, and evidenced by the signature of any member who is so
authorized by the committee. The COMPANY indemnifies each member of each
committee against any personal liability or expense arising out of any
action or inaction of the committee or of any member of the committee or of
such individual, except that due to his own willful misconduct.
18. Funding and Investment Provisions
---------------------------------
The EMPLOYEE BENEFIT FINANCE COMMITTEE appointed by the COMPANY's Board of
Directors to serve at its pleasure has the express powers and duties
described in this Section.
(a) Appointments. The EMPLOYEE BENEFIT FINANCE COMMITTEE has the sole
------------
power and duty from time to time to appoint and remove the Funding
Agents, the Investment Manager, actuaries, accountants, and such other
advisors and consultants as may be needed for the proper financial
administration and investment of the assets of the PLAN. Supplementing
such appointments, the EMPLOYEE BENEFIT FINANCE COMMITTEE may enter
into appropriate agreements with each Trustee, Investment Manager or
other advisors appointed under this paragraph and delegate to them
appropriate powers and duties. The EMPLOYEE BENEFIT FINANCE COMMITTEE
may appoint and delegate to one or more individuals the power and duty
to handle the day-to-day financial administration of the PLAN. Such
individuals need not be members of the committee and shall serve at
the pleasure of the committee.
(b) Funding Policy. The EMPLOYEE BENEFIT FINANCE COMMITTEE has the sole
--------------
power and duty to establish a funding policy and an investment policy
and to review and revise it from time to time as the committee shall
determine in its sole discretion. All EMPLOYER contributions to the
PLAN shall be paid to Funding Agents which may be one or more
insurance companies or corporate trustees, or to any combination
thereof, as the EMPLOYEE BENEFIT FINANCE COMMITTEE may determine from
time to time. These contributions, and all previous contributions of
PARTICIPANTS and EMPLOYERS, together with the proceeds of their
investment, shall be held and administered by these Funding Agents
pursuant to the agreements between the COMPANY and the Funding Agents.
All of the PLAN'S assets held by Funding Agents are available to pay
benefits on behalf of all PARTICIPANTS covered by this PLAN.
19. Administration
--------------
The EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE, appointed by the COMPANY's
Board of Directors to serve at its pleasure, is the ADMINISTRATOR of the
PLAN and is responsible for the overall administration of the PLAN. The
ADMINISTRATOR has the sole power and duty to establish, and from time to
time revise, such rules and regulations as may be necessary to administer
the PLAN in a nondiscriminatory manner for the exclusive benefit of
PARTICIPANTS and all other persons entitled to benefits under the PLAN.
The ADMINISTRATOR shall also maintain such records and make such
computations, interpretations, and decisions as may be necessary or
desirable for the proper administration of the PLAN. The ADMINISTRATOR may
demand such proof of age of any PARTICIPANT, JOINT PENSIONER, or SPOUSE as
it considers necessary, and it may adjust any PENSION or other payment or
payments thereafter due under the PLAN as it deems appropriate and
equitable to correct any factual error or misrepresentation. The
ADMINISTRATOR shall maintain for PARTICIPANTS' inspection copies of the
PLAN, trust agreement,
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<PAGE>
investment policy, each agreement with an Investment Manager, the latest
annual report, PLAN description, and summary description, and any
amendments or changes in any of these documents. On written request,
PARTICIPANTS may obtain from the ADMINISTRATOR a copy of any of these
documents at a cost established by the ADMINISTRATOR from time to time.
All expenses of administration may be paid out of the PLAN's assets upon
authorization by the appropriate committee, unless paid by the COMPANY.
Such expenses shall include any expenses incident to the functioning of the
ADMINISTRATOR, including, but not limited to, fees for accountants,
actuaries, counsel, investment managers and other specialists and their
agents, and other costs of administering the PLAN.
20. Claims Procedure
----------------
If a claim is denied in whole or in part, the ADMINISTRATOR shall furnish
to the claimant a written notice setting forth:
(a) Specific reason(s) for the denial,
(b) The PLAN provision(s) on which the denial is based,
(c) A description of any material or information, if any, necessary for
the claimant to perfect the claim, and an explanation of why such
material or information is necessary, and
(d) Information concerning the steps to be taken if claimant wishes to
submit a claim for review.
The above information shall be furnished to the claimant within 90 days
after the claim is received by the ADMINISTRATOR.
If a claimant is not satisfied with the written notice described in the
preceding paragraph, such claimant may request a full and fair review by so
notifying the ADMINISTRATOR in writing within 90 days after receiving such
notice. If a review is requested the claimant shall also be entitled, upon
written request, to review pertinent documents and to submit issues and
comments in writing. The EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE shall
furnish the claimant with a written final decision within 60 days after
receipt of the request for review.
21. Qualified Domestic Relations Orders
-----------------------------------
The EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE shall apply the provisions of
this section with regard to a Domestic Relations Order (as defined below)
to the extent not inconsistent with Section 414(p) of the CODE.
The EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE shall establish procedures,
consistent with Section 414(p) of the CODE, to determine the qualified
status of any Domestic Relations Order, to administer distributions under
any Qualified Domestic Relations Order (as defined below), and to provide
to the PARTICIPANT and the Alternate Payee(s) (as defined below) all
notices required under Section 414(p) of the CODE with respect to any
Domestic Relations Order.
Within a reasonable period of time after the receipt of a Domestic
Relations Order (or any modification thereof), the EMPLOYEE BENEFIT
ADMINISTRATIVE COMMITTEE shall determine whether such order is a Qualified
Domestic Relations Order.
For purposes of this section:
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<PAGE>
(a) Alternate Payee shall mean any SPOUSE, former SPOUSE, child, or other
dependent of a PARTICIPANT who is recognized by a Domestic Relations
Order as having a right to receive all, or a portion of, the benefits
payable under the PLAN with respect to such PARTICIPANT.
(b) Domestic Relations Order shall mean any judgment, decree, or order
(including approval of a property settlement) which:
(1) relates to the provision of child support, alimony payments, or
marital property rights to a SPOUSE, former SPOUSE, child, or
other dependent of a PARTICIPANT; and
(2) is made pursuant to a state domestic relations law (including a
community property law).
(c) Qualified Domestic Relations Order shall mean a Domestic
Relations Order which meets the requirements of Section 414(p)(1)
of the CODE.
22. Amendment, Termination, and Merger
----------------------------------
The COMPANY hopes and expects to continue this PLAN indefinitely but,
because future conditions cannot be foreseen, its Board of Directors
necessarily reserves the right to change, suspend, or terminate the PLAN at
any time. However, no change can be made which would adversely affect the
rights which any PARTICIPANT, retired EMPLOYEE, former EMPLOYEE, SPOUSE,
JOINT PENSIONER, or BENEFICIARY may then have with respect to funds then
being held under the PLAN by any Funding Agent or permit any such funds to
revert to an EMPLOYER or be used for any purpose except for the exclusive
benefit of PARTICIPANTS, Pensioners, and their SPOUSES, JOINT PENSIONERS,
and BENEFICIARIES.
In the event the PLAN is partially terminated, terminated or suspended, all
EMPLOYER contributions with respect to the affected PARTICIPANTS shall
cease and the accrued benefits of the affected PARTICIPANTS shall become
nonforfeitable. Subject to applicable requirements of notice to the
Pension Benefit Guaranty Corporation governing termination of PENSION
benefit plans, the funds held under the PLAN by the Funding Agents shall be
applied to provide the PENSIONS, benefits and refunds accrued to the date
of termination or suspension and to the extent funded. Such provision
shall be made in such manner as the ADMINISTRATOR shall direct, including
the purchase of paid-up annuities, distribution in installments, or lump-
sum distributions and shall be in conformance with the requirements and
priorities established by various governmental agencies to oversee PLAN
suspensions and terminations. Notwithstanding any contrary provisions of
the PLAN, after its termination and after all liabilities for the payment
of PENSIONS, benefits and refunds to the date of termination have been
satisfied or provided for in accordance with the foregoing, any funds
remaining with the Funding Agents shall be returned to the COMPANY.
This PLAN shall not be merged into or consolidated with any other PLAN, nor
shall any of its assets or liabilities be transferred to any other PLAN,
unless each PARTICIPANT in this PLAN would (if such other PLAN then
terminated) receive a benefit immediately after the merger, consolidation,
or transfer which is equal to or greater than the benefit such PARTICIPANT
would have been entitled to receive immediately before the merger,
consolidation, or transfer (if this PLAN had then terminated).
23. Definitions and Cross-References
--------------------------------
<TABLE>
<S> <C>
Actual Retirement Date: The date of one of the following, whichever is applicable:
- ----------------------
(a) The date on which an EARLY RETIREMENT PENSION begins, or
</TABLE>
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<PAGE>
<TABLE>
<S> <C>
(b) The PARTICIPANT'S Normal Retirement Date, or
(c) If the PARTICIPANT continues in the employ of an EMPLOYER
beyond Normal Retirement Date, the first day of the month
following termination of SERVICE.
Actuarial Equivalent or For purposes of determining actuarially equivalent benefits under
Actuarial Equivalence: this PLAN, the provisions of Special Provision D shall apply.
- ---------------------
Administrator: The EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE referred to in
- ------------- Section 20, 201 Mission Street, 19th Floor, Mail Code P19A, P.O.
Box 770000, San Francisco, California 94177.
Basic Monthly Salary: The rate of pay used to calculate the monthly earnings from an
- -------------------- EMPLOYER, adjusted to reflect nuclear premium payments, if any,
but excluding payments from the LONG TERM DISABILITY PLAN and all
other bonuses, premiums, special allowances, overtime pay, or any
other payments. For a PARTICIPANT who is paid weekly or
bi-weekly, BASIC MONTHLY SALARY shall be equal to the
PARTICIPANT'S weekly pay rate multiplied by 4.33, rounded up to
the nearest Five Dollars.
For purposes of calculating a PARTICIPANT'S accrued benefit under
this PLAN, the compensation limitations of CODE Section
401(a)(17) shall be applicable. For purposes of calculating
accruals after December 31, 1993, the amount of a PARTICIPANT'S
compensation taken into account shall not exceed $150,000, or
such greater amount permitted by the Secretary of the Treasury.
For purposes of calculating accruals after December 31, 1988, and
before January 1, 1994, the amount of compensation taken into
account shall not exceed $200,000, or such greater amount
permitted by the Secretary of the Treasury.
Unless otherwise provided under this PLAN, each CODE Section
401(a)(17) employee's accrued benefit under this PLAN will be the
greater of the accrued benefit determined for the employee under
1 or 2 below:
1. The employee's accrued benefit determined with respect to the
benefit formula applicable for the PLAN YEAR beginning on or
after January 1, 1994, as applied to the employee's total years
of SERVICE taken into account under the PLAN for the purposes of
benefit accruals, or
2. The sum of:
(a) the employee's accrued benefit as of the last day of the last PLAN YEAR
beginning before January 1, 1994, frozen in accordance with CODE Section
1.401(a)(4)-13, and
(b) the employee's accrued benefit determined under the benefit formula
applicable for the PLAN YEAR beginning on or after January 1, 1994, as
</TABLE>
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<PAGE>
<TABLE>
<S> <C>
applied to the employee's years of service credited to the employee for
PLAN YEARS beginning on or after January 1, 1994, for purposes of benefit
accrual.
A CODE Section 401(a)(17) employee means an employee whose current accrued benefit
as of a date on or after the first day of the first PLAN YEAR beginning on or after
January 1, 1994, is based on compensation for a year beginning prior to the first
day of the first PLAN YEAR beginning on or after January 1, 1994, that exceeded
$150,000.
Basic Pension: The PENSION due at the later of NORMAL RETIREMENT DATE or ACTUAL
- ------------- RETIREMENT DATE and unreduced because of marital status. See
Sections 6 and 10b.
Beneficiary: The individual or individuals or intervivos trust or trusts that
- ----------- a PARTICIPANT, SPOUSE, or JOINT PENSIONER designates to receive
any death benefits due pursuant to Section 13. Such designation
must be made on forms provided by the EMPLOYER and filed with the
ADMINISTRATOR. A PARTICIPANT, or the PARTICIPANT'S SPOUSE (if
receiving a SPOUSE's PENSION), may change the designated
Beneficiary from time to time by filing an appropriate written
notice with the ADMINISTRATOR. In the absence of a designation,
the Beneficiary shall be the estate of the person entitled to
make the designation. There were no employee contributions after
December 31, 1972. Therefore, EMPLOYEES who first became
Participants in the PLAN after said date were not required or
permitted to name a Beneficiary.
Break in Service: A BREAK IN SERVICE occurs 12 months after the SEVERANCE FROM
- ---------------- SERVICE DATE if during such 12-month period an EMPLOYEE does not
work for an EMPLOYER. Once a Break in Service occurs, it
continues until an EMPLOYEE is reemployed by an EMPLOYER.
Code: CODE shall mean the Internal Revenue CODE of 1986, as amended
- ---- from time to time.
Company: Pacific Gas and Electric Company.
- -------
Consent: The CONSENT by a SPOUSE that is required for a QUALIFIED
- ------- ELECTION. Any such CONSENT shall be effective only with respect
to such SPOUSE. A CONSENT permitting designation by the
PARTICIPANT without further CONSENT from the SPOUSE must
acknowledge that the SPOUSE has the right to limit CONSENT to a
specific BENEFICIARY and also to a specific benefit form, and
that the SPOUSE voluntarily elects to relinquish either or both
of such rights. A revocation of a prior QUALIFIED ELECTION may be
made by a PARTICIPANT without the CONSENT of the SPOUSE at any
time prior to the commencement of benefits. An unlimited number
of revocations shall be permitted. No CONSENT obtained under this
provision shall be valid unless the PARTICIPANT has received
proper
</TABLE>
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<PAGE>
<TABLE>
<S> <C>
NOTICE.
Contributions Plus Interest: The cumulative total of contributions made by a PARTICIPANT to
- --------------------------- the PLAN under Section 13; paragraph (b) of Special Provision F;
and to the COMPANY's Retirement PLAN as it existed before 1969,
plus interest at two percent per year on a PARTICIPANT's
contributions made after 1953, compounded annually to 1976,
together with interest at five percent compounded annually after
1975 on all contributions and previous interest.
Credited Service: See Special Provision F.
- ----------------
Early Retirement Date: See Section 7.
- ---------------------
Early Retirement Pension: See Section 7.
- -------------------------
Employee: An EMPLOYEE of an EMPLOYER who is not covered by a collective
- -------- bargaining agreement. A "leased employee," as defined in Section
414(n) of the CODE, shall not be considered an EMPLOYEE eligible
to become a PARTICIPANT in the PLAN. Notwithstanding any other
provisions in the PLAN, solely for purposes of CODE Section
414(n)(3), the term EMPLOYEE shall, to the extent required by
CODE Section 414, include leased EMPLOYEES.
Employee Benefit The EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE referred to in
Administrative Committee: Section 19.
- ------------------------
The Employee Benefit The EMPLOYEE BENEFIT FINANCE COMMITTEE referred to in Section 18.
Finance Committee:
- -----------------
Employer: Pacific Gas and Electric Company, Pacific Service Employees
- -------- Association, and any other company, association, or credit union
designated by the Board of Directors as eligible to participate
in this PLAN is an EMPLOYER.
Joint Pension: See Section 10.
- -------------
Joint Pensioner: The individual designated by a PARTICIPANT upon the election of a
- --------------- JOINT PENSION who will be entitled upon the PARTICIPANT's death
to receive a PENSION, as explained in Section 10.
Long Term Disability Plan: Part B of the Pacific Gas and Electric Company's Group Life
- ------------------------- Insurance and Long Term Disability Plan.
Marital Pension: See Section 10(b).
- ---------------
Maximum Pension: See Special Provision H.
- ---------------
Normal Retirement Date: The first of the month following the PARTICIPANT's 65th birthday.
- ----------------------
Notice: The NOTICE that is required by this PLAN pursuant to CODE
- ------
</TABLE>
-16-
<PAGE>
<TABLE>
<S> <C>
Section 417 in order to waive the MARITAL PENSION.
In the case of MARITAL PENSION, the PLAN shall provide to each
PARTICIPANT, and to each vested former EMPLOYEE, no less than 30
days and no more than 90 days prior to the annuity starting date
a written explanation of: (i) the terms and conditions of the
MARITAL PENSION, (ii) the right to make and the effect of an
election to waive the MARITAL PENSION, (iii) the rights of the
PARTICIPANT's or the former EMPLOYEE'S SPOUSE, (iv) the right to
make an election to waive the MARITAL PENSION and the effect of
revoking a previous election to waive the MARITAL PENSION, and
(v) the relative values of the various optional forms of benefit
under the PLAN.
Participant: See Section 2.
- -----------
Part-Time Employee: An EMPLOYEE whose regularly scheduled work week is less than 40
- ------------------ hours.
Pension: Retirement income payable under the PLAN.
- -------
Plan: The Company's Retirement Plan as amended, revised and set forth
- ---- herein.
Plan Year: The PLAN YEAR shall be the calendar year which shall also be the
- --------- limitation year for purposes of applying the annual benefit
limitations of CODE Section 415.
Qualified Election: An election qualifying under CODE Section 417(a) to waive either,
- ------------------ or both, of the 50 percent spousal survivor annuities that are
based on the MARITAL PENSION and that are described in Sections
10(b) or 11(b) of the PLAN. Any such waiver shall not be
considered a QUALIFIED ELECTION unless: (a) the PARTICIPANT'S
SPOUSE furnishes a written CONSENT to the election, (b) the
election designates a specific alternate BENEFICIARY, including
any class of BENEFICIARIES or any contingent BENEFICIARIES, which
may not be changed without spousal CONSENT (or the SPOUSE
expressly permits designations by the PARTICIPANT without any
further spousal CONSENT, (c) the SPOUSE'S CONSENT acknowledges
the effect of the election, and (d) the SPOUSE'S CONSENT is
witnessed by a PLAN representative or a notary public. A
PARTICIPANT'S waiver of the survivor annuity will not constitute
a QUALIFIED ELECTION unless the form of benefit payment may not
be changed without spousal CONSENT, or the SPOUSE expressly
permits designations by the PARTICIPANT without any further
spousal CONSENT. If it is established to the satisfaction of the
PLAN representative that such written CONSENT may not be obtained
because there is no SPOUSE or the SPOUSE cannot be located, then
a waiver will be deemed a QUALIFIED ELECTION.
Service: For full-time EMPLOYEES, the period of time commencing with the
- ------- first day of work for an EMPLOYER and ending on PARTICIPANT's
SEVERANCE FROM SERVICE Date. For
</TABLE>
-17-
<PAGE>
<TABLE>
<S> <C>
periods of PART-TIME and intermittent employment, SERVICE for purposes of benefit
accrual is prorated based on the ratio of actual hours worked in the calendar year
to the full-time equivalent (2,080 per calendar year) rounded to the nearest month.
Such proration is applicable for any employment period beginning with initiation of
PART-TIME or intermittent status on or after January 1, 1991, and ending on the
earlier of Participant's return to full time status or the PARTICIPANT'S SEVERANCE
FROM SERVICE DATE. The method of computing SERVICE is described in Section 3.
Severance from Service Date: (i) The date prior to NORMAL RETIREMENT DATE on which an EMPLOYEE quits, retires,
- --------------------------- is discharged or dies, or the ACTUAL RETIREMENT DATE; or
(ii) The first anniversary of the first date of a period in which a PARTICIPANT
remains absent from work for an EMPLOYER for any reason other than a quit,
retirement, discharge, or death.
For the purpose of determining the Severance from SERVICE Date,
the following periods shall not be considered as absences from
work for an EMPLOYER:
(a) Absence on a leave of absence authorized by the EMPLOYER.
(b) Absence because of illness or injury so long as the PARTICIPANT is entitled to
receive sick leave pay or is entitled to receive benefits under the provisions
of the Voluntary Wage Benefit Plan, a state disability plan, Part B of the
Group Life Insurance and Long Term Disability Plan, or a Workers' Compensation
Law.
(c) Absence for military service or service in the Merchant
Marines so long as reemployment rights are protected by law.
(d) Absence caused by layoff for lack of work of less than 12
continuous months for a PARTICIPANT who has less than five years
of SERVICE, or 24 continuous months for a PARTICIPANT who has
five years or more of SERVICE.
Special Joint Pension: See Section 10.
- ---------------------
Spouse: (a) If a PARTICIPANT dies in SERVICE, SPOUSE shall mean the
- ------ PARTICIPANT's wife or husband at the time of the PARTICIPANT's
death.
(b) If a PARTICIPANT dies after ACTUAL RETIREMENT DATE, SPOUSE
shall means the PARTICIPANT's wife or husband at the time of the
PARTICIPANT's Actual Retirement.
</TABLE>
-18-
<PAGE>
<TABLE>
<S> <C>
Spouse's Pension: See Section 11.
- ----------------
</TABLE>
-19-
<PAGE>
SPECIAL PROVISION A
Payment of all PENSIONS to PARTICIPANTS which commenced before January 1,
1969, under the Retirement Plan of the COMPANY, its Past Service Plan, its
Supplemental Benefits and under any applicable retirement plan of a predecessor
company shall continue to be made under the PLAN, without regard to the separate
sources from which such pensions were previously paid.
SPECIAL PROVISION B
EARLY RETIREMENT REDUCTIONS IN PERCENTAGE POINTS
------------------------------------------------
Years Of Service At Early Retirement Date
-----------------------------------------
<TABLE>
<CAPTION>
Age at Less Than 15 But Less 25 But Less 30 Years
Retirement 15 Years Than 25 Years Than 30 Years And Above
- ------------ --------- ------------- ------------- ---------
<S> <C> <C> <C> <C>
64 3 0 0 0
63 6 0 0 0
62 9 0 0 0
61 12 3 3 0
60 15 6 6 0
59 18 10 9 6
58 21 14 12 9
57 24 18 15 12
56 27 22 18 15
55 30 26 21 18
</TABLE>
-20-
<PAGE>
SPECIAL PROVISION C
JOINT PENSION WITH NON-SPOUSE
(Entire Provision Amended 1/1/88)
The amount of non-spouse JOINT PENSION shall be determined by the use of
Actuarial Tables which provide 12%, 16%, 25%, 33-1/3%, 50%, 66-2/3%, 75% and
100% of the JOINT PENSION to a non-spouse JOINT PENSIONER who survives the death
of the PARTICIPANT.
Partial Actuarial Tables of 50% and 100% have been attached.
The following tables illustrate the factors to be applied for typical
options which may be elected for 50% and 100%.
EXAMPLE: Assume the PARTICIPANT is age 62 and elects a 50% or 100% option with
a non-spouse age 50. Also assume that the PARTICIPANT's BASIC PENSION
is $1,000 per month.
<TABLE>
Non- Non- Non-Spouse's Pension
Spouse's Option Basic Reduced Spouse's In Event of
Option Factor Pension Pension Portion Participant's Death
- --------- ------ ------- ------- --------- --------------------
<S> <C> <C> <C> <C> <C>
50% .861 X $1,000. = $861. X .50 = $430.50
100% .756 X $1,000. = $756. X 1.00 = $756.00
</TABLE>
Tables for 12%, 16%, 33-1/3%, 66-2/3%, or 75% are available upon request.
Tables for Beneficiary's Age at Pensioner's Retirement of less than 25 years or
greater than 84 years are also available upon request.
-21-
<PAGE>
<TABLE>
<CAPTION>
SPECIAL PROVISION C
FACTORS TO BE APPLIED TO EMPLOYEE'S RETIREMENT INCOME TO DETERMINE INCOME UNDER CONTINGENT
ANNUITANT OPTION IF 50% OF SUCH INCOME IS CONTINUED TO CONTINGENT ANNUITANT
BENEFICIARY'S BENEFICIARY'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 RETIREMENT
- --------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- -------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
25 .844 .836 .827 .817 .807 .797 .786 .775 .763 .751 .738 .725 .711 .697 .682 .667 25
26 .847 .838 .829 .819 .809 .799 .788 .777 .765 .753 .740 .727 .713 .699 .684 .669 26
27 .849 .840 .831 .821 .811 .801 .790 .779 .767 .755 .742 .729 .715 .701 .686 .671 27
28 .851 .842 .833 .824 .814 .803 .793 .781 .769 .757 .745 .731 .718 .703 .689 .674 28
29 .853 .844 .835 .826 .816 .806 .795 .784 .772 .760 .747 .734 .720 .706 .691 .676 29
30 .855 .847 .838 .828 .818 .808 .797 .786 .774 .762 .750 .736 .723 .708 .694 .679 30
31 .858 .849 .840 .831 .821 .811 .800 .789 .777 .765 .752 .739 .725 .711 .696 .681 31
32 .860 .852 .843 .833 .824 .813 .803 .792 .780 .768 .755 .742 .728 .714 .699 .684 32
33 .863 .854 .846 .836 .826 .816 .806 .794 .783 .771 .758 .745 .731 .717 .702 .687 33
34 .866 .857 .848 .839 .829 .819 .809 .797 .786 .774 .761 .748 .734 .720 .705 .690 34
35 .868 .860 .851 .842 .832 .822 .812 .801 .789 .777 .764 .751 .737 .723 .708 .693 35
36 .871 .863 .854 .845 .835 .825 .815 .804 .792 .780 .768 .754 .741 .727 .712 .697 36
37 .874 .866 .857 .848 .839 .829 .818 .807 .796 .784 .771 .758 .744 .730 .715 .700 37
38 .877 .869 .860 .851 .842 .832 .821 .811 .799 .787 .775 .761 .748 .734 .719 .704 38
39 .880 .872 .864 .855 .845 .835 .825 .814 .803 .791 .778 .765 .752 .737 .723 .708 39
40 .884 .875 .867 .858 .849 .839 .829 .818 .806 .795 .782 .769 .756 .741 .727 .712 40
41 .887 .879 .870 .862 .852 .843 .832 .822 .810 .798 .786 .773 .760 .746 .731 .716 41
42 .890 .882 .874 .865 .856 .846 .836 .826 .814 .803 .790 .777 .764 .750 .735 .720 42
43 .893 .886 .877 .869 .860 .850 .840 .830 .818 .807 .794 .782 .768 .754 .740 .725 43
44 .897 .889 .881 .873 .864 .854 .844 .834 .823 .811 .799 .786 .773 .759 .744 .729 44
45 .900 .893 .885 .876 .868 .858 .848 .838 .827 .816 .803 .791 .777 .764 .749 .734 45
46 .904 .896 .889 .880 .872 .862 .853 .842 .832 .820 .808 .795 .782 .768 .754 .739 46
47 .907 .900 .892 .884 .876 .867 .857 .847 .836 .825 .813 .800 .787 .774 .759 .744 47
48 .911 .904 .896 .888 .880 .871 .861 .851 .841 .830 .818 .805 .792 .779 .764 .750 48
49 .914 .907 .900 .892 .884 .875 .866 .856 .846 .835 .823 .811 .798 .784 .770 .755 49
</TABLE>
-22-
<PAGE>
<TABLE>
<CAPTION>
SPECIAL PROVISION C
FACTORS TO BE APPLIED TO EMPLOYEE'S RETIREMENT INCOME TO DETERMINE INCOME UNDER CONTINGENT
ANNUITANT OPTION IF 50% OF SUCH INCOME IS CONTINUED TO CONTINGENT ANNUITANT
BENEFICIARY'S BENEFICIARY'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 RETIREMENT
- --------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- -------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
50 .918 .911 .904 .896 .888 .880 .870 .861 .850 .840 .828 .816 .803 .790 .775 .761 50
51 .921 .915 .908 .900 .892 .884 .875 .866 .855 .845 .833 .821 .808 .795 .781 .767 51
52 .925 .918 .912 .904 .897 .888 .880 .870 .860 .850 .839 .827 .814 .801 .787 .773 52
53 .928 .922 .916 .908 .901 .893 .884 .875 .865 .855 .844 .832 .820 .807 .793 .779 53
54 .932 .926 .919 .913 .905 .897 .889 .880 .870 .860 .849 .838 .826 .813 .799 .785 54
55 .935 .929 .923 .917 .909 .902 .894 .885 .876 .866 .855 .844 .832 .819 .806 .792 55
56 .938 .933 .927 .921 .914 .906 .898 .890 .881 .871 .861 .849 .838 .825 .812 .798 56
57 .942 .936 .931 .925 .918 .911 .903 .895 .886 .876 .866 .855 .844 .831 .819 .805 57
58 .945 .940 .934 .928 .922 .915 .908 .900 .891 .882 .872 .861 .850 .838 .825 .812 58
59 .948 .943 .938 .932 .926 .920 .912 .905 .896 .887 .878 .867 .856 .844 .832 .819 59
60 .951 .947 .942 .936 .930 .924 .917 .910 .902 .893 .883 .873 .863 .851 .839 .826 60
61 .954 .950 .945 .940 .934 .928 .922 .914 .907 .898 .889 .879 .869 .858 .846 .833 61
62 .957 .953 .948 .944 .938 .932 .926 .919 .912 .904 .895 .885 .875 .864 .853 .840 62
63 .960 .956 .952 .947 .942 .937 .931 .924 .917 .909 .901 .891 .882 .871 .860 .848 63
64 .963 .959 .955 .951 .946 .941 .935 .929 .922 .914 .906 .897 .888 .878 .867 .855 64
65 .965 .962 .958 .954 .949 .944 .939 .933 .927 .920 .912 .903 .894 .884 .874 .862 65
66 .968 .965 .961 .957 .953 .948 .943 .938 .931 .925 .917 .909 .900 .891 .881 .870 66
67 .970 .967 .964 .960 .956 .952 .947 .942 .936 .930 .923 .915 .907 .897 .888 .877 67
68 .972 .970 .967 .963 .960 .955 .951 .946 .940 .934 .928 .920 .913 .904 .894 .884 68
69 .975 .972 .969 .966 .963 .959 .955 .950 .945 .939 .933 .926 .918 .910 .901 .891 69
70 .977 .974 .972 .969 .966 .962 .958 .954 .949 .944 .938 .931 .924 .916 .908 .898 70
71 .979 .976 .974 .971 .968 .965 .961 .957 .953 .948 .942 .936 .930 .922 .914 .905 71
72 .980 .978 .976 .974 .971 .968 .965 .961 .957 .952 .947 .941 .935 .928 .920 .912 72
73 .982 .980 .978 .976 .973 .971 .968 .964 .960 .956 .951 .946 .940 .933 .926 .918 73
74 .984 .982 .980 .978 .976 .973 .970 .967 .964 .960 .955 .950 .945 .939 .932 .925 74
</TABLE>
-23-
<PAGE>
<TABLE>
<CAPTION>
SPECIAL PROVISION C
FACTORS TO BE APPLIED TO EMPLOYEE'S RETIREMENT INCOME TO DETERMINE INCOME UNDER CONTINGENT
ANNUITANT OPTION IF 50% OF SUCH INCOME IS CONTINUED TO CONTINGENT ANNUITANT
BENEFICIARY'S BENEFICIARY'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 RETIREMENT
- --------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- -------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
75 .985 .984 .982 .980 .978 .976 .973 .970 .967 .963 .959 .954 .949 .944 .937 .931 75
76 .987 .985 .984 .982 .980 .978 .976 .973 .970 .966 .963 .958 .954 .948 .943 .936 76
77 .988 .987 .985 .984 .982 .980 .978 .975 .973 .970 .966 .962 .958 .953 .948 .942 77
78 .989 .988 .987 .985 .984 .982 .980 .978 .975 .972 .969 .966 .962 .957 .952 .947 78
79 .990 .989 .988 .987 .985 .984 .982 .980 .978 .975 .972 .969 .965 .961 .957 .952 79
80 .991 .990 .989 .988 .987 .985 .984 .982 .980 .978 .975 .972 .969 .965 .961 .956 80
81 .992 .991 .990 .989 .988 .987 .986 .984 .982 .980 .978 .975 .972 .969 .965 .961 81
82 .993 .992 .991 .991 .990 .988 .987 .986 .984 .982 .980 .978 .975 .972 .968 .964 82
83 .994 .993 .992 .992 .991 .990 .989 .987 .986 .984 .982 .980 .978 .975 .972 .968 83
84 .995 .994 .993 .993 .992 .991 .990 .989 .987 .986 .984 .982 .980 .978 .975 .972 84
</TABLE>
-24-
<PAGE>
<TABLE>
<CAPTION>
SPECIAL PROVISION C
FACTORS TO BE APPLIED TO EMPLOYEE'S RETIREMENT INCOME TO DETERMINE INCOME UNDER CONTINGENT
ANNUITANT OPTION IF 50% OF SUCH INCOME IS CONTINUED TO CONTINGENT ANNUITANT
BENEFICIARY'S BENEFICIARY'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 70 71 72 73 74 75 76 77 78 79 80 81 82 83 84 85 RETIREMENT
- --------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- -------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
25 .667 .652 .636 .620 .603 .586 .569 .551 .533 .515 .497 .479 .461 .442 .424 .406 25
26 .669 .654 .638 .622 .605 .588 .571 .553 .535 .517 .499 .481 .462 .444 .426 .407 26
27 .671 .656 .640 .624 .607 .590 .573 .555 .537 .519 .501 .483 .464 .446 .427 .409 27
28 .674 .658 .642 .626 .609 .592 .575 .557 .539 .521 .503 .485 .466 .448 .429 .411 28
29 .676 .661 .645 .628 .612 .595 .577 .560 .542 .524 .505 .487 .468 .450 .431 .413 29
30 .679 .663 .647 .631 .614 .597 .580 .562 .544 .526 .507 .489 .470 .452 .433 .414 30
31 .681 .666 .650 .633 .617 .600 .582 .564 .546 .528 .510 .491 .473 .454 .435 .417 31
32 .684 .669 .653 .636 .619 .602 .585 .567 .549 .531 .512 .494 .475 .456 .437 .419 32
33 .687 .671 .655 .639 .622 .605 .588 .570 .552 .533 .515 .496 .477 .459 .440 .421 33
34 .690 .675 .659 .642 .625 .608 .591 .573 .555 .536 .518 .499 .480 .461 .442 .423 34
35 .693 .678 .662 .645 .628 .611 .594 .576 .558 .539 .520 .502 .483 .464 .445 .426 35
36 .697 .681 .665 .649 .632 .614 .597 .579 .561 .542 .524 .505 .486 .467 .448 .429 36
37 .700 .685 .669 .652 .635 .618 .600 .582 .564 .545 .527 .508 .489 .470 .451 .431 37
38 .704 .688 .672 .656 .639 .621 .604 .586 .567 .549 .530 .511 .492 .473 .454 .434 38
39 .708 .692 .676 .659 .643 .625 .607 .589 .571 .552 .534 .515 .495 .476 .457 .438 39
40 .712 .696 .680 .663 .647 .629 .611 .593 .575 .556 .537 .518 .499 .480 .460 .441 40
41 .716 .700 .684 .668 .651 .633 .616 .597 .579 .560 .541 .522 .503 .483 .464 .444 41
42 .720 .705 .689 .672 .655 .638 .620 .602 .583 .564 .545 .526 .507 .487 .468 .448 42
43 .725 .709 .693 .677 .660 .642 .624 .606 .588 .569 .550 .530 .511 .491 .472 .452 43
44 .729 .714 .698 .681 .664 .647 .629 .611 .592 .573 .554 .535 .515 .495 .476 .456 44
45 .734 .719 .703 .686 .669 .652 .634 .616 .597 .578 .559 .539 .520 .500 .480 .460 45
46 .739 .724 .708 .691 .674 .657 .639 .621 .602 .583 .564 .544 .524 .505 .485 .465 46
47 .744 .729 .713 .697 .680 .662 .644 .626 .607 .588 .569 .549 .529 .509 .489 .469 47
48 .750 .734 .718 .702 .685 .668 .650 .631 .613 .594 .574 .554 .535 .515 .494 .474 48
49 .755 .740 .724 .708 .691 .673 .655 .637 .618 .599 .580 .560 .540 .520 .500 .479 49
</TABLE>
-25-
<PAGE>
<TABLE>
<CAPTION>
SPECIAL PROVISION C
FACTORS TO BE APPLIED TO EMPLOYEE'S RETIREMENT INCOME TO DETERMINE INCOME UNDER CONTINGENT
ANNUITANT OPTION IF 50% OF SUCH INCOME IS CONTINUED TO CONTINGENT ANNUITANT
BENEFICIARY'S BENEFICIARY'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 70 71 72 73 74 75 76 77 78 79 80 81 82 83 84 85 RETIREMENT
- --------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- -------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
50 .761 .746 .730 .713 .697 .679 .661 .643 .624 .605 .585 .566 .546 .525 .505 .485 50
51 .767 .752 .736 .720 .703 .685 .667 .649 .630 .611 .591 .572 .551 .531 .511 .490 51
52 .773 .758 .742 .726 .709 .692 .674 .655 .637 .617 .598 .578 .558 .537 .517 .496 52
