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, 1996
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
77 Beale Street 94177
P.O. Box 770000 (ZIP CODE)
San Francisco, California
(ADDRESS OF PRINCIPAL EXECUTIVE
OFFICES)
(415) 973-7000
(REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE)
SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:
NAME OF EACH EXCHANGE ON
TITLE OF EACH CLASS WHICH REGISTERED
- ------------------- ---------------------------
PG&E CORPORATION
Common Stock, no par value New York Stock Exchange and
Pacific Stock Exchange
PACIFIC GAS AND ELECTRIC COMPANY
First Preferred Stock, cumulative, American Stock Exchange and
par value $25 per share: Pacific Stock Exchange
Redeemable:
7.44% 5% Series A
7.04% 4.80%
6-7/8% 4.50%
5% 4.36%
Mandatorily Redeemable:
6.57% 6.30%
Nonredeemable:
6% 5-1/2% 5%
7.90% Cumulative Quarterly Income Preferred American Stock Exchange and
Securities, Series A (liquidation preference Pacific Stock 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 18, 1997:
PG&E Corporation Common Stock $9,460 million
Pacific Gas and Electric Company First Preferred Stock $453 million
COMMON STOCK OUTSTANDING AS OF FEBRUARY 18, 1997:
PG&E Corporation: 416,528,027
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 Annual Report
to Shareholders for the year ended
December 31, 1996.......................... Part II (Items 5, 6, 7 and 8)
Part IV (Item 14)
(2) Designated portions of the Joint Proxy
Statement relating to the 1997 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.............. 2
Electric Industry.............................................. 3
Gas Industry................................................... 4
Regulation of PG&E............................................... 5
State Regulation............................................... 5
Federal Regulation............................................. 5
Local Regulation............................................... 5
Licenses and Permits........................................... 5
Regulation of PG&E Corporation................................... 6
Rate Matters..................................................... 6
California Ratemaking Mechanisms............................... 6
1997 Revenues.................................................. 8
Future Ratemaking................................................ 9
Electric Ratemaking............................................ 9
Gas Ratemaking................................................. 11
Capital Requirements and Financing Programs...................... 11
Risk Management Programs......................................... 13
ELECTRIC UTILITY OPERATIONS...................................... 14
Electric Industry Restructuring Legislation...................... 14
Independent System Operator and Power Exchange................. 14
Direct Access.................................................. 14
Rate Levels and Recovery of CTCs............................... 14
Base Revenue Increases......................................... 15
Public Purpose Programs........................................ 15
Electric Operating Statistics.................................... 17
Electric Generating and Transmission Capacity.................... 18
Diablo Canyon.................................................... 20
Diablo Canyon Operations....................................... 20
Diablo Settlement.............................................. 20
Nuclear Fuel Supply and Disposal............................... 21
Insurance...................................................... 22
Decommissioning................................................ 22
Other Electric Resources......................................... 23
QF Generation and Other Power Purchase Contracts............... 23
Geothermal Generation.......................................... 24
Helms Pumped Storage Plant..................................... 24
Electric Load Forecast and Resource Planning and Procurement..... 24
Electric Transmission............................................ 25
GAS UTILITY OPERATIONS........................................... 26
Gas Operations................................................... 26
Gas Operating Statistics......................................... 27
Natural Gas Supplies............................................. 28
Gas Regulatory Framework......................................... 28
i
TABLE OF CONTENTS--(CONTINUED)
PAGE
----
Transportation Commitments..................................... 29
El Paso and PGT Capacity..................................... 29
Transwestern Capacity........................................ 30
Gas Reasonableness Proceedings................................. 30
1988-1990 Canadian Gas Procurement Activities................ 30
Gas Settlement Agreement..................................... 31
PGT/PG&E Pipeline Expansion ................................... 31
CPUC Ratemaking.............................................. 31
FERC Ratemaking.............................................. 32
DIVERSIFIED OPERATIONS......................................... 32
PG&E ENVIRONMENTAL MATTERS..................................... 33
Environmental Matters.......................................... 33
Environmental Protection Measures............................ 33
Hazardous Waste Compliance and Remediation................... 34
Potential Recovery of Hazardous Waste Compliance and
Remediation Costs............................................ 36
Compressor Station Litigation................................ 36
Electric and Magnetic Fields................................. 36
Low Emission Vehicle Programs................................ 37
FORMATION OF PG&E CORPORATION.................................. 38
Item 2. Properties..................................................... 39
Item 3. Legal Proceedings.............................................. 39
Antitrust Litigation......................................... 39
Counties Franchise Fees Litigation........................... 39
Cities Franchise Fees Litigation............................. 40
Norcen Litigation............................................ 41
California Attorney General Investigation.................... 41
Diablo Canyon Environmental Litigation....................... 42
Compressor Station Chromium Litigation....................... 42
Item 4. Submission of Matters to a Vote of Security Holders............ 43
EXECUTIVE OFFICERS OF THE REGISTRANT........................... 44
PART II
Item 5. Market for the Registrant's Common Equity and Related
Stockholder Matters............................................ 46
Item 6. Selected Financial Data........................................ 46
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations.......................................... 46
Item 8. Financial Statements and Supplementary Data.................... 46
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure........................................... 46
PART III
Item 10. Directors and Executive Officers of the Registrant............. 46
Item 11. Executive Compensation......................................... 47
Item 12. Security Ownership of Certain Beneficial Owners and Management. 47
Item 13. Certain Relationships and Related Transactions................. 47
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on
Form 8-K...................................................... 47
Signatures............................................................... 52
Report of Independent Public Accountants................................. 53
Financial Statement Schedule............................................. 54
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
Bechtel......... Bechtel Enterprises, Inc.
BCAP............ Biennial Cost Allocation Proceeding
BRPU............ Biennial Resource Plan Update
BTA............. best technology available
Btu............. British thermal unit
California
Superfund...... California Hazardous Substance Account Act
CARE............ California Alternate Rates for Energy
CCAA............ California Clean Air Act
CEC............. California Energy Commission
Central Coast
Board.......... Central Coast Regional Water Quality Control Board
CERCLA.......... Comprehensive Environmental Response, Compensation, and Liability Act
CIG............. customer identified gas program
Company......... Pacific Gas and Electric Company and its subsidiaries, or PG&E
Corporation and its subsidiaries, as determined by the context
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 costs
Diablo Canyon... Diablo Canyon Nuclear Power Plant
Diablo
Settlement..... Diablo Canyon rate case settlement
DOE............. U.S. Department of Energy
DSM............. Demand Side Management
ECAC............ Energy Cost Adjustment Clause
EDRA............ electric deferred refund account
El Paso......... El Paso Natural Gas Company
EMF............. electric and magnetic fields
Enterprises..... PG&E Enterprises
EPA............. United States Environmental Protection Agency
ERAM............ Electric Revenue Adjustment Mechanism
ESI............. Energy Source, Inc.
FERC............ Federal Energy Regulatory Commission
Gas Accord...... Gas Accord Settlement
Geysers......... The Geysers Power Plant
GRC............. General Rate Case
Helms........... Helms hydroelectric pumped storage plant
Holding Company
Act............ Public Utility Holding Company Act of 1935
Humboldt........ Humboldt Bay Power Plant
ICIP............ Incremental Cost Incentive Price
InterGen........ International Generating Company, Ltd.
ISO............. Independent System Operator
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
NEIL............ Nuclear Electric Insurance Limited
NML............. Nuclear Mutual Limited
noncore
customers...... industrial and larger commercial gas customers
NOx............. oxides of nitrogen
NRC............. Nuclear Regulatory Commission
Nuclear Waste
Act............ Nuclear Waste Policy Act of 1982
ORA............. Office of Ratepayer Advocates, formerly known as the Division of
Ratepayer Advocates
PBR............. performance-based ratemaking
PEPR............ Pipeline Expansion Project Reasonableness case
PG&E............ Pacific Gas and Electric Company
PG&E Expansion.. the PG&E portion of the Pipeline Expansion
PGT............. Pacific Gas Transmission Company
PGT Expansion... the PGT portion of the Pipeline Expansion
Pipeline
Expansion...... PGT/PG&E Pipeline Expansion
PPPs............ public purpose programs
PRP............. potentially responsible party
PX.............. California Power Exchange
QF.............. qualifying facility
RAP............. Revenue Adjustment Proceeding
SEC............. Securities and Exchange Commission
Teco............ Teco Pipeline Company
TRA............. Transition Revenue Account
transition
period......... the period during which electric rates are frozen at 1996 levels, which
extends until the earlier of March 31, 2002 or the point in time when
PG&E has recovered its transition costs
Transwestern.... Transwestern Pipeline Company
TURN............ The Utility Reform Network
USGen........... U.S. Generating Company
USOSC........... U.S. Operating Services Company
Vantus.......... Vantus Energy Corporation
Valero.......... Valero Natural Gas Company
PART I
ITEM 1. BUSINESS.
GENERAL
CORPORATE STRUCTURE AND BUSINESS
PG&E Corporation was incorporated in California in 1995 for the purpose of
becoming the parent holding company of Pacific Gas and Electric Company
(PG&E). Effective January 1, 1997, PG&E became a subsidiary of PG&E
Corporation. PG&E's ownership interest in PG&E Enterprises (Enterprises) and
Pacific Gas Transmission Company (PGT) has been transferred to PG&E
Corporation. PG&E's outstanding common stock was converted on a share-for-
share basis into PG&E Corporation common stock. PG&E's debt securities and
preferred stock were unaffected and remain securities of PG&E. The
consolidated financial statements of PG&E incorporated herein include the
accounts of PG&E and its wholly-owned and controlled subsidiaries
(collectively, the Company), and, therefore, also represent the accounts of
PG&E Corporation and its subsidiaries (also referred to collectively as, the
Company). For financial information summarizing certain pro forma financial
effects of the restructuring of PG&E, see "Formation of PG&E Corporation"
below.
The principal executive offices of PG&E Corporation and PG&E are located at
77 Beale Street, P.O. Box 770000, San Francisco, California 94177, and their
telephone number is (415) 973-7000.
PG&E, incorporated in California in 1905, is an operating public utility
engaged principally in the business of providing electric and natural gas
services throughout most of Northern and Central California. As of December
31, 1996, the Company had $26.1 billion in assets. The Company generated $9.6
billion in operating revenues for 1996. As of December 31, 1996, the Company
had approximately 22,000 employees.
PG&E's gas and electric utility operations, which include Diablo Canyon
Nuclear Power Plant (Diablo Canyon) operations, represent the principal
component of its business, contributing $9.2 billion in revenues in 1996 (96%
of the Company's total revenues). PG&E's utility operations contributed $1.83
of the Company's total 1996 earnings per share of $1.75. (Utility earnings
were offset by losses at Enterprises.)
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. In 1996, Diablo Canyon contributed $1.8 billion of revenues (19% of
the Company's total revenues) and $1.18 in earnings per share (67% of the
Company's total 1996 earnings per share). PG&E has proposed a modification to
existing Diablo Canyon ratemaking, which if adopted, would significantly
reduce PG&E's future revenues from Diablo Canyon operations. See "Future
Ratemaking--Electric Ratemaking" below.
PG&E'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, 1996, PG&E served approximately 4.5 million electric
customers. PG&E serves its electric customers with power generated by seven
primarily natural gas-fueled steam power plants with 21 units, ten combustion
turbines, Diablo Canyon's two units, 68 hydroelectric powerhouses with 109
units, the Helms hydroelectric pumped storage plant (Helms) with three units,
and a geothermal energy complex of 14 units. (PG&E has announced plans to sell
four fossil-fueled power plants, with an aggregate of 12 units, in connection
with the ongoing electric industry restructuring. See "Electric Utility
Operations--Electric Industry Restructuring Legislation" below.) PG&E 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, PG&E is interconnected with
electric power systems in 14 western states and British Columbia, Canada, for
the purposes of buying, selling, and transmitting power.
1
PG&E served approximately 3.7 million gas customers at December 31, 1996. To
ensure a diverse and competitive mix of natural gas supplies, PG&E purchases
gas from both Canadian and United States suppliers. In 1996, about 65% of
PG&E's gas supply came from fields in Canada, about 7% came from fields in
California, and about 28% came from fields in other states (substantially all
from the U.S. Southwest).
PG&E's utility operations in 1996 also included PGT's gas pipeline
operations. PGT owns and operates gas transmission pipelines and associated
facilities capable of transporting approximately 2.4 billion cubic feet per
day of natural gas over 612 miles from the Canada-U.S. border to the Oregon-
California border, as well as two smaller diameter pipeline extensions within
Oregon, totaling 106 miles. In 1996, PGT acquired the PGT Queensland Gas
Pipeline, an approximately 389-mile 12-inch pipeline in Queensland, Australia,
which provides natural gas transportation service to customers in the vicinity
of the pipeline. As noted above, at present PGT is a wholly owned subsidiary
of PG&E Corporation.
Building on its expertise in the energy industry, PG&E Corporation is
expanding its operations in the "midstream" portion of the gas business, the
independent power generation business, and the energy services business. The
midstream portion of the gas business includes gas gathering, processing,
storage, and transportation. The energy services business includes obtaining
gas and electricity from competitive producers, arranging for distribution and
transmission service, and providing customized energy billing and analysis,
power quality assessments, energy efficiency products and services, and
facility improvements.
Enterprises, through its subsidiaries and affiliates, develops, owns, and
operates unregulated electric and gas projects both in and outside the United
States. Vantus Energy Corporation (Vantus), a subsidiary of Enterprises,
markets gas and electricity commodities and provides energy services. In 1996,
Enterprises generated approximately $127 million in revenues and accounted for
$(0.08) of the Company's total 1996 earnings per share of $1.75. As noted
above, Enterprises is now a wholly owned subsidiary of PG&E Corporation.
In December 1996, PGT acquired the gas marketing operations of Edisto
Resources Corporation in the United States and Canada, known jointly as Energy
Source, Inc. (ESI). The acquisition included most of ESI's existing contracts
for the purchase, sale, and transportation of natural gas and natural gas
futures. In January 1997, PG&E Corporation acquired Teco Pipeline Company
(Teco) in Texas. Teco is an owner of a 500-mile natural gas pipeline system in
Texas. Teco also has investments in gas gathering and processing facilities,
and owns a gas marketing company in Houston, Texas. Also in January 1997, PG&E
Corporation agreed to acquire Valero Natural Gas Company (Valero). Valero's
operations include the gathering, transportation, marketing, and storage of
natural gas, the processing, transportation, and marketing of natural gas
liquids, and the marketing of electric power. Valero operates approximately
7,500 miles of natural gas pipeline and also owns and operates approximately
540 miles of natural gas liquid pipelines and eight natural gas processing
plants in Texas. The acquisition is expected to be completed by mid-1997 and
is subject to applicable regulatory and shareholder approvals.
The following discussion of the Company's business includes some forward-
looking statements that involve risks and uncertainties. Words such as
"estimates," "expects," "anticipates," "plans," and similar expressions
identify forward-looking statements involving risks and uncertainties. Those
risks and uncertainties include, but are not limited to, the ongoing
restructuring of the electric and gas industries and the outcome of regulatory
proceedings related to that restructuring. The ultimate impacts of both
increased competition and the changing regulatory environment on future
results are uncertain, but are expected to fundamentally change how the
Company conducts its business. The outcome of these changes and other matters
discussed below may cause future results to differ materially from historic
results, or from results or outcomes currently expected or sought by the
Company.
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
2
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 are challenging the utilities' exclusive relationship with
their customers and are seeking to replace certain utility functions with
their own. Customers, too, are asking for choice in their energy provider.
These pressures are causing a move from the existing regulatory framework to a
framework under which competition would be allowed in certain segments of the
gas and electric industries.
For several years, PG&E has been working with its regulators to achieve an
orderly transition to competition and to ensure that PG&E has an opportunity
to recover investments made under traditional regulatory policies. In
addition, PG&E has proposed alternative forms of regulation for those services
for which prices and terms will not be determined by competition. These
alternative forms include performance-based ratemaking (PBR) and other
incentive-based alternatives. Over the next five years, a significant portion
of PG&E's business will be transformed from the current utility monopoly to a
competitive operation. This change will impact PG&E's financial results and
may result in greater earnings volatility. During the transition period, PG&E
expects the return on Diablo Canyon and certain other generation assets to be
significantly lower than historical levels.
ELECTRIC INDUSTRY
In 1995, the California Public Utilities Commission (CPUC) issued a decision
that provides a plan to restructure California's electric industry. The
decision acknowledges that much of utilities' current costs and commitments
result from past CPUC decisions and that, in a competitive generation market,
utilities would not recover some of these costs through market-based revenues.
To assure the continued financial integrity of California utilities, the CPUC
authorized recovery of these above-market costs, called competition transition
costs, or CTCs, through a nonbypassable charge to be collected over a period
of years.
In 1996, legislation on electric industry restructuring, Assembly Bill 1890
(AB 1890), was signed into law in California. AB 1890 adopts the basic tenets
of the CPUC's restructuring decision and establishes the operating framework
for a competitive electric generation market. Key features of AB 1890 include:
--mandatory unbundling of transmission, distribution, and generation
services;
--formation by January 1, 1998, of a California Power Exchange (PX) to
provide a competitive auction process to establish the price of
electricity;
--establishing an Independent System Operator (ISO) to ensure system
reliability and provide electric generators with open and comparable
access to transmission and distribution services;
--an electric rate freeze at 1996 levels until the earlier of March 31,
2002, or the point in time when PG&E has recovered its CTCs (the
transition period);
--a 10% rate reduction by January 1, 1998, for residential and small
commercial customers, financed through "rate reduction bonds";
--nonbypassable charges to provide the opportunity for utilities to recover
their CTCs and required accelerated recovery of CTCs associated with
utility owned generation facilities;
--direct access for all electric customers;
--market valuation for utility owned fossil generation assets by 2001,
followed by an end to cost-of-service ratemaking for most plants; and
--continued support for renewable generation resources, conservation and
other public purpose programs.
Under AB 1890, PG&E and other utilities will continue to own transmission
and distribution facilities and must continue to offer bundled electric
service to customers who request it.
3
Recent regulatory changes enacted at the federal level are also changing the
electric industry. In 1996, the Federal Energy Regulatory Commission (FERC)
paved the way for the transition to more competitive electric markets by
providing open access to electric transmission. See "Electric Utility
Operations--Electric Transmission" below.
Additional information concerning electric industry restructuring, the
expected operating framework for a competitive generation market and the
financial impact of these changes on the Company is provided in "Management's
Discussion and Analysis of Consolidated Results of Operations and Financial
Condition" in the 1996 Annual Report to Shareholders, beginning on page 9, and
in Note 2 of the "Notes to Consolidated Financial Statements" beginning on
page 29 of the 1996 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.
PG&E's customers may buy commodity gas directly from competing suppliers and
purchase transmission- and distribution-only services from PG&E. PG&E's
transmission and distribution services have remained "bundled," or sold
together at a combined rate, within California. PGT, as an interstate
pipeline, has provided nondiscriminatory transmission-only service since 1993,
and no longer sells commodity gas.
Most of PG&E's industrial and larger commercial (noncore) customers purchase
their commodity gas from marketers and brokers. Substantially all residential
and smaller commercial (core) customers continue to buy commodity gas as well
as transmission and distribution from PG&E as a bundled service.
In 1995 and 1996, PG&E actively pursued changes in the California gas
industry in an effort to promote competition and increase options for all
customers, as well as to position itself for the competitive marketplace. In
1996, PG&E submitted to the CPUC the Gas Accord Settlement (Gas Accord). The
Gas Accord is the result of an extensive negotiation process, begun in 1995,
among a broad coalition of customer groups and industry participants. The Gas
Accord must be approved by the CPUC before it can be implemented. A CPUC
decision is expected in 1997.
The Gas Accord consists of three broad initiatives:
--The Gas Accord would separate, or "unbundle," PG&E's gas transmission and
storage services from its distribution services and would change the
terms of service and rate structure for gas transportation. Unbundling
would give customers the opportunity to select from a menu of services
offered by PG&E and would enable them to pay only for the services they
use. PG&E would be at risk for variations in revenues resulting from
differences between actual and forecasted transmission throughput. PG&E
would also continue to provide cost-of-service based distribution
service, much as it does today.
--The Gas Accord would increase opportunities for PG&E's core customers to
purchase gas from competing suppliers and, therefore, could reduce PG&E's
role in procuring gas for such customers. However, PG&E would continue to
procure gas as a regulated utility supplier for those customers who
request it. The Gas Accord also would establish principles for continuing
negotiations between PG&E and California gas producers for the mutual
release of supply contracts and the sale of gas gathering facilities.
Also related to PG&E's procurement activities, PG&E has proposed that
traditional reasonableness reviews of its core gas costs be replaced with
a core procurement incentive mechanism (CPIM) for the period June 1,
1994, through 2002. See "Future Ratemaking--Gas Ratemaking" below.
