SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year Ended December 31, 1998
OR
[_] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
Commission Exact Name of Registrant IRS Employer
File as specified in its State of Identification
Number charter Incorporation Number
---------- ------------------------ ------------- --------------
1-12609 PG&E CORPORATION California 94-3234914
1-2348 PACIFIC GAS AND ELECTRIC California 94-0742640
COMPANY
Pacific Gas and Electric Company PG&E Corporation
77 Beale Street One Market, Spear Tower
P.O. Box 770000 Suite 2400
San Francisco, California San Francisco, California
(Address of principal executive (Address of principal executive
offices) offices)
94105
(Zip Code)
94177
(Zip Code) (415) 267-7000
(Registrant's telephone number,
(415) 973-7000 including area code)
(Registrant's telephone number,
including area code)
Securities registered pursuant to Section 12(b) of the Act:
Name of Each Exchange on
Title of Each Class Which Registered
- ------------------- ---------------------------
PG&E Corporation
Common Stock, no par value New York Stock Exchange and
Pacific Exchange
Pacific Gas and Electric Company
First Preferred Stock, cumulative, American Stock Exchange and
par value $25 per share: Pacific Exchange
Redeemable: 7.04%, 5% Series A, 5%, 4.80%, 4.50%, 4.36%.
Mandatorily Redeemable: 6.57%, 6.30%
Nonredeemable: 6%, 5.50%, 5%
7.90% Cumulative Quarterly Income Preferred American Stock Exchange and
Securities, Series A (liquidation preference Pacific Exchange
$25), issued by PG&E Capital I and guaranteed
by Pacific Gas and Electric Company
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days.
Yes [X] No [_]
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to
the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [X]
Aggregate market value of the voting stock held by non-affiliates of the
registrant as of February 22, 1999:
PG&E Corporation Common Stock $11,810 million
Pacific Gas and Electric Company First Preferred Stock $422 million
Common Stock outstanding as of February 22, 1999:
PG&E Corporation: 382,964,605
Pacific Gas and Electric Company: Wholly owned by PG&E Corporation
The market values of certain series of First Preferred Stock, for which
market prices as of a date within 60 days prior to the date of filing were not
available, were derived by dividing the annual dividend rate of each such
series of stock by the average yield of all of Pacific Gas and Electric
Company's Preferred Stock outstanding for which market prices were available.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the documents listed below have been incorporated by reference
into the indicated parts of this report, as specified in the responses to the
item numbers involved.
(1) Designated portions of the combined
Annual Report to Shareholders for the year
ended December 31, 1998................... Part II (Items 5, 6, 7.7A and 8)
Part IV (Item 14)
(2) Designated portions of the Joint Proxy
Statement relating to the 1999 Annual
Meetings of Shareholders.................. Part III (Items 10, 11, 12 and 13)
TABLE OF CONTENTS
Page
----
Glossary of Terms
PART I
Item 1. Business......................................................... 1
GENERAL.......................................................... 1
Corporate Structure and Business................................. 1
Competition and the Changing Regulatory Environment.............. 3
Electric Industry................................................ 3
Gas Industry..................................................... 4
Regulation of Pacific Gas and Electric Company................... 5
State Regulation................................................. 5
Federal Regulation............................................... 6
Licenses and Permits............................................. 6
Regulation of PG&E Corporation and Other Subsidiaries............ 6
PG&E Corporation................................................. 6
Wholesale Operations of Affiliates............................... 7
Capital Requirements and Financing Programs...................... 9
Price Risk Management Programs................................... 10
Year 2000 Matters................................................ 10
UTILITY OPERATIONS............................................... 11
California Ratemaking Mechanisms................................. 11
Electric Ratemaking.............................................. 12
Gas Ratemaking................................................... 13
Electric Utility Operations...................................... 14
Implementation of Electric Industry Restructuring................ 14
Independent System Operator and Power Exchange................... 14
Voluntary Generation Asset Divestiture........................... 15
Direct Access.................................................... 16
Electric Base Revenue Increase................................... 16
Rate Levels and Rate Reduction Bonds............................. 17
Recovery of Transition Costs..................................... 17
Public Purpose Programs.......................................... 18
Electric Operating Statistics.................................... 19
Electric Generating Capacity..................................... 20
Diablo Canyon.................................................... 21
Diablo Canyon Operations......................................... 21
Diablo Canyon Ratemaking......................................... 21
Nuclear Fuel Supply and Disposal................................. 22
Insurance........................................................ 23
Decommissioning.................................................. 23
Other Electric Resources......................................... 24
QF Generation and Other Power-Purchase Contracts................. 24
Geothermal Generation............................................ 25
Electric Transmission and Distribution........................... 25
Gas Utility Operations........................................... 26
Gas Operating Statistics......................................... 27
Natural Gas Supplies............................................. 28
Gas Regulatory Framework......................................... 28
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TABLE OF CONTENTS--(Continued)
Page
----
Transportation Commitments.................................... 29
Core Procurement Incentive Mechanism.......................... 30
PGT/Pacific Gas and Electric Company Pipeline Expansion....... 30
WHOLESALE OPERATIONS OF AFFILIATES............................ 31
Gas Transmission Operations................................... 31
Independent Power Generation.................................. 31
Portfolio of Operating Generating Plants...................... 34
Energy Trading................................................ 35
RETAIL OPERATIONS OF AFFILIATES............................... 35
Energy Services............................................... 35
ENVIRONMENTAL MATTERS......................................... 36
Environmental Matters......................................... 36
Environmental Protection Measures............................. 36
Air Quality................................................... 36
Water Quality................................................. 37
Hazardous Waste Compliance and Remediation.................... 38
Potential Recovery of Hazardous Waste Compliance and
Remediation Costs............................................. 39
Compressor Station Litigation................................. 40
Electric and Magnetic Fields.................................. 40
Low Emission Vehicle Programs................................. 41
Item 2. Properties.................................................... 41
Item 3. Legal Proceedings............................................. 41
Compressor Station Chromium Litigation........................ 41
Texas Franchise Fee Litigation................................ 42
Item 4. Submission of Matters to a Vote of Security Holders........... 44
EXECUTIVE OFFICERS OF THE REGISTRANTS......................... 45
PART II
Item 5. Market for the Registrant's Common Equity and Related
Stockholder Matters........................................... 48
Item 6. Selected Financial Data....................................... 48
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations..................................... 48
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.... 48
Item 8. Financial Statements and Supplementary Data................... 49
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure...................................... 49
PART III
Item 10. Directors and Executive Officers of the Registrant............ 49
Item 11. Executive Compensation........................................ 49
Item 12. Security Ownership of Certain Beneficial Owners and
Management.................................................... 49
Item 13. Certain Relationships and Related Transactions................ 49
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form
8-K........................................................... 50
Signatures.................................................... 54
Report of Independent Public Accountants...................... 55
ii
GLOSSARY OF TERMS
AB 1890........... Assembly Bill 1890, the California electric industry
restructuring legislation
AEAP.............. Annual Earnings Assessment Proceeding
AER............... Annual Energy Rate
AFUDC............. allowance for funds used during construction
ALJ............... Administrative Law Judge
ATCP.............. Annual Transition Cost Proceeding
Betz.............. Betz Laboratories, Inc. and affiliated entities
BCAP.............. Biennial Cost Allocation Proceeding
bcf............... billion cubic feet
BRPU.............. Biennial Resource Plan Update
BTA............... best technology available
Btu............... British thermal unit
CARE.............. California Alternate Rates for Energy
CCAA.............. California Clean Air Act
CEC............... California Energy Commission
CEMA.............. Catastrophic Emergency Memorandum Account
Central Coast
Board............ Central Coast Regional Water Quality Control Board
CERCLA............ Comprehensive Environmental Response, Compensation, and
Liability Act
Company........... Pacific Gas and Electric Company and its subsidiaries
core customers.... residential and smaller commercial gas customers
core subscription
customers........ noncore customers who choose bundled service
CPIM.............. core procurement incentive mechanism
CPUC.............. California Public Utilities Commission
CTC............... competition transition charge
Diablo Canyon..... Diablo Canyon Nuclear Power Plant
DOE............... United States Department of Energy
DSM............... demand side management
EDRA.............. Electric Deferred Refund Account
El Paso........... El Paso Natural Gas Company
EMF............... electric and magnetic fields
EPA............... United States Environmental Protection Agency
FERC.............. Federal Energy Regulatory Commission
Gas Accord........ Gas Accord Settlement
Geysers........... The Geysers Power Plant
GRC............... General Rate Case
HCP............... Habitat Conservation Plan
Helms............. Helms hydroelectric pumped storage plant
Holding Company
Act.............. Public Utility Holding Company Act of 1935
Humboldt.......... Humboldt Bay Power Plant
HWRC.............. hazardous waste remediation costs
ICIP.............. Incremental Cost Incentive Price
IPP............... Independent power producer
ISO............... Independent System Operator
ITCBA............. Interim Transition Cost Balancing Account
ITCS.............. Interstate Transition Cost Surcharge
kV................ kilovolts
kVa............... kilovolt-amperes
kW................ kilowatts
kWh............... kilowatt-hour
LEV............... low emission vehicle
Mcf............... thousand cubic feet
MMcf.............. million cubic feet
MMcf/d............ million cubic feet per day
MW................ megawatts
MWh............... megawatt-hour
NEES.............. New England Electric System
NEIL.............. Nuclear Electric Insurance Limited
NGL............... natural gas liquids
noncore
customers........ industrial and larger commercial gas customers
NOx............... oxides of nitrogen
NRC............... Nuclear Regulatory Commission
Nuclear Waste
Act.............. Nuclear Waste Policy Act of 1982
ORA............... Office of Ratepayer Advocates, a division of the California
Public Utilities Commission
PBR............... performance-based ratemaking
PG&E Expansion.... the Pacific Gas and Electric Company portion of the
Pipeline Expansion
PG&E ES........... PG&E Corporation's energy services operations, PG&E Energy
Services or PG&E ES
PG&E GT........... PG&E Corporation's gas transmission operations, PG&E Gas
Transmission or PG&E GT
PG&E GTT.......... PG&E Gas Transmission, Texas Corporation
PG&E ET........... PG&E Corporation's energy commodities activities, PG&E
Energy Trading or PG&E ET
PGT Expansion..... Pacific Gas Transmission Company (now known as PG&E Gas
Transmission, Northwest Corporation) portion of the
Pipeline Expansion
Pipeline
Expansion........ PGT/Pacific Gas and Electric Company Pipeline Expansion
PPPs.............. public purpose programs
PRP............... potentially responsible party
PX................ California Power Exchange
QF................ qualifying facility
RAP............... Revenue Adjustment Proceeding
RRC............... The Railroad Commission of Texas
SEC............... Securities and Exchange Commission
SOS............... Standard Offer Service
Teco.............. Teco Pipeline Company
TRA............... Transition Revenue Account
transition the period during which electric rates are frozen at 1996
period........... levels, which extends until the earlier of March 31, 2002
or the point in time when Pacific Gas and Electric Company
has recovered its transition costs
Transwestern...... Transwestern Pipeline Company
USGen............. U.S. Generating Company, LLC and its affiliates
USGenNE........... USGen New England, Inc.
USOSC............. U.S. Operating Services Company
Valero............ Valero Energy Corporation
PART I
ITEM 1. Business.
GENERAL
Corporate Structure and Business
PG&E Corporation is a holding company based in San Francisco, California,
which provides energy services throughout North America. Effective January 1,
1997, Pacific Gas and Electric Company (sometimes referred to herein as the
"Company") and its subsidiaries became subsidiaries of PG&E Corporation, which
was incorporated in 1995. Pacific Gas and Electric Company, incorporated in
California in 1905, is an operating public utility primarily regulated by the
California Public Utilities Commission (CPUC) and engaged principally in the
business of providing electric and natural gas services throughout most of
Northern and Central California. In the holding company reorganization,
Pacific Gas and Electric Company's outstanding common stock was converted on a
share-for-share basis into PG&E Corporation common stock. Pacific Gas and
Electric Company's debt securities and preferred stock were unaffected and
remain securities of Pacific Gas and Electric Company.
The consolidated financial statements of PG&E Corporation incorporated
herein include the accounts of PG&E Corporation and its wholly owned and
controlled subsidiaries (collectively, PG&E Corporation). The consolidated
financial statements of Pacific Gas and Electric Company incorporated herein
include the accounts of Pacific Gas and Electric Company and its wholly owned
and controlled subsidiaries. Because PG&E Corporation did not become the
holding company for Pacific Gas and Electric Company until January 1, 1997,
the 1996 consolidated financial statements represent the accounts of Pacific
Gas and Electric Company on a consolidated basis as predecessor of PG&E
Corporation.
The principal executive offices of PG&E Corporation are located at One
Market, Spear Tower, Suite 2400, San Francisco, California 94105, and its
telephone number is (415) 267-7000. The principal executive offices of Pacific
Gas and Electric Company are located at 77 Beale Street, P.O. Box 770000, San
Francisco, California 94177, and its telephone number is (415) 973-7000.
As of December 31, 1998, PG&E Corporation had $33.2 billion in assets. PG&E
Corporation generated $19.9 billion in operating revenues for 1998. As of
December 31, 1998, PG&E Corporation and its subsidiaries and affiliates had
approximately 23,300 employees. As of December 31, 1998, Pacific Gas and
Electric Company had $23 billion in assets. The Company generated $8.9 billion
in operating revenues for 1998. As of December 31, 1998, Pacific Gas and
Electric Company had approximately 19,800 employees.
In addition to the regulated utility business of Pacific Gas and Electric
Company, PG&E Corporation's other affiliated businesses include the ownership
and operation of natural gas pipelines, natural gas storage facilities, and
natural gas processing plants, primarily in the Pacific Northwest and Texas,
through various subsidiaries of PG&E Corporation (PG&E Gas Transmission or
PG&E GT); the development, construction, operation, ownership, and management
of independent power generation facilities through U.S. Generating Company,
LLC and its affiliates (USGen); the purchase and sale of energy commodities
and financial instruments to PG&E Corporation's other businesses, unaffiliated
utilities, marketers, municipalities, cooperatives, independent power
producers, and large end-use customers through PG&E Energy Trading Corporation
and its affiliates (PG&E Energy Trading or PG&E ET); and the provision to
customers nationwide with competitively priced natural gas and electricity and
services to manage and make more efficient their energy consumption through
PG&E Energy Services Corporation (PG&E Energy Services or PG&E ES). On
September 1, 1998, PG&E Corporation, through its indirect subsidiary, USGen
New England, Inc. (USGenNE), completed the acquisition of a portfolio of
electric generating assets and power supply contracts from the New England
Electric System (NEES) for approximately $1.59 billion plus $85 million for
certain employee-related costs. See "Wholesale Operations of Affiliates--
Independent Power Generation" below.
1
The gas and electric utility operations of Pacific Gas and Electric Company
represent the principal component of PG&E Corporation's business, contributing
45% of PG&E Corporation's total revenues in 1998. Pacific Gas and Electric
Company's utility operations contributed $1.82 of PG&E Corporation's total
1998 earnings per share of $1.88.
Pacific Gas and Electric Company's utility service territory covers 70,000
square miles with an estimated population of approximately 13 million and
includes all or portions of 48 of California's 58 counties. The area's diverse
economy includes aerospace, electronics, financial services, food processing,
petroleum refining, agriculture, and tourism.
At December 31, 1998, Pacific Gas and Electric Company served approximately
4.6 million electric customers. In 1998, Pacific Gas and Electric Company
served its electric customers with power generated by seven primarily natural
gas-fueled steam power plants with 21 units, ten combustion turbines, two
nuclear power reactor units at Diablo Canyon Nuclear Power Plant (Diablo
Canyon), 68 hydroelectric powerhouses with 109 units, the Helms hydroelectric
pumped storage plant (Helms) with three units, and a geothermal energy complex
of 14 units. (In connection with the ongoing California electric industry
restructuring, on July 1, 1998, the Company sold three fossil-fueled power
plants which included six steam units and three combustion turbines. In late
1998 and in January 1999, the Company entered into agreements to sell three of
its five remaining fossil-fueled power plants, which include 10 steam units
and three combustion turbines, and its geothermal facilities. The sales are
expected to be completed in 1999. See "Utility Operations--Electric Utility
Operations--Implementation of Electric Industry Restructuring" below.) The
Company also purchases power produced by other generating entities that use a
wide array of resources and technologies, including hydroelectric, wind,
solar, biomass, geothermal, and cogeneration. In addition, the Company is
interconnected with electric power systems in 14 western states and British
Columbia, Canada, for the purposes of buying, selling, and transmitting power.
Pacific Gas and Electric Company served approximately 3.8 million gas
customers at December 31, 1998. Most of these customers continue to obtain gas
supplies from the Company under regulated tariff rates. To ensure a diverse
and competitive mix of natural gas supplies to serve customers that choose the
Company as its supplier, the Company directly purchases gas from producers and
marketers in both Canada and the United States. In 1998, about 68% of the
Company's gas supply was purchased in Canada, about 4% was purchased in
California, and about 28% was purchased in the U.S. Southwest.
In 1998, California became one of the first states in the nation to
implement an electric industry restructuring plan. (The framework of this plan
was established by Assembly Bill 1890 (AB 1890) passed by the California
Legislature and signed by the Governor in 1996.) In California, electric
customers may choose to purchase their electricity from investor-owned
utilities (such as Pacific Gas and Electric Company), unregulated retail
electricity providers (such as marketers, including PG&E Energy Services,
brokers, and aggregators), or unregulated power generators, on a competitive
basis (i.e., "direct access"). The California restructuring plan contemplates
that the investor-owned utilities (such as Pacific Gas and Electric Company)
will continue to provide distribution services to substantially all customers
within their service territories. In November 1998, the California voters
defeated Proposition 9, a voter initiative which would have overturned major
portions of AB 1890 if it had been approved. See "Utility Operations--Electric
Utility Operations--Implementation of Electric Industry Restructuring" below.
The following information includes forward-looking statements about the
future that involve a number of risks and uncertainties. Words such as
"estimates," "expects," "intends," "anticipates," and "plans," and similar
expressions identify those statements which are forward-looking. These
forward-looking statements are based on management's beliefs and assumptions
and on information currently available to management. Actual results could
differ materially from those contemplated by the forward-looking statements.
Some of the factors that could cause actual results to differ materially from
those contemplated in the forward-looking statements include, but are not
limited to, the pace and extent of the ongoing restructuring of the electric
and gas industries across the United States; the outcome of regulatory and
legislative proceedings and operational changes related to industry
restructuring; any changes in the amount Pacific Gas and Electric Company is
allowed to collect
2
(recover) from its customers for certain costs which prove to be uneconomic
under the new competitive market (called transition costs) in accordance with
the Company's plan for recovering those costs; the successful integration and
performance of recently acquired assets; the Corporation's ability to
successfully compete outside of the traditional regulated markets; the ability
to lessen the risk of the impact of the Year 2000 on internal and external
computer and software systems; the outcome of ongoing regulatory proceedings,
including Pacific Gas and Electric Company's pending General Rate Case which
will determine whether the Company will have the opportunity to earn its
authorized rate of return, the Cost of Capital proceeding, which will
determine the amount of return the Company will be authorized to earn on its
assets and recover from ratepayers, the Company's proposal to adopt
performance-based ratemaking, the Company's electric transmission rate case
applications, and the CPUC's proceeding relating to the Company's affiliate
transactions; fluctuations in commodity gas and electric prices and the
ability to successfully manage such price fluctuations; and the pace and
extent of competition in the California generation market and its impact on
the Company's costs and resulting collection of transition costs. As the
ultimate impacts of these and other factors is uncertain, these and other
factors may cause future results to differ materially from results or outcomes
currently expected or sought by PG&E Corporation.
Competition and the Changing Regulatory Environment
The electric and gas industries are undergoing significant change. Under
traditional regulation, utilities were provided the opportunity to earn a fair
return on their invested capital in exchange for a commitment to serve all
customers within a designated service territory. The objective of this
regulatory policy was to provide universal access to safe and reliable utility
services. Regulation was designed in part to take the place of competition and
ensure that these services were provided at fair prices.
Today, competitive pressures and emerging market forces are exerting an
increasing influence over the structure of the gas and electric industries.
Other companies have challenged the utilities' exclusive relationship with
their customers and have sought to replace certain utility functions with
their own. Customers, too, have asked for choice in their energy provider.
These pressures have caused a move from the traditional regulatory framework
to one in which competition is allowed in certain segments of the gas and
electric industries.
In 1998, a significant portion of Pacific Gas and Electric Company's
business was transformed from the traditional monopoly structure to a
competitive operation. The return on Diablo Canyon and certain other
generation assets continued to be significantly lower in 1998 than historical
levels and will remain at this lower level throughout the transition period.
See "Utility Operations--Electric Utility Operations--Diablo Canyon--Diablo
Canyon Ratemaking" below. The new competitive environment and the regulatory
decisions made in the context of electric and gas industry restructuring will
continue to affect PG&E Corporation's financial results and may result in
greater earnings volatility. The changes in both the electric and gas
industries, as described below, require the Company to develop and implement
changes to its business processes and systems, including customer information
and billing systems, to accommodate electric and gas industry restructuring.
To the extent the Company is unable to successfully and timely develop and
implement such changes, there could be an adverse impact on the Company's
future results of operations.
Electric Industry
In 1998, California became one of the first states in the nation to
implement an electric industry restructuring plan, the framework of which was
established by AB 1890. Pursuant to AB 1890, on January 1, 1997, electric
rates were frozen, at the levels in effect on June 10, 1996, until the earlier
of March 31, 2002, or when the particular utility has recovered its
generation-related transition costs (the transition period). The following key
features of AB 1890 have been implemented:
--Mandatory unbundling of transmission, distribution, and generation
services, although the utilities must continue to offer bundled electric
service to customers who wish to continue receiving it from the utility.
--Commencement of operations of the California Power Exchange (PX) which
provides a competitive auction process to establish a transparent market
clearing price for electricity in California.
3
--Relinquishment of control (but not ownership or maintenance) of the
utilities' transmission facilities to the California Independent System
Operator (ISO).
--Commencement of operations of the ISO which ensures system reliability
and provides electric market participants with open and comparable access
to transmission services.
--A 10% reduction in the previously frozen rates, effective January 1,
1998, through the end of the transition period, for residential and small
commercial customers.
--The issuance of rate reduction bonds in December 1997 to finance the 10%
rate reduction.
--Collection of a nonbypassable charge (the competition transition charge
or CTC) to provide the opportunity for utilities to recover their
transition costs.
--Accelerated recovery of transition costs associated with utility-owned
generation facilities.
--Commencement of direct access to competitive generation resources for all
retail electric customers on March 31, 1998.
--Commencement of the market valuation process for utility-owned non-
nuclear generation assets, to be completed by 2001.
For more information about California electric industry restructuring, see
"Utility Operations--Electric Utility Operations--Implementation of Electric
Industry Restructuring" below.
Other states also have moved forward with their electric industry
restructuring plans to increase competition. PG&E Corporation's national
energy strategy includes active pursuit of opportunities created by the
gradual deregulation of the electric industry across the nation. PG&E
Corporation's ability to anticipate and capture profitable business
opportunities created by deregulation will have a significant impact on the
Corporation's future operating results.
Additional information concerning electric industry restructuring and the
financial impact of these changes on PG&E Corporation is provided in
"Management's Discussion and Analysis" in the 1998 Annual Report to
Shareholders, beginning on page 18, and in Note 2 of the "Notes to
Consolidated Financial Statements" beginning on page 49 of the 1998 Annual
Report to Shareholders.
Gas Industry
Restructuring of the natural gas industry on both the national and state
levels has given customers greater options in meeting their gas supply needs.
Regulators and legislators are using "unbundling" (separating the various
services and the pricing of those services) to increase competition for non-
monopoly energy services and to increase choices for customers. In the gas
industry, Federal Energy Regulatory Commission (FERC) Order 636 required
interstate pipeline companies to divide their services into separate sales,
transportation, and storage services. Under Order 636, interstate pipelines
must provide transportation service regardless of whether the customer
(typically a local gas distribution company) buys the gas commodity from the
pipeline.
During 1998, the California gas industry continued to be restructured
pursuant to the Gas Accord Settlement, a multi-party agreement approved by the
CPUC in 1997 (Gas Accord). The Gas Accord separates, or "unbundles," Pacific
Gas and Electric Company's gas transmission services from its distribution
services and changes the terms of service and rate structure for gas
transportation. Unbundling gives noncore customers the opportunity to select
from a menu of services offered by Pacific Gas and Electric Company and
enables them to pay only for the services they use. Unbundling also makes
access to the transmission system possible for all gas marketers and shippers,
as well as noncore end-users. As a result, the transmission system is now more
accessible to a greater number of customers.
Pacific Gas and Electric Company's customers may buy gas directly from
competing suppliers and purchase transmission-only and distribution-only
services from Pacific Gas and Electric Company. The Company's
4
transmission and distribution services historically have been "bundled," or
sold together at a combined rate, within California. Most of Pacific Gas and
Electric Company's industrial and larger commercial (noncore) customers now
purchase their gas from marketers and brokers. Substantially all residential
and smaller commercial (core) customers buy gas as well as transmission and
distribution services from Pacific Gas and Electric Company as a bundled
service. Customer rates for gas are updated on a monthly basis in order to
reflect changes in Pacific Gas and Electric Company's gas procurement costs.
The Gas Accord increases opportunities for Pacific Gas and Electric
Company's core customers to purchase gas from competing suppliers and,
therefore, may reduce the Company's role in procuring gas for such customers.
However, Pacific Gas and Electric Company will continue to procure gas as a
regulated utility supplier for those customers who do not obtain gas supplies
from an alternative provider.
Under the Gas Accord, Pacific Gas and Electric Company's core gas
procurement costs for the period 1994 to 2002 are recoverable under a core
procurement incentive mechanism (CPIM), a form of incentive regulation. The
CPIM provides the Company with a direct financial incentive to procure gas and
transportation services at the lowest reasonable costs by comparing all
procurement costs to an aggregate market-based benchmark. If costs fall within
a range (tolerance band) around the benchmark, costs are deemed reasonable and
fully recoverable from ratepayers. If the Company's actual core procurement
costs fall outside the tolerance band, the Company's ratepayers and
shareholders share savings or costs, respectively.