53 .779 .764 .748 .732 .715 .698 .680 .662 .643 .624 .604 .584 .564 .543 .523 .502 53
54 .785 .770 .755 .739 .722 .705 .687 .669 .650 .631 .611 .591 .571 .550 .529 .508 54
55 .792 .777 .762 .746 .729 .712 .694 .676 .657 .638 .618 .598 .578 .557 .536 .515 55
56 .798 .784 .768 .753 .736 .719 .701 .683 .664 .645 .625 .605 .585 .564 .543 .522 56
57 .805 .790 .775 .760 .743 .726 .709 .691 .672 .653 .633 .613 .592 .571 .550 .529 57
58 .812 .798 .783 .767 .751 .734 .717 .699 .680 .661 .641 .621 .600 .579 .558 .537 58
59 .819 .805 .790 .775 .759 .742 .725 .707 .688 .669 .649 .629 .608 .587 .566 .545 59
60 .826 .812 .798 .783 .767 .750 .733 .715 .696 .677 .658 .638 .617 .596 .575 .553 60
61 .833 .820 .805 .790 .775 .758 .741 .724 .705 .686 .667 .646 .626 .605 .584 .562 61
62 .840 .827 .813 .799 .783 .767 .750 .733 .714 .695 .676 .656 .635 .614 .593 .571 62
63 .848 .835 .821 .807 .792 .776 .759 .742 .724 .705 .685 .665 .645 .624 .602 .581 63
64 .855 .843 .829 .815 .800 .785 .768 .751 .733 .715 .695 .675 .655 .634 .612 .591 64
65 .862 .850 .837 .824 .809 .794 .778 .761 .743 .725 .705 .686 .665 .644 .623 .601 65
66 .870 .858 .845 .832 .818 .803 .787 .770 .753 .735 .716 .696 .676 .655 .634 .612 66
67 .877 .866 .854 .841 .827 .812 .797 .780 .763 .745 .727 .707 .687 .666 .645 .623 67
68 .884 .873 .862 .849 .836 .821 .806 .790 .774 .756 .738 .718 .698 .678 .657 .635 68
69 .891 .881 .870 .858 .845 .831 .816 .801 .784 .767 .749 .730 .710 .690 .668 .647 69
70 .898 .888 .878 .866 .853 .840 .826 .811 .795 .778 .760 .741 .722 .702 .681 .659 70
71 .905 .896 .885 .874 .862 .849 .836 .821 .805 .789 .771 .753 .734 .714 .693 .672 71
72 .912 .903 .893 .882 .871 .859 .845 .831 .816 .800 .783 .765 .746 .727 .706 .685 72
73 .918 .910 .900 .890 .879 .868 .855 .841 .826 .811 .794 .777 .759 .739 .719 .698 73
74 .925 .917 .908 .898 .888 .876 .864 .851 .837 .822 .806 .789 .771 .752 .732 .712 74
</TABLE>
-26-
<PAGE>
<TABLE>
<CAPTION>
SPECIAL PROVISION C
FACTORS TO BE APPLIED TO EMPLOYEE'S RETIREMENT INCOME TO DETERMINE INCOME UNDER CONTINGENT
ANNUITANT OPTION IF 50% OF SUCH INCOME IS CONTINUED TO CONTINGENT ANNUITANT
BENEFICIARY'S BENEFICIARY'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 70 71 72 73 74 75 76 77 78 79 80 81 82 83 84 85 RETIREMENT
- --------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- -------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
75 .931 .923 .915 .906 .896 .885 .873 .861 .847 .833 .817 .801 .784 .765 .746 .726 75
76 .936 .929 .921 .913 .904 .893 .882 .870 .858 .844 .829 .813 .796 .778 .759 .740 76
77 .942 .935 .928 .920 .911 .902 .891 .880 .868 .854 .840 .825 .808 .791 .773 .754 77
78 .947 .941 .934 .927 .918 .909 .900 .889 .877 .865 .851 .836 .821 .804 .786 .768 78
79 .952 .946 .940 .933 .925 .917 .908 .898 .887 .875 .862 .848 .833 .817 .800 .782 79
80 .956 .951 .945 .939 .932 .924 .916 .906 .896 .885 .872 .859 .845 .829 .813 .795 80
81 .961 .956 .951 .945 .938 .931 .923 .914 .905 .894 .883 .870 .856 .842 .826 .809 81
82 .964 .960 .955 .950 .944 .937 .930 .922 .913 .903 .892 .881 .868 .854 .839 .823 82
83 .968 .964 .960 .955 .950 .943 .937 .929 .921 .912 .902 .891 .879 .866 .851 .836 83
84 .972 .968 .964 .960 .955 .949 .943 .936 .928 .920 .911 .900 .889 .877 .863 .849 84
</TABLE>
-27-
<PAGE>
<TABLE>
<CAPTION>
SPECIAL PROVISION C
FACTORS TO BE APPLIED TO EMPLOYEE'S RETIREMENT INCOME TO DETERMINE INCOME UNDER CONTINGENT
ANNUITANT OPTION IF 100% OF SUCH INCOME IS CONTINUED TO CONTINGENT ANNUITANT
BENEFICIARY'S BENEFICIARY'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 RETIREMENT
- --------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- -------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
25 .731 .718 .704 .691 .676 .662 .647 .632 .617 .601 .585 .568 .551 .535 .518 .500 25
26 .734 .721 .707 .694 .679 .665 .650 .635 .619 .603 .587 .571 .554 .537 .520 .503 26
27 .737 .724 .710 .697 .683 .668 .653 .638 .622 .606 .590 .574 .557 .540 .523 .505 27
28 .740 .727 .714 .700 .686 .671 .656 .641 .625 .609 .593 .576 .560 .543 .525 .508 28
29 .744 .731 .717 .703 .689 .675 .660 .644 .629 .613 .596 .580 .563 .545 .528 .511 29
30 .747 .734 .721 .707 .693 .678 .663 .648 .632 .616 .599 .583 .566 .549 .531 .514 30
31 .751 .738 .725 .711 .696 .682 .667 .651 .636 .619 .603 .586 .569 .552 .534 .517 31
32 .755 .742 .728 .715 .700 .686 .671 .655 .639 .623 .607 .590 .573 .555 .538 .520 32
33 .759 .746 .732 .719 .704 .690 .675 .659 .643 .627 .610 .593 .576 .559 .541 .523 33
34 .763 .750 .737 .723 .708 .694 .679 .663 .647 .631 .614 .597 .580 .562 .545 .527 34
35 .768 .754 .741 .727 .713 .698 .683 .667 .651 .635 .618 .601 .584 .566 .549 .531 35
36 .772 .759 .746 .732 .717 .703 .687 .672 .656 .639 .623 .606 .588 .570 .553 .535 36
37 .777 .764 .750 .736 .722 .707 .692 .677 .661 .644 .627 .610 .593 .575 .557 .539 37
38 .781 .768 .755 .741 .727 .712 .697 .681 .665 .649 .632 .615 .597 .579 .561 .543 38
39 .786 .773 .760 .746 .732 .717 .702 .687 .670 .654 .637 .620 .602 .584 .566 .548 39
40 .791 .779 .765 .751 .737 .723 .707 .692 .676 .659 .642 .625 .607 .589 .571 .552 40
41 .797 .784 .771 .757 .743 .728 .713 .697 .681 .665 .648 .630 .612 .594 .576 .557 41
42 .802 .789 .776 .762 .748 .734 .719 .703 .687 .670 .653 .636 .618 .600 .581 .563 42
43 .807 .795 .782 .768 .754 .740 .724 .709 .693 .676 .659 .642 .624 .605 .587 .568 43
44 .813 .800 .788 .774 .760 .746 .731 .715 .699 .682 .665 .648 .630 .611 .593 .574 44
45 .819 .806 .793 .780 .766 .752 .737 .721 .705 .689 .671 .654 .636 .618 .599 .580 45
46 .824 .812 .799 .786 .773 .758 .743 .728 .712 .695 .678 .660 .642 .624 .605 .586 46
47 .830 .818 .806 .793 .779 .765 .750 .734 .718 .702 .685 .667 .649 .631 .612 .593 47
48 .836 .824 .812 .799 .785 .771 .757 .741 .725 .709 .692 .674 .656 .638 .619 .600 48
49 .842 .830 .818 .805 .792 .778 .764 .748 .732 .716 .699 .681 .663 .645 .626 .607 49
</TABLE>
-28-
<PAGE>
<TABLE>
<CAPTION>
SPECIAL PROVISION C
FACTORS TO BE APPLIED TO EMPLOYEE'S RETIREMENT INCOME TO DETERMINE INCOME UNDER CONTINGENT
ANNUITANT OPTION IF 100% OF SUCH INCOME IS CONTINUED TO CONTINGENT ANNUITANT
BENEFICIARY'S BENEFICIARY'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 RETIREMENT
- --------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- -------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
50 .848 .837 .825 .812 .799 .785 .771 .756 .740 .723 .706 .689 .671 .652 .633 .614 50
51 .854 .843 .831 .819 .806 .792 .778 .763 .747 .731 .714 .697 .679 .660 .641 .622 51
52 .860 .849 .838 .826 .813 .799 .785 .770 .755 .739 .722 .705 .687 .668 .649 .630 52
53 .866 .855 .844 .832 .820 .807 .793 .778 .763 .747 .730 .713 .695 .676 .657 .638 53
54 .872 .862 .851 .839 .827 .814 .800 .786 .771 .755 .738 .721 .703 .685 .666 .646 54
55 .878 .868 .857 .846 .834 .821 .808 .794 .779 .763 .747 .730 .712 .693 .674 .655 55
56 .884 .874 .864 .853 .841 .829 .816 .802 .787 .771 .755 .738 .721 .702 .683 .664 56
57 .890 .880 .870 .860 .848 .836 .823 .810 .795 .780 .764 .747 .730 .712 .693 .673 57
58 .895 .886 .877 .866 .855 .844 .831 .818 .804 .789 .773 .756 .739 .721 .702 .683 58
59 .901 .893 .883 .873 .863 .851 .839 .826 .812 .798 .782 .766 .749 .731 .712 .693 59
60 .907 .898 .890 .880 .870 .859 .847 .834 .821 .806 .791 .775 .758 .741 .722 .703 60
61 .912 .904 .896 .887 .877 .866 .855 .842 .829 .815 .800 .785 .768 .751 .733 .714 61
62 .918 .910 .902 .893 .884 .873 .862 .851 .838 .824 .810 .794 .778 .761 .743 .725 62
63 .923 .916 .908 .900 .890 .881 .870 .859 .846 .833 .819 .804 .788 .772 .754 .736 63
64 .928 .921 .914 .906 .897 .888 .878 .867 .855 .842 .829 .814 .799 .782 .765 .747 64
65 .933 .926 .919 .912 .904 .895 .885 .875 .863 .851 .838 .824 .809 .793 .776 .758 65
66 .937 .931 .925 .918 .910 .902 .892 .882 .872 .860 .847 .833 .819 .803 .787 .770 66
67 .942 .936 .930 .924 .916 .908 .900 .890 .880 .868 .856 .843 .829 .814 .798 .781 67
68 .946 .941 .935 .929 .922 .915 .906 .897 .888 .877 .865 .853 .839 .825 .809 .793 68
69 .950 .946 .940 .934 .928 .921 .913 .905 .895 .885 .874 .862 .849 .835 .820 .804 69
70 .954 .950 .945 .939 .933 .927 .920 .912 .903 .893 .883 .871 .859 .845 .831 .816 70
71 .958 .954 .949 .944 .939 .932 .926 .918 .910 .901 .891 .880 .868 .855 .842 .827 71
72 .962 .958 .953 .949 .944 .938 .932 .925 .917 .908 .899 .889 .878 .865 .852 .838 72
73 .965 .961 .957 .953 .948 .943 .937 .931 .923 .916 .907 .897 .887 .875 .863 .849 73
74 .968 .965 .961 .957 .953 .948 .942 .936 .930 .922 .914 .905 .895 .884 .873 .860 74
</TABLE>
-29-
<PAGE>
<TABLE>
<CAPTION>
SPECIAL PROVISION C
FACTORS TO BE APPLIED TO EMPLOYEE'S RETIREMENT INCOME TO DETERMINE INCOME UNDER CONTINGENT
ANNUITANT OPTION IF 100% OF SUCH INCOME IS CONTINUED TO CONTINGENT ANNUITANT
BENEFICIARY'S BENEFICIARY'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 RETIREMENT
- --------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- -------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
75 .971 .968 .965 .961 .957 .952 .948 .942 .936 .929 .921 .913 .904 .893 .882 .870 75
76 .974 .971 .968 .965 .961 .957 .952 .947 .941 .935 .928 .920 .912 .902 .892 .880 76
77 .976 .974 .971 .968 .965 .961 .957 .952 .947 .941 .934 .927 .919 .910 .900 .890 77
78 .979 .976 .974 .971 .968 .965 .961 .957 .952 .946 .940 .934 .926 .918 .909 .899 78
79 .981 .979 .976 .974 .971 .968 .965 .961 .956 .952 .946 .940 .933 .926 .917 .908 79
80 .983 .981 .979 .977 .974 .971 .968 .965 .961 .956 .951 .946 .939 .932 .925 .916 80
81 .985 .983 .981 .979 .977 .974 .971 .968 .965 .961 .956 .951 .945 .939 .932 .924 81
82 .986 .985 .983 .981 .979 .977 .975 .972 .968 .965 .961 .956 .951 .945 .939 .931 82
83 .988 .986 .985 .983 .982 .980 .977 .975 .972 .969 .965 .961 .956 .951 .945 .938 83
84 .989 .988 .987 .985 .984 .982 .980 .978 .975 .972 .969 .965 .961 .958 .951 .945 84
</TABLE>
-30-
<PAGE>
<TABLE>
<CAPTION>
SPECIAL PROVISION C
FACTORS TO BE APPLIED TO EMPLOYEE'S RETIREMENT INCOME TO DETERMINE INCOME UNDER CONTINGENT
ANNUITANT OPTION IF 100% OF SUCH INCOME IS CONTINUED TO CONTINGENT ANNUITANT
BENEFICIARY'S BENEFICIARY'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 70 71 72 73 74 75 76 77 78 79 80 81 82 83 84 85 RETIREMENT
- --------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- -------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
25 .500 .483 .466 .449 .432 .414 .397 .380 .364 .347 .331 .315 .299 .284 .269 .254 25
26 .503 .486 .468 .451 .434 .416 .399 .382 .365 .349 .333 .316 .301 .285 .270 .256 26
27 .505 .488 .471 .453 .436 .419 .401 .384 .367 .351 .334 .318 .302 .287 .272 .257 27
28 .508 .491 .473 .456 .438 .421 .403 .386 .369 .353 .336 .320 .304 .288 .273 .258 28
29 .511 .493 .476 .458 .441 .423 .406 .388 .371 .355 .338 .322 .306 .290 .275 .260 29
30 .514 .496 .478 .461 .443 .426 .408 .391 .374 .357 .340 .324 .307 .292 .276 .261 30
31 .517 .499 .481 .464 .446 .428 .411 .393 .376 .359 .342 .326 .309 .294 .278 .263 31
32 .520 .502 .484 .466 .449 .431 .413 .396 .378 .361 .344 .328 .311 .295 .280 .265 32
33 .523 .505 .488 .470 .452 .434 .416 .398 .381 .364 .347 .330 .314 .298 .282 .267 33
34 .527 .509 .491 .473 .455 .437 .419 .401 .384 .366 .349 .332 .316 .300 .284 .269 34
35 .531 .513 .494 .476 .458 .440 .422 .404 .387 .369 .352 .335 .318 .302 .286 .271 35
36 .535 .516 .498 .480 .462 .443 .425 .407 .390 .372 .355 .337 .321 .304 .288 .273 36
37 .539 .520 .502 .484 .465 .447 .429 .411 .393 .375 .357 .340 .323 .307 .291 .275 37
38 .543 .525 .506 .488 .469 .451 .432 .414 .396 .378 .361 .343 .326 .310 .293 .277 38
39 .548 .529 .511 .492 .473 .455 .436 .418 .400 .382 .364 .346 .329 .312 .296 .280 39
40 .552 .534 .515 .496 .478 .459 .440 .422 .403 .385 .367 .350 .332 .315 .299 .283 40
41 .557 .539 .520 .501 .482 .463 .445 .426 .407 .389 .371 .353 .336 .319 .302 .286 41
42 .563 .544 .525 .506 .487 .468 .449 .430 .412 .393 .375 .357 .339 .322 .305 .289 42
43 .568 .549 .530 .511 .492 .473 .454 .435 .416 .397 .379 .361 .343 .326 .309 .292 43
44 .574 .555 .536 .517 .497 .478 .459 .440 .421 .402 .383 .365 .347 .329 .312 .295 44
45 .580 .561 .542 .522 .503 .483 .464 .445 .425 .406 .388 .369 .351 .333 .316 .299 45
46 .586 .567 .548 .528 .509 .489 .469 .450 .431 .411 .392 .374 .355 .337 .320 .303 46
47 .593 .573 .554 .534 .515 .495 .475 .455 .436 .417 .397 .379 .360 .342 .324 .307 47
48 .600 .580 .561 .541 .521 .501 .481 .461 .442 .422 .403 .384 .365 .346 .328 .311 48
49 .607 .587 .567 .548 .528 .507 .487 .467 .447 .428 .408 .389 .370 .351 .333 .315 49
</TABLE>
-31-
<PAGE>
<TABLE>
<CAPTION>
SPECIAL PROVISION C
FACTORS TO BE APPLIED TO EMPLOYEE'S RETIREMENT INCOME TO DETERMINE INCOME UNDER CONTINGENT
ANNUITANT OPTION IF 100% OF SUCH INCOME IS CONTINUED TO CONTINGENT ANNUITANT
BENEFICIARY'S BENEFICIARY'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 70 71 72 73 74 75 76 77 78 79 80 81 82 83 84 85 RETIREMENT
- --------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- -------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
50 .614 .594 .575 .555 .534 .514 .494 .474 .454 .434 .414 .394 .375 .356 .338 .320 50
51 .622 .602 .582 .562 .542 .521 .501 .480 .460 .440 .420 .400 .381 .362 .343 .325 51
52 .630 .610 .590 .570 .549 .529 .508 .487 .467 .446 .426 .406 .387 .367 .348 .330 52
53 .638 .618 .598 .577 .557 .536 .515 .495 .474 .453 .433 .413 .393 .373 .354 .335 53
54 .646 .626 .606 .586 .565 .544 .523 .502 .481 .461 .440 .419 .399 .379 .360 .341 54
55 .655 .635 .615 .594 .574 .553 .532 .510 .489 .468 .447 .426 .406 .386 .366 .347 55
56 .664 .644 .624 .603 .582 .561 .540 .519 .497 .476 .455 .434 .413 .393 .373 .353 56
57 .673 .654 .633 .613 .592 .570 .549 .528 .506 .484 .463 .442 .421 .400 .380 .360 57
58 .683 .663 .643 .622 .601 .580 .558 .537 .515 .493 .472 .450 .429 .408 .387 .367 58
59 .693 .673 .653 .632 .611 .590 .568 .546 .524 .502 .481 .459 .437 .416 .395 .374 59
60 .703 .684 .663 .643 .622 .600 .578 .556 .534 .512 .490 .468 .446 .424 .403 .382 60
61 .714 .694 .674 .654 .632 .611 .589 .567 .545 .522 .500 .478 .455 .434 .412 .391 61
62 .725 .705 .685 .665 .644 .622 .600 .578 .556 .533 .510 .488 .465 .443 .421 .400 62
63 .736 .716 .697 .676 .655 .634 .612 .589 .567 .644 .521 .499 .476 .453 .431 .409 63
64 .747 .728 .708 .688 .667 .646 .624 .601 .579 .556 .533 .510 .487 .464 .441 .419 64
65 .758 .740 .720 .700 .679 .658 .636 .614 .591 .568 .545 .522 .498 .475 .452 .430 65
66 .770 .751 .732 .712 .692 .671 .649 .627 .604 .581 .557 .534 .511 .487 .464 .441 66
67 .781 .763 .745 .725 .705 .684 .662 .640 .617 .594 .571 .547 .523 .500 .476 .453 67
68 .793 .775 .757 .738 .718 .697 .676 .653 .631 .608 .584 .560 .537 .513 .489 .465 68
69 .804 .787 .769 .751 .731 .711 .689 .667 .645 .622 .598 .574 .550 .526 .502 .478 69
70 .816 .799 .782 .764 .744 .724 .703 .682 .659 .636 .613 .589 .565 .540 .516 .492 70
71 .827 .811 .794 .777 .758 .738 .718 .696 .674 .651 .628 .604 .580 .555 .531 .506 71
72 .838 .823 .807 .790 .771 .752 .732 .711 .689 .666 .643 .619 .595 .571 .546 .521 72
73 .849 .835 .819 .802 .785 .766 .746 .726 .704 .682 .659 .635 .611 .586 .562 .536 73
74 .860 .846 .831 .815 .798 .780 .761 .741 .720 .698 .675 .651 .627 .603 .578 .553 74
</TABLE>
-32-
<PAGE>
<TABLE>
<CAPTION>
SPECIAL PROVISION C
FACTORS TO BE APPLIED TO EMPLOYEE'S RETIREMENT INCOME TO DETERMINE INCOME UNDER CONTINGENT
ANNUITANT OPTION IF 100% OFSUCH INCOME IS CONTINUED TO CONTINGENT ANNUITANT
BENEFICIARY'S BENEFICIARY'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 70 71 72 73 74 75 76 77 78 79 80 81 82 83 84 85 RETIREMENT
- --------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- -------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
75 .870 .857 .843 .828 .811 .794 .775 .756 .735 .714 .691 .668 .644 .620 .595 .569 75
76 .880 .868 .854 .840 .824 .807 .790 .771 .751 .730 .708 .685 .661 .637 .612 .587 76
77 .890 .878 .865 .852 .837 .821 .804 .785 .766 .746 .724 .702 .679 .654 .630 .605 77
78 .899 .888 .876 .863 .849 .834 .818 .800 .781 .762 .741 .719 .696 .672 .648 .623 78
79 .908 .898 .886 .874 .861 .847 .831 .814 .797 .778 .757 .736 .714 .690 .666 .641 79
80 .916 .907 .896 .885 .873 .859 .844 .828 .811 .793 .774 .753 .731 .709 .685 .660 80
81 .924 .915 .906 .895 .884 .871 .857 .842 .826 .808 .790 .770 .749 .727 .704 .680 81
82 .931 .923 .915 .905 .894 .882 .869 .855 .840 .823 .806 .787 .766 .745 .723 .699 82
83 .938 .931 .923 .914 .904 .893 .881 .868 .853 .838 .821 .803 .784 .763 .741 .718 83
84 .945 .938 .931 .922 .913 .903 .892 .880 .866 .852 .836 .819 .800 .781 .760 .738 84
</TABLE>
-33-
<PAGE>
SPECIAL PROVISION D
MARITAL PENSIONS, JOINT PENSIONS WITH SPOUSES AND
SPECIAL JOINT PENSIONS WITH SPOUSES
MARITAL PENSIONS and JOINT PENSIONS with SPOUSES shall be determined by
multiplying factors calculated in accordance with the 1951 Male Group Annuity
Table at 5% interest, with the following modifications:
(i) PARTICIPANT's mortality rates shall be determined by adding 41% of the
rates at PARTICIPANT's ages to 59% of the rates at ages five years lower.
(ii) SPOUSE's mortality rates shall be determined by adding 59% of the rates at
SPOUSE's ages to 41% of the rates at ages five years lower.
(iii) For MARITAL PENSIONS, the factors shall be calculated taking into account
only one-half of the costs of the benefits to surviving SPOUSES.
(iv) When the proportions of the JOINT PENSIONS to be continued to SPOUSES
exceed 50%, the factors shall be calculated in such a way that the values
of such JOINT PENSIONS are equal to the values of corresponding MARITAL
PENSION.
(v) When the proportions of the JOINT PENSIONS to be continued to SPOUSES are
less than 50%, the factors shall be calculated taking into account only
one-half of the costs to surviving SPOUSES.
(vi) Whenever a factor calculated for a MARITAL or JOINT PENSION with SPOUSE is
smaller than the corresponding factor for a non- spouse JOINT PENSION, the
non-spouse JOINT PENSION factor shall be substituted for the calculated
factor.
The following tables illustrate the factors to be applied for typical
options which may be elected between 25% and 100%.
EXAMPLE: Assume the PARTICIPANT is age 62 and Spouse age 60. Also assume that
the PARTICIPANT's BASIC PENSION is $1,000 per month.
<TABLE>
<CAPTION> Spouse's Pension
Spouse's Option Basic Reduced Spouse's In Event of
Option Factor Pension Pension Portion Participant's Death
- --------- ------ -------- -------- -------- --------------------
<S> <C> <C> <C> <C> <C>
25% .976 X $1,000. = $976. X .25 = $244.00
50% .955 X $1,000. = $955. X .50 = $477.50
75% .914 X $1,000. = $914. X .75 = $685.50
100% .876 X $1,000. = $876. X 1.00 = $876.00
</TABLE>
SPECIAL JOINT PENSIONS with SPOUSES shall be determined using the same
actuarial assumptions described above and are illustrated in the tables
following the JOINT PENSION tables.
-34-
<PAGE>
SPECIAL PROVISION D
FACTORS USED TO DETERMINE THE REDUCED ANNUAL RATE
OF RETIREMENT ANNUITY PAYABLE TO JOINT PENSIONERS
WHO ELECT VARIOUS OPTIONS WITH THEIR ELIGIBLE SPOUSE
25% OPTION ELECTION
-------------------
<TABLE>
<CAPTION>
SPOUSE'S SPOUSE'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 RETIREMENT
- ------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ----- ---- ---- -----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
40 .969 .967 .964 .962 .959 .956 .953 .950 .946 .943 .939 .935 .930 .926 .921 .916 40
41 .970 .968 .965 .963 .960 .957 .954 .951 .948 .944 .940 .936 .932 .927 .922 .917 41
42 .971 .969 .966 .964 .961 .958 .955 .952 .949 .945 .941 .937 .933 .929 .924 .919 42
43 .972 .970 .967 .965 .962 .960 .957 .953 .950 .947 .943 .939 .934 .930 .925 .920 43
44 .973 .971 .968 .966 .963 .961 .958 .955 .951 .948 .944 .940 .936 .931 .927 .922 44
45 .974 .972 .969 .967 .965 .962 .959 .956 .953 .949 .946 .942 .937 .933 .928 .923 45
46 .975 .973 .970 .968 .966 .963 .960 .957 .954 .951 .947 .943 .939 .935 .930 .925 46
47 .976 .974 .972 .969 .967 .964 .962 .959 .955 .952 .948 .945 .940 .936 .932 .927 47
48 .977 .975 .973 .970 .968 .966 .963 .960 .957 .953 .950 .946 .942 .938 .933 .928 48
49 .978 .976 .974 .972 .969 .967 .964 .961 .958 .955 .951 .948 .944 .939 .935 .930 49
50 .979 .977 .975 .973 .970 .968 .965 .963 .960 .956 .953 .949 .945 .941 .937 .932 50
51 .980 .978 .976 .974 .972 .969 .967 .964 .961 .958 .955 .951 .947 .943 .939 .934 51
52 .980 .979 .977 .975 .973 .970 .968 .965 .962 .959 .956 .953 .949 .945 .940 .936 52
53 .981 .980 .978 .976 .974 .972 .969 .967 .964 .961 .958 .954 .951 .947 .942 .938 53
54 .982 .981 .979 .977 .975 .973 .971 .968 .965 .962 .959 .956 .952 .948 .944 .940 54
55 .983 .982 .980 .978 .976 .974 .972 .969 .967 .964 .961 .958 .954 .950 .946 .942 55
56 .984 .983 .981 .979 .977 .975 .973 .971 .968 .966 .963 .959 .956 .952. .948 .944 56
57 .985 .984 .982 .980 .979 .977 .975 .972 .970 .967 .964 .961 .958 .954 .950 .946 57
58 .986 .984 .983 .981 .980 .978 .976 .974 .971 .969 .966 .963 .959 .956 .952 .948 58
59 .987 .985 .984 .982 .981 .979 .977 .975 .973 .970 .967 .964 .961 .958 .954 .950 59
</TABLE>
NOTE: Factors for additional age combinations are available from the
Administrator.
-35-
<PAGE>
SPECIAL PROVISION D
FACTORS USED TO DETERMINE THE REDUCED ANNUAL RATE
OF RETIREMENT ANNUITY PAYABLE TO JOINT PENSIONERS
WHO ELECT VARIOUS OPTIONS WITH THEIR ELIGIBLE SPOUSE
25% OPTION ELECTION
-------------------
(Continued)
<TABLE>
<CAPTION>
SPOUSE'S SPOUSE'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 RETIREMENT
- ------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- -----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
60 .987 .986 .985 .984 .982 .980 .978 .976 .974 .972 .969 .966 .963 .960 .956 .952 60
61 .988 .987 .986 .985 .983 .981 .980 .978 .976 .973 .971 .968 .965 .962 .958 .954 61
62 .989 .988 .987 .985 .984 .983 .981 .979 .977 .975 .972 .970 .967 .964 .960 .957 62
63 .990 .989 .988 .986 .985 .984 .982 .980 .978 .976 .974 .971 .969 .966 .962 .959 63
64 .990 .990 .988 .987 .986 .985 .983 .981 .980 .978 .975 .973 .970 .967 .964 .961 64
65 .991 .990 .989 .988 .987 .986 .984 .983 .981 .979 .977 .975 .972 .969 .966 .963 65
66 .992 .991 .990 .989 .988 .987 .985 .984 .982 .980 .978 .976 .974 .971 .968 .965 66
67 .992 .992 .991 .990 .989 .988 .986 .985 .983 .982 .980 .978 .975 .973 .970 .967 67
68 .993 .992 .992 .991 .990 .989 .987 .986 .985 .983 .981 .979 .977 .975 .972 .969 68
69 .994 .993 .992 .991 .990 .989 .988 .987 .986 .984 .983 .981 .979 .976 .974 .971 69
70 .994 .993 .993 .992 .991 .990 .989 .988 .987 .985 .984 .982 .980 .978 .976 .973 70
71 .995 .994 .993 .993 .992 .991 .990 .989 .988 .987 .985 .984 .982 .980 .978 .975 71
72 .995 .995 .994 .993 .993 .992 .991 .990 .989 .988 .986 .985 .983 .981 .979 .977 72
73 .995 .995 .995 .994 .993 .993 .992 .991 .990 .989 .987 .986 .985 .983 .981 .979 73
74 .996 .995 .995 .994 .994 .993 .992 .992 .991 .990 .989 .987 .986 .984 .982 .980 74
</TABLE>
NOTE: Factors for additional age combinations are available from the
Administrator.
-36-
<PAGE>
SPECIAL PROVISION D
FACTORS USED TO DETERMINE THE REDUCED ANNUAL RATE
OF RETIREMENT ANNUITY PAYABLE TO JOINT PENSIONERS
WHO ELECT VARIOUS OPTIONS WITH THEIR ELIGIBLE SPOUSE
50% OPTION ELECTION
-------------------
<TABLE>
<CAPTION>
SPOUSE'S SPOUSE'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 RETIREMENT
- ------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- -----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
40 .942 .938 .934 .929 .924 .919 .914 .909 .903 .897 .891 .885 .878 .871 .863 .856 40
41 .943 .939 .935 .931 .926 .921 .916 .911 .905 .899 .893 .887 .880 .873 .865 .858 41
42 .945 .941 .937 .933 .928 .923 .918 .913 .907 .901 .895 .889 .882 .875 .868 .860 42
43 .947 .943 .939 .934 .930 .925 .920 .915 .909 .903 .897 .891 .884 .877 .870 .862 43
44 .948 .945 .941 .936 .932 .927 .922 .917 .911 .906 .899 .893 .886 .879 .872 .865 44
45 .950 .946 .942 .938 .934 .929 .924 .919 .914 .908 .902 .895 .889 .882 .875 .867 45
46 .952 .948 .944 .940 .936 .931 .926 .921 .916 .910 .904 .898 .891 .884 .877 .870 46
47 .954 .950 .946 .942 .938 .933 .929 .923 .918 .912 .906 .900 .894 .887 .880 .872 47
48 .955 .952 .948 .944 .940 .935 .931 .926 .920 .915 .909 .903 .896 .889 .882 .875 48
49 .957 .954 .950 .946 .942 .938 .933 .928 .923 .917 .911 .905 .899 .892 .885 .878 49
50 .959 .956 .952 .948 .944 .940 .935 .930 .925 .920 .914 .908 .901 .895 .888 .880 50
51 .961 .957 .954 .950 .946 .942 .938 .933 .928 .922 .917 .911 .904 .898 .891 .883 51
52 .962 .959 .956 .952 .948 .944 .940 .935 .930 .925 .919 .913 .907 .900 .894 .886 52
53 .964 .961 .958 .954 .950 .946 .942 .938 .933 .927 .922 .916 .910 .903 .897 .889 53
54 .966 .963 .960 .956 .953 .949 .945 .940 .935 .930 .925 .919 .913 .906 .900 .893 54
55 .968 .965 .962 .958 .955 .951 .947 .942 .938 .933 .927 .922 .916 .909 .903 .896 55
56 .969 .966 .963 .960 .957 .953 .949 .945 .940 .936 .930 .925 .919 .913 .906 .899 56
57 .971 .968 .965 .962 .959 .955 .952 .947 .943 .938 .933 .928 .922 .916 .909 .902 57
58 .972 .970 .967 .964 .961 .958 .954 .950 .946 .941 .936 .931 .925 .919 .913 .906 58
59 .974 .972 .969 .966 .963 .960 .956 .952 .948 .944 .939 .934 .928 .922 .916 .909 59
</TABLE>
NOTE: Factors for additional age combinations are available from the
Administrator.
-37-
<PAGE>
SPECIAL PROVISION D
FACTORS USED TO DETERMINE THE REDUCED ANNUAL RATE
OF RETIREMENT ANNUITY PAYABLE TO JOINT PENSIONERS
WHO ELECT VARIOUS OPTIONS WITH THEIR ELIGIBLE SPOUSE
50% OPTION ELECTION
-------------------
(Continued)
<TABLE>
<CAPTION>
SPOUSE'S SPOUSE'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 RETIREMENT
- ------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- -----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
60 .976 .973 .971 .968 .965 .962 .959 .955 .951 .946 .942 .937 .931 .926 .919 .913 60
61 .977 .975 .973 .970 .967 .964 .961 .957 .953 .949 .945 .940 .934 .929 .923 .916 61
62 .979 .976 .974 .972 .969 .966 .963 .960 .956 .952 .947 .943 .938 .932 .926 .920 62
63 .980 .978 .976 .974 .971 .968 .965 .962 .958 .955 .950 .946 .941 .936 .930 .924 63
64 .981 .979 .977 .975 .973 .970 .967 .964 .961 .957 .953 .949 .944 .939 .933 .928 64
65 .983 .981 .979 .977 .975 .972 .970 .967 .963 .960 .956 .952 .947 .942 .937 .931 65
66 .984 .982 .980 .979 .976 .974 .972 .969 .966 .962 .959 .955 .950 .945 .940 .935 66
67 .985 .984 .982 .980 .978 .976 .974 .971 .968 .965 .961 .957 .953 .949 .944 .939 67
68 .986 .985 .983 .982 .980 .978 .975 .973 .970 .967 .964 .960 .956 .952 .947 .942 68
69 .987 .986 .985 .983 .981 .979 .977 .975 .972 .970 .966 .963 .959 .955 .951 .946 69
70 .988 .987 .986 .984 .983 .981 .979 .977 .974 .972 .969 .966 .962 .958 .954 .949 70
71 .989 .988 .987 .986 .984 .983 .981 .979 .976 .974 .971 .968 .965 .961 .957 .953 71
72 .990 .989 .988 .987 .985 .984 .982 .980 .978 .976 .973 .971 .967 .964 .960 .956 72
73 .991 .990 .989 .988 .987 .985 .984 .982 .980 .978 .976 .973 .970 .967 .963 .959 73
74 .992 .991 .990 .989 .988 .987 .985 .984 .982 .980 .978 .975 .972 .969 .966 .962 74
</TABLE>
NOTE: Factors for additional age combinations are available from the
Administrator.
-38-
<PAGE>
SPECIAL PROVISION D
FACTORS USED TO DETERMINE THE REDUCED ANNUAL RATE
OF RETIREMENT ANNUITY PAYABLE TO JOINT PENSIONERS
WHO ELECT VARIOUS OPTIONS WITH THEIR ELIGIBLE SPOUSE
75% OPTION ELECTION
-------------------
<TABLE>
<CAPTION>
SPOUSE'S SPOUSE'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 RETIREMENT
- ------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- -----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
40 .890 .883 .875 .868 .859 .851 .842 .833 .824 .814 .803 .793 .782 .771 .760 .748 40
41 .893 .886 .878 .871 .863 .854 .845 .836 .827 .817 .807 .796 .785 .774 .763 .751 41
42 .896 .889 .881 .874 .866 .857 .849 .840 .830 .820 .810 .800 .789 .778 .766 .754 42
43 .899 .892 .885 .877 .869 .861 .852 .843 .834 .824 .814 .803 .792 .781 .770 .758 43
44 .902 .895 .888 .880 .872 .864 .856 .847 .837 .827 .817 .807 .796 .785 .773 .762 44
45 .905 .898 .891 .884 .876 .868 .859 .850 .841 .831 .821 .811 .800 .789 .777 .765 45
46 .908 .901 .894 .887 .879 .871 .863 .854 .845 .835 .825 .814 .804 .792 .781 .769 46
47 .911 .905 .898 .891 .883 .875 .867 .858 .849 .839 .829 .819 .808 .797 .785 .773 47
48 .915 .908 .901 .894 .887 .879 .870 .862 .853 .843 .833 .823 .812 .801 .789 .778 48
49 .918 .911 .905 .898 .890 .883 .874 .866 .857 .847 .837 .827 .816 .805 .794 .782 49
50 .921 .915 .908 .901 .894 .886 .878 .870 .861 .851 .842 .831 .821 .810 .798 .786 50
51 .924 .918 .912 .905 .898 .890 .882 .874 .865 .856 .846 .836 .825 .814 .803 .791 51
52 .927 .922 .915 .909 .902 .894 .887 .878 .869 .860 .851 .840 .830 .819 .808 .796 52
53 .931 .925 .919 .912 .906 .898 .891 .883 .874 .865 .855 .845 .835 .824 .813 .801 53
54 .934 .928 .922 .916 .910 .902 .895 .887 .878 .869 .860 .850 .840 .829 .818 .806 54
55 .937 .932 .926 .920 .913 .906 .899 .891 .883 .874 .865 .855 .845 .834 .823 .811 55
56 .940 .935 .930 .924 .917 .911 .903 .896 .887 .879 .870 .860 .850 .839 .828 .817 56
57 .943 .938 .933 .927 .921 .915 .908 .900 .892 .884 .875 .865 .855 .845 .834 .822 57
58 .946 .942 .936 .931 .925 .919 .912 .905 .897 .888 .880 .870 .860 .850 .839 .828 58
59 .949 .945 .940 .935 .929 .923 .916 .909 .901 .893 .885 .876 .866 .856 .845 .834 59
</TABLE>
NOTE: Factors for additional age combinations are available from the
Administrator.
-39-
<PAGE>
SPECIAL PROVISION D
FACTORS USED TO DETERMINE THE REDUCED ANNUAL RATE
OF RETIREMENT ANNUITY PAYABLE TO JOINT PENSIONERS
WHO ELECT VARIOUS OPTIONS WITH THEIR ELIGIBLE SPOUSE
75% OPTION ELECTION
-------------------
(Continued)
<TABLE>
<CAPTION>
SPOUSE'S SPOUSE'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 RETIREMENT
- ------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- -----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
60 .952 .948 .943 .938 .933 .927 .920 .914 .906 .898 .890 .881 .871 .861 .851 .840 60
61 .955 .951 .946 .942 .936 .931 .925 .918 .911 .903 .895 .886 .877 .867 .857 .846 61
62 .958 .954 .950 .945 .940 .935 .929 .922 .915 .908 .900 .892 .883 .873 .863 .852 62
63 .961 .957 .953 .948 .944 .939 .933 .927 .920 .913 .905 .897 .888 .879 .869 .858 63
64 .963 .960 .956 .952 .947 .942 .937 .931 .925 .918 .910 .902 .894 .885 .875 .865 64
65 .966 .962 .959 .955 .951 .946 .941 .935 .929 .923 .916 .908 .900 .891 .881 .871 65
66 .968 .965 .962 .958 .954 .950 .945 .939 .934 .927 .921 .913 .905 .897 .887 .878 66
67 .971 .968 .964 .961 .957 .953 .948 .943 .938 .932 .925 .918 .911 .902 .894 .884 67
68 .973 .970 .967 .964 .960 .956 .952 .947 .942 .936 .930 .924 .916 .908 .900 .891 68
69 .975 .972 .970 .967 .963 .960 .956 .951 .946 .941 .935 .929 .922 .914 .906 .897 69
70 .977 .975 .972 .969 .966 .963 .959 .955 .950 .945 .940 .933 .927 .920 .912 .903 70
71 .979 .977 .974 .972 .969 .966 .962 .958 .954 .949 .944 .938 .932 .925 .918 .910 71
72 .981 .979 .976 .974 .971 .968 .965 .962 .958 .953 .948 .943 .937 .930 .923 .916 72
73 .982 .980 .978 .976 .974 .971 .968 .965 .961 .957 .952 .947 .942 .936 .929 .922 73
74 .984 .982 .980 .978 .976 .974 .971 .968 .964 .960 .956 .951 .946 .940 .934 .927 74
</TABLE>
NOTE: Factors for additional age combinations are available from the
Administrator.
-40-
<PAGE>
SPECIAL PROVISION D
FACTORS USED TO DETERMINE THE REDUCED ANNUAL RATE
OF RETIREMENT ANNUITY PAYABLE TO JOINT PENSIONERS
WHO ELECT VARIOUS OPTIONS WITH THEIR ELIGIBLE SPOUSE
100% OPTION ELECTION
--------------------
<TABLE>
<CAPTION>
SPOUSE'S SPOUSE'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 RETIREMENT
- ------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- -----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
40 .844 .834 .824 .814 .803 .792 .781 .769 .757 .744 .732 .719 .705 .692 .678 .664 40
41 .847 .838 .828 .818 .807 .796 .785 .773 .761 .748 .736 .723 .709 .696 .682 .668 41
42 .851 .842 .832 .822 .811 .800 .789 .777 .765 .753 .740 .727 .713 .700 .686 .672 42
43 .855 .846 .836 .826 .816 .805 .793 .782 .770 .757 .744 .731 .718 .704 .690 .676 43
44 .860 .850 .841 .831 .820 .809 .798 .786 .774 .762 .749 .736 .722 .709 .695 .680 44
45 .864 .855 .845 .835 .825 .814 .803 .791 .779 .766 .754 .740 .727 .713 .699 .685 45
46 .868 .859 .850 .840 .829 .819 .807 .796 .784 .771 .759 .745 .732 .718 .704 .690 46
47 .873 .864 .854 .844 .834 .824 .812 .801 .789 .776 .764 .750 .737 .723 .709 .695 47
48 .877 .868 .859 .849 .839 .829 .817 .806 .794 .782 .769 .756 .742 .728 .714 .700 48
49 .881 .873 .864 .854 .844 .834 .823 .811 .799 .787 .774 .761 .748 .734 .719 .705 49
50 .886 .877 .868 .859 .849 .839 .828 .817 .805 .793 .780 .767 .753 .739 .725 .711 50
51 .890 .882 .873 .864 .854 .844 .833 .822 .810 .798 .786 .772 .759 .745 .731 .716 51
52 .895 .887 .878 .869 .860 .850 .839 .828 .816 .804 .791 .778 .765 .751 .737 .722 52
53 .899 .892 .883 .874 .865 .855 .845 .834 .822 .810 .797 .784 .771 .757 .743 .728 53
54 .904 .896 .888 .879 .870 .860 .850 .839 .828 .816 .804 .791 .777 .763 .749 .735 54
55 .908 .901 .893 .884 .876 .866 .856 .845 .834 .822 .810 .797 .784 .770 .756 .741 55
56 .913 .906 .898 .890 .881 .872 .862 .851 .840 .829 .816 .804 .791 .777 .763 .748 56
57 .917 .910 .903 .895 .886 .877 .868 .857 .846 .835 .823 .810 .797 .784 .770 .755 57
58 .922 .915 .908 .900 .892 .883 .873 .863 .853 .842 .830 .817 .804 .791 .777 .762 58
59 .926 .919 .912 .905 .897 .888 .879 .870 .859 .848 .837 .824 .811 .798 .784 .770 59
</TABLE>
NOTE: Factors for additional age combinations are available from the
Administrator.
-41-
<PAGE>
SPECIAL PROVISION D
FACTORS USED TO DETERMINE THE REDUCED ANNUAL RATE
OF RETIREMENT ANNUITY PAYABLE TO JOINT PENSIONERS
WHO ELECT VARIOUS OPTIONS WITH THEIR ELIGIBLE SPOUSE
100% OPTION ELECTION
--------------------
(Continued)
<TABLE>
<CAPTION>
SPOUSE'S SPOUSE'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 RETIREMENT
- ------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- -----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
60 .930 .924 .917 .910 .902 .894 .885 .876 .866 .855 .843 .831 .819 .805 .792 .777 60
61 .934 .928 .922 .915 .908 .900 .891 .882 .872 .861 .850 .839 .826 .813 .799 .785 61
62 .938 .933 .926 .920 .913 .905 .897 .888 .878 .868 .857 .846 .834 .821 .807 .793 62
63 .942 .937 .931 .925 .918 .911 .903 .894 .885 .875 .864 .853 .841 .829 .815 .802 63
64 .946 .941 .935 .929 .923 .916 .908 .900 .891 .882 .871 .860 .849 .837 .824 .810 64
65 .950 .945 .940 .934 .928 .921 .914 .906 .897 .888 .878 .868 .857 .845 .832 .819 65
66 .953 .949 .944 .938 .933 .926 .919 .912 .904 .895 .885 .875 .864 .853 .840 .827 66
67 .957 .952 .948 .943 .937 .931 .925 .918 .910 .901 .892 .882 .872 .860 .848 .836 67
68 .960 .956 .951 .947 .942 .936 .930 .923 .916 .908 .899 .890 .879 .868 .857 .844 68
69 .963 .959 .955 .951 .946 .941 .935 .928 .921 .914 .906 .897 .887 .876 .865 .853 69
70 .966 .962 .959 .955 .950 .945 .940 .934 .927 .920 .912 .903 .894 .884 .873 .862 70
71 .969 .965 .962 .958 .954 .949 .944 .939 .932 .926 .918 .910 .901 .892 .881 .870 71
72 .971 .968 .965 .962 .958 .953 .949 .943 .938 .931 .924 .917 .908 .899 .889 .879 72
73 .974 .971 .968 .965 .961 .957 .953 .948 .943 .937 .930 .923 .915 .906 .897 .887 73
74 .976 .974 .971 .968 .965 .961 .957 .952 .947 .952 .936 .929 .921 .913 .904 .895 74
</TABLE>
NOTE: Factors for additional age combinations are available from the
Administrator.
