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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(MARK ONE)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF
THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1996
OR
[_] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF
THE SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM TO
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COMMISSION EXACT NAME OF REGISTRANT IRS EMPLOYER
FILE AS SPECIFIED IN ITS STATE OF IDENTIFICATION
NUMBER CHARTER INCORPORATION NUMBER
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<C> <S> <C> <C>
1-12609 PG&E CORPORATION California 94-3234914
1-2348 PACIFIC GAS AND ELECTRIC California 94-0742640
COMPANY
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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:
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NAME OF EACH EXCHANGE ON
TITLE OF EACH CLASS WHICH REGISTERED
- ------------------- ---------------------------
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PG&E CORPORATION
Common Stock, no par value New York Stock Exchange and
Pacific Stock Exchange
PACIFIC GAS AND ELECTRIC COMPANY
First Preferred Stock, cumulative, American Stock Exchange and
par value $25 per share: Pacific Stock Exchange
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Redeemable:
7.44% 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)
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TABLE OF CONTENTS
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Glossary of Terms
PART I
Item 1. Business......................................................... 1
GENERAL.......................................................... 1
Corporate Structure and Business................................. 1
Competition and the Changing Regulatory Environment.............. 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
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TABLE OF CONTENTS--(CONTINUED)
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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
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GLOSSARY OF TERMS
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AB 1890......... Assembly Bill 1890, the California electric industry restructuring
legislation
AEAP............ Annual Earnings Assessment Proceeding
AER............. Annual Energy Rate
AFUDC........... allowance for funds used during construction
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
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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
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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.
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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
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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.
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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
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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
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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
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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.
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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
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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)
<TABLE>
<CAPTION>
ELECTRIC GAS TOTAL
-------- --- -----
<S> <C> <C> <C>
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)
===== === =====
</TABLE>
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
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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
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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.
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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)
<TABLE>
<CAPTION>
1997 1998 1999 TOTAL
---- ---- ---- -----
<S> <C> <C> <C> <C>
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
====== ====== ====== ======
</TABLE>
- --------
(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.
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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.
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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
<PAGE>
$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
<PAGE>
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
<PAGE>
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.
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31
--------------------------------------------------------
1996 1995 1994 1993 1992
---------- ---------- ---------- ---------- ----------
CUSTOMERS (AVERAGE FOR THE
YEAR):
<S> <C> <C> <C> <C> <C>
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 $7,763,011
========== ========== ========== ========== ==========
</TABLE>
- --------
(1) Includes energy supplied through PG&E's system by the City and County of
San Francisco for San Francisco's own use and for sale by San Francisco to
its customers, by the Department of Energy for government use and sale to
its customers, and by the State of California for California Water Project
pumping, as well as energy supplied by QFs and purchases from other
utilities.
(2) Includes energy output from Modesto and Turlock Irrigation Districts' own
resources.
(3) Represents energy required for pumping operations.
(4) Includes use by business units other than the electric utility business
units.
17
<PAGE>
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31
-------------------------------------------------
1996 1995 1994 1993 1992
--------- --------- --------- --------- ---------
SELECTED STATISTICS:
<S> <C> <C> <C> <C> <C>
Total customers (at year-
end)....................... 4,500,000 4,400,000 4,400,000 4,400,000 4,300,000
Average annual residential
usage (kWh)................ 6,571 6,377 6,422 6,431 6,381
Average billed revenues per
kWh (cents):
Residential................ 11.92 12.22 12.25 12.25 11.79
Commercial................. 10.19 10.97 11.04 11.10 10.92
Industrial................. 6.37 6.88 7.05 7.18 7.29
Agricultural............... 10.92 11.37 10.78 11.43 10.10
Net plant investment per
customer ($)............... 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
</TABLE>
- --------
(1) Area net capability at time of annual peak, based on actual water
conditions.
(2) Net control area peak demand includes demand served by Modesto and Turlock
Irrigation Districts' own resources.
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:
<TABLE>
<CAPTION>
NET
OPERATING
NUMBER CAPACITY
GENERATION TYPE COUNTY LOCATION OF UNITS KW
--------------- --------------- -------- ----------
<S> <C> <C> <C>
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
=== ==========
</TABLE>
- --------
(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
<PAGE>
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.
<TABLE>
<CAPTION>
CONTROL AREA
NET CAPACITY
(AT DATE OF 1996 PEAK)
----------------------
KW %
-------------- -------
<S> <C> <C>
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
==============
</TABLE>
<TABLE>
<CAPTION>
GENERATION
YEAR ENDED
DECEMBER 31, 1996(3)
--------------------
KWH
THOUSANDS %
-------------- ------
<S> <C> <C>
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
============== ======
</TABLE>
- --------
(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
<PAGE>
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.
<TABLE>
<CAPTION>
1997 1998 1999 2000 2001
----- -------- -------- --------- -----
<S> <C> <C> <C> <C> <C>
Unit 1
Refueling........................... April January September
Startup............................. May March October
Unit 2
Refueling........................... February October April
Startup............................. March November June
</TABLE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
The amount of energy received and the total payments made (including
termination and suspension payments) under QF contracts and other power
purchase contracts were:
<TABLE>
<CAPTION>
1996 1995 1994
------ ------ ------
(IN MILLIONS)
<S> <C> <C> <C>
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
</TABLE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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.
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31
----------------------------------------------------------
1996 1995 1994 1993 1992
---------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C>
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
========== ========== ========== ========== ==========
</TABLE>
- --------
(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
<PAGE>
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31
-------------------------------------------------
1996 1995 1994 1993 1992
--------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C>
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
</TABLE>
- --------
(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.
<TABLE>
<CAPTION>
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)
--------- -------- --------- ------- --------- ------- --------- -------- --------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
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
======= ===== ======= ===== ======= ===== ======= ===== ======= =====
</TABLE>
- --------
(1) The average prices for Canadian and U.S. Southwest gas include the
commodity gas prices, interstate pipeline demand or reservation charges,
transportation charges, and other pipeline assessments, including direct
bills allocated over the quantities received at the California border. The
average prices for California gas include only commodity gas prices
delivered to 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
<PAGE>
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
<PAGE>
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
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<PAGE>
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
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<PAGE>
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.
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<PAGE>
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
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<PAGE>
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.
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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
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<PAGE>
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.
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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.
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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.
<TABLE>
<CAPTION>
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)
<S> <C> <C> <C> <C>
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
======= =======
</TABLE>
- --------
(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
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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*:
<TABLE>
<CAPTION>
AGE AT
DECEMBER 31,
NAME 1996 POSITION
---- ------------ --------
<C> <C> <S>
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*:
<CAPTION>
AGE AT
DECEMBER 31,
NAME 1996 POSITION
---- ------------ --------
<C> <C> <S>
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
</TABLE>
*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*:
<TABLE>
<CAPTION>
NAME POSITION PERIOD HELD OFFICE
---- -------- ------------------
<C> <S> <C>
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
</TABLE>
44
<PAGE>
<TABLE>
<CAPTION>
NAME POSITION PERIOD HELD OFFICE
---- -------- ------------------
<C> <S> <C>
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
</TABLE>
*All positions are with PG&E, unless otherwise noted.
45
<PAGE>
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
<PAGE>
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
<PAGE>
Schedules not included are omitted because of the absence of conditions
under which they are required or because the required information is provided
in the consolidated financial statements including the notes thereto.
4. Exhibits required to be filed by Item 601 of Regulation S-K:
<TABLE>
<C> <S>
3.1 Restated Articles of Incorporation of PG&E Corporation effective as
of December 19, 1996 (PG&E Corporation's Form 8-B (File No. 1-
12609), Exhibit 3.1).
3.2 By-Laws of PG&E Corporation 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)
</TABLE>
- --------
* Management contract or compensatory plan or arrangement required to be
filed as an exhibit to this report pursuant to Item 14(c) of Form 10-K.
48
<PAGE>
<TABLE>
<C> <S>
*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.
</TABLE>
- --------
* Management contract or compensatory plan or arrangement required to be filed
as an exhibit to this report pursuant to Item 14(c) of Form 10-K.
49
<PAGE>
<TABLE>
<C> <S>
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.
</TABLE>
The exhibits filed herewith are attached hereto (except as noted) and those
indicated above which are not filed herewith were previously filed with the
Commission 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
<PAGE>
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
<PAGE>
SIGNATURES
PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(D) OF THE SECURITIES
EXCHANGE ACT OF 1934, THE REGISTRANTS HAVE DULY CAUSED THIS REPORT TO BE SIGNED
ON THEIR BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED, IN THE CITY AND
COUNTY OF SAN FRANCISCO, ON THE 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.
<TABLE>
<CAPTION>
SIGNATURE TITLE DATE
--------- ----- ----
<S> <C> <C>
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
</TABLE>
GARY P. ENCINAS
*By ________________________________
(Gary P. Encinas, Attorney-in-
Fact)
52
<PAGE>
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
<PAGE>
SCHEDULE II
PACIFIC GAS AND ELECTRIC COMPANY
SCHEDULE II -- CONSOLIDATED VALUATION AND
QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994
<TABLE>
<CAPTION>
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)
<S> <C> <C> <C> <C> <C>
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
======= ======= ====== ======= =======
</TABLE>
- --------
(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
<PAGE>
INDEX TO EXHIBITS
<TABLE>
EXHIBIT DESCRIPTION OF EXHIBITS
NUMBER -----------------------
-------
<C> <S>
3.1 Restated Articles of Incorporation of PG&E Corporation effective as of
December 19, 1996 (PG&E Corporation's Form 8-B (File No. 1-12609), Exhibit
3.1).
3.2 By-Laws of PG&E Corporation 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).
</TABLE>
- --------
* Management contract or compensatory plan or arrangement required to be filed
as an exhibit to this report pursuant to Item 14(c) of Form 10-K.
<PAGE>
<TABLE>
EXHIBIT DESCRIPTION OF EXHIBITS
NUMBER -----------------------
-------
<C> <S>
*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.
</TABLE>
- --------
* Management contract or compensatory plan or arrangement required to be filed
as an exhibit to this report pursuant to Item 14(c) of Form 10-K.
<PAGE>
EXHIBIT 3.5
BYLAWS
OF
PACIFIC GAS AND ELECTRIC COMPANY
AS AMENDED AS OF JANUARY 1, 1997
--------------------------------
ARTICLE I.
SHAREHOLDERS.
1. PLACE OF MEETING. All meetings of the shareholders shall be held at
the office of the Corporation in the City and County of San Francisco, State of
California, or at such other place within the State of California as may be
designated by the Board of Directors.
2. ANNUAL MEETINGS. The annual meeting of shareholders shall be held each
year on a date and at a time designated by the Board of Directors.
Written notice of the annual meeting shall be given not less than ten (or,
if sent by third-class mail, thirty) nor more than sixty days prior to the date
of the meeting to each shareholder entitled to vote thereat. The notice shall
state the place, day, and hour of such meeting, and those matters which the
Board, at the time of mailing, intends to present for action by the
shareholders.
Notice of any meeting of the shareholders shall be given by mail or
telegraphic or other written communication, postage prepaid, to each holder of
record of the stock entitled to vote thereat, at his address, as it appears on
the books of the Corporation.
3. SPECIAL MEETINGS. Special meetings of the shareholders shall be called
by the Secretary or an Assistant Secretary at any time on order of the Board of
Directors, the Chairman of the Board, the Vice Chairman of the Board, the
Chairman of the Executive Committee, or the President. Special meetings of the
shareholders shall also be called by the Secretary or an Assistant Secretary
upon the written request of holders of shares entitled to cast not less than ten
percent of the votes at the meeting. Such request shall state the purposes of
the meeting, and shall be delivered to the Chairman of the Board, the Vice
Chairman of the Board, the Chairman of the Executive Committee, the President or
the Secretary.
1
<PAGE>
A special meeting so requested shall be held on the date requested, but not
less than thirty-five nor more than sixty days after the date of the original
request. Written notice of each special meeting of shareholders, stating the
place, day, and hour of such meeting and the business proposed to be transacted
thereat, shall be given in the manner stipulated in Article I, Section 2,
Paragraph 3 of these Bylaws within twenty days after receipt of the written
request.
4. ATTENDANCE AT MEETINGS. At any meeting of the shareholders, each
holder of record of stock entitled to vote thereat may attend in person or may
designate an agent or a reasonable number of agents, not to exceed three to
attend the meeting and cast votes for his shares. The authority of agents must
be evidenced by a written proxy signed by the shareholder designating the agents
authorized to attend the meeting and be delivered to the Secretary of the
Corporation prior to the commencement of the meeting.
5. NO CUMULATIVE VOTING. No shareholder of the Corporation shall be
entitled to cumulate his or her voting power.
ARTICLE II.
DIRECTORS.
1. NUMBER. The Board of Directors shall consist of sixteen (16)
directors.
2. POWERS. The Board of Directors shall exercise all the powers of the
Corporation except those which are by law, or by the Articles of Incorporation
of this Corporation, or by the Bylaws conferred upon or reserved to the
shareholders.
3. EXECUTIVE COMMITTEE. There shall be an Executive Committee of the
Board of Directors consisting of the Chairman of the Committee, the Chairman of
the Board, if these offices be filled, the President, and four Directors who are
not officers of the Corporation. The members of the Committee shall be elected,
and may at any time be removed, by a two-thirds vote of the whole Board.
The Executive Committee, subject to the provisions of law, may exercise any
of the powers and perform any of the duties of the Board of Directors; but the
Board may by an affirmative vote of a majority of its members withdraw or limit
any of the powers of the Executive Committee.
The Executive Committee, by a vote of a majority of its members, shall fix
its own time and place of meeting, and shall prescribe its own rules of
procedure. A quorum of the Committee for the transaction of business shall
consist of three members.
4. TIME AND PLACE OF DIRECTORS' MEETINGS. Regular meetings of the Board
of Directors shall be held on such days and at such times and at such locations
as shall be fixed by resolution of the Board, or designated by the Chairman of
the Board or, in his absence, the Vice Chairman of the Board, or the President
of the Corporation and contained in the notice of any such meeting. Notice of
meetings shall be delivered personally or sent by mail or telegram at least
seven days in advance.
2
<PAGE>
5. SPECIAL MEETINGS. The Chairman of the Board, the Vice Chairman of the
Board, the Chairman of the Executive Committee, the President, or any five
directors may call a special meeting of the Board of Directors at any time.
Notice of the time and place of special meetings shall be given to each Director
by the Secretary. Such notice shall be delivered personally or by telephone to
each Director at least four hours in advance of such meeting, or sent by first-
class mail or telegram, postage prepaid, at least two days in advance of such
meeting.
6. QUORUM. A quorum for the transaction of business at any meeting of the
Board of Directors shall consist of six members.
7. ACTION BY CONSENT. Any action required or permitted to be taken by the
Board of Directors may be taken without a meeting if all Directors individually
or collectively consent in writing to such action. Such written consent or
consents shall be filed with the minutes of the proceedings of the Board of
Directors.
8. MEETINGS BY CONFERENCE TELEPHONE. Any meeting, regular or special, of
the Board of Directors or of any committee of the Board of Directors, may be
held by conference telephone or similar communication equipment, provided that
all Directors participating in the meeting can hear one another.
ARTICLE III.
OFFICERS.
1. OFFICERS. The officers of the Corporation shall be a Chairman of the
Board, a Vice Chairman of the Board, a Chairman of the Executive Committee
(whenever the Board of Directors in its discretion fills these offices), a
President, one or more Vice Presidents, a Secretary and one or more Assistant
Secretaries, a Treasurer and one or more Assistant Treasurers, a General
Counsel, a General Attorney (whenever the Board of Directors in its discretion
fills this office), and a Controller, all of whom shall be elected by the Board
of Directors. The Chairman of the Board, the Vice Chairman of the Board, the
Chairman of the Executive Committee, and the President shall be members of the
Board of Directors.
2. CHAIRMAN OF THE BOARD. The Chairman of the Board, if that office be
filled, shall preside at all meetings of the shareholders, of the Directors, and
of the Executive Committee in the absence of the Chairman of that Committee. He
shall be the chief executive officer of the Corporation if so designated by the
Board of Directors. He shall have such duties and responsibilities as may be
prescribed by the Board of Directors or the Bylaws. The Chairman of the Board
shall have authority to sign on behalf of the Corporation agreements and
instruments of every character, and in the absence or disability of the
President, shall exercise his duties and responsibilities.
3. VICE CHAIRMAN OF THE BOARD. The Vice Chairman of the Board, if that
office be filled, shall have such duties and responsibilities as may be
prescribed by the Board of Directors, the Chairman of the Board, or the Bylaws.
He shall be the chief executive officer of
3
<PAGE>
the Corporation if so designated by the Board of Directors. In the absence of
the Chairman of the Board, he shall preside at all meetings of the Board of
Directors and of the shareholders; and, in the absence of the Chairman of the
Executive Committee and the Chairman of the Board, he shall preside at all
meetings of the Executive Committee. The Vice Chairman of the Board shall have
authority to sign on behalf of the Corporation agreements and instruments of
every character.
4. CHAIRMAN OF THE EXECUTIVE COMMITTEE. The Chairman of the Executive
Committee, if that office be filled, shall preside at all meetings of the
Executive Committee. He shall aid and assist the other officers in the
performance of their duties and shall have such other duties as may be
prescribed by the Board of Directors or the Bylaws.
5. PRESIDENT. The President shall have such duties and responsibilities as
may be prescribed by the Board of Directors, the Chairman of the Board, or the
Bylaws. He shall be the chief executive officer of the Corporation if so
designated by the Board of Directors. If there be no Chairman of the Board, the
President shall also exercise the duties and responsibilities of that office.
The President shall have authority to sign on behalf of the Corporation
agreements and instruments of every character.
6. VICE PRESIDENTS. Each Vice President shall have such duties and
responsibilities as may be prescribed by the Board of Directors, the Chairman of
the Board, the Vice Chairman of the Board, the President, or the Bylaws. Each
Vice President's authority to sign agreements and instruments on behalf of the
Corporation shall be as prescribed by the Board of Directors. The Board of
Directors, the Chairman of the Board, the Vice Chairman of the Board, or the
President may confer a special title upon any Vice President.
7. SECRETARY. The Secretary shall attend all meetings of the Board of
Directors and the Executive Committee, and all meetings of the shareholders, and
he shall record the minutes of all proceedings in books to be kept for that
purpose. He shall be responsible for maintaining a proper share register and
stock transfer books for all classes of shares issued by the Corporation. He
shall give, or cause to be given, all notices required either by law or the
Bylaws. He shall keep the seal of the Corporation in safe custody, and shall
affix the seal of the Corporation to any instrument requiring it and shall
attest the same by his signature.
The Secretary shall have such other duties as may be prescribed by the Board
of Directors, the Chairman of the Board, the Vice Chairman of the Board, the
President, or the Bylaws.
The Assistant Secretaries shall perform such duties as may be assigned from
time to time by the Board of Directors, the Chairman of the Board, the Vice
Chairman of the Board, the President, or the Secretary. In the absence or
disability of the Secretary, his duties shall be performed by an Assistant
Secretary.
8. TREASURER. The Treasurer shall have custody of all moneys and funds of
the Corporation, and shall cause to be kept full and accurate records of
receipts and disbursements of the Corporation. He shall deposit all moneys and
other valuables of the Corporation in the name and to the credit of the
Corporation in such depositaries as may be designated by the Board of Directors
or any employee of the Corporation designated by the Board of Directors. He
shall disburse such funds of the Corporation as have been duly approved for
disbursement.
4
<PAGE>
The Treasurer shall perform such other duties as may from time to time be
prescribed by the Board of Directors, the Chairman of the Board, the Vice
Chairman of the Board, the President, or the Bylaws.
The Assistant Treasurer shall perform such duties as may be assigned from
time to time by the Board of Directors, the Chairman of the Board, the Vice
Chairman of the Board, the President, or the Treasurer. In the absence or
disability of the Treasurer, his duties shall be performed by an Assistant
Treasurer.
9. GENERAL COUNSEL. The General Counsel shall be responsible for handling
on behalf of the Corporation all proceedings and matters of a legal nature. He
shall render advice and legal counsel to the Board of Directors, officers, and
employees of the Corporation, as necessary to the proper conduct of the
business. He shall keep the management of the Corporation informed of all
significant developments of a legal nature affecting the interests of the
Corporation.
The General Counsel shall have such other duties as may from time to time be
prescribed by the Board of Directors, the Chairman of the Board, the Vice
Chairman of the Board, the President, or the Bylaws.
10. CONTROLLER. The Controller shall be responsible for maintaining the
accounting records of the Corporation and for preparing necessary financial
reports and statements, and he shall properly account for all moneys and
obligations due the Corporation and all properties, assets, and liabilities of
the Corporation. He shall render to the officers such periodic reports covering
the result of operations of the Corporation as may be required by them or any
one of them.
The Controller shall have such other duties as may from time to time be
prescribed by the Board of Directors, the Chairman of the Board, the Vice
Chairman of the Board, the President, or the Bylaws. He shall be the principal
accounting officer of the Corporation, unless another individual shall be so
designated by the Board of Directors.
ARTICLE IV.
MISCELLANEOUS.
1. RECORD DATE. The Board of Directors may fix a time in the future as a
record date for the determination of the shareholders entitled to notice of and
to vote at any meeting of shareholders, or entitled to receive any dividend or
distribution, or allotment of rights, or to exercise rights in respect to any
change, conversion, or exchange of shares. The record date so fixed shall be
not more than sixty nor less than ten days prior to the date of such meeting nor
more than sixty days prior to any other action for the purposes for which it is
so fixed. When a record date is so fixed, only shareholders of record on that
date are entitled to notice of and to vote at the meeting, or entitled to
receive any dividend or distribution, or allotment of rights, or to exercise the
rights, as the case may be.
5
<PAGE>
2. TRANSFERS OF STOCK. Upon surrender to the Secretary or Transfer Agent
of the Corporation of a certificate for shares duly endorsed or accompanied by
proper evidence of succession, assignment, or authority to transfer, and payment
of transfer taxes, the Corporation shall issue a new certificate to the person
entitled thereto, cancel the old certificate, and record the transaction upon
its books. Subject to the foregoing, the Board of Directors shall have power
and authority to make such rules and regulations as it shall deem necessary or
appropriate concerning the issue, transfer, and registration of certificates for
shares of stock of the Corporation, and to appoint and remove Transfer Agents
and Registrars of transfers.
3. LOST CERTIFICATES. Any person claiming a certificate of stock to be
lost, stolen, mislaid, or destroyed shall make an affidavit or affirmation of
that fact and verify the same in such manner as the Board of Directors may
require, and shall, if the Board of Directors so requires, give the Corporation,
its Transfer Agents, Registrars, and/or other agents a bond of indemnity in form
approved by counsel, and in amount and with such sureties as may be satisfactory
to the Secretary of the Corporation, before a new certificate may be issued of
the same tenor and for the same number of shares as the one alleged to have been
lost, stolen, mislaid, or destroyed.
ARTICLE V.
AMENDMENTS.
1. AMENDMENT BY SHAREHOLDERS. Except as otherwise provided by law, these
Bylaws, or any of them, may be amended or repealed or new Bylaws adopted by the
affirmative vote of a majority of the outstanding shares entitled to vote at any
regular or special meeting of the shareholders.
2. AMENDMENT BY DIRECTORS. To the extent provided by law, these Bylaws,
or any of them, may be amended or repealed or new Bylaws adopted by resolution
adopted by a majority of the members of the Board of Directors.
6
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff Second Revised Sheet No. 12
First Revised Volume No. 1-A Superseding
First Revised Sheet No. 12
________________________________________________________________________________
EXHIBIT 10.1
RATE SCHEDULE FTS-1
FIRM TRANSPORTATION SERVICE
1. AVAILABILITY
This rate schedule is available to any party (hereinafter called "Shipper")
qualifying for service pursuant to the Commission's Regulations contained in
18 CFR Part 284, and who has executed a Firm Transportation Service
Agreement with PGT in the form contained in this FERC Gas Tariff First
Revised Volume No. 1-A.
2. APPLICABILITY AND CHARACTER OF SERVICE
This rate schedule shall apply to firm gas transportation services performed
by PGT for Shipper pursuant to the executed Firm Transportation Service
Agreement between PGT and Shipper. PGT shall receive from Shipper such daily
quantities of gas up to the Shipper's Maximum Daily Quantity as specified in
the executed Firm Transportation Service Agreement between PGT and Shipper
plus the required quantity of gas for fuel and line loss associated with
service under this Rate Schedule FTS-1 and redeliver an amount equal to the
quantity received less the required quantity of gas for fuel and line loss.
This transportation service shall be firm and not subject to curtailment or
interruption except as provided in the Transportation General Terms and
Conditions.
Firm transportation service shall be subject to all provisions of the
executed Firm Transportation Service Agreement between PGT and Shipper and
the applicable Transportation General Terms and Conditions.
3. RATES
Shipper shall pay PGT each month the sum of the Reservation Charge, the
Delivery Charge, plus any applicable Extension Charge, Overrun Charge and
applicable surcharges for the quantities of natural gas delivered. The
rate(s) set forth in PGT's current Statement of Effective Rates and Charges
for Transportation of Natural Gas in this FERC Gas Tariff First Revised
Volume No. 1-A are applied to transportation service rendered under this
rate schedule.
(Continued)
________________________________________________________________________________
Issued by: R.T. Howard, Manager, Rates and Regulatory Affairs
Issued on: SEPTEMBER 30, 1996 Effective: NOVEMBER 01, 1996
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RP94-149, 76-61,246, dated SEPTEMBER 11, 1996
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff Second Revised Sheet No. 13
First Revised Volume No. 1-A Superseding
First Revised Sheet No. 13
________________________________________________________________________________
RATE SCHEDULE FTS-1
FIRM TRANSPORTATION SERVICE
(Continued)
3.RATES (Continued)
3.1 Reservation Charge
The Reservation Charge shall be the sum of the Mileage and the Non-
Mileage Component:
(a) Mileage Component
The Mileage Component shall be the product of the currently effective
Mileage Rate as set forth on Effective Tariff Sheet No. 4, the distance,
in pipeline miles, from the Primary Point(s) of receipt to the Primary
Point(s) of Delivery on Mainline Facilities as set forth in Shipper's
Contract, and the Shipper's Maximum Daily Quantity at such Point(s).
(b) Non-Mileage Component
The Non-Mileage Component shall be the product of the currently effective
Non-Mileage Rate as set forth on Effective Tariff Sheet No. 4 and the
Shipper's Maximum Daily Quantity at Primary Point(s) of Delivery on
Mainline Facilities.
(c) Mitigation Revenue Recovery Surcharge
If Shipper is a Subject Shipper, the Mitigation Revenue Recovery
Surcharge for the Mileage and Non-Mileage Components as set forth on
Effective Tariff Sheet No. 4 shall be included in, and become a part of,
the maximum Mileage and Non-Mileage Base Reservation Rates used for
computing the Mileage and Non-Mileage Components of the Reservation
Charge. The Mileage Component shall be designed to recover, on the basis
of the mileage billing determinants of the Subject Shippers underlying
PGT's currently effective rates, mileage mitigation revenues not
recovered from other shippers in accordance with Article IV, Section 1(b)
of the Stipulation and Agreement in Docket No. RP94-149-000, et al., and
the Non-Mileage Component shall be designed to recover, on the basis of
the Non-Mileage billing determinants of the Subject Shippers underlying
PGT's currently effective rates, Non-Mileage mitigation revenues not
recovered from other shippers in accordance with Article IV, Section 1(b)
of the Stipulation and Agreement in Docket No. RP94-149-000, et al.
(Continued)
________________________________________________________________________________
Issued by: R.T. Howard, Manager, Rates and Regulatory Affairs
Issued on: SEPTEMBER 30, 1996 Effective: NOVEMBER 01, 1996
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RP94-149, 76-61,246, dated SEPTEMBER 11, 1996
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff Original Sheet No. 13A
First Revised Volume No. 1-A
________________________________________________________________________________
RATE SCHEDULE FTS-1
FIRM TRANSPORTATION SERVICE
(Continued)
3.RATES (Continued)
3.1 Reservation Charge (Continued)
(d) Shipper's obligation to pay the Reservation Charge and applicable
Reservation Surcharge is independent of Shipper's ability to obtain
export authorization from the National Energy Board of Canada,
Canadian provincial removal authority, and/or import authorization
from the United States Department of Energy, and shall begin with
the execution of the Firm Transportation Service Agreement by both
parties. The Reservation Charge and Reservation Surcharge due and
payable shall be computed beginning in the month in which service
is first available (prorated if beginning in the month in which
service is available on a date other than the first day of the
month). Thereafter, the monthly Reservation Charge and Reservation
Surcharge shall be due and payable each month during the Initial
(and Subsequent) Term(s) of the Shipper's executed Firm
Transportation Service Agreement and is unaffected by the quantity
of gas transported by PGT to Shipper's delivery point(s) in any
month except as provided for in Paragraphs 3.10 and 3.11 of this
rate schedule.
3.2 Delivery Charge
The Delivery Charge shall be the product of the Delivery Rate as set forth
on Effective Tariff Sheet No. 4, the quantities of gas delivered in the
month (in MMBtu) (excluding Authorized Overrun) at point(s) of delivery on
Mainline Facilities, and the distance, in pipeline miles, from the
point(s) of receipt to point(s) of delivery on Mainline Facilities.
(Continued)
________________________________________________________________________________
Issued by: R.T. Howard, Manager, Rates and Regulatory Affairs
Issued on: SEPTEMBER 30, 1996 Effective: NOVEMBER 01, 1996
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RP94-149, 76-61,246, dated SEPTEMBER 11, 1996
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff Second Revised Sheet No. 14
First Revised Volume No. 1-A Superseding
First Revised Sheet No. 14
________________________________________________________________________________
RATE SCHEDULE FTS-1
FIRM TRANSPORTATION SERVICE
(Continued)
3. RATES (Continued)
3.3 Extension Charge
If Shipper designates a Primary Point of delivery on an Extension
Facility, then in addition to all other charges that are applicable,
Shipper shall pay the Extension Charge, which shall consist of a
reservation and delivery component.
(a) The reservation component of the Extension Charge shall be the
product of Shipper's Maximum Daily Quantity at the Primary
Point(s) of delivery on the Extension Facility, the applicable
Extension reservation rate as set forth on Effective Tariff Sheet
No. 4, and the distance, in pipeline miles, from the Receipt
Point(s) on the Extension Facility to the Primary Point(s) of
delivery.
(b) The delivery component of the Extension Surcharge shall be the
product of the quantities delivered at the point(s) of delivery
on the Extension Facility, the applicable Extension delivery rate
as set forth on Effective Tariff Sheet No. 4, and the distance,
in pipeline miles, from the Receipt Point(s) on the Extension
Facility to the point(s) of delivery.
3.4 Authorized Overrun Charge
Quantities in excess of Shipper's MDQ shall be transported when
capacity is available on the PGT system and when the provision of such
Authorized Overruns shall not effect any Shipper's rights on the PGT
System. Authorized Overruns are interruptible in nature. The rate
charged shall be the same as the rates and charges for interruptible
transportation under Rate Schedule ITS-1 as set forth on effective
tariff Sheet No. 4, and such Authorized Overruns shall be subject to
the priority of service provisions of Paragraph 19 of the
Transportation General Terms and Conditions.
3.5 Applicability of Surcharges
Shipper shall pay all reservation and usage surcharges applicable to
the service provided to such Shipper as set forth in PGT's FERC Gas
Tariff, First Revised Volume No. 1-A. Such surcharges shall be deemed
to be part of Shipper's Reservation and Delivery Charges.
(Continued)
________________________________________________________________________________
Issued by: R.T. Howard, Manager, Rates and Regulatory Affairs
Issued on: SEPTEMBER 30, 1996 Effective: NOVEMBER 01, 1996
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RP94-149, 76-61,246, dated SEPTEMBER 11, 1996
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff Original Sheet No. 14A
First Revised Volume No. 1-A
________________________________________________________________________________
RATE SCHEDULE FTS-1
FIRM TRANSPORTATION SERVICE
(Continued)
3. RATES (Continued)
3.6 Shipper shall pay the Reservation Charge, and the Maximum Delivery
Charge for service under this Rate Schedule unless PGT offers to
discount the Mileage Rate components or the Non-Mileage Rate components
of the Reservation Rate or the Delivery Rate or the GRI surcharge under
this rate schedule. If PGT elects to discount any such rate, PGT shall,
up to forty-eight (48) hours prior to such discount, by written notice,
advise Shipper of the effective date of such charges and the quantity
of gas so affected; provided, however, such discount shall not be
anticompetitive or unduly discriminatory between individual shippers.
The rates for service under this rate schedule shall not be discounted
below the Minimum Reservation Charge, the Minimum Delivery Rate, and
applicable GSR and ACA Surcharges.
(Continued)
________________________________________________________________________________
Issued by: R.T. Howard, Manager, Rates and Regulatory Affairs
Issued on: SEPTEMBER 30, 1996 Effective: NOVEMBER 01, 1996
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RP94-149, 76-61,246, dated SEPTEMBER 11, 1996
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff First Revised Sheet No. 15
First Revised Volume No. 1-A Superseding
Original Sheet No. 15
________________________________________________________________________________
RATE SCHEDULE FTS-1
FIRM TRANSPORTATION SERVICE
(Continued)
3. RATES (Continued)
3.7 Gas Supply Restructuring (GSR) Transition Cost Surcharge
Shipper shall pay a GSR Transition Cost Surcharge for PGT's approved
GSR costs as defined in Paragraph 30 of the Transportation General
Terms and Conditions. This surcharge is stated on the Statement of
Effective Rates and Charges and is defined in Paragraph 30 of the
Transportation General Terms and Conditions. The surcharge shall be the
product of the surcharge rate, the quantities of gas delivered during
the month and the distance in pipeline miles from the point(s) of
receipt to the point(s) of delivery.
3.8 Backhauls or upstream deliveries shall be subject to the same charges
as forward haul or downstream transportation arrangements except that
no gas shall be retained by PGT for compressor station fuel, line loss
and other unaccounted-for gas.
3.9 Direct Bills
PG&E shall pay a Direct Bill for 100% of the costs allocated to the
Direct Bill portion of Approved Gas Supply Restructuring (GSR) Costs
excluding the amount to be collected from the Northwest Shippers as
defined in Paragraph 30 of the Transportation General Terms and
Conditions and credited against the Direct Bill portion of Approved GSR
Costs as defined in Paragraph 30 of the Transportation General Terms
and Conditions. In accordance with Paragraph 30.5(b) of the
Transportation General Terms and Conditions, PG&E may elect to pay its
Direct Bill in a lump sum or select one of three payment plans as shown
on the Statement of Rates and Charges for Transportation of Natural
Gas.
(Continued)
________________________________________________________________________________
Issued by: R.T. Howard, Manager, Rates and Regulatory Affairs
Issued on: SEPTEMBER 30, 1996 Effective: NOVEMBER 01, 1996
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RP94-149, 76-61,246, dated SEPTEMBER 11, 1996
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff First Revised Sheet No. 16
First Revised Volume No. 1-A Superseding
Original Sheet No. 16
________________________________________________________________________________
RATE SCHEDULE FTS-1
FIRM TRANSPORTATION SERVICE
(Continued)
3. RATES (Continued)
3.10 Capacity Release
(a) Releasing Shippers:
Shipper shall have the option to release capacity pursuant to
the provisions of PGT's capacity release program as specified in
the Transportation General Terms and Conditions. Shipper may
release its capacity, up to Shipper's Maximum Daily Quantity
under this rate schedule, in accordance with the provisions of
Paragraph 28 of PGT's Transportation General Terms and
Conditions of this FERC Gas Tariff, First Revised Volume No. 1-
A. Shipper shall pay a fee associated with the marketing of
capacity by PGT (if applicable) in accordance with Paragraph 28
of the Transportation General Terms and Conditions. This fee
shall be negotiated between PGT and the Releasing Shipper.
(b) Replacement Shippers:
Shipper may receive released capacity service under this rate
schedule pursuant to Paragraph 28 of the Transportation General
Terms and Conditions and is required to execute a service
agreement in the form contained for capacity release under Rate
Schedule FTS-1 in this First Revised Volume No. 1-A.
Shipper shall pay PGT each month for transportation service
under this rate schedule and as set forth in PGT's current
Statement of Effective Rates and Charges in this First Revised
Volume No. 1-A. Charges to be paid shall be the sum of the
Reservation Charge, Delivery Charge, and other applicable
surcharges or penalties.
The rates paid by Shipper receiving capacity release
transportation service shall be adjusted as provided on Exhibit
R in the executed Transportation Service Agreement For Capacity
Release between PGT and Shipper.
(Continued)
________________________________________________________________________________
Issued by: R.T. Howard, Manager, Rates and Regulatory Affairs
Issued on: SEPTEMBER 30, 1996 Effective: NOVEMBER 01, 1996
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RP94-149, 76-61,246, dated SEPTEMBER 11, 1996
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff Second Revised Sheet No. 16A
First Revised Volume No. 1-A Superseding
First Revised Sheet No. 16A
________________________________________________________________________________
RATE SCHEDULE FTS-1
FIRM TRANSPORTATION SERVICE
(Continued)
3.11 Reservation Charge Credit - Malin Primary Delivery Point
If PGT fails to deliver to Malin, Oregon ninety-five percent (95%) or
more of the aggregate Confirmed Daily Nominations (as hereinafter
defined) of all Shippers with a Malin primary delivery point receiving
service under this rate schedule (hereinafter referred to as the "Non-
Deficiency Amount") for more than twenty-five (25) days in any given
Contract Year, then for each day during that Contract Year in excess of
twenty-five (25) days that PGT so fails to deliver the Non-Deficiency
Amount (a "Credit Day") Shipper, as its sole remedy, shall be entitled
to a Reservation Charge Credit calculated in the manner hereinafter set
forth.
For the purpose of this Paragraph 3.10, Confirmed Daily Nomination shall
mean for any day, the lesser of (1) Shipper's Maximum Daily Quantity or
(2) the actual quantity of gas that the connecting pipeline upstream of
PGT is capable of delivering for Shipper's account to PGT at Shipper's
primary point of receipt(s) on PGT less Shipper's requirement to provide
compressor fuel and line losses under the Statement of Effective Rates
and Charges of PGT's FERC Gas Tariff, First Revised Volume No. 1-A or
(3) the quantity of gas that Pacific Gas And Electric Company (PG&E) is
capable of accepting at Malin for Shipper's account or (4) Shipper's
nomination to PGT.
The Reservation Charge Credit for each Credit Day for a particular
Shipper shall be computed as follows:
Reservation Charge A B - C
Credit for Each ____ x _____
Credit Day = 30.4 B
where A = Shipper's Monthly Reservation Charge
B = Shipper's confirmed daily nomination for the Credit Day
C = Actual quantity of gas delivered by PGT to PG&E at Malin for
Shipper's account for the Credit Day
Except as provided for in Paragraph 3.11 of this rate schedule, this
Reservation Charge Credit is Shipper's sole remedy for nondelivery of
gas by PGT.
(Continued)
________________________________________________________________________________
Issued by: R.T. Howard, Manager, Rates and Regulatory Affairs
Issued on: SEPTEMBER 30, 1996 Effective: NOVEMBER 01, 1996
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RP94-149, 76-61,246, dated SEPTEMBER 11, 1996
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff Second Revised Sheet No. 16B
First Revised Volume No. 1-A Superseding
First Revised Sheet No. 16B
________________________________________________________________________________
RATE SCHEDULE FTS-1
FIRM TRANSPORTATION SERVICE (Continued)
3.12 Reservation Charge Credit - Other than Malin Primary Delivery Point
If PGT fails to deliver to a primary delivery point on its system other
than Malin, Oregon, ninety-five percent (95%) or more of the aggregate
Confirmed Daily Nominations (as hereinafter defined) of all Shippers at
such primary delivery point other than Malin receiving service under
this rate schedule (hereinafter referred to as the "Non-Deficiency
Amount") for more than twenty-five (25) days in any given Contract Year,
then for each day during that Contract Year in excess of twenty-five
(25) days that PGT so fails to deliver the Non-Deficiency Amount (a
"Credit Day") Shipper, as its sole remedy, shall be entitled to a
Reservation Charge Credit calculated in the manner hereinafter set
forth.
For the purpose of this Paragraph 3.11, Confirmed Daily Nomination shall
mean for any day, the lesser of (1) Shipper's Maximum Daily Quantity or
(2) the quantity of gas that the connecting downstream pipeline(s),
local distribution company pipeline(s), or end-user(s) is/are capable of
accepting for Shipper's account at Shipper's point(s) of primary
delivery on PGT or (3) the quantity of gas that the connecting pipeline
upstream of PGT is capable of delivering to PGT for Shipper's account to
PGT at Shipper's primary point of receipt(s) on PGT less Shipper's
requirement to provide compressor fuel and line losses under the
Statement of Effective Rates and Charges of PGT's FERC Gas Tariff, First
Revised Volume No. 1-A or (4) Shipper's nomination to PGT.
