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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(MARK ONE) ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF
[X] THE SECURITIES EXCHANGE ACT OF 1934 [FEE REQUIRED]
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1995
OR
[_] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF
THE SECURITIES EXCHANGE ACT OF 1934 [NO FEE REQUIRED]
FOR THE TRANSITION PERIOD FROM TO
COMMISSION FILE NUMBER 1-2348
PACIFIC GAS AND ELECTRIC COMPANY
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
California 94-0742640
(STATE OR OTHER JURISDICTION OF (IRS EMPLOYER IDENTIFICATION NO.)
INCORPORATION OR ORGANIZATION)
77 Beale Street 94177
P.O. Box 770000 (ZIP CODE)
San Francisco, California
(ADDRESS OF PRINCIPAL EXECUTIVE
OFFICES)
(415) 973-7000
(REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE)
SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:
NAME OF EACH EXCHANGE ON
TITLE OF EACH CLASS WHICH REGISTERED
- ------------------- ---------------------------
[S] [C]
Common Stock, par value $5 per share New York Stock Exchange and
Pacific Stock Exchange
First Preferred Stock, cumulative, American Stock Exchange and
par value $25 per share: Pacific Stock Exchange
Redeemable:
7.44% 5% Series A
7.04% 4.80%
6-7/8% 4.50%
5% 4.36%
Mandatorily Redeemable:
6.57% 6.30%
Nonredeemable:
6% 5-1/2% 5%
First and Refunding Mortgage Bonds: New York Stock Exchange
INTEREST DATE OF
SERIES RATE % MATURITY
- ------ -------- ------------
[S] [C] [C]
JJ 4-1/2 Jun. 1, 1996
KK 4-1/2 Dec. 1, 1996
7.90% Cumulative Quarterly Income American Stock Exchange and
Preferred Securities, Series A Pacific Stock Exchange
(liquidation preference $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]
The total number of shares of PG&E's Common Stock outstanding at March 7,
1996 was 414,516,477. On that date the aggregate market value of the voting
stock held by nonaffiliates of PG&E was approximately $11,274 million. The
market values of the various classes of voting stock held by nonaffiliates
were as follows: Common Stock, $10,827 million; and First Preferred Stock,
$447 million. 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 PG&E'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 Part II (Items 5, 6, 7 and 8)
December 31, 1995.......................... Part IV (Item 14)
(2) Designated portions of the Proxy
Statement and Prospectus relating to the
1996 annual meeting 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
Corporate Structure and Business................................. 1
Competition and Industry Restructuring........................... 2
Electric Industry................................................ 3
Gas Industry..................................................... 4
The Company's Response to the New Competitive Environment........ 4
Proposed Holding Company Structure............................... 5
Rate Matters..................................................... 6
California Ratemaking Mechanisms................................. 6
1996 Rate Proceedings............................................ 9
1997 Rate Filings................................................ 10
Workforce Reduction Rate Mechanism............................... 11
Customer Energy Efficiency/Demand Side Management Programs....... 11
Capital Requirements and Financing Programs...................... 12
Electric Utility Operations
Electric Industry Restructuring.................................. 14
Market Structure................................................. 14
Market Power..................................................... 14
Customer Choice.................................................. 15
CTC/Stranded Costs............................................... 15
Proposed Modification to Diablo Ratemaking....................... 16
Public Purpose Programs.......................................... 17
Implementation Schedule.......................................... 17
Application for Rehearing........................................ 18
Potential CTC Bypass............................................. 18
Financial Impact of Electric Industry Restructuring.............. 19
Storm Response Proceedings....................................... 20
Electric Operating Statistics.................................... 22
Electric Generating and Transmission Capacity.................... 23
Diablo Canyon.................................................... 24
Diablo Canyon Operations......................................... 24
Diablo Settlement................................................ 25
Nuclear Fuel Supply and Disposal................................. 26
Insurance........................................................ 27
Decommissioning.................................................. 27
Other Electric Resources......................................... 28
QF Generation.................................................... 28
Geothermal Generation............................................ 28
Western Systems Power Pool....................................... 29
Helms Pumped Storage Plant....................................... 29
Pending Electric Reasonableness Issues........................... 30
Electric Load Forecast and Resource Planning and Procurement..... 30
Electric Transmission............................................ 31
Transmission Access and Wholesale Power Market Competition....... 31
Regional Transmission Groups..................................... 33
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Gas Utility Operations
Gas Operations.................................................. 33
Gas Operating Statistics........................................ 34
Natural Gas Supplies............................................ 35
Gas Regulatory Framework........................................ 35
Restructuring of Gas Supply Arrangements........................ 37
ANG and NOVA Capacity........................................... 37
El Paso and PGT Capacity........................................ 38
Transwestern Capacity........................................... 39
Gas Reasonableness Proceedings.................................. 39
1988-1990 Canadian Gas Procurement Activities................... 39
Gas Settlement Agreements....................................... 40
Financial Impact of Gas Reasonableness Proceedings.............. 41
PGT/PG&E Pipeline Expansion .................................... 41
CPUC Ratemaking................................................. 41
FERC Ratemaking................................................. 42
Other Competitive Pipeline Projects............................. 43
Storage Service................................................. 43
PG&E Enterprises
Domestic Non-Utility Electric Generation........................ 44
International Power Generation.................................. 44
International Gas and Electric Distribution..................... 44
Energy Products and Services.................................... 44
Real Estate Development......................................... 44
Other........................................................... 45
Environmental Matters and Other Regulation
Environmental Matters........................................... 45
Environmental Protection Measures............................... 45
Hazardous Materials and Hazardous Waste Compliance and
Remediation.................................................... 46
Electric and Magnetic Fields.................................... 48
Low Emission Vehicle Programs................................... 49
Other Regulation................................................ 49
California Public Utilities Commission.......................... 49
California Energy Commission.................................... 49
Federal Energy Regulatory Commission............................ 50
Nuclear Regulatory Commission................................... 50
Item 2. Properties...................................................... 50
Item 3. Legal Proceedings............................................... 50
Antitrust Litigation............................................ 50
Hinkley Compressor Station Litigation........................... 51
Counties Franchise Fees Litigation.............................. 52
Cities Franchise Fees Litigation................................ 52
Time-of-Use Meter/Customer Notification Litigation.............. 53
Norcen Litigation............................................... 53
Coastal League Litigation....................................... 54
California Attorney General Investigation....................... 54
Item 4. Submission of Matters to a Vote of Security Holders............. 54
Executive Officers of the Registrant............................ 55
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PART II
Item 5. Market for the Registrant's Common Equity and Related Stockholder Matters............. 55
Item 6. Selected Financial Data............................................................... 55
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations. 56
Item 8. Financial Statements and Supplementary Data........................................... 56
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.. 56
PART III
Item 10. Directors and Executive Officers of the Registrant.................................... 56
Item 11. Executive Compensation................................................................ 56
Item 12. Security Ownership of Certain Beneficial Owners and Management........................ 56
Item 13. Certain Relationships and Related Transactions........................................ 56
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K...................... 57
Indemnification Undertaking........................................................... 61
Signatures..................................................................................... 62
Report of Independent Public Accountants....................................................... 63
Financial Statement Schedule................................................................... 64
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GLOSSARY OF TERMS
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AEAP............ Annual Earnings Assessment Proceeding
AER............. Annual Energy Rate
AFUDC........... allowance for funds used during construction
ALJ............. Administrative Law Judge
ANG............. Alberta Natural Gas Company Ltd
ARA............. Attrition Rate Adjustment
A&S............. Alberta and Southern Gas Co. Ltd.
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
CEE............. Customer Energy Efficiency
CEMA............ Catastrophic Events Memorandum Account
CERCLA.......... Comprehensive Environmental Response, Compensation, and Liability Act
CIG............. customer identified gas program
Company......... Pacific Gas and Electric Company and its wholly owned and controlled
subsidiaries
core customers.. residential and smaller commercial customers
core
subscription Noncore customers who elect to receive combined gas procurement and
customers...... transportation service
CPIM............ Core Procurement Incentive Mechanism
CPUC............ California Public Utilities Commission
CTC............. competition transition charge
DALEN........... DALEN Corporation
Diablo Canyon... Diablo Canyon Nuclear Power Plant
Diablo
Settlement..... Diablo Canyon rate case settlement
DOE............. U.S. Department of Energy
DRA............. Division of Ratepayer Advocates
DSM............. Demand Side Management
EAD............. Expedited Application Docket
EBB............. electronic bulletin board
ECAC............ Energy Cost Adjustment Clause
El Paso......... El Paso Natural Gas Company
EMF............. electric and magnetic fields
Energy Act...... National Energy Policy Act of 1992
Enterprises..... PG&E Enterprises
EPA............. U.S. Environmental Protection Agency
ERAM............ Electric Revenue Adjustment Mechanism
ER94............ 1994 Electricity Report
Exchange........ wholesale power pool
FERC............ Federal Energy Regulatory Commission
Geysers......... The Geysers Power Plant
GRC............. General Rate Case
GWh............. gigawatt-hours
Helms........... Helms Pumped Storage Plant
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Helms
Settlement..... proposed settlement resolving the treatment of unrecovered Helms costs
Humboldt........ Humboldt Bay Power Plant
ICIP............ Incremental Cost Incentive Price
InterGen........ International Generating Company, Ltd.
IOUs............ investor-owned utilities
IPP............. independent power producer
ISO............. Independent System Operator
ITCS............ Interstate Transition Cost Surcharge
JMC............. J. Makowski Company, Inc.
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
Mojave.......... Mojave Pipeline Company
MW.............. megawatts
NEIL............ Nuclear Electric Insurance Limited
NML............. Nuclear Mutual Limited
noncore
customers...... industrial and large commercial customers
NOPR............ Notice of Proposed Rulemaking
NOx............. oxides of nitrogen
NOVA............ NOVA Corporation of Alberta
NRC............. Nuclear Regulatory Commission
Nuclear Waste
Act............ Nuclear Waste Policy Act of 1982
ParentCo........ parent holding company
PBR............. performance-based ratemaking
PEPR............ Pipeline Expansion Project Reasonableness
PG&E............ Pacific Gas and Electric Company
PG&E Pipeline
Expansion...... the PG&E, or California, portion of the PGT/PG&E Pipeline Expansion
PGT............. Pacific Gas Transmission Company
PGT Pipeline
Expansion...... the PGT, or interstate, portion of the PGT/PG&E Pipeline Expansion
Pipeline
Expansion...... PGT/PG&E Pipeline Expansion
Properties...... PG&E Properties, Inc.
PRP............. potentially responsible party
PURPA........... Public Utility Regulatory Policies Act of 1978
QF.............. qualifying facility
RTG............. Regional Transmission Group
SCE............. Southern California Edison Company
SFAS............ Statement of Financial Accounting Standards
SoCal Gas....... Southern California Gas Company
SONGS........... San Onofre Nuclear Generating Station
TCRM............ Transition Cost Recovery Mechanism
Transwestern.... Transwestern Pipeline Company
Tuscarora....... Tuscarora Gas Transmission Company
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USGen........... U.S. Generating Company
USGen Power
Services....... USGen Power Services, L.P.
USOSC........... U.S. Operating Services Company
Vantus.......... Vantus Energy Corporation
WRTA............ Western Regional Transmission Association
WSPP............ Western Systems Power Pool
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PART I
ITEM 1. BUSINESS.
GENERAL
CORPORATE STRUCTURE AND BUSINESS
Pacific Gas and Electric Company, incorporated in California in 1905, is an
operating public utility engaged principally in the business of supplying
electric and natural gas service throughout most of Northern and Central
California. (Unless specified otherwise, "PG&E" shall refer to Pacific Gas and
Electric Company and the "Company" shall refer to PG&E and its wholly owned and
controlled subsidiaries.)
PG&E's principal executive office is located at 77 Beale Street, P.O. Box
770000, San Francisco, California 94177, and its telephone number is (415) 973-
7000.
As of December 31, 1995, the Company had $26.9 billion in assets. The Company
generated $9.6 billion in operating revenues for 1995. As of December 31, 1995,
the Company had approximately 22,000 employees.
The Company's gas and electric utility operations, which include Diablo
Canyon Nuclear Power Plant (Diablo Canyon) operations, represent the principal
component of its business, contributing $9.4 billion in revenues in 1995 (98%
of the Company's total revenues). The Company's utility operations contributed
$2.96 of the Company's total 1995 earnings per share of $2.99. The Company's
utility assets were $25.8 billion at December 31, 1995, representing 96% of the
Company's total assets.
Diablo Canyon operations consist of two nuclear power reactor units, each
capable of generating up to approximately 26 million kilowatt-hours (kWh) of
electricity per day. In 1995, Diablo Canyon contributed $1.8 billion of
revenues (19% of the Company's total revenues) and $1.16 in earnings per share
(39% of the Company's total 1995 earnings per share). Diablo Canyon had assets
of $5.7 billion at December 31, 1995 (21% of the Company's total assets).
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 included in PG&E's service territory is
smaller than previously reported due to new calculations based on more advanced
land measurement technology and the exclusion of areas formerly included in
PG&E's service territory that are now served by municipalities and irrigation
districts.) The area's diverse economy includes aerospace, electronics,
financial services, food processing, petroleum refining, agriculture and
tourism. At December 31, 1995, PG&E served approximately 4.4 million electric
customers and 3.6 million gas 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, 70 hydroelectric powerhouses with 111 units, the
Helms hydroelectric pumped storage plant (Helms) with three units, and a
geothermal energy complex of 14 units. 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.
To ensure a diverse and competitive mix of natural gas supplies, PG&E
purchases gas from both Canadian and United States suppliers. In 1995, about
64% of PG&E's gas supply came from fields in Canada, about 8% came from fields
in California and about 28% came from fields in other states (substantially all
from the U.S. Southwest).
The Company's utility operations also include Pacific Gas Transmission
Company (PGT), a wholly owned gas pipeline subsidiary of PG&E. 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
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from the Canadian-U.S. border to the Oregon-California border. In 1995, PGT
placed in service two smaller diameter pipeline extensions within Oregon,
totaling 106 miles. PGT had assets of approximately $1.2 billion at December
31, 1995. PGT's revenues in 1995 were approximately $194 million, excluding
revenues related to services provided to PG&E.
Currently, the Company's utility operations, other than Diablo Canyon, are
regulated primarily under the traditional cost-based approach to ratemaking.
However, as discussed below (see "Competition and Industry Restructuring"),
ongoing regulatory reform in both the electric and gas utility businesses would
shift utility regulation for certain services to concepts based upon market
competition and benchmarks. Diablo Canyon operations are already conducted
under an alternative performance-based approach to ratemaking, as a result of
the Diablo Canyon rate case settlement (Diablo Settlement), effective in 1988.
Under this approach, revenues for the plant are based primarily on the amount
of electricity generated, rather than on the costs associated with the plant's
operations.
PG&E has proposed certain modifications to the Diablo Settlement in
conjunction with adoption of a customer electric rate freeze, effective January
1, 1997. If adopted, PG&E's proposal to modify Diablo Canyon pricing and
implement a customer electric rate freeze, and to accelerate recovery of
utility generation-related investments, including Diablo Canyon, and related
regulatory assets would result in a significant reduction in annual earnings
beginning in 1997. See "Electric Utility Operations--Electric Industry
Restructuring--Proposed Modification to Diablo Ratemaking" and "--Financial
Impact of Electric Industry Restructuring" below.
Building on its expertise in the energy industry, the Company is expanding
its diversified operations, principally through its wholly owned subsidiary,
PG&E Enterprises (Enterprises). Enterprises, through its subsidiaries and
affiliates, engages in nonutility electric generation, power plant operations
and services, power marketing, energy management services and real estate
development. Enterprises generated approximately $176 million in revenues in
1995 and contributed $.03 of the Company's total 1995 earnings per share of
$2.99. Enterprises had assets of $1.0 billion at December 31, 1995.
In October 1995, the Board of Directors of PG&E authorized management to seek
regulatory approvals to establish a holding company structure for the Company.
PG&E and its two principal subsidiaries, PGT and Enterprises, would become
subsidiaries of the holding company. PG&E's common shareholders would own the
common stock of the holding company rather than that of PG&E itself. See
"Proposed Holding Company Structure" for further discussion of this proposal.
COMPETITION AND INDUSTRY RESTRUCTURING
Under traditional utility regulatory schemes, utilities have been accorded
the right to serve customers within designated geographical areas in return for
the commitment to provide service to all who request it. Regulation was
designed in part to take the place of competition to ensure that utility
services were provided at fair prices. Currently, rates are set under
traditional cost-of-service ratemaking under which rates are set to collect
authorized revenues to cover operating expenses and capital costs, including a
fair return on investment.
Recent changes in both the gas and electric industries have allowed
competition to develop in the gas supply and electric generation segments of
the Company's business. A number of reforms at both the federal and state level
have been implemented, and even more far-reaching reforms proposed, which are
designed to restructure the energy supply industry and promote competition by
providing electric and gas customers with purchasing options. While the
ultimate impact of these developments is uncertain, they are expected to result
in fundamental changes in the way the Company conducts its business and to
cause future earnings to be more volatile.
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ELECTRIC INDUSTRY
PG&E currently performs the functions of electric generation, transmission,
distribution and customer service. However, self-generation and cogeneration
have provided some major utility customers with alternative sources to satisfy
their electric supply needs and competition from nonutility and nonregulated
electric suppliers is expected to provide additional alternative sources in the
near future. PG&E itself obtains a portion of its electric supply from
generation sources outside its service territory and from qualifying
facilities, or QFs (small power producers or cogenerators that meet certain
federal guidelines qualifying them to supply generating capacity and electric
energy to utilities).
Regulatory changes enacted at the federal level and those contemplated at the
state level have transformed and will continue to transform the electric
transmission function by promoting open access to nonutility suppliers. At the
federal level, the National Energy Policy Act of 1992 (Energy Act) reduced
various restrictions on the operation and ownership of nonutility power
generators, known as independent power producers (IPPs), including QFs, and
provided them and other wholesale suppliers and purchasers with increased
access to electric transmission service throughout the United States. The
Federal Energy Regulatory Commission (FERC) has issued a Notice of Proposed
Rulemaking (NOPR) on open access transmission. The NOPR proposes to require
that all utilities offer open access wholesale transmission service that is
comparable to the wholesale transmission service that utilities provide
themselves. In addition, the FERC accepted, subject to refund and the outcome
of a hearing on PG&E's transmission rates and a final decision in the NOPR,
PG&E's proposed open access wholesale electric transmission tariffs, effective
July 1, 1995. These tariffs generally conform to the FERC NOPR.
In December 1995, the California Public Utilities Commission (CPUC) issued a
decision calling for the restructuring of California's electric industry. The
CPUC's goal is to provide a structure that will ultimately allow California
consumers to choose among competing suppliers of electricity.
In summary, the CPUC's decision would (1) simultaneously create a wholesale
power pool (the Exchange) and allow direct access for certain customers to
contract directly with nonutility electric generation providers beginning, at
the latest, on January 1, 1998, with all customers phased into direct access
within five years, (2) establish an Independent System Operator (ISO) to manage
and control the transmission system, and (3) provide recovery of utilities'
stranded costs (costs which could not be recovered under market-based pricing)
through a non-bypassable surcharge, or competition transition charge (CTC), to
be imposed on all customers taking retail electric service as of or after
December 20, 1995. Under this new market structure, PG&E and the other
investor-owned utilities (IOUs) in California would be required during an
initial interim five-year period to bid all their own electric generation into
the Exchange, which would set a market clearing price. The IOUs would also be
required to turn over control of their transmission systems to the ISO, which
would operate those systems to provide open and nondiscriminatory transmission
access for retail and wholesale generation transactions under filed
transmission tariffs. Ultimately, it is contemplated that all customers will
have the choice of buying electricity from their local distribution utility,
through the Exchange, or directly from electric generators through direct
access bilateral contracts. The decision also ordered PG&E and Southern
California Edison Company (SCE) to file plans relating to the voluntary
divestiture of at least 50% of their fossil fuel generation assets.
Under the restructured industry contemplated in the CPUC's decision, PG&E
would ultimately be directly competing with other generation providers to
supply its customers' electric generation needs. PG&E would continue to provide
distribution functions as a regulated monopoly, but its rates for these
services would be based upon a method of regulation which includes performance
benchmarks. See "Electric Utility Operations--Electric Industry Restructuring"
below.
The CPUC restructuring plan is likely to be the subject of further federal
and state regulatory and legislative action, and accordingly there is no
assurance that the market structure outlined in the order will be established
as proposed. Nevertheless, the order indicates the likely direction of electric
utility
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restructuring in California, namely increased competition in the electric
generation market accompanied by regulatory reforms to provide stronger
incentives for efficient utility operations, management and investment in the
areas where utilities still provide monopoly functions.
GAS INDUSTRY
Restructuring of the natural gas industry has given customers more options in
meeting their gas supply needs. Industrial and large commercial (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. In
the latter half of 1993, more noncore customers began purchasing their own gas
with the implementation of FERC Order 636 and the CPUC's capacity brokering
program. FERC Order 636 required interstate pipeline companies, including PGT,
to unbundle their services into separate sales, transmission and storage
services. The CPUC's capacity brokering program required California utilities
to release firm interstate pipeline capacity that they no longer needed. These
changes have made it easier for customers to purchase gas directly from
suppliers. Certain customers can also use alternative transmission services
provided by competing companies.
While noncore customers have had options in the gas marketplace, residential
and smaller commercial (core) customers have had more limited opportunities in
choosing their gas suppliers. Currently, substantially all core customers
receive bundled services from PG&E. PG&E purchases and delivers gas to these
customers and prices such service as a package.
In an effort to promote competition and increase options for all customers,
as well as to position itself for success in the competitive marketplace, PG&E
is actively pursuing changes in the California gas industry as part of its "Gas
Accord" proposal. See "Gas Utility Operations -- Gas Regulatory Framework"
below.
THE COMPANY'S RESPONSE TO THE NEW COMPETITIVE ENVIRONMENT
PG&E has taken several significant steps to address the issues raised by the
new competitive environment in the energy industry. These steps are intended to
help PG&E compete effectively in the restructured electric and gas industries.
With this objective in mind:
-- In 1995, PG&E announced a five-year goal of reducing its system average
electric rate from 10.8 cents per kWh to 10 cents per kWh or less. As a
result of several CPUC decisions issued in 1995, PG&E's system average
electric rate has fallen to 9.9 cents per kWh as of January 1, 1996.
PG&E's system average electric rate also has declined relative to the
national average rate, falling from nearly 50% above the projected
national average electric rate for IOUs in 1995 to approximately 39%
above the estimated national average in 1996. In 1996, PG&E's average
residential gas rate is more than 8% below the projected national average
rate.
-- PG&E has taken a leadership role in seeking a restructuring of the
California gas marketplace in proposing its Gas Accord. As part of that
proposal, PG&E seeks to build a consensus supporting a restructuring of
the gas industry that will result in greater customer choice and more
competitive gas services.
-- PG&E is seeking the approval of regulatory authorities and its
shareholders of a plan to change the corporate organization of PG&E and
its subsidiaries to form a holding company. PG&E and its two principal
subsidiaries, PGT and Enterprises, would become subsidiaries of the
holding company, and PG&E's current common shareholders would own the
common stock of the holding company. The Company believes that the
formation of a holding company will help the Company to respond more
effectively and efficiently to competitive changes taking place in the
utility industry and to new business opportunities that may arise from
those changes. This structure should enhance the financial separation of
the Company's California utility business from its other businesses and
also provide greater financing flexibility. See "Proposed Holding Company
Structure" below for a more detailed description of the proposed new
corporate structure.
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-- Through Enterprises, the Company continues to explore opportunities to
develop businesses and compete in the nonregulated energy business. U.S.
Generating Company (USGen) has already established itself as one of the
largest independent power producers in the United States, and recently
formed a new entity, USGen Power Services, L.P. (USGen Power Services),
that will focus on power marketing and bulk power trading activities
outside of PG&E's service territory. Enterprises is exploring
international electric generation opportunities through International
Generating Company, Ltd. (InterGen), a company recently formed in a
partnership with Bechtel Enterprises, Inc., which will develop, build, own
and operate electric generation and related energy projects outside the
United States. Enterprises has also formed a new energy products services
and marketing company, Vantus Energy Corporation (Vantus), which will
market competitively priced energy commodities bundled with new products
and services for customers.
-- In connection with the CPUC's electric industry restructuring decision, on
March 29, 1996, PG&E filed a comprehensive plan with the CPUC that could
significantly facilitate the transition to a more open and competitive
electric power market. PG&E's proposal has four elements: (1)
significantly reducing PG&E's utility generation-related transition costs
by modifying the ratemaking for Diablo Canyon to recover the sunk costs of
Diablo Canyon over a five year period through 2001 and adjusting the
variable price received from Diablo Canyon generation; (2) freezing
customer electric rates at current levels for the next five years, until
the end of 2001; (3) using part of the revenues from the rate freeze to
cover maintenance, operating and customer service activities already being
undertaken but which are not covered by current base rates; and (4) using
the remainder of the revenues from the rate freeze to accelerate the
recovery of remaining utility generation-related transition costs. PG&E
would be at risk for completing recovery of such costs by the end of 2001.
Under PG&E's proposal, and in conjunction with the earlier Diablo Canyon
repricing approved by the CPUC in May 1995 (see "Electric Utility
Operations -- Diablo Canyon -- Diablo Settlement" below), PG&E will have
reduced by more than 60% of the total PG&E utility generation-related
transition costs which customers would otherwise have paid under the
original Diablo Settlement. See "Electric Utility Operations -- Electric
Industry Restructuring -- Proposed Modification to Diablo Ratemaking"
below for a more detailed description of PG&E's proposal.
The Company cannot predict the ultimate outcome of the ongoing changes that
are taking place in the utility industry or predict whether such outcome will
have a material impact on its financial condition or results of operations.
However, the Company believes the end result will involve a fundamental change
in the way it conducts business. These changes will impact financial operating
trends resulting in greater earnings volatility. The Company is actively
seeking regulatory and operational changes that will allow it to provide energy
services in a safe and reliable manner at competitive prices while achieving
strong financial performance.
PROPOSED HOLDING COMPANY STRUCTURE
The PG&E Board of Directors has authorized, subject to shareholder approval,
a plan to restructure the corporate organization of PG&E and its subsidiaries.
The result of the change in corporate structure will be to have PG&E become a
separate subsidiary of a parent holding company (ParentCo) with the present
holders of PG&E Common Stock becoming holders of ParentCo Common Stock. As part
of the change in structure, it is contemplated that PG&E will transfer its
ownership interests in its two principal subsidiaries -- PGT and Enterprises --
to ParentCo, so that PGT and Enterprises will become subsidiaries of ParentCo.
The debt and preferred stock of PG&E would remain outstanding at the PG&E level
and would not become obligations or securities of ParentCo.
As facets of the traditional utility business, such as electric generation
and gas transmission, become less regulated and more competitive, the energy
options for customers, particularly large industrial users of energy, are
expanding and the challenges to utility operations are intensifying. At the
same time that the regulatory framework and energy markets within California
are changing, industry change outside PG&E's Northern and Central California
service territory is presenting the Company with new business opportunities.
5
<PAGE>
The corporate separation and financing flexibility afforded by a holding
company structure will increase the Company's ability to respond to the
changing operational, regulatory and economic environment for utilities. For
example, should it become necessary or appropriate, a holding company structure
could accommodate separation of components of PG&E's business from PG&E's
remaining core utility business, while allowing for common ownership of these
businesses under ParentCo. Similarly, when new business opportunities arise,
the new businesses can be operated through subsidiaries of ParentCo rather than
through subsidiaries of PG&E, thereby enhancing the separation between PG&E and
those businesses.
This separation of business functions will facilitate the development of
other businesses while helping to insulate PG&E -- the utility -- from the
risks associated with their activities. Such separation will also permit a more
effective and flexible use of financing techniques that are directly suited to
the particular requirements, characteristics and risks of the Company's other
businesses. Accordingly, it is believed that the holding company structure will
support PG&E's ability to continue to meet its customers' needs efficiently
while permitting ParentCo to respond to a changing business environment.
As part of the change in corporate structure, it is intended that PG&E will
transfer to ParentCo its ownership interests in PGT and Enterprises. As a
result of the proposed transfer, PGT and Enterprises and their assets would no
longer be owned by PG&E. If the separation of these subsidiaries had occurred
on January 1, 1995, the net income (before PG&E Preferred Stock dividend
requirements) of PG&E for the year ended December 31, 1995, would have
decreased by approximately $59 million, or approximately 4%, and total assets
would have decreased by approximately $2,198 million, or approximately 8%.
PG&E's net investment in PGT and Enterprises was approximately $1,221 million
on December 31, 1995, representing approximately 14% of the PG&E Common Stock
shareholders' equity as of that date.
The transfer of PGT and Enterprises to ParentCo, like other aspects of the
proposed change in corporate structure, is conditioned upon obtaining certain
consents and other approvals, the specific terms and conditions of which PG&E
cannot predict. Moreover, at the time of the transfers, PG&E's net investment
in PGT and Enterprises and their contribution to the net income of PG&E may
differ materially from the amounts and percentages shown above due in part to
the impact of the changing regulatory environment on PG&E's future operations
as well as new business opportunities and other changes in the Company's
business. It is possible that, based on future events, the PG&E Board of
Directors may determine that it is not in the best interests of PG&E or its
shareholders to transfer one or both of these subsidiaries to ParentCo in
connection with the proposed change in corporate structure.