The Gas Accord also established gas transmission and storage rates for the
period from March 1, 1998, through December 31, 2002. During this period,
Pacific Gas and Electric Company is at risk for revenue fluctuations resulting
from variances in demand for noncore gas transmission throughput. Rates for
distribution service continue to be set by the CPUC, and are designed to
provide the Company an opportunity to recover its costs of service and include
a return on investment.
In January 1998, the CPUC opened a rulemaking proceeding to expand market-
oriented policies in the natural gas industry, including the further
unbundling of services to promote competition, streamlining regulation for
noncompetitive services, mitigating the potential for anti-competitive
behavior, and establishing appropriate consumer protections. In August 1998,
the Governor of California signed Senate Bill 1602, allowing the CPUC to
investigate issues associated with the further restructuring of natural gas
services. If the CPUC determines that further changes are in the public
interest, it is required to submit its findings to the Legislature. Senate
Bill 1602 prohibits the CPUC from adopting any decisions regarding gas
industry restructuring until January 1, 2000. The CPUC has completed hearings
dealing with market conditions and has indicated that it will issue a decision
identfiying the most promising structural changes for further study. The CPUC
will hold hearings in the future on safety issues associated with gas revenue
cycle service unbundling and the costs and benefits associated with the most
promising options. The CPUC then intends to conduct open public comment
meetings, develop consumer protection rules, and submit a report to the
Legislature setting forth its recommendations.
Additional information concerning gas industry restructuring, and the
financial impact of these changes on PG&E Corporation, is provided in
"Management's Discussion and Analysis" in the 1998 Annual Report to
Shareholders, beginning on page 18.
Regulation of Pacific Gas and Electric Company
State Regulation
The CPUC consists of five members appointed by the Governor (although there
are currently two vacancies) and confirmed by the State Senate for six-year
terms. The CPUC regulates Pacific Gas and Electric Company's rates and
conditions of service, sales of securities, dispositions of utility property,
rate of return, rates of depreciation, uniform systems of accounts, long-term
resource procurement, and transactions between Pacific Gas and Electric
Company and its subsidiaries and affiliates. The CPUC also conducts various
reviews of utility performance and conducts investigations into various
matters, such as deregulation, competition, and the environment, in order to
determine its future policies.
5
The California Energy Commission (CEC) has the responsibility to make
electric-demand forecasts for the state and for specific service territories.
Based upon these forecasts, the CEC determines the need for additional energy
sources and for conservation programs. The CEC sponsors alternative-energy
research and development projects, promotes energy conservation programs, and
maintains a statewide plan of action in case of energy shortages. In addition,
the CEC certifies power-plant sites and related facilities within California.
The CEC also administers funding for public purpose research and development,
and renewable technologies programs. The funding will be collected from
ratepayers through a nonbypassable public benefits charge. See "Utility
Operations--Electric Utility Operations--Implementation of Electric Industry
Restructuring--Public Purpose Programs" below.
Federal Regulation
The Federal Energy Regulatory Commission (FERC) regulates electric
transmission rates and access, operation of the California Independent System
Operator and the California Power Exchange, compliance with the uniform
systems of accounts, and electric contracts involving sales of electricity for
resale. The FERC also has jurisdiction over Pacific Gas and Electric Company's
electric transmission revenue requirements and rates. The FERC also regulates
the interstate transportation of natural gas. Further, most of Pacific Gas and
Electric Company's hydroelectric facilities are subject to licenses issued by
the FERC.
The Nuclear Regulatory Commission (NRC) oversees the licensing,
construction, operation, and decommissioning of nuclear facilities, including
Diablo Canyon and the nuclear generating unit at Humboldt Bay Power Plant
(Unit 3). NRC regulations require extensive monitoring and review of the
safety, radiological, and environmental aspects of these facilities.
Licenses and Permits
Pacific Gas and Electric Company obtains a number of permits,
authorizations, and licenses in connection with the construction and operation
of its generating plants and gas compressor station facilities. Discharge
permits, various Air Pollution Control District permits, FERC hydroelectric
facility licenses, and NRC licenses are the most significant examples. Some
licenses and permits may be revoked or modified by the granting agency if
facts develop or events occur that differ significantly from the facts and
projections assumed in granting the approval. Furthermore, discharge permits
and other approvals and licenses are granted for a term less than the expected
life of the associated facility. Licenses and permits may require periodic
renewal, which may result in additional requirements being imposed by the
granting agency.
Regulation of PG&E Corporation and Other Subsidiaries
PG&E Corporation
PG&E Corporation and its subsidiaries are exempt from all provisions, except
Section 9(a)(2), of the federal Public Utility Holding Company Act of 1935
(Holding Company Act) on the basis that PG&E Corporation and Pacific Gas and
Electric Company are incorporated in the same state and their business is
predominantly intrastate in character and carried on substantially in the
state of incorporation. At present, PG&E Corporation has no expectation of
becoming a registered holding company under the Holding Company Act.
PG&E Corporation is not a public utility under the laws of California and is
not subject to regulation as such by the CPUC. However, the CPUC approval
authorizing Pacific Gas and Electric Company to form a holding company was
granted subject to various conditions related to finance, human resources,
records and bookkeeping, and the transfer of customer information. The
financial conditions provide that Pacific Gas and Electric Company is
precluded from guaranteeing any obligations of PG&E Corporation without prior
written consent from the CPUC, Pacific Gas and Electric Company's dividend
policy shall continue to be established by Pacific Gas and Electric Company's
Board of Directors as though Pacific Gas and Electric Company were a
comparable stand-alone utility company, and the capital requirements of
Pacific Gas and Electric Company, as
6
determined to be necessary to meet Pacific Gas and Electric Company's service
obligations, shall be given first priority by the Boards of Directors of PG&E
Corporation and Pacific Gas and Electric Company. The conditions also provide
that Pacific Gas and Electric Company shall maintain on average its CPUC-
authorized utility capital structure, although it shall have an opportunity to
request a waiver of this condition if an adverse financial event reduces the
utility's equity ratio by 1% or more.
A further condition of the CPUC's approval of the holding company formation
was that an audit of affiliate transactions from 1994 to 1996 be conducted and
supervised by the CPUC's Office of Ratepayer Advocates (ORA). The audit
report, completed in November 1997, was critical of Pacific Gas and Electric
Company's affiliate transaction internal controls and compliance. The report
contained numerous recommendations for additional conditions to be imposed on
the holding company. Pacific Gas and Electric Company has responded to the
audit report, and the CPUC held hearings in 1998 to determine if the
additional recommended conditions should be imposed on the holding company. On
February 23, 1999, a CPUC administrative law judge (ALJ) issued a proposed
decision which declines to adopt most of the recommended conditions, including
all of the financial conditions contested by the Company. Instead, the ALJ's
proposed decision directs the CPUC staff to prepare for the CPUC's
consideration a draft CPUC order to institute a generic proceeding to
determine whether the recommended financial conditions, or other appropriate
financial conditions, should be imposed on all California electric and gas
utilities within the CPUC's jurisdiction with respect to their holding company
operations. The ALJ's proposed decision also proposes to require Pacific Gas
and Electric Company to establish and maintain various accounting and internal
control practices and systems with respect to affiliate transactions. A final
CPUC decision is expected in early 1999.
On December 16, 1997, the CPUC issued a decision that adopted rules
governing transactions between California's natural gas local distribution and
electric utility companies and their non-regulated affiliates. This decision
permits non-regulated affiliates of regulated utilities (such as PG&E Energy
Services, the non-regulated energy marketing subsidiary of PG&E Corporation)
to compete in the affiliated utility's service territory, and also to use the
name and logo of their affiliated utility, provided that in California the
affiliate includes certain designated disclaimer language which emphasizes the
separateness of the entities and that the affiliate is not regulated by the
CPUC. The decision adopts complex and detailed rules requiring the separation
of regulated utilities and their non-regulated affiliates, and also contains
rules regarding information exchange among the affiliates and prohibits the
utility from engaging in certain practices which would discriminate against
energy service providers which compete with the utility's non-regulated
affiliates. As required by the decision, Pacific Gas and Electric Company
filed a comprehensive plan to comply with the affiliate transaction rules and
on September 17, 1998, the CPUC approved parts of the plan and ordered that
other parts be resubmitted. The Company has resubmitted its plan and expects
the CPUC to act on the plan in early 1999.
On December 17, 1998, the CPUC issued a decision establishing specific
penalties and enforcement procedures for affiliate rules violations. The
decision included a new requirement that utilities self-report for affiliate
rules violations, provided for an experimental advisory ruling process to be
established, and established an informal inquiry and a formal complaint
process.
Wholesale Operations of Affiliates
In addition to Pacific Gas and Electric Company, certain of PG&E
Corporation's other subsidiaries which conduct interstate gas transmission and
electric wholesale power marketing operations, are subject to FERC
jurisdiction. The FERC also has authority to regulate rates for natural gas
transportation in interstate commerce. The FERC also regulates certain
transportation transactions on the intrastate pipelines pursuant to Section
311 of the Natural Gas Policy Act of 1978.
The Railroad Commission of Texas (RRC) regulates gas utilities, including
those owned by PG&E Corporation through PG&E Gas Transmission, Texas
Corporation, (PG&E GTT), PG&E Gas Transmission Teco, Inc., and other
affiliates operating in Texas. The RRC's gas proration rules govern the
wellhead production and purchase of gas. Intrastate pipelines can provide
intrastate gas transportation at negotiated rates which are
7
presumed just and reasonable. If the criteria for negotiated rates cannot be
met, the RRC may assess a cost-of-service-based rate. The RRC also may
regulate certain sales of gas. Currently, the price of natural gas sold under
a majority of PG&E GTT's gas sales contracts is not regulated by the RRC. All
transportation and gathering of gas is subject to the RRC Code of Conduct
which prohibits undue discrimination among similarly situated shippers.
Further, all transportation of gas, processing of gas, and transportation of
natural gas liquids are subject to safety regulations enforced by the RRC and
the Texas Natural Resource Conservation Commission.
In addition, the power generation projects that USGen develop, manage, or
own are subject to differing types of federal regulation depending on the
regulatory status of the particular project. Some of these projects are exempt
wholesale generators (EWG) under the National Energy Policy Act of 1992, which
status exempts the project from the Holding Company Act. EWG status is granted
by the FERC upon application by the project. Some projects have received
authority from the FERC to charge market-based rates for the power they sell,
rather than traditional cost-based rates. Many of USGen's affiliated projects
are qualifying facilities (QFs) under the Public Utility Regulatory Policies
Act of 1978. QF status exempts the project from regulation under various
federal and state laws concerning the electric industry. USGen's projects are
also subject to various federal, state, and local regulations concerning
siting and environmental matters.
PG&E Corporation's indirect subsidiary, USGen New England, Inc. (USGenNE),
acquired the electric generating facilities of the New England Electric System
(NEES) in September 1998. USGenNE also is subject to numerous federal, state,
and local statutes and regulations. USGenNE sells at wholesale all of the
electricity it generates, as well as electricity it purchases from third
parties under existing power sales agreements. Under the Federal Power Act
("FPA"), the FERC regulates these wholesale sales. The FERC has approved
USGenNE's rate schedule as a market-based schedule and, accordingly, the FERC
granted USGenNE waivers of certain other requirements that otherwise are
imposed on utilities with cost-based rate schedules. In addition, USGenNE owns
and operates a number of hydroelectric and pumped-storage projects that are
licensed by the FERC. These licenses expire periodically and the projects must
be relicensed at that time. USGenNE's licenses for these hydroelectric
projects expire over a period from 2001 to 2020. Prior to the expiration of
any one of the hydroelectric licenses, there is an opportunity for the
existing licensee (as well as others interested in owning and operating the
project) to apply for, and obtain, a new license.
USGenNE also is subject to limited regulation by certain state public
utility commissions located in states where USGenNE owns and operates electric
generating facilities. This regulation does not extend to its rates, which are
regulated exclusively by the FERC, and the scope of this regulation has been
substantially limited by various legislative initiatives.
Other regulatory matters are described throughout this report.
8
Capital Requirements and Financing Programs
PG&E Corporation and Pacific Gas and Electric Company continue to require
capital for improvements to facilities to enhance their efficiency and
reliability, to extend their useful lives, and to comply with environmental
laws and regulations. PG&E Corporation's expenditures for these purposes,
including the allowance for funds used during construction (AFUDC), were
approximately $1,633 million for 1998. New investments totaled $1,779 million
in 1998.
The following table sets forth estimated capital expenditures, as well as
amounts for maturing debt and sinking funds, for PG&E Corporation subsidiaries
for the years 1999 through 2001. The amount of capital expenditures for
Pacific Gas and Electric Company (other than estimated capital expenditures
for Diablo Canyon) include estimates prepared for the Company's GRC
application now pending at the CPUC, excluding capital expenditures for
divested fossil and geothermal power plants. The amount of capital
expenditures for Pacific Gas and Electric Company shown in the table will be
reduced if the CPUC authorizes base revenues significantly lower than those
requested by the Company in its GRC filing.
1999 2000 2001
------ ------ ------
(in millions)
Utility Capital Expenditures(1)........................ $1,598 $1,666 $1,681
Other Capital Expenditures(2).......................... 364 205 157
Maturing Debt and Sinking Funds........................ 628 988 771
------ ------ ------
Total Capital Requirements........................... $2,590 $2,859 $2,609
====== ====== ======
- --------
(1) Utility capital expenditures include the estimates prepared for Pacific
Gas and Electric Company's GRC but exclude capital expenditures for
divested fossil and geothermal power plants. These numbers are shown net
of reimbursed capital and include AFUDC.
(2) Other expenditures include those of PG&E GT, PG&E ES, PG&E ET, and USGen.
Most of the estimated capital expenditures for Pacific Gas and Electric
Company for 1999 through 2001 are associated with short lead time capital
expenditure projects aimed at the replacement and enhancement of existing
facilities, and compliance with environmental laws and regulations. Also
included are proposed expenditures to maintain and improve safety and
reliability of Pacific Gas and Electric Company's electric transmission and
distribution system, as well as proposed expenditures for major projects
associated with customer service improvements.
PG&E Corporation estimates that its total capital requirements for the years
1999 through 2001 will include approximately $2.4 billion for payment at
maturity of outstanding long-term debt and for meeting sinking fund
requirements for debt, as indicated above.
The funds necessary for 1999-2001 capital requirements of PG&E Corporation
and its subsidiaries will be obtained from (i) internal sources, principally
net income before noncash charges for depreciation and deferred income taxes,
and (ii) external sources, including short-term financing, such as bank loans
and the sale of short-term notes, and long-term financing, such as sales of
equity and long-term debt securities, when and as required.
PG&E Corporation and its subsidiaries and affiliates conduct a continuing
review of their capital expenditures and financing programs. The amounts shown
in the table above are forward-looking statements based on a number of
assumptions and which are subject to various uncertainties. Actual amounts may
differ materially based upon a number of factors, including the outcome of
Pacific Gas and Electric Company's GRC filing, changes in assumptions about
system load growth, rates of inflation, receipt of adequate and timely rate
relief, availability and timing of regulatory approvals, total cost of major
projects, availability and cost of suitable nonregulated investments, and
availability and cost of external sources of capital, as well as the outcome
of the ongoing restructuring in both the electric and gas industries.
9
Price Risk Management Programs
PG&E Corporation has an officer-level Price Risk Management Committee and
has adopted a Risk Management Policy, approved by the Board of Directors of
PG&E Corporation, for trading and risk management activities. The Price Risk
Management Committee oversees implementation of the policy, approves the
trading and price risk management policies of subsidiaries, and monitors
compliance with the policy.
The Risk Management Policy allows derivatives to be used for both hedging
and non-hedging purposes. (A derivative is a contract whose value is dependent
on or derived from the value of some underlying asset.) PG&E Corporation uses
derivatives for hedging purposes primarily to offset underlying commodity
price risks. PG&E Corporation also participates in markets using derivatives
to create liquidity and maintain a market presence. Such derivatives include
forward contracts, futures, swaps, and options. The Risk Management Policy and
the trading and risk management policies of PG&E Corporation's subsidiaries
prohibit the use of derivatives whose payment formula includes a multiple of
some underlying asset. PG&E Corporation also monitors the trading and risk
management of PG&E ET, consistent with PG&E Corporation's Risk Management
Policy. See "Wholesale Operations of Affiliates--Energy Trading."
In 1998, the CPUC granted authority to Pacific Gas and Electric Company to
trade natural gas-based financial instruments to manage the influence of
natural gas prices on the cost of electricity purchased under existing power-
purchase contracts and to manage price and revenue risks associated with its
natural gas transmission and storage assets, subject to certain conditions.
The CPUC had previously granted authority to Pacific Gas and Electric Company
to trade natural gas-based financial instruments to hedge the gas commodity
price swings in serving core gas customers.
Additional information concerning price risk management activities and the
financial impact of price risk management activities on PG&E Corporation and
Pacific Gas and Electric Company is provided in "Management's Discussion and
Analysis" in the 1998 Annual Report to Shareholders, beginning on page 18 and
in Notes 1, 3, and 4 of the "Notes to Consolidated Financial Statements"
beginning on page 46 of the 1998 Annual Report to Shareholders.
Year 2000 Matters
PG&E Corporation's Year 2000 compliance program generally is proceeding on
schedule. However, if PG&E Corporation or third parties with whom PG&E
Corporation or Pacific Gas and Electric Company have significant business
relationships fail to achieve Year 2000 readiness with respect to mission-
critical systems, there could be a material adverse impact on PG&E Corporation
and Pacific Gas and Electric Company's financial position, results of
operations, and cash flow.
Additional information concerning Year 2000 matters and the financial impact
of Year 2000 matters on PG&E Corporation and Pacific Gas and Electric Company
is provided in "Management's Discussion and Analysis" in the 1998 Annual
Report to Shareholders, beginning on page 18.
10
UTILITY OPERATIONS
California Ratemaking Mechanisms
The CPUC authorizes an amount, known as "base revenues," to be collected
from ratepayers to recover Pacific Gas and Electric Company's basic business
and operational costs for its gas and electric operations. Base revenues,
which include non-fuel-related operating and maintenance costs, depreciation,
taxes, and a return on invested capital, are currently authorized by the CPUC
in General Rate Case (GRC) proceedings before the CPUC. During the GRC, which
occurs every three years, the CPUC examines Pacific Gas and Electric Company's
costs and operations to determine the amount of base revenue requirement the
Company is authorized to collect from customers through base revenues. The
revenue requirement is forecasted on the basis of a specified test year. (The
return component of Pacific Gas and Electric Company's revenue requirement is
computed using the overall cost of capital authorized in other proceedings.)
Following the revenue requirement phase of a GRC, the CPUC conducts a rate
design phase, which allocates revenue requirements and establishes rate levels
for the different classes of customers. The Company's current GRC application
pending at the CPUC is discussed below.
In December 1997, the CPUC adopted a cost-of-service-based ratemaking
mechanism for determining Pacific Gas and Electric Company's revenue
requirement for its hydroelectric and geothermal generation facilities. Under
this mechanism, the revenue requirements for these facilities will be
calculated as the sum of the capital-related revenue requirement (based on
recorded capital costs), the expense revenue requirement (based on the current
GRC-adopted expenses), and actual fuel expenses. A reduced rate of return on
common equity of 6.77% applies to these facilities. This alternative revenue
requirement mechanism will be in place through 2001, unless the CPUC
determines otherwise.
Each year, Pacific Gas and Electric Company files an application with the
CPUC to determine the authorized rate of return that the Company may earn on
its assets (subject to the rates of return established for Diablo Canyon and
non-nuclear generation-related assets discussed in the previous paragraph) and
recover from ratepayers. On May 8, 1998, the Company filed its 1999 Cost of
Capital application. Since (i) the CPUC separately reduced the rate of return
on the Company's generation-related assets including Diablo Canyon, (ii) the
FERC will authorize the rate of return for electric transmission assets at a
later date (see discussion below), and (iii) gas transmission and storage
rates have been set in the Gas Accord, the rate of return adopted in the 1999
Cost of Capital Proceeding only applies to the Company's electric and gas
distribution assets. The Company has requested an increase in the rate of
return on common equity to 12.10% and an overall utility return on rate base
of 9.53% compared to the 1998 authorized returns of 11.20% and 9.17%,
respectively. No request was made to change the capital structure for the
Company, which continues to be composed of 48.00% common equity, 5.80%
preferred stock, and 46.20% long-term debt. Other parties have recommended
lower rates of return than the amounts requested. If the Company's requested
increase is approved, the authorized cost of capital will increase 1999
authorized electric and gas revenue by $49.7 million and $15.5 million,
respectively.
In November 1998, Pacific Gas and Electric Company filed an application with
the CPUC to establish performance-based ratemaking (PBR) for electric and gas
distribution services. If approved, the distribution PBR will establish
electric and gas distribution revenue requirements for the years 2000 to 2004.
The Company has proposed that the revenue requirement for the year 2000 be
determined by applying a formula, based principally on inflation and
productivity factors, to the 1999 GRC authorized revenue requirement. In
subsequent years, the formula would be applied to the previous year's
authorized revenue requirement. The proposed PBR also includes a sharing
mechanism for earnings that are significantly above or below the authorized
cost of capital, and a framework for rewards and penalties based upon the
achievement of various performance measures. As the CPUC has indicated that a
decision will not be issued until as late as May 2000, in February 1999, the
Company requested interim relief to be effective starting January 2000.
The 1998 Annual Earnings Assessment Proceeding (AEAP), which determines
shareholder incentives earned for Pacific Gas and Electric Company's 1996 and
1997 demand side management (DSM) programs, was submitted in May 1998. In the
1998 AEAP, the Company has requested an incentive payment of approximately
11
$39.8 million for the Company's 1997 DSM programs, to be trued-up and
collected in installments over a 10-year period. After consolidating the
adjusted incentive payment installments from prior years, the net revenue
change in 1999 from DSM shareholder incentives should be an electric decrease
of approximately $14.3 million and a gas decrease of approximately $2.5
million. A final CPUC decision is expected during the first quarter of 1999.
On January 7, 1999, Pacific Gas and Electric Company filed an application
with the CPUC in its first Catastrophic Event Memorandum Account (CEMA)
requesting increases in electric and gas revenue requirements of $60.1 million
and $15.8 million, respectively, for costs incurred for several emergencies,
including the 1997 storms. The Company has requested that these costs be
included in rates effective January 1, 2000.
Electric Ratemaking
During 1998, the CPUC issued many decisions to implement electric industry
restructuring and the new market structure, including decisions related to
unbundling of rates, the recovery of transition costs, performance-based
ratemaking (PBR), and other activities that affect rates and revenue
requirements. Because electric rates are frozen, any change in Pacific Gas and
Electric Company's electric revenue requirements (the amount of revenue
required to pay certain costs) resulting from the items discussed below will
not change electric customer rates. Under the electric rate freeze, the
portion of total actual revenue that exceeds authorized base revenues and
certain other authorized revenue requirements is available to recover
transition costs. Therefore, increases in base revenues would reduce the
amount of revenue available to recover transition costs. Conversely, decreases
in base revenues would increase revenue available from frozen rates for
recovery of transition costs.
General Rate Case. In Pacific Gas and Electric Company's GRC now pending
before the CPUC, the Company is requesting increases in electric base revenues
of $445 million over electric base revenues authorized in 1998 to reflect
increasing levels of electric demand as well as customer growth in the service
territory, the costs of continued and enhanced maintenance activities, and
increased capital expenditures. The GRC electric revenue request includes
proposed funding for distribution services, including system reliability and
safety projects, increased distribution capacity (poles, wires, substations,
etc.), equipment inspection and maintenance, a continuation of tree-trimming
programs, and enhanced customer service and information technology systems.
Since the FERC authorizes the rates collected from customers for electric
transmission services, the GRC application does not seek approval of base
revenues to recover the cost of transmission services. In December 1998, the
CPUC issued a decision granting the requested increases on an interim basis
effective January 1, 1999. This interim decision will be in effect until the
CPUC issues its final decision, expected in June 1999. The interim decision
allows the Company to reflect the increased revenue requirements in its
balancing accounts to permit the Company to track the differences between
actual revenue requirements in effect on January 1, 1999, and the requested
revenue requirements. The interim decision did not increase electric rates.
Recovery of Transition Costs. On January 1, 1998, the Transition Revenue
Account (TRA) was established. Within the TRA, revenue from frozen rates
collected from ratepayers are allocated to transmission costs, distribution
costs, the costs of public purpose programs, nuclear decommissioning costs,
and energy procurement costs. Remaining revenues, if any, are transferred to
the Transition Cost Balancing Account (TCBA) to offset transition costs. The
CPUC established a separate annual proceeding, the Revenue Adjustment
Proceeding (RAP), to review, track, and compare each electric utility's
authorized revenue requirements with the actual recorded revenues, and to make
any necessary adjustments to reflect the authorized revenues that are approved
in other proceedings. The RAP is a consolidation proceeding to verify that the
outcomes from other proceedings are properly reflected and that the utilities
accurately calculate the amount of revenues available to transfer to the TCBA
to offset transition costs. On July 1, 1998, Pacific Gas and Electric Company
filed an application with the CPUC in its first RAP requesting CPUC approval
of entries made into the TRA from January 1 through May 31, 1998, and
requesting approval of the Company's accounting, revenue allocation, and rate
design proposals. On September 1, 1998, Pacific Gas and Electric Company also
filed an application in its first Annual Transition Cost Proceeding (ATCP)
requesting recovery of transition costs recorded in the TCBA from January 1
through June 30, 1998. This 1998 ATCP will verify the accounting and recording
of costs and revenues in the TCBA and ensure that only eligible transition
costs have been entered. Transition costs will receive a limited
"reasonableness" review.