The Reservation Charge Credit for each Credit Day for a particular
Shipper shall be computed as follows:
Reservation Charge A B - C
Credit for Each ____ x _____
Credit Day = 30.4 B
where A = Shipper's Monthly Reservation Charge
B = Shipper's confirmed daily nomination for the Credit Day
C = Actual quantity of gas delivered by PGT to a Shipper's
primary delivery point(s) (other than Malin) for Shipper's
account for the Credit Day
Except as provided for in Paragraph 3.10 of this rate schedule, this
Reservation Charge Credit is Shipper's sole remedy for nondelivery of
gas by PGT.
(Continued)
________________________________________________________________________________
Issued by: R.T. Howard, Manager, Rates and Regulatory Affairs
Issued on: SEPTEMBER 30, 1996 Effective: NOVEMBER 01, 1996
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RP94-149, 76-61,246, dated SEPTEMBER 11, 1996
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff Third Revised Sheet No. 17
First Revised Volume No. 1-A Superseding
Second Revised Sheet No. 17
________________________________________________________________________________
RATE SCHEDULE FTS-1
FIRM TRANSPORTATION SERVICE
(Continued)
4. FUEL AND LINE LOSS
Shipper shall furnish to PGT quantities of gas for compressor station fuel,
line loss and other utility purposes, plus other unaccounted for gas used in
the operation of PGT's combined pipeline system between the International
Boundary near Kingsgate, British Columbia and the Oregon-California boundary
for the transportation quantities of gas delivered by PGT to Shipper, based
upon the effective fuel and line loss percentages in accordance with
Paragraph 37 of the General Terms and Conditions.
5. TRANSPORTATION GENERAL TERMS AND CONDITIONS
All of the Transportation General Terms and Conditions are applicable to this
rate schedule, unless otherwise stated in the executed Firm Transportation
Service Agreement between PGT and Shipper. Any future modifications,
additions or deletions to said Transportation General Terms and Conditions,
unless otherwise provided, are applicable to firm transportation service
rendered under this rate schedule, and by this reference, are made a part
hereof.
________________________________________________________________________________
Issued by: R.T. Howard, Manager, Rates and Regulatory Affairs
Issued on: SEPTEMBER 30, 1996 Effective: NOVEMBER 01, 1996
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RP94-149, 76-61,246, dated SEPTEMBER 11, 1996
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff Eighth Revised Sheet No. 51
First Revised Volume No. 1-A Superseding
Seventh Revised Sheet No. 51
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
TABLE OF CONTENTS
<TABLE>
<CAPTION>
Paragraph No. Provision Sheet No.
<S> <C> <C>
1 Definitions 52
2 Gas Research Institute Charge Adjustment Provision 55
3 Quality of Gas 56
4 Measuring Equipment 58
5 Measurements 60
6 Inspection of Equipment and Records 61
7 Billing 61
8 Payment 62
9 Reserved 63
10 Force Majeure 63
11 Warranty of Eligibility for Transportation 64
12 Possession of Gas and Responsibility 64
13 Indemnification 65
14 Arbitration 65
15 Governmental Regulations 66
16 Miscellaneous Provision 66
17 Transportation Service Agreement 66
18 Operating Provisions 67
19 Priority of Service, Scheduling and Nominations 81
20 Curtailment 81C
21 Balancing 82
22 Annual Charge Adjustment (ACA) Provision 85
23 Shared Operating Personnel and Facilities 85
24 Complaint Procedures 86
25 Information Concerning Availability and Pricing
of Transportation Service and Capacity Available for
Transportation 87
26 Market Centers 88
27 Planned PGT Capacity Curtailments and Interruptions 88A
28 Capacity Release 89
29 Flexible Receipt and Delivery Points 119
30 Gas Supply Restructuring Transition Costs 123
31 Reserved 127
32 Equality of Transportation Service 129
33 Right of First Refusal Upon Termination of
Firm Shipper's Service Agreement 130
34 Electronic Bulletin Board 132
35 Reserved 137
35A Crediting of Interruptible Transportation Revenues for
Extensions 138A
36 Discount Policy 139
37 Adjustment Mechanism for Fuel, Line Loss and Other
Unaccounted For Gas Percentages 140
38 Reserved 142
39 Sales of Excess Gas 143
(Continued)
</TABLE>
________________________________________________________________________________
Issued by: R.T. Howard, Manager, Rates and Regulatory Affairs
Issued on: SEPTEMBER 30, 1996 Effective: SEPTEMBER 13, 1996
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RP94-149, 76-61,246, dated SEPTEMBER 11, 1996
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff Second Revised Sheet No. 52
First Revised Volume No. 1-A Superseding
First Revised Sheet No. 52
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
1. DEFINITIONS
1.1 The word "day" shall mean a period of twenty-four (24) consecutive
hours, beginning and ending at 7:00 o'clock a.m. Pacific Standard Time
or such other time as Shipper and PGT may agree upon.
1.2 The word "month" shall mean a period extending from the beginning of
the first day in a calendar month to the beginning of the first day in
the next succeeding calendar month.
1.3 The term "Maximum Daily Quantity" (MDQ) shall mean the maximum daily
quantity in MMBtu of gas which PGT agrees to deliver exclusive of an
allowance for compressor station fuel, line loss and other unaccounted
for gas and transport for the account of Shipper to Shipper's point(s)
of delivery on each day during each year during the term of Shipper's
Transportation Service Agreement with PGT.
1.4 The term "marketing affiliate" shall mean Pacific Gas and Electric
Company and Hermiston Generating Company, L.P.
1.5 The word "gas" shall mean natural gas.
1.6 The term "cubic foot of gas" shall mean that quantity of gas which, at
a temperature of sixty degrees (60/./) Fahrenheit and at a pressure of
14.73 pounds per square inch absolute, occupies one (1) cubic foot.
1.7 The term "Mcf" shall mean one thousand (1,000) cubic feet of gas and
shall be measured as set forth in Paragraph 5 hereof. The term "MMcf"
shall mean one million (1,000,000) cubic feet of gas.
1.8 The term "Btu" shall mean British Thermal Unit. The term "MMBtu" shall
mean one million (1,000,000) British Thermal Units.
1.9 The term "gross heating value" shall mean the number of Btu's in a
cubic foot of gas at a temperature of sixty degrees (60/./)
Fahrenheit, saturated with water vapor, and at an absolute pressure
equivalent to thirty (30) inches of mercury at thirty-two degrees
(32/./) Fahrenheit.
1.10 The term "psig" shall mean pounds per square inch gauge.
(Continued)
________________________________________________________________________________
Issued by: R.T. Howard, Manager, Rates and Regulatory Affairs
Issued on: MARCH 01, 1996 Effective: APRIL 01,1996
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff First Revised Sheet No. 53
First Revised Volume No. 1-A Superseding
Original Sheet No. 53
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
1. DEFINITIONS (Continued)
1.11 Releasing Shipper: A firm transportation Shipper which intends to
post its service to be released to a Replacement Shipper, has posted
the service for release, or has released its service.
1.12 Replacement Shipper: A Shipper which has contracted to utilize a
Releasing Shipper's service for a specified period of time.
1.13 Posting Period: The period of time during which a Releasing Shipper
may post, or have posted by the pipeline, all or a part of its
service for release to a Replacement Shipper.
1.14 Release Term: The period of time during which a Releasing Shipper
intends to release, or has released all or a portion of its
contracted quantity of service to a Replacement Shipper.
1.15 Bid Period: The period of time during which a Replacement Shipper may
bid to contract for a parcel which has been posted for release by a
Releasing Shipper.
1.16 Parcel: The term utilized to describe an amount of capacity,
expressed in MMBtu/d, from a specific receipt point to a specific
delivery point for a specific period of time which is released and
bid on pursuant to the capacity release provisions contained in
Paragraph 28 of these Transportation General Terms and Conditions.
1.17 Primary Release: The term used to describe the release of capacity by
a Releasing Shipper receiving service under a Part 284 firm
transportation rate schedule.
1.18 Secondary Release: The term used to describe the release of capacity
by a Replacement Shipper receiving service under a Part 284 firm
transportation rate schedule.
(Continued)
________________________________________________________________________________
Issued by: R.T. Howard, Manager, Rates and Regulatory Affairs
Issued on: AUGUST 13, 1996 Effective: SEPTEMBER 13, 1996
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff Third Revised Sheet No. 54
First Revised Volume No. 1-A Superseding
Second Revised Sheet No. 54
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
1. DEFINITIONS (Continued)
1.19 Bid Reconciliation Period: The period of time subsequent to the Bid
Period during which bids are evaluated by PGT.
1.20 Match Period: The period of time subsequent to the Bid Reconciliation
Period and before the notification deadline for awarding capacity for
Prearranged Deal C during which the Prearranged Shipper may match any
higher bids for the Parcel.
1.21 The term Mainline Facilities shall mean the 36-inch and 42-inch mains
and appurtenant facilities extending from the interconnection with
the pipeline facilities of Alberta Natural Gas Company and Foothills
Pipe Lines (South B.C.) Ltd., near Kingsgate, British Columbia to the
interconnection with the pipeline facilities of Pacific Gas and
Electric Company near Malin, Oregon.
1.22 The term Extension Facilities shall mean the 12-inch mains and
appurtenant facilities extending from PGT's mainline facilities at
Milepost 304.25 and the 16-inch and 12-inch mains and appurtenant
facilities extending from PGT's Mainline Facilities at Milepost
599.20 that were authorized in Docket No. CP93-618-000. The term
"Extension Facility" shall mean one of the Extension Facilities.
1.23 The term "Subject Shipper" shall mean the Shippers identified in
Appendix G of the Stipulation and Agreement in Docket No. RP94-149-
000, et al., and Shippers that have obtained service rights from such
Shippers.
(Continued)
________________________________________________________________________________
Issued by: R.T. Howard, Manager, Rates and Regulatory Affairs
Issued on: SEPTEMBER 30, 1996 Effective: NOVEMBER 01, 1996
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RP94-149, 76-61,246, dated SEPTEMBER 11, 1996
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff Second Revised Sheet No. 55
First Revised Volume No. 1-A Superseding
First Revised Sheet No. 55
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
2. GAS RESEARCH INSTITUTE CHARGE ADJUSTMENT PROVISION
2.1 Purpose: PGT has joined with other gas enterprises in the formation
of, and participation in, the activities and financing of the Gas
Research Institute (GRI), an Illinois Not For Profit corporation. GRI
has been organized for the purpose of sponsoring Research,
Development and Demonstration (RD&D) programs in the field of natural
and manufactured gas for the purpose of assisting all segments of the
gas industry in providing adequate, reliable, safe, economic and
environmentally acceptable gas service for the benefit of gas
consumers and the general public.
For the purpose of funding GRI's approved expenditures, this
Paragraph 2 establishes a GRI Adjustment Charge to be applicable to
PGT's Rate Schedules ITS-1, AIS-1, PS-1 and FTS-1 in this FERC Gas
Tariff First Revised Volume No. 1-A; provided, however, such charge
shall not be applicable in the event gas is delivered to a downstream
interstate pipeline that is a member of GRI.
2.2 Basis for the GRI Adjustment Charges: The rate schedule specified in
Paragraph 2.1 hereof shall include an increment for a GRI Adjustment
Charge for RD&D. Such GRI Adjustment Charge shall be that increment,
adjusted to PGT's pressure base and heating value if required, which
has been approved by Federal Energy Regulatory Commission Orders
approving GRI's RD&D expenditures. The GRI Adjustment Charge shall be
reflected in the current Statement of Effective Rates and Charges for
Transportation of Natural Gas in this FERC Gas Tariff First Revised
Volume No. 1-A.
2.3 Filing Procedure: The notice period and proposed effective date of
filings pursuant to this paragraph shall be as permitted under
Section 4 of the Natural Gas Act; provided, however, that any such
filing shall not become effective unless it becomes effective without
suspension or refund obligation.
2.4 Remittance to GRI: PGT shall remit to GRI, not later than fifteen
(15) days after the receipt thereof, all monies received by virtue of
the GRI Adjustment Charge, less any amounts properly payable to a
Federal, State or Local authority relating to the monies received
hereunder.
(Continued)
________________________________________________________________________________
Issued by: R.T. Howard, Manager, Rates and Regulatory Affairs
Issued on: AUGUST 13, 1996 Effective: SEPTEMBER 13, 1996
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff Original Sheet No. 55A
First Revised Volume No. 1-A
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
2. GAS RESEARCH INSTITUTE CHARGE ADJUSTMENT PROVISION (Continued)
2.5 A high load factor Shipper is a Shipper with a load factor greater
than fifty (50) percent. A low load factor Shipper is a Shipper with
a load factor equal to or less than fifty (50) percent. A Shipper's
load factor for each service agreement shall be determined annually
using the most recent twelve (12) months of actual throughput
available (including throughput using capacity released pursuant to
Paragraph 28 of the Transportation General Terms and Conditions). The
Shipper's load factor shall remain in effect during the calendar
year. In the event twelve (12) months of actual data does not exist,
the Shipper's load factor shall be determined monthly based on the
latest recorded throughput data. The appropriate GRI demand surcharge
is applied monthly until such time as twelve (12) months of actual
data is accumulated. At such time the Shipper's load factor shall
remain in effect during the calendar year.
2.6 For the purpose of funding GRI's approved expenditures, and subject
to the further terms and conditions set forth in the Stipulation and
Agreement Concerning the Post-1993 GRI Funding Mechanism and the
orders approving such Stipulation and Agreement found at Gas Research
Institute, 62 FERC (P)61,316 (1993) this Paragraph 2 establishes a
GRI Funding Unit which shall be collected for quantities of gas
transported under PGT's rate schedules provided, however, such charge
shall not be applicable to discounted transactions except where the
discounted rate is less than the GRI Funding Unit. In this instance
PGT shall remit that portion of the GRI Funding Unit actually
collected. For purposes of discounted transactions, any GRI Funding
Unit shall be considered to be the first component of rates
discounted. The GRI Funding Unit may be discounted to zero and shall
not be applied to the same quantity of gas more than once.
(Continued)
________________________________________________________________________________
Issued by: P.G. Rosput, Senior Vice President
Issued on: JANUARY 10, 1994 Effective: JANUARY 01, 1994
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. TM94-2-86-000, dated DECEMBER 30, 1993
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff First Revised Sheet No. 56
First Revised Volume No. 1-A Superseding
Original Sheet No. 56
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
3. QUALITY OF GAS
3.1 Quality Standards: The gas which Shipper delivers hereunder to PGT
for transport (and the gas which PGT transports hereunder for
Shipper) shall be merchantable gas at all times complying with the
following quality requirements:
(a) Heating Value: The gas shall have a gross heating value of not
less than nine hundred ninety-five (995) Btus per standard cubic
foot on a dry basis, but with the consent of Shipper, PGT may
deliver gas at a lower gross heating value.
(b) Freedom from Objectionable Matter: The gas:
(1) Shall be commercially free from sand, dust, gums, crude
oil, impurities and other objectionable substances which
may be injurious to pipelines or which may interfere with
its transmission through pipelines or its commercial
utilization.
(2) Shall not have a hydrocarbon dew-point in excess of fifteen
degrees (15/./) Fahrenheit at pressures up to eight hundred
(800) psig.
(3) Shall not contain more than one-quarter (1/4) grain of
hydrogen sulfide per one hundred (100) standard
cubic feet.
(4) Shall not contain more than ten(10) grains of total sulphur
per one hundred (100) standard cubic feet.
(5) Shall not contain more than two percent (2%) by volume of
carbon dioxide.
(6) Shall not contain more than four (4) pounds of water vapor
per one million (1,000,000) standard cubic feet.
(7) Shall not exceed one hundred ten degrees (110/./)
Fahrenheit in temperature at the point of measurement.
(8) Shall be as free of oxygen as it can be kept through the
exercise of all reasonable precautions, and shall not in
any event contain more than four-tenths of one percent
(0.4%) by volume of oxygen.
(Continued)
________________________________________________________________________________
Issued by: P.G. Rosput, Senior Vice President
Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff Second Revised Sheet No. 57
First Revised Volume No. 1-A Superseding
First Revised Sheet No. 57
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
3. QUALITY OF GAS (Continued)
3.2 Quality Tests:
(a) The quality specifications of the gas received by PGT hereunder
shall be determined by tests which PGT shall cause to be made at
the International Boundary or such other locations on PGT's system
if required accordance with this Paragraph 3.2.
(b) The gross heating value of gas delivered hereunder shall be
determined from read-outs of continuously operating measuring
instruments. The method shall consist of one or more of the
following:
(1) calorimeter
(2) gas chromatograph
(3) any other method mutually agreed upon by the parties.
Measurement of gross heating value with the calorimeters shall
comply with the standards set forth in the American Society for
Testing and Materials' ASTM D 1826. Analysis of gas with gas
chromatograph shall comply with the standards set forth in ASTM D
1945. Calculation of the gross heating value from compositional
analysis by gas chromatography shall comply with the standards set
forth in ASTM D 3588.
PGT or its agent shall calibrate and maintain the gross heating
value measurement device at intervals as agreed upon by PGT and
Shipper. Shipper shall have access to PGT's devices and shall be
allowed to inspect the devices and all charts or other records of
measurement at any reasonable time.
(Continued)
________________________________________________________________________________
Issued by: R.T. Howard, Manager, Rates and Regulatory Affairs
Issued on: AUGUST 13, 1996 Effective: SEPTEMBER 13, 1996
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff Original Sheet No. 58
First Revised Volume No. 1-A
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
3. QUALITY OF GAS (Continued)
3.2 Quality Tests (Continued)
(c) Tests shall be made to determine the total sulphur, hydrogen
sulfide, carbon dioxide and oxygen content of the gas, by approved
standard methods in general use in the gas industry, and to
determine the hydrocarbon dew-point and water vapor content of such
gas by methods satisfactory to the parties. Tests shall be made
frequently enough to ensure that the gas is conforming continuously
to the quality requirements. Shipper shall have the right to
require PGT to have remedied any deficiency in quality of the gas
and, in the event such deficiency is not remedied, the right, in
addition to all other remedies available to it by law, to refuse to
accept such deficient gas until such deficiency is remedied.
4. MEASURING EQUIPMENT
4.1 Installation: Unless PGT and Shippers agree otherwise, all gas volume
measuring equipment, devices and materials at the point(s) of receipt
and/or delivery shall be furnished and installed by PGT at Shipper's
expense including the tax-on-tax effect. All such equipment, devices
and materials shall be owned, maintained and operated by PGT. Shipper
may install and operate check measuring equipment provided it does not
interfere with the use of PGT's equipment.
4.2 Testing Meter Equipment: The accuracy of either PGT's or Shippers
measuring equipment shall be verified by test, using means and methods
acceptable to the other party, at intervals mutually agreed upon, and at
other times upon request. Notice of the time and nature of each test
shall be given by the entity conducting the test to the other entity
sufficiently in advance to permit convenient arrangement for the
presence of the representative of the other entity. If, after notice,
the other entity fails to have a representative present, the results of
the test shall nevertheless be considered accurate until the next test.
If any of the measuring equipment is found to be registering
inaccurately in any percentage, it shall be adjusted at once to read
as accurately as possible. All tests of such measuring equipment
shall be made at the expense of the entity conducting the same, except
that the other entity shall bear the expense of tests made at its
request if the inaccuracy is found to be two percent (2%) or less.
(Continued)
________________________________________________________________________________
Issued by: P.G. Rosput, Senior Vice President
Issued on: AUGUST 02, 1993 Effective: NOVEMBER 01, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-46-000, et al, dated JULY 12, 1993
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff Original Sheet No. 59
First Revised Volume No. 1-A
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
4. MEASURING EQUIPMENT (Continued)
4.3 Correction and Adjustment: If at any time any of the measuring
equipment is registering inaccurately by an amount exceeding two percent
(2%) at a reading corresponding to the average hourly rate of flow, the
previous readings of such equipment shall be corrected to zero error for
any period definitely known or agreed upon, or if not so known or agreed
upon, one-half (1/2) of the elapsed time since the last test. If the
measuring equipment is out-of-service, the volume of gas delivered
during such period shall be determined:
(a) By using the data recorded by any check measuring equipment
accurately registering; or
(b) If such check measuring equipment is not registering accurately but
the percentage of error is ascertainable by a calibration test, by
using the data recorded, corrected to zero error; or
(c) If neither of the methods provided in (a) and (b) above can be used,
by estimating the quantity delivered, by reference to deliveries
under similar conditions during a period when the equipment was
registering accurately.
No correction shall be made in the recorded volumes of gas delivered
hereunder for measuring equipment inaccuracies of two percent (2%)
or less, and in no event shall inaccuracies less than 25 Mcf be
considered for adjustment.
(Continued)
________________________________________________________________________________
Issued by: P.G. Rosput, Senior Vice President
Issued on: AUGUST 02, 1993 Effective: NOVEMBER 01, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-46-000, et al, dated JULY 12, 1993
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff First Revised Sheet No. 60
First Revised Volume No. 1-A Superseding
Original Sheet No. 60
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
5. MEASUREMENTS
5.1 Metering: The gas shall be metered by one or more orifice,
turbine, or displacement-type meters, at the discretion of PGT.
When orifice meters are used, they shall be installed and
maintained, and volumes shall be measured, in accordance with the
methods prescribed in ANSI/API 2530, also published as A.G.A No.
3. When turbine meters are used, they shall be installed and
maintained, and volumes shall be measured, in accordance with
methods prescribed in AGA Report No. 4 or any subsequent revision.
When displacement meters are used, they shall be installed and
maintained and quantities shall be measured in accordance with
methods prescribed in A.G.A. No. 2, and the number of Mcf
delivered hereunder shall be computed by including factors for
pressure, temperature and deviation from Boyle's Law. To
accurately determine the deviation from Boyle's Law, a
quantitative analysis of the gas components shall be made at
reasonable intervals with such apparatus as shall be agreed upon
by both parties.
5.2 Specific Gravity: The specific gravity of the gas delivered
hereunder shall be determined from the read-outs of continuously
operating measuring instruments. The method shall consist of one
of the following:
(a) gravitometer
(b) gas chromatography
(c) other instruments acceptable to both parties
Analysis of chromatograph shall comply with the standards set forth in
ASTM D 1945. Calculation of the specific gravity from compositional
analysis by gas chromatography shall comply with the standards set
forth in ASTM D 3588. Measurement of the specific gravity with a
gravitometer shall comply with the standards set forth in ASTM D 1070.
5.3 Flowing Temperature: Flowing gas temperature shall be
continuously measured and used in flow calculations.
(Continued)
________________________________________________________________________________
Issued by: P.G. Rosput, Senior Vice President
Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff First Revised Sheet No. 61
First Revised Volume No. 1-A Superseding
Original Sheet No. 61
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
6. INSPECTION OF EQUIPMENT AND RECORDS
6.1 Inspection of Equipment and Data: PGT and Shipper shall have the right to
inspect equipment installed or furnished by the other, and the charts and
other measurement or test data of the other, at all times during business
hours; but the reading, calibration and adjustment of such equipment and
changing of charts shall be done only by the entity installing or
furnishing same. Unless PGT and Shipper otherwise agree, each shall
preserve all original test data, charts and other similar records in such
party's possession, for a period of at least six (6) years.
6.2 Information for Billing: When information necessary for billing by PGT is
in the control of Shipper, Shipper shall furnish such information,
estimated if actual is not available, to PGT on or before the third (3rd)
working day of the month following the month transportation service was
rendered. If shipper furnishes estimated information, the actual
information shall be furnished to PGT on or before the sixth (6th)
working day of the month following the month transportation service was
rendered.
6.3 Verification of Computations: PGT and Shipper shall have the right to
examine at reasonable times the books, records and charts of the other to
the extent necessary to verify the accuracy of any statement, charge or
computation made pursuant to these Transportation General Terms and
Conditions and to the rate schedules to which they apply, within twelve
(12) months of any such statement, charge or computation.
7. BILLING
7.1 Billing under all Rate Schedules: On or before the twentieth (20th) day
of each month, PGT shall render a bill to each Shipper under all
applicable Rate Schedules for the service(s) rendered during the
preceding month.
(Continued)
________________________________________________________________________________
Issued by: P.G. Rosput, Senior Vice President
Issued on: FEBRUARY 24, 1994 Effective: MARCH 27, 1994
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff Second Revised Sheet No. 62
First Revised Volume No. 1-A Superseding
First Revised Sheet No. 62
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
8. PAYMENT
8.1 Payment under all Rate Schedules: On or before the last day of each
month, each Shipper under all applicable Rate Schedules shall pay to or
upon the order of PGT in lawful money of the United States at PGT's
office in Portland, Oregon, the amount of the bill rendered by PGT during
the month in accordance with Paragraph 7.1 of these Transportation
General Terms and Conditions.
8.2 Interest on Unpaid Amounts: Should Shipper fail to pay the amount of any
bill rendered by PGT when such amount is due, interest thereon shall
accrue from the due date until paid at the rate of interest effective
from time to time under 18 CFR Section 154.67.
8.3 Remedies for Failure to Pay: If such failure to pay continues for thirty
(30) days after payment is due, PGT, in addition to any other remedy it
may have, may suspend further delivery of gas until such amount is paid,
unless Shipper in good faith disputes the amount owing and pays such
amount as it concedes to be correct. Either party may submit to
arbitration in accordance with Paragraph 14 of these Transportation
General Terms and Conditions any dispute as to the amount due PGT
hereunder.
8.4 Late Billing: If presentation of a bill by PGT is delayed after the date
specified in Paragraph 7.1 hereof, then the time for payment shall be
extended correspondingly unless Shipper is responsible for such delay.
8.5 Adjustment of Billing Error: In the event an error is discovered in any
bill rendered by PGT, the amount of such error shall be adjusted,
provided that claim therefor shall have been made within twelve (12)
months from the date such bill was rendered. The adjustment shall be made
within thirty (30) days of such timely claim.
(Continued)
________________________________________________________________________________
Issued by: R.T. Howard, Manager, Rates and Regulatory Affairs
Issued on: OCTOBER 18, 1995 Effective: NOVEMBER 18, 1995
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff First Revised Sheet No. 63
First Revised Volume No. 1-A Superseding
Original Sheet No. 63
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
9. NOTICE OF CHANGES IN OPERATING CONDITIONS
PGT and Shipper shall each ensure that the other is notified from time
to time as necessary of expected changes in the rates of delivery or
receipt of gas, or in the pressures or other operating conditions, and
the reason for such expected changes, so that they may be accommodated
when they occur.
10. FORCE MAJEURE
10.1 If either party shall fail to perform any obligation imposed upon
it by these Transportation General Terms and Conditions or by an
executed Transportation Service Agreement, and such failure shall
be caused, or materially contributed to, by force majeure which
means any acts of God, strikes, lockouts, or other industrial
disturbances, acts of public enemies, sabotage, wars, blockades,
insurrections, riots, epidemics, landslides, lightning,
earthquakes, floods, storms, fires, washouts, extreme cold or
freezing weather, arrests and restraints of rulers and people,
civil disturbances, explosions, breakage of or accident to
machinery or lines of pipe, hydrate obstructions of lines of
pipe, inability to obtain pipe, materials or equipment,
legislative, administrative or judicial action which has been
resisted in good faith by all reasonable legal means, any acts,
omissions or causes whether of the kind herein enumerated or
otherwise not reasonably within the control of the party invoking
this paragraph and which by the exercise of due diligence such
party could not have prevented, the necessity for making repairs
to, replacing, or reconditioning machinery, equipment, or
pipelines not resulting from the fault or negligence of the party
invoking this paragraph, such failure shall be deemed not to be a
breach of the obligation of such party, but such party shall use
reasonable diligence to put itself in a position to carry out its
obligations. Nothing contained herein shall be construed to
require either party to settle a strike or lockout by acceding
against its judgment to the demands of the opposing parties.
(Continued)
________________________________________________________________________________
Issued by: P.G. Rosput, Senior Vice President
Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff First Revised Sheet No. 64
First Revised Volume No. 1-A Superseding
Original Sheet No. 64
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
10. FORCE MAJEURE (Continued)
10.2 No such cause as described in Paragraph 10.1 affecting the
performance of either party shall continue to relieve such party from
its obligation after the expiration of a reasonable period of time
within which by the use of due diligence such party could have
remedied the situation preventing its performance, nor shall any such
cause relieve either party from any obligation unless such party
shall give notice thereof in writing to the other party with
reasonable promptness; and like notice shall be given upon
termination of such cause.
10.3 No cause whatsoever, including without limitation the failure of PGT
to perform including the causes specified in Paragraph 10.1, shall
relieve Shipper from its obligations to make payments due, including
the payments of reservation charges for the duration of such cause
except as provided for in Paragraphs 3.10 and 3.11 of Rate Schedule
FTS-1.
11. WARRANTY OF ELIGIBILITY FOR TRANSPORTATION
Any Shipper transporting gas on the PGT system under this FERC Gas Tariff
First Revised Volume No. 1-A warrants for itself, its successors and
assigns, that it will have at the time of delivery of the gas to PGT
hereunder good title to such gas and that all gas delivered to PGT for
transportation hereunder is eligible for the requested transportation in
interstate commerce under applicable rules, regulations or orders of the
FERC, or other agency having jurisdiction. Shipper will indemnify PGT and
save it harmless from all suits, actions, damages, costs, losses, expenses
(including reasonable attorney fees) and costs connected with regulatory
proceedings, arising from breach of this warranty.
12. POSSESSION OF GAS AND RESPONSIBILITY
PGT shall be deemed to be in control and possession of, and responsible
for, all gas delivered from the time that such gas is received by it at the
point of receipt to the time that it is delivered at the point of delivery.
(Continued)
________________________________________________________________________________
Issued by: P.G. Rosput, Senior Vice President
Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff Original Sheet No. 65
First Revised Volume No. 1-A
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
13. INDEMNIFICATION
Shipper agrees to indemnify and hold harmless PGT, its officers, agents,
employees and contractors against any liability, loss or damage whatsoever
occurring in connection with or relating in any way to the executed
Transportation Service Agreement, including costs and attorneys' fees,
whether or not such liability, loss or damage results from any demand,
claim, action, cause of action, or suit brought by Shipper or by any
person, association or entity, public or private, that is not a party to
the executed Transportation Service Agreement, where such liability, loss
or damage is suffered by PGT, its officers, agents, employees or
contractors as a direct or indirect result of any breach of the executed
Transportation Service Agreement or sole or concurrent negligence or gross
negligence or other tortious act(s) or omission(s) by Shipper, its
officers, agents, employees or contractors.
14. ARBITRATION
Any arbitration provided for or agreed to by Shipper and PGT shall be
conducted in accordance with the following procedures and principles:
Upon the written demand of either PGT or Shipper and within ten (10) days
from the date of such demand, each entity shall appoint an arbitrator and
the two arbitrators so appointed shall promptly thereafter appoint a third.
If either PGT or Shipper shall fail to appoint an arbitrator within ten
(10) days from the date of such demand, then the arbitrator shall be
appointed by a Superior Court of the State of California in accordance with
the California Code of Civil Procedure. If the two arbitrators shall fail
within ten (10) days from their appointment to agree upon and appoint the
third arbitrator, then upon the application of either PGT or Shipper such
third arbitrator shall be appointed by a Superior Court of the State of
California in accordance with the California Code of Civil Procedure.
The arbitrators shall proceed immediately to hear and determine the matter
in controversy. The award of the arbitrators, or a majority of them, shall
be made within forty-five (45) days after the appointment of the third
arbitrator, subject to any reasonable delay due to unforeseen
circumstances. The award of the arbitrators shall be drawn up in writing
and signed by the arbitrators, or a majority of them, and shall be final
and binding on both PGT and Shipper, and PGT and Shipper shall abide by the
award and perform the terms and conditions thereof. Unless otherwise
determined by the arbitrators, the fees and expenses of the arbitrator
named for each party shall be paid by that party and the fees and expenses
of the third arbitrator shall be paid in equal proportion by both PGT and
Shipper.
(Continued)
________________________________________________________________________________
Issued by: P.G. Rosput, Senior Vice President
Issued on: AUGUST 02, 1993 Effective: NOVEMBER 01, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-46-000, et al, dated JULY 12, 1993
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff Original Sheet No. 66
First Revised Volume No. 1-A
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
15. GOVERNMENTAL REGULATIONS
These Transportation General Terms and Conditions, the rate schedules to
which they apply, and any executed Transportation Service Agreement are
subject to valid laws, orders, rules and regulations of duly constituted
authorities having jurisdiction.
16. MISCELLANEOUS PROVISION
16.1 Waiver of Default: No waiver by either PGT or Shipper of any default
by the other in the performance of any provisions of an executed
Transportation Service Agreement shall operate as a waiver of any
continuing or future default, whether of a like or different
character.
16.2 Assignability: An executed Transportation Service Agreement shall
bind and inure to the respective successors and assignees of PGT and
Shipper thereto, but no assignment shall release either party
thereto from such party's obligations without the written consent of
the other party, which consent shall not be unreasonably withheld;
provided, however, nothing contained herein shall give Shipper the
right to reassign or broker its right to ship the quantities of gas
specified in the Transportation Service Agreement on PGT's system to
others. Further, nothing contained herein shall prevent either party
from pledging, mortgaging or assigning its rights as security for
its indebtedness and either party may assign to the pledgee or
mortgagee (or to a trustee for the holder of such indebtedness) any
money due or to become due under any service agreement.
16.3 Effect of Headings: The headings used throughout these
Transportation General Terms and Conditions, the rate schedules to
which they apply, and the executed Transportation Service Agreements
are inserted for reference purposes only and are not to be
considered or taken into account in construing the terms and
provisions of any paragraph nor to be deemed in any way to qualify,
modify or explain the effects of any such terms or provisions.
17. TRANSPORTATION SERVICE AGREEMENT
17.1 Form: Shipper shall enter into a contract with PGT utilizing PGT's
appropriate standard form of Transportation Service Agreement.
17.2 Term: The term of the Transportation Service Agreement shall be
agreed upon between Shipper and PGT at the time of the execution
thereof.
(Continued)
________________________________________________________________________________
Issued by: P.G. Rosput, Senior Vice President
Issued on: AUGUST 02, 1993 Effective: NOVEMBER 01, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-46,000, et al., dated JULY 12, 1993
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff Second Revised Sheet No. 67
First Revised Volume No. 1-A Superseding
First Revised Sheet No. 67
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
18. OPERATING PROVISIONS
Initial Service: For purposes of scheduling commencement of initial
transportation service five (5) business days prior to the day on which
Shipper desires service to commence, or such lesser period of time as
mutually agreed upon by PGT and Shipper, Shipper will provide PGT a
completed Customer Nomination Form provided to:
Pacific Gas Transmission Company
Gas Transportation and Services
2100 Southwest River Parkway
Portland, OR 97201
Phone - 503-833-4300
Fax -503-833-4396
Shipper shall not be entitled to receive transportation service under this
FERC Gas Tariff First Revised Volume No. 1-A if Shipper is not current in
its payments to PGT for any charge, rate or fee authorized by the
Commission for transportation service; provided, however, if the amount not
current pertains to a bona fide dispute, including but not limited to force
majeure claims relating to this FERC Gas Tariff, Shipper shall be entitled
to receive or continue to receive transportation service if Shipper posts a
bond satisfactory to PGT to cover the payment due PGT.
18.1 Firm Service
The provisions of this Paragraph 18.1 shall be applicable to firm
transportation service under Rate Schedule FTS-1 contained in this
First Revised Volume No. 1-A. Firm transportation service under this
First Revised Volume No. 1-A shall be provided when, and to the extent
that, PGT determines that firm capacity is available on PGT's existing
facilities. PGT shall not be required to provide firm transportation
service in the event firm capacity is unavailable or to construct new
facilities to provide firm service.
(Continued)
________________________________________________________________________________
Issued by: R.T. Howard, Manager, Rates and Regulatory Affairs
Issued on: OCTOBER 18, 1995 Effective: NOVEMBER 18, 1995
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff First Revised Sheet No. 68
First Revised Volume No. 1-A Superseding
Original Sheet No. 68
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
18. OPERATING PROVISIONS (Continued)
18.1 Firm Service (Continued)
For capacity that becomes available other than the circumstances
identified in Paragraphs 28 and 33, requests for firm capacity shall be
accommodated in the following manner and subject to the following
conditions and limitations:
(a) In order to be eligible for firm capacity, a party requesting
service (requestor) must be deemed credit-worthy per Paragraph 18.3
and submit a valid request in accordance with the provisions
herein.
(b) PGT will post on Pacific Trail, PGT's Electronic Bulletin Board
(EBB), available capacity. A requestor that submits a valid request
may submit a bid via the EBB for the available capacity subsequent
to PGT's posting of such capacity on the EBB. The Bid Period will
be 5 business days, during which time other requestors with valid
requests may submit a bid. All bids not withdrawn prior to the
close of the Bidding Period shall be binding. At the end of the
Bidding Period, PGT will evaluate the bids and determine the bid(s)
having the greatest economic value as determined in Paragraph
18.1(c) below.
(c) After the close of the Bidding Period, PGT may tender a Service
Agreement for execution to the requestor(s) submitting the bid(s)
having the greatest economic value for the capacity available,
subject to the provisions of Paragraph 18.1(e). The criteria for
determining which requestor(s) has submitted the bid(s) with the
greatest economic value shall be the Net Present Value (NPV) of the
reservation charge as calculated at Paragraph 28 that requestor(s)
would pay at the rates requestor(s) has bid, which shall not be
less than the Minimum Rate nor greater than the Maximum Rate, as
stated on the currently effective Statement of Rates and Charges
governing such service, over the term of service specified in the
request. If the economic values of separate bids are equal, then
service shall be offered to such requestors on a pro-rata basis.
(Continued)
________________________________________________________________________________
Issued by: P.G. Rosput, Senior Vice President
Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff First Revised Sheet No. 69
First Revised Volume No. 1-A Superseding
Original Sheet No. 69
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
18. OPERATING PROVISIONS (Continued)
18.1 Firm Service (Continued)
(d) If PGT accepts the winning bid(s) and tenders a Service Agreement,
requestor(s) shall complete and return the Service Agreement within
thirty (30) days.
(e) Except as provided in Paragraph 28, PGT shall not be obligated to
tender or execute a Service Agreement for service at any rate less
than the Maximum Rate set forth in the Statement of Effective Rates
and Charges applicable to the service requested.
(f) A Shipper receiving service under FTS-1 shall not lose its priority
for purposes of Paragraph 19 by the renewal or extension of term of
that service; provided, however, any renewal or extension must be
pursuant to a rollover or evergreen provision of the Service
Agreement. Shipper's preexisting priority shall not apply,
however, to any increase in transportation quantity or new primary
point of delivery.
18.2 Interruptible Service
The provisions of this Paragraph 18.2 shall be applicable to
interruptible transportation service under Rate Schedule ITS-1
contained in this First Revised Volume No. 1-A.
(a) Interruptible transportation service under this First Revised
Volume No. 1-A shall be provided when, and to the extent that,
capacity is available in PGT's existing facilities, which capacity
is not subject to a prior claim under a pre-existing agreement
pursuant to Rate Schedule FTS-1 or under another class of firm
service.
(b) In the event where natural gas tendered by Shipper to PGT at the
receipt point(s) for transportation, or delivered by PGT to Shipper
(or for Shipper's account) at the delivery point(s), is commingled
with other natural gas at the time of measurement, the
determination of deliveries applicable to Shipper shall be made in
accordance with operating arrangements satisfactory to Shipper, PGT
and any third party transporting to or from PGT's system.
(Continued)
________________________________________________________________________________
Issued by: P.G. Rosput, Senior Vice President
Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff First Revised Sheet No. 70
First Revised Volume No. 1-A Superseding
Original Sheet No. 70
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
18. OPERATING PROVISIONS (Continued)
18.2 Interruptible Service (Continued)
(c) PGT shall process the requests of potential Shippers requesting
similar interruptible transportation service under this FERC Gas
Tariff First Revised Volume No. 1-A on a first-come, first-served
basis, to the extent practicable, taking into account the nature
and character of the service requested. Available interruptible
capacity shall be allocated by PGT on a first-come, first-served
basis as provided in Paragraph 19 and determined by the date and
time PGT receives a completed request for service under this FERC
Gas Tariff which conforms to Paragraph 18 of these Transportation
General Terms and Conditions.
(d) A Shipper receiving service under ITS-1 shall not lose its priority
for purposes of Paragraph 19 by the renewal or extension of term of
that service; provided, however, any renewal or extension must be
pursuant to a rollover or evergreen provision of the Service
Agreement. Shipper's pre-existing priority shall not apply,
however, to any increase in transportation quantity or new primary
points of delivery.