PG&E shareholders will be asked to approve the change in corporate structure
at PG&E's Annual Meeting of Shareholders to be held on April 17, 1996. If
shareholder approval is received, it is contemplated that these structural
changes will be effected as soon as practicable following receipt of all
required regulatory approvals, including approval by the CPUC, the FERC and the
Nuclear Regulatory Commission (NRC). An application for approval by the CPUC
was filed by PG&E on October 20, 1995 and PG&E subsequently filed for approvals
from the FERC and the NRC.
RATE MATTERS
CALIFORNIA RATEMAKING MECHANISMS
The ratemaking mechanisms currently applied by the CPUC in setting PG&E's
rates are described below. It is expected that many of these mechanisms may be
changed significantly or even eliminated as both the electric and gas utility
industries are restructured and regulatory reforms proposed by both PG&E and
government authorities are implemented.
Under the CPUC's Rate Case Plan, the CPUC sets PG&E's base revenue
requirements for both electric and gas operations in the General Rate Case
(GRC) proceeding, which occurs every three years. Base revenue is revenue
intended to recover PG&E's fixed costs and non-fuel variable costs and to
provide a return on
6
<PAGE>
invested capital. 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). The CPUC then determines the revenue
requirement to cover those costs, including items such as depreciation, taxes,
cost of capital, operation, maintenance, and administrative and general
expenses. The revenue requirement is forecasted on the basis of a specified
test year. 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 decision in the revenue requirement phase of the 1996 GRC was issued in
December 1995, setting base rates effective January 1, 1996. In issuing that
decision the CPUC noted that this may be the last time PG&E's costs are
reviewed in a GRC because the CPUC is considering moving to a performance-based
ratemaking (PBR) mechanism.
The 1996 GRC decision did not set the revenue requirement for the PG&E, or
California, portion of the PGT/PG&E Pipeline Expansion (Pipeline Expansion),
which will be determined in a separate proceeding. The CPUC has approved
separate incremental ratemaking for the PG&E portion of the Pipeline Expansion
(PG&E Pipeline Expansion). The costs of PG&E Pipeline Expansion operations are
recovered only from PG&E Pipeline Expansion customers, through rates
established in separate PG&E Pipeline Expansion rate proceedings. Currently,
PG&E Pipeline Expansion customers pay rates based on an interim revenue
requirement. The final 1996 rates will be based on the outcome of the Pipeline
Expansion Project Reasonableness (PEPR) proceeding, with a final decision
expected in late 1996. Thereafter, PG&E Pipeline Expansion rate cases will
occur every three years. See "Gas Utility Operations -- PGT/PG&E Pipeline
Expansion -- CPUC Ratemaking" below.
Base rates may be adjusted in the years between GRCs through an attrition
rate adjustment (ARA). The ARA is intended to allow PG&E to recover specific
uncontrollable cost changes in its base revenue requirement, thereby preserving
PG&E's opportunity to earn its authorized rate of return in the years between
GRCs. The cost of capital incorporated in an ARA is determined separately by
the CPUC in the annual Cost of Capital consolidated proceeding which reviews
financing costs and adopts capital structures for all California energy
utilities. PG&E did not include an ARA request for 1997 or 1998 in its 1996 GRC
application. It is likely that the ARA will be discontinued in the future
because the CPUC is moving to a PBR structure.
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 or ARA
proceeding. 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, and are
recovered from or returned to customers through higher or lower future rates.
ERAM rate adjustments are made as part of the ECAC proceeding described below.
The Energy Cost Adjustment Clause (ECAC) provides for recovery of 91% of
PG&E's recorded (or actual) electric fuel and fuel-related energy costs, and
for collection of revenues attributable to Diablo Canyon generation.
Differences between the sum of actual costs and Diablo Canyon revenues
recoverable through ECAC, and the revenues intended to cover such amounts,
accumulate in a balancing account, usually with interest, and are recovered
from or returned to ratepayers through ECAC adjustments to future rates. ECAC
rate adjustments are set once a year, based on a January 1 effective date, to
recover the adjustment amount over a forward-looking calendar test year.
Revenue adjustments resulting from the California Alternate Rates for Energy
(CARE) program and the ERAM are consolidated with the ECAC adjustment in the
annual ECAC proceeding. The CARE program provides for discount residential
rates for customers who qualify under low-income criteria, with the direct
costs of CARE electric rate discounts funded through revenue adjustments made
in the ECAC proceeding. Rates are subject to a further ECAC adjustment
effective May 1 if the required adjustment would be more than 5% of total
annual electric revenues.
7
<PAGE>
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. 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.
The Annual Energy Rate (AER) mechanism provides for recovery of 9% of
forecasted electric fuel and fuel-related costs, without balancing account
protection for actual costs that are higher or lower than forecasted. Thus, the
AER mechanism places PG&E at partial risk for variations between actual and
forecasted electric energy costs. To minimize the revenue risk resulting from
the potential for substantial swings in energy-related expenses, the increase
or reduction in earnings due to operation of the AER is limited to a change in
return on equity of 1.4 percent.
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 Pipeline
Expansion. As part of this proceeding, the gas fuel revenue requirement and gas
transportation revenue requirement are adopted, based on forecasts and
assumptions for the upcoming two-year period. The gas fuel revenue requirement
provides for the recovery of the cost of the gas procured for customers who buy
gas from PG&E; the gas transportation revenue requirement provides for the
recovery of the cost of providing gas transportation service for all gas
customers and other costs incurred in providing gas service, including the gas
base revenue requirement set in the GRC and adjusted by the ARA mechanism.
Both the gas fuel and transportation revenue requirements set in the BCAP
include amounts accumulated in several associated balancing accounts. These
balancing accounts accumulate differences between actual expenses and revenue
earned to cover those expenses or between adopted revenue or cost targets and
the actual revenue earned to meet those targets. BCAP rate adjustments may also
include amounts accumulated in the Interstate Transition Cost Surcharge (ITCS)
balancing account. See "Gas Utility Operations -- Restructuring of Gas Supply
Arrangements" below for more detail regarding the ITCS account. Currently,
recovery of gas costs accumulated in the various gas balancing accounts that
recover actual expenses is subject to a CPUC determination that such costs were
incurred reasonably. PG&E has filed an application seeking a core procurement
incentive mechanism which would replace reasonableness reviews of gas costs.
See "Gas Utility Operations -- Gas Regulatory Framework" below.
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.
Generally, a BCAP filing is made on August 15 of every other year for rates
to be effective on April 1 of the following year. PG&E's latest BCAP, filed
November 1994, set rates effective January 1, 1996, except for service on the
PG&E Pipeline Expansion. That BCAP decision ordered PG&E to file its next BCAP
on March 1, 1997, for rates to be effective January 1, 1998. The latest BCAP
decision authorizes annual rate changes to recover from, or return to,
ratepayers undercollections or overcollections in balancing accounts.
Under the Customer Energy Efficiency (CEE) shareholder incentive mechanism
adopted in 1994, PG&E is authorized to recover in rates some of the energy
savings resulting from and costs of certain of its CEE, or Demand Side
Management (DSM), programs. CEE rate adjustments resulting from shareholder
incentives earned on CEE programs are determined as part of the Annual Earnings
Assessment Proceeding (AEAP), a consolidated proceeding established by the CPUC
to authorize shareholder earnings for PG&E and the other California energy
utilities arising out of the previous year's DSM program accomplishments. AEAP
rate adjustments will be consolidated with any other rate changes effective on
January 1 of each year. See "Customer Energy Efficiency/Demand Side Management
Programs" below.
8
<PAGE>
The Catastrophic Events Memorandum Account (CEMA) permits utilities to record
for eventual recovery through rates the reasonable costs they incur in
restoring service, repairing or replacing facilities and complying with
government orders following a catastrophic event which is declared a disaster
by the appropriate federal or state authorities. The utility must seek recovery
of costs accumulated in the CEMA through a GRC or other formal rate-setting
application, with recovery subject to a reasonableness review by the CPUC.
1996 RATE PROCEEDINGS
In December 1995, the CPUC issued decisions which authorize for PG&E a
consolidated annual electric revenue decrease of $443 million and an annual gas
revenue decrease of $211 million. This represents an electric and gas revenue
decrease of 5.6% and 9.5%, respectively from rates in effect in 1995.
The following table summarizes the various rate case decisions that became
effective on January 1, 1996.
SUMMARY OF RATE CASE DECISIONS
EFFECTIVE JANUARY 1, 1996
(IN MILLIONS)
<TABLE>
<CAPTION>
ELECTRIC GAS TOTAL
-------- ----- -----
<S> <C> <C> <C>
1996 GRC and related proceedings (excluding Cost of
Capital)............................................... $(273) $(256) $(529)
1996 Cost of Capital.................................... (45) (14) (59)
ECAC/AER/ERAM/CARE...................................... (112) -- (112)
BCAP.................................................... -- 62 62
AEAP.................................................... (13) (3) (16)
----- ----- -----
Total Change in Revenue Requirement................. $(443) $(211) $(654)
===== ===== =====
</TABLE>
1996 GRC. The CPUC's decision in PG&E's 1996 GRC authorized annual electric
and gas base revenue decreases of approximately $300 million and $270 million,
respectively, from rates in effect in 1995. The total $570 million revenue
decrease in the GRC decision incorporates the rate impact of the 11.60% return
on equity authorized by the CPUC in PG&E's Cost of Capital proceeding (as
described below) and the resulting 9.49% overall authorized utility rate of
return for 1996. The revenue decrease is attributable to declining capital
expenditures, lower cost of capital and reductions in expense levels,
principally relating to workforce reductions. PG&E's budgeted earnings for 1996
were derived, in part, from the revenues authorized by the CPUC in the 1996
GRC, but also include budgeted utility operating expenses that are
approximately $250 million greater than the amount adopted by the CPUC for
setting rates in the 1996 GRC. The higher expense level is primarily
attributable to several projects related to distribution system reliability,
and improved customer service and public information systems.
In addition, base revenue changes resulting from certain related proceedings
were consolidated with the GRC base revenue decrease, as shown in the table
above. The GRC proceeding was held open to consider, among other things, the
cost effectiveness of Helms (see "Electric Utility Operations-- Other Electric
Resources -- Helms Pumped Storage Plant" below) and PG&E's response to outages
caused by recent storms (see "Electric Utility Operations -- Storm Response
Proceedings" below). In January 1996, PG&E filed an application for rehearing
of the CPUC's decision in the revenue requirements phase of the 1996 GRC. PG&E
seeks rehearing on a number of issues, including pension contributions, funding
for nonresidential customer service and the elimination of the Air Quality
Adjustment mechanism.
With respect to Helms, the CPUC directed PG&E to perform a cost-effectiveness
study of Helms, to be submitted by July 1996. The study will consider changes
in rate recovery for the plant which will include, among other things, the
option of retirement with recovery of the investment without a return over a
four-year period. Helms had a net book value of $631 million at December 31,
1995.
9
<PAGE>
1996 Cost of Capital Proceeding. As part of its ruling in the annual generic
Cost of Capital proceeding for California's major energy utilities, the CPUC
authorized for PG&E a utility return on common equity of 11.60%. This
represents a decrease from the 12.10% return on common equity allowed in 1995.
The decision authorizes a utility capital structure of 48.00% common equity,
5.50% preferred stock and 46.50% 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 rate base of 9.49% for 1996, compared with the 9.79%
authorized for 1995.
ECAC. In December 1995, the CPUC also issued a decision in PG&E's ECAC
proceeding. The decision reduces electric revenues by approximately $112
million for the twelve-month forecast period beginning January 1, 1996. The
decrease is composed of a decrease of approximately $263 million in the ECAC
revenue requirement, an increase in the ERAM of approximately $157 million, a
decrease of approximately $12 million under the AER and an increase of
approximately $6 million under the CARE program. The amounts adopted in the
ECAC decision reflected the continuation of PG&E's economic stimulus rate
reduction, an annual $70 million rate reduction offered to PG&E's largest
business customers. The rate reduction, offered since July 1993, was developed
to help attract and retain major employers in Northern and Central California.
BCAP. The CPUC issued a decision in PG&E's BCAP in December 1995, authorizing
an increase of approximately $60 million in annual gas revenues, for a two-year
period beginning January 1, 1996. The BCAP decision also ordered a one-time
refund to core customers, which with interest totaled approximately $218
million, to be made in March 1996. The refund represents an overcollection in
certain gas procurement balancing accounts and disallowances ordered by the
CPUC relating to previous gas procurement and planning practices. Annual gas
revenues were also increased by an additional $2 million as a result of certain
adjustments related to other aspects of gas operations considered in the GRC.
AEAP. In December 1995, the CPUC also issued a decision in the AEAP, which
determines the shareholder incentives earned for PG&E's CEE programs. The
decision adopts PG&E's requested incentive payment of $19.3 million for its
1994 programs, to be collected in installments over a 10-year period. The
ultimate amount of the shareholder incentive to be collected may vary,
depending upon the results of studies to be conducted to measure the actual
energy savings resulting from PG&E's CEE programs. (See "Customer Energy
Efficiency/Demand Side Management Programs" below.) However, because the
incentives from PG&E's 1991 programs are expiring, the net revenue change in
1996 from energy efficiency shareholder incentives is an electric decrease of
$12.8 million and a gas decrease of $3.1 million, which are reflected in the
ECAC and BCAP decisions discussed above.
1997 RATE FILINGS
On March 29, 1996, PG&E filed an application with the CPUC seeking approval
to modify Diablo Canyon ratemaking and adopt a customer electric rate freeze,
effective January 1, 1997, which would result in customer electric rates in
1997 being the same as those in effect on January 1, 1996. See "Electric
Utility Operations--Electric Industry Restructuring--Proposed Modification to
Diablo Ratemaking" below. To achieve the customer electric rate freeze, PG&E
proposes to consolidate the revenue requirement changes resulting from the
following applications PG&E has filed, or will be filing, at the CPUC in 1996:
the ECAC application described below, the application to modify Diablo Canyon
pricing and adopt a customer electric rate freeze, the 1997 base revenue
application described below, the 1997 Cost of Capital application and the 1996
AEAP application.
On April 1, 1996, PG&E intends to file with the CPUC a rate case application
to increase electric base revenues by approximately $156 million, with recovery
of approximately $33 million effective January 1, 1997. Recovery of the
remaining $123 million would be deferred until January 1, 1998 unless otherwise
offset by further decreases in forecasted ECAC costs for 1997. The filing
requests recovery of expenses for electric distribution operations and
maintenance and call center operations. The amounts requested are above the
levels authorized by the CPUC for these activities in the 1996 GRC. The filing
also requests an inflation adjustment from 1996 to 1997.
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<PAGE>
Also on April 1, 1996, PG&E expects to file an application (ECAC
application) with the CPUC to request a revenue requirement decrease of
approximately $405 million, composed of an ECAC decrease of approximately $346
million, an AER decrease of approximately $10 million, an ERAM decrease of
approximately $48 million and a CARE decrease of approximately $1 million.
PG&E's ECAC application includes reports on PG&E's gas and electric system
operations during 1995 and requests a finding that PG&E's gas and electric
operations were reasonable during the 1995 record period.
WORKFORCE REDUCTION RATE MECHANISM
In March 1993, the CPUC authorized the establishment of a memorandum account
to record all costs and savings incurred in connection with PG&E's 1993
workforce reduction program, subject to a reasonableness review. In October
1993, PG&E filed a report with the CPUC to update the forecasted costs and
savings associated with the workforce reduction program. As proposed in its
filing with the CPUC, PG&E's net revenue requirement savings expected to be
achieved during the 1993 GRC cycle through the workforce reduction program
were passed on to ratepayers over a two-year period beginning January 1, 1994.
These savings totaled approximately $156 million. PG&E will file an updated
report with the CPUC in 1996.
The total cost of the 1993 workforce reduction program was $264 million. As
a result of a freeze on electric rates in 1994, PG&E expensed $190 million of
such costs relating to electric operations. The amount relating to gas
operations was deferred and amortized over the period 1993 to 1995.
CUSTOMER ENERGY EFFICIENCY/DEMAND SIDE MANAGEMENT PROGRAMS
PG&E has long been active in the implementation of CEE and other DSM
programs which encourage customers to implement energy-efficient measures.
These measures allow PG&E to defer capital expenditures in connection with
generation, transmission and distribution facilities, reduce operating costs,
reduce the environmental impact of operations and provide service options to
customers. In addition, these measures help to minimize the use of existing
fossil fueled generation. Since the mid-1970s, PG&E has expended over $1.5
billion on DSM programs, allowing PG&E to avoid the need for approximately
1,600 MW of new generating capacity.
Since 1990, the CPUC has permitted PG&E to earn shareholder incentives on
its CEE programs. For resource programs which are designed to produce positive
net benefits (i.e., the net present value of the avoided energy, capacity,
transmission and distribution costs of the programs exceeds the cost of the
CEE
program), the shareholder incentive is 30% of the positive net benefits.
However, the utilities must guarantee the overall cost effectiveness of their
residential and non-residential portfolio of programs in order to earn
shareholder incentives on those programs. If a portfolio is not cost-
effective, the utility must refund to ratepayers the amount by which the costs
of the programs exceed the resource benefits of the portfolio. If the actual
accomplishments of a portfolio fall below a minimum performance standard
established for the portfolio, the entire portfolio will be ineligible for
shareholder incentives. For certain service programs, including PG&E's direct
weatherization and energy efficiency education programs, the shareholder
incentive target is 5% of the cost of the programs. Actual earnings for these
service programs are based on documented program accomplishments.
Shareholder incentives on resource programs are based on actual measured
energy savings rather than forecasted savings and are recovered in rates in
four equal installments over a ten-year period, with the amount recoverable
subject to the outcome of periodic measurement and evaluation studies. The
amount of shareholder incentives authorized for PG&E and other California
utilities is determined annually in the AEAP.
PG&E plans to spend approximately $134 million on CEE programs in 1996,
compared to the $127 million spent on 1995 programs. PG&E is permitted to
recover, through a balancing account, up to a maximum of 130% of the
authorized program expenses for resource programs. The shareholder incentive
mechanism and the requirement of ex post measurement of energy savings over
the 10 years make an estimate of earnings over that period difficult at this
time. PG&E currently estimates it will earn approximately $26 million in
shareholder incentives over the 10-year period as a result of the 1996
programs.
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<PAGE>
CAPITAL REQUIREMENTS AND FINANCING PROGRAMS
The Company continues to require capital for improving its existing
generation, transmission and distribution facilities to enhance their
efficiency and reliability, to extend their useful lives and to comply with
environmental laws and regulations. Expenditures for these purposes, including
the allowance for funds used during construction (AFUDC), were approximately
$963 million for 1995. New investments in diversified operations totaled $181
million in 1995.
The following table sets forth the estimated total capital requirements,
consisting of capital expenditures for the utility functions, Diablo Canyon and
the nonregulated investments of Enterprises and amounts for maturing debt and
sinking funds for the years 1996 through 2000. These are forward looking
statements which involve a number of assumptions and uncertainties. Actual
amounts may differ materially from the estimated amounts shown below.
CAPITAL REQUIREMENTS
(IN MILLIONS)
<TABLE>
<CAPTION>
1996 1997 1998 1999 2000 TOTAL
---- ---- ---- ---- ---- -----
<S> <C> <C> <C> <C> <C> <C>
Utility(1)(2)......................... $1,291 $1,220 $1,283 $1,298 $1,251 $6,343
Diablo Canyon(2)...................... 36 37 39 40 42 194
Enterprises(3)
USGen(4)............................. 124 51 210 57 294 736
InterGen(4).......................... 34 100 120 194 188 636
Other................................ 4 2 2 2 1 11
------ ------ ------ ------ ------ ------
Total Capital Expenditures.......... 1,489 1,410 1,654 1,591 1,776 7,920
Maturing Debt and Sinking Funds....... 304 322 668 272 447 2,013
------ ------ ------ ------ ------ ------
Total Capital Requirements.......... $1,793 $1,732 $2,322 $1,863 $2,223 $9,933
====== ====== ====== ====== ====== ======
</TABLE>
- --------
(1) Utility expenditures are shown net of reimbursed capital and include
California electric and gas operations and existing operations of the gas
pipeline from Canada to California.
(2) Utility expenditures include AFUDC. Expenditures for Diablo Canyon and the
California portion of the PGT/PG&E Pipeline Expansion (see "Gas Utility
Operations -- PGT/PG&E Pipeline Expansion" below) include capitalized
interest.
(3) Enterprises' actual capital expenditures may vary significantly depending
on the availability of attractive investment opportunities.
(4) USGen and InterGen expenditures include commitments by 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 $114
million and $29 million in 1996 and 1997, respectively. There are no
current commitments to make contributions in 1998 or thereafter.
Most of the utility capital expenditures for 1996 through 2000 are associated
with short lead time, modest capital expenditure projects aimed at providing
the facilities required by new customers and at the replacement and enhancement
of existing generation, transmission, distribution and common utility
facilities to enhance their efficiency and reliability and to comply with
environmental laws and regulations. Exceptions include certain major projects
associated with customer service improvements.
The Company estimates that, in addition to the capital expenditure objectives
referred to above, its total capital requirements for the years 1996 through
2000 will include approximately $2,013 million for payment at maturity of
outstanding long-term debt and for meeting sinking fund requirements for debt,
as indicated above.
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<PAGE>
The funds necessary for the Company's 1996-2000 capital requirements 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.
The Company conducts a continuing review of its 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. See "Competition and
Industry Restructuring" above and "Electric Utility Operations -- Electric
Industry Restructuring" below.
13
<PAGE>
ELECTRIC UTILITY OPERATIONS
ELECTRIC INDUSTRY RESTRUCTURING
On December 20, 1995, the CPUC, by a three to two vote, issued a decision
calling for the restructuring of California's electric industry. The
restructuring contemplated in the decision would (1) simultaneously create a
wholesale power pool, or Exchange, and allow direct access for certain
customers to contract directly with electric generation providers beginning, at
the latest, on January 1, 1998, with all customers phased into direct access
within five years, (2) establish an ISO to manage and control the transmission
system, and (3) provide recovery of utilities' stranded costs through a non-
bypassable surcharge, or CTC, to be imposed on all customers taking retail
electric service as of or after December 20, 1995. The decision, while
effective immediately, also provides a 100-day period for legislative review
and sets out an ambitious schedule for various implementing filings and
comments over the period ending in October 1996.
MARKET STRUCTURE
The CPUC decision requires the three largest IOUs to develop a detailed
proposal for submission to the FERC for creation of the ISO. The decision
contemplates that the IOUs, after approvals from the FERC and the CPUC, turn
over control, but not ownership, of their transmission systems 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.
The decision requires the three largest IOUs, in conjunction with other
interested parties, to work together to prepare a joint proposal for the
creation of the Exchange which will be separate from and independent of the
ISO. The Exchange would manage bids for energy, set the market clearing price,
and then submit its delivery schedule to the ISO for dispatch. The IOUs will be
required to bid all their generation output into the Exchange and purchase all
their energy from the Exchange during the five-year transition period to full
direct access. Participation in the Exchange will be voluntary for all other
market participants.
The ISO and Exchange would be separate, independent entities. The decision
instructs the IOUs to file a proposal to establish the ISO and Exchange with
the CPUC and FERC by April 29, 1996.
MARKET POWER
The CPUC concluded that market power issues associated with the electric
industry restructuring almost certainly mandate that PG&E and SCE divest
themselves of a substantial portion of their fossil fuel generating assets. To
encourage divestiture, for each 10% of fossil fuel generation capacity
divested, the decision proposes an increase of up to ten basis points in the
equity return on the undepreciated net book value of fossil fuel generation
assets. The decision required PG&E and SCE to file plans to voluntarily divest
themselves of at least 50% of their fossil fuel generation assets. On March 19,
1996, PG&E filed its response. In its filing, PG&E indicated its willingness to
proceed with divestiture of at least 50% of its fossil-fueled generation assets
as long as CTC recovery is satisfactorily resolved. PG&E stated that it had
retained an investment banker to assist it in evaluating the market for
generation assets, including which plants might be divested and the form which
such divestiture might take. PG&E also indicated that, in light of certain
commissioners' belief that utilities should divest substantially all, if not
all, generation, it would request its investment banker to evaluate the
feasibility and desirability of divesting additional non-nuclear generating
assets. PG&E indicated that it does not propose to divest Diablo Canyon. PG&E's
filing also suggests various steps the CPUC could take to facilitate the
divestiture process.
The decision also directed the IOUs to file comments on the feasibility,
timing and consequences of a corporate restructuring to separate their
operations and assets between the generation, transmission and distribution
functions, including the option of forming a holding company structure. On
March 19, 1996, PG&E filed its comments, indicating that it saw no compelling
reason to effect a corporate separation of its
14
<PAGE>
transmission and distribution functions and anticipated significant practical
obstacles to doing so. PG&E indicated that corporate separation of utility
generation merits further consideration. As PG&E moves toward reducing its
ownership of generation it may be appropriate in the future to locate remaining
generating assets in a separate affiliated corporate entity. Separation in this
manner would be consistent with PG&E's proposed holding company structure.
CUSTOMER CHOICE
Under the CPUC's restructuring decision, the IOUs would continue to provide
distribution, generation and procurement functions for those customers choosing
to take bundled service from the utilities, all of which would be regulated
under a form of PBR during the transition period. The CPUC decision provides
that by January 1, 1998, a representative number of customers from all customer
groups, individually or in an aggregate, will be able to participate in the
first phase of direct access which will last one year, with the balance of
customers phased in to direct access within five years, or sooner if
technically possible. Ultimately, it is contemplated that all customers will
have the choice of buying electricity from their local distribution utility,
through the Exchange or directly from electricity generators through direct
access bilateral contracts.
CTC/STRANDED COSTS
The decision provides for the collection of transition costs through the
imposition of a non-bypassable CTC applied to transmission and distribution
rates. Transition cost recovery shall not increase rates beyond the rate levels
in effect as of January 1, 1996. A transition cost account will be established
for each utility. Electric generation regulatory assets will be included in the
account as authorized by the CPUC. The account will be adjusted annually for
the difference between the authorized CTC obligation associated with the
generation assets and actual revenues earned in the market. The CTC account
will recover the undepreciated book value of a utility's fossil fuel generation
assets as reflected in rate base at a reduced return on equity equal to 10%
below the utility's embedded cost of debt. For hydroelectric and geothermal
generation assets, the CTC will be the above- or below-market portion of the
revenue requirement for those facilities derived through a PBR method. Final
valuation of above-market generation assets will be included in the CTC account
and must be completed by 2003. Non-nuclear generation assets will be valued
through sale, spin-off or market appraisal.
Transition costs resulting from the operation of nuclear generation
facilities and electricity purchases under existing wholesale and QF contracts
will also be recorded in this account. Transition costs for these resources
will be calculated annually over the terms of the contracts or until the
authorized transition cost recovery has been completed. Except for existing QF
generation contracts for which CTC collection will continue until expiration of
the contracts, all transition costs will be collected by 2005.
With respect to recovery of costs associated with Diablo Canyon and the
Diablo Settlement, the decision confirms that the CPUC will continue to honor
regulatory commitments regarding the recovery of nuclear power costs. The
decision provides that (1) transition costs associated with Diablo Canyon will
be calculated as the difference between the Diablo Settlement price and the
market price as determined by the Exchange calculated over the term of the
Diablo Settlement; and (2) the ISO will schedule power from Diablo Canyon on a
must-take basis, consistent with the Diablo Settlement. The CPUC decision
required PG&E to file by March 29, 1996 a proposal for pricing Diablo Canyon
generation at market prices by 2003 and for completing recovery of Diablo
Canyon CTC by 2005 while assuring no overall rate increase over January 1, 1996
levels. Decommissioning costs will also be included in the transition cost
account. The CPUC required that at least one of the alternatives presented in
PG&E's proposal be structured to accelerate recovery of the undepreciated
portion of Diablo Canyon, at a significantly reduced return tied to the
embedded cost of debt, and to include PBR for recovery of operating costs and
prospective capital additions.
15
<PAGE>
PROPOSED MODIFICATION TO DIABLO RATEMAKING
Pursuant to the CPUC's decision, on March 29, 1996, PG&E filed an application
with the CPUC seeking expedited approval to modify Diablo Canyon pricing and
adopt a customer electric rate freeze, effective January 1, 1997. PG&E
indicated that the purpose of the modification application is to accelerate
competition and customer choice in California electricity markets. The
application would reduce the amount of Diablo Canyon transition costs by over
$3.7 billion (net present value) compared to transition costs that would arise
under existing Diablo Canyon prices, while recovering remaining Diablo Canyon
and other utility generation assets by no later than the end of 2001. The
filing would accelerate PG&E's recovery of utility generation-related
transition costs caused by industry restructuring without raising customer
rates. PG&E's application would result in the termination of the modified
Diablo Canyon pricing agreement by the end of 2001, which is fifteen years
earlier than the Diablo Settlement would otherwise terminate, so that Diablo
Canyon generation may be priced at market levels consistent with the goals of
the CPUC restructuring decision. The effect of the modified Diablo Canyon
pricing would be to increase Diablo Canyon's revenue requirement by
approximately $372 million in 1997, compared to existing rates. However, these
revenues will be offset by other rate decreases in order to assure that PG&E's
customer electric rates do not increase above levels in effect as of January 1,
1996. See "General--Rate Matters--1997 Rate Filings" above.
PG&E proposes that the current pricing of Diablo Canyon generation, as set
forth in the Diablo Settlement, be replaced by a new performance-based pricing
schedule which is consistent with the settlement recently adopted by the CPUC
concerning rate recovery for the San Onofre Nuclear Generating Station (SONGS),
owned by SCE and San Diego Gas & Electric Company. Under this approach, the
current Diablo Canyon fixed price would be replaced by a sunk cost revenue
requirement consisting of PG&E's remaining sunk costs in Diablo Canyon as of
December 31, 1996, depreciated over a five year period and subject to a reduced
return consistent with the SONGS settlement. Sunk costs consist of net plant,
working capital and regulatory assets, all net of deferred taxes. The sunk cost
revenue requirement would be recovered without reference to Diablo Canyon's
performance, unless the plant were shut down for nine months or more.