--The Gas Accord would resolve various regulatory issues including the
recovery of certain capital costs associated with the PG&E portion (PG&E
Expansion) of the PGT/PG&E Pipeline Expansion (Pipeline Expansion),
recovery of costs related to PG&E's capacity commitments with
Transwestern Pipeline Company (Transwestern) through 2002, certain
disallowances ordered by the CPUC in connection with PG&E's 1988 through
1995 gas reasonableness proceedings, and the recovery, through the
Interstate
4
Transition Cost Surcharge (ITCS), of fixed demand charges paid to El Paso
Natural Gas Company (El Paso) and PGT for firm capacity held by PG&E on
behalf of its customers.
Additional information concerning gas industry restructuring, and the
financial impact of these changes on the Company is provided in "Management's
Discussion and Analysis of Consolidated Results of Operations and Financial
Condition" in the 1996 Annual Report to Shareholders, beginning on page 13,
and in Note 3 of the "Notes to Consolidated Financial Statements" beginning on
page 31 of the 1996 Annual Report to Shareholders.
REGULATION OF PG&E
STATE REGULATION
The CPUC consists of five members appointed by the governor and confirmed by
the senate for six-year terms. The CPUC regulates PG&E's rates and conditions
of service, sales of securities, dispositions of utility property, rate of
return, rates of depreciation, uniform systems of accounts, examination of
records, long-term resource procurement, and transactions between PG&E and its
subsidiaries and affiliates. The CPUC also conducts various reviews of utility
performance and conducts investigations into various matters, such as
deregulation, competition, and the environment, to determine its future
policies.
The California Energy Commission (CEC) has discretion over electric-demand
forecasts for the state and for specific service territories. Based upon these
forecasts, the CEC determines the need for additional energy sources and for
conservation programs. The CEC sponsors alternative-energy research and
development projects, promotes energy conservation programs, and maintains a
state-wide plan of action in case of energy shortages. In addition, the CEC
certifies power-plant sites and related facilities within California.
Beginning January 1, 1998, the CEC will also administer funding for public
purpose research and development, and renewable technologies programs. The
funding will be collected from ratepayers through a nonbypassable public
benefits charge. See "Electric Utility Operations--Electric Industry
Restructuring Legislation--Public Purpose Programs" below.
FEDERAL REGULATION
Both PG&E and PGT are subject to regulation by the FERC. The FERC regulates
electric transmission rates and access, compliance with the uniform systems of
accounts, and electric contracts involving sales for resale. The FERC also
regulates the interstate transportation of natural gas. In addition, most of
PG&E'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. NRC
regulations require extensive monitoring and review of the safety,
radiological, and environmental aspects of these facilities.
LOCAL REGULATION
PG&E has separate electric and gas franchises with the 48 counties and the
241 cities in its service territory. These franchises allow PG&E to locate
facilities for the transmission and distribution of electricity and gas in the
streets and other public ways. With few exceptions, the franchises do not have
fixed terms and remain in effect as long as PG&E meets the terms and
conditions of the franchises. PG&E is currently involved in litigation brought
by several counties and cities who have granted franchises to PG&E. See
Item 3, Legal Proceedings, "Counties Franchise Fees Litigation" and "Cities
Franchise Fees Litigation" below for more information.
LICENSES AND PERMITS
PG&E obtains a number of permits, authorizations, and licenses in connection
with the construction and operation of its generating plants. Discharge
permits, various Air Pollution Control District permits, FERC hydroelectric
facility licenses, and NRC licenses are the most significant examples. Some
licenses and permits
5
may be revoked or modified by the granting agency if facts develop or events
occur that differ significantly from the facts and projections assumed in
granting the approval. Furthermore, discharge permits and other approvals and
licenses are granted for a term less than the expected life of the associated
facility. Licenses and permits may require periodic renewal, which may result
in additional requirements imposed by the granting agency.
REGULATION OF PG&E CORPORATION
PG&E Corporation and its subsidiaries are exempt from all provisions, except
Section 9(a)(2), of the Public Utility Holding Company Act of 1935 (Holding
Company Act) on the basis that PG&E Corporation and PG&E are incorporated in
the same state and their business is predominantly intrastate in character and
carried on substantially in the state of incorporation. It is necessary for
PG&E Corporation to file an annual exemption statement with the Securities and
Exchange Commission (SEC), and the exemption may be revoked by the SEC upon a
finding that the exemption may be detrimental to the public interest or the
interest of investors or consumers. At present, PG&E Corporation has no
intention 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 PG&E to form a holding company was granted subject to various
conditions related to finance, human resources, record and book-keeping, and
the transfer of customer information. The financial conditions provide that
PG&E is precluded from guaranteeing any obligations of PG&E Corporation
without prior written consent from the CPUC, PG&E's dividend policy shall
continue to be established by PG&E's Board of Directors as though PG&E were a
comparable stand-alone utility company, and the capital requirements of PG&E,
as determined to be necessary to meet PG&E's service obligations, shall be
given first priority by the Boards of Directors of PG&E Corporation and PG&E.
The conditions also provide that PG&E shall maintain on average its CPUC-
authorized utility capital structure, although it shall have an opportunity to
request a waiver of this condition in the event an adverse financial event
reduces the utility's equity ratio by 1% or more.
PG&E Corporation and PG&E have agreed to be subject to the conditions
included in the CPUC approval. PG&E Corporation may also be subject to
additional conditions based upon the outcome of an audit of affiliate
transactions currently underway. The audit is being conducted by an outside
consultant and supervised by the CPUC's Office of Ratepayer Advocates (ORA),
formerly known as the Division of Ratepayer Advocates.
Other regulatory matters are described throughout this report.
RATE MATTERS
CALIFORNIA RATEMAKING MECHANISMS
The principal ratemaking mechanisms currently applied by the CPUC in setting
PG&E's revenue requirements are described below. It is expected that many of
these mechanisms may be changed significantly or eliminated as both the
electric and gas utility industries are restructured and regulatory reforms
proposed by PG&E and government authorities are implemented. See "Future
Ratemaking" below.
PG&E's utility operations, other than Diablo Canyon, are regulated primarily
under the traditional cost-based approach to ratemaking. In 1996, Diablo
Canyon operations were regulated under a performance-based approach under
which revenues for the plant are based primarily on the amount of electricity
generated, rather than on the costs associated with the plant's operations.
However, PG&E has proposed a significant modification to Diablo Canyon
ratemaking. See "Electric Utility Operations--Diablo Canyon--Diablo
Settlement" below.
PG&E's basic business and operational costs for its utility operations,
other than Diablo Canyon, are recovered through base revenues. Base revenues
are intended to recover operation and maintenance expenses (excluding fuel
expenses, fuel-related energy costs, and purchased power costs), depreciation
expense, taxes, and return on invested capital. Base revenue requirements are
currently set in general rate case (GRC) proceedings
6
held before the CPUC every three years. (PG&E's current base revenues were set
in the 1996 GRC; its next scheduled GRC would establish base revenue
requirements effective January 1, 1999.)
During a GRC, the CPUC critically reviews PG&E's operations and general
costs to provide service (excluding energy costs and, in certain instances,
major plant additions), and then determines the revenue requirement to cover
those costs. The revenue requirement is forecasted on the basis of a specified
test year. (The return component of PG&E's revenue requirement is computed
using the overall cost of capital authorized by the CPUC in the annual Cost of
Capital consolidated proceeding, in which financing costs are reviewed and
capital structures for all California energy utilities are adopted.) 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 Electric Revenue Adjustment Mechanism (ERAM) allows rate adjustments to
offset the effect on base revenues of differences between actual electric
sales volumes and the forecasted volumes used to set rates in the last GRC.
The ERAM eliminates the impact on earnings of sales fluctuations, including
those resulting from conservation and weather conditions. Base revenue
differences resulting from the disparity between actual and forecasted
electric sales accumulate in a balancing account, with interest. ERAM rate
adjustments are made as part of the Energy Cost Adjustment Clause (ECAC)
proceeding described below.
Most of PG&E's fuel, purchased-power, and energy-related costs of providing
electric service, as well as revenues attributable to Diablo Canyon
generation, are recovered through a balancing account mechanism called the
ECAC. Under the ECAC balancing account procedure, actual costs are compared
with revenues designated for recovery of such costs, and the difference is
recorded as either an undercollection or overcollection. The differential
between forecasted Diablo Canyon revenues under the Diablo Canyon rate case
settlement (Diablo Settlement) and actual revenues also is tracked in the ECAC
balancing account. In prior years, rates would be adjusted such that the
amount of overcollections would be returned to ratepayers through lower rates
and undercollections would be recovered through higher rates. However, as part
of the electric industry restructuring, PG&E's electric rates have been frozen
at 1996 levels, and the recorded overcollection in PG&E's ECAC/ERAM balancing
accounts, if any, as of December 31, 1996, will be applied to offset PG&E's
CTCs. See "1997 Revenues" below. The disposition of 1997 balancing accounts is
being addressed at the CPUC in connection with electric industry
restructuring. PG&E has proposed to recover 1997 year end balancing account
balances through the CTC ratemaking mechanism.
The Annual Energy Rate (AER) mechanism has provided for recovery of 9% of
forecasted electric fuel and fuel-related costs, without balancing account
protection for differences between actual and forecasted costs. However, the
AER was indefinitely suspended by the CPUC in a December 1996 decision.
In December 1996, the CPUC issued a decision establishing an electric
deferred refund account (EDRA). The CPUC ordered PG&E to place into the EDRA
credits for CPUC-ordered electric disallowances, the utility electric
generation share of CPUC-ordered gas disallowances, electric and utility
electric generation gas settlement amounts resulting from reasonableness
disputes and fuel-related cost refunds made to PG&E based on regulatory agency
decisions, plus interest charges. The CPUC ordered PG&E to file advice letters
by January 31 of each year, setting forth its annual refund plans for directly
refunding to electric customers the dollars accumulated in the EDRA. The CPUC
also ordered PG&E to include initially in the EDRA any such credits which were
already recorded in the ECAC and ERAM but had not yet been amortized in rates.
The effect of this is to reduce the amount available to offset PG&E's CTCs by
approximately $75 million. PG&E is seeking rehearing of this decision at the
CPUC. PG&E is also seeking an injunction in federal court to block the refund
of $50 million of the initial EDRA amount pending resolution of PG&E's lawsuit
challenging the disallowance order issued in PG&E's 1988-1990 gas
reasonableness proceeding that gave rise to that portion of the initial EDRA
amount.
Fuel and fuel-related costs included in an ECAC adjustment are subject to a
subsequent reasonableness review, in which the CPUC determines whether those
costs were reasonably incurred. Costs found to be unreasonable may be
disallowed, or deducted, from the amount to be recovered in rates. Currently,
the amount of Diablo Canyon revenues recovered through the ECAC is determined
under the Diablo Settlement and is not subject to reasonableness review. See
"Electric Utility Operations--Diablo Canyon--Diablo Settlement" below.
7
The Biennial Cost Allocation Proceeding (BCAP) is the major rate proceeding
for PG&E's natural gas service, other than service on the PG&E Expansion which
is addressed in a separate proceeding. Rates to recover the cost of gas
procured for customers who buy gas from PG&E and the cost of providing gas
transportation service for gas customers are determined in the BCAP. 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 and sales volumes are similar to those for
electric fuel costs and sales volumes.
In addition to adopting the gas revenue requirements in the BCAP, the CPUC
also allocates both the gas fuel and transportation revenue requirements among
core and noncore classes and among the customer groups within those classes.
The BCAP also includes the rate design process, in which it is determined how
specific costs are recovered from customers, with rates set accordingly.
1997 REVENUES
Cost Recovery Plan. In December 1996, the CPUC approved the cost recovery
plan filed by PG&E in compliance with AB 1890. The provisions of the plan
approved by the CPUC include a freeze of electric rates at 1996 levels
beginning on January 1, 1997, and pursuant to the provisions of AB 1890, an
increase in PG&E's electric base revenues for 1997 of approximately $164
million to be used to enhance transmission and distribution system safety and
reliability. In January 1997, The Utility Reform Network (TURN) filed an
application for rehearing of the CPUC's decision. TURN's application for
rehearing argues that the CPUC exceeded its authority in interpreting AB 1890
to authorize a base revenue increase for PG&E, and that the CPUC's decision
requires clarification to ensure that any such base revenue increase as is
granted is used only to fund activities which are supplemental to those funded
in the most recent GRC. PG&E believes it is entitled to the base revenue
increase provided for in AB 1890. However, if the CPUC were to find that those
funds were not properly used to supplement PG&E's system safety and
reliability expenditures, the CPUC might order disallowances that could
negatively impact 1997 earnings.
ECAC. In December 1996, the CPUC issued a decision in PG&E's ECAC
proceeding, authorizing a decrease in electric revenue requirements of
approximately $720 million. The three elements of this decrease are: (1) a
reduction in ECAC revenues of approximately $565 million; (2) a reduction in
ERAM revenues of approximately $153 million; and (3) an increase in the
California Alternate Rates for Energy (CARE) program, which supports energy
rate discounts for low income customers, of approximately $2 million. This net
reduction of approximately $720 million is partially offset by an electric
revenue requirement increase of approximately $164 million resulting from the
consolidation of revenue changes from the ERAM component of other proceedings,
the base revenue increase authorized by AB 1890 and included in PG&E's cost
recovery plan, the Cost of Capital proceeding, and the Annual Energy
Assessment Proceeding (AEAP), which sets rate adjustments resulting from
shareholder incentives earned on demand side management (DSM), or energy
efficiency, programs. The ECAC decision also indefinitely suspends the AER
mechanism, which had placed PG&E at partial risk for variations between actual
and forecasted electric energy costs.
Cost of Capital. The CPUC's decision in the 1997 Cost of Capital proceeding
authorized a utility return on common equity of 11.60%, a continuation of the
1996 level. The decision authorizes a utility capital structure for PG&E of
48.00% common equity, 5.80% preferred stock, and 46.20% long-term debt. The
combined authorized costs of debt, preferred stock, and the 11.60% return on
common equity result in an overall return on utility rate base (excluding
Diablo Canyon and the PG&E Expansion) of 9.45%, a decrease from the 9.49%
authorized for 1996. (However, actual returns for 1997 are expected to be
substantially less than authorized levels as a result of the electric industry
restructuring. See "Future Ratemaking--Electric Ratemaking" below.) Also as
part of the Cost of Capital decision, the CPUC set the authorized return on
equity and capital structure for the PG&E Expansion. See "Gas Utility
Operations--PGT/PG&E Pipeline Expansion--CPUC Ratemaking" below.
BCAP. The CPUC's December 1995 decision in PG&E's last BCAP authorized an
increase of approximately $60 million in annual gas revenues beginning January
1, 1996. In November 1996, PG&E submitted an interim filing, as permitted
under the BCAP mechanism to set new rates for the second year of the
8
two-year BCAP period. If approved by the CPUC, the filing would result in an
approximately $17 million increase in total gas revenues effective upon CPUC
approval, which is not reflected in the table below.
AEAP. The CPUC's December 1996 decision in the annual AEAP, which determines
shareholder incentives earned for PG&E's DSM programs, adopted an incentive
payment of approximately $72 million for PG&E's 1995 programs, to be collected
in installments over a 10-year period. After consolidating incentive payment
installments from prior years, the net revenue change in 1997 from DSM
shareholder incentives is an electric increase of approximately $9 million and
a gas decrease of approximately $2 million.
The consolidated effect of these decisions on authorized revenue
requirements for 1997 is indicated in the table below:
SUMMARY OF RATE CASE DECISIONS
EFFECTIVE AS OF JANUARY 1, 1997
(IN MILLIONS)
ELECTRIC GAS TOTAL
-------- --- -----
ECAC/ERAM/CARE/AER......................................... $(720) $-- $(720)
AB 1890 base revenue increase.............................. 164 -- 164
1997 Cost of Capital....................................... (5) (2) (7)
ERAM in other proceedings.................................. (4) -- (4)
BCAP....................................................... -- -- --
AEAP....................................................... 9 (2) 7
----- --- -----
Total Change in Authorized Revenue Requirement from
1996 Levels........................................... $(556) $(4) $(560)
===== === =====
Pursuant to PG&E's cost recovery plan and AB 1890, electric rates will not
be changed from 1996 levels. Instead, the consolidated net reduction in
electric revenue requirements of approximately $556 million will be available
to offset PG&E's CTCs and any increase in revenue requirements resulting from
PG&E's proposed cost recovery plan.
FUTURE RATEMAKING
Although it is clear that ratemaking for both electric and gas utilities in
California will be significantly different in the future as a result of the
ongoing restructuring in both industries, many of the specifics concerning how
rates will be set, adjusted, and billed after 1997 remain to be resolved by
the relevant regulatory authorities, utilities, and other interested parties.
Outlined below are the more significant regulatory rulings to date on this
issue, and some of the proposals made by PG&E in connection with changes to
ratemaking in the new restructured markets.
ELECTRIC RATEMAKING
In December 1996, the CPUC issued a "roadmap" decision outlining the
necessary steps to accomplish electric industry restructuring and commence the
transition period no later than January 1, 1998. In that decision, the CPUC
notes that ratemaking has not changed in that the CPUC will still determine
the rate components, revenue allocation, and rate design necessary to derive a
rate for each customer class. However, the CPUC recognizes that the process
must be revised to accommodate changes in the electric industry necessary for
implementation of AB 1890 and the new market structure beginning in 1998. A
consideration of necessary changes includes unbundling of rates, transition
costs, PBR, and other activities that affect rates and revenue requirements.
In its roadmap decision, the CPUC establishes a separate annual proceeding
to consider ratemaking issues related to each electric utility's revenues,
which will consolidate all pending revenue changes and track utility revenues
at present rate levels for the purpose of comparison with authorized amounts.
This annual Revenue Adjustment Proceeding (RAP) will be designed to annually
review, track, and compare each electric utility's authorized revenue
requirements with the actual recorded revenues, and to make any necessary
adjustments or
9
updates due to authorized revenues from PBR mechanisms and other proceedings,
or revenues for various power purchase contracts, public purpose programs,
nuclear facilities, nuclear decommissioning, and transition costs. The
differential between actual recorded revenues and the consolidated authorized
revenue requirement will be applied to recover CTCs. The authorized revenues
will be established in their respective proceedings and consolidated into the
RAP. The first RAP will begin in 1998.
PG&E has filed numerous regulatory applications and proposals that detail
its cost recovery plan during the transition period. PG&E's recovery plan
includes: (1) separation or unbundling of its previously approved cost-of-
service revenue requirement for its electric operations into distribution,
transmission, public purpose programs (PPPs), and generation, (2) accelerated
recovery of transition costs, and (3) development of a ratemaking mechanism to
track and match revenues and cost recovery during the transition period.
PG&E's unbundling application, filed in December 1996, proposes to unbundle
PG&E's revenue requirements, enabling it to separate revenues provided by
frozen rates into transmission, distribution, PPPs, and generation. As
proposed, revenues collected under frozen rates would be assigned to
transmission, distribution, and PPPs, based upon their respective cost of
service. Revenue would also be provided for other costs, including nuclear
decommissioning, rate-reduction-bond debt service, the ongoing cost of
generation, and CTC recovery. The combination of a rate freeze and decreasing
costs, based upon existing ratemaking and cost recovery periods, provides an
adequate amount of revenue available for full CTC recovery. PG&E's unbundling
application also presents a method to separate electric rates into the four
functional cost categories of PPPs, distribution, transmission, and generation
(including energy costs based on the PX price, and CTCs, determined after all
other costs are accounted for), effective January 1, 1998. Bills for all
customers would describe what portion of the bill is attributable to
transmission, distribution, PPPs, energy, and CTCs and other nonbypassable
charges. PG&E's unbundling application also proposes to replace the ECAC and
ERAM during the transition period with a single balancing account, the
Transition Revenue Account (TRA). The TRA would be functionally equivalent to
the current system in that it would match revenues with cost components. With
the TRA, CTC would be the only cost component for which recovery during the
transition period would be affected by any variation in billed revenues due to
sales fluctuations.
PG&E has proposed to accelerate recovery for certain CTCs related to
generation facilities, including Diablo Canyon. Additionally, PG&E would
receive a reduced return on common equity associated with generation plant
assets for which recovery is accelerated. The lower return is intended to
reflect reduced risk associated with the shorter amortization period and
increased certainty of recovery.
In applying its cost recovery plan to Diablo Canyon, PG&E has proposed a
significant modification to the existing Diablo Canyon ratemaking. Under the
current Diablo Settlement, Diablo Canyon revenues are based on a pre-
established price per kWh of plant generation. PG&E proposes to replace the
existing settlement price with: (1) a sunk cost revenue requirement to recover
fixed costs, including a return on those fixed costs, and (2) a PBR mechanism
to recover the facility's variable costs and capital addition costs. As
proposed, the sunk cost revenue requirement would accelerate recovery of
Diablo Canyon sunk costs from a twenty-year period ending in 2016 to a five-
year period beginning in 1997 and ending in 2001. The related return on common
equity associated with Diablo Canyon sunk costs would be reduced to 90% of
PG&E's long-term cost of debt. PG&E's authorized long-term cost of debt was
7.52% in 1996. The reduced rate of return combined with a shorter recovery
period would result in an estimated $4.0 billion decrease in the net present
value of PG&E's future revenues from Diablo Canyon operations. If the proposed
cost recovery plan for Diablo Canyon had been adopted during 1996, Diablo
Canyon's 1996 reported net income would have been reduced by $350 million
($0.85 per share). The assigned CPUC administrative law judge (ALJ) has issued
a proposed decision on PG&E's proposal to modify existing Diablo Canyon
ratemaking. With significant exceptions, the proposed decision generally
adopts the overall ratemaking structure proposed by PG&E, but would
substantially alter the proposed ICIP mechanism and would exclude certain
items from the sunk cost revenue requirement. See "Electric Utility
Operations--Diablo Canyon--Diablo Settlement" below for more information
regarding PG&E's proposed modification and the proposed decision issued by the
ALJ. The proposed decision is not a final decision of the CPUC, and is subject
10
to change prior to a vote of the full CPUC. The proposed decision currently is
scheduled for consideration by the full CPUC at its April 9, 1997 meeting.