-42-
<PAGE>
SPECIAL PROVISION D
SPECIAL JOINT PENSION WITH SPOUSE
FACTORS USED TO DETERMINE THE REDUCED ANNUAL RATE
OF RETIREMENT ANNUITY PAYABLE TO JOINT PENSIONERS
WHO ELECT THE SPECIAL JOINT PENSION OPTION WITH THEIR SPOUSE
50% OPTION ELECTION
-------------------
<TABLE>
<CAPTION>
SPOUSE'S SPOUSE'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 RETIREMENT
- ------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- -----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
20 .966 .964 .961 .959 .956 .953 .950 .947 .944 .940 .937 .933 .929 .926 .921 .917 20
21 .967 .964 .962 .959 .957 .954 .951 .948 .945 .941 .938 .934 .930 .926 .922 .918 21
22 .967 .965 .963 .960 .957 .955 .952 .949 .945 .942 .938 .935 .931 .927 .923 .919 22
23 .968 .966 .963 .961 .958 .955 .952 .949 .946 .943 .939 .936 .932 .928 .924 .920 23
24 .969 .966 .964 .961 .959 .956 .953 .950 .947 .944 .940 .937 .933 .929 .925 .921 24
25 .969 .967 .965 .962 .960 .957 .954 .951 .948 .944 .941 .937 .934 .930 .926 .921 25
26 .970 .968 .965 .963 .960 .958 .955 .952 .949 .945 .942 .938 .935 .931 .927 .922 26
27 .971 .969 .966 .964 .961 .959 .956 .953 .950 .946 .943 .939 .936 .932 .928 .923 27
28 .971 .969 .967 .965 .962 .959 .957 .954 .950 .947 .944 .940 .936 .933 .929 .924 28
29 .972 .970 .968 .965 .963 .960 .957 .954 .951 .948 .945 .941 .937 .934 .930 .925 29
30 .973 .971 .969 .966 .964 .961 .958 .955 .952 .949 .946 .942 .939 .935 .931 .927 30
31 .974 .972 .969 .967 .965 .962 .959 .956 .953 .950 .947 .943 .940 .936 .932 .928 31
32 .974 .972 .970 .968 .965 .963 .960 .957 .954 .951 .948 .944 .941 .937 .933 .929 32
33 .975 .973 .971 .969 .966 .964 .961 .958 .955 .952 .949 .945 .942 .938 .934 .930 33
34 .976 .974 .972 .970 .967 .965 .962 .959 .956 .953 .950 .947 .943 .939 .935 .931 34
35 .977 .975 .973 .970 .968 .966 .963 .960 .957 .954 .951 .948 .944 .940 .937 .933 35
36 .977 .975 .973 .971 .969 .967 .964 .961 .958 .955 .952 .949 .945 .942 .938 .934 36
37 .978 .976 .974 .972 .970 .968 .965 .962 .960 .957 .953 .950 .947 .943 .939 .935 37
38 .979 .977 .975 .973 .971 .969 .966 .963 .961 .958 .955 .951 .948 .944 .940 .937 38
39 .980 .978 .976 .974 .972 .970 .967 .964 .962 .959 .956 .952 .949 .946 .942 .938 39
</TABLE>
NOTE: Factors for additional age combinations are available from the
Administrator.
-43-
<PAGE>
SPECIAL PROVISION D
SPECIAL JOINT PENSION WITH SPOUSE
FACTORS USED TO DETERMINE THE REDUCED ANNUAL RATE
OF RETIREMENT ANNUITY PAYABLE TO JOINT PENSIONERS
WHO ELECT THE SPECIAL JOINT PENSION OPTION WITH THEIR SPOUSE
50% OPTION ELECTION
-------------------
(continued)
<TABLE>
<CAPTION>
SPOUSE'S SPOUSE'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 RETIREMENT
- ------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- -----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
40 .980 .979 .977 .975 .973 .970 .968 .966 .963 .960 .957 .954 .950 .947 .943 .939 40
41 .981 .979 .978 .976 .974 .971 .969 .967 .964 .961 .958 .955 .952 .948 .945 .941 41
42 .982 .980 .978 .977 .975 .972 .970 .968 .965 .962 .959 .956 .953 .950 .946 .942 42
43 .983 .981 .979 .977 .975 .973 .971 .969 .966 .963 .961 .958 .954 .951 .947 .944 43
44 .983 .982 .980 .978 .976 .974 .972 .970 .967 .965 .962 .959 .956 .952 .949 .945 44
45 .984 .982 .981 .979 .977 .975 .973 .971 .968 .966 .963 .960 .957 .954 .950 .947 45
46 .985 .983 .982 .980 .978 .976 .974 .972 .969 .967 .964 .961 .958 .955 .952 .948 46
47 .985 .984 .982 .981 .979 .977 .975 .973 .971 .968 .965 .963 .960 .957 .953 .950 47
48 .986 .984 .983 .981 .980 .978 .976 .974 .972 .969 .967 .964 .961 .958 .955 .951 48
49 .986 .985 .984 .982 .981 .979 .977 .975 .973 .970 .968 .965 .962 .959 .956 .953 49
50 .987 .986 .984 .983 .981 .980 .978 .976 .974 .971 .969 .966 .964 .961 .958 .954 50
51 .988 .986 .985 .984 .982 .981 .979 .977 .975 .973 .970 .968 .965 .962 .959 .956 51
52 .988 .987 .986 .984 .983 .981 .980 .978 .976 .974 .971 .969 .966 .963 .961 .957 52
53 .989 .988 .986 .985 .984 .982 .980 .979 .977 .975 .972 .970 .968 .965 .962 .959 53
54 .989 .988 .987 .986 .984 .983 .981 .980 .978 .976 .974 .971 .969 .966 .963 .960 54
55 .990 .989 .988 .986 .985 .984 .982 .980 .979 .977 .975 .972 .970 .968 .965 .962 55
56 .990 .989 .988 .987 .986 .984 .983 .981 .980 .978 .976 .974 .971 .969 .966 .963 56
57 .991 .990 .989 .988 .987 .985 .984 .982 .981 .979 .977 .975 .973 .970 .968 .965 57
58 .991 .990 .989 .988 .987 .986 .985 .983 .981 .980 .978 .976 .974 .971 .969 .966 58
59 .992 .991 .990 .989 .988 .987 .985 .984 .982 .981 .979 .977 .975 .973 .970 .968 59
</TABLE>
NOTE: Factors for additional age combinations are available from the
Administrator.
-44-
<PAGE>
SPECIAL PROVISION D
SPECIAL JOINT PENSION WITH SPOUSE
FACTORS USED TO DETERMINE THE REDUCED ANNUAL RATE
OF RETIREMENT ANNUITY PAYABLE TO JOINT PENSIONERS
WHO ELECT THE SPECIAL JOINT PENSION OPTION WITH THEIR SPOUSE
50% OPTION ELECTION
-------------------
(continued)
<TABLE>
<CAPTION>
SPOUSE'S SPOUSE'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 RETIREMENT
- ------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- -----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
60 .992 .991 .990 .989 .988 .987 .986 .985 .983 .981 .980 .978 .976 .974 .972 .969 60
61 .993 .992 .991 .990 .989 .988 .987 .985 .984 .982 .981 .979 .977 .975 .973 .971 61
62 .993 .992 .991 .991 .990 .988 .987 .986 .985 .983 .982 .980 .978 .976 .974 .972 62
63 .993 .993 .992 .991 .990 .989 .988 .987 .985 .984 .983 .981 .979 .977 .975 .973 63
64 .994 .993 .992 .991 .991 .990 .989 .987 .986 .985 .983 .982 .980 .978 .976 .974 64
65 .994 .993 .993 .992 .991 .990 .989 .988 .987 .986 .984 .983 .981 .979 .978 .976 65
66 .994 .994 .993 .992 .992 .991 .990 .989 .988 .986 .985 .984 .982 .980 .979 .977 66
67 .995 .994 .994 .993 .992 .991 .990 .989 .988 .987 .986 .984 .983 .981 .980 .978 67
68 .995 .994 .994 .993 .993 .992 .991 .990 .989 .988 .987 .985 .984 .982 .981 .979 68
69 .995 .995 .994 .994 .993 .992 .991 .990 .989 .988 .987 .986 .985 .983 .982 .980 69
70 .996 .995 .995 .994 .993 .993 .992 .991 .990 .989 .988 .987 .986 .984 .983 .981 70
71 .996 .995 .995 .994 .994 .993 .992 .991 .991 .990 .989 .987 .986 .985 .984 .982 71
72 .996 .996 .995 .995 .994 .993 .993 .992 .991 .990 .989 .988 .987 .986 .985 .983 72
73 .996 .996 .996 .995 .994 .994 .993 .992 .992 .991 .990 .989 .988 .987 .985 .984 73
74 .997 .996 .996 .995 .995 .994 .994 .993 .992 .991 .990 .989 .988 .987 .986 .985 74
75 .997 .996 .996 .996 .995 .995 .994 .993 .993 .992 .991 .990 .989 .988 .987 .986 75
76 .997 .997 .996 .996 .995 .995 .994 .994 .993 .992 .992 .991 .990 .989 .988 .987 76
77 .997 .997 .997 .996 .996 .995 .995 .994 .993 .993 .992 .991 .990 .989 .988 .987 77
78 .997 .997 .997 .996 .996 .996 .995 .994 .994 .993 .992 .992 .991 .990 .989 .988 78
79 .998 .997 .997 .997 .996 .996 .995 .995 .994 .994 .993 .992 .991 .991 .990 .989 79
</TABLE>
NOTE: Factors for additional age combinations are available from the
Administrator.
-45-
<PAGE>
SPECIAL PROVISION D
SPECIAL JOINT PENSION WITH SPOUSE
FACTORS USED TO DETERMINE THE REDUCED ANNUAL RATE
OF RETIREMENT ANNUITY PAYABLE TO JOINT PENSIONERS
WHO ELECT THE SPECIAL JOINT PENSION OPTION WITH THEIR SPOUSE
50% OPTION ELECTION
-------------------
(continued)
<TABLE>
<CAPTION>
SPOUSE'S SPOUSE'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 RETIREMENT
- ------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- -----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
80 .998 .997 .997 .997 .997 .996 .996 .995 .995 .994 .993 .993 .992 .991 .990 .990 80
81 .998 .998 .997 .997 .997 .996 .996 .995 .995 .994 .994 .993 .993 .992 .991 .990 81
82 .998 .998 .998 .997 .997 .997 .996 .996 .995 .995 .994 .994 .993 .992 .992 .991 82
83 .998 .998 .998 .997 .997 .997 .996 .996 .996 .995 .995 .994 .993 .993 .992 .991 83
84 .998 .998 .998 .998 .997 .997 .997 .996 .996 .995 .995 .994 .994 .993 .993 .992 84
85 .998 .998 .998 .998 .998 .997 .997 .997 .996 .996 .995 .995 .994 .994 .993 .992 85
86 .999 .998 .998 .998 .998 .997 .997 .997 .996 .996 .996 .995 .995 .994 .994 .993 86
87 .999 .998 .998 .998 .998 .998 .997 .997 .997 .996 .996 .995 .995 .995 .994 .993 87
88 .999 .999 .998 .998 .998 .998 .998 .997 .997 .997 .996 .996 .995 .995 .994 .994 88
89 .999 .999 .999 .998 .998 .998 .998 .997 .997 .997 .996 .996 .996 .995 .995 .994 89
</TABLE>
NOTE: Factors for additional age combinations are available from the
Administrator.
-46-
<PAGE>
SPECIAL PROVISION D
SPECIAL JOINT PENSION WITH SPOUSE
FACTORS USED TO DETERMINE THE REDUCED ANNUAL RATE
OF RETIREMENT ANNUITY PAYABLE TO JOINT PENSIONERS
WHO ELECT THE SPECIAL JOINT PENSION OPTION WITH THEIR SPOUSE
50% OPTION ELECTION
-------------------
<TABLE>
<CAPTION>
SPOUSE'S SPOUSE'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 RETIREMENT
- ------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- -----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
20 .917 .913 .908 .903 .898 .893 .888 .882 .876 .870 .864 .857 .850 .843 .836 .828 20
21 .918 .913 .909 .904 .899 .894 .888 .883 .877 .871 .865 .858 .851 .844 .837 .829 21
22 .919 .914 .910 .905 .900 .895 .889 .884 .878 .872 .865 .859 .852 .845 .838 .830 22
23 .920 .915 .911 .906 .901 .896 .890 .885 .879 .873 .866 .860 .853 .846 .838 .831 23
24 .921 .916 .912 .907 .902 .897 .891 .886 .880 .874 .867 .861 .854 .847 .839 .832 24
25 .921 .917 .912 .908 .903 .898 .892 .887 .881 .875 .868 .862 .855 .848 .840 .833 25
26 .922 .918 .913 .909 .904 .899 .893 .888 .882 .876 .869 .863 .856 .849 .841 .834 26
27 .923 .919 .914 .910 .905 .900 .894 .889 .883 .877 .870 .864 .857 .850 .842 .835 27
28 .924 .920 .916 .911 .906 .901 .895 .890 .884 .878 .871 .865 .858 .851 .844 .836 28
29 .925 .921 .917 .912 .907 .902 .896 .891 .885 .879 .873 .866 .859 .852 .845 .837 29
30 .927 .922 .918 .913 .908 .903 .898 .892 .886 .880 .874 .867 .860 .853 .846 .838 30
31 .928 .923 .919 .914 .909 .904 .899 .893 .887 .881 .875 .868 .862 .855 .847 .840 31
32 .929 .925 .920 .915 .911 .905 .900 .895 .889 .883 .876 .870 .863 .856 .849 .841 32
33 .930 .926 .921 .917 .912 .907 .901 .896 .890 .884 .878 .871 .864 .857 .850 .842 33
34 .931 .927 .923 .918 .913 .908 .903 .897 .891 .885 .879 .873 .866 .859 .851 .844 34
35 .933 .928 .924 .919 .915 .909 .904 .899 .893 .887 .881 .874 .867 .860 .853 .845 35
36 .934 .930 .925 .921 .916 .911 .906 .900 .894 .888 .882 .876 .869 .862 .854 .847 36
37 .935 .931 .927 .922 .917 .912 .907 .902 .896 .890 .884 .877 .870 .863 .856 .849 37
38 .937 .932 .928 .924 .919 .914 .909 .903 .897 .892 .885 .879 .872 .865 .858 .850 38
39 .938 .934 .930 .925 .920 .915 .910 .905 .899 .893 .887 .880 .874 .867 .859 .852 39
</TABLE>
NOTE: Factors for additional age combinations are available from the
Administrator.
-47-
<PAGE>
SPECIAL PROVISION D
SPECIAL JOINT PENSION WITH SPOUSE
FACTORS USED TO DETERMINE THE REDUCED ANNUAL RATE
OF RETIREMENT ANNUITY PAYABLE TO JOINT PENSIONERS
WHO ELECT THE SPECIAL JOINT PENSION OPTION WITH THEIR SPOUSE
50% OPTION ELECTION
-------------------
(continued)
<TABLE>
<CAPTION>
SPOUSE'S SPOUSE'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 RETIREMENT
- ------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- -----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
40 .939 .935 .931 .927 .922 .917 .912 .906 .901 .895 .889 .882 .875 .868 .861 .854 40
41 .941 .937 .933 .928 .924 .919 .914 .908 .903 .897 .890 .884 .877 .870 .863 .856 41
42 .942 .938 .934 .930 .925 .920 .915 .910 .904 .898 .892 .886 .879 .872 .865 .858 42
43 .944 .940 .936 .931 .927 .922 .917 .912 .906 .900 .894 .888 .881 .874 .867 .860 43
44 .945 .941 .937 .933 .929 .924 .919 .914 .908 .902 .896 .890 .883 .876 .869 .862 44
45 .947 .943 .939 .935 .930 .926 .921 .915 .910 .904 .898 .892 .885 .878 .871 .864 45
46 .948 .944 .941 .936 .932 .927 .922 .917 .912 .906 .900 .894 .887 .880 .873 .866 46
47 .950 .946 .942 .938 .934 .929 .924 .919 .914 .908 .902 .896 .889 .883 .876 .868 47
48 .951 .948 .944 .940 .936 .931 .926 .921 .916 .910 .904 .898 .892 .885 .878 .871 48
49 .953 .949 .946 .942 .937 .933 .928 .923 .918 .912 .907 .900 .894 .887 .880 .873 49
50 .954 .951 .947 .943 .939 .935 .930 .925 .920 .915 .909 .903 .896 .890 .883 .875 50
51 .956 .953 .949 .945 .941 .937 .932 .927 .922 .917 .911 .905 .899 .892 .885 .878 51
52 .957 .954 .951 .947 .943 .939 .934 .929 .924 .919 .913 .907 .901 .895 .888 .880 52
53 .959 .956 .952 .949 .945 .941 .936 .932 .927 .921 .916 .910 .904 .897 .890 .883 53
54 .960 .957 .954 .950 .947 .943 .938 .934 .929 .924 .918 .912 .906 .900 .893 .886 54
55 .962 .959 .956 .952 .948 .945 .940 .936 .931 .926 .920 .915 .909 .902 .896 .889 55
56 .963 .960 .957 .954 .950 .946 .942 .938 .933 .928 .923 .917 .911 .905 .898 .891 56
57 .965 .962 .959 .956 .952 .948 .944 .940 .935 .931 .925 .920 .914 .908 .901 .894 57
58 .966 .964 .961 .957 .954 .950 .946 .942 .938 .933 .928 .922 .917 .910 .904 .897 58
59 .968 .965 .962 .959 .956 .952 .948 .944 .940 .935 .930 .925 .919 .913 .907 .900 59
</TABLE>
NOTE: Factors for additional age combinations are available from the
Administrator.
-48-
<PAGE>
SPECIAL PROVISION D
SPECIAL JOINT PENSION WITH SPOUSE
FACTORS USED TO DETERMINE THE REDUCED ANNUAL RATE
OF RETIREMENT ANNUITY PAYABLE TO JOINT PENSIONERS
WHO ELECT THE SPECIAL JOINT PENSION OPTION WITH THEIR SPOUSE
50% OPTION ELECTION
-------------------
(continued)
<TABLE>
<CAPTION>
SPOUSE'S SPOUSE'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 RETIREMENT
- ------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- -----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
60 .969 .967 .964 .961 .958 .954 .950 .946 .942 .938 .933 .927 .922 .916 .910 .903 60
61 .971 .968 .965 .962 .959 .956 .952 .949 .944 .940 .935 .930 .925 .919 .913 .906 61
62 .972 .969 .967 .964 .961 .958 .954 .951 .947 .942 .938 .933 .927 .922 .916 .909 62
63 .973 .971 .968 .966 .963 .960 .956 .953 .949 .945 .940 .935 .930 .924 .919 .912 63
64 .974 .972 .970 .967 .965 .962 .958 .955 .951 .947 .942 .938 .933 .927 .922 .916 64
65 .976 .974 .971 .969 .966 .963 .960 .957 .953 .949 .945 .940 .935 .930 .925 .919 65
66 .977 .975 .973 .970 .968 .965 .962 .959 .955 .951 .947 .943 .938 .933 .928 .922 66
67 .978 .976 .974 .972 .969 .967 .964 .961 .957 .954 .950 .945 .941 .936 .930 .925 67
68 .979 .977 .975 .973 .971 .968 .966 .963 .959 .956 .952 .948 .943 .939 .933 .928 68
69 .980 .978 .977 .975 .972 .970 .967 .964 .961 .958 .954 .950 .946 .941 .936 .931 69
70 .981 .980 .978 .976 .974 .971 .969 .966 .963 .960 .956 .953 .948 .944 .939 .934 70
71 .982 .981 .979 .977 .975 .973 .971 .968 .965 .962 .959 .955 .951 .947 .942 .937 71
72 .983 .982 .980 .978 .976 .974 .972 .970 .967 .964 .961 .957 .953 .949 .945 .940 72
73 .984 .983 .981 .979 .978 .976 .974 .971 .969 .966 .963 .959 .956 .952 .947 .943 73
74 .985 .984 .982 .981 .979 .977 .975 .973 .970 .968 .965 .961 .958 .954 .950 .946 74
75 .986 .985 .983 .982 .980 .978 .976 .974 .972 .969 .967 .963 .960 .956 .953 .948 75
76 .987 .985 .984 .983 .981 .980 .978 .976 .973 .971 .968 .965 .962 .959 .955 .951 76
77 .987 .986 .985 .984 .982 .981 .979 .977 .975 .973 .970 .967 .964 .961 .957 .954 77
78 .988 .987 .986 .985 .983 .982 .980 .978 .976 .974 .972 .969 .966 .963 .960 .956 78
79 .989 .988 .987 .986 .984 .983 .981 .980 .978 .976 .974 .971 .968 .965 .962 .959 79
</TABLE>
NOTE: Factors for additional age combinations are available from the
Administrator.
-49-
<PAGE>
SPECIAL PROVISION D
SPECIAL JOINT PENSION WITH SPOUSE
FACTORS USED TO DETERMINE THE REDUCED ANNUAL RATE
OF RETIREMENT ANNUITY PAYABLE TO JOINT PENSIONERS
WHO ELECT THE SPECIAL JOINT PENSION OPTION WITH THEIR SPOUSE
50% OPTION ELECTION
-------------------
(continued)
<TABLE>
<CAPTION>
SPOUSE'S SPOUSE'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 RETIREMENT
- ------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- -----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
80 .990 .989 .988 .986 .985 .984 .983 .981 .979 .977 .975 .973 .970 .967 .964 .961 80
81 .990 .989 .988 .987 .986 .985 .984 .982 .980 .979 .977 .974 .972 .969 .966 .963 81
82 .991 .990 .989 .988 .987 .986 .985 .983 .982 .980 .978 .976 .974 .971 .968 .965 82
83 .991 .991 .990 .989 .988 .987 .986 .984 .983 .981 .979 .978 .975 .973 .970 .968 83
84 .992 .991 .990 .990 .989 .988 .987 .985 .984 .982 .981 .979 .977 .975 .972 .970 84
85 .992 .992 .991 .990 .989 .988 .987 .986 .985 .984 .982 .980 .978 .976 .974 .972 85
86 .993 .992 .992 .991 .990 .989 .988 .987 .986 .985 .983 .982 .980 .978 .976 .973 86
87 .993 .993 .992 .992 .991 .990 .989 .988 .987 .986 .984 .983 .981 .979 .977 .975 87
88 .994 .993 .993 .992 .991 .991 .990 .989 .988 .987 .985 .984 .983 .981 .979 .977 88
89 .994 .994 .993 .993 .992 .991 .991 .990 .989 .988 .987 .985 .984 .982 .980 .978 89
</TABLE>
NOTE: Factors for additional age combinations are available from the
Administrator.
-50-
<PAGE>
SPECIAL PROVISION D
SPECIAL JOINT PENSION WITH SPOUSE
FACTORS USED TO DETERMINE THE REDUCED ANNUAL RATE
OF RETIREMENT ANNUITY PAYABLE TO JOINT PENSIONERS
WHO ELECT THE SPECIAL JOINT PENSION OPTION WITH THEIR SPOUSE
100% OPTION ELECTION
--------------------
<TABLE>
<CAPTION>
SPOUSE'S SPOUSE'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 RETIREMENT
- ------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- -----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
20 .904 .898 .892 .885 .879 .872 .864 .856 .849 .840 .832 .823 .815 .805 .796 .787 20
21 .906 .900 .894 .887 .880 .873 .866 .858 .850 .842 .834 .825 .816 .807 .798 .788 21
22 .908 .902 .896 .889 .882 .875 .868 .860 .852 .844 .836 .827 .818 .809 .800 .790 22
23 .909 .904 .897 .891 .884 .877 .870 .862 .854 .846 .838 .829 .820 .811 .802 .792 23
24 .911 .905 .899 .893 .886 .879 .872 .864 .856 .848 .840 .831 .822 .813 .804 .794 24
25 .913 .907 .901 .895 .888 .881 .874 .866 .858 .850 .842 .833 .824 .815 .806 .796 25
26 .915 .909 .903 .897 .890 .883 .876 .868 .860 .852 .844 .835 .826 .817 .808 .798 26
27 .917 .911 .905 .899 .892 .885 .878 .870 .862 .854 .846 .837 .829 .820 .810 .801 27
28 .919 .913 .907 .901 .894 .887 .880 .872 .865 .857 .848 .840 .831 .822 .813 .803 28
29 .921 .915 .909 .903 .896 .889 .882 .875 .867 .859 .851 .842 .833 .824 .815 .805 29
30 .923 .917 .911 .905 .899 .892 .885 .877 .869 .861 .853 .845 .836 .827 .817 .808 30
31 .925 .919 .913 .907 .901 .894 .887 .880 .872 .864 .856 .847 .838 .829 .820 .811 31
32 .927 .921 .916 .909 .903 .896 .889 .882 .874 .866 .858 .850 .841 .832 .823 .813 32
33 .929 .923 .918 .912 .905 .899 .892 .884 .877 .869 .861 .852 .844 .835 .825 .816 33
34 .931 .926 .920 .914 .908 .901 .894 .887 .879 .872 .864 .855 .846 .838 .828 .819 34
35 .933 .928 .922 .916 .910 .904 .897 .890 .882 .874 .866 .858 .849 .840 .831 .822 35
36 .935 .930 .924 .919 .913 .906 .899 .892 .885 .877 .869 .861 .852 .843 .834 .825 36
37 .937 .932 .927 .921 .915 .909 .902 .895 .888 .880 .872 .864 .855 .846 .837 .828 37
38 .939 .934 .929 .923 .917 .911 .905 .898 .890 .883 .875 .867 .858 .850 .840 .831 38
39 .941 .936 .931 .926 .920 .914 .907 .900 .893 .886 .878 .870 .861 .853 .844 .834 39
</TABLE>
NOTE: Factors for additional age combinations are available from the
Administrator.
-51-
<PAGE>
SPECIAL PROVISION D
SPECIAL JOINT PENSION WITH SPOUSE
FACTORS USED TO DETERMINE THE REDUCED ANNUAL RATE
OF RETIREMENT ANNUITY PAYABLE TO JOINT PENSIONERS
WHO ELECT THE SPECIAL JOINT PENSION OPTION WITH THEIR SPOUSE
100% OPTION ELECTION
--------------------
(continued)
<TABLE>
<CAPTION>
SPOUSE'S SPOUSE'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 RETIREMENT
- ------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- -----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
40 .943 .939 .934 .928 .922 .916 .910 .903 .896 .889 .881 .873 .865 .856 .847 .838 40
41 .945 .941 .936 .930 .925 .919 .913 .906 .899 .892 .884 .876 .868 .859 .850 .841 41
42 .947 .943 .938 .933 .927 .921 .915 .909 .902 .895 .887 .879 .871 .863 .854 .845 42
43 .949 .945 .940 .935 .930 .924 .918 .912 .905 .898 .890 .883 .874 .866 .857 .848 43
44 .951 .947 .942 .937 .932 .927 .921 .914 .908 .901 .893 .886 .878 .869 .861 .852 44
45 .953 .949 .945 .940 .935 .929 .923 .917 .911 .904 .897 .889 .881 .873 .864 .856 45
46 .955 .951 .947 .942 .937 .932 .926 .920 .914 .907 .900 .892 .885 .876 .868 .859 46
47 .957 .953 .949 .944 .939 .934 .929 .923 .916 .910 .903 .896 .888 .880 .872 .863 47
48 .959 .955 .951 .946 .942 .937 .931 .925 .919 .913 .906 .899 .891 .884 .875 .867 48
49 .960 .957 .953 .949 .944 .939 .934 .928 .922 .916 .909 .902 .895 .887 .879 .871 49
50 .962 .959 .955 .951 .946 .941 .936 .931 .925 .919 .912 .906 .898 .891 .883 .875 50
51 .964 .960 .957 .953 .948 .944 .939 .934 .928 .922 .916 .909 .902 .894 .887 .878 51
52 .965 .962 .959 .955 .951 .946 .941 .936 .931 .925 .919 .912 .905 .898 .890 .882 52
53 .967 .964 .960 .957 .953 .948 .944 .939 .933 .928 .922 .915 .909 .902 .894 .886 53
54 .969 .966 .962 .959 .955 .951 .946 .941 .936 .931 .925 .918 .912 .905 .898 .890 54
55 .970 .967 .964 .960 .957 .953 .948 .944 .939 .933 .928 .922 .915 .909 .901 .894 55
56 .971 .969 .966 .962 .959 .955 .951 .946 .941 .936 .931 .925 .919 .912 .905 .898 56
57 .973 .970 .967 .964 .961 .957 .953 .948 .944 .939 .933 .928 .922 .915 .909 .902 57
58 .974 .972 .969 .966 .962 .959 .955 .951 .946 .941 .936 .931 .925 .919 .912 .905 58
59 .975 .973 .970 .967 .964 .961 .957 .953 .949 .944 .939 .934 .928 .922 .916 .909 59
</TABLE>
NOTE: Factors for additional age combinations are available from the
Administrator.
-52-
<PAGE>
SPECIAL PROVISION D
SPECIAL JOINT PENSION WITH SPOUSE
FACTORS USED TO DETERMINE THE REDUCED ANNUAL RATE
OF RETIREMENT ANNUITY PAYABLE TO JOINT PENSIONERS
WHO ELECT THE SPECIAL JOINT PENSION OPTION WITH THEIR SPOUSE
100% OPTION ELECTION
--------------------
(continued)
<TABLE>
<CAPTION>
SPOUSE'S SPOUSE'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 RETIREMENT
- ------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- -----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
60 .977 .974 .972 .969 .966 .963 .959 .955 .951 .946 .942 .937 .931 .925 .919 .913 60
61 .978 .976 .973 .971 .968 .964 .961 .957 .953 .949 .944 .939 .934 .929 .923 .917 61
62 .979 .977 .975 .972 .969 .966 .963 .959 .955 .951 .947 .942 .937 .932 .926 .920 62
63 .980 .978 .976 .974 .971 .968 .965 .961 .958 .954 .949 .945 .940 .935 .929 .924 63
64 .981 .979 .977 .975 .972 .970 .967 .963 .960 .956 .952 .947 .943 .938 .933 .927 64
65 .982 .981 .978 .976 .974 .971 .968 .965 .962 .958 .954 .950 .945 .941 .936 .930 65
66 .983 .982 .980 .978 .975 .973 .970 .967 .964 .960 .956 .952 .948 .944 .939 .934 66
67 .984 .983 .981 .979 .977 .974 .971 .969 .965 .962 .959 .955 .951 .946 .942 .937 67
68 .985 .984 .982 .980 .978 .976 .973 .970 .967 .964 .961 .957 .953 .949 .945 .940 68
69 .986 .985 .983 .981 .979 .977 .974 .972 .969 .966 .963 .959 .955 .952 .947 .943 69
70 .987 .985 .984 .982 .980 .978 .976 .973 .971 .968 .965 .961 .958 .954 .950 .946 70
71 .988 .986 .985 .983 .981 .979 .977 .975 .972 .970 .967 .963 .960 .956 .953 .948 71
72 .988 .987 .986 .984 .983 .981 .979 .976 .974 .971 .968 .965 .962 .959 .955 .951 72
73 .989 .988 .987 .985 .984 .982 .980 .978 .975 .973 .970 .967 .964 .961 .957 .954 73
74 .990 .989 .987 .986 .985 .983 .981 .979 .977 .974 .972 .969 .966 .963 .960 .956 74
75 .990 .989 .988 .987 .986 .984 .982 .980 .978 .976 .973 .971 .968 .965 .962 .959 75
76 .991 .990 .989 .988 .986 .985 .983 .981 .979 .977 .975 .972 .970 .967 .964 .961 76
77 .992 .991 .990 .989 .987 .986 .984 .983 .981 .979 .976 .974 .972 .969 .966 .963 77
78 .992 .991 .990 .989 .988 .987 .985 .984 .982 .980 .978 .976 .973 .971 .968 .965 78
79 .993 .992 .991 .990 .989 .988 .986 .985 .983 .981 .979 .977 .975 .972 .970 .967 79
</TABLE>
NOTE: Factors for additional age combinations are available from the
Administrator.
-53-
<PAGE>
SPECIAL PROVISION D
SPECIAL JOINT PENSION WITH SPOUSE
FACTORS USED TO DETERMINE THE REDUCED ANNUAL RATE
OF RETIREMENT ANNUITY PAYABLE TO JOINT PENSIONERS
WHO ELECT THE SPECIAL JOINT PENSION OPTION WITH THEIR SPOUSE
100% OPTION ELECTION
--------------------
(continued)
<TABLE>
<CAPTION>
SPOUSE'S SPOUSE'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 RETIREMENT
- ------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- -----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
80 .993 .992 .992 .991 .990 .988 .987 .986 .984 .982 .980 .978 .976 .974 .972 .969 80
81 .994 .993 .992 .991 .990 .989 .988 .987 .985 .983 .982 .980 .978 .976 .973 .971 81
82 .994 .993 .993 .992 .991 .990 .989 .987 .986 .985 .983 .981 .979 .977 .975 .973 82
83 .995 .994 .993 .992 .992 .991 .990 .988 .987 .986 .984 .982 .981 .979 .977 .975 83
84 .995 .994 .994 .993 .992 .991 .990 .989 .988 .986 .985 .983 .982 .980 .978 .976 84
85 .995 .995 .994 .994 .993 .992 .991 .990 .989 .987 .986 .985 .983 .981 .980 .978 85
86 .996 .995 .995 .994 .993 .992 .992 .991 .989 .988 .987 .986 .984 .983 .981 .979 86
87 .996 .995 .995 .994 .994 .993 .992 .991 .990 .989 .988 .987 .985 .984 .982 .981 87
88 .996 .996 .995 .995 .994 .994 .993 .992 .991 .990 .989 .988 .986 .985 .983 .982 88
89 .996 .996 .996 .995 .995 .994 .993 .993 .992 .991 .990 .988 .987 .986 .985 .983 89
</TABLE>
NOTE: Factors for additional age combinations are available from the
Administrator.
-54-
<PAGE>
SPECIAL PROVISION D
SPECIAL JOINT PENSION WITH SPOUSE
FACTORS USED TO DETERMINE THE REDUCED ANNUAL RATE
OF RETIREMENT ANNUITY PAYABLE TO JOINT PENSIONERS
WHO ELECT THE SPECIAL JOINT PENSION OPTION WITH THEIR SPOUSE
100% OPTION ELECTION
--------------------
<TABLE>
<CAPTION>
SPOUSE'S SPOUSE'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 RETIREMENT
- ------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- -----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
20 .787 .777 .767 .757 .746 .736 .725 .714 .702 .691 .679 .667 .654 .642 .629 .617 20
21 .788 .779 .769 .759 .748 .737 .726 .715 .704 .692 .680 .668 .656 .643 .631 .618 21
22 .790 .781 .771 .760 .750 .739 .728 .717 .705 .694 .682 .670 .657 .645 .632 .620 22
23 .792 .782 .772 .762 .752 .741 .730 .719 .707 .695 .683 .671 .659 .646 .634 .621 23
24 .794 .784 .774 .764 .754 .743 .732 .721 .709 .697 .685 .673 .661 .648 .635 .623 24
25 .796 .787 .776 .766 .756 .745 .734 .723 .711 .699 .687 .675 .662 .650 .637 .624 25
26 .798 .789 .779 .768 .758 .747 .736 .725 .713 .701 .689 .677 .664 .652 .639 .626 26
27 .801 .791 .781 .771 .760 .749 .738 .727 .715 .703 .691 .679 .666 .653 .641 .628 27
28 .803 .793 .783 .773 .762 .751 .740 .729 .717 .705 .693 .681 .668 .655 .643 .630 28
29 .805 .796 .786 .775 .765 .754 .743 .731 .719 .708 .695 .683 .670 .658 .645 .632 29
30 .808 .798 .788 .778 .767 .756 .745 .734 .722 .710 .698 .685 .673 .660 .647 .634 30
31 .811 .801 .791 .780 .770 .759 .748 .736 .724 .712 .700 .688 .675 .662 .649 .636 31
32 .813 .803 .793 .783 .772 .761 .750 .739 .727 .715 .703 .690 .677 .664 .651 .638 32
33 .816 .806 .796 .786 .775 .764 .753 .741 .730 .718 .705 .693 .680 .667 .654 .641 33
34 .819 .809 .799 .789 .778 .767 .756 .744 .732 .720 .708 .695 .682 .669 .656 .643 34
35 .822 .812 .802 .792 .781 .770 .759 .747 .735 .723 .711 .698 .685 .672 .659 .646 35
36 .825 .815 .805 .795 .784 .773 .762 .750 .738 .726 .714 .701 .688 .675 .662 .648 36
37 .828 .818 .808 .798 .787 .776 .765 .753 .742 .729 .717 .704 .691 .678 .665 .651 37
38 .831 .821 .811 .801 .791 .780 .768 .757 .745 .733 .720 .707 .694 .681 .668 .654 38
39 .834 .825 .815 .805 .794 .783 .772 .760 .748 .736 .723 .711 .698 .684 .671 .657 39
</TABLE>
NOTE: Factors for additional age combinations are available from the
Administrator.
-55-
<PAGE>
SPECIAL PROVISION D
SPECIAL JOINT PENSION WITH SPOUSE
FACTORS USED TO DETERMINE THE REDUCED ANNUAL RATE
OF RETIREMENT ANNUITY PAYABLE TO JOINT PENSIONERS
WHO ELECT THE SPECIAL JOINT PENSION OPTION WITH THEIR SPOUSE
100% OPTION ELECTION
--------------------
(continued)
<TABLE>
<CAPTION>
SPOUSE'S SPOUSE'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 RETIREMENT
- ------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- -----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
40 .838 .828 .818 .808 .797 .787 .775 .764 .752 .739 .727 .714 .701 .688 .674 .661 40
41 .841 .832 .822 .812 .801 .790 .779 .767 .755 .743 .730 .718 .704 .691 .678 .664 41
42 .845 .835 .825 .815 .805 .794 .783 .771 .759 .747 .734 .721 .708 .695 .681 .667 42
43 .848 .839 .829 .819 .808 .798 .786 .775 .763 .751 .738 .725 .712 .698 .685 .671 43
44 .852 .843 .833 .823 .812 .802 .790 .779 .767 .755 .742 .729 .716 .702 .689 .675 44
45 .856 .846 .837 .827 .816 .806 .794 .783 .771 .759 .746 .733 .720 .706 .693 .679 45
46 .859 .850 .841 .831 .820 .810 .799 .787 .775 .763 .750 .737 .724 .711 .697 .683 46
47 .863 .854 .845 .835 .825 .814 .803 .791 .780 .767 .755 .742 .728 .715 .701 .687 47
48 .867 .858 .849 .839 .829 .818 .807 .796 .784 .772 .759 .746 .733 .719 .705 .691 48
49 .871 .862 .853 .843 .833 .823 .812 .800 .789 .776 .764 .751 .738 .724 .710 .696 49
50 .875 .866 .857 .847 .837 .827 .816 .805 .793 .781 .769 .756 .742 .729 .715 .701 50
51 .878 .870 .861 .852 .842 .832 .821 .810 .798 .786 .773 .761 .747 .734 .720 .706 51
52 .882 .874 .865 .856 .846 .836 .825 .814 .803 .791 .778 .766 .752 .739 .725 .711 52
53 .886 .878 .869 .860 .851 .841 .830 .819 .808 .796 .784 .771 .757 .744 .730 .716 53
54 .890 .882 .874 .865 .855 .845 .835 .824 .813 .801 .789 .776 .763 .749 .735 .721 54
55 .894 .886 .878 .869 .860 .850 .840 .829 .818 .806 .794 .781 .768 .755 .741 .727 55
56 .898 .890 .882 .873 .864 .855 .845 .834 .823 .812 .799 .787 .774 .760 .747 .732 56
57 .902 .894 .886 .878 .869 .860 .850 .839 .828 .817 .805 .793 .780 .766 .752 .738 57
58 .905 .898 .890 .882 .874 .864 .855 .845 .834 .822 .811 .798 .785 .772 .758 .744 58
59 .909 .902 .895 .887 .878 .869 .860 .850 .839 .828 .816 .804 .791 .778 .764 .750 59
</TABLE>
NOTE: Factors for additional age combinations are available from the
Administrator.