Consistent with the SONGS settlement, PG&E's proposal provides for a
significantly reduced rate of return on common equity equal to 6.77 percent.
The sunk cost revenue requirement would eliminate the need for the floor
payments provision in the Diablo Settlement (see "Diablo Canyon--Diablo
Settlement" below for a more detailed description of the terms of the Diablo
Settlement), and therefore PG&E's right to such floor payments in the event of
prolonged or permanent plant outages would be deleted.
The escalating component of current Diablo Canyon prices would be replaced by
a performance-based Incremental Cost Incentive Price (ICIP) similar to that
used in the SONGS settlement for performance-based recovery of Diablo Canyon's
variable costs and future capital additions. Under the ICIP, the variable costs
and incremental capital additions are recovered under a pre-set price per kWh
of plant output based on an initial forecast of such costs. The ICIP prices
would be 3.65 cents, 3.76 cents, 3.89 cents, 4.04 cents and 4.25 cents, in each
of 1997, 1998, 1999, 2000 and 2001, respectively. This performance-based price
will recover approximately 40% of Diablo Canyon's annual revenue requirement.
The 2016 termination date in the Diablo Settlement would be changed to
December 31, 2001, and related abandonment payment provisions in the Diablo
Settlement would be replaced with closure cost recovery provisions consistent
with the SONGS settlement, under which PG&E would be entitled to recover a
percentage of its annual operating and maintenance and administrative and
general costs for a limited period of years following plant closure. If Diablo
Canyon is shut down prior to such time as transition costs are fully recovered,
PG&E's continued recovery of the sunk cost revenue requirement would be subject
to CPUC evaluation. After such time as transition costs are fully recovered,
there would be no restrictions on Diablo Canyon's operations or on which
markets it could sell into, but 50% of any profits earned after such time would
be allocated to ratepayers.
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<PAGE>
Certain fixed or safety-related costs, such as decommissioning costs, would
continue to be recovered in PG&E's base rates without reference to Diablo
Canyon's performance. At PG&E's option, recovery of estimated decommissioning
costs could be accelerated under the customer electric rate freeze over the
same depreciation period as Diablo Canyon's sunk costs.
In conjunction with these modifications to Diablo Canyon pricing
arrangements, PG&E's application proposes that the CPUC adopt a customer
electric rate freeze at 1996 levels through the end of 2001, in order to permit
PG&E to accelerate capital recovery of its other utility generation and
associated regulatory assets through 2001. PG&E would be at risk for completing
recovery of PG&E's utility generation-related investments, including Diablo
Canyon, and related regulatory assets by the end of 2001.
PG&E indicated that adoption of its customer electric rate freeze proposal is
linked inextricably with the modified Diablo Canyon pricing proposal. In the
event that the CPUC is unable to adopt the proposed customer electric rate
freeze, PG&E would withdraw its proposal to price Diablo Canyon generation in a
manner similar to that contemplated in the SONGS settlement, and instead would
propose an alternative modification of Diablo Canyon pricing. Under this
alternative, transition costs would consist of that portion of payments under
the Diablo Settlement in excess of market value, including estimated payments
through the 2016 termination date of the Diablo Settlement, as determined by
the Exchange price. The portion of Diablo Canyon transition costs relating to
the period between 2003 and 2016 would need to be estimated. PG&E proposes that
the estimate be based on Diablo Canyon's expected profits, projected for the
period 2004-2016 and then discounted to a present value. The post 2003
transition costs would be amortized and recovered in the transition cost
account, along with the 1997-2003 transition costs, over the 1997-2005 period.
Under this alternative proposal, the Diablo Settlement would be modified to
terminate effective December 31, 2003 and to authorize PG&E thereafter to
operate Diablo Canyon or sell its output into any markets without restriction,
with all profits after 2003 allocated to ratepayers. PG&E would also reserve
the right under this alternative to request electric rate increases above the
1996 levels if PG&E's combined annual revenue requirement for transition cost
recovery and for providing necessary and reasonable utility services exceeds
the 1996 customer electric rate cap adopted in the CPUC's electric industry
restructuring decision.
In its application, PG&E argues that its preferred alternative of modified
pricing of Diablo Canyon prices consistent with the SONGS settlement together
with a customer electric rate freeze will clear the way for PG&E and the CPUC
to implement at an early date comprehensive restructuring of the electric
utility industry in California. In addition, the proposal would provide
substantial benefits to PG&E's customers by reducing the burden of transition
costs and pricing Diablo Canyon power at market prices fifteen years earlier
than under current ratemaking.
PUBLIC PURPOSE PROGRAMS
The CPUC decision suggests that the California State Legislature adopt a non-
bypassable "public goods charge" to fund research and development and energy
efficiency programs that serve the public good. The CPUC also will support
legislation authorizing a separate surcharge to fund low-income rate assistance
and energy efficiency programs. The decision also expresses the CPUC's
intention to maintain resource diversity and encourage development of renewable
generation resources by imposing a minimum purchase requirement on retail
electric sellers or generators.
IMPLEMENTATION SCHEDULE
In a March 13, 1996 order, the CPUC set a procedural schedule for
implementation filings to be made by the IOUs in order to achieve the January
1998 start date for the restructured industry. Future filings include proposals
to establish the ISO and Exchange (to be filed by April 29, 1996), proposals to
establish PBR for generation and distribution functions (to be filed by July
15, 1996), proposals to establish unbundled distribution services and address
related pricing and rate design issues (to be filed by July 15, 1996),
estimates of the book value of utility non-nuclear generation assets (to be
filed by July 15, 1996), proposals concerning
17
<PAGE>
implementation of direct access (to be filed by August 30, 1996) and PG&E's
application to implement a CTC charge to be effective January 1, 1998 (to be
filed by August 30, 1996). The CPUC indicated that the assigned commissioners
or administrative law judges, acting on behalf of the CPUC, may exercise their
discretion to amend the schedule if necessary and desirable.
APPLICATION FOR REHEARING
On February 13, 1996, PG&E filed an application for rehearing of the CPUC's
electric industry restructuring decision. PG&E's filing did not contest the
CPUC's policy direction but questioned whether the transition cost recovery
mechanism approved by the CPUC provides adequate assurances that PG&E will be
able to recover its stranded costs. The filing was intended to preserve PG&E's
legal options in the event that implementation proceedings do not produce
adequate transition cost recovery.
In its application for rehearing, PG&E argued, among other things, that (1)
the CPUC should have held evidentiary hearings to provide a proper basis for
its decision; (2) the CPUC's decision may be confiscatory since it appears to
limit the amount of transition costs potentially recoverable by establishing a
cut-off date of 2005 and since it would not allow the utility to adequately
recover its operating and capital costs, or an adequate return on capital,
associated with fossil generation; (3) the decision would accomplish an
unlawful permanent physical "taking" of PG&E's property by directing the
transfer of PG&E's transmission system to the ISO and mandating access to those
facilities by others; (4) the CPUC decision is preempted by the Federal Power
Act; and (5) the CPUC decision is unconstitutional as a violation of the
Commerce Clause of the United States Constitution. Other parties also filed
applications for rehearing challenging, among other things, the validity of the
CTC recovery, the extent to which new entrants in the generation market can be
regulated by the CPUC, and whether in issuing the restructuring decision the
CPUC complied with the California Environmental Quality Act.
POTENTIAL CTC BYPASS
On February 15, 1996, PG&E filed with the CPUC a motion for emergency relief
requesting authority to establish an Interim CTC Procedure. The Interim CTC
Procedure will be immediately applicable to current electric retail customers
with a monthly peak load over 500 kilowatts (kW) that intend to terminate or
reduce bundled electric service from PG&E and transfer their purchases of
electricity for that load to other suppliers. PG&E's motion indicates that
immediate relief is necessary to ensure that these departing customers do not
undermine the CPUC's plan for implementation of direct access and evade
responsibility for the non-bypassable CTC contemplated in the CPUC's
restructuring decision.
In its motion, PG&E cites current efforts by certain of its retail customers
to obtain power from alternative sources based on the assumption that, by
acting before the CPUC implements the CTC, they will be able to avoid paying
their share of transition costs. Utilities not regulated by the CPUC are
building duplicative electric lines linking their loads to PG&E retail
customers in order to bypass PG&E's distribution and transmission system and
purchase power from alternate sources. These customers hope to avoid CTC if
they eliminate their need for distribution service from PG&E before the CTC is
fully implemented. PG&E's motion also cites recent efforts by a power marketer
to serve a PG&E retail customer by having an irrigation district buy the
customer's substation and claim it to be a wholesale load, thereby seeking to
obtain direct access years in advance of the CPUC's schedule and before
complete implementation of a CTC mechanism. In that instance, PG&E has filed a
petition with the FERC seeking a declaration that these efforts amount to a
retail transaction which is prohibited under the Energy Act.
In order to avoid confusion and address these efforts to evade CTC, PG&E
proposes that an Interim CTC Procedure be implemented which will require the
payment of Interim CTC charges prior to the termination or reduction of service
from PG&E by departing customers. Amounts collected under the Interim CTC
Procedure would be subject to refund pending implementation of a final CTC
mechanism by the CPUC. If the CPUC eventually determines that the scope of the
CTC should be different from the Interim CTC Procedure or that certain classes
of customers should be exempt from it, any amounts collected under the interim
approach will be refunded with interest.
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<PAGE>
FINANCIAL IMPACT OF ELECTRIC INDUSTRY RESTRUCTURING
In December 1994, in response to one of the proceedings leading to the CPUC
electric industry restructuring decision, PG&E estimated the revenue
requirements of its owned generation assets and power purchase obligations to
be above market by $3 billion and $11 billion (net present value) at assumed
market prices of $.040 and $.032 per kWh, respectively. These market prices
were used to provide a range of possible transition costs and do not represent
a forecast of expected market prices. Market prices could be less than $.032
per kWh. The above-market estimates filed in December 1994 were determined by
comparing future revenue requirements of generation assets and power purchase
obligations, over a 20-year and 30-year period, respectively, with revenues
computed at assumed market prices. Diablo Canyon was included in the revenue
requirements calculation using the revised pricing included in the existing
modified Diablo Settlement. The revenue requirement for Diablo Canyon and all
PG&E-owned generation assets included a return on investment. The actual
amounts of above-market revenue requirements may differ materially from those
indicated above and will depend on the final regulations and the actual market
prices of electricity or a definitive market valuation.
The net present value of above-market revenue requirements for Diablo Canyon
included in the December 1994 estimates were $4 billion and $6 billion at
assumed market prices of $.040 and $.032 per kWh, respectively. In connection
with PG&E's proposal to modify Diablo Canyon pricing, filed with the CPUC on
March 29, 1996, the net present value of above-market revenue requirements for
Diablo Canyon were estimated to be $10.1 billion at a market price of $.025 per
kWh, which reflects PG&E's current estimate of Diablo Canyon generation's
market price beginning in 1997.
The CPUC electric industry restructuring decision establishes an account to
track the accumulation of transition costs and their recovery. While the
decision provides an opportunity for recovery of all above-market costs, actual
recovery of the CTC will be limited to an amount that does not increase the
customers' aggregate rates above those in effect on January 1, 1996. Recent
CPUC decisions effective on January 1, 1996, including PG&E's 1996 GRC, have
resulted in an average electric system rate of 9.9 cents per kWh. PG&E's
ability to recover its transition costs will be dependent on achieving overall
reductions in costs such that it can recover its ongoing operating costs,
capital costs and transition costs at the 1996 rate level and on continuing to
collect CTC for the duration of the recovery period.
As a result of applying the provisions of Statement of Financial Accounting
Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of
Regulation," PG&E had accumulated approximately $2.6 billion of electric
regulatory assets, including balancing accounts, at December 31, 1995. The
regulatory assets attributable to electric generation, excluding balancing
accounts of $248 million which are expected to be recovered in the near term,
were approximately $1.5 billion at December 31, 1995. When generation rates are
no longer based on cost of service, as ultimately contemplated under the
decision, PG&E will discontinue application of SFAS No. 71 for that portion of
its business. However, PG&E expects to recover its regulatory assets as
transition costs through the CTC and does not expect a material loss from the
discontinuance of SFAS No. 71. PG&E's transmission and distribution businesses
are expected to remain on cost-of-service rates.
In addition, the adoption of SFAS No. 121, "Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to Be Disposed Of," in 1996 will
require that regulatory assets continue to be probable of recovery in rates. In
the event that this criterion can no longer be met, whether due to changing
regulation or PG&E's inability to collect these costs, applicable portions of
any regulatory assets would be written off. The transition cost account will be
a regulatory asset also subject to the criteria of SFAS No. 121.
The CPUC decision provides a structure for full recovery of PG&E's generation
investments and costs through market prices and the CTC. However, the proposed
modification to Diablo Canyon pricing, possible divestiture of generation
assets and lower returns on a portion of its investments in generation assets
will adversely impact PG&E's future returns on its generation investments. The
proposed modification to Diablo
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<PAGE>
Canyon ratemaking offers substantial reductions in post-2001 performance-based
revenues in exchange for a commitment to freeze customer electric rates through
2001 to allow accelerated collection of utility generation-related CTC. If
accepted, the proposed modification will significantly reduce the level of
PG&E's CTC by reducing the common equity returns on the Diablo Canyon plant
investment to 6.77% and accelerating the capital recovery of the plant and
other utility generation-related assets. If the proposal to freeze customer
electric rates is adopted, PG&E will depreciate and recover the Diablo Canyon
plant balance at January 1997 over five years rather than the current recovery
period through 2016. In addition, the proposal would also limit recovery of all
utility generation-related CTC to amounts collected through 2001. While it
would not adversely affect PG&E's cash flow, PG&E's proposal to modify Diablo
Canyon pricing and effect a customer electric rate freeze, and to accelerate
recovery of utility generation-related investments, including Diablo Canyon,
and regulatory assets would result in a significant reduction in annual
earnings beginning in 1997. If the revised return currently contemplated for
Diablo Canyon had been adopted for 1995 and PG&E recovered no more than its
actual variable costs under the performance-based ICIP, Diablo Canyon's
earnings available for common stock would have been $115 million, as compared
to $492 million. In addition, PG&E's recovery of revenue based on the
performance-based ICIP will depend on the capacity factor and variable cost
assumptions adopted by the CPUC in implementing PG&E's Diablo Canyon pricing
proposal. To the extent that the actual capacity factor or variable expenses
are different than those adopted by the CPUC in setting the ICIP price, the
Company's earnings will be impacted.
As of December 31, 1995, the net book values of Diablo Canyon and the
remaining PG&E owned generating plants, including an allocation of common
plant, were approximately $4.8 billion and $3.1 billion, respectively, and
regulatory assets attributable to electric generation were approximately $1.5
billion. Because of the expected transition cost recovery as provided in the
decision, PG&E does not anticipate a material impairment loss on its investment
in generation assets due to electric industry restructuring. However, should
final implementing regulations differ significantly from the CPUC decision or
should full recovery of generation assets and obligations not be achieved due
to changing costs or limitations imposed by the market, a material loss could
occur.
The Company cannot predict the ultimate outcome of the ongoing changes that
are taking place in the electric utility industry or predict whether such
outcome will have a material impact on its financial position or results of
operations. However, the Company believes the end result will involve a
fundamental change in the way it conducts business. These changes will impact
financial operating trends, resulting in greater earnings volatility. PG&E's
common stock dividend is based on a number of financial considerations,
including sustainability, financial flexibility and competitiveness with
investment opportunities of similar risk. In addition to the other factors
affecting PG&E's dividend policy, PG&E plans to evaluate the level of its
common stock dividend as key issues related to electric industry restructuring
are more clearly resolved.
STORM RESPONSE PROCEEDINGS
As part of PG&E's 1996 GRC, the CPUC held hearings in April 1995 addressing
issues relating to customer service and PG&E's response to service
interruptions caused by severe storms in January and March of 1995. A CPUC
order issued in September 1995 required PG&E to implement improvements in its
telephone system and public information activities and to report on those
improvements by year end 1995.
In early December 1995, PG&E's service territory experienced storms and
hurricane-force winds which caused approximately 1.7 million electrical service
interruptions. On December 19, 1995, the assigned commissioner in PG&E's 1996
GRC issued a ruling which ordered hearings on various issues arising out of
PG&E's response to those wind storms. The ruling ordered PG&E to include in the
report due at year end an explanation of how the telephone system and public
information improvements that were to be implemented pursuant to the CPUC's
September order, or any lack thereof, may have affected PG&E's response to the
December storms.
On January 2, 1996, PG&E submitted the required report to the CPUC on the
telephone system and public information improvements. PG&E indicated that it
had complied with the various telephone improvement activities ordered by the
CPUC, noting that several of the improvements, such as achieving quicker
response time by adding additional service representatives and telephone lines,
were in place by the
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time of the December 1995 storm. Other improvements, such as exploring an
interactive voice response system, are actively underway and could be in place
later this year. Nevertheless, PG&E noted that it was neither feasible nor
practicable to construct call center operations to meet the level of customer
demand faced in extreme situations such as those experienced in the December
storm. Hearings were held in February and March of 1996 to consider the issues
addressed in PG&E's report. The CPUC has indicated that PG&E may be subject to
penalties if the CPUC finds that PG&E has failed to comply with the September
order without adequate justification.
The December 1995 assigned commissioner's ruling also ordered further
proceedings to consider whether PG&E acted reasonably in maintaining its system
to assure integrity during storms and other natural disasters and in responding
to its customers during the December storms. Hearings in this phase of the
proceeding have been set for June 1996. Issues that will be addressed in these
hearings include, among others, customer access to service employees and
availability of operations and field employees, the adequacy of plant
maintenance and repair prior to and during the emergency, a comparison of
PG&E's storm response to that of other utilities, and PG&E's standards and
procedures for paying customers for storm-related damages. The CPUC has
indicated that the hearings will address potential remedies, including
reparations to customers for reduced reliability, penalties, disallowances and
damages to customers for property loss.
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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
-------------------------------------------------------
1995 1994 1993 1992 1991
---------- ---------- ---------- ---------- ----------
CUSTOMERS (AVERAGE FOR THE
YEAR):
<S> <C> <C> <C> <C> <C>
Residential.............. 3,825,413 3,788,044 3,748,831 3,708,374 3,665,055
Commercial............... 454,718 452,049 449,619 455,480 450,789
Industrial............... 1,253 1,260 1,243 1,207 1,186
Agricultural............. 88,546 90,520 91,376 94,562 96,270
Public street and highway
lighting................ 17,089 16,709 16,096 15,681 15,314
Other electric utilities. 35 29 28 24 21
---------- ---------- ---------- ---------- ----------
Total.................. 4,387,054 4,348,611 4,307,193 4,275,328 4,228,635
========== ========== ========== ========== ==========
GENERATED, RECEIVED AND
SOLD -- KWH (IN
MILLIONS):
Generated:
Hydroelectric plants..... 16,608 7,791 14,403 7,537 7,996
Thermal-electric plants:
Fossil fueled........... 13,729 29,543 19,070 26,623 21,984
Geothermal.............. 4,001 6,024 6,491 7,007 6,947
Nuclear................. 16,269 15,265 16,816 16,698 15,073
---------- ---------- ---------- ---------- ----------
Total thermal-electric
plants................ 33,999 50,832 42,377 50,328 44,004
Wind and solar plants.... 1 1 -- -- --
Received from other
sources(1).............. 54,935 47,199 48,859 46,243 48,966
---------- ---------- ---------- ---------- ----------
Total gross system
output(2)............. 105,543 105,823 105,639 104,108 100,966
Delivered for interchange
or exchange............. 4,261 3,275 8,848 3,912 5,391
Delivered for the account
of others(1)............ 18,946 18,622 13,726 17,235 13,602
Helms pumpback energy
(3)..................... 937 467 452 398 593
PG&E use, losses,
etc.(4)................. 6,040 7,838 6,960 7,278 7,184
---------- ---------- ---------- ---------- ----------
Total energy sold...... 75,359 75,621 75,653 75,285 74,196
========== ========== ========== ========== ==========
POWER PLANT FUEL SUPPLY
(IN THOUSANDS):
Natural gas (equivalent
barrels)................ 23,143 44,119 28,791 43,446 36,262
Fuel oil................. 756 2,395 2,080 171 631
Nuclear (equivalent
barrels)................ 27,814 26,135 28,724 28,540 25,808
---------- ---------- ---------- ---------- ----------
Total.................. 51,713 72,649 59,595 72,157 62,701
========== ========== ========== ========== ==========
POWER PLANT FUEL COSTS
(AVERAGE COST PER MILLION
BTU'S):
Natural gas.............. $ 2.06 $ 2.19 $ 2.86 $ 2.61 $ 2.75
Fuel oil................. $ 1.28 $ 2.83 $ 3.49 $ 3.13 $ 3.00
Weighted average......... $ 2.03 $ 2.23 $ 2.90 $ 2.62 $ 2.75
SALES -- KWH (IN
MILLIONS):
Residential.............. 24,391 24,326 24,111 23,664 23,535
Commercial............... 27,014 26,195 26,258 26,246 25,758
Industrial............... 16,879 16,010 16,492 16,600 16,472
Agricultural............. 3,478 4,426 3,672 4,741 4,734
Public street and highway
lighting................ 425 418 419 400 389
Other electric utilities. 3,172 4,246 4,701 3,634 3,308
---------- ---------- ---------- ---------- ----------
Total energy sold...... 75,359 75,621 75,653 75,285 74,196
========== ========== ========== ========== ==========
REVENUES (IN THOUSANDS):
Residential.............. $2,979,590 $2,980,966 $2,952,893 $2,790,605 $2,729,763
Commercial............... 2,964,568 2,892,302 2,914,855 2,864,817 2,745,040
Industrial............... 1,160,938 1,128,561 1,183,728 1,210,754 1,186,452
Agricultural............. 395,531 477,330 419,628 478,941 477,397
Public street and highway
lighting................ 56,154 55,545 55,976 53,133 50,631
Other electric utilities. 133,566 201,133 242,433 185,555 204,089
---------- ---------- ---------- ---------- ----------
Revenues from energy
sales................. 7,690,347 7,735,837 7,769,513 7,583,805 7,393,372
Miscellaneous............ 92,538 142,771 87,991 51,716 103,180
Regulatory balancing
accounts................ (396,578) 142,939 19,421 127,490 (97,016)
---------- ---------- ---------- ---------- ----------
Operating revenues..... $7,386,307 $8,021,547 $7,876,925 $7,763,011 $7,399,536
========== ========== ========== ========== ==========
</TABLE>
- --------
(1) Includes energy supplied through PG&E's system by the City and County of
San Francisco for San Francisco's own use and for sale by San Francisco to
its customers, by the Department of Energy for government use and sale to
its customers, and by the State of California for California Water Project
pumping, as well as energy supplied by QFs and purchases from other
utilities.
(2) Includes energy output from Modesto and Turlock Irrigation Districts' own
resources.
(3) Represents energy required for pumping operations.
(4) Includes use by business units other than the electric utility business
units.
22
<PAGE>
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31
-------------------------------------------------
1995 1994 1993 1992 1991
--------- --------- --------- --------- ---------
SELECTED STATISTICS:
<S> <C> <C> <C> <C> <C>
Total customers (at year-
end)...................... 4,400,000 4,400,000 4,400,000 4,300,000 4,300,000
Average annual residential
usage (kWh)............... 6,377 6,422 6,431 6,381 6,421
Average billed revenues per
kWh (c):
Residential............... 12.22 12.25 12.25 11.79 11.60
Commercial................ 10.97 11.04 11.10 10.92 10.66
Industrial................ 6.88 7.05 7.18 7.29 7.20
Agricultural.............. 11.37 10.78 11.43 10.10 10.08
Net plant investment per
customer ($).............. 3,228 3,362 3,436 3,428 3,445
Electric control area
capability(1)(MW)......... 22,099 21,851 23,009 22,475 21,670
Electric net control area
peak demand(2)(MW)........ 20,317 19,118 19,607 18,594 18,620
</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, 1995, 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............ 16 counties in Northern and 111 2,703,100
Central California
Helms Pumped Storage Plant..... Fresno 3 1,212,000
--- ----------
Hydroelectric Subtotal....... 114 3,915,100
--- ----------
Steam Plants:
Contra Costa................... Contra Costa 2 680,000
Humboldt Bay................... Humboldt 2 105,000
Hunters Point.................. San Francisco 3 377,000
Morro Bay...................... San Luis Obispo 4 1,002,000
Moss Landing................... 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........................ Alameda 3 165,000
Potrero........................ San Francisco 3 156,000
Mobile Turbines(1)............. Contra Costa and Humboldt 3 45,000
--- ----------
Combustion Turbines Subtotal... 10 418,000
--- ----------
Geothermal:
The Geysers Power Plant(2)..... Sonoma and Lake 14 1,224,000
Nuclear:
Diablo Canyon.................. San Luis Obispo 2 2,160,000
--- ----------
Thermal Subtotal............. 47 9,673,000
--- ----------
Total................................................... 161 13,588,100
=== ==========
</TABLE>
- --------
(1) Listed to show capability; subject to relocation within the system as
required.
(2) 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. See "Other Electric Resources-- Geothermal Generation" below.
23
<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, 1995.
<TABLE>
<CAPTION>
CONTROL AREA
NET CAPACITY
(AT DATE OF 1995 PEAK)
----------------------
KW %
-------------- ----------
<S> <C> <C>
Sources of
Electric
Generation:
PG&E-Owned
Plants:
Fossil Fueled.... 6,289,000 47
Geothermal....... 1,224,000 9
Nuclear.......... 2,160,000 16
-------------- -------
Total Thermal... 9,673,000 72
Hydroelectric
(available)..... 3,771,100 28
Solar............ 0 0
-------------- -------
Total PG&E-Owned
Capacity........ 13,444,100 100
============== =======
Less Unavailable
Capacity........ (536,100)
--------------
Total PG&E
Available
Capacity........ 12,908,000 59
Capacity Received
from Others:
QF Producers
(available)..... 2,952,400 13
Area Producers &
Imports......... 6,198,600 28
-------------- -------
Capacity from
Others.......... 9,151,000 41
-------------- -------
Total Available
Capacity........ 22,059,000 100
============== =======
Total Area
Demand(1)(2)..... 20,317,000
==============
</TABLE>
<TABLE>
<CAPTION>
GENERATION
YEAR ENDED
DECEMBER 31, 1995(3)
--------------------
KWH
THOUSANDS %
-------------- ------
<S> <C> <C>
Electric
Generation:
PG&E-Owned
Plants:
Fossil Fueled.... 13,729,015 13
Geothermal....... 4,000,930 4
Nuclear.......... 16,269,002 16
-------------- ------
Total Thermal... 33,998,947 33
Hydroelectric.... 16,607,737 16
Solar............ 1,451 0
Total PG&E
Generation...... 50,608,135 -
Helms Pumpback
Energy.......... (936,882) 0
-------------- ------
Net PG&E
Generation...... 49,671,253 49
Generation
Received from
Others:
QF Producers..... 20,376,389 20
Area Producers &
Imports......... 31,920,289 31
-------------- ------
Generation from
Others.......... 52,296,678 51
Total Area
Generation...... 101,967,931 100
============== ======
</TABLE>
- --------
(1) The maximum control area peak demand to date was 20,317,000 kW which
occurred in August 1995.
(2) The reserve capacity margin at the time of the 1995 control area peak,
taking into account short-term firm capacity purchases from utilities
located outside PG&E's service area: spinning reserve (capability already
connected to the system and ready to meet instantaneous changes in demand)
to the control area peak was 6.7% of the peak demand and total reserve
(spinning reserve and capability available within a short period of time)
was 8.6%.
(3) Represents actual year net generation from sources shown.
DIABLO CANYON
DIABLO CANYON OPERATIONS
Diablo Canyon Units 1 and 2 began commercial operation in May 1985 and March
1986, respectively. As of December 31, 1995, Diablo Canyon Units 1 and 2 had
achieved lifetime capacity factors of 78.4% and 81.6%, 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 is scheduling refueling outages every
21 months as allowed under its existing NRC operating license, 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>
1996 1997 1998 1999 2000
----- ---- -------- --------- ---------
<S> <C> <C> <C> <C> <C>
Unit 1
Refueling........................... May January September
Startup............................. June February October
Unit 2
Refueling........................... April January September
Startup............................. May February October
</TABLE>
24
<PAGE>
License amendments were issued by the NRC in March 1995 to extend the
operating license expiration dates for Diablo Canyon Units 1 and 2 to September
2021 and April 2025, respectively.