PG&E has proposed a PBR mechanism for recovery of its hydroelectric and
geothermal generating unit costs. The proposed mechanism consists of a base
revenue amount that is adjusted to account for inflation less a productivity
offset. In its unbundling application, PG&E proposed a starting point for the
hydroelectric/geothermal generation PBR at approximately $545 million in 1998.
Under the AB 1890 cost recovery plan submitted by PG&E and approved by the
CPUC, the difference between the authorized revenue requirement for these
units and revenues earned at PX prices would be credited against CTC recovery
if, as currently expected, the revenues earned at market prices exceed the
cost of operating these facilities as set under the PBR mechanism.
Additional information concerning the Company's transition cost recovery
plan, the financial impact of electric industry restructuring and these
various proposals is provided in "Management's Discussion and Analysis of
Consolidated Results of Operations and Financial Condition" in the 1996 Annual
Report to Shareholders, beginning on page 9, and in Notes 2 and 4 of the
"Notes to Consolidated Financial Statements" beginning on pages 29 and 32,
respectively, of the 1996 Annual Report to Shareholders.
GAS RATEMAKING
As noted above (see "Competition and the Changing Regulatory Environment--
Gas Industry" above), PG&E has submitted to the CPUC the Gas Accord, which
would offer increased customer choice, establish gas transmission rates for
the period July 1997 through December 2002, and resolve various pending
regulatory issues. The Gas Accord must be approved by the CPUC before it can
be implemented. Among other things, the Gas Accord would unbundle PG&E's gas
transmission and storage services from its distribution services and would
change the terms of service and rate structure for gas transportation.
Unbundling would give customers the opportunity to select from a menu of
services offered by PG&E and would enable them to pay only for the services
they use. PG&E would be at risk for variations in revenues resulting from
differences between actual and forecasted transmission throughput. PG&E would
continue to provide cost-of-service based distribution service, much as it
does today. Additional information concerning the potential financial impact
of the Gas Accord is provided in "Management's Discussion and Analysis of
Consolidated Results of Operations and Financial Condition" in the 1996 Annual
Report to Shareholders, beginning on page 13, and in Note 3 of the "Notes to
Consolidated Financial Statements" beginning on page 31 of the 1996 Annual
Report to Shareholders.
As part of the Gas Accord, PG&E has proposed that traditional reasonableness
reviews of its core gas costs be replaced with a CPIM for the period June 1,
1994, through 2002. Under the CPIM, PG&E would be able to recover its gas
commodity and interstate transportation costs and would receive benefits or be
penalized depending on whether its actual core procurement costs were within,
below, or above a "tolerance band" constructed around market benchmarks.
Actual core procurement costs measured for the period June 1, 1994, through
December 31, 1996, have generally been within the CPIM "tolerance band." The
CPIM proposal also requests authorization to use derivative financial
instruments to reduce the risk of gas price and foreign currency fluctuations.
Gains, losses, and transaction costs associated with the use of derivative
financial instruments would be included in the purchased gas account and the
measurement against the benchmarks.
CAPITAL REQUIREMENTS AND FINANCING PROGRAMS
PG&E and PGT 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's and PGT's expenditures
for these purposes, including the allowance for funds used during construction
(AFUDC), were approximately $1,244 million for 1996. New investments totaled
$159 million in 1996.
11
The following table sets forth PG&E Corporation's estimated total capital
requirements, consisting of capital expenditures for PG&E's utility functions,
including Diablo Canyon, as well as capital requirements for PGT and
diversified operations and amounts for maturing debt and sinking funds for the
years 1997 through 1999. These are forward-looking statements which involve a
number of assumptions and uncertainties. Actual amounts may differ materially
from the estimated amounts shown below.
PG&E CORPORATION CAPITAL REQUIREMENTS
(IN MILLIONS)
1997 1998 1999 TOTAL
---- ---- ---- -----
Utility(1)......................................... $1,773 $1,825 $1,705 $5,303
Diablo Canyon...................................... 38 39 41 118
Diversified Operations(2)
U.S. Generating Company(3)........................ 160 57 169 386
Other(4).......................................... 51 23 3 77
------ ------ ------ ------
Total Capital Expenditures....................... 2,022 1,944 1,918 5,884
Maturing Debt and Sinking Funds.................... 210 660 270 1,140
------ ------ ------ ------
Total Capital Requirements....................... $2,232 $2,604 $2,188 $7,024
====== ====== ====== ======
- --------
(1) Utility expenditures include PG&E's electric and gas operations and PGT's
gas pipeline operations, are shown net of reimbursed capital, and include
AFUDC.
(2) Actual capital expenditures may vary significantly depending on the
availability of attractive investment opportunities. PG&E has announced an
agreement to sell its interest in International Generating Company, Ltd.
in 1997 and capital requirements for that company are not included in the
table.
(3) U.S. Generating Company expenditures include commitments by PG&E
Corporation, PG&E, and/or Enterprises to make capital contributions for
Enterprises' equity share of currently identified generating facility
projects. These contributions, payable upon commercial operation of the
projects, are estimated to be $52 million and $15 million in 1997 and
1998, respectively.
(4) Other expenditures include ongoing capital requirements for ESI and Teco.
Most of Utility and Diablo Canyon capital expenditures for 1997 through 1999
are associated with short lead time, modest capital expenditure projects aimed
at the replacement and enhancement of existing facilities, and compliance with
environmental laws and regulations. Also included are expenditures to improve
the safety and reliability of PG&E's electric transmission and distribution
system consistent with AB 1890, as well as major projects associated with
customer service improvements.
PG&E Corporation estimates that its total capital requirements for the years
1997 through 1999 will include approximately $1,140 million for payment at
maturity of outstanding long-term debt and for meeting sinking fund
requirements for debt, as indicated above.
The funds necessary for 1997-1999 capital requirements of PG&E Corporation
and its subsidiaries will be obtained from (i) internal sources, principally
net income before noncash charges for depreciation and deferred income taxes,
and (ii) external sources, including short-term financing, such as bank loans
and the sale of short-term notes, and long-term financing, such as sales of
equity and long-term debt securities, when and as required.
PG&E Corporation and its subsidiaries and affiliates conduct a continuing
review of their capital expenditures and financing programs. The programs and
estimates above are subject to revision and actual amounts may vary based upon
changes in assumptions as to system load growth, rates of inflation, receipt
of adequate and timely rate relief, availability and timing of regulatory
approvals, total cost of major projects, availability and cost of suitable
nonregulated investments, and availability and cost of external sources of
capital, as well as the outcome of the ongoing restructuring in both the
electric and gas industries.
12
In January 1997, PG&E Corporation acquired Teco and its subsidiaries for
approximately $380 million, consisting of the purchase of a $61 million note,
and $319 million of PG&E Corporation common stock. Also in January 1997, PG&E
Corporation agreed to acquire Valero for approximately $1.5 billion,
consisting of approximately $720 million of PG&E Corporation common stock and
the assumption of debt and liabilities. The cost of these acquisitions is not
included in the table above, nor are estimates of expected ongoing capital
requirements for Valero.
RISK MANAGEMENT PROGRAMS
Due to the changing business environment, the Company's exposure to risks
associated with changes in energy commodity prices, interest rates, and
foreign currencies is increasing. To manage these risks, the Company has
adopted a price risk management policy and established an officer-level price
risk management committee. The Company's price risk management committee
oversees implementation of the policy, approves each price risk management
program, and monitors compliance with the policy.
The Company's price risk management policy and procedures adopted by the
committee establish guidelines for implementation of price risk management
programs. Such programs may include the use of energy and financial
derivatives. (A derivative is a contract whose value is dependent on or
derived from the value of some underlying asset.) Additionally, the Company's
policy allows derivatives to be used for hedging and non-hedging purposes.
(Hedging is the process of protecting one transaction by means of another to
reduce price risk.) Both hedging and non-hedging activities are limited to
those specifically approved by the committee only after appropriate controls
and procedures are put in place to measure, monitor, and control the risk of
such activities. The Company's policy prohibits the use of derivatives whose
payment formula includes a multiple of some underlying asset.
In 1996, the Company approved and implemented interest rate and foreign
exchange risk management programs, applied for regulatory approval to use
energy derivatives to manage commodity price risk in its utility business, and
acquired certain natural gas marketing operations which engage in both hedging
and non-hedging derivative transactions. Gains and losses associated with
price risk management activities during 1996 were immaterial.
Additional information concerning the Company's risk management activities
is provided in "Management's Discussion and Analysis of Consolidated Results
of Operations and Financial Condition" in the 1996 Annual Report to
Shareholders, beginning on page 18, and in Note 1 of the "Notes to
Consolidated Financial Statements" on page 28 of the 1996 Annual Report to
Shareholders.
13
ELECTRIC UTILITY OPERATIONS
ELECTRIC INDUSTRY RESTRUCTURING LEGISLATION
In 1996, comprehensive legislation on electric industry restructuring, in
the form of AB 1890, was signed into law in California. AB 1890 adopted the
basic tenets of the CPUC's 1995 restructuring decision and provides guidance
to the CPUC on a number of implementation issues. Although many details remain
to be worked out, implementation of AB 1890 will have a significant impact on
PG&E's electric utility operations beginning as early as 1998.
Major provisions of AB 1890 include the following:
INDEPENDENT SYSTEM OPERATOR AND POWER EXCHANGE
AB 1890 requires the CPUC to facilitate the development of an ISO and a PX,
and establishes a five-member Oversight Board to oversee the ISO and PX and
appoint the members of the ISO and PX Governing Boards. The ISO and PX
Governing Boards will include representatives of investor owned utility
transmission owners, publicly owned utility transmission owners, nonutility
electricity sellers, public buyers and sellers, private buyers and sellers,
industrial end-users, commercial end-users, residential end-users,
agricultural end-users, public interest groups, and non-market participant
representatives. In a November 1996 order approving in concept the proposed
ISO/PX framework, the FERC limited the ongoing role of the Oversight Board and
eliminated the requirement of AB 1890 that members of the Oversight Board be
residents of California.
Under AB 1890, it is intended that both California's investor owned
utilities and its publicly owned utilities commit control 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.
To prevent undue influence on the PX price by any participant in the
competitive framework, PG&E has indicated that it is willing to proceed with
voluntary divestiture of at least 50% of its fossil-fueled power plants as
directed by the CPUC. PG&E has filed an application seeking approval from the
CPUC to sell four plants (comprised of 12 units) before the end of 1997. The
book value for these plants is approximately $400 million, and together they
generate approximately 10% of PG&E's total electric sales. PG&E proposes to
recover any shortfall in proceeds from divestitures of these plants as CTCs.
DIRECT ACCESS
AB 1890 authorizes direct transactions between electricity suppliers and
customers, beginning January 1, 1998, and on a phased-in schedule, if
justified by technical considerations, through December 31, 2001, that is
equitable to all customer classes. Aggregation of customer electrical load for
such direct transactions is authorized.
RATE LEVELS AND RECOVERY OF CTCS
AB 1890 provides for a 10% rate reduction for residential and small
commercial electric customers, freezes electric customer rates for all other
customers, and requires the accelerated recovery of CTCs associated with
utility owned generation facilities. The rate freeze will continue until the
end of the transition period, which extends to the earlier of March 31, 2002,
or until PG&E has recovered its CTCs. The freeze will hold rates at 1996
levels for all customers except those receiving the 10% rate reduction. The
rate freeze will hold the rates for these customers at the reduced level.
To achieve the 10% rate reduction, AB 1890 authorizes utilities to finance a
portion of their CTCs with "rate reduction bonds." PG&E expects to work with
state authorities to coordinate the issuance of up to
14
$2.5 billion of these bonds by a special purpose entity. The maturity period
of the bonds is expected to extend beyond the transition period. Also, the
interest cost of the bonds is expected to be lower than PG&E's current cost of
capital. Once the bonds are issued, PG&E would collect, on behalf of the
special purpose entity, a separate tariff to recover principal, interest, and
issuance costs over the life of the bonds from residential and small
commercial customers. The combination of the longer maturity period and the
reduced interest costs will lower the amounts paid by these customers each
year during the transition period thereby achieving the 10% reduction in
rates. PG&E does not expect to secure the bonds with the Company's assets or
unrelated future revenues.
AB 1890 authorizes utilities to recover transition costs, or CTCs (the
uneconomic costs of their generation-related assets and obligations, including
regulatory assets and the costs associated with nuclear ratemaking settlements
such as the Diablo Settlement), from all customers (with certain exceptions)
through a nonbypassable charge included as part of rates over the period
ending December 31, 2001. Recovery may extend beyond December 31, 2001, for
certain CTCs, such as certain employee-related transition costs (recoverable
through December 31, 2006) and costs resulting from implementation of direct
access and creation of the PX and ISO, and above market costs associated with
power purchase agreements. As a prerequisite to any consumer obtaining direct
access services, the consumer must agree to pay its applicable nonbypassable
CTC charge.
CTCs associated with utility owned fossil generation would be limited to
regulatory assets and the uneconomic net book value of the fossil capital
investment as of January 1, 1998, plus the costs of capital additions
subsequent to December 20, 1995, that the CPUC determines are reasonable and,
in the case of fossil plant additions, are necessary to maintain the
facilities through December 31, 2001. CTCs associated with utility owned
generation-related costs not recovered during the transition period will be
absorbed by PG&E. Operating costs for such facilities would generally be
recoverable through market-based rates, excluding facilities that are required
to be operated for reliability purposes by the ISO. Operating costs for those
facilities would be recovered on a cost-of-service basis through ISO
contracts. CTCs associated with existing power purchase contracts, such as
those for purchases from qualifying facilities (QFs), also would be
recoverable through nonbypassable rates, except that the recovery period would
be over the duration of the contract or any restructuring thereof.
Nuclear decommissioning costs would continue to be recovered through a
nonbypassable charge separate from CTCs until fully recovered. Recovery of
nuclear decommissioning costs may be accelerated.
BASE REVENUE INCREASES
AB 1890 provides for annual increases in base revenues for PG&E, effective
in 1997 and 1998, equal to the inflation rate for the prior year plus two
percentage points. Given the rate freeze, the base revenue increase would
reduce the amount available for CTC recovery. The increases will remain in
effect pending PG&E's next GRC, which will set rates effective January 1999.
The base revenue increases must be used for enhancing transmission and
distribution system safety and reliability, and any such revenues not expended
for such purposes must be credited against subsequent safety and reliability
revenue requirements in future years.
In December 1996, the CPUC approved the cost recovery plan filed by PG&E in
compliance with AB 1890, which included an increase in PG&E's electric base
revenues for 1997 of approximately $164 million to be used to enhance
transmission and distribution system safety and reliability as contemplated by
AB 1890. TURN has filed an application for rehearing of the CPUC's decision,
challenging the base revenue increase. See "General--Rate Matters--1997
Revenues" above.
PUBLIC PURPOSE PROGRAMS
Under AB 1890, energy efficiency, research and development, and low income
programs will be funded in electric rates pursuant to a separate,
nonbypassable charge at current levels from January 1, 1998, through December
31, 2001. Under this provision, PG&E is obligated to fund through electric
rates energy efficiency and conservation programs at not less than $106
million per year, research and development programs at not less than $30
million per year, and renewable technologies at not less than $48 million per
year.
15
In February 1997, the CPUC adopted a decision that changes the way these
programs will be administered, beginning after 1997. Currently, PG&E and other
utilities administer public purpose programs for energy efficiency and
conservation, research and development and low income customer assistance.
Under the CPUC's decision, the CPUC will appoint independent boards to oversee
energy efficiency and low income assistance programs. These boards will
solicit competitive bids to determine who will administer the programs from
January 1, 1998, through 2001. PG&E or an affiliate will be permitted to bid
for administration of the energy efficiency programs. The decision also turns
over administration of the funding for research and development, and renewable
technologies programs to the CEC, beginning January 1, 1998.
Additional information concerning AB 1890 and its financial impact on the
Company is provided in "Management's Discussion and Analysis of Consolidated
Results of Operations and Financial Condition" in the 1996 Annual Report to
Shareholders, beginning on page 9, and in Note 2 of the "Notes to Consolidated
Financial Statements" beginning on page 29 of the 1996 Annual Report to
Shareholders.
16
ELECTRIC OPERATING STATISTICS
The following table shows PG&E'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
--------------------------------------------------------
1996 1995 1994 1993 1992
---------- ---------- ---------- ---------- ----------
CUSTOMERS (AVERAGE FOR THE
YEAR):
Residential.............. 3,874,223 3,825,413 3,788,044 3,748,831 3,708,374
Commercial............... 459,001 454,718 452,049 449,619 455,480
Industrial............... 1,248 1,253 1,260 1,243 1,207
Agricultural............. 87,250 88,546 90,520 91,376 94,562
Public street and highway
lighting................ 17,583 17,089 16,709 16,096 15,681
Other electric utilities. 28 35 29 28 24
---------- ---------- ---------- ---------- ----------
Total.................. 4,439,333 4,387,054 4,348,611 4,307,193 4,275,328
========== ========== ========== ========== ==========
GENERATED, RECEIVED AND
SOLD -- KWH (IN
MILLIONS):
Generated:
Hydroelectric plants..... 15,158 16,608 7,791 14,403 7,537
Thermal-electric plants:
Fossil fueled........... 11,620 13,729 29,543 19,070 26,623
Geothermal.............. 4,514 4,001 6,024 6,491 7,007
Nuclear................. 16,720 16,269 15,265 16,816 16,698
---------- ---------- ---------- ---------- ----------
Total thermal-electric
plants................ 32,854 33,999 50,832 42,377 50,328
Wind and solar plants.... 2 1 1 -- --
Received from other
sources(1).............. 57,134 54,935 47,199 48,859 46,243
---------- ---------- ---------- ---------- ----------
Total gross system
output(2)............. 105,148 105,543 105,823 105,639 104,108
Delivered for interchange
or exchange............. 4,000 4,261 3,275 8,848 3,912
Delivered for the account
of others(1)............ 19,356 18,946 18,622 13,726 17,235
Helms pumpback energy(3). 898 937 467 452 398
PG&E use, losses,
etc.(4)................. 6,500 6,040 7,838 6,960 7,278
---------- ---------- ---------- ---------- ----------
Total energy sold...... 74,394 75,359 75,621 75,653 75,285
========== ========== ========== ========== ==========
POWER PLANT FUEL SUPPLY
(IN THOUSANDS):
Natural gas (equivalent
barrels)................ 20,193 23,143 44,119 28,791 43,446
Fuel oil................. 686 756 2,395 2,080 171
Nuclear (equivalent
barrels)................ 28,574 27,814 26,135 28,724 28,540
---------- ---------- ---------- ---------- ----------
Total.................. 49,453 51,713 72,649 59,595 72,157
========== ========== ========== ========== ==========
POWER PLANT FUEL COSTS
(AVERAGE COST PER MILLION
BTU'S):
Natural gas.............. $ 1.83 $ 2.06 $ 2.19 $ 2.86 $ 2.61
Fuel oil................. $ 2.66 $ 1.28 $ 2.83 $ 3.49 $ 3.13
Weighted average......... $ 1.92 $ 2.03 $ 2.23 $ 2.90 $ 2.62
SALES -- KWH (IN
MILLIONS):
Residential.............. 25,458 24,391 24,326 24,111 23,664
Commercial............... 27,868 27,014 26,195 26,258 26,246
Industrial............... 15,786 16,879 16,010 16,492 16,600
Agricultural............. 3,631 3,478 4,426 3,672 4,741
Public street and highway
lighting................ 438 425 418 419 400
Other electric utilities. 1,213 3,172 4,246 4,701 3,634
---------- ---------- ---------- ---------- ----------
Total energy sold...... 74,394 75,359 75,621 75,653 75,285
========== ========== ========== ========== ==========
REVENUES (IN THOUSANDS):
Residential.............. $3,033,613 $2,979,590 $2,980,966 $2,952,893 $2,790,605
Commercial............... 2,840,101 2,964,568 2,892,302 2,914,855 2,864,817
Industrial............... 1,005,694 1,160,938 1,128,561 1,183,728 1,210,754
Agricultural............. 396,469 395,531 477,330 419,628 478,941
Public street and highway
lighting................ 55,372 56,154 55,545 55,976 53,133
Other electric utilities. 81,855 133,566 201,133 242,433 185,555
---------- ---------- ---------- ---------- ----------
Revenues from energy
sales................. 7,413,104 7,690,347 7,735,837 7,769,513 7,583,805
Miscellaneous............ 112,303 92,538 142,771 87,991 51,716
Regulatory balancing
accounts................ (365,192) (396,578) 142,939 19,421 127,490
---------- ---------- ---------- ---------- ----------
Operating revenues..... $7,160,215 $7,386,307 $8,021,547 $7,876,925 $7,763,011
========== ========== ========== ========== ==========
- --------
(1) Includes energy supplied through PG&E's system by the City and County of
San Francisco for San Francisco's own use and for sale by San Francisco to
its customers, by the Department of Energy for government use and sale to
its customers, and by the State of California for California Water Project
pumping, as well as energy supplied by QFs and purchases from other
utilities.