12
Electric Industry Restructuring Implementation Costs. Under AB 1890, certain
electric industry restructuring implementation costs, that are found
reasonable by the CPUC may be recovered from ratepayers. Eligible costs
include FERC-authorized start-up and development costs of the ISO and PX, CPUC
approved consumer education programs, and the costs of implementing direct
access and demand PX billing and settlement systems. A multiparty settlement
agreement filed with the CPUC on November 13, 1998, proposes that Pacific Gas
and Electric Company would recover $40 million in 1997 and 1998 restructuring
implementation costs during the rate freeze (on a revenue requirements basis).
If recovery of these restructuring implementation costs during the rate freeze
displaces recovery of transition costs, the settlement agreement proposes that
Pacific Gas and Electric Company may recover up to $95 million of such
displaced transition costs after the rate freeze. A proposed CPUC decision is
expected in June 1999.
Revenues from Must-Run Contracts. The ISO has designated certain units at
electric generation facilities as necessary to remain available and
operational to maintain the reliability of the electric transmission system.
These units are called "must-run" units. In general, the ISO dispatches these
units under cost-based rate schedules that allow the owners to recover sunk
costs and ongoing operating costs of the must-run units. Although still
subject to FERC approval, the owners of must-run units choose among three
forms of must-run rate schedules, all of which are premised upon a different
mix of cost-based payments and revenues earned in the market.
Electric Transmission Revenues. Beginning in 1998, the FERC obtained
jurisdiction to determine the annual amount of Pacific Gas and Electric
Company's authorized revenue for transmission services that it may collect
from customers. The Company expects to file an application with the FERC in
March 1999 requesting 1999 electric transmission revenues of approximately
$425 million, an increase of approximately 8% over transmission revenues
sought by the Company and accepted, subject to refund, by the FERC in 1998.
Electric Deferred Refund Account (EDRA). In December 1996, the CPUC issued a
decision establishing an EDRA. The CPUC ordered Pacific Gas and Electric
Company to place into the EDRA credits for CPUC-ordered electric
disallowances, the utility electric generation share of gas disallowances
ordered by the CPUC or the FERC, and amounts resulting from reasonableness
disputes or fuel-related cost refunds made to Pacific Gas and Electric Company
based on regulatory agency decisions, plus interest charges. The Company
requested, and the CPUC approved, an early refund of amounts accrued in EDRA
in 1998. In 1998, the Company refunded approximately $36.4 million of EDRA
refunds to customers.
Post-Rate Freeze Ratemaking Mechanisms. On January 15, 1999, Pacific Gas and
Electric Company filed an application with the CPUC to determine the
ratemaking mechanisms to be in effect after the end of the electric rate
freeze period.
Additional information concerning Pacific Gas and Electric Company's
transition cost recovery plan, and the financial impact of electric industry
restructuring, is provided in "Management's Discussion and Analysis" in the
1998 Annual Report to Shareholders, beginning on page 18, and in Note 2 of the
"Notes to Consolidated Financial Statements" beginning on page 49 of the 1998
Annual Report to Shareholders.
Gas Ratemaking
Gas Accord. As noted above (see "General--Competition and the Changing
Regulatory Environment--Gas Industry"), the CPUC approved the Gas Accord in
1997. As part of the Gas Accord, the CPUC's traditional reasonableness reviews
of Pacific Gas and Electric Company's core gas costs have been replaced with a
CPIM (which also is discussed below in "Utility Operations--Gas Utility
Operations--Core Procurement Incentive Mechanism") for the period from June 1,
1994, through 2002. Additional information concerning the potential financial
impact of the Gas Accord is provided in "Management's Discussion and Analysis"
in the 1998 Annual Report to Shareholders, beginning on page 18.
13
General Rate Case. The Company is requesting an increase in gas base
revenues of $377 million, over base revenues authorized in 1998. The requested
increase in base revenues reflects increasing levels of gas demand as well as
customer growth in the service territory, the costs of continued and enhanced
maintenance activities, and increased capital expenditures. The GRC gas base
revenue request includes proposed funding for distribution system safety and
reliability improvements, increased depreciation costs of the gas pipeline
system, expanded customer service, and expanded customer and other information
systems. In December 1998, the CPUC issued a decision granting the requested
increase on an interim basis effective January 1, 1999. This interim decision
will be in effect until the CPUC issues its final decision, expected in June
1999. The interim decision allows the Company to reflect the increased revenue
requirements in its balancing accounts to permit the Company to track the
differences between actual revenue requirements in effect on January 1, 1999,
and the requested revenue requirements. The interim decision did not increase
gas rates. However, gas customers would experience an increase in gas
distribution rates if the CPUC approves the requested gas base revenue
increase. The requested increase in gas base revenues will not result in an
increase in customer gas transmission and storage rates, since the Gas Accord
has set gas transmission and storage rates for the period from implementation
of the Gas Accord through December 2002.
The Biennial Cost Allocation Proceeding (BCAP). The BCAP remains the
proceeding in which distribution costs and balancing account balances are
allocated to customers. The BCAP normally occurs every two years and is
updated in the interim year for purposes of amortizing any accumulation in the
balancing accounts. Balancing accounts for natural gas costs accumulate
differences between the actual recovery of gas costs and the revenues designed
for recovery of such costs. Balancing accounts for sales volumes accumulate
differences between authorized and actual base revenues. In 1997, Pacific Gas
and Electric Company filed its 1998 BCAP application. In June 1998, the CPUC
adopted a decision in the 1998 BCAP granting an annual $97.8 million revenue
requirement decrease effective September 1, 1998, compared to revenues
established by the Gas Accord on March 1, 1998. The overall annual revenue
requirement for the two-year BCAP period (September 1, 1998, through August
31, 2000) is approximately $1.5 billion, of which an annual average of
approximately $102 million is allocated for the collection of balancing
accounts. The previous annual revenue requirement was approximately $1.8
billion, of which approximately $303 million was allocated for the collection
of balancing accounts.
Electric Utility Operations
Implementation of Electric Industry Restructuring
In 1998, electric industry restructuring in California became effective with
the commencement of operations of the California Independent System Operator
(ISO) and the California Power Exchange (PX) on March 31, 1998.
Independent System Operator and Power Exchange
The ISO operates and controls most of the state's electric transmission
facilities (which continue to be owned and maintained by the California
utilities) and provides comparable open access to electric transmission
service. The ISO accepts balanced supply and load schedules from market
participants and manages the availability of electric transmission on a
statewide basis for these transactions. The ISO also purchases necessary
generation and ancillary services to maintain grid reliability.
In 1998, California's three largest investor-owned utilities relinquished
operational control, but not ownership, of their transmission facilities to
the ISO. The ISO is required to ensure reliable transmission services
consistent with planning and operating reserve criteria no less stringent than
those established by the Western Systems Coordinating Council and the North
American Electric Reliability Council. Oversight responsibility for
reliability of utility distribution systems remains with the CPUC.
The PX provides a competitive auction process to establish transparent
market clearing prices for electricity in the markets operated by the PX. The
three largest investor-owned utilities in California are required to sell into
the PX all of their generated electric power. "Must-take" generation
resources, such as nuclear generation,
14
electric power generated by QFs which the utilities are required to purchase
under existing contractual commitments, are also scheduled through the PX. The
utilities must then purchase all electric power for their retail customers
through the PX. Customers who buy power directly from non-regulated suppliers
pay for that generation based upon negotiated contracts. The PX sets a market
clearing price for electricity by matching all demand load bids with supply
bids ranked from lowest to highest. The highest-accepted generation supply bid
used to serve load sets the PX market clearing price for electricity.
The FERC has jurisdiction over both the ISO and the PX. In October 1997, the
FERC granted authority for the ISO and the PX to commence operations and
approved the initial structure, rates, terms and conditions applicable to the
new market structure. The ISO and PX both have made numerous tariff amendment
filings with the FERC to address issues which arose after the commencement of
ISO and PX operations. The FERC has acted on several of these filings and
several remain pending.
The ISO and PX, California public benefit non-profit corporations, each has
a Governing Board that includes representatives of investor-owned utility
transmission systems, publicly-owned utility transmission systems, non-utility
electricity sellers, public buyers and sellers, private buyers and sellers,
industrial end-users, commercial end-users, residential end-users,
agricultural end-users, public interest groups, and non-market participant
representatives. The ISO and PX currently are overseen by a five-member
Electricity Oversight Board which appoints the members of the ISO and PX
Governing Boards. However, this appointment power has been rejected by the
FERC and new bylaws for the ISO and the PX have been filed with the FERC
which, if approved by the FERC, would eliminate this role of the Electricity
Oversight Board.
Voluntary Generation Asset Divestiture
As part of the electric industry restructuring plan to promote a competitive
electric generation market, California utilities, including Pacific Gas and
Electric Company, have voluntarily begun divestiture of some of their
generation assets. On July 1, 1998, Pacific Gas and Electric Company sold
three electric generating plants with a combined capacity of 2,645 megawatts
(MW): the Morro Bay Power Plant located in San Luis Obispo County, the Moss
Landing Power Plant located in Monterey County, and the Oakland Power Plant
located in Alameda County. The aggregate sale price for these three fossil-
fueled plants was $501 million and the combined book value for these three
plants was approximately $346 million as of July 1, 1998. Pacific Gas and
Electric Company has retained liability for required environmental remediation
of any preclosing soil or groundwater contamination at these plants.
In late 1998 and in January 1999, Pacific Gas and Electric Company agreed to
sell three fossil-fueled generating facilities (the Pittsburg and Contra Costa
power plants located in Contra Costa County, and the Potrero power plant in
San Francisco) and its geothermal generating facilities (The Geysers Power
Plant located in Lake and Sonoma Counties) for a combined sale price of $1.014
billion compared to their combined book value of approximately $523 million
(as of December 31, 1998). The aggregate purchase price of the fossil-fueled
power plants is $801 million. The purchase price for the Geysers geothermal
facilities is $213 million. The sales are subject to approval by various
regulatory agencies, including the CPUC, and are conditioned upon the transfer
of various permits and licenses. The transactions are expected to close by the
first half of 1999.
Together, the seven power plants represent 91% of Pacific Gas and Electric
Company's fossil-fueled generating capacity and all of its geothermal
generating capacity. The facilities generated approximately 31% of Pacific Gas
and Electric Company's total electric energy production. The gain from the
sale of these power plants will be used to offset Pacific Gas and Electric
Company's transition costs.
As required by the California electric industry restructuring legislation,
Pacific Gas and Electric Company employees, under two-year operations and
maintenance agreements with the new owners, will continue to operate and
maintain the power plants that are sold. To the extent that payments to the
Company under these agreements exceed the Company's cost of operating the
plants, the Company would offset other transition costs. Conversely, to the
extent the Company's operating costs exceed the revenues from these
agreements, the Company would have lower earnings.
15
In May 1998, Pacific Gas and Electric Company notified the CPUC that its
non-nuclear generating facilities, including the hydroelectric facilities,
will not be retained by the Company. In July 1998, the Company reached an
agreement with the City and County of San Francisco regarding the Hunters
Point fossil-fueled power plant, which the ISO has designated as a "must run"
facility. The agreement expresses the Company's intention to retire the plant
when it is no longer needed by the ISO. In December 1998, the Company asked
the CPUC to allow it to hire appraisers to determine the market value of the
hydroelectric system. Under the Company's proposal, the Company would have the
option of accepting the appraised value and transferring the assets to another
unit of PG&E Corporation or rejecting the appraised value and auctioning the
assets. The Company expects the CPUC to issue a decision on the appraisal
process in 1999.
Direct Access
Although the restructuring legislation contemplated that direct access would
begin on January 1, 1998, the ISO and PX delayed the commencement of
operations until March 31, 1998. Customers participating in direct access may
purchase their electric power directly either through (1) competing non-
utility retail electric providers such as brokers, marketers, aggregators, or
other retailers, or (2) direct negotiated contracts with electric generators.
All customers (with limited exceptions), whether they choose direct access or
not, must pay the nonbypassable CTC, which will be collected by their
distribution utility in connection with recovery of the utilities' transition
costs. Utilities began accepting requests for direct access in November 1997
to become effective after direct access began. As of February 24, 1999,
Pacific Gas and Electric Company had transferred 53,990 customers to direct
access. The CPUC requires that electric customers with an electricity demand,
or load, of 50 kilowatts (kW) or more must have meters that are capable of
providing hourly data in order to participate in direct access. Those
customers with a load less than 50 kW may participate in direct access either
through "load profiling" or by installing an hourly meter. (Load profiling
approximates the pattern of electricity usage for a given customer class and
provides the equivalent of hourly meter reads.) The customer is responsible
for the cost of the meter and the meter installation.
Energy service providers supplying the direct access market may choose one
of three billing options: (1) consolidated energy supplier billing, under
which the utility bills the energy supplier for the services provided directly
by the utility to the customer, and the supplier, in turn, provides a
consolidated bill to the customer, (2) consolidated distribution company
billing, under which the utility places the supplier's energy charge on a
distribution bill, or (3) dual billing, under which the energy supplier and
the utility bill separately for their own services. Since January 1, 1998,
energy service providers have been allowed to provide metering services to
their customers with a demand greater than 20 kW, and beginning January 1,
1999, energy service providers may provide metering to all of their customers.
During 1998, Pacific Gas and Electric Company continued its efforts to
develop and implement changes to its business processes and systems, including
customer information and billing systems, to accommodate direct access. To the
extent the Company is unable to successfully and timely develop and implement
such changes, there could be an adverse impact on the Company's future results
of operations.
Electric Base Revenue Increase
AB 1890 provides for an increase in Pacific Gas and Electric Company's
electric base revenues for 1997 and 1998, for enhancement of transmission and
distribution system safety and reliability. The CPUC authorized a 1997 base
revenue increase of $164 million. For 1998, the CPUC authorized an additional
base revenue increase of $77 million, for a total authorized base revenue
increase for 1997 and 1998 of $406 million. The recovery of these amounts from
ratepayers is subject to a reasonableness review by the CPUC. In May 1998, the
Company filed its report on 1997 expenditures with the CPUC seeking review of
approximately $183 million for costs incurred in 1997 for safety and system
reliability enhancements, which exceeded the 1997 authorized revenue
requirement by approximately $19 million. On January 29, 1999, the ORA issued
its report on the claimed expenditures and recommended that a total of
approximately $50 million, including the $19 million amount overspent, be
disallowed, for a net recommended disallowance of $31 million. Under AB 1890,
the
16
disallowance or underspending of the 1997 revenue requirement, if adopted by
the CPUC, would be credited as an expense against the 1998 authorized revenue
requirement. To the extent that 1998 expenditures (including any amounts
carried over from 1997) exceed the 1998 authorized revenue requirement, the
amount overspent would not be recoverable from ratepayers. The Company plans
to file its report on 1998 expenditures seeking review of its 1997 and 1998
costs for safety and system reliability enhancements in March 1999.
Rate Levels and Rate Reduction Bonds
To achieve the 10% rate reduction for residential and eligible small
commercial customers, effective January 1, 1998, AB 1890 authorized utilities
to finance a portion of their transition costs with "rate reduction bonds." On
December 8, 1997, a special purpose entity established by the California
Infrastructure and Economic Development Bank issued $2.9 billion of rate
reduction bonds on behalf of a wholly owned subsidiary of Pacific Gas and
Electric Company. The bonds were issued in eight classes with maturities
ranging from 10 months to 10 years, and bearing interest at rates ranging from
5.94% to 6.48%. Pacific Gas and Electric Company is collecting a separate
nonbypassable charge on behalf of the bondholders to recover principal,
interest, and related costs over the life of the bonds from residential and
small commercial customers. The bond proceeds were used by the wholly owned
subsidiary to purchase from Pacific Gas and Electric Company the right to be
paid the revenues from this separate charge. The bonds are secured by the
future revenue from the separate charge and not by Pacific Gas and Electric
Company's assets. While the bonds are reflected as long-term debt on Pacific
Gas and Electric Company's balance sheet, creditors of Pacific Gas and
Electric Company do not have any recourse to the revenues from the separate
charge.
In November 1998, the California voters defeated a voter initiative known as
Proposition 9. If it had passed, Proposition 9 would have, among other things,
(i) required investor-owned California utilities to provide an additional 10%
rate reduction to residential and small commercial customers, (ii) eliminated
transition cost recovery for nuclear investments by utilities (other than
reasonable decommissioning costs), (iii) restricted transition cost recovery
for non-nuclear investments (other than costs associated with QFs), unless the
CPUC found that the utility would be deprived of the opportunity to earn a
fair rate of return, and (iv) prohibited the collection of any customer
charges for rate reduction bonds, or alternatively, required the utility to
offset such charges with an equal credit to customers.
Recovery of Transition Costs
Under electric industry restructuring, utilities are authorized to recover
their transition costs--the utilities' costs of their generation-related
assets and obligations which prove to be uneconomic in the new competitive
framework. Costs eligible for recovery as transition costs, as determined by
the CPUC, include (1) above-market sunk costs (sunk costs are costs associated
with utility generating facilities that are fixed and unavoidable and
currently included in customer rates), and future sunk costs, such as costs
related to plant removal; (2) costs associated with long-term contracts to
purchase power at above-market prices from QFs and other power suppliers; and
(3) generation-related regulatory assets and obligations. (In general,
regulatory assets are expenses deferred in the current or prior periods to be
included in rates in subsequent periods.) Transition costs are eligible for
recovery from all customers (with certain exceptions) through a nonbypassable
competition transition charge, or CTC, included as part of rates. Transition
costs that are disallowed by the CPUC for collection from customers will be
written off.
As a prerequisite to any consumer obtaining direct access services, the
consumer must agree to pay its applicable nonbypassable CTC. Further, nuclear
decommissioning costs are being recovered through a separate CPUC-authorized
charge. Most transition costs must be recovered by December 31, 2001, although
certain transition costs may be recovered after December 31, 2001. These costs
include certain employee-related transition costs, costs that are unrecovered
as result of the implementation of direct access and creation of the PX and
ISO, and above-market costs associated with power-purchase agreements. In
addition, costs financed by the issuance of rate reduction bonds are expected
to be recovered over the term of the bonds.
17
The total amount of sunk costs to be included as transition costs will be
based on the aggregate of above-market and below-market values of utility-
owned generation assets and obligations. Under AB 1890, valuation of
generation-related assets through appraisal or sale must be completed by
December 31, 2001. In 1997, the value of three of Pacific Gas and Electric
Company's electric facilities was established through the auction process. In
1998, the value of four of the Company's remaining power plants and its
geothermal facilities also has been established by the auction process,
subject to CPUC approval. In October 1998, the CPUC ruled that the market
value of the Hunters Point power plant is zero. In December 1998, the Company
filed an application with the CPUC requesting approval for the Company to hire
appraisers to establish a market value for the Company's hydroelectric
facilities.
In September 1997, the CPUC adopted a decision addressing transition cost
recovery for capital additions to Pacific Gas and Electric Company's non-
nuclear generating facilities. The decision allows Pacific Gas and Electric
Company to recover costs of capital additions made in 1996 and 1997 (and in
1998 for fossil-fueled plants completely divested by March 31, 1998) based
upon an after-the-fact reasonableness review. All capital additions found
reasonable by the CPUC through this process will be recoverable as transition
costs. Capital additions made in 1998 and thereafter to non-nuclear
generation-related assets, and capital additions made to fossil-fueled
generating assets which are not completely divested by March 31, 1998, must be
recovered either through revenues from the ISO agreements for "must-run"
plants or from sales of electricity to the PX. The CPUC decision allows
Pacific Gas and Electric Company to seek an after-the-fact reasonableness
review of post-1997 capital addition expenditures for collection as transition
costs in certain limited circumstances. In May 1998, the CPUC approved $53
million in 1996 non-nuclear generation capital additions as eligible for
recovery as transition costs. Further, a multiparty settlement agreement filed
with the CPUC on January 8, 1999, proposes that Pacific Gas and Electric
Company would recover approximately $128.5 million of its $133 million request
for recovery of 1997 and first quarter 1998 capital additions. A CPUC decision
on the 1997 and first quarter 1998 capital additions is expected in 1999.
In 1997, to reflect the accelerated recovery of transition costs related to
non-nuclear generation-related assets, including hydroelectric and geothermal
facilities, and for Diablo Canyon, the CPUC reduced the authorized rate of
return on common equity for these assets to 6.77%. The reduced rate of return
will be effective for the duration of the transition period.
During 1998, proceedings commenced at the CPUC to review, track, and compare
each electric utility's authorized revenue requirements with the actual
recorded revenues, and to make any necessary adjustments to reflect the
authorized revenues that are approved in other proceedings. An annual
proceeding also was established to verify the accounting and recording of
transition costs and revenues available for recovery of transition costs and
to ensure that only eligible transition costs have been entered. In this
proceeding, transition costs will receive a limited "reasonableness" review.
Public Purpose Programs
On January 1, 1998, and continuing through December 31, 2001, energy
efficiency, research and development, and low-income programs are being funded
through a separate nonbypassable charge included in frozen electric rates, in
compliance with AB 1890. Low-income programs are funded at the level of need,
but are not to be funded at less than the 1996 level of expenditures. Under
this provision of AB 1890, Pacific Gas and Electric Company is obligated to
fund through electric rates energy efficiency and conservation programs in an
amount not less than $106 million per year, public interest research and
development programs at not less than $30 million per year, renewable
technologies at not less than $48 million per year, and low-income energy
efficiency programs at not less than $14 million per year. The California
Alternative Rates for Energy (CARE) low-income discount rate, a rate subsidy
paid for by the Company's other customers, is currently about $31 million per
year.
The California Energy Commission (CEC) administers the public interest
research and development program and the renewable program. The CPUC has set
up public member boards to advise the CPUC on public purpose programs related
to energy efficiency and low-income programs. Initially, these boards also
were
18
assigned to solicit competitive bids to determine who will administer the
programs in place of the utility's interim administration. However, the CPUC
appointed Pacific Gas and Electric Company as interim administrator of energy
efficiency and low-income programs for 1999. The CPUC recently has issued a
draft decision which, if adopted, would continue the Company's interim
administration of these programs through the end of the transition period.
Additional information concerning AB 1890 and its financial impact on PG&E
Corporation is provided in "Management's Discussion and Analysis" in the 1998
Annual Report to Shareholders, beginning on page 18, and in Note 2 of the
"Notes to Consolidated Financial Statements" beginning on page 49 of the 1998
Annual Report to Shareholders.
Electric Operating Statistics
The following table shows Pacific Gas and Electric Company's operating
statistics (excluding subsidiaries except where indicated) for electric
energy, including the classification of sales and revenues by type of service.
Years Ended December 31
----------------------------------------------------------
1998 1997 1996 1995 1994
---------- ---------- ---------- ---------- ----------
Customers (average for
the year):
Residential............ 3,962,318 3,915,370 3,874,223 3,825,413 3,788,044
Commercial............. 469,136 465,461 459,001 454,718 452,049
Industrial............. 1,093 1,121 1,248 1,253 1,260
Agricultural........... 85,429 86,359 87,250 88,546 90,520
Public street and
highway lighting...... 18,351 17,955 17,583 17,089 16,709
Other electric
utilities............. 14 47 28 35 29
---------- ---------- ---------- ---------- ----------
Total............... 4,536,341 4,486,313 4,439,333 4,387,054 4,348,611
========== ========== ========== ========== ==========
Sales-kWh (in millions):
Residential............ 26,846 25,946 25,458 24,391 24,326
Commercial............. 28,839 28,887 27,868 27,014 26,195
Industrial............. 16,327 16,876 15,786 16,879 16,010
Agricultural........... 3,069 3,932 3,631 3,478 4,426
Public street and
highway lighting...... 445 446 438 425 418
Other electric
utilities............. 2,358 3,291 1,213 3,172 4,246
---------- ---------- ---------- ---------- ----------
Total energy
delivered.......... 77,884 79,378 74,394 75,359 75,621
========== ========== ========== ========== ==========
Revenues (in thousands):
Residential............ $2,891,424 $3,082,013 $3,033,613 $2,979,590 $2,980,966
Commercial............. 2,793,336 2,932,560 2,840,101 2,964,568 2,892,302
Industrial............. 933,316 1,028,378 1,005,694 1,160,938 1,128,561
Agricultural........... 350,445 413,711 396,469 395,531 477,330
Public street and
highway lighting...... 51,195 53,183 55,372 56,154 55,545
Other electric
utilities............. 50,166 118,781 81,855 133,566 201,133
---------- ---------- ---------- ---------- ----------
Revenues from energy
deliveries......... 7,069,882 7,628,626 7,413,104 7,690,347 7,735,837
Miscellaneous.......... 161,156 (9,439) 112,303 92,538 142,771
Regulatory balancing
accounts.............. (40,408) 71,441 (365,192) (396,578) 142,939
---------- ---------- ---------- ---------- ----------
Operating revenues.. $7,190,630 $7,690,628 $7,160,215 $7,386,307 $8,021,547
========== ========== ========== ========== ==========
19
The following table shows certain customer information:
Selected Statistics:
Total customers (at year-
end)....................... 4,565,000 4,500,000 4,500,000 4,400,000 4,400,000
Average annual residential
usage (kWh)................ 6,776 6,627 6,571 6,377 6,422
Average billed revenues per
kWh (cents per kWh):
Residential............... 10.77 11.88 11.92 12.22 12.25
Commercial................ 9.69 10.15 10.19 10.97 11.04
Industrial................ 5.72 6.09 6.37 6.88 7.05
Agricultural................ 11.42 10.52 10.92 11.37 10.78
Net plant investment per
customer ($)............... 2,705 3,027 3,198 3,228 3,362
Electric Generating Capacity
As described above in "Implementation of Electric Industry Restructuring--
Voluntary Generation Asset Divestiture," in 1998, Pacific Gas and Electric
Company sold three fossil-fueled power plants and entered into agreements for
the sale of an additional four fossil-fueled power plants and its geothermal
facilities. Except as otherwise noted below, as of December 31, 1998, Pacific
Gas and Electric Company owned and operated the following generating plants,
all located in California, listed by energy source:
Net
Number Operating
of Capacity
Generation Type County Location Units kW
--------------- --------------- ------ ----------
Hydroelectric:
Conventional Plants.............. 16 counties in Northern and
Central California 109 2,698,100
Helms Pumped Storage Plant....... Fresno 3 1,212,000
--- ----------
Hydroelectric Subtotal......... 112 3,910,100
--- ----------
Steam Plants:
Contra Costa(1).................. Contra Costa 2 680,000
Humboldt Bay..................... Humboldt 2 105,000
Hunters Point.................... San Francisco 3 377,000
Pittsburg(1)..................... Contra Costa 7 2,022,000
Potrero(1)....................... San Francisco 1 207,000
--- ----------
Steam Subtotal................... 15 3,391,000
--- ----------
Combustion Turbines:
Hunters Point.................... San Francisco 1 52,000
Potrero(1)....................... San Francisco 3 156,000
Mobile Turbines(2)............... Humboldt and Mendocino 3 45,000
--- ----------
Combustion Turbines Subtotal..... 7 253,000
--- ----------
Geothermal:
The Geysers Power Plant(1)(3).... Sonoma and Lake 14 1,224,000
Nuclear:
Diablo Canyon.................... San Luis Obispo 2 2,160,000
--- ----------
Thermal Subtotal............... 38 7,028,000
--- ----------
Total......................... 150 10,938,100
=== ==========
- --------
(1) In 1998, Pacific Gas and Electric Company entered into agreements to sell
these power plants and its geothermal facilities in connection with
electric industry restructuring.