DIABLO SETTLEMENT
In May 1995, the CPUC approved an agreement, executed by PG&E, the CPUC's
Division of Ratepayer Advocates (DRA), the California Attorney General and
several other parties representing energy consumers, which modifies the pricing
provisions of the Diablo Settlement. Under the modification, the price for
power produced by Diablo Canyon is reduced from the level set in the Diablo
Settlement as originally adopted in 1988. All other terms and conditions of the
Diablo Settlement remain unchanged. However, PG&E has proposed further
modifications to the Diablo Settlement in connection with electric industry
restructuring. See "Electric Industry Restructuring--Proposed Modification to
Diablo Ratemaking" above for a more detailed description of the proposed
modifications.
Based on Diablo Canyon's current operating performance, the May 1995
modification will result in approximately $2.1 billion less revenue over the
five-year period ended December 31, 1999, compared to the original pricing
provisions of the Diablo Settlement. The CPUC decision approving the
modification adopts the parties' proposal that the difference between PG&E's
revenue requirement under the original terms of the Diablo Settlement and the
new prices will be applied to the ECAC balancing account until the ECAC
undercollection as of December 31, 1995 is fully amortized.
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 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.
Earnings relating to Diablo Canyon will fluctuate significantly as a result of
refueling or other extended plant outages, plant expenses and the effects of a
peak-period pricing mechanism. See "Diablo Canyon Operations" above for the
plant refueling schedule.
Under the Diablo Settlement, revenues are based on a pre-established price
per kWh consisting of a fixed component (3.15 cents per kWh) and an escalating
component for each kWh of electricity generated by the plant. The Diablo
Settlement, as modified in May 1995, provides total prices for the years 1995
through 1999, effective January 1 of each year, of 11.00 cents, 10.50 cents,
10.00 cents, 9.50 cents and 9.00 cents, respectively. After 1999, the
escalating component will be adjusted by the change in the consumer price index
plus 2.5%, divided by two. PG&E has the right to reduce the price below the
amount specified if it so chooses. During the first 700 hours of full-power
operation for each unit during the peak period (10 a.m. to 10 p.m. on weekdays
in June through September), the price is 130% of the stated amount to encourage
PG&E to utilize the plant during the peak period. During the first 700 hours of
full-power operation for each unit during the non-peak period of the year, the
price is 70% of the stated amount. At all other times, the price is 100% of the
stated amount.
If power generation drops below specified capacity levels, PG&E may trigger
an annual revenue floor provision or, under certain conditions, seek
abandonment of the plant (discussed below). Floor payments ensure that PG&E
will receive some revenue, even if the plant stops producing power. Floor
payments are based on the prices set in the Diablo Settlement at a 36% capacity
factor from 1988 through 1997 (reduced by 3% each time the floor provision is
exercised and not repaid) with the capacity factor decreasing in the future.
Floor payments must be refunded to customers under specified circumstances.
If actual operation falls below the floor capacity factor in three
consecutive years, whether or not the floor payment provision has been
triggered, PG&E must file for abandonment or explain why continued application
of the Diablo Settlement is appropriate. In the event there is a prolonged
plant outage and PG&E files for abandonment, PG&E may ask for recovery of the
lesser of (a) floor payments allowed for ten years, less any years of floor
payments already received and not repaid, or (b) $3 billion, reduced by $100
million per year of operation on January 1 of each year starting in 1989.
25
<PAGE>
The Diablo Settlement provides that certain Diablo Canyon costs, including
decommissioning costs, be recovered over the term of the Diablo Settlement,
including a full return on such costs through base rates.
The decision originally adopting the Diablo Settlement explicitly affirmed
that Diablo Canyon costs and operations no longer should be subject to CPUC
reasonableness reviews. However, the DRA has challenged the reasonableness of
economy energy sales made during periods of severe minimum load conditions in
1993. The DRA contends that during those periods, PG&E should recover no more
than the value of the economy energy sales, as opposed to revenue for
comparable generation at Diablo Settlement prices, when PG&E would have had to
curtail Diablo Canyon operation or commence hydro spill (i.e., releasing water
through a hydroelectric facility without generating electricity) but for the
economy energy sales. See "Pending Electric Reasonableness Issues" below. The
decision adopting the Diablo Settlement states that, to the extent permitted by
law, the CPUC intends that this decision be binding upon future Commissions,
based upon a determination that taken as a whole the Diablo Settlement produces
a just and reasonable result, and that the Diablo Settlement has been approved
based on the reasonable reliance of the parties and the CPUC that all of the
terms and conditions will remain in effect for the full term of the Diablo
Settlement, ending 2016. However, the decision states that the CPUC cannot bind
future Commissions in fixing just and reasonable rates for Diablo Canyon.
As noted above, in connection with the CPUC's electric industry restructuring
decision, PG&E filed on March 29, 1996 a proposal for pricing Diablo Canyon
generation at market prices by the end of 2001 and for completing recovery of
Diablo Canyon CTC by the end of 2001 while assuring no overall rate increase
over January 1, 1996 levels. PG&E proposes to accelerate recovery of the
undepreciated portion of Diablo Canyon, at a significantly reduced return tied
to the embedded cost of debt, and to include performance-based prices for
recovery of variable costs and incremental capital additions. In addition to
modifying the pricing provisions of the Diablo Settlement, PG&E's proposal
would eliminate the floor payment provisions described above, change the Diablo
Settlement termination date from 2016 to December 31, 2001 and replace the
abandonment payment provision described above with other closure cost recovery
provisions.
NUCLEAR FUEL SUPPLY AND DISPOSAL
PG&E has purchase contracts for, and an inventory of, uranium concentrates
and contracts for conversion of uranium to uranium hexafluoride, uranium
enrichment and fuel fabrication. Based on current operations forecasts, Diablo
Canyon's requirements for uranium supply, conversion services and enrichment
services will be satisfied through existing long-term contracts through 1997,
1999 and 2002, respectively. Fuel fabrication contracts for the two units will
supply their requirements for the next five operating cycles for each unit.
These contracts are intended to ensure long-term 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 waste. The Nuclear
Waste Act sets a national policy for the disposal of nuclear waste from
commercial reactors, and establishes a timetable for the DOE to choose one or
more sites for the deep underground burial of wastes from nuclear power plants.
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, although the DOE has indicated that
such sites may not be in operation until 2015. The United States Congress is
also considering legislation providing for interim storage in a monitored
retrievable storage facility earlier than 2010. However, 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
2015, 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. In the event an interim or permanent DOE storage facility is not
available for Diablo Canyon's spent fuel by 2006, PG&E will examine options for
providing additional temporary spent fuel storage at Diablo Canyon or other
26
<PAGE>
facilities, pending disposal or storage at a DOE facility. Such additional
temporary spent fuel storage may be necessary in order for PG&E to continue
operating Diablo Canyon beyond approximately 2006, and may require approval by
the NRC and other regulatory agencies.
In June 1994, a number of utilities (including PG&E), state utility
commissions and state attorneys general filed lawsuits seeking declaratory and
injunctive relief against the DOE's alleged failure to meet its obligations
under the Nuclear Waste Act. A decision in the lawsuits is expected in 1996.
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 is 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. If the nuclear generating facility of a member utility suffers a
property damage loss or a business interruption loss due to a prolonged
accidental outage, PG&E may be subject to maximum retrospective premium
assessments of $26 million (property damage) or $8 million (business
interruption), in each case per one-year policy period, if losses exceed the
resources of NML or NEIL.
Federal law requires all utilities with nuclear generating facilities with a
capacity of 100 megawatts (MW) or more to share in payment of claims resulting
from a nuclear incident and limits industry liability for third-party claims to
$8.9 billion per incident. Coverage of the first $200 million is provided by a
pool of commercial insurers. 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;
payments in excess of the maximum assessment are deferred to the next calendar
year.
DECOMMISSIONING
The estimated cost of decommissioning PG&E's nuclear power facilities is
recovered in base rates through an annual allowance. The estimated total
obligation for decommissioning costs is approximately $1.2 billion in 1995
dollars (or $5.9 billion in future dollars). This obligation is being
recognized ratably over the facilities' lives. This estimate considers the
total costs of decommissioning and dismantling plant systems and structures and
includes a contingency factor for possible changes in regulatory requirements
and waste disposal cost increases.
As of December 31, 1995, PG&E had accumulated external trust funds with an
estimated fair value of $770 million, based on quoted market prices, to be used
for the decommissioning of PG&E's nuclear facilities. Corresponding amounts are
included in accumulated depreciation and 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.
The CPUC reviews the funding levels for PG&E's decommissioning trust in each
GRC. Based upon the trust's then-current asset level, and revised earnings and
decommissioning cost assumptions, the CPUC may revise the amount of
decommissioning costs it has authorized in rates for contribution to the trust.
The funds to be 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, 1995, the amount recovered in rates for
decommissioning costs was $54 million. As part of the 1996 GRC decision, the
CPUC reduced the annual amount of decommissioning
27
<PAGE>
costs included in rates to $36 million beginning January 1, 1996. This amount
was calculated assuming decommissioning costs were collected through 2016.
However, the CPUC's electric industry restructuring decision contemplates that
decommissioning costs will be included in the transition cost account and be
collected as part of CTC through 2005 (see "Electric Industry Restructuring--
CTC/Standard Costs" above) and PG&E has proposed that it be given the option to
accelerate recovery of decommissioning costs over a shorter period (see
"Electric Industry Restructuring--Proposed Modification to Diablo Ratemaking"
above).
OTHER ELECTRIC RESOURCES
QF GENERATION
Under the Public Utility Regulatory Policies Act of 1978 (PURPA), PG&E is
required to purchase electric energy and capacity produced by QFs. The CPUC
established a series of power purchase agreements which set the applicable
terms, conditions and price options. The total cost of prudently incurred
energy and capacity payments to QFs is recoverable in rates. PG&E's contracts
with QFs expire on various dates from 1996 to 2026. Under these contracts, PG&E
is required to make payments only when energy is supplied or when capacity
commitments are met. Payments to QFs are expected to vary in future years with
decreases expected in the years 1998 through 2000 under the terms of the QF
contracts.
In 1995 and 1994, PG&E negotiated the early termination or temporary
suspension of certain QF contracts at a cost of $142 million and $155 million,
respectively, to be paid through 1999. These amounts are expected to be
recovered in rates. At December 31, 1995, $159 million remained to be paid to
the QFs.
QF deliveries in the aggregate accounted for approximately 20% of PG&E's 1995
total electric energy requirements and no single contract accounted for more
than 5% of PG&E's electric energy needs. The QF deliveries represented
approximately 83% of the QF's output, in the aggregate.
The amount of energy received from QFs, and the total energy (including
termination and suspension payments) and capacity payments made under these
agreements were:
<TABLE>
<CAPTION>
1995 1994 1993
------ ------ ------
(IN MILLIONS)
<S> <C> <C> <C>
kWh received......................................... 20,496 21,699 21,242
Energy payments...................................... $1,140 $1,196 $1,099
Capacity payments.................................... $484 $518 $503
</TABLE>
As of December 31, 1995, PG&E had approximately 5,900 MW of QF capacity under
CPUC-mandated power purchase agreements. Of the 5,900 MW, approximately 4,800
MW were operational. Development of the balance is uncertain but it is
estimated that only 100 MW of the remaining contracts will become operational.
The 5,900 MW of QF capacity consists of 3,100 MW from cogeneration projects,
1,800 MW from wind projects and 1,000 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 35.8% of
installed capacity in 1996, which includes economic curtailments, forced
outages, scheduled overhauls and projected steam shortage curtailments, as
compared to the actual Geysers capacity factor of 37.3% in 1995.
In August 1995, PG&E and three of its steam suppliers at the Geysers entered
into an agreement which lowered the price of generation produced from those
steam supplies, for generation above the 40% of annual field capacity which
PG&E is required to take or pay for without taking. The discounted price
resulted in
28
<PAGE>
PG&E increasing generation at the Geysers over what it would have taken at the
higher price. That agreement expired December 31, 1995. The parties entered
into a similar agreement for the month of February 1996 and are negotiating for
a discounted steam price agreement for the remainder of 1996.
In October 1995, construction of the Southeast Geysers Pipeline Project
began. This is a joint project involving PG&E and several other entities to
bring treated effluent to the Geysers for injection to enhance steam
production. The pipeline is scheduled to begin operation before the end of
1996.
WESTERN SYSTEMS POWER POOL
In 1991, the FERC approved an agreement among 40 utilities (including PG&E)
operating in 22 states and British Columbia for a permanent Western Systems
Power Pool (WSPP). The entities participating in the WSPP may, on a voluntary
basis, buy and sell surplus power and transmission capacity by posting quotes
daily on a computer "bulletin board." The prices are negotiable but cannot
exceed ceilings approved by the FERC. The permanent WSPP agreement approved by
the FERC, among other things, imposes cost-based ceilings calculated from pool-
wide average costs and allows QFs to participate in the pool.
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 are not yet included in rate base and lost revenues
during the period the plant was under repair. Excluding the costs of the
conduit rupture already expensed by PG&E and the amount received in settlement
of litigation with the supplier of the plant's generators, the remaining
unrecovered costs of Helms (after adjustment for depreciation) and revenues
discussed above totaled approximately $102 million at December 31, 1995.
In October 1994, PG&E and the DRA filed a joint motion seeking CPUC approval
of a proposed all-parties settlement (Helms Settlement) resolving the treatment
of remaining unrecovered Helms costs. The Helms Settlement would permit
recovery of $48.9 million of Helms plant-related costs and $14.6 million of
prior revenue requirements to be included in PG&E's rate base on January 1,
1995. An additional amount of $35.3 million, representing revenues lost during
the time the generators were being repaired, would be transferred to the ERAM
account and amortized over the life of Helms, to 2034. Under the Helms
Settlement, PG&E would also agree not to seek recovery of the costs associated
with the 1982 water conduit rupture, estimated to be $72.4 million. PG&E took a
charge against earnings for such costs in 1990.
In September 1995, the CPUC issued for comment the proposed decision of the
assigned Administrative Law Judge (ALJ) which denied approval of the Helms
Settlement. The proposed decision found that the maximum amount PG&E would be
entitled to recover under the prior CPUC decisions is $82 million, while the
Helms Settlement would authorize recovery of approximately $98 million.
Accordingly, the proposed decision found that the Helms Settlement is not
consistent with the law or in the public interest. The proposed decision
directed PG&E to amend its application to include only those costs authorized
for potential recovery as specified by the terms of the proposed decision.
In its comments on the proposed decision, PG&E indicated that the proposed
decision fails to construe properly the prior CPUC decisions which permitted
accrual and recovery of interest. It is PG&E's position that had the proposed
decision properly construed prior CPUC orders and included accrued interest,
the $82 million figure cited in the proposed decision as potentially eligible
for recovery would have been well above the settlement amount of $98 million.
The DRA has filed comments on the proposed decision which are supportive of
PG&E's assessment of potentially eligible costs. The CPUC has since withdrawn
the proposed decision from consideration, and it is currently expected that the
proposed decision will be revised. Although
29
<PAGE>
a final decision has not yet been issued, the associated revenues were included
in rates effective January 1, 1995 and January 1, 1996. The CPUC is expected to
take action regarding the Helms Settlement in 1996.
As part of the 1996 GRC decision issued in December 1995, the CPUC directed
PG&E to perform a cost-effectiveness study of Helms, to be submitted by July
1996. The study will consider changes in rate recovery for the plant which will
include, among other things, the option of retirement with recovery of the
investment without a return over a four-year period. Helms had a net book value
of $631 million at December 31, 1995.
PENDING ELECTRIC REASONABLENESS ISSUES
Recovery of electric generation costs through the ECAC are 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.
In August 1993, the DRA filed a report on PG&E's ECAC expenses for the 1991
record period, which questioned PG&E's execution of amendments to three power
purchase agreements with Texaco, Inc. for three QFs. In its report and in
testimony filed in February 1994, the DRA asserted that PG&E improperly agreed
to extend the construction time under these agreements and recommended that the
CPUC find these extensions unreasonable. Although no payments are at issue in
the 1991 record period, the DRA argues that certain capacity payments under the
contracts should be disallowed in subsequent year proceedings over the 15-year
term of the contracts. In its August 1993 report, the DRA indicated that this
disallowance over the 15-year term of the contracts would approximate $80
million. In its report on ECAC expenses for the 1992, 1993 and 1994 record
periods, the DRA recommended disallowances of approximately $3.5 million, $3.0
million and $6.1 million, respectively, for two of these agreements.
In its report on PG&E's ECAC expenses for the 1993 record period, the DRA
recommended a $240,000 disallowance for economy energy sales alleged to have
been made to avoid hydro spill conditions. The Diablo Settlement provides that
during hydro spill conditions, ratepayers shall not pay for Diablo Canyon
output to the extent of the hydro spill. The amount of the disallowance
represents the difference between the amount received by PG&E for the economy
sales and the cost of that power at Diablo Canyon generation prices. PG&E filed
a motion to strike that portion of DRA's report, arguing that DRA's proposed
disallowance was barred by the Diablo Settlement, which exempts Diablo Canyon
operation from all reasonableness reviews and which specifies that the only
time PG&E is not paid for Diablo Canyon generation is during hydro spill
conditions. In January 1996, the ALJ denied PG&E's motion to strike and set the
matter for hearing in May 1996. The DRA may make a similar disallowance
recommendation for the 1995 record period. Given the greater availability of
hydroelectric generation during 1995, PG&E estimates that a DRA disallowance
recommendation based on the same principles at issue in the 1993 record period
would be approximately $10 million for the 1995 period.
ELECTRIC LOAD FORECAST AND RESOURCE PLANNING AND PROCUREMENT
At present, California's long-range electric resource planning is coordinated
between the California Energy Commission (CEC) and the CPUC. Every two years,
the CEC prepares an Electricity Report that includes load forecasts and
resource assumptions for a 20-year period. The CPUC conducts 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 (as described below). In making this
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
CPUC's pending initative concerning 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.
30
<PAGE>
The CEC officially adopted the 1994 Electricity Report (ER94) on November 1,
1995. The forecast for area electric peak demand (on a CEC area basis)
indicates an increase from approximately 16,300 MW in 1994 to approximately
21,450 MW in 2013, reflecting a compound annual growth rate of 1.5%. The
forecast for area electric energy load indicates an increase from approximately
88,600 gigawatt-hours (GWh) in 1994 to 116,050 GWh in 2013, reflecting a
compound annual growth rate of 1.4%.
For the remainder of this decade, PG&E anticipates adding between 300 and 400
MW of electric resources. These resources will be comprised of (i) up to 265 MW
of new purchases resulting from the 1993 BRPU solicitation or from other
sources outside of the BRPU, (ii) approximately 100 MW of new QF purchases on
line by the end of 1996, (iii) approximately 34 MW of DSM resources resulting
from the integrated bid solicitation described below, (iv) improvements in its
existing generating system, including 20 MW of upgrades of the hydroelectric
system, and (v) further developments in regional operations efficiency from
PG&E's existing transmission lines from the Pacific Northwest. PG&E currently
plans no new major construction projects for electric supply.
The future of electric resource acquisition is being addressed as part of the
CPUC's electric industry restructuring initiative (see "Electric Industry
Restructuring" above). Under the plan contemplated in the CPUC's restructuring
decision issued in December 1995, utilities would retain the obligation to
acquire resources for core customers. However, under the CPUC's restructuring
decision this obligation would be met entirely through purchases from the
Exchange during the transition period of approximately five years from January
1, 1998. 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 1993, the CPUC issued a decision in a DSM proceeding (see "General --
Customer Energy Efficiency/Demand Side Management Programs" above) which
selected PG&E to conduct a pilot auction to test integrated bidding. In this
auction both electric generation resources and DSM bidders were to compete in
the procurement process. PG&E issued a request for bids in December 1994 and
received 40 proposals from both demand-side and supply-side bidders. After an
extensive evaluation process and contract negotiations, PG&E executed contracts
for 34 MW of DSM resources. PG&E filed for CPUC approval of the contracts in
March 1996.
ELECTRIC TRANSMISSION
To transport energy to load centers, PG&E as of December 31, 1995, owned and
operated approximately 18,450 circuit miles of interconnected transmission
lines of 60 kilovolts (kV) to 500 kV and transmission substations having a
capacity of approximately 34,209,000 kilovolt-amperes (kVa). Energy is
distributed to customers through approximately 106,495 circuit miles of
distribution system and distribution substations having a capacity of
approximately 22,125,000 kVa.
TRANSMISSION ACCESS AND WHOLESALE POWER MARKET COMPETITION
The pending CPUC electric industry restructuring initiative discussed above
reflects ongoing regulatory and market trends in the electric industry favoring
greater competition and freedom of choice of electric generators. See "General
- -- Competition and Industry Restructuring." These trends have already resulted
in significant changes in the access accorded to others to transmission over
PG&E's system and the pricing of transmission services.
Traditionally, the transmission of electric energy in interstate commerce and
the sale of electric energy for resale (wholesale sales) has been regulated by
the FERC. Recent federal legislation and FERC regulatory actions have begun a
process intended to expand the extent to which the interstate electric
transmission system is available for use by those that do not own needed
transmission facilities, resulting in increased competition in the bulk, or
wholesale, electric generation market. In part, this change has been an effort
to meet the needs of small municipal providers who are without needed
transmission facilities.
31
<PAGE>
An important step in this process was the enactment of PURPA in 1978, under
which utilities were required to purchase electric power from QFs. This
contributed to establishment of a robust electric generating industry
independent of the traditional electric utilities. Many in the industry,
however, argued that development of a competitive market for bulk electric
power was being hampered by the lack of sufficient open access to transmission
for electricity purchased from QFs and IPPs. The Energy Act addressed this with
a provision which allowed the FERC to issue orders requiring electric utilities
to transmit over their transmission systems electric energy for other electric
utilities, federal power marketing agencies and any other persons generating
electric energy for wholesale sales.
Since then, the FERC has taken a number of actions with the objective of
removing barriers to the development of a fully competitive bulk power market,
placing emphasis on opening up access to electric transmission as the major
means of doing so. In July 1993, the FERC issued a policy statement on regional
transmission groups (RTGs) that recognized the formation of RTGs as necessary
to provide for regional-wide planning and coordination of the transmission
networks needed for competitive bulk power markets. See "Regional Transmission
Groups" below. In June 1994, the FERC issued a NOPR on recovery of stranded
costs by public utilities and transmitting utilities which addresses how
utilities can recover the costs of assets acquired by them in order to provide
service to customers who leave to take service from others as a result of the
availability of open access transmission service. In October 1994, the FERC
issued a transmission pricing policy statement to establish what it will
require for setting transmission rates under both traditional and new,
innovative transmission rate methodologies. In December 1995, the FERC also
issued a NOPR on real-time information systems and electronic bulletin boards
(EBBs). This NOPR will establish the means by which market information will
become freely available to all market participants on a non-discriminatory
basis.
Most significantly, in March 1995, the FERC issued a NOPR on open access
transmission. The NOPR proposes concepts for electric transmission that were
used in gas industry restructuring and proposes rules that would require all
public utilities subject to FERC jurisdiction to provide wholesale open access
transmission service and ancillary services in accordance with specified pro
forma tariffs which the filing utilities would also have to use to transmit
their own wholesale energy transactions. Such open access tariffs are intended,
in part, to alleviate concerns about generation market power typically held by
vertically integrated transmission owning utilities and to enable such
utilities to more readily obtain marketer status for their subsidiaries to sell
electric power at market rates rather than traditional cost-based rates. A
final order establishing open access transmission access rules is expected in
1996.
Since the issuance of the open access NOPR, a number of utilities have
voluntarily filed open access wholesale electric transmission tariffs. PG&E was
one of the first to do so, and in June 1995, the FERC accepted, subject to
refund and the outcome of a hearing on PG&E transmission service rates, PG&E's
tariffs, effective July 1, 1995. These tariffs conform to the guidelines laid
out in the FERC open access NOPR with very few modifications. PG&E's open
access filing proposes to enhance the existing wholesale market and is a step
towards the goal of promoting competition in electric generation for all
customers. PG&E's open access tariffs will be subject to revision to reflect
the FERC's final order in the open access NOPR.
PG&E has filed comments with the FERC on the open access NOPR strongly
supporting the direction of the FERC reflected in the NOPR. PG&E emphasized in
its comments that it is essential that the FERC allow utilities to introduce
new innovative transmission models that would allow utilities to respond more
efficiently to changing market demands. PG&E also supports the FERC's positions
that utilities should be allowed full recovery of their stranded costs, that
the states have the primary role in determining and levying transition cost
surcharges on retail customers, and that transition cost recovery at the FERC
is appropriate for former retail customers which municipalize or in other ways
become wholesale entities. A final rule on the NOPR is not expected to be
issued before mid-1996.
In its open access transmission tariffs filing, PG&E committed to the prompt
establishment of an EBB to provide real-time market information. PG&E has since
implemented an EBB, which, among other things, posts available transmission
capacity at PG&E's control area boundaries and allows wholesale customers to
electronically request service.
32
<PAGE>
REGIONAL TRANSMISSION GROUPS
In 1993, the FERC issued a policy statement on RTGs, voluntary associations
of transmission owners and wholesale transmission users, that would facilitate
transmission access, coordinate transmission planning and resolve disputes. In
May 1994, the Western Regional Transmission Association (WRTA) became the first
RTG to file its governing agreement at the FERC. PG&E was one of the founding
members of WRTA and supported FERC's approval of the bylaws. As a condition to
its acceptance of the WRTA bylaws, the FERC required all WRTA transmitting
utility members to file tariffs providing transmission service to all other
members comparable to their own uses of their systems. The FERC also required
WRTA to develop a single coordinated regional transmission plan and to update
that plan as necessary.
GAS UTILITY OPERATIONS
GAS OPERATIONS
PG&E owns and operates an integrated gas transmission, storage and
distribution system in California. At December 31, 1995, PG&E's "vintage"
system consisted of approximately 5,350 miles of transmission pipelines, three
gas storage facilities and approximately 35,800 miles of gas distribution
lines. In addition, in November 1993, PG&E placed in service another
transmission pipeline of approximately 400 miles (Line 401) as the PG&E
Pipeline Expansion. See "PGT/PG&E Pipeline Expansion" below.
PG&E's peak day send-out of gas on its integrated system in California during
the year ended December 31, 1995 was 3,328 million cubic feet (MMcf). The total
volume of gas throughput during 1995 was approximately 784,000 MMcf, of which
270,000 MMcf was sold to direct end-use or resale customers, 130,000 MMcf was
used by PG&E primarily for its fossil fueled electric generating plants, and
384,000 MMcf was transported as customer-owned gas.
The California Gas Report, which presents the outlook for natural gas
requirements and supplies for the State of California over a long-term planning
horizon, is prepared annually by the California electric and gas utilities as a
result of a CPUC order. In 1995, that order was modified to require a
comprehensive biennial report in even-numbered years (beginning in 1996) and a
supplemental report in intervening odd-numbered years (beginning in 1995).
The 1995 Supplemental Report updates PG&E's annual gas requirements forecast
(excluding bypass volumes) for the years 1995 through 1999, forecasting growth
in gas thoughput served by PG&E of 3.8% per year from 1995 through 1999.
Although this is a higher growth rate than the 1.4% shown for the same period
in the 1994 California Gas Report, the annual system throughput volumes
forecasted in the 1995 Supplemental Report are on average 3% lower than the
throughput volumes forecasted in the 1994 California Gas Report. The reduction
in overall volumes reflects, among other things, a substantial reduction in
PG&E's power plant gas demand as a result of heavy precipitation in recent
years and a reduction in expected industrial load due to an updated forecast of
economic activity.
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 1995
Supplemental Report does not update the bypass forecast included in the 1994
California Gas Report. The 1994 California Gas Report forecasted a total bypass
volume of 126 billion cubic feet for 1994 and did not include any potential
bypass from the proposed Mojave Pipeline Company expansion project, which has
since been cancelled. See "Other Competitive Pipeline Projects" below.