(2) Includes energy output from Modesto and Turlock Irrigation Districts' own
resources.
(3) Represents energy required for pumping operations.
(4) Includes use by business units other than the electric utility business
units.
17
YEARS ENDED DECEMBER 31
-------------------------------------------------
1996 1995 1994 1993 1992
--------- --------- --------- --------- ---------
SELECTED STATISTICS:
Total customers (at year-
end)....................... 4,500,000 4,400,000 4,400,000 4,400,000 4,300,000
Average annual residential
usage (kWh)................ 6,571 6,377 6,422 6,431 6,381
Average billed revenues per
kWh (cents):
Residential................ 11.92 12.22 12.25 12.25 11.79
Commercial................. 10.19 10.97 11.04 11.10 10.92
Industrial................. 6.37 6.88 7.05 7.18 7.29
Agricultural............... 10.92 11.37 10.78 11.43 10.10
Net plant investment per
customer ($)............... 3,198 3,228 3,362 3,436 3,428
Electric control area
capability(megawatts)(1)... 22,724 22,099 21,851 23,009 22,475
Electric net control area
peak demand(megawatts)(2).. 21,437 20,317 19,118 19,607 18,594
- --------
(1) Area net capability at time of annual peak, based on actual water
conditions.
(2) Net control area peak demand includes demand served by Modesto and Turlock
Irrigation Districts' own resources.
ELECTRIC GENERATING AND TRANSMISSION CAPACITY
As of December 31, 1996, PG&E owned and operated the following generating
plants, all located in California, listed by energy source:
NET
OPERATING
NUMBER CAPACITY
GENERATION TYPE COUNTY LOCATION OF UNITS KW
--------------- --------------- -------- ----------
Hydroelectric:
Conventional Plants(1)......... 16 counties in Northern and 109 2,698,100
Central California
Helms Pumped Storage Plant..... Fresno 3 1,212,000
--- ----------
Hydroelectric Subtotal....... 112 3,910,100
--- ----------
Steam Plants:
Contra Costa................... Contra Costa 2 680,000
Humboldt Bay................... Humboldt 2 105,000
Hunters Point(2)............... San Francisco 3 377,000
Morro Bay(2)................... San Luis Obispo 4 1,002,000
Moss Landing(2)................ Monterey 2 1,478,000
Pittsburg...................... Contra Costa 7 2,022,000
Potrero........................ San Francisco 1 207,000
--- ----------
Steam Subtotal................. 21 5,871,000
--- ----------
Combustion Turbines:
Hunters Point.................. San Francisco 1 52,000
Oakland(2)..................... Alameda 3 165,000
Potrero........................ San Francisco 3 156,000
Mobile Turbines(3)............. Humboldt and Mendocino 3 45,000
--- ----------
Combustion Turbines Subtotal... 10 418,000
--- ----------
Geothermal:
The Geysers Power Plant(4)..... Sonoma and Lake 14 1,224,000
Nuclear:
Diablo Canyon.................. San Luis Obispo 2 2,160,000
--- ----------
Thermal Subtotal............. 47 9,673,000
--- ----------
Total................................................... 159 13,583,100
=== ==========
- --------
(1) Two hydroelectric plants with approximately 5,000 kW of net operating
capacity were sold in 1996.
(2) PG&E has announced plans to sell these power plants in connection with
electric industry restructuring.
(3) Listed to show capability; subject to relocation within the system as
required.
(4) The Geysers Power Plant net operating capacity is based on adequate
geothermal steam supply conditions. Any decrease in capacity, at peak, is
included as unavailable capacity in the Control Area Net Capacity table
below.
18
The following table sets forth the available capacity for the control area
(the area served by PG&E and various publicly owned systems in Northern
California) at the date of peak (including reduction for scheduled and forced
outages and based on actual water conditions) by various sources of generation
available to the control area and the total amount of generation provided by
these sources during the year ended December 31, 1996.
CONTROL AREA
NET CAPACITY
(AT DATE OF 1996 PEAK)
----------------------
KW %
-------------- -------
Sources of Electric Generation:
PG&E-Owned Plants:
Fossil Fueled.................... 6,289,000 48
Geothermal....................... 1,224,000 9
Nuclear.......................... 2,160,000 16
-------------- -------
Total Thermal................... 9,673,000 73
Hydroelectric (available)........ 3,603,300 27
Solar............................ 0 0
-------------- -------
Total PG&E-Owned Capacity........ 13,276,300 100
============== =======
Less Unavailable Capacity........ 2,750,000
--------------
Total PG&E Available Capacity.... 10,526,300 46
Capacity Received from Others:
QF Producers (available)......... 3,039,600 14
Area Producers & Imports......... 9,158,100 40
-------------- -------
Capacity from Others............. 12,197,700 54
-------------- -------
Total Available Capacity......... 22,724,000 100
============== =======
Total Area Demand(1)(2)........... 21,437,000
==============
GENERATION
YEAR ENDED
DECEMBER 31, 1996(3)
--------------------
KWH
THOUSANDS %
-------------- ------
Electric Generation:
PG&E-Owned Plants:
Fossil Fueled................... 11,619,910 11
Geothermal...................... 4,514,643 4
Nuclear......................... 16,719,721 17
-------------- ------
Total Thermal.................. 32,854,274 32
Hydroelectric................... 15,157,798 15
Solar........................... 1,580 0
Total PG&E Generation........... 48,013,652 --
-------------- ------
Helms Pumpback Energy........... (897,506) (1)
-------------- ------
Net PG&E Generation............. 47,116,146 46
============== ======
Generation Received from Others:
QF Producers.................... 20,351,814 20
Area Producers & Imports........ 34,532,040 34
-------------- ------
Generation from Others.......... 54,883,854 54
============== ======
Total Area Generation........... 102,000,000 100
============== ======
- --------
(1) The maximum control area peak demand to date was 21,437,000 kW which
occurred in August 1996.
(2) The reserve capacity margin at the time of the 1996 control area peak,
taking into account short-term firm capacity purchases from utilities
located outside PG&E's service area: PG&E's load responsibility for
spinning reserve (capability already connected to the system and ready to
meet instantaneous changes in demand) to the control area peak was 7.3% of
the peak demand and total reserve (spinning reserve and capability
available within a short period of time) was 7.8%.
(3) Represents actual year net generation from sources shown. Generation
received from others is based on the best available information at the
publication date of this document.
19
DIABLO CANYON
DIABLO CANYON OPERATIONS
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, 1996, Diablo Canyon Units 1 and 2 had achieved lifetime capacity factors
of 79.7% and 81.7%, respectively.
The table below outlines Diablo Canyon's refueling schedule for the next
five years. In the past, Diablo Canyon refueling outages typically have
occurred every 18 months. Beginning in 1996, PG&E schedules refueling outages
every 21 months, and it intends to seek NRC licensing authority to schedule
such outages once every 24 months beginning in 2001. The schedule below
assumes that a refueling outage for a unit will last approximately six weeks,
depending on the scope of the work required for a particular outage. The
schedule is subject to change in the event of unscheduled plant outages or
changes in the length of the fuel cycle.
1997 1998 1999 2000 2001
----- -------- -------- --------- -----
Unit 1
Refueling........................... April January September
Startup............................. May March October
Unit 2
Refueling........................... February October April
Startup............................. March November June
DIABLO SETTLEMENT
The Diablo Settlement adopted alternative ratemaking for Diablo Canyon by
basing revenues primarily on the amount of electricity generated by the plant,
rather than on traditional cost-based ratemaking. Under the existing Diablo
Settlement, revenues are based on a pre-established price per kWh of
electricity generated by the plant. That price consists of a fixed component
(3.15 cents per kWh) and a separate component that declines until 2000, at
which point the variable component begins to escalate. The total price per kWh
for the year 1996 was 10.50 cents. Under this "performance-based" approach,
PG&E assumes a significant portion of the operating risk of the plant because
the extent and timing of the recovery of actual operating costs, depreciation,
and a return on the investment in the plant primarily depend on the amount of
power produced and the level of costs incurred. PG&E's earnings are affected
directly by plant performance and costs incurred. Currently, earnings relating
to Diablo Canyon can fluctuate significantly as a result of refueling or other
extended plant outages, plant expenses, and the effects of a peak-period
pricing mechanism.
As noted above, in connection with electric industry restructuring, PG&E has
proposed to modify the existing Diablo Settlement. Under the modification
proposal, PG&E would replace the existing Diablo Settlement price with a sunk
cost revenue requirement and a performance-based Incremental Cost Incentive
Price (ICIP). The sunk cost revenue requirement for Diablo Canyon would
include recovery of the net investment in Diablo Canyon over a five-year
period and a return on common equity of 90% of PG&E's long-term cost of debt.
PG&E's authorized long-term cost of debt was 7.52% in 1996. Under the ICIP,
the plant's variable and other operating costs and future capital additions
would be recovered under a pre-set price per kWh of plant output based on an
initial expectation of such costs and output.
Under PG&E's modification proposal, the termination date in the existing
Diablo Settlement would be changed from 2016 to 2001. As proposed, closure
cost recovery provisions would replace existing abandonment payment
provisions. Under the cost recovery provisions, PG&E would be entitled to
recover a percentage of its annual operating costs for a limited number of
years following the plant's permanent closure. PG&E's continued recovery of
the sunk cost revenue requirement would be subject to CPUC evaluation if
Diablo Canyon is shut down for nine months or more before the end of the
transition period. After such time, there would be no restrictions on Diablo
Canyon's operations, to which customers it could sell and at what prices,
terms, and
20
conditions; however, 50% of any after-tax earnings available for common equity
after such time would be allocated to ratepayers.
More information concerning the financial impact of the proposed Diablo
Settlement modification is included in "Management's Discussion and Analysis
of Consolidated Results of Operations and Financial Condition" in the 1996
Annual Report to Shareholders, beginning on page 9, and in Notes 2 and 4 of
the "Notes to Consolidated Financial Statements" beginning on pages 29 and 32,
respectively, of the 1996 Annual Report to Shareholders.
On February 28, 1997, the assigned ALJ issued a proposed decision on PG&E's
proposed modification to Diablo Canyon ratemaking. With significant
exceptions, the proposed decision generally adopts the overall ratemaking
structure proposed by PG&E, but would substantially alter the proposed ICIP
mechanism and would exclude certain items from the sunk cost revenue
requirement.
Instead of adopting the fixed forecast of ICIP prices for the 1997-2001
period proposed by PG&E, the proposed decision adopts an alternative cost of
service approach, which would establish an initial forecast of ICIP prices
which will be adjusted annually through 2001 to reflect a new forecast
incorporating Diablo Canyon's actual operating costs and capacity factor. With
respect to sunk costs, the proposed decision adopts a "prudence" disallowance
based on the finding that PG&E admitted in pre-1988 Diablo testimony that a
design error cost $100 million. The disallowance would be equal to $100
million times the ratio of depreciated value of the original plant to
undepreciated value of the original plant, which PG&E estimates would equal
approximately $60-$70 million. The proposed decision also excludes 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 proposed decision requires that out-of-core fuel
inventory and materials and supplies inventory be recovered in ICIP prices.
The proposed decision requires an independent financial verification audit of
Diablo Canyon sunk costs, to be completed within six months. Diablo Canyon
sunk cost recovery would be adjusted to reflect the results of this audit.
In addition, the proposed decision terminates, rather than modifies as
proposed by PG&E, the Diablo Settlement on the date the proposed decision is
adopted by the CPUC. PG&E intends to seek clarification from the CPUC that the
termination of the Diablo Settlement would not affect Diablo Canyon's "must
take" status during the transition period.
Based on a very preliminary review and interpretation of the proposed
decision and assuming that the modified rates are effective January 1, 1997,
PG&E Corporation estimates that the impact on 1997 earnings could be
approximately five cents per share negative compared to PG&E Corporation's
1997 budget. This estimate is subject to change, and the actual impact of the
proposed decision on the Company's financial results will depend on several
factors, including clarification of several ambiguities in the proposed
decision. In addition, there could be a further negative impact compared to
PG&E Corporation's 1997 budgeted results if the modified rates are effective
on the date the CPUC adopts the final decision, given the timing of recovery
of Diablo Canyon transition costs.
The proposed decision is not a final decision of the CPUC, and is subject to
change prior to a vote of the full CPUC. The proposed decision currently is
scheduled for consideration by the full CPUC at its April 9, 1997 meeting.
NUCLEAR FUEL SUPPLY AND DISPOSAL
PG&E has purchase contracts for, and inventories of, uranium concentrates,
uranium hexaflouride, and enriched uranium; it has one contract for fuel
fabrication. Based on current operations forecasts, Diablo Canyon's
requirements for uranium supply, the conversion of uranium to uranium
hexaflouride, and the enrichment of the uranium hexaflouride to enriched
uranium will be satisfied by a combination of existing contracts and
inventories through 2000, 1999, and 2002, respectively. The fuel fabrication
contract for the two units will supply their requirements for the next eight
operating cycles of each unit. These contracts are intended to ensure long-
term
21
fuel supply, but permit PG&E the flexibility to take advantage of short-term
supply opportunities. In most cases, PG&E's nuclear fuel contracts are
requirements-based, with PG&E'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, PG&E has
signed a contract with the DOE providing for the disposal of the spent nuclear
fuel and high-level radioactive waste from PG&E's nuclear power facilities
beginning not later than January 1998. However, due to delays in identifying a
storage site, the DOE has officially acknowledged that it will not be able to
meet its contract commitment to begin accepting spent fuel by January 1998.
Further, under the DOE's current estimated acceptance schedule for spent fuel,
Diablo Canyon's spent fuel may not be accepted by the DOE for interim or
permanent storage before 2012, at the earliest. At the projected level of
operation for Diablo Canyon, PG&E'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. PG&E 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 PG&E's plan to store
radioactive waste from the Humboldt Bay Power Plant (Humboldt) at Humboldt for
20 to 30 years and, ultimately, to decommission the unit. The license
amendment issued by the NRC allows storage of spent fuel rods at Humboldt
until a federal repository is established. PG&E has agreed to remove all
nuclear waste as soon as possible after the federal disposal site is
available.
INSURANCE
PG&E has insurance coverage for property damage and business interruption
losses as a member of Nuclear Mutual Limited (NML) and Nuclear Electric
Insurance Limited (NEIL). These companies, which are owned by utilities with
nuclear generating facilities, provide 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 PG&E's policies, if the nuclear generating
facility of a member utility suffers a loss due to a prolonged accidental
outage, PG&E may be subject to maximum retrospective premium assessments of
$29 million (property damage) and $8 million (business interruption), in each
case per one-year policy period, if losses exceed the resources of NML or
NEIL.
PG&E has purchased primary insurance of $200 million for public liability
claims resulting from a nuclear incident. An additional $8.7 billion of
coverage is provided by secondary financial protection required by federal law
and provides for loss sharing among utilities owning nuclear generating
facilities if a costly incident occurs. If a nuclear incident results in
claims in excess of $200 million, PG&E may be assessed up to $159 million per
incident, with payments in each year limited to a maximum of $20 million per
incident.
DECOMMISSIONING
The estimated total obligation for decommissioning PG&E's nuclear power
facilities is comprised of the total cost (including labor, materials, and
other costs) of decommissioning and dismantling plant systems and structures.
In addition, a contingency amount for possible changes in regulatory
requirements and increases in waste disposal costs is included in the
estimated total obligation. The estimated total obligation for nuclear
decommissioning costs, based on a 1994 site study, is approximately $1.2
billion in 1996 dollars (or $5.9 billion in future dollars). Actual
decommissioning costs are expected to vary from this estimate because of
changes in assumed dates of decommissioning, regulatory requirements,
technology, and costs of labor, materials, and equipment. The estimated total
obligation is being recognized proportionately over the license term of each
facility.
22
Decommissioning costs recovered in rates are placed in external trust funds.
These funds, along with accumulated earnings, will be used exclusively for
decommissioning. The trust funds maintain substantially all of their
investments in debt and equity securities. All fund earnings are reinvested.
Funds may not be released from the external trust funds until authorized by
the CPUC. As of December 31, 1996, PG&E had accumulated external trust funds
with an estimated fair value of $883 million, based on quoted market prices,
to be used for the decommissioning of PG&E's nuclear facilities.
In the past, the amount recovered in rates for decommissioning costs through
an annual allowance has been reviewed by the CPUC as part of the GRC. The CPUC
considers the trust's asset level, together with revised earnings and
decommissioning cost assumptions, to determine the amount of decommissioning
costs it will authorize in rates for contribution to the trust. The funds
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, 1996,
nuclear decommissioning costs recovered in rates were $33 million.
In the future, AB 1890 provides that nuclear decommissioning costs, which
are not transition costs, will be recovered through a nonbypassable charge
until those costs are fully recovered. Recovery of decommissioning costs may
be accelerated to the extent possible under the rate freeze. In its roadmap
decision, the CPUC established a Nuclear Decommissioning Costs Triennial
Proceeding to determine the decommissioning costs and establish the annual
revenue requirement and attrition factors over three-year periods when and if
GRCs are discontinued.
OTHER ELECTRIC RESOURCES
QF GENERATION AND OTHER POWER PURCHASE CONTRACTS
Under the Public Utility Regulatory Policies Act of 1978, PG&E is required
to purchase electric energy and capacity provided by QFs which are
cogenerators and small power producers. The CPUC established a series of power
purchase contracts with QFs and set the applicable terms, conditions, and
price options. Under these contracts, PG&E is required to purchase electric
energy and capacity; however, payments are only required when energy is
supplied or when capacity commitments are met. The total cost of these
payments is recoverable in rates. PG&E's contracts with QFs expire on various
dates from 1997 to 2028. Energy payments to QFs are expected to decline in the
years 1997 through 2000. Capacity payments are expected to remain at current
levels.
In 1996, 1995 and 1994, PG&E negotiated the early termination or suspension
of certain QF contracts at discounted costs of $25 million, $142 million, and
$155 million, respectively. Amounts to be paid for termination or suspension
are payable through 1999. These amounts are expected to be recovered in rates.
At December 31, 1996, the total discounted future payments remaining under QF
early termination or suspension contracts was $68 million.
QF deliveries in the aggregate account for approximately 19% of PG&E's 1996
electric energy requirements and no single contract accounted for more than 5%
of PG&E's energy needs.
PG&E also has contracts with various irrigation districts and water agencies
to purchase hydroelectric power. Under these contracts, PG&E must make
specified semi-annual minimum payments whether or not any energy is supplied
(subject to the provider's retention of the FERC's authorization) and variable
payments for operation and maintenance costs incurred by the providers. These
contracts expire on various dates from 2004 to 2031. The total cost of these
payments is recoverable in rates. At December 31, 1996, the undiscounted
future minimum payments under these contracts are $34 million for each of the
years 1997 through 2001, and a total of $383 million for periods thereafter.
Irrigation district and water agency deliveries in the aggregate account for
approximately 6% of PG&E's 1996 electric energy requirements, and no single
contract accounted for more than 5% of PG&E's energy needs.
23
The amount of energy received and the total payments made (including
termination and suspension payments) under QF contracts and other power
purchase contracts were:
1996 1995 1994
------ ------ ------
(IN MILLIONS)
kWh received........................................ 26,056 26,468 23,903
QF energy payments.................................. $1,136 $1,140 $1,196
QF capacity payments................................ $ 521 $ 484 $ 518
Other power purchase payments....................... $ 52 $ 50 $ 49
As of December 31, 1996, PG&E had approximately 5,800 megawatts (MW) of QF
capacity under CPUC-mandated power purchase agreements. Of the 5,800 MW,
approximately 4,600 MW were operational. Development of the balance is
uncertain and it is estimated that very few of the remaining contracts will
become operational. The 5,800 MW of QF capacity consists of 2,900 MW from
cogeneration projects, 1,700 MW from wind projects and 1,200 MW from other
projects, including biomass, waste-to-energy, geothermal, solar, and
hydroelectric.
GEOTHERMAL GENERATION
PG&E's geothermal units at The Geysers Power Plant (Geysers) are forecast to
operate at reduced capacities because of declining geothermal steam supplies
and curtailment of the Geysers due to the existence of more economic sources
of electric generation. PG&E's agreements with several of its steam suppliers
permit PG&E to curtail generation at the Geysers at PG&E's discretion. The
consolidated Geysers capacity factor is forecast to be approximately 40% of
installed capacity in 1997, which includes economic curtailments, forced
outages, scheduled overhauls, and projected steam shortage curtailments, as
compared to the actual Geysers capacity factor of 42% in 1996.