(e) If Shipper fails to nominate and tender gas within the later of:
(a) fifteen (15) days after initial notification by PGT of the
availability of service, (b) receipt of any necessary regulatory
approvals, or (c) the installation of any necessary facilities,
Shipper's priority date shall be deemed null and void, and the day
Shipper first tenders gas to PGT at any receipt point shall be
Shipper's new assigned priority date for service. Shipper's
priority date designation pursuant to Section 2.3 of the
Transportation Service Agreement shall not be deemed null and void
if Shipper's failure to nominate and tender gas is caused by an
event of force majeure as defined in PGT's Transportation General
Terms and Conditions.
(Continued)
________________________________________________________________________________
Issued by: P.G. Rosput, Senior Vice President
Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff First Revised Sheet No. 70A
First Revised Volume No. 1-A Superseding
Original Sheet No. 70A
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
18. OPERATING PROVISIONS (Continued)
18.3 Credit-worthiness
(A) Credit-worthiness for Firm Transportation Service
(1) PGT shall not be required to perform or to continue
transportation service under this FERC Gas Tariff First
Revised Volume 1-A on behalf of any Shipper who is or has
become insolvent or who, after PGT's request, fails within a
reasonable period to establish or confirm credit-worthiness.
Shippers shall provide, initially and on a continuing basis,
financial statements, evidence of debt and/or credit ratings,
and other such information as is reasonably requested by PGT
to establish or confirm Shipper's qualification for service.
Credit limits will be established based on the level of
requested service and Shipper credit-worthiness as established
by the following:
(a) Credit-worthiness must be evidenced by at least a long term
bond (or other senior debt) rating of BBB or an equivalent
rating.
Such rating may be obtained in one of three ways:
(i) The rating will be determined by Standard and Poors or
another recognized U.S. or Canadian debt rating service;
(ii) If Shipper's debt is not rated by a recognized debt
rating service, an equivalent rating as determined by
PGT, based on the financial rating methodology, criteria
and ratios for the industry of the Shipper as published
by the above rating agencies from time to time. In
general, such equivalent rating will be based on the
audited financial statements for the Shipper's two most
recent fiscal years, all interim reports, and any other
relevant information;
(Continued)
________________________________________________________________________________
Issued by: P.G. Rosput, Senior Vice President
Issued on: APRIL 20, 1994 Effective: MAY 21, 1994
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff Third Revised Sheet No. 71
First Revised Volume No. 1-A Superseding
Second Revised Sheet No. 71
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
18. OPERATING PROVISIONS (Continued)
18.3 (A) Credit-worthiness for Firm Transportation Service (Continued)
(iii) Shipper may, at its own expense, obtain a private rating
from a recognized debt rating service, or request that an
independent accountant or financial advisor, mutually
acceptable to PGT and the Shipper, prepare an equivalent
evaluation based on the financial rating methodology,
criteria, and ratios for the industry of the Shipper as
published by the above rating agencies from time to time;
or
(b) Approval by PGT's lenders; or
(c) If Shipper is requesting credit to bid on a parcel that is for
one year (365 days) or less of service through PGT's Capacity
Release Program contained in Paragraph 28, and this option is
selected by the Releasing Shipper, Shipper may demonstrate
credit-worthiness by providing two years of audited financial
statements for itself, or for its parent company if it is a
subsidiary which is consolidated with its parent company and
does not issue stand-alone financial statements, demonstrating
adequate financial strength to justify the amount of credit to
be extended. PGT shall apply consistent evaluation practices
to determine credit-worthiness.
(2) If Shipper does not establish or maintain credit-worthiness as
described above, Shipper has the option of receiving
transportation service under this FERC Gas Tariff by providing
to PGT one of the following alternatives:
(Continued)
________________________________________________________________________________
Issued by: R.T. Howard, Manager, Rates and Regulatory Affairs
Issued on: AUGUST 13, 1996 Effective: SEPTEMBER 13, 1996
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff Second Revised Sheet No. 72
First Revised Volume No. 1-A Superseding
First Revised Sheet No. 72
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
18. OPERATING PROVISIONS (Continued)
18.3 (A) Credit-worthiness for Firm Transportation Service (Continued)
(a) A guarantee of Shipper's financial performance in a form
satisfactory to PGT and for the term of the Gas Transportation
Agreement from a corporate affiliate of the Shipper or a third
party either of which meets the credit-worthiness standard
discussed above.
(b) Other security acceptable to PGT's lenders.
18.3 (B) Credit-worthiness for Interruptible Transportation Service
(1) PGT shall not be required to perform or to continue interruptible
transportation service under this FERC Gas Tariff First Revised Volume
No. 1-A on behalf of any Shipper who is or has become insolvent or who,
at PGT's request, fails within a reasonable period to demonstrate
credit-worthiness. Shipper's credit-worthiness shall be determined by
providing proof of least two of the items listed below:
(a) A long-term bond or commercial paper rating from Standard and
Poors or Moody's equivalent to a "Ba" or better, or a
commercial paper rating from Standard and Poors or Moody's
equivalent to Prime-3 or better.
(b) Audited financial statements for itself, or for its parent
company if it is a subsidiary which is consolidated with its
parent company and does not issue stand-alone financial
statements, for the two preceding years showing good financial
strength.
(c) An estimated financial strength rating by Dun and Bradstreet
sufficient to cover the credit to be extended and a
corresponding Dun and Bradstreet composite credit appraisal of
"fair" or better.
(Continued)
________________________________________________________________________________
Issued by: R.T. Howard, Manager, Rates and Regulatory Affairs
Issued on: AUGUST 13, 1996 Effective:SEPTEMBER 13, 1996
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff First Revised Sheet No. 73
First Revised Volume No. 1-A Superseding
Original Sheet No. 73
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
18. OPERATING PROVISIONS (Continued)
18.3 (B) Credit-worthiness for Interruptible Transportation Service
(Continued)
(d) A demonstration by the Shipper that the Company has
sufficient financial capacity or backing to warrant an
extension of credit. This demonstration could include proof
of banking relationships sufficient to cover the service
agreement, or a detailed listing of credit references
within the industry, exhibiting a good credit history.
(2) If Shipper does not demonstrate credit-worthiness, Shipper has
the option of receiving interruptible transportation service
under this FERC Gas Tariff First Revised Volume No. 1-A if
Shipper provides PGT a letter of credit in an amount equal to the
cost of performing the maximum level of service requested for a
three (3) month period of time. The letter of credit must be from
a credit worthy financial institution and be in place before the
Transportation Service Agreement can be signed. The Shipper also
has the option of receiving transportation service if Shipper
prepays for transportation services on a month-to-month basis
pursuant to the following terms:
(a) For a calendar month in which transportation service is
desired (delivery month), Shipper must notify PGT no later
than eight (8) business days prior to the commencement of
delivery month (estimation date) of its estimation of the
maximum, cumulative gas deliveries (monthly estimation)
desired for the delivery month. (For Shipper's initial
monthly estimation, the delivery month, or remaining portion
thereof, shall commence eight (8) days after the estimation
date.) Notice of monthly estimation may be telephonic or
written; telephonic notices must be confirmed in writing and
received by PGT within five (5) business days. PGT will
advise Shipper within forty-eight (48) hours of the
estimation date of the exact dollar amount of the
prepayment. Shipper shall not deliver or receive gas in
excess of the monthly estimation during delivery month.
(Continued)
________________________________________________________________________________
Issued by: P.G. Rosput, Senior Vice President
Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff First Revised Sheet No. 74
First Revised Volume No. 1-A Superseding
Original Sheet No. 74
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
18. OPERATING PROVISIONS (Continued)
18.3 (B) Credit-Worthiness for Interruptible Transportation Service
(Continued)
(b) No later than three (3) business days (settlement date) prior to
commencement of delivery month, Shipper shall pay to PGT and PGT
shall have received from Shipper lawful money of the United States
in an amount equal to the prepayment amount provided to Shipper by
PGT described above.
(c) On or before the twentieth (20th) day following delivery month, PGT
shall provide a statement to Shipper detailing the transportation
service provided during the delivery month. The statement will
reconcile the amount prepaid in accordance with the monthly
estimation, with the actual cost of transportation service
provided, and provide a credit to Shipper, if applicable. Any such
credit will be deducted from the prepayment for the following
month. Should the Shipper elect not to receive transportation
services for the following month, Shipper shall so notify PGT in
writing; PGT will issue a check to the Shipper within seven (7)
business days following receipt by PGT of such notice.
18.3 (C) Credit-worthiness for Firm and Interruptible Transportation Service
For purposes of this FERC Gas Tariff First Revised Volume No. 1-A
the insolvency of a Shipper shall be evidenced by the filing by
such Shipper or any parent entity thereof (hereinafter
collectively referred in this paragraph to as "the Shipper") of a
voluntary petition in bankruptcy or the entry of a decree or order
by a court having jurisdiction in the premises adjudging the
Shipper as bankrupt or insolvent, or approving as properly filed a
petition seeking reorganization, arrangement, adjustment or
composition of or in respect of the Shipper under the Federal
Bankruptcy Act or any Act or any other applicable federal or state
law, or appointing a receiver, liquidator, assignee, trustee,
sequestrator (or other similar official) of the Shipper
(Continued)
________________________________________________________________________________
Issued by: P.G. Rosput, Senior Vice President
Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff First Revised Sheet No. 75
First Revised Volume No. 1-A Superseding
Original Sheet No. 75
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
18. OPERATING PROVISIONS (Continued)
18.3 (C) Credit-worthiness for Firm and Interruptible Transportation Service
(Continued)
or composition of or in respect of the Shipper under the Federal
Bankruptcy Act or any Act or any other applicable federal or state
law, or appointing a receiver, liquidator, assignee, trustee,
sequestrator (or other similar official) of the Shipper or of any
substantial part of its property, or the ordering of the winding-up
liquidation of its affairs, with said order or decree continuing
unstayed and in effect for a period of sixty (60) consecutive days.
(Continued)
________________________________________________________________________________
Issued by: P.G. Rosput, Senior Vice President
Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff First Revised Sheet No. 76
First Revised Volume No. 1-A Superseding
Original Sheet No. 76
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
18. OPERATING PROVISIONS (Continued)
18.4 Upon request of PGT, Shipper shall from time to time submit estimates
of daily, monthly and annual quantities of gas to be transported,
including peak day requirements.
18.5 PGT shall not be obligated to install additional facilities, other than
those specified in Paragraph 4.1 herein, that are required to provide
service under this FERC Gas Tariff First Revised Volume No. 1-A;
provided, however, PGT may install or Shipper may pay all of the
expenses incurred for installing additional facilities on a
nondiscriminatory basis and under terms that are mutually agreeable. In
the event PGT incurs the cost of installing additional facilities on
behalf of a Shipper, Shipper shall pay, in addition to the rate(s)
stated in the applicable rate schedule, the prorated(based on
Transportation Contract Demand) cost of service attributable to any
such additional facilities until such time as a different allocation
procedure is specified by Commission order.
18.6 No transportation service will be conducted for the account of Shipper
by PGT until PGT has received the completed service request form,
unedited and complete as to form, and Shipper has been advised by PGT
that the transportation service may commence.
18.7 Requests for interruptible and firm transportation service hereunder
shall be made by providing the information contained in PGT's
Transportation Request Form to PGT.
(Continued)
________________________________________________________________________________
Issued by: P.G. Rosput, Senior Vice President
Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff First Revised Sheet No. 77
First Revised Volume No. 1-A Superseding
Original Sheet No. 77
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
18. OPERATING PROVISIONS (Continued)
18.8 Transportation Request Form
Gentlemen:
________________________________ (Shipper) hereby requests gas transportation
service from Pacific Gas Transmission Company (PGT) in accordance with Paragraph
18.8 of the Transportation General Terms and Conditions of PGT's tariff and
concurrently provides the following information relative to this request:
1. Shipper's Name ___________________________________________
Business Address __________________________________________
State or Province of Incorporation ________________________
2. Requesting Party ____________________ Title _______________
Contact Name ________________________ Phone _______________
3. Shipper's Status: LDC ____ Intrastate ____ End User ____
(Check one) Producer ____ Marketer/Broker __________
Gatherer ____ Interstate ____
Other __________________________________
4. Type of Service Requested: (Check all applicable)
a. Part 284 Interruptible ____
b. Part 284 Firm ____*
c. New Service ____
d. Amendment to PGT Contract #_______
e. Add/Change Receipt/Delivery Point ____
f. Authority to Bid for Released Capacity ____
* PGT will accept requests for firm transportation service. At such time
that firm capacity may become available, PGT will evaluate such requests.
Currently, no excess firm capacity is available on the PGT system.
5. Type of Authority: Blanket Section 7 (Part 284,
Subpart G)____
Section 311(a) (Part 284, Subpart B)____
(Continued)
________________________________________________________________________________
Issued by: P.G. Rosput, Senior Vice President
Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff Second Revised Sheet No. 78
First Revised Volume No. 1-A Superseding
First Revised Sheet No. 78
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
18. OPERATING PROVISIONS (Continued)
18.8 Transportation Request Form (Continued)
6. If Shipper requests service under Section 311(a), provide the following
information concerning the party on whose behalf the transportation will be
provided (the "On Behalf of" party):
(a) The exact legal name of the "On Behalf Of" party:
________________________________________________________________
(b) The "On Behalf Of" party's address (if other than Shipper):
________________________________________________________________
________________________________________________________________
________________________________________________________________
(c) Is the "On Behalf Of" party:
A Local Distribution Company ______
An Intrastate Pipeline ______
7. If Shipper requests service under Section 311(a), Shipper must provide a
certification that the service qualifies under 18 C.F.R. (S) 284.102. To
enable PGT to verify that the requested transportation service will qualify
under 18 C.F.R. (S) 284.102, the certification must provide facts showing
that:
(a) the "On Behalf Of" party will have physical custody of and
transport the natural gas at some point; or
(b) the "On Behalf Of" party will hold title to the natural gas at
some point, which may occur prior to , during, or after the time that
the gas is transported by PGT, for a purpose related to the "On Behalf
Of" party's status and function as an intrastate pipeline or its
status and function as a local distribution company; or
(c) the gas will be delivered to a customer that is either located
in the "On Behalf Of" party's service area, if the "On Behalf Of"
party is a local distribution company, or is physically able to
receive direct deliveries of gas from the "On Behalf Of" party, if the
"On Behalf Of" party is an interstate pipeline, and that "On Behalf
Of" party has certified that it is on its behalf that PGT will be
providing the requested transportation service. (The "On Behalf Of"
party's certification must be submitted with the Transportation
Request Form.)
(Continued)
________________________________________________________________________________
Issued by: P.G. Rosput, Senior Vice President
Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff First Revised Sheet No. 79
First Revised Volume No. 1-A Superseding
Substitute Original Sheet No. 79
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
18. OPERATING PROVISIONS (Continued)
18.8 Transportation Request Form (Continued)
8. The intended use of the gas is:
_____ utility or pipeline system supply
_____ end use by industry or commerce
_____ other (specify)
9. Requested Commencement Date _______________ (not to exceed
3 months from request date)
Termination Date __________________
Evergreen clause desired (Complete for Part 284 Interruptible or Firm
Service only): Yes _____ No _____
10. Transportation Quantities:
a) Total Maximum Daily Quantity (MDQ): __________ MMBtu/day
b) Total quantity for contract period: __________ MMBtu
11. Notices to:
_______________________________________________________
Mailing Address
_______________________________________________________
City State Zip
_______________________________________________________
Street Address (if P.O. Box was used above)
_______________________________________________________
City State Zip
_______________________________________________________
Attention Title
_______________________________________________________
Telephone Number Fax Number
(Continued)
________________________________________________________________________________
Issued by: P.G. Rosput, Senior Vice President
Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff First Revised Sheet No. 80
First Revised Volume No. 1-A Superseding
Substitute Revised Sheet No. 80
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
18. OPERATING PROVISIONS (Continued)
18.8 Tranportation Request Form (Continued)
Invoices to:
_______________________________________________________
Mailing Address
_______________________________________________________
City State Zip
_______________________________________________________
Street Address (if P.O. Box was used above)
_______________________________________________________
City State Zip
_______________________________________________________
Attention Title
_______________________________________________________
Telephone Number Fax Number
(Continued)
________________________________________________________________________________
Issued by: P.G. Rosput, Senior Vice President
Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff Second Revised Sheet No. 81
First Revised Volume No. 1-A Superseding
First Revised Sheet No. 81
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
19. PRIORITY OF SERVICE, SCHEDULING AND NOMINATIONS
19.1 Priority of Firm Service
PGT shall provide service first for firm transportation Shippers for
service at Shipper's primary receipt and delivery points in accordance
with the applicable executed service agreements and rate schedules.
Next, PGT will provide firm transportation service for service at
Shipper's secondary receipt and delivery points or primary receipt and
secondary delivery points in accordance with the applicable executed
service agreements and rate schedules.
If full service cannot be provided, PGT shall provide service on a pro
rata basis according to the respective total Maximum Daily Demand or
Maximum Daily Quantity, as appropriate, specified in each executed
service agreement, first for service at Shipper's primary receipt and
delivery points and second for service at Shipper's secondary receipt
and delivery points.
These provisions also apply for capacity released under PGT's capacity
release program, and are subject to the terms and conditions as
specified in an executed firm service agreement between PGT and
Shipper. All service under the capacity release program shall be
considered firm for purposes of priority of service.
19.2 Priority of Interruptible Service
Interruptible transportation service under this FERC Gas Tariff First
Revised Volume No. 1-A shall be provided when, and to the extent that,
capacity is available in PTG's existing facilities, which capacity is
not subject to a prior claim under a pre-existing contract, service
agreement, certificate or under Priority 1 - Firm Service. PGT will
provide interruptible transportation service, as set forth in
Paragraph 19 of these Transportation General Terms and Conditions, on
a first-come, first-served basis, as determined by the date and time
PGT receives a completed request for service conforming to Paragraph
18.8, as approved by the Commission in Docket No. CP87-159-000.
(Continued)
________________________________________________________________________________
Issued by: R.T. Howard, Manager, Rates and Regulatory Affairs
Issued on: AUGUST 13, 1996 Effective: SEPTEMBER 13, 1996
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff Original Sheet No. 81.01
First Revised Volume No. 1-A
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
19. PRIORITY OF SERVICE, SCHEDULING AND NOMINATIONS (Continued)
19.2 Priority of Interruptible Service
Interruptible transportation service under this FERC Gas Tariff First
Revised Volume No. 1-A shall be provided when, and to the extent that,
capacity is available in PGT's existing facilities, which capacity is
not subject to a prior claim under a pre-existing contract, service
agreement, certificate or under Priority 1 - Firm Service. PGT will
provide interruptible transportation service, as set forth in
Paragraph 19 of these Transportation General Terms and Conditions,
first to shippers paying the maximum rate in accordance with PGT's IT
Queue, which is determined by the date and time PGT receives a
completed request for service conforming to Paragraph 18.8, as
approved by the Commission in Docket No. CP87-159-000. PGT will next
allocate capacity to shippers paying a discounted rate to the
shipper(s) paying the highest rate. For the purposes of this Section
19.2, the term "highest rate" shall be determined by multiplying the
distance in pipeline miles from the receipt point to the delivery
point by the sum of the Base Tariff Rate, GRI Surcharge, GSR
Surcharge, and ACA Surcharge. In the event of a tie, shippers shall
receive a pro-rata allocation based on the quantity that otherwise
would be scheduled if not for the capacity limitation.
(Continued)
________________________________________________________________________________
Issued by: R.T. Howard, Manager, Rates and Regulatory Affairs
Issued on: AUGUST 13, 1996 Effective: SEPTEMBER 13, 1996
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff First Revised Sheet No. 81A
First Revised Volume No. 1-A Superseding
Original Sheet No. 81A
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
19. PRIORITY OF SERVICE, SCHEDULING AND NOMINATIONS (Continued)
19.3 Priority of Authorized Overrun Service
Authorized overrun service shall have a priority lower than firm or
interruptible as defined above. Priority within the overrun class
shall be determined using a first-come, first-serve procedure.
19.4 Nominations
Quantities nominated for transportation shall be for previously
approved and valid receipt and delivery points and shall be provided
by Shipper via the Electronic Bulletin Board (EBB), to PGT's Gas
Control no later than 10:00 a.m. Pacific Time for the following day.
Nominations for an entire month may be made at any time up to 10:00
a.m. Pacific Time on the last day of the month. PGT shall have the
discretion to accept nominations at such other later times as
operating conditions may permit and without detrimental impact to
other Shippers and upon confirmation that corresponding upstream and
downstream arrangements in a manner satisfactory to PGT have been
made. The receipt of the nomination by PGT is notice that all
necessary regulatory approvals have been received and that valid
upstream and downstream transportation and other contractual
arrangements are in place. Shipper shall provide as a component of its
nomination such other information as may be required by PGT to enable
it to identify, confirm and schedule the nomination. Shipper shall
also prioritize nominated receipts and deliveries when there is more
than one supplier and more than one shipper customer respectively.
Shipper designated priorities will be used to allocate gas when the
upstream and downstream nominations vary from PGT's Shipper
nominations. PGT shall be allowed to rely conclusively on the
information submitted as part of the nomination in confirming the
nomination for scheduling and allocation.
(Continued)
________________________________________________________________________________
Issued by: P.G. Rosput, Senior Vice President
Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff Second Revised Sheet No. 81B
First Revised Volume No. 1-A Superseding
First Revised Sheet No. 81B
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
19. PRIORITY OF SERVICE, SCHEDULING AND NOMINATIONS (Continued)
19.4 Nominations (Continued)
Requests to amend previously scheduled nominations may be accepted
during the gas day, subject to operational conditions and, further
that corresponding upstream and downstream adjustments in a manner
satisfactory to PGT can be confirmed. A request to increase a
nomination for firm transportation up to the MDQ specified in the
Service Agreement will be accommodated to the extent operating
conditions permit; provided, however an increased nomination will not
be scheduled to the extent it would affect another Shipper's flowing
quantities during the Gas Day that the increased nomination is
received. A request to increase a nomination for interruptible
transportation shall be permitted only to the extent that capacity is
available and that no displacement of other interruptible
transportation occurs. Such changes will become effective only when
system operating conditions, as determined by PGT, permit changes to
occur.
Quantities nominated are for a daily rate, and will be received and
delivered at a uniform hourly rate of confirmed quantity divided by
24, unless as determined by PGT, variance from the hourly rate will
not be detrimental to the operation of the pipeline or adversely
affect other PGT Shippers. Nominations, as amended by Shipper and
received by PGT, shall remain in effect during the month for which the
nomination is applicable, whether or not transportation occurs, until
a new or amended nomination is provided by Shipper and received by
PGT. PGT reserves the right to reject any nominated quantity of less
than 24 MMBTU/day. PGT's primary method of nomination transmission
shall be the EBB. If and only if, the EBB is inoperable, shall PGT
accept nominations via alternative means such as fax transmittal. PGT
requires that a Shipper designate, in writing, those individuals who
will be authorized to place nominations for transportation on the
system.
19.5 Priority of Parking and Authorized Imbalance Service
Parking and Authorized Imbalance Service shall have the lowest
priority on PGT's system. All other transportation service, including
rectification of imbalances, have superior priority to these services.
(Continued)
________________________________________________________________________________
Issued by: P.G. Rosput, Senior Vice President
Issued on: AUGUST 12, 1994 Effective: SEPTEMBER 14, 1994
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RP94-145-000, dated AUGUST 03, 1994
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff Second Revised Sheet No. 81C
First Revised Volume No. 1-A Superseding
First Revised Sheet No. 81C
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
20. CURTAILMENT
PGT shall have the right to curtail, interrupt, or discontinue
Transportation Service on any portion of its system at any time for reasons
of Force Majeure or when capacity, supply, or operating conditions so
require or it is necessary or desirable to make modifications, repairs, or
operating changes to its system. PGT shall provide notice of such
occurrences as is reasonable under the circumstances.
Capacity may become constrained at individual receipt points, delivery
points or on segments of the pipeline. PGT shall exercise this curtailment
provision only at the point(s) or segment(s) of the pipeline affected by
the constraint. When capacity is constrained or otherwise insufficient to
serve all the transportation requirements which are scheduled to receive
service, transportation service will be curtailed in reverse order of the
scheduling provided in Paragraph 19.
Curtailment of firm service if necessary, will be performed pro rata based
on the MDQ across the contracts scheduled to use capacity at the applicable
delivery point(s) or mainline segment(s) of pipeline, applied first to
secondary delivery points.
Curtailment of firm service, if necessary, at receipt points will be
performed pro rata based on the quantities scheduled at the affected
receipt point(s), applied first to secondary receipt points.
If, on any day, PGT determines the capacity of its mainline system, or any
portion thereof, including the points at which gas is tendered for
transportation, is insufficient to serve transportation requirements which
are otherwise scheduled to receive service on such day, or to accept the
quantities of gas tendered, capacity which requires allocation shall be
allocated in a manner which results in curtailment of capacity, to zero if
necessary, first to the last quantities scheduled, and then sequentially in
reverse order to the scheduling provided for in Paragraph 19, except that
mid-gas day nomination increases by interruptible Shippers shall not bump
those interruptible Shippers' volumes already confirmed for that gas day.
(Continued)
________________________________________________________________________________
Issued by: R.T. Howard, Manager, Rates and Regulatory Affairs
Issued on: AUGUST 13, 1996 Effective: SEPTMBER 13, 1996
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff First Revised Sheet No. 82
First Revised Volume No. 1-A Superseding
Original Sheet No. 82
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
21. BALANCING
Balancing of thermally equivalent quantities of gas received and delivered
by PGT shall be achieved as nearly as feasible on a daily basis, with any
cumulative imbalance accounted for on a monthly basis. Correction of
imbalances shall be the responsibility of the Shipper whether or not
notified by PGT at the time of incurrence of the imbalance. Correction of
imbalances shall be scheduled with PGT using the nomination process as soon
as an imbalance is known to exist based on the best available current data.
Nominations to correct imbalances shall have the lowest priority for
scheduling purposes and shall be subject to the availability of capacity
and other operational constraints for imbalance correction. If on any day
capacity is insufficient to schedule all imbalance nominations, all such
nominations shall be prorated accordingly. To maintain the operational
integrity of its system, PGT shall have the right to balance any Shipper's
account as conditions may warrant.
Imbalances shall exist as defined below and be subject to the applicable
charges and penalties if not corrected.
a) Actual delivered quantity exceeds MDQ
An imbalance shall exist if the actual delivered quantity on any day
exceeds the MDQ and the delivered quantity in excess of the MDQ has
not been authorized by PGT (Unauthorized Overrun).
Penalty: A Shipper shall be assessed $5/MMBTU for the quantity that is
greater than 10% of the MDQ or 1000 MMBTU, whichever is greater.
In addition, the quantity delivered in excess of the MDQ shall be
charged the Authorized Overrun charge as provided in the applicable
rate schedule of Shipper.
(Continued)
________________________________________________________________________________
Issued by: P.G. Rosput, Senior Vice President
Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff First Revised Sheet No. 83
First Revised Volume No. 1-A Superseding
Original Sheet No. 83
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
21. BALANCING (Continued)
(b) Actual delivered quantity exceeds receipt quantity
A net positive imbalance shall exist if the difference between the
delivered quantity and the quantity received, taking into account the
reduction in quantity for compressor fuel use, yields a positive
result. Commencing upon notification by PGT of the existence of the
imbalance, Shipper shall have 3 days to correct the imbalance.
Penalty: If, at the end of the 3 day period the difference between the
actual delivered quantity and the receipt quantity is in excess of 10%
of the delivered quantity or 1000 MMBTU, whichever is greater, the
Shipper shall be assessed a charge of $5/MMBTU applied to the excess
quantities. If the imbalance is not corrected within 45 days of PGT's
notice of an imbalance, the Shipper shall be assessed an additional
charge of $5/MMBTU, applied to the net imbalance remaining at the end
of the 45 day balancing period.
(Continued)
________________________________________________________________________________
Issued by: P.G. Rosput, Senior Vice President
Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff First Revised Sheet No. 84
First Revised Volume No. 1-A Superseding
Original Sheet No. 84
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
21. BALANCING (Continued)
(c) Actual quantity received exceeds delivered quantity
A net negative imbalance shall exist if the difference between the
delivered quantity and the quantity received taking into account the
reduction in quantity for compressor fuel use, yields a negative
result. Commencing upon notification by PGT of the existence of the
imbalance, Shipper shall have 3 days to correct the imbalance.
Penalty: If, at the end of the 3 day period the difference between the
actual quantity received and the delivered quantity is in excess of
10% of the delivered quantity or 1000 MMBTU, whichever is greater, the
Shipper shall be assessed a penalty of $2/MMBTU applied to the excess
quantity. If the imbalance is not corrected within 45 days of PGT's
notice of an imbalance, PGT shall be able to retain the remaining
imbalance quantity without compensation to the Shipper and free and
clear of any adverse claim.
(d) Scheduled delivery quantity exceeds actual delivered quantity
An imbalance shall exist when the quantity scheduled (nominated and
confirmed) for delivery exceeds the actual delivered quantity.
Penalty: When the difference between the scheduled delivery quantity
and actual delivered quantity is in excess of 10% of the actual
deliveries, or 1000 MMBTU, whichever is greater, the Shipper shall be
assessed the maximum applicable interruptible transportation rate
applied to the excess quantities.
(Continued)
________________________________________________________________________________
Issued by: P.G. Rosput, Senior Vice President
Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff Original Sheet No. 84A
First Revised Volume No. 1-A
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
21. BALANCING (Continued)
(e) Actual delivered quantity exceeds scheduled delivery quantity
An imbalance shall exist when the quantity delivered exceeds the
quantity scheduled (nominated and confirmed).
Penalty: When the difference between the actual delivered quantity and
the scheduled delivery quantity is in excess of 10% of the scheduled
quantity or 1000 MMBTU whichever is greater, the Shipper shall be
assessed a charge of $5/MMBTU applied to the excess quantity.
Imbalance determinations as described above will be performed on a daily
basis and each daily occurrence will constitute a separate incident. It is
recognized and understood that more than one penalty provision may apply to
each imbalance incident.
In the event that any penalty would otherwise be applicable under these
provisions as a direct consequence of any action or failure to take action
by PGT or the failure of any facility under PGT's control, or an event of
force majeure as defined in these Transportation General Terms and
Conditions, said penalty shall not apply.
The payment of a penalty in dollars pursuant to Paragraph 21 shall under no
circumstances be considered as giving any Shipper the right to deliver or
take overrun quantities.
Upon termination of a Service Agreement, Shipper shall have 60 days to
correct any remaining imbalances. After his period has elapsed, PGT shall
have the right to retain any negative imbalance quantity without
compensation to the Shipper and shall assess a charge of $5/MMBTU for any
positive imbalance quantity as applicable.
(Continued)
________________________________________________________________________________
Issued by: P.G. Rosput, Senior Vice President
Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff Original Sheet No. 85
First Revised Volume No. 1-A
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
22. ANNUAL CHARGE ADJUSTMENT (ACA) PROVISION
22.1 Purpose: PGT shall recover from Shippers the annual charge assessedto
PGT by the Federal Energy Regulatory Commission for budgetary
expenses pursuant to Section 154.38(d)(6) of the Commission's
regulations and Order No. 472 issued May 29, 1987. PGT shall recover
this charge by means of an Annual Charge Adjustment (ACA); a per unit
rate equivalent to the unit rate assessed against PGT by the
Commission shall be included in PGT's transportation rates. (During
the period that this ACA provision is in effect, PGT shall not
recover in a Natural Gas Act Section 4 rate case annual charges
recorded in FERC Account No. 928 assessed to PGT by the Commission
pursuant to Order No. 472.)
22.2 Filing Procedure: The notice period and proposed effective date of
filings pursuant to this paragraph shall be as permitted under
Section 4 of the Natural Gas Act; provided, however, that any such
filing shall not become effective unless they become effective
without suspension or refund obligation.
22.3 ACA Unit Rate Adjustment: PGT's ACA unit rate shall be the unit rate
used by the Commission to determine the annual charge assessment to
PGT, and shall be reflected in the Statement of Effective Rates and
Charges of this FERC Gas Tariff First Revised Volume No. 1-A.
22.4 Affected Rate Schedules: The ACA provision shall apply to all rate
schedules contained in PGT's FERC Gas Tariff First Revised Volume No.
1-A.
23. SHARED OPERATING PERSONNEL AND FACILITIES
PGT and its marketing affiliate do not share any operating personnel. PGT
does not share any facilities with its marketing affiliate. To the extent
PG&E elects service under Rate Schedule USS-1, PGT employees involved with
the implementation of USS-1 service will operate independently from PGT's
pipeline operating employees.
(Continued)
________________________________________________________________________________
Issued by: P.G. Rosput, Senior Vice President
Issued on: AUGUST 02, 1993 Effective: NOVEMBER 01, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-46-000, et al., dated JULY 12, 1993
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff First Revised Sheet No. 86
First Revised Volume No. 1-A Superseding
Original Sheet No. 86
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
24. COMPLAINT PROCEDURES
24.1 Any Shipper or potential Shipper may register a complaint regarding
requested or provided transportation service. The complaint may be
communicated to PGT primarily by use of PGT's Electronic Bulletin
Board (EBB) and secondarily either orally, and/or in writing. Oral
complaints should be made to PGT's Manager of Gas Transportation and
Services, telephone (503) 833-4300. Written complaints should be sent
via registered or certified mail, facsimile (FAX No. (503) 833-4396) ,
or hand delivered to:
Pacific Gas Transmission Company
2100 Southwest River Parkway
Portland, OR 97201
Attention: Manager of Gas Transportation and Services
Oral, written and EBB-submitted complaints must contain the following
minimum information:
- Shipper or potential Shipper's name, address, and FAX and
telephone numbers;
- Shipper or potential Shipper's contact representative;
- A clear, concise statement of the complaint.
Each complaint will be recorded in PGT's Transportation Service
Complaint Log maintained by PGT's Gas Transportation and Services
Department located in Portland. Complaints will be logged by date and
time received by PGT.
24.2 PGT will initially respond to each complaint within forty-eight (48)
hours after PGT receives it. PGT will provide a written response to
each complaint within thirty (30) days after PGT receives it. PGT's
written response will be sent to Shipper or potential Shipper by
certified or registered mail If the complaint was filed by the EBB,
then PGT shall respond via the EBB. A copy of all complaints will be
filed in the Transportation Service Complaint Log.
(Continued)
________________________________________________________________________________
Issued by: R.T. Howard, Manager, Rates and Regulatory Affairs
Issued on: OCTOBER 18, 1995 Effective: NOVEMBER 18, 1995
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff Second Revised Sheet No. 87
First Revised Volume No. 1-A Superseding
First Revised Sheet No. 87
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
25. INFORMATION CONCERNING AVAILABILITY AND PRICING OF TRANSPORTATION SERVICE
AND CAPACITY AVAILABLE FOR TRANSPORTATION
25.1 Any affiliated or nonaffiliated Shipper or potential Shipper may
obtain information concerning the availability and pricing of PGT's
transportation services and the pipeline capacity available for
transportation by:
(a) Contacting PGT at:
Pacific Gas Transmission Company
Marketing and Transportation Department
2100 Southwest River Parkway
Portland, OR 97201
Telephone: (503) 833-4300
or (California customers)
Pacific Gas Transmission Company
California Marketing Group
101 Spear Street, Suite 200
San Francisco, CA 94105
Telephone: (415) 778-3000
Fax: (415) 778-3091
Inquiries may be made orally or in writing.
Upon request, PGT will provide to any Shipper or potential
Shipper a copy of its FERC Gas Tariff, First Revised Volume No.
1-A, as well as any published notices concerning discounts then
available to existing Shippers on the PGT system.
(b) Subscribing to PGT's twenty-four (24) hour Electronic Bulletin
Board by calling 1-503-833-4310. The Electronic Bulletin Board
provides current information concerning the availability and
pricing of transportation service on the PGT system, including
all effective rates and discount notices, and capacity available
for transportation.
25.2 The procedures to be followed by a potential Shipper requesting
transportation service from PGT or by an existing Shipper requesting
an amendment to its existing service or additional service from PGT
are specified in Paragraph 18 of these Transportation General Terms
and Conditions.
(Continued)
________________________________________________________________________________
Issued by: R.T. Howard, Manager, Rates and Regulatory Affairs
Issued on: OCTOBER 18, 1995 Effective: NOVEMBER 18, 1995
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff Second Revised Sheet No. 88
First Revised Volume No. 1-A Superseding
First Revised Sheet No. 88
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
25. INFORMATION CONCERNING AVAILABILITY AND PRICING OF TRANSPORTATION SERVICE
AND CAPACITY AVAILABLE FOR TRANSPORTATION (Continued)
25.3 The procedures to be followed by Shippers for submitting nominations
for transportation service are specified in Paragraph 19 of these
Transportation General Terms and Conditions.
26. MARKET CENTERS
The Market Center is defined as a point of interconnection between PGT and
other pipelines and local distribution companies. PGT shall provide for
Market Centers on PGT. Parties wishing to use Market Centers on the PGT
system shall contact PGT for this service. At these Market Centers,
entities may trade gas quantities without actively shipping the gas either
upstream or downstream of the Market Center. Such entities must nominate
for the gas transactions in accordance with the nomination procedures of
the Transportation General Terms and Conditions of First Revised Volume No.
1-A. An entity's nomination for upstream supply and downstream delivery
must match the corresponding upstream Shipper nomination and the downstream
customer request.
(Continued)
________________________________________________________________________________
Issued by: R.T. Howard, Manager, Rates and Regulatory Affairs
Issued on: AUGUST 13, 1996 Effective: SEPTEMBER 13, 1996
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff Original Sheet No. 88A
First Revised Volume No. 1-A
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
27. PLANNED PGT CAPACITY CURTAILMENTS AND INTERRUPTIONS
27.1 When PGT needs to temporarily curtail or interrupt service to any
Shipper hereunder for the purpose of making planned alterations or
repairs, PGT shall give Shipper as much notice as possible of the
process so that each Shipper's firm transportation requirements are
taken into account in the planning process.
27.2 In the spring of each year PGT shall publish on its electronic
bulletin board (EBB) to all Shippers a schedule of planned major
maintenance and repairs which affect system capacity. The schedule
shall show the estimated delivery point capacity for the next 12
months.
27.3 On a daily basis PGT shall post, on its EBB, capacity for each
forthcoming gas day plus the estimated capacity for the next two gas
days.
(Continued)
________________________________________________________________________________
Issued by: P.G. Rosput, Senior Vice President
Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff Substitute Original Sheet No. 89
First Revised Volume No. 1-A Superseding
Original Sheet No. 89
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
28. CAPACITY RELEASE
28.1 Eligibility to Release
Any firm Shipper which contracts for firm transportation service under
Part 284 of the Commission's regulations (Releasing Shipper) is
eligible to release all or part of its capacity (Parcel) for use by
another party (Replacement Shipper). Any Replacement Shipper which has
previously contracted for a Parcel may also release its capacity to
another party as a secondary release subject to the terms and
conditions described herein.
Upon releasing a Parcel, consistent with the terms and conditions
described herein, all Releasing Shippers shall remain ultimately
liable for all reservation charges billable for the originally
contracted service. The Releasing Shipper, whether a primary or
secondary capacity holder, must post the capacity it seeks to release
on PGT's Electronic Bulletin Board (EBB) prior to the close of the
Posting Period defined herein.
A Releasing Shipper may release all or a portion of its capacity for
the remainder of the term of its contract and extinguish its
contractual obligations to PGT with respect to that portion provided
that: 1) the Replacement Shipper for this capacity is creditworthy
pursuant to PGT's credit standards; and 2) that the rate paid by the
Replacement Shipper be no less than the rate contracted between the
Releasing Shipper and PGT for the maximum volume, for the remaining
term of the contract or the Releasing Shipper's maximum tariff rate.
The release may be structured such that the right of first refusal may
transfer to the Replacement Shipper even if the release has recall
provisions and has been recalled by the Releasing Shipper at the end
of the service agreement.
(Continued)
________________________________________________________________________________
Issued by: P.G. Rosput, Senior Vice President
Issued on: OCTOBER 13, 1993 Effective: NOVEMBER 01, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-46-000, et al., dated OCTOBER 01, 1993
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff Sub. Second Revised Sheet No. 90
First Revised Volume No. 1-A Superseding
First Revised Sheet No. 90
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
28. CAPACITY RELEASE (Continued)
28.2 Types of Release
A Releasing Shipper may release a Parcel for a term (Release Term) up
to or equivalent to the remaining term under its service agreement
with PGT. Types of releases include:
Rapid Release - thirty-one days or less, is not prearranged, requires
bidding and is restricted to options 1 or 2 for the allocation of
Parcels without special terms or conditions. A standard recall
provision may be selected. (Capacity up to the full quantity of the
release maybe recallable on 2 business days notice. This capacity may
be returned to the Replacement Shipper on 2 business days notice.
Replacement Shipper may refuse to accept such capacity returned in
this fashion.)