-56-
<PAGE>
SPECIAL PROVISION D
SPECIAL JOINT PENSION WITH SPOUSE
FACTORS USED TO DETERMINE THE REDUCED ANNUAL RATE
OF RETIREMENT ANNUITY PAYABLE TO JOINT PENSIONERS
WHO ELECT THE SPECIAL JOINT PENSION OPTION WITH THEIR SPOUSE
100% OPTION ELECTION
--------------------
(continued)
<TABLE>
<CAPTION>
SPOUSE'S SPOUSE'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 RETIREMENT
- ------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- -----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
60 .913 .906 .899 .891 .883 .874 .865 .855 .844 .834 .822 .810 .797 .784 .771 .757 60
61 .917 .910 .903 .895 .887 .879 .870 .860 .850 .839 .828 .816 .803 .790 .777 .763 61
62 .920 .914 .907 .900 .892 .884 .875 .865 .855 .845 .834 .822 .810 .797 .784 .770 62
63 .924 .917 .911 .904 .896 .888 .880 .870 .861 .850 .839 .828 .816 .803 .790 .776 63
64 .927 .921 .915 .908 .901 .893 .884 .876 .866 .856 .845 .834 .822 .810 .797 .783 64
65 .930 .925 .918 .912 .905 .897 .889 .881 .871 .862 .851 .840 .828 .816 .803 .790 65
66 .934 .928 .922 .916 .909 .902 .894 .886 .877 .867 .857 .846 .835 .823 .810 .797 66
67 .937 .931 .926 .920 .913 .906 .899 .891 .882 .873 .863 .852 .841 .829 .817 .804 67
68 .940 .935 .929 .924 .917 .911 .903 .895 .887 .878 .868 .858 .847 .836 .824 .811 68
69 .943 .938 .933 .927 .921 .915 .908 .900 .892 .883 .874 .864 .854 .842 .830 .818 69
70 .946 .941 .936 .931 .925 .919 .912 .905 .897 .889 .880 .870 .860 .849 .837 .825 70
71 .948 .944 .939 .934 .929 .923 .916 .909 .902 .894 .885 .876 .866 .855 .844 .832 71
72 .951 .947 .942 .938 .932 .927 .921 .914 .907 .899 .890 .881 .872 .861 .851 .839 72
73 .954 .950 .945 .941 .936 .931 .925 .918 .911 .904 .896 .887 .878 .868 .857 .846 73
74 .956 .952 .948 .944 .939 .934 .929 .922 .916 .909 .901 .893 .884 .874 .864 .853 74
75 .959 .955 .951 .947 .943 .938 .932 .927 .920 .913 .906 .898 .889 .880 .870 .859 75
76 .961 .958 .954 .950 .946 .941 .936 .931 .924 .918 .911 .903 .895 .886 .876 .866 76
77 .963 .960 .957 .953 .949 .944 .940 .934 .929 .922 .916 .908 .900 .892 .882 .873 77
78 .965 .962 .959 .955 .952 .948 .943 .938 .933 .927 .920 .913 .906 .897 .888 .879 78
79 .967 .964 .961 .958 .954 .951 .946 .942 .936 .931 .925 .918 .911 .903 .894 .885 79
</TABLE>
NOTE: Factors for additional age combinations are available from the
Administrator.
-57-
<PAGE>
SPECIAL PROVISION D
SPECIAL JOINT PENSION WITH SPOUSE
FACTORS USED TO DETERMINE THE REDUCED ANNUAL RATE
OF RETIREMENT ANNUITY PAYABLE TO JOINT PENSIONERS
WHO ELECT THE SPECIAL JOINT PENSION OPTION WITH THEIR SPOUSE
100% OPTION ELECTION
--------------------
(continued)
<TABLE>
<CAPTION>
SPOUSE'S SPOUSE'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 RETIREMENT
- ------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- -----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
80 .969 .967 .964 .961 .957 .953 .949 .945 .940 .935 .929 .923 .916 .908 .900 .891 80
81 .971 .969 .966 .963 .960 .956 .952 .948 .944 .939 .933 .927 .920 .913 .906 .897 81
82 .973 .970 .968 .965 .962 .959 .955 .951 .947 .942 .937 .931 .925 .918 .911 .903 82
83 .975 .972 .970 .967 .965 .961 .958 .954 .950 .946 .941 .936 .930 .923 .916 .909 83
84 .976 .974 .972 .969 .967 .964 .961 .957 .953 .949 .945 .939 .934 .928 .921 .914 84
85 .978 .976 .974 .971 .969 .966 .963 .960 .956 .952 .948 .943 .938 .932 .926 .919 85
86 .979 .977 .975 .973 .971 .968 .966 .963 .959 .956 .951 .947 .942 .937 .931 .924 86
87 .981 .979 .977 .975 .973 .971 .968 .965 .962 .958 .955 .950 .946 .941 .935 .929 87
88 .982 .980 .979 .977 .975 .973 .970 .967 .965 .961 .958 .954 .949 .945 .939 .934 88
89 .983 .982 .980 .978 .976 .974 .972 .970 .967 .964 .961 .957 .953 .948 .943 .938 89
</TABLE>
NOTE: Factors for additional age combinations are available from the
Administrator.
-58-
<PAGE>
SPECIAL PROVISION E
As in Effect Prior to January 1, 1976
A PARTICIPANT who is rehired after a BREAK IN SERVICE shall be treated as a
new PARTICIPANT for all purposes, and the PARTICIPANT's SERVICE and compensation
before the BREAK IN SERVICE shall not be recognized for any purpose of the PLAN,
except as follows:
(a) Upon either the death or retirement of a PARTICIPANT with broken
SERVICE, the last period of CREDITED SERVICE immediately preceding the
PARTICIPANT's latest employment date by EMPLOYER shall be counted as
SERVICE provided:
(1) The PARTICIPANT has accrued at least five years of SERVICE
since last re-employed by EMPLOYER, and
(2) The PARTICIPANT was last re-employed by EMPLOYER within five
years of the date the PARTICIPANT's latest previous employment was
terminated; and
(3) The PARTICIPANT had accrued at least five years of CREDITED
SERVICE prior to the date the PARTICIPANT's last previous employment
with EMPLOYER terminated.
(b) All other periods of prior employment with EMPLOYER, if any,
shall not be counted as SERVICE.
SPECIAL PROVISION F
CREDITED SERVICE
(a) As in effect prior to January 1, 1976:
All SERVICE prior to ACTUAL RETIREMENT DATE, provided the
PARTICIPANT joined the PLAN on the date when the PARTICIPANT first became
eligible and participated therein continuously thereafter. An EMPLOYEE who
first became eligible to join the COMPANY's Retirement PLAN prior to
January 1, 1969, was permitted a grace period of six months beyond the
EMPLOYEE'S eligibility date. An EMPLOYEE who first became eligible to join
the PLAN on or after January 1, 1969, was permitted a grace period of 60
days beyond the EMPLOYEE'S eligibility date. Subject to these grace
periods, if an EMPLOYEE did not become a PARTICIPANT when first eligible
the EMPLOYEE'S CREDITED SERVICE did not begin until the EMPLOYEE became a
PARTICIPANT. If a PARTICIPANT suspended contributions at any time between
January 1, 1969, and December 31, 1972, inclusive. CREDITED SERVICE did
not accrue to the PARTICIPANT after the date of such suspension of
contributions. CREDITED SERVICE did not include any time for which a
vacation allowance may be paid subsequent to an EMPLOYEE'S NORMAL
RETIREMENT DATE.
(b) Effective April 1, 1981:
An EMPLOYEE who first became eligible to join the PLAN prior to
January 1, 1973, but who for any reason did not do so, shall, except those
EMPLOYEES who have had their CREDITED SERVICE previously adjusted by action
of the EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE (EBAC), be allowed the
opportunity to have such lost CREDITED SERVICE restored. An EMPLOYEE'S
CREDITED SERVICE shall not be adjusted or restored except as follows:
(1) Prior to April 1, 1982, any EMPLOYEE described above shall,
upon application to EBAC, be permitted to buy back any portion of the
five years of lost CREDITED SERVICE
-59-
<PAGE>
immediately preceding the latest date on which an EMPLOYEE became a
member of the PLAN. Such restored CREDITED SERVICE shall not, in
combination with current SERVICE, exceed PARTICIPANT's actual COMPANY
SERVICE. The cost for restoring such CREDITED SERVICE shall be
computed at the rate of five percent of an EMPLOYEE'S current monthly
wage rate for each month of restored CREDITED SERVICE.
(2) In addition to the above, and prior to April 1, 1982, any
EMPLOYEE described above shall, upon application to EBAC, be permitted
to buy back any portion of the lost CREDITED SERVICE which is in
excess of the five years permitted in (1) above. The cost for
restoring such excess CREDITED SERVICE shall be computed at the rate
of ten percent of an EMPLOYEE'S current monthly wage rate for each
month of restored excess CREDITED SERVICE.
For the purpose of applying Section 13 (Withdrawal of PARTICIPANT
Contributions on Termination of Employment) only that portion of the
payment made above, for restoration of lost CREDITED SERVICE, which
the EMPLOYEE would have contributed had the EMPLOYEE participated in
the PLAN at that time will be considered as CONTRIBUTIONS.
SPECIAL PROVISION G
PENSION AND LTD ADJUSTMENTS
---------------------------
(a) Effective December 31, 1997, the PENSION of any PARTICIPANT who
retired or the PENSION of a person receiving a SPOUSE's PENSION or a JOINT
PENSION, will be increased as follows:
<TABLE>
<CAPTION>
Increase
--------
<S> <C>
Retired on or before 12/31/78 9.0%
Retired between 1/1/79 and 12/31/86 5.0%
Retired between 1/1/87 and 12/31/92 2.5%
</TABLE>
A minimum monthly increase of $50 will be provided to retirees with at
least 30 years of SERVICE, and a retirement date at or after normal
retirement age. A minimum monthly increase of $25 will be provided to
surviving SPOUSES of such retirees.
(b) The above adjustments shall apply to those Participants who are
receiving Long Term Disability Benefit payments.
(c) By Company resolutions dated June 17, 1964, February 25, 1969,
April 9, 1974, September 20, 1977, March 4, 1980, July 15, 1981, and
December 21, 1983, the amounts of pensions received by certain pensioners
were increased in accordance with the provisions of said resolutions. The
money required to fund these additional payments is based on actuarial
factors and the required contributions are paid into the Plan. The Company
intends to continue making these additional payments out of Plan assets and
on the same basis as it has done in the past.
-60-
<PAGE>
SPECIAL PROVISION H
MAXIMUM PENSION
This PLAN incorporates by reference the benefit limitations imposed by CODE
Section 415.
The annual benefit amount otherwise payable to a former EMPLOYEE at any
time will not exceed the maximum permissible amount under CODE Section 415. For
purposes of determining compliance with the Section 415 benefit limitations, the
limitation year shall be the PLAN YEAR. If the benefit the PARTICIPANT would
otherwise accrue in a limitation year would produce an annual benefit in excess
of the maximum permissible amount under CODE Section 415, then the rate of
accrual will be reduced so that the annual benefit will equal the maximum
permissible amount.
If a PARTICIPANT in this PLAN also participates in any defined contribution
plan maintained by an EMPLOYER, the sum of the PARTICIPANT'S "Defined Benefit
Fraction" and the PARTICIPANT'S "Defined Contribution Fraction" shall not exceed
1.0. In the event that in any PLAN YEAR the sum of the PARTICIPANT'S Defined
Benefit Fraction and the PARTICIPANT'S Defined Contribution Fraction exceed 1.0,
then the PENSION payable under this PLAN shall be reduced so that the sum of
such fractions in respect of that PARTICIPANT will not exceed 1.0."
For purposes of determining the PLAN'S compliance with CODE Section 415,
the annual benefit is a retirement benefit payable under the PLAN in the form of
a straight life annuity. Except as provided below, a benefit payable in a form
other than a straight life annuity must be adjusted to an actuarially equivalent
straight life annuity before applying the limitations of Section 415. The
interest rate assumption used to determine actuarial equivalence will be the
greater of rate used in Special Provision D or 5 percent. No actuarial
adjustment to the benefit is required for the value of a qualified joint and
survivor annuity, the value of benefits that are not directly related to
retirement benefits (such as the qualified disability benefit, pre-retirement
death benefits, and post-retirement medical benefits), and the value of post-
retirement cost-of-living increases made in accordance with 415(d) of the CODE.
The annual benefit does not include any benefits attributable to EMPLOYEE
contributions or rollover contributions or the assets transferred from a
qualified plan not maintained by the COMPANY.
Compensation, for purposes of determining the PLAN'S compliance with
Section 415 of the CODE, shall mean all of each PARTICIPANT'S wages, tips, and
other Box 10 compensation on the PARTICIPANT'S Form W-2.
SPECIAL PROVISION I
If prior to 1989 SERVICE terminates with at least ten years of SERVICE, or
with at least five years of SERVICE after 1988, the PENSION the PARTICIPANT
would otherwise be entitled to receive shall be reduced because of the
withdrawal.
If the withdrawal occurs prior to age 55, the yearly PENSION payable at the
NORMAL RETIREMENT DATE, prior to reduction for EARLY RETIREMENT (if any), shall
be reduced by the product of the amount withdrawn and the applicable factor
selected from the following table:
-61-
<PAGE>
<TABLE>
<CAPTION>
Age Last Age Last
Birthday At Birthday At
Refund Date Factor Refund Date Factor
- ------------- ------ ----------- ------
<S> <C> <C> <C>
25 .6705 40 .3225
26 .6385 41 .3072
27 .6081 42 .2925
28 .5792 43 .2786
29 .5516 44 .2653
30 .5253 45 .2527
31 .5003 46 .2407
32 .4765 47 .2292
33 .4538 48 .2183
34 .4321 49 .2079
35 .4116 50 .1980
36 .3920 51 .1886
37 .3733 52 .1796
38 .3556 53 .1710
39 .3386 54 .1629
</TABLE>
If the withdrawal occurs after age 55, the yearly PENSION payable at the
ACTUAL RETIREMENT DATE, after reduction for EARLY RETIREMENT (if any), shall be
reduced by the product of the amount withdrawn and the applicable factor
selected from the following table:
<TABLE>
<CAPTION>
Age Last
Birthday At
Refund Date Factor
----------- ------
<S> <C>
55 .0775
56 .0792
57 .0810
58 .0829
59 .0849
60 .0871
61 .0894
62 .0919
63 .0946
64 .0975
65 .1000
66 .1039
67 .1074
68 .1111
69 .1151
70 .1192
</TABLE>
Notwithstanding the foregoing, in no event will the PENSION be reduced by
more than one-third.
The monthly reduction is computed by multiplying the appropriate factor
times the PARTICIPANT'S contributions including interest and dividing that
amount by twelve months.
-62-
<PAGE>
EXAMPLE:
- --------
Assumptions: Age 60
Basic Pensions = $1,500.00/month
Contributions = $6,000.00
Interest = 3,000.00
---------
Total = $9,000.00 - 65.33*
------
Pension with contributions = $1,434.67/month
plus interest withdrawn
_______________________
*Calculation: (Contributions + Interest x Age 60 Refund Factor) : 12 Months
($9,000 x .0871 : 12 Months = $65.33)
-63-
<PAGE>
SPECIAL PROVISION J
TOP HEAVY PROVISIONS
--------------------
(a) General Rule
------------
For any PLAN YEAR for which this PLAN is a "top-heavy plan" as defined in
subsection (g) below, any other provisions of this PLAN to the contrary
notwithstanding, this PLAN shall be subject to the following provisions:
(1) The vesting provisions of subsection (b).
(2) The minimum benefit provisions of subsection (c).
(3) The limitation on compensation set by subsection (d).
(4) The limitation on benefits set by subsection (e).
If any individual has not performed SERVICE for an EMPLOYER at any time
during the five-year period ending on the last day of the preceding PLAN YEAR,
any accrued benefit for such individual shall not be taken into account for
purposes of determining whether the PLAN is a "top-heavy plan." For purposes of
determining whether the PLAN is top-heavy, a non-key EMPLOYEE'S accrued benefit
must be determined as if it is accrued not more rapidly than the slowest accrual
rate permitted under CODE Section 411(b)(1)(C) (i.e., the "fractional rule").
(b) Vesting Provisions
------------------
Each PARTICIPANT who (i) has completed an hour of SERVICE during any PLAN
YEAR in which the PLAN is top heavy and (ii) has completed the number of years
of credited SERVICE specified in the following table shall have a nonforfeitable
right to the percentage of the benefit accrued under this PLAN derived from
EMPLOYER contributions correspondingly specified in the following table:
<TABLE>
<CAPTION>
Years of Percentage of
credited service: nonforfeitable
benefit:
<S> <C>
2 20
3 40
4 60
5 80
6 or more 100
"Credited service" as used in this subsection (b) shall constitute SERVICE
as defined in Section 22 of this PLAN.
</TABLE>
Each PARTICIPANT's nonforfeitable accrued benefit shall not be less than
his nonforfeitable accrued benefit determined as of the last day of the last
PLAN YEAR in which the PLAN was a top-heavy PLAN. If the PLAN ceases to be top-
heavy, each PARTICIPANT with five or more years of SERVICE, whether or not
consecutive, shall have his nonforfeitable accrued benefit determined in
accordance with this Section and Section 3. Each such PARTICIPANT shall have
the right to elect the applicable schedule within 60 days after the day the
PARTICIPANT is issued written notice by the EMPLOYEE BENEFIT ADMINISTRATIVE
COMMITTEE, or as otherwise provided in accordance with regulations issued under
the provision of the Internal Revenue CODE of 1954, as amended, relating to
changes in the vesting schedule.
-64-
<PAGE>
This provision shall apply without regard to contributions or benefits
under Social Security or any other Federal or State law.
(c) Minimum Benefit Provisions
--------------------------
Each PARTICIPANT who (i) is a non-key employee (as defined in subsection
(i) below) and (ii) has completed 1,000 hours of SERVICE during any PLAN YEAR
shall be entitled to an accrued benefit in the form of an annual retirement
benefit (as defined in paragraph (1) below) that shall be not less than the
applicable percentage (as defined in paragraph (2) below) of the PARTICIPANT's
average annual compensation for years in the testing period (as defined in
paragraph (3) below).
(1) "Annual retirement benefit" means a benefit payable annually in the
form of a single life annuity (with no ancillary benefits) beginning
at NORMAL RETIREMENT DATE as defined in Section 22 of this PLAN or its
actuarial equivalent.
(2) "Applicable percentage" means the lesser of two percent multiplied by
the number of top-heavy PLAN YEARs of service (as defined in paragraph
(4) below) of 20 percent.
(3) "Testing period" means, with respect to a PARTICIPANT, the period of
consecutive years (not exceeding five) of SERVICE during which the
PARTICIPANT had the greatest aggregate compensation from the EMPLOYER.
The testing period shall not include any year of SERVICE not included
as a year of SERVICE as defined in paragraph (4) below. The testing
period shall also not include any year of SERVICE that ends in a PLAN
YEAR beginning before January 1, 1984 or during which the PLAN was not
a top-heavy plan.
(4) "Years of service" means SERVICE as defined in Section 3 of this PLAN.
Benefits taken into account under this Subsection shall not include any
benefits payable under the Social Security Act or any other Federal or State
law.
(d) Limitation on Benefits
----------------------
In the event that the EMPLOYER also maintains a defined contribution PLAN
providing contributions on behalf of PARTICIPANTS in this PLAN, one of the two
following provisions shall apply:
(1) If for the PLAN YEAR this PLAN would not be a "top-heavy plan" as
defined in subsection (g) below if "90 percent" were substituted for
"60 percent," then subsection (c) shall apply for such PLAN YEAR as if
amended so that the "applicable percentage" means the lesser of three
percent multiplied by the number of years of SERVICE (as defined in
paragraph (4) of subsection (c)) during which the PLAN would be top-
heavy (as defined in subsection (g)) and the overall applicable
percentage does not exceed the lesser of 30% or 20% plus 1% for each
year the PLAN is taken into account under this subsection ((e)(1)).
(2) If for the PLAN YEAR this PLAN would continue to be a "top-heavy plan"
as defined in subsection (g) below if "90 percent" were substituted
for "60 percent," then the denominator of both the defined
contribution PLAN fraction and the defined benefit plan fraction shall
be calculated as set forth in Special Provision H for the limitation
year ending in such PLAN YEAR by substituting "1.0" for "1.25," except
with respect to any individual for whom there are no EMPLOYER
contributions, forfeitures or voluntary nondeductible contributions
allocated or any accruals for such individual under the defined
benefit PLAN. Furthermore, the transitional rule set forth in CODE
Section 415 shall be applied by substituting "$41,500" for $51,875".
-65-
<PAGE>
(e) Coordination with Other Plans
-----------------------------
In the event that another defined contribution or defined benefit PLAN
maintained by the EMPLOYER provides contributions or benefits on behalf of
PARTICIPANTS in this PLAN, such other PLAN shall be treated as a part of this
PLAN pursuant to applicable principles (such as Rev. Rul. 81-202 or any
successor ruling) in determining whether this PLAN satisfies the requirements of
subsection (b), (c) and (d). Such determination shall be made upon the advice
of counsel by the EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE.
(f) Top-heavy Plan Definition
-------------------------
This PLAN shall be a "top-heavy plan" for any PLAN YEAR if, as of the
determination date (as defined in subsection (g)(1) below), the present value
(as determined in subsection (g)(2) below) of the cumulative accrued benefits
under the PLAN for participants (including former participants) who are key
employees (as defined in subsection (h) below) exceeds 60 percent of the present
value of the cumulative accrued benefits under the PLAN for all participants,
excluding former key employees, or if this PLAN is required to be in a
aggregation group (as defined in subsection (g)(3) below) which for such PLAN
YEAR is a top-heavy group (as defined in subsection (g)(4) below).
(1) "Determination date" means for any PLAN YEAR the last day of the
immediately preceding PLAN YEAR.
(2) The present value shall be determined as of the most recent valuation
date that is within the twelve-month period ending on the
determination date and as described in the regulations under the
Internal Revenue CODE as of 1954, as amended.
(3) "Aggregation group" means the group of plans, if any, that includes
both the group of plans that are required to be aggregated and the
group of plans that are permitted to be aggregated.
(A) The group of plans that are required to be aggregated (the
"required aggregation group") includes
(i) Each plan of the EMPLOYER (as defined in subsection (j)
below) in which a key employee is a PARTICIPANT, including
collectively-bargained plans, and
(ii) Each other plan, including collectively-bargained plans of
the EMPLOYER (as defined in subsection (j) below) which
enables a plan in which a key employee is a PARTICIPANT to
meet the requirements of the Internal Revenue CODE of 1954,
as amended, prohibiting discrimination as to contributions
or benefits in favor of employees who are officers,
shareholders or the highly-compensated or prescribing the
minimum participation standards.
(B) The group of plans that are permitted to be aggregated (the
"permissive aggregation group") includes the required aggregation
group plus one or more plans of the EMPLOYER (as defined in
subsection (j) below) that is not part of the required
aggregation group and that the EMPLOYEE BENEFIT ADMINISTRATIVE
COMMITTEE certifies as constituting a plan within the permissive
aggregation group. Such plan or plans may be added to the
permissive aggregation group only if, after the addition, the
aggregation group as a whole continue not to discriminate as to
contributions or benefits in favor of officers, shareholders or
the highly-compensated and to meet the minimum participation
standards under the Internal Revenue CODE of 1954, as amended.
(4) "Top-heavy group" means the aggregation group, if as of the applicable
determination date, the sum of the present value of the cumulative accrued
benefits for key employees under all defined benefit plans included in the
aggregation group plus the aggregate of the accounts of key employees
under all defined
-66-
<PAGE>
contribution plans included in the aggregation group exceeds 60% of the sum
of the present value of the cumulative accrued benefits for all employees,
excluding former key employees, under all such defined benefit plans plus
the aggregate accounts for all employees, excluding former key employees,
under such defined contribution plans. If the aggregation group that is a
top-heavy group is a required aggregation group, each Plan in the group
will be top heavy. If the aggregation group that is a top-heavy group is a
permissive aggregation group, only those plans that are part of the
required aggregation group will be treated as top-heavy. If the aggregation
group is not a top-heavy group, no plan within such group will be top-
heavy.
(5) In determining whether this PLAN constitutes a "top-heavy plan", the
EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE (or its agent) shall make the
following adjustments in connection therewith:
(A) When more than one plan is aggregated, the EMPLOYEE BENEFIT
ADMINISTRATIVE COMMITTEE shall determine separately for each plan as
of each plan's determination date the present value of the accrued
benefits or account balance. The results shall then be aggregated by
adding the results of each plan as of the determination dates for such
plans that fall within the same calendar year.
(B) In determining the present value of the cumulative accrued benefit or
the amount of the account of any employee, such present value or
account shall include the amount in dollar value of the aggregate
distributions made to such employee under the applicable plan during
the five-year period ending on the determination date, unless
reflected in the value of the accrued benefit or account balance as of
the most recent valuation date. Such amounts shall include
distributions to employees which represented the entire amount
credited to their accounts under the applicable plan.
(C) Further, in making such determination, in any case where an individual
is a "non-key employee" as defined in subsection (h) below, with
respect to an applicable plan, but was a key employee with respect to
such plan for any prior PLAN YEAR, any accrued benefit and any account
of such employee shall be altogether disregarded. For this purpose,
to the extent that a key employee is deemed to be a key employee if he
met the definition of key employee within any of the four preceding
PLAN YEARS, this provision shall apply following the end of such
period of time.
(g) Key Employee
------------
The term "key employee" means any employee or former employee under this
PLAN who, at any time during the PLAN YEAR containing the determination date or
during any of the four preceding PLAN YEARS, is or was one of the following:
(1) An officer of the EMPLOYER (as defined in subsection (j)). Whether an
individual is an officer shall be determined by the EMPLOYEE BENEFIT
ADMINISTRATIVE COMMITTEE on the basis of all the facts and
circumstances, such as an individual's authority, duties and term of
office, not on the mere fact that the individual has the title of an
officer. For any such PLAN YEAR, there shall be treated as officers
no more than the lesser of:
(A) 50 employees, or
(B) the greater of three employees or 10 percent of the employees.
For this purpose, the highest-paid officers shall be selected.
Business organizations other than corporations shall be deemed to have
no officers.
(2) One of the ten employees owning (or considered as owning, within the
meaning of the constructive ownership rules of the Internal Revenue
CODE of 1954, as amended) the largest
-67-
<PAGE>
interests in the EMPLOYER (as defined in subsection (j)). An employee
who has some ownership interest is considered to be one of the top ten
owners unless at least ten other employees own a greater interest than
that employee. However, an employee will not be considered a top ten
owner for a PLAN YEAR if the employee earns less than the maximum
dollar limitation on contributions and other annual additions to a
PARTICIPANT's account in a defined contribution plan under the
Internal Revenue CODE of 1954, as amended, as in effect for the
calendar year in which the determination date falls.
(3) Any person who owns (or is considered as owning within the meaning of
the constructive ownership rules of the CODE more than five percent of
the outstanding stock of the EMPLOYER or stock possessing more than
five percent of the combined total voting power of all stock of the
EMPLOYER.
(4) A one percent owner of the EMPLOYER having an annual compensation from
the EMPLOYER of more than $150,000, and possessing more than five
percent of the combined total voting power of all stock of the
EMPLOYER. For purposes of this subsection, compensation means all
items includable as compensation for purposes of applying the
limitations on contributions and other annual additions to a
PARTICIPANT's account in a defined contribution plan and the maximum
benefit payable under a defined plan under the Internal Revenue CODE
of 1954, as amended.
For purposes of parts (1), (2), (3) and (4) of this definition, a
beneficiary of a key employee shall be treated as a key employee. For
purposes of parts (3) and (4), each EMPLOYER is treated separately
(without regard to the definition in subsection (j)) in determining
ownership percentages; but, in determining the amount of compensation,
the definition of EMPLOYER in subsection (j) is taken into account.
(h) Non-Key Employee
----------------
The term "non-key employee" means any employee (and any beneficiary of an
employee) who is not a key employee.
(i) Employer
--------
The term "employer" means EMPLOYER as defined in Section 22 of this PLAN.
(j) Collective Bargaining Rules
---------------------------
The provisions of subsection (b), (c) and (d) above do not apply with
respect to any employee included in a unit of employees covered by a collective
bargaining agreement unless the application of such subsections has been agreed
upon with the collective bargaining agent.
(k) Distributions to Key Employees
------------------------------
Any other provisions of this PLAN to the contrary notwithstanding,
distribution of the entire interest in this PLAN of each PARTICIPANT who is or
any time has been a key employee shall commence no later than the end of the
taxable year of the PARTICIPANT in which the PARTICIPANT attains age 70 1/2.
SPECIAL PROVISION K
I. Introduction
------------
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<PAGE>
This Special Provision K, an amendment to the COMPANY'S RETIREMENT
PLAN, adopted by the COMPANY'S Board of Directors on December 17, 1986, is
the controlling and definitive statement of the Voluntary Retirement
Incentive program ("VRI"). The purpose of the VRI is to reduce a surplus
--- ---
of COMPANY employees in certain designated operations. The VRI is a part
---
of the RETIREMENT PLAN, and except as otherwise provided in this Special
Provision K, shall be administered in accordance with and subject to the
terms of the RETIREMENT PLAN. Terms in all capitals are defined in Section
22 of the RETIREMENT PLAN. Terms underlined are defined in Section VII of
Special Provision K.
The decision of an Eligible Employee to elect to participate in the
-------- --------
VRI is wholly voluntary, and an election not to participate in the VRI
--- ---
shall in no way affect benefits under the RETIREMENT PLAN to which an
Eligible Employee might otherwise be entitled.
-------- --------
II. Eligibility to Participate in the VRI
-------------------------------------
Eligible Employees shall be any full-time active employee of the
COMPANY or of a Participating Employer, born on or before January 1, 1937,
------------- --------
who has at least 15 years of SERVICE on January 1, 1987. For purposes of
this VRI only, the term active employee shall not include an employee of
---
the COMPANY or a Participating Employer, (i) who, on January 1, 1987, is
------------- --------
presently receiving benefits under Part B of the Group Life Insurance and
Long Term Disability Plan; (ii) who, as of January 1, 1987, is on personal
or medical leave, with or without pay; or (iii) who is a former employee
whose ACTUAL RETIREMENT DATE was November 1, 1986, or earlier.
Anything herein to the contrary notwithstanding, an Eligible Employee
-------- --------
who (i) elects not to participate in the VRI and (ii) prior to January 1,
---
1988, is severed under the Company's Corporate Severance Program, shall be
entitled to receive a Basic VRI Benefit under this Special Provision K.
---
Such Basic VRI Benefit shall be in lieu of any benefits to which the
----- --- -------
Eligible EMPLOYEE would otherwise be entitled to receive under the
-------- --------
Corporate Severance Program. For purposes of calculating the Basic VRI
----- ---
Benefit under this provision, the VRI Retirement Date shall be the first of
------- --- ---------- ----
the month following the month in which the employee is severed.
III. Election to Participate
-----------------------
An Eligible EMPLOYEE must elect to participate in the VRI by
-------- -------- ---
submitting a completed and signed VRI enrollment form which is received by
---
a designated COMPANY representative no later than January 30, 1987, except
that Eligible Employees who are employed by Pacific Gas Transmission
-------- ---------
Company will have until the close of business, September 30, 1987, to
submit their completed and signed VRI enrollment form to a designated
---
employer representative. An Eligible EMPLOYEE who fails to submit a timely
-------- --------
enrollment form shall be deemed to have elected not to participate in the
VRI. The election of an Eligible Employee not to participate in the VRI,
--- -------- -------- ---
whether through failure to timely submit a VRI election form or otherwise,
---
shall be conclusive and binding on the employee, employee's spouse, heirs,
and assigns.
IV. VRI Benefit
-----------
A. Basic VRI Benefit. An Eligible Employee who elects in a timely manner
----- --- ------- -------- --------
to participate in the VRI shall be entitled to receive a Basic VRI
--- ----- ---
Benefit under the RETIREMENT PLAN equal to the BASIC PENSION benefit
-------
formula calculated under Subsection 6(a)(1), with the following
adjustments:
-69-
<PAGE>
1. BASIC MONTHLY SALARY shall mean the PARTICIPANT'S BASIC MONTHLY
SALARY on January 1, 1986, increased by 5 percent;
2. SERVICE shall mean the PARTICIPANT'S SERVICE as of the VRI
---
Retirement Date selected by the PARTICIPANT, increased by five
---------- ----
years; and
3. The EARLY RETIREMENT PENSION reduction provisions of Subsection
7(b) shall not apply to any Basic VRI Benefit payable under this
----- --- -------
Special Provision K.
B. A Basic VRI Benefit shall be payable as of the VRI Retirement Date
----- --- ------- --- ---------- ----
selected by the Eligible Employee and shall be paid as soon as
-------- --------
practicable after the applicable VRI Retirement Date. Eligible
--- ---------- ---- --------
Employees who elect to participate in the VRI shall not be subject to
--------- ---
the age 55 requirement contained in Section 8.
C. Section 10 of the RETIREMENT PLAN shall control the conditions under
which other forms of pension may be substituted for the Basic VRI
----- ---
Benefit. Thus, although a PARTICIPANT is entitled to receive a Basic
------- -----
VRI Benefit, if the PARTICIPANT is married, Section 10(b) of the
--- -------
RETIREMENT PLAN requires that the Basic VRI Benefit be converted to a
----- --- -------
MARITAL PENSION, unless the PARTICIPANT'S spouse CONSENTS to an
alternative form of pension.
D. The Basic VRI Benefit payable under this Special Provision K shall be
----- -------
in lieu of any benefit which might otherwise be payable under the
RETIREMENT PLAN.
E. A participant who elects to participate in VRI shall also be entitled
---
to make the elections provided in Sections 10 (Forms of Pension), 12
(Withdrawal of Participant Contributions on Termination of
Employment), 13 (Death Benefits), and 14 (Facility of Payment).
V. VRI Retirement Dates
--------------------
At such time as an employee elects to participate in the VRI, he shall
---
select a VRI Retirement Date. For purposes of this Special Provision K, a
--- ---------- ----
VRI Retirement Date shall mean one of the following:
--- ---------- ----
A. For Eligible Employees other than Eligible Employees employed by
-------- --------- -------- ---------
Pacific Gas Transmission Company:
1. February 1, 1987, provided, however, that eligible participants
have completed all necessary VRI enrollment procedures prior to
---
January 15, 1987;
2. March 1, 1987;
3. April 1, 1987; or
4. The first of any month during the period commencing with March 1,
1987, and ending with and including October 1, 1987. This
Subsection V.A.4. shall only apply in the event that the COMPANY
or the Participating Employer, as the case may be, has a
------------- --------
demonstrated business need which requires the retention of the
Eligible Employee. Should the business needs of the COMPANY or
-------- --------
of a Participating Employer require the retention of an Eligible
------------- -------- --------
Employee beyond October 1, 1987, the VRI Retirement Date shall be
-------- --- ---------- ----
the first of any month during the period subsequent to October 1,
1987, and ending with and including July 1, 1988. The selection
of any such VRI Retirement Date subsequent to October 1, 1987,
--- ---------- ----
shall be made by the COMPANY, or Participating Employer, through
------------- --------
an appropriate member of the COMPANY's Management Committee.
-70-
<PAGE>
B. For Eligible Employees employed by Pacific Gas Transmission Company:
-------- ---------
1. October 1, 1987, provided, however, that eligible participants
have completed all necessary VRI enrollment procedures prior to
---
September 15, 1987;
2. November 1, 1987; or
3. The first of any month during the period commencing with December
1, 1987, and ending with and including June 1, 1988. This
Subsection V.B.3. shall only apply in the event that Pacific Gas
Transmission Company has a demonstrated need which requires the
retention of the Eligible Employee.
-------- --------
The VRI Retirement Date selected shall also be the date as of
--- ---------- ----
which an Eligible Employee ceases to be an employee of the COMPANY or
-------- --------
a Participating Employer, as the case may be.
------------- --------
VI. Revocation of Election
----------------------
An Eligible Employee who has elected to participate in the VRI may
-------- -------- ---
revoke his election, provided, however, that any such revocation shall only
be effective if received by the COMPANY on or before January 30, 1987, for
those Eligible Employees who elected a VRI Retirement Date of February 1,
-------- --------- --- ---------- ----
1987; February 15, 1987, for those Eligible Employees who elected a VRI
-------- --------- ---
Retirement Date of March 1, 1987, or later; September 30, 1987, for those
---------- ----
Eligible Employees of Pacific Gas Transmission Company who elected a VRI
-------- --------- ---
Retirement Date of October 1, 1987; or October 15, 1987, for those Eligible
---------- ---- --------
Employees of Pacific Gas Transmission Company who elected a VRI Retirement
--------- --- ----------
Date of November 1, 1987, or later.
----
VII. Definitions
-----------
A. Basic VRI Benefit: The benefit calculated under Section IV of this
----- --- -------
Special Provision K.
B. Eligible Employee: An employee of the COMPANY or of a Participating
-------- --------
Employer who has met the eligibility criteria as set forth in Section
II on January 1, 1987. For purposes of this Special Provision K only,
Eligible Employee shall not include any COMPANY Officer at the vice
presidential level, or above.
C. Participating Employer: Natural Gas Corporation, Pacific Gas
------------- --------
Transmission Company, and Pacific Service Employees Association.
D. VRI: The COMPANY's Voluntary Retirement Incentive program as set
---
forth in this Special Provision K.
E. VRI Retirement Date: The date selected by an Eligible Employee under
--- ---------- ----
Section V of this Special Provision K.
SPECIAL PROVISION M
I. Introduction
------------
This Special Provision M, an amendment to the COMPANY'S RETIREMENT
PLAN, adopted by the COMPANY'S Board of Directors on February 17, 1993, is
the controlling and definitive statement of the Voluntary Retirement
Incentive program ("VRI"). The purpose of the VRI is to reduce a surplus
--- ---
of
-71-
<PAGE>
COMPANY employees in certain designated operations. The VRI is a part
---
of the RETIREMENT PLAN, and except as otherwise provided in this Special
Provision M, shall be administered in accordance with and subject to the
terms of the RETIREMENT PLAN. Terms in all capitals are defined in Section
22 of the RETIREMENT PLAN. Terms underlined are defined in Section VII of
Special Provision M.
The decision of an Eligible Employee to elect to participate in the
-------- --------
VRI is wholly voluntary, and an election not to participate in the VRI
--- ---
shall in no way affect benefits under the RETIREMENT PLAN to which an
Eligible Employee might otherwise be entitled.
-------- --------
II. Eligibility to Participate in the VRI
-------------------------------------
An Eligible Employee shall be any active employee of the COMPANY whose
-------- --------
base job classification on February 17, 1993, is in a Targeted Organization
-------- ------------
and who was born on or before December 31, 1942, and has at least 15 years
of SERVICE on December 31, 1992. For purposes of this VRI only, the term
---
active employee shall not include an employee of the COMPANY (i) who, on
February 17, 1993, is presently receiving benefits under Part B of the
Group Life Insurance and Long Term Disability Plan; (ii) who is on a leave
of absence, with or without pay, which began on or prior to August 17,
1992; or (iii) who is a former employee whose ACTUAL RETIREMENT DATE was
February 1, 1993, or earlier.
III. Election to Participate
-----------------------
An Eligible Employee must elect to participate in the VRI by
-------- -------- ---
submitting a completed and signed VRI enrollment form which is received by
a designated COMPANY representative no later than April 23, 1993. An
Eligible Employee who fails to submit a timely enrollment form shall be
-------- --------
deemed to have elected not to participate in the VRI. The election of an
---
Eligible Employee not to participate in the VRI, whether through failure to
-------- -------- ---
submit a timely VRI election form or otherwise, shall be conclusive and
---
binding on the employee, employee's spouse, heirs, and assigns.
IV. VRI Benefit
-----------
A. Basic VRI Benefit. An Eligible Employee who elects in a timely manner
----- --- ------- -------- --------
to participate in the VRI shall be entitled to receive a Basic VRI
--- ----- ---
Benefit under the RETIREMENT PLAN equal to the BASIC PENSION benefit
-------
formula calculated under Subsection 6(a)(1), with the following
adjustments:
1. SERVICE shall mean the PARTICIPANT'S SERVICE as of last VRI
---
Retirement Date for such Eligible Employee, increased by three
---------- ---- -------- --------
years; and
2. The EARLY RETIREMENT PENSION reduction provisions of Subsection
7(b) shall not apply to any Basic VRI Benefit payable under this
----- --- -------
Special Provision M.
B. A Basic VRI Benefit shall be payable as of the VRI Retirement Date
----- --- ------- --- ---------- ----
selected by the Eligible Employee and shall be paid as soon as
-------- --------
practicable after the applicable VRI Retirement Date. Eligible
--- ---------- ---- --------
Employees who elect to participate in the VRI shall not be subject to
--------- ---
the age 55 requirement contained in Section 8.
C. Section 10 of the RETIREMENT PLAN shall control the conditions under
which other forms of pension may be substituted for the Basic VRI
----- ---
Benefit. Thus, although a PARTICIPANT is
-------
-72-
<PAGE>
entitled to receive a Basic VRI Benefit, if the PARTICIPANT is
----- --- -------
married, Section 10(b) of the RETIREMENT PLAN requires that the Basic
-----
VRI Benefit be converted to a MARITAL PENSION, unless the
--- -------
PARTICIPANT'S spouse CONSENTS to an alternative form of pension.
D. The Basic VRI Benefit payable under this Special Provision M shall be
----- --- -------
in lieu of any benefit which might otherwise be payable under the
RETIREMENT PLAN.