HELMS PUMPED STORAGE PLANT
Helms is a three-unit hydroelectric combined generating and pumped storage
facility, completion of which was delayed due to a water conduit rupture in
September 1982 and various start-up problems related to the plant's
generators. Helms became commercially operable in June 1984. As a result of
the damage caused by the rupture and the delay in the operational date, PG&E
incurred additional costs which were not initially included in rate base, and
lost revenues during the period the plant was under repair. In September 1996,
the CPUC approved a settlement resolving the treatment of remaining
unrecovered Helms costs.
As part of the 1996 GRC decision issued in December 1995, the CPUC directed
PG&E to perform a cost-effectiveness study of Helms. The CPUC indicated the
study should consider changes in rate recovery for the plant including, among
other things, the option of retirement with recovery of the investment without
a return. The cost-effectiveness study submitted by PG&E in July 1996
concluded that the continued operation of Helms is cost effective. PG&E
recommended that the CPUC take no action based on the study, but address Helms
along with other generating plants in the context of electric industry
restructuring. PG&E is currently unable to predict whether there will be a
change in rate recovery resulting from the study. As with its other
hydroelectric generating plants, PG&E expects to seek recovery of its net
investment in Helms ($710 million at December 31, 1996) through the
hydroelectric and geothermal PBR and CTC recovery.
ELECTRIC LOAD FORECAST AND RESOURCE PLANNING AND PROCUREMENT
At present, California's long-range electric resource planning is
coordinated between the CEC and the CPUC. Applicable statutes require that,
every two years, the CEC prepare an Electricity Report that includes load
forecasts and resource assumptions for a 20-year period and the CPUC conduct a
Biennial Resource Plan Update (BRPU) proceeding which is linked to a specific
CEC Electricity Report. The purpose of the BRPU is to determine whether any
cost-effective electric resources (either new generating resources or power
purchases) should be added to the regulated utilities' electric systems based
on a 12-year planning horizon. In making this
24
determination, the CPUC gives great weight to the load forecasts and resource
assumptions included in the CEC's Electricity Report. However, in light of the
restructuring of the electric utility industry, it is unclear what relevance,
if any, the BRPU and the CEC's Electricity Report proceedings will have with
regard to California utility resource planning and procurement in the future.
The timetable for release of the draft 1996 Electricity Report has been
delayed.
The future of electric resource acquisition is being addressed as part of
electric industry restructuring. Under the plan contemplated in the CPUC's
restructuring decision issued in December 1995, utilities would retain the
obligation to acquire resources for customers who continue to take bundled
electric utility services, but this obligation would be met entirely through
purchases from the PX during the transition period starting January 1, 1998.
Beginning in 2002, PG&E could acquire power from sources other than the PX to
satisfy the demands of its utility customers.
PG&E's demand forecasts and resource procurement plans are subject to
possibly significant changes depending on the ultimate outcome of electric
industry restructuring. In 1997, PG&E does not anticipate adding any new MW of
resources to its system. PG&E currently plans no new major construction
projects for electric supply.
ELECTRIC TRANSMISSION
To transport energy to load centers, PG&E as of December 31, 1996, owned and
operated approximately 18,516 circuit miles of interconnected transmission
lines of 60 kilovolts (kV) to 500 kV and transmission substations having a
capacity of approximately 32,892,000 kilovolt-amperes (kVa). Energy is
distributed to customers through approximately 108,170 circuit miles of
distribution system and distribution substations having a capacity of
approximately 23,000,000 kVa.
Traditionally, the transmission of electric energy in interstate commerce
and the sale of electric energy for resale (wholesale sales) have been
regulated by the FERC. In 1996, the FERC issued an order requiring utilities
to provide wholesale open access to electric transmission systems on terms
that are comparable to the way utilities use their own systems. PG&E's open
access tariff, filed in July 1996, is now available for service to any
eligible party interested in wholesale transmission service over PG&E's
transmission system. The FERC also reaffirmed its intention to permit
utilities to recover any legitimate, verifiable, and prudently incurred costs
stranded as a result of customers taking advantage of wholesale open access
orders to meet their power needs from other sources.
Pursuant to the CPUC's electric industry restructuring decision, PG&E and
the other two California investor owned electric utilities filed a joint ISO
application with the FERC. The application requested authorization to transfer
operational control (but not ownership) of certain transmission facilities to
the ISO. The ISO will control the dispatch of generation and the operation of
the transmission system and provide open access transmission service on a
nondiscriminatory basis. In November 1996, the FERC issued an order approving
the structure of the ISO and PX as proposed by the utilities, but requiring
detailed tariffs and other required filings by March 31, 1997. Also in
connection with electric industry restructuring, the FERC issued an order in
December 1996 addressing market power issues. That decision relied on measures
to mitigate and monitor market power rather than on continued studies to
determine whether the utilities had market power.
The FERC has also approved a proposal from PG&E 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.
25
GAS UTILITY OPERATIONS
PG&E owns and operates an integrated gas transmission, storage, and
distribution system in California. At December 31, 1996, PG&E's system,
including the PG&E Expansion (Line 401), consisted of approximately 5,700
miles of transmission pipelines, three gas storage facilities, and
approximately 36,200 miles of gas distribution lines.
GAS OPERATIONS
PG&E's peak day send-out of gas on its integrated system in California
during the year ended December 31, 1996 was 3,407 million cubic feet (MMcf).
The total volume of gas throughput during 1996 was approximately 826,000 MMcf,
of which 264,000 MMcf was sold to direct end-use or resale customers, 134,000
MMcf was used by PG&E primarily for its fossil-fueled electric generating
plants, and 428,000 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 1996 Report updates PG&E's annual gas requirements forecast (excluding
bypass volumes) for the years 1996 through 2010, forecasting growth in gas
thoughput served by PG&E of 2% per year. The gas requirements forecast is
subject to many uncertainties and there are many factors that can influence
the demand for natural gas, including weather conditions, level of utility
electric generation, fuel switching and new technology. In addition, some
large customers, mostly in the industrial and enhanced oil recovery sectors,
may have the ability to use unregulated private pipelines or interstate
pipelines, bypassing PG&E's system entirely. The 1996 Report forecasts a total
bypass volume of 133,600 MMcf for 1996.
26
GAS OPERATING STATISTICS
The following table shows PG&E'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
----------------------------------------------------------
1996 1995 1994 1993 1992
---------- ---------- ---------- ---------- ----------
CUSTOMERS (AVERAGE FOR
THE YEAR):
Residential............ 3,455,086 3,417,556 3,372,768 3,339,859 3,311,881
Commercial............. 198,071 197,939 196,509 195,815 195,689
Industrial............. 1,500 1,500 1,400 1,265 1,185
Other gas utilities.... 2 2 2 4 4
---------- ---------- ---------- ---------- ----------
Total............... 3,654,659 3,616,997 3,570,679 3,536,943 3,508,759
========== ========== ========== ========== ==========
GAS SUPPLY -- THOUSAND
CUBIC FEET (MCF) (IN
THOUSANDS):
Purchased:
From Canada........... 253,209 261,800 319,453 329,693 321,770
From California....... 28,130 31,158 31,757 32,096 50,953
From other states..... 110,604 117,538 249,733 243,058 327,272
---------- ---------- ---------- ---------- ----------
Total purchased..... 391,943 410,496 600,943 604,847 699,995
Net from storage (to
storage).............. 6,871 (10,921) 3,591 (12,234) 10,135
---------- ---------- ---------- ---------- ----------
Total............... 398,814 399,575 604,534 592,613 710,130
PG&E use, losses,
etc.(1)............... 134,375 129,671 297,604 161,895 281,021
---------- ---------- ---------- ---------- ----------
Net gas for sales... 264,439 269,904 306,930 430,718 429,109
========== ========== ========== ========== ==========
BUNDLED GAS SALES AND
TRANSPORTATION SERVICE
-- MCF (IN THOUSANDS):
Residential............ 190,246 191,724 214,358 206,053 190,176
Commercial............. 62,178 64,135 72,183 82,048 79,983
Industrial............. 12,015 14,045 19,495 133,178 145,356
Other gas utilities.... 0 0 894 9,439 13,594
---------- ---------- ---------- ---------- ----------
Total(2)............ 264,439 269,904 306,930 430,718 429,109
========== ========== ========== ========== ==========
TRANSPORTATION SERVICE
ONLY -- MCF (IN
THOUSANDS):
Vintage system
(Substantially all
Industrial)(3)........ 189,695 143,921 142,393 101,888 103,186
PG&E Expansion (Line
401).................. 237,776 240,506 200,755 20,513 --
---------- ---------- ---------- ---------- ----------
Total............... 427,471 384,427 343,148 122,401 103,186
========== ========== ========== ========== ==========
REVENUES (IN THOUSANDS):
Bundled gas sales and
transportation
service:
Residential........... $1,109,463 $1,205,223 $1,268,966 $1,152,494 $1,092,324
Commercial............ 362,819 421,397 444,805 467,962 479,599
Industrial............ 42,520 42,106 57,297 367,221 425,467
Other gas utilities... 510 0 2,371 25,654 38,504
---------- ---------- ---------- ---------- ----------
Bundled gas
revenues........... 1,515,312 1,668,726 1,773,439 2,013,331 2,035,894
Transportation only
revenue:
Vintage system
(Substantially all
Industrial).......... 180,197 167,325 132,509 56,733 75,606
PG&E Expansion (Line
401)................. 85,144 82,904 58,442 8,097 --
---------- ---------- ---------- ---------- ----------
Transportation
service only
revenue............ 265,341 250,229 190,951 64,830 75,606
Miscellaneous.......... (9,271) (18,018) 40,427 (16,692) 21,022
Regulatory balancing
accounts.............. 57,864 (43,771) (101,443) 95,339 40,199
Subsidiaries(4)........ 210,556 201,951 177,688 264,925 173,587
---------- ---------- ---------- ---------- ----------
Operating revenues.. $2,039,802 $2,059,117 $2,081,062 $2,421,733 $2,346,308
========== ========== ========== ========== ==========
- --------
(1) Includes use by business units other than the Gas Supply business unit,
principally as fuel for fossil-fueled generating plants.
(2) In August 1991, PG&E implemented its customer identified gas (CIG)
program. Sales included approximately 105,000 MMcf and 130,000 MMcf in
1993 and 1992, respectively, of gas procured by PG&E for CIG customers at
prices negotiated directly between those customers and suppliers. The CIG
Program was terminated on October 31, 1993 upon full implementation of the
CPUC's capacity brokering program.
(3) Does not include on-system transportation volumes transported on the PG&E
Expansion of 78,552 MMcf, 100,207 MMcf, 79,749 MMcf, and 7,205 MMcf for
1996, 1995, 1994, and 1993, respectively.
(4) Includes gas transportation revenues from PGT.
27
YEARS ENDED DECEMBER 31
-------------------------------------------------
1996 1995 1994 1993 1992
--------- --------- --------- --------- ---------
SELECTED STATISTICS:
Total customers (at year-
end)....................... 3,700,000 3,600,000 3,500,000 3,600,000 3,500,000
Average annual residential
usage (Mcf)................ 55 56 64 62 57
Heating temperature -- % of
normal(1).................. 75.7 75.3 104.4 89.9 76.0
Average billed bundled gas
sales revenues per Mcf:
Residential................. $5.83 $6.29 $5.92 $5.59 $5.74
Commercial.................. 5.84 6.57 6.16 5.70 6.00
Industrial.................. 3.54 3.00 2.94 2.76 2.93
Average billed
transportation only revenue
per Mcf:
Vintage system.............. 0.67 0.69 0.60 0.52 0.73
PG&E Expansion (Line 401)... 0.36 0.34 0.29 0.39 --
Net plant investment per
customer................... $1,378 $1,315 $1,340 $1,339 $1,170
- --------
(1) Over 100% indicates colder than normal.
NATURAL GAS SUPPLIES
The objective of PG&E'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, PG&E purchases natural gas from its various
suppliers based on economic considerations, consistent with regulatory,
contractual, and operational constraints. During the year ended December 31,
1996, approximately 65% of PG&E's total purchases of natural gas consisted of
Canadian gas purchased from various Canadian producers and transported by
Canadian pipeline companies and PGT; approximately 7% was purchased from
various California producers; and approximately 28% was purchased from other
states (substantially all U.S. Southwest sources and transported by El Paso or
Transwestern). The following table shows the volume and average price of gas
in dollars per thousand cubic feet (Mcf) purchased by PG&E from these sources
during each of the last five years.
YEARS ENDED DECEMBER 31
--------------------------------------------------------------------------------------------------
1996 1995 1994 1993 1992
------------------ ----------------- ----------------- ------------------ ------------------
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............ 253,209 $1.57 261,800 $1.34 319,453 $1.94 329,693 $2.26 321,770 $2.14
California........ 28,130 $1.90 31,158 $1.32 31,757 1.55 32,096 1.65 50,953 1.73
Other states
(substantially
all U.S.
Southwest)....... 110,604 $3.72 117,538 $2.64 249,733 2.41 243,058 2.84 327,272 2.51
------- ------- ------- ------- -------
Total/Weighted
Average.......... 391,943 $2.21 410,496 $1.71 600,943 $2.12 604,847 $2.46 699,995 $2.28
======= ===== ======= ===== ======= ===== ======= ===== ======= =====
- --------
(1) The average prices for Canadian and U.S. Southwest gas include the
commodity gas prices, interstate pipeline demand or reservation charges,
transportation charges, and other pipeline assessments, including direct
bills allocated over the quantities received at the California border. The
average prices for California gas include only commodity gas prices
delivered to PG&E's gas system.
GAS REGULATORY FRAMEWORK
The current regulatory framework for natural gas service in California (i)
segments customers into core and noncore classes; (ii) unbundles utilities'
gas transportation and procurement services; (iii) allows customers to
purchase gas directly from producers, aggregators, or marketers, and to
separately purchase gas transportation from their utilities; and (iv) places
the utilities at risk for collecting a portion of the transportation revenues
associated with their noncore markets.
28
Under this regulatory framework, noncore customers have the option of buying
gas directly from the supplier of their choice and purchasing from PG&E
transmission and distribution services only. Certain customers can also use
alternative transportation services provided by competing pipeline companies.
However, core customers continue to have more limited opportunities in
choosing their gas suppliers, with substantially all core customers receiving
bundled services from PG&E.
In an effort to promote competition and increase options for all customers,
as well as to position itself in the competitive marketplace, PG&E has
submitted to the CPUC for its approval a Gas Accord, which would restructure
PG&E's gas services and its role in the gas market. As discussed above (see
"Competition and the Changing Regulatory Environment--Gas Industry"), the Gas
Accord consists of three broad initiatives: (1) unbundling of PG&E's gas
transmission and storage services from its distribution services; (2)
reduction of PG&E's role in procuring gas supplies for core customers in order
to increase opportunities for such customers to purchase gas from their
supplier of choice; and (3) resolution of major outstanding regulatory issues.
Also as part of the Gas Accord, PG&E has proposed that traditional
reasonableness reviews of its core gas procurement costs be replaced with a
CPIM, under which PG&E would be able to recover its gas commodity and
interstate transportation costs and receive benefits or be penalized depending
on whether its actual core procurement costs were within, below, or above a
"tolerance band" constructed around market benchmarks.
The Gas Accord must be approved by the CPUC before it can be implemented.
TRANSPORTATION COMMITMENTS
PG&E 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 PG&E will pay each year may change due to changes in
tariff rates. The total demand and transportation charges paid by PG&E under
these agreement (excluding agreements with PGT) was approximately $212 million
in 1996.
As a result of regulatory changes, PG&E no longer procures gas for its
noncore customers, resulting in a decrease in PG&E's need for firm
transportation capacity for its gas purchases. PG&E continues to procure gas
for almost all of its core customers and those noncore customers who choose
bundled service (core subscription customers).
PG&E is continuing its efforts to broker or assign any remaining unused
capacity, including unused capacity held for its core and core subscription
customers. Due to relatively low demand for Southwest pipeline capacity, PG&E
cannot predict the volume or price of the capacity on El Paso and Transwestern
that will be brokered or assigned.
In general, demand charges incurred by PG&E for pipeline capacity are
eligible for rate recovery, subject to a reasonableness review. The demand
charges include the cost of capacity that was formerly used to serve noncore
customers but which at present cannot be brokered or which is brokered at a
discount. However, certain groups, including the ORA and intervenors, have
challenged the recovery of these unrecovered demand charges in the proceeding
relating to ITCS recovery (see "El Paso and PGT Capacity" below). In addition,
the CPUC has issued an unfavorable decision addressing recovery of
Transwestern charges (see "Transwestern Capacity" below).
EL PASO AND PGT CAPACITY
PG&E's firm transportation agreement with PGT for 1,066 million cubic feet
per day (MMcf/d) runs through October 31, 2005. PG&E's firm transportation
agreement with El Paso for 1,140 MMcf/d runs through December 31, 1997. The
firm transportation reservation charges associated with PG&E's firm capacity
on PGT and El Paso are approximately $57 million and $163 million per year,
respectively.
Pursuant to FERC rules on capacity relinquishment and release and the CPUC's
capacity brokering program, PG&E currently retains approximately 600 MMcf/d on
each of the PGT and El Paso systems to support its core and core subscription
customers. PG&E made capacity not needed to support such customers available
29
for release and brokering to other potential shippers beginning in 1993. PG&E
has assigned substantially all of its unused capacity on PGT. Due to lower
demand for Southwest pipeline capacity, PG&E cannot predict the volume or
price of the capacity on El Paso that will be brokered or assigned. To the
extent PG&E is unable to broker its firm interstate capacity above core and
core subscription reservations at the full as-billed rate, PG&E has been
authorized to accumulate unrecovered demand charges for El Paso and PGT in the
ITCS account pending CPUC reasonableness review of those amounts in the ITCS
proceeding.
As noted above, in the ITCS proceeding, certain intervenors have challenged
PG&E's recovery of amounts in the ITCS account, and suggested disallowances
and/or a reallocation among customers of between $40 and $101 million. Pending
a final decision in the ITCS proceeding, the CPUC has approved collection in
rates (subject to refund) of approximately 50% of the demand charges for
unbrokered or discounted El Paso and PGT capacity formerly used to serve
PG&E's noncore customers.
In the meantime, PG&E has proposed a resolution of this matter as part of
the Gas Accord. Under the Gas Accord, PG&E would forgo recovery of 100% and
50% of the ITCS amounts allocated to its core and noncore customers,
respectively.
TRANSWESTERN CAPACITY
In April 1992, PG&E executed firm transportation agreements with
Transwestern to transport approximately 200 MMcf/d of San Juan basin gas
supplies into PG&E's southern gas system, of which approximately 150 MMcf/d is
to be used to meet PG&E's core gas sales demands and approximately 50 MMcf/d
is for use by PG&E's electric department. The agreements with Transwestern
expire in 2007. The demand charges associated with the entire Transwestern
capacity are currently approximately $29 million per year.
Currently, PG&E is not permitted to include any Transwestern firm capacity
demand charges in rates or in the ITCS account. PG&E is authorized to record
costs associated with its Transwestern capacity in a balancing account, with
recovery of such costs subject to reasonableness review proceedings.
In December 1995, the CPUC issued a decision on the reasonableness of PG&E's
1992 gas operations, which concluded that it was unreasonable for PG&E to
commit to transportation capacity with Transwestern. The decision orders that
costs for the capacity in subsequent years of the contract, which expires in
2007, be disallowed each year unless PG&E can demonstrate that the benefits of
the commitment outweight the costs in that year.
PG&E has also addressed the Transwestern issue in its Gas Accord proposal.
The Gas Accord provides that PG&E would not recover costs through 1997
associated with Transwestern capacity originally subscribed to in order to
serve core customers and would have limited recovery during the period 1998
through 2002.
PG&E has recorded reserves relating to its gas capacity commitments and the
issues addressed by the Gas Accord. More information concerning the financial
impact of these matters is included in "Management's Discussion and Analysis
of Financial Condition and Results of Operations" in the 1996 Annual Report to
Shareholders, beginning on page 13, and in Note 3 of the "Notes to
Consolidated Financial Statements" beginning on page 31 of the 1996 Annual
Report to Shareholders.
GAS REASONABLENESS PROCEEDINGS
Recovery of gas costs through PG&E's regulatory balancing account mechanisms
is subject to a CPUC determination that such costs were incurred reasonably.
Under the current regulatory framework, annual reasonableness proceedings are
conducted by the CPUC on a historic calendar year basis.
1988-1990 CANADIAN GAS PROCUREMENT ACTIVITIES
In March 1994, the CPUC issued a final decision on PG&E's Canadian gas
procurement activities during 1988 through 1990. The CPUC found that PG&E
could have saved its customers money if it had bargained more
30
aggressively with its existing Canadian suppliers or bought less expensive gas
from other Canadian sources. The decision ordered a disallowance of $90
million of gas costs, plus accrued interest estimated at approximately $25
million through December 31, 1993.
In December 1994, PG&E filed a complaint against the CPUC in the U.S.
District Court for the Northern District of California challenging this
decision by the CPUC. The complaint alleges that the CPUC disallowance order
purports to regulate the foreign and interstate purchase and transportation of
natural gas, matters within the exclusive jurisdiction of United States and
Canadian regulatory authorities. Accordingly, the complaint alleges, such
order is preempted by federal law and violates PG&E's rights under the United
States Constitution. The complaint seeks injunctive and declaratory relief.