Standard Release - greater than or equal to one day, is not
prearranged, and requires bidding.
Prearranged Deal-A - less than or equal to thirty-one days. This type
of release is prearranged and does not require bidding. Such
prearranged deals shall be posted for informational purposes within 48
hours after the release transaction commences. This release cannot be
rolled-over, renewed or otherwise extended beyond the term described
above unless the Releasing Shipper follows the posting and bidding
procedures that apply to the particular term sought contained in this
Paragraph 28. The Releasing Shipper may not re-release this Parcel to
the same Replacement Shipper until 28 days after the term of the
initial release has ended. Rollovers are permitted without bidding or
a waiting period provided the Prearranged Shipper agrees to pay the
maximum rate and meet all the other terms and conditions of the
release.
Prearranged Deal-B - greater than or equal to thirty-one days at the
maximum rate bid pursuant to the methodology selected by Releasing
Shipper. This type of release is prearranged and does not require
bidding.
Prearranged Deal-C - greater than or equal to one day at a rate less
than the maximum rate bid pursuant to the methodology selected by the
Releasing Shipper. This type of release is prearranged, allows for
bidding, and allows the right of first refusal.
(Continued)
________________________________________________________________________________
Issued by: R.T. Howard, Mgr. Gas Supply & Reg. Affairs
Issued on: JUNE 19, 1995 Effective: JULY 10, 1995
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RM95-5-00, dated MAY 31, 1995
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff Second Revised Sheet No. 91
First Revised Volume No. 1-A Superseding
First Revised Sheet No. 91
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
28. CAPACITY RELEASE (Continued)
28.3 Notice Requirements
Any Releasing Shipper electing to release capacity shall submit a
notice via PGT's EBB that it elects to release firm capacity.
The notice shall set forth the following information:
(a) Releasing Shipper's legal name, contract number, and the
name, title, address, telephone number, and fax number of
the individual responsible for authorizing the release of
capacity.
(b) Rate schedule of the Releasing Shipper.
(c) Whether bidders will bid on the reservation charge or a
volumetric equivalent of the maximum reservation charge
applicable to the Parcel on a 100% load-factor basis. If a
volumetric rate is used, Releasing Shipper must indicate
whether bids on a reservation charge basis will be accepted
as well and if so must specify the method of evaluating the
two types of bids. Releasing Shipper also should indicate
whether bids will be accepted on a dollar basis or as a
percentage of the Releasing Shipper's as-billed rate.
(d) Daily quantity of capacity to be released, expressed in
MMBtu/d, at the designated delivery point(s). (This must
not exceed Releasing Shipper's maximum contract demand
available for capacity release and shall state the minimum
quantity expressed in MMBtu/d acceptable for release.)
(Continued)
________________________________________________________________________________
Issued by: R.T. Howard, Manager, Rates and Regulatory Affairs
Issued on: AUGUST 13, 1996 Effective: SEPTEMBER 13, 1996
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff First Revised Sheet No. 92
First Revised Volume No. 1-A Superseding
Original Sheet No. 92
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
28. CAPACITY RELEASE (Continued)
28.3 Notice Requirements (Continued)
(e) The term of the release, identifying the date release is to
begin and terminate. The minimum release term acceptable to
PGT shall be one day.
(f) Whether the Releasing Shipper is willing to consider release
for a shorter period of time than that specified in (e) above
and if so, the minimum acceptable period of release.
(g) The receipt and delivery point.
(h) Whether Option 1, 2, or 3 shall be used to determine the
highest valued bid. If Option 3 is selected, Releasing
Shipper must describe the criteria by which bids are to be
evaluated.
(i) Whether the Releasing Shipper wants PGT to market its
released capacity.
(j) Whether the Releasing Shipper requests to waive the
creditworthiness requirements and agrees in such event to
remain liable for all charges, or, if the release is for one
year (365 days) or less, whether Releasing Shipper requests
that the creditworthiness provisions of Paragraph
18.3(A)(1)(c) shall apply.
(k) Whether Releasing Shipper is a marketing or other affiliate
of PGT.
(l) If release is a prearranged release, the Prearranged Shipper
must be qualified pursuant to the criteria of Paragraph
28.6(a) unless waived above. Releasing Shipper shall include
the Prearranged Shipper bid information pursuant to Paragraph
28.6(b) with its release information and shall indicate
whether the Prearranged Shipper is affiliated with PGT or the
Releasing Shipper.
(m) Any special nondiscriminatory terms and conditions applicable
to the release.
(Continued)
________________________________________________________________________________
Issued by: P.G. Rosput, Senior Vice President
Issued on: MAY 31, 1994 Effective: MAY 21, 1994
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RP94-211-000, dated MAY 20, 1994
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff Substitute Original Sheet No. 93
First Revised Volume No. 1-A Superseding
Original Sheet No. 93
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
28. CAPACITY RELEASE (Continued)
28.3 Notice Requirements (Continued)
(n) Tie-breaker method preferred: (1) pro rata, (2) lottery,
(3) order of submission (first-come/first-serve), (4) other.
Other method must be objectively stated, administratively
feasible as determined by PGT and nondiscriminatory. If
none are selected, the system defaults to pro rata.
(o) Recall provisions. These provisions must be objectively
stated, nondiscriminatory, applicable to all bidders,
operationally and administratively feasible as determined by
PGT and in accordance with PGT's tariff.
(p) The minimum rate (percentage of: reservation charge or a
volumetric equivalent of the maximum reservation charge
applicable to the Parcel on a 100% load-factor basis)
acceptable to Releasor for this Parcel. Releasing Shipper
also should indicate whether bids will be accepted on a
dollar basis or as a percentage of the Releasing Shipper's
as-billed rate.
(q) Whether the Releasing Shipper is willing to accept
contingent bids that extend beyond the close of the Bid
Period and, if so, any nondiscriminatory terms and
conditions applicable to such contingencies including the
date by which such contingency must be satisfied (which date
shall not be later than the last day upon which PGT must
award capacity) and whether, or for what time period, the
next highest bidder(s) will be obligated to acquire the
capacity should the winning contingent bidder be unable to
satisfy the contingency specified in its bid.
(r) Whether the Releasing Shipper wants to specify a longer
bidding period for its Parcel than specified at Paragraph
28.8.
(Continued)
________________________________________________________________________________
Issued by: R.T. Howard, Manager, Rates and Regulatory Affairs
Issued on: AUGUST 13, 1996 Effective: SEPTEMBER 13, 1996
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff Substitute Original Sheet No. 94
First Revised Volume No. 1-A Superseding
Original Sheet No. 94
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
28. CAPACITY RELEASE (Continued)
28.4 Marketing of Capacity Fee
PGT may act as a facilitator between a Releasing Shipper and a
Replacement Shipper(s) that wishes to contract for that Releasing
Shipper's capacity. All such Parcels must be posted on the EBB
initially. A posting of a Parcel facilitated by PGT will include
both the Parcel by the Releasing Shipper and the bid by the
Prearranged Shipper. A marketing of capacity fee shall be
negotiated between PGT and Releasing Shipper in a
nondiscriminatory manner. Such a fee will apply when: a
Releasing Shipper requests PGT to market released capacity, PGT
actively markets such capacity beyond posting on the EBB, and such
marketing results in capacity being released to a Replacement
Shipper.
28.5 Posting of a Parcel
The posting of a Parcel constitutes an offer to release the
capacity provided a willing Replacement Shipper submits a valid
bid consistent with PGT's Transportation General Terms and
Conditions. The posting must contain the information contained in
Paragraph 28.3. Any specific conditions posted by the Releasing
Shipper must be operationally feasible, nondiscriminatory to other
shippers, and in conformance with PGT's tariffs. If the Parcel is
being released as a secondary release, then any recall provisions
included in the primary release which may affect the re-release of
this capacity must be included in the terms and conditions of the
secondary release. Each Parcel will be reviewed by PGT prior to
posting on the EBB for bidding. The receipt of a valid release
will be acknowledged by the issuance of a release confirmation to
the Releasing Shipper's EBB mailbox by PGT.
It is the Releasing Shipper's sole responsibility to provide
release and Prearranged Shipper bid information in advance of the
close of the Posting Period.
(Continued)
________________________________________________________________________________
Issued by: P.G. Rosput, Senior Vice President
Issued on: OCTOBER 13, 1993 Effective: NOVEMBER 01, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-46-000, et al., dated OCTOBER 01, 1993
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff Original Sheet No. 95
First Revised Volume No. 1-A
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
28. CAPACITY RELEASE (Continued)
28.5 Posting of a Parcel (Continued)
Releasing Shippers who elect to release capacity and select Option
3 for the highest valued bid methodology and/or include, in their
release, nondiscriminatory recall provisions and/or special terms
and conditions are required to submit their request to release
capacity by 12:00 p.m. Pacific Time at least two business days
before the close of the Posting Period. This is to ensure
adequate time for PGT to review and validate that the Option 3
criteria and/or any recall and special terms and conditions are
not discriminatory.
All Prearranged Shipper bids are subject to the Prearranged
Shipper(s) meeting the preliminary qualifications as defined in
Paragraph 28.6(a) for Replacement Shippers.
A Parcel may be revised or withdrawn by the Releasing Shipper at
any time prior to the close of the Posting Period. A Parcel
cannot be revised after the close of the Posting Period. Parcels
may be withdrawn subsequent to the close of the Posting Period and
up until the close of the Bid Period only in situations where the
Releasing Shipper has an unanticipated need for the capacity. In
such instances, Releasing Shipper shall notify PGT via the EBB of
its need to withdraw the Parcel due to an unanticipated need for
the capacity. The withdrawal or revision of a Parcel will
terminate all bids submitted for that Parcel to date. Replacement
Shippers will need to resubmit their bids for the Parcel if the
Parcel is resubmitted for release.
(Continued)
________________________________________________________________________________
Issued by: P.G. Rosput, Senior Vice President
Issued on: AUGUST 02, 1993 Effective: NOVEMBER 01, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-46-000, et al., dated JULY 12, 1993
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff Original Sheet No. 96
First Revised Volume No. 1-A
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
28. CAPACITY RELEASE (Continued)
28.6 Bidding for a Parcel
(a) Preliminary Qualification
To bid for a Parcel, a Replacement Shipper must: pre-qualify
by submitting a completed request for authority to bid for a
Parcel, meet PGT's credit criteria, and execute an FTS-1
service agreement for capacity release as set forth in these
Transportation General Terms and Conditions.
Replacement Shippers may carry out these requirements through
the use of PGT's EBB. Replacement Shippers are encouraged to
pre-qualify in advance of any postings on PGT's EBB as credit
requirements will take differing amounts of time to process
depending on the particular financial profile of Replacement
Shippers. The pre-qualification process will authorize a
pre-set maximum monthly financial exposure level for the
Replacement Shipper. Such exposure levels may be adjusted by
PGT periodically re-evaluating a Replacement Shipper's
credit-worthiness.
Releasing Shippers may exercise their option to waive the
credit requirements for any Replacement Shipper wishing to
bid on a Parcel posted by that Releasing Shipper. Such
waiver must be made on a nondiscriminatory basis. PGT must
be informed of such waiver via the EBB before it will
authorize such Replacement Shipper's participation with
respect to that particular Parcel. In this instance, no pre-
set maximum monthly financial exposure level is applicable.
Should a Releasing Shipper waive the credit requirements for
a Replacement Shipper, the Releasing Shipper shall be liable
for all charges incurred by the Replacement Shipper in the
event such Replacement Shipper defaults on payment to PGT for
such capacity release service. (Continued)
________________________________________________________________________________
Issued by: P.G. Rosput, Senior Vice President
Issued on: AUGUST 02, 1993 Effective: NOVEMBER 01, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-46-000, et al., dated JULY 12, 1993
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff Original Sheet No. 97
First Revised Volume No. 1-A
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
28. CAPACITY RELEASE (Continued)
28.6 Bidding for a Parcel (Continued)
(a) Preliminary Qualification (Continued)
The execution of the FTS-1 service agreement for capacity
release is to be signed "electronically" by the Replacement
Shipper. The Replacement Shipper shall execute the FTS-1
service agreement for capacity release (exhibits excluded)
through the use of an authorization code procedure on the
EBB.
Upon notification by PGT of an award of a Parcel, PGT shall
complete Exhibit R with the particulars of the awarded Parcel
and Replacement Shipper shall execute, electronically,
Exhibit R to the FTS-1 service agreement for capacity
release.
A hard copy of the FTS-1 service agreement for capacity
release, including Exhibit R (signed by hand by PGT and
Replacement Shipper), will follow subsequent to the awarding
of a Parcel.
A Replacement Shipper that subsequently obtains additional
Parcels is not required to execute an additional FTS-1
service agreement for capacity release; rather, for each such
additional Parcel obtained, an additional Exhibit R
(designated sequentially "Exhibit R-2", "Exhibit R-3", etc.)
will be executed and amended to such Replacement Shipper's
FTS-1 service agreement for capacity release.
Once the Replacement Shipper has met PGT's preliminary
contractual and credit requirements, PGT will amend the
Replacement Shipper's authorization to add access to the
bidding and releasing portions of PGT's capacity release
program on its EBB. This authorization, in combination with
the Replacement Shipper's password, which will be unique and
known only by the Replacement Shipper, will entitle the
(Continued)
________________________________________________________________________________
Issued by: P.G. Rosput, Senior Vice President
Issued on: AUGUST 02, 1993 Effective: NOVEMBER 01, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-46-000, et al., dated JULY 12, 1993
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff Original Sheet No. 98
First Revised Volume No. 1-A
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
28. CAPACITY RELEASE (Continued)
28.6 Bidding for a Parcel (Continued)
(a) Preliminary Qualification (Continued)
Replacement Shipper to submit a bid for a Parcel. Once a
Replacement Shipper has acquired capacity, authority is
granted to the Replacement Shipper to release that capacity.
The execution of the FTS-1 service agreement for capacity
release and use of this authorization to submit a bid or to
release capacity will constitute an obligation on the part of
the Replacement Shipper to be bound by the terms and
conditions of PGT's capacity release program as set forth in
these Transportation General Terms and Conditions.
(b) Submitting a Bid
All bids must be submitted through the use of PGT's EBB.
Such bids shall be "open" for all participants to review.
The particulars of all bids will be available for review but
not the identity of bidders. PGT will post the identity of
the winning bidder(s) only.
A Replacement Shipper cannot request that its bid be
"closed", nor can a Releasing Shipper specify that "closed"
bids be submitted on its releases. A Replacement Shipper
may submit only one bid per Parcel posted at any one point in
time. Bids received after the close of the Bid Period shall
be invalid. The Replacement Shipper may bid for no more than
the quantity of the Parcel posted by the Releasing Shipper.
Simultaneous bids for more than one Parcel are permitted.
(Continued)
________________________________________________________________________________
Issued by: P.G. Rosput, Senior Vice President
Issued on: AUGUST 02, 1993 Effective: NOVEMBER 01, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-46-000, et al., dated JULY 12, 1993
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff Original Sheet No. 99
First Revised Volume No. 1-A
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
28. CAPACITY RELEASE (Continued)
28.6 Bidding for a Parcel (Continued)
(b) Submitting a Bid (Continued)
A valid bid to contract for a Parcel must contain the
following information:
(1) Replacement Shipper's legal name, address, telephone and
fax numbers and the name and title of the individual
responsible for authorizing the bid.
(2) The identification of the Parcel bid on.
(3) Term of service requested. The term of service must not
exceed the term included in the Parcel.
(4) Percentage of the applicable maximum rate, as identified
in the Parcel, that Replacement Shipper is willing to
pay. A Replacement Shipper may not bid below the
minimum applicable charge or rate nor above the maximum
authorized charge or rate for the Parcel.
(5) The quantity desired not to exceed the quantity
contained in the Parcel, expressed on a MMBtu/d
delivered basis and greater than the minimum quantity
acceptable to Replacement Shipper.
(6) Under Options 1 or 2 acceptance or rejection of all
recall provisions and special nondiscriminatory terms
and conditions of service associated with the release.
Rejection of any terms results in an invalid bid.
(7) Whether or not Replacement Shipper is an affiliate of
the Releasing Shipper.
(8) A statement as to whether or not Replacement Shipper is
affiliated with PGT.
(Continued)
________________________________________________________________________________
Issued by: P.G. Rosput, Senior Vice President
Issued on: AUGUST 02, 1993 Effective: NOVEMBER 01, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-46-000, et al, dated JULY 12, 1993
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff Original Sheet No. 100
First Revised Volume No. 1-A
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
28. CAPACITY RELEASE (Continued)
28.6 Bidding for a Parcel (Continued)
(b) Submitting a Bid (Continued)
(9) An affirmative statement that Replacement Shipper agrees
to be bound by the terms and conditions of Rate Schedule
FTS-1 and PGT's capacity release provisions in its
tariff.
(10) Whether the bid is a contingent bid and the
contingencies which must be satisfied by the date
specified by the Releasing Shipper in its posting of the
Parcel.
(c) Confirmation of Bids
The receipt of a valid bid by PGT will be acknowledged by the
issuance of a bid confirmation to the Replacement Shipper's
EBB mailbox by PGT. It is the Replacement Shipper's sole
responsibility to verify the correctness of the submitted bid
and to take any corrective action necessary by resubmitting a
bid when notified of an invalid or incomplete bid by PGT via
the EBB. This must be done before the close of the Bid
Period.
(d) Withdrawn or Revision of Bids
A previously submitted bid may be withdrawn or revised and
resubmitted at any time prior to the close of the Bid Period
with no obligation on the Replacement Shipper's part.
Resubmitted bids must be equal to or greater in value than
the initial bids. Lower valued bids will be invalid.
(Continued)
________________________________________________________________________________
Issued by: P.G. Rosput, Senior Vice President
Issued on: AUGUST 02, 1993 Effective: NOVEMBER 01, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-46-000, et al., dated JULY 12, 1993
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff Original Sheet No. 101
First Revised Volume No. 1-A
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
28. CAPACITY RELEASE (Continued)
28.7 Allocation of Parcels
(a) Primary Allocation
Winning bids for Parcels shall be awarded based on one of
the following three options to be selected by the
Releasing Shipper when posting a Parcel:
Option 1 - Price
Bids will be given priority based on the maximum rate bid
as represented by a Replacement Shipper's bid of the
percentage of: the maximum authorized reservation charge
or a volumetric equivalent of the maximum reservation
charge applicable to the Parcel on a 100% load factor
basis. Releasing Shippers using a volumetric rate and
wishing to accept reservation charge bids will be
considered an Option 3 criteria. In this instance
Releasing Shipper must define the method for evaluating
such bids. A bid queue will be maintained for each
individual Parcel.
Option 2 - Net Present Value
Bids will be given priority based on the net present value
per MMBtu for the term of the bid according to the
following formula:
n
(1 + i) -1
Present Value per unit = P * R * _________
n
i (1 + i)
where: P = percent of the rate or charge that the
Replacement Shipper is willing to pay.
(Continued)
________________________________________________________________________________
Issued by: P.G. Rosput, Senior Vice President
Issued on: AUGUST 02, 1993 Effective: NOVEMBER 01, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-46-000, et al., dated JULY 12, 1993
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff Original Sheet No. 102
First Revised Volume No. 1-A
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
28. CAPACITY RELEASE (Continued)
28.7 Allocation of Parcels (Continued)
(a) Primary Allocation (Continued)
R = Rate or charge calculated as: The maximum authorized
reservation charge (or a volumetric equivalent of the maximum
reservation charge applicable to the Parcel on a 100% load
factor basis) in effect at the time of the bid for service
from the same receipt point to the same delivery point under
the Releasing Shipper's rate schedule.
i = FERC's annual interest rate divided by 12.
n = number of periods for which the bidder wishes to
contract, not to exceed the maximum periods to be released by
the Releasing Shipper. For releases greater than or equal to
one month, the period is the number of months. For releases
less than one month the period is the number of days.
A bid queue will be maintained for each individual Parcel.
Option 3 - Releasing Shipper's Criteria for Highest Valued
Bids
Bids will be given priority based on the criteria established
by the Releasing Shipper for determining the highest valued
bids. The criteria must be objectively stated, applicable to
all potential bidders, operationally and administratively
feasible as determined by PGT, nondiscriminatory, and in
conformance with PGT's tariff. A bid queue will be
maintained for each individual Parcel.
If Releasing Shipper does not specify an option for
determining best bid, Option 2 will be the default option
used.
Under all options, PGT will evaluate and rank all bids for
Parcels.
(Continued)
________________________________________________________________________________
Issued by: P.G. Rosput, Senior Vice President
Issued on: AUGUST 02,1993 Effective: NOVEMBER 01, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-46-000, et al., dated JULY 12, 1993
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff First Revised Sheet No. 103
First Revised Volume No. 1-A Superseding
Original Sheet No. 103
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
28. CAPACITY RELEASE (Continued)
28.7 Allocation of Parcels (Continued)
(b) Right of First Refusal
In the case of a Prearranged Shipper's bid for a Parcel with
a term equal to one month or greater, at a rate other than
at the highest valued bid, pursuant to the methodology
specified by the Releasing Shipper, if the bid submitted by
a subsequent Replacement Shipper exceeds the value of the
Prearranged Shipper's bid, the Prearranged Shipper will be
allowed to match the higher valued bid. The Prearranged
Shipper will be allowed 1 business day from the close of
the Bid Reconciliation Period to match the higher valued
bid, otherwise, the allocation will be awarded to
subsequent Replacement Shipper(s) in accordance with the
primary and secondary allocation mechanisms.
(c) Secondary Allocation
To the extent there is more than one Replacement Shipper
submitting a winning bid, the Parcel shall be allocated
based on one of the following tie-breaker methodologies to
be selected by the Releasing Shipper: pro rata, lottery,
order of submission (first come/first serve), or by a method
designated by the Releasing Shipper. Releasing Shipper's
method must be objectively stated, applicable to all
bidders, nondiscriminatory, administratively feasible as
determined by PGT and in accordance with PGT's tariffs.
(Continued)
________________________________________________________________________________
Issued by: P.G. Rosput, Senior Vice President
Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff Original Sheet No. 104
First Revised Volume No. 1-A
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
28. CAPACITY RELEASE (Continued)
28.7 Allocation of Parcels (Continued)
(d) Confirmation of Allocation
Upon each completion of an allocation, the successful
Replacement Shipper(s) will be notified of the terms under
which they have contracted for the awarded Parcel. The
notification will be provided in the form of a notice in the
Replacement Shipper's EBB mailbox. The notice will include
an Exhibit R to the Replacement Shipper's Rate Schedule FTS-1
service agreement for capacity release which specifies the
pertinent terms of the Replacement Shipper's bid as well as
any additional terms specified by the Releasing Shipper. The
Releasing Shipper will be notified of the terms under which
its Parcel has been awarded. The notification will be
provided in the form of a notice in the Releasing Shipper's
EBB mailbox. The notification will include an Exhibit C to
the Releasing Shipper's service agreement which specifies the
pertinent terms of the credit to be applied to the Releasing
Shipper as a result of the awarding of Parcel to the
Replacement Shipper(s). In the case of multiple Replacement
Shippers and Parcels, an Exhibit C to the Releasing Shippers'
service agreement will be generated for each Parcel and
Replacement Shipper. The Exhibit C's shall be numbered
sequentially as Exhibit C-1, C-2, etc.
(e) Purging of Expired Bids
All unfulfilled bids, as well as any unfulfilled portions of
bids which receive a partial award, will become ineffective
as of the completion of bid reconciliation and the close of
the Bid Period. Each unsuccessful Replacement Shipper which
has bid shall receive a notice in its EBB mailbox indicating
the ineffectiveness of the bid.
(Continued)
________________________________________________________________________________
Issued by: P.G. Rosput, Senior Vice President
Issued on: AUGUST 02, 1993 Effective: NOVEMBER 01, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-46-000, et al., dated JULY 12, 1993
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff First Revised Sheet No. 105
First Revised Volume No. 1-A Superseding
Original Sheet No. 105
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
28. CAPACITY RELEASE (Continued)
28.7 Allocation of Parcels (Continued)
(e) Purging of Expired Bids (Continued)
Information regarding all bids for all Parcels shall be archived
off-line before being purged from the system.
28.8 Scheduling of Parcels, Bids and Notifications
(a) Rapid Release - one month or less, not prearranged.
Posting Period - up to 12:00 p.m. Pacific Time on the 2nd
business day before the commencement of the Release Term.
Bid Period - a minimum period of 2 hours subsequent to the close
of the Posting Period. The bid period may be extended by the
Releasing Shipper. The Bid Period closes at 2:00 p.m. Pacific
Time on the 2nd business day before the commencement of the
Release Term. Notification of the results of the bidding for
Parcels will be posted at 2:00 p.m. Pacific Time on the 2nd
business day prior to the commencement of the Release Term.
(b) Standard Release-greater than or equal to one day, not
prearranged.
Posting Period - up to 12:00 p.m. Pacific Time 5 business days
prior to the commencement of the Release Term.
Bid Period - a minimum period of 1 business day subsequent to the
close of the Posting Period. The Bid Period closes at 2:00 p.m.
Pacific Time 4 business days prior to the commencement of the
Release Term.
Bid Reconciliation Period - a period of 2 business days
subsequent to the close of the Bid Period. The Bid
Reconciliation Period closes at 2:00 p.m. Pacific Time 2 business
days prior to the commencement of the Release Term at which time
notification of the results of the bidding for Parcels will be
posted.
(Continued)
________________________________________________________________________________
Issued by: P.G. Rosput, Senior Vice President
Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff Sub. Second Revised Sheet No. 106
First Revised Volume No. 1-A Superseding
First Revised Sheet No. 106
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
28. CAPACITY RELEASE (Continued)
28.8 Scheduling of Parcels, Bids and Notifications (Continued)
(c) Prearranged Deal-A - less than or equal to thirty-one days.
Releasing Shipper must inform PGT via the EBB of the particulars
of the prearranged deal by 12:00 p.m. Pacific Time on the 2nd
business day before the commencement of the Release Term.
Posting Period - PGT will post the particulars of the prearranged
deal no later than 12:00 p.m. Pacific Time 2 business days after
the commencement of the Release Term.
(d) Prearranged Deal-B - equal to or greater than thirty-one days at
the highest valued bid pursuant to the methodology selected by
the Releasing Shipper.
Posting Period - Releasing Shipper must submit the particulars of
the prearranged deal to PGT for posting on the EBB no later than
12:00 p.m. Pacific Time 2 business days before the commencement
of the Release Term.
(e) Prearranged Deal-C - greater than or equal to one day.
Posting Period - up to 12:00 p.m. Pacific Time on the 6th
business day before the commencement of the Release Term.
Bid Period - a minimum period of 1 business day subsequent to the
close of the Posting Period. The Bid Period closes at 2:00 p.m.
Pacific Time on the 5th business day before the commencement of
the Release Term.
Bid Reconciliation Period - a period of 2 business days
subsequent to the close of the Bid Period. The Bid
Reconciliation Period closes at 2:00 p.m. Pacific Time on the 3rd
business day before the commencement of the Release Term.
(Continued)
________________________________________________________________________________
Issued by: R.T. Howard, Mgr. Gas Supply & Reg. Affairs
Issued on: JUNE 19, 1995 Effective: JULY 10, 1995
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RM95-5-000, dated MAY 31, 1995
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff First Revised Sheet No. 107
First Revised Volume No. 1-A Superseding
Original Sheet No. 107
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
28. CAPACITY RELEASE (Continued)
28.8 Scheduling of Parcels, Bids and Notifications (Continued)
(e) Prearranged Deal-C - greater than or equal to one day (Continued)
Match Period - a period of 1 business day subsequent to the close
of the Bid Reconciliation Period. The Match Period closes at
2:00 p.m. Pacific Time on the 2nd business day before the
commencement of the Release Term. At that time results of the
bidding shall be posted no later than 2:00 p.m. Pacific Time on
the 2nd business day before the commencement of the Release Term.
(Continued)
________________________________________________________________________________
Issued by: P.G. Rosput, Senior Vice President
Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff First Revised Sheet No. 108
First Revised Volume No. 1-A Superseding
Original Sheet No. 108
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
Reserved For Future Use.
________________________________________________________________________________
Issued by: P.G. Rosput, Senior Vice President
Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff First Revised Sheet No. 109
First Revised Volume No. 1-A Superseding
Original Sheet No. 109
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
28. CAPACITY RELEASE (Continued)
28.9 Crediting, Billing Adjustments and Refunds
(a) Eligibility
PGT shall provide revenue credits to any Releasing Shipper which
releases capacity to a Replacement Shipper pursuant to the
provisions of Paragraph 28.
(b) Monthly Crediting Procedure
Revenue credits for released capacity shall be credited monthly
as an offset to a Releasing Shipper's reservation charge (or the
volumetric equivalent of the reservation charge on a 100% load-
factor basis applicable to the Releasing Shipper. This shall
also be referred to in this Paragraph 28.9 as the equivalent
volumetric rate) payable to PGT under the applicable rate
schedule for the service that has been released. PGT shall
credit each month to the Releasing Shipper's account 100% of the
revenues from the charges invoiced to the Replacement Shipper(s)
for the reservation charge (or equivalent volumetric rate).
(c) Billing Adjustments
PGT shall apply the revenues received from Replacement Shippers
first to the reservation charge (or equivalent volumetric rate),
next to the GRI reservation surcharge.
Should Replacement shipper default on payment to PGT of the
reservation charge (or equivalent volumetric rate) PGT shall bill
Releasing Shipper for such unpaid charges and apply interest to
such adjustments in accordance with the provisions of Paragraph 8
of the Transportation General Terms and Conditions.
(Continued)
________________________________________________________________________________
Issued by: R.T. Howard, Manager, Rates and Regulatory Affairs
Issued on: AUGUST 13, 1996 Effective: SEPTEMBER 13, 1996
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff Original Sheet No. 110
First Revised Volume No. 1-A
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
28. CAPACITY RELEASE (Continued)
28.9 Crediting, Billing Adjustments and Refunds (Continued)
(d) Excess Revenue Credits
Releasing Shipper is entitled to excess revenue credits resulting
when the reservation charge (or equivalent volumetric rate)
revenues actually received by PGT from the Replacement Shipper(s)
exceed the reservation charge (or equivalent volumetric rate)
revenues which would have been received by PGT from the Releasing
Shipper if capacity was not released.
(e) Refunds
PGT shall track all changes in its rates approved by the
Commission. In the event the Commission orders refunds of any
such rates charged by PGT and previously approved, PGT shall make
corresponding refunds to all affected Shippers including Shippers
receiving capacity release service.
In such instances when rates to Replacement Shippers are reduced,
PGT shall make corresponding adjustments to the crediting of
revenues to Releasing Shippers for the period such refunds are
payable.
(Continued)
________________________________________________________________________________
Issued by: P.G. Rosput, Senior Vice President
Issued on: AUGUST 02, 1993 Effective: NOVEMBER 01, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-46-000, et al., dated JULY 12, 1993
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff First Revised Sheet No. 111
First Revised Volume No. 1-A Superseding
Original Sheet No. 111
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
28. CAPACITY RELEASE (Continued)
(STANDARD RELEASE)
SEE GRAPHIC INDEX AT REAR OF DOCUMENT.
(CAPACITY RELEASE TIMELINE GRAPH)
________________________________________________________________________________
Issued by: P.G. Rosput, Senior Vice President
Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff First Sheet No. 112
First Revised Volume No. 1-A Superseding
Original Sheet No. 112
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
28. CAPACITY RELEASE (Continued)
(RAPID RELEASE)
SEE GRAPHIC INDEX AT REAR OF DOCUMENT.
(CAPACITY RELEASE TIMELINE GRAPH)
________________________________________________________________________________
Issued by: P.G. Rosput, Senior Vice President
Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff Sub. Second Revised Sheet No. 113
First Revised Volume No. 1-A Superseding
First Revised Sheet No. 113
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
28. CAPACITY RELEASE (Continued)
(PRE-ARRANGED DEAL - A)
SEE GRAPHIC INDEX AT REAR OF DOCUMENT.
(CAPACITY RELEASE TIMELINE GRAPH)
________________________________________________________________________________
Issued by: R.T. Howard, Mgr. Gas Supply & Regulatory Affairs
Issued on: JUNE 19, 1995 Effective: JULY 10, 1995
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RM95-5-000, dated MAY 31, 1995
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff Sub. Second Revised Sheet No. 114
First Revised Volume No. 1-A Superseding
First Revised Sheet No. 114
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
28. CAPACITY RELEASE (Continued)
(PRE-ARRANGED DEAL - B)
SEE GRAPHIC INDEX AT REAR OF DOCUMENT.
(CAPACITY RELEASE TIMELINE GRAPH)
________________________________________________________________________________
Issued by: R.T. Howard, Mgr. Gas Supply & Reg. Affairs
Issued on: JUNE 19, 1995 Effective: JULY 10, 1995
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RM95-5-000, dated MAY 31, 1995
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff First Revised Sheet No. 115
First Revised Volume No. 1-A Superseding
Original Sheet No. 115
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
28. CAPACITY RELEASE (Continued)
(PRE-ARRANGED DEAL - C)
SEE GRAPHIC INDEX AT REAR OF DOCUMENT.
(CAPACITY RELEASE TIMELINE GRAPH)
________________________________________________________________________________
Issued by: P.G. Rosput, Senior Vice President
Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff First Revised Sheet No. 116
First Revised Volume No. 1-A Superseding
Sheet Nos. 116 - 118
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
Reserved For Future Use
________________________________________________________________________________
Issued by: P.G. Rosput, Senior Vice President
Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff First Revised Sheet No. 119
First Revised Volume No. 1-A Superseding
Original Sheet No. 119
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
29. FLEXIBLE RECEIPT AND DELIVERY POINTS
29.1 Firm Service
(a) Addition of a Receipt Point
Any firm Shipper receiving service under Part 284 of the
Commission's regulations is entitled to use the receipt point
specified in its service agreement as a primary receipt point. A
firm Shipper may add a secondary receipt point, provided the
secondary receipt point is downstream of the primary receipt
point at any time during the life of the contract.
Firm Shippers who are billed under a reservation charge and a
delivery rate will continue to be billed reservation charges
based on the primary receipt point while delivery rates,
including fuel, will be calculated on the receipt point actually
used.
To the extent additional meter station capacity or other
facilities are required to effect the receipt point change, PGT
will construct the additional capacity consistent with Paragraph
18.5.
(b) Changing a Receipt Point
A firm Shipper may change primary receipt points to a downstream
receipt point but will continue to be billed reservation charges
based on the original primary receipt point. Changes in receipt
points will be permitted provided sufficient receipt point
capacity exists at the receiving meter station and subject to any
operating constraints. To the extent additional meter station
capacity or other facilities are required to effect the receipt
point change, PGT will construct the additional capacity at the
firm Shipper's expense consistent with Paragraph 18.5.
(Continued)
________________________________________________________________________________
Issued by: P.G. Rosput, Senior Vice President
Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff First Revised Sheet No. 120
First Revised Volume No. 1-A Superseding
Original Sheet No. 120
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
29. FLEXIBLE RECEIPT AND DELIVERY POINTS (Continued)
29.1 Firm Service (Continued)
(c) Addition of a Delivery Point
Each firm Shipper is entitled to an allocation of its MDQ to a
delivery point(s) as its primary delivery point(s).
A firm Shipper may add secondary delivery points provided the
secondary delivery points are upstream of the primary delivery
point, at any time during the life of the contract. In this
case, the firm Shipper will continue to be billed any applicable
reservation charges based on the primary delivery point; however,
delivery rates, including fuel, will be calculated based on the
delivery point actually used.
A firm Shipper with primary deliveries allocated to a minor
delivery point may add secondary delivery points to its contract
provided that the addition of the secondary delivery point does
not materially impact service to other firm Shippers.
To the extent additional meter station capacity is required to
effect the delivery point(s) change, and subject to any operating
constraints PGT will construct the additional capacity consistent
with Paragraph 18.5.
(Continued)
________________________________________________________________________________
Issued by: P.G. Rosput, Senior Vice President
Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff First Revised Sheet No. 121
First Revised Volume No. 1-A Superseding
Original Sheet No. 121
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
29. FLEXIBLE RECEIPT AND DELIVERY POINTS (Continued)
29.1 Firm Service (Continued)
(d) Changing a Delivery Point
A firm Shipper may change primary delivery points, to an upstream
delivery point but will continue to be billed reservation charges
based on the original primary delivery point. Changes in
delivery points will be permitted provided sufficient delivery
point capacity exists at the delivery meter station. To the
extent additional meter station and subject to any operating
constraints capacity is required to effect the delivery point
change, PGT will construct the additional capacity at the firm
Shipper's expense consistent with Paragraph 18.5.
A firm Shipper with primary deliveries allocated to a minor
delivery point may change primary delivery points in its contract
provided that the change of primary delivery point does not
materially impact service to other firm Shippers.
29.2 Interruptible Service
(a) Change of a Receipt/Delivery Point
Interruptible Shippers will have the right to flexible receipt
and delivery points, at a lower priority than firm or released
services.
(b) Addition of a Receipt Point
Except as otherwise provided in this paragraph, Shippers
receiving service under any Part 284 interruptible transportation
rate schedule may add any receipt point downstream of the primary
receipt point on the PGT system at any time during the life of
the contract with no effect on the Interruptible Shipper's
previously granted interruptible transportation priority.
However, requests by an interruptible Shipper to increase its
total MDQ and/or to add an upstream receipt point will be
considered a new request for service.
(Continued)
________________________________________________________________________________
Issued by: P.G. Rosput, Senior Vice President
Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff First Revised Sheet No. 122
First Revised Volume No. 1-A Superseding
Original Sheet No. 122
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
29. FLEXIBLE RECEIPT AND DELIVERY POINTS (Continued)
29.2 Interruptible Service (Continued)
(c) Addition of a Delivery Point
An Interruptible Shipper may request interruptible service at
additional delivery points at any time. The request of an
additional downstream delivery point, or a request to increase
the delivery quantity at an existing delivery point, will be
considered a new request for service with priority assigned in
accordance with Paragraph 19.2.
(Continued)
________________________________________________________________________________
Issued by: P.G. Rosput, Senior Vice President
Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff Original Sheet No. 123
First Revised Volume No. 1-A
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
30. GAS SUPPLY RESTRUCTURING TRANSITION COSTS
30.1 Purpose
This Paragraph 30 establishes the means by which PGT shall recover GSR
Costs. PGT will make one or more separate rate filings to recover GSR
Costs pursuant to this Paragraph 30.
30.2 Definitions
The following defines certain terms as they are used in this Paragraph
30:
(a) "Gas Supply Restructuring Costs" shall mean amounts in cash or
other consideration eligible for recovery under Order Nos. 500, et
seq., or 528, et seq., or 636, et seq., or which are incurred to
restructure, reform or terminate the existing International
Contract between PGT and A&S and underlying A&S gas supply
contracts, or to resolve claims by Canadian gas suppliers related
to past or future liabilities or obligations of PGT or A&S under
the International Contract and underlying A&S gas supply
contracts.
(b) "The Initial GSR Cost Collection Period" will consist of the three
(3) years commencing with the effective date of the rate filing to
recover GSR Costs. An Initial GSR Cost Collection Period shall
apply to each rate filing PGT makes to recover GSR Costs.
(c) "Carryover GSR Cost Collection Period" will consist of the
extension of the Initial GSR Collection Period in accordance with
Paragraph 30.6 hereof to complete the full recovery (but no
overrecovery) of PGT's GSR Costs.
(d) "Approved GSR Costs" shall mean those GSR costs as defined in
Paragraph 30.2(a) above, which are approved by FERC for recovery
by PGT through the Transition Cost Recovery Mechanism as defined
in this Paragraph 30.
(e) "Northwest Shippers", for purposes of this paragraph, are defined
as Washington Natural Gas Company, Cascade Natural Gas Company,
Washington Water Power Company/WP Natural Gas and Northwest
Natural Gas Company.
(Continued)
________________________________________________________________________________
Issued by: P.G. Rosput, Senior Vice President
Issued on: AUGUST 02, 1993 Effective: NOVEMBER 01, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-46-000, et al., dated JULY 12, 1993
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff Substitute Original Sheet No. 124
First Revised Volume No. 1-A Superseding
Original Sheet No. 124
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
30. GAS SUPPLY RESTRUCTURING TRANSITION COSTS (Continued)
30.3 Applicability of GSR Transition Costs
GSR Transition Costs shall be applicable to all Shippers except those
firm Shippers paying incremental rates on PGT which are also
Supporting Parties to the FERC-approved settlement in Docket No. RS92-
46-000.
30.4 Recovery of Surcharge Amounts
PGT shall recover from each Shipper meeting the applicability criteria
defined in Paragraph 30.3 the affected Shipper's GSR Surcharge amounts
and Direct Bill, if applicable, during the Initial GSR Cost Collection
Period and shall continue to recover such amounts during any
applicable Carryover GSR Cost Collection Period as necessary to
complete the full recovery (but no overrecovery) of PGT's GSR Costs.