33
<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
---------------------------------------------------------
1995 1994 1993 1992 1991
---------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C>
CUSTOMERS (AVERAGE FOR
THE YEAR):
Residential............ 3,417,556 3,372,768 3,339,859 3,311,881 3,275,247
Commercial............. 197,939 196,509 195,815 195,689 197,029
Industrial............. 1,500 1,400 1,265 1,185 1,150
Other gas utilities.... 2 2 4 4 4
---------- ---------- ---------- ---------- ----------
Total............... 3,616,997 3,570,679 3,536,943 3,508,759 3,473,430
========== ========== ========== ========== ==========
GAS SUPPLY -- THOUSAND
CUBIC FEET (MCF) (IN
THOUSANDS):
Purchased:
From Canada........... 261,800 319,453 329,693 321,770 345,020
From California....... 31,158 31,757 32,096 50,953 73,257
From other states..... 117,538 249,733 243,058 327,272 240,141
---------- ---------- ---------- ---------- ----------
Total purchased..... 410,496 600,943 604,847 699,995 658,418
Net from storage (to
storage).............. (10,921) 3,591 (12,234) 10,135 (6,849)
---------- ---------- ---------- ---------- ----------
Total............... 399,575 604,534 592,613 710,130 651,569
PG&E use, losses,
etc.(1)............... 129,671 297,604 161,895 281,021 223,176
---------- ---------- ---------- ---------- ----------
Net gas for sales... 269,904 306,930 430,718 429,109 428,393
========== ========== ========== ========== ==========
BUNDLED GAS SALES AND
TRANSPORTATION SERVICE
-- MCF (IN THOUSANDS):
Residential............ 191,724 214,358 206,053 190,176 210,657
Commercial............. 64,135 72,183 82,048 79,983 85,203
Industrial............. 14,045 19,495 133,178 145,356 119,916
Other gas utilities.... 0 894 9,439 13,594 12,617
---------- ---------- ---------- ---------- ----------
Total(2)............ 269,904 306,930 430,718 429,109 428,393
========== ========== ========== ========== ==========
TRANSPORTATION SERVICE
ONLY -- MCF (IN
THOUSANDS):
Vintage system
(Substantially all
Industrial)(3)........ 143,921 142,393 101,888 103,186 207,544
PG&E Pipeline Expansion
(Line 401)............ 240,506 200,755 20,513 -- --
---------- ---------- ---------- ---------- ----------
Total............... 384,427 343,148 122,401 103,186 207,544
========== ========== ========== ========== ==========
REVENUES (IN THOUSANDS):
Bundled gas sales and
transportation
service:
Residential........... $1,205,223 $1,268,966 $1,152,494 $1,092,324 $1,226,094
Commercial............ 421,397 444,805 467,962 479,599 551,669
Industrial............ 42,106 57,297 367,221 425,467 366,346
Other gas utilities... 0 2,371 25,654 38,504 43,224
---------- ---------- ---------- ---------- ----------
Bundled gas
revenues........... 1,668,726 1,773,439 2,013,331 2,035,894 2,187,333
Transportation only
revenue:
Vintage system
(Substantially all
Industrial).......... 167,325 132,509 56,733 75,606 133,348
PG&E Pipeline
Expansion (Line 401). 82,904 58,442 8,097 -- --
---------- ---------- ---------- ---------- ----------
Transportation
service only
revenue............ 250,229 190,951 64,830 75,606 133,348
Miscellaneous.......... (18,018) 40,427 (16,692) 21,022 (59,056)
Regulatory balancing
accounts.............. (43,771) (101,443) 95,339 40,199 (30,091)
Subsidiaries(4)........ 201,951 177,688 264,925 173,587 123,642
---------- ---------- ---------- ---------- ----------
Operating revenues.. $2,059,117 $2,081,062 $2,421,733 $2,346,308 $2,355,176
========== ========== ========== ========== ==========
</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, 130,000 MMcf and
50,000 MMcf in 1993, 1992 and 1991, 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
Pipeline Expansion of 100,207 MMcf, 79,749 MMcf and 7,205 MMcf for 1995,
1994 and 1993, respectively.
(4) Includes gas transportation revenues from PGT.
34
<PAGE>
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31
-------------------------------------------------
1995 1994 1993 1992 1991
--------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C>
SELECTED STATISTICS:
Total customers (at year-
end)....................... 3,600,000 3,500,000 3,600,000 3,500,000 3,500,000
Average annual residential
usage (Mcf)................ 56 64 62 57 64
Heating temperature -- % of
normal(1).................. 75.3 104.4 89.9 76.0 101.5
Average billed bundled gas
sales revenues per Mcf:
Residential................. $6.29 $5.92 $5.59 $5.74 $5.82
Commercial.................. 6.57 6.16 5.70 6.00 6.47
Industrial.................. 3.00 2.94 2.76 2.93 3.06
Average billed
transportation only revenue
per Mcf:
Vintage system.............. 0.69 0.60 0.52 0.73 0.64
PG&E Pipeline Expansion
(Line 401)................. 0.34 0.29 0.39 -- --
Net plant investment per
customer................... $1,315 $1,340 $1,339 $1,170 $893
</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,
1995, approximately 64% 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 8% 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
Natural Gas Company (El Paso) or Transwestern Pipeline Company (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
--------------------------------------------------------------------------------------------------
1995 1994 1993 1992 1991
----------------- ----------------- ------------------ ------------------ ------------------
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> <C>
Canada............ 261,800 $1.34 319,453 $1.94 329,693 $2.26 321,770 $2.14 345,020 $2.34
California........ 31,158 $1.32 31,757 1.55 32,096 1.65 50,953 1.73 73,257 2.00
Other states
(substantially
all U.S.
Southwest)....... 117,538 $2.64 249,733 2.41 243,058 2.84 327,272 2.51 240,141 2.61
------- ------- ------- ------- -------
Total/Weighted
Average.......... 410,496 $1.71 600,943 $2.12 604,847 $2.46 699,995 $2.28 658,418 $2.40
======= ===== ======= ===== ======= ===== ======= ===== ======= =====
</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 noncore customers and
some core customers to purchase gas directly from producers, aggregators or
marketers, and to separately negotiate gas transportation with their utilities;
and (iv) places the utilities at risk for collecting a portion of the
transportation revenues associated with their noncore markets.
35
<PAGE>
In April 1992, the FERC issued its Order 636, which required interstate
pipelines to unbundle sales services from transportation services, established
various programs providing for reallocation of pipeline capacity and adopted
various mechanisms by which pipelines may recover transition costs arising from
the restructuring of their services. Under the Order 636 capacity allocation
rules, firm capacity holders were permitted to exercise a one-time opportunity
to "relinquish," i.e., permanently abandon, some or all of their transportation
capacity, either by paying a negotiated exit fee or through a third party
assuming the obligations of the existing transportation agreement. Thereafter,
firm capacity holders may also "release" some or all of their capacity, i.e.,
give up capacity rights to third parties for a limited period of time.
Releasing capacity holders remain liable on their existing contracts, but will
receive a credit for the acquiring third parties' demand charge payments, the
amounts of which will depend on the percentage of full rate paid by the
acquiring third party.
Under the CPUC's capacity brokering program implemented in 1993, PG&E is
required to make available for brokering all interstate pipeline capacity not
reserved for its core customers and core subscription customers (noncore
customers who elect to receive combined gas procurement and transportation
service). Noncore customers, marketers and shippers, and PG&E's electric
department can bid for such capacity.
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 for success in the competitive marketplace, PG&E
has presented a proposal, called the "Gas Accord," to numerous parties active
in the California gas marketplace, including consumer groups, industrial
customers, shippers and marketers. The Gas Accord proposes three broad
initiatives:
(1) Increased Customer Choice -- Under the Gas Accord, PG&E proposes to
give all customers greater ability to choose their gas suppliers in the
future. PG&E has formed an advisory group to help it design a program that
will facilitate opening the core market for full competition.
(2) Separation of Transmission and Distribution Service and Rates -- PG&E
proposes to charge separately for, or unbundle, its gas transmission and
distribution services. This would give noncore customers and gas suppliers
more flexibility with respect to the purchase of gas transportation
services.
(3) Resolution of Existing Regulatory Issues -- PG&E also proposes to
settle several outstanding gas regulatory issues that are currently pending
at the CPUC in separate proceedings. These issues include recovery of costs
related to PG&E's capacity commitments with Transwestern, PG&E's capacity
commitments with El Paso and PGT related to its noncore customers, and the
initial capital costs for the PG&E Pipeline Expansion. (See "Restructuring
of Gas Supply Arrangements" and "PGT/PG&E Pipeline Expansion" below.)
Negotiations on the Gas Accord began in October 1995. Any agreement reached
by PG&E and other parties must be approved by the CPUC before it may be
implemented.
The Gas Accord, if adopted, will result in a change in the way PG&E charges
for its gas transportation services. Based on the current status of the Gas
Accord negotiations, the Company believes the ultimate outcome of such
negotiations, including resolution of gas regulatory issues, will not have a
material impact on its financial position or results of operations.
36
<PAGE>
PG&E has also proposed a significant change to the current gas ratemaking
mechanisms. In December 1994, PG&E filed an application for approval of a core
procurement incentive mechanism (CPIM). If approved by the CPUC, the CPIM would
replace traditional reasonableness review of PG&E's core gas costs with a
market benchmark against which PG&E's actual gas costs would be compared. PG&E
would be able to fully recover its gas costs, earn additional rewards or be
penalized depending on whether its actual core procurement costs are within,
below or above the "tolerance band" constructed around that benchmark. Hearings
on the CPIM have been scheduled for June 1996.
In light of the changes instituted in the gas regulatory framework and the
possibility of uneconomic bypass of utilities' gas transmission systems by
competing pipelines, in 1992 the CPUC instituted a procedure for expedited
approval of discounted long-term gas transportation contracts with large
customers. PG&E currently has 13 contracts for discounted intrastate gas
transportation service that have been approved by the CPUC under this Expedited
Application Docket (EAD) procedure. Currently, 75% of revenue shortfalls
attributable to these EAD contracts are recovered from other ratepayers. In a
pending EAD contract proceeding, the CPUC plans to consider changing the
revenue shortfall allocation and to address the issue of the protection against
antitrust liability that will be accorded to PG&E by virtue of the state
regulation of these EAD contracts.
RESTRUCTURING OF GAS SUPPLY ARRANGEMENTS
As noted above, under the current regulatory framework, many of PG&E's
noncore customers arrange for the purchase and interstate transportation of
their own gas supplies. This has resulted in a decrease in the amount of gas
required to be purchased by PG&E and a related decrease in PG&E's need for firm
transportation capacity, and contributed to the restructuring of PG&E's gas
supply arrangements.
ANG AND NOVA CAPACITY
Until November 1993, PG&E purchased Canadian natural gas from PGT, which in
turn purchased such gas from Alberta and Southern Gas Co. Ltd. (A&S), a wholly
owned gas procurement subsidiary of PG&E. A&S had commitments to purchase
minimum quantities of gas from Canadian producers under various contracts, most
of which extended through 2005. Under a Decontracting Plan implemented November
1, 1993, the Canadian producers' contracts with A&S, the sales agreement
between A&S and PGT, and PG&E's service agreement with PGT each were
terminated. Settlement payments of approximately $210 million were paid to the
Canadian producers. A&S permanently assigned approximately 600 MMcf per day
(MMcf/d) of capacity with NOVA Corporation of Alberta (NOVA) through October
2001 and Alberta Natural Gas Company Ltd (ANG) through October 2005 to PG&E for
use in the servicing of PG&E's core customers and core subscription customers.
As of December 1995, A&S had completed the permanent assignment to others of
substantially all of the balance of its NOVA and ANG capacity.
The FERC approved a transition cost recovery mechanism (TCRM) for PGT under
which most costs which were incurred to restructure, reform or terminate the
sales arrangements between A&S and PGT and underlying A&S gas supply contracts,
or to resolve claims by gas suppliers related to past or future liabilities or
obligations of PGT or A&S, are eligible for recovery in PGT's rates. Under the
TCRM (1) 25% of such costs are absorbed by PGT; (2) 25% are recovered by PGT
through direct bills (substantially all to PG&E as PGT's principal customer);
and (3) 50% are recovered by PGT through volumetric surcharges over a three-
year period. Costs associated with A&S's commitments for Canadian pipeline
capacity do not qualify as transition costs recoverable under this mechanism.
The FERC has approved recovery by PGT of $168 million under the TCRM. PG&E has
paid PGT approximately $56 million in payment of direct bills charged by PGT
for transition costs under the TCRM. Recovery by PG&E of the first direct bill
(approximately $51 million) and the volumetric surcharges billed to PG&E was
authorized in PG&E's 1996 BCAP.
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EL PASO AND PGT CAPACITY
PG&E's firm transportation agreement with PGT for 1,066 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 agreements include provisions for
fixed demand charges for reserving firm capacity on the pipelines. 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 retained approximately 600 MMcf/d on each of
the PGT and El Paso systems to support its core and core subscription customers
and made amounts not needed to support such customers available for capacity
release and brokering to other potential shippers beginning in 1993. PG&E has
permanently assigned portions of the capacity it no longer uses and is
continuing its efforts to assign or broker the remaining unused capacity. Until
permanently assigned, amounts brokered have generally been on a short-term
basis, most of which were at a discounted price. As of December 1995, PG&E had
assigned substantially all of its unused capacity on PGT. Due to lower demand
for Southwest pipeline capacity, PG&E cannot predict with certainty the volume
or price of the capacity on El Paso that will be brokered or assigned.
Interstate transportation capacity which cannot be marketed at the full rate
results in unrecovered demand charges. 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 for later review and
recovery from customers.
Ultimate recovery of unrecovered interstate pipeline demand charges
accumulated in the ITCS will be subject to CPUC reasonableness review. There
may be instances where the CPUC may not allow full recovery with respect to
discounted rates. For example, the CPUC has indicated that if a rate discount
given to a customer in a contract entered into pursuant to PG&E's EAD procedure
results in a shortfall in recovery of ITCS costs contained in the otherwise
applicable tariff rate, PG&E will not recover those ITCS costs from other
customers.
In November 1994, the CPUC issued an interim decision on PG&E's application
seeking recovery of amounts accumulated in the ITCS account through August 31,
1994. In its decision, the CPUC authorized recovery of one-half of the
accumulated demand charges, or approximately $30 million, subject to refund
should ITCS costs prove to have been caused by improper acts of PG&E. In
addition, as part of its decision issued in December 1995 on PG&E's 1996 BCAP,
the CPUC authorized PG&E to recover 50% of recorded and forecasted ITCS amounts
through September 30, 1997, again subject to refund depending on the final
resolution of the issue in the proceeding concerning recovery of ITCS amounts.
The DRA has submitted testimony in the ITCS proceeding indicating that it had
found no basis for recommending any direct disallowance of costs associated
with amounts allocated to the ITCS account. Two intervenors, Toward Utility
Rate Normalization and El Paso, have submitted testimony suggesting
disallowances and/or a reallocation among customers of between $40 million and
$101 million, respectively, based on allegations that PG&E's imprudent actions,
including actions which allegedly resulted in the devaluation of interstate
pipeline capacity, have unreasonably increased the amount of unrecovered demand
charges.
The ITCS proceeding has been consolidated with the market issues phase of the
PEPR proceeding, with hearings scheduled to begin in April 1996. In the
meantime, PG&E continues to pursue the resolution of issues concerning past and
future ITCS costs as part of its Gas Accord negotiations. See "Gas Regulatory
Framework" above.
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TRANSWESTERN CAPACITY
In April 1992, PG&E executed firm transportation agreements with Transwestern
to transport 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
$28 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 in PG&E's gas reasonableness
proceeding for the 1992 record period which concludes that it was unreasonable
for PG&E to subscribe for Transwestern capacity. The decision finds PG&E acted
unreasonably in deciding to undertake its Transwestern subscription at a time
when its procurement and interstate transportation roles were being
significantly reduced and contemporaneously with its decision to go forward
with its own pipeline expansion to Canada, knowing it would thereby strand
significant amounts of Southwest capacity. The decision also finds that PG&E
failed to offer evidence showing that the benefits of the subscription
outweighed the costs during 1992, and orders that all costs incurred by PG&E
for Transwestern capacity in that year (approximately $18 million) be
disallowed. The decision further orders that costs for the capacity in
subsequent years of the 15-year contract be disallowed unless PG&E can
establish by clear and convincing evidence that the benefits of the
Transwestern capacity exceeded the costs of such capacity in that year.
In January 1996, PG&E filed a request for rehearing of this decision,
contesting the disallowance of its Transwestern costs on grounds that the
subscription has yielded benefits for its ratepayers, both directly to the
extent PG&E received service from Transwestern and indirectly by reducing the
cost of gas supplied over other competing pipelines. PG&E argued that the
amount of any disallowance should be reduced to reflect the existence of these
benefits. PG&E also continues to pursue the resolution of issues concerning
past and future Transwestern costs as part of its Gas Accord negotiations. See
"Gas Regulatory Framework" above.
The DRA has recommended a disallowance of approximately $24.3 million in
respect of Transwestern costs incurred by PG&E in 1993. The basis for this
disallowance recommendation is essentially the same as that underlying the
CPUC's decision disallowing Transwestern costs for the 1992 record period.
Using the same rationale, the DRA has also recommended a disallowance of
approximately $7 million for demand charges incurred by PG&E's electric
department for Transwestern capacity in 1994 and approximately $8.6 million for
demand charges paid to Transwestern during the period January 1, 1994 to May
31, 1994 to serve core gas customers. The DRA also indicated it would recommend
an additional disallowance of $11.1 million for Transwestern core capacity
costs from June through December 1994 if the DRA did not, as it has pursuant to
an agreement with PG&E, use the CPIM in evaluating PG&E's procurement
activities for core customers during that period.
The Company believes that the ultimate resolution of past and future
Transwestern costs will not have a material adverse impact on its financial
position or 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 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
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more aggressively with its existing Canadian suppliers or bought less expensive
gas from other Canadian sources. The CPUC concluded that it was appropriate for
PG&E to take a substantial portion (up to 700 MMcf/d) of its Canadian gas at
its then-existing price, but that PG&E could have met the remainder of its
demand for Canadian gas at lower prices, either from the same suppliers or with
purchases from other available Canadian natural gas sources. The decision
ordered a disallowance of $90 million of gas costs, plus accrued interest
estimated at approximately $25 million through December 31, 1993. The CPUC also
issued a final decision on PG&E's non-Canadian gas operations during 1988
through 1990, ordering a disallowance of $8 million.
PG&E filed a request for rehearing of the CPUC's decision ordering a
disallowance in connection with PG&E's Canadian gas procurement activities in
1988-1990, which was denied in November 1994. 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. In September 1995, the District Court denied
a motion filed by the CPUC which sought to dismiss the lawsuit.
GAS SETTLEMENT AGREEMENTS
During 1995, the CPUC approved settlement agreements between the DRA and PG&E
which resolve $25 million of disallowances recommended by the DRA relating to
certain non-Canadian gas issues arising from the 1991 and 1992 record periods.
Pursuant to these agreements, PG&E will return $1.1 million to ratepayers.
A number of other reasonableness issues related to PG&E's gas procurement
practices and supply operations for periods dating from 1988 through 1994 are
still under review by the CPUC. The DRA recommended disallowances of
approximately $79 million and a penalty of $50 million and indicated that it
was considering additional recommendations for pending issues. PG&E and the DRA
have signed a settlement agreement to resolve these issues for a $67 million
refund by PG&E.
Significant issues covered by the gas settlement agreement include (i) PG&E's
purchases of Canadian, Southwest and California gas for its electric department
in 1991 and 1992 and its gas customers from 1991 through May 1994; (ii) issues
not related to gas procurement which arise from the DRA's investigation of A&S,
and the proposed investigation of ANG, a former affiliate of PG&E; (iii) the
effects PG&E's Canadian gas procurement costs may have had on amounts paid by
PG&E for Northwest power purchases for 1988 through 1992 and for power
purchased from geothermal and QF producers during 1991 and 1992; (iv) the costs
of capacity PG&E held on the NOVA and ANG pipelines on behalf of its core
customers for the period November 1, 1993 through May 31, 1994; (v) PG&E's
Southwest gas procurement activities for 1988 through 1990; and (vi) Canadian
gas decontracting activities.
Agreements with the DRA do not constitute a CPUC decision and are subject to
modification by the CPUC in its final decisions. The gas settlement agreement
is expressly conditioned upon CPUC approval. Upon such approval, PG&E would
return approximately $67 million to its ratepayers.
The proposed gas settlement agreement does not resolve issues related to the
effect PG&E's Canadian gas procurement costs during the 1988 through 1990
period may have had on the price PG&E paid to geothermal and QF producers
during those years. Hearings on those issues have not yet been scheduled by the
CPUC. The proposed gas settlement agreement also does not resolve the
reasonableness of PG&E's subscription to Transwestern pipeline capacity or the
costs accrued in PG&E's ITCS account.
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FINANCIAL IMPACT OF GAS REASONABLENESS PROCEEDINGS
As of December 31, 1995, PG&E had accrued approximately $208 million for gas
reasonableness matters. Such accruals include the CPUC decisions for the years
1988 through 1992 and issues covered by the settlement agreement described
above. The Company believes that the ultimate outcome of these matters will not
have a material impact on its financial position or results of operations.
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. The
total cost of construction is currently estimated to be approximately $1.7
billion consisting of $813 million for the facilities within California (i.e.,
the PG&E Pipeline Expansion) and $852 million for the facilities outside
California (i.e., the PGT Pipeline Expansion).
CPUC RATEMAKING
The conditions of the CPUC's approval of the construction of the PG&E
Pipeline 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 of the Pipeline
Expansion must be transported at an incremental PG&E Pipeline Expansion rate.
Incremental rate design is based on the concept that expansion shippers pay for
the incremental capital and operating costs incurred by the pipeline owner in
constructing the expansion facilities. Under incremental rates, a pipeline
would generally charge higher rates to shippers contracting for capacity on the
newly-added expansion facilities as compared to shippers having firm
transportation service rights on depreciated pre-expansion facilities.
Capacity on the PGT Pipeline Expansion is fully subscribed under long-term
firm transportation contracts. To date, shippers have executed long-term firm
transportation contracts for approximately 40% of capacity on the PG&E Pipeline
Expansion, and PG&E continues negotiations for the remainder of that capacity.
The CPUC has authorized PG&E to provide as-available service on the PG&E
Pipeline Expansion, which provides additional revenues to recover the
incremental costs of the expansion.
In February 1994, the CPUC issued a decision on PG&E's request for an
increase in the cost cap for the PG&E Pipeline Expansion and its interim rate
filing in the 1993 Pipeline Expansion Rate Case. The cost cap represented the
maximum amount determined by the CPUC to be reasonable and prudent based on an
estimate of the anticipated construction costs at that time. The CPUC granted
PG&E's request to increase the cost cap to $849 million, but set interim rates
based on the original cost cap of $736 million, subject to adjustment within
the newly approved cost cap after the outcome of a reasonableness review of
capital costs. The CPUC's decision finds that given market conditions at the
time, PG&E was reasonable in constructing the PG&E Pipeline Expansion. The CPUC
has denied rehearing of this decision.
In September 1994, PG&E filed its application in the PEPR proceeding. PG&E
requested that the CPUC find reasonable the full capital costs of the PG&E
Pipeline Expansion (estimated to be $813 million) and its initial operating
expenses and allow recovery of the difference between revenues related to the
interim rates and the revenue requirement associated with actual costs incurred
in 1993 through 1995. PG&E's PEPR filing also presents the base revenue
requirement for 1996 and asks that the CPUC approve new PG&E Pipeline Expansion
rates and services for the 1996 through 1998 time period.
In December 1995, the DRA filed its report in the PEPR proceeding,
recommending a "minimum" disallowance of $100 million in capital costs for the
PG&E Pipeline Expansion. In its report, the DRA
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identifies approximately $55 million of costs that it contends are directly
attributable to unreasonable management, but asserts that it is impossible to
quantify the total impact of PG&E's alleged mismanagement due to the fixed
price nature of the construction contract. However, based on a comparison of
other pipeline projects, DRA estimates the total excess costs to be $100
million. Two intervenors have also recommended a disallowance or reallocation
of costs totaling $223 million. An order issued by a CPUC ALJ has also reopened
the 1993 Pipeline Expansion Rate Case to allow reconsideration of issues
regarding the decision to construct the PG&E Pipeline Expansion.
In January 1996, a CPUC ALJ ordered consolidation of the market impact phase
of the PEPR proceeding and the ITCS proceeding discussed above.
If the CPUC were to reverse its previous decision finding that PG&E was
reasonable in constructing the PG&E Pipeline Expansion, the ultimate outcome
could have an impact on PG&E's ability to recover its cost for unused capacity
on other pipelines as well as on its own intrastate facilities.
FERC RATEMAKING
In its 1991 orders approving construction of the PGT portion of the Pipeline
Expansion, the FERC concluded that PGT had not sufficiently demonstrated that
shippers would not be subject to discriminatory restraints on access into
California or on the PGT Pipeline Expansion as a result of the "cross-over" ban
imposed by the CPUC. As a result, the FERC reduced PGT's approved rate of
return on equity on the PGT Pipeline Expansion until such time as PGT
demonstrates that neither its rates or transportation policies nor those of
PG&E result in unduly discriminatory restraints.
In February 1994, PGT filed an application with the FERC to increase its
rates for transportation services. These rates are based on an overall cost of
service of approximately $217 million, including a cost of equity of 13%. The
proposed rate of return on equity applies to all facilities and assumed the
discontinuance of the penalty rate of return on equity of 10.13%, which the
FERC had earlier required to be used to develop initial rates for the PGT
Pipeline Expansion.
A major issue in this proceeding is whether PGT's mainline transportation
rates should be equalized through the use of rolled-in cost allocation, or
whether they should continue to reflect the current use of incremental costs to
determine rates to be paid by shippers. PGT proposed that mainline rates
reflect the rolled-in approach on a prospective basis.
In March 1994, the FERC issued an order that accepted PGT's interim
incremental rates and authorized PGT to place these rates into effect on
September 1, 1994, subject to refund. Although the FERC rejected the proposal
to place rolled-in rates into effect on September 1, 1994, the FERC indicated
that PGT would be afforded the opportunity in hearings to support and justify a
rolled-in rate proposal. Hearings were concluded in September 1995.
PGT has reached an agreement in principle with the FERC staff and a majority
of the active parties in its 1994 rate case which would resolve all issues in
this case. Of primary significance to the case, the proposed settlement
provides that rolled-in rates will become effective on November 1, 1996. To
mitigate the impact of the higher rolled-in rates, most of the shippers using
firm capacity on the pre-expansion facilities will be receiving a reduction
from the rolled-in rates for six years, while the PGT Pipeline Expansion
shippers will pay a surcharge in addition to the rolled-in rates to offset the
effect of the mitigation. Although the implementation of rolled-in rates by
itself will not change PGT's total revenue requirement, the settlement does
provide for, among other things, a lower total cost of service of $206 million,
lower depreciation rates and a return on equity of 12.2% for both the PGT
Pipeline Expansion and PGT's pre-expansion facilities, effective as of
September 1, 1994. The proposed settlement is subject to approval by the FERC
and may be opposed by several parties. In the event the FERC rejects the
settlement, PGT's 1994 rate case would proceed to a FERC decision based on the
evidence in the case.
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OTHER COMPETITIVE PIPELINE PROJECTS
In March 1993, Mojave Pipeline Company (Mojave), which is a subsidiary of El
Paso, filed a request seeking FERC authorization for construction of a 475
MMcf/d transportation-only pipeline expansion of its interstate natural gas
pipeline. The expansion would have extended Mojave's system from its current
terminus in Bakersfield, California, through California's Central Valley to
Sacramento and the San Francisco Bay Area. Mojave's filing indicated that 433
MMcf/d of the firm service capacity that would be provided by the proposed
expansion would be provided to customers located in PG&E's service territory,
with approximately 257 MMcf/d of that amount to be used to provide gas service
that currently is not provided by PG&E. The remaining 176 MMcf/d represented
service to customers currently served by PG&E.
The FERC granted final approval for the Mojave project in December 1995, but
in February 1996 Mojave announced that it did not intend to proceed with its
proposed expansion. Mojave indicated that the construction and operation of the
expansion was economically infeasible under current market conditions.
Another possible entrant into the California gas transportation market is
Tuscarora Gas Transmission Company (Tuscarora), which has announced plans to
study the feasibility of constructing a 142-mile lateral pipeline to the
Sacramento area. Tuscarora currently operates a 230-mile pipeline under FERC
jurisdiction that runs from the California-Oregon border at Malin, Oregon to
Reno, Nevada.
PG&E also faces competition from various other pipeline projects completed in
recent years to serve the enhanced oil recovery market in Southern California
and other customers. In 1992, projects sponsored by Mojave and the Kern River
Gas Transmission Company commenced commercial operations, and both Transwestern
and El Paso put into service expanded pipeline facilities from the San Juan
Basin in New Mexico to the California border. These projects provide additional
capacity to some of the same markets served by the Pipeline Expansion. Some of
the gas available from the U.S. Southwest over these projects is priced equal
to or lower than the price of Canadian gas available over the Pipeline
Expansion, due in part to federal tax credits available for certain San Juan
gas production.
STORAGE SERVICE
PG&E has generally provided natural gas storage service only in conjunction
with its procurement and transportation services. In February 1993, the CPUC
adopted policies and rules for permanent unbundled gas storage programs for
noncore customers, and an unbundled storage program for PG&E was approved by
the CPUC in May 1994. Storage service for core customers remains bundled with
procurement and transportation services.
In September 1994, PG&E began offering unbundled storage to noncore customers
for varying terms of one year or less. Customers bid to purchase this storage
capacity, with available capacity awarded to the highest bids first. To the
extent PG&E does not recover the full costs allocated to this noncore storage
program, the CPUC authorized a Noncore Storage Balancing Account in which these
unrecovered costs are accumulated for later review and allocation among
customer classes. The CPUC also approved negotiated discounted rates for
storage services for noncore customers under certain circumstances, but
provided that a portion of any revenue shortfalls attributable to such
discounted rates may not be recovered from other customers.
PG&E ENTERPRISES
Enterprises is the parent company established to oversee the Company's
nonregulated non-utility business activities. Enterprises was established in
1988 and is a wholly owned subsidiary of PG&E. Enterprises' wholly owned
subsidiaries include PG&E Generating Company, PG&E Generating International
Company, Vantus and PG&E Properties, Inc. Enterprises and its affiliated
entities are engaged in the activities described below.
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DOMESTIC NON-UTILITY ELECTRIC GENERATION
PG&E Generating Company was formed to partner with Bechtel Enterprises, Inc.
in USGen, a California partnership. USGen manages the development, construction
and operation of non-utility electric generation facilities that compete in the
U.S. power generation market and sell power to utilities other than PG&E.