PG&E's lawsuit is still pending in federal court. However, as part of the
Gas Accord, PG&E would agree to forgo recovery of the $90 million disallowance
ordered in the 1988-1990 reasonableness proceeding, irrespective of the
outcome of the lawsuit challenging the disallowance.
GAS SETTLEMENT AGREEMENT
In December 1996, the CPUC approved a settlement agreement resolving various
issues related to PG&E's gas procurement practices and supply operations for
periods from 1988 through May 1994. Pursuant to the settlement agreement, PG&E
will return approximately $75 million (including interest) to ratepayers.
PGT/PG&E PIPELINE EXPANSION
In November 1993, PGT and PG&E 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.
CPUC RATEMAKING
The conditions of the CPUC's approval of the construction of the PG&E
Expansion place PG&E 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 PGT portion (PGT Expansion) of
the Pipeline Expansion must be transported at an incremental PG&E Expansion
rate. The costs of PG&E Expansion operations are recovered only from PG&E
Expansion customers, through rates established in separate PG&E Expansion rate
proceedings.
To date, shippers have executed long-term firm transportation contracts for
approximately 40% of capacity on the PG&E Expansion. However, one of those
shippers, which holds a substantial portion of the capacity held under long-
term firm contracts, has an option to buy out its contract. The option is
exercisable on or before May 1, 1997. PG&E will continue to market available
capacity on the PG&E Expansion on both firm and as-available bases. Revenues
are being collected on the basis of an interim revenue requirement, pending a
final decision in the Pipeline Expansion Project Reasonableness case (PEPR).
In 1994, PG&E filed its application in the PEPR requesting that the CPUC
find reasonable the full capital costs of the PG&E Expansion (estimated to be
$810 million). In that proceeding, the ORA recommended a minimum of $100
million in capital costs be disallowed, while two intervenors jointly
recommended a $237 million disallowance or reallocation of costs among
customers. In addition, in 1996, a CPUC ALJ ordered consolidation of the
market impact phase of the PEPR and the ITCS proceeding described above. An
ALJ also ordered reopening of the 1993 PG&E Pipeline Expansion Rate Case to
allow reconsideration of issues regarding the decision to construct the PG&E
Expansion. Were the CPUC to reverse its previous decision, which found that
PG&E was reasonable in constructing the PG&E Expansion, the ultimate outcome
could have an adverse impact on PG&E's ability to recover its cost for unused
capacity on other pipelines as well as on its own intrastate facilities.
Decisions in these proceedings are expected in 1997, if the matters are not
otherwise resolved
31
as part of the Gas Accord. Under the Gas Accord, PG&E would agree to set rates
for the PG&E Expansion based on total capital costs of $736 million.
The CPUC's decision in the 1997 Cost of Capital proceeding authorized a 1997
return on equity for PG&E Expansion operations of 11.6%, resulting in an
overall rate of return of 8.99%. Authorized long-term debt levels for the PG&E
Expansion will be reduced from their current 67% to 64% for 1997.
FERC RATEMAKING
In September 1996, the FERC approved a settlement of PGT's 1994 rate case.
The major issue in this proceeding was whether PGT'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. The settlement also
provides for rates based on a return on equity of 12.2%. Several parties are
seeking rehearing of the FERC order approving the settlement, but PGT currently
expects the settlement to be upheld.
DIVERSIFIED OPERATIONS
In 1996, diversified operations primarily consisted of Enterprises.
Enterprises participates in multiple domestic and international energy
businesses. Enterprises, through its wholly owned subsidiary, PG&E Generating
Company, has made the majority of its investments in nonregulated energy
projects through U.S. Generating Company (USGen), in partnership with Bechtel
Enterprises, Inc. (Bechtel). USGen, a California partnership, manages the
development, construction, and operation of non-utility electric generation
facilities that compete in the United States power generation market.
Enterprises' average overall ownership in all the projects in which USGen
participates is approximately 42 percent.
As of December 31, 1996, USGen's partners had ownership interests in 17
operating plants. The total generating capacity of these 17 plants is 3,375 MW,
of which Enterprises' share is 1,424 MW. The projects were largely financed
with a combination of equity or equity commitments from the project sponsors
and non-recourse debt. USGen, through its affiliate, U.S. Operating Services
Company (USOSC), provides contract operations and maintenance services to many
of these facilities. USGen, through its affiliate, USGen Power Services, L.P.,
is also an active power marketer. USGen also manages approximately 5.6 million
tons per year of coal deliveries to its plants and approximately 875 MMcf/d of
Canadian and U.S. natural gas supplies for deliveries to its plants and to
local gas distribution companies in the Northeast.
Enterprises' entry into the international market was also made in partnership
with Bechtel. Enterprises and Bechtel formed International Generating Company,
Ltd. (InterGen), which develops, owns, and operates international electric
generation projects. However, in November 1996, Enterprises and Bechtel reached
an agreement for Bechtel to acquire Enterprises' interest in InterGen. The
Company expects to complete the sale in the first quarter of 1997 and to
realize an after-tax gain. Enterprises has refined its international strategy
to focus on select countries and to concentrate on end-use energy customers.
In 1995, Enterprises formed Vantus, a retail energy services provider, to
assist customers in locating the most cost-effective electric and gas products
and services. Vantus' energy services include power marketing for industrial
and large commercial businesses nationwide. In 1996, Vantus opened new offices
in the western United States to establish a presence and market its services in
emerging energy markets.
32
PG&E ENVIRONMENTAL MATTERS
ENVIRONMENTAL MATTERS
The following discussion includes certain forward-looking information
relating to estimated expenditures for environmental protection and the
possible future impact of environmental compliance. This information reflects
PG&E's current estimates which are periodically evaluated and revised. These
estimates are subject to a number of assumptions and uncertainties, including
changing laws and regulations, the ultimate outcome of complex factual
investigations, evolving technologies, selection of compliance alternatives,
the nature and extent of required remediation, the extent of PG&E'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 and its 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.
PG&E 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 PG&E's bulk waste handling and storage facilities. The costs of
compliance with environmental laws and regulations have generally been
recovered in rates.
ENVIRONMENTAL PROTECTION MEASURES
PG&E's estimated expenditures for environmental protection are subject to
periodic review and revision to reflect changing technology and evolving
regulatory requirements. PG&E's capital expenditures for environmental
protection are currently estimated to be approximately $36 million,
$50 million, and $72 million for 1997, 1998 and 1999, respectively, and are
included in PG&E's three-year estimate of capital requirements shown above in
"General--Capital Requirements and Financing Programs." Expenditures during
these years will be primarily for oxides of nitrogen (NOx) emission reduction
projects at PG&E's fossil-fueled generating plants and natural gas compressor
stations as described below, which currently are expected to decline in the
later years as the NOx reduction projects are completed.
Air Quality
PG&E's existing 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, the
three local air districts in which PG&E operates fossil-fueled generating
plants adopted final rules that require a reduction in NOx emissions from the
power plants of approximately 90% by 2004 (with numerous interim compliance
deadlines). The first major retrofits began in 1995. Certain retrofits will
not be required if the smaller generating units are operated for emergency
purposes only after 2000. PG&E currently estimates that compliance with these
NOx rules could require capital expenditures of up to $360 million over
10 years. This estimate assumes that most of the 170 MW and smaller boilers
will be retired before the retrofits are required. Ongoing business and
engineering studies could change this estimate.
Other air districts have adopted NOx rules for PG&E's natural gas compressor
stations in California, and these rules continue to be modified. Eventually
the rules are likely to require NOx reductions of up to 80% for many of PG&E's
natural gas compressor stations. PG&E currently estimates that the total cost
of complying with these rules will be up to $58 million over five years.
In PG&E's 1996 GRC, the CPUC included $11.5 million in 1996 rate base for
the estimated $60 million cost of gas and electric NOx retrofit projects to be
installed in 1996. In the future, PG&E's electric NOx costs may be recoverable
as CTCs or through PBR, market pricing, or other means established as part of
electric industry restructuring. Under AB 1890, NOx costs would be eligible
for recovery as CTCs 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
33
through 2001. With respect to gas NOx costs, under the proposed Gas Accord $42
million would be included in rates for gas NOx retrofit projects through 2002.
Water Quality
PG&E's existing power plants, including Diablo Canyon, are subject to
federal and state water quality standards with respect to discharge
constituents and thermal effluents. PG&E'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 PG&E continue its thermal effects monitoring
program. In 1995, the Central Coast Board requested that PG&E prepare an
updated comprehensive assessment of Diablo Canyon's thermal effects and
approved a reduced environmental monitoring program. The new comprehensive
assessment is scheduled for completion in the fourth quarter of 1997. 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, PG&E 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. PG&E 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. PG&E 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
federal, state, and regional water quality control plans may impose
increasingly stringent cooling water discharge requirements on PG&E 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 certain of PG&E's power plants. There are
severe restrictions on the "taking" (e.g., harassing, wounding, or killing) of
such species. Therefore, significant modifications could be required to plant
operations (e.g., cooling towers) if a plant intake structure or thermal
discharge is found to "take" an endangered species.
HAZARDOUS WASTE COMPLIANCE AND REMEDIATION
PG&E assesses, on an ongoing basis, measures that may need to be taken to
comply with laws and regulations related to hazardous materials and hazardous
waste compliance and remediation activities. At present, these compliance and
remediation costs (other than certain costs directly attributable to
generation facilities) would generally be recovered through the GRC process or
through a separate mechanism established by the CPUC in 1994 for recovery of
certain hazardous waste remediation costs. At present, environmental
remediation costs attributable to the decommissioning of generation facilities
are included in rates as part of decommissioning costs. Under electric
industry restructuring, remediation costs for generation facilities can be
included as eligible CTCs that may be recovered during the transition period.
It is not clear at this time what specific ratemaking mechanisms may be
available for recovery of hazardous waste compliance and remediation costs
after the transition period.
PG&E has a comprehensive program to comply with the many hazardous waste
storage, handling, and disposal requirements promulgated by the United States
Environmental Protection Agency (EPA) under the Resource Conservation and
Recovery Act and the Comprehensive Environmental Response, Compensation, and
Liability Act (CERCLA), along with California's hazardous waste laws and other
environmental requirements.
34
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 PG&E, 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), PG&E'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. PG&E has identified and reported to federal and California
environmental agencies 96 manufactured gas plant sites which operated in
PG&E's service territory. PG&E owns all or a portion of 29 of these
manufactured gas plant sites. PG&E 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 PG&E owns. PG&E
currently estimates that this program may result in expenditures of
approximately $8 million to $10 million over the period 1997 through 1998. 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 PG&E is found to be responsible for cleanup at sites
it does not currently own.
Manufactured gas plant sites at which PG&E has been designated as a
potentially responsible party (PRP) under the California Hazardous Substance
Account Act (California Superfund) include the Martin Service Center site and
Midway/Bayshore sites in Daly City, California, the San Rafael site, and the
Sacramento site.
In addition to the manufactured gas plant sites, PG&E 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. PG&E has been designated
as a PRP under CERCLA (the federal Superfund law) with respect to the Purity
Oil Sales site in Malaga, California, the Jibboom Junkyard site in Sacramento,
California, the Industrial Waste Processing site near Fresno, California, and
the Lorentz Barrel and Drum site in San Jose, California. The Purity Oil Sales
site is a former used oil recycling facility at which PG&E is one of nine PRPs
named in an EPA order requiring groundwater remediation at the site. PG&E has
also entered into an Administrative Order with the EPA to address soil
contamination at the site. PG&E has accrued a $4.5 million liability as of
December 31, 1996, for the Purity Oil Sales site. With respect to the Casmalia
site near Santa Maria, California, PG&E and several other generators of waste
sent to the site have entered into an 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. Court approval of the agreement is being sought. PG&E has accrued
a $3.2 million liability as of December 31, 1996, for the Casmalia site.
Although PG&E 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 PG&E and other parties to initiate measures with respect
to the study and remediation of that site. PG&E has accrued a liability of
$12.5 million as of December 31, 1996, for the Geothermal Incorporated site.
In addition to the sites discussed above, PG&E has also been identified as a
PRP at certain disposal sites under the California Superfund. These sites
include the Emeryville Service Center site in Emeryville, California, and the
GBF Landfill at Pittsburg, California. PG&E has also been sued for
reimbursement of cleanup costs incurred by the State of California at PG&E's
former Jibboom Street Station B power plant in Sacramento, California. In
addition, PG&E has been named as a defendant in several civil lawsuits in
which plaintiffs allege that PG&E is responsible for performing or paying for
remedial action at sites PG&E no longer owns or never owned.
The cost of hazardous substance remediation ultimately undertaken by the
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. The Company had an
accrued liability at December 31, 1996, of $170 million for hazardous waste
remediation costs at those sites where such costs are probable and
quantifiable. Environmental remediation at identified sites may be as much as
$400 million if, among other things, other PRPs are not
35
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 among 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.
POTENTIAL RECOVERY OF HAZARDOUS WASTE COMPLIANCE AND REMEDIATION COSTS
In 1994, the CPUC established a ratemaking mechanism for hazardous waste
remediation costs. That mechanism assigns 90% of the includable hazardous
substance cleanup costs to utility ratepayers and 10% to utility shareholders,
without a reasonableness review of such costs or of underlying activities.
However, under the proposed mechanism, utilities will have the opportunity to
recover the shareholder portion of the cleanup costs from insurance carriers.
Under the mechanism, 70% of the ratepayer portion of PG&E's cleanup costs is
attributed to its gas department and 30% is attributed to its electric
department. PG&E can seek to recover hazardous substance cleanup costs under
the new mechanism in the rate proceeding it deems most appropriate. In
connection with electric industry restructuring, PG&E has proposed that any
hazardous waste cleanup costs related to electric generation facilities be
removed from this mechanism and included in CTCs. In addition, PG&E has
proposed that this mechanism no longer be used for electric generation-related
cleanup costs after January 1, 1998.
PG&E expects to seek recovery of prudently incurred hazardous substance
remediation costs through ratemaking procedures approved by the CPUC. The
Company has recorded a regulatory asset at December 31, 1996, of $146 million
for recovery of these costs in future rates. Additionally, PG&E will seek
recovery of costs from insurance carriers and from other third parties.
In 1992, PG&E 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. PG&E had previously notified its insurance
carriers that it seeks coverage under its comprehensive general liability
policies to recover costs incurred at certain specified sites. In the main,
PG&E's carriers neither admitted nor denied coverage, but requested additional
information from PG&E. Although PG&E has received some amounts in settlements
with certain of its insurers, 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
In 1996, litigation brought against PG&E relating to alleged chromium
contamination near PG&E's Hinkley Compressor Station was settled for the
aggregate sum of $333 million. The Hinkley Compressor Station is located along
PG&E's gas transmission system in San Bernardino County, California. The
plaintiffs had contended that between 1951 and 1966, PG&E discharged chromium-
contaminated wastewater into unlined ponds, which led to chromium percolating
into the groundwater of surrounding property.
Several other cases have been brought against PG&E seeking damages from
alleged chromium contamination at PG&E's Hinkley, Topock, and Kettleman
Compressor Stations. See Item 3, "Legal Proceedings--Compressor Station
Chromium Litigation" 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.
36
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, PG&E provides
interested customers with information regarding the EMF exposure issue. PG&E
also provides a free field measurement service to inform customers about EMF
levels at different locations in and around their residences or commercial
buildings.
PG&E and other utilities are involved in litigation concerning EMF. In
August 1996, the California Supreme Court held that homeowners are barred from
suing utilities for alleged property value losses caused by fear of EMF from
power lines. The Court expressly limited its holding to property value issues,
leaving open the question as to whether lawsuits for alleged personal injury
resulting from exposure to EMF are similarly barred. PG&E is named as a
defendant in one pending civil appeal in which plaintiffs allege personal
injury resulting from exposure to EMF.
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, PG&E may be
required to take mitigation measures at its facilities. The costs of such
mitigation measures cannot be estimated with any certainty at this time.
However, such costs could be significant depending on the particular
mitigation measures undertaken, especially if relocation of existing power
lines is ultimately required.
LOW EMISSION VEHICLE PROGRAMS
In December 1995, the CPUC issued its decision in the Low Emission Vehicle
(LEV) proceeding which approved approximately $36 million in funding for
PG&E'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.
37
FORMATION OF PG&E CORPORATION
As previously noted, effective January 1, 1997, PG&E Corporation became the
parent holding company of PG&E. PG&E's ownership interest in PGT and
Enterprises was transferred to PG&E Corporation. The following financial
information summarizes certain pro forma financial effects of the
restructuring of PG&E. The restructuring resulted in PG&E becoming a separate
subsidiary of PG&E Corporation with the present holders of PG&E common stock
becoming holders of PG&E Corporation common stock. The pro forma balance sheet
is as of December 31, 1996, and the pro forma income statement is for the
twelve months ended December 31, 1996, as if the restructuring occurred
December 31, 1996, and January 1, 1996, respectively. The restructuring was
accounted for as an as-if pooling of interests.
PRO FORMA (UNAUDITED)
----------------------------
PG&E PG&E
CONSOLIDATED PRO FORMA PG&E CORPORATION
HISTORICAL ADJUSTMENTS(1) CONSOLIDATED(1) CONSOLIDATED
------------ -------------- --------------- ------------
(IN MILLIONS, EXCEPT PER SHARE AMOUNTS)
BALANCE SHEETS--AS OF
DECEMBER 31, 1996
ASSETS
Net plant in service... $18,594 $(1,176) $17,418 $18,594
Investments and other
noncurrent assets..... 2,249 (853) 1,396 2,249
Current assets......... 2,671 (574) 2,097 2,671
Deferred charges....... 2,616 (91) 2,525 2,616
------- ------- ------- -------
TOTAL ASSETS............ $26,130 $(2,694) $23,436 $26,130
======= ======= ======= =======
CAPITALIZATION AND LIA-
BILITIES CAPITALIZATION
Common stock equity... $ 8,363 $(1,142) $ 7,221 $ 8,363
Preferred stock and
preferred securities. 840 -- 840 840
Long-term debt........ 7,770 (701) 7,069 7,770
------- ------- ------- -------
TOTAL CAPITALIZATION... 16,973 (1,843) 15,130 16,973
Current liabilities.... 3,240 (343) 2,897 3,240
Deferred credits and
other noncurrent lia-
bilities.............. 5,917 (508) 5,409 5,917
------- ------- ------- -------
TOTAL CAPITALIZATION AND
LIABILITIES............ $26,130 $(2,694) $23,436 $26,130
======= ======= ======= =======
BOOK VALUE PER COMMON
SHARE.................. 20.73 20.73
======= =======
STATEMENTS OF INCOME--
YEAR ENDED DECEMBER 31, 1996
Operating Revenues...... $ 9,610 $ (620) $ 8,990 $ 9,610
Operating Expenses...... 7,714 (537) 7,177 7,714
------- ------- ------- -------
Operating Income........ 1,896 (83) 1,813 1,896
Interest Income......... 73 (3) 70 73
Interest Expense........ (640) 32 (608) (640)
Other Income and (Ex-
pense)................. (19) 10 (9) (19)
Preferred Dividend Re-
quirements of PG&E..... -- -- -- 33(2)
------- ------- ------- -------
Pretax Income........... 1,310 (44) 1,266 1,277
Income Taxes............ 555 (29) 526 555
------- ------- ------- -------
Net Income.............. 755 (15) 740 722
======= =======
Preferred Dividend Re-
quirements............. 33 33(2) --
------- ======= -------
Earnings Available for
Common Shares.......... $ 722 $ 722
======= =======
Earnings per Common
Share.................. $ 1.75 $ 1.75
======= =======
- --------
(1) Reflects transfer of PGT and Enterprises from PG&E to PG&E Corporation in
connection with restructuring.
(2) Reflects dividends associated with PG&E Preferred Stock as a charge
against retained earnings for PG&E and as a charge against net income for
PG&E Corporation.
38
ITEM 2. PROPERTIES.
Information concerning PG&E'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 PG&E are subject to the lien of an indenture which provides
security to the holders of PG&E's First and Refunding Mortgage Bonds.
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 is subject to routine litigation incidental to its business.
ANTITRUST LITIGATION
On December 3, 1993, the County of Stanislaus and Mary Grogan, a residential
customer of PG&E, filed a complaint in the U.S. District Court, Eastern
District of California, against PG&E and PGT, on behalf of themselves and
purportedly as a class action on behalf of all natural gas customers of PG&E
during the period of February 1988 through October 1993. The complaint alleged
that the purchase of natural gas in Canada was accomplished in violation of
various antitrust laws and sought damages of as much as $950 million, before
trebling. In August 1994, the District Court dismissed plaintiffs' antitrust
claims, and in September 1994, the plaintiffs filed an amended complaint which
added Alberta and Southern Gas Co. Ltd., PG&E's gas purchasing subsidiary, as
a defendant. The amended complaint reiterated price fixing claims and also
alleged that the defendants, through anticompetitive practices, foreclosed
access over the PGT pipeline to alternative sources of gas in Canada.