(2) Listed to show capability; subject to relocation within the system as
required.
(3) The Geysers Power Plant net operating capacity is based on adequate
geothermal steam supply conditions. (Present steam conditions prevent the
units from operating at full operating capacity.)
20
Diablo Canyon
Diablo Canyon Operations
Diablo Canyon consists of two nuclear power reactor units, each capable of
generating up to approximately 26 million kilowatt-hours (kWh) of electricity
per day. Diablo Canyon Units 1 and 2 began commercial operation in May 1985
and March 1986, respectively. The operating license expiration dates for
Diablo Canyon Units 1 and 2 are September 2021 and April 2025, respectively.
As of December 31, 1998, Diablo Canyon Units 1 and 2 had achieved lifetime
capacity factors of 81.4% and 82.9%, respectively.
The table below outlines Diablo Canyon's refueling schedule for the next
five years. Diablo Canyon refueling outages typically are scheduled every 19
to 21 months. Pacific Gas and Electric Company has been seeking NRC licensing
authority to schedule such outages once every 24 months. Though nominal 20-
month cycles are firm, achieving a 24-month cycle is uncertain and its
implementation could be delayed. The schedule below assumes that a refueling
outage for a unit will last approximately five weeks, depending on the scope
of the work required for a particular outage. The schedule is subject to
change in the event of unscheduled plant outages or changes in the length of
the fuel cycle.
1999 2000 2001 2002 2003
-------- -------- ---- ---- --------
Unit 1
Refueling............................ February October May
Startup.............................. March November June
Unit 2
Refueling............................ October May February
Startup.............................. November June March
Diablo Canyon Ratemaking
Effective January 1, 1997, Pacific Gas and Electric Company's sunk costs in
Diablo Canyon are recovered from ratepayers through a sunk cost revenue
requirement, at a reduced return on common equity equal to 6.77% that will
remain in effect through the end of the transition period. (Sunk costs are
costs associated with the facility that are fixed and unavoidable and
currently included in customers' electric rates.) Also effective January 1,
1997, a performance-based Incremental Cost Incentive Price (ICIP) mechanism
was established to recover Diablo Canyon's variable and other operating costs
and capital addition costs. The ICIP mechanism establishes a rate per kWh
generated by the facility. This rate is based upon a fixed forecast of ongoing
costs, capital additions, and capacity factors for the period 1997 through
2001. The fixed forecast of ICIP for 1999-2001 is shown below. The revenues
are based on an assumed capacity factor of 83.6%.
Incremental Cost Incentive Prices and Estimated
Total CPUC Revenue Requirement
Estimated Total
Revenue Requirement
--------------------
1999 2000 2001
------ ------ ------
ICIP (cents per kWh)................................. 3.37 3.43 3.49
Sunk Cost Recovery ($ in millions)................... $1,259 $1,197 $1,135
ICIP Revenues ($ in millions)........................ 532 542 552
------ ------ ------
Total Revenue Requirement ($ in millions)............ $1,791 $1,739 $1,687
The CPUC decision adopting the ratemaking mechanism excluded several items
totaling $160 million from the sunk cost revenue requirement, including out-
of-core fuel inventory, materials and supplies inventory, and prepaid
insurance expenses. The CPUC decision requires that the costs of materials,
supplies, and nuclear fuel be recovered through the ICIP mechanism as these
items are used. The CPUC also disallowed about $70 million in plant costs from
the sunk cost revenue requirement.
21
The CPUC decision also ordered that a financial verification audit of Diablo
Canyon plant accounts be performed by an independent accounting firm, and that
the CPUC hold a proceeding to review the results of the audit, including any
proposed adjustments to Diablo Canyon accounts, following the completion of
the audit. On August 31, 1998, an independent accounting firm retained by the
CPUC completed its financial verification audit of Diablo Canyon plant
accounts at December 31, 1996. The audit resulted in the issuance of an
unqualified opinion. The audit verified that Diablo Canyon sunk costs at
December 31, 1996, were $3.3 billion of the total $7.1 billion construction
costs. The independent accounting firm also issued an agreed-upon special
procedures report, requested by the CPUC, which questioned $200 million of the
$3.3 billion sunk costs. The CPUC will review the results of the audit and may
seek to make adjustments to Diablo Canyon sunk costs subject to transition
cost recovery. At this time, the amount of transition cost disallowances, if
any, cannot be predicted.
Additional information concerning the financial impact of Diablo Canyon
ratemaking is included in "Management's Discussion and Analysis" in the 1998
Annual Report to Shareholders, beginning on page 18, and in Note 2 of the
"Notes to Consolidated Financial Statements" beginning on page 49 of the 1998
Annual Report to Shareholders.
Nuclear Fuel Supply and Disposal
Pacific Gas and Electric Company has purchase contracts for, and inventories
of, uranium concentrates, uranium hexaflouride, and enriched uranium, as well
as one contract for fuel fabrication. Based on current operations forecasts,
Diablo Canyon's requirements for uranium supply, the conversion of uranium to
uranium hexaflouride, and the enrichment of the uranium hexaflouride to
enriched uranium will be satisfied by a combination of existing contracts and
inventories through 2002, 2000, and 2002, respectively. The fuel fabrication
contract for the two units will supply their requirements for the next seven
operating cycles of each unit. These contracts are intended to ensure long-
term fuel supply, but permit Pacific Gas and Electric Company the flexibility
to take advantage of short-term supply opportunities. In most cases, Pacific
Gas and Electric Company's nuclear fuel contracts are requirements-based, with
the Company's obligations linked to the continued operation of Diablo Canyon.
Under the Nuclear Waste Policy Act of 1982 (Nuclear Waste Act), the U.S.
Department of Energy (DOE) is responsible for the transportation and ultimate
long-term disposal of spent nuclear fuel and high-level radioactive waste.
Under the Nuclear Waste Act, utilities are required to provide interim storage
facilities until permanent storage facilities are provided by the federal
government. The Nuclear Waste Act mandates that one or more such permanent
disposal sites be in operation by 1998. Consistent with the law, Pacific Gas
and Electric Company signed a contract with the DOE providing for the disposal
of the spent nuclear fuel and high-level radioactive waste from the Company's
nuclear power facilities beginning not later than January 1998. However, due
to delays in identifying a storage site, the DOE has been unable to meet its
contract commitment to begin accepting spent fuel by January 1998. Further,
under the DOE's current estimated acceptance schedule for spent fuel, Diablo
Canyon's spent fuel may not be accepted by the DOE for interim or permanent
storage before 2010, at the earliest. At the projected level of operation for
Diablo Canyon, Pacific Gas and Electric Company's facilities are sufficient to
store on-site all spent fuel produced through approximately 2006 while
maintaining the capability for a full-core off-load. It is likely that an
interim or permanent DOE storage facility will not be available for Diablo
Canyon's spent fuel by 2006. Pacific Gas and Electric Company is examining
options for providing additional temporary spent fuel storage at Diablo Canyon
or other facilities, pending disposal or storage at a DOE facility.
In July 1988, the NRC gave final approval to Pacific Gas and Electric
Company's plan to store radioactive waste from the nuclear generating unit
(Unit 3) at Humboldt Bay Power Plant (Humboldt) at Humboldt prior to
ultimately decommissioning the unit. The Company has agreed to remove all
spent fuel when the federal disposal site is available.
22
Insurance
Pacific Gas and Electric Company has insurance coverage for property damage
and business interruption losses as a member of Nuclear Electric Insurance
Limited (NEIL). NEIL, which is owned by utilities with nuclear generating
facilities, provides insurance coverage against property damage,
decontamination, decommissioning, and business interruption and/or extra
expenses during prolonged accidental outages for reactor units in commercial
operation. Under these insurance policies, if the nuclear generating facility
of a member utility suffers a loss due to a prolonged accidental outage, the
Company may be subject to maximum retrospective premium assessments of $17
million (property damage) and $5 million (business interruption), in each case
per one-year policy period, if losses exceed the resources of NEIL.
Pacific Gas and Electric Company has purchased primary insurance of $200
million for public liability claims resulting from a nuclear incident. An
additional $9.6 billion of coverage is provided by secondary financial
protection required by federal law and provides for loss sharing among
utilities owning nuclear generating facilities if a costly incident occurs. If
a nuclear incident results in claims in excess of $200 million, Pacific Gas
and Electric Company may be assessed up to $176 million per incident, with
payments in each year limited to a maximum of $20 million per incident.
Decommissioning
Pacific Gas and Electric Company's estimated total obligation to
decommission and dismantle its nuclear power facilities is $1.5 billion in
1998 dollars ($5.1 billion in future dollars). This estimate, which includes
labor, materials, waste disposal charges, and other costs, is based on a 1997
decommissioning cost study. A contingency to capture engineering, regulatory,
and business environment changes is included in the total estimated
obligation. Actual decommissioning costs are expected to vary from this
estimate because of changes in the assumed dates of decommissioning,
regulatory requirements, and technology, as well as differences in the amount
of labor, materials, and equipment needed to complete decommissioning. The
estimated total obligation needed to complete decommissioning is recognized
proportionately over the license term of each facility.
Nuclear decommissioning costs recovered in rates are placed in external
trust funds. These funds, along with accumulated earnings, will be used
exclusively for decommissioning and dismantling the nuclear facilities. The
trust funds maintain substantially all of their investments in debt and equity
securities. All earnings on the trust fund, net of authorized disbursements
from the trusts and management and administrative fees, are reinvested. Monies
may not be released from the external trust funds until authorized by the
CPUC. In December 1997, the CPUC granted Pacific Gas and Electric Company's
request for authority to disburse up to $15.7 million from the Humboldt Bay
Power Plant decommissioning trust funds to finance three partial nuclear
decommissioning projects at Humboldt Bay Power Plant Unit 3. Accordingly, as
of December 31, 1998, $7.2 million (net of taxes) was disbursed from the
Humboldt Bay Power Plant Unit 3 non-tax-qualified trust to reimburse the
Company for nuclear decommissioning expenses associated with the partial
decommissioning projects.
In its 1999 GRC, Pacific Gas and Electric Company is seeking approval from
the CPUC to use the tax savings resulting from the payment of tax-deductible
nuclear decommissioning expenses from the Humboldt Bay Power Plant Unit 3 non-
tax-qualified trust to fund nuclear decommissioning work. If the CPUC rejects
the Company's request, an additional $4.9 million will be disbursed from the
trust to reimburse the Company for the full amount of the 1998 nuclear
decommissioning expenses of $12.1 million. A mechanism to flow the realized
tax savings of $4.9 million associated with $12.1 million tax-deductible
nuclear decommissioning expenses to ratepayers will be established.
As of December 31, 1998, Pacific Gas and Electric Company had accumulated
external trust funds with an estimated fair value of $1.2 billion, based on
quoted market prices and net of deferred taxes on unrealized gains, to be used
for the decommissioning of the Company's nuclear facilities.
The amount recovered in rates for nuclear decommissioning costs is
authorized by the CPUC as part of the GRC. The CPUC considers the trusts'
asset levels, together with revised earnings and decommissioning cost
23
assumptions, to determine the amount of decommissioning costs it will
authorize in rates for contribution to the trusts. The monies contributed to
the decommissioning trusts, together with existing trust fund balances and
projected earnings, are intended to satisfy the estimated future obligation
for decommissioning costs. For the year ended December 31, 1998, nuclear
decommissioning costs recovered in rates were $33 million.
Beginning January 1, 1998, nuclear decommissioning costs, which are not
transition costs, were being recovered through a nonbypassable charge which
will continue until those costs are fully recovered. Recovery of
decommissioning costs may be accelerated to the extent possible under the rate
freeze. The CPUC has established a Nuclear Decommissioning Costs Triennial
Proceeding to determine the decommissioning costs and to establish the annual
revenue requirement and attrition factors over subsequent three-year periods
when and if GRCs are discontinued.
Other Electric Resources
QF Generation and Other Power-Purchase Contracts
By federal law, Pacific Gas and Electric Company is required to purchase
electric energy and capacity provided by independent power producers. The CPUC
established a series of power-purchase contracts and set the applicable terms,
conditions, price options, and eligibility requirements.
Under these contracts, Pacific Gas and Electric Company is required to make
payments only when energy is supplied or when capacity commitments are met.
The total cost of these payments is recoverable in rates. Pacific Gas and
Electric Company's contracts with these power producers expire on various
dates through 2028. Total energy payments are expected to decline in the years
1999 through 2001. Total capacity payments are expected to remain at current
levels during this period. Deliveries from these power producers account for
approximately 23% of Pacific Gas and Electric Company's 1998 electric energy
requirements and no single contract accounted for more than 5% of the
Company's energy needs.
Pacific Gas and Electric Company has negotiated early termination or
suspension of certain power-purchase contracts. These amounts are expected to
be recovered in rates and as such are reflected as deferred charges on the
Company's balance sheet. At December 31, 1998, the total discounted future
payments remaining under early termination or suspension contracts is $48
million.
Pacific Gas and Electric Company also has contracts with various irrigation
districts and water agencies to purchase hydroelectric power. Under these
contracts, the Company must make specified semi-annual minimum payments
whether or not any energy is supplied (subject to the provider's retention of
the FERC's authorization) and variable payments for operation and maintenance
costs incurred by the suppliers. These contracts expire on various dates from
2004 to 2031. The total cost of these payments is recoverable in rates. At
December 31, 1998, the undiscounted future minimum payments under these
contracts are $32 million for each of the years 1999 through 2003 and a total
of $280 million for periods thereafter. Irrigation district and water agency
deliveries in the aggregate account for approximately 7.5% of Pacific Gas and
Electric Company's 1998 electric energy requirements.
The amount of energy received and the total payments made under all these
power-purchase contracts were:
1998 1997 1996
------ ------ ------
(in millions)
Kilowatt-hours received.............................. 25,994 24,389 26,056
Energy payments...................................... $ 943 $1,157 $1,136
Capacity payments.................................... $ 529 $ 538 $ 521
Irrigation district and water agency payments........ $ 53 $ 56 $ 52
As of December 31, 1998, Pacific Gas and Electric Company had commitments to
purchase approximately 5,200 MW of capacity under CPUC-mandated power-purchase
agreements. Of the 5,200 MW, approximately
24
4,400 MW were operational. Development of the majority of the balance is
uncertain and it is estimated that very few of the remaining contracts will
become operational. The 4,400 MW of operational capacity consists of 2,800 MW
from cogeneration projects, 600 MW from wind projects, and 1,000 MW from other
projects, including biomass, waste-to-energy, geothermal, solar, and
hydroelectric.
Geothermal Generation
In late 1998 and January 1999, Pacific Gas and Electric Company entered into
agreements to sell its geothermal units at The Geysers Power Plant located in
Lake and Sonoma counties (Geysers) for a total of $213 million. The sale is
subject to final approval by the CPUC and other regulatory agencies, and the
transaction is expected to close by the first half of 1999. See "Electric
Utility Operations--Implementation of Electric Industry Restructuring--
Voluntary Generation Asset Divestiture" above.
The Geysers are forecast to operate at reduced capacities because of
declining geothermal steam supplies and curtailment of the Geysers due to the
existence of more economic sources of electric generation. The Company's
agreements with several of its steam suppliers permit the Company to curtail
generation at the Geysers at the Company's discretion. The 1999 consolidated
Geysers capacity factor through the expected close of sale is forecast to be
approximately 38% of installed capacity in 1999, which includes economic
curtailments, forced outages, scheduled overhauls, and projected steam
shortage curtailments, as compared to the actual Geysers capacity factor of
44% in 1998.
Electric Transmission and Distribution
To transport energy to load centers, Pacific Gas and Electric Company as of
December 31, 1998, owned and operated approximately 18,624 circuit miles of
interconnected transmission lines of 60 kilovolts (kV) to 500 kV and
transmission substations having a capacity of approximately 39,565,906
kilovolt-amperes (kVa), including spares, excluding power plant
interconnection facilities. Energy is distributed to customers through
approximately 112,080 circuit miles of distribution system and distribution
substations having a capacity of approximately 23,575,800 kVa.
In 1998, the utilities relinquished control, but not ownership, of their
transmission facilities to the ISO. The ISO commenced operations on March 31,
1998. The ISO, regulated by the FERC, controls the operation of the
transmission system and provides open access transmission service on a
nondiscriminatory basis. In 1998, the FERC approved the various forms of
agreements for must-run facilities that have been entered into between the
utilities and the ISO to ensure grid reliability.
The FERC has also approved a proposal from Pacific Gas and Electric Company
and the other California utilities that distinguishes between local
distribution facilities and transmission facilities. The order defines
jurisdiction for the CPUC over local distribution and retail power customers.
The FERC will have jurisdiction over the transmission facilities as defined in
the order and over the transmission aspects of retail direct access. Most of
Pacific Gas and Electric Company's distribution services will remain subject
to CPUC jurisdiction.
On December 17, 1998, the CPUC opened a rulemaking proceeding to consider
whether it should pursue further reforms in the structure and regulatory
framework governing electricity distribution service. The CPUC will solicit
comments and proposals regarding the scope and substance of issues, possible
policy options, and procedural steps the CPUC could pursue in considering
distributed generation and competition in electric distribution service. The
rulemaking was opened, in part, in response to a request from Pacific Gas and
Electric Company for a comprehensive review of distribution competition.
Initial comments are due to the CPUC on March 17, 1999.
On December 8, 1998, Pacific Gas and Electric Company lost power on all its
115 kV transmission lines from the San Mateo Substation to San Francisco, and
the two San Francisco power plants tripped off line, leaving more than 456,000
customers without power. The Company immediately notified the ISO of the
outage. Only the approximately 13,000 customers served from the 230 kV
transmission line maintained power. Six hours later, the Company had restored
service to all but 27,000 customers. Within the next two hours, all customers
had power.
25
Pacific Gas and Electric Company immediately began an internal investigation
of the outage. On December 17, 1998, the CPUC issued an Order Instituting
Investigation concerning the power outage. The order required Pacific Gas and
Electric Company to file a report by January 25, 1999 to address various
issues arising from the outage, including chronology, cause, response,
mitigation, prevention, and handling of claims.
On January 25, 1999, the Company completed its internal investigation and
filed a report with the CPUC detailing the results of its investigation. The
Company's internal investigation confirmed that the outage resulted when a
construction crew working on an equipment upgrade project at the San Mateo
Substation failed to follow established procedures and practices, and failed
to remove temporary protective grounds. Separately, a transmission operator at
the substation then energized the substation bus, but failed to engage the
protective relays associated with the bus. (A "bus" refers to a collection
point for connecting transmission lines and flowing power out from a
substation.) Without the local protective system in place, the electric
current was sent to ground, and the system took a half second to isolate the
fault instead of the one-tenth of a second that would normally be required.
This delay resulted in a sharp drop in transmission line voltages, and the
transmission system into San Francisco then experienced large power
fluctuations. As they are designed to do, protective systems at other
substations and at the Hunters Point and Potrero power plants separated from
the transmission system to make sure that the fluctuations did not extend to
other parts of the Company's system, and that no damage occurred to equipment
in San Francisco's electric facilities that could have delayed restoration of
operations.
Pacific Gas and Electric Company is taking actions to strengthen and adjust
its grounding and switching procedures as preventative measures to minimize
the risk that such an initiating event could occur in the future. The
Company's internal investigation found that the transmission system design is
consistent with the requirements of the North American Electric Reliability
Council and the Western Systems Coordinating Council, and performed as
designed given the initiating event that occurred. As a result of this
finding, the Company is not proposing modifications to the system design.
Finally, the Company and the ISO are using the lessons learned in this event
to strengthen their communications.
Gas Utility Operations
Pacific Gas and Electric Company owns and operates an integrated gas
transmission, storage, and distribution system in California. At December 31,
1998, Pacific Gas and Electric Company's system, including the PG&E Expansion
(Line 401), consisted of approximately 5,706 miles of transmission pipelines,
three gas storage facilities, and approximately 37,023 miles of gas
distribution lines.
Pacific Gas and Electric Company's peak day send-out of gas on its
integrated system in California during the year ended December 31, 1998, was
4,300 million cubic feet (MMcf). The total volume of gas throughput during
1998 was approximately 850,000 MMcf, of which 295,000 MMcf was sold to direct
end-use or resale customers, 158,000 MMcf was used by Pacific Gas and Electric
Company primarily for its fossil-fueled electric generating plants, and
397,000 MMcf was transported as customer-owned gas.
The California Gas Report, which presents the outlook for natural gas
requirements and supplies for California over a long-term planning horizon, is
prepared annually by the California electric and gas utilities as a result of
a CPUC order. A comprehensive biennial report is prepared in even-numbered
years with a supplemental report in intervening odd-numbered years.
The 1998 California Gas Report updates Pacific Gas and Electric Company's
annual gas requirements forecast (excluding bypass volumes) for the years 1998
through 2015, forecasting average annual growth in gas throughput served by
the Company of approximately 1%. The gas requirements forecast is subject to
many uncertainties and there are many factors that can influence the demand
for natural gas, including weather conditions, level of utility electric
generation, fuel switching, and new technology. In addition, some large
customers, mostly in the industrial and enhanced oil recovery sectors, may
have the ability to use unregulated private pipelines or interstate pipelines,
bypassing the Company's system entirely. The 1998 California Gas Report
forecasts a total bypass volume of 133,600 MMcf for 1999.
26
Gas Operating Statistics
The following table shows Pacific Gas and Electric Company's operating
statistics (excluding subsidiaries except where indicated) for gas, including
the classification of sales and revenues by type of service.
Years Ended December 31
----------------------------------------------------------
1998 1997 1996 1995 1994
---------- ---------- ---------- ---------- ----------
Customers (average for
the year):
Residential............ 3,536,089 3,491,963 3,455,086 3,417,556 3,372,768
Commercial............. 200,620 198,453 198,071 197,939 196,509
Industrial............. 1,610 1,650 1,500 1,500 1,400
Other gas utilities.... 5 3 2 2 2
---------- ---------- ---------- ---------- ----------
Total.............. 3,738,324 3,692,069 3,654,659 3,616,997 3,570,679
========== ========== ========== ========== ==========
Gas supply--thousand
cubic feet (Mcf) (in
thousands):
Purchased from
suppliers in:
Canada............... 298,125 280,084 253,209 261,800 319,453
California........... 17,724 10,655 28,130 31,158 31,757
Other states......... 122,342 131,074 110,604 117,538 249,733
---------- ---------- ---------- ---------- ----------
Total purchased.... 438,191 421,813 391,943 410,496 600,943
Net from storage (to
storage).............. 14,468 14,160 6,871 (10,921) 3,591
---------- ---------- ---------- ---------- ----------
Total.............. 452,659 435,973 398,814 399,575 604,534
Pacific Gas and
Electric Company use,
losses, etc.(1)....... 158,241 173,789 134,375 129,671 297,604
---------- ---------- ---------- ---------- ----------
Net gas for sales.. 294,418 262,184 264,439 269,904 306,930
========== ========== ========== ========== ==========
Bundled gas sales and
transportation
service--Mcf (in
thousands):
Residential............ 223,706 191,327 190,246 191,724 214,358
Commercial............. 66,082 60,803 62,178 64,135 72,183
Industrial............. 4,616 10,054 12,015 14,045 19,495
Other gas utilities.... 14 0 0 0 894
---------- ---------- ---------- ---------- ----------
Total.............. 294,418 262,184 264,439 269,904 306,930
========== ========== ========== ========== ==========
Transportation service
only--Mcf (in
thousands):
Vintage system
(Substantially all
Industrial)(2)........ 319,099 218,660 189,695 143,921 142,393
PG&E Expansion (Line
401).................. 77,773 233,269 237,776 240,506 200,755
---------- ---------- ---------- ---------- ----------
Total.............. 396,872 451,929 427,471 384,427 343,148
========== ========== ========== ========== ==========
Revenues (in thousands):
Bundled gas sales and
transportation
service:
Residential.......... $1,414,313 $1,170,135 $1,109,463 $1,205,223 $1,268,966
Commercial........... 426,299 374,084 362,819 421,397 444,805
Industrial........... 24,634 46,592 42,520 42,106 57,297
Other gas utilities.. 1,072 3,701 510 0 2,371
---------- ---------- ---------- ---------- ----------
Bundled gas
revenues.......... 1,866,318 1,594,512 1,515,312 1,668,726 1,773,439
Transportation only
revenue:
Vintage system
(Substantially all
Industrial)......... 232,038 207,160 180,197 167,325 132,509
PG&E Expansion (Line
401)................ 42,194 90,180 85,144 82,904 58,442
---------- ---------- ---------- ---------- ----------
Transportation service
only revenue.......... 274,232 297,340 265,341 250,229 190,951
Miscellaneous.......... 41,364 50,295 (9,271) (18,018) 40,427
Regulatory balancing
accounts.............. (448,351) (137,787) 57,864 (43,771) (101,443)
Subsidiaries(3)........ 0 0 210,556 201,951 177,688
---------- ---------- ---------- ---------- ----------
Operating
revenues.......... $1,733,563 $1,804,360 $2,039,802 $2,059,117 $2,081,062
========== ========== ========== ========== ==========
- --------
(1) Primarily includes fuel for Pacific Gas and Electric Company's fossil-
fueled generating plants.