E. A participant who elects to participate in VRI shall also be entitled
---
to make the elections provided in Sections 10 (Forms of Pension), 12
(Withdrawal of Participant Contributions on Termination of
Employment), 13 (Death Benefits), and 14 (Facility of Payment).
V. VRI Retirement Dates
--------------------
At such time as an employee elects to participate in the VRI, he shall
---
select a VRI Retirement Date. For purposes of this Special Provision M, a
--- ---------- ----
VRI Retirement Date shall mean one of the following:
--- ---------- ----
A. May 1, 1993;
B. June 1, 1993; or
C. The first of any month during the period commencing with July 1, 1993,
and ending with and including June 1, 1994. This Subsection C shall
only apply in the event that the COMPANY has a demonstrated business
need which requires the retention of the Eligible Employee. The
-------- --------
selection of any such VRI Retirement Date subsequent to June 1, 1993,
--- ---------- ----
can be made only with the written approval of both of the Company's
Executive Vice Presidents.
The VRI Retirement Date selected shall also be the date as of which an
--- ---------- ----
Eligible Employee ceases to be an employee of the COMPANY.
-------- --------
VI. Revocation of Election
----------------------
An Eligible Employee who has elected to participate in the VRI may
-------- -------- ---
revoke his election, provided, however, that any such revocation shall only
be effective if received by the COMPANY on or before April 23, 1993, for
those Eligible Employees who elected a VRI Retirement Date of May 1, 1993;
-------- --------- --- ---------- ----
or April 30, 1993, for those Eligible Employees who elected a VRI
-------- --------- ---
Retirement Date of June 1, 1993, or later.
---------- ----
VII. Definitions
-----------
A. Basic VRI Benefit: The benefit calculated under Section IV of this
----- --- -------
Special Provision M.
B. Eligible Employee: An employee of the COMPANY who has met the
-------- --------
eligibility criteria as set forth in Section II. For purposes of this
Special Provision M only, Eligible Employee shall not include any
COMPANY Officer.
C. Targeted Organization: Distribution Business Unit; Engineering and
---------------------
Construction Business Unit; Gas Supply Business Unit except the Gas
Dispatch Department and except employees with job levels of 32 and
above; Nuclear Operations Support Department; Nuclear Safety and
Regulatory Affairs Department; Nuclear Engineering and Construction
Services Department; Nuclear Business and Financial Management
Department; Nuclear Documentation and Support Department; Quality
Assurance Department; human resources departments, including business
unit
-73-
<PAGE>
human resources organizations being consolidated with corporate human
resources; computer and telecommunication services departments,
including business unit and corporate services organizations being
consolidated with corporate computer and telecommunication services
departments; Corporate Communications departments, including business
unit media and employee communications units being consolidated with
Corporate Communications departments; community and governmental
relations departments including regional public affairs units being
consolidated with corporate governmental relations departments; and
the Economics and Forecasting Department.
D. VRI: The COMPANY's Voluntary Retirement Incentive program as set
---
forth in this Special Provision M.
E. VRI Retirement Date: The date selected by an Eligible Employee under
--- ---------- ----
Section V of this Special Provision M.
SPECIAL PROVISION N
I. Introduction
This Special Provision N, an amendment to the COMPANY'S RETIREMENT
PLAN, authorized by the COMPANY'S Board of Directors on September 21, 1994,
is the controlling and definitive statement of the Voluntary Retirement
Incentive program ("VRI"). The purpose of the VRI is to reduce a surplus
--- ---
of COMPANY EMPLOYEES. The VRI is a part of the RETIREMENT PLAN, and except
---
as otherwise provided in this Special Provision N, shall be administered in
accordance with and subject to the terms of the RETIREMENT PLAN. Terms in
all capitals are defined in Section 22 of the RETIREMENT PLAN. Terms
underlined are defined in Section VII of Special Provision N.
The decision of an Eligible Employee to elect to participate in the
-------- --------
VRI is wholly voluntary, and an election not to participate in the VRI
--- ---
shall in no way affect benefits under the RETIREMENT PLAN to which an
Eligible Employee might otherwise be entitled.
-------- --------
II. Eligibility to Participate in the VRI
---
An Eligible Employee shall be any active EMPLOYEE of the COMPANY who
-------- --------
was born on or before September 30, 1944, and has at least 15 years of
SERVICE on September 30, 1994. For purposes of this VRI only, the term
---
active EMPLOYEE shall not include an EMPLOYEE of the COMPANY (i) who, on
September 30, 1994, is presently receiving benefits under Part B of the
Group Life Insurance and Long Term Disability Plan; (ii) who is on a leave
of absence, with or without pay, which began on or prior to March 30, 1994;
(iii) who elected to retire under Special Provision M of Part I of the
RETIREMENT PLAN or Special Provision N of Part II of the RETIREMENT PLAN;
(iv) who has received or is scheduled to receive severance benefits under
the COMPANY'S Workforce Management Program, Letter Agreement No. 93-42-PGE
and Letter Agreement No. 93-23esc, or under any other written agreement
between the COMPANY and the EMPLOYEE in which the EMPLOYEE has received
benefits in connection with the termination of such EMPLOYEE'S employment;
(v) who is a former EMPLOYEE who was terminated for cause; or (vi) who is a
former EMPLOYEE whose ACTUAL RETIREMENT DATE was July 1, 1994, or earlier.
III. Election to Participate
-74-
<PAGE>
An Eligible Employee must elect to participate in the VRI by
-------- -------- ---
completing and signing the VRI enrollment and waiver and release forms
---
provided by the COMPANY and returning the completed forms to a designated
COMPANY representative no later than November 21, 1994. An Eligible
--------
Employee who fails to submit timely both enrollment and waiver and release
--------
forms shall be deemed to have elected not to participate in the VRI. The
---
election of an Eligible Employee not to participate in the VRI, whether
-------- -------- ---
through failure to timely submit VRI election and waiver and release forms
---
or otherwise, shall be conclusive and binding on the EMPLOYEE, EMPLOYEE'S
spouse, heirs, and assigns.
IV. VRI Benefit
---
A. Basic VRI Benefit. An Eligible Employee who elects in a timely manner
----- --- ------- -------- --------
to participate in the VRI shall be entitled to receive a Basic VRI
--- ----- ---
Benefit under the RETIREMENT PLAN equal to the BASIC PENSION benefit
-------
formula calculated under Subsection 6(a)(1) with the following
adjustments:
1. SERVICE shall mean the PARTICIPANT'S SERVICE as of the VRI
---
Retirement Date for such Eligible Employee, increased by three
---------- ---- -------- --------
years; and
2. The EARLY RETIREMENT PENSION reduction provisions of Subsection
7(b) shall not apply to any Basic VRI Benefit payable under this
----- --- -------
Special Provision N.
B. A Basic VRI Benefit shall be payable as of the VRI Retirement Date and
----- --- ------- --- ---------- ----
shall be paid as soon as practicable after the applicable VRI
---
Retirement Date. Eligible Employees who elect to participate in the
---------- ---- -------- ---------
VRI shall not be subject to the age 55 requirement contained in
---
Section 8.
C. Section 10 of the RETIREMENT PLAN shall control the conditions under
which other forms of pension may be substituted for the Basic VRI
----- ---
Benefit. Thus, although a PARTICIPANT is entitled to receive a Basic
------- -----
VRI Benefit, if the PARTICIPANT is married, Subsection 10(b) of the
--- -------
RETIREMENT PLAN requires that the Basic VRI Benefit be converted to a
----- --- -------
MARITAL PENSION, unless the PARTICIPANT'S spouse consents to an
alternative form of pension.
D. The Basic VRI Benefit payable under this Special Provision N shall be
----- --- -------
in lieu of any benefit which might otherwise be payable under the
RETIREMENT PLAN.
E. A PARTICIPANT who elects to participate in VRI shall also be entitled
---
to make the elections provided in Sections 10 (Forms of Pension), 12
(Withdrawal of Participant Contributions on Termination of
Employment), 13 (Death Benefits), and 14 (Facility of Payment).
V. VRI Retirement Dates
--- ---------- -----
At such time as an EMPLOYEE elects to participate in the VRI, he shall
---
select a VRI Retirement Date. For purposes of this Special Provision N, a
--- ---------- ----
VRI Retirement Date shall mean one of the following:
--- ---------- ----
A. January 1, 1995; or
B. The first of any month during the period commencing with February 1,
1995, and ending with and including January 1, 1996. This Subsection
B shall only apply in the event that the COMPANY has a demonstrated
business need which requires the retention of the Eligible Employee.
-------- --------
The selection of any such VRI Retirement Date subsequent to January 1,
--- ---------- ----
1995, can be made only with the written approval of the COMPANY'S
Chief Executive Officer.
The VRI Retirement Date selected shall also be the date as of which an
--- ---------- ----
Eligible Employee ceases to be an EMPLOYEE of the COMPANY.
-------- --------
-75-
<PAGE>
VI. Revocation of Election
An Eligible Employee who has elected to participate in the VRI may
-------- -------- ---
revoke his election, provided, however, that any such revocation shall only
be effective if received by the COMPANY on or before November 28, 1994.
VII. Definitions
A. Basic VRI Benefit: The benefit calculated under Section IV of this
----- --- -------
Special Provision N.
B. Eligible Employee: An EMPLOYEE of the COMPANY who has met the
-------- --------
eligibility criteria as set forth in Section II. EMPLOYEES of Pacific
Gas Transmission Company, PG&E Enterprises, Pacific Service Employees
Association, and any other subsidiary or affiliate of the COMPANY are
not Eligible Employees for purposes of this VRI.
-------- --------- ---
C. VRI: The COMPANY's Voluntary Retirement Incentive program as set
---
forth in this Special Provision N.
D. VRI Retirement Date: The date selected by an Eligible Employee under
--- ---------- ---- -------- --------
Section V of this Special Provision N.
-76-
<PAGE>
EXHIBIT 10.13
PG&E CORPORATION
RETIREMENT PLAN FOR NON-EMPLOYEE DIRECTORS
(As Amended December 17, 1997)
1. Purpose and Effective Date
--------------------------
The purpose of the Plan, which was effective January 1, 1997, was to
promote the interests of the Corporation by providing Retirement benefits
to Directors in order to encourage their continued service on the Board of
Directors of the Corporation. The Plan was terminated effective January 1,
1998, except that (i) Directors who had retired from the Corporation's
Board of Directors prior to that date continue to receive payments under
the Plan in accordance with the terms of the Plan as they existed prior to
said date; and (ii) Directors who had not retired prior to that date were
offered the one time election to (a) convert the net present value of the
benefit accrued immediately prior to January 1, 1998, into units in the
PG&E Stock Fund of the Deferred Compensation Plan for Non-Employee
Directors and to transfer such units to that plan, the valuation of said
accrued benefits to be made according to assumptions adopted by the Senior
Human Resources Officer of the Corporation, or (b) to receive the benefits
accrued under this Plan prior to January 1, 1998, upon their retirement
from the Board in accordance with Section 3. In computing the benefits to
be received under (ii)(a) or (b) above, the Retainer used shall be the
Retainer applicable as of January 1, 1998.
2. Definitions
-----------
The following terms shall have the meanings set forth below, if
capitalized:
(a) "Retainer" means the annual retainer paid to Board members for service
on the Board of Directors as adjusted from time to time. The
definition does not include any additional amount paid for service on
a Board committee or as Board committee chairman or any amount
specifically paid for attendance at Board or Board committee meetings.
(b) "Corporation" means PG&E Corporation.
(c) "Board" means the Board of Directors of the Corporation.
(d) "Director" means a non-employee director or advisory director of PG&E
Corporation.
(e) "Plan" means the PG&E Corporation Retirement Plan for Non-Employee
Directors, as amended from time to time.
(f) "Eligible Director" means a Director who (i) is not an employee of the
Corporation or its subsidiaries or affiliates at the time of the
Director's Retirement; (ii) was a Director on or after January 1,
1997; and (iii) has served as a Director for a total of sixty calendar
months or more, including service as an employee-director. Solely for
purposes of determining whether a Director is an Eligible Director,
service also shall include calendar months during which a Director (i)
was serving as a director or advisory director of Pacific Gas and
Electric Company, or (ii) was serving concurrently as a Director and
as a director or advisory director of Pacific Gas and Electric
Company. A month in which a
<PAGE>
Director was serving concurrently as a director or advisory director
of Pacific Gas and Electric Company shall be counted as one month.
(g) "Retirement" occurs when an Eligible Director ceases to be a member
of the Board for any reason other than as a result of gross
misconduct.
(h) "Length of Service" is the Eligible Director's number of months of
service as a Director, rounded to the next highest calendar quarter
(for example, a Director who served 73 months would receive 25
quarterly payments--73 divided by 3, rounded to the next highest
integer). Length of Service shall also include (i) service prior to
January 1, 1997, as a director or advisory director of Pacific Gas and
Electric Company; and (ii) concurrent service as both a Director of
this Corporation and as a director or advisory director of the Pacific
Gas and Electric Company. Length of Service shall not include service
after December 31, 1997. Service as an employee-director shall not be
included in the computation of Length of Service for purposes of
determining the amount of Retirement benefits.
3. Retirement Payments
-------------------
(a) Upon Retirement, an Eligible Director shall be paid each quarter an
amount equal to the quarterly retainer paid to Directors as of the
earlier of (i) the date of the Eligible Director's retirement from the
Board, or (ii) the date immediately preceding the termination of the
Plan. Retirement payments shall not be adjusted to reflect changes in
the quarterly retainer effective after the date of the Eligible
Director's Retirement.
(b) Retirement payments shall begin in the calendar quarter immediately
following the calendar quarter in which the Eligible Director retired
from the Board or attained the age of 65, whichever comes later. The
payments shall continue on a quarterly basis for a period equal to the
Eligible Director's Length of Service.
(c) If an Eligible Director dies after completing the service requirement
for Retirement, but prior to receiving all Retirement payments, any
remaining payments shall be made to such deceased Director's surviving
spouse.
(d) If an Eligible Director dies after completing the service requirement
for Retirement, but prior to Retirement, his or her surviving spouse
will receive payments equal to the amount to which the Eligible
Director would have been entitled had he or she retired on the day
prior to his or her date of death.
4. Disability
----------
If an Eligible Director ceases to serve on the Board as a result of
disability, the Board in its sole discretion may waive the minimum service
requirements or permit the commencement of Retirement benefits prior to age
65.
-2-
<PAGE>
5. Gross Misconduct
----------------
If an Eligible Director ceases to serve on the Board as a result of gross
misconduct, any Retirement benefits payable under the Plan to such Eligible
Director shall be canceled immediately and irrevocably. For purposes of
this section, "gross misconduct" shall mean that an Eligible Director has
(i) disclosed confidential business information of any type concerning the
Corporation or any of its subsidiaries or affiliates to any party for any
form of compensation which constitutes "gross income," as defined under
Section 61 of the Internal Revenue Code or Regulations issued thereunder;
or (ii) been indicted for intentionally or knowingly committing a crime
against the Corporation or any of its subsidiaries or affiliates under
federal law or the law of the state in which such act occurred; provided,
however, an Eligible Director shall not be deemed to have committed gross
misconduct if subsequent to being indicted for such a crime, the indictment
is dismissed, a plea of nolo contendere is accepted, or the Eligible
---- ----------
Director has been found to be "not guilty" in a trial before an appropriate
criminal court.
6. Amendment and Termination
-------------------------
The Board reserves the right to amend, suspend, or terminate this Plan at
any time. However, no such amendment, suspension, or termination shall
have an adverse effect on Retirement payments to be made to an Eligible
Director who retires prior to such amendment, suspension, or termination.
7. Prohibition or Alienation
-------------------------
No Director shall have the right to alienate, assign, encumber,
hypothecate, or pledge his or her interest in any payments to be made under
the Plan, voluntarily or involuntarily, and any attempt to so dispose of
any such interest shall be void. The Corporation shall have the right to
set off against Retirement payments under the Plan any amounts due and
owing from the Eligible Director to the Corporation and its parent,
subsidiaries, or affiliates, to the extent permitted by law.
8. Unfunded Plan
-------------
The Plan is unfunded, and the Corporation shall not be required to
segregate any cash or establish any separate account or accounts to fund
any Retirement payment to be made under the Plan.
9. Entire Plan
-----------
This document is a complete statement of the Plan and as of its effective
date supersedes all prior plans, proposals, representations, promises,
inducements, written or oral, relating to its subject matter. The
Corporation shall not be bound or liable to any Director for any
representation, promise, or inducement made by any person which is not
embodied in this document or in any authorized written amendment to the
Plan.
-3-
<PAGE>
10. Applicable Law
--------------
The Plan will be construed and enforced in accordance with the laws of
California.
-4-
<PAGE>
EXHIBIT 10.15
PG&E CORPORATION
LONG-TERM INCENTIVE PROGRAM
(As amended and restated effective as of January 1, 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;
(c) to designate the types of INCENTIVE AWARD being granted;
- -----------------
/1/ Capitalized words are defined in Section 20 hereof.
<PAGE>
(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 DI RECTORS 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 requires approval
by the COMMITTEE; (b) to determine the time or times at which INCENTIVE
AWARDS shall be granted to such ELIGIBLE
2
<PAGE>
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
RECIPIENT or the CORPORATION to terminate such employment, service as a
DIRECTOR or consulting relationship at any time, with or without cause.
3
<PAGE>
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.
INCENTIVE AWARDS shall be awarded at no cost to the RECIPIENT. 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, subject to the terms
and conditions set forth in the PERFORMANCE UNIT PLAN attached hereto as
Exhibit B.
4
<PAGE>
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 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.
5
<PAGE>
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):
(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;
6
<PAGE>
(c) All conditions relating to the realization of any STOCK-BASED AWARD
granted hereunder shall immediately terminate; and
(d) The COMMITTEE may offer any RECIPIENT the option of having the
CORPORATION purchase his or her INCENTIVE AWARD for an amount of cash
which could have been attained upon the exercise or realization of
such INCENTIVE AWARD had it been fully exercisable or realizable;
unless the COMMITTEE in its sole discretion determines that such CHANGE IN
CONTROL will not adversely impact the RECIPIENTS of INCENTIVE AWARDS
hereunder and is in the best interests of the shareholders of PG&E
CORPORATION. The COMMITTEE may make such further provisions with respect
to a CHANGE IN CONTROL as it shall deem equitable and in the best interests
of the shareholders of PG&E CORPORATION. Such provision may be made in any
agreement relating to any INCENTIVE AWARD granted hereunder, by amendment
to any such agreement or by resolution of the COMMITTEE.
The phrase "CHANGE IN CONTROL" shall have such meaning as ascribed thereto
from time to time by the COMMITTEE and set forth in any agreement relating
to any INCENTIVE AWARD granted hereunder or by resolution of the COMMITTEE;
provided, however, that, notwithstanding the foregoing, 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
(c) the shareholders of PG&E CORPORATION shall have approved (i) any
consolidation or merger of PG&E CORPORATION in which PG&E CORPORATION
is not the continuing or surviving corporation or pursuant to which
shares of COMMON STOCK are converted into cash, securities or other
property, other than a merger of PG&E CORPORATION in which the holders
of the COMMON STOCK
7
<PAGE>
immediately prior to the merger have the same proportionate ownership
of common stock of the surviving corporation immediately after the
merger, (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 PG&E CORPORATION.
Notwithstanding the foregoing, the phrase "CHANGE IN CONTROL" shall not
apply to any reorganization or merger initiated voluntarily by PG&E
CORPORATION in which PG&E CORPORATION is the continuing surviving entity.
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
8
<PAGE>
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 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
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 subsequent
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 October 15,1997, 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.
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.
9
<PAGE>
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. 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
10
<PAGE>
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. 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 CORPORATION 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.
11
<PAGE>
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.
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.
12
<PAGE>
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, 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.
---------------------
13
<PAGE>
EXHIBIT A
PG&E CORPORATION
STOCK OPTION PLAN
(As amended and restated effective as of January 1, 1997)
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;
(c) to designate the OPTIONS being granted as ISOS or NON-QUALIFIED
STOCK OPTIONS;
- ------------------
/2/ Capitalized words are defined in Section 20 hereof.
14
<PAGE>
(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 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
15
<PAGE>
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.
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
16
<PAGE>
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.
OPTIONS shall be awarded at no cost to the OPTIONEE.
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 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
17
<PAGE>
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.
(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.
18
<PAGE>
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. Notwithstanding the foregoing, any ISOS held by the OPTIONEE may be
exercised only within their respective terms or within three (3) months after
RETIREMENT, whichever is shorter.
(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 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.
Notwithstanding the foregoing, any ISOS held by the OPTIONEE may be
19
<PAGE>
exercised only within their respective terms or within three (3) months after
such TERMINATION, whichever is shorter.
(e) In the event of a TERMINATION for any reason other than those
specified in subparagraphs (a) through (d) 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 any) shall not be credited with any dividends paid after the date of
such TERMINATION.
(f) Notwithstanding the provisions of subparagraphs (a) through (e)
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.
20
<PAGE>
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.
16. Change in Control
-----------------
Upon the occurrence of a CHANGE IN CONTROL (as defined below):
(a) 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; and
(b) The COMMITTEE may offer any OPTIONEE the option of having the
CORPORATION purchase his or her OPTION for an amount of cash which could have
been attained upon the exercise of such OPTION had it been fully exercisable;
unless the COMMITTEE in its sole discretion determines that such CHANGE IN
CONTROL will not adversely impact the OPTIONEES of OPTIONS hereunder and is in
the best interests of the shareholders of PG&E CORPORATION. The COMMITTEE may
make such further provisions with respect to a CHANGE IN CONTROL as it shall
deem equitable and in the best interests of the shareholders of PG&E
CORPORATION. Such provision may be made in any agreement relating to any OPTION
granted hereunder, by amendment to any such agreement or by resolution of the
COMMITTEE.
The phrase "CHANGE IN CONTROL" shall have such meaning as ascribed
thereto from time to time by the COMMITTEE and set forth in any agreement
relating to any OPTION granted hereunder or by resolution of the COMMITTEE;
provided, however, that, notwithstanding the foregoing, 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
21
<PAGE>
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 PG&E CORPORATION shall have approved (i) any
consolidation or merger of PG&E CORPORATION in which PG&E CORPORATION is not the
continuing or surviving corporation or pursuant to which shares of COMMON STOCK
are converted into cash, securities or other property, other than a merger of
PG&E CORPORATION in which the holders of the COMMON STOCK immediately prior to
the merger have the same proportionate ownership of common stock of the
surviving corporation immediately after the merger, (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 PG&E
CORPORATION.
Notwithstanding the foregoing, the phrase "CHANGE IN CONTROL" shall
not apply to any reorganization or merger initiated voluntarily by PG&E
CORPORATION in which PG&E CORPORATION is the continuing surviving entity.
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 RULE 16b-3 or 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
22
<PAGE>
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 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. 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.
23
<PAGE>
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.
---
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.
24
<PAGE>
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 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.
----------------
25
<PAGE>
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.
ab. 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.
ac. 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.
ad. 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.
ae. TANDEM refers to a DIVIDEND EQUIVALENT or SAR (as the case may be)
------
granted in conjunction with an OPTION.
af. 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.
ag. TERMINATION FOR CAUSE has the meaning set forth in Section 12 hereof.
---------------------
26
<PAGE>
EXHIBIT B
PERFORMANCE UNIT PLAN
OF
PG&E CORPORATION
___________________________
(As amended and restated effective as of January 1, 1997)
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.
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<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;
b. One-third after the end of the second YEAR of the VESTING PERIOD;
and
28
<PAGE>
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.
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
29
<PAGE>
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.
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 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.
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<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 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.
31
<PAGE>
EXHIBIT C
PG&E CORPORATION
NON-EMPLOYEE DIRECTOR STOCK INCENTIVE PLAN
(As amended and restated effective as of January 1, 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/4/). 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
- --------------------
/4/ Capitalized words are defined in Section 15 hereof.
32
<PAGE>
this Section 3(a). The number of shares of DIRECTOR RESTRICTED 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, 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.
33
<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 a value (as determined in
accordance with the Black-Scholes stock option valuation method which
will use the average November closing price of PG&E Corporation stock
as the value for PG&E Corporation stock) equal to $5,000, $10,000,
$15,000, or $20,000, as previously elected by the NON-EMPLOYEE
DIRECTOR (the "Elected Option Value"), provided, however that a NON-
EMPLOYEE DIRECTOR who has failed to make a timely election in
accordance with Section 4 shall receive a grant of NON-QUALIFIED STOCK
OPTIONS with a value (as determined in accordance with the Black-
Scholes stock option valuation method which will use the average
November closing price of PG&E Corporation stock as the value for PG&E
Corporation stock) equal to $10,000. The number of shares subject to
the NON-QUALIFIED STOCK OPTIONS to be granted to each NON-EMPLOYEE
DIRECTOR each calendar year shall be that number which will yield a
present value of the NON-QUALIFIED STOCK OPTIONS, as of the first
business day of the applicable calendar year, equal to (i) the Elected
Option 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), and (ii) rounding
the resulting number 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
34
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OPTION. The CORPORATION shall not make loans to any GRANTEE for the
purpose of exercising NON-QUALIFIED STOCK OPTIONS.
(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 sixty 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 to be granted to
each NON-EMPLOYEE DIRECTOR each calendar year shall be determined by
(i) 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 and (ii) rounding the
resulting number down to the nearest whole share. 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 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.
35
<PAGE>
(b) Each NON-EMPLOYEE DIRECTORS' PHANTOM STOCK account shall be credited
quarterly on each dividend record date with additional shares of
PHANTOM STOCK determined by (i) dividing the amount of dividends which
would have been paid on the number of shares of COMMON STOCK equal to
the number of shares of PHANTOM STOCK previously credited to the
PHANTOM STOCK account by the FAIR MARKET VALUE of the COMMON STOCK on
the dividend record date, and (ii) rounding the resulting number down
to the nearest whole share of PHANTOM STOCK. No additional shares of
PHANTOM STOCK shall be credited to a NON-EMPLOYEE DIRECTOR'S account
after the date of the NON-EMPLOYEE DIRECTOR'S TERMINATION.
(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
RETIREMENT or MANDATORY RETIREMENT. 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 an
equal number of annual installments over a period not to exceed ten
years from the date of the NON-EMPLOYEE DIRECTOR'S RETIREMENT or
MANDATORY RETIREMENT.
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
36
<PAGE>
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
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. 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
37
<PAGE>
PHANTOM STOCK account shall become payable to the GRANTEE in
accordance with Section 6(c) hereof.
(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
38
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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 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, unless the COMMITTEE or
BOARD OF DIRECTORS determines that such CHANGE IN CONTROL will not
adversely impact the GRANTEES' DIRECTOR RESTRICTED STOCK, NON-QUALIFIED
STOCK OPTIONS, or PHANTOM STOCK granted hereunder and is in the best
interests of the shareholders of PG&E CORPORATION. The COMMITTEE or BOARD
OF DIRECTORS may make such further provisions with respect to a CHANGE IN
CONTROL as it shall deem equitable and in the best interests of the
shareholders of PG&E CORPORATION. Such provision may be made in any
agreement relating to any DIRECTOR RESTRICTED STOCK, NON-QUALIFIED STOCK
OPTIONS, or PHANTOM STOCK granted hereunder, by amendment to any such
agreement or by resolution of the COMMITTEE or BOARD OF DIRECTORS.
The phrase "CHANGE IN CONTROL" shall have such meaning as ascribed thereto
from time to time by the COMMITTEE or BOARD OF DIRECTORS and set forth in
any agreement relating to any DIRECTOR RESTRICTED STOCK, NON-QUALIFIED
STOCK OPTIONS, or PHANTOM STOCK granted hereunder or by resolution of the
COMMITTEE or BOARD OF DIRECTORS; provided, however, that, notwithstanding
the foregoing, 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;
39
<PAGE>
(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
(c) the shareholders of PG&E CORPORATION shall have approved (i) any
consolidation or merger of PG&E CORPORATION in which PG&E CORPORATION
is not the continuing or surviving corporation or pursuant to which
shares of COMMON STOCK are converted into cash, securities or other
property, other than a merger of PG&E CORPORATION in which the holders
of the COMMON STOCK immediately prior to the merger have the same
proportionate ownership of common stock of the surviving corporation
immediately after the merger, (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 PG&E
CORPORATION.
Notwithstanding the foregoing, the phrase "CHANGE IN CONTROL" shall not
apply to any reorganization or merger initiated voluntarily by PG&E
CORPORATION in which PG&E CORPORATION is the continuing surviving entity.
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,
40
<PAGE>
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. Unless terminated sooner
pursuant to Section 13 hereof, the PLAN shall terminate on December 31,
2005.
15. Definitions
-----------
i) BOARD OF DIRECTORS means the Board of Directors of PG&E CORPORATION.
------------------
ii) CHANGE IN CONTROL has the meaning set forth in Section 10 hereof.
-----------------
iii) CODE means the Internal Revenue Code of 1986, as amended from time to
----
time.
iv) COMMITTEE means the Nominating and Compensation Committee of the
---------
BOARD OF DIRECTORS or any successor to such committee.
v) 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.
vi) 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).
vii) 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.
41
<PAGE>
viii) DIRECTOR RESTRICTED STOCK means RESTRICTED STOCK granted to a NON-
-------------------------
EMPLOYEE DIRECTOR under the PLAN.
ix) 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.
x) ERISA means the Employee Retirement Income Security Act of 1974, as
-----
amended.
xi) EXCHANGE ACT means the Securities Exchange Act of 1934, as amended.
------------
xii) 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.
xiii) GRANTEE means the NON-EMPLOYEE DIRECTOR receiving the DIRECTOR
-------
RESTRICTED STOCK, NON-QUALIFIED STOCK OPTIONS and PHANTOM STOCK or
his or her legal representative, legatees, distributees or alternate
payees, as the case may be.
xiv) 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.
xv) NON-EMPLOYEE DIRECTOR means a DIRECTOR who is not an EMPLOYEE.
---------------------
xvi) 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.
xvii) PG&E CORPORATION means PG&E CORPORATION, a California corporation.
----------------
xviii) PHANTOM STOCK means allocated hypothetical shares of COMMON STOCK
-------------
that can be converted at a future date into stock.
xix) 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
42
<PAGE>
with respect to the grant of DIRECTOR RESTRICTED STOCK,
NON-QUALIFIED STOCK OPTIONS, PHANTOM STOCK or other stock-based
incentive awards under the PROGRAM.
xx) 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.
xxi) 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.
xxii) RETIREMENT means TERMINATION of service on the BOARD OF DIRECTORS
----------
after serving continuously for five consecutive years.
xxiii) 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.
xxiv) 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).
43
<PAGE>
Exhibit 10.16
PG&E CORPORATION
EXECUTIVE STOCK OWNERSHIP PROGRAM
Administrative Guidelines
-------------------------
(November 19, 1997)
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, 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 & VP-HR 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.
<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 equivalent 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 (including
vested SISOP units, as discussed below) is determined by
multiplying the number of vested units held by the Eligible
Executive 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 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.
2
<PAGE>
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 7. 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. 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 PG&E Corporation Phantom Stock Fund of the Deferred
Compensation Plan and converted into Units of that Fund. The initial
value of a Unit shall be calculated in accordance with the valuation of
initial deferrals into the PG&E Corporation Phantom Stock Fund of the
Deferred Compensation Plan. Once a SISOP Unit is credited to the account
of an Eligible Executive under the Deferred Compensation Plan, it shall
be subject to all of the terms and conditions applicable to Units held
in the PG&E Corporation Phantom Stock Fund, and such other Plan
provisions which by their terms specifically govern SISOPs.
7. Forfeiture of Units. Units attributable to SISOPs do not vest until the
-------------------
third anniversary of the date that they are credited to the Deferred
Compensation Plan. So long as SISOP Units remain unvested, such Units
are subject to forfeiture if, on each Measurement Date, the number of
shares and units held by the Eligible Executive 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 vested units held by the Eligible
Executive 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, vested units, and share-equivalents of
vested "in the money" options is added together. This total
(Current Holdings) is compared
3
<PAGE>
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 SISOPs are forfeited. If
the Current Holdings are less than the Minimum Ownership Level,
then the unvested SISOPs 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 SISOPs are
forfeited).
8. 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 Phantom Stock Fund of the Deferred
Compensation Plan of annual awards from the Performance Unit Plan
("PUP") and the Performance Incentive Plan ("PIP"). As of any
measurement date, to the extent that stock ownership levels are below
Target, PUP awards shall be converted into Units and held in the Phantom
Stock Fund. If, with the addition of the Units attributable to the PUP
award, the stock ownership level is still below Target for any
Measurement Date, any PIP award above target also shall be converted
into Units held in the Phantom Stock Fund, to the extent of Target. Such
conversion of PUP and PIP awards shall continue for successive
Measurement Dates, if necessary, until Target is met. Units attributable
to PUP and PIP awards described in this paragraph 8 will be paid from
the Deferred Compensation Plan as soon as practicable after the date on
which such payment will not result in a stock ownership level below
Target, or such latter date as may be elected by the Eligible Executive
at the time that the award is credited to the Deferred Compensation Plan
for Officers.
4
<PAGE>
EXHIBIT 11
PG&E CORPORATION
COMPUTATION OF EARNINGS PER COMMON SHARE
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------
Year ended December 31,
----------------------------------
(in thousands, except per share amounts) 1997 1996 1995
- --------------------------------------------------------------------------------
<S> <C> <C> <C>
EARNINGS PER COMMON SHARE (EPS) AS SHOWN
IN THE STATEMENT OF CONSOLIDATED INCOME
Earnings available for common stock $715,940 $722,096 $1,268,597
======== ======== ==========
Average common shares outstanding 410,040 412,542 423,692
======== ======== ==========
Basic EPS $1.75 $1.75 $2.99
======== ======== ==========
DILUTED EPS (1)
Earnings available for common stock $715,940 $722,096 $1,268,597
======== ======== ==========
Average common shares outstanding 410,040 412,542 423,692
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) 211 9 126
-------- -------- ----------
Average common shares outstanding as
adjusted 410,251 412,551 423,818
======== ======== ==========
Diluted EPS $ 1.75 $ 1.75 $ 2.99
======== ======== ==========
- -----------------------------------------------------------------------------
</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) 1997 1996 1995 1994 1993
- -----------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Earnings:
Net income $ 768 $ 755 $ 1,339 $ 1,007 $ 1,065
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) 7
Income tax expense 609 555 895 837 902
Net fixed charges 628 683 716 729 775
-------- -------- -------- ------- -------
Total Earnings $ 2,005 $ 1,996 $ 2,954 $ 2,570 $ 2,749
======== ======== ======== ======= =======
Fixed Charges:
Interest on long-term debt, net $ 485 $ 574 $ 616 $ 639 $ 652
Interest on short-term borrowings 101 75 83 77 88
Interest on capital leases 2 3 3 2 2
Capitalized Interest 1 1 - 2 46
AFUDC Debt 16 7 11 11 33
Earnings required to cover the preferred stock
dividend and preferred security distribution
requirements of majority owned subsidiaries 24 24 3 - -
-------- -------- -------- ------- ------
Total Fixed Charges $ 629 $ 684 $ 716 $ 731 $ 821
======== ======== ======== ======= ======
Ratios of Earnings to Fixed Charges 3.19 2.92 4.13 3.52 3.35
- -----------------------------------------------------------------------------------------------------------
</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>
EXHIBIT 12.2
PACIFIC GAS AND ELECTRIC COMPANY
COMPUTATION OF RATIOS OF EARNINGS TO COMBINED FIXED CHARGES AND PREFERRED STOCK
DIVIDENDS
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------------------------------------
Year ended December 31,
------------------------------------------------------
(dollars in millions) 1997 1996 1995 1994 1993
- ------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Earnings:
Net income $ 768 $ 755 $ 1,339 $ 1,007 $ 1,065
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) 7
Income tax expense 609 555 895 837 902
Net fixed charges 628 683 716 729 775
-------- -------- -------- ------- -------
Total Earnings $ 2,005 $ 1,996 $ 2,954 $ 2,570 $ 2,749
======== ======== ======== ======= =======
Fixed Charges:
Interest on long-term debt $ 485 $ 574 $ 616 $ 639 $ 652
Interest on short-term debt 101 75 83 77 88
Interest on capital leases 2 3 3 2 2
Capitalized Interest 1 1 - 2 46
AFUDC Debt 16 7 11 11 33
Earnings required to cover the preferred stock
dividend and preferred security distribution
requirements of majority owned subsidiaries 24 24 3 - -
-------- -------- -------- ------- -------
Total Fixed Charges $ 629 $ 684 $ 716 $ 731 $ 821
-------- -------- -------- ------- -------
Preferred Stock Dividends:
Tax deductible dividends $ 10 $ 10 $ 11 $ 5 $ 5
Pretax earnings required to cover non-tax
deductible preferred stock dividend
requirements 39 39 100 96 109
-------- -------- -------- ------- -------
Total Preferred Stock Dividends $ 49 $ 49 $ 111 $ 101 $ 114
-------- -------- -------- ------- -------
Total Combined Fixed Charges and Preferred
Stock Dividends $ 678 $ 733 $ 827 $ 832 $ 935
======== ======== ======== ======= =======
Ratios of Earnings to Combined Fixed Charges
and Preferred Stock Dividends 2.96 2.72 3.57 3.09 2.94
- ------------------------------------------------------------------------------------------------------------
</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) 1997 1996 1995 1994 1993
- -------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
PG&E Corporation(1)
For the Year
Operating revenues $15,400 $ 9,610 $ 9,622 $10,350 $10,550
Operating income 1,728 1,896 2,763 2,424 2,560
Net income 716 722 1,269 950 1,002
Earnings per common share 1.75 1.75 2.99 2.21 2.33
Dividends declared per common share 1.20 1.77 1.96 1.96 1.88
At Year End
Book value per common share $ 21.30 $ 20.73 $ 20.77 $ 20.07 $ 19.77
Common stock price per share 30.31 21.00 28.38 24.38 35.13
Total assets 30,557 26,237 26,871 27,738 27,234
Long-term debt (excluding current portions) 7,659 7,770 8,049 8,676 9,292
Rate reduction bonds (excluding current portions) 2,776 - - - -
Preferred stock and securities of subsidiary with
mandatory redemption provisions (excluding
current portions) 437 437 437 137 75
Pacific Gas and Electric Company
For the Year
Operating revenues $ 9,495 $ 9,610 $ 9,622 $10,350 $10,550
Operating income 1,831 1,896 2,763 2,424 2,560
Income available for common stock 735 722 1,269 950 1,002
At Year End
Total assets $25,147 $26,237 $26,871 $27,738 $27,234
Long-term debt (excluding current portions) 6,218 7,770 8,049 8,676 9,292
Rate reduction bonds (excluding current portions) 2,776 - - - -
Preferred stock and securities with mandatory
redemption provisions (excluding current portions) 437 437 437 137 75
</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 for the years 1993 through 1996 are identical
because they represent the accounts of Pacific Gas and Electric Company as the
predecessor of PG&E Corporation. See Management's Discussion and Analysis of
Consolidated Results of Operations and Financial Condition for further
discussion of the holding company formation and matters relating to certain data
above.
16
<PAGE>
Management's Discussion and Analysis of
Consolidated Results of Operations and Financial Condition
San Francisco-based PG&E Corporation provides energy services throughout the
United States and Australia. We were formed as a holding company on January 1,
1997, to respond to new business opportunities and changes in the energy
industry. As a result, Pacific Gas and Electric Company became a subsidiary of
its new parent holding company, PG&E Corporation, and its ownership interest in
its unregulated subsidiaries was transferred to PG&E Corporation. Under our new
corporate structure, we provide integrated energy services through our various
business lines:
Pacific Gas and Electric Company (Utility)
Our Utility provides gas and electric service to Northern and Central
California. Our Utility is regulated by the California Public Utilities
Commission (CPUC), the Federal Energy Regulatory Commission (FERC), and the
Nuclear Regulatory Commission, among others.
Unregulated Business Operations
We provide a wide range of integrated energy products and services designed to
take advantage of the opening of the competitive energy marketplace throughout
the United States. Through our other subsidiaries, we provide the following
energy services:
Gas Transmission: We own and operate approximately 10,000 miles of natural gas
pipelines, natural gas storage facilities, and natural gas processing plants in
the Pacific Northwest, Texas, and Australia through PG&E Gas Transmission (PG&E
GT). PG&E GT's Pacific Northwest operations are regulated by the FERC, and its
Texas operations are regulated by the Texas Railroad Commission.
Electric Generation: We develop, build, operate, own, and manage power
generation facilities across the United States through U.S. Generating Company
(USGen). In 1998, USGen expects to complete the acquisition of the New England
Electric System fossil fuel and hydroelectric power plants. This acquisition is
discussed further in the Acquisitions and Sales section below.
Energy Services and Commodities: We provide 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 (PG&E ES).
Through PG&E Energy Trading (PG&E ET), we purchase and resell energy
commodities and related financial instruments in major domestic markets, serving
PG&E Corporation's other unregulated businesses, unaffiliated utilities, and
large end-use customers.
Overview
This is a combined annual report of PG&E Corporation and Pacific Gas and
Electric Company. Therefore, our Management's Discussion and Analysis of
Consolidated Results of Operations and Financial Condition apply to both PG&E
Corporation and the Utility. PG&E Corporation's consolidated financial
statements include the accounts of PG&E Corporation and its wholly owned and
controlled subsidiaries, including the Utility (collectively, the Corporation).