USGen's owners' overall ownership in all the projects in which USGen
participates is approximately 64%. PG&E Generating Company's average overall
ownership represents approximately 74% of the owners' equity in the total
project portfolio developed by USGen.
As of December 31, 1995, USGen's partners had ownership interests in 14
operating plants and three under construction. The total generating capacity of
these 17 plants is 3,369 MW, of which PG&E Generating Company's share is 1,611
MW. The projects were largely financed with a combination of equity or equity
commitments from the project sponsors and non-recourse debt. In addition to its
asset management responsibilities in these 17 power plants, USGen, through its
affiliate, U.S. Operating Services Company (USOSC), provides contract
operations and maintenance services to 10 of these facilities. Also, USOSC
provides management and technical support for the operation of four other
operating plants, with a total generating capacity of 935 MWs.
In August 1994, Enterprises and Bechtel Enterprises, Inc. acquired J.
Makowski Company, Inc. (JMC), a Boston-based company engaged in developing
natural gas-fueled electric generation projects, natural gas distribution and
underground gas storage projects. JMC has been integrated into USGen's and
InterGen's portfolio of domestic and international projects.
INTERNATIONAL POWER GENERATION
PG&E Generating International Company was formed to partner with Bechtel
Enterprises, Inc. in InterGen, a Cayman Islands company. InterGen was formed in
April 1995 to manage the development, construction and operation of
international electric generation projects. InterGen is headquartered in Boston
and has established regional offices in Hong Kong, London and Miami.
As of December 31, 1995, InterGen's owners had a 10% ownership interest in
one project under construction in India with a total capacity of 740 MW, of
which PG&E Generating International Company's share is 37 MW. Currently, seven
projects are under development in China, Colombia, India, Mexico, the
Philippines, Taiwan and the United Kingdom with a total capacity of 4,643 MW,
of which PG&E Generating International Company's share is 1,839 MW.
INTERNATIONAL GAS AND ELECTRIC DISTRIBUTION
Enterprises may also pursue opportunities to acquire electric and gas
distribution companies outside the United States. Such opportunities are
expected to arise as governments around the world restructure and privatize
their electric and gas systems.
ENERGY PRODUCTS AND SERVICES
In August 1995, Enterprises formed Vantus, an energy products, services and
power marketing company. Vantus has received authority from the FERC to market
competitively priced electricity, which it intends to sell with other energy
commodities and new products and services.
USGen has recently formed a bulk power trading group, USGen Power Services,
to participate in the short-term wholesale power market. USGen Power Services
has received authorization from the FERC to market competitively priced
electricity. USGen Power Services sells uncommitted capacity from USGen's
facilities and has begun to aggregate surplus generation from unaffiliated
sources for trading or sale to wholesale and large retail customers.
REAL ESTATE DEVELOPMENT
PG&E Properties, Inc. (Properties) develops real estate in PG&E's service
territory, focusing on mixed-use planned development. Enterprises currently has
no plans for substantial future additional investments in Properties.
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OTHER
In June 1995, Enterprises completed the sale of DALEN Corporation, formerly
DALEN Resources Corp. (DALEN), its wholly owned subsidiary engaged in natural
gas and oil exploration and production. The decision to sell DALEN was based on
the determination that gas and oil exploration and production activities do not
fit within PG&E's long-term corporate strategy.
ENVIRONMENTAL MATTERS AND OTHER REGULATION
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
the Company's current estimates which are periodically evaluated and revised.
These estimates are subject to a number of assumptions and uncertainties,
including changing laws and regulations, the ultimate outcome of complex
factual investigations, evolving technologies, selection of compliance
alternatives, the nature and extent of required remediation, the extent of the
Company's responsibility and the availability of recoveries or contributions
from third parties. Future estimates and actual results may differ materially
from those indicated below.
The Company is 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. The Company has undertaken
major compliance efforts with specific emphasis on its purchase, use and
disposal of hazardous materials, the cleanup or mitigation of historic waste
spill and disposal activities, and the upgrading or replacement of 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 $64 million,
$67 million, $120 million, $76 million and $52 million for 1996, 1997, 1998,
1999 and 2000, respectively, and are included in PG&E's five-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 as described below, which
currently are expected to decline in the later years as the NOx reduction
projects are completed. In addition, PGT estimates its capital expenditures for
environmental protection will be approximately $2 million, $1 million and $1
million in 1996, 1997, and 1998, respectively.
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 fuel fired 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 are scheduled to begin in 1996. 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 $335 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.
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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 $80 million over five years.
In PG&E's 1993 GRC, the CPUC established an Air Quality Adjustment mechanism
under which PG&E could seek cost recovery in rates for NOx reduction projects.
However, in PG&E's 1996 GRC, the CPUC eliminated the Air Quality Adjustment
mechanism and 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 NOx costs may be recoverable only through PBR, market
pricing, or other means established as part of the CPUC's electric industry
restructuring initiative.
In 1990 Congress passed extensive amendments to the Federal Clean Air Act.
The U.S. Environmental Protection Agency (EPA) has issued numerous regulations
for the implementation of these amendments. PG&E is currently assessing the
impact of the regulations. Generally, existing or proposed state and local air
quality requirements are more stringent than the new federal requirements,
which should therefore have little impact on PG&E.
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 has been reviewed
by the Central Coast Regional Water Quality Control Board. The Board has not
yet made a final decision on the report and has requested that PG&E continue
the marine monitoring program. In the event that Diablo Canyon does not comply
with the thermal limitations and in the unlikely event that major modifications
are required (e.g., cooling towers), significant additional construction
expenditures 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. However, 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. PG&E is currently involved in litigation and a
California Attorney General investigation concerning a 1988 study of Diablo
Canyon's compliance with BTA requirements. See "Legal Proceedings -- Coastal
League Litigation" and "-- California Attorney General Investigation" below. An
adverse outcome in these proceedings could result in parties raising questions
regarding Diablo Canyon's compliance with BTA requirements.
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 MATERIALS AND 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. Generally, these compliance costs
are recovered through the GRC process. However, as discussed below, the CPUC
has established a separate mechanism for recovery of certain hazardous waste
remediation costs.
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PG&E has a comprehensive program to comply with the many hazardous waste
storage, handling and disposal requirements promulgated by the EPA under the
Resource Conservation and Recovery Act and the Comprehensive Environmental
Response, Compensation, and Liability Act (CERCLA), along with California's
hazardous waste laws and other environmental requirements. One part of this
program is aimed at assessing whether and to what extent remedial action may be
necessary to mitigate potential hazards posed by certain disposal sites and
retired manufactured gas plant sites. During their operation, manufactured gas
plant facilities produced lampblack and tar residues, byproducts of a process
that PG&E 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 PG&E
operated in its service territory. PG&E owns all or a portion of 29 of these
manufactured gas plant sites. PG&E has begun 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 $30 million over the period 1996 through 1997. 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. PG&E performed a groundwater remedial action at its Sacramento
former manufactured gas plant site during 1995. PG&E had accrued a $9.3 million
liability as of December 31, 1995 for the Sacramento gas plant 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 had accrued a $6.6 million liability as of
December 31, 1995 for the Purity Oil Sales site. Although PG&E has not been
named as a PRP with respect to the Casmalia site near Santa Maria, California,
the EPA has notified PG&E and approximately 65 other generators who allegedly
sent the largest volumes of waste to the site that action is needed to clean up
and close the site. PG&E is working with other alleged generators to evaluate
measures which may need to be taken at the site. PG&E had accrued a
$3.2 million liability as of December 31, 1995 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 had accrued a liability of $10 million as of
December 31, 1995 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 received a demand from the
California Attorney General seeking 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.
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The overall costs of the hazardous materials and hazardous waste compliance
and remediation activities ultimately undertaken by the Company are difficult
to estimate and 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, 1995 of $122 million for hazardous waste remediation costs at
those sites where such costs are probable and quantifiable. The costs may be as
much as $287 million if, among other things, other PRPs are not financially
able to contribute to these costs or further investigation indicates that the
extent of contamination or necessary remediation is greater than anticipated at
sites for which the Company is responsible. This upper limit of the range of
costs was estimated using assumptions least favorable to the Company 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 May 1994, the CPUC issued a decision in the Southern California Gas
Company's (SoCal Gas) environmental reasonableness proceeding. The final
decision adopts the settlement and proposed ratemaking mechanism for hazardous
waste remediation costs which was previously submitted by PG&E and other
interested parties. 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.
To the extent that hazardous waste compliance and remediation costs are not
recovered through insurance or by other means, PG&E may apply for recovery
through ratemaking procedures established by the CPUC and, assuming
continuation of these procedures, expects that most prudently incurred
hazardous waste compliance and remediation costs will be recovered through
rates. As of December 31, 1995, PG&E had a deferred charge of $107 million for
hazardous waste remediation costs, which represents costs expected to be
recovered in the future under the current ratemaking mechanisms. 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.
In December 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. The amount of recovery from insurance coverage, if any, cannot be
quantified at this time.
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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The CPUC proceeding was subsequently bifurcated into two phases -- one
focusing on EMF related to electric power and the other on EMF generated by
cellular telephone transmitters. In the electric power phase, 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 its customers which informs
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 EMFs. PG&E is
named as a defendant in one pending civil appeal. Plaintiffs allege personal
injury resulting from exposure to EMFs.
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 October 1991, the CPUC issued an Order Instituting Investigation/Order
Instituting Rulemaking on Low Emission Vehicles (LEVs) to investigate policy
issues surrounding electric and natural gas utility involvement in the market
associated with LEVs, specifically natural gas vehicles and electric vehicles.
In July 1993, the CPUC issued a decision in Phase I of the LEV proceeding that
directed PG&E to file a request for funding for a six-year program. In December
1995, the CPUC issued its decision in Phase II of the 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 (see "Electric Utility Operations -- Electric Industry
Restructuring" above) finds that the costs of utility LEV programs should
continue to be collected by the regulated utility.
OTHER REGULATION
CALIFORNIA PUBLIC UTILITIES COMMISSION
In addition to its jurisdiction over rate matters, the CPUC has the
authority, among other things, to establish rules and conditions of service, to
authorize disposition of utility property, to establish rules and policies
governing utility facilities, to regulate securities issues, to prescribe rates
of depreciation and uniform systems of accounts and to regulate transactions
between PG&E and its subsidiaries and affiliates.
CALIFORNIA ENERGY COMMISSION
PG&E also is subject to the jurisdiction of the CEC. The CEC has developed
programs for forecasting peak demands and energy requirements, is encouraging
certain types of energy conservation, has developed energy shortage and
contingency plans, and is developing and coordinating a program of energy
research and development. In addition, the CEC has statutory authority to
certify future thermal-electric power plant sites and related facilities 50 MW
and above within California.
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FEDERAL ENERGY REGULATORY COMMISSION
PG&E is subject to regulation by the FERC under the Federal Power Act as a
"public utility" as defined in the Federal Power Act. The FERC has authority,
among other things, to regulate PG&E's rates and terms and conditions for sales
of electricity for resale and transmission of electricity in interstate
commerce, and to prescribe rates of depreciation and uniform systems of
accounts. The FERC also regulates the terms and conditions of interstate
pipeline transportation service utilized by PG&E to transport gas it purchases
outside California. In addition, the FERC regulates PGT's rates and charges for
the transportation of natural gas in interstate commerce, the extension,
enlargement or abandonment of PGT's facilities and PGT's accounting, among
other things.
Most of PG&E's hydroelectric facilities are subject to licenses issued by the
FERC under Part I of the Federal Power Act, with various expiration dates to
the year 2033 and involving a total normal operating capability of 2,703 MW.
Helms adds an additional capacity of 1,212 MW. As the initial licenses for
these projects expire, they become susceptible to competition for a new
license. New licenses may contain or require environmental or recreational
mitigation and enhancement measures that can result in reduced generation and
unfavorable project economics.
NUCLEAR REGULATORY COMMISSION
PG&E also is subject to the jurisdiction of the NRC as to the operation and
decommissioning of its nuclear generating plants.
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 A&S, the Company's wholly owned 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.
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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 a notice of appeal to
preserve their right to appeal the dismissal to the Court of Appeals. If
plaintiffs pursue that appeal, the case would not likely be resolved for at
least another year.
The Company believes that the ultimate outcome of this matter will not have a
material adverse impact on its financial position.
HINKLEY COMPRESSOR STATION LITIGATION
In May 1993, a complaint was filed in San Bernardino County Superior Court on
behalf of a number of individuals seeking recovery of an unspecified amount of
damages for personal injuries and property damage allegedly suffered as a
result of exposure to chromium near PG&E's Hinkley Compressor Station, located
along PG&E's gas transmission system in San Bernardino County, as well as
punitive damages. The original complaint has been amended, and additional
complaints have been filed, to include additional plaintiffs. The complaints
plead several causes of action, including negligence, negligent and intentional
misrepresentation, fraudulent concealment, strict liability and violation of
California's Safe Drinking Water and Toxic Enforcement Act of 1986 (Proposition
65).
The plaintiffs contend that between 1951 and 1966 PG&E discharged Chromium
VI-contaminated wastewater into unlined ponds, which led to chromium
percolating into the groundwater of surrounding property. The plaintiffs
further allege that PG&E disposed of the chromium in those ponds to avoid
costly alternatives. In 1987, PG&E undertook an extensive project to remediate
potential groundwater chromium contamination. PG&E has incurred substantially
all of the costs it currently deems necessary to clean up the affected
groundwater contamination. In accordance with the remediation plan approved by
the regional water quality board, PG&E will continue to monitor the affected
area and periodically perform environmental assessments.
PG&E has reached an agreement with plaintiffs pursuant to which plaintiffs'
actions will be submitted to binding arbitration for resolution of issues
concerning the cause and extent of any damages suffered by plaintiffs. Under
the terms of the agreement, PG&E will pay an aggregate amount of no more than
$400 million in settlement of such plaintiffs' claims, including $50 million
paid to escrow to date. In turn, those plaintiffs, and their attorneys, agree
to indemnify PG&E against any additional losses PG&E may incur with respect to
related claims pursued by the identified plaintiffs who do not agree to this
settlement or by other third parties who may be sued by the identified
plaintiffs in connection with the alleged chromium contamination.
In July 1995, the parties began arbitration of 30 more cases. This followed
the completion of the arbitration of ten representative cases and the ensuing
unsuccessful mediation of the remaining 625 cases. The current arbitration was
concluded in March 1996 and is now under submission to the judges. Following a
decision in this latest arbitration, the parties will attempt to mediate the
remaining cases. Should that mediation not be successful, the process will
continue until all cases are arbitrated or settled.
As of December 31, 1995, PG&E had paid $50 million to escrow and recorded an
additional $150 million reserve against any future potential liability in this
case. The Company believes the ultimate outcome of this matter will not have a
material adverse impact on its financial position or results of operations.
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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
Court granted PG&E's motion for summary judgment in the class action lawsuit.
The plaintiffs have appealed that ruling. 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 have not indicated
damages to be sought in that separate action, but they are not anticipated to
be material.
Should the counties win the issue of franchise fee calculation methodology,
PG&E's annual systemwide county franchise fees could increase by approximately
$15 million. Damages for alleged underpayments in prior years could be as much
as $117 million (exclusive of interest, estimated to be $34 million as of
December 31, 1995).
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.
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. PG&E intends to file a motion to dismiss the
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discrimination claims of all the other plaintiff cities based on the Court's
ruling. On March 19, 1996, the Court granted PG&E's motion for judgment against
31 other class member cities, including the class representative (the City of
Santa Cruz). The Court determined that those cities were precluded from
contesting their franchise payment formulas since they had freely chosen the
formula used in the franchises. Those cities have indicated that they intend to
seek appellate review of these rulings. In the meantime, a June 1996 trial date
has been set.
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 $17 million and damages for alleged underpayments in
prior years could be as much as $131 million (exclusive of interest, estimated
to be $31 million as of December 31, 1995). If the Court's recent rulings
become final, the amount of alleged damages would be significantly reduced,
such that if the remaining plaintiffs ultimately prevailed, PG&E's annual
systemwide city electric franchise fees for the remaining class member cities
could increase by approximately $5.3 million and damage for alleged
underpayments could be as much as $39.1 million (exclusive of interest).
However, the ultimate damages and/or increase in fees might vary depending on
the Court's interpretation of the plaintiffs' claims.
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.
TIME-OF-USE METER/CUSTOMER NOTIFICATION LITIGATION
On July 21, 1994, Milton L. Grinstead, Michael Davis, Joan A. Williamson,
Frank H. Lacy and Matthew Doerksen filed a complaint in the Stanislaus County
Superior Court against PG&E on behalf of themselves and purportedly as a class
action on behalf of all of PG&E's customers, for "refund of unlawfully charged
fees." In April 1995, the Court dismissed the claims of two of the individual
plaintiffs.
On June 8, 1995, the three remaining plaintiffs filed an amended complaint
which alleged that (a) under certain circumstances PG&E has a duty to notify a
particular customer of the most favorable rate for that customer and (b) PG&E
has systematically failed to reasonably advise new and existing customers of
available advantageous rate structures, including the time-of-use billing
option. The amended complaint estimated classwide damages related to time-of-
use rates to be in excess of $16 billion and that the damages relating to other
programs and rate structures was at least an additional $10 billion. The
amended complaint also sought $100 billion in exemplary damages relating to
PG&E's alleged willful failure to provide required notice to customers of rate
options.
On October 18, 1995, the Court issued an order addressing several motions
filed by PG&E. The Court's order granted PG&E's motion to strike the class,
leaving only the claims of the individuals, and granted summary judgment
against one of the three remaining plaintiffs. The Court rejected PG&E's
assertion that the CPUC has exclusive jurisdiction over this dispute, but held
that PG&E does not have an obligation to advise customers of their best
available rates and is only obligated to give customers notice of rate options.
Although the Court's order gave the remaining two plaintiffs an opportunity to
amend their complaint to state a claim based upon an alleged failure to give
them notice of available rate options, an amended complaint was not filed. On
March 5, 1996, the Court entered judgment in favor of PG&E. Plaintiffs have
until early May 1996 to file a notice of appeal of that judgment.
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, a wholly
owned subsidiary of PG&E. Norcen Marketing has a 30-year
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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. Those antitrust claims were dismissed by the
District Court in September 1994, and subsequently reasserted in part by
plaintiffs in an amended complaint filed in October 1994.
On July 27, 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.
In addition to recission of their gas transportation contract, the plaintiffs
are seeking an unspecified amount of contract damages. Based on available
information, plaintiffs' out-of-pocket contract damages appear to be less than
$10 million. The plaintiffs are also seeking punitive damages in connection
with the remaining state law claims.
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.
COASTAL LEAGUE 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, Inc., alleging violations of the California Business and
Professions Code in connection with a 1988 study of the cooling water intake
system (1988 Study) at Diablo Canyon. The 1988 Study is also the subject of an
investigation by the California Attorney General, as described below. 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 October 13, 1995, the Coastal League also served PG&E with
a notice that it intends to file a citizens suit under the Federal Clean Water
Act alleging related violations of Diablo Canyon's water discharge permit.
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.,
violated the Federal Clean Water Act and the California Water Code in
connection with the 1988 Study of the cooling water intake system at Diablo
Canyon. The AG has issued a subpoena to PG&E seeking documents and has
interviewed PG&E employees in connection with this investigation. The AG has
not determined whether any violation of law has occurred and has not determined
whether it will initiate legal proceedings against PG&E arising out of this
investigation. If a legal action is initiated, PG&E could be subject to fines
and penalties which could exceed $100,000, but it cannot be determined with any
certainty at present whether a fine will ultimately be imposed or what the
amount of any such fine would be.
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.
54
<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 are as
follows:
<TABLE>
<CAPTION>
AGE AT
DECEMBER 31,
NAME 1995 POSITION EFFECTIVE DATE
---- ------------ -------- --------------
<S> <C> <C> <C>
S. T. Skinner........... 58 Chairman of the Board and Chief Executive Officer June 1, 1995
R. D. Glynn, Jr. ....... 53 President and Chief Operating Officer June 1, 1995
J. D. Shiffer........... 57 Executive Vice President November 1, 1991
R. J. Haywood........... 51 Senior Vice President and General Manager, December 21, 1994
Customer Energy Services
T. W. High.............. 48 Senior Vice President--Corporate Services June 1, 1995
J. F. Jenkins-Stark..... 44 Senior Vice President and General Manager, Gas Supply August 1, 1993
Business Unit
G. R. Smith............. 47 Senior Vice President and Chief Financial Officer June 1, 1995
B. R. Worthington....... 46 Senior Vice President and General Counsel June 1, 1995
J. Pfannenstiel......... 48 Vice President--Corporate Planning February 1, 1987
</TABLE>
All officers serve at the pleasure of the Board of Directors. All executive
officers have been employees of PG&E for the past five years. In addition to
their current positions, the executive officers had the following business
experience during that period:
<TABLE>
<CAPTION>
NAME POSITION PERIOD HELD OFFICE
---- -------- ------------------
<S> <C> <C>
S. T. Skinner....... President and Chief Executive July 1, 1994 to May 31, 1995
Officer
President and Chief Operating November 1, 1991 to June 30,
Officer 1994
Vice Chairman of the Board May 1, 1986 to October 31,
1991
J. D. Shiffer....... Senior Vice President and General February 1, 1990 to October
Manager, 31, 1991
Nuclear Power Generation
Business Unit
R. D. Glynn, Jr..... Executive Vice President July 1, 1994 to May 31, 1995
Senior Vice President and General January 1, 1994 to June 30,
Manager, 1994
Customer Energy Services
Business Unit
Senior Vice President and General November 1, 1991 to December
Manager, 31, 1993
Electric Supply Business Unit
Vice President--Power Generation January 1, 1988 to October
31, 1991
R. J. Haywood....... Vice President of Power System February 22, 1993 to
December 20, 1994
Vice President--Power Planning April 20, 1988 to February
and Contracts 21, 1993
T. W. High.......... Vice President and Assistant to July 1, 1994 to May 31, 1995
the Chief Executive Officer
Vice President and Assistant to November 1, 1991-June 30,
the Chairman of the Board 1994
Vice President and Corporate May 1, 1986 to October 31,
Secretary 1991
J. F. Jenkins-Stark. Vice President and Treasurer January 15, 1992 to July 31,
1993
Treasurer November 1, 1987 to January
14, 1992
G. R. Smith......... Vice President and Chief November 1, 1991 to May 31,
Financial Officer 1995
Vice President--Finance and Rates November 1, 1987 to October
31, 1991
B. R. Worthington... Vice President and General December 21, 1994 to May 31,
Counsel 1995
Chief Counsel--Corporate January 10, 1991-December
20, 1994
Attorney June 10, 1974-January 9,
1991
</TABLE>
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS.
Information responding to Item 5 is set forth on page 51 under the heading
"Quarterly Consolidated Financial Data" in PG&E's 1995 Annual Report to
Shareholders, which information is hereby incorporated by reference and filed
as part of Exhibit 13 to this report.
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 12 under the heading "Selected
Financial Data" in PG&E's 1995 Annual Report to Shareholders, which information
is hereby incorporated by reference and filed as part of Exhibit 13 to this
report.
55
<PAGE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS.
A discussion of the Company's results of operations and liquidity and capital
resources is set forth on pages 13 through 24 under the heading "Management's
Discussion and Analysis of Consolidated Results of Operations and Financial
Condition" in PG&E's 1995 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 PG&E's 1995 Annual Report to
Shareholders on page 52 and pages 25 through 51 under the headings "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," 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 page 55 in
Part I of this report. Other information responding to Item 10 is included on
pages 3 through 5 under the heading "Nominees for Director" in the 1996 Proxy
Statement and Prospectus relating to the 1996 Annual Meeting of Shareholders,
which information is hereby incorporated by reference.
ITEM 11. EXECUTIVE COMPENSATION.
Information responding to Item 11 is included on pages 7 through 8 under the
heading "Compensation of Directors" and on pages 35 through 43 under the
heading "Executive Compensation" in the 1996 Proxy Statement and Prospectus
relating to the 1996 Annual Meeting 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 8 through 9 and 44
under the headings "Security Ownership of Management" and "Principal
Shareholders" in the 1996 Proxy Statement and Prospectus relating to the 1996
Annual Meeting 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 8 under the heading
"Certain Relationships and Related Transactions" in the 1996 Proxy Statement
and Prospectus relating to the 1996 Annual Meeting of Shareholders, which
information is hereby incorporated by reference.
56
<PAGE>
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K.
(A) THE FOLLOWING DOCUMENTS ARE FILED AS A PART OF THIS REPORT:
1. The following consolidated financial statements, schedules of
consolidated segment information, supplemental information and
report of independent public accountants contained in the 1995
Annual Report to Shareholders, are incorporated by reference in this
report:
Statement of Consolidated Income for the Years Ended December 31,
1995, 1994 and 1993.
Consolidated Balance Sheet at December 31, 1995 and 1994.
Statement of Consolidated Cash Flows for the Years Ended December
31, 1995, 1994 and 1993.
Statement of Consolidated Common Stock Equity, Preferred Stock and
Preferred Securities for the Years Ended December 31, 1995, 1994
and 1993.
Statement of Consolidated Capitalization at December 31, 1995 and
1994.
Schedule of Consolidated Segment Information for the Years Ended
December 31, 1995, 1994 and 1993.
Notes to Consolidated Financial Statements.
Quarterly Consolidated Financial Data.
Report of Independent Public Accountants.
2. Report of Independent Public Accountants.
3. Consolidated financial statement schedules:
II -- Consolidated Valuation and Qualifying Accounts for the Years
Ended December 31, 1995, 1994 and 1993.
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 effective as of July 26, 1994
(Form 10-Q for quarter ended June 30, 1994 (File No. 1-2348), Exhibit
3.1).
3.2 By-Laws dated as of February 21, 1996.
4. First and Refunding Mortgage 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; Form 8-K
dated January 18, 1989 (File No. 1-2348), Exhibit 4.2).
</TABLE>
57
<PAGE>
<TABLE>
<C> <S>
10.1 Firm Transportation Service Agreement between the Company and
Pacific Gas Transmission Company dated October 26, 1993 (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
the Company and El Paso Natural Gas Company dated November 1, 1993
(Form 10-K for fiscal year 1993 (File No. 1-2348), Exhibit 10.5),
rate schedule FT-1, and general terms and conditions.
10.3 Diablo Canyon Settlement Agreement (Diablo Settlement) dated June
24, 1988 (Form 8-K dated June 27, 1988) (File No. 1-2348), Exhibit
10.1), Implementing Agreement dated July 15, 1988 (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 (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.
*10.4 Pacific Gas and Electric Company Deferred Compensation Plan for
Directors (Form 10-K for fiscal year 1992 (File No. 1-2348),
Exhibit 10.5).
*10.5 Pacific Gas and Electric Company Deferred Compensation Plan for
Officers (Form 10-K for fiscal year 1991 (File No. 1-2348),
Exhibit 10.6).
*10.6 Savings Fund Plan for Employees of Pacific Gas and Electric
Company applicable to non-union employees, as amended January 17,
1996, effective January 1, 1996.
*10.7 Short-Term Incentive Plan for Officers of Pacific Gas and Electric
Company, effective January 1, 1996.
*10.8 The Pacific Gas and Electric Company Retirement Plan applicable to
non-union employees, as amended October 18, 1995, effective
January 1, 1996.
*10.9 Pacific Gas and Electric Company Supplemental Executive Retirement
Plan, as amended through October 16, 1991 (Form 10-K for fiscal
year 1991 (File No. 1-2348), Exhibit 10.11).
*10.10 Pacific Gas and Electric Company Stock Option Plan, as amended and
restated effective as of January 1, 1996.
*10.11 Performance Unit Plan of Pacific Gas and Electric Company, as
amended and restated effective as of January 1, 1996.
*10.12 Pacific Gas and Electric Company Relocation Assistance Program for
Officers (Form 10-K for fiscal year 1989 (File No. 1-2348),
Exhibit 10.16).
*10.13 Pacific Gas and Electric Company Executive Flexible Perquisites
Program (Form 10-K) for fiscal year 1993 (File No. 1-2348),
Exhibit 10.16).
*10.14 PG&E Postretirement Life Insurance Plan (Form 10-K for fiscal year
1991 (File No. 1-2348), Exhibit 10.16).
*10.15 Pacific Gas and Electric Company Retirement Plan for Non-Employee
Directors (Form 10-K for fiscal year 1991 (File No. 1-2348),
Exhibit 10.18).
</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.
58
<PAGE>
<TABLE>
<C> <S>
*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 (Form 10-K for fiscal year 1991
(File No. 1-2348), Exhibit 10.19).
*10.17 Pacific Gas and Electric Company Long-Term Incentive Program, as
amended and restated effective as of January 1, 1996.
*10.18 Pacific Gas and Electric Company Restricted Stock Plan for Non-
Employee Directors, effective as of January 1, 1996.
11. Computation of Earnings Per Common Share (Form 8-K dated February
21, 1996 (File No. 1-2348), Exhibit 11).
12.1 Computation of Ratios of Earnings to Fixed Charges (Form 8-K dated
February 21, 1996 (File No. 1-2348), Exhibit 12.1).
12.2 Computation of Ratios of Earnings to Combined Fixed Charges and
Preferred Stock Dividends (Form 8-K dated February 21, 1996 (File
No. 1-2348), Exhibit 12.2).
13. 1995 Annual Report to Shareholders (portions of the 1995 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 1995 Annual Report to Shareholders is furnished
for the information of the Commission and is not deemed to be
"filed" herein).