(2) Does not include on-system transportation volumes transported on the PG&E
Expansion of 34,169 MMcf, 72,958 MMcf, 78,552 MMcf, 100,207 MMcf, and
79,749 MMcf, for 1998, 1997, 1996, 1995, and 1994, respectively.
(3) In January 1997, a Pacific Gas and Electric Company subsidiary--Pacific
Gas Transmission Company (PGT)--became a subsidiary of PG&E Corporation
and is now known as PG&E Gas Transmission, Northwest Corporation.
27
Years Ended December 31
-------------------------------------------------
1998 1997 1996 1995 1994
--------- --------- --------- --------- ---------
Selected Statistics:
Total customers (at year-
end)....................... 3,766,000 3,700,000 3,700,000 3,600,000 3,500,000
Average annual residential
usage (Mcf)................ 63 55 55 56 64
Heating temperature--% of
normal(1).................. 93.0 71.7 75.7 75.3 104.4
Average billed bundled gas
sales revenues per Mcf:
Residential................. $6.32 $6.12 $5.83 $6.29 $5.92
Commercial.................. 6.45 6.15 5.84 6.57 6.16
Industrial.................. 5.36 4.63 3.54 3.00 2.94
Average billed
transportation only revenue
per Mcf:
Vintage system.............. 0.66 0.71 0.67 0.69 0.60
PG&E Expansion (Line 401)... 0.54 0.39 0.36 0.34 0.29
Net plant investment per
customer (2)............... $1,040 $1,031 $1,378 $1,315 $1,340
- --------
(1) Over 100% indicates colder than normal.
(2) The net plant investment per customer figures for 1997 and 1998 are lower
than in previous years because they exclude subsidiaries.
Natural Gas Supplies
The objective of Pacific Gas and Electric Company's gas supply planning is
to maintain a balanced supply portfolio which provides supply reliability and
contract flexibility, minimizes costs, and fosters competition among
suppliers.
Under current CPUC regulations, Pacific Gas and Electric Company purchases
natural gas from its various suppliers based on economic considerations,
consistent with regulatory, contractual, and operational constraints. During
the year ended December 31, 1998, approximately 68% of the Company's total
purchases of natural gas consisted of Canadian gas purchased from various
Canadian producers and transported by Canadian pipeline companies and PG&E Gas
Transmission, Northwest Corporation; approximately 4% was purchased in
California; and approximately 28% was purchased in the U.S. Southwest and
transported by the El Paso Natural Gas Company or Transwestern Pipeline
Company pipelines. California purchases include both purchases from various
California producers and purchases of gas transported to California by others.
The following table shows the total volume and average price of gas in dollars
per thousand cubic feet (Mcf) purchased by Pacific Gas and Electric Company
from these sources during each of the last five years.
Years Ended December 31
----------------------------------------------------------------------------------------------
1998 1997 1996 1995 1994
------------------ ------------------ ------------------ ------------------ ------------------
Thousands Avg. Thousands Avg. Thousands Avg. Thousands Avg. Thousands Avg.
of Mcf Price(1) of Mcf Price(1) of Mcf Price(1) of Mcf Price(1) of Mcf Price(1)
--------- -------- --------- -------- --------- -------- --------- -------- --------- --------
Canada................. 298,125 $2.00 280,084 $1.77 253,209 $1.57 261,800 $1.34 319,453 $1.94
California............. 17,724 2.44 10,655 2.12 28,130 1.90 31,158 1.32 31,757 1.55
Other states...........
(substantially all
U.S Southwest)....... 122,342 2.62 131,074 3.75 110,604 3.72 117,538 2.64 249,733 2.41
------- ----- ------- ----- ------- ----- ------- ----- ------- -----
Total/Weighted
Average............... 438,191 $2.19 421,813 $2.39 391,943 $2.21 410,496 $1.71 600,943 $2.12
======= ===== ======= ===== ======= ===== ======= ===== ======= =====
- --------
(1) The average prices for Canadian and U.S. Southwest gas include the
commodity gas prices, interstate pipeline demand or reservation charges,
transportation charges, and other pipeline assessments, including direct
bills allocated over the quantities received at the California border.
Beginning March 1, 1998, the average price for gas also includes
intrastate pipeline demand and reservation charges. These costs were
previously bundled in gas rates.
Gas Regulatory Framework
In August 1997, the CPUC approved the Gas Accord which restructures Pacific
Gas and Electric Company's gas services and its role in the gas market. As
discussed above (see "General--Competition and the Changing Regulatory
Environment--Gas Industry"), the Gas Accord separates, or "unbundles," the
rates for Pacific Gas
28
and Electric Company's gas transmission services from its distribution
services, increases the opportunities for core customers to purchase gas from
competing suppliers, establishes a form of incentive regulation to measure the
reasonableness of core procurement costs, and establishes gas transmission and
storage rates from March 1998 through December 2002. The Gas Accord also
settled various issues pending in certain regulatory proceedings.
The CPUC is considering further changes in California's natural gas
industry. See "General--Competition and the Changing Regulatory Environment--
Gas Industry" above.
Transportation Commitments
Pacific Gas and Electric Company has gas transportation service agreements
with various Canadian and interstate pipeline companies. These agreements
include provisions for payment of fixed demand charges for reserving firm
capacity on the pipelines. The total demand charges that Pacific Gas and
Electric Company will pay each year may change due to changes in tariff rates.
The total demand and volumetric transportation charges paid by Pacific Gas and
Electric Company under these agreements were approximately $113 million in
1998. This amount includes payments made to PG&E Gas Transmission,
Northwest Corporation (PG&E GT-Northwest) of approximately $49 million in
1998, but which are eliminated in the consolidated financial statements of
PG&E Corporation.
As a result of regulatory changes, Pacific Gas and Electric Company no
longer procures gas for most of its noncore customers, resulting in a decrease
in the Company's need for firm transportation capacity for its gas purchases.
Pacific Gas and Electric Company continues to procure gas for almost all of
its core customers and those noncore customers who choose bundled service
(core subscription customers). Pacific Gas and Electric Company is continuing
its efforts to broker or assign any of its remaining contracted-for but unused
interstate transportation capacity, including unused capacity held for its
core and core subscription customers.
Under a firm transportation agreement with PG&E GT-Northwest that runs
through October 31, 2005, Pacific Gas and Electric Company currently retains
approximately 600 million cubic feet per day (MMcf/d) on the PG&E GT-Northwest
system to support its core and core subscription customers. The Company has
been able to broker its unused capacity on PG&E GT-Northwest's system, when
not needed for core and core subscription customers.
In general, any shortfall resulting from the difference between the fixed
demand charges Pacific Gas and Electric Company pays under gas transportation
contracts with interstate pipeline companies for the reservation of interstate
pipeline capacity that the Company no longer uses to serve noncore customers,
and the revenues Pacific Gas and Electric Company obtains from brokering that
capacity, is eligible for rate recovery through the Interstate Transition Cost
Surcharge (ITCS), subject to a reasonableness review. Various groups had
challenged Pacific Gas and Electric Company's recovery of these amounts,
including amounts which arose in connection with firm transportation
commitments that the Company had entered into with PG&E GT-Northwest and El
Paso Natural Gas Company (El Paso). (The agreement with El Paso terminated as
of December 31, 1997.) Under the Gas Accord, these challenges were resolved
through Pacific Gas and Electric Company's agreement to forgo recovery of 100
percent and 50 percent of the ITCS amounts allocated for collection from its
core and noncore customers, respectively.
In 1992, Pacific Gas and Electric Company entered into a firm transportation
agreement with Transwestern Pipeline Company (Transwestern), which expires in
2007, to meet core gas sales demands and electric generation needs. The demand
charges associated with the entire Transwestern capacity are currently
approximately $26 million per year. Pacific Gas and Electric Company was not
permitted to include any Transwestern firm capacity demand charges in rates or
in the ITCS account, although the Company was authorized to record costs
associated with its Transwestern capacity in a balancing account, with
recovery of such costs subject to reasonableness review proceedings. In 1995,
the CPUC determined that it was unreasonable for Pacific Gas and Electric
Company to commit to transportation capacity with Transwestern and disallowed
recovery of the costs
29
of capacity for 1992. It indicated that it would disallow costs through the
term of the contract unless Pacific Gas and Electric Company could demonstrate
on an annual basis that the benefit of the commitment outweighed the costs in
a particular year. As part of the Gas Accord, Pacific Gas and Electric Company
agreed to resolve this issue by forgoing the recovery of costs associated with
capacity originally subscribed to in order to serve core customers through
1997 and to limit its recovery of demand charges through the CPIM during the
period 1998 through 2002.
Core Procurement Incentive Mechanism
Pacific Gas and Electric Company's core gas procurement costs for the period
June 1994 to 2002 are recoverable under a core procurement incentive mechanism
(CPIM), a form of incentive regulation established by the Gas Accord. The CPIM
provides the Company with a direct financial incentive to procure gas and
transportation services at the lowest reasonable costs by comparing all
procurement costs to an aggregate market-based benchmark. If costs fall within
a range (tolerance band) around the benchmark, costs are deemed reasonable and
fully recoverable from ratepayers. If procurement costs fall outside the
tolerance band, the Company's ratepayers and shareholders share savings or
costs, respectively. In January 1999, the Company filed a performance report
with the ORA of the CPUC, recommending a shareholder award of $190,766, for
the period January 1, 1998 through October 31, 1998. During 1998, the Company
submitted a similar report to the ORA for its January 1997 through December
1997 performance, recommending a shareholder award of approximately $1.8
million. After ORA comments on the Company's performance reports, the Company
will seek CPUC approval for all gas procurement costs for both periods,
including the Company's shareholder awards.
PGT/Pacific Gas and Electric Company Pipeline Expansion
In November 1993, PG&E GT-Northwest (then known as Pacific Gas Transmission
Company or PGT) and Pacific Gas and Electric Company placed in service the
Pipeline Expansion, an expansion of their interconnected natural gas
transmission systems from the Canadian border into California. The 840-mile
combined Pipeline Expansion provides an additional 148 MMcf/d of firm capacity
to the Pacific Northwest and an additional 851 MMcf/d of capacity to Northern
and Southern California.
The conditions of the CPUC's approval of the construction of Pacific Gas and
Electric Company's portion of the Pipeline Expansion (PG&E Expansion or Line
401) placed the Company at risk for its decision to construct based on its
assessment of market demand and for undersubscription and underutilization of
the facility. The CPUC required the application of a "cross-over" ban under
which volumes delivered from the incremental portion owned by PG&E GT-
Northwest (PGT Expansion) of the Pipeline Expansion must be transported at an
incremental PG&E Expansion rate. The costs of PG&E Expansion operations were
recovered only from PG&E Expansion customers, through rates established in
separate PG&E Expansion rate proceedings.
Under the Gas Accord, Pacific Gas and Electric Company is at risk for
recovery of all gas transmission costs, including costs of the PG&E Expansion,
through rates; however, a portion of the PG&E Expansion will be combined with
other transmission assets (specifically, a portion of the Company's Line 400)
for ratemaking purposes. This new ratemaking treatment for gas transmission
assets allows all shippers supplying noncore customers to transport Canadian
gas in California at a single rate, and obviates the need for the "cross-over"
ban, which was eliminated under the Gas Accord. Further, in the Gas Accord,
the CPUC adopted a rule under which Pacific Gas and Electric Company is
required, whenever it discounts service for a shipper on its Line 400/401
delivering primarily Canadian gas within the Company's service territory, to
contemporaneously offer a commensurate discount to all shippers delivering
Southwest or California source gas on Line 300 within the Company's service
territory.
30
WHOLESALE OPERATIONS OF AFFILIATES
Gas Transmission Operations
PG&E Corporation participates in the "midstream" portion of the gas business
through PG&E GTT, PG&E Gas Transmission Teco, Inc. and PG&E GT-Northwest. The
"midstream" gas business includes (1) gas gathering, processing, and storage,
and transportation of natural gas and natural gas liquids (NGLs); (2) the
marketing of natural gas to gas distribution companies, electric utilities,
municipalities, marketers, independent power producers, and end-use customers;
(3) the transportation of natural gas for these customers, producers, and
other pipelines; and (4) the marketing and transportation of NGLs to various
customers, including end-use customers.
PG&E GTT and PG&E Gas Transmission Teco, Inc. own and operate gas gathering,
transportation, and processing facilities, and NGL pipelines. The NGL business
includes the gathering of natural gas, the extraction of NGLs from natural
gas, the fractionation of mixed NGLs into component products (e.g., ethane,
propane, butane, and natural gasoline), and the transportation and marketing
of NGLs. The Texas operations include approximately 6,600 miles of natural gas
pipelines and joint ownership or leasehold interests in approximately 1,900
miles of pipelines, including pipelines from Waha in west Texas to the Katy
area near Houston, Texas. These pipeline systems have the capacity to
transport more than 3 billion cubic feet (bcf) of gas per day. Other Texas
assets include a long-term lease of 7.2 bcf of storage capacity, approximately
536 miles of NGL pipelines and nine natural gas processing plants with a
combined capacity of approximately 1.6 bcf per day of gas throughput, capable
of producing approximately over 100,000 barrels per day of NGLs.
PG&E GT-Northwest owns and operates gas transmission pipelines and
associated facilities which extend over 612 miles from the Canada-U.S. border
to the Oregon-California border and are capable of transporting 2.4 bcf per
day of natural gas. It also owns two smaller diameter pipeline extensions
within Oregon, totaling 106 miles. In July 1998, PG&E Corporation sold its
natural gas pipeline in Australia as part of its strategy to focus on the
domestic market.
In September 1996, the FERC approved a settlement of PG&E GT-Northwest's
1994 rate case. The major issue in this proceeding was whether PG&E GT-
Northwest's mainline transportation rates should be equalized through the use
of rolled-in cost allocations or whether they should continue to reflect the
use of incremental cost allocation to determine the rates to be paid by firm
shippers. (Under incremental rates, a pipeline would generally charge higher
rates to shippers contracting for capacity on newly-added expansion
facilities, as compared to shippers using depreciated pre-expansion
facilities.) The settlement provides for rolled-in rates effective November
1996. To mitigate the impact of the higher rolled-in rates on shippers who
were paying lower rates under contracts executed prior to construction of the
PGT Expansion, most of the firm shippers who took service prior to such time
receive a reduction from the rolled-in rate for a six-year period, while PGT
Expansion firm shippers pay a surcharge in addition to the rolled-in rates to
offset the effect of the mitigation. See "Utility Operations--Gas Utility
Operations--PGT/Pacific Gas and Electric Company Pipeline Expansion" above.
The settlement also provides for rates based on a return on equity of 12.2%.
In 1998, petitions filed by various parties for rehearing of the FERC order
approving the settlement were denied. Some parties have appealed the FERC's
denial of these rehearing petitions to the U.S. Court of Appeals for the
District of Columbia Circuit, but PG&E GT-Northwest currently expects the
settlement to be upheld.
Independent Power Generation
Through USGen and its affiliates, PG&E Corporation participates in the
development, construction, operation, ownership, and management of non-utility
electric generating facilities that compete in the United States power
generation market. USGen is headquartered in Bethesda, Maryland.
In 1998, PG&E Corporation, through its indirect subsidiary, USGen New
England, Inc. (USGenNE), completed the acquisition of a portfolio of electric
generating assets and power supply contracts from NEES for
31
$1.59 billion, plus $85 million for early retirement and severance costs
previously committed to by NEES. Including fuel and other inventories and
transaction costs, PG&E Corporation's financing requirements were
approximately $1.8 billion, funded through $1.3 billion of debt, a $425
million equity contribution, and $70 million from cash on hand and other
sources. The debt was raised through revolving credit facilities established
at both the USGen and the USGenNE levels. Specifically, a $1.1 billion credit
facility was established at the USGen level, and $575 million credit facility
was established at the USGenNE level. In December 1998, USGenNE canceled $475
million of this $575 million facility through a sale-leaseback transaction
involving the pumped storage facility acquired from NEES.
The acquired NEES facilities consist of two conventional hydroelectric
systems with 14 stations, three fossil-fuel stations (coal, oil, and natural
gas) with 11 units, and a pumped storage facility, with a combined generating
capacity of approximately 4,000 MW. In addition, USGenNE assumed the purchase
obligations under 27 multi-year power-purchase agreements between NEES's
subsidiary, New England Power, and other utility and non-utility wholesale
suppliers representing an additional 1,100 MW of production capacity.
Subsequently, several of the power-purchase agreements expired and/or were
transferred, thereby reducing the total capacity to the current level of
approximately 800 MW. USGenNE entered into agreements with NEES as part of the
acquisition, which (1) provide that NEES shall make annual support payments
through early 2008 to offset the cost of power associated with these above-
market contracts, and (2) require that USGenNE provide electricity to NEES
under supply agreements that expire over the next six to 11 years.
Three of the four states in which the acquired assets are located
(Massachusetts, Rhode Island, and New Hampshire) were also among the first
states in the country to introduce retail competition. (A referendum in
Massachusetts reaffirming electric industry restructuring was approved by the
voters in November 1998.) Connecticut also has passed retail competition
legislation.
The acquired assets are located within the New England Power Pool (NEPOOL).
The wholesale electricity market in New England features a bid-based, real-
time pricing structure. Traditionally, NEPOOL has operated as a "tight power
pool," one in which the utilities within the pool dedicate their generation
resources to be centrally dispatched. Dispatch starts with the lowest-cost
generation and ends with the highest-cost generation. In 1998, an independent
system operator for the New England states (ISO-NE) began to provide central
dispatch service and to operate the power pool as a competitive wholesale
marketplace.
As a result, the NEPOOL market is in the midst of transitioning to a
competitive market. The duties of the ISO-NE include scheduling the operations
of the regional transmission systems and, importantly, operating a power
exchange for seven generation products (the "Interchange"). These products are
energy, installed (monthly) capacity and operable (hourly) capacity, three
types of reserves and automatic generation control (adjustment of generators
to meet the second-to-second changes in electric load). The installed capacity
market began operations on April 1, 1998. The balance of the Interchange is
anticipated to begin operations on April 1, 1999, although this date is
subject to final implementation by the ISO-NE.
In these New England states, the utility companies providing service to
retail customers are required to provide Standard Offer Service (SOS) to those
customers. The SOS is intended to provide consumers with a price benefit (the
commodity electric price offered to the retail customer is expected to be less
than the market price) for the first several years, followed by a price
disincentive that is intended to stimulate the retail market.
Retail customers may continue to receive SOS through June 30, 2002, in New
Hampshire (subject to early termination on December 31, 2000, at the
discretion of the New Hampshire Public Service Commission); through December
31, 2004, in Massachusetts; and through December 31, 2009, in Rhode Island.
However, if any customer elects to have their electricity provided by an
alternate supplier, they are precluded from returning to the SOS. In
connection with the purchase of the NEES generation assets, PG&E Corporation,
through USGenNE, entered into agreements to supply the electric capacity and
energy requirements necessary for NEES to meet its SOS obligations. In
December 1998, NEES's New Hampshire utility subsidiary, Granite State Electric
Co., reached an agreement with Constellation Power Source, Inc. under which
Constellation Power Source, Inc. will
32
provide the SOS for Granite State Electric Co.'s customers. USGenNE retains
its supply obligations for Massachusetts Electric Company and Narrangansett
Electric Company, two utility subsidiaries of NEES located in Massachusetts
and Rhode Island, respectively. NEES is responsible for passing on to PG&E
Corporation the revenues generated from the SOS.
Initially, approximately 90% of the operating capacity acquired from NEES,
including capacity and energy generated by independent power producers (IPPs)
under the assumed power-purchase agreements, has been dedicated to providing
SOS. To the extent that customers eligible to receive SOS choose alternate
suppliers this percentage will decrease.
Like California utilities, the New England utilities have entered into
agreements with IPPs to provide energy and capacity at prices which are
anticipated to be in excess of market prices. As described above, USGenNE
assumed NEES's contractual rights and duties under certain power-purchase
agreements with IPPs, which in the aggregate provide for approximately 800 MW
of capacity. In connection with the acquisition of NEES's generating assets,
USGenNE is required to pay NEES amounts due from NEES to the IPPs in
accordance with their power-purchase agreements. These payment obligations are
reduced by monthly support payments that NEES pays USGenNE.
Finally, in connection with the NEES acquisition, USGenNE obtained the right
to purchase NEES's nuclear generated electric energy, capacity, and associated
products at market prices up to the entire amount available. This right
terminates automatically with respect to any nuclear facility that is sold or
ceases operation for any reason, and if not terminated earlier, expires at
termination of the SOS.
The financial impact of the acquisition of the NEES assets on PG&E
Corporation is subject to a number of risks and uncertainties, including
future market prices of power in the region where the NEES assets are located,
future fuel prices, the development of a competitive market in the states in
which the NEES assets are located, the extent to which operating efficiencies
at the NEES plants can be attained, changes in legislation affecting electric
industry restructuring and in the regulatory environment in the states where
the NEES assets are located, the extent of the obligation to provide
electricity under the SOS at prices below cost or market, the extent to which
a liquid, well-structured trading market develops for wholesale electric power
in the states in which the NEES assets are located, and generating capacity
expansion and retirements by others.
As of December 31, 1998, USGen affiliates had ownership interests in 30
operating plants (including the assets acquired from NEES) in 10 states. The
total generating capacity of these 30 plants is approximately 6,560 MW. PG&E
Corporation's combined net equity ownership and leased interest in these
plants as of December 31, 1998, represented approximately 5,300 MW. The plants
were financed largely with a combination of equity or equity commitments from
the project sponsors and non-recourse debt. (For a description of the
financing of the NEES acquisition, see above.) USGen, through its affiliate,
U.S. Operating Services Company (USOSC), provides contract operations and
maintenance services to many of these facilities. Nationwide, USGen's power
plant development activities exceed 8,600 MW in 8 states. USGen and its
affiliated or managed facilities sold 22,242,949 million megawatt-hours (MWh)
of electricity in 1998, including sales of electricity from the generating
facilities acquired from NEES on September 1, 1998.
33
The following table sets forth information regarding the operating
generating plants in which USGen affiliates have ownership or leasehold
interests. The table also notes the operating plants which USGen affiliates
manage or operate, or both manage and operate, power plant operations.
Portfolio of Operating Generating Plants
Date Placed in
Commercial
Plant MWs Fuel Location Service
----- --- ---- -------- --------------
Bear Swamp Facility(1),(2)
Pumped Storage 2 Units........... 588 Water Massachusetts 1974
Fife Brook....................... 10 Water 1974
Brayton Point Station (2)
Unit Nos. 1, 2 and 3............. 1,130 Coal Massachusetts 1963, '64, '69
Unit No. 4....................... 446 Oil/Gas 1974
Diesel Generators................ 10 Diesel Oil N/A
Carneys Point....................... 260 Coal New Jersey 1994
Cedar Bay........................... 250 Coal Florida 1994
Connecticut River (2)
Hydroelectric 26 Units........... 484 Water New Hampshire/Vermont 1909-1957
Deerfield River (2)
Hydroelectric 15 Units........... 84 Water Massachusetts/Vermont 1912-1927
Hermiston........................... 474 Natural Gas Oregon 1996
Indiantown.......................... 330 Coal Florida 1995
Logan............................... 225 Coal New Jersey 1995
Manchester St. Station (2)
3 Combined Cycle Units........... 495 Natural Gas Rhode Island 1995
MASSPOWER........................... 240 Natural Gas Massachusetts 1993
Northampton......................... 110 Waste Coal Pennsylvania 1995
Pittsfield.......................... 165 Natural Gas Massachusetts 1990
Salem Harbor Station (2)
Unit Nos. 1, 2 and 3............. 314 Coal Massachusetts 1952, '52, '58
Unit No. 4....................... 400 Oil 1972
Scrubgrass.......................... 83 Waste Coal Pennsylvania 1993
Selkirk............................. 345 Natural Gas New York 1994
-----
Total MWs/Operating Plants... 6,443
USGen Affiliate Investments
Colstrip (3)........................ 37 Waste Coal Montana 1990
Panther Creek (3)................... 83 Waste Coal Pennsylvania 1992
-----
Total MWs from Investments... 120
=====
Total MWs in Operation (4)... 6,563
- --------
(1) Unlike other operating facilities in which USGen affiliates have ownership
and management interests, the Bear Swamp Facility is owned by a third
party through a single-investor lease arrangement. USGen maintains full
management and operating responsibility for the facility.
(2) Acquired from NEES on September 1, 1998.
(3) USGen affiliates have an ownership or leasehold interest in these plants,
but do not manage power plant operations.
(4) Of the total of 6,563 megawatts, USGen's net equity ownership and leased
percentage is 5,282 megawatts.
34
Energy Trading
PG&E Energy Trading-Gas Corporation and PG&E Energy Trading-Power, L.P.
(collectively referred to as PG&E Energy Trading), headquartered in Houston,
Texas, purchase bulk volumes of power and natural gas from PG&E Corporation
affiliates and the wholesale market. PG&E Energy Trading then schedules,
transports, and resells these commodities, either directly to third parties or
to other PG&E Corporation affiliates. PG&E Energy Trading also provides price
risk management services to PG&E Corporation's other businesses (except
Pacific Gas and Electric Company) and to wholesale customers. Additionally,
PG&E Energy Trading provides PG&E Energy Services Corporation with a broad
portfolio of energy products and services for the retail market. For more
information, see "General--Price Risk Management Programs" above.
Additional information concerning the wholesale operations of PG&E
Corporation's affiliates is provided in "Management's Discussion and Analysis"
in the 1998 Annual Report to Shareholders, beginning on page 18, and in Note
16 of the "Notes to Consolidated Financial Statements" beginning on page 67 of
the 1998 Annual Report to Shareholders.