Our Utility's consolidated financial statements include its accounts as well as
those of its wholly owned and controlled subsidiaries. Because PG&E Corporation
did not become the holding company for the Utility until January 1, 1997, the
1995 and 1996 consolidated financial statements represent the accounts of the
Utility on a consolidated basis as predecessor of PG&E Corporation. Management's
Discussion and Analysis should be read in conjunction with the consolidated
financial statements.
In Management's Discussion and Analysis, we explain the results of operations
for the years 1995 through 1997 and discuss our financial condition. Our
discussion of financial condition includes:
. energy industry restructuring and how this restructuring will influence
future results of operations,
. liquidity and capital resources, including discussions of capital financing
activities, estimated capital spending for the next three years, and
uncertainties that could affect future results, and
. risk management activities.
17
<PAGE>
Management's Discussion and Analysis of
Consolidated Results of Operations and Financial Condition
This combined annual report, including our Letter to Shareholders above and
our discussion of results of operations and financial condition below, contains
forward-looking statements that involve risks and uncertainties. Also, words
such as "estimates," "expects," "anticipates," "plans," "believes," and similar
expressions identify forward-looking statements involving risks and
uncertainties.
These risks and uncertainties include, but are not limited to, the ongoing
restructuring of the electric and gas industries, the outcome of the regulatory
proceedings related to those restructurings, our Utility's ability to collect
revenues sufficient to recover transition costs in accordance with its cost
recovery plan, the impact of our recent or planned acquisitions as discussed in
the Acquisitions and Sales section below, the approval of our Utility's 1999
General Rate Case application resulting in the Utility's ability to earn its
authorized rate of return as discussed in the Letter to Shareholders above and
in the Regulatory Activity section below, and our ability to successfully
compete outside our traditional regulated markets, as discussed in the Letter to
Shareholders above. The ultimate impacts on future results of increased
competition, the changing regulatory environment, our expansion into new
businesses and markets, and the CPUC's decision on the 1999 General Rate Case
application are uncertain, but all are expected to fundamentally change how we
conduct our business. The outcome of these changes and other matters discussed
below may cause future results to differ materially from historic results, or
from results or outcomes currently expected or sought by PG&E Corporation.
Results of Operations
In this section, we provide the components of our earnings for 1997, 1996, and
1995. We then explain why operating revenues and expenses for 1997 and 1996 were
different from the year before.
The following table shows our results of operations and total assets for 1997,
1996, and 1995. The results of operations for PG&E Corporation on a stand-alone
basis and intercompany eliminations have been shown as Corporate and Other.
<TABLE>
<CAPTION>
Unregulated Corporate
Business and
Utility Operations Other Total
- ---------------------------------------------------------------------------
(in millions)
<S> <C> <C> <C> <C>
1997
Operating revenues $ 9,495 $6,351 $ (446) $15,400
Operating expenses 7,664 6,433 (425) 13,672
--------------------------------------------
Operating income (loss)
before income taxes $ 1,831 $ (82) $ (21) $ 1,728
============================================
Income available for
common stock $ 735 $ 8 $ (27) $ 716
============================================
Total assets $25,147 $6,224 $ (814) $30,557
============================================
1996
Operating revenues $ 8,989 $ 679 $ (58) $ 9,610
Operating expenses 7,179 595 (60) 7,714
--------------------------------------------
Operating income
before income taxes $ 1,810 $ 84 $ 2 $ 1,896
============================================
Income available for
common stock $ 707 $ 15 $ - $ 722
============================================
Total assets $23,567 $2,858 $ (188) $26,237
============================================
1995
Operating revenues $ 9,243 $ 447 $ (68) $ 9,622
Operating expenses 6,556 376 (73) 6,859
--------------------------------------------
Operating income
before income taxes $ 2,687 $ 71 $ 5 $ 2,763
============================================
Income available for
common stock $ 1,210 $ 59 $ - $ 1,269
============================================
Total assets $24,689 $2,578 $ (396) $26,871
============================================
</TABLE>
Earnings Per Common Share: Basic and diluted earnings per common share were
$1.75, $1.75, and $2.99 for 1997, 1996, and 1995, respectively. Earnings per
common share were affected by the activity discussed below.
18
<PAGE>
Utility Results:
1997 COMPARED TO 1996
Our Utility operating revenues in 1997 increased $506 million from 1996. The
largest portion of the increase was due to transition cost recovery related to
the revisions in the Diablo Canyon Nuclear Power Plant (Diablo Canyon)
ratemaking structure discussed in Electric Transition Plan below. A portion of
the increase is due to increased revenues associated with electric transmission
and distribution system reliability authorized by California Assembly Bill 1890,
the electric industry restructuring legislation. There was also an increase in
energy cost revenues to recover energy cost increases and changes in sales
volume provided by our Utility's energy rate recovery mechanism. Under energy
rate recovery mechanisms, energy rate revenues generally equal energy costs and,
thus, increases in the cost of energy do not affect operating income.
Our Utility operating expenses in 1997 increased $485 million from 1996. The
increase was due primarily to the increase in Diablo Canyon depreciation (which
provided the revenue increases discussed above for recovery of the increased
depreciation) and the increase in cost of energy. This increase was partially
offset by a decrease in expenses for several 1996 one-time charges associated
with gas transportation commitments and a 1996 one-time charge due to a
litigation reserve.
Other income increased in 1997 compared to 1996 primarily due to a gain on the
buyout of a long-term contract for gas transportation service.
1996 COMPARED TO 1995
Our Utility operating revenues in 1996 decreased $254 million from 1995 due to
revenue reductions ordered in the 1996 General Rate Case. The revenue decrease
was also due to a decline in the Diablo Canyon generation price, as provided in
the Diablo Canyon rate case settlement. This lower generation price was
partially offset by higher net generation, which was a result of fewer scheduled
refuelings in 1996 compared to 1995. We maintain an automatic adjustment clause
(Gas Balancing Account) pursuant to which 1996 revenues were increased to
reflect the increase in gas prices in 1996 as compared to 1995. However, this
increase to gas revenues was offset by a corresponding revenue decrease ordered
in the 1996 General Rate Case.
Our Utility operating expenses increased $623 million in 1996 primarily due to
charges for gas transportation commitments, increases in gas and purchased power
prices, increases in expenses related to transmission and distribution system
reliability, and increases in litigation costs.
Unregulated Business Results:
1997 COMPARED TO 1996
Our unregulated business operating revenues in 1997 increased $5,672 million
from 1996. This was primarily due to a $4,524 million increase in energy
commodities and services revenues from the acquisitions of Energy Source (ES) in
December 1996, Teco Pipeline Company (Teco) in January 1997, and Valero Energy
Corporation (Valero) in July 1997. Also contributing to the increase were the
new revenues from the gas pipeline operations of Teco and Valero.
Our unregulated business operating expenses in 1997 increased $5,838 million
from 1996 which essentially reflects the increase in the cost of gas for resale
due to the above acquisitions and our expansion into the energy commodities and
services industry.
Other income increased in 1997 compared to 1996 primarily due to the gain on
the sale of International Generating Company, Ltd. which was partially offset by
write-downs of certain nonregulated investments.
1996 COMPARED TO 1995
Our unregulated business operating revenues and operating expenses in 1996
increased $232 and $219 million, respectively, from 1995 primarily due to the
purchase of ES in December 1996. This purchase created $283 million of revenue
but was offset by an increase in the cost of gas for resale. The increase in
both operating revenues and operating expenses was partially offset by a
decrease due to the sale of DALEN Corporation in 1995.
Other income decreased in 1996 compared to 1995 primarily due to write-downs
of certain nonregulated investments in 1996.
19
<PAGE>
Management's Discussion and Analysis of
Consolidated Results of Operations and Financial Condition
Common Stock Dividend: Our common stock dividend is based 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.
The CPUC set a number of conditions when PG&E Corporation was formed as a
holding company. One of these conditions requires our Utility to maintain, on
average, its CPUC-authorized capital structure, potentially limiting the amount
of dividends our Utility may pay PG&E Corporation. At December 31, 1997, our
Utility was in compliance with its CPUC-authorized capital structure. We believe
that our Utility will continue to meet this condition in the future without
affecting our ability to pay common stock dividends to common shareholders.
Financial Condition
We begin this section by discussing the energy industry. We also discuss how the
Corporation is responding to restructuring on a national level, including recent
and planned acquisitions. We then discuss liquidity and capital resources and
our risk management activities.
Energy Industry:
The Electric Business:
California has been in the forefront of the nation's move towards competitive
energy markets. In 1998, Californians will be able to choose who will provide
their electric power. Customers within our Utility's service territory can
purchase electricity (1) from our Utility, (2) from retail electricity providers
(for example, marketers including our energy service subsidiary, brokers, and
aggregators), or (3) directly from unregulated power generators. Our Utility
will continue to provide distribution services to substantially all electric
consumers within its service territory.
To create this competitive generation market, California has established a
Power Exchange (PX) and an Independent Systems Operator (ISO). The PX will be an
open electric marketplace where electricity prices are set. The ISO will oversee
California's electric transmission grid making sure that all generators have
comparable access. California utilities will retain ownership of utility
transmission facilities but will relinquish operating control to the ISO.
Competing electric providers will bid their electric commodity into the PX. The
PX will accept the lowest bids to satisfy the aggregate electric demand and
establish a market price. Customers choosing to buy power directly from non-
regulated generators or retailers will pay for that generation based upon
negotiated contracts. The PX and ISO are expected to be operational by March 31,
1998.
CPUC regulation requires our Utility to purchase all electric power for its
retail customers from the PX. And, we must bid all of our Utility-generated
electric power to the PX.
Generation revenues currently make up approximately 30 percent of our total
Utility revenues. The competitive market environment will significantly change
the way our Utility earns revenues. Over the past several years, we have been
taking steps to prepare for these changes. We have been working with the CPUC to
ensure a smooth transition into the competitive market environment. And, we have
made strategic investments throughout the nation that will further position us
as a national energy provider. The following sections discuss the transition
plan. A discussion of the investments we have made is included in Our Response
to Changes in Our Industry, below.
ELECTRIC TRANSITION PLAN
In the new competitive market, our Utility's generation revenues will be
determined principally by the market through sales to the PX. However, market-
based revenues may not be sufficient to recover (that is, to collect from
customers) all generation costs resulting from past CPUC decisions. To recover
these uneconomic costs, called "transition costs," and to ensure a smooth
transition to the competitive environment, our Utility in conjunction with other
California electric utilities, the CPUC, state legislators, consumer advocates,
and others, developed a transition plan, in the form of state legislation, to
position California for the new market environment.
20
<PAGE>
There are three principal elements to this transition plan: (1) an electric
rate freeze and rate reduction, (2) recovery of transition costs, and (3)
economic divestiture of Utility-owned generation facilities. Each one of these
three elements, the impact of the transition plan on our Utility's customers,
and the impact of the transition plan on our application of Statement of
Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of
Certain Types of Regulation," are discussed below. The transition plan will
remain in effect until the earlier of March 31, 2002, or when we have recovered
our authorized transition costs as determined by the CPUC. This period is
referred to as the transition period. At the conclusion of the transition
period, we will be at risk to recover any of our Utility's remaining generation
costs through market-based revenues.
. Rate Freeze and Rate Reduction
The first element of the transition plan is an electric rate freeze and an
electric rate reduction. During 1997, electric rates for our Utility's customers
were held at 1996 levels. Effective January 1, 1998, we reduced electric rates
for our Utility's residential and small commercial customers by 10 percent and
will hold their rates at that level. The rate freeze will continue until the end
of the transition period.
To pay for the 10 percent rate reduction, we financed $2.9 billion of our
transition costs with rate reduction bonds. See Cash Flows from Financing
Activities below.
. Transition Cost Recovery
The second element of the transition plan is recovery of transition costs.
Transition cost recovery has five parts for determining: (1) which costs are
eligible for recovery as transition costs, (2) when they can be recovered, (3)
how transition cost revenues will be determined, (4) how transition costs will
be expensed, and (5) what happens when transition cost revenues differ from the
related expenses. Each of these five parts is discussed below.
The first part of transition cost recovery is determining which Utility costs
are eligible for recovery as transition costs. These costs include: (1) above-
market sunk costs (sunk costs are costs associated with Utility-owned generating
facilities that are fixed and unavoidable and currently included in our Utility
customers' electric rates) and future costs, such as costs related to plant
removal, (2) costs associated with the Utility's long-term contracts to purchase
power at above-market prices from Qualifying Facilities (QF) 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 that are
disallowed by the CPUC for collection from Utility customers will be written
off. Each of the types of eligible transition costs are discussed below.
Sunk costs associated with Utility-owned generation facilities are currently
included in our Utility customers' rates. Above-market sunk costs are those
whose values recorded on our balance sheet (book value) are expected to be in
excess of their market values. Conversely, below-market sunk costs are those
whose market values are expected to be in excess of their book values. In
general, 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. The above-
market portion of sunk costs is eligible for recovery as a transition cost. The
below-market portion of sunk costs will reduce other unrecovered transition
costs. A valuation of Utility-owned generation facilities where the market value
exceeds the book value could result in a material charge if the Utility retains
the facility. This is because any excess of market value over book value would
be used to reduce other transition costs without being collected in rates.
We will not be able to determine the exact amount of sunk costs that will be
recoverable as transition costs until a market valuation process (appraisal,
spin, or sale) is completed for each of our Utility's generation facilities. The
first of these valuations occurred in 1997 when we agreed to sell three Utility-
owned electric plants for $501 million. The sale is expected to close during
1998. (See Generation Divestiture below.) The rest of the valuation process will
be completed by December 31, 2001. At December 31, 1997, our Utility's net
investment in Diablo Canyon and Utility-owned non-nuclear generation facilities
was $3.7 billion and $2.7 billion, respectively, including the plants to be sold
in 1998.
21
<PAGE>
Management's Discussion and Analysis of
Consolidated Results of Operations and Financial Condition
Our Utility has agreed to purchase electric power from QFs and other power
suppliers under long-term contracts expiring on various dates through 2028. Over
the life of these contracts, the Utility estimates that it will purchase
approximately 360 million megawatt-hours (MWh) at an aggregate average price of
6.3 cents per kilowatt-hour (kWh). To the extent that this price is above the
market price, our 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.
In addition, as of December 31, 1997, we have accumulated approximately $1.5
billion of generation-related net regulatory assets. The net regulatory assets
are eligible for recovery as transition costs.
The CPUC has the ultimate authority to determine which costs are eligible to
be recovered as transition costs. Reviews by the CPUC to determine the
reasonableness of transition costs are being conducted and will continue to be
conducted throughout the transition period.
The second part of transition cost recovery is determining when eligible
transition costs can be recovered. Under the transition plan, most transition
costs must be recovered by March 31, 2002. This recovery period is significantly
shorter than the recovery period of the related assets prior to restructuring.
Recovery of transition costs during this shorter period is referred to as
accelerated recovery. The CPUC believes that acceleration reduces risks
associated with recovery of all our Utility's generation assets, including
Diablo Canyon and hydroelectric facilities. As a result, in accordance with the
transition plan, we are receiving a reduced return for all of our Utility-owned
generation facilities. In 1997, the reduced return was 7.13 percent as compared
to an authorized return of 9.45 percent. The reduced return on non-nuclear
generation assets, effective July 28, 1997, resulted in a $24 million decrease
in earnings ($0.06 per share) in 1997 and will have a continued impact
throughout the transition period.
Although most transition costs must be recovered by March 31, 2002, certain
transition costs can be included in customers' electric rates after the
transition period. These costs include: (1) certain employee-related transition
costs, (2) above-market payments under existing QF and power-purchase contracts
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 the facility. During the rate freeze, this charge will not increase
our Utility customers' electric rates. Excluding these exceptions, we will
write-off any transition costs not recovered during the transition period.
The third part in transition cost recovery is determining the amount of
electric utility revenues under frozen rates that are available to recover
eligible transition costs. As directed by the CPUC, we have separated, or
unbundled, the Utility's previously authorized cost-of-service electric revenues
into separate categories. Unbundling enables us to allocate revenue provided by
frozen electric rates into transmission, distribution, public purpose programs,
and generation based upon their respective cost of service. Revenues provided by
frozen rates will also be used to recover other authorized Utility costs,
including nuclear decommissioning, rate reduction bond debt service, and
transition cost recovery.
The portion of the unbundled revenue to be provided for transition cost
recovery is based upon mechanisms approved by the CPUC. Revenue provided for
recovery of most non-nuclear transition costs is based upon their acceleration
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 acceleration of our investment in
Diablo Canyon from a period ending in 2016 to a five-year period ending December
31, 2001.
The fourth part of transition cost recovery addresses the depreciation and
amortization of transition costs. Based on our Utility's evaluation of the
transition plan and state legislation and CPUC decisions related to the
transition plan, our Utility is depreciating Diablo Canyon over a five-year
period ending December 31, 2001. The change in depreciable life increased Diablo
Canyon's depreciation expense for 1997, as
22
<PAGE>
compared to 1996, by $583 million. In addition, most generation-related
regulatory assets are being amortized on a straight-line basis, in accordance
with their recovery under the transition plan, beginning January 1, 1998.
Further, upon valuation of generation facilities, any losses will be amortized
over the remaining transition period as a transition cost. Any gains will be
recognized and used to reduce other transition costs at the time of valuation.
In the fifth part of transition cost recovery we compare (1) revenues provided
for transition cost recovery with (2) the costs associated with accelerated
recovery including the depreciation of Diablo Canyon and the amortization of
regulatory assets. If the revenues exceed the accelerated costs, certain
transition costs may be further accelerated until all transition costs are
recovered or March 31, 2002, whichever is earlier. If the accelerated costs
exceed the revenues, the costs will be deferred. At the end of the transition
period, any over collection of these amounts will be returned to customers.
Our Utility's ability to recover its transition costs during the transition
period will be dependent on several factors. These factors include: (1) the
continued application of the regulatory framework established by the CPUC and
state legislation, (2) the amount of transition costs approved by the CPUC, (3)
the market value of our Utility-owned generation facilities, (4) future Utility
sales levels, (5) future Utility fuel and operating costs, (6) the extent to
which our Utility's authorized revenues to recover distribution costs are
increased or decreased, and (7) the market price of electricity. Given our
current evaluation of these factors, we believe that we will recover our
transition costs. Also, we believe that our regulatory assets and Utility-owned
generation plants are not impaired. 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.
During 1997, the difference between billed revenues and authorized revenues
was used to recover transition costs, including most of the accelerated Diablo
Canyon sunk costs.
. Generation Divestiture
The third element of the transition plan is the economic divestiture of Utility-
owned generation facilities. In 1997, California utilities produced a
significant portion of the state's electric generation needs. In a competitive
market, the CPUC is concerned that this level of generation may give existing
utilities undue influence on the PX price. As part of the transition plan, we
have agreed to sell a significant portion of our generation facilities to
alleviate this concern.
In 1997, we agreed to sell three electric Utility-owned fossil-fueled
generating plants to Duke Energy through an auction process. The aggregate bid
accepted for these plants was $501 million. These three fossil-fueled plants
have a combined book value at December 31, 1997, of approximately $370 million
and a combined capacity of 2,645 megawatts (MW). The three power plants were
Morro Bay, Moss Landing, and Oakland.
The sales have been approved by the CPUC. However, they are still subject to
approval of the transfer of various permits and licenses. Additionally, the
Utility will retain liability for required environmental remediation of any pre-
closing soil or groundwater contamination at these plants. As a result of
retaining such environmental remediation liability, we do not expect any
material adverse impact on the Utility's or our financial position or results of
operations. We expect the sale of these three plants to close in 1998.
We plan to conduct another auction of our four remaining Utility-owned fossil-
fueled plants and our Utility-owned geothermal facilities in the first half of
1998. These additional plants have a combined generating capacity of 4,718 MW
and a combined book value at December 31, 1997, of approximately $790 million.
Together the eight power plants represent 98 percent of the Utility's fossil-
fueled generating capacity and all of the Utility's geothermal generating
capacity. The eight plants currently generate approximately 22 percent of the
Utility's total electric sales. The Utility is currently evaluating its options
related to its remaining generation facilities and may decide not to retain its
economic investment in those facilities. During the transition period, the
proceeds from the sale of our plants will be used to offset transition costs
associated with other Utility electric generation facilities. Therefore, we do
not expect any material adverse impact on the Utility's or our financial
position or results of operations
23
<PAGE>
Management's Discussion and Analysis of
Consolidated Results of Operations and Financial Condition
from any of these divestitures.
. Customer Impacts of Transition Plan
Under the transition plan, once the PX and ISO are operational, all electric
customers may choose their electric commodity provider. During the transition
period, all customers will be billed for electricity used, for transmission and
distribution services, for public purpose programs, and for recovery of
transition costs. Customers who choose to purchase their electricity from non-
Utility energy providers will see a change in their total bill only to the
extent that their contracted electric commodity price differs from the PX price.
Transition costs are being recovered from all Utility distribution customers
through a nonbypassable charge regardless of their choice in commodity provider.
As transition costs are nonbypassable, we do not believe that the availability
of choice to our customers will have a material impact on our ability to recover
transition costs.
In addition to supplying commodity electric power, once the ISO and PX are
operational, commodity electric providers will be able to choose the method of
billing their customers and whether to provide their customers with metering
services. We will track cost savings that result when billing, metering, and
related services within our Utility's service territory are provided by another
entity. Once these cost savings, or credits, are approved by the CPUC and the
customer's energy provider is performing billing and metering services, we will
reduce the customer's bill by the savings. The electric provider will then
charge their customers for these services. To the extent that these credits
equate to our actual cost savings from reduced billing, metering, and related
services, we do not expect a material adverse impact on the Utility's or our
financial condition or results of operations.
. The Transition Plan and SFAS No. 71
In 1997, to comply with new accounting guidance, we discontinued the application
of SFAS No. 71 for the generation portion of our Utility business. The new
accounting guidance requires that regulatory assets and liabilities (both those
in existence today and those created under the terms of the transition plan) be
allocated to the portion of the business from which the source of the regulated
cash flows is derived. Under the transition plan, generation-related regulatory
assets are eligible for recovery as transition costs from customers of our
Utility's electric distribution business. Accordingly, they have been allocated
to that business. As we believe the recovery of our transition costs from these
customers is probable, the discontinuation of application of SFAS No. 71 to our
Utility's generation business did not have a material effect on our financial
statements. As of December 31, 1997, we have recorded approximately $1.5 billion
of generation-related regulatory assets.
Given the current regulatory environment, our Utility's electric transmission
business and most areas of the Utility's electric distribution business are
expected to remain rate regulated and, as a result, we will continue to apply
the provisions of SFAS No. 71. However, as discussed above, once the ISO and PX
are operational, unregulated electric providers may provide their customers with
billing and metering services. In the future, electric providers may be allowed
to provide other distribution services (such as customer inquiries and
uncollectibles). Any discontinuance of SFAS No. 71 for these portions of our
Utility electric distribution business is not expected to have a material
adverse impact on the Utility's or our financial position or results of
operations.
The Gas Business:
Through our Utility, we sell natural gas and provide natural gas transportation
services to our customers. Currently, our customers may buy gas directly from
competing suppliers and purchase gas transmission- and distribution-only
services from us. Our Utility transmission system transports gas throughout
California to our distribution system which, in turn, delivers gas to end-use
customers. Utility transmission and distribution services for all customers have
historically been "bundled" or sold together at a combined rate. Most of our
industrial and larger commercial (noncore) customers purchase their commodity
gas from marketers and brokers. Substantially all residential and smaller
commercial (core) customers buy their commodity gas as well as transmission and
distribution services from us. In order to ensure competitive prices for our
customers, we negotiate short-term supply arrangements with numerous providers.
24
<PAGE>
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 is expected to be implemented in March 1998. More
specifically, the Accord has four principal elements:
1. The Accord separates or "unbundles" the rates for our Utility's gas
transportation system. Once the Accord is implemented, we will offer
transmission and distribution services as separate and distinct services to
our noncore customers. Unbundling will give these customers the opportunity
to select from a menu of services offered by the Utility and will enable
them to pay only for the services that they use. Unbundling will also make
access to the transmission system possible for all gas marketers and
shippers, as well as noncore end-users. As a result, the Accord will make
our Utility's transmission system more accessible to a greater number of
customers.
2. The Accord increases the opportunity for our Utility's core customers to
select the commodity gas supplier of their choice. Greater customer choice
will increase competition among suppliers providing gas to core customers
and will reduce our role in purchasing gas for such customers. Despite these
changes, we will continue to purchase gas as a regulated supplier for those
who request it.
3. The Accord changes the way in which our Utility's costs of purchasing gas
for core customers through 2002 are regulated. Prior to 1994, we were
authorized to collect all costs of purchased gas through rates as long as
the CPUC deemed the costs to be reasonable. The Accord replaces the CPUC
reasonableness reviews with the core procurement incentive mechanism (CPIM),
a form of incentive ratemaking. Apart from a "tolerance band" constructed
around market benchmarks, the CPIM will reward us if we are able to buy gas
for our core customers at a price below a specified market index price and
penalize us if we buy gas at a price above the market index price. Actual
core procurement costs measured from 1994 through 1997 have generally been
within the CPIM tolerance band.
4. The Accord settled various regulatory issues involving our 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 for the period from March
1998 through December 2002 for our Utility's core and noncore customers and
eliminates regulatory protection for variations in sales volumes for noncore
transmission revenues. As a result, we will be 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 distribution
services will continue to be set by the CPUC and designed to provide us an
opportunity to recover our costs of service and include a return on our
investment.
Our Response to Changes in Our Industry:
ACQUISITIONS AND SALES
Over the past several years, we have taken steps to take advantage of the
changing electric and gas markets and to become a national energy company. In
order to accomplish this, we have made several investments to position ourselves
to expand and to integrate in the gas transmission market, the energy trading
market, the retail energy services market, and the unregulated electric
generation market. These investments are highlighted below.
In 1997, we created a gas transmission business in Texas, through the
acquisitions of Teco Pipeline Company (Teco) and Valero Energy Corporation's
(Valero) natural gas and natural gas liquids business. Teco was acquired for
approximately $378 million, consisting of $317 million of PG&E Corporation
common stock and the purchase of a $61 million note. Valero was acquired for
approximately $1.5 billion, consisting of 31 million shares of PG&E Corporation
common stock along with the assumption of approximately $780 million in long-
term debt. Valero pipeline operations have averaged approximately $147 million
in revenues and expenses each month since August 1997. Teco pipeline operations
have averaged approximately $6 million in revenues and expenses each month since
January 1997.
Further, in 1997, we strengthened our presence in the
25
<PAGE>
Management's Discussion and Analysis of
Consolidated Results of Operations and Financial Condition
unregulated electric generation market. We completed our acquisition of our
partner's interests in three U.S. Generating Company (USGen) partnerships we
previously jointly owned with Bechtel Enterprises, Inc. (Bechtel). We are now
the sole owner of USGen, the largest independent power developer and manager
operating in the United States, U.S. Operating Services Company, USGen's
operations and maintenance affiliate, and its power marketing affiliate USGen
Power Services, L.P. Additionally, we have acquired all or part of Bechtel's
interest in several power projects that are affiliated with USGen. Through its
affiliates, USGen has ownership or management interests in 15 electric
generating facilities operating in eight states.
Additionally, in 1997, USGen was selected to buy a portfolio of electric
generating assets and power supply contracts from the New England Electric
System (NEES) for $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, financing requirements are expected to total
approximately $1.75 billion, of which approximately $1 billion will be funded
through a combination of project level debt as well as debt of USGen. In
addition, $750 million of equity will be contributed over two years and will be
financed initially using short-term debt of PG&E Corporation. The assets contain
a balance of hydro, coal, oil, and natural gas generation facilities. The
acquisition is subject to regulatory approval, among other conditions. We expect
the acquisition to be completed in the second half of 1998.
Maximizing the benefits of the gas transmission, electric generation, and
energy service supply businesses on a national level requires procurement,
scheduling, and risk management capabilities. In order to assure the efficient
management of the risks and rewards of supplying our customers' energy needs and
to optimize our corporate assets, we have combined the trading and risk
management businesses of Energy Source (acquired in 1996), Teco, and Valero to
form PG&E Energy Trading (PG&E ET). PG&E ET purchases and resells energy
commodities and related financial instruments in major domestic markets, serving
PG&E Corporation's other unregulated businesses, unaffiliated utilities, and
large end-use customers.
Our national energy strategy does not currently contemplate continued
investment in international generation projects. Therefore, in 1997, we sold to
Bechtel our interest in International Generating Company, Ltd., a joint venture
between PG&E Corporation and Bechtel, together with all of our related project
interests. The sale has resulted in an after-tax gain of approximately $120
million, which was recorded in 1997.
REGULATORY ACTIVITY
This section discusses items affecting future Utility authorized revenues: the
1999 General Rate Case; a 1998 Revenue Adjustment associated with the electric
transition plan, discussed above; and the 1998 Cost of Capital Proceeding. Any
requested change in authorized electric revenues resulting from any of these
proceedings would not impact our Utility's customer electric rates because these
rates are frozen in accordance with the electric transition plan. However,
increases in authorized electric revenues would reduce the amount of revenue
available to recover transition costs.
. The Utility's 1999 General Rate Case (GRC)
In December 1997, we filed our 1999 GRC application with the CPUC. During the
GRC process, the CPUC examines our Utility's non-fuel related costs to determine
the amount we can charge customers. In our application, we requested an increase
in our Utility's authorized revenues, effective January 1, 1999. The requested
increase consists of an increase of $693 million in electric utility revenues
and an increase of $501 million in gas utility revenues over authorized 1997
revenues.
The 1999 GRC will not affect the authorized revenues of electric and gas
transmission services or of gas storage services. The authorized revenues for
each of these services are determined in other proceedings.
Electric transmission revenues for 1998 are expected to be authorized by the
FERC. In 1997, we filed an application with the FERC requesting electric
transmission revenues of $305 million. The requested revenue is consistent with
electric transmission revenues in CPUC-authorized 1997 electric rates. The FERC-
authorized rates will be effective
26
<PAGE>
once the ISO and PX are operational.
Also, revenues associated with gas transmission and storage services were
authorized as part of the Gas Accord. See Gas Business, above, for a discussion
of the Gas Accord.
. The Utility's 1998 Electric Revenue Adjustment
The electric transition plan (see Electric Business above) allows for increases
in revenues previously authorized in the 1996 GRC for system safety and
reliability. The CPUC increased 1997 authorized revenues for these services by
$160 million. The CPUC also authorized an additional $86 million in 1998 for
system safety and reliability.
. The Utility's 1998 Cost of Capital Proceeding
The CPUC authorized a cost of capital for the Utility's gas and electric
distribution assets in 1998 of 9.17 percent. The authorized 1998 cost of common
equity is 11.20 percent which is lower than the 11.60 percent authorized for
1997. The CPUC contends that this decrease reflects the level of business and
regulatory risks the Utility now faces. The authorized cost of capital will
decrease 1998 authorized electric and gas revenue by approximately $25 million
and $9 million, respectively. The Utility has requested a rehearing of the Cost
of Capital decision. We believe that business and regulatory risks have not been
reduced and that our requested cost of common equity of 12.25 percent is more
appropriate. The rehearing is expected to occur in 1998.
Consistent with the rate freeze, there will be no change in electric rates in
1998 and the lower authorized revenues will be offset by additional transition
cost recovery. As discussed above, the CPUC separately reduced the authorized
return on our Utility's electric generation-related assets to 7.13 percent.
Also, the return on our Utility's electric transmission-related assets will be
determined by the FERC in 1998. Finally, the return on our Utility's gas
transmission and storage businesses was incorporated in rates established in the
Gas Accord.
Liquidity and Capital Resources:
Cash Flows from Operating Activities:
Net cash provided by operating activities totaled $2.6, $2.6, and $3.3 billion
in 1997, 1996, and 1995, respectively. Cash from operations exceeded capital
requirements for all years presented.
Cash Flows from Financing Activities:
PG&E CORPORATION
During 1997, we issued $752 and $317 million of common stock to acquire Valero
and Teco, respectively. These acquisitions did not require the use of cash. We
also issued $54 million of common stock through the Dividend Reinvestment Plan
and the employee Long-Term Incentive Plan. Also in 1997, we repurchased $804
million of our common stock on the open market and paid dividends of $524
million.
During 1996 and 1995, we issued $220 and $140 million shares of common stock,
respectively, through the employee Savings Fund Plan, the Dividend Reinvestment
Plan, and the employee Long-Term Incentive Plan. In 1996, we repurchased $455
million shares of our common stock and paid dividends of $844 million. In 1995,
we repurchased $601 million shares of our common stock and paid dividends of
$891 million.
In previous years, the Board of Directors (Board) authorized us to repurchase
up to $2 billion of our common stock on the open market or in negotiated
transactions. In 1997, the Board increased this authorization to a total of $4
billion. Through December 31, 1997, the Corporation had repurchased
approximately $2.3 billion of its common stock under this program. As part of
this Board authorization, in January 1998, the Corporation entered into a
specific transaction to repurchase 37 million shares of common stock at $30.3125
per share. In connection with this transaction, the Corporation has entered into
a forward contract with an investment institution. The 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 the
Corporation through purchases on the open market or through privately negotiated
transactions. The contract is anticipated to expire by December 31, 1998.
In January 1997, we established a $500 million revolving credit facility, and
in August 1997, we entered into an
27
<PAGE>
Management's Discussion and Analysis of
Consolidated Results of Operations and Financial Condition
additional $500 million temporary credit facility. Both of these credit
facilities are to be used for general corporate purposes. There were no
borrowings under these facilities at December 31, 1997.
During 1997, our unregulated business operations issued $30 million and
retired $109 million of long-term debt. Also in 1997, we assumed approximately
$780 million of long-term debt in connection with the acquisition of Valero.
In 1996, we entered into additional loan agreements of $92 million to finance
the PG&E Gas Transmission acquisition of assets in Queensland, Australia.
During 1995, our unregulated business operations issued $400 million of bonds,
$70 million of medium-term notes, and $109 million of commercial paper which is
classified as long-term debt. Substantially all of the proceeds from the debt
issued in 1995 were used to refinance outstanding debt. The classification of
commercial paper as long-term debt is based on the availability of committed
credit facilities expiring in 2000 and management's intent to maintain such
amounts in excess of one year.
UTILITY
In 1997, 1996, and 1995, our Utility redeemed or repurchased $225, $1,113, and
$758 million, respectively, of long-term debt to manage the overall balance of
our Utility's capital structure. Long-term debt maturing during 1997, 1996, and
1995 was not refinanced.
In 1997, our Utility issued $360 million of variable rate pollution control
bonds and repurchased the same amount of fixed-rate pollution control bonds.
In 1996, our Utility repurchased $988 million of variable and fixed interest
rate pollution control mortgage bonds and loan agreements which were replaced
with variable interest rate pollution control loan agreements.
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 will be used by the
Utility to retire debt and reduce equity. The bonds will facilitate a 10 percent
rate reduction for residential and eligible small commercial customers,
effective January 1, 1998. During the term of the bonds, the Utility will
collect from its residential and small commercial customers a separate
nonbypassable charge on behalf of the special purpose entity to recover
principal, interest, and related costs of the bonds. The bonds are secured by
the separate charge, which does not belong to the Utility. The bonds are not
secured by the Utility's assets. While the bonds are reflected as a long-term
liability on our balance sheet, creditors of the Utility do not have any
recourse to revenues from the separate charge.
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
mutual agreement between the Utility and the banks. There were no borrowings
under this credit facility in 1997 or 1996.
The table below provides information about our debt obligations and the rate
reduction bonds at December 31, 1997:
<TABLE>
<CAPTION>
Expected maturity date 1998 1999 2000 2001 2002 Thereafter Total(1)
- ----------------------------------------------------------------------------------------------------
(in millions)
<S> <C> <C> <C> <C> <C> <C> <C>
Long-term debt
Fixed rate $659 $294 $460 $330 $515 $4,712 $6,970
Average interest rate 5.8% 6.3% 6.0% 7.8% 7.7% 7.2% 6.9%
Variable rate - - - - - $1,348 $1,348
Rate reduction bonds $125 $265 $280 $300 $290 $1,641 $2,901
Average interest rate 5.9% 6.0% 6.2% 6.2% 6.3% 6.4% 6.3%
</TABLE>
(1) The fair value of long-term debt and rate reduction bonds is essentially the
same as the book value.
28
<PAGE>
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.
Capital Spending:
Our estimated capital spending for the next three years is shown below:
<TABLE>
<CAPTION>
Year ended December 31, 1998 1999 2000
- --------------------------------------------------------------
(in millions)
<S> <C> <C> <C>
Utility capital requirements $1,835 $1,739 $1,617
Other capital requirements 2,091 246 192
Maturing debt obligations and
sinking funds 784 559 740
--------------------------
Total $4,710 $2,544 $2,549
==========================
</TABLE>
Utility expenditures will be primarily for improvements to facilities to
enhance their efficiency and reliability, to extend their useful lives, and to
comply with environmental laws and regulations.
Other capital expenditures will be primarily for the purchase of electric
generating assets and power supply contracts for NEES, discussed above in
Acquisitions and Sales.
Environmental Matters:
We are subject to laws and regulations established to both improve and maintain
the quality of the environment. Where our properties contain hazardous
substances, these laws and regulations require us to remove or remedy the effect
on the environment.
At December 31, 1997, the Utility expects to spend $232 million for clean-up
costs at identified sites over the next 30 years. If other responsible parties
fail to pay or identified outcomes change, then these costs may be as much as
$442 million. Of the $232 million, the Utility expects to recover $157 million
in future rates. The liability also includes $58 million related to power plant
decommissioning for environmental clean-up, which the Utility recovered through
depreciation. Additionally, the Utility is seeking recovery of costs from
insurance carriers and from other third parties. (See Note 13 of Notes to
Consolidated Financial Statements.)
Year 2000:
In 1995, we began and presently continue to review and assess our computer and
information systems in anticipation of the year 2000. At that time, our software
programs and systems for critical financial and operational information will be
required to recognize this date in the next millennium. The Year 2000 issue
exists because many computer programs use only two digits to identify a year in
the date field and were developed without considering the impact of the upcoming
change in the century. We currently expect to complete critical software
conversion modifications by the end of 1998. We do not currently anticipate any
material adverse impact on the Utility's or our financial position or results of
operations as a result of the Year 2000 issue.
Accounting for Decommissioning Expense:
In 1996, the Financial Accounting Standards Board issued an Exposure Draft (ED)
entitled "Accounting for Certain Liabilities Related to Closure and Removal of
Long-Lived Assets." A revised ED is expected in 1998. If the ED is adopted as
currently proposed: (1) annual expense for power plant decommissioning could
increase, and (2) the estimated total cost for power plant decommissioning could
be recorded as a liability, with recognition of an increase in the cost of the
related power plant, rather than accrued over time as accumulated depreciation.
We do not believe that this change, if implemented as proposed, would have a
material adverse impact on the Utility's or our financial position or results of
operations. (See Note 2 of Notes to Consolidated Financial Statements for
discussion of electric industry restructuring.)
Legal Matters:
In the normal course of business, the Corporation and the Utility are named as a
party in a number of claims and lawsuits. Substantially all of these have been
litigated or settled with no material adverse impact on either the Utility's or
our financial position or results of operations. See Note 13 of Notes to
Consolidated Financial Statements for further discussion of significant pending
legal matters.
29
<PAGE>
Inflation:
Financial statements, which are prepared in accordance with generally accepted
accounting principles, report operating results in terms of historic 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 future results of
operations.
Price Risk Management: We have established an officer-level price risk
management committee and adopted a price risk management policy approved by the
Board for our trading and risk management activities. The price risk management
committee oversees implementation of our policy, approves the trading and price
risk management policies of our subsidiaries, and monitors compliance with the
policy.
Our price risk management policy allows derivatives to be used for both
hedging and non-hedging purposes (a derivative is a contract whose value is
dependent on or derived from the value of some underlying asset). We use
derivatives for hedging purposes primarily to offset underlying commodity price
risks. We also participate in markets using derivatives to create liquidity and
maintain a market presence. Such derivatives include forward contracts, futures,
swaps, and options. 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.
In 1997, we approved and implemented trading and risk management policies for
PG&E ET and continued to seek regulatory approval to manage commodity price
risks in our Utility business.
The fair value of market risk sensitive instruments (which includes our
hedging and non-hedging instruments described above) as of December 31, 1997, is
immaterial for financial instruments subject to commodity price risk.
Additionally, as of December 31, 1997, the Corporation calculated value-at-risk
based on a 95 percent confidence level using five-day holding periods. Using
this methodology, the potential for near-term losses in future earnings, fair
values, and cash flows from reasonably possible near-term changes in market
prices for financial instruments subject to commodity price risk is immaterial.
We anticipate an increase in the level of trading and risk management activity
in 1998 due to expected growth in our unregulated national energy businesses and
a continuing effort to manage anticipated price risks in our Utility business.
Our Utility manages price risk independently from the activities in our
unregulated businesses.