21. Subsidiaries of the Company (not included because the Company's
subsidiaries, considered in the aggregate as a single subsidiary,
would not constitute a "significant subsidiary" under Rule 1-02(w)
of Regulation S-X as of the end of the year covered by this
report).
23. Consent of Arthur Andersen LLP.
24.1 Resolution of the Board of Directors authorizing the execution of
the Form 10-K.
24.2 Powers of Attorney.
27. Financial Data Schedule (Form 8-K dated February 21, 1996 (File
No. 1-2348), Exhibit 27).
99. Information required by Form 11-K with respect to the Savings Fund
Plan for Employees of Pacific Gas and Electric Company, as
permitted by Rule 15d-21.
</TABLE>
- --------
* Management contract or compensatory plan or arrangement required to be filed
as an exhibit to this report pursuant to Item 14(c) of Form 10-K.
The exhibits filed herewith are attached hereto (except as noted) and those
indicated above which are not filed herewith were previously filed with the
Commission 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 $.30 per page, which fee covers only the Company's
reasonable expenses in furnishing such exhibits.
59
<PAGE>
(B) REPORTS ON FORM 8-K
Reports on Form 8-K during the quarter ended December 31, 1995 and through
the date hereof:
1. October 4, 1995
Item 5. Other Events
-- Gas Accord
2. October 19, 1995
Item 5. Other Events
-- Performance Incentive Plan -- Year-to-Date Financial Results
-- Holding Company Formation
3. October 26, 1995
Item 5. Other Events
-- Diablo Canyon Outage
4. November 2, 1995
Item 5. Other Events
-- General Rate Case
5. November 20, 1995
Item 5. Other Events
-- Electric Industry Restructuring
6. December 22, 1995
Item 5. Other Events
-- California Public Utilities Commission Proceedings
--Electric Industry Restructuring
--1996 Rate Case Proceedings
--Storm Response Proceedings
--Gas Reasonableness -- Transwestern Capacity Costs
-- Legal Proceedings -- Antitrust Litigation
7. January 17, 1996
Item 5. Other Events
-- Performance Incentive Plan -- Year-to-Date Financial Results
-- Performance Incentive Plan -- 1996 Target
-- 1995 Consolidated Earnings (unaudited)
-- Common Stock Dividend
8. January 18, 1996
Item 5. Other Events
-- Performance Incentive Plan -- Year-to-Date Financial Results
-- Performance Incentive Plan -- 1996 Target
-- 1995 Consolidated Earnings (unaudited)
-- Common Stock Dividend
9. February 21, 1996
Item 7. Financial Statements, Pro Forma Financial Information and Exhibits
-- 1995 Financial Statements
-- Ratios of Earnings to Fixed Charges and Ratios of Earnings to Combined
Fixed Charges and Preferred Stock Dividends
60
<PAGE>
INDEMNIFICATION UNDERTAKING
For purposes of complying with the amendments to the rules governing Form S-8
(effective July 13, 1990) under the Securities Act of 1933, the undersigned
registrant hereby undertakes as follows, which undertaking shall be
incorporated by reference into the registrant's Registration Statement on Form
S-8 No. 33-23692 (filed August 12, 1988):
Insofar as indemnification for liabilities arising under the Securities
Act of 1933 may be permitted to directors, officers and controlling persons
of the registrant pursuant to the foregoing provisions, or otherwise, the
registrant has been advised that in the opinion of the Securities and
Exchange Commission such indemnification is against public policy as
expressed in the Act and is, therefore, unenforceable. In the event that a
claim for indemnification against such liabilities (other than the payment
by the registrant of expenses incurred or paid by a director, officer or
controlling person of the registrant in a successful defense of any action,
suit or proceeding) is asserted by such director, officer or controlling
person in connection with the securities being registered, the registrant
will, unless in the opinion of its counsel the matter has been settled by
controlling precedent, submit to a court of appropriate jurisdiction the
question whether such indemnification by it is against public policy as
expressed in the Act and will be governed by the final adjudication of such
issue.
61
<PAGE>
SIGNATURES
PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(D) OF THE SECURITIES
EXCHANGE ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED
ON ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED, IN THE CITY AND
COUNTY OF SAN FRANCISCO, ON THE 29TH DAY OF MARCH, 1996.
PACIFIC GAS AND ELECTRIC COMPANY
(Registrant)
GARY P. ENCINAS
By __________________________________
(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, Chief March 29, 1996
Executive Officer and Director
B. PRINCIPAL FINANCIAL
OFFICER AND PRINCIPAL
ACCOUNTING OFFICER
GORDON R. SMITH Senior Vice President and Chief March 29, 1996
Financial Officer
C. DIRECTORS
RICHARD A. CLARKE
H. M. CONGER
C. LEE COX
WILLIAM S. DAVILA
ROBERT D. GLYNN, JR.
DAVID M. LAWRENCE
RICHARD B. MADDEN
MARY S. METZ Directors March 29, 1996
REBECCA Q. MORGAN
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)
62
<PAGE>
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Shareholders and the Board of Directors
of Pacific Gas and Electric Company:
We have audited in accordance with generally accepted auditing standards, the
consolidated financial statements and the schedule of consolidated segment
information included in the Pacific Gas and Electric Company Annual Report to
Shareholders incorporated by reference in this Annual Report on Form 10-K and
have issued our report thereon dated February 12, 1996.
Our audits of the consolidated financial statements and the schedule of
consolidated segment information were made for the purpose of forming an
opinion on those statements taken as a whole. The supplemental 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 consolidated financial statements. The supplemental schedule has been
subjected to the auditing procedures applied in the audits of the basic
consolidated financial statements and the schedule of consolidated segment
information 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 and schedule of consolidated segment
information taken as a whole.
ARTHUR ANDERSEN LLP
San Francisco, California
February 12, 1996
63
<PAGE>
SCHEDULE II
PACIFIC GAS AND ELECTRIC COMPANY
SCHEDULE II -- CONSOLIDATED VALUATION AND
QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 1995, 1994 AND 1993
<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:
1995:
Reserve for impairment of
oil and gas properties.... $ 4,341 $ -- $ -- $ 4,341(1) $ 0
======== ======= ====== ======== =======
Reserve for deferred
project costs............. $ 25,800 $ -- $ -- $ 20,090(2) $ 5,710
======== ======= ====== ======== =======
Allowance for uncollectible
accounts.................. $ 29,769 $50,327 $ -- $ 44,576(3) $35,520
======== ======= ====== ======== =======
Reserve for land costs..... $ 5,960 $ -- $ -- $ 1,516(2) $ 4,444
======== ======= ====== ======== =======
1994:
Reserve for impairment of
oil and gas properties.... $ 7,924 $ 4,565 $ -- $ 8,148(1) $ 4,341
======== ======= ====== ======== =======
Reserve for deferred
project costs............. $ 18,689 $ 7,111 $ -- $ -- $25,800
======== ======= ====== ======== =======
Allowance for uncollectible
accounts.................. $ 23,647 $44,415 $ -- $ 38,293(3) $29,769
======== ======= ====== ======== =======
Reserve for land costs..... $ 6,154 $ -- $ -- $ 194(2) $ 5,960
======== ======= ====== ======== =======
1993:
Reserve for investment in
Alaska Natural Gas
Transportation System..... $152,517 $ -- $ -- $152,517(4) $ 0
======== ======= ====== ======== =======
Reserve for impairment of
oil and gas properties.... $ 10,417 $ 7,165 $ -- $ 9,658(1) $ 7,924
======== ======= ====== ======== =======
Reserve for deferred
project costs............. $ 9,207 $11,086 $ -- $ 1,604(2) $18,689
======== ======= ====== ======== =======
Allowance for uncollectible
accounts.................. $ 23,806 $30,187 $ -- $ 30,346(3) $23,647
======== ======= ====== ======== =======
Reserve for land costs..... $ 1,724 $ 4,749 $ -- $ 319(2) $ 6,154
======== ======= ====== ======== =======
</TABLE>
- --------
(1) Deductions consist principally of write-offs of expired leaseholds on
reserved property. Deduction in 1995 results from sale of oil and gas
properties.
(2) 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.
(3) Deductions consist principally of write-offs, net of collections of
receivables previously written off.
(4) The Company disposed of its investment in Alaska Natural Gas
Transportation System in January 1993.
64
<PAGE>
INDEX TO EXHIBITS
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION OF EXHIBITS
------- -----------------------
<C> <S>
3.1 Restated Articles of Incorporation effective as of July 26, 1994 (Form
10-Q for quarter ended June 30, 1994 (File No. 1-2348), Exhibit 3.1).
3.2 By-Laws dated as of February 21, 1996.
4. First and Refunding Mortgage 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; Form 8-K
dated January 18, 1989 (File No. 1-2348), Exhibit 4.2).
10.1 Firm Transportation Service Agreement between the Company and Pacific
Gas Transmission Company dated October 26, 1993 (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 the
Company and El Paso Natural Gas Company dated November 1, 1993 (Form
10-K for fiscal year 1993 (File No. 1-2348), Exhibit 10.5), rate
schedule FT-1, and general terms and conditions.
10.3 Diablo Canyon Settlement Agreement (Diablo Settlement) dated June 24,
1988 (Form 8-K dated June 27, 1988) (File No. 1-2348), Exhibit 10.1),
Implementing Agreement dated July 15, 1988 (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 (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.
*10.4 Pacific Gas and Electric Company Deferred Compensation Plan for
Directors (Form 10-K for fiscal year 1992 (File No. 1-2348), Exhibit
10.5).
*10.5 Pacific Gas and Electric Company Deferred Compensation Plan for
Officers (Form 10-K for fiscal year 1991 (File No. 1-2348), Exhibit
10.6).
*10.6 Savings Fund Plan for Employees of Pacific Gas and Electric Company
applicable to non-union employees, as amended January 17, 1996,
effective January 1, 1996.
*10.7 Short-Term Incentive Plan for Officers of Pacific Gas and Electric
Company, effective January 1, 1996.
*10.8 The Pacific Gas and Electric Company Retirement Plan applicable to
non-union employees, as amended October 18, 1995, effective January 1,
1996.
*10.9 Pacific Gas and Electric Company Supplemental Executive Retirement
Plan, as amended through October 16, 1991 (Form 10-K for fiscal year
1991 (File No. 1-2348), Exhibit 10.11).
*10.10 Pacific Gas and Electric Company Stock Option Plan, as amended and
restated effective as of January 1, 1996.
*10.11 Performance Unit Plan of Pacific Gas and Electric Company, as amended
and restated effective as of January 1, 1996.
*10.12 Pacific Gas and Electric Company Relocation Assistance Program for
Officers (Form 10-K for fiscal year 1989 (File No. 1-2348), Exhibit
10.16).
</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>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION OF EXHIBITS
------- -----------------------
<C> <S>
*10.13 Pacific Gas and Electric Company Executive Flexible Perquisites
Program (Form 10-K) for fiscal year 1993 (File No. 1-2348), Exhibit
10.16).
*10.14 PG&E Postretirement Life Insurance Plan (Form 10-K for fiscal year
1991 (File No. 1-2348), Exhibit 10.16).
*10.15 Pacific Gas and Electric Company Retirement Plan for Non-Employee
Directors (Form 10-K for fiscal year 1991 (File No. 1-2348), Exhibit
10.18).
*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 (Form 10-K for fiscal year 1991 (File No.
1-2348), Exhibit 10.19).
*10.17 Pacific Gas and Electric Company Long-Term Incentive Program, as
amended and restated effective as of January 1, 1996.
*10.18 Pacific Gas and Electric Company Restricted Stock Plan for Non-
Employee Directors, effective as of January 1, 1996.
11. Computation of Earnings Per Common Share (Form 8-K dated February 21,
1996 (File No. 1-2348), Exhibit 11).
12.1 Computation of Ratios of Earnings to Fixed Charges (Form 8-K dated
February 21, 1996 (File No. 1-2348), Exhibit 12.1).
12.2 Computation of Ratios of Earnings to Combined Fixed Charges and
Preferred Stock Dividends (Form 8-K dated February 21, 1996 (File No.
1-2348), Exhibit 12.2).
13. 1995 Annual Report to Shareholders (portions of the 1995 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 1995 Annual Report to Shareholders is
furnished for the information of the Commission and is not deemed to
be "filed" herein).
21. Subsidiaries of the Company (not included because the Company's
subsidiaries, considered in the aggregate as a single subsidiary,
would not constitute a "significant subsidiary" under Rule 1-02(w) of
Regulation S-X as of the end of the year covered by this report).
23. Consent of Arthur Andersen LLP.
24.1 Resolution of the Board of Directors authorizing the execution of the
Form 10-K.
24.2 Powers of Attorney.
27. Financial Data Schedule (Form 8-K dated February 21, 1996 (File No. 1-
2348), Exhibit 27).
99. Information required by Form 11-K with respect to the Savings Fund
Plan for Employees of Pacific Gas and Electric Company, as permitted
by Rule 15d-21.
</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 $.30 per page, which fee covers only the Company's
reasonable expenses in furnishing such exhibits.
- --------
* 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>
BYLAWS
OF
PACIFIC GAS AND ELECTRIC COMPANY
AS AMENDED AS OF FEBRUARY 21, 1996
----------------------------------
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.
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.
[1]
<PAGE>
4. ATTENDANCE AT MEETINGS. At any meeting of the shareholders, each
holder of record of stock entitled to vote thereat may attend in person or may
designate an agent or a reasonable number of agents, not to exceed three to
attend the meeting and cast votes for his shares. The authority of agents must
be evidenced by a written proxy signed by the shareholder designating the agents
authorized to attend the meeting and be delivered to the Secretary of the
Corporation prior to the commencement of the meeting.
5. NO CUMULATIVE VOTING. No shareholder of the Corporation shall be
entitled to cumulate his or her voting power.
ARTICLE II.
DIRECTORS.
1. NUMBER. The Board of Directors shall consist of fifteen (15)
directors.
2. POWERS. The Board of Directors shall exercise all the powers of the
Corporation except those which are by law, or by the Articles of Incorporation
of this Corporation, or by the Bylaws conferred upon or reserved to the
shareholders.
3. EXECUTIVE COMMITTEE. There shall be an Executive Committee of the
Board of Directors consisting of the Chairman of the Committee, the Chairman of
the Board, if these offices be filled, the President, and four Directors who are
not officers of the Corporation. The members of the Committee shall be elected,
and may at any time be removed, by a two-thirds vote of the whole Board.
The Executive Committee, subject to the provisions of law, may exercise any
of the powers and perform any of the duties of the Board of Directors; but the
Board may by an affirmative vote of a majority of its members withdraw or limit
any of the powers of the Executive Committee.
The Executive Committee, by a vote of a majority of its members, shall fix
its own time and place of meeting, and shall prescribe its own rules of
procedure. A quorum of the Committee for the transaction of business shall
consist of three members.
4. TIME AND PLACE OF DIRECTORS' MEETINGS. Regular meetings of the Board
of Directors shall be held on such days and at such times and at such locations
as shall be fixed by resolution of the Board, or designated by the Chairman of
the Board or, in his absence, the Vice Chairman of the Board, or the President
of the Corporation and contained in the notice of any such meeting. Notice of
meetings shall be delivered personally or sent by mail or telegram at least
seven days in advance.
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.
[2]
<PAGE>
7. ACTION BY CONSENT. Any action required or permitted to be taken by the
Board of Directors may be taken without a meeting if all Directors individually
or collectively consent in writing to such action. Such written consent or
consents shall be filed with the minutes of the proceedings of the Board of
Directors.
8. MEETINGS BY CONFERENCE TELEPHONE. Any meeting, regular or special, of
the Board of Directors or of any committee of the Board of Directors, may be
held by conference telephone or similar communication equipment, provided that
all Directors participating in the meeting can hear one another.
ARTICLE III.
OFFICERS.
1. OFFICERS. The officers of the Corporation shall be a Chairman of the
Board, a Vice Chairman of the Board, a Chairman of the Executive Committee
(whenever the Board of Directors in its discretion fills these offices), a
President, one or more Vice Presidents, a Secretary and one or more Assistant
Secretaries, a Treasurer and one or more Assistant Treasurers, a General
Counsel, a General Attorney (whenever the Board of Directors in its discretion
fills this office), and a Controller, all of whom shall be elected by the Board
of Directors. The Chairman of the Board, the Vice Chairman of the Board, the
Chairman of the Executive Committee, and the President shall be members of the
Board of Directors.
2. CHAIRMAN OF THE BOARD. The Chairman of the Board, if that office be
filled, shall preside at all meetings of the shareholders, of the Directors, and
of the Executive Committee in the absence of the Chairman of that Committee. He
shall be the chief executive officer of the Corporation if so designated by the
Board of Directors. He shall have such duties and responsibilities as may be
prescribed by the Board of Directors or the Bylaws. The Chairman of the Board
shall have authority to sign on behalf of the Corporation agreements and
instruments of every character, and in the absence or disability of the
President, shall exercise his duties and responsibilities.
3. VICE CHAIRMAN OF THE BOARD. The Vice Chairman of the Board, if that
office be filled, shall have such duties and responsibilities as may be
prescribed by the Board of Directors, the Chairman of the Board, or the Bylaws.
He shall be the chief executive officer of the Corporation if so designated by
the Board of Directors. In the absence of the Chairman of the Board, he shall
preside at all meetings of the Board of Directors and of the shareholders; and,
in the absence of the Chairman of the Executive Committee and the Chairman of
the 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.
[3]
<PAGE>
5. PRESIDENT. The President shall have such duties and responsibilities as
may be prescribed by the Board of Directors, the Chairman of the Board, or the
Bylaws. He shall be the chief executive officer of the Corporation if so
designated by the Board of Directors. If there be no Chairman of the Board, the
President shall also exercise the duties and responsibilities of that office.
The President shall have authority to sign on behalf of the Corporation
agreements and instruments of every character.
6. VICE PRESIDENTS. Each Vice President shall have such duties and
responsibilities as may be prescribed by the Board of Directors, the Chairman of
the Board, the Vice Chairman of the Board, the President, or the Bylaws. Each
Vice President's authority to sign agreements and instruments on behalf of the
Corporation shall be as prescribed by the Board of Directors. The Board of
Directors, the Chairman of the Board, the Vice Chairman of the Board, or the
President may confer a special title upon any Vice President.
7. SECRETARY. The Secretary shall attend all meetings of the Board of
Directors and the Executive Committee, and all meetings of the shareholders, and
he shall record the minutes of all proceedings in books to be kept for that
purpose. He shall be responsible for maintaining a proper share register and
stock transfer books for all classes of shares issued by the Corporation. He
shall give, or cause to be given, all notices required either by law or the
Bylaws. He shall keep the seal of the Corporation in safe custody, and shall
affix the seal of the Corporation to any instrument requiring it and shall
attest the same by his signature.
The Secretary shall have such other duties as may be prescribed by the Board
of Directors, the Chairman of the Board, the Vice Chairman of the Board, the
President, or the Bylaws.
The Assistant Secretaries shall perform such duties as may be assigned from
time to time by the Board of Directors, the Chairman of the Board, the Vice
Chairman of the Board, the President, or the Secretary. In the absence or
disability of the Secretary, his duties shall be performed by an Assistant
Secretary.
8. TREASURER. The Treasurer shall have custody of all moneys and funds of
the Corporation, and shall cause to be kept full and accurate records of
receipts and disbursements of the Corporation. He shall deposit all moneys and
other valuables of the Corporation in the name and to the credit of the
Corporation in such depositaries as may be designated by the Board of Directors
or any employee of the Corporation designated by the Board of Directors. He
shall disburse such funds of the Corporation as have been duly approved for
disbursement.
The Treasurer shall perform such other duties as may from time to time be
prescribed by the Board of Directors, the Chairman of the Board, the Vice
Chairman of the Board, the President, or the Bylaws.
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.
[4]
<PAGE>
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.
ARTICLE IV.
MISCELLANEOUS.
1. RECORD DATE. The Board of Directors may fix a time in the future as a
record date for the determination of the shareholders entitled to notice of and
to vote at any meeting of shareholders, or entitled to receive any dividend or
distribution, or allotment of rights, or to exercise rights in respect to any
change, conversion, or exchange of shares. The record date so fixed shall be
not more than sixty nor less than ten days prior to the date of such meeting nor
more than sixty days prior to any other action for the purposes for which it is
so fixed. When a record date is so fixed, only shareholders of record on that
date are entitled to notice of and to vote at the meeting, or entitled to
receive any dividend or distribution, or allotment of rights, or to exercise the
rights, as the case may be.
2. TRANSFERS OF STOCK. Upon surrender to the Secretary or Transfer Agent
of the Corporation of a certificate for shares duly endorsed or accompanied by
proper evidence of succession, assignment, or authority to transfer, and payment
of transfer taxes, the Corporation shall issue a new certificate to the person
entitled thereto, cancel the old certificate, and record 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.
[5]
<PAGE>
4. EMPLOYEE'S STOCK PURCHASE PLAN. Subject to any limitation contained in
the Articles of Incorporation, the Board of Directors may in it discretion, from
time to time, authorize the issue and sale of shares of capital stock of this
Corporation to employees, pursuant to an employee's stock purchase plan, for
such consideration as the Board shall determine to be reasonable. Such plan may
provide for payment for such shares by installments over a period of time fixed
by the Board. In any
such plan, the Board may provide for interest on any installment payments, and
that an employee may cancel his agreement to purchase all or part of the shares
thereunder. The Board may fix such other terms and conditions for any such plan
as it shall deem, in its discretion, to be in the best interests of this
Corporation. Any such plan may include employees of: This Corporation's
subsidiaries and affiliates; Pacific Service Employees Association; Pacific
Service Federal Credit Union; and such other associated organizations as may be
approved by the Board.
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 First Revised Sheet No. 12
First Revised Volume No. 1-A Superseding
Original Sheet No. 12
- --------------------------------------------------------------------------------
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,
applicable Reservation Surcharge, the Firm Transportation Charge and
other applicable surcharges for the quantities of natural gas delivered.
The rate(s) and the Maximum Daily Quantity 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: P.G. Rosput, Senior Vice President
Issued on: JULY 29, 1994 Effective: SEPTEMBER 01, 1994
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff First Revised Sheet No. 13
First Revised Volume No. 1-A Superseding
Original Sheet No. 13
- --------------------------------------------------------------------------------
RATE SCHEDULE FTS-1
FIRM TRANSPORTATION SERVICE
(Continued)
3.RATES (Continued)
3.1 Reservation Charge
The monthly Reservation Charge shall be the currently effective
rate times the distance, in pipeline miles, from the point(s) of
receipt to the point(s) of delivery times the Shipper's Maximum
Daily Quantity delivered.
3.2 Reservation Surcharge
Shippers converting to firm transportation under Rate Schedule FTS-
1 from Rate Schedules T-2 or T-3 of PGT's Second Revised Volume No.
1 tariff shall pay a Reservation Surcharge. The Reservation
Surcharge shall be calculated in the following manner: The
currently effective T-2 or T-3 Reservation Surcharge Rate times the
distance, in pipeline miles, from the point(s) of receipt to the
point(s) of delivery times the Shipper's Maximum Daily Quantity
delivered. The Reservation Surcharge Rates are stated on the
Statement of Effective Rates and Charges of PGT's First Revised
Volume No. 1-A tariff.
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.
(Continued)
- --------------------------------------------------------------------------------
Issued by: P.G. Rosput, Senior Vice President
Issued on: JULY 29, 1994 Effective: SEPTEMBER 01, 1994
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff First Revised Sheet No. 14
First Revised Volume No. 1-A Superseding
Original Sheet No. 14
- --------------------------------------------------------------------------------
RATE SCHEDULE FTS-1
FIRM TRANSPORTATION SERVICE
(Continued)
3. RATES (Continued)
3.3 Firm Transportation Charge
The monthly Firm Transportation Charge shall be the product of the
following:
(a) The quantities of gas (excluding Authorized Overruns)
delivered during the month (MMBtu);
(b) An amount no less than the Minimum Delivery Rate, nor greater
than the Maximum Delivery Rate set forth in the Statement of
Effective Rates and Charges for Transportation of Natural Gas
in this FERC Gas Tariff First Revised Volume No. 1-A; and
(c) The distance, in pipeline miles, from the point(s) of receipt
to the point(s) of delivery.
3.4 Delivery Rate Surcharge
Shippers converting from Rate Schedules T-2 or T-3 of PGT's Second
Revised Volume No. 1 tariff shall receive a credit calculated as
the product of the applicable Delivery Rate Surcharge, 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. The Delivery Rate Surcharges are stated on the Statement
of Effective Rates and Charges of PGT's First Revised Volume No. 1-
A Tariff.
3.5 Shipper shall pay the Maximum Monthly Reservation Charge,
applicable Reservation Surcharge, and the Maximum Delivery Rate for
service under this rate schedule unless PGT offers to discount the
Monthly Reservation Charge, Reservation Surcharge or the Delivery
Rate or all to Shipper under this rate schedule. If PGT elects to
discount the Monthly Reservation Charge, Reservation Surcharge or
the Delivery Rate or all, 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 Monthly Reservation Charge, the Minimum Delivery Rate, and
applicable GSR and ACA Surcharges.
(Continued)
- --------------------------------------------------------------------------------
Issued by: P.G. Rosput, Senior Vice President
Issued on: JULY 29, 1994 Effective: SEPTEMBER 01, 1994
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff Substitute 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)
3.6 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.
This surcharge shall not apply to those Shippers converting to firm
transportation under this rate schedule from Rate Schedules T-2 or
T-3 of PGT's Second Revised Volume No. 1 and which are Supporting
Parties to the FERC-approved settlement in Docket No. RS92-46-000
for as long as these services are charged incremental rates. T-1
Shippers are also exempt from this surcharge, with the exception of
Washington Natural Gas Company, per the provisions of Paragraph
30.5(d).
3.7 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.
3.8 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 select one of three payment plans as shown on
the Statement of Rates and Charges for Transportation of Natural
Gas.
(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. 16
First Revised Volume No. 1-A
- --------------------------------------------------------------------------------
RATE SCHEDULE FTS-1
FIRM TRANSPORTATION SERVICE
(Continued)
3. RATES (Continued)
3.9 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 the rates 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. The
rates to be paid shall be the sum of the Reservation
Charge, any applicable Reservation Surcharge and GSR
Transition Cost Surcharge, Delivery Rate 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.
- --------------------------------------------------------------------------------
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. 16A
First Revised Volume No. 1-A Superseding
Original Sheet No. 16A
- --------------------------------------------------------------------------------
RATE SCHEDULE FTS-1
FIRM TRANSPORTATION SERVICE
(Continued)
3.10 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: P.G. Rosput, Senior Vice President
Issued on: FEBRUARY 17, 1995 Effective: MARCH 20, 1995
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff First Revised Sheet No. 16B
First Revised Volume No. 1-A Superseding
Original Sheet No. 16B
- --------------------------------------------------------------------------------
RATE SCHEDULE FTS -1
FIRM TRANSPORTATION SERVICE
(Continued)
3.11 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: P.G. Rosput, Senior Vice President
Issued on: FEBRUARY 17, 1995 Effective: MARCH 20, 1995
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff Substitute Second Revised Sheet No. 17
First Revised Volume No. 1-A Superseding
First Revised Sheet No. 17
- --------------------------------------------------------------------------------
RATE SCHEDULE FTS-1
FIRM TRANSPORTATION SERVICE
(Continued)
4. AUTHORIZED OVERRUNS
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 affect any Shipper's rights on the PGT system.
Authorized Overruns are interruptible in nature. The rate charged shall
be the rates and charges as specified in the current Statement of
Effective Rates and Charges for Transportation of Natural Gas of this
First Revised Volume No. 1-A, and such Authorized Overruns shall be
subject to the priority of service provisions of Paragraph 19 of the
Transportation General Terms and Conditions. Revenues derived from
Authorized Overruns shall be deemed to be interruptible revenues and
credited in accordance with Paragraph 35 of the Transportation General
Terms and Conditions.
5. 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.
6. 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: P.G. Rosput, Senior Vice President
Issued on: JULY 29, 1994 Effective: SEPTEMBER 01, 1994
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff Sixth Revised Sheet No. 51
First Revised Volume No. 1-A Superseding
Fifth 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 Notice of Changes in Operating Conditions 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 Former Buyer's Obligation for Unrecovered
Account No. 191 Amounts 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 Crediting of Interruptible Transportation Revenues 137
35A Crediting of Interruptible Transportation Revenues for
Extensions 138A
36 Capacity Relinquishment 139
37 Adjustment Mechanism for Fuel, Line Loss and Other
Unaccounted For Gas Percentages 140
38 Crediting of Parking and Authorized Imbalance Revenues 142
39 Sales of Excess Gas 143
(Continued)
</TABLE>
- --------------------------------------------------------------------------------
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 First Revised Sheet No. 52
First Revised Volume No. 1-A Superseding
Original 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.
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 degrees) 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 degrees)
Fahrenheit, saturated with water vapor, and at an absolute pressure
equivalent to thirty (30) inches of mercury at thirty-two degrees
(32 degrees) Fahrenheit.
1.10 The term "psig" shall mean pounds per square inch gauge.
(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. 53
First Revised Volume No. 1-A
- --------------------------------------------------------------------------------
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 The term "Agent" as defined in connection with PGT's Market Center
Service is any party which contracts with PGT for Market Center
Service and which itself is not a Shipper on PGT.