On December 18, 1995, the District Court dismissed the plaintiffs' amended
complaint with prejudice. In dismissing the lawsuit, the District Court
determined that plaintiffs were barred from making price fixing allegations
because gas rates had been reviewed by various federal authorities and the
CPUC. The District Court also found that plaintiffs were barred from making
foreclosure of access claims because the volume of imports of gas had been
reviewed by federal authorities, and the CPUC had actively overseen the
allocation of pipeline capacity. Plaintiffs have filed an appeal with the
Court of Appeals.
The Company believes that the ultimate outcome of this matter will not have
a material adverse impact on its financial position.
COUNTIES FRANCHISE FEES LITIGATION
On March 31, 1994, the Counties of Alameda and Santa Clara filed a complaint
in Santa Clara County Superior Court against PG&E on behalf of themselves and
purportedly as a class action on behalf of 47 counties with which PG&E has gas
or electric franchise contracts. Franchise contracts require PG&E to pay fees
on an annual basis to cities and counties for the right to use or occupy
public streets and roads. The complaint alleges that, since at least 1987,
PG&E has intentionally underpaid its franchise fees to the counties in an
unspecified amount.
The complaint cites two reasons for the alleged underpayment of fees. Based
on their interpretation of certain legislation, the plaintiffs allege that
PG&E has been using the wrong methodology to compute the franchise fees
payable to the plaintiff counties. The plaintiffs also allege that fees have
been underpaid due to incorrect calculations under the methodology used by
PG&E.
The parties agreed to stipulate to this case proceeding as a class action
lawsuit regarding the issue of the correct payment methodology to be applied
in calculating the franchise fees due to the plaintiffs. On March 14, 1995,
the Superior Court granted PG&E's motion for summary judgment in the class
action lawsuit. The plaintiffs appealed that ruling and on January 14, 1997,
the Court of Appeal upheld the summary judgment
39
in PG&E's favor. The plaintiffs did not seek review of the Court of Appeal's
ruling, and accordingly the summary judgment has become final, resolving the
issue regarding the payment methodology.
Consistent with the agreement between the parties noted above, the
plaintiffs refiled a separate action covering just the issue of whether PG&E
properly computed its franchise payments, assuming that PG&E has been using
the correct methodology. Plaintiffs may now reactivate this case, which had
been stayed pending resolution of the challenge to the payment formula.
Plaintiffs have not indicated damages to be sought in that separate action,
but they are not anticipated to be material.
CITIES FRANCHISE FEES LITIGATION
On May 13, 1994, the City of Santa Cruz filed a complaint in Santa Cruz
County Superior Court against PG&E on behalf of itself and purportedly as a
class action on behalf of 107 cities with which PG&E has certain electric
franchise contracts. The complaint alleges that, since at least 1987, PG&E has
intentionally underpaid its franchise fees to the cities in an unspecified
amount.
The complaint alleges that PG&E has asked for and accepted electric
franchises from the cities included in the purported class, which provide for
lower franchise payments than required by franchises granted by other cities
in PG&E's service territory. Plaintiff asserts that this was done in an
unlawfully discriminatory manner based solely on location. The plaintiff also
alleges that the transfer of these franchises to PG&E by its predecessor
companies was not approved by the CPUC as required, and, therefore, all such
franchise contracts are void.
The Court has certified the class of 107 cities in this action, and approved
the City of Santa Cruz as the class representative. On September 1, 1995, the
Court denied PG&E's motions for summary judgment and class decertification in
this case. The Court did bifurcate the issues in the case for trial such that
the issue concerning whether PG&E engaged in unlawful discrimination in
accepting certain franchise contracts with differing payment formulas would be
tried first, to be followed by the issue relating to the validity of PG&E's
current franchise contracts with the plaintiff cities.
On January 22, 1996, the Court granted PG&E's motion for summary judgment
against five class member cities with respect to the cities' claims that the
different franchise payment formulas in the 1937 Franchise Act constitute
unlawful discrimination. On March 19, 1996, the Court granted PG&E's motion
for judgment against the 31 charter cities who are members of the plaintiff
class, including the class representative (the City of Santa Cruz). The Court
determined that those cities had no basis for their claims against PG&E since
their franchise fee structure was of their own choosing as a matter of "home
rule" under the California Constitution.
At present, 71 general law cities remain as members of the plaintiff class.
Given the Court's prior rulings, the only remaining triable issue relates to
the validity of PG&E's current franchise contracts with the remaining
plaintiffs. Trial has been postponed indefinitely pending plaintiffs' appeal
of the rulings against them.
Should the cities prevail on the issue of franchise fee calculation
methodology, PG&E's annual system-wide city electric franchise fees could
increase by approximately $14 million and damages for alleged underpayments
for the years 1987 to 1996 could be as much as $145 million (exclusive of
interest). If the Court's rulings effectively eliminating certain cities'
claims become final, PG&E's potential damages and increased fees would be
significantly reduced. In that event, should the remaining plaintiffs prevail,
PG&E's annual systemwide city electric franchise fees could increase by
approximately $4 million and damages for the remaining plaintiffs for alleged
underpayments could be as much as $39 million (exclusive of interest). The
ultimate damages and/or increase in fees in any case might vary depending on
the Court's interpretation of the plaintiffs' claims.
40
The Company believes that the ultimate outcome of this matter will not have
a material adverse impact on its financial position or results of operations.
NORCEN LITIGATION
In March 1994, Norcen Energy Resources Limited (Norcen Energy) and Norcen
Marketing Incorporated (Norcen Marketing) filed a complaint in the U.S.
District Court, Northern District of California, against PG&E and PGT. Norcen
Marketing has a 30-year gas transportation contract with PGT, which is
guaranteed by Norcen Energy. The complaint alleged that PGT and PG&E
wrongfully induced Norcen Energy and Norcen Marketing to enter into the 30-
year contract by concealing legal action taken by PG&E before the CPUC
(requesting clarification that gas shipped on the PGT portion of the Pipeline
Expansion should pay PG&E's incremental Expansion rates for in-state service)
two days before Norcen Marketing's contract became binding. The complaint also
alleged breach of representations to plaintiffs that PG&E would not
"unreasonably" build its Pipeline Expansion with less than "sufficient" firm
subscription and a breach of an agreement between PGT and a Norcen predecessor
relating to the installation of additional capacity. In addition to state law
contract claims, the complaint also alleged a series of federal and state
antitrust claims related to the construction of the Pipeline Expansion and
PG&E's alleged refusals to allow access to the original PGT and California
transmission systems.
In September 1994, the District Court granted PGT's and PG&E's motion to
dismiss all federal antitrust claims in the complaint originally filed in this
case, and dismissed the remaining state law claims for lack of jurisdiction.
In October 1994, plaintiffs filed an amended complaint. The amended
complaint reasserted part of the original complaint's antitrust claims,
asserted new antitrust claims based on the same facts, and specifically
alleged diversity jurisdiction for the state law contract claims. In July
1995, the District Court issued an order on PG&E's motion to dismiss the
amended complaint. The order dismisses all of plaintiffs' federal and state
antitrust claims, but does not dismiss various state law contract claims,
including claims based on fraudulent inducement and breach of contract.
Plaintiffs have the right to appeal the dismissal of the antitrust claims to
the Court of Appeals. Plaintiffs still seek rescission of their gas
transportation contracts and compensatory and punitive damages in connection
with their remaining state law claims. The Company believes plaintiffs in this
action might seek contract damages of approximately $100 million in this
matter.
The Company believes that the ultimate outcome of this matter will not have
a material adverse impact on its financial position or results of operations.
CALIFORNIA ATTORNEY GENERAL INVESTIGATION
In February 1995, the California Attorney General (AG) initiated an
investigation to determine whether PG&E and its consultant, Tenera, Inc.
(Tenera), violated the Federal Clean Water Act and the California Water Code
in connection with a 1988 study of the cooling water intake system at Diablo
Canyon (1988 Study). The United States Department of Justice (DOJ) has since
joined the AG's investigation. PG&E has been in discussions with the AG and
the DOJ concerning the disposition of this matter and related litigation with
the League For Coastal Protection and John W. Carter (collectively, the Diablo
Canyon Environmental Litigation). See "Diablo Canyon Environmental Litigation"
below. In those discussions, the AG and DOJ have indicated their belief that
PG&E violated the Federal Clean Water Act, the California Water Code, and
other provisions of California law in connection with the 1988 Study. The AG
and DOJ have proposed a resolution of these matters that involves the payment
by PG&E of civil penalties and mitigation project costs.
The Company believes that the ultimate outcome of these matters will not
have a material adverse impact on its financial position or results of
operations.
41
DIABLO CANYON ENVIRONMENTAL LITIGATION
On October 13, 1995, the League for Coastal Protection (Coastal League)
filed a lawsuit in San Francisco County Superior Court against PG&E and its
consultant, Tenera, alleging violations of the California Business and
Professions Code in connection with the 1988 Study. The 1988 Study is also the
subject of an investigation by the AG and DOJ, as described above. The Coastal
League alleges that PG&E and its consultant violated the law by making
misrepresentations in connection with the 1988 Study. The Coastal League seeks
an unspecified amount of damages related to restitution or disgorgement of
improper or excessive profits, punitive damages, injunctive relief, and
attorneys' fees.
On April 16, 1996, the Coastal League filed another lawsuit in the United
States District Court, Northern District of California, against PG&E and
Tenera, alleging violations of the federal Clean Water Act in connection with
the 1988 Study. The Coastal League alleges that PG&E and Tenera withheld data
from the 1988 Study and submitted misleading information to the state and
federal agencies. The Coastal League seeks a judgment that PG&E has violated
its discharge permit for Diablo Canyon, revocation of the permit, an order
requiring restoration of the marine environment, an unspecified amount of
civil penalties, and recovery of its litigation and attorneys' fees.
Also on April 16, 1996, PG&E received a copy of a complaint filed in a third
case involving the 1988 Study. In this case, John W. Carter (Carter) alleges
on behalf of himself and the United States and the State of California that
PG&E, Tenera, and certain of their employees violated the federal and state
False Claims Acts by filing an incomplete report in 1988 (i.e., the 1988
Study) and failing to correct it. The United States and the State of
California have declined to prosecute this action, and it is maintained by
Carter, who is represented by the same attorneys representing the Coastal
League. The plaintiffs seek civil penalties, treble damages, a separate
payment to Carter under the False Claims Acts, and attorneys' fees.
See "California Attorney General Investigation" above for a discussion of a
possible resolution of this litigation.
The Company believes that the ultimate outcome of this matter will not have
a material adverse impact on its financial position or results of operations.
COMPRESSOR STATION CHROMIUM LITIGATION
PG&E has been named as a defendant in several civil actions filed in
Southern California courts on behalf of more than 1,500 plaintiffs. These
cases are Aguayo v. PG&E, filed March 15, 1995, in Los Angeles County Superior
Court; Aguilar v. PG&E, filed October 4, 1996, in Los Angeles County Superior
Court; Tate v. PG&E, filed October 29, 1996, in San Bernardino County Superior
Court; and Adams v. Betz, filed September 21, 1994, in Los Angeles County
Superior Court. In the Adams case, the claims remaining against PG&E arise
from a cross-claim filed by Betz Chemical Company (Betz), the supplier of
water treatment products containing chromium which are used at the gas
compressor stations. All of these cases will be referred to collectively as
the "Aguayo Litigation." Each of the complaints in the Aguayo Litigation
allege personal injuries and seek compensatory and punitive damages in an
unspecified amount arising out of alleged exposure to chromium contamination
in the vicinity of PG&E's gas compressor stations at Kettleman, Hinkley, and
Topock, California. Betz also is named as a defendant in the Aguayo
Litigation. The plaintiffs in the Aguayo Litigation include PG&E employees,
former PG&E employees, relatives of PG&E employees or former employees,
residents in the vicinity of the compressor stations, and persons who visited
the gas compressor stations, alleging exposure to chromium at or near the
compressor stations. The plaintiffs also include spouses or children of these
plaintiffs who claim only loss of consortium or injury through the alleged
exposure of their parents. PG&E is responding to the complaints and asserting
affirmative defenses. PG&E will pursue appropriate legal defenses, including
statute of limitations or exclusivity of workers' compensation laws, and
factual defenses, including lack of exposure to chromium and the inability of
chromium to cause certain of the illnesses alleged. At this stage of the
proceedings, there is substantial uncertainty concerning the claims alleged,
and PG&E 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.
42
The Company believes that the ultimate outcome of this matter will not have a
material adverse impact on its financial position or results of operations.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
Not applicable.
43
EXECUTIVE OFFICERS OF THE REGISTRANT
"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 1996 POSITION
---- ------------ --------
S. T. Skinner........ 59 Chairman of the Board and Chief Executive
Officer
R. D. Glynn, Jr. .... 54 President and Chief Operating Officer
J. D. Shiffer**...... 58 Executive Vice President (PG&E)
R. J. Haywood........ 52 Senior Vice President and General
Manager, Customer Energy Services (PG&E)
T. W. High........... 49 Senior Vice President--Corporate Services
(PG&E)
J. F. Jenkins-Stark.. 45 Senior Vice President and General
Manager,
Gas Supply Business Unit (PG&E)
G. R. Smith.......... 48 Chief Financial Officer
B. R. Worthington.... 47 General Counsel
J. Pfannenstiel...... 49 Vice President--Corporate Planning (PG&E)
*All positions are with PG&E Corporation, unless otherwise noted.
**Mr. Shiffer will retire effective April 1, 1997.
"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 are as
follows*:
AGE AT
DECEMBER 31,
NAME 1996 POSITION
---- ------------ --------
S. T. Skinner........ 59 Chairman of the Board and Chief Executive
Officer
R. D. Glynn, Jr. .... 54 President and Chief Operating Officer
J. D. Shiffer**...... 58 Executive Vice President
R. J. Haywood........ 52 Senior Vice President and General
Manager, Customer Energy Services
T. W. High........... 49 Senior Vice President--Corporate Services
J. F. Jenkins-Stark.. 45 Senior Vice President and General
Manager, Gas Supply Business Unit
G. R. Smith.......... 48 Senior Vice President and Chief Financial
Officer
B. R. Worthington.... 47 Senior Vice President and General Counsel
J. Pfannenstiel...... 49 Vice President--Corporate Planning
*All positions are with PG&E.
**Mr. Shiffer will retire effective April 1, 1997.
All officers of PG&E Corporation and PG&E serve at the pleasure of the
relevant Board of Directors. All executive officers of both companies have
been employees of PG&E for the past five years. During that period, the
executive officers had the following business experience as PG&E employees
and/or officers, and/or PG&E Corporation officers*:
NAME POSITION PERIOD HELD OFFICE
---- -------- ------------------
S.T. Skinner......... Chairman of the Board December 18, 1996 to current
and Chief Executive
Officer (PG&E
Corporation)
Chairman of the Board June 1, 1995 to current
and Chief Executive
Officer
President and Chief July 1, 1994 to May 31, 1995
Executive Officer
President and Chief November 1, 1991 to June 30, 1994
Operating Officer
R.D. Glynn, Jr....... President and Chief December 18, 1996 to current
Operating Officer (PG&E
Corporation)
President and Chief June 1, 1995 to current
Operating Officer
Executive Vice President July 1, 1994 to May 31, 1995
Senior Vice President January 1, 1994 to June 30, 1994
and General Manager,
Customer Energy
Services Business Unit
Senior Vice President November 1, 1991 to December 31, 1993
and General Manager,
Electric Supply
Business Unit
J.D. Shiffer......... Executive Vice President November 1, 1991 to current
44
NAME POSITION PERIOD HELD OFFICE
---- -------- ------------------
R.J. Haywood......... Senior Vice President December 21, 1994 to current
and General Manager,
Customer Energy
Services Business Unit
Vice President of Power February 22, 1993 to December 20, 1994
System
Vice President-Power April 20, 1988 to February 21, 1993
Planning and Contracts
T.W. High............ Senior Vice President- June 1, 1995 to current
Corporate Services
Vice President and July 1, 1994 to May 31, 1995
Assistant to the Chief
Executive Officer
Vice President and November 1, 1991 to June 30, 1994
Assistant to the
Chairman of the Board
J.F. Jenkins-Stark... Senior Vice President August 1, 1993 to current
and General Manager,
Gas Supply Business
Unit
Vice President and January 15, 1992 to July 31, 1993
Treasurer
G.R. Smith........... Chief Financial Officer December 18, 1996 to current
(PG&E Corporation)
Senior Vice President June 1, 1995 to current
and Chief Financial
Officer
Vice President and Chief November 1, 1991 to May 31, 1995
Financial Officer
B.R. Worthington..... General Counsel (PG&E December 18, 1996 to current
Corporation)
Senior Vice President June 1, 1995 to current
and General Counsel
Vice President and December 21, 1994 to May 31, 1995
General Counsel
Chief Counsel-Corporate January 10, 1991 to December 20, 1994
*All positions are with PG&E, unless otherwise noted.
45
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS.
Information responding to part of Item 5 is set forth on page 42 under the
heading "Quarterly Consolidated Financial Data" in the 1996 Annual Report to
Shareholders, which information is hereby incorporated by reference and filed
as part of Exhibit 13 to this report.
PG&E has made no sales of unregistered equity securities in the last three
years. PG&E Corporation has made the following sales of unregistered equity
securities during such period:
On January 27, 1997, PG&E Corporation issued 14,607,143 shares of common
stock. The shares were issued to nine former shareholders of Teco in
connection with the acquisition by PG&E Corporation of Teco. 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 the Company for each of the
last five fiscal years is set forth on page 8 under the heading "Selected
Financial Data" in the 1996 Annual Report to Shareholders, which information
is hereby incorporated by reference and filed as part of Exhibit 13 to this
report.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS.
A discussion of the Company's financial condition, changes in financial
condition and results of operations is set forth on pages 9 through 19 under
the heading "Management's Discussion and Analysis of Consolidated Results of
Operations and Financial Condition" in the 1996 Annual Report to Shareholders,
which discussion is hereby incorporated by reference and filed as part of
Exhibit 13 to this report.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
Information responding to Item 8 is contained in the 1996 Annual Report to
Shareholders on pages 20 through 43 under the headings "Statement of
Consolidated Income," "Statement of Consolidated Cash Flows," "Consolidated
Balance Sheet," "Statement of Consolidated Common Stock Equity, Preferred
Stock and Preferred Securities," "Statement of Consolidated Capitalization,"
"Statement of Consolidated Segment Information," "Notes to Consolidated
Financial Statements," "Quarterly Consolidated Financial Data (Unaudited),"
and "Report of Independent Public Accountants," which information is hereby
incorporated by reference and filed as part of Exhibit 13 to this report.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE.
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
Information regarding executive officers of PG&E is included in a separate
item captioned "Executive Officers of the Registrant" contained on pages 44
through 45 in Part I of this report. Other information responding to Item 10
is included on pages 2 through 5 under the heading "Election of Directors of
PG&E Corporation and PG&E" and page 29 under the heading "Section 16(a)
Beneficial Ownership Reporting Compliance" in the 1997 Joint Proxy Statement
relating to the 1997 Annual Meetings of Shareholders, which information is
hereby incorporated by reference.
46
ITEM 11. EXECUTIVE COMPENSATION.
Information responding to Item 11 is included on page 8 under the heading
"Compensation of Directors" and on pages 19 through 27 under the heading
"Executive Compensation" (excluding the sections thereunder entitled
"Nominating and Compensation Committee Report on Compensation" and "Comparison
of Five-Year Cumulative Total Shareholder Return") in the 1997 Joint Proxy
Statement relating to the 1997 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 is included on pages 10 and 28 under the
headings "Security Ownership of Management" and "Principal Shareholders" in
the 1997 Joint Proxy Statement relating to the 1997 Annual Meetings of
Shareholders, which information is hereby incorporated by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
Information responding to Item 13 is included on page 9 under the heading
"Certain Relationships and Related Transactions" in the 1997 Joint Proxy
Statement relating to the 1997 Annual Meetings of Shareholders, which
information is hereby incorporated by reference.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K.
(A) THE FOLLOWING DOCUMENTS ARE FILED AS A PART OF THIS REPORT:
1. The following consolidated financial statements, schedules of
consolidated segment information, supplemental information, and report
of independent public accountants contained in the 1996 Annual Report
to Shareholders, are incorporated by reference in this report:
Statement of Consolidated Income for the Years Ended December 31,
1996, 1995, and 1994.
Statement of Consolidated Cash Flows for the Years Ended December 31,
1996, 1995, and 1994.
Consolidated Balance Sheet at December 31, 1996, and 1995.
Statement of Consolidated Common Stock Equity, Preferred Stock and
Preferred Securities for the Years Ended December 31, 1996, 1995, and
1994.
Statement of Consolidated Capitalization at December 31, 1996, and
1995.
Schedule of Consolidated Segment Information for the Years Ended
December 31, 1996, 1995, and 1994.
Notes to Consolidated Financial Statements.
Quarterly Consolidated Financial Data (Unaudited).
Report of Independent Public Accountants.
2. Report of Independent Public Accountants included at page 53 of this
Form 10-K.
3. Consolidated financial statement schedules:
II -- Consolidated Valuation and Qualifying Accounts for the Years
Ended December 31, 1996, 1995 and 1994.