RETAIL OPERATIONS OF AFFILIATES
Energy Services
PG&E Energy Services (PG&E ES), headquartered in San Francisco, California,
provides retail gas and electric commodities nationwide, where permitted under
applicable laws, and provides energy related value-added services, including
billing and information management services, energy efficiency and other
energy management services, regulatory and rate analysis, and power quality
solutions. PG&E ES targets primarily industrial, commercial, and institutional
customers, offering comprehensive energy management solutions to reduce their
energy costs and improve their productivity. PG&E ES has 20 offices nationwide
to support its sales activities. PG&E ES currently competes with other non-
utility electric retailers in California for direct access customers. See
"Utility Operations--Electric Utility Operations--Implementation of Electric
Industry Restructuring" above.
Additional information concerning the retail operations of PG&E ES is
provided in "Management's Discussion and Analysis" in the 1998 Annual Report
to Shareholders, beginning on page 18, and in Note 16 of the "Notes to
Consolidated Financial Statements" beginning on page 67 of the 1998 Annual
Report to Shareholders.
35
ENVIRONMENTAL MATTERS
Environmental Matters
The following discussion includes certain forward-looking information
relating to estimated expenditures for environmental protection and the
possible future impact of environmental compliance. This information below
reflects current estimates, which are periodically evaluated and revised.
These estimates are subject to a number of assumptions and uncertainties,
including changing laws and regulations, the ultimate outcome of complex
factual investigations, evolving technologies, selection of compliance
alternatives, the nature and extent of required remediation, the extent of the
facility owner's responsibility, and the availability of recoveries or
contributions from third parties. Future estimates and actual results may
differ materially from those indicated below.
PG&E Corporation, Pacific Gas and Electric Company, U.S. Generating Company
and its affiliates (including USGen New England, Inc. (USGenNE) which holds
the electric generating facilities acquired from NEES in September 1998), and
other PG&E Corporation subsidiaries and affiliates, are subject to a number of
federal, state, and local laws and regulations designed to protect human
health and the environment by imposing stringent controls with regard to
planning and construction activities, land use, and air and water pollution,
and, in recent years, by governing the use, treatment, storage, and disposal
of hazardous or toxic materials. These laws and regulations affect future
planning and existing operations, including environmental protection and
remediation activities. Pacific Gas and Electric Company has undertaken major
compliance efforts with specific emphasis on its purchase, use, and disposal
of hazardous materials, the cleanup or mitigation of historic waste spill and
disposal activities, and the upgrading or replacement of the Company's bulk
waste handling and storage facilities. The costs of compliance with
environmental laws and regulations generally have been recovered in rates.
Environmental Protection Measures
The estimated expenditures of PG&E Corporation's subsidiaries for
environmental protection are subject to periodic review and revision to
reflect changing technology and evolving regulatory requirements. It is likely
that the stringency of environmental regulations will increase in the future.
With Pacific Gas and Electric Company's 1998 sale of its Morro Bay, Moss
Landing, and Oakland power plants, and the upcoming sale of the Company's
Contra Costa, Pittsburg, Potrero, and Geysers power plants (expected to close
in 1999), the Company's oxides of nitrogen (NOx) emission reduction compliance
costs will be reduced significantly. See "Utility Operations--Electric Utility
Operations--Implementation of Electric Industry Restructuring--Voluntary
Generation Asset Divestiture" above.
Air Quality
Pacific Gas and Electric Company's thermal electric generating plants are
subject to numerous air pollution control laws, including the California Clean
Air Act (CCAA) with respect to emissions. Pursuant to the CCAA and the Federal
Clean Air Act, three of the local air districts in which Pacific Gas and
Electric Company operates fossil-fueled generating plants have adopted final
rules that require a reduction in NOx emissions from the power plants of
approximately 90% by 2004 (with numerous interim compliance deadlines).
Following divestiture of the Company's fossil-fueled generating plants in
connection with electric industry restructuring, the new owners will bear NOx
retrofit costs. Under AB 1890, NOx retrofit costs would be eligible for
recovery as transition costs but only to the extent that those costs are found
by the CPUC to be both reasonable and necessary to maintain the unit in
operation through 2001.
The Gas Accord authorizes $42 million to be included in rates through 2002,
for gas NOx retrofit projects related to natural gas compressor stations on
Pacific Gas and Electric Company's Line 300, which delivers Southwest gas.
Other air districts are considering NOx rules which would apply to Pacific Gas
and Electric
36
Company's other natural gas compressor stations in California. Eventually the
rules are likely to require NOx reductions of up to 80% at many of these
natural gas compressor stations. Pacific Gas and Electric Company currently
estimates that the total cost of complying with these various NOx rules will
be up to $51.9 million over four years.
USGen's compliance with certain future regulatory requirements limiting the
total amount of NOx emissions from its fossil-fueled power plants is expected
to be achieved by installing additional controls, fuel switching and
purchasing of NOx allowances. USGenNE has agreed to be bound by a number of
state and regional initiatives that will require it to achieve significant
reductions of sulfur dioxide (SO/2/) and NOx emissions by the time its older
fossil-fueled power plants have been in operation for 40 years or by 2010,
whichever comes first. It is expected that USGenNE can meet these requirements
through the utilization of allowances it currently owns, installation of
additional controls or through the purchase of additional allowances. (SO/2/
allowances are emission credits that are traded in a national market under the
United States Environmental Protection Agency's (EPA) Acid Rain Program. NOx
allowances are emission credits that are traded in a regional market
consisting of seven Northeast states known as the Ozone Transport Region.) It
is estimated that USGenNE's total cost of complying with these requirements
will be up to $6 million through the year 2000.
Water Quality
Pacific Gas and Electric Company's existing power plants, including Diablo
Canyon, are subject to federal and state water quality standards with respect
to discharge constituents and thermal effluents. Pacific Gas and Electric
Company's fossil-fueled power plants comply in all material respects with the
discharge constituents standards and either comply in all material respects
with or are exempt from the thermal standards. A thermal effects study at
Diablo Canyon was completed in May 1988, and was reviewed by the Central Coast
Regional Water Quality Control Board (Central Coast Board). The Central Coast
Board did not make a final decision on the report and requested that Pacific
Gas and Electric Company continue its thermal effects monitoring program. In
1995, the Central Coast Board requested that Pacific Gas and Electric Company
prepare an updated comprehensive assessment of Diablo Canyon's thermal effects
and approved a reduced environmental monitoring program. A comprehensive
statistical analysis of Diablo Canyon's thermal effects was submitted to the
Central Coast Board in December 1997 and a regulatory assessment was submitted
in November 1998. In the unlikely event that the Central Coast Board finds
that Diablo Canyon's existing thermal limits are not protective of beneficial
uses of the marine waters and that major modifications are required (e.g.,
cooling towers), significant additional construction expenses could be
required.
Pursuant to the federal Clean Water Act, Pacific Gas and Electric Company is
required to demonstrate that the location, design, construction, and capacity
of power plant cooling water intake structures reflect the best technology
available (BTA) for minimizing adverse environmental impacts at all existing
water-cooled thermal plants. The Company has submitted detailed studies of
each power plant's intake structure to various governmental agencies. Each
plant's existing water intake structure was found to meet the BTA
requirements. The Company is currently preparing a new study for Diablo
Canyon. The study is scheduled to be submitted to the Central Coast Board for
review in 1999. In the event that the Central Coast Board finds that Diablo
Canyon's cooling water intake structure does not meet the BTA requirements,
significant additional expenses for construction or mitigation could be
required. In addition, the promulgation or modification of statutes,
regulations, or water quality control plans at the federal, state, or regional
level may impose increasingly stringent cooling water discharge requirements
on Pacific Gas and Electric Company power plants in the future. Costs to
comply with renewed permit conditions required to meet any more stringent
requirements that might be imposed cannot be estimated at the present time.
Several fish species listed or proposed for listing as endangered species
may be found in the waters near Pacific Gas and Electric Company's Delta power
plants (the Contra Costa and Pittsburgh fossil-fueled power plants). To
address the impacts of operation and maintenance activities at the Delta
plants on sensitive species, the Company has developed a Habitat Conservation
Plan (HCP) pursuant to the requirements of Section 10(a) of the federal
Endangered Species Act. The HCP is designed to minimize and mitigate any
incidental "take"
37
(e.g., harassing, wounding, or killing) of listed species that may occur from
the operation, maintenance, and repair of the power plants, in order to
support the issuance of a Section 10(a) incidental take permit necessary for
continued operation of the plants.
USGen's existing power plants, including USGenNE facilities, are subject to
federal and state water quality standards with respect to discharge
constituents and thermal effluents. Two of the fossil-fueled plants owned and
operated by USGenNE are operating in compliance with National Pollutant
Discharge Elimination System (NPDES) permits that have expired and the NPDES
permit for a third facility is scheduled to expire in 1999. As to the
facilities for which the NPDES permit has expired, new permit applications are
pending and it is anticipated that all three facilities should be able to
continue to operate under existing terms and conditions until new permits are
issued. USGenNE has submitted a permit renewal application and is negotiating
with EPA on ongoing studies and permit conditions. It is estimated that
USGenNE's cost to comply with these conditions could be as much as $4 million
through the year 2000.
Hazardous Waste Compliance and Remediation
PG&E Corporation subsidiaries assess, on an ongoing basis, measures that may
need to be taken to comply with laws and regulations related to hazardous
materials and hazardous waste compliance and remediation activities. Pacific
Gas and Electric Company has a comprehensive program to comply with many
hazardous waste storage, handling, and disposal requirements promulgated by
the EPA under the Resource Conservation and Recovery Act (RCRA) and the
Comprehensive Environmental Response, Compensation, and Liability Act
(CERCLA), along with other state hazardous waste laws and other environmental
requirements.
One part of this program is aimed at assessing whether and to what extent
remedial action may be necessary to mitigate potential hazards posed by
certain disposal sites and retired manufactured gas plant sites. During their
operation, manufactured gas plants produced lampblack and tar residues,
byproducts of a process that Pacific Gas and Electric Company, its predecessor
companies, and other utilities used as early as the 1850s to manufacture gas
from coal and oil. As natural gas became widely available (beginning about
1930), Pacific Gas and Electric Company's manufactured gas plants were removed
from service. The residues which may remain at some sites contain chemical
compounds which now are classified as hazardous. The Company has identified
and reported to federal and California environmental agencies 96 manufactured
gas plant sites which operated in the Company's service territory. The Company
owns all or a portion of 30 of these manufactured gas plant sites. The Company
has a program, in cooperation with environmental agencies, to evaluate and
take appropriate action to mitigate any potential health or environmental
hazards at sites which the Company owns. It is estimated that the Company's
program may result in expenditures of approximately $8 million in 1999. The
full long-term costs of the program cannot be determined accurately until a
closer study of each site has been completed. It is expected that expenses
will increase as remedial actions related to these sites are approved by
regulatory agencies or if Pacific Gas and Electric Company is found to be
responsible for cleanup at sites it does not currently own.
In addition to the manufactured gas plant sites, Pacific Gas and Electric
Company may be required to take remedial action at certain other disposal
sites if they are determined to present a significant threat to human health
and the environment because of an actual or potential release of hazardous
substances. Pacific Gas and Electric Company has been designated as a
potentially responsible party (PRP) under CERCLA (the federal Superfund law)
with respect to the Purity Oil Sales site in Malaga, California, the
Industrial Waste Processing site near Fresno, California, and the Lorentz
Barrel and Drum site in San Jose, California. With respect to the Casmalia
site near Santa Maria, California, the Company and several other generators of
waste sent to the site have entered into a court-approved agreement with the
EPA that requires these generators to perform certain site investigation and
mitigation measures, and provides a release from liability for certain other
site cleanup obligations. Although the Company has not been formally
designated a PRP with respect to the Geothermal Incorporated site in Lake
County, California, the Central Valley Regional Water Quality Control Board
and the California Attorney General's office have directed the Company and
other parties to initiate measures with respect to the study and remediation
of that site.
38
In addition, Pacific Gas and Electric Company has been named as a defendant
in several civil lawsuits in which plaintiffs allege that the Company is
responsible for performing or paying for remedial action at sites the Company
no longer owns or never owned.
The cost of hazardous substance remediation ultimately undertaken by Pacific
Gas and Electric Company is difficult to estimate. It is reasonably possible
that a change in the estimate will occur in the near term due to uncertainty
concerning the Company's responsibility, the complexity of environmental laws
and regulations, and the selection of compliance alternatives. Pacific Gas and
Electric Company had an accrued liability at December 31, 1998, of $296
million for hazardous waste remediation costs at those sites, including
fossil-fueled power plants, where such costs are probable and quantifiable.
Environmental remediation at identified sites may be as much as $487 million
if, among other things, other PRPs are not financially able to contribute to
these costs or further investigation indicates that the extent of
contamination or necessary remediation is greater than anticipated at sites
for which the Company is responsible. This upper limit of the range of costs
was estimated using assumptions least favorable to the Company based upon a
range of reasonably possible outcomes. Costs may be higher if the Company is
found to be responsible for cleanup costs at additional sites or identifiable
possible outcomes change.
USGen acquired the onsite environmental liability associated with USGenNE's
acquisition of electric generating facilities from NEES, but did not acquire
any offsite pollution liability associated with the past disposal practices at
the acquired facilities. USGen has obtained pollution liability and
environmental remediation insurance coverage to limit the financial risk
associated with the onsite pollution liability at all of its facilities.
Potential Recovery of Hazardous Waste Compliance and Remediation Costs
In 1994, the CPUC established a ratemaking mechanism for hazardous waste
remediation costs (HWRC). That mechanism assigns 90% of the includable
hazardous substance cleanup costs to utility ratepayers and 10% to utility
shareholders, without a reasonableness review of such costs or of underlying
activities. However, utilities will have the opportunity to recover the
shareholder portion of the cleanup costs from insurance carriers. Under the
HWRC, 70% of the ratepayer portion of Pacific Gas and Electric Company's
cleanup costs is attributed to its gas department and 30% is attributed to its
electric department. The Company can seek to recover hazardous substance
cleanup costs under the HWRC in the rate proceeding it deems most appropriate.
In connection with electric industry restructuring, the HWRC mechanism may no
longer be used to recover electric generation-related clean-up costs for
contamination caused by events occurring after January 1, 1998.
Pacific Gas and Electric Company retains liability for certain required
environmental remediation of pre-closing soil or groundwater contamination for
fossil and geothermal generation facilities which are sold in connection with
electric industry restructuring. As each generation facility is divested, the
Company is required to prepare a forecast of environmental remediation costs
for that plant and to use the forecast to adjust the current plant
decommissioning cost estimate, eventually to be recovered through the
Transition Cost Balancing Account (TCBA). (For ratemaking purposes, estimates
of environmental remediation costs are discounted to present value, whereas
for accounting purposes the nominal value of estimated remediation costs is
used.) The discounted environmental liability associated with the Morro Bay,
Moss Landing, and Oakland power plants (which were sold on July 1, 1998) and
approved by the CPUC is $31.6 million. (The buyer of these plants has assumed
the decommissioning liability for the purchased plants.) As of July 1, 1998,
the Company had recovered $66 million from ratepayers for both the
environmental and non-environmental decommissioning accrual related to the
Morro Bay, Moss Landing, and Oakland power plants. The excess recovery related
to these plants in the amount of $34.5 million ($66 million minus $31.6
million) resulted in a net credit to the sunk cost of the remaining plants
(the Contra Costa, Pittsburgh, and Potrero power plants, and the Geysers
geothermal facilities) reducing the amount of sunk costs to be amortized over
the transition period, offsetting other transition costs.
On October 23, 1998, Pacific Gas and Electric Company requested that the
CPUC approve a total of $88.6 million of estimated costs of environmental
remediation liability that the Company will retain for the Contra Costa,
Pittsburg, and Potrero power plants, and the Geysers geothermal facilities.
(The buyers will assume
39
the decommissioning liability.) The Company also requested that the CPUC
approve similar accounting and ratemaking treatment of environmental
remediation and non-environmental decommissioning for these plants as the CPUC
approved for the first group of plants sold. As of December 31, 1998, Pacific
Gas and Electric Company has recovered from ratepayers approximately $141
million for environmental and non-environmental decommissioning accrual
related to these plants. After the plant sales are completed, the excess
recovery of approximately $48.5 million (as adjusted for decommissioning costs
that will continue to be accrued) would reduce the amount of generation-
related sunk costs to be amortized over the transition period, offsetting
other transition costs.
Pacific Gas and Electric Company expects to recover $160 million of the $296
million accrued liability, discussed above, in future rates. The liability
also includes $76 million related to power plant decommissioning for
environmental clean-up, which is recovered through depreciation. Additionally,
the Company is seeking recovery of costs from insurance carriers and from
other third parties.
In 1992, Pacific Gas and Electric Company filed a complaint in San Francisco
County Superior Court against more than 100 of its domestic and foreign
insurers, seeking damages and declaratory relief for remediation and other
costs associated with hazardous waste mitigation. The Company previously had
notified its insurance carriers that it seeks coverage under its comprehensive
general liability policies to recover costs incurred at certain specified
sites. In general, the Company's carriers neither admitted nor denied
coverage, but requested additional information from the Company. Although the
Company has received some amounts in settlements with certain of its insurers
(approximately $49.6 million through December 31, 1998), the ultimate amount
of recovery from insurance coverage, either in the aggregate or with respect
to a particular site, cannot be quantified at this time.
Compressor Station Litigation
Several cases have been brought against Pacific Gas and Electric Company
seeking damages from alleged chromium contamination at the Company's Hinkley,
Topock, and Kettleman Compressor Stations. See Item 3, "Legal Proceedings--
Compressor Station Chromium Litigation" below, for a description of the
pending litigation.
Electric and Magnetic Fields
In January 1991, the CPUC opened an investigation into potential interim
policy actions to address increasing public concern, especially with respect
to schools, regarding potential health risks which may be associated with
electric and magnetic fields (EMF) from utility facilities. In its order
instituting the investigation, the CPUC acknowledged that the scientific
community has not reached consensus on the nature of any health impacts from
contact with EMF, but went on to state that a body of evidence has been
compiled which raises the question of whether adverse health impacts might
exist.
In November 1993, the CPUC adopted an interim EMF policy for California
energy utilities which, among other things, requires California energy
utilities to take no-cost and low-cost steps to reduce EMF from new and
upgraded utility facilities. California energy utilities are required to fund
a $1.5 million EMF education program and a $5.6 million EMF research program
managed by the California Department of Health Services.
As part of its effort to educate the public about EMF, Pacific Gas and
Electric Company provides interested customers with information regarding the
EMF exposure issue. The Company also provides a free field measurement service
to inform customers about EMF levels at different locations in and around
their residences or commercial buildings.
Pacific Gas and Electric Company is not currently involved in third party
litigation concerning EMF. In August 1996, the California Supreme Court held
that homeowners are barred from suing utilities for alleged property value
losses caused by fear of EMF from power lines. The Court expressly limited its
holding to
40
property value issues, leaving open the question as to whether lawsuits for
alleged personal injury resulting from exposure to EMF are similarly barred.
Pacific Gas and Electric Company was a defendant in civil litigation in which
plaintiffs alleged personal injuries resulting from exposure to EMF. In
January 1998, the appeals court in this matter held that the CPUC has
exclusive jurisdiction over personal injury and wrongful death claims arising
from allegations of harmful exposure to EMF and barred plaintiffs' personal
injury claims. Plaintiffs filed an appeal of this decision with the California
Supreme Court. The California Supreme Court declined to hear the case.
In the event that the scientific community reaches a consensus that EMF
presents a health hazard and further determines that the impact of utility-
related EMF exposures can be isolated from other exposures, Pacific Gas and
Electric Company may be required to take mitigation measures at its
facilities. The costs of such mitigation measures cannot be estimated with any
certainty at this time. However, such costs could be significant, depending on
the particular mitigation measures undertaken, especially if relocation of
existing power lines is ultimately required.
Low Emission Vehicle Programs
In December 1995, the CPUC issued its decision in the Low Emission Vehicle
(LEV) proceeding which approved approximately $42 million in funding for
Pacific Gas and Electric Company's LEV program for the six-year period
beginning in 1996. The CPUC's decision on electric industry restructuring
finds that the costs of utility LEV programs should continue to be collected
by the utility for the duration of the six-year period. Pacific Gas and
Electric Company continues to run its LEV program as funded.
ITEM 2. Properties.
Information concerning Pacific Gas and Electric Company's electric
generation units, gas transmission facilities, and electric and gas
distribution facilities is included in response to Item 1. All real properties
and substantially all personal properties of Pacific Gas and Electric Company
are subject to the lien of an indenture which provides security to the holders
of Pacific Gas and Electric Company's First and Refunding Mortgage Bonds.
Information concerning properties and facilities owned by other PG&E
Corporation subsidiaries is included in the discussion under the heading of
this report entitled "Wholesale Operations of Affiliates."
ITEM 3. Legal Proceedings.
See Item 1, Business, for other proceedings pending before governmental and
administrative bodies. In addition to the following legal proceedings, PG&E
Corporation and Pacific Gas and Electric Company are subject to routine
litigation incidental to their business.
Compressor Station Chromium Litigation
Pacific Gas and Electric Company is a defendant in five civil actions
pending in California courts on behalf of approximately 2,300 plaintiffs.
These cases are (1) Aguayo v. Pacific Gas and Electric Company, filed
March 15, 1995, in Los Angeles County Superior Court; (2) Aguilar v. Pacific
Gas and Electric Company, filed October 4, 1996 in Los Angeles County Superior
Court; (3) Acosta, et al. v. Betz Laboratories, Inc., et al., filed November
27, 1996, in Los Angeles Superior Court; (4) Little and Mustafa v. Pacific Gas
and Electric Company and PG&E Corporation, filed September 10, 1997, in San
Bernardino Superior Court; and (5) Whipple, et al. v. Pacific Gas and Electric
Company and PG&E Corporation, et al., filed September 10, 1997, in San
Bernardino Superior Court. (Plaintiffs have agreed to dismiss PG&E Corporation
in these last two suits.) These cases are collectively referred to as the
"Aguayo Litigation."
Each of the complaints in the Aguayo Litigation, except the Little case
described below, alleges personal injuries and seeks compensatory and punitive
damages in an unspecified amount arising out of alleged exposure to chromium
contamination in the vicinity of Pacific Gas and Electric Company's gas
compressor stations at
41
Kettleman, Hinkley, and Topock, California. The plaintiffs in the Aguayo
Litigation include current and former Pacific Gas and Electric Company
employees, relatives of current and former Company employees, residents in the
vicinity of the compressor stations, and persons who visited the gas
compressor stations. The plaintiffs also include spouses or children of these
plaintiffs who claim only loss of consortium or injury through the alleged
exposure of their spouses or parents.
In the Whipple case, pending in San Bernardino Superior Court, the
plaintiffs (four members of one family) allege personal injuries, injury to a
business enterprise, and injury to real property based upon causes of action
for (1) actual fraud and deceit, (2) negligence, (3) negligence per se, (4)
strict liability, (5) battery, (6) intentional misrepresentation, (7)
negligent misrepresentation, (8) fraudulent concealment, and (9) intentional
spoliation of evidence. In the Little case, also pending in San Bernardino
Superior Court, two plaintiffs allege injury to real property based upon
causes of action for (1) actual fraud and deceit, (2) negligence, and (3)
negligence per se. Plaintiffs in each action are seeking unspecified
compensatory and punitive damages, as well as civil penalties pursuant to
Proposition 65.
In June 1998, a Los Angeles Superior Court judge found that preconception
claims are not recognizable under California law and ordered the dismissal of
235 plaintiffs with such claims from the Aguayo Litigation. Judgment was
entered against these plaintiffs in December 1998. During September and
October 1998, the court made similar rulings in the Acosta and Aguilar cases.
The Company expects that plaintiffs may appeal these rulings.
All discovery and discovery motion practice in three of the cases brought in
Los Angeles Superior Court (Acosta v. Betz, Aguilar v. Pacific Gas and
Electric Company, and Aguayo v. Pacific Gas and Electric Company) has been
referred by the judge to a discovery referee. The court ordered that those
plaintiffs who did not respond to written discovery requests served by Pacific
Gas and Electric Company by November 15, 1998, would be dismissed. The Company
has submitted stipulations to dismiss approximately 630 plaintiffs who failed
to respond to discovery requests. It is not anticipated that these plaintiffs
will appeal.
After the entry of the dismissal of plaintiffs with preconception claims and
those plaintiffs who failed to respond to discovery requests, there will be
approximately 1,650 plaintiffs remaining in the Aguayo Litigation.
On September 16, 1998, a discovery referee set the procedures for selecting
20 trial test plaintiffs and two alternates in the Aguayo, Acosta, and Aguilar
cases. Ten of these trial test plaintiffs and one alternate were selected by
plaintiffs, six plaintiffs and one alternate were selected by defendants, and
four plaintiffs were selected at random (by selecting seven plaintiffs at
random and allowing each party -- plaintiffs, Pacific Gas and Electric
Company, and Betz to strike one). A trial date has been set for November 16,
1999. The Company has filed a motion to transfer venue to Fresno County
Superior Court which is scheduled to be heard on March 22, 1999.
Pacific Gas and Electric Company is responding to the complaints and
asserting affirmative defenses. The Company will pursue appropriate legal
defenses including statute of limitations, inability of certain plaintiffs to
state a claim for alleged preconception exposure, or exclusivity of workers'
compensation laws, and factual defenses including lack of exposure to chromium
and the inability of chromium to cause certain of the illnesses alleged. At
this stage of the proceedings, there is substantial uncertainty concerning the
claims alleged. The Company is attempting to gather information concerning the
alleged type and duration of exposure, the nature of injuries alleged by
individual plaintiffs, and the additional facts necessary to support its legal
defenses, in order to better evaluate and defend this litigation.
PG&E Corporation believes that the ultimate outcome of this matter will not
have a material adverse impact on its or Pacific Gas and Electric Company's
financial position or results of operations.
Texas Franchise Fee Litigation
On July 31, 1997, PG&E Corporation acquired Valero Energy Corporation
(Valero), now known as PG&E Gas Transmission, Texas Corporation or PG&E GTT.