30.5 Transition Cost Recovery Mechanism
(a) Absorption -- PGT's shareholder shall absorb 25% of all Approved
GSR Costs.
(b) Direct Bill -- 25% of all Approved GSR Costs will be recovered by
PGT through a Direct Bill. A Direct Bill will be assessed to
PG&E for 100% of the Direct Bill amount, excluding the amount to
be collected from the Northwest Shippers and credited against the
Direct Bill portion as defined in Paragraph 30.5(d). PG&E may
pay its Direct Bill in a lump sum, plus carrying charges on the
principal amount accrued, in accordance with Paragraph 30.5(e)
until the payment is made. In lieu of paying the Direct Bill in
a lump sum, PG&E may elect one of three payment schedules.
PG&E's Direct Bill amount and the monthly amount due under each
extended payment option, which shall include carrying charges
accrued on the unpaid balance in accordance with Paragraph
30.5(e), shall be specified in the Statement of Effective Rates
and Charges of First Revised Volume No. 1-A.
(c) GSR Transition Cost Surcharge -- 50% of all Approved GSR Costs
will be recovered by PGT through a volumetric MMBtu-mile
surcharge. The GSR Transition Cost Surcharge shall include any
applicable carrying charges accruing on the unrecovered balance.
The GSR Transition Cost Surcharge shall be stated in the
Statement of Effective Rates and Charges of PGT's FERC Gas Tariff
First Revised Volume No. 1-A as the same may change from time to
time, depending on PGT's GSR Costs.
(Continued)
________________________________________________________________________________
Issued by: P.G. Rosput, Senior Vice President
Issued on: DECEMBER 10, 1993 Effective: NOVEMBER 15, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RP94-24-000, dated NOVEMBER 12, 1993
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff Original Sheet No. 125
First Revised Volume No. 1-A
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
30. GAS SUPPLY RESTRUCTURING TRANSITION COSTS (Continued)
30.5 Transition Cost Recovery Mechanism (Continued)
(d) Northwest Shippers' GSR Cost Responsibility -- All Northwest
Shippers (excluding Washington Natural Gas Company) shall pay a
Direct Bill and Washington Natural Gas shall pay a GSR transition
cost surcharge (different from that provided in (c) above) for
their share of GSR transition costs. The Northwest Shippers'
responsibility shall be equal to 1.3 percent of the Approved GSR
costs that are not absorbed by PGT and in any event shall not
exceed a total of $1,454,000. Of this amount, one-third, up to
$485,000, will be credited against the amount allocated to the
Direct Bill as described in Paragraph 30.5(b), and two-thirds, up
to $969,000, will be credited against the amount allocated to the
GSR surcharge provided in Paragraph 30.5(c). The amounts
allocated to the Northwest Shippers as a group will be allocated
among the individual Northwest Shippers based on the percentages
shown below and will not exceed the applicable total amount for
each Shipper.
<TABLE>
<CAPTION>
Total
Percentage Amount
<S> <C> <C>
Washington Natural Gas Company 55.02% up to $ 800,000
Cascade Natural Gas Corporation 24.07% up to 350,000
Washington Water Power Company/
WP Natural Gas 18.57% up to 270,000
Northwest Natural Gas Company 2.34% up to 34,000
Total Northwest Shippers 100.00% $1,454,000
</TABLE>
Washington Water Power Company/WP Natural Gas (WWP), Cascade
Natural Gas Corporation (CNG), and Northwest Natural Gas Company
(NNG) will be billed and will pay immediately all amounts of the
Approved GSR Costs allocated to them up to the total maximums
noted above. The total amount allocated to Washington Natural Gas
Company (WNG) will be recovered through a volumetric surcharge
over a three-year amortization period based on the approved
commodity throughput for WNG. Any amounts not recovered at the
end of the 36-month amortization period will be due and payable in
one lump sum. Once the maximum GSR Costs applicable to Northwest
Shipper(s), as such amounts may be adjusted pursuant to the
application of rolled-in rates on the PGT system, have been
collected then the GSR Cost tariff provisions will no longer apply
to such Northwest Shipper(s). (Continued)
________________________________________________________________________________
Issued by: P.G. Rosput, Senior Vice President
Issued on: AUGUST 02, 1993 Effective: NOVEMBER 01, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-46-000, et al., dated JULY 12, 1993
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff Substitute Original Sheet No. 126
First Revised Volume No. 1-A Superseding
Original Sheet No. 126
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
30. GAS SUPPLY RESTRUCTURING TRANSITION COSTS (Continued)
30.5 Transition Cost Recovery Mechanism (Continued)
(e) Carrying Charges -- Carrying charges shall accrue beginning on
the effective date of PGT's filing to recover GSR costs or the
date PGT initiates payment for GSR costs, whichever is later.
Carrying charges shall be calculated in accordance with Section
154.67 of the Commission's regulations.
30.6 Reconciliation
(a) At the conclusion of the Initial GSR Cost Collection Period, PGT
will determine its GSR Costs and the actual amounts of GSR
Transition Cost Surcharge revenues.
(b) If PGT's collections hereunder shall equal or exceed its GSR
Costs, PGT shall file to terminate further collections hereunder.
The amount of any excess collected shall be repaid to all Shippers
affected hereby in proportion to the principal amount of GSR
Transition Cost Surcharge payments they have provided pursuant to
this Paragraph 30. Within ninety (90) days of the termination of
collections pursuant to this Paragraph 30, PGT will submit a
report to the Commission setting out a comparison of its GSR costs
and the amounts collected hereunder and any repayments to be
provided hereunder. Within thirty (30) days of the Commission's
approval of such report, repayments, with applicable carrying
charges, shall be paid.
(c) If PGT's collections hereunder are less than its GSR Costs, PGT
shall be permitted to recover such deficiency, including carrying
charges, during the Carryover GSR Cost Collection Period by filing
with the Commission GSR Transition Cost Surcharges within ninety
(90) days of the conclusion of the Initial GSR Cost Collection
Period. The GSR Transition Cost Surcharge will be determined by
dividing the remaining GSR costs by the applicable quantities
underlying PGT's then-effective rates. The GSR Transition Cost
Surcharge shall be effective on the first day of the month
following Commission approval of such filing.
(Continued)
________________________________________________________________________________
Issued by: P.G. Rosput, Senior Vice President
Issued on: OCTOBER 13, 1993 Effective: NOVEMBER 01, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-46-000, et al., dated OCTOBER 01, 1993
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff Second Revised Sheet No. 127
First Revised Volume No. 1-A Superseding
First Revised Sheet No. 127
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
31. Reserved
(Continued)
________________________________________________________________________________
Issued by: R.T. Howard, Manager, Rates and Regulatory Affairs
Issued on: AUGUST 13, 1996 Effective: SEPTEMBER 13,1996
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff First Revised Sheet No. 128
First Revised Volume No. 1-A Superseding
Original Sheet No. 128
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
Reserved for future use.
(Continued)
________________________________________________________________________________
Issued by: R.T. Howard, Manager, Rates and Regulatory Affairs
Issued on: AUGUST 13, 1996 Effective: SEPTEMBER 13,1996
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff Second Revised Sheet No. 129
First Revised Volume No. 1-A Superseding
First Revised Sheet No. 129
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
32. EQUALITY OF TRANSPORTATION SERVICE
PGT hereby states that the terms and conditions of service for all
unbundled sales and transportation services provided in PGT's FERC Gas
Tariff Second Revised Volume No. 1 and First Revised Volume No. 1-A, are
provided on a basis that is equal in quality for all Shippers. All
Shippers can access all sellers of gas and receive the same quality of
service on PGT whether their gas supplies are purchased from PGT or any
other seller. Furthermore, no preference is accorded to any affiliate of
PGT for sales and transportation services provided by PGT.
(Continued)
________________________________________________________________________________
Issued by: R.T. Howard, Manager, Rates and Regulatory Affairs
Issued on: AUGUST 13, 1996 Effective: SEPTEMBER 13,1996
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff Original Sheet No. 130
First Revised Volume No. 1-A
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
33. RIGHT OF FIRST REFUSAL UPON TERMINATION OF FIRM SHIPPER'S SERVICE AGREEMENT
Firm Shippers (original capacity holders) under PGT's firm
transportation rate schedules of First Revised Volume No. 1-A shall have the
right of first refusal at the termination of their service agreements.
Original capacity holders must notify PGT one year prior to termination of
their intent to terminate the service agreement.
One year prior to the expiration of the service agreement, PGT will
post a notice on its EBB that the original capacity holder's service
agreement will terminate in one year and the original capacity holder has
either elected or not elected to terminate.
33.1 In the event original capacity holder elects termination, PGT shall
subject this capacity to a bidding process. PGT shall require bids be
submitted no later than 6 months prior to the service agreement
expiration. The bid period will be 2 months. PGT will announce the
bid winner(s) 1 month after the close of the bid period. Tied bids
will be awarded on a pro rata basis. Winning Shipper(s) and PGT must
execute a new firm transportation service agreement prior to service
commencement.
33.2 In the event original capacity holder does not elect termination, PGT
will commence open bidding 6 months prior to the service agreement
termination. The bid period will be 1 month. The original capacity
holder will have 1 month from the close of the bid period to match the
highest bid(s). PGT will announce the winning bid(s) within 1 month
after the close of the match period. If the original capacity holder
matches the highest bid(s), the capacity is awarded to the original
capacity holder. If the original capacity holder does not match the
highest bid(s), the original capacity holder's bid shall be rejected.
If there is more than one winning bid, PGT shall award capacity on a
pro rata basis. New Shippers must execute a firm transportation
service agreement with PGT prior to service commencement. Original
capacity holder is allowed to retain a portion of its capacity by
matching price and term according to the procedure outlined in this
provision.
(Continued)
________________________________________________________________________________
Issued by: P.G. Rosput, Senior Vice President
Issued on: AUGUST 02, 1993 Effective: NOVEMBER 01, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-46-000, et al., dated JULY 12, 1993
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff Original Sheet No. 131
First Revised Volume No. 1-A
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
33. RIGHT OF FIRST REFUSAL UPON TERMINATION OF FIRM SHIPPER'S SERVICE AGREEMENT
(Continued)
33.3 Bids shall be evaluated on the net present value incorporating price
and term. The price shall be the rate Shippers are willing to pay up
to the maximum authorized rate. The maximum term is 20 years.
33.4 If there are no competing bids other than that of the original capacity
holder, the rate and terms of continuing service is to be negotiated
between existing capacity holder and PGT. In addition, in this
instance, if the existing capacity holder agrees to pay the maximum
authorized rate, the existing capacity holder may determine the term it
desires and PGT must extend its contract to the existing capacity
holder accordingly.
33.5 Shippers who terminate their service agreements are not liable for any
reservation charges or other charges applicable to the new Shipper
contracting for this capacity.
33.6 Only bona fide bids will be accepted. A bona fide bid offer shall be:
(a) submitted via PGT's EBB; (b) accepted in principle; and (c)
pursuant to an arms-length transaction. If the Service Agreement is
not executed within 30 days, the request for capacity shall expire
without prejudice to the prospective Shipper's right to submit a new
request for capacity. PGT shall then notify the Shipper via the EBB of
the acceptable offer, if any, having the next greatest economic value
in accordance with the provisions of this Paragraph. If there is no
other acceptable offer, the Shipper may continue service in accordance
with this Paragraph.
(Continued)
________________________________________________________________________________
Issued by: P.G. Rosput, Senior Vice President
Issued on: AUGUST 02, 1993 Effective: NOVEMBER 01, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-46-000, et al., dated JULY 12, 1993
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff Second Revised Sheet No. 132
First Revised Volume No. 1-A Superseding
First Revised Sheet No. 132
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
34. ELECTRONIC BULLETIN BOARD
34.1 General
PGT shall use its Electronic Bulletin Board (EBB), "Pacific Trail"
for capacity release. PGT shall maintain an EBB which will provide a
range of electronic pipeline services and information to all parties
on a nondiscriminatory basis. The EBB is available to any party that
has compatible equipment for electronic communication and transmission
of data. Access to the EBB is obtained by contacting PGT's Gas
Control Department at 1-800-238-2781 and requesting a user
identification. The EBB will operate 24 hours a day; however, certain
functions may be limited to specific operating times during the
business day. There is no direct connection charge to use the EBB.
However, PGT reserves the right to change the telephone access from an
"800" number to a "900" number at its sole discretion.
PGT shall exercise reasonable efforts to ensure the accuracy and
security of information presented on the EBB.
34.2 Menu of Services and Information
PGT's EBB will provide the following main menu of services and
information:
(a) Capacity Release
(b) Bulletins and Capacity Available
(c) Nominations
(d) Submit Request for Firm or Interruptible Service
(e) Interruptible Transportation Queue
(f) Tariffs and Rates
(g) Account Status of Shipper
(h) Marketing Affiliate Information
(i) Offers to Purchase Capacity
(j) Procedures for Filing Complaints
(k) E-mail to Other Shippers/PGT System Administrator
(l) EBB Mailbox
(Continued)
________________________________________________________________________________
Issued by: R.T. Howard, Manager, Rates and Regulatory Affairs
Issued on: AUGUST 13, 1996 Effective: SEPTEMBER 13,1996
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff First Revised Sheet No. 133
First Revised Volume No. 1-A Superseding
Original Sheet No. 133
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
34. ELECTRONIC BULLETIN BOARD (Continued)
34.2 Menu of Services and Information (Continued)
(a) Capacity Release
The capacity release menu would allow the following options:
(1) Review Available Released Parcels
(2) Submit/Check Status of Request for Authority to\
Bid/Release Capacity
(3) Post/Withdraw Capacity for Release
(4) Submit/Withdraw Bid for Released Capacity
(5) Review the Status of Shipper's Active Bids
(6) Review the Status of Shipper's Active Released Parcels
(7) Review Shipper's Authority to Bid for Released
Capacity
(8) Review Transaction Log of Previous Releases
(b) Bulletins and Capacity Available
The bulletins and capacity available menu would allow the
following options:
Capacity Availability Information:
(1) At Receipt Points
(2) At Major Delivery Points
(3) At Minor Delivery Points
(4) Projected Capacity
(5) PGT Maintenance Schedules
(6) Whether the Capacity is Available From PGT or
Through PGT's Capacity Release Program
(7) Operational Bulletins
(8) Regulatory Bulletins
(c) Nominations
(1) Submit Nominations to PGT Gas Control
(2) Review Confirmation
(3) E-mail to Gas Control
(Continued)
________________________________________________________________________________
Issued by: R.T. Howard, Manager, Rates and Regulatory Affairs
Issued on: AUGUST 13, 1996 Effective: SEPTEMBER 13,1996
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff First Revised Sheet No. 134
First Revised Volume No. 1-A Superseding
Original Sheet No. 134
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
34. ELECTRONIC BULLETIN BOARD (Continued)
34.2 Menu of Services and Information (Continued)
(d) Submit Request for Firm or Interruptible Service
(e) Interruptible Transportation Queue
(f) Tariffs and Rates
The tariffs and rates menu would allow the following options:
(1) Transportation Rates
(2) Transportation Rate Discounts (including negotiated ITS-1
rates)
(3) First Revised Volume No. 1-A - Tariff
(4) Second Revised Volume No. 1 - Tariff
(g) Account Status of Shippers
(h) Marketing Affiliate Information
The marketing affiliate information would allow the following
options:
(1) Transportation request data
(2) Receipt/delivery point data
(3) Delivery point discount data
(Continued)
________________________________________________________________________________
Issued by: R.T. Howard, Manager, Rates and Regulatory Affairs
Issued on: AUGUST 13, 1996 Effective: SEPTEMBER 13,1996
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff First Revised Sheet No. 135
First Revised Volume No. 1-A Superseding
Original Sheet No. 135
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
34. ELECTRONIC BULLETIN BOARD (Continued)
34.2 Menu of Services and Information (Continued)
(i) Offers to Purchase Capacity
PGT shall post the following information on offers to purchase
capacity:
(1) Legal Name of Offerer
(2) Name, telephone Number, Fax Number, Address of Contact
Person and Alternate Contact Person
(3) Firm or Interruptible Service Requested
(4) Amount of Capacity Sought
(5) Term Sought
(6) Other Information
(j) Procedures for Filing Complaints
The Procedures for filing complaints menu offers the following
options:
(1) Review Complaint Procedure
(2) Enter a Complaint
(3) Send E-Mail to PGT System Administrator
(k) E-Mail to other Shippers/PGT Systems Administrator
(l) EBB Mailbox
(Continued)
________________________________________________________________________________
Issued by: R.T. Howard, Manager, Rates and Regulatory Affairs
Issued on: AUGUST 13, 1996 Effective: SEPTEMBER 13,1996
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff Original Sheet No. 136
First Revised Volume No. 1-A
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
34. ELECTRONIC BULLETIN BOARD (Continued)
34.3 Historical Information
PGT will back up daily transaction information on the EBB. This
historical information shall be kept for a three-year period and may be
archived off-line. Information that may be accessed includes Parcel
information and bid information associated with that Parcel, including
the identity of the winning bid and bidder.
PGT will provide access to historical data in one of the following
manners:
(a) Direct access by parties via the EBB. In such cases, data may be
viewed, down loaded to a computer or printed by the party.
(b) PGT may elect to archive historical data off-line. Parties may
access this data by sending a written or an electronic mail
request to the PGT Capacity Release System Administrator
requesting such historical data. PGT will make such information
available to Shippers.
(Continued)
________________________________________________________________________________
Issued by: P.G. Rosput, Senior Vice President
Issued on: AUGUST 02, 1993 Effective: NOVEMBER 01, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-46-000, et al., dated JULY 12, 1993
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff Second Revised Sheet No. 137
First Revised Volume No. 1-A Superseding
First Revised Sheet No. 137
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
35. Reserved
(Continued)
________________________________________________________________________________
Issued by: R.T. Howard, Manager, Rates and Regulatory Affairs
Issued on: SEPTEMBER 30, 1996 Effective: SEPTEMBER 11, 1996
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RP94-149, 76-61,246, dated SEPTEMBER 11, 1996
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff First Revised Sheet No. 138
First Revised Volume No. 1-A Superseding
Original Sheet No. 138
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
Reserved for future use.
(Continued)
________________________________________________________________________________
Issued by: R.T. Howard, Manager, Rates and Regulatory Affairs
Issued on: SEPTEMBER 30, 1996 Effective: SEPTEMBER 11, 1996
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RP94-149, 76-61,246, dated SEPTEMBER 11, 1996
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff Original Sheet No. 138A
First Revised Volume No. 1-A
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
35A. CREDITING OF INTERRUPTIBLE TRANSPORTATION REVENUES ON EXTENSIONS
(1) Interruptible Transportation Revenue Credits on Coyote Springs
Extension
(a) Applicability. Revenue credits from interruptible transportation
revenues received by PGT from Rate Schedule ITS-1 (E-3) Shippers shall be
provided to PGT's firm Shippers under Rate Schedules FTS-1 (E-3) ("Eligible
Shippers"), excluding Shippers receiving service under a Capacity Release
Service Agreement.
(b) Crediting Percentage. PGT shall credit to Eligible Shippers 90 percent
of interruptible transportation revenues received during each 12-month
period, commencing November 1st of each year, but only to the extent that
such transportation revenues exceed the amount of fixed costs which were
allocated to interruptible transportation (Cost Allocation Amount) by PGT as
part of designing PGT's effective transportation rates during such 12-month
period. To the extent that PGT is required to provide interruptible
transportation revenue credits during any period during which this Paragraph
35A shall be or shall have been in effect for less than 12 months, a "Short
Period", PGT shall pro rate the Cost Allocation Amount by the number of days
during such Short Period as compared to the total number of days in such 12
months. To calculate the interruptible transportation revenue credit due
under the provisions of this paragraph, where applicable, such pro rated
Cost Allocation Amount shall be compared to PGT's actual interruptible
revenues for the Short Period.
(c) Timing of Credits. Within 45 days after November 1st of each 12-month
period or after the end of a Short Period, if applicable, PGT shall
determine the total amount of the applicable Rate Schedule ITS-1 (E-3)
revenues received during the 12-month period or Short Period and the
distribution of the interruptible revenue credits due to Eligible Shippers
as described below. Such revenue credits shall be reflected as a credit
billing adjustment in the next invoices rendered to the Eligible Shippers.
In the event that such credit billing adjustment would result in a credit
total invoice to any Shipper, PGT will refund the excess credit billing
adjustment to the Shipper in cash within 15 days after determination of the
amount of the credit due to the Shipper.
(Continued)
________________________________________________________________________________
Issued by: R.T. Howard, Manager, Rates and Regulatory Affairs
Issued on: SEPTEMBER 29, 1995 Effective: NOVEMBER 01, 1995
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff Original Sheet No. 138B
First Revised Volume No. 1-A
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
35A. CREDITING OF INTERRUPTIBLE TRANSPORTATION REVENUES ON EXTENSIONS
(Continued)
(1) Interruptible Transportation Revenue Credits on Coyote Springs
Extension (Continued)
(d) Exclusion. Revenue credits shall not be awarded for that portion of
interruptible revenues that are attributable to: (1) the recovery by PGT
of variable costs, which portion shall be equal to the minimum usage
charge for Rate Schedule ITS-1 (E-3), (2) the recovery of Gas Supply
Restructuring (GSR) costs to be recovered by a GSR volumetric surcharge
under Rate Schedule ITS-1 (E-3), and (3) relate to other volumetric
surcharges such as GRI and ACA.
(e) Distribution Method. Interruptible transportation revenue credits
shall be credited to each Eligible Shipper on a pro rata basis in
proportion to the reservation revenues received during the 12-month period
or Short Period from each Eligible Shipper divided by the total
reservation revenue for each Eligible Shipper received during such period.
The reservation revenues shall include the reservation charges which the
Eligible Shippers actually pay prior to the distribution of all revenue
credits, and including reservation charges applicable to capacity which
was released into PGT's Capacity Release Programs during the 12-month
period year or Short Period by the Eligible Shipper.
(f) PGT shall pay interest to Eligible Shippers on any revenue credits
from the date such credits accrue. Such interest shall be calculated based
upon the rate of interest specified in Section 154.67(c) of the
Commission's regulations.
(Continued)
________________________________________________________________________________
Issued by: R.T. Howard, Manager, Rates and Regulatory Affairs
Issued on: SEPTEMBER 29, 1995 Effective: NOVEMBER 01, 1995
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff Original Sheet No. 138C
First Revised Volume No. 1-A
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
35A. CREDITING OF INTERRUPTIBLE TRANSPORTATION REVENUES ON EXTENSIONS
(Continued)
(2) Interruptible Transportation Revenue Credits on Medford Extension
(a) Applicability. Revenue credits from interruptible transportation
revenues received by PGT from Rate Schedule ITS-1
(E-1) Shippers shall be credited to the deferred account for Washington
Water Power Company's WP Natural Gas subsidiary in accordance with the
mechanism approved by Order of June 1, 1995, 71 FERC Paragraph 61,268.
(b) Crediting Percentage. PGT shall credit to the deferred account 90
percent of interruptible transportation revenues received during each 12-
month period, commencing November 1st of each year, but only to the extent
that such transportation revenues exceed the amount of fixed costs which
were allocated to interruptible transportation (Cost Allocation Amount) by
PGT as part of designing PGT's effective transportation rates during such
12-month period. To the extent that PGT is required to provide
interruptible transportation revenue credits during any period during
which this Paragraph 35A shall be or shall have been in effect for less
than 12 months, a "Short Period", PGT shall pro rate the Cost Allocation
Amount by the number of days during such Short Period as compared to the
total number of days in such 12 months. To calculate the interruptible
transportation revenue credit due under the provisions of this paragraph,
where applicable, such pro rated Cost Allocation Amount shall be compared
to PGT's actual interruptible revenues for the Short Period.
(c) Exclusion. Revenue credits shall not be awarded for that portion of
interruptible revenues that are attributable to the recovery by PGT of
variable costs, which portion shall be equal to the minimum usage charge
for Rate Schedule ITS-1 (E-1).
(Continued)
________________________________________________________________________________
Issued by: R.T. Howard, Manager, Rates and Regulatory Affairs
Issued on: SEPTEMBER 29, 1995 Effective: NOVEMBER 01, 1995
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff 2nd Sub. First Revised Sheet No. 139
First Revised Volume No. 1-A Superseding
Original Sheet No. 139
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
36. DISCOUNT POLICY
PGT may from time to time offer a discount from the maximum applicable rate
for service under any service agreement governed by this FERC Gas Tariff.
If and when PGT offers a discount, such discount shall first be applied to
the GRI Surcharge and last to the base tariff rate. PGT shall not discount
its GSR Surcharge.
________________________________________________________________________________
Issued by: R.T. Howard, Manager, Rates and Regulatory Affairs
Issued on: SEPTEMBER 26, 1996 Effective: SEPTEMBER 13, 1996
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RM95-3, 76-61,300, dated SEPTEMBER 28, 1995
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff Original Sheet No. 140
First Revised Volume No. 1-A
________________________________________________________________________________
GENERAL TERMS AND CONDITIONS
(Continued)
37. ADJUSTMENT MECHANISM FOR FUEL, LINE LOSS, AND OTHER UNACCOUNTED FOR GAS
PERCENTAGES
The effective fuel and line loss percentages under Rate Schedules FTS-1 and
ITS-1 shall be adjusted downward to reflect reductions and may be adjusted
upward to reflect increases in fuel usage and line loss in accordance with
this Section 37.
37.1 Computation of Effective Fuel and Line Loss Percentage
The effective fuel and line loss percentage shall be the sum of the
current fuel and line loss percentage and the fuel and line loss
surcharge percentage.
37.2 The Current Fuel and Line Loss Percentage
(a) For each month, the current fuel and line loss percentage shall be
determined in accordance with Section 37.2(c) hereof. The current fuel
and line loss shall be effective from the first day of such month and
shall remain in effect for the month.
(b) The current fuel and line loss percentage to be applicable for the
month shall be posted on PGT's Electronic Bulletin Board not less than
seven (7) days prior to the beginning of the month.
(c) The current fuel and line loss percentage for the month shall be
determined on the basis of (1) the estimated quantities of gas to be
delivered by PGT for the account of Shippers during such month and (ii)
the projected quantities of gas that shall be required for fuel and
line loss during such month, adjusted for overrecoveries or
underrecoveries of fuel and line loss during such month preceding the
month in which the current fuel and line loss percentage is posted;
provided, that the percentage shall not exceed the maximum current fuel
and line loss percentage and shall not be less than the minimum current
fuel and line loss percentage set forth on the Statement of Effective
Rates and Charges.
(Continued)
________________________________________________________________________________
Issued by: P.G. Rosput, Senior Vice President
Issued on: DECEMBER 22, 1993 Effective: JANUARY 22, 1994
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff Substitute Original Sheet No. 141
First Revised Volume No. 1-A Superseding
Original Sheet No. 141
________________________________________________________________________________
GENERAL TERMS AND CONDITIONS
(Continued)
37. ADJUSTMENT MECHANISM FOR FUEL, LINE LOSS AND OTHER UNACCOUNTED FOR GAS
PERCENTAGES (Continued)
37.2 The Current Fuel and Line Loss Percentage (Continued)
(d) At least thirty (30) days prior to July 1 and January 1, PGT shall
file with the Commission schedules supporting the current fuel and
line loss percentages applicable during the six (6) months ending
April 30 and October 31, respectively.
37.3 The Fuel and Line Loss Surcharge Percentage
(a) For each six (6) month period beginning July 1 and January 1, the fuel
and line loss surcharge percentage shall be determined in accordance
with Section 37.3(c) hereof. The fuel and line loss surcharge
percentage shall become effective on July 1 and January 1 and shall
remain in effect for the six (6) month period ending December 31 and
June 30, respectively.
(b) At least thirty (30) days prior to each July 1 and January 1, PGT shall
file with the Commission and post, as defined by Section 154.16 of the
Commission's regulations, the fuel and line loss surcharge percentage,
together with supporting documentation.
(c) The fuel and line loss percentage shall be computed by (i) determining
PGT's actual fuel and line loss for the six (6) month period ending
April 30, if the effective date is July 1, or October 31, if the
effective date is January 1, (ii) subtracting the actual quantities
retained by PGT during such six (6) month period, and (iii) dividing
the result by the estimated quantities of gas to be delivered by PGT
for the account of Shippers during the six month period beginning with
the effective date of the fuel and line loss surcharge percentage. If
the percentage so determined is 0.0001% or less, the fuel and line loss
surcharge percentage shall be deemed to be zero.
________________________________________________________________________________
Issued by: P.G. Rosput, Senior Vice President
Issued on: JANUARY 10, 1994 Effective: JANUARY 22, 1994
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. TM94-2-86-000, dated DECEMBER 30, 1993
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff First Revised Sheet No. 142
First Revised Volume No. 1-A Superseding
Original Sheet No. 142
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
38. Reserved.
(Continued)
________________________________________________________________________________
Issued by: R.T. Howard, Manager, Rates and Regulatory Affairs
Issued on: SEPTEMBER 30, 1996 Effective: SEPTEMBER 11, 1996
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RP94-149, 76-61,246, dated SEPTEMBER 11, 1996
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff Third Revised Sheet No. 143
First Revised Volume No. 1-A Superseding
Second Revised Sheet No. 143
________________________________________________________________________________
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
39. SALES OF EXCESS GAS
PGT may from time to time purchase or sell gas on an interruptible basis at
its Stanfield or Kingsgate receipt points as necessary to manage system
pressure and maintain system integrity. Prior to purchasing or selling gas
pursuant to this section, PGT shall post notice of its intent to purchase
or sell gas through its EBB. Purchase or sale of gas shall be made on a
nondiscriminatory basis.
________________________________________________________________________________
Issued by: R.T. Howard, Manager, Rates and Regulatory Affairs
Issued on: SEPTEMBER 30, 1996 Effective: SEPTEMBER 11, 1996
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RP94-149, 76-61,246, dated SEPTEMBER 11, 1996
<PAGE>
Graphic List to Exhibit 10.1 of the Form 10-K
The substantive information conveyed by the Capacity Release Timelines Standard
Release (Greater Than or Equal to One Day) graph (appearing in Paragraph 28) is
described in the body of the electronic document at Paragraph 28.2 and Paragraph
28.8 (b) as permitted by Item 304 of Regulation S-T.
The substantive information conveyed by the Capacity Release Timelines Rapid
Release (Equal to or Less Than One Month) graph (appearing in Paragraph 28) is
described in the body of the electronic document at Paragraph 28.2 and Paragraph
28.8 (a) as permitted by Item 304 of Regulation S-T.
The substantive information conveyed by the Capacity Release Timelines Pre-
Arranged Deal - A (Less Than or Equal to Thirty-One Days) graph (appearing in
Paragraph 28) is described in the body of the electronic document at Paragraph
28.2 and Paragraph 28.8 (c) as permitted by Item 204 of Regulation S-T.
The substantive information conveyed by the Capacity Release Timelines Pre-
Arranged Deal - B (Equal To or Greater Than Thirty-One Days At the Highest Value
Bid) graph (appearing at Paragraph 28) is described in the body of the
electronic document at Paragraph 28.2 and Paragraph 28.8 (d) as permitted by
Item 304 of Regulation S-T.
The substantive information conveyed by the Capacity Release Timelines Pre-
Arranged Deal - C (Greater Than or Equal to One Day) graph (appearing at
Paragraph 28) is described in the body of the electronic document at Paragraph
28.2 and Paragraph 28.8 (e) as permitted by Item 304 of Regulation S-T.
<PAGE>
EXHIBIT 11
PG&E CORPORATION
COMPUTATION OF EARNINGS PER COMMON SHARE
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------------------------------------
Year Ended December 31,
----------------------------------------
(in thousands, except per share amounts) 1996 1995 1994
- ----------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
EARNINGS PER COMMON SHARE (EPS) AS SHOWN
IN THE STATEMENT OF CONSOLIDATED INCOME
Net income $755,209 $1,338,885 $1,007,450
Less: preferred dividend requirement and
redemption premium 33,113 70,288 57,603
-------- ---------- ----------
Net income for calculating EPS for
Statement of Consolidated Income $722,096 $1,268,597 $ 949,847
======== ========== ==========
Average common shares outstanding 412,542 423,692 429,846
======== ========== ==========
EPS as shown in the Statement of
Consolidated Income $ 1.75 $ 2.99 $ 2.21
======== ========== ==========
PRIMARY EPS (1)
Net income $755,209 $1,338,885 $1,007,450
Less: preferred dividend requirement and
redemption premium 33,113 70,288 57,603
-------- ---------- ----------
Net income for calculating primary EPS $722,096 $1,268,597 $ 949,847
======== ========== ==========
Average common shares outstanding 412,542 423,692 429,846
Add exercise of options, reduced by the
number of shares that could have been
purchased with the proceeds from
such exercise (at average market price) 9 126 57
-------- ---------- ----------
Average common shares outstanding as
adjusted 412,551 423,818 429,903
======== ========== ==========
Primary EPS $ 1.75 $ 2.99 $ 2.21
======== ========== ==========
FULLY DILUTED EPS (1)
Net income $755,209 $1,338,885 $1,007,450
Less: preferred dividend requirement and
redemption premium 33,113 70,288 57,603
-------- ---------- ----------
Net income for calculating fully diluted EPS $722,096 $1,268,597 $ 949,847
======== ========== ==========
Average common shares outstanding 412,542 423,692 429,846
Add exercise of options, reduced by the
number of shares that could have been
purchased with the proceeds from such
exercise (at the greater of average or
ending market price) 9 149 57
-------- ---------- ----------
Average common shares outstanding as
adjusted 412,551 423,841 429,903
======== ========== ==========
Fully diluted EPS $ 1.75 $ 2.99 $ 2.21
======== ========== ==========
- ----------------------------------------------------------------------------------------------------------
</TABLE>
(1) This presentation is submitted in accordance with Item 601(b)(11) of
Regulation S-K. This presentation is not required by APB Opinion No. 15,
because it results in dilution of less than 3%.
<PAGE>
EXHIBIT 12.1
PG&E CORPORATION AND SUBSIDIARIES
COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------------------
Year ended December 31,
-------------------------------------------------------------
(dollars in thousands) 1996 1995 1994 1993 1992
- ------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Earnings:
Net income $ 755,209 $1,338,885 $1,007,450 $1,065,495 $1,170,581
Adjustments for minority
interests in losses of
less than 100% owned
affiliates and the
Company's equity in
undistributed losses
(income) of less than
50% owned affiliates 2,488 3,820 (2,764) 6,895 (3,349)
Income tax expense 554,994 895,289 836,767 901,890 895,126
Net fixed charges 683,393 715,975 730,965 821,166 802,198
---------- ---------- ---------- ---------- ----------
Total Earnings $1,996,084 $2,953,969 $2,572,418 $2,795,446 $2,864,556
========== ========== ========== ========== ==========
Fixed Charges:
Interest on long-
term debt $ 580,510 $ 627,375 $ 651,912 $ 731,610 $ 739,279
Interest on short-
term borrowings 75,310 83,024 77,295 87,819 61,182
Interest on capital
leases 3,508 2,735 1,758 1,737 1,737
Capitalized Interest 637 957 2,660 46,055 6,511
Earnings required to
cover the preferred
stock dividend and
preferred security
distribution requirements
of majority owned
subsidiaries 24,319 3,306 - - -
---------- ---------- ---------- ---------- ----------
Total Fixed
Charges $ 684,284 $ 717,397 $ 733,625 $ 867,221 $ 808,709
========== ========== ========== ========== ==========
Ratios of Earnings to
Fixed Charges 2.92 4.12 3.51 3.22 3.54
- ------------------------------------------------------------------------------------------
</TABLE>
Note: For the purpose of computing the Company's ratios of earnings to fixed
charges, "earnings" represent net income adjusted for the minority
interest in losses of less than 100% owned affiliates, the Company's
equity in undistributed income or loss of less than 50% owned affiliates,
income taxes and fixed charges (excluding capitalized interest). "Fixed
charges" include interest on long-term debt and short-term borrowings
(including a representative portion of rental expense), amortization of
bond premium, discount and expense, interest on capital leases, and
earnings required to cover the preferred stock dividend requirements of
majority owned subsidiaries.
<PAGE>
EXHIBIT 12.2
PG&E CORPORATION AND SUBSIDIARIES
COMPUTATION OF RATIOS OF EARNINGS TO COMBINED FIXED CHARGES AND PREFERRED STOCK
DIVIDENDS
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------------------
Year ended December 31,
--------------------------------------------------------------
(dollars in thousands) 1996 1995 1994 1993 1992
- -------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Earnings:
Net income $ 755,209 $1,338,885 $1,007,450 $1,065,495 $1,170,581
Adjustments for minority
interests in losses of
less than 100% owned
affiliates and the
Company's equity in
undistributed losses
(income) of less than
50% owned affiliates 2,488 3,820 (2,764) 6,895 (3,349)
Income tax expense 554,994 895,289 836,767 901,890 895,126
Net fixed charges 683,393 715,975 730,965 821,166 802,198
---------- ---------- ---------- ---------- ----------
Total Earnings $1,996,084 $2,953,969 $2,572,418 $2,795,446 $2,864,556
========== ========== ========== ========== ==========
Fixed Charges:
Interest on long-
term debt $ 580,510 $ 627,375 $ 651,912 $ 731,610 $ 739,279
Interest on short-
term debt 75,310 83,024 77,295 87,819 61,182
Interest on capital
leases 3,508 2,735 1,758 1,737 1,737
Capitalized Interest 637 957 2,660 46,055 6,511
Earnings required to
cover the preferred stock
dividend and preferred
security distribution
requirements of majority
owned subsidiaries 24,319 3,306 - - -
---------- ---------- ---------- ---------- ----------
Total Fixed Charges $ 684,284 $ 717,397 $ 733,625 $ 867,221 $ 808,709
---------- ---------- ---------- ---------- ----------
Preferred Stock Dividends:
Tax deductible dividends 10,057 11,343 4,672 4,814 5,136
Pretax earnings required
to cover non-tax
deductible preferred
stock dividend
requirements 39,108 99,984 96,039 108,937 130,147
---------- ---------- ---------- ---------- ----------
Total Preferred
Stock Dividends 49,165 111,327 100,711 113,751 135,283
---------- ---------- ---------- ---------- ----------
Total Combined Fixed
Charges and Preferred
Stock Dividends $ 733,449 $ 828,724 $ 834,336 $ 980,972 $ 943,992
========== ========== ========== ========== ==========
Ratios of Earnings to
Combined Fixed Charges and
Preferred Stock Dividends 2.72 3.56 3.08 2.85 3.03
- -------------------------------------------------------------------------------------------
</TABLE>
Note: For the purpose of computing the Company's ratios of earnings to combined
fixed charges and preferred stock dividends, "earnings" represent net
income adjusted for the minority interest in losses of less than 100%
owned affiliates, the Company's equity in undistributed income or loss of
less than 50% owned affiliates, income taxes and fixed charges (excluding
capitalized interest). "Fixed charges" include interest on long-term debt
and short-term borrowings (including a representative portion of rental
expense), amortization of bond premium, discount and expense, interest on
capital leases, and earnings required to cover the preferred stock
dividend requirements of majority owned subsidiaries. "Preferred stock
dividends" represent pretax earnings which would be required to cover
such dividend requirements.
<PAGE>
Exhibit 13
PG&E Corporation
Selected Financial Data
<TABLE>
<CAPTION>
(in thousands, except per share amounts) 1996 1995 1994 1993 1992
------------- ------------- ------------- ------------- -------------
<S> <C> <C> <C> <C> <C>
For the Year
Operating revenues $ 9,609,972 $ 9,621,765 $10,350,230 $10,550,002 $10,315,713
Operating income 1,895,585 2,762,985 2,423,786 2,560,235 2,699,824
Net income 755,209 1,338,885 1,007,450 1,065,495 1,170,581
Earnings per common share 1.75 2.99 2.21 2.33 2.58
Dividends declared per common share 1.77 1.96 1.96 1.88 1.76
At Year End
Book value per common share $ 20.73 $ 20.77 $ 20.07 $ 19.77 $ 19.41
Common stock price per share 21.00 28.38 24.38 35.13 33.13
Total assets 26,129,925 26,850,290 27,708,564 27,145,899 24,188,159
Long-term debt and preferred
stock and securities with mandatory
redemption provisions (excluding
current portions) 8,207,567 8,486,046 8,812,591 9,367,100 8,525,948
</TABLE>
Matters relating to certain data above are discussed in Management's Discussion
and Analysis of Consolidated Results of Operations and Financial Condition and
in Notes to the Consolidated Financial Statements.
8
<PAGE>
PG&E Corporation
Management's Discussion and Analysis of
Consolidated Results of Operations and Financial Condition
Effective January 1, 1997, Pacific Gas and Electric Company (PG&E) became a
subsidiary of its new parent holding company, PG&E Corporation. PG&E's ownership
interest in Pacific Gas Transmission Company (PGT) and PG&E Enterprises
(Enterprises) was 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.