30
<PAGE>
PG&E Corporation
Statement of Consolidated Income
<TABLE>
<CAPTION>
(in millions, except per share amounts) Year ended December 31, 1997 1996 1995
- ------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Operating Revenues
Utility $ 9,495 $8,989 $9,243
Energy commodities and services 5,905 621 379
------------------------------------
Total operating revenues 15,400 9,610 9,622
------------------------------------
Operating Expenses
Cost of energy for utility 2,974 2,709 2,403
Cost of energy commodities and services 5,511 356 47
Operating and maintenance 3,298 3,427 3,049
Depreciation and decommissioning 1,889 1,222 1,360
------------------------------------
Total operating expenses 13,672 7,714 6,859
------------------------------------
Operating Income 1,728 1,896 2,763
Interest expense, net (665) (632) (678)
Other income and expense 201 13 79
------------------------------------
Income Before Income Taxes 1,264 1,277 2,164
Income taxes 548 555 895
------------------------------------
Net Income $ 716 $ 722 $1,269
====================================
Weighted Average Common Shares Outstanding 410 413 424
Earnings Per Common Share, Basic and Diluted $ 1.75 $ 1.75 $ 2.99
Dividends Declared Per Common Share $ 1.20 $ 1.77 $ 1.96
The accompanying Notes to the Consolidated Financial Statements are an integral part of this statement.
</TABLE>
31
<PAGE>
PG&E Corporation
Consolidated Balance Sheet
<TABLE>
<CAPTION>
(in millions) At December 31, 1997 1996
- ------------------------------------------------------------------------------
<S> <C> <C>
Assets
Current Assets
Cash and cash equivalents $ 237 $ 131
Short-term investments 1,160 13
Accounts receivable
Customers, net 1,514 1,152
Regulatory balancing accounts 658 444
Energy marketing 830 387
Inventories and prepayments 626 584
-------- --------
Total current assets 5,025 2,711
Property, Plant, and Equipment
Utility 32,972 31,716
Gas transmission 3,484 1,594
Other 57 -
-------- --------
Total property, plant, and equipment (at original cost) 36,513 33,310
Accumulated depreciation and decommissioning (16,041) (14,302)
-------- --------
Net property, plant, and equipment 20,472 19,008
Other Noncurrent Assets
Regulatory assets 2,337 2,518
Nuclear decommissioning funds 1,024 883
Other 1,699 1,117
-------- --------
Total noncurrent assets 5,060 4,518
-------- --------
Total Assets $ 30,557 $ 26,237
======== ========
</TABLE>
32
<PAGE>
PG&E Corporation
Consolidated Balance Sheet
<TABLE>
<CAPTION>
(in millions) At December 31, 1997 1996
- ------------------------------------------------------------------------------------------------------------------
<S> <C> <C>
Liabilities and Equity
Current Liabilities
Short-term borrowings $ 103 $ 681
Current portion of long-term debt 659 210
Current portion of rate reduction bonds 125 -
Accounts payable
Trade creditors 754 490
Other 620 548
Energy marketing 758 388
Accrued taxes 226 310
Other 739 653
----------------------
Total current liabilities 3,984 3,280
Noncurrent Liabilities
Long-term debt 7,659 7,770
Rate reduction bonds 2,776 -
Deferred income taxes 4,029 3,941
Deferred tax credits 339 380
Other 2,034 1,663
----------------------
Total noncurrent liabilities 16,837 13,754
Preferred Stock of Subsidiary With Mandatory Redemption Provisions
6.30% and 6.57%, outstanding 5,500,000 shares, due 2002-2009 137 137
Utility 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 of subsidiary, par value $25, authorized 75,000,000 shares
Without mandatory redemption provisions
Nonredeemable-5% to 6%, outstanding 5,784,825 shares 145 145
Redeemable-4.36% to 7.44%, outstanding 10,297,404 shares 257 257
Common stock, no par value, authorized 800,000,000 shares; issued and outstanding,
417,665,891 and 403,504,292 shares 6,366 5,728
Reinvested earnings 2,531 2,636
----------------------
Total stockholders' equity 9,299 8,766
Commitments and Contingencies (Notes 1, 2, 3, 4, 12, and 13) - -
----------------------
Total Liabilities and Stockholders' Equity $30,557 $ 26,237
======================
The accompanying Notes to the Consolidated Financial Statements are an integral part of this statement.
</TABLE>
33
<PAGE>
PG&E Corporation
Statement of Consolidated Cash Flows
<TABLE>
<CAPTION>
(in millions) Year ended December 31, 1997 1996 1995
- -------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Cash Flows From Operating Activities
Net income $ 716 $ 722 $ 1,269
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, decommissioning, and amortization 2,014 1,316 1,449
Deferred income taxes and tax credits-net (159) (150) (116)
Other deferred charges and noncurrent liabilities 159 22 (25)
Gain on sale of assets (120) - -
Net effect of changes in operating assets and liabilities:
Accounts receivable (242) (70) 200
Regulatory balancing accounts receivable (74) 302 499
Inventories (4) 32 32
Accounts payable 210 217 62
Accrued taxes (54) 36 (162)
Other working capital (85) (6) 8
Other-net 257 160 99
-----------------------------
Net cash provided by operating activities 2,618 2,581 3,315
-----------------------------
Cash Flows From Investing Activities
Capital expenditures (1,822) (1,230) (945)
Investments in unregulated projects (75) (70) (157)
Acquisitions (41) (159) -
Proceeds from sale of assets 146 - 340
Other-net 21 (120) (123)
-----------------------------
Net cash used by investing activities (1,771) (1,579) (885)
-----------------------------
Cash Flows From Financing Activities
Net increase (decrease) in short-term borrowings (587) (115) 305
Long-term debt issued 386 1,088 591
Long-term debt matured, redeemed, or repurchased-net (961) (1,472) (1,297)
Proceeds from issuance of rate reduction bonds 2,881 - -
Preferred stock redeemed or repurchased - - (358)
Utility obligated mandatorily redeemable preferred securities issued - - 300
Common stock issued 54 220 140
Common stock repurchased (804) (455) (601)
Dividends paid (524) (844) (891)
Other-net (39) (14) (22)
-----------------------------
Net cash used by financing activities 406 (1,592) (1,833)
-----------------------------
Net Change in Cash and Cash Equivalents 1,253 (590) 597
Cash and Cash Equivalents at January 1 144 734 137
-----------------------------
Cash and Cash Equivalents at December 31 $ 1,397 $ 144 $ 734
=============================
Supplemental disclosures of cash flow information
Cash paid for:
Interest (net of amounts capitalized) $ 624 $ 598 $ 645
Income taxes 801 640 1,126
The accompanying Notes to the Consolidated Financial Statements are an integral part of this statement.
</TABLE>
34
<PAGE>
PG&E Corporation
Statement of Consolidated Common Stock Equity,
Preferred Stock, and Preferred Securities
<TABLE>
<CAPTION>
Preferred Preferred
Stock of Stock of
Subsidiary Subsidiary
Total Without With
Additional Common Mandatory Mandatory
Common Paid-in Reinvested Stock Redemption Redemption
(dollars in millions) Stock Capital Earnings Equity Provisions Provisions
- ------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Balance December 31, 1994 $2,151 $3,806 $2,677 $8,634 $733 $137
---------------------------------------------------------------------------
Net income 1,269 1,269
Common stock issued
(5,316,876 shares) 27 113 140
Common stock repurchased
(21,533,977 shares) (108) (195) (298) (601)
Preferred securities issued(1)
(12,000,000 shares) 300
Preferred stock redeemed
(13,237,554 shares) (8) (8) (331)
Cash dividends declared
Common stock (830) (830)
Other (5) (5)
---------------------------------------------------------------------------
Balance December 31, 1995 2,070 3,716 2,813 8,599 402 437
---------------------------------------------------------------------------
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 8,364 402 437
---------------------------------------------------------------------------
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 $402 $437
===========================================================================
(1)Relates to utility obligated mandatorily redeemable preferred securities of trust holding solely Utility subordinated debentures.
The accompanying Notes to the Consolidated Financial Statements are an integral part of this statement.
</TABLE>
35
<PAGE>
Pacific Gas and Electric Company
Statement of Consolidated Income
<TABLE>
<CAPTION>
(in millions) Year ended December 31, 1997 1996 1995
- -----------------------------------------------------------------------------
<S> <C> <C> <C>
Operating Revenues
Electric utility $7,691 $7,160 $7,387
Gas utility 1,804 1,829 1,856
Energy commodities and services - 621 379
----------------------
Total operating revenues 9,495 9,610 9,622
Operating Expenses
Cost of electric energy 2,501 2,261 2,117
Cost of gas 473 448 286
Cost of energy commodities and services - 356 47
Operating and maintenance 2,905 3,427 3,049
Depreciation and decommissioning 1,785 1,222 1,360
----------------------
Total operating expenses 7,664 7,714 6,859
Operating Income 1,831 1,896 2,763
Interest expense, net (570) (632) (678)
Other income and expense 116 46 149
----------------------
Income Before Income Taxes 1,377 1,310 2,234
Income taxes 609 555 895
----------------------
Net income 768 755 1,339
Preferred dividend requirement and redemption premium 33 33 70
----------------------
Income Available for Common Stock $ 735 $ 722 $1,269
======================
The accompanying Notes to the Consolidated Financial Statements are an integral part of this statement.
</TABLE>
36
<PAGE>
Pacific Gas and Electric Company
Statement of Consolidated Cash Flows
<TABLE>
<CAPTION>
(in millions) Year ended December 31, 1997 1996 1995
- ------------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Cash Flows From Operating Activities
Net income $ 768 $ 755 $ 1,339
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, decommissioning, and amortization 1,914 1,316 1,449
Deferred income taxes and tax credits-net (182) (150) (116)
Other deferred charges and noncurrent liabilities 167 22 (25)
Net effect of changes in operating assets and liabilities:
Accounts receivable (582) (70) 200
Regulatory balancing accounts receivable (74) 302 499
Inventories 12 32 32
Accounts payable (80) 217 62
Accrued taxes (62) 36 (162)
Other working capital (128) (6) 8
Other-net 15 127 29
---------------------------
Net cash provided by operating activities 1,768 2,581 3,315
---------------------------
Cash Flows From Investing Activities
Capital expenditures (1,522) (1,230) (945)
Investments in unregulated projects - (70) (157)
Acquisitions - (159) -
Proceeds from sale of assets - - 340
Other-net (117) (120) (123)
---------------------------
Net cash used by investing activities (1,639) (1,579) (885)
---------------------------
Cash Flows From Financing Activities
Net increase (decrease) in short-term borrowings (681) (115) 305
Long-term debt issued 355 1,088 591
Long-term debt matured, redeemed, or repurchased-net (852) (1,472) (1,297)
Proceeds from issuance of rate reduction bonds 2,881 - -
Preferred stock redeemed or repurchased - - (353)
Company obligated mandatorily redeemable preferred securities issued - - 300
Dividends paid (739) (844) (891)
Other-net (14) (249) (488)
---------------------------
Net cash used by financing activities 950 (1,592) (1,833)
---------------------------
Net Change in Cash and Cash Equivalents 1,079 (590) 597
Cash and Cash Equivalents at January 1 144 734 137
---------------------------
Cash and Cash Equivalents at December 31 $ 1,223 $ 144 $ 734
===========================
Supplemental disclosures of cash flow information
Cash paid for:
Interest (net of amounts capitalized) $ 547 $ 598 $ 645
Income taxes 841 640 1,126
</TABLE>
The accompanying Notes to the Consolidated Financial Statements are an integral
part of this statement.
37
<PAGE>
Pacific Gas and Electric Company
Consolidated Balance Sheet
<TABLE>
<CAPTION>
(in millions) At December 31, 1997 1996
- -------------------------------------------------------------------------------------------
<S> <C> <C>
Assets
Current Assets
Cash and cash equivalents $ 80 $ 131
Short-term investments 1,143 13
Accounts receivable
Customers, net 1,204 1,152
Regulatory balancing accounts 658 444
Related parties 459 -
Energy marketing - 387
Inventories and prepayments 523 584
-----------------------
Total current assets 4,067 2,711
Property, Plant, and Equipment
Electric 26,033 25,052
Gas 6,939 8,258
-----------------------
Total property, plant, and equipment (at original cost) 32,972 33,310
Accumulated depreciation and decommissioning (15,558) (14,302)
-----------------------
Net property, plant, and equipment 17,414 19,008
Other Noncurrent Assets
Regulatory assets 2,283 2,518
Nuclear decommissioning funds 1,024 883
Other 359 1,117
-----------------------
Total noncurrent assets 3,666 4,518
-----------------------
Total Assets $ 25,147 $ 26,237
=======================
</TABLE>
38
<PAGE>
Pacific Gas and Electric Company
Consolidated Balance Sheet
<TABLE>
<CAPTION>
(in millions) At December 31, 1997 1996
- --------------------------------------------------------------------------------------------------------
<S> <C> <C>
Liabilities and Equity
Current Liabilities
Short-term borrowings $ - $ 681
Current portion of long-term debt 580 210
Current portion of rate reduction bonds 125 -
Accounts payable
Trade creditors 441 490
Related parties 134 -
Other 578 548
Energy marketing - 388
Accrued taxes 229 310
Deferred income taxes 149 157
Other 373 496
----------------------
Total current liabilities 2,609 3,280
Noncurrent Liabilities
Long-term debt 6,218 7,770
Rate reduction bonds 2,776 -
Deferred income taxes 3,304 3,941
Deferred tax credits 338 380
Other 1,810 1,663
----------------------
Total noncurrent liabilities 14,446 13,754
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, par value $25, authorized 75,000,000 shares
Without mandatory redemption provisions
Nonredeemable-5% to 6%, outstanding 5,784,825 shares 145 145
Redeemable-4.36% to 7.44%, outstanding 10,297,404 shares 257 257
Common stock, no par value, authorized 800,000,000 shares,
403,504,292 shares outstanding, each year 4,582 5,728
Reinvested earnings 2,671 2,636
----------------------
Total stockholders' equity 7,655 8,766
Commitments and Contingencies (Notes 1, 2, 3, 12, and 13) - -
----------------------
Total Liabilities and Stockholders' Equity $25,147 $26,237
======================
</TABLE>
The accompanying Notes to the Consolidated Financial Statements are an integral
part of this statement.
39
<PAGE>
Pacific Gas and Electric Company
Statement of Consolidated Common Stock Equity,
Preferred Stock, and Preferred Securities
<TABLE>
<CAPTION>
Preferred Preferred
Stock Stock
Total Without With
Additional Common Mandatory Mandatory
Common Paid-in Reinvested Stock Redemption Redemption
(dollars in millions) Stock Capital Earnings Equity Provisions Provisions
- ------------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Balance December 31, 1994 $2,151 $ 3,806 $2,677 $ 8,634 $ 733 $137
----------------------------------------------------------------------------
Net income 1,339 1,339
Common stock issued
(5,316,876 shares) 27 113 140
Common stock repurchased
(21,533,977 shares) (108) (195) (298) (601)
Preferred securities issued(1)
(12,000,000 shares) 300
Preferred stock redeemed
(13,237,554 shares) (8) (14) (22) (331)
Cash dividends declared
Preferred stock (56) (56)
Common stock (830) (830)
Other (5) (5)
----------------------------------------------------------------------------
Balance December 31, 1995 2,070 3,716 2,813 8,599 402 437
----------------------------------------------------------------------------
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 8,364 402 437
----------------------------------------------------------------------------
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 $437
============================================================================
</TABLE>
(1) Relates to Company obligated mandatorily redeemable preferred securities of
trust holding solely Utility subordinated debentures.
The accompanying Notes to the Consolidated Financial Statements are an integral
part of this statement.
40
<PAGE>
Notes to Consolidated Financial Statements
Note 1:
Significant Accounting Policies
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. 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 and its wholly owned and
controlled subsidiaries, including the Utility (collectively, the Corporation).
The Utility's consolidated financial statements include its accounts as well as
those of its wholly owned and controlled subsidiaries. PG&E Corporation and the
Utility have identical 1995 and 1996 consolidated financial statements because
they each represent the accounts of the Utility as a 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 1997
presentation.
The preparation of financial statements in conformity with generally
accepted accounting principles (GAAP) 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: The Corporation is a national energy company providing electric
and gas utility services through its regulated subsidiary Pacific Gas and
Electric Company and other energy related services through its unregulated
integrated subsidiaries. The Utility generates electricity and procures,
transmits, and distributes both electricity and natural gas to customers
throughout most of Northern and Central California.
Through its other subsidiaries, the Corporation:
. Owns and operates natural gas pipelines, natural gas storage facilities,
and natural gas processing plants in the Pacific Northwest, Texas, and
Australia.
. Develops, builds, operates, owns, and manages power generation facilities
across the United States.
. Provides customers nationwide with competitively-priced natural gas and
electricity and services to manage and make more efficient their energy
consumption.
. Purchases and resells energy commodities and related financial instruments
in major domestic markets, serving PG&E Corporation's other unregulated
businesses, unaffiliated utilities, and large end-use customers.
Regulation and SFAS No. 71: The Utility is regulated by the CPUC, the FERC,
and the Nuclear Regulatory Commission, 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.
The Corporation and the Utility account for the financial effect of
regulation in accordance with Statement of Financial Accounting Standards (SFAS)
No. 71, "Accounting for the Effects of Certain Types of Regulation." This
statement allows them to record certain regulatory assets and liabilities which
will be included in future rates and would not be recorded under GAAP for
nonregulated entities. In addition, SFAS No. 121, "Accounting for the Impairment
of Long-Lived Assets and for Long-Lived Assets to be Disposed Of," requires the
Corporation and the Utility to write off regulatory assets when they are no
longer probable of recovery. On an ongoing basis, the Corporation and the
Utility review their regulatory assets and liabilities for the continued
applicability of SFAS No. 71 and the effect of SFAS No. 121.
41
<PAGE>
Notes to Consolidated Financial Statements
Net regulatory assets including regulatory balancing accounts receivable and net
regulatory liabilities are comprised of the following:
<TABLE>
<CAPTION>
December 31, 1997
- -------------------------------------------------------------------------------
<S> <C>
(in millions)
Electric industry restructuring transition costs/(1)/ $1,535
Unamortized loss, net of gain, on reacquired debt 296
Regulatory assets for deferred income tax 278
Regulatory balancing accounts (net) 235
Other (net) 174
------
$2,518
======
<CAPTION>
December 31, 1996
- --------------------------------------------------------------------------------
<S> <C>
(in millions)
Regulatory assets for deferred income tax $1,133
Unamortized loss, net of gain, on reacquired debt 377
Diablo Canyon regulatory assets 364
Regulatory balancing accounts (net) 323
Other (net) 555
------
$2,752
======
</TABLE>
/(1)/ See Note 2, "Electric Industry Restructuring," for further discussion.
Revenues and Regulatory Balancing Accounts: Electric and gas utility revenues
recorded by the Utility include amounts for services rendered but unbilled at
the end of the year. The Utility also records revenues for changes in
regulatory balancing accounts established by the CPUC. Specifically, sales
balancing accounts accumulate differences between authorized and actual base
revenues. Energy cost balancing accounts accumulate differences between the
actual cost of gas and electric energy and the revenues designated for recovery
of such costs. Recovery of gas and electric energy costs through energy cost
balancing accounts is subject to reasonableness reviews by the CPUC. The
regulatory balancing accounts accumulate balances until they are refunded to or
received from Utility customers through authorized rate adjustments.
Accounting for Derivative Instruments: The Corporation, through its
subsidiaries, engages in price risk management activities for both non-hedging
and hedging purposes. The Corporation conducts non-hedging activities
principally through its unregulated subsidiary, PG&E Energy Trading (PG&E ET),
using a variety of financial instruments. These instruments include forward
contracts involving the physical delivery of an energy commodity, swaps,
futures, options, and other contractual arrangements. Additionally, the
Corporation engages in hedging activities using futures, options, and swaps to
hedge the impact of market fluctuations on energy commodity prices, interest
rates, and foreign currencies. The Utility manages price risk independently from
the activities in our unregulated businesses.
The Corporation's net gains and losses associated with price risk
management activities during 1997 were immaterial.
Property, Plant, and Equipment: Plant additions and replacements are
capitalized. The capitalized costs include labor, materials, construction
overhead, and an allowance for funds used during construction (AFUDC) or
capitalized interest. 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.
Property, plant, and equipment is depreciated using a straight-line
remaining-life method. The Utility's composite depreciation rates were 5.00,
3.65, and 4.09 percent for the years ended December 31, 1997, 1996, and 1995,
respectively. The increase in the composite rate in 1997 as compared to 1996
and 1995 reflects higher depreciation expense associated with Diablo Canyon
Nuclear Power Plant (Diablo Canyon). See Note 2, Electric Industry
Restructuring.
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.
42
<PAGE>
Inventories: 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. Other inventories include materials and supplies, gas stored
underground, and fuel oil. Materials and supplies and gas stored underground
are valued at average cost. 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. The Utility's short-term
investments consist primarily of money market funds and some commercial paper
with original maturities of three months or less. These investments were made
with the proceeds from the issuance of the rate reduction bonds. See Note 7,
Rate Reduction Bonds.
Note 2:
Electric Industry Restructuring
1997 was the first year of California's transition into a new competitive
electric generation market. In the new competitive market, the Utility's
generation revenues will be determined principally by the market. However,
market-based revenues may not be sufficient to recover (that is, to collect from
customers) certain generation costs resulting from past CPUC decisions. To
recover these uneconomic costs, called "transition costs," and to ensure a
smooth transition to the competitive environment, the Utility, in conjunction
with other California electric utilities, the CPUC, state legislators, consumer
advocates, and others, developed a transition plan, in the form of state
legislation, to position California for the new market environment.
There are three principal elements to this transition plan: (1) an electric
rate freeze and rate reduction, (2) recovery of transition costs, and (3)
economic divestiture of Utility-owned generation facilities. Each one of these
three elements and the impact of the transition plan on the application of SFAS
No. 71 are discussed below. The transition plan will remain in effect until the
earlier of March 31, 2002, or when the Utility recovers its authorized
transition costs as determined by the CPUC. This period is referred to as 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.
Rate Freeze and Rate Reduction
During 1997, electric rates for the Utility's customers were held at 1996
levels. Effective January 1, 1998, the Utility reduced electric rates for its
residential and small commercial customers by 10 percent and will hold their
rates at that level. The rate freeze will continue until the end of the
transition period.
To pay for the 10 percent rate reduction, the Utility financed $2.9 billion
of its transition costs with rate reduction bonds. See Note 7, Rate Reduction
Bonds.
Transition Cost Recovery
Costs eligible for transition cost recovery include: (1) above-market sunk 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) and future costs, such as costs related to plant removal,
(2) costs associated with the Utility's long-term contracts to purchase power at
prices from Qualifying Facilities (QF) 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 that are disallowed
by the CPUC for collection from customers will be written off.
Sunk costs associated with Utility-owned generation facilities are
currently included in the Utility customers' rates. Above-market sunk costs are
those whose values recorded on the Utility's balance sheet (book value) are
expected to be in excess of their market values. Conversely, below-market sunk
costs are those whose market values are expected to be in excess of their book
values. In general, 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.
The above-market portion of sunk costs is eligible for recovery as a transition
cost. The below-market portion of sunk costs will reduce other unrecovered
43
<PAGE>
Notes to Consolidated Financial Statements
transition costs. A valuation of Utility-owned generation facilities where the
market value exceeds the book value could result in a material charge if the
Utility retains the facility. This is because any excess of market value over
book value would be used to reduce other transition costs without being
collected in rates.
The Utility will not be able to determine the exact amount of sunk costs
that will be recoverable as transition costs until a market valuation process
(appraisal, spin, or sale) is completed for each of the Utility's generation
facilities. The first of these valuations occurred in 1997 when the Utility
agreed to sell three of its electric plants for $501 million. This sale is
expected to close during 1998 (see Generation Divestiture below). The rest of
the valuation process will be completed by December 31, 2001. At December 31,
1997, the Utility's net investment in Diablo Canyon and non-nuclear generation
facilities was $3.7 billion and $2.7 billion, respectively, including the plants
to be sold in 1998.
The Utility has agreed to purchase electric power from QFs and other power
suppliers under long-term contracts expiring on various dates through 2028. Over
the life of these contracts, the Utility estimates that it will purchase
approximately 360 million megawatt-hours (MWh) at an average aggregate price of
6.3 cents per kilowatt-hour (kWh). To the extent that this price is 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.
In addition, as of December 31, 1997, the Utility has accumulated
approximately $1.5 billion of generation-related net regulatory assets. The net
regulatory assets are eligible for recovery as transition costs.
The CPUC has the ultimate authority to determine which costs are eligible
to be recovered as transition costs. Reviews by the CPUC to determine the
reasonableness of transition costs are being conducted and will continue to be
conducted throughout the transition period.
Under the transition plan, most transition costs must be recovered by March
31, 2002. This recovery period is significantly shorter than the recovery
period of the related assets prior to restructuring. Recovery of transition
costs during this shorter period is referred to as accelerated recovery. The
CPUC believes that acceleration reduces risks associated with recovery of all
utility generation assets, including Diablo Canyon and hydroelectric facilities.
As a result, in accordance with the transition plan, the Utility is receiving a
reduced return for all of its generation facilities. In 1997, the reduced
return was 7.13 percent as compared to an authorized return of 9.45 percent.
The reduced return on non-nuclear generation assets, effective July 28, 1997,
resulted in a $24 million decrease in earnings ($.06 per share) in 1997 and will
have a continued impact throughout the transition period.
Although most transition costs must be recovered by March 31, 2002, certain
transition costs can be included in customers' electric rates after the
transition period. These costs include: (1) certain employee-related transition
costs, (2) above-market payments under existing QF and power- purchase
contracts, 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
the facility. During the rate freeze, this charge will not increase 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, as directed by the CPUC, the
Utility has separated, or unbundled, its previously authorized cost-of-service
electric revenues into separate categories. Unbundling enables the Utility to
allocate revenue provided by frozen electric rates into transmission,
distribution, public purpose programs, and generation based upon their
respective cost of service. Revenues provided by frozen rates will also be used
to recover other authorized Utility costs, including nuclear decommissioning,
rate reduction bond debt service, and transition cost recovery.
The portion of the unbundled revenue to be provided for transition cost
recovery is based upon mechanisms approved by the CPUC. Revenue provided for
recovery of most non-nuclear transition costs is based upon their acceleration
44
<PAGE>
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 acceleration of recovery of the
Utility's investment in Diablo Canyon from a period ending in 2016 to a five-
year period ending December 31, 2001.
Based on the Utility's evaluation of the transition plan and state
legislation and CPUC decisions related to the transition plan, the Utility is
depreciating Diablo Canyon over a five-year period ending December 31, 2001.
The change in depreciable life increased Diablo Canyon's depreciation expense
for 1997, as compared to 1996, by $583 million. In addition, most generation-
related regulatory assets are being amortized on a straight-line basis, in
accordance with their recovery under the transition plan, beginning on January
1, 1998. Further, upon valuation of generation facilities, any losses will be
amortized over the remaining transition period as a transition cost. Any gains
will be recognized and used to reduce other transition costs at the time of
valuation.
Any difference between (1) revenues provided for transition cost recovery
and (2) the costs associated with accelerated recovery, including the
depreciation of Diablo Canyon and the amortization of regulatory assets, is
being tracked. If the revenues exceed the accelerated costs, certain transition
costs may be further accelerated until all transition costs are recovered or
March 31, 2002, whichever is earlier. If the accelerated costs exceed the
revenues, the costs will be deferred. At the end of the transition period, any
overcollection of these amounts will be returned to customers.
The Utility's ability to recover its transition costs during the transition
period will be dependent on several factors. These factors include: (1) the
continued application of the regulatory framework established by the CPUC and
state legislation, (2) the amount of transition costs approved by the CPUC, (3)
the market value of 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 its
current evaluation of these factors, the Utility believes that it will recover
its transition costs. Also, the Utility believes that its regulatory assets and
generation facilities are not impaired. 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.
During 1997, the difference between billed revenues and authorized revenues
was used to recover transition costs, including most of the accelerated Diablo
Canyon sunk costs.
Generation Divestiture
In 1997, California utilities produced a significant portion of the state's
electric generation needs. In a competitive market, the CPUC is concerned that
this level of generation may give existing utilities undue influence on the
market price for power. As part of the transition plan, the Utility has agreed
to sell a significant portion of its generation facilities to alleviate this
concern.
In 1997, the Utility agreed to sell three fossil-fueled electric generating
plants to Duke Energy through an auction process. The aggregate bid accepted
for these plants was $501 million. These three plants have a combined book
value at December 31, 1997, of approximately $370 million and a combined
capacity of 2,645 megawatts (MW). The three power plants were Morro Bay, Moss
Landing, and Oakland.
The sales have been approved by the CPUC. However, they are still subject
to approval of the transfer of various permits and licenses. Additionally, the
Utility will retain liability for required environmental remediation of any pre-
closing soil or groundwater contamination at these plants. The Utility does not
expect any material adverse impact on its financial position or results of
operations as a result of retaining such environmental remediation liability.
The Utility expects the sale of these three plants to close in 1998.
The Utility plans to conduct another auction of its four remaining Utility-
owned fossil-fueled plants and its geothermal facilities in the first half of
1998. These additional plants have a combined generating capacity of 4,718 MW
and a combined book value at December 31, 1997, of approximately $790 million.
Together the eight power plants represent 98 percent of the Utility's
fossil-fueled generating capacity and all of the
45
<PAGE>
Notes to Consolidated Financial Statements
Utility's geothermal generating capacity. The eight plants generate
approximately 22 percent of the Utility's total electric sales. The Utility is
currently evaluating its options related to its remaining generation facilities
and may decide not to retain its economic investment in those facilities.
During the transition period, the proceeds from the sale of the plants will be
used to offset transition costs associated with other Utility electric
generation facilities. Therefore, the Corporation does not expect any material
adverse impact on its or the Utility's financial position or results of
operations from any of these divestitures.
The Transition Plan and SFAS No. 71
The Utility accounts for the financial effect of regulation in accordance with
SFAS No. 71. This statement allows the Utility to record certain regulatory
assets and liabilities which would be included in future rates and would not be
recorded under generally accepted accounting principles for nonregulated
entities. In addition, SFAS No. 121, "Accounting for the Impairment of Long-
Lived Assets and for Long-Lived Assets to be Disposed Of," requires the Utility
to write off regulatory assets when they are no longer probable of recovery.
In 1997, the Emerging Issues Task Force (EITF) of the Financial Accounting
Standards Board (FASB) reached a consensus on Issue No. 97-4, "Deregulation of
the Pricing of Electricity - Issues Related to the Application of FASB
Statements No. 71, Accounting for the Effects of Certain Types of Regulation,
and No. 101, Regulated Enterprises - Accounting for the Discontinuation of
Application of FASB Statement No. 71" (EITF 97-4), which provided authoritative
guidance on the applicability of SFAS No. 71 during the transition period. The
EITF requires the Utility to discontinue the application of SFAS No. 71 for the
generation portion of its operations as of July 24, 1997, the effective date of
EITF 97-4. The discontinuation of application of SFAS No. 71 did not have a
material effect on the Utility's financial statements because EITF 97-4 requires
that regulatory assets and liabilities (both those in existence today and those
created under the terms of the transition plan) be allocated to the portion of
the business from which the source of the regulated cash flows is derived. The
Utility has accumulated approximately $1.5 billion of generation-related
regulatory assets which are eligible for collection from distribution customers
and which the Utility considers probable of recovery. Substantially all
regulatory assets are reflected on the Utility's and PG&E Corporation's balance
sheets in regulatory balancing accounts and regulatory assets. In addition,
above-market generation-related sunk costs, which will be determined as part of
the market valuation process discussed above, and above-market QF costs will be
eligible for collection from distribution customers.
Given the current regulatory environment, the Utility's electric
transmission business and most areas of the distribution business are expected
to remain regulated, and as a result, the Utility will continue to apply the
provisions of SFAS No. 71. However, in May 1997, the CPUC issued decisions that
allow customers to choose their electricity provider beginning January 1, 1998.
The decisions also allow the electricity provider to provide their customers
with billing and metering services, and indicate that electricity providers may
be allowed to provide other distribution services (such as customer inquiries
and uncollectibles) in the future. Any discontinuance of SFAS No. 71 for these
portions of the Utility's electric distribution business is not expected to have
a material adverse impact on the Utility's or the Corporation's financial
position or results of operations.
Note 3:
Natural Gas Matters
Gas Accord: In 1998, the Utility will implement a multi-party settlement, called
the Gas Accord (Accord), that will continue to restructure the gas industry in
California. The Accord, which received CPUC approval in 1997, has four
principal elements. First, the Accord separates the rates for gas transmission
services from gas distribution services. Second, the Accord increases the
opportunity for residential and smaller commercial (core) customers to choose
the commodity gas supplier of their choice. Third, the Accord establishes a new
way to measure the reasonableness of the Utility's gas purchases based upon
market indices. Fourth,
46
<PAGE>
the Accord settled numerous regulatory issues between the Utility and other
parties. The resolution of these issues did not have a material adverse impact
on the Utility's or the Corporation's financial position or results of
operations.
The Accord also establishes gas transmission rates for the period from
March 1998 through December 2002 for all customers and eliminates regulatory
protection for variations in sales volumes for transmission revenues from
industrial and larger commercial (noncore) customers. As a result, the Utility
will be at risk for variations between actual and forecasted noncore
transmission throughput volumes. However, these variations are not expected to
have a material adverse impact on the Utility's or the Corporation's financial
position or results of operations.
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 total amounts the Utility paid under these contracts
were approximately $255, $269, and $245 million in 1997, 1996, and 1995,
respectively. These amounts include payments made by the Utility to PG&E Gas
Transmission (PG&E GT) of approximately $49, $57, and $70 million in 1997, 1996,
and 1995, respectively. These payments are eliminated in the consolidated
financial statements of the Corporation. Also, a contract for Southwest
pipeline capacity expired in December 1997. Total payments associated with this
contract were approximately $149 million in 1997.
The following table summarizes the Utility's capacity on various pipelines
and the related annual payments for capacity at December 31, 1997:
<TABLE>
<CAPTION>
Total
Firm Annual
Capacity Demand
Held Charges Contract
Pipeline Company (MMcf/d) (in millions) Expiration
============================================================================
<S> <C> <C> <C>
PG&E GT 600 $44 Oct. 2005
Transwestern 200 29 Mar. 2007
NOVA 600 20 Oct. 2001
ANG 600 13 Oct. 2005
</TABLE>
As a result of regulatory changes, the Utility no longer procures gas for
most of its noncore customers, resulting in a decrease in the Utility's need for
capacity on these pipelines. Despite these changes, the Utility continues to
procure gas for substantially all of its 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.
Note 4:
Acquisitions and Sales
In December 1996, the Corporation acquired Energy Source, a wholesale commodity
marketing company for approximately $23 million. The acquisition was accounted
for as a purchase.
In January 1997, the Corporation acquired Teco Pipeline Company (Teco) for
approximately $378 million, consisting of $317 million of PG&E Corporation
common stock and the purchase of a $61 million note. Teco has investments in
natural gas pipelines and gas gathering and processing facilities located in
Texas. Teco also owns a gas marketing company in Houston. The acquisition was
accounted for as a purchase.
In April 1997, PG&E Enterprises (Enterprises), a wholly owned subsidiary of
PG&E Corporation, sold its interest in International Generating Company, Ltd.
(InterGen), a joint venture between Enterprises and Bechtel Enterprises, Inc.
(Bechtel), and all of its related project interests, to Bechtel. The sale has
resulted in an after-tax gain of approximately $120 million.
On July 31, 1997, the Corporation completed its acquisition of Valero
Energy Corporation's (Valero) natural gas business located in Texas. Valero
also owns a gas marketing business. PG&E Corporation issued approximately 31
million shares of its common stock to acquire Valero along with the assumption
of approximately $780 million in long-term debt, equating to a purchase price of
approximately $1.5 billion. The acquisition was accounted for as a purchase.
In August 1997, the Corporation announced that its subsidiary, U.S.
Generating Company (USGen), had agreed
47
<PAGE>
Notes to Consolidated Financial Statements
to buy a portfolio of electric generating assets and power supply contracts from
the New England Electric System (NEES) for $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, financing requirements are
expected to total approximately $1.75 billion, of which approximately $1 billion
will be funded through a combination of project level debt as well as debt of
USGen. In addition, $750 million of equity will be contributed over two years
and will be financed initially using short-term debt of PG&E Corporation. The
assets to be acquired contain a balance of hydro, coal, oil, and natural gas
generation facilities. We expect the acquisition to be completed in the second
half of 1998. The acquisition is subject to regulatory approval, among other
conditions.
In September 1997, the Corporation completed an acquisition of two
partnerships previously jointly owned by it and Bechtel. In December 1997, the
Corporation closed the acquisition of a third such partnership. The Corporation
is now the sole owner of USGen, an independent power developer and manager, U.S.
Operating Services Company, USGen's operations and maintenance affiliate, and
USGen's power marketing affiliate, USGen Power Services, L.P. Additionally, the
Corporation has acquired all or part of Bechtel's interest in several power
projects that are affiliated with USGen.
In connection with the acquisitions completed in 1996 and 1997, discussed
above, the Corporation recorded approximately $432 million of goodwill, subject
to final purchase price adjustments. These amounts will be amortized on a
straight-line basis over a 30 to 40 year period.
Note 5:
Common and Preferred Stock and
Utility Obligated Mandatorily Redeemable
Preferred Securities of Trust Holding Solely
Utility Subordinated Debentures
Common Stock:
PG&E Corporation:
The Corporation has authorized 800 million shares of no-par common stock of
which 418 million shares were issued and outstanding as of December 31, 1997.
Prior to the formation of the Corporation, the Utility held $5 par value common
stock. The stock was converted to PG&E Corporation common stock (no par value)
at the formation of the holding company.
As of December 31, 1997, the Board of Directors has authorized the
repurchase of up to $1.7 billion of common stock on the open market or in
negotiated transactions. In January 1998, the Corporation repurchased 37
million shares of its common stock at $30.3125 per share. In connection with
this transaction, the Corporation has entered into a forward contract with an
investment institution. The 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 the Corporation through purchases on
the open market or through privately negotiated transactions. The contract is
anticipated to expire by December 31, 1998.
Utility:
The CPUC set a number of conditions when PG&E Corporation was formed as a
holding company. One of these conditions requires the Utility to maintain, on
average, its CPUC-authorized capital structure, potentially limiting the amount
of dividends the Utility may pay PG&E Corporation. At December 31, 1997, the
Utility was in compliance with its CPUC-authorized capital structure. The
Corporation believes that the Utility will continue to meet this condition in
the future without affecting the Corporation's ability to pay common stock
dividends to common shareholders.
Preferred Stock: Holders of the Utility's nonredeemable preferred stock at
December 31, 1997, have rights to annual dividends per share ranging from $1.25
to $1.50.
The Utility's redeemable preferred stock without mandatory redemption
provisions 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, 1997, range from $1.09 to $1.86 and from $25.00
to $27.25, respectively. In January 1998, the Utility redeemed all of its
48
<PAGE>
7.44% redeemable preferred stock, of which $65 million was outstanding at
December 31, 1997, at a redemption price of $25 per share.
The Utility's redeemable preferred stock with mandatory redemption
provisions consists of 3 million shares of the 6.57% and 2.5 million shares of
the 6.30% series at December 31, 1997. 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. The estimated fair value of the Utility's preferred stock with
mandatory redemption provisions at December 31, 1997, and 1996, was
approximately $146 million and $135 million, respectively, based on quoted
market prices.
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.
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 approximately $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 approximately $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. The subordinated debentures may be
redeemed at the Utility's option beginning in 2000 at par 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, 1997, and 1996, was approximately
$304 million and $291 million, respectively, based on quoted market prices.
Note 6:
Long-Term Debt
Long-term debt at December 31, 1997, and 1996, consisted of the following:
<TABLE>
<CAPTION>
December 31, 1997 1996
==========================================================================
(in millions)
<S> <C> <C>
Utility long-term debt
First and refunding mortgage bonds
Maturity Interest rates
1998-2001 4.63% to 8.75% $ 861 $ 880
2002-2006 5.875% to 7.875% 1,354 1,392
2007-2019 6.35% to 8.875% 160 520
2020-2026 5.85% to 8.80% 2,498 2,628
---------------------
Principal amounts outstanding 4,873 5,420
Unamortized discount net of premium (42) (50)
---------------------
Total mortgage bonds 4,831 5,370
Pollution control loan agreements,
variable rates, due 2016-2026 1,348 988
Unsecured medium-term notes,
4.93% to 9.9%, due 1998-2014 587 829
Debentures, 12%, due 2000 - 58
Other long-term debt 32 31
---------------------
Total Utility long-term debt 6,798 7,276
Long-term debt of unregulated
business operations 1,520 704
---------------------
Total long-term debt 8,318 7,980
Current portion of long-term debt 659 210
---------------------
Long-term debt, net of current portion $7,659 $7,770
=====================
</TABLE>
49
<PAGE>
Notes to Consolidated Financial Statements
Utility:
Mortgage Bonds:
All real properties and substantially all personal properties of the Utility are
subject to the lien of the mortgage bonds, and the Utility is required to make
semi-annual sinking fund payments for the retirement of the bonds. Additional
mortgage bonds may be issued subject to CPUC approval, up to a maximum total
amount outstanding of $10 billion.
The Utility redeemed or repurchased $167 million and $182 million of
mortgage bonds in 1997 and 1996, respectively, with interest rates ranging from
5.375 percent to 8.875 percent.
Included in the total of outstanding mortgage bonds at December 31, 1997,
and 1996, are $705 million of mortgage bonds held in trust for the California
Pollution Control Financing Authority (CPCFA) with interest rates ranging from
5.85 percent to 8.875 percent and maturity dates ranging from 2007 to 2026. In
addition to these mortgage bonds, the Utility holds long-term loan agreements
with the CPCFA as described below.