PG&E GTT succeeded to the eight cases described below
42
which were pending at the time of the acquisition against Valero and its
affiliates (collectively referred to as the "Texas Franchise Fees
Litigation"). These actions were brought by various cities in Texas arising
out of several Texas statutes and city ordinances involving the following: (a)
what rights, if any, Texas cities may have to require companies engaged in the
gathering, production, distribution, transmission, and/or sale of natural gas
(gas business) to obtain consent from, and pay fees to, the cities within
which such activities are being conducted, (b) what form any such consent, if
required, must take, (c) what constitutes "use" of city property, and (d) what
types of charges, if any, a Texas city properly can assess against gas
pipeline and marketing companies for use of that city's property.
These seven cases pending against Valero entities at the time of the
acquisition are: (1) City of Edinburg v. Rio Grande Valley Gas Co. (RGVG),
Valero Energy Corporation (now known as PG&E GTT), Valero Transmission Company
(now known as PG&E Texas Pipeline Company), Valero Natural Gas Company (now
known as PG&E Texas Natural Gas Company), Reata Industrial Gas Company (now
known as PG&E Energy Trading Holdings Corporation), Valero Transmission, L.P.
(now known as PG&E Texas Pipeline, L.P.), and Reata Industrial Gas, L.P. (now
known as PG&E Reata Energy, L.P.), Southern Union Gas Co., and Mercado Gas
Services, Inc., filed August 31, 1995, in the 92nd State District Court,
Hidalgo County, Texas; (2) Cities of San Benito, Primera, and Port Isabel v.
RGVG, Valero Energy Corporation (now known as PG&E GTT), Southern Union
Company, et al., filed December 31, 1996, in the 107th State District Court,
Cameron County, Texas; (3) City of Mercedes v. Reata Industrial Gas L.P. (now
known as PG&E Reata Energy, L.P.), and Reata Industrial Gas Company (now known
as PG&E Energy Trading Holdings Corporation), filed April 16, 1997, in the
92nd State District Court in Hidalgo County, Texas; (4) Cities of Alton and
Dana v. Rio Grande Valley Gas Co., Valero Energy Corporation (now known as
PG&E GTT), Valero Transmission Company (now known as PG&E Texas Pipeline
Company), Valero Natural Gas Company (now known as PG&E Texas Natural Gas
Company), Reata Industrial Gas Company (now known as PG&E Energy Trading
Holdings Corporation), Valero Transmission, L.P. (now known as PG&E Texas
Pipeline, L.P.), and Reata Industrial Gas, L.P. (now known as PG&E Reata
Energy, L.P.), Southern Union Gas Co., and Mercado Gas Services, Inc., filed
July 18, 1996, in the 92nd State District Court, Hidalgo County, Texas; (5)
City of La Joya v. Rio Grande Valley Gas Company, Valero Energy Corporation
(now known as PG&E GTT), Southern Union Company, et al., filed December 27,
1996, in the 92nd State District Court, Hidalgo County, Texas; (6) City of San
Juan, City of La Villa, City of Penitas, City of Edcouch, and City of Palmview
v. Rio Grande Valley Gas Company, Valero Energy Corporation (now known as PG&E
GTT), Southern Union Company, et al., filed December 27, 1996, in the 93rd
State District Court, Hidalgo County, Texas; and (7) City of Weslaco v. Valero
Natural Gas Company (now known as PG&E Texas Natural Gas Company), Reata
Industrial Gas Company (now known as PG&E Energy Trading Holdings Corporation)
and Reata Industrial Gas, L.P. (now known as PG&E Reata Energy L.P.) filed
April 17, 1997, in the 92nd State District Court, Hidalgo County, Texas.
The trial in the City of Edinburg case began on June 15, 1998. On August 14,
1998, a jury returned a verdict in favor of the City of Edinburg, and awarded
damages in the approximate aggregate amount of $9.8 million, plus attorneys'
fees of approximately $3.5 million, against PG&E GTT, Southern Union Gas
Company and various affiliates of PG&E GTT. The jury refused to award punitive
damages against the PG&E GTT defendants. On December 1, 1998, based on the
jury verdict, the court entered a judgment in the City's favor, and awarded
damages of $5.3 million, attorneys' fees of up to $3.5 million (to the extent
that the City is successful on appeal), prejudgment interest of $1.6 million
and post-judgment interest at the rate of 10 percent per year, compounded
annually, from December 1, 1998. The court found that various PG&E GTT and
Southern Union defendants were jointly and severally liable for $3.3 million
of the damages, prejudgment interest in the amount of $1.1 million, and all
the attorneys' fees. Certain PG&E GTT subsidiaries were found solely liable
for $1.4 million of the damages and prejudgment interest of $440,000. The
court did not clearly indicate the extent to which the PG&E GTT defendants
could be found liable for the remaining damages. The judgment also decreed
that (1) certain pipelines owned by PG&E GTT subsidiaries encroached on the
City's property without the City's consent and (2) based on certain jury
findings, PG&E GTT was vicariously liable for certain conduct of the local
distribution company, RGVG, from October 1, 1985, to September 30, 1993 (the
date Valero, PG&E GTT's predecessor, sold RGVG to Southern Union). The PG&E
GTT defendants are appealing the judgment.
43
On November 4, 1997, the lawsuit filed in Cameron County, Texas, by the
cities of San Benito, Primera, and Port Isabel was amended to name as
defendants PG&E GTT and all of its subsidiaries (excluding its Canadian gas
trading and power trading company), PG&E Gas Transmission Teco, Inc. and its
subsidiaries, and PG&E Energy Trading Corporation (now known as PG&E Energy
Trading--Gas Corporation), and to dismiss the Southern Union defendants. In
connection with the certification of a class in this case, the court ordered
notice to be sent to all potential class members and setting an opt-out
deadline of December 31, 1997. Notices were mailed to approximately 159 Texas
cities. Fewer than 20 cities opted out by the deadline. Some of the cities
opting out include Austin, Brownsville, Houston, Pharr, and San Antonio.
Defendants' motion to transfer venue of this case to Bexar County, Texas, is
currently pending.
The factual allegations and claims asserted in the lawsuit filed by the city
of La Joya, and in the lawsuit filed by the cities of San Juan, Lavilla,
Penitas, Edcouch, and Palmview, are similar to the claims made in the lawsuit
filed by the cities of San Benito, Primera, and Port Isabel. Defendants'
motion to transfer venue of both cases to Bexar County, Texas, also is
currently pending.
In July 1996, the lawsuits brought by the cities of Alton and Dana were
originally brought as intervening actions in the City of Edinburg case, but
were severed from the Edinburg lawsuit. The claims asserted by the cities of
Alton and Dana are substantially similar to the Edinburg litigation claims.
Damages are not quantified. Defendants' motion to transfer venue of both cases
to Bexar County, Texas, also is currently pending.
On September 4, 1997, the City of Mercedes amended its petition to include
class action claims and requested to be named as class representative for a
statewide class consisting of all Texas municipal corporations,
municipalities, towns, and villages, excluding the cities of Edinburg and
Weslaco (both of which filed separate actions), in which any of the defendants
have sold or supplied gas, or used public rights-of-way to transport gas. The
City of Mercedes has requested a damage award, but has not specified an
amount. On November 26, 1997, defendants' motion to recuse the presiding judge
was granted. Plaintiffs' request for class certification is still pending. If
a class is certified, defendants anticipate that they will challenge such
certification. Defendants' motion to transfer venue to Bexar County, Texas,
also is still pending.
The causes of action alleged in the case brought by the city of Weslaco are
identical to those alleged in the City of Mercedes case. Defendants' motion to
transfer venue to Bexar County, Texas, is currently pending. Defendants also
have filed a motion to disqualify or recuse the presiding judge (the same
judge that was recused in the Mercedes case) which is also pending.
In addition to the seven cases described above, a lawsuit was filed on April
3, 1996, in the 92nd State District Court, Hidalgo County, Texas, by the City
of Pharr against Southern Union Company, et al., and RGVG. On June 24, 1996,
the court certified the case as a class action and named Pharr as the class
representative for the class consisting of those Texas cities, excluding
Edinburg and McAllen, that have, or had natural gas franchises with RGVG. The
Pharr class was certified as to two claims: breach of contract and declaratory
relief dealing with the rights, status, and legal relationship between
plaintiff, the class members, and the local distribution company regarding
payment of franchise fees and use of granted easements. Plaintiffs' original
petition also sought injunctive relief, but the class order does not include
injunctive relief. Plaintiffs seek actual damages, exemplary damages,
attorneys' fees, costs, and pre- and post-judgment interest, but have not
specified any amounts. The court records show that a pleading was allegedly
filed on December 12, 1997, but not docketed until mid-February 1998, that
purports to add as defendants the same 29 PG&E Corporation entities that are
parties in the San Benito class action. These PG&E Corporation entities have
not been served in this litigation. On December 30, 1997, in affirming the
Pharr class certification, the appellate court specifically found that the
PG&E Corporation-related entities were not parties to the class action.
PG&E Corporation believes that the ultimate outcome of the Texas franchise
fee cases described above could have a material adverse impact on its
financial position or results of operation.
ITEM 4. Submission of Matters to a Vote of Security Holders.
Not applicable.
44
EXECUTIVE OFFICERS OF THE REGISTRANTS
"Executive officers," as defined by Rule 3b-7 of the General Rules and
Regulations under the Securities and Exchange Act of 1934, of PG&E Corporation
are as follows:
Age at
December 31,
Name 1998 Position
---- ------------ --------
R. D. Glynn, Jr. ....... 56 Chairman of the Board, Chief Executive
Officer, and President
S. W. Gebhardt.......... 47 Senior Vice President; President and
Chief Executive Officer, PG&E Energy
Services Corporation
T. W. High.............. 51 Senior Vice President, Administration
and External Relations
P. C. Iribe............. 48 Senior Vice President; President and
Chief Operating Officer, U.S.
Generating Company
T. B. King.............. 37 Senior Vice President; President and
Chief Operating Officer, PG&E Gas
Transmission Corporation
L. E. Maddox............ 43 Senior Vice President, President and
Chief Executive Officer, PG&E Energy
Trading Corporation
M. E. Rescoe............ 46 Senior Vice President, Chief Financial
Officer, and Treasurer
G. R. Smith............. 50 Senior Vice President; President and
Chief Executive Officer, Pacific Gas
and Electric Company
G. B. Stanley........... 52 Senior Vice President, Human Resources
B. R. Worthington....... 49 Senior Vice President and General
Counsel
All officers of PG&E Corporation serve at the pleasure of the Board of
Directors. During the past five years, the executive officers of PG&E
Corporation had the following business experience. Except as otherwise noted,
all positions have been held at PG&E Corporation.
Name Position Period Held Office
---- -------- ------------------
R. D. Glynn, Jr. .... Chairman of the Board, January 1, 1998, to current
Chief Executive
Officer, and President
Chairman of the Board of January 1, 1998, to current
Directors, Pacific Gas
and Electric Company
President and Chief June 1, 1997, to current
Executive Officer
President and Chief December 18, 1996, to May 31, 1997
Operating Officer
President and Chief June 1, 1995, to May 31, 1997
Operating Officer,
Pacific Gas and
Electric Company
Executive Vice July 1, 1994, to May 31, 1995
President, Pacific Gas
and Electric Company
Senior Vice President January 1, 1994, to June 30, 1994
and General Manager,
Customer Energy
Services Business Unit,
Pacific Gas and
Electric Company
Senior Vice President November 1, 1991, to December 31, 1993
and General Manager,
Electric Supply
Business Unit, Pacific
Gas and Electric
Company
S. W. Gebhardt....... Senior Vice President April 1, 1997, to current
President and Chief April 1, 1997, to current
Executive Officer, PG&E
Energy
Services Corporation
Executive Vice April 1, 1996, to March 28, 1997
President, PennUnion
Energy Services
Vice President, Enron January 1, 1993, to December 31, 1995
Capital & Trade
Resources
T. W. High........... Senior Vice President, June 1, 1997, to current
Administration and
External Relations
Senior Vice President, June 1, 1995, to May 31, 1997
Corporate Services,
Pacific Gas and
Electric Company
Vice President and July 1, 1994, to May 31, 1995
Assistant to the Chief
Executive Officer,
Pacific Gas and
Electric Company
Vice President and November 1, 1991, to June 30, 1994
Assistant to the
Chairman of the Board,
Pacific Gas and
Electric Company
45
Name Position Period Held Office
---- -------- ------------------
P. C. Iribe.......... Senior Vice President January 1, 1999, to current
President and Chief November 1, 1998, to current
Operating Officer, U.S.
Generating Company
Executive Vice President September 1, 1997, to October 31, 1998
and Chief Operating
Officer, U.S.
Generating Company
Executive Vice May 1994 to September 1, 1997
President, Marketing,
Development, and Asset
Management, U.S.
Generating Company
Senior Vice President, September 1990 to May 1994
U.S. Generating Company
T. B. King........... Senior Vice President January 1, 1999, to current
President and Chief November 23, 1998, to current
Operating Officer, PG&E
Gas Transmission
Corporation
President and Chief February 14, 1997, to November 22, 1998
Operating Officer,
Kinder Morgan
Energy Partners, L.P.
Vice President, July 1, 1995, to February 14, 1997
Commercial Operations--
Midwest Region, Enron
Liquid Services
Corporation
Vice President, July 1994 to July 1, 1995
Gathering Services,
Northern Natural Gas
Company and
Transwestern Pipeline
Company
Vice President, September 1993 to July 1994
Transportation
Marketing Northern
Natural Gas Company
L. E. Maddox......... Senior Vice President June 1, 1997, to current
President and Chief June 1, 1997, to current
Executive Officer, PG&E
Energy Trading
Corporation
President, PennUnion May 1995 to May 1997
Energy Services, L.L.C.
President, Brooklyn January 1993 to May 1995
Interstate Natural
Gas Corp.
M. E. Rescoe......... Senior Vice President, January 1, 1998, to current
Chief Financial
Officer, and Treasurer
Senior Vice President September 1, 1997, to December 31, 1997
and Chief Financial
Officer
Executive Vice August 11, 1997, to August 31, 1997
President, Strategic
Planning and Corporate
Development, Texas
Utilities Company
Senior Vice President, July 1995 to August 10, 1997
Chief Financial
Officer, Enserch Corp.
(gas and power)
Senior Managing July 1992 to July 1995
Director, Bear, Stearns
& Co., Inc.
(investment bankers)
G. R. Smith.......... Senior Vice President January 1, 1999, to current
(Please refer to
description of business
experience for
executive officers of
Pacific Gas and
Electric Company below.)
G. B. Stanley........ Senior Vice President, January 1, 1998, to current
Human Resources
Vice President, Human June 1, 1997, to December 31, 1997
Resources
Vice President, Human July 1, 1996, to May 31, 1997
Resources, Pacific Gas
and Electric Company
Self-employed (human January 1995 to June 1996
resources consultant)
Senior Vice President, January 1992 to December 1994
Human Resources, The
Gap, Inc.
(retail clothing)
B. R. Worthington.... Senior Vice President June 1, 1997, to current
and General Counsel
General Counsel December 18, 1996, to May 31, 1997
Senior Vice President June 1, 1995, to June 30, 1997
and General Counsel,
Pacific Gas and
Electric Company
Vice President and December 21, 1994, to May 31, 1996
General Counsel,
Pacific Gas and
Electric Company
Chief Counsel-Corporate, January 10, 1991, to December 20, 1994
Pacific Gas and
Electric Company
46
"Executive officers," as defined by Rule 3b-7 of the General Rules and
Regulations under the Securities and Exchange Act of 1934, of Pacific Gas and
Electric Company are as follows:
Age at
December 31,
Name 1998 Position
---- ------------ --------
G. R. Smith............. 50 President and Chief Executive Officer
K. M. Harvey............ 40 Senior Vice President, Treasurer and
Chief Financial Officer
E. J. Macias............ 44 Senior Vice President and General
Manager, Generation, Transmission,
and Supply Business Unit
R. J. Peters............ 48 Senior Vice President and General
Counsel
J. K. Randolph.......... 54 Senior Vice President and General
Manager, Distribution and Customer
Service Business Unit
D. D. Richard, Jr. ..... 48 Senior Vice President, Governmental
and Regulatory Relations
G. M. Rueger............ 48 Senior Vice President and General
Manager, Nuclear Power Generation
Business Unit
All officers of Pacific Gas and Electric Company serve at the pleasure of
the Board of Directors. During the past five years, the executive officers of
Pacific Gas and Electric Company had the following business experience. Except
as otherwise noted, all positions have been held at Pacific Gas and Electric
Company.
Name Position Period Held Office
---- -------- ------------------
G. R. Smith.......... President and Chief June 1, 1997 to current
Executive Officer
Chief Financial Officer, December 18, 1996 to May 31, 1997
PG&E Corporation
Senior Vice President June 1, 1995 to May 31, 1997
and Chief Financial
Officer
Vice President and Chief November 1, 1991 to May 31, 1995
Financial Officer
K. M. Harvey......... Senior Vice President, July 1, 1997 to current
Chief Financial
Officer, and Treasurer
Vice President and June 1, 1995 to June 30, 1997
Treasurer
Treasurer August 1, 1993 to May 31, 1995
Corporate Secretary November 1, 1991 to July 31, 1993
E. J. Macias......... Senior Vice President July 1, 1997 to current
and General Manager,
Generation,
Transmission and Supply
Business Unit
Vice President and November 15, 1995 to June 30, 1997
General Manager,
Electric Transmission
Vice President, Power December 21, 1994 to November 14, 1995
System
Manager, Power Control March 1993 to December 20, 1994
and System Operation
R. J. Peters......... Vice President and July 1, 1997 to current
General Counsel
Chief Counsel, January 1, 1993 to June 30, 1997
Regulatory
J. K. Randolph....... Senior Vice President July 1, 1997 to current
and General Manager,
Distribution and
Customer Service
Business Unit
Vice President and January 1, 1997 to June 30, 1997
General Manager, Power
Generation
Vice President, Power November 1, 1991 to December 31, 1996
Generation
D. D. Richard, Jr. .. Senior Vice President, July 1, 1997 to current
Governmental and
Regulatory Relations
Vice President, July 1, 1997 to current
Governmental Relations,
PG&E Corporation
Vice President, January 1, 1997 to June 30, 1997
Governmental Relations
Executive Vice President January 1993 to December 1996
and Principal, Morse,
Richard, Weisenmiller &
Assoc., Inc. (energy,
project finance, and
environmental
consulting)
G. M. Rueger......... Senior Vice President November 1, 1991 to current
and General Manager,
Nuclear Power
Generation Business
Unit
47
PART II
ITEM 5. Market for the Registrant's Common Equity and Related Stockholder
Matters.
Information responding to part of Item 5, for each of PG&E Corporation and
Pacific Gas and Electric Company, is set forth on page 69 under the heading
"Quarterly Consolidated Financial Data (Unaudited)" in the 1998 Annual Report
to Shareholders, which information is hereby incorporated by reference and
filed as part of Exhibit 13 to this report. As of February 22, 1999, there
were 162,261 holders of record of PG&E Corporation common stock.
Pacific Gas and Electric Company has made no sales of unregistered equity
securities in the last three years. PG&E Corporation has made the following
sales of unregistered equity securities during such period:
On January 27, 1997, PG&E Corporation issued 14,607,143 shares of common
stock. The shares were issued to nine former shareholders of Teco Pipeline
Company (Teco) in connection with the acquisition of Teco by PG&E
Corporation. PG&E Corporation owns all the outstanding shares of Teco as a
result of the acquisition. The shares were issued in reliance upon the
exemption from registration under the Securities Act of 1933, as amended,
pursuant to Section 4(2) thereof and Rule 506 of Regulation D thereunder.
All of the former shareholders of Teco represented that they were
"accredited investors" as defined in Rule 501(a) under the Securities Act
of 1933 and made other representations establishing the basis for the
exemption. A legend as provided for by Rule 501(d)(3) was placed on each of
the stock certificates representing the shares of PG&E Corporation common
stock received by the former shareholders of Teco.
ITEM 6. Selected Financial Data.
A summary of selected financial information for each of PG&E Corporation and
Pacific Gas and Electric Company for each of the last five fiscal years is set
forth on page 17 under the heading "Selected Financial Data" in the 1998
Annual Report to Shareholders, which information is hereby incorporated by
reference and filed as part of Exhibit 13 to this report.
Pacific Gas and Electric Company's earnings to fixed charges ratio for the
year ended December 31, 1998, was 3.02. Pacific Gas and Electric Company's
earnings to combined fixed charges and preferred stock dividends ratio for the
year ended December 31, 1998, was 2.85. The statement of the foregoing ratios,
together with the statements of the computation of the foregoing ratios filed
as Exhibits 12.1 and 12.2 hereto, are included herein for the purpose of
incorporating such information and exhibits into Registration Statement Nos.
33-62488, 33-64136, 33-50707, and 33-61959 relating to Pacific Gas and
Electric Company's various classes of debt and first preferred stock
outstanding.
ITEM 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations.
A discussion of PG&E Corporation's and Pacific Gas and Electric Company's
consolidated results of operations and financial condition is set forth on
pages 18 through 35 under the heading "Management's Discussion and Analysis"
in the 1998 Annual Report to Shareholders, which discussion is hereby
incorporated by reference and filed as part of Exhibit 13 to this report.
ITEM 7A. Quantitative and Qualitative Disclosures About Market Risk.
Information responding to Item 7A appears in the 1998 Annual Report to
Shareholders on page 32 under the heading "Management's Discussion and
Analysis--Debt Obligations and Rate Reduction Bonds," on pages 34 and 35 under
the heading "Management's Discussion and Analysis--Price Risk Management
Activities," and on pages 47, 48, 53, and 54 under Notes 1, 3, and 4 of the
"Notes to Consolidated Financial Statements" of the 1998 Annual Report to
Shareholders, which information is hereby incorporated by reference and filed
as part of Exhibit 13 to this report.
48
ITEM 8. Financial Statements and Supplementary Data.
Information responding to Item 8 appears on pages 36 through 70 of the 1998
Annual Report to Shareholders under the following headings for PG&E
Corporation: "Statement of Consolidated Income," "Consolidated Balance Sheet,"
"Statement of Consolidated Cash Flows," and "Statement of Consolidated Common
Stock Equity;" under the following headings for Pacific Gas and Electric
Company: "Statement of Consolidated Income," "Consolidated Balance Sheet,"
"Statement of Consolidated Cash Flows," and "Statement of Consolidated Common
Stock Equity, Preferred Stock, and Preferred Securities;" and under the
following headings for PG&E Corporation and Pacific Gas and Electric Company
jointly: "Notes to Consolidated Financial Statements," "Quarterly Consolidated
Financial Data (Unaudited)," and "Report of Independent Public Accountants,"
which information is hereby incorporated by reference and filed as part of
Exhibit 13 to this report.
ITEM 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure.
Information responding to Item 9 has been previously reported by PG&E
Corporation and Pacific Gas and Electric Company in a current report on Form
8-K dated February 17, 1999 and filed on February 23, 1999.
PART III
ITEM 10. Directors and Executive Officers of the Registrant.
Information regarding executive officers of PG&E Corporation and Pacific Gas
and Electric Company is included in a separate item captioned "Executive
Officers of the Registrant" contained on pages 45 through 47 in Part I of this
report. Other information responding to Item 10 is included on pages 3 through
6 under the heading "Item No. 1: Election of Directors of PG&E Corporation and
Pacific Gas and Electric Company" and page 43 under the heading "Section 16(a)
Beneficial Ownership Reporting Compliance" in the 1999 Joint Proxy Statement
relating to the 1999 Annual Meetings of Shareholders, which information is
hereby incorporated by reference.
ITEM 11. Executive Compensation.
Information responding to Item 11, for each of PG&E Corporation and Pacific
Gas and Electric Company, is included on pages 9 and 10 under the heading
"Compensation of Directors" and on pages 36 through 41 under the headings
"Summary Compensation Table," "Option/SAR Grants in 1998," "Aggregated
Option/SAR Exercises in 1998 and Year-End Option/SAR Values," "Long-Term
Incentive Plan--Awards in 1998," "Retirement Benefits," and "Termination of
Employment and Change In Control Provisions" in the 1999 Joint Proxy Statement
relating to the 1999 Annual Meetings of Shareholders, which information is
hereby incorporated by reference.
ITEM 12. Security Ownership of Certain Beneficial Owners and Management.
Information responding to Item 12, for each of PG&E Corporation and Pacific
Gas and Electric Company, is included on pages 11 and 12 under the heading
"Security Ownership of Management" and on pages 42 and 43 under the heading
"Principal Shareholders" in the 1999 Joint Proxy Statement relating to the
1999 Annual Meetings of Shareholders, which information is hereby incorporated
by reference.
ITEM 13. Certain Relationships and Related Transactions.
Information responding to Item 13, for each of PG&E Corporation and Pacific
Gas and Electric Company, is included on page 10 under the heading "Certain
Relationships and Related Transactions" in the 1999 Joint Proxy Statement
relating to the 1999 Annual Meetings of Shareholders, which information is
hereby incorporated by reference.
49
PART IV
ITEM 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K.
(a) The following documents are filed as a part of this report:
1. The following consolidated financial statements, supplemental
information, and report of independent public accountants contained
in the 1998 Annual Report to Shareholders, which have been
incorporated by reference in this report:
Statements of Consolidated Income for the Years Ended December 31,
1998, 1997, and 1996, for each of PG&E Corporation and Pacific Gas
and Electric Company.
Statements of Consolidated Cash Flows for the Years Ended December
31, 1998, 1997, and 1996, for each of PG&E Corporation and Pacific
Gas and Electric Company.
Consolidated Balance Sheets at December 31, 1998, and 1997, for each
of PG&E Corporation and Pacific Gas and Electric Company.
Statement of Consolidated Common Stock Equity for the Years Ended
December 31, 1998, 1997, and 1996, for PG&E Corporation.
Statement of Consolidated Common Stock Equity, Preferred Stock and
Preferred Securities for the Years Ended December 31, 1998, 1997,
and 1996, for Pacific Gas and Electric Company.
Notes to Consolidated Financial Statements.
Quarterly Consolidated Financial Data (Unaudited).