47
Schedules not included are omitted because of the absence of conditions
under which they are required or because the required information is provided
in the consolidated financial statements including the notes thereto.
4. Exhibits required to be filed by Item 601 of Regulation S-K:
3.1 Restated Articles of Incorporation of PG&E Corporation effective as
of December 19, 1996 (PG&E Corporation's Form 8-B (File No. 1-
12609), Exhibit 3.1).
3.2 By-Laws of PG&E Corporation effective as of December 19, 1996 (PG&E
Corporation's Form 8-B (File No. 1-12609), Exhibit 3.2).
3.3 Agreement of Merger (PG&E Corporation's Form 8-B (File No. 1-
12609), Exhibit 1).
3.4 Restated Articles of Incorporation of Pacific Gas and Electric
Company effective as of July 26, 1994 (PG&E's Form 10-Q, for
quarter ended June 30, 1994 (File No. 1-2348), Exhibit 3.1).
3.5 By-Laws of Pacific Gas and Electric Company as of January 1, 1997.
4. First and Refunding Mortgage of PG&E 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;
PG&E's Form 8-K dated January 18, 1989 (File No. 1-2348), Exhibit
4.2).
10.1 Firm Transportation Service Agreement between PG&E and Pacific Gas
Transmission Company dated October 26, 1993 (PG&E's Form 10-K for
fiscal year 1993 (File No. 1-2348), Exhibit 10.4), rate schedule
FTS-1, and general terms and conditions.
10.2 Transportation Service Agreement as Amended and Restated between
PG&E and El Paso Natural Gas Company dated November 1, 1993 (PG&E's
Form 10-K for fiscal year 1993 (File No. 1-2348), Exhibit 10.5),
rate schedule FT-1, and general terms and conditions. (PG&E's Form
10-K for fiscal year 1995 (File No. 1-2348, Exhibit 10.2).
10.3 Diablo Canyon Settlement Agreement (Diablo Settlement) dated June
24, 1988 (PG&E's Form 8-K dated June 27, 1988) (File No. 1-2348),
Exhibit 10.1), Implementing Agreement dated July 15, 1988 (PG&E's
Form 10-Q for the quarter ended June 30, 1988 (File No. 1-2348),
Exhibit 10.1), portions of the California Public Utilities
Commission Decision No. 88-12-083, dated December 19, 1988,
interpreting the Diablo Settlement (PG&E's Form 10-K for fiscal
year 1988 (File No. 1-2348), Exhibit 10.4) and Settlement Agreement
dated December 14, 1994, modifying the Diablo Settlement (PG&E's
Form 10-K for fiscal year 1995 (File No. 1-2348), Exhibit 10.3).
*10.4 Pacific Gas and Electric Company Deferred Compensation Plan for
Directors (PG&E's Form 10-K for fiscal year 1992 (File No. 1-2348),
Exhibit 10.5).
*10.5 PG&E Corporation Deferred Compensation Plan for Directors. (PG&E
Corporation's Form 8-B (File No. 1-12609), Exhibit 10.5)
- --------
* 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.
48
*10.6 Pacific Gas and Electric Company Deferred Compensation Plan for
Officers (PG&E's Form 10-K for fiscal year 1991 (File No. 1-2348),
Exhibit 10.6).
*10.7 Savings Fund Plan for Employees of Pacific Gas and Electric
Company applicable to non-union employees, as amended and restated
effective as of January 1, 1997 (PG&E Corporation's Form 8-B
(File No. 1-12609), Exhibit 10.7).
*10.8 Short-Term Incentive Plan for Officers of Pacific Gas and Electric
Company, effective January 1, 1996 (PG&E's Form 10-K for fiscal
year 1995 (File No. 1-2348), Exhibit 10.7).
*10.9 The Pacific Gas and Electric Company Retirement Plan applicable to
non-union employees, as amended October 18, 1995, effective
January 1, 1996 (PG&E's Form 10-K for fiscal year 1995 (File No.
1-2348), Exhibit 10.8).
*10.10 Pacific Gas and Electric Company Supplemental Executive Retirement
Plan, as amended through October 16, 1991 (PG&E's Form 10-K for
fiscal year 1991 (File No. 1-2348), Exhibit 10.11).
*10.11 Pacific Gas and Electric Company Relocation Assistance Program for
Officers (PG&E's Form 10-K for fiscal year 1989 (File No. 1-2348),
Exhibit 10.16).
*10.12 Pacific Gas and Electric Company Executive Flexible Perquisites
Program (PG&E's Form 10-K for fiscal year 1993 (File No. 1-2348),
Exhibit 10.16).
*10.13 PG&E Postretirement Life Insurance Plan (PG&E's Form 10-K for
fiscal year 1991 (File No. 1-2348), Exhibit 10.16).
*10.14 PG&E Corporation Retirement Plan for Non-Employee Directors (PG&E
Corporation's Form 8-B (File No. 1-12609), Exhibit 10.14).
*10.15 Pacific Gas and Electric Company Retirement Plan for Non-Employee
Directors (PG&E Corporation's Form 8-B (File No. 1-12609), Exhibit
10.15).
*10.16 Executive Compensation Insurance Indemnity in respect of Deferred
Compensation Plan for Directors, Deferred Compensation Plan for
Officers, Supplemental Executive Retirement Plan and Retirement
Plan for Non-Employee Directors (PG&E's Form 10-K for fiscal year
1991 (File No. 1-2348), Exhibit 10.19).
*10.17 PG&E Corporation Long-Term Incentive Program, as amended and
restated effective as of January 1, 1997, including the PG&E
Corporation Stock Option Plan, Performance Unit Plan and
Restricted Stock Plan for Non-Employee Directors (PG&E
Corporation's Form 8-B (File No. 1-12609), Exhibit 10.17).
11. Computation of Earnings Per Common Share.
12.1 Computation of Ratios of Earnings to Fixed Charges.
12.2 Computation of Ratios of Earnings to Combined Fixed Charges and
Preferred Stock Dividends.
- --------
* 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.
49
13. 1996 Annual Report to Shareholders (portions of the 1996 Annual
Report to Shareholders under the headings "Selected Financial Data,"
"Management's Discussion and Analysis of Consolidated Results of
Operations and Financial Condition," "Report of Independent Public
Accountants," "Statement of Consolidated Income," "Consolidated
Balance Sheet," "Statement of Consolidated Cash Flows," "Statement
of Consolidated Common Stock Equity, Preferred Stock and Preferred
Securities," "Statement of Consolidated Capitalization," "Schedule
of Consolidated Segment Information," "Notes to Consolidated
Financial Statements" and "Quarterly Consolidated Financial Data,"
included only) (except for those portions which are expressly
incorporated herein by reference, such 1996 Annual Report to
Shareholders is furnished for the information of the Commission and
is not deemed to be "filed" herein).
21. Subsidiaries of the Registrants.
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. Financial Data Schedule.
The exhibits filed herewith are attached hereto (except as noted) and those
indicated above which are not filed herewith were previously filed with the
Commission as indicated and are hereby incorporated by reference. Exhibits
will be furnished to security holders of the Company upon written request and
payment of a fee of $0.30 per page, which fee covers only the Company's
reasonable expenses in furnishing such exhibits. The Company agrees to furnish
to the Commission upon request a copy of any instrument defining the rights of
long-term debt holders not otherwise required to be filed hereunder.
(B) REPORTS ON FORM 8-K
Reports on Form 8-K during the quarter ended December 31, 1996 and through
the date hereof:
1. October 16, 1996(1)
Item 5. Other Events
-- Performance Incentive Plan -- Year-to-Date Financial Results
-- Common Stock Dividend Reduction
2. November 22, 1996(1)
Item 5. Other Events
-- Acquisitions and Dispositions
3.December 20, 1996(1)
Item 5. Other Events
-- Performance Incentive Plan -- 1997 Target
4. January 2, 1997(1)(2)
Item 5. Other Events
-- Holding Company Formation
5. January 7, 1997(1)(2)
Item 5. Other Events
-- Electric Industry Restructuring
-- 1997 ECAC
6.January 16, 1997(1)(2)
Item 5. Other Events
--Performance Incentive Plan -- Year-to-Date Financial Results
--1996 Consolidated Earnings (unaudited)
50
7.January 31, 1997(1)(2)
Item 5. Other Events
--Acquisition of Valero Energy Corporation
--Acquisition of Teco Pipeline Company
--Electric Industry Restructuring Cost Recovery Plan
8.February 19, 1997(1)(2)
Item 7. Financial Statements, Pro Forma Financial Information and Exhibits
--1996 Financial Statements
9.March 3, 1997(1)(2)
Item 5. Other Events
--Proposed Decision on Diablo Canyon Ratemaking Proposal
- --------
(1)Filed under Commission File Number 1-2348 (PG&E)
(2)Filed under Commission File Number 1-12609 (PG&E Corporation)
51
SIGNATURES
PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(D) OF THE SECURITIES
EXCHANGE ACT OF 1934, THE REGISTRANTS HAVE DULY CAUSED THIS REPORT TO BE SIGNED
ON THEIR BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED, IN THE CITY AND
COUNTY OF SAN FRANCISCO, ON THE 4TH DAY OF MARCH, 1997.
PG&E CORPORATION PACIFIC GAS AND ELECTRIC COMPANY
(Registrant) (Registrant)
GARY P. ENCINAS GARY P. ENCINAS
By _________________________________ By _________________________________
(Gary P. Encinas, Attorney-in-Fact) (Gary P. Encinas, Attorney-in-
Fact)
PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS
REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE
REGISTRANT AND IN THE CAPACITIES AND ON THE DATES INDICATED.
SIGNATURE TITLE DATE
--------- ----- ----
A. PRINCIPAL EXECUTIVE
OFFICER OR OFFICERS
*STANLEY T. SKINNER Chairman of the Board, March 4, 1997
Chief Executive Officer, and
Director
(PG&E Corporation)
Chairman of the Board,
Chief Executive Officer, and
Director
(Pacific Gas and Electric
Company)
B. PRINCIPAL FINANCIAL
OFFICER
*GORDON R. SMITH Chief Financial Officer March 4, 1997
(PG&E Corporation)
Senior Vice President and
Chief Financial Officer
(Pacific Gas and Electric
Company)
C. PRINCIPAL ACCOUNTING
OFFICER
*CHRISTOPHER P. JOHNS Controller (PG&E Corporation) March 4, 1997
Vice President and Controller
(Pacific Gas and Electric
Company)
D. DIRECTORS
*RICHARD A. CLARKE
*H. M. CONGER
*C. LEE COX
*ROBERT D. GLYNN, JR.
*DAVID M. LAWRENCE
*RICHARD B. MADDEN Directors (PG&E Corporation and March 4, 1997
*MARY S. METZ Pacific Gas and Electric
*REBECCA Q. MORGAN Company)
*SAMUEL T. REEVES
*CARL E. REICHARDT
*JOHN C. SAWHILL
*ALAN SEELENFREUND
*BARRY LAWSON WILLIAMS
GARY P. ENCINAS
*By ________________________________
(Gary P. Encinas, Attorney-in-
Fact)
52
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Shareholders and the Board of Directors
of PG&E Corporation:
We have audited in accordance with generally accepted auditing standards,
the consolidated financial statements included in the PG&E Corporation Annual
Report to Shareholders incorporated by reference in this Annual Report on Form
10-K, and have issued our report thereon dated February 10, 1997. Our audits
were made for the purpose of forming an opinion on those statements taken as a
whole. The schedule listed in Part IV, Item 14. (a)(3) of this Annual Report
on Form 10-K is the responsibility of the Company's management and is
presented for the purpose of complying with the Securities and Exchange
Commission's rules and is not part of the basic consolidated financial
statements. The schedule has been subjected to the auditing procedures applied
in the audit of the basic consolidated financial statements and, in our
opinion, fairly states in all material respects the financial data required to
be set forth therein in relation to the basic consolidated financial
statements taken as a whole.
ARTHUR ANDERSEN LLP
ARTHUR ANDERSEN LLP
San Francisco, California
February 10, 1997
53
SCHEDULE II
PACIFIC GAS AND ELECTRIC COMPANY
SCHEDULE II -- CONSOLIDATED VALUATION AND
QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E
ADDITIONS
-----------------
BALANCE CHARGED BALANCE
AT TO COSTS CHARGED AT END
BEGINNING AND TO OTHER OF
DESCRIPTION OF PERIOD EXPENSES ACCOUNTS DEDUCTIONS PERIOD
----------- --------- -------- -------- ---------- --------
(IN THOUSANDS)
VALUATION AND QUALIFYING
ACCOUNTS DEDUCTED FROM
ASSETS:
1996:
Reserve for deferred
project costs............ $ 5,710 $ -- $ -- $ 5,710(1) $ 0
======= ======= ====== ======= =======
Allowance for
uncollectible accounts... $35,520 $55,566 $1,836 $35,018(2) $57,904
======= ======= ====== ======= =======
Reserve for land costs.... $ 4,444 $ -- $ -- $ 4,444(1) $ 0
======= ======= ====== ======= =======
1995:
Reserve for impairment of
oil and gas properties... $ 4,341 $ -- $ -- $ 4,341(3) $ 0
======= ======= ====== ======= =======
Reserve for deferred
project costs............ $25,800 $ -- $ -- $20,090(1) $ 5,710
======= ======= ====== ======= =======
Allowance for
uncollectible accounts... $29,769 $50,327 $ -- $44,576(2) $35,520
======= ======= ====== ======= =======
Reserve for land costs.... $ 5,960 $ -- $ -- $ 1,516(1) $ 4,444
======= ======= ====== ======= =======
1994:
Reserve for impairment of
oil and gas properties... $ 7,924 $ 4,565 $ -- $ 8,148(3) $ 4,341
======= ======= ====== ======= =======
Reserve for deferred
project costs............ $18,689 $ 7,111 $ -- $ -- $25,800
======= ======= ====== ======= =======
Allowance for
uncollectible accounts... $23,647 $44,415 $ -- $38,293(2) $29,769
======= ======= ====== ======= =======
Reserve for land costs.... $ 6,154 $ -- $ -- $ 194(1) $ 5,960
======= ======= ====== ======= =======
- --------
(1) Deductions consist principally of write-offs. Reserve for deferred project
costs is classified on the balance sheet in other deferred charges. Reserve
for land costs is classified on the balance sheet in investment in
nonregulated projects.
(2) Deductions consist principally of write-offs, net of collections of
receivables previously written off.
(3) Deductions consist principally of write-offs of expired leaseholds on
reserved property. Deduction in 1995 results from sale of oil and gas
properties.
54
INDEX TO EXHIBITS
EXHIBIT DESCRIPTION OF EXHIBITS
NUMBER -----------------------
-------
3.1 Restated Articles of Incorporation of PG&E Corporation effective as of
December 19, 1996 (PG&E Corporation's Form 8-B (File No. 1-12609), Exhibit
3.1).
3.2 By-Laws of PG&E Corporation effective as of December 19, 1996 (PG&E
Corporation's Form 8-B (File No. 1-12609), Exhibit 3.2).
3.3 Agreement of Merger (PG&E Corporation's Form 8-B (File No. 1-12609),
Exhibit 1).
3.4 Restated Articles of Incorporation of Pacific Gas and Electric Company
effective as of July 26, 1994 (PG&E's Form 10-Q, for quarter ended June
30, 1994 (File No. 1-2348), Exhibit 3.1).
3.5 By-Laws of Pacific Gas and Electric Company as of January 1, 1997.
4. First and Refunding Mortgage of PG&E 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; PG&E's Form 8-K dated January 18, 1989 (File No. 1-2348),
Exhibit 4.2).
10.1 Firm Transportation Service Agreement between PG&E and Pacific Gas
Transmission Company dated October 26, 1993 (PG&E's Form 10-K for fiscal
year 1993 (File No. 1-2348), Exhibit 10.4), rate schedule FTS-1, and
general terms and conditions.
10.2 Transportation Service Agreement as Amended and Restated between PG&E and
El Paso Natural Gas Company dated November 1, 1993 (PG&E's Form 10-K for
fiscal year 1993 (File No. 1-2348), Exhibit 10.5), rate schedule FT-1, and
general terms and conditions. (PG&E's Form 10-K for fiscal year 1995 (File
No. 1-2348, Exhibit 10.2).
10.3 Diablo Canyon Settlement Agreement (Diablo Settlement) dated June 24, 1988
(PG&E's Form 8-K dated June 27, 1988) (File No. 1-2348), Exhibit 10.1),
Implementing Agreement dated July 15, 1988 (PG&E's Form 10-Q for the
quarter ended June 30, 1988 (File No. 1-2348), Exhibit 10.1), portions of
the California Public Utilities Commission Decision No. 88-12-083, dated
December 19, 1988, interpreting the Diablo Settlement (PG&E's Form 10-K
for fiscal year 1988 (File No. 1-2348), Exhibit 10.4) and Settlement
Agreement dated December 14, 1994, modifying the Diablo Settlement (PG&E's
Form 10-K for fiscal year 1995 (File No. 1-2348), Exhibit 10.3).
*10.4 Pacific Gas and Electric Company Deferred Compensation Plan for Directors
(PG&E's Form 10-K for fiscal year 1992 (File No. 1-2348), Exhibit 10.5).
*10.5 PG&E Corporation Deferred Compensation Plan for Directors. (PG&E
Corporation's Form 8-B (File No. 1-12609), Exhibit 10.5).
*10.6 Pacific Gas and Electric Company Deferred Compensation Plan for Officers
(PG&E's Form 10-K for fiscal year 1991 (File No. 1-2348), Exhibit 10.6).
*10.7 Savings Fund Plan for Employees of Pacific Gas and Electric Company
applicable to non-union employees, as amended and restated effective as of
January 1, 1997 (PG&E Corporation's Form 8-B (File No. 1-12609), Exhibit
10.7).
*10.8 Short-Term Incentive Plan for Officers of Pacific Gas and Electric
Company, effective January 1, 1996 (PG&E's Form 10-K for fiscal year 1995
(File No. 1-2348), Exhibit 10.7).
- --------
* 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.
EXHIBIT DESCRIPTION OF EXHIBITS
NUMBER -----------------------
-------
*10.9 The Pacific Gas and Electric Company Retirement Plan applicable to non-
union employees, as amended October 18, 1995, effective January 1, 1996
(PG&E's Form 10-K for fiscal year 1995 (File
No. 1-2348), Exhibit 10.8).
*10.10 Pacific Gas and Electric Company Supplemental Executive Retirement Plan,
as amended through October 16, 1991 (PG&E's Form 10-K for fiscal year 1991
(File No. 1-2348), Exhibit 10.11).
*10.11 Pacific Gas and Electric Company Relocation Assistance Program for
Officers (PG&E's Form 10-K for fiscal year 1989 (File No. 1-2348), Exhibit
10.16).
*10.12 Pacific Gas and Electric Company Executive Flexible Perquisites Program
(PG&E's Form 10-K for fiscal year 1993 (File No. 1-2348), Exhibit 10.16).
*10.13 PG&E Postretirement Life Insurance Plan (PG&E's Form 10-K for fiscal year
1991 (File No. 1-2348), Exhibit 10.16).
*10.14 PG&E Corporation Retirement Plan for Non-Employee Directors (PG&E
Corporation's Form 8-B (File No. 1-12609), Exhibit 10.14).
*10.15 Pacific Gas and Electric Company Retirement Plan for Non-Employee
Directors (PG&E Corporation's Form 8-B (File No. 1-12609), Exhibit 10.15).
*10.16 Executive Compensation Insurance Indemnity in respect of Deferred
Compensation Plan for Directors, Deferred Compensation Plan for Officers,
Supplemental Executive Retirement Plan and Retirement Plan for Non-
Employee Directors (PG&E's Form 10-K for fiscal year 1991 (File No. 1-
2348), Exhibit 10.19).
*10.17 PG&E Corporation Long-Term Incentive Program, as amended and restated
effective as of January 1, 1997, including the PG&E Corporation Stock
Option Plan, Performance Unit Plan and Restricted Stock Plan for Non-
Employee Directors (PG&E Corporation's Form 8-B (File No. 1-12609),
Exhibit 10.17).
11. Computation of Earnings Per Common Share.
12.1 Computation of Ratios of Earnings to Fixed Charges.
12.2 Computation of Ratios of Earnings to Combined Fixed Charges and Preferred
Stock Dividends.
13. 1996 Annual Report to Shareholders (portions of the 1996 Annual Report to
Shareholders under the headings "Selected Financial Data," "Management's
Discussion and Analysis of Consolidated Results of Operations and
Financial Condition," "Report of Independent Public Accountants,"
"Statement of Consolidated Income," "Consolidated Balance Sheet,"
"Statement of Consolidated Cash Flows," "Statement of Consolidated Common
Stock Equity, Preferred Stock and Preferred Securities," "Statement of
Consolidated Capitalization," "Schedule of Consolidated Segment
Information," "Notes to Consolidated Financial Statements" and "Quarterly
Consolidated Financial Data," included only) (except for those portions
which are expressly incorporated herein by reference, such 1996 Annual
Report to Shareholders is furnished for the information of the Commission
and is not deemed to be "filed" herein).
21. Subsidiaries of the Registrants.
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. Financial Data Schedule.
- --------
* 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.