1.17 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.
1.18 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.
1.19 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: 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. 54
First Revised Volume No. 1-A Superseding
Original Sheet No. 54
- --------------------------------------------------------------------------------
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
1. DEFINITIONS (Continued)
1.20 Bid Reconciliation Period: The period of time subsequent to the Bid
Period during which bids are evaluated by PGT.
1.21 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.
(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. 55
First Revised Volume No. 1-A Superseding
Original 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 to Shippers which are interstate pipelines
and which include in their rates a charge for RD&D by 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: 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 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
Commisssion, 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 degrees) 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 degrees)
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 First Revised Sheet No. 57
First Revised Volume No. 1-A Superseding
Original 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: 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. 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: NOVEMBR 01, 1993
Issued to comply with order of the Federal Energy Regulatory
Commisssion, 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
Commisssion, 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
ieentified 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 Substitute Second Revised Sheet No. 71
First Revised Volume No. 1-A Superseding
First 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 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: 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 First Revised Sheet No. 72
First Revised Volume No. 1-A Superseding
Original 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 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: 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. 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 Original 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 First Revised Sheet No. 81
First Revised Volume No. 1-A Superseding
Substitute Original 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: 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. 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
Commssion, Docket No. RP94-145-000 , dated AUGUST 03, 1994
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff First Revised Sheet No. 81C
First Revised Volume No. 1-A Superseding
Original 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 domination increases by interruptible
Shippers shall not bump those interruptible Shippers' volumes already
confirmed for that gas day.
(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. 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 ocmply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-46-000, et al. , date 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 First Revised Sheet No. 87
First Revised Volume No. 1-A Superseding
Original 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 First Revised Sheet No. 88
First Revised Volume No. 1-A Superseding
Original 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,
Agents other than the pipeline Shippers, trade gas quantities without
actively shipping the gas either upstream or downstream of the Market
Center.
Agents 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 Agent's nomination for upstream
supply and downstream delivery must match the corresponding upstream
Shipper nomination and the downstream customer request.
(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. 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 First Revised 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 of its capacity for the
remainder of the term of its contract and extinguish its
contractual obligations to PGT provided that: 1) the
Replacement Shipper for this capacity is creditworthy pursuant
to PGT's credit standards; 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; and 3) the release is for all
of the Releasing Shipper's capacity. 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. RM95-5-000 , dated MAY 31, 1995
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff
First Revised Volume No. 1-A First Revised Sheet No. 91
Superseding
Original 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.
(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: 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. 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 First Revised 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.
(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: 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. 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 O1, 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., date 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 N0.99
First Revised Volume N0. 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 N0. 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 N0. 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 Original Sheet No. 109
First Revised Volume No. 1-A
- --------------------------------------------------------------------------------
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 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,
applicable Gas Supply Restructuring Surcharge, delivery rate,
GRI and ACA charges and any applicable interest and penalties
billed to the Replacement Shipper.
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: P.G. Rosput, Senior Vice President
Issued on: AUGUST 02, 1993 Effective: NOVEMBER 01, 199:
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. 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)
CAPACITY RELEASE TIMELESS
STANDARD RELEASE
(GREATER THAN OR EQUAL TO ONE DAY)
- --------------------------------------------------------------------------------
RELEASE/(1)/ BID PERIOD/(2)/ RELEASE AWARDED NOMINATION/(3)/ GAS FLOWS
POSTED ENDS @ @ 2:00p.m by 10:00 a.m. @ 7:00 a.m.
by 12:00 P.M 2:00 p.m
- --------------------------------------------------------------------------------
5 4 2 1
BUSINESS DAYS BEFORE RELEASE BEGINS
Notes:
(1) Releases which have special terms
or conditions, or special bid
criteria will require two extra
business days notice.
(2) Minimum bid period indicated.
Shippers may extend this period
(3) Nomination must be made not later
than one calendar day before gas
flows.
(4) All times are Pacific Time.
- --------------------------------------------------------------------------------
Issued by: P.G. Rosput, Senior Vice President
Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994
<PAGE>
Pacific Gas Transmission Company
FIRC Gas Tariff First Revised Sheet No. 112
First Revised Volume No. 1-A Superseding
Original Sheet No. 112
- --------------------------------------------------------------------------------
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
28. CAPACITY RELEASE (Continued)
CAPACITY RELEASE TIMELINES
RAPID REALEASE
(EQUAL TO OR LESS THAN ONE MONTH)
- --------------------------------------------------------------------------------
RELEASE BID PERIOD(1) RELEASE AWARDED NOMINATION(2) GAS FLOWS
POSTED ENDS @ @ 2:00 p.m. by 10:00 a.m. @ 7:00 a.m.
by 12:00 p.m. 2:00 p.m.
- --------------------------------------------------------------------------------
2 1
BUSINESS DAYS BEFORE RELEASE BEGINS
Notes:
(1) Minimum bid period indicated. Shippers may extend this period.
(2) Nomination must be made no later later than one calendar day before
gas flows.
(3) All times are Pacific Time.
(4) Released under Options 1 or 2 only no special terms or conditions.
- ------------------------------------------------------------------------------
ISSUED BY: P.G. ROSPUT, SENIOR VICE PRESIDENT
ISSUED ON: FEBRUARY 29, 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)
CAPACITY RELEASE TIMELINES
PRE-ARRANGED DEAL - A
(LESS THAN OR EQUAL TO THIRTY-ONE DAYS)
- ------------------------------------------------------------------------------
DEAL INFO TO PGT NOMINATION(1) GAS FLOWS RELEASE
by 12:00 p.m. by 10:00 a.m. @ 7:00 a.m. POSTED
PGT VERIFIES INFO by 12:00 p.m.
- ------------------------------------------------------------------------------
-2 -1 1 2
BUSINESS DAYS BEFORE RELEASE BEGINS
Notes:
(1) Nomination must be made no later than one calendar day before gas
flows.
(2) All times are Pacific Time.
(3) No bidding required, deals posted for informational purposes only.
- --------------------------------------------------------------------------------
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 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)
CAPACITY RELEASE TIMELINES
PRE-ARRANGED DEAL-B
(EQUAL TO OR GREATER THAN THIRTY-ONE DAYS AT HIGHEST VALUE BID)
- ------------------------------------------------------------------------------
RELEASE POSTED/1/ NOMINATION/2/ GAS FLOWS
by 12:00 p.m. by 10:00 a.m. @ 7:00 a.m.
- ------------------------------------------------------------------------------
2 1
BUSINESS DAYS BEFORE RELEASE BEGINS
Notes:
(1) No bidding required.
(2) Nomination must be made no later than one calendar day before gas
flows.
(3) All times are Pacific Time.
- --------------------------------------------------------------------------------
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)
CAPACITY RELEASE TIMELINES
PRE-ARRANGED DEAL - C
(GREATER THAN OR EQUAL TO ONE DAY)
- ------------------------------------------------------------------------------
RELEASE/1/ BID PERIOD/2/ CLOSE OF MATCH PERIOD NOMINATION GAS FLOWS
POSTED ENDS @ RELEASE AWARDED by 10:00 a.m. @ 7:00 a.m.
by 12:00 p.m. 2:00 p.m. @ 2:00 p.m.
- ------------------------------------------------------------------------------
6 5 2 1
BUSINESS DAYS BEFORE RELEASE BEGINS
Notes:
(1) Releases which have special terms or conditions or special bid
criteria will require two extra business days notice.
(2) Minimum bid period indicated. Shippers may extend this period.
(3) Nomination must be made no later than one calendar day before gas
flows.
(4) All times are Pacific Time.
- --------------------------------------------------------------------------------
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 First Revised 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 Substitute First Revised Sheet No. 127
First Revised Volume No. 1-A Superseding
Original Sheet No. 127
- --------------------------------------------------------------------------------
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
31. FORMER BUYER'S OBLIGATION FOR UNRECOVERED ACCOUNT NO. 191 AMOUNTS
31.1 Purpose
This Paragraph 31 establishes the disposition of PGT's FERC Account
No. 191 as it exists on the day preceding the effectiveness of
PGT's Compliance Filing in Docket No. RS92-46-000.
31.2 Disposition of Account No. 191 Amounts
Upon the effectiveness of PGT's Compliance Filing in Docket No.
RS92-46, PGT shall be permitted to direct bill to Pacific Gas and
Electric Company (PG&E): (1) the total unrecovered amounts
remaining in PGT's FERC Account No. 191; and (2) direct bill all
prior period billing adjustments which PGT shall become obligated
to pay, if such prior period adjustments arise from services
provided or Gas purchased prior to the effectiveness of this
Paragraph 31. Upon the effectiveness of this Paragraph 31, the
unrecovered Account No. 191 Deferred Account Balance shall be
adjusted to include a final reconciliation of amounts for exchange
transactions and transportation imbalances recorded in Account No.
806. If the balance of PGT's FERC Account No. 191 shall be a credit
balance, or PGT later receives refunds from its suppliers for
services provided prior to the effectiveness of this Paragraph 31,
PGT shall refund such balance or refunds to PG&E.
31.3 Amount of Direct Bills and Refund
The amount of the Direct Bill and Refunds to PG&E shall consist of
a prior Period Adjustment Component, as described in Paragraph 31.4
hereof. Each component shall reflect demand and commodity charges,
as may be appropriate.
31.4 Calculation of Prior Period Adjustment Component
(a) The Prior Period Adjustment Component of PG&E's Direct Bill
shall be computed by adding the commodity and demand portions
of each prior period adjustment which has been charged to PGT
within nine months of the effective date of this Paragraph 31
or refunded to PGT at any time, as the case may be and which
have not been reflected in PGT's deferred account prior to
application of this Paragraph 31.
(Continued)
- --------------------------------------------------------------------------------
Issued by: P.G. Rosput, Senior Vice President
Issued on: MAY 23, 1994 Effective: NOVEMBER 01, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RF94-106-000 , dated FEBRUARY 01, 1994
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff Original Sheet No. 128
First Revised Volume No. 1-A
- --------------------------------------------------------------------------------
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
31. FORMER BUYER'S OBLIGATION FOR UNRECOVERED ACCOUNT NO. 191 AMOUNTS
(Continued)
31.4 Calculation of Prior Period Adjustment Component (Continued)
(b) Carrying charges on all such amounts shall be calculated using
the methods specified in Section 154.67 of the Commission's
regulations.
31.5 Nature of Obligations
(a) The entire amount of PG&E's obligation to PGT as described in
this Paragraph 31, including its subsections, shall be deemed
to be due on the day prior to the date this Paragraph becomes
effective.
(b) PGT shall invoice PG&E for the Direct Bill component hereunder
on or after the tenth day of the month following the
effectiveness of this Paragraph 31. The entire amount of
PG&E's unrecovered Account No. 191 Direct Bill Amount shall be
payable ten (10) days thereafter. Should PG&E fail to pay any
amount which shall become due hereunder interest thereon shall
accrue at the rate computed using the factors specified in
Section 154.67 of the Commission's regulations, until such
time as the full amount due has been paid or collected.
(c) PG&E shall have the option, in lieu of a lump sum payment of
the total Direct Bill for its obligation for unrecovered
Account No. 191 amounts, of paying twelve (12) consecutive
monthly payments equal to 1/12th of such amount. Carrying
charges on the total unrecovered Account No. 191 Direct Bill
amount shall commence on the effective date of this Paragraph
31 and shall be calculated and included on each monthly
invoice to the extent PG&E elects the twelve (12) month
payment option. Notwithstanding such election, PG&E may, at
any time, pay the entire amount of its unpaid share of the
unrecovered Account No. 191 Direct Bill amount to PGT, with no
further obligation for carrying charges.
(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. 129
First Revised Volume No. 1-A Superseding
Original Sheet No. 129
- --------------------------------------------------------------------------------
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
31. FORMER BUYER'S OBLIGATION FOR UNRECOVERED ACCOUNT NO. 191 AMOUNTS
(Continued)
31.5 Nature of Obligations (Continued)
(d) The Prior Period Adjustment component shall be filed six (6)
and twelve (12) months after the effective date of this
Paragraph 31. Additional unrecovered Account No. 191 amounts
will be direct billed in accordance with Paragraph 31.5(b),
and refunds of Account No. 191 amounts will be paid by PGT to
PG&E after approval of the Commission. Prior Period
Adjustments which are refunded by PG&E thereafter shall be
refunded to PG&E after Commission approval.
(e) Carrying charges on unpaid unrecovered Account No. 191 Direct
Bill amounts in the event PG&E elects to extend its payments
in accordance with Paragraph 31.5(c) for the Prior Period
component shall be calculated using the methods specified in
Section 154.67 of the Commission's regulations.
(f) PGT will provide an accounting of the costs involved in the
closeout of Account No. 191, and will provide any refund to
PG&E within 60 days after the effective date of the tariff
provisions submitted by PGT at Docket No. RS92-46-000 and, if
necessary, subsequent adjustments will be refunded to or
collected from PG&E within 60 days of these adjustments.
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: P.G. Rosput, Senior Vice President
Issued on: FEBRUARY 10, 1994 Effective: NOVEMBER 01, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RP94-106-000 , dated FEBRUARY 01, 1994
<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 First Revised Sheet No. 132
First Revised Volume No. 1-A Superseding
Substitute Original 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) Buy-Sell Transactions in California
(j) Offers to Purchase Capacity
(k) Procedures for Filing Complaints
(l) E-mail to Other Shippers/PGT System Administrator
(m) EBB Mailbox
(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. 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 (including: (1) any assignment by
PGT of any portion of its international contract if PG&E
reduces its firm sales rights and (2) the posting of
notices of conversion)
(c) Nominations
(1) Submit Nominations to PGT Gas Control
(2) Review Confirmation
(3) E-mail to Gas Control
(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. 134
First Revised Volume No. 1-A
- --------------------------------------------------------------------------------
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
(i) Buy-Sell Transactions in California
PGT will provide the following information:
(1) Rate Schedule Under Which Buy/Sell Transaction Is
Conducted
(2) Name of End User
(3) Maximum Daily Amount To Be Purchased and Transported
(4) Receipt and Delivery Points
(5) Term of Service
(6) Other Terms and Conditions
(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. 135
First Revised Volume No. 1-A
- --------------------------------------------------------------------------------
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
34. ELECTRONIC BULLETIN BOARD (Continued)
34.2 Menu of Services and Information (Continued)
(j) 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
(k) 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
(l) E-Mail to other Shippers/PGT Systems Administrator
(m) EBB Mailbox
(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. 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 First Revised Sheet No. 137
First Revised Volume No. 1-A Superseding
Original Sheet No. 137
- --------------------------------------------------------------------------------
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
35. CREDITING OF INTERRUPTIBLE TRANSPORTATION REVENUES
Interruptible Transportation Revenue Credits
(a) Applicability. Revenue credits from interruptible transportation
revenues received by PGT from Rate Schedule ITS-1 Shippers shall be
provided to PGT's firm Shippers under Rate Schedules FTS-1, and T-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 35 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 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: 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. 138
First Revised Volume No. 1-A
- --------------------------------------------------------------------------------
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
35. CREDITING OF INTERRUPTIBLE TRANSPORTATION REVENUES (Continued)
Interruptible Transportation Revenue Credits (Continued)
(d) Exclusion. Revenue credits shall not be awarded for that portion
of interruptible revenues that are attributable to: (1) relate to the
recovery by PGT of variable costs, which portion shall be equal to the
minimum usage charge for Rate Schedule FTS-1, (2) the recovery of Gas
Supply Restructuring (GSR) costs to be recovered by a GSR volumetric
surcharge under Rate Schedule ITS-1, 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: 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. 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 Original Sheet No. 139
First Revised Volume No. 1-A
- --------------------------------------------------------------------------------
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
36. CAPACITY RELINQUISHMENT
Firm capacity holders are permitted to permanently relinquish capacity up
to 60 days after issuance of an order accepting this tariff sheet by the
FERC approving PGT's compliance filing at Docket No. RS92-46-000 or the
effective date of the filing, whichever is later.
PGT shall permit such capacity relinquishment only if a qualified
Replacement Shipper(s) is found willing to assume the capacity for at
least the remaining contract term and agrees to pay the Reservation
Charge, including surcharges, the Relinquishing Shipper is obligated to
pay.
PGT shall post a notice of relinquishment on the EBB for competitive
bidding. Bids must be for at least the minimum term of the remaining
contract term but may not be for a term of more than the remaining
contract term plus 20 years. Bids will be evaluated on a net present value
basis utilizing the formula defined in Paragraph 28. Tie bids will be
awarded on a pro-rata basis.
- --------------------------------------------------------------------------------
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. 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 01, 1994
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff First Revised 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 Original Sheet No. 142
First Revised Volume No. 1-A
- --------------------------------------------------------------------------------
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
38. CREDITING OF PARKING AND AUTHORIZED IMBALANCE SERVICE REVENUES
38.1 Applicability
Revenue credits from Parking and Authorized Imbalance Service
revenues received by PGT from Rate Schedule PS-1 and AIS-1 Shippers
shall be provided to all of PGT's Shippers who are receiving
transportation service under a valid transportation service
agreement (Eligible Shippers).
38.2 Crediting Percentage
PGT shall credit to Eligible Shippers 90 percent of Parking and
Imbalance Service revenues received during each 12-month period,
commencing November 1st of each year.
38.3 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 PS-1 and Rate Schedule
AIS-1 revenues received during the 12-month period or Short Period
and the distribution of the revenue credits due to Eligible
Shippers as described below. A "Short Period" shall be the period
for which this Paragraph 38 shall have been in effect for less than
12 months. Such revenue credits shall be reflected as a credit
billing adjustment in the next invoice rendered to 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.
38.4 Distribution Method
Parking and Authorized Imbalance Service revenue credits shall be
credited to each Eligible Shipper on a pro rata basis in proportion
to the revenues received during the 12-month period or Short Period
from each Eligible Shipper divided by the total revenues for all
Eligible Shippers received during such period.
(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. 143
First Revised Volume No. 1-A Superseding
Original Sheet No. 143
- --------------------------------------------------------------------------------
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
38. CREDITING OF PARKING AND AUTHORIZED IMBALANCE SERVICE REVENUES
(Continued)
38.5 Intent
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.
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: P.G. Rosput, Senior Vice President
Issued on: APRIL 06, 1995 Effective: MAY 07, 1995
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS95-206-001 , dated MARCH 31, 1995
<PAGE>
Pacific Gas Transmission Company
FERC Gas Tariff Sheet Nos. 144-150
First Revised Volume No. 1-A
- --------------------------------------------------------------------------------
Reserved for future use
- --------------------------------------------------------------------------------
Issued by: P.G. Rosput, Senior Vice President
Issued on: FEBRUARY 24, 1994 Effective: MARCH 27, 1994
<PAGE>
Graphic List to Exhibit 10.1 of the Form 10-K
Description
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 Timeslines 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 at
Paragraph 28) is described in the body of the electronic document at Paragraph
28.2 and Paragraph 28.8 (c) as permitted by Item 304 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 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>
TF01005708112495El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03110 1 0 4P126First Revised Sheet No. 110
TF04 Original Sheet No. 110
TF05Patricia A.Shelton, Vice President
TF06112295092895RM95-3-000 122495
RATE SCHEDULE FT-1
Firm Transportation Service
1. AVAILABILITY
This Rate Schedule is available to any party (hereinafter referred to
as "Shipper") for the transportation of natural gas on a firm basis by El Paso
Natural Gas Company (hereinafter referred to as "El Paso") under the following
conditions:
(a) El Paso determines it has available capacity to render the firm
transportation service; and
(b) Shipper and El Paso have executed a Transportation Service
Agreement, in the form contained in this Volume No. 1-A Tariff,
for such firm transportation service.
2. APPLICABILITY AND CHARACTER OF SERVICE
This Rate Schedule shall apply to all natural gas transported by El
Paso for Shipper pursuant to the executed Transportation Service Agreement.
Transportation service hereunder shall be firm, subject to the
provisions of the executed Transportation Service Agreement and to the
Transportation General Terms and Conditions incorporated herein by reference.
Transportation service hereunder shall consist of the acceptance by El
Paso of natural gas on behalf of Shipper for transportation at the Receipt
Point(s) specified in the executed Transportation Service Agreement, the
transportation of that natural gas through El Paso's pipeline system, and the
delivery of that gas, after appropriate reductions as provided for in this
Rate Schedule, to Shipper or for Shipper's account at the Delivery Point(s)
specified in the executed Transportation Service Agreement.
3. DEFINITIONS
3.1 Transportation Contract Demand: A Shipper's Transportation Contract
Demand shall be the maximum quantity of gas El Paso is obligated to
deliver to Shipper (or for Shipper's account) at the Delivery Point(s)
under this Rate Schedule. The Transportation Contract Demand shall be
specified on Exhibit B of the executed Transportation Service
Agreement, except that the Transportation Contract Demand shall not
apply to full requirements agreements.
<PAGE>
TF01005708112995El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03111 2 0 4P126Second Revised Sheet No. 111
TF04 First Revised Sheet No. 111
TF05Patricia A.Shelton, Vice President
TF06112895091395CP94-183-000 and 001010196
RATE SCHEDULE FT-1
Firm Transportation Service
(Continued)
3. DEFINITIONS (Continued)
3.2 Maximum Daily Quantity: The maximum quantity that El Paso is obligated
to receive at each Receipt Point or deliver at each Delivery Point as
specified in the executed Transportation Service Agreement; provided,
however, that the Maximum Daily Quantity for a full requirements
customer on any day shall be its full requirements on that day.
4. RATE
Shipper shall pay to El Paso each month the charges set forth below as
such charges are designated to be applicable to the transportation service
rendered by El Paso for Shipper under the executed Transportation Service
Agreement. The quantity of natural gas to which the charges shall apply is set
forth below.
4.1 Transportation Charges: As compensation for the use of El Paso's
facilities in the transportation of natural gas under the executed
Transportation Service Agreement, Shipper shall pay the following
rate(s):
(a) Mainline Transportation Reservation Charges: The maximum unit
amount in dollars per dth, unless otherwise provided, applicable
to the production area or state(s) in which deliveries are made
as set forth from time to time on the currently effective Sheet
No. 22 of this Volume No. 1-A Tariff, or superseding tariff,
multiplied by Shipper's Transportation Contract Demand, except
for those Shippers who have converted their existing sales
entitlements to full requirements firm transportation service in
which case the applicable Transportation Reservation Charge will
be multiplied by each Shipper's respective Billing Determinant,
as specified in Section 9(b) of this Rate Schedule. For the
purpose of computing the Reservation Charges specified herein, if
Shipper's Transportation Contract Demand or Maximum Daily
Quantity is expressed in Mcf, it shall be converted to dth's by
multiplying the number of Mcf by the heating value conversion
factor of 1.030 which is the factor utilized in designing such
charges.
<PAGE>
TF01005708112995El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03112 2 0 4P126Second Revised Sheet No. 112
TF04 First Revised Sheet No. 112
TF05Patricia A.Shelton, Vice President
TF06112895091395CP94-183-000 and 001010196
RATE SCHEDULE FT-1
Firm Transportation Service
(Continued)
4. RATE (Continued)
4.1 Transportation Charges (Continued)
(b) Usage Charges: Except as otherwise provided below, in addition to
the applicable Reservation Charge, Shipper shall pay an amount
determined as the quantity of natural gas delivered in dth
multiplied, as applicable, by the following:
(i) Mainline Transportation Usage Charges: The maximum rate(s)
per dth, unless otherwise provided, applicable from the
production basin(s) in which natural gas is received to the
production area(s) within such basin or state(s) in which
deliveries are made set forth from time to time on currently
effective Sheet Nos. 23 and 24 of this Volume No. 1-A
Tariff, or superseding tariff; or
(ii) Mainline Shorthaul Usage Charge: The maximum rate(s) per
dth, unless otherwise provided, as set forth from time to
time on currently effective Sheet No. 24 of this Volume No.
1-A Tariff, or superseding tariff, if the transportation
service rendered by El Paso pursuant to the executed
Transportation Service Agreement is a forward haul of one
hundred miles or less; or
(iii) Mainline Backhaul Usage Charge: The maximum rate(s) per dth,
unless otherwise provided, as set forth from time to time on
currently effective Sheet No. 24 of this Volume No. 1-A
Tariff, or superseding tariff, if the transportation service
rendered by El Paso pursuant to the executed Transportation
Service Agreement is by backhaul.
(iv) Comparable Discounts: If El Paso agrees to provide its
marketing affiliate a discount for any pipeline service, El
Paso shall make such discounted rate contemporaneously
available to similarly situated unaffiliated Shippers.
<PAGE>
TF01005708122895El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03113 3 0 4P126Third Revised Sheet No. 113
TF04 Second Revised Sheet No. 113
TF05Patricia A.Shelton, Vice President
TF06122795****** 010196
RATE SCHEDULE FT-1
Firm Transportation Service
(Continued)
4. RATE (Continued)
4.1 Transportation Charges (Continued)
For those agreements in which transportation by El Paso is provided in
two steps, with intermediate transportation service in between
provided by a third party, the quantity of natural gas to which the
charges set forth in Section 4.1(b) shall apply is determined by the
quantity delivered by El Paso to the intermediate third-party.
El Paso, at its sole discretion, may from time to time and at any time
selectively adjust any or all of the rates stated above applicable to any
individual Shipper; provided, however, that such adjusted rate(s) shall not
exceed the applicable Maximum Rate(s) nor shall they be less than the Minimum
Rate(s) set forth on Sheet Nos. 22, 23, and 24 of this Volume No. 1-A Tariff,
or superseding tariff. If El Paso so adjusts any rates to any Shipper, El Paso
shall file with the Federal Energy Regulatory Commission any and all required
reports respecting such adjusted rates.
5. RESERVED
6. SCHEDULED OVERRUN TRANSPORTATION
Upon request of Shipper, El Paso, at its reasonable discretion, may
receive, transport and deliver natural gas in excess of Shipper's
Transportation Contract Demand specified in the executed Transportation
Service Agreement. Payments for any excess quantity shall be equivalent to the
maximum "Mainline Transportation Charge," or a lesser charge as mutually
agreed upon, applicable from the production basin(s) in which the natural gas
is received to the production area(s) within such basin or state(s) in which
deliveries are made for service under El Paso's Rate Schedule IT-1, as such
rate is in effect and reflected from time to time on Sheet No. 20 of this
Volume No. 1-A Tariff, or superseding tariff. Fuel and/or shrinkage for any
excess quantities shall be in accordance with Section 5 of Rate Schedule IT-1.
7. FUEL AND/OR SHRINKAGE
In addition to the payments made pursuant to Section 3 of this Rate
Schedule, Shipper shall provide and be responsible for fuel and shrinkage that
occurs in transporting natural gas pursuant to Shipper's executed
Transportation Service Agreement which shall be 5% of the quantity received.
Fuel and shrinkage for shorthaul and backhaul transportation may be discounted
by El Paso between 0% and 5%; however, the discounted percentage applied shall
not be less than actual fuel and shrinkage.
<PAGE>
TF01005708112995El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03114 0 0 4P1262nd Revised Original Sheet No. 114
TF04 1st Revised Original Sheet No. 114
TF05Patricia A.Shelton, Vice President
TF06112895091395CP94-183-000 and 001010196
RATE SCHEDULE FT-1
Firm Transportation Service
(Continued)
8. GENERAL TERMS AND CONDITIONS
Except as otherwise expressly indicated in this Rate Schedule or by
the executed Transportation Service Agreement, all of the Transportation
General Terms and Conditions contained in this Volume No. 1-A Tariff,
including (from and after their effective date) any future modifications,
additions or deletions to said General Terms and Conditions, are applicable to
transportation service rendered under this Rate Schedule and, by this
reference, are made a part hereof.
9. PROVISIONS APPLICABLE TO SHIPPERS THAT CONVERTED TO FIRM TRANSPORTATION
(a) Any Shipper that converted firm sales entitlements to firm
transportation in accordance with the settlement of the proceeding at
Docket No. RP88-44-000, et al., shall be entitled to receive firm
transportation of the quantities specified by its Transportation
Service Agreement with El Paso for a period, unless
<PAGE>
TF01005708112995El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03115 0 0 4P1262nd Revised Original Sheet No. 115
TF04 Sheet Nos. 115 and 116
TF05Patricia A.Shelton, Vice President
TF06112895091395CP94-183-000 and 001010196
Reserved Sheet
3rd Revised Original Sheet No. 115 and
Second Revised Sheet No. 116 have been reserved.
<PAGE>
TF03117 0 0 4P1261st Revised Original Sheet No. 117
TF04 Original Sheet No. 117
TF05Patricia A.Shelton, Vice President
TF06112295092895RM95-3-000 122495
RATE SCHEDULE FT-1
Firm Transportation Service
(Continued)
9. PROVISIONS APPLICABLE TO SHIPPERS THAT CONVERTED TO FIRM TRANSPORTATION
(Continued)
otherwise agreed, which is at least as long as the period El Paso's
Gas Inventory Charge certificate remains in effect. Following such
period, El Paso shall not be authorized, in the absence of written
concurrence by the affected Shipper, to avail itself of the "pre-
granted" abandonment authority granted by the Commission's Regulations
(currently codified at Section 284.221(d)).
(b) The Billing Determinants to be utilized in determining the
Transportation Reservation Charges set forth in Section 4.1(a) for
those Shippers who are full requirements Shippers are as follows:
<TABLE>