Report of Independent Public Accountants.
2. Report of Independent Public Accountants included at page 55 of this
Form 10-K.
3. Consolidated financial statement schedules:
I --Condensed Financial Information of Parent for the Years Ended
December 31, 1998 and 1997.
II--Consolidated Valuation and Qualifying Accounts for each of PG&E
Corporation and Pacific Gas and Electric Company for the Years
Ended December 31, 1998, 1997 and 1996.
Schedules not included are omitted because of the absence of conditions
under which they are required or because the required information is provided
in the consolidated financial statements including the notes thereto.
4.Exhibits required to be filed by Item 601 of Regulation S-K:
3.1 Restated Articles of Incorporation of PG&E Corporation effective
as of December 19, 1996 (PG&E Corporation's Form 8-B (File No. 1-
12609), Exhibit 3.1).
3.2 By-Laws of PG&E Corporation amended as of January 27, 1999.
3.3 Restated Articles of Incorporation of Pacific Gas and Electric
Company effective as of May 6, 1998 (Pacific Gas and Electric
Company's Form 10-Q for the quarter ended March 31, 1998 (File No.
1-2348), Exhibit 3.1).
3.4 By-Laws of Pacific Gas and Electric Company amended as of January
27, 1999.
4. First and Refunding Mortgage of Pacific Gas and Electric Company
dated December 1, 1920, and supplements thereto dated April 23,
1925, October 1, 1931, March 1, 1941, September 1, 1947, May 15,
1950, May 1, 1954, May 21, 1958, November 1, 1964, July 1, 1965,
July 1, 1969, January 1, 1975, June 1, 1979, August 1, 1983, and
December 1, 1988 (Registration No. 2-1324, Exhibits B-1, B-2, B-3;
Registration No. 2-4676, Exhibit B-22; Registration No. 2-7203,
Exhibit B-23; Registration No. 2-8475, Exhibit B-24; Registration
No. 2-10874, Exhibit 4B; Registration No. 2-14144, Exhibit 4B;
Registration
50
No. 2-22910, Exhibit 2B; Registration No. 2-23759, Exhibit 2B;
Registration No. 2-35106, Exhibit 2B; Registration No. 2-54302,
Exhibit 2C; Registration No. 2-64313, Exhibit 2C; Registration
No. 2-86849, Exhibit 4.3; Pacific Gas and Electric Company's Form
8-K dated January 18, 1989 (File No. 1-2348), Exhibit 4.2).
10.1 Asset Purchase Agreement by and among New England Power Company,
The Narragansett Electric Company, and USGen Acquisition
Corporation, dated as of August 5, 1997 (PG&E Corporation's Form
10-Q for the quarter ended September 30, 1997 (File No. 1-12609,
Exhibit No. 10.1). Filed only as an exhibit to the Annual Report
on Form 10-K filed by PG&E Corporation under Commission File
Number 1-12609.
10.2 The Gas Accord Settlement Agreement, together with accompanying
tables, adopted by the California Public Utilities Commission on
August 1, 1997, in Decision 97-08-055. (PG&E Corporation and
Pacific Gas and Electric Company's Form 10-K for the year ended
December 31, 1997 (File No. 1-12609 and File No. 1-2348), Exhibit
No. 10.2.)
*10.3 PG&E Corporation Deferred Compensation Plan for Non-Employee
Directors, as amended and restated effective as of July 22, 1998.
(PG&E Corporation's Form 10-Q for the quarter ended September 30,
1998 (File No. 1-12609), Exhibit 10.2).
*10.4 PG&E Corporation Deferred Compensation Plan for Officers, as
amended and restated effective as of October 21, 1998.
*10.5 Description of Short-Term Incentive Plan for Officers of PG&E
Corporation and its subsidiaries, effective January 1, 1998.
*10.6 Description of Short-Term Incentive Plan for Officers of PG&E
Corporation and its subsidiaries, effective January 1, 1999.
*10.7 Supplemental Executive Retirement Plan of the Pacific Gas and
Electric Company, effective January 1, 1998.
*10.8 PG&E Corporation Supplemental Executive Retirement Savings Plan,
effective January 1, 1998.
*10.9 Pacific Gas and Electric Company Relocation Assistance Program
for Officers (Pacific Gas and Electric Company's Form 10-K for
fiscal year 1989 (File No. 1-2348), Exhibit 10.16).
*10.10 Postretirement Life Insurance Plan of the Pacific Gas and
Electric Company (Pacific Gas and Electric Company's Form 10-K
for fiscal year 1991 (File No. 1-2348), Exhibit 10.16).
*10.11 PG&E Corporation Retirement Plan for Non-Employee Directors, as
amended and terminated January 1, 1998. (PG&E Corporation Form
10-K for the year ended December 31, 1997, (File No. 1-12609),
Exhibit No. 10.13.)
*10.12 PG&E Corporation Long-Term Incentive Program, as amended and
restated effective as of October 21, 1998, including the PG&E
Corporation Stock Option Plan, Performance Unit Plan, and Non-
Employee Director Stock Incentive Plan.
*10.13 PG&E Corporation Executive Stock Ownership Program, effective
January 1, 1998, as amended October 21, 1998.
*10.14 PG&E Corporation Officer Severance Policy, effective as of
December 16, 1998.
*10.15 PG&E Corporation Director Grantor Trust Agreement dated April 1,
1998 (PG&E Corporation's Form 10-Q for the quarter ended March
31, 1998 (File No. 1-12609), Exhibit 10.1).
*10.16 PG&E Corporation Officer Grantor Trust Agreement dated April 1,
1998 (PG&E Corporation's Form 10-Q for the quarter ended March
31, 1998 (File No. 1-12609), Exhibit 10.2).
51
11. Computation of Earnings Per Common Share.
12.1 Computation of Ratios of Earnings to Fixed Charges for Pacific Gas
and Electric Company.
12.2 Computation of Ratios of Earnings to Combined Fixed Charges and
Preferred Stock Dividends for Pacific Gas and Electric Company.
13. 1998 Annual Report to Shareholders of PG&E Corporation and Pacific
Gas and Electric Company--portions of the 1998 Annual Report to
Shareholders under the headings "Selected Financial Data,"
"Management's Discussion and Analysis," "Report of Independent
Public Accountants," financial statements of PG&E Corporation
entitled "Statement of Consolidated Income," "Consolidated Balance
Sheet," "Statement of Consolidated Cash Flows," "Statement of
Consolidated Common Stock Equity," financial statements of Pacific
Gas and Electric Company entitled "Statement of Consolidated
Income," "Consolidated Balance Sheet," "Statement of Consolidated
Cash Flows," "Statement of Consolidated Common Stock Equity,
Preferred Stock and Preferred Securities," "Notes to Consolidated
Financial Statements" and "Quarterly Consolidated Financial Data
(Unaudited)" are included only. (Except for those portions which
are expressly incorporated herein by reference, such 1998 Annual
Report to Shareholders is furnished for the information of the
Commission and is not deemed to be "filed" herein.)
21. Subsidiaries of the Registrant (incorporated by reference from
PG&E Corporation's Statement by Holding Company Claiming Exemption
from the Public Utility Holding Company Act of 1935 under Rule 2
by filing Form U-3A-2 dated March 1, 1999, pages 1 through 34).
23. Consent of Arthur Andersen LLP.
24.1 Resolutions of the Boards of Directors of PG&E Corporation and
Pacific Gas and Electric Company authorizing the execution of the
Form 10-K.
24.2 Powers of Attorney.
27.1 Financial Data Schedule for the year ended December 31, 1998, for
PG&E Corporation.
27.2 Financial Data Schedule for the year ended December 31, 1998, for
Pacific Gas and Electric Company.
- --------
* Management contract or compensatory plan or arrangement required to be
filed as an exhibit to this report pursuant to Item 14(c) of Form 10-K.
The exhibits filed herewith are attached hereto (except as noted) and those
indicated above which are not filed herewith were previously filed with the
Commission and are hereby incorporated by reference. All exhibits filed
herewith or incorporated by reference are filed with respect to both PG&E
Corporation (File No. 1-12609) and Pacific Gas and Electric Company (File No.
1-2348), unless otherwise noted. Exhibits will be furnished to security
holders of PG&E Corporation or Pacific Gas and Electric Company upon written
request and payment of a fee of $0.30 per page, which fee covers only the
registrants' reasonable expenses in furnishing such exhibits. The registrants
agree to furnish to the Commission upon request a copy of any instrument
defining the rights of long-term debt holders not otherwise required to be
filed hereunder.
52
(b) Reports on Form 8-K
Reports on Form 8-K(/1/) during the quarter ended December 31, 1998, and
through the date hereof:
1. October 21, 1998
Item 5. Other Events
-- Year-to-Date Financial Results
2. November 4, 1998
Item 5. Other Events
A. Electric Industry Restructuring
3. November 25, 1998
Item 5. Other Events
A. Electric Industry Restructuring
4. January 20, 1999
Item 5. Other Events
A. 1998 Consolidated Earnings (unaudited)
B.1999 Outlook
C.Share Repurchase Program
5. February 17, 1999
Item 4. Changes in Registrant's Certifying Accountant
Item 5. Other Events
-- Share Repurchase Program
- --------
(1) Unless otherwise noted, all reports were filed under Commission File
Number 1-2348 (Pacific Gas and Electric Company) and Commission File
Number 1-12609 (PG&E Corporation)
53
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrants have duly caused this report to be
signed on their behalf by the undersigned, thereunto duly authorized, in the
City and County of San Francisco, on the 5th day of March, 1999.
PG&E CORPORATION PACIFIC GAS AND ELECTRIC COMPANY
(Registrant) (Registrant)
By /s/ Gary P. Encinas By /s/ Gary P. Encinas
--------------------------------- ---------------------------------
(Gary P. Encinas, Attorney-in-Fact) (Gary P. Encinas, Attorney-in-Fact)
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrants and in the capacities and on the dates indicated.
Signature Title Date
--------- ----- ----
A. Principal Executive Officers
*ROBERT D. GLYNN, JR. Chairman of the Board, Chief March 5, 1999
Executive Officer, and President
(PG&E Corporation)
*GORDON R. SMITH President and Chief Executive Officer
(Pacific Gas and Electric Company)
B. Principal Financial Officers
*MICHAEL E. RESCOE Senior Vice President, Chief March 5, 1999
Financial Officer, and Treasurer
(PG&E Corporation)
*KENT M. HARVEY Senior Vice President, Treasurer, and
Chief Financial Officer
(Pacific Gas and Electric Company)
C. Principal Accounting Officer
*CHRISTOPHER P. JOHNS Vice President and Controller March 5, 1999
(PG&E Corporation)
Vice President and Controller
(Pacific Gas and Electric Company)
D. Directors
*RICHARD A. CLARKE
*DAVID A. COULTER
*C. LEE COX
*WILLIAM S. DAVILA
*ROBERT D. GLYNN, JR.
*DAVID M. LAWRENCE Directors of PG&E Corporation and March 5, 1999
*RICHARD B. MADDEN Pacific Gas and Electric Company,
*MARY S. METZ except as noted
*REBECCA Q. MORGAN
*JOHN C. SAWHILL
*GORDON R. SMITH
(Director of Pacific Gas and
Electric Company, only)
*BARRY LAWSON WILLIAMS
*By /s/ Gary P. Encinas
----------------------------
(Gary P. Encinas, Attorney-in-Fact)
54
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Shareholders and the Board of Directors of
PG&E Corporation and Pacific Gas and Electric Company:
We have audited in accordance with generally accepted auditing standards,
the consolidated financial statements included in the PG&E Corporation and
Pacific Gas and Electric Company Annual Report to Shareholders incorporated by
reference in this Form 10-K, and have issued our report thereon dated February
8, 1999. Our audits were made for the purpose of forming an opinion on those
statements taken as a whole. The schedules listed in Part IV, Item 14. (a)(3)
in this Form 10-K are the responsibility of the management of PG&E Corporation
and of Pacific Gas and Electric Company and are presented for purposes of
complying with the Securities and Exchange Commission's rules and are not part
of the consolidated financial statements. These schedules have been subjected
to the auditing procedures applied in the audits of the consolidated financial
statements and, in our opinion, fairly state in all material respects the
financial data required to be set forth therein in relation to the
consolidated financial statements taken as a whole.
/s/ ARTHUR ANDERSEN LLP
San Francisco, California
February 8, 1999
55
SCHEDULE I--CONDENSED FINANCIAL INFORMATION OF PARENT
CONDENSED BALANCE SHEET
December 31,
--------------
1998 1997
------ ------
(in millions)
Assets:
Cash and cash equivalents.................................... $ 9 $ 1
Accounts Receivable
Related parties............................................ 448 149
Other current assets......................................... 2 --
------ ------
Total current assets..................................... 459 150
Property, plant, and equipment............................... 6 --
Construction work in progress................................ 2 --
------ ------
Total property, plant, and equipment......................... 8 --
Accumulated depreciation and decommissioning................. (1) --
------ ------
Net property, plant, and equipment........................... 7 --
Investments in subsidiaries.................................. 8,780 9,556
Other noncurrent assets...................................... 41 --
Other deferred charges....................................... 1 1
------ ------
Total Assets............................................. $9,288 $9,707
====== ======
Liabilities and Stockholders' Equity:
Current Liabilities
Short-term borrowings...................................... $ 683 $ --
Accounts payable
Related parties........................................... 221 635
Other..................................................... 9 10
Accrued taxes.............................................. 155 46
Dividends payable.......................................... 115 118
Other...................................................... 16 --
------ ------
Total current liabilities.................................. 1,199 809
Noncurrent Liabilities
Deferred income taxes...................................... 19 --
Other...................................................... 4 1
------ ------
Total noncurrent liabilities............................... 23 1
Stockholder's Equity
Common stock............................................... 5,862 6,366
Reinvested earnings........................................ 2,204 2,531
------ ------
Total stockholders' equity................................. 8,066 8,897
------ ------
Total Liabilities and Stockholders' Equity............... $9,288 $9,707
====== ======
SCHEDULE I--CONDENSED FINANCIAL INFORMATION FOR PARENT--(Continued)
CONDENSED STATEMENTS OF INCOME
For the years ended December 31, 1998 and 1997
1998 1997
------- -------
(in millions,
except per
share amounts)
Equity in earnings of subsidiaries......................... $ 684 $ 743
Operating expenses......................................... 1 (21)
Interest expense........................................... (52) (23)
Other income............................................... 5 --
------- -------
Income Before Income Taxes................................. 638 699
Less: Income taxes......................................... (83) (17)
------- -------
Net Income................................................. $ 721 $ 716
Elimination of intercompany profit......................... (2) --
------- -------
Income Available for Common Stock.......................... $ 719 $ 716
======= =======
Weighted Average Common Shares Outstanding................. 382 410
Earnings Per Common Share.................................. $ 1.88 $ 1.75
======= =======
CONDENSED STATEMENTS OF CASH FLOWS
For the years ended December 31, 1998 and 1997
1998 1997
------- -------
(in millions)
Cash Flows From Operating Activities
Net income............................................... $ 721 $ 716
Adjustments to reconcile net income to net cash provided
by operating activities:
Dividends received from consolidated subsidiaries...... 445 763
Other--net............................................. (1,291) (167)
------- -------
Net cash provided by operating activities................ $ (125) $ 1,312
Cash Flows From Investing Activities
Capital expenditures................................... (8) --
Investments in unregulated projects.................... (575) (150)
Repurchase of Utility stock holdings by parent......... 1,600 --
------- -------
Net cash provided by investing activities................ $ 1,017 $ (150)
Cash Flows From Financing Activities
Common stock repurchased............................... (1,158) (804)
Short-term debt issued--net............................ 683 --
Dividends paid......................................... (470) (367)
Other--net............................................. 61 10
------- -------
Net cash used by financing activities.................... (884) (1,161)
Net Change in Cash and Cash Equivalents.................. 8 1
Cash and Cash Equivalents at January 1................... 1 --
------- -------
Cash and Cash Equivalents at December 31................. $ 9 $ 1
======= =======
PG&E CORPORATION
SCHEDULE II--CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
For the years ended December 31, 1998, 1997, and 1996
Column A Column B Column C Column D Column E
Additions
---------------------
Balance
Balance at Charged Charged at end
beginning to costs to other of
Description of period and expenses accounts Deductions period
----------- ---------- ------------ -------- ---------- --------
(in thousands)
Valuation and qualifying
accounts deducted from
assets:
1998:
Allowance for
uncollectible
accounts............. $72,912 $10,978 $(2,893) $22,420(2) $58,577
======= ======= ======= ======= =======
1997:
Allowance for
uncollectible
accounts............. $57,904 $42,500 $ -- $27,492(2) $72,912
======= ======= ======= ======= =======
1996:
Reserve for deferred
project costs........ $ 5,710 $ -- $ -- $ 5,710(1) $ --
======= ======= ======= ======= =======
Allowance for
uncollectible
accounts............. $35,520 $55,566 $ 1,836 $35,018(2) $57,904
======= ======= ======= ======= =======
Reserve for land
costs................ $ 4,444 $ -- $ -- $ 4,444(1) $ --
======= ======= ======= ======= =======
- --------
(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.
PACIFIC GAS AND ELECTRIC COMPANY
SCHEDULE II--CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
For the years ended December 31, 1998, 1997, and 1996
Column A Column B Column C Column D Column E
Additions
---------------------
Balance
Balance at Charged Charged at end
beginning to costs to other of
Description of period and expenses accounts Deductions period
----------- ---------- ------------ -------- ---------- --------
(in thousands)
Valuation and qualifying
accounts deducted from
assets:
1998:
Allowance for
uncollectible
accounts............. $59,608 $10,007 $ 152 $22,420(2) $47,347
======= ======= ======= ======= =======
1997:
Allowance for
uncollectible
accounts............. $57,904 $30,718 $(1,836) $27,178(2) $59,608
======= ======= ======= ======= =======
1996:
Reserve for deferred
project costs........ $ 5,710 $ -- $ -- $ 5,710(1) $ --
======= ======= ======= ======= =======
Allowance for
uncollectible
accounts............. $35,520 $55,566 $ 1,836 $35,018(2) $57,904
======= ======= ======= ======= =======
Reserve for land
costs................ $ 4,444 $ -- $ -- $ 4,444(1) $ --
======= ======= ======= ======= =======
- --------
(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.
EXHIBIT INDEX
Exhibit
No. Description
------- -----------
3.1 Restated Articles of Incorporation of PG&E Corporation effective as of
December 19, 1996 (PG&E Corporation's Form 8-B (File No. 1-12609),
Exhibit 3.1).
3.2 By-Laws of PG&E Corporation amended as of January 27, 1999.
3.3 Restated Articles of Incorporation of Pacific Gas and Electric Company
effective as of May 6, 1998 (Pacific Gas and Electric Company's Form
10-Q for the quarter ended March 31, 1998 (File No. 1-2348), Exhibit
3.1).
3.4 By-Laws of Pacific Gas and Electric Company amended as of January 27,
1999.
4. First and Refunding Mortgage of Pacific Gas and Electric Company dated
December 1, 1920, and supplements thereto dated April 23, 1925,
October 1, 1931, March 1, 1941, September 1, 1947, May 15, 1950, May
1, 1954, May 21, 1958, November 1, 1964, July 1, 1965, July 1, 1969,
January 1, 1975, June 1, 1979, August 1, 1983, and December 1, 1988
(Registration No. 2-1324, Exhibits B-1, B-2, B-3; Registration No. 2-
4676, Exhibit B-22; Registration No. 2-7203, Exhibit B-23;
Registration No. 2-8475, Exhibit B-24; Registration No. 2-10874,
Exhibit 4B; Registration No. 2-14144, Exhibit 4B; Registration No. 2-
22910, Exhibit 2B; Registration No. 2-23759, Exhibit 2B; Registration
No. 2-35106, Exhibit 2B; Registration No. 2-54302, Exhibit 2C;
Registration No. 2-64313, Exhibit 2C; Registration No. 2-86849,
Exhibit 4.3; Pacific Gas and Electric Company's Form 8-K dated
January 18, 1989 (File No. 1-2348), Exhibit 4.2).
10.1 Asset Purchase Agreement by and among New England Power Company, The
Narragansett Electric Company, and USGen Acquisition Corporation,
dated as of August 5, 1997 (PG&E Corporation's Form 10-Q for the
quarter ended September 30, 1997 (File No. 1-12609, Exhibit No.
10.1). Filed only as an exhibit to the Annual Report on Form 10-K
filed by PG&E Corporation under Commission File Number 1-12609.
10.2 The Gas Accord Settlement Agreement, together with accompanying
tables, adopted by the California Public Utilities Commission on
August 1, 1997, in Decision 97-08-055. (PG&E Corporation and Pacific
Gas and Electric Company's Form 10-K for the year ended December 31,
1997, (File No. 1-12609 and File No. 1-2348), Exhibit No. 10.2.)
*10.3 PG&E Corporation Deferred Compensation Plan for Non-Employee
Directors, as amended and restated effective as of July 22, 1998.
(PG&E Corporation's Form 10-Q for the quarter ended September 30,
1998 (File No. 1-12609), Exhibit 10.2).
*10.4 PG&E Corporation Deferred Compensation Plan for Officers, as amended
and restated effective as of October 21, 1998.
*10.5 Description of Short-Term Incentive Plan for Officers of PG&E
Corporation and its subsidiaries, effective January 1, 1998.
*10.6 Description of Short-Term Incentive Plan for Officers of PG&E
Corporation and its subsidiaries, effective January 1, 1999.
*10.7 Supplemental Executive Retirement Plan of the Pacific Gas and Electric
Company, effective January 1, 1998.
*10.8 PG&E Corporation Supplemental Executive Retirement Savings Plan,
effective January 1, 1998.
*10.9 Pacific Gas and Electric Company Relocation Assistance Program for
Officers (Pacific Gas and Electric Company's Form 10-K for fiscal
year 1989 (File No. 1-2348), Exhibit 10.16).
*10.10 Postretirement Life Insurance Plan of the Pacific Gas and Electric
Company (Pacific Gas and Electric Company's Form 10-K for fiscal year
1991 (File No. 1-2348), Exhibit 10.16).
*10.11 PG&E Corporation Retirement Plan for Non-Employee Directors, as
amended and terminated January 1, 1998. (PG&E Corporation Form 10-K
for the year ended December 31, 1997, (File No. 1-12609), Exhibit No.
10.13.)
56
EXHIBIT
NO. DESCRIPTION
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*10.12 PG&E Corporation Long-Term Incentive Program, as amended and restated
effective as of October 21, 1998, including the PG&E Corporation
Stock Option Plan, Performance Unit Plan, and Non-Employee Director
Stock Incentive Plan.
*10.13 PG&E Corporation Executive Stock Ownership Program, effective January
1, 1998, as amended October 21, 1998.
*10.14 PG&E Corporation Officer Severance Policy, effective as of December
16, 1998.
*10.15 PG&E Corporation Director Grantor Trust Agreement dated April 1, 1998
(PG&E Corporation's Form 10-Q for the quarter ended March 31, 1998
(File No. 1-12609), Exhibit 10.1).
*10.16 PG&E Corporation Officer Grantor Trust Agreement dated April 1, 1998
(PG&E Corporation's Form 10-Q for the quarter ended March 31, 1998
(File No. 1-12609), Exhibit 10.2).
11. Computation of Earnings Per Common Share.
12.1 Computation of Ratios of Earnings to Fixed Charges for Pacific Gas and
Electric Company.
12.2 Computation of Ratios of Earnings to Combined Fixed Charges and
Preferred Stock Dividends for Pacific Gas and Electric Company.
13. 1998 Annual Report to Shareholders of PG&E Corporation and Pacific Gas
and Electric Company--portions of the 1998 Annual Report to
Shareholders under the headings "Selected Financial Data,"
"Management's Discussion and Analysis," "Report of Independent Public
Accountants," financial statements of PG&E Corporation entitled
"Statement of Consolidated Income," "Consolidated Balance Sheet,"
"Statement of Consolidated Cash Flows," "Statement of Consolidated
Common Stock Equity," financial statements of Pacific Gas and
Electric Company entitled "Statement of Consolidated Income,"
"Consolidated Balance Sheet," "Statement of Consolidated Cash Flows,"
"Statement of Consolidated Common Stock Equity, Preferred Stock and
Preferred Securities," "Notes to Consolidated Financial Statements"
and "Quarterly Consolidated Financial Data (Unaudited)" are included
only. (Except for those portions which are expressly incorporated
herein by reference, such 1998 Annual Report to Shareholders is
furnished for the information of the Commission and is not deemed to
be "filed" herein.)
21. Subsidiaries of the Registrant (incorporated by reference from PG&E
Corporation's Statement by Holding Company Claiming Exemption from
the Public Utility Holding Company Act of 1935 under Rule 2 by filing
Form U-3A-2 dated March 1, 1999, pages 1 through 34).
23. Consent of Arthur Andersen LLP.
24.1 Resolutions of the Boards of Directors of PG&E Corporation and Pacific
Gas and Electric Company authorizing the execution of the Form 10-K.
24.2 Powers of Attorney.
27.1 Financial Data Schedule for the year ended December 31, 1998, for PG&E
Corporation.
27.2 Financial Data Schedule for the year ended December 31, 1998, for
Pacific Gas and Electric Company.
The exhibits filed herewith are attached hereto (except as noted) and those
indicated above which are not filed herewith were previously filed with the
Commission and are hereby incorporated by reference. All exhibits filed
herewith or incorporated by reference are filed with respect to both PG&E
Corporation (File No. 1-12609) and Pacific Gas and Electric Company (File No.
1-2348), unless otherwise noted. Exhibits will be furnished to security
holders of PG&E Corporation or Pacific Gas and Electric Company upon written
request and payment of a fee of $0.30 per page, which fee covers only the
registrants' reasonable expenses in furnishing such exhibits. The registrants
agree to furnish to the Commission upon request a copy of any instrument
defining the rights of long-term debt holders not otherwise required to be
filed hereunder.
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* Management contract or compensatory plan or arrangement required to be filed
as an exhibit to this report pursuant to Item 14(c) of Form 10-K.
57