This holding company structure is intended to improve PG&E Corporation's
ability to respond to new business opportunities and changes in the utility
industry. It will enhance the financial separation of the California utility
business from PG&E Corporation's other businesses and will provide greater
financing flexibility.
The consolidated financial statements in this annual report 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. PG&E provides generation, procurement, transmission, and
distribution of electricity and natural gas to customers throughout most of
Northern and Central California. PG&E is regulated by the California Public
Utilities Commission (CPUC), the Federal Energy Regulatory Commission (FERC),
and the Nuclear Regulatory Commission, among others.
PGT and Enterprises, previously wholly-owned by PG&E, are now wholly-owned
subsidiaries of PG&E Corporation. Through these subsidiaries, the Company is
expanding its presence 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.
PGT transports gas from the Canadian border to the California border and the
Pacific Northwest and is regulated by the FERC. In 1996, PGT acquired PGT
Queensland Gas Pipeline in Australia and Energy Source, the North American gas
operations of Edisto Resources Corporation. In January 1997, PG&E Corporation
acquired Teco Pipeline Company (Teco) in Texas. Teco owns a natural gas pipeline
system in Texas, investments in gas gathering and processing facilities, and a
gas marketing company in Houston. Also in January 1997, PG&E Corporation agreed
to acquire Valero Natural Gas Company (Valero) (see Acquisitions and Sales
below).
Enterprises, through its subsidiaries and affiliates, develops, owns, and
operates unregulated electric and gas projects in the U.S. and around the world.
Vantus Energy Corporation (Vantus), a subsidiary of Enterprises, markets gas and
electricity commodities and provides energy services.
The following discussion of consolidated results of operations and financial
condition includes 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.
These 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 both 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 Changing Regulatory Environment: The electric and gas industries
are undergoing significant change. Under traditional regulation, utilities were
provided the opportunity to earn a fair return on their invested capital in
exchange for a commitment to serve all customers within a designated service
territory. The objective of this regulatory policy was to provide universal
access to safe and reliable utility services. Regulation was designed in part to
take the place of competition and ensure that these services were provided at
fair prices.
Today, competitive pressures and emerging market forces are exerting an
increasing influence over the structure of the gas and electric industries.
Other companies are challenging the utilities' exclusive relationship with
customers and are seeking to replace certain utility functions with their own.
Customers, too, are asking for choice in their energy provider.
9
<PAGE>
PG&E Corporation
Management's Discussion and Analysis of
Consolidated Results of Operations and Financial Condition
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 the 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 Nuclear Power Plant (Diablo Canyon) and certain other
generation assets to be significantly lower than historical levels.
Electric Industry Restructuring: In 1995, the CPUC issued a decision that
provides a plan to restructure California's electric utility industry. The
decision acknowledges that much of utilities' current costs and commitments
result from past CPUC decisions and that, in a competitive generation market,
utilities would not recover some of these costs through market-based revenues.
To assure the continued financial integrity of California utilities, the CPUC
authorized recovery of these above-market costs, called "transition costs."
In 1996, California legislation was passed that adopts the basic tenets of
the CPUC's restructuring decision, including recovery of transition costs. In
addition, the legislation provides a 10 percent rate reduction for residential
and small commercial customers by January 1, 1998, freezes electric customer
rates for all other customers, and requires the accelerated recovery of
transition costs associated with owned generation facilities. The legislation
also establishes the operating framework for a competitive generation market.
The rate freeze will continue until the earlier of March 31, 2002, or until
PG&E has recovered its transition costs (the transition period). The freeze will
hold rates at 1996 levels for all customers except those receiving the 10
percent rate reduction. The rate freeze will hold the rates for these customers
at the reduced level.
To achieve the 10 percent rate reduction, the legislation authorizes
utilities to finance a portion of their transition costs with "rate reduction
bonds." 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 this portion of transition costs is
financed, PG&E would collect 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 percent reduction in
rates.
During 1997, differences between authorized and actual base revenues and
differences between the actual cost of electric generation and the revenue
designated for recovery of such revenues or costs will be recorded in balancing
accounts. Any residual balance will be available for transition cost recovery.
During 1997, amounts recorded in balancing accounts will be subject to a
reasonableness review by the CPUC.
Absent the rate freeze, PG&E's rates would be expected to decline under
existing cost-based ratemaking methodologies. The most significant reasons for
the decrease in cost-based rates are the declining cost of power committed under
certain purchased power contracts, the reduction in the Diablo Canyon price for
power under the existing CPUC-approved settlement, and the decline in
uncollected electric balancing accounts.
Transition Cost Recovery: The legislation authorizes the CPUC to determine the
costs eligible for recovery as transition costs. The amount of costs will be
based on the aggregate of above-market and below-market values of utility-owned
generation assets and obligations. PG&E has proposed that costs eligible for
transition cost recovery include: (1) above-market sunk costs (costs associated
with utility generating facilities that are fixed and unavoidable and currently
collected through rates) and future costs, such as costs related to plant
removal, (2) above-market costs associated with purchase power obligations with
Qualifying Facilities (QFs) and other Power Purchase Agreements, and (3)
generation-related regulatory assets and obligations. PG&E cannot determine the
exact amount of sunk
10
<PAGE>
costs that will be above market and recoverable as transition costs until a
market valuation process (appraisal or sale) is completed for each generation
facility. This process will be completed during the transition period.
In compliance with the CPUC's restructuring decision and the restructuring
legislation, PG&E has filed numerous regulatory applications and proposals that
detail its transition cost recovery plan. 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.
The unbundling of PG&E's revenue requirement enables it to separate revenue
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 on-going cost of
generation, and transition cost 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 transition cost
recovery.
PG&E has proposed to accelerate recovery for certain transition costs 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 reflects the 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 to
replace the existing settlement prices with: (1) a sunk cost revenue requirement
to recover fixed costs, including a return on these 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 percent of
PG&E's long-term cost of debt. PG&E's authorized long-term cost of debt was 7.52
percent in 1996. The reduced rate of return combined with a shorter recovery
period would result in an estimated $4 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 were adopted during 1996, Diablo Canyon's 1996
reported net income would have been reduced by $350 million ($0.85 per share).
Most transition costs must be recovered by March 1, 2002. However, the
legislation authorizes recovery of certain transition costs after that time.
These costs include: (1) certain employee-related transition costs, (2) payments
under existing QF and power purchase contracts, and (3) unrecovered
implementation costs. Excluding these exceptions, any transition costs not
recovered during the transition period will be absorbed by PG&E. Nuclear
decommissioning costs, which are not considered transition costs, will be
recovered through a CPUC authorized charge. During the transition period, this
charge will be incorporated into the frozen rates. After the transition period,
customers will be assessed a surcharge until the nuclear decommissioning costs
are fully recovered.
PG&E's ability to recover its transition costs during the transition period
will be dependent on several factors. These factors include: (1) the extent to
which application of the current regulatory framework established by the
restructuring legislation will continue to be applied, (2) the amount of
transition costs approved by the CPUC, (3) the market value of PG&E's generation
plants, (4) future sales levels, (5) fuel and operating costs, (6) the market
price of electricity, and (7) the ratemaking methodology adopted for Diablo
Canyon. Considering its current evaluation of these factors, PG&E believes it
will recover its transition costs and that its owned generation plants are not
impaired. However, a change in these factors could affect the probability of
recovery of transition costs and result in a material loss.
PG&E has proposed to implement portions of its transition cost recovery plan
in 1997. The CPUC decision on PG&E's 1997 Energy Cost Adjustment Clause (ECAC)
application would decrease PG&E's 1997 revenue requirement by $720 million. This
decrease would be partially offset by a $160 million revenue requirement
increase, provided by the legislation, for purposes of enhancing transmission
and distribution system
11
<PAGE>
PG&E Corporation
Management's Discussion and Analysis of
Consolidated Results of Operations and Financial Condition
safety and reliability. This increase was approved by the CPUC as part of PG&E's
transition cost recovery plan.
Given the electric customer rate freeze, the $560 million net revenue
requirement decrease resulting from the consolidation of the ECAC decision and
the revenue requirement increase contemplated in the cost recovery plan would be
available for transition cost recovery. The proposed accelerated recovery of
Diablo Canyon would absorb an estimated $400 million of this available revenue
requirement. The remaining revenue requirement would be available to recover
other transition costs.
Competitive Market Framework: In addition to transition cost recovery, the
legislation establishes the operating framework for the competitive generation
market in California. This framework will consist of a power exchange (PX) and
an independent system operator (ISO). The PX, open to all electricity providers,
will conduct a competitive auction to establish the price of electricity. The
ISO will ensure system reliability and provide all electricity generators with
open and comparable access to transmission and distribution services.
Although the PX will be available to all customers, the legislation allows
customers to bypass the PX by entering into direct access contracts with other
electricity providers, subject to a nonbypassable transition charge. This direct
access will be available to certain customers by January 1, 1998, and will be
phased in for all remaining customers through December 31, 2001. During the
transition period, PG&E will bill direct access customers based upon fully
bundled frozen rates. Direct access customers' bills from PG&E would then be
reduced by an amount based on the PX price and the customers' electric usage.
These customers can be billed for their usage directly by their chosen supplier,
or the supplier may contract with PG&E to perform this billing. During the
transition period, these customers' overall electric rates will vary only to the
extent that their direct access contract price differs from the PX price.
To prevent undue influence on the PX price by any participant in the
competitive framework, PG&E has indicated it is willing to proceed with
divestiture of at least 50 percent 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 before the end of 1997. The book value for these plants is
approximately $400 million, and together they generate approximately 10 percent
of PG&E's total electric sales. PG&E proposes to recover any shortfall in
proceeds from divestiture of these plants as a transition cost. Accordingly, the
Company does not expect any adverse impact on its results of operations from the
sale of these plants.
In addition to the CPUC's electric industry restructuring discussed above,
the FERC has required 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, provides access 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. Further, the FERC asserted that it has
jurisdiction over the transmission component of retail direct access.
By developing the PX and the ISO and by implementing direct access to
generation and open access to transmission, regulators have established the
operating framework of the competitive generation and wholesale transmission
markets. Although this framework will fundamentally change the way PG&E does
business, the Company does not believe that the changes will have a material
adverse impact on its ability to recover transition costs.
Accounting for the Effects of Regulation: PG&E accounts for the financial
effects of regulation in accordance with Statement of Financial Accounting
Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of
Regulation." This statement allows the Company to record certain regulatory
assets and liabilities that would not be recorded under generally accepted
accounting principles for nonregulated entities. In addition, SFAS No. 121,
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to
Be Disposed Of," requires that regulatory assets be written off when they are no
longer probable of recovery and that impairment losses be recorded for
long-lived assets when related future cash flows are less than the carrying
value of the asset.
As a result of applying the provisions of SFAS No. 71, PG&E has accumulated
approximately $1.6 billion of regulatory assets attributable to electric
generation at December 31, 1996.
12
<PAGE>
The net investments in Diablo Canyon and the other generation assets were
$4.5 billion and $2.7 billion, respectively, at December 31, 1996. The net
present value of above-market QF power purchase obligations is estimated to be
$5.3 billion at January 1, 1998, at an assumed PX price of $0.025 per
kilowatt-hour (kWh) beginning in 1997 and escalating at 3.2 percent per year.
PG&E believes that the restructuring legislation establishes a definitive
transition to market-based pricing for electric generation. Incorporating the
effects of the PX and direct access, this transition includes cost-of-service
based ratemaking. In addition, PG&E's generation-related transition costs will
be collected through a nonbypassable charge. Based on this structure, PG&E
believes it will continue to meet the requirements of SFAS No. 71 throughout the
transition period.
At the conclusion of the transition period, PG&E believes it will be at risk
to recover its generation costs through market-based revenues. At that time,
PG&E expects to discontinue the application of SFAS No. 71 for the electric
generation portion of its business. Since PG&E anticipates it will have
recovered all transition costs required to be recovered during the transition
period, including generation-related regulatory assets and above-market
investments in net plant, PG&E does not expect a material adverse impact on its
financial position or results of operations from discontinuing the application
at that time.
As a result of the CPUC's restructuring decision and California's electric
industry restructuring legislation, the Securities and Exchange Commission (SEC)
has begun inquiries regarding the appropriateness of the continued application
of SFAS No. 71 by California utilities to their electric generation businesses.
As discussed above, PG&E believes it currently meets and will continue to meet
the requirements to apply SFAS No. 71 during the transition period. In the event
that the SEC concludes that the current regulatory and legal framework in
California no longer meets the requirements to apply SFAS No. 71 to the
generation business, the Company would reevaluate the financial impact of
electric industry restructuring and a material write-off could occur.
Given the current regulatory environment, PG&E's electric transmission and
distribution businesses are expected to remain regulated and, as a result, will
continue application of the provisions of SFAS No. 71.
Gas Industry Restructuring: Restructuring of the natural gas industry on both
the national and the state level 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. Transmission and distribution services have remained "bundled," or
sold together at a combined rate, within the state. 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 (Accord). The Accord
is the result of an extensive negotiation process, begun in 1995, among a broad
coalition of customer groups and industry participants. The Accord must be
approved by the CPUC before it can be implemented. A CPUC decision is expected
in 1997.
The Accord consists of three broad initiatives:
(1) The 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.
(2) The 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 Accord
also would establish principles for continuing negotiations between PG&E and
California gas producers for
13
<PAGE>
PG&E Corporation
Management's Discussion and Analysis of
Consolidated Results of Operations and Financial Condition
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. 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.
(3) The Accord would resolve various regulatory issues (see further
discussion in Note 3 to the Consolidated Financial Statements) including:
. the disallowances ordered by the CPUC in connection with PG&E's 1988 through
1995 gas reasonableness proceedings;
. the recovery of certain capital costs associated with the PG&E portion of the
PGT/PG&E Pipeline Expansion;
. the recovery of costs related to PG&E's capacity commitments with
Transwestern Pipeline Company through 2002; and
. the recovery, through PG&E's interstate transition cost surcharge, of fixed
demand charges paid to El Paso Natural Gas Company and PGT for firm capacity
held by PG&E on behalf of its customers.
As of December 31, 1996, PG&E has reserved approximately $527 million,
including $182 million reserved during 1996, relating to its gas regulatory
issues and gas capacity commitments, the majority of which are addressed by the
Accord. PG&E believes the ultimate resolution of these matters, whether through
approval of the Accord or otherwise, will not have a material adverse impact on
its financial position or future results of operations.
Acquisitions and Sales: The Company has developed strategies to focus on the
unregulated independent power generation market, the unregulated energy services
market, and the regulated and unregulated "midstream" portions of the gas
market. As a result of this focus, the Company has been acquiring related
businesses and disposing of unrelated businesses.
Enterprises participates in multiple domestic and international energy
businesses. The majority of Enterprises' domestic investments are in
nonregulated energy projects through U.S. Generating Company (USGen), a joint
venture with Bechtel Enterprises, Inc. (Bechtel). USGen and its affiliates
develop, own, and operate power plants in the United States.
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 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.
Also in 1995, Enterprises sold DALEN Corporation (DALEN). The sales price was
$455 million, including $340 million cash and the assumption of $115 million of
existing debt. The sale resulted in an after-tax gain of approximately $13
million.
14
<PAGE>
The Company is pursuing gas-related opportunities as the gas industry
continues to evolve. In July 1996, the Company, through its subsidiary PGT,
purchased PGT Queensland State Gas Pipeline, a 389-mile natural gas
transportation system in the Australian state of Queensland. The final purchase
price was $136 million.
In December 1996, PGT entered the unregulated gas marketing arena with the
purchase of Energy Source (ESI), the North American gas marketing operations of
Edisto Resources Corporation for approximately $23 million. The purchase
included most of ESI's existing contracts for the purchase, sale, and
transportation of natural gas and natural gas futures. In 1996, ESI generated
over $1.1 billion in gas marketing revenues, of which $283 million was earned in
December 1996.
In January 1997, PG&E Corporation acquired Teco and its subsidiaries for
approximately $380 million. 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.
Also in January 1997, PG&E Corporation agreed to acquire 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 536 miles of
natural gas liquid pipeline and eight natural gas processing plants in Texas.
PG&E Corporation will acquire Valero for approximately $1.5 billion, comprised
of approximately $720 million in PG&E Corporation common stock and the
assumption of debt and liabilities. The acquisition is expected to be completed
by mid-1997 and is subject to applicable regulatory and shareholder approvals.
All of the above acquisitions have been or will be accounted for using the
purchase method of accounting.
Results of Operations: The Company's results of operations were derived from
three business lines: utility (excluding Diablo Canyon and including PGT's gas
pipeline operations), Diablo Canyon, and diversified operations (principally,
Enterprises and ESI). The results of operations and total assets for 1996, 1995,
and 1994 are reflected in the following table and discussed below:
<TABLE>
<CAPTION>
Diablo Diversified
Utility Canyon/(1)/ Operations Total
---------- ------------ ----------- ----------
(in millions, except per share
amounts)
<S> <C> <C> <C> <C>
1996
Operating revenues $ 7,411 $1,789 $ 410 $ 9,610
Operating expenses 6,465 791 458 7,714
------- ------ ------ -------
Operating income (loss)
before income taxes $ 946 $ 998 $ (48) $ 1,896
======= ====== ====== =======
Net income (loss) $ 292 $ 497 $(34)/(2)/ $ 755
======= ====== ====== =======
Earnings per
common share $ .65 $ 1.18 $(.08) $ 1.75
======= ====== ====== =======
Total assets at year end $19,283 $5,413 $1,434 $26,130
======= ====== ====== =======
1995
Operating revenues $ 7,601 $1,845 $ 176 $ 9,622
Operating expenses 5,820 816 223 6,859
------- ------ ------ -------
Operating income (loss)
before income taxes $ 1,781 $1,029 $ (47) $ 2,763
======= ====== ====== =======
Net income $ 820 $ 507 $ 12/(2)/ $ 1,339
======= ====== ====== =======
Earnings per
common share $ 1.80 $ 1.16 $ .03 $ 2.99
======= ====== ====== =======
Total assets at year end $20,090 $5,717 $1,043 $26,850
======= ====== ====== =======
1994
Operating revenues $ 8,232 $1,870 $ 248 $10,350
Operating expenses 6,732 914 280 7,926
------- ------ ------ -------
Operating income (loss)
before income taxes $ 1,500 $ 956 $ (32) $ 2,424
======= ====== ====== =======
Net income $ 539 $ 461 $ 7/(2)/ $ 1,007
======= ====== ====== =======
Earnings per
common share $ 1.15 $ 1.04 $ .02 $ 2.21
======= ====== ====== =======
Total assets at year end $20,295 $5,978 $1,436 $27,709
======= ====== ====== =======
</TABLE>
/(1)/ See Note 4 to the Consolidated Financial Statements for discussion
of allocations.
/(2)/ Includes non-operating income resulting from property sales, partnership
earnings, and investment income.
Earnings Per Common Share: Earnings per common share were $1.75, $2.99, and
$2.21 for 1996, 1995, and 1994, respectively. Utility earnings in 1996 were
lower than 1995, reflecting revenue reductions ordered in the 1996 General Rate
Case (GRC) and other related rate proceedings and reflecting several one-time
charges. The revenue reductions resulted from a lower cost of capital, lower
capital expenditures, and reductions in authorized expense levels. Actual
maintenance and other operating expenses for distribution
15
<PAGE>
PG&E Corporation
Management's Discussion and Analysis of
Consolidated Results of Operations and Financial Condition
and customer-related services increased in 1996 and exceeded levels authorized
in the 1996 GRC. These increases were primarily attributable to several projects
related to transmission and distribution system reliability, and improved
customer-related services. Additionally, PG&E recorded a charge of $.26 per
common share for contingencies related to gas transportation commitments and
recorded a charge of $.19 per common share for settlement of litigation. (See
Operating Expenses below and Notes 3 and 13 to the Consolidated Financial
Statements.) Finally, the Company recorded a charge of $.09 per common share for
write-downs of nonregulated investments.
Earnings per common share for 1995 were higher than 1994 due to fewer
one-time charges against earnings than in 1994 (see Operating Expenses below).
In addition, there were fewer scheduled refueling outages at Diablo Canyon in
1995, compared with 1994.
On a consolidated basis, the Company earned 8.5, 14.6, and 11.1 percent
returns on average common stock equity for the years ended December 31, 1996,
1995, and 1994, respectively. PG&E has received a CPUC decision which
authorizes, for 1997, a return on common equity of 11.6 percent and an overall
rate of return of 9.45 percent. However, PG&E has filed a proposal with the CPUC
to accelerate recovery of certain transition costs 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. This return would equal 90 percent of PG&E's long-term
cost of debt. PG&E's authorized long-term cost of debt was 7.52 percent in 1996.
(See Electric Industry Restructuring above.)
Common Stock Dividend: The Company's common stock dividend is based on a number
of financial considerations, including sustainability, financial flexibility,
and competitiveness with investment opportunities of similar risk. The Company's
current quarterly common stock dividend is $.30 per common share which
corresponds to an annualized dividend of $1.20 per common share. This represents
a decrease from the previous annualized dividend of $1.96 per common share. The
Company has identified a dividend payout ratio objective (dividends declared
divided by earnings available for common stock) of between 50 and 65 percent
(based on earnings exclusive of nonrecurring adjustments).
Operating Revenues: Operating revenues in 1996 decreased slightly from 1995. The
decreases in utility revenues as ordered in the 1996 GRC, discussed above, and
in Diablo Canyon revenues were offset by increased revenues from diversified
operations. Revenues from Diablo Canyon decreased due to a decline in the
generation price, as provided in the Diablo Canyon rate case settlement as
modified in 1995 (Diablo Settlement) (see Note 4 to the Consolidated Financial
Statements). This decline was partially offset by higher net generation, which
was a result of fewer scheduled refuelings in 1996 compared to 1995. Revenues
from diversified operations increased primarily due to the purchase of ESI in
December 1996. This purchase created $283 million of revenue but was partially
offset by a decline in revenue due to the sale of DALEN in 1995. (See
Acquisitions and Sales above.)
Operating revenues for 1995 decreased $728 million from 1994. The decrease in
utility revenues was primarily due to a decrease in electric energy costs caused
by favorable hydroelectric conditions and lower natural gas prices. Diablo
Canyon operating revenues decreased due to a decrease in the generation price as
provided in the modified Diablo Settlement (see Note 4 to the Consolidated
Financial Statements for further discussion). This decrease was partially offset
by favorable operating revenues from Diablo Canyon resulting from fewer
refueling days in 1995. Revenues from diversified operations decreased $72
million in 1995 compared to 1994 primarily due to the sale of DALEN in June
1995.
Operating Expenses: Operating expenses increased $855 million in 1996 compared
to 1995, primarily due to: (1) a charge of $182 million for contingencies
related to gas transportation commitments, (2) increases in the cost of gas due
to price increases, (3) increases in purchased power prices and volumes, (4)
increases in maintenance and other operating expenses for transmission and
distribution system reliability and for improved customer-related services, (5)
increases in litigation costs, and (6) an increase in the cost of gas for resale
due to the purchase of ESI in December 1996. The cost of gas increase from the
purchase of ESI was offset by revenues as discussed above.
Operating expenses decreased $1,067 million in 1995 compared to 1994
primarily due to decreased electric costs caused by favorable hydroelectric
conditions, decreased natural gas
16
<PAGE>
prices, and no workforce reduction charges in 1995. (See Note 10 to the
Consolidated Financial Statements.)
Other Income and (Expense): Other income and expense changed in 1996 compared to
1995 primarily due to write-downs of certain nonregulated investments.
Liquidity and Capital Resources:
The Company's capital requirements are funded from cash provided from operations
and, to the extent necessary, external financing. The Company's policy is to
finance its assets with a capital structure that minimizes financing costs,
maintains financial flexibility, and complies with regulatory guidelines. Based
on cash provided from operations and its capital requirements, the Company may
repurchase equity and long-term debt in order to manage the overall balance of
its capital structure.
Debt: In 1996, 1995, and 1994, the Company redeemed or repurchased $1,113, $758,
and $202 million, respectively, of long-term debt to manage the overall balance
of the Company's capital structure. Long-term debt maturing during 1996, 1995,
and 1994 was not refinanced.
Included in the 1996 repurchases is $988 million of variable and fixed
interest rate pollution control mortgage bonds and loan agreements which were
replaced with variable interest rate pollution control loan agreements. Also in
1996, the Company entered into additional loan agreements of $92 million to
finance the PGT acquisition of PGT Queensland State Gas Pipeline. In addition,
the Company used its cash balances to reduce short-term borrowings by $115
million in 1996.
In 1995, PGT issued $400 million of bonds and $70 million of medium-term
notes. In addition, PGT issued commercial paper which is classified as long-term
debt. This classification is based upon the availability of committed credit
facilities expiring in 2000 and management's intent to maintain such amounts in
excess of one year. The commercial paper outstanding was $108 and $109 million
at December 31, 1996, and 1995, respectively. Substantially all of the proceeds
of PGT's debt issued in 1995 were used to refinance outstanding debt.
PG&E issues short-term debt (principally commercial paper) to fund fuel oil,
nuclear fuel, and gas inventories, unrecovered balances in balancing accounts,
and cyclical fluctuations in daily cash flows. At December 31, 1996, and 1995,
PG&E had $681 and $796 million, respectively, of commercial paper outstanding.
PG&E maintains a $1 billion revolving credit facility which primarily provides
support for PG&E's commercial paper issuance. At maturity, commercial paper can
be either reissued or replaced with borrowings from this credit facility. The
facility can also be used for general corporate purposes. There were no
borrowings under this facility in 1996, 1995, or 1994.
In January 1997, PG&E Corporation established a $500 million revolving credit
facility in order to provide for corporate short-term liquidity needs and other
purposes.
As discussed in electric industry restructuring above, to achieve the 10
percent rate reduction for residential and small commercial customers, the
electric industry restructuring legislation authorizes utilities to finance a
portion of the transition costs with "rate reduction bonds." PG&E expects to
work with state authorities to coordinate the issuance of up to $2.5 billion of
these bonds by a special purpose entity. Once 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. PG&E does not expect to secure the bonds with the
Company's assets or unrelated future revenues.
Equity: In 1996, 1995, and 1994, PG&E received $220, $140, and $274 million,
respectively, in proceeds from the sale of common stock under the employee
Savings Fund Plan, the Dividend Reinvestment Plan, and the employee Long-term
Incentive Program.
Since 1993, the Board has authorized the Company to repurchase up to $2
billion of its common stock on the open market or in negotiated transactions.
These repurchases are funded by internally generated funds and are used to
manage the overall balance of common stock in the Company's capital structure.
Through December 31, 1996, the Company had repurchased approximately $1.5
billion of its common stock under this program. Repurchases for 1996, 1995, and
1994 were $455, $601, and $182 million, respectively.
In 1996, PG&E did not redeem or repurchase any preferred stock. In 1995 and
1994, PG&E redeemed or repurchased $331 and $75 million, respectively, of its
higher-cost preferred stock. In 1994, PG&E issued $62 million of preferred
stock.
PG&E is limited as to the amount of dividends that it may pay to PG&E
Corporation based on PG&E's regulatory capital
17
<PAGE>
PG&E Corporation
Management's Discussion and Analysis of
Consolidated Results of Operations and Financial Condition
structure authorized by the CPUC. PG&E's equity shall be retained such that, on
average, the capital structure authorized by the CPUC is maintained. This
restriction is not expected to affect PG&E Corporation's ability to meet its
cash obligations.
Other Capital: In 1995, PG&E through its wholly-owned subsidiary, PG&E Capital
I, issued $300 million of cumulative quarterly income preferred securities. Net
proceeds were used to redeem and repurchase higher-cost preferred stock.
Investing Activities: The Company's estimated capital requirements for the next
three years are shown below:
<TABLE>
<CAPTION>
Year ended December 31, 1997 1998 1999
--------- --------- ---------
(in millions)
<S> <C> <C> <C>
Utility (including PGT) $1,773 $1,825 $1,705
Diablo Canyon 38 39 41
Diversified operations 211 80 172
--------- --------- ---------
Total capital expenditures 2,022 1,944 1,918
Maturing debt and sinking funds 210 660 270
--------- --------- ---------
Total capital requirements $2,232 $2,604 $2,188
========= ========= =========
</TABLE>
Utility and Diablo Canyon expenditures will be primarily for improvements to
the Company's facilities to enhance their efficiency and reliability, to extend
their useful lives, and to comply with environmental laws and regulations.
Expenditures for diversified operations (consisting primarily of Enterprises)
include capital contributions for Enterprises' equity share of generating
facility projects. Ongoing capital expenditures for Teco are included in
diversified operations in the above estimated capital requirements.
In addition to the above, the Company, in January 1997, has acquired Teco for
approximately $380 million, consisting of a note payable of $61 million and $319
million of PG&E Corporation's common stock. Further, the Company, in January
1997, agreed to acquire Valero for approximately $1.5 billion, consisting of
approximately $720 million of PG&E Corporation's common stock and the assumption
of debt and liabilities. The Company has other commitments as discussed in Notes
3 and 12 to the Consolidated Financial Statements.
In December 1995, the Company had a balance of $734 million of cash and cash
equivalents due to the sale of DALEN and the retention of cash for potential
investments.
Risk Management: 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.
Environmental Matters: The Company's projected expenditures for environmental
protection are subject to periodic review and revision to reflect changing
technology and evolving regulatory requirements. Capital expenditures for
environmental protection are currently estimated to be approximately $36, $50,
and $72 million for 1997, 1998, and 1999, respectively. Expenditures during
these years will be primarily for nitrogen oxide (NOx) emission reduction
projects at the Company's fossil fuel generating plants and natural gas
compressor stations. Pursuant to federal and state legislation,
18
<PAGE>
local air districts have adopted rules that require reductions in NOx emissions.
These rules are subject to continued review and modification by the local air
districts in which PG&E operates. The Company currently estimates that
compliance with NOx rules could require capital expenditures of up to $360
million over the next ten years.
On an ongoing basis, the Company assesses compliance with laws and
regulations related to hazardous substance remediation. The Company has an
accrued liability at December 31, 1996, of $170 million for remediation costs at
sites where such costs are probable and quantifiable. The costs at identified
sites may be as much as $400 million if, among other things, other potentially
responsible parties are not financially able to contribute to these costs, or
identifiable possible outcomes change. The Company will seek recovery of
prudently incurred compliance 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, the
Company will seek recovery of costs from insurance carriers and from other third
parties. (See Note 13 to the Consolidated Financial Statements.)
Effective January 1, 1997, the Company will adopt the provisions of the
American Institute of Certified Public Accountants' Statement of Position (SOP)
96-1, Environmental Remediation Liabilities. This SOP provides authoritative
guidance for recognition, measurement, display, and disclosure of environmental
remediation liabilities in financial statements. The adoption of SOP 96-1 is not
expected to have a material adverse impact on the Company's financial position
or results of operations.
Legal Matters: In the normal course of business, the Company is named as a party
in a number of claims and lawsuits. Substantially all of these have been
litigated or settled with no material adverse impact on either the Company's
results of operations or financial position. In addition, the Company believes
that the litigation or settlement of pending claims and lawsuits will not have a
material adverse impact on its results of operations or financial position. See
Note 13 to the Consolidated Financial Statements for further discussion of
significant pending legal matters.
Accounting for Decommissioning Expense:
In 1996, the Financial Accounting Standards Board issued an exposure draft on a
proposed SFAS entitled "Accounting for Certain Liabilities Related to Closure or
Removal of Long-Lived Assets." If this exposure draft is adopted: (1) annual
expense for power plant decommissioning could increase, and (2) the estimated
total cost for power plant decommissioning could be recorded as a liability,
with recognition of an increase in the cost of the related power plant, rather
than accrued over time as accumulated depreciation. The Company does not believe
that this change, if implemented as proposed, would have a material adverse
impact on its results of operations due to its current and future ability to
recover decommissioning costs through rates. (See Note 2 to the Consolidated
Financial Statements for discussion of electric industry restructuring.)
Inflation: The Company's rates are designed to recover operating and historical
plant investment costs. Financial statements, which are prepared in accordance
with generally accepted accounting principles, report operating results in terms
of historic costs and do not evaluate the impact of inflation.
Inflation affects the Company's construction costs, operating expenses, and
interest charges. Due to the Company's five-year electric rate freeze, electric
revenues will not reflect the impact of inflation. However, inflation at the
levels currently being experienced is not expected to have a material adverse
impact on the Company's future results of operations.
19
<PAGE>
PG&E Corporation
Statement of Consolidated Income
<TABLE>
<CAPTION>
Year ended December 31, 1996 1995 1994
--------------- --------------- ---------------
(in thousands, except per share amounts)
<S> <C> <C> <C>
Operating Revenues
Electric utility $7,160,215 $7,386,307 $ 8,021,547
Gas utility 2,039,802 2,059,117 2,081,062
Diversified operations 409,955 176,341 247,621
--------------- --------------- ---------------
Total operating revenues 9,609,972 9,621,765 10,350,230
--------------- --------------- ---------------
Operating Expenses
Cost of electric energy 2,303,488 2,116,840 2,570,723
Cost of gas 761,837 333,280 583,356
Maintenance and other operating 2,118,174 1,799,781 1,855,585
Depreciation and decommissioning 1,221,952 1,360,118 1,397,470
Administrative and general 1,016,439 971,576 973,302
Workforce reduction costs -- (18,195) 249,097
Property and other taxes 292,497 295,380 296,911
--------------- --------------- ---------------
Total operating expenses 7,714,387 6,858,780 7,926,444
--------------- --------------- ---------------
Operating Income 1,895,585 2,762,985 2,423,786
--------------- --------------- ---------------
Interest income 72,900 72,524 79,643
Interest expense (639,823) (688,408) (729,207)
Other income and (expense) (18,459) 87,073 69,995
--------------- --------------- ---------------
Pretax Income 1,310,203 2,234,174 1,844,217
--------------- --------------- ---------------
Income Taxes 554,994 895,289 836,767
--------------- --------------- ---------------
Net Income 755,209 1,338,885 1,007,450
Preferred dividend requirement and redemption premium 33,113 70,288 57,603
--------------- --------------- ---------------
Earnings Available for Common Stock $ 722,096 $1,268,597 $ 949,847
=============== =============== ===============
Weighted Average Common Shares Outstanding 412,542 423,692 429,846
Earnings Per Common Share $ 1.75 $ 2.99 $ 2.21
Dividends Declared Per Common Share $ 1.77 $ 1.96 $ 1.96
</TABLE>
The accompanying Notes to the Consolidated Financial Statements are an integral
part of this statement.
20
<PAGE>
PG&E Corporation
Statement of Consolidated Cash Flows
<TABLE>
<CAPTION>
Year ended December 31, 1996 1995 1994
------------ ------------ ------------
(in thousands)
<S> <C> <C> <C>
Cash Flows From Operating Activities
Net income $ 755,209 $ 1,338,885 $ 1,007,450
Adjustments to reconcile net income to net cash provided by
operating activities
Depreciation and decommissioning 1,221,952 1,360,118 1,397,470
Amortization 93,948 89,353 95,331
Deferred income taxes and tax credits--net (149,990) (116,069) 15,312
Other deferred charges 94,475 61,700 32,740
Other noncurrent liabilities 113,244 (17,218) 181,902
Noncurrent balancing account liabilities and other deferred credits (185,390) (69,787) 316,920
Net effect of changes in operating assets and liabilities
Accounts receivable (46,368) 212,515 (116,936)
Regulatory balancing accounts receivable 302,188 498,756 (269,250)
Inventories 32,043 32,409 66,783
Accounts payable 193,012 49,702 (110,033)
Accrued taxes 36,014 (162,374) 132,892
Other working capital (6,234) 8,304 5,821
Other--net 156,773 50,423 191,285
------------ ------------ ------------
Net cash provided by operating activities 2,610,876 3,336,717 2,947,687
------------ ------------ ------------
Cash Flows From Investing Activities
Capital expenditures (1,230,331) (944,618) (1,126,904)
Diversified operations (99,532) (178,874) (308,810)
Acquisition of PGT Queensland Gas Pipeline (136,227) -- --
Acquisition of Energy Source (23,270) -- --
Proceeds from sale of DALEN -- 340,000 --
Other--net (119,923) (122,913) (29,914)
------------ ------------ ------------
Net cash used by investing activities (1,609,283) (906,405) (1,465,628)
------------ ------------ ------------
Cash Flows From Financing Activities
Common stock issued 219,726 139,595 274,269
Common stock repurchased (455,278) (601,360) (181,558)
Preferred stock issued -- -- 62,312
Preferred stock redeemed or repurchased -- (358,212) (82,875)
Company obligated mandatorily redeemable preferred securities issued -- 300,000 --
Long-term debt issued 1,087,732 591,160 60,907
Long-term debt matured, redeemed, or repurchased (1,471,390) (1,296,549) (436,673)
Short-term debt issued (redeemed)--net (115,243) 305,262 (239,478)
Dividends paid (843,997) (891,270) (891,850)
Other--net (14,036) (21,543) 28,721
------------ ------------ ------------
Net cash used by financing activities (1,592,486) (1,832,917) (1,406,225)
------------ ------------ ------------
Net Change in Cash and Cash Equivalents (590,893) 597,395 75,834
Cash and Cash Equivalents at January 1 734,295 136,900 61,066
------------ ------------ ------------
Cash and Cash Equivalents at December 31 $ 143,402 $ 734,295 $ 136,900
============ ============ ============
Supplemental disclosures of cash flow information
Cash paid for
Interest (net of amounts capitalized) $ 598,394 $ 644,978 $ 674,758
Income taxes 639,813 1,125,635 712,777
</TABLE>
The accompanying Notes to the Consolidated Financial Statements are an integral
part of this statement.
21
<PAGE>
PG&E Corporation
Consolidated Balance Sheet
<TABLE>
<CAPTION>
December 31, 1996 1995
------------- -------------
(in thousands)
<S> <C> <C>
Assets
Plant in Service
Electric
Nonnuclear $18,099,342 $17,530,446
Diablo Canyon 6,658,137 6,646,853
Gas 8,138,106 7,732,681
------------- -------------
Total plant in service (at original cost) 32,895,585 31,909,980
Accumulated depreciation and decommissioning (14,301,934) (13,311,500)
------------- -------------
Net plant in service 18,593,651 18,598,480
------------- -------------
Construction Work in Progress 414,229 333,263
Other Noncurrent Assets
Nuclear decommissioning funds 882,929 769,829
Investment in nonregulated projects 817,259 855,962
Other assets 134,271 130,128
------------- -------------
Total other noncurrent assets 1,834,459 1,755,919
------------- -------------
Current Assets
Cash and cash equivalents 143,402 734,295
Accounts receivable, net 1,499,674 1,268,936
Regulatory balancing accounts receivable 444,156 746,344
Inventories
Materials and supplies 185,771 181,763
Gas stored underground 130,229 146,499
Fuel oil 23,433 40,756
Nuclear fuel 190,652 175,957
Prepayments 54,116 47,025
------------- -------------
Total current assets 2,671,433 3,341,575
------------- -------------
Deferred Charges
Income tax-related deferred charges 1,133,043 1,079,673
Other deferred charges 1,483,110 1,741,380
------------- -------------
Total deferred charges 2,616,153 2,821,053
------------- -------------
Total Assets $26,129,925 $26,850,290
============= =============
</TABLE>
The accompanying Notes to the Consolidated Financial Statements are an integral
part of this statement.
22
<PAGE>
PG&E Corporation
Consolidated Balance Sheet
<TABLE>
<CAPTION>
December 31, 1996 1995
------------ ------------
(in thousands)
<S> <C> <C>
Capitalization and Liabilities
Capitalization
Common stock equity $ 8,363,301 $ 8,599,133
Preferred stock without mandatory redemption provisions 402,056 402,056
Preferred stock with mandatory redemption provisions 137,500 137,500
Company obligated mandatorily redeemable preferred securities of trust
holding solely PG&E subordinated debentures 300,000 300,000
Long-term debt 7,770,067 8,048,546
------------ ------------
Total capitalization 16,972,924 17,487,235
------------ ------------
Current Liabilities
Short-term borrowings 680,900 829,947
Current portion of long-term debt 209,867 304,204
Accounts payable
Trade creditors 834,143 413,972
Other 365,499 387,747
Accrued taxes 310,271 274,093
Amounts due customers 186,899 49,175
Deferred income taxes 157,064 227,782
Interest payable 63,193 70,179
Dividends payable 123,310 205,467
Other 309,104 455,798
------------ ------------
Total current liabilities 3,240,250 3,218,364
------------ ------------
Deferred Credits and Other Noncurrent Liabilities
Deferred income taxes 3,941,435 3,933,765
Deferred tax credits 379,563 393,255
Noncurrent balancing account liabilities 120,858 185,647
Other 1,474,895 1,632,024
------------ ------------
Total deferred credits and other noncurrent liabilities 5,916,751 6,144,691
------------ ------------
Commitments and Contingencies (Notes 1, 2, 3, 12, and 13) -- --
------------ ------------
Total Capitalization and Liabilities $26,129,925 $26,850,290
============ ============
</TABLE>
23
<PAGE>
PG&E Corporation
<TABLE>
<CAPTION>
Statement of Consolidated Common Stock Equity, Preferred Stock, and Preferred Securities
Preferred Preferred
Stock Stock
Total Without With
Additional Common Mandatory Mandatory
Common Paid-in Reinvested Stock Redemption Redemption
(dollars in thousands) Stock Capital Earnings Equity Provisions Provisions
---------- ---------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C> <C>
Balance December 31, 1993 $2,136,095 $3,666,455 $2,643,487 $8,446,037 $ 807,995 $ 75,000
---------- ---------- ---------- ---------- ---------- ----------
Net income 1,007,450 1,007,450
Common stock issued
(10,508,483 shares) 52,543 221,726 274,269
Common stock repurchased
(7,485,001 shares) (37,425) (66,334) (77,799) (181,558)
Preferred stock issued
(2,500,000 shares) (188) (188) 62,500
Preferred stock redeemed
(3,000,000 shares) (5,331) (2,544) (7,875) (75,000)
Cash dividends declared
Preferred stock (58,203) (58,203)
Common stock (840,627) (840,627)
Other (9,820) 5,540 (4,280)
---------- ---------- ---------- ---------- ---------- ----------
Balance December 31, 1994 2,151,213 3,806,508 2,677,304 8,635,025 732,995 137,500
---------- ---------- ---------- ---------- ---------- ----------
Net income 1,338,885 1,338,885
Common stock issued
(5,316,876 shares) 26,584 113,011 139,595
Common stock repurchased
(21,533,977 shares) (107,669) (195,383) (298,308) (601,360)
Preferred securities issued/(1)/
(12,000,000 shares) 300,000
Preferred stock redeemed or
repurchased (13,237,554 shares) (7,814) (19,459) (27,273) (330,939)
Cash dividends declared
Preferred stock (56,006) (56,006)
Common stock (829,828) (829,828)
Other 95 95
---------- ---------- ---------- ---------- ---------- ----------
Balance December 31, 1995 2,070,128 3,716,322 2,812,683 8,599,133 402,056 437,500
---------- ---------- ---------- ---------- ---------- ----------
Net income 755,209 755,209
Common stock issued
(9,290,102 shares) 46,448 173,278 219,726
Common stock repurchased
(19,811,396 shares) (99,055) (182,088) (174,135) (455,278)
Cash dividends declared
Preferred stock (33,113) (33,113)
Common stock (728,727) (728,727)
Other 2,381 3,970 6,351
---------- ---------- ---------- ---------- ---------- ----------
Balance December 31, 1996 $2,017,521 $3,709,893 $2,635,887 $8,363,301 $ 402,056 $437,500
========== ========== ========== ========== ========== ==========
</TABLE>
/(1)/ Relates to company obligated mandatorily redeemable preferred securities
of trust holding solely PG&E subordinated debentures.
The accompanying Notes to the Consolidated Financial Statements are an integral
part of this statement.
24
<PAGE>
PG&E Corporation
Statement of Consolidated Capitalization
<TABLE>
<CAPTION>
December 31, 1996 1995
------------ -----------
(dollars in thousands, except per share amounts)
<S> <C> <C>
Common Stock Equity
Common stock, par value $5 per share (authorized 800,000,000 shares, issued and
outstanding 403,504,292 and 414,025,856) $ 2,017,521 $ 2,070,128
Additional paid-in capital 3,709,893 3,716,322
Reinvested earnings 2,635,887 2,812,683
------------ -----------
Common stock equity 8,363,301 8,599,133
Preferred Stock and Preferred Securities
Preferred stock without mandatory redemption provisions
Par value $25 per share/(1)/
Nonredeemable
5% to 6%--5,784,825 shares outstanding 144,621 144,621
Redeemable
4.36% to 7.44%--10,297,404 shares outstanding 257,435 257,435
------------ -----------
Total preferred stock without mandatory redemption provisions 402,056 402,056
------------ -----------
Preferred stock with mandatory redemption provisions
Par value $25 per share/(1)/
6.30% and 6.57%--5,500,000 shares outstanding, due 2002-2009 137,500 137,500
------------ -----------
Preferred stock 539,556 539,556
------------ -----------
Company obligated mandatorily redeemable preferred securities of trust holding
solely PG&E subordinated debentures
7.90%--12,000,000 shares outstanding, due 2025 300,000 300,000
------------ -----------
Long-Term Debt
PG&E long-term debt
First and refunding mortgage bonds
Maturity Interest rates
1996-2001 4.50% to 8.75% 880,450 915,249
2002-2006 5.875% to 7.875% 1,392,135 1,450,000
2007-2012 6.25% to 8.875% 475,000 477,870
2013-2019 7.5% to 8.2% 45,000 105,000
2020-2026 5.85% to 8.875% 2,627,736 2,749,651
------------ -----------
Principal amounts outstanding 5,420,321 5,697,770
Unamortized discount net of premium (49,923) (55,802)
------------ -----------
Total mortgage bonds 5,370,398 5,641,968
Debentures, 12%, due 2000 57,539 57,539
Pollution control loan agreements, variable rates, due 2016-2026 987,870 925,000
Unsecured medium-term notes, 4.93% to 9.9%, due 1997-2014 828,900 1,096,400
Unamortized discount related to unsecured medium-term notes (1,187) (1,652)
Other long-term debt 32,800 20,298
------------ -----------
Total PG&E long-term debt 7,276,320 7,739,553
Long-term debt of PGT and Enterprises 703,614 613,197
------------ -----------
Total long-term debt 7,979,934 8,352,750
Less current portion 209,867 304,204
------------ -----------
Long-term debt, excluding current portion 7,770,067 8,048,546
------------ -----------
Total Capitalization $16,972,924 $17,487,235
============ ===========
</TABLE>
/(1)/ Authorized 75,000,000 shares in total (both with and without mandatory
redemption provisions).
The accompanying Notes to the Consolidated Financial Statements are an integral
part of this statement.
25
<PAGE>
PG&E Corporation
Statement of Consolidated Segment Information
<TABLE>
<CAPTION>
Electric Gas Diversified Intersegment
(in thousands) Utility Utility Operations/(4)/ Eliminations Total
------------ ----------- -------------- -------------- ------------
<S> <C> <C> <C> <C> <C>
1996
Operating revenues $ 7,160,215 $2,039,802 $ 409,955 $ -- $ 9,609,972
Intersegment revenues/(1)/ 12,156 69,645 -- (81,801) --
------------ ----------- -------------- -------------- ------------
Total operating revenues $ 7,172,371 $2,109,447 $ 409,955 $(81,801) $ 9,609,972
============ =========== ============== ============== ============
Depreciation and decommissioning $ 919,958 $ 288,994 $ 13,000 $ -- $ 1,221,952
Operating income before
income taxes/(2)/ 1,757,611 184,506 (47,921) 1,389 1,895,585
Capital expenditures/(3)/ 921,425 459,074 23,270 -- 1,403,769
Identifiable assets/(3)/ $18,005,105 $6,215,028 $1,434,216 $ -- $25,654,349
Corporate assets 475,576
------------
Total assets at year end $26,129,925
============
1995
Operating revenues $ 7,386,307 $2,059,117 $ 176,341 $ -- $ 9,621,765
Intersegment revenues/(1)/ 12,678 85,356 -- (98,034) --
------------ ----------- -------------- -------------- ------------
Total operating revenues $ 7,398,985 $2,144,473 $ 176,341 $(98,034) $ 9,621,765
============ =========== ============== ============== ============
Depreciation and decommissioning $ 1,007,467 $ 306,717 $ 45,934 $ -- $ 1,360,118
Operating income before
income taxes/(2)/ 2,267,193 540,378 (46,618) 2,032 2,762,985
Capital expenditures/(3)/ 679,866 282,724 2,067 -- 964,657
Identifiable assets/(3)/ $18,610,610 $6,064,596 $1,042,764 $ -- $25,717,970
Corporate assets 1,132,320
------------
Total assets at year end $26,850,290
============
1994
Operating revenues $ 8,021,547 $2,081,062 $ 247,621 $ -- $10,350,230
Intersegment revenues/(1)/ 12,852 85,341 -- (98,193) --
------------ ----------- -------------- -------------- ------------
Total operating revenues $ 8,034,399 $2,166,403 $ 247,621 $(98,193) $10,350,230
============ =========== ============== ============== ============
Depreciation and decommissioning $ 982,859 $ 295,979 $ 118,632 $ -- $ 1,397,470
Operating income before
income taxes/(2)/ 2,187,569 271,537 (32,093) (3,227) 2,423,786
Capital expenditures/(3)/ 834,494 292,000 19,456 -- 1,145,950
Identifiable assets/(3)/ $19,637,222 $6,167,314 $1,436,128 $ -- $27,240,664
Corporate assets 467,900
-----------
Total assets at year end $27,708,564
============
</TABLE>
/(1)/ Intersegment electric and gas revenues are accounted for at tariff rates
prescribed by the CPUC.
/(2)/ General corporate expenses are allocated in accordance with FERC Uniform
System of Accounts and requirements of the CPUC.
/(3)/ Includes an allocation of common plant in service and allowance for funds
used during construction.
/(4)/ Represents the nonregulated operations of wholly-owned subsidiaries
including Enterprises, Mission Trail Insurance Ltd. (liability
insurance), and Energy Source (gas marketing).
The accompanying Notes to the Consolidated Financial Statements are an integral
part of this schedule.
26
<PAGE>
PG&E Corporation
Notes to Consolidated Financial Statements
Note 1: Significant Accounting Policies
Corporate Restructuring: Effective January 1, 1997, Pacific Gas and Electric
Company (PG&E) became a subsidiary of its new parent holding company, PG&E
Corporation. PG&E's ownership interest in Pacific Gas Transmission Company (PGT)
and PG&E Enterprises (Enterprises) was transferred to PG&E Corporation. PG&E's
outstanding common stock was converted on a share-for-share basis into PG&E
Corporation's outstanding common stock. PG&E's debt securities and preferred
stock were unaffected and remain securities of PG&E. The members of PG&E's
current Board of Directors became directors of PG&E Corporation.
Basis of Presentation: The consolidated financial statements 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. All significant intercompany transactions have been
eliminated. Certain amounts in the prior years' consolidated financial
statements have been reclassified to conform to the 1996 presentation.
The preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions.
These estimates and assumptions affect the reported amounts of revenues,
expenses, assets, and liabilities and disclosure of contingencies. Actual
results could differ from these estimates.
Operations: The Company and its subsidiaries provide electric and natural gas
services and retail energy services. PG&E is a regulated public utility which
provides generation, procurement, transmission, and distribution of electricity
and natural gas throughout most of Northern and Central California. PGT
transports gas from the Canadian border to the California border and the Pacific
Northwest. PGT also has operations in Australia and Texas. Enterprises, through
its subsidiaries and affiliates, develops, owns, and operates electric and gas
projects and provides energy services.
Regulation: PG&E is regulated by the California Public Utilities Commission
(CPUC), the Federal Energy Regulatory Commission (FERC), and the Nuclear
Regulatory Commission, among others. PG&E currently accounts for the economic
effects of regulation in accordance with Statement of Financial Accounting
Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of
Regulation." This statement allows the Company to record certain regulatory
assets and liabilities which would be included in future rates and would not be
recorded under generally accepted accounting principles for nonregulated
entities.
Effective January 1, 1996, the Company adopted SFAS No. 121, "Accounting for
the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed
Of." SFAS No. 121 prescribes general standards for the recognition and
measurement of impairment losses. In addition, it requires that regulatory
assets continue to be probable of recovery in rates, rather than only at the
time the regulatory asset is recorded. Regulatory assets currently recorded
would be written off if recovery is no longer probable. Adoption of this
standard had no material impact on the Company's financial position or results
of operations.
On an ongoing basis, PG&E reviews its regulatory assets and liabilities for
the continued applicability of SFAS No. 71 and the effect of SFAS No. 121. (See
Note 2 for further discussion.)
Net regulatory assets and liabilities include the following:
<TABLE>
<CAPTION>
December 31, 1996 1995
------ ------
(in millions)
<S> <C> <C>
Deferred income tax $1,133 $1,080
Unamortized loss net of gain on reacquired debt 377 392
Diablo Canyon pre-settlement costs 364 382
Workers' compensation and disability claims costs 288 297
Regulatory balancing accounts (net) 323 561
Other deferred (net) 267 474
------ ------
$2,752 $3,186
====== ======
</TABLE>
Revenues and Regulatory Balancing Accounts: Revenues are recorded primarily for
delivery of gas and electric energy to customers. Electric and gas utility
revenues include amounts for services rendered but unbilled at the end of the
year. Revenues also are recorded for changes in regulatory balancing accounts
established by the CPUC. Specifically, sales balancing accounts accumulate
differences between authorized and actual base revenues. Energy cost balancing
accounts accumulate differences between the actual cost of gas and electric
energy and the revenues designated for recovery of such costs. Recovery of gas
and electric energy costs through energy cost balancing accounts is subject to
27
<PAGE>
PG&E Corporation
Notes to Consolidated Financial Statements
reasonableness reviews by the CPUC. The regulatory balancing accounts accumulate
balances until they are refunded to or received from utility customers through
authorized rate adjustments.
Dividend Restriction: PG&E is limited as to the amount of dividends that it may
pay to PG&E Corporation based on PG&E's regulatory capital structure authorized
by the CPUC. PG&E's equity shall be retained such that, on average, the capital
structure authorized by the CPUC is maintained. This restriction is not expected
to affect PG&E Corporation's ability to meet its cash obligations.
Financial Derivative Instruments (Derivatives): The Company engages in price
risk management activities to manage risks associated with changes in energy
commodity prices, interest rates, and foreign currencies. These price risk
management activities include the use of derivatives.
Gains and losses on derivatives used for hedging purposes are intended to
offset losses and gains on the underlying hedged item. Under hedge accounting,
changes in the market value of these transactions are deferred and recognized as
an addition to the income or expense of the underlying instrument upon
completion of the underlying transaction. All 1996 transactions were accounted
for using hedge accounting. Gains and losses associated with derivative
transactions during 1996 were immaterial.
Plant in Service: The cost of plant additions and replacements includes labor,
materials, construction overhead, and an allowance for funds used during
construction (AFUDC) or capitalized interest. AFUDC is the estimated cost of
debt and equity funds used to finance regulated plant additions. Capitalized
interest is the interest incurred on borrowed funds used to finance nonregulated
plant additions. The original cost of retired plant and removal costs less
salvage value is charged to accumulated depreciation upon retirement of plant in
service.
Plant in service is depreciated using a straight-line remaining-life method.
The Company's composite depreciation rates were 3.65, 4.09, and 4.31 percent for
the years ended December 31, 1996, 1995, and 1994.
Nuclear Decommissioning Costs: 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
of each facility.
For the years ended December 31, 1996, 1995, and 1994, nuclear
decommissioning costs recovered in rates through an annual allowance were $33,
$54, and $54 million, respectively. Based on the 1994 site study, the amount
assumed to be recovered in rates in 1997 and annually up to the commencement of
decommissioning is $33 million. This amount will be reviewed in future rate
proceedings.
At December 31, 1996, the total nuclear decommissioning obligation accrued
was $889 million and was included in the balance sheet classification of
Accumulated Depreciation and Decommissioning.
Decommissioning costs recovered in rates are placed in external trust funds.
These funds along with accumulated earnings will be used exclusively for
decommissioning. (See Note 8 for further discussion of nuclear decommissioning
funds.)
Decommissioning is scheduled to begin for Diablo Canyon Nuclear Power Plant's
(Diablo Canyon) Unit 1 and Unit 2 in 2015 and 2016, respectively, with scheduled
completion for both units in 2034. The decommissioning method selected for
Diablo Canyon anticipates that the facilities will be decontaminated to a level
that permits the property to be released for unrestricted use.
Decommissioning for Humboldt Bay Power Plant is scheduled to begin in 2015.
The decommissioning method selected consists of placing and maintaining the
facility in protective storage until some future time when dismantling can be
initiated.
PG&E, as required by federal law, has signed a contract with the U.S.
Department of Energy (DOE) to provide for the
28
<PAGE>
disposal of 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. The DOE's current estimate
for an available site to begin accepting physical possession of the spent
nuclear fuel is 2010.
At the projected level of operation for Diablo Canyon, PG&E's facilities are
sufficient to store on-site all spent fuel produced through approximately 2006.
It is likely that an interim or permanent DOE storage facility will not be
available for Diablo Canyon's spent fuel by 2006. 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.
Gains and Losses on Reacquired Debt: Gains and losses on reacquired debt charged
to operations subject to the provisions of SFAS No. 71 are deferred and
amortized over the remaining original lives of the debt reacquired, consistent
with ratemaking principles. Gains and losses on reacquired debt associated with
other operations are recognized in earnings at the time such debt is reacquired.
Inventories: Stored nuclear fuel inventory is stated at lower of average cost or
market. Nuclear fuel in the reactor is amortized based on the amount of energy
output. Other inventories are valued at average cost except for fuel oil, which
is valued by the last-in-first-out method.
Cash Equivalents: Cash equivalents (stated at cost, which approximates market)
include working funds and short-term investments with original maturities of
three months or less.
Note 2: Electric Industry Restructuring
In 1995, the CPUC issued a decision that provides a plan to restructure
California's electric utility industry. The decision acknowledges that much of
utilities' current costs and commitments result from past CPUC decisions and
that, in a competitive generation market, utilities would not recover some of
these costs through market-based revenues. To assure the continued financial
integrity of California utilities, the CPUC authorized recovery of these
above-market costs, called "transition costs."
In 1996, California legislation was passed that adopts the basic tenets of
the CPUC's restructuring decision, including recovery of transition costs. In
addition, the legislation provides a 10 percent rate reduction for residential
and small commercial customers by January 1, 1998, freezes electric customer
rates for all other customers, and requires the accelerated recovery of
transition costs associated with owned generation facilities. The legislation
also establishes the operating framework for a competitive generation market.
The rate freeze will continue until the earlier of March 31, 2002, or until
PG&E has recovered its transition costs (the transition period). The freeze will
hold rates at 1996 levels for all customers except those receiving the 10
percent rate reduction. The rate freeze will hold the rates for these customers
at the reduced level.
To achieve the 10 percent rate reduction, the legislation authorizes
utilities to finance a portion of their transition costs with "rate reduction
bonds." 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 this portion of transition costs is
financed, PG&E would collect a bond service payment 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 percent reduction in
rates.
Tax-exempt trusts have been established to oversee the development of the
operating framework for the competitive generation market. The CPUC has
authorized California utilities to guarantee bank loans of up to $250 million to
be used by the trusts for this purpose. Under this authorization, PG&E will
guarantee a maximum of $112.5 million of these loans.
Transition Cost Recovery: The legislation authorizes the CPUC to determine the
costs eligible for recovery as transition costs. The amount of costs will be
based on the aggregate of above-market and below-market values of utility-owned
generation assets and obligations. PG&E has proposed that costs eligible for
transition cost recovery include: (1) above-market sunk costs (costs associated
with utility generating facilities that are fixed and unavoidable and currently
collected through rates) and future costs, such as costs related to plant
removal,
29
<PAGE>
PG&E Corporation
Notes to Consolidated Financial Statements
(2) above-market costs associated with purchase power obligations with
Qualifying Facilities (QFs) and other Power Purchase Agreements, and (3)
generation-related regulatory assets and obligations. PG&E cannot determine the
exact amount of sunk costs that will be above market and recoverable as
transition costs until a market valuation process (appraisal or sale) is
completed for each generation facility. This process will be completed during
the transition period.
Most transition costs must be recovered by March 1, 2002. However, the
legislation authorizes recovery of certain transition costs after that time.
These costs include: (1) certain employee-related transition costs, (2) payments
under existing QF and power purchase contracts, and (3) unrecovered
implementation costs. Excluding these exceptions, any transition costs not
recovered during the transition period will be absorbed by PG&E. Nuclear
decommissioning costs, which are not considered transition costs, will be
recovered through a CPUC authorized charge. During the transition period, this
charge will be incorporated into the frozen rates. After the transition period,
customers will be assessed a surcharge until the nuclear decommissioning costs
are fully recovered.
PG&E's ability to recover its transition costs during the transition period
will be dependent on several factors. These factors include: (1) the extent to
which application of the current regulatory framework established by the
restructuring legislation will continue to be applied, (2) the amount of
transition costs approved by the CPUC, (3) the market value of its generation
plants, (4) future sales levels, (5) fuel and operating costs, (6) the market
price of electricity, and (7) the ratemaking methodology adopted for Diablo
Canyon. Considering its current evaluation of these factors, PG&E believes it
will recover its transition costs and that its owned generation plants are not
impaired. However, a change in these factors could affect the probability of
recovery of transition costs and result in a material loss.
PG&E has proposed to implement portions of its transition cost recovery plan
in 1997. The CPUC decision on PG&E's 1997 Energy Cost Adjustment Clause (ECAC)
application would decrease PG&E's 1997 revenue requirement by $720 million. This
decrease would be partially offset by a $160 million revenue requirement
increase, provided by the legislation, for purposes of enhancing transmission
and distribution system safety and reliability. This increase was approved by
the CPUC as part of PG&E's transition cost recovery plan.
Given the electric customer rate freeze, the $560 million net revenue
requirement decrease resulting from the consolidation of the ECAC decision and
the revenue requirement increase contemplated in the cost recovery plan would be
available for transition cost recovery. The proposed accelerated recovery of
Diablo Canyon would absorb an estimated $400 million of this available revenue
requirement. The remaining revenue requirement would be available to recover
other transition costs.
Accounting for the Effects of Regulation: As a result of applying the provisions
of SFAS No. 71 (discussed in Note 1 above), PG&E has accumulated approximately
$1.6 billion of regulatory assets attributable to electric generation at
December 31, 1996. The net investments in Diablo Canyon and the other generation
assets were $4.5 and $2.7 billion, respectively, at December 31, 1996. The net
present value of above-market QF power purchase obligations is estimated to be
$5.3 billion at January 1, 1998, at an assumed market price of $0.025 per
kilowatt-hour (kWh) beginning in 1997 and escalating at 3.2 percent per year.
PG&E believes that the restructuring legislation establishes a definitive
transition to market-based pricing for electric generation. Incorporating the
effects of the competitive auction pricing of electricity and customer direct
access, this transition includes cost-of-service based ratemaking. In addition,
PG&E's generation-related transition costs will be collected through a
nonbypassable charge. Based on this structure, PG&E believes it will continue to
meet the requirements of SFAS No. 71 throughout the transition period.
At the conclusion of the transition period, PG&E believes it will be at risk
to recover its generation costs through market-based revenues. At that time,
PG&E expects to discontinue the application of SFAS No. 71 for the electric
generation portion of its business. Since PG&E anticipates it will have
recovered all transition costs required to be recovered during the transition
period, including generation-related regulatory assets and above-market
investments in net plant, PG&E does not expect a material adverse impact on its
financial position or results of operations from discontinuing the application
at that time.
As a result of the CPUC's restructuring decision and California's electric
industry restructuring legislation, the Securities and Exchange Commission (SEC)
has begun inquiries regarding the appropriateness of the continued application
of
30
<PAGE>
SFAS No. 71 by California utilities to their electric generation businesses. As
discussed above, PG&E believes it currently meets and will continue to meet the
requirements to apply SFAS No. 71 during the transition period. In the event
that the SEC concludes that the current regulatory and legal framework in
California no longer meets the requirements to apply SFAS No. 71 to the
generation business, the Company would reevaluate the financial impact of
electric industry restructuring and a material write-off could occur.
Given the current regulatory environment, PG&E's electric transmission and
distribution businesses are expected to remain regulated and, as a result, will
continue application of the provisions of SFAS No. 71.
Note 3: Natural Gas Matters
The Gas Accord Settlement (Accord): In an effort to promote competition and to
give all residential and smaller commercial (core) customers the same options
that exist for industrial and larger commercial (noncore) customers, PG&E
submitted the Accord to the CPUC in 1996. In addition to offering increased
customer choice, the Accord would establish gas transmission rates for the
period July 1997 through December 2002 and resolve various pending regulatory
issues. The Accord must be approved by the CPUC before it can be implemented. A
CPUC decision is expected in 1997.
The major outstanding gas regulatory issues that the Accord would resolve
include the 1988 through 1995 gas reasonableness proceedings, the initial
capital costs for the PG&E Pipeline Expansion, the interstate transition cost
surcharge (ITCS) recovery, and the PG&E pipeline transportation commitments, all
of which are discussed in further detail below.
As of December 31, 1996, PG&E has reserved approximately $527 million,
including $182 million reserved during 1996, relating to its gas regulatory
issues and gas capacity commitments, the majority of which are addressed by the
Accord. The Company believes the ultimate resolution of these matters, whether
through approval of the Accord or otherwise, will not have a material adverse
impact on its financial position or future results of operations.
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 reasonable. Under the current regulatory framework, annual reasonableness
proceedings are conducted by the CPUC on a historic calendar year basis.
In 1994, the CPUC issued a decision which ordered a disallowance of
approximately $90 million of gas costs plus accrued interest of approximately
$25 million through 1993 for PG&E's Canadian gas procurement activities from
1988 through 1990. PG&E has filed a lawsuit in a federal district court
challenging the CPUC's decision on Canadian gas costs. PG&E expects this issue
to be resolved as part of the Accord discussed above. Under the Accord, PG&E
would agree to forgo recovery of the $90 million disallowance ordered in the
1988 through 1990 gas reasonableness proceeding, irrespective of the outcome of
the lawsuit.
A number of other reasonableness issues related to PG&E's gas procurement
practices, transportation capacity commitments, and supply operations for
periods dating from 1988 to 1994 were resolved when the CPUC accepted a
settlement in December 1996 between PG&E and the Office of Ratepayer Advocates
(ORA) of the CPUC. Under the terms of that settlement, PG&E will return $67
million plus interest to ratepayers in 1997. PG&E has previously recorded
reserves for this settlement.
PGT/PG&E Pipeline Expansion: In November 1993, the Company expanded its natural
gas transmission system providing additional firm transportation capacity from
the Canadian border to Northern and Southern California and the Pacific
Northwest.
PG&E has filed an application with the CPUC requesting that capital costs of
$810 million and ongoing operating costs for the PG&E, or California, portion of
the Pipeline Expansion be found reasonable. Revenues are currently being
collected under interim rates approved by the CPUC, subject to adjustment.
In 1996, a CPUC Administrative Law Judge (ALJ) ordered consolidation of the
market impact phase of the PG&E Pipeline Expansion reasonableness proceeding and
the ITCS proceeding discussed below. 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 Pipeline Expansion. Were the CPUC to reverse
its previous decision, which found that PG&E was reasonable in constructing the
PG&E Pipeline Expansion, the ultimate outcome could have an adverse impact on
PG&E's ability to recover its cost for unused
31
<PAGE>
PG&E Corporation
Notes to Consolidated Financial Statements
capacity on other pipelines as well as on its own intrastate facilities. PG&E
expects these issues to be resolved as part of the Accord discussed above. Under
the Accord, PG&E would agree to set rates for the PG&E Pipeline Expansion based
on total capital costs of $736 million.
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 agreements (excluding agreements with PGT) were
approximately $212, $175, and $225 million in 1996, 1995, and 1994,
respectively.
The following table summarizes the approximate capacity held by PG&E on
various pipelines (excluding PGT) and the related annual demand charges at
December 31, 1996:
<TABLE>
<CAPTION>
Total
Annual
Firm Gross
Capacity Demand
Pipeline Held Charges Contract
Company (MMcf/d) (in millions) Expiration
--------------- --------------- ---------------
<S> <C> <C> <C>
El Paso 1,140 $163 Dec. 1997
Transwestern 200 $ 29 Mar. 2007
NOVA 600 $ 20 Oct. 2001
ANG 600 $ 13 Oct. 2005
</TABLE>
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). To serve these customers, PG&E holds
approximately 600 million cubic feet per day (MMcf/d) of firm capacity for its
core and core subscription customers on each of the pipelines owned by El Paso
Natural Gas Company (El Paso), NOVA Corporation of Alberta (NOVA), Alberta
Natural Gas Company Ltd (ANG), and PGT.
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
Pipeline Company (Transwestern) that will be brokered or assigned.
Substantially all demand charges incurred by PG&E for pipeline capacity are
eligible for rate recovery, subject to a reasonableness review. These demand
charges include 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 December 1995, the CPUC issued a decision on the reasonableness of PG&E's
1992 operations, concluding 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 unless PG&E can demonstrate that the benefits of the commitment
outweigh the costs.
The recovery of demand charges associated with capacity which was formerly
used to serve PG&E's noncore customers will be decided by the CPUC in the ITCS
proceeding, unless otherwise resolved as part of the Accord. Pending a final
decision in the ITCS proceeding, the CPUC has approved collection (subject to
refund) in rates of approximately 50 percent of the demand charges for
unbrokered or discounted El Paso and PGT capacity which was formerly used to
serve PG&E's noncore customers.
Under the Accord, 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. Also as
part of the Accord, PG&E would forgo recovery of 100 percent and 50 percent of
the ITCS amounts allocated to its core and noncore customers, respectively.
The Company believes ultimate resolution of its capacity commitments and the
ITCS proceeding, either through approval of the Accord or otherwise, will not
have a material adverse impact on its financial position or future results of
operations.
Note 4: Diablo Canyon
The Diablo Canyon rate case settlement as adopted in 1988 and modified in 1995
(Diablo Settlement) bases revenues primarily on the amount of electricity
generated by Diablo Canyon. The Diablo Settlement provides that Diablo Canyon
costs and operations are not subject to CPUC reasonableness reviews. Only
certain Diablo Canyon costs may be recovered
32
<PAGE>
through base revenues over the term of the Diablo Settlement, including a full
return on such costs. The revenues to recover all Diablo Canyon costs are
included in Diablo Canyon operating revenues reported below. Other than for
these and decommissioning costs, Diablo Canyon discontinued the application of
SFAS No. 71 in July 1988.
Under the pricing provisions of the existing Diablo Settlement, the price for
power produced by Diablo Canyon for 1997 is 10.0 cents per kWh effective January
1. PG&E has the right to reduce the price below the amount specified. Under the
existing settlement, at full operating power, each Diablo Canyon unit would
contribute approximately $2.6 million in revenues per day in 1997. The prices
per kWh of electricity generated by Diablo Canyon for 1996, 1995, and 1994 were
10.50, 11.00, and 11.89 cents per kWh, respectively.
Selected financial information for Diablo Canyon is shown below:
<TABLE>
<CAPTION>
Year ended December 31, 1996 1995 1994
-------- --------- ---------
(in millions)
<S> <C> <C> <C>
Operating revenues $1,789 $1,845 $1,870
Operating income before
income taxes 998 1,029 956
Net income 497 507 461
</TABLE>
In determining operating results of Diablo Canyon, operating revenues and the
majority of operating expenses were specifically identified pursuant to the
Diablo Settlement. Administrative and general expenses, principally labor costs,
are allocated based on a study of labor costs. Interest is charged to Diablo
Canyon based on an allocation of PG&E debt.
In conjunction with electric industry restructuring, PG&E filed in March 1996
a proposal for pricing Diablo Canyon generation at market prices and completing
recovery of the investment in Diablo Canyon by the end of 2001. If this proposal
is adopted, there would be a significant change to the manner in which Diablo
Canyon earns revenues.
Under its proposal, PG&E would replace the existing settlement prices with:
(1) a sunk cost revenue requirement to recover fixed costs, including a return
on these costs, and (2) a performance-based ratemaking (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 percent of
pg&e's long-term cost of debt. PG&E's authorized long-term cost of debt was 7.52
percent in 1996. The reduced rate of return combined with a shorter recovery
period would result in an estimated $4 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 were adopted during 1996, Diablo Canyon's 1996
reported net income would have been reduced by $350 million ($0.85 per share).
Note 5: Preferred Stock and Company Obligated Mandatorily Redeemable Preferred
Securities of Trust Holding Solely PG&E Subordinated Debentures
(See the Statement of Consolidated Capitalization for additional information.)
Preferred Stock: PG&E's nonredeemable preferred stock at December 31, 1996, has
rights to annual dividends per share ranging from $1.25 to $1.50.
PG&E's redeemable preferred stock without mandatory redemption provisions is
subject to redemption at PG&E's option, in whole or in part, if PG&E pays the
specified redemption price plus accumulated and unpaid dividends through the
redemption date. Annual dividends and redemption prices per share at December
31, 1996, range from $1.09 to $1.86 and from $25.75 to $27.25, respectively.
PG&E's redeemable preferred stock with mandatory redemption provisions
consists of the 6.30% and 6.57% series at December 31, 1996. These series of
preferred stock are subject to mandatory redemption provisions entitling them to
sinking funds providing for the retirement of stock outstanding. They may be
redeemed at PG&E's option, beginning in 2004 and 2002, respectively, at par
value plus accumulated and unpaid dividends through the redemption date. The
estimated fair value of PG&E's preferred stock with mandatory redemption
provisions at December 31, 1996, and 1995, was approximately $135 and $139
million, respectively, based on quoted market prices.
In 1995, PG&E redeemed all of its series 7.84%, 8%, and 8.20% redeemable
preferred stock. In addition, PG&E repurchased partial amounts of its series
67/8%, 7.04%, and 7.44% redeemable
33
<PAGE>
PG&E Corporation
Notes to Consolidated Financial Statements
preferred stock through a tender offer. The aggregate par value of these
redemptions and repurchases was $331 million.
Dividends on all preferred stock are cumulative. All shares of preferred
stock have voting rights and equal preference in dividend and liquidation
rights. Upon liquidation or dissolution of PG&E, holders of preferred stock
would be entitled to the par value of such shares plus all accumulated and
unpaid dividends, as specified for the class and series.
Company Obligated Mandatorily Redeemable Preferred Securities of Trust Holding
Solely PG&E Subordinated Debentures: During 1995, PG&E through its wholly-owned
subsidiary, PG&E Capital I (Trust), completed a public offering of 12 million
shares of 7.90% cumulative quarterly income preferred securities (QUIPS), with
an aggregate liquidation value of $300 million. Concurrent with the issuance of
the QUIPS, the Trust issued to PG&E 371,135 shares of common securities with an
aggregate liquidation value of approximately $9 million. The Trust in turn used
the net proceeds from the QUIPS offering and issuance of the common securities
to purchase subordinated debentures issued by PG&E with a face value of
approximately $309 million, an interest rate of 7.90 percent, and a maturity
date of 2025. These subordinated debentures are the only assets of the Trust.
Proceeds to PG&E from the sale of the subordinated debentures were used to
redeem and repurchase higher-cost preferred stock.
PG&E's guarantee of the QUIPS, considered together with the other obligations
of PG&E with respect to the QUIPS, constitutes a full and unconditional
guarantee by PG&E of the Trust's obligations under the QUIPS issued by the
Trust. The subordinated debentures may be redeemed at PG&E's option beginning in
2000 at par plus accrued interest through the redemption date. The proceeds of
any redemption will be used by the Trust to redeem QUIPS in accordance with
their terms.
Upon liquidation or dissolution of PG&E, holders of these QUIPS would be
entitled to the liquidation preference of $25 per share plus all accrued and
unpaid dividends thereon to the date of payment. The estimated fair value of
PG&E's QUIPS at December 31, 1996, and 1995, was approximately $291 and $311
million, respectively, based on quoted market prices.
Note 6: Long-term Debt
(See the Statement of Consolidated Capitalization for additional information.)
Mortgage Bonds: PG&E had $5.4 and $5.7 billion of mortgage bonds outstanding at
December 31, 1996, and 1995, respectively. Additional mortgage bonds may be
issued, subject to CPUC approval, up to a maximum total amount outstanding of
$10 billion. All real properties and substantially all personal properties of
PG&E are subject to the lien of the mortgage, and PG&E is required to make semi-
annual sinking fund payments for the retirement of the bonds.
PG&E redeemed or repurchased $182 and $114 million of mortgage bonds in 1996
and 1995, respectively, with interest rates ranging from 5.375 to 12.75 percent.
Included in the total of outstanding mortgage bonds at December 31, 1996, and
1995, are $705 and $768 million, respectively, of mortgage bonds held in trust
for the California Pollution Control Financing Authority (CPCFA) with interest
rates ranging from 5.85 to 8.875 percent and maturity dates from 2007 to 2023.
In addition to these mortgage bonds, PG&E holds long-term loan agreements with
the CPCFA as described below.
Pollution Control Loan Agreements: In 1996, PG&E refinanced $925 million of
variable interest rate pollution control loan agreements with variable interest
rate pollution control loan agreements to extend certain maturities and achieve
cost savings. These loan agreements from the CPCFA totaled $988 and $925
million, respectively, at December 31, 1996, and 1995. Interest rates on the
loans vary with average annual interest rates for 1996 ranging from 3.24 to 3.54
percent. These loans are subject to redemption by the holder under certain
circumstances. These loans are secured by irrevocable letters of credit which
mature as early as 1999.
Long-term Debt of PGT: In 1996, PGT borrowed $92 million of long-term debt to
finance the acquisition of PGT Queensland Gas Pipeline.
In 1995, PGT issued $470 million of long-term debt, the proceeds of which were
used to refinance $600 million of outstanding PGT debt.
34
<PAGE>
Additionally, in 1995, PGT issued commercial paper classified as long-term
debt based upon the availability of committed credit facilities expiring in 2000
and management's intent to maintain such amounts in excess of one year. The
commercial paper outstanding was $108 and $109 million at December 31, 1996, and
1995, respectively.
Repayment Schedule: At December 31, 1996, the Company's combined aggregate
amounts of maturing long-term debt and sinking fund requirements, for the years
1997 through 2001, are $210, $660, $270, $413, and $376 million, respectively.
Fair Value: The estimated fair value of the Company's total long-term debt of
$8.0 and $8.4 billion at December 31, 1996, and 1995, respectively, was
approximately $8.0 and $8.7 billion, respectively. The estimated fair value of
long-term debt was determined based on quoted market prices, where available.
Where quoted market prices were not available, the estimated fair value was
determined using other valuation techniques (e.g., the present value of future
cash flows).
Note 7: Short-term Borrowings
Substantially all short-term borrowings consist of commercial paper, having a
maturity of one to ninety days. Commercial paper outstanding and the associated
weighted average interest rate at December 31, 1996, and 1995, were $681 million
and 5.86 percent and were $796 million and 5.92 percent, respectively. The
carrying amount of short-term borrowings approximates fair value.
PG&E maintains a $1 billion revolving credit facility which expires in 2001;
however, it may be extended annually for additional one-year periods upon mutual
agreement between PG&E and the banks. This credit facility primarily provides
support for PG&E's commercial paper issuance. At maturity, commercial paper can
be either reissued or replaced with borrowings from this credit facility. There
were no borrowings under this facility in 1996 or 1995.
In January 1997, PG&E Corporation established a $500 million revolving credit
facility in order to provide for corporate short-term liquidity needs and other
purposes.
Note 8: Investments in Debt and
Equity Securities
All of PG&E's investments in debt and equity securities are held in external
trust funds and are reported at fair value. These investments, which are
included in Nuclear Decommissioning Funds, cannot be released from the trust
funds until authorized by the CPUC.
The proceeds received during 1996 and 1995 from sales were approximately $1.5
billion in each year. During 1996 and 1995, the gross realized gains on sales of
securities held as available-for-sale were $14 and $9 million, respectively, and
the gross realized losses on sales of securities held as available-for-sale
were $20 and $22 million, respectively. The cost of debt and equity securities
sold is determined by specific identification.
The following table provides a summary of amortized cost and fair value of
these investments:
<TABLE>
<CAPTION>
Year ended December 31, 1996 1995
------------ ------------
(in thousands)
<S> <C> <C>
Amortized Cost:
U.S. government and agency issues $374,931 $322,838
Equity securities 281,532 269,117
Municipal bonds and other 32,952 63,061
Gross unrealized holding gains 198,875 117,673
Gross unrealized holding losses (5,361) (2,860)
------------ ------------
Fair value $882,929 $769,829
============ ============
</TABLE>
Note 9: Employee Benefit Plans
Retirement Plan: The Company provides noncontributory defined benefit pension
plans covering substantially all employees. Pension benefits are based on an
employee's years of service and base salary. The Company's policy is to fund
each year not more than the maximum amount deductible for federal income tax
purposes and not less than the minimum legal funding requirement.
35
<PAGE>
PG&E Corporation
Notes to Consolidated Financial Statements
The following schedule reconciles the plans' funded status to the pension
liability recorded on the Consolidated Balance Sheet:
<TABLE>
<CAPTION>
December 31, 1996 1995
------------ ------------
(in thousands)
<S> <C> <C>
Actuarial present value of benefit
obligations
Vested benefits $(3,486,136) $(3,464,782)
Nonvested benefits (177,782) (182,503)
------------ ------------
Accumulated benefit obligation (3,663,918) (3,647,285)
Effect of projected future
compensation increases (529,045) (548,743)
------------ ------------
Projected benefit obligation (4,192,963) (4,196,028)
Plan assets at market value 5,526,247 4,935,267
------------ ------------
Plan assets in excess of projected
benefit obligation 1,333,284 739,239
Unrecognized prior service cost 82,756 90,496
Unrecognized net gain (1,559,281) (1,074,347)
Unrecognized net transition
obligation 85,895 97,348
------------ ------------
Accrued pension liability $ (57,346) $ (147,264)
============ ============
</TABLE>
Plan assets consist primarily of common stocks and fixed-income securities.
Unrecognized prior service costs and net gains are amortized on a straight-line
basis over the average remaining service period of active plan participants. The
transition obligation is being amortized over 17.5 years from 1987.
Using the projected unit credit actuarial cost method, net pension income
consisted of the following components:
<TABLE>
<CAPTION>
Year ended December 31, 1996 1995 1994
----------- ----------- -----------
(in thousands)
<S> <C> <C> <C>
Service cost for benefits
earned $ (99,946) $ (82,814) $(109,132)
Interest cost (301,631) (290,563) (272,932)
Actual return (loss) on
plan assets 811,130 968,126 (20,358)
Net amortization and
deferral (353,195) (586,350) 412,547
----------- ----------- -----------
Net pension income $ 56,358 $ 8,399 $ 10,125
=========== =========== ===========
</TABLE>
The following actuarial assumptions were used in determining the plans'
funded status and net pension income. Year-end assumptions are used to compute
funded status, while prior year-end assumptions are used to compute net pension
income.
<TABLE>
<CAPTION>
December 31, 1996 1995 1994
-------- -------- --------
<S> <C> <C> <C>
Discount rate 7.5% 7.25% 8%
Rate of future
compensation increases 5% 5% 5%
Expected long-term rate
of return on plan assets 9% 9% 9%
</TABLE>
Net pension income or cost is calculated using expected return on plan
assets. The difference between actual and expected return on plan assets is
included in net amortization and deferral and is considered in the determination
of future net pension income or cost. In 1996 and 1995, actual return on plan
assets exceeded expected return. In 1994, the plan experienced a negative
investment return due to weak performance in domestic equities and bonds.
In conformity with SFAS No. 71, regulatory adjustments have been recorded in
the income statement and balance sheet for the difference between utility
pension income or cost determined for accounting purposes and that for
ratemaking, which is based on a funding approach.
Postretirement Benefits Other Than Pensions:
The Company provides contributory defined benefit medical plans for retired
employees and their eligible dependents and noncontributory defined benefit life
insurance plans for retired employees. Substantially all employees retiring at
or after age 55 are eligible for these benefits. The medical benefits are
provided through plans administered by an insurance carrier or a health
maintenance organization. Certain retirees are responsible for a portion of the
cost based on past claims experience of the Company's retirees.
The CPUC has authorized PG&E to recover these benefits for 1993 and beyond.
Recovery is based on the lesser of the annual accounting costs or annual
contributions on a tax-deductible basis to appropriate trusts. The Company's
policy is to fund each year an amount consistent with the basis for rate
recovery.
36
<PAGE>
The following schedule reconciles the medical and life insurance plans'
funded status to the postretirement benefit liability recorded on the
Consolidated Balance Sheet:
<TABLE>
<CAPTION>
December 31, 1996 1995
------------- ------------
(in thousands)
<S> <C> <C>
Accumulated postretirement benefit
obligation
Retirees $(444,782) $(528,367)
Other fully eligible participants (132,797) (123,615)
Other active plan participants (343,864) (309,405)
------------- ------------
Total accumulated postretirement
benefit obligation (921,443) (961,387)
Plan assets at market value 666,287 538,905
------------- ------------
Accumulated postretirement benefit
obligation in excess of plan assets (255,156) (422,482)
Unrecognized prior service cost 21,946 23,761
Unrecognized net gain (226,753) (104,167)
Unrecognized transition obligation 419,617 449,647
------------- ------------
Accrued postretirement benefit liability $ (40,346) $ (53,241)
</TABLE>
Plan assets consist primarily of common stocks and fixed-income securities.
Unrecognized prior service costs are amortized on a straight-line basis over the
average remaining years of service to full eligibility of active plan
participants. Unrecognized net gains are amortized on a straight-line basis over
the average remaining years of service of active plan participants. The
transition obligation is being amortized over 20 years from 1993.
Using the projected unit credit actuarial cost method, net postretirement
medical and life insurance cost consisted of the following components:
<TABLE>
<CAPTION>
Year ended December 31, 1996 1995 1994
---------- ----------- -----------
(in thousands)
<S> <C> <C> <C>
Service cost for
benefits earned $ 21,954 $ 17,004 $ 23,617
Interest cost 65,629 64,776 64,872
Actual return on
plan assets (91,050) (108,932) (1,232)
Amortization of
unrecognized prior
service cost 1,602 1,616 1,711
Amortization of
transition obligation 26,314 26,533 28,913
Net amortization
and deferral 38,329 70,070 (29,804)
---------- ---------- ----------
Net postretirement
benefit cost $ 62,778 $ 71,067 $ 88,077
========== ========== ==========
</TABLE>
The discount rate, rate of future compensation increases, and expected long-
term rate of return on plan assets used in accounting for the postretirement
benefit plans for 1996, 1995, and 1994 were the same as those used for the
pension plan.
The assumed health care cost trend rate for 1997 is approximately 10.0
percent, grading down to an ultimate rate in 2005 of approximately 6.0 percent.
The effect of a one-percentage-point increase in the assumed health care cost
trend rate for each future year would increase the accumulated postretirement
benefit obligation at December 31, 1996, by approximately $75 million and the
1996 aggregate service and interest costs by approximately $8 million.
The decrease in net postretirement benefit cost in 1995 compared to 1994 was
primarily due to a reduction in workforce and an increase in discount rate.
Net postretirement benefit cost is calculated using expected return on plan
assets. The difference between actual and expected return on plan assets is
included in net amortization and deferral and is considered in the determination
of future postretirement benefit cost. In 1996 and 1995, actual return on plan
assets exceeded expected return. In 1994, actual return on plan assets was less
than expected.
Workforce Reductions: The effects of workforce reductions announced by PG&E in
1994 are reflected in the pension and postretirement benefits funded status
tables above, and the costs are discussed in Note 10.
Long-term Incentive Program: PG&E Corporation maintains a Long-term Incentive
Program (Program) which provides for grants of stock options to eligible
participants with or without associated stock appreciation rights and dividend
equivalents. The Program also grants performance-based units to eligible
participants. As of December 31, 1996, 24.5 million shares of common stock have
been authorized for award under the program. At December 31, 1996, stock options
on 3,461,733 shares, granted at option prices ranging from $16.75 to $34.25,
were outstanding, of which 1,655,450 were exercisable. In 1996, 877,900 options
were granted at an option price of $28.25, which was the market price per share
on the date of grant.
Outstanding stock options expire ten years and one day after the date of
grant and become exercisable on a cumulative
37
<PAGE>
PG&E Corporation
Notes to Consolidated Financial Statements
basis at one-third each year commencing two years from the date of grant. In
1996, 1995, and 1994, stock options on 72,960, 235,568, and 52,143 shares,
respectively, were exercised at option prices ranging from $16.75 to $33.13,
$16.75 to $33.13, and $24.75 to $32.13, respectively.
Effective January 1, 1996, the Company adopted SFAS No. 123, "Accounting for
Stock-Based Compensation." SFAS No. 123 requires the Company to disclose stock
option costs based on the fair value of options granted. For the years ended
December 31, 1996, and 1995, the fair value of options granted was not material
to the Company's results of operations or earnings per share.
Note 10: Workforce Reductions
In 1994, PG&E expensed the total cost of its planned 1994-1995 workforce
reductions of $249 million and recorded a corresponding liability for benefits
to be funded or paid. This amount consisted of $136 million for additional
pension benefits, $52 million for other postretirement benefits, and $61 million
for estimated severance costs. PG&E did not seek rate recovery for the cost of
the 1994-1995 workforce reductions.
In 1995, PG&E canceled approximately 800 of the 3,000 planned 1994-1995
reductions in response to the severity of the damage caused by the winter storms
of 1995 and the identification of certain facilities that would benefit from a
more extensive and accelerated maintenance program. As a result, the estimated
severance costs accrued and expensed in 1994 were reduced by $18 million in
1995.
Note 11: Income Taxes
The Company files a consolidated federal income tax return that includes
domestic subsidiaries in which its ownership is 80 percent or more. Income tax
expense includes current and deferred income taxes resulting from operations
during the year. Tax credits are amortized over the life of the related
property.
The significant components of income tax expense were:
<TABLE>
<CAPTION>
Year ended December 31, 1996 1995 1994
------------ ------------ ----------
(in thousands)
<S> <C> <C> <C>
Current $ 704,984 $1,011,358 $821,455
Deferred (132,250) (97,864) 34,657
Tax credits--net (17,740) (18,205) (19,345)
------------ ------------- ----------
Total income
tax expense $ 554,994 $ 895,289 $836,767
============ ============= ==========
</TABLE>
The significant components of net deferred income tax liabilities were:
<TABLE>
<CAPTION>
December 31, 1996 1995
------------ ------------
(in thousands)
<S> <C> <C>
Deferred income tax assets $1,308,395 $1,203,981
------------ ------------
Deferred income tax liabilities:
Regulatory balancing accounts $ 294,494 $ 385,604
Plant in service 3,623,544 3,552,974
Income tax-related deferred
charges /(1)/ 454,359 443,152
Other 1,034,497 983,798
------------ ------------
Total deferred income tax liabilities $5,406,894 $5,365,528
------------ ------------
Total net deferred income taxes $4,098,499 $4,161,547
============ ============
Classification of net deferred
income taxes:
Included in current liabilities $ 157,064 $ 227,782
Included in deferred credits 3,941,435 3,933,765
------------ ------------
Total net deferred income taxes $4,098,499 $4,161,547
============ ============
</TABLE>
/(1)/ Represents the portion of the deferred income tax liability related to the
revenues required to recover future income taxes.
The differences between income taxes and amounts determined by applying the
federal statutory rate to income before income tax expense were:
<TABLE>
<CAPTION>
Year ended December 31, 1996 1995 1994
-------- --------- --------
(in thousands)
<S> <C> <C> <C>
Federal statutory income tax rate 35.0% 35.0% 35.0%
Increase (decrease) in income
tax rate resulting from:
State income tax
(net of federal benefit) 3.7 4.8 8.3
Effect of regulatory treatment
of depreciation differences 5.9 3.2 3.7
Tax credits--net (1.4) (.8) (1.1)
Other--net (.8) (2.1) (.5)
-------- --------- --------
Effective tax rate 42.4% 40.1% 45.4%
======== ========= ========
</TABLE>
Note 12: Commitments
Capital Projects: Capital expenditures for 1997 are estimated to be $1,773
million for utility, $38 million for Diablo Canyon, and $211 million for
diversified operations.
At December 31, 1996, Enterprises had $67 million in firm commitments to make
capital contributions for its equity share of generating facility projects. The
contributions, payable upon commercial operation of the projects, are estimated
to be
38
<PAGE>
$52 million in 1997 (included in the expenditures above) and $15 million in
1998.
Letters of Credit: PG&E utilizes approximately $247 million in standby letters
of credit to secure future workers' compensation liabilities.
Qualifying Facilities 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
certain 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 early termination or suspension of
certain QF contracts to be paid through 1999 at discounted costs of $25, $142,
and $155 million for 1996, 1995, and 1994, respectively. These amounts are
expected to be recovered in rates and as such are reflected as deferred charges
on the accompanying balance sheet. At December 31, 1996, the total discounted
future payments remaining under QF early termination or suspension contracts is
$68 million.
QF deliveries in the aggregate account for approximately 19 percent of PG&E's
1996 electric energy requirements, and no single contract accounted for more
than 5 percent 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
six percent of PG&E's 1996 electric energy requirements, and no single contract
accounted for more than five percent of PG&E's energy needs.
The amount of energy received and the total payments made under QF and other
power-purchase contracts were:
<TABLE>
<CAPTION>
Year ended December 31, 1996 1995 1994
---------- ---------- ----------
(in millions)
<S> <C> <C> <C>
Kilowatt-hours 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
</TABLE>
Note 13: Contingencies
Nuclear 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). Under these policies, if a nuclear generating
facility of a member utility suffers a loss due to a prolonged accidental
outage, PG&E may be subject to maximum assessments of $29 million (property
damage) and $8 million (business interruption), in each case per policy period,
in the event 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 which 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.
Environmental Remediation: The Company may be required to pay for environmental
remediation at sites where the Company has been or may be a potentially
responsible party under the Comprehensive Environmental Response, Compensation
and Liability Act (CERCLA) or the California Hazardous Substance Account Act.
These sites include former manufactured gas plant sites and sites used by PG&E
for the storage or disposal of materials which may be determined to present a
significant threat to human health or the environment because of an actual or
potential release of hazardous
39
<PAGE>
PG&E Corporation
Notes to Consolidated Financial Statements
substances. Under CERCLA, the Company's financial responsibilities may include
remediation of hazardous substances, even if the Company did not deposit those
substances on the site.
The Company records a liability when site assessments indicate remediation is
probable and a range of reasonably likely cleanup costs can be estimated. The
Company reviews its sites and measures the liability quarterly, by assessing a
range of reasonably likely costs for each identified site using currently
available information, including existing technology, presently enacted laws and
regulations, experience gained at similar sites, and the probable level of
involvement and financial condition of other potentially responsible parties.
These estimates include costs for site investigations, remediation, operations
and maintenance, monitoring, and site closure. Unless there is a better estimate
within this range of possible costs, the Company records the lower end of this
range (classified as other noncurrent liabilities).
The cost of the 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 has 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 potentially responsible parties are not financially able to
contribute to these costs, or further investigation indicates that the extent of
contamination or necessary remediation is greater than anticipated at sites for
which the Company is responsible. This upper limit of the range of costs was
estimated using assumptions least favorable to the Company, based upon a range
of reasonably possible outcomes. Costs may be higher if the Company is found to
be responsible for cleanup costs at additional sites or identifiable possible
outcomes change.
The Company will 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, the Company will seek
recovery of costs from insurance carriers and from other third parties. The
Company believes the ultimate outcome of these matters will not have a material
adverse impact on its financial position or results of operations.
Helms Pumped Storage Plant (Helms): Helms is a three-unit hydroelectric combined
generating and pumped storage plant with a net investment of $710 million at
December 31, 1996. The net investment is comprised of the pumped storage
facility (including regulatory assets of $51 million), common plant, and
dedicated transmission plant. As part of the 1996 General Rate Case decision in
December 1995, the CPUC directed PG&E to perform a cost-effectiveness study of
Helms. In July 1996, PG&E submitted its study, which concluded that the
continued operation of Helms is cost effective. As a result of the study, PG&E
recommended that the CPUC take no action and 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, the Company expects to seek recovery of its net investment in Helms
through PBR and transition cost recovery. 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.
Helms became commercially operable in 1984, following delays due to a water
conduit rupture in 1982 and various start-up problems related to the plant's
generators. As a result of the rupture damage and the operational delay, PG&E
incurred additional costs which were excluded from rate base and lost revenues
during the period the plant was under repair. In 1994, PG&E submitted for CPUC
approval a settlement with the ORA regarding recovery of such additional costs
and lost revenues, amounting to approximately $98 million. In September 1996,
the CPUC issued a final decision adopting the settlement which permits PG&E to
recover that amount. Because PG&E's current rate recovery already reflects the
anticipated settlement, adoption of the settlement will have no impact on rates.
40
<PAGE>
Legal Matters:
Cities Franchise Fees Litigation: In 1994, the City of Santa Cruz filed a class
action suit in a state superior court (Court) against PG&E on behalf of itself
and 106 other cities in PG&E's service area. The complaint alleges that PG&E has
underpaid electric franchise fees to the cities by calculating those fees at
different rates from other cities not included in the complaint.
In September 1995, the Court certified the class of 107 cities in this suit
and approved the City of Santa Cruz as the class representative. In January and
March 1996, the Court made two rulings against certain cities effectively
eliminating a major portion of the suit. The Court's rulings do not resolve the
suit completely. The cities appealed both rulings. The trial has been postponed
pending the cities' appeal.
Should the cities prevail on the issue of franchise fee calculation
methodology, PG&E's annual systemwide 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 January and March 1996 rulings become final, PG&E's annual
systemwide city electric franchise fees for the remaining class member cities
not subject to the Court's rulings could increase by approximately $4 million
and damages for alleged underpayments for the years 1987 to 1996 could be as
much as $39 million (exclusive of interest).
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.
Hinkley: In 1996, PG&E settled a 1993 lawsuit seeking damages for personal
injuries allegedly suffered as a result of exposure to chromium near PG&E's gas
compressor station at Hinkley. This lawsuit was settled for the aggregate sum of
$333 million, of which $50 million had been paid in 1994, with the remaining
$283 million paid in 1996. PG&E had previously reserved $200 million for this
litigation and in 1996 recorded an additional reserve of $133 million for this
settlement. The settlement does not resolve other pending chromium litigation,
described below.
Chromium Litigation: In 1994 through 1996, several civil suits were filed
against PG&E on behalf of more than 1,500 individuals. The complaints seek an
unspecified amount of compensatory and punitive damages for alleged personal
injuries resulting from exposure to chromium in the vicinity of PG&E's gas
compressor stations at Hinkley, Kettleman, and Topock.
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.
Given the uncertainty, the Company cannot predict the outcome of this
litigation. However, 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.
41
<PAGE>
PG&E Corporation
Quarterly Consolidated Financial Data (Unaudited)
Quarterly Financial Data: Due to the seasonal nature of the utility business and
the scheduled refueling outages for Diablo Canyon, operating revenues, operating
income, and net income are not generated evenly every quarter during the year.
All four quarters of 1996 reflected a decline in price per kilowatt-hours as
provided in the modified pricing provisions of the Diablo Canyon rate case
settlement, and revenue reductions authorized by the 1996 General Rate Case
(GRC) and other related rate proceedings. In addition, maintenance and operating
expenses exceeded levels authorized by the GRC.
In the second quarter of 1996, the Company charged to earnings $133 million
for the settlement of a litigation claim. Revenues were also reduced due to a
greater number of scheduled refueling days and unscheduled outages.
In the third quarter of 1996, the Company took charges against earnings of
$182 million for contingencies related to gas transportation commitments.
In the fourth quarter of 1996, the Company charged to earnings $59 million in
write-downs of nonregulated investments.
The Company recorded additional litigation reserves of $50 million in the
first and third quarters of 1995. Diablo Canyon scheduled refueling days and
unscheduled outages reduced earnings per common share in the fourth quarter of
1995.
The Company's common stock is traded on the New York, Pacific, and Swiss
stock exchanges. There were approximately 198,000 common shareholders of record
at December 31, 1996. Dividends are paid on a quarterly basis, and net cash
flows are sufficient to maintain the current payment of dividends.
<TABLE>
<CAPTION>
Quarter ended December 31 September 30 June 30 March 31
-------------- --------------- ------------- -------------
(in thousands, except per share amounts)
<S> <C> <C> <C> <C>
1996
Operating revenues $2,700,686 $2,521,852 $2,138,666 $2,248,768
Operating income 508,970 524,846 288,375 573,394
Net income 149,030 233,695 111,780 260,704
Earnings per common share .34 .55 .25 .61
Dividends declared per common share .30 .49 .49 .49
Common stock price per share
High 24.25 23.88 23.75 28.38
Low 20.88 19.50 21.50 22.38
1995
Operating revenues $2,227,224 $2,637,653 $2,448,641 $2,308,247
Operating income 451,674 781,912 820,370 709,029
Net income 227,085 377,593 405,520 328,687
Earnings per common share .48 .85 .92 .73
Dividends declared per common share .49 .49 .49 .49
Common stock price per share
High 30.63 30.00 29.75 25.75
Low 27.13 28.38 24.75 24.25
</TABLE>
42
<PAGE>
PG&E Corporation
Report of Independent Public Accountants
To the Shareholders and the Board of Directors of PG&E Corporation:
We have audited the accompanying consolidated balance sheet and the statement of
consolidated capitalization of PG&E Corporation (a California corporation) and
subsidiaries as of December 31, 1996, and 1995, and the related statements of
consolidated income, cash flows, common stock equity, preferred stock and
preferred securities, and the schedule of consolidated segment information for
each of the three years in the period ended December 31, 1996. These financial
statements and schedule of consolidated segment information are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements and schedules based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements and schedule of
consolidated segment information referred to above present fairly, in all
material respects, the financial position of PG&E Corporation and subsidiaries
as of December 31, 1996, and 1995, and the results of their operations and cash
flows for each of the three years in the period ended December 31, 1996, in
conformity with generally accepted accounting principles.
ARTHUR ANDERSEN LLP
ARTHUR ANDERSEN LLP
San Francisco, California
February 10, 1997
43
<PAGE>
PG&E Corporation
Responsibility for Consolidated Financial Statements
The responsibility for the integrity of the consolidated financial statements
and related financial information included in this report rests with management.
The consolidated financial statements have been prepared in accordance with
generally accepted accounting principles appropriate in the circumstances and
are based on the Company's best estimates and judgments after giving
consideration to materiality.
The Company maintains systems of internal controls supported by formal
policies and procedures which are communicated throughout the Company. These
controls are adequate to provide reasonable assurance that assets are
safeguarded from material loss or unauthorized use and to produce the records
necessary for the preparation of consolidated financial statements. There are
limits inherent in all systems of internal controls, based on the recognition
that the costs of such systems should not exceed the benefits to be derived. The
Company believes its systems provide this appropriate balance. In addition, the
Company's internal auditors perform audits and evaluate the adequacy of and the
adherence to these controls, policies, and procedures.
Arthur Andersen LLP, the Company's independent public accountants, considered
the Company's systems of internal accounting controls and conducted other tests
as they deemed necessary to support their opinion on the consolidated financial
statements. Their auditors' report contains an independent informed judgment as
to the fairness, in all material respects, of the Company's reported results of
operations and financial position.
The financial data contained in this report have been reviewed by the Audit
Committee of the Board of Directors. The Audit Committee is composed of six
outside directors who meet regularly with management, the corporate internal
auditors, and Arthur Andersen LLP, jointly and separately, to review internal
accounting controls and auditing and financial reporting matters.
The Company maintains high standards in selecting, training, and developing
personnel to ensure that management's objectives of maintaining strong and
effective internal controls and maintaining unbiased and uniform reporting
standards are attained. The Company believes its policies and procedures provide
reasonable assurance that operations are conducted in conformity with applicable
laws and with its commitment to a high standard of business conduct.
44
<PAGE>
Exhibit 21
SUBSIDIARIES OF THE REGISTRANTS
A. PG&E Corporation:
1. Pacific Gas and Electric Company, a California corporation. Pacific Gas
and Electric Company has the following subsidiaries:
1.1 Alberta and Southern Gas Co. Ltd., incorporated under the laws of
Alberta, Canada
1.1.1 Alberta and Southern Gas Marketing Inc., incorporated
under the laws of Alberta, Canada
1.2 Mission Trail Insurance (Cayman) Ltd., incorporated under the
laws of the Cayman Islands
1.3 Natural Gas Corporation of California, a California corporation
1.3.1. NGC Production Company, a California corporation
1.4 Pacific Conservation Services Company, a California corporation
1.5 Calaska Energy Company, a California corporation
1.6 Eureka Energy Company, a California corporation
1.7 Standard Pacific Gas Line Incorporated, a California corporation
1.8 Pacific California Gas System, Inc., California corporation
1.9 Pacific Energy Fuels Company, a California corporation
1.10 Pacific Gas Properties Company, a California corporation
2. Pacific Gas Transmission Company ("PGT"), a California corporation. PGT
has the following subsidiaries:
2.1 PGT Australia Pty Limited, formed under the laws of New South
Wales, Australia
2.2 Pacific Gas Transmission International, Inc., a California
corporation
2.3 PGT Queensland Pty Limited, formed under the laws of New South
Wales, Australia
2.4 PGT Victoria Pty Limited, formed under the laws of New South
Wales, Australia
2.5 PGT Western Australia Pty Limited, formed under the laws of New
South Wales, Australia
<PAGE>
2.6 PGT Nominees Pty Limited, formed under the laws of New South
Wales, Australia
2.7 Energy Source, Inc., a California corporation
2.7.1 PG&E Energy Source Canada, Inc., incorporated under the
laws of Alberta, Canada
B. Pacific Gas and Electric Company:
Pacific Gas and Electric Company's subsidiaries, considered in the aggregate as
a single subsidiary (as defined by Rule 1-02 (w) of Regulation S-X), would not
constitute a significant subsidiary of Pacific Gas and Electric Company as of
December 31, 1996.
<PAGE>
EXHIBIT 23
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation by
reference of our reports dated February 10, 1997, included or incorporated by
reference in this Form 10-K, into the previously filed registration statements
as follows: (1) PG&E Corporation's Form S-3 Registration Statement File No.333-
16255 (relating to PG&E Corporation's Dividend Reinvestment Plan); (2) Pacific
Gas and Electric Company's Form S-3 Registration Statement File No. 33-64136
(relating to $2,000,000,000 aggregate principal amount of Pacific Gas and
Electric Company's First and Refunding Mortgage Bonds and Medium-Term Notes);
(3) Pacific Gas and Electric Company's Form S-3 Registration Statement File No.
33-50707 (relating to $1,500,000,000 aggregate principal amount of Pacific Gas
and Electric Company's First and Refunding Mortgage Bonds); (4) PG&E
Corporation's Form S-8 Registration Statement File No. 33-50601 (relating to the
Pacific Gas and Electric Company's Savings Fund Plan for Employees); (5) PG&E
Corporation's Form S-8 Registration Statement File No. 33-23692 (relating to
PG&E Corporation's 1986 Stock Option Plan); (6) Pacific Gas and Electric
Company's Form S-3 Registration Statement File No: 33-62488 (relating to
10,000,000 shares of Pacific Gas and Electric Company's Redeemable First
Preferred Stock); (7) Form S-3 Registration Statement File No: 33-61959
(relating to $335,000,000 aggregate liquidation value of Cumulative Quarterly
Income Preferred Securities); and (8) PG&E Corporation's Form S-8 Registration
Statement File No: 333-16253 (relating to PG&E Corporation's Long-Term Incentive
Program).
ARTHUR ANDERSEN LLP
San Francisco, California,
March 4, 1997
<PAGE>
EXHIBIT 24.1
RESOLUTION OF THE
-----------------
BOARD OF DIRECTORS OF
---------------------
PG&E CORPORATION
----------------
February 19, 1997
-----------------
BE IT RESOLVED that each of LESLIE H. EVERETT, LINDA Y.H. CHENG, ERIC
MONTIZAMBERT, KATHLEEN RUEGER, GARY P. ENCINAS, and JULIE C. GAVIN is hereby
authorized to sign on behalf of this corporation and as attorneys in fact for
the Chairman of the Board and Chief Executive Officer, Chief Financial Officer,
and Controller of this corporation the Form 10-K Annual Report for the year
ended December 31, 1996, required by Section 13 or 15(d) of the Securities
Exchange Act of 1934 and all amendments and other filings or documents related
thereto to be filed with the Securities and Exchange Commission, and to do any
and all acts necessary to satisfy the requirements of the Securities Exchange
Act of 1934 and the regulations of the Securities and Exchange Commission
adopted thereunder with regard to said Form 10-K Annual Report.
<PAGE>
I, KATHLEEN RUEGER, do hereby certify that I am an
Assistant Corporate Secretary of PG&E CORPORATION, a corporation organized and
existing under the laws of the State of California; that the above and foregoing
is a full, true and correct copy of a resolution which was duly adopted by the
Board of Directors of said corporation at a meeting of said Board which was duly
and regularly called and held at the office of said corporation on February 19,
1997, and that this resolution has never been amended, revoked, or repealed, but
is still in full force and effect.
WITNESS my hand and the seal of said corporation hereunto affixed this
20th day of February, 1997.
KATHLEEN RUEGER
---------------
Kathleen Rueger
Assistant Corporate Secretary
PG&E CORPORATION
[CORPORATE SEAL]
<PAGE>
RESOLUTION OF THE
-----------------
BOARD OF DIRECTORS OF
---------------------
PACIFIC GAS AND ELECTRIC COMPANY
--------------------------------
February 19, 1997
-----------------
BE IT RESOLVED that each of LESLIE H. EVERETT, LINDA Y.H. CHENG, ERIC
MONTIZAMBERT, KATHLEEN RUEGER, GARY P. ENCINAS, and JULIE C. GAVIN, is hereby
authorized to sign on behalf of this company and as attorneys in fact for the
Chairman of the Board and Chief Executive Officer, Senior Vice President and
Chief Financial Officer, and Vice President and Controller of this company the
Form 10-K Annual Report for the year ended December 31, 1996, required by
Section 13 or 15(d) of the Securities Exchange Act of 1934 and all amendments
and other filings or documents related thereto to be filed with the Securities
and Exchange Commission, and to do any and all acts necessary to satisfy the
requirements of the Securities Exchange Act of 1934 and the regulations of the
Securities and Exchange Commission adopted thereunder with regard to said Form
10-K Annual Report.
<PAGE>
I, KATHLEEN RUEGER, do hereby certify that I am an
Assistant Corporate Secretary of PACIFIC GAS AND ELECTRIC
COMPANY, a corporation organized and existing under the laws of the
State of California; that the above and foregoing is a full, true and correct
copy of a resolution which was duly adopted by the Board of Directors of
said corporation at a meeting of said Board which was duly and regularly
called and held at the office of said corporation on February 19, 1997, and
that this resolution has never been amended, revoked, or repealed, but is
still in full force and effect.
WITNESS my hand and the seal of said corporation hereunto affixed this
20th day of February, 1997.
KATHLEEN RUEGER
Kathleen Rueger
Assistant Corporate Secretary
PACIFIC GAS AND ELECTRIC COMPANY
[CORPORATE SEAL]
<PAGE>
EXHIBIT 24.2
POWER OF ATTORNEY
Each of the undersigned Directors of PG&E Corporation hereby constitutes
and appoints LESLIE H. EVERETT, LINDA Y.H. CHENG, ERIC MONTIZAMBERT, KATHLEEN
RUEGER, GARY P. ENCINAS and JULIE C. GAVIN, and each of them, as his or her
attorneys in fact with full power of substitution to sign and file with the
Securities and Exchange Commission in his or her capacity as such Director of
said corporation the Form 10-K Annual Report for the year ended December 31,
1996, required by Section 13 or 15(d) of the Securities Exchange Act of 1934 and
any and all amendments and other filings or documents related thereto, and
hereby ratifies all that said attorneys in fact or any of them may do or cause
to be done by virtue hereof.
IN WITNESS WHEREOF, we have signed these presents this 19th day of
February, 1997.
Stanley T. Skinner Richard B. Madden
- ------------------ -----------------
Robert D. Glynn, Jr. John C. Sawhill
- -------------------- ---------------
Richard A. Clarke David M. Lawrence
- ----------------- -----------------
H. M. Conger Alan Seelenfreund
- ------------ -----------------
Mary S. Metz Samuel T. Reeves
- ------------ ----------------
Rebecca Q. Morgan Carl E. Reichardt
- ----------------- -----------------
C. Lee Cox
- ----------
Barry Lawson Williams
- ---------------------
<PAGE>
POWER OF ATTORNEY
STANLEY T. SKINNER, the undersigned, Chairman of the Board and Chief
Executive Officer of PG&E Corporation, hereby constitutes and appoints LESLIE H.
EVERETT, LINDA Y.H CHENG, ERIC MONTIZAMBERT, KATHLEEN RUEGER, GARY P. ENCINAS
and JULIE C. GAVIN, and each of them, as his attorneys in fact with full power
of substitution to sign and file with the Securities and Exchange Commission in
his capacity as Chairman of the Board and Chief Executive Officer (principal
executive officer) of said corporation the Form 10-K Annual Report for the year
ended December 31, 1996, required by Section 13 or 15(d) of the Securities
Exchange Act of 1934 and any and all amendments and other filings or documents
related thereto, and hereby ratifies all that said attorneys in fact or any of
them may do or cause to be done by virtue hereof.
IN WITNESS WHEREOF, I have signed these presents this 19th day of
February, 1997.
STANLEY T. SKINNER
------------------
STANLEY T. SKINNER
<PAGE>
POWER OF ATTORNEY
GORDON R. SMITH, the undersigned, Chief Financial Officer of PG&E
Corporation, hereby constitutes and appoints LESLIE H. EVERETT, LINDA Y.H.
CHENG, ERIC MONTIZAMBERT, KATHLEEN RUEGER, GARY P. ENCINAS and JULIE C. GAVIN,
and each of them, as his attorneys in fact with full power of substitution to
sign and file with the Securities and Exchange Commission in his capacity as
Chief Financial Officer (principal financial officer) of said corporation the
Form 10-K Annual Report for the year ended December 31, 1996, required by
Section 13 or 15(d) of the Securities Exchange Act of 1934 and any and all
amendments and other filings or documents related thereto, and hereby ratifies
all that said attorneys in fact or any of them may do or cause to be done by
virtue hereof.
IN WITNESS WHEREOF, I have signed these presents this 19th day of
February, 1997.
GORDON R. SMITH
---------------
GORDON R. SMITH
<PAGE>
POWER OF ATTORNEY
CHRISTOPHER P. JOHNS, the undersigned, Controller of PG&E Corporation,
hereby constitutes and appoints LESLIE H. EVERETT, LINDA Y.H. CHENG, ERIC
MONTIZAMBERT, KATHLEEN RUEGER, GARY P. ENCINAS and JULIE C. GAVIN, and each of
them, as his attorneys in fact with full power of substitution to sign and file
with the Securities and Exchange Commission in his capacity as Controller
(principal accounting officer) of said corporation the Form 10-K Annual Report
for the year ended December 31, 1996, required by Section 13 or 15(d) of the
Securities Exchange Act of 1934 and any and all amendments and other filings or
documents related thereto, and hereby ratifies all that said attorneys in fact
or any of them may do or cause to be done by virtue hereof.
IN WITNESS WHEREOF, I have signed these presents this 19th day of
February, 1997.
CHRISTOPHER P. JOHNS
--------------------
CHRISTOPHER P. JOHNS
<PAGE>
POWER OF ATTORNEY
Each of the undersigned Directors of Pacific Gas and Electric Company
hereby constitutes and appoints LESLIE H. EVERETT, LINDA Y.H. CHENG, ERIC
MONTIZAMBERT, KATHLEEN RUEGER, GARY P. ENCINAS and JULIE C. GAVIN, and each of
them, as his or her attorneys in fact with full power of substitution to sign
and file with the Securities and Exchange Commission in his or her capacity as
such Director of said corporation the Form 10-K Annual Report for the year ended
December 31, 1996, required by Section 13 or 15(d) of the Securities Exchange
Act of 1934 and any and all amendments and other filings or documents related
thereto, and hereby ratifies all that said attorneys in fact or any of them may
do or cause to be done by virtue hereof.
IN WITNESS WHEREOF, we have signed these presents this 19th day of
February, 1997.
Stanley T. Skinner Richard B. Madden
- ------------------ -----------------
Robert D. Glynn, Jr. John C. Sawhill
- -------------------- ---------------
Richard A. Clarke David M. Lawrence
- ----------------- -----------------
H. M. Conger Alan Seelenfreund
- ------------ -----------------
Mary S. Metz Samuel T. Reeves
- ------------ ----------------
Rebecca Q. Morgan Carl E. Reichardt
- ----------------- -----------------
C. Lee Cox
- ----------
Barry Lawson Williams
- ---------------------
<PAGE>
POWER OF ATTORNEY
STANLEY T. SKINNER, the undersigned, Chairman of the Board and Chief
Executive Officer of Pacific Gas and Electric Company, hereby constitutes and
appoints LESLIE H. EVERETT, LINDA Y.H CHENG, ERIC MONTIZAMBERT, KATHLEEN RUEGER,
GARY P. ENCINAS and JULIE C. GAVIN, and each of them, as his attorneys in fact
with full power of substitution to sign and file with the Securities and
Exchange Commission in his capacity as Chairman of the Board and Chief Executive
Officer (principal executive officer) of said corporation the Form 10-K Annual
Report for the year ended December 31, 1996, required by Section 13 or 15(d) of
the Securities Exchange Act of 1934 and any and all amendments and other filings
or documents related thereto, and hereby ratifies all that said attorneys in
fact or any of them may do or cause to be done by virtue hereof.
IN WITNESS WHEREOF, I have signed these presents this 19th day of
February, 1997.
STANLEY T. SKINNER
------------------
STANLEY T. SKINNER
<PAGE>
POWER OF ATTORNEY
GORDON R. SMITH, the undersigned, Senior Vice President and Chief
Financial Officer of Pacific Gas and Electric Company, hereby constitutes and
appoints LESLIE H. EVERETT, LINDA Y.H. CHENG, ERIC MONTIZAMBERT, KATHLEEN
RUEGER, GARY P. ENCINAS and JULIE C. GAVIN, and each of them, as his attorneys
in fact with full power of substitution to sign and file with the Securities and
Exchange Commission in his capacity as Senior Vice President and Chief Financial
Officer (principal financial officer) of said corporation the Form 10-K Annual
Report for the year ended December 31, 1996, required by Section 13 or 15(d) of
the Securities Exchange Act of 1934 and any and all amendments and other filings
or documents related thereto, and hereby ratifies all that said attorneys in
fact or any of them may do or cause to be done by virtue hereof.
IN WITNESS WHEREOF, I have signed these presents this 19th day of
February, 1997.
GORDON R. SMITH
---------------
GORDON R. SMITH
<PAGE>
POWER OF ATTORNEY
CHRISTOPHER P. JOHNS, the undersigned, Vice President and Controller
of Pacific Gas and Electric Company, hereby constitutes and appoints LESLIE H.
EVERETT, LINDA Y.H. CHENG, ERIC MONTIZAMBERT, KATHLEEN RUEGER, GARY P. ENCINAS
and JULIE C. GAVIN, and each of them, as his attorneys in fact with full power
of substitution to sign and file with the Securities and Exchange Commission in
his capacity as Vice President and Controller (principal accounting officer) of
said corporation the Form 10-K Annual Report for the year ended December 31,
1996, required by Section 13 or 15(d) of the Securities Exchange Act of 1934 and
any and all amendments and other filings or documents related thereto, and
hereby ratifies all that said attorneys in fact or any of them may do or cause
to be done by virtue hereof.
IN WITNESS WHEREOF, I have signed these presents this 19th day of
February, 1997.
CHRISTOPHER P. JOHNS
--------------------
CHRISTOPHER P. JOHNS
<TABLE> <S> <C>
<PAGE>
<ARTICLE> UT
<LEGEND> This schedule contains summary financial information extracted from
PG&E CORPORATION and is qualified in its entirety by reference to such
financial statements.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1996
<PERIOD-START> JAN-01-1996
<PERIOD-END> DEC-31-1996
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 19,007,880
<OTHER-PROPERTY-AND-INVEST> 1,834,459
<TOTAL-CURRENT-ASSETS> 2,671,433
<TOTAL-DEFERRED-CHARGES> 2,616,153
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 26,129,925
<COMMON> 2,017,521
<CAPITAL-SURPLUS-PAID-IN> 3,709,893
<RETAINED-EARNINGS> 2,635,887
<TOTAL-COMMON-STOCKHOLDERS-EQ> 8,363,301
437,500
402,056
<LONG-TERM-DEBT-NET> 7,770,067
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 680,900
<LONG-TERM-DEBT-CURRENT-PORT> 209,867
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 8,266,234
<TOT-CAPITALIZATION-AND-LIAB> 26,129,925
<GROSS-OPERATING-REVENUE> 9,609,972
<INCOME-TAX-EXPENSE> 554,994
<OTHER-OPERATING-EXPENSES> 7,714,387
<TOTAL-OPERATING-EXPENSES> 7,714,387
<OPERATING-INCOME-LOSS> 1,895,585
<OTHER-INCOME-NET> 54,441
<INCOME-BEFORE-INTEREST-EXPEN> 1,950,026
<TOTAL-INTEREST-EXPENSE> 639,823
<NET-INCOME> 755,209
33,113
<EARNINGS-AVAILABLE-FOR-COMM> 722,096
<COMMON-STOCK-DIVIDENDS> 728,727
<TOTAL-INTEREST-ON-BONDS> 0
<CASH-FLOW-OPERATIONS> 2,610,876
<EPS-PRIMARY> 1.75
<EPS-DILUTED> 1.75
</TABLE>