Pollution Control Loan Agreements:
Loan agreements from the CPCFA totaled $1,348 million and $988 million,
respectively, at December 31, 1997, and 1996. Interest rates on the loans vary
with average annual interest rates for 1997 ranging from 3.01 percent to 3.92
percent. These loans are subject to redemption by the holder under certain
circumstances. These loans are secured by irrevocable letters of credit which
mature as early as 2000.
Unregulated Business Operations: Long-term debt of unregulated business
operations, as of December 31, 1997, consisted primarily of first mortgage bonds
of $409 million, medium-term and senior notes of $404 million, unsecured notes
and debentures of $397 million, and other long-term debt of $310 million. The
fixed interest rates on these obligations range from 6.33 percent to 9.25
percent, with maturities ranging from 1998 to 2025.
Outstanding long-term debt as of December 31, 1996, consisted primarily of
$470 million of unsecured notes and debentures, and other long-term debt of $234
millon.
Repayment Schedule: At December 31, 1997, the Corporation's combined aggregate
amounts of maturing long-term debt and sinking fund requirements for the years
1998 through 2002, are $659, $294, $460, $330, and $515 million, respectively.
The Utility's share of those sinking fund requirements is $601, $217, $223,
$233, and $389 million, respectively.
Fair Value: The estimated fair value of the Corporation's total long-term debt
at December 31, 1997, and 1996, was approximately $8.3 billion and $8.0 billion,
respectively. The estimated fair value of the Utility's total long-term debt at
December 31, 1997, and 1996, was approximately $7.0 billion and $7.3 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 7:
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.
The rate reduction bonds have maturities ranging from ten months to ten
years, and bear interest at rates ranging from 5.94 percent to 6.48 percent.
The bonds are secured solely by the transition property and there is no recourse
to the Utility or the Corporation.
At December 31, 1997, the combined aggregate amounts of maturing rate
reduction bonds, for the years 1998
50
<PAGE>
through 2002, are $125, $265, $280, $300, and $290 million, respectively.
The estimated fair value of the rate reduction bonds was approximately $2.9
billion at December 31, 1997. 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 the Corporation, and
the transition property is legally not an asset of the Utility or the
Corporation.
Note 8:
Short-Term Borrowings
In January 1997, the Corporation established a $500 million revolving credit
facility, which expires in 2002. In August 1997, the Corporation entered into
an additional $500 million temporary credit facility which expires in 1998.
Both of these credit facilities are to be used for general corporate purposes.
There were no borrowings under these credit facilities at December 31, 1997.
In addition, 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 mutual agreement between the Utility and the banks. There
were no borrowings under this credit facility in 1997 or 1996.
At December 31, 1997, the Corporation had outstanding $103 million of
short-term bank borrowings at a 6.9 percent weighted average interest rate. In
addition to borrowing from banks on a short-term basis, the Corporation and
certain of its subsidiaries sell commercial paper, having a maturity of one to
ninety days, to provide financing for various corporate purposes. The carrying
amount of short-term borrowings approximates fair value. At maturity,
commercial paper can be either reissued or replaced with borrowings from the
revolving credit facility. At December 31, 1997, the Corporation had no
commercial paper outstanding.
At December 31, 1996, the Utility had outstanding $681 million of
commercial paper at a 5.83 percent weighted average interest rate. At December
31, 1997, the Utility required no short-term borrowings due to the receipt of
the rate reduction bond proceeds.
Note 9:
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 radio activity 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 approximately $1.4 billion in 1997 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, 1997, 1996, and 1995, nuclear
decommissioning costs recovered in rates were $33, $33, and $54 million,
respectively. Based on the 1997 site study, the amount approved to be recovered
in rates in 1998 and annually, until the commencement of decommissioning, is $33
million. This amount will be reviewed in future rate proceedings.
At December 31, 1997, the total nuclear decommissioning obligation accrued
was $1.0 billion and was included in the balance sheet classification of
Accumulated Depreciation and Decommissioning. Decommissioning costs recovered
in rates are placed in external trust funds. The earnings on the external
trusts accumulate in the fund balance and are included in the
51
<PAGE>
Notes to Consolidated Financial Statements
balance sheet classification of Other Noncurrent Assets. 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 of
these nuclear decommissioning funds:
<TABLE>
<CAPTION>
Year ended December 31, Maturity Dates 1997 1996
===============================================================================
(in millions)
<S> <C> <C> <C>
Amortized cost
U.S. government and
agency issues 1998-2027 $ 422 $375
Equity securities - 257 281
Municipal bonds and other 1998-2021 70 33
Gross unrealized holding gains 287 199
Gross unrealized holding losses (12) (5)
-------------------
Fair value $1,024 $883
===================
</TABLE>
The proceeds received during 1997 and 1996 from sales of securities were
approximately $1.4 billion and $1.5 billion in each year, respectively. During
1997 and 1996, the gross realized gains on sales of securities held as
available-for-sale were $40 million and $14 million, respectively, and the gross
realized losses on sales of securities held as available-for-sale were $24
million and $20 million, 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 2012. 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.
Note 10:
Employee Benefit Plans
Retirement Plans: Several of the Corporation's subsidiaries provide
noncontributory defined benefit pension plans for their employees. The
Utility's plan represents substantially all of the plan assets and the projected
benefit obligation. All descriptions and assumptions are based on the Utility's
plan which covers the largest number of employees. The schedules below
aggregate all of the Corporation's plans.
Pension benefits are based on an employee's years of service and base
salary. The Corporation's policy is to fund each year not more than the maximum
amount deductible for federal income tax purposes and not less than the minimum
legal funding requirement.
The following schedule reconciles the plans' funded status to the prepaid
pension cost or accrued pension liability recorded on the Consolidated Balance
Sheet:
<TABLE>
<CAPTION>
December 31, 1997 1996
================================================================================
(in millions)
<S> <C> <C>
Actuarial present value of benefit obligations
Vested benefits $(3,659) $(3,486)
Nonvested benefits (198) (178)
----------------------
Accumulated benefit obligation (3,857) (3,664)
Effect of projected future compensation
increases (561) (529)
----------------------
Projected benefit obligation (4,418) (4,193)
Plan assets at market value 6,419 5,526
----------------------
Plan assets in excess of projected benefit
obligation 2,001 1,333
Unrecognized prior service cost 121 83
Unrecognized net gain (2,135) (1,559)
Unrecognized net transition obligation 74 86
----------------------
Prepaid pension cost (accrued pension liability) $ 61 $ (57)
======================
</TABLE>
The Utility's share of the plan assets in excess of projected benefit
obligation for 1997 and 1996 was $2.0 and $1.3 billion, respectively. The
Utility's share of the prepaid pension cost for 1997 was $75 million and the
accrued pension liability for 1996 was $53 million.
Plan assets consist primarily of common stocks and fixed income securities.
Unrecognized prior service costs and net gains are amortized on a straight-line
basis over the
52
<PAGE>
average remaining service period of active plan participants. The transition
obligation is being amortized over 17.5 years from 1987.
Using the projected unit credit actuarial cost method, net pension income
consisted of the following components:
<TABLE>
<CAPTION>
Year ended December 31, 1997 1996 1995
================================================================================
(in millions)
<S> <C> <C> <C>
Service cost for benefits earned $ (101) $(100) $ (83)
Interest cost (313) (302) (291)
Actual return on plan assets 1,139 811 968
Net amortization and deferral (598) (353) (586)
-----------------------------------
Net pension income $ 127 $ 56 $ 8
===================================
</TABLE>
The Utility's share of the plan's net pension income for 1997, 1996, and
1995 was $128, $57, and $8 million, respectively.
Net pension income or cost is calculated using expected return on plan
assets. 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 pension income or cost. In 1997, 1996, and 1995, 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 or cost determined for accounting
purposes and that for rate making, which is based on a funding approach.
The following actuarial assumptions were used in determining the plans'
funded status and net pension income. Year-end assumptions are used to compute
funded status, while prior year-end assumptions are used to compute net pension
income.
<TABLE>
<CAPTION>
December 31, 1997 1996 1995
================================================================================
(in millions)
<S> <C> <C> <C>
Discount rate 7.5% 7.5% 7.25%
Rate of future compensation
increases 5% 5% 5%
Expected long-term rate of return
on plan assets 9% 9% 9%
</TABLE>
Postretirement Benefits Other Than Pensions: Several of the Corporation's
subsidiaries provide contributory defined benefit medical plans for retired
employees and their eligible dependents and noncontributory defined benefit life
insurance plans for retired employees. The Utility's plan represents
substantially all of the plan assets and the total accumulated postretirement
benefit obligation. All descriptions and assumptions are based on the Utility's
plan which covers the largest number of employees. The schedules below
aggregate all of the Corporation's plans.
Most employees retiring at or after age 55 are eligible for these benefits.
The medical benefits are provided through plans administered by an insurance
carrier or a health maintenance organization. Certain retirees are responsible
for a portion of the costs for these benefits.
The CPUC has authorized the Utility to recover these benefits 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 appropriate trusts. The
policy is to fund each year an amount consistent with the basis for rate
recovery.
The following schedule reconciles the medical and life insurance plans'
funded status to the postretirement benefit liability recorded on the
Consolidated Balance Sheet:
<TABLE>
<CAPTION>
December 31, 1997 1996
==========================================================================
(in millions)
<S> <C> <C>
Accumulated postretirement benefit obligation
Retirees $(400) $(445)
Other fully eligible participants (140) (132)
Other active plan participants (367) (344)
--------------------
Total accumulated postretirement benefit
obligation (907) (921)
Plan assets at market value 823 666
--------------------
Accumulated postretirement benefit obligation
in excess of plan assets (84) (255)
Unrecognized prior service cost 20 22
Unrecognized net gain (375) (227)
Unrecognized transition obligation 393 420
--------------------
Accrued postretirement benefit liability $ (46) $ (40)
====================
</TABLE>
The Utility's share of the accumulated postretirement benefit obligation in
excess of plan assets for 1997 and 1996 was $64 and $249 million, respectively.
The Utility's share of the accrued postretirement benefit liability for 1997 and
1996 was $29 and $38 million, respectively.
Plan assets consist primarily of common stocks and
53
<PAGE>
Notes to Consolidated Financial Statements
fixed income securities. Unrecognized prior service costs are amortized on a
straight-line basis over the average remaining years of service to full
eligibility of active plan participants. Unrecognized net gains are amortized
on a straight-line basis over the average remaining years of service of active
plan participants. The transition obligation is being amortized over 20 years
from 1993.
Using the projected unit credit actuarial cost method, net postretirement
medical and life insurance cost consisted of the following components:
<TABLE>
<CAPTION>
Year ended December 31, 1997 1996 1995
================================================================================
(in millions)
<S> <C> <C> <C>
Service cost for benefits earned $(21) $(22) $(17)
Interest cost (65) (66) (65)
Actual return on plan assets 144 91 109
Amortization of unrecognized prior
service cost (2) (2) (2)
Amortization of transition obligation (25) (26) (26)
Net amortization and deferral (71) (38) (70)
----------------------------------
Net postretirement benefit income
(cost) $(40) $(63) $(71)
==================================
</TABLE>
The Utility's share of the plan's net postretirement benefit cost for 1997,
1996, and 1995 was $38, $61, and $71 million, respectively.
The discount rate, rate of future compensation increases, and expected
long-term rate of return on plan assets used in accounting for the
postretirement benefit plans for 1997, 1996, and 1995 were the same as those
used for the pension plan.
The assumed health care cost trend rate for 1998 is approximately 9.5
percent, grading down to an ultimate rate in 2005 of approximately 6.0 percent.
The effect of a one-percentage-point increase in the assumed health care cost
trend rate for each future year would increase the accumulated postretirement
benefit obligation at December 31, 1997, by approximately $76 million and the
1997 aggregate service and interest costs by approximately $8 million.
Net postretirement benefit cost is calculated using expected return on plan
assets. The difference between actual and expected return on plan assets is
included in net amortization and deferral and is considered in the deter-
mination of future postretirement benefit cost. In 1997, 1996, and 1995, actual
return on plan assets exceeded expected return.
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, 1997, 24.5 million shares of common stock have
been authorized for award under the program. At December 31, 1997, stock
options on 6,181,819 shares, granted at option prices ranging from $16.75 to
$34.25, were outstanding, of which 1,902,545 were exercisable. In 1997,
3,048,400 options were granted at an average option price of $22.55.
Outstanding stock options expire ten years and one day after the date of
grant and become exercisable on a cumulative basis at one-third each year
commencing two years from the date of grant. In 1997, 1996, and 1995, stock
options on 232,815, 72,960, and 235,568 shares, respectively, were exercised at
option prices ranging from $16.75 to $33.13.
Effective January 1, 1996, the Corporation adopted SFAS No. 123,
"Accounting for Stock-Based Compensation." SFAS No. 123 requires the Corporation
to disclose stock option costs based on the fair value of options granted. For
the years ended December 31, 1997 and 1996, the fair value of options granted
was not material to the Corporation's results of operations or earnings per
share.
Note 11:
Income Taxes
The Corporation files a consolidated federal income tax return that
includes domestic subsidiaries in which its ownership is 80 percent or more.
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.
54
<PAGE>
The significant components of income tax expense were:
<TABLE>
<CAPTION>
PG&E Corporation Utility
Year ended December 31, 1997 1996 1995 1997 1996 1995
==================================================================================
(in millions)
<S> <C> <C> <C> <C> <C> <C>
Current $ 707 $ 705 $1,011 $ 791 $ 705 $1,011
Deferred (119) (132) (98) (142) (132) (98)
Tax credits-net (40) (18) (18) (40) (18) (18)
--------------------------------------------------------
Total income tax expense $ 548 $ 555 $ 895 $ 609 $ 555 $ 895
========================================================
</TABLE>
The significant components of net deferred income tax liabilities were:
<TABLE>
<CAPTION>
PG&E Corporation Utility
December 31, 1997 1996 1997 1996
=====================================================================================================
(in millions)
<S> <C> <C> <C> <C>
Deferred income tax assets $1,108 $1,308 $ 962 $1,308
Deferred income tax liabilities:
Regulatory balancing accounts 311 294 311 294
Plant in service 3,621 3,624 3,144 3,624
Income tax regulatory asset 430 454 420 454
Other 924 1,034 540 1,034
---------------------------------------------------
Total deferred income tax liabilities 5,286 5,406 4,415 5,406
---------------------------------------------------
Total net deferred income taxes $4,178 $4,098 $3,453 $4,098
===================================================
Classification of net deferred income taxes:
Included in current liabilities $ 149 $ 157 $ 149 $ 157
Included in noncurrent liabilities 4,029 3,941 3,304 3,941
---------------------------------------------------
Total net deferred income taxes $4,178 $4,098 $3,453 $4,098
===================================================
</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, 1997 1996 1995 1997 1996 1995
===============================================================================================================================
<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) 5.3 3.8 5.0 4.6 3.7 4.8
Effect of regulatory treatment of depreciation differences 8.1 6.0 3.2 7.5 5.9 3.2
Tax credits-net (3.2) (1.4) (0.8) (2.9) (1.4) (0.8)
Effect of lower taxes on foreign earnings (2.2) - - - - -
Other-net 0.3 - (1.0) - (0.8) (2.1)
------------------------------------------------------
Effective tax rate 43.3% 43.4% 41.4% 44.2% 42.4% 40.1%
======================================================
</TABLE>
55
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 12:
Commitments
Letters of Credit: The Utility uses approximately $335 million in standby
letters of credit to secure future workers' compensation liabilities.
Restructuring Trust Guarantees: Tax-exempt trusts have been established to
oversee the development of the operating framework for the competitive
generation market (See Note 2, Electric Industry Restructuring). 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.
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 1998 through 2001. Total capacity payments are
expected to remain at current levels during this period. Deliveries from these
power producers account for approximately 18 percent of the Utility's 1997
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 on the accompanying balance sheet. At
December 31, 1997, the total discounted future payments remaining under early
termination or suspension contracts is $53 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 provider's retention of the FERC's authorization) and
variable payments for operation and maintenance costs incurred by the providers.
These contracts expire on various dates from 2004 to 2031. These costs are also
recoverable in rates. At December 31, 1997, the undiscounted future minimum
payments under these contracts are $34 million for each of the years 1998
through 2002 and a total of $349 million for periods thereafter. Irrigation
district and water agency deliveries in the aggregate account for approximately
four percent of the Utility's 1997 electric 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, 1997 1996 1995
- ------------------------------------------------------------------------------------------------
(in millions)
<S> <C> <C> <C>
Kilowatt-hours received 24,389 26,056 26,468
Energy payments $ 1,157 $ 1,136 $ 1,140
Capacity payments $ 538 $ 521 $ 484
Irrigation district and water
agency payments $ 56 $ 52 $ 50
</TABLE>
Note 13:
Contingencies
Nuclear Insurance: The Utility has insurance coverage for property damage and
business interruption losses as a member of Nuclear Electric Insurance Limited
(NEIL). Under this policy, if a nuclear generating facility of a member utility
suffers a loss due to a prolonged accidental outage, the Utility may be subject
to maximum assessments of $23 million (property damage) and $7 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. An additional $8.7 billion
of coverage is provided by secondary financial protection which provides for
loss sharing among utilities owning nuclear generating facilities if a costly
incident occurs. If a nuclear incident results in
56
<PAGE>
claims in excess of $200 million, the Utility may be assessed up to $159 million
per incident, with payments in each year limited to a maximum of $20 million per
incident.
Environmental Remediation: The Corporation may be required to pay for
environmental remediation at sites where the Corporation 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
materials which may be determined to present a significant threat to human
health or the environment because of an actual or potential release of hazardous
substances. Under CERCLA, the Corporation's financial responsibilities may
include 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 sites and measures the liability quarterly, by assessing a
range of reasonably likely costs for each identified site using currently
available information, including existing technology, presently enacted laws and
regulations, experience gained at similar sites, and the probable level of
involvement and financial condition of other potentially responsible parties.
These estimates include costs for site investigations, remediation, operations
and maintenance, monitoring, and site closure. 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. It is reasonably possible that a change in the
estimate will 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 at
December 31, 1997, of $232 million for hazardous waste remediation costs at
those sites, including fossil-fueled power plants, where such costs are probable
and quantifiable. Environmental remediation at identified sites may be as much
as $442 million if, among other things, other 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 at sites for which the Utility is responsible. This upper limit
of the range of costs was estimated using assumptions least favorable to the
Utility, based upon a range of reasonably possible outcomes. Costs may be higher
if the Utility is found to be responsible for cleanup costs at additional sites
or identifiable possible outcomes change.
Of the $232 million liability discussed above, the Utility expects to recover
$157 million in future rates. The liability also includes $58 million related to
power plant decommissioning for environmental clean-up, which the Utility
recovered through depreciation. Additionally, the Utility is seeking recovery of
costs from insurance carriers and from other third parties. The Corporation
believes the ultimate outcome of these matters will not have a material adverse
impact on its or the Utility's financial position or results of operations.
Helms Pumped Storage Plant (Helms): Helms is a three-unit hydroelectric combined
generating and pumped storage plant owned by the Utility. At December 31, 1997,
the Utility's net investment was $691 million. This net investment is comprised
of the pumped storage facility (including regulatory assets of $51 million),
common plant, and dedicated transmission plant. As part of the 1996 General Rate
Case decision in December 1995, the CPUC directed the Utility to perform a cost-
effectiveness study of Helms. In July 1996, the Utility submitted its study,
which concluded that the continued operation of Helms is cost effective. The
Utility recommended that the CPUC take no action and address Helms along with
other generating plants in the context of electric industry restructuring.
Under electric industry restructuring, the uneconomic, above-market portion
of Helms is eligible for recovery as a transition cost. However, the Utility
will be placed at risk to recover its future operating costs in the newly
restructured electric generation market.
57
<PAGE>
Notes to Consolidated Financial Statements
Because the CPUC has not specifically addressed the cost-effectiveness study,
the Utility is currently unable to predict whether there will be further changes
in rate recovery. The Corporation believes that the ultimate outcome of this
matter will not have a material adverse impact on its or the Utility's financial
position or results of operations.
Legal Matters:
Chromium Litigation:
In 1994 through 1997, several civil suits were filed against the Utility on
behalf of approximately 3,000 individuals. The suits seek an unspecified 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.
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.
The Corporation believes that the ultimate outcome of this matter will not
have a material adverse 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, now known as PG&E
Gas Transmission, Texas Corporation (GTT), GTT succeeded to the litigation
described below.
GTT and various of its affiliates are defendants in at least two class action
suits and five separate suits filed by various Texas cities. The class action
suits involve plaintiffs that serve as class representatives for classes
consisting of every municipality in Texas (excluding certain cities which filed
separate suits) in which any of the defendants engaged in business activities
related to natural gas or natural gas liquids or sold or supplied gas or used
public rights-of-way. Generally, these cities allege, among other things, that
(1) the defendants that own or operate pipelines have occupied city property and
conducted pipeline operations without the cities' consent and without
compensating the cities, and (2) the defendants that are gas marketers have
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.
The Corporation believes that the ultimate outcome of these matters will not
have a material adverse impact on its financial position.
58
<PAGE>
Note 14:
Segment Information
The Corporation's business segments consist of the Utility and Unregulated
Business Operations (consisting of gas transmission, electric generation, and
energy services and commodities).
The Corporation's business segment information was:
<TABLE>
<CAPTION>
Pacific Gas and Electric Company
Unregulated
Electric Gas Total Business Corporate
(in millions) Utility Utility Utility Operations and Other Total
- -----------------------------------------------------------------------------------------------------------------------------
1997
<S> <C> <C> <C> <C> <C> <C>
Operating revenues $ 7,691 $ 1,804 $ 9,495 $5,905 $ -- $15,400
Intersegment revenues(1) 13 90 103 446 (549) --
------------------------------------------------------------------------------
Total operating revenues 7,704 1,894 9,598 6,351 (549) 15,400
------------------------------------------------------------------------------
Depreciation and decommissioning 1,521 264 1,785 104 -- 1,889
Operating income before income taxes(2) 1,510 321 1,831 (82) (21) 1,728
Capital expenditures 1,196 333 1,529 341 -- 1,870
Total assets at year end(3) 19,546 5,601 25,147 6,224 (814) 30,557
1996
Operating revenues $ 7,160 $ 1,829 $ 8,989 $ 621 $ -- $ 9,610
Intersegment revenues(1) 12 70 82 58 (140) --
------------------------------------------------------------------------------
Total operating revenues 7,172 1,899 9,071 679 (140) 9,610
------------------------------------------------------------------------------
Depreciation and decommissioning 920 256 1,176 46 -- 1,222
Operating income before income taxes(2) 1,758 52 1,810 84 2 1,896
Capital expenditures 922 309 1,231 173 -- 1,404
Total assets at year end(3) 18,431 5,136 23,567 2,858 (188) 26,237
1995
Operating revenues $ 7,387 $1,856 $ 9,243 $ 379 $ -- $ 9,622
Intersegment revenues(1) 13 85 98 68 (166) --
------------------------------------------------------------------------------
Total operating revenues 7,400 1,941 9,341 447 (166) 9,622
------------------------------------------------------------------------------
Depreciation and decommissioning 1,007 267 1,274 86 -- 1,360
Operating income before income taxes(2) 2,267 420 2,687 71 5 2,763
Capital expenditures 680 195 875 90 -- 965
Total assets at year end(3) 19,441 5,248 24,689 2,578 (396) 26,871
</TABLE>
(1) Intersegment electric and gas revenues are accounted for at tariff rates
prescribed by the CPUC.
(2) General corporate expenses are allocated in accordance with FERC Uniform
System of Accounts and requirements of the CPUC.
(3) Utility includes an allocation of common plant in service and allowance for
funds used during construction.
(4) Corporate and other assets consist of cash and cash equivalents, short-term
investments, receivables transferred from affiliates, and other assets.
(5) Includes consolidating eliminations.
59
<PAGE>
Quarterly Consolidated Financial Data (Unaudited)
Due to the seasonal nature of the Utility business and the scheduled refueling
outages for Diablo Canyon, operating revenues, operating income, and net income
are not generated evenly every quarter during the year.
PG&E Corporation 1997:
All four quarters of 1997 reflected an increase in revenues and expenses due to
the acquisitions discussed in the Notes to the Consolidated Financial
Statements.
In the second quarter of 1997, other income increased primarily due to the
gain on the sale of International Generating Company, Ltd., which was partially
offset by write-downs of certain nonregulated investments.
Utility 1997:
All four quarters of 1997 reflected an increase in operating revenues primarily
due to the revisions to the Diablo Canyon ratemaking structure, changes in sales
volume provided by the Utility's energy rate recovery mechanisms, and an
increase in energy cost revenues to recover energy cost increases. Operating
expenses increased primarily due to the increases in Diablo Canyon depreciation
and the cost of energy.
1996:
In the second quarter of 1996, operating expenses increased primarily due to the
settlement of a litigation claim. In the third quarter of 1996, operating
expenses increased primarily due to charges for gas transportation commitments.
In the fourth quarter of 1996, operating revenues and operating expenses
increased primarily due to the purchase of Energy Source in December 1996. Other
income decreased due to write-downs of certain nonregulated investments.
The Corporation's common stock is traded on the New York, Pacific, and Swiss
stock exchanges. There were approximately 180,000 common shareholders of record
at December 31, 1997. Dividends are paid on a quarterly basis.
<TABLE>
<CAPTION>
Quarter ended December 31 September 30 June 30 March 31
- ----------------------------------------------------------------------------------------------------------------------------
(in millions, except per share amounts)
1997
<S> <C> <C> <C> <C>
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
1996
PG&E Corporation and Utility
Operating revenues $2,700 $2,522 $2,139 $2,249
Operating income 509 525 288 574
Net income 141 225 104 252
Earnings per common share, basic and diluted .34 .55 .25 .61
Dividends declared per common share .30 .49 .49 .49
Common stock price per share
High 24.25 23.88 23.75 28.38
Low 20.88 19.50 21.50 22.38
</TABLE>
60
<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 the accompanying consolidated balance sheets of PG&E Corporation
(a California corporation) and subsidiaries and of Pacific Gas and Electric
Company (a California corporation) and subsidiaries as of December 31, 1997, and
1996, and the related statements of consolidated income, cash flows, and common
stock equity, preferred stock, and preferred securities for each of the three
years in the period ended December 31, 1997. These financial statements are the
responsibility of the management of PG&E Corporation and of Pacific Gas and
Electric Company. Our responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial positions of PG&E Corporation and
subsidiaries and of Pacific Gas and Electric Company and subsidiaries as of
December 31, 1997, and 1996, and the results of their operations and their cash
flows for each of the three years in the period ended December 31, 1997, in
conformity with generally accepted accounting principles.
ARTHUR ANDERSEN LLP
San Francisco, California
February 9, 1998
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 the 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 is taking 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 are conducted in conformity with
applicable laws and with their commitment to ethical conduct.
61
<PAGE>
Directors
Boards of Directors of
PG&E Corporation and
Pacific Gas and
Electric Company*
Richard A. Clarke
Chairman of the Board, Retired,
Pacific Gas and Electric Company
Harry M. Conger
Chairman of the Board,
Homestake Mining Company
David A. Coulter
Chairman and Chief
Executive Officer,
BankAmerica Corporation and
Bank of America NT&SA
C. Lee Cox
Vice Chairman, Retired,
AirTouch Communications, Inc.
and President and Chief Executive Officer, Retired,
AirTouch Cellular
William S. Davila
President Emeritus,
The Vons Companies, Inc.
(retail grocery)
Robert D. Glynn, Jr.
Chairman of the Board,
Chief Executive Officer, and President,
PG&E Corporation and
Chairman of the Board,
Pacific Gas and Electric Company
David M. Lawrence, MD
Chairman and
Chief Executive Officer,
Kaiser Foundation Health Plan, Inc.
and Kaiser Foundation Hospitals
Richard B. Madden
Chairman of the Board and
Chief Executive Officer, Retired,
Potlatch Corporation
(diversified forest products)
Mary S. Metz
Dean, University Extension,
University of California, Berkeley
Rebecca Q. Morgan
President and
Chief Executive Officer,
Joint Venture:
Silicon Valley Network
(nonprofit collaborative addressing
critical issues facing Silicon Valley)
Carl E. Reichardt
Chairman of the Board and
Chief Executive Officer, Retired,
Wells Fargo & Company and
Wells Fargo Bank, N.A.
John C. Sawhill
President and
Chief Executive Officer,
The Nature Conservancy
(international environmental
organization)
Alan Seelenfreund
Chairman of the Board and
former Chief Executive Officer,
McKesson Corporation
(distributor of pharmaceuticals and
health care products)
Gordon R. Smith*
President and
Chief Executive Officer,
Pacific Gas and Electric Company
Barry Lawson Williams
President,
Williams Pacific Ventures, Inc.
(venture capital and real estate,
consulting, and mediation)
Permanent Committees of
PG&E Corporation and
Pacific Gas and
Electric Company**
Executive Committees
Within limits, may exercise powers
and perform duties of the Boards.
Robert D. Glynn, Jr., Chair
Harry M. Conger
Richard B. Madden
Mary S. Metz
Carl E. Reichardt
Gordon R. Smith**
Audit Committee
Reviews financial statements and
internal audit and control
procedures with independent
public accountants.
Harry M. Conger, Chair
C. Lee Cox
William S. Davila
Mary S. Metz
Barry Lawson Williams
Finance Committee
Reviews long-term financial and
capital investment policies and objectives, and actions required to achieve
those objectives.
Richard B. Madden, Chair
Richard A. Clarke
David A. Coulter
Carl E. Reichardt
John C. Sawhill
Barry Lawson Williams
Nominating and Compensation Committee
Recommends candidates for nomination as directors, recommends compensation and
employee benefit policies and practices, and reviews planning for executive
development and succession.
Carl E. Reichardt, Chair
David A. Coulter
David M. Lawrence, MD
John C. Sawhill
Alan Seelenfreund
Public Policy Committee
Reviews public policy issues which
could significantly affect customers, shareholders, employees, or the
communities served, and recommends plans and programs to
address such issues.
Mary S. Metz, Chair
Richard A. Clarke
William S. Davila
Rebecca Q. Morgan
John C. Sawhill
** The composition of the Boards of Directors is the same, except that Gordon R.
Smith is a member of the Pacific Gas and Electric Company Board of Directors
only.
** Except for the Executive Committee, all Committees listed above are
committees of the PG&E Corporation Board of Directors. The Executive
Committees of the PG&E Corporation and Pacific Gas and Electric Company
Boards have the same members, except that Gordon R. Smith is a member of the
Pacific Gas and Electric Company Executive Committee only.
62
<PAGE>
Officers
PG&E Corporation
Robert D. Glynn, Jr.
Chairman of the Board,
Chief Executive Officer,
and President
Tony F. DiStefano
Senior Vice President,
Corporate Development
Scott W. Gebhardt
Senior Vice President
Thomas W. High
Senior Vice President, Administration and
External Relations
Jack F. Jenkins-Stark
Senior Vice President
Joseph P. Kearney
Senior Vice President
L. E. Maddox
Senior Vice President
Michael E. Rescoe
Senior Vice President,
Chief Financial Officer, and Treasurer
G. Brent Stanley
Senior Vice President,
Human Resources
Bruce R. Worthington
Senior Vice President and
General Counsel
Leslie H. Everett
Vice President and
Corporate Secretary
Christopher P. Johns
Vice President and
Controller
Jackalyne Pfannenstiel
Vice President,
Business Planning
Greg S. Pruett
Vice President,
Corporate Communications
Daniel D. Richard, Jr.
Vice President,
Governmental Relations
Linda Y. H. Cheng
Assistant Corporate Secretary
Wondy S. Lee
Assistant Corporate Secretary
Eric Montizambert
Assistant Corporate Secretary
Gabriel B. Togneri
Assistant Treasurer
Pacific Gas and
Electric Company
Robert D. Glynn, Jr.
Chairman of the Board
Gordon R. Smith
President and
Chief Executive Officer
Kent M. Harvey
Senior Vice President,
Chief Financial Officer,
and Treasurer
E. James Macias
Senior Vice President and
General Manager,
Generation, Transmission, and
Supply Business Unit
James K. Randolph
Senior Vice President and
General Manager,
Distribution and Customer Service Business Unit
Daniel D. Richard, Jr.
Senior Vice President,
Governmental and
Regulatory Relations
Gregory M. Rueger
Senior Vice President and
General Manager,
Nuclear Power Generation
Business Unit
Shan Bhattacharya
Vice President,
Distribution Engineering and
Planning
Thomas E. Bottorff
Vice President,
Rates and Account Services
Jeffrey D. Butler
Vice President,
Distribution Operations,
Maintenance, and Construction
Barbara Coull Williams
Vice President,
Human Resources
Leslie H. Everett
Vice President and
Corporate Secretary
Katheryn M. Fong
Vice President,
Customer Revenue Transactions
Roger J. Gray
Vice President,
General Services
Robert L. Harris
Vice President,
Community Relations
Russell M. Jackson
Vice President,
Customer Service
Christopher P. Johns
Vice President and
Controller
Junona A. Jonas
Vice President,
Gas and Electric Supply
Steven L. Kline
Vice President,
Regulatory Relations
Thomas C. Long
Vice President,
General Rate Case Project
William R. Mazotti
Vice President,
Gas and Electric Transmission
Roger J. Peters
Vice President and
General Counsel
Robert P. Powers
Vice President,
Diablo Canyon Operations and
Plant Manager
Frank J. Regan
Vice President,
Governmental Relations
Lawrence F. Womack
Vice President,
Nuclear Technical Services
Linda Y. H. Cheng
Senior Assistant
Corporate Secretary
Wondy S. Lee
Assistant Corporate Secretary
Eric Montizambert
Assistant Corporate Secretary
Gabriel B. Togneri
Assistant Treasurer
U.S. Generating Company
Joseph P. Kearney
President and
Chief Executive Officer
P. Chrisman Iribe
Executive Vice President and
Chief Operating Officer
PG&E Gas Transmission
Jack F. Jenkins-Stark
President and
Chief Executive Officer
Terrence E. Ciliske
President and
Chief Executive Officer of
PG&E Gas Transmission-Texas
Michael J. McDonald
Managing Director of
PG&E Gas Transmission - Australia
PG&E Energy Services
Scott W. Gebhardt
President and
Chief Executive Officer
James C. Davis
Senior Vice President,
Integrated Services
William R. Doucette
Senior Vice President,
Sales
PG&E Energy Trading
L. E. Maddox
President and
Chief Executive Officer
63
<PAGE>
Shareholder Information
Shareholder Services Office
77 Beale Street, Room 2600
San Francisco, CA 94105-1814
Call Toll Free 1.800.367.7731
Fax 415.973.7831
For financial and other information about PG&E Corporation and Pacific Gas and
Electric Company, please visit our web sites, www.pgecorp.com and www.pge.com
If you have questions about your account or need copies of PG&E Corporation's or
Pacific Gas and Electric Company's publications, please write or call the
Shareholder Services Office at:
Manager of Shareholder Services
David M. Kelly
Mail Code B26B
P.O. Box 770000
San Francisco, CA 94177-0001
1.800.367.7731
If you have general questions about PG&E Corporation or Pacific Gas and Electric
Company, please write or call the Corporate Secretary's Office:
Corporate Secretary
Leslie H. Everett
One Market, Spear Tower, Suite 2400
San Francisco, CA 94105-1108
415.973.2880
Securities analysts, portfolio managers, or other representatives of the
investment community should write or call the Investor Relations Office:
Manager of Investor Relations
David E. Kaplan
One Market, Spear Tower, Suite 2400
San Francisco, CA 94105-1108
415.973.3007
PG&E Corporation
General Information
415.973.7000
Pacific Gas and Electric Company
General Information
415.973.7000
Stock Held in Brokerage Accounts
("Street Name")
When you purchase your stock and it is held for you by your broker, the shares
are listed with us in the broker's name, or "street name." We do not know the
identity of the individual shareholders who hold their shares in this manner-we
simply know that a broker holds a number of shares which may be held for any
number of investors. If you hold your stock in a street name account, you
receive all dividend payments, tax forms, publications, and proxy materials
through your broker. If you are receiving unwanted duplicate mailings, you
should contact your broker to eliminate the duplications.
PG&E Corporation Dividend Reinvestment Plan
If you hold PG&E Corporation or Pacific Gas and Electric Company stock in your
own name, rather than through a broker, you may automatically reinvest dividend
payments from common and/or preferred stock in shares of PG&E Corporation common
stock through the Dividend Reinvestment Plan (the "Plan"). You may obtain a Plan
prospectus and enroll by contacting the Shareholder Services Office. If your
certificates are held by a broker (in "street name"), you are not eligible to
participate in the Plan.
Direct Deposit of Dividends
If you hold stock in your own name, rather than through a broker, you may have
your common and/or preferred dividends transmitted to your bank electronically.
You may obtain a direct deposit authorization form by contacting the Shareholder
Services Office.
Replacement of Dividend Checks
If you hold stock in your own name and do not receive your dividend check within
five business days after the payment date, or if a check is lost or destroyed,
you should notify the Shareholder Services Office so that payment may be stopped
on the check and a replacement mailed.
Lost or Stolen Stock Certificates
If you hold stock in your own name and your stock certificate has been lost,
stolen, or in some way destroyed, you should notify the Shareholder Services
Office immediately.
[LOGO OF RECYCLED PAPER] Pages 17-64 printed on recycled paper.
64
<PAGE>
EXHIBIT 23
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation by
reference of our reports dated February 9, 1998, included or incorporated by
reference in this Form 10-K, into the 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), and (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).
/s/ Arthur Anderson LLP
San Francisco, California
March 4, 1998
<PAGE>
Exhibit 24.1
RESOLUTION OF THE
-----------------
BOARD OF DIRECTORS OF
---------------------
PG&E CORPORATION
----------------
February 18, 1998
-----------------
BE IT RESOLVED that each of LESLIE H. EVERETT, LINDA Y.H. CHENG, ERIC
MONTIZAMBERT, WONDY S. LEE, 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, 1997, 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, WONDY S. LEE, 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 on February 18, 1998; 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 4th
day of March, 1998.
Wondy S. Lee
------------------------
Wondy S. Lee
Assistant Corporate Secretary
PG&E CORPORATION
[CORPORATE
SEAL]
<PAGE>
RESOLUTION OF THE
-----------------
BOARD OF DIRECTORS OF
---------------------
PACIFIC GAS AND ELECTRIC COMPANY
--------------------------------
February 18, 1998
-----------------
BE IT RESOLVED that each of LESLIE H. EVERETT, LINDA Y.H. CHENG, ERIC
MONTIZAMBERT, WONDY S. LEE, 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, 1997,
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, WONDY S. LEE, do hereby certify that I am an 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 on February 18, 1998, 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
4th day of March, 1998.
Wondy S. Lee
---------------------------
Wondy S. Lee
Assistant Corporate Secretary
PACIFIC GAS AND ELECTRIC COMPANY
[CORPORATE
SEAL]
<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, ERIC MONTIZAMBERT, WONDY S.
LEE, 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,
1997, 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 18th day of
February, 1998.
Richard A. Clarke Richard B. Madden
Harry M. Conger Mary S. Metz
David A. Coulter Rebecca Q. Morgan
C. Lee Cox Carl E. Reichardt
William S. Davilla John C. Sawhill
Robert D. Glynn, Jr. Barry Lawson Williams
David M. Lawrence, MD
<PAGE>
POWER OF ATTORNEY
ROBERT D. GLYNN, 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, ERIC MONTIZAMBERT, WONDY S. LEE,
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, 1997, 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 18th day of
February, 1998.
Robert D. Glynn, Jr.
--------------------------------
Robert D. Glynn, Jr.
<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, ERIC MONTIZAMBERT, WONDY S. LEE, 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, 1997,
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 18th day of
February, 1998.
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, ERIC
MONTIZAMBERT, WONDY S. LEE, 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, 1997, 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 18th day of
February, 1998.
Richard A. Clarke Richard B. Madden
Harry M. Conger Mary S. Metz
David A. Coulter Rebecca Q. Morgan
C. Lee Cox Carl E. Reichardt
William S. Davilla John C. Sawhill
Robert D. Glynn, Jr. Gordon R. Smith
David M. Lawrence, MD Barry Lawson Williams
<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, ERIC MONTIZAMBERT, WONDY S. LEE, 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, 1997, 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 18th day of
February, 1998.
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, ERIC MONTIZAMBERT, WONDY S.
LEE, 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, 1997, 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 18th day of
February, 1998.
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, ERIC MONTIZAMBERT, WONDY S. LEE, 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, 1997,
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 18th day of
February, 1998.
Christopher P. Johns
--------------------------------
Christopher P. Johns
<TABLE> <S> <C>
<PAGE>
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THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM PG&E
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437
402
<LONG-TERM-DEBT-NET> 7,579
<SHORT-TERM-NOTES> 103
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<COMMERCIAL-PAPER-OBLIGATIONS> 80
<LONG-TERM-DEBT-CURRENT-PORT> 659
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<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
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<TOT-CAPITALIZATION-AND-LIAB> 30,557
<GROSS-OPERATING-REVENUE> 15,400
<INCOME-TAX-EXPENSE> 548
<OTHER-OPERATING-EXPENSES> 13,672
<TOTAL-OPERATING-EXPENSES> 13,672
<OPERATING-INCOME-LOSS> 1,728
<OTHER-INCOME-NET> 201
<INCOME-BEFORE-INTEREST-EXPEN> 1,929
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0
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<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>
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<NUMBER> 1
<NAME> PACIFIC GAS AND ELECTRIC
<MULTIPLIER> 1,000,000
<S> <C>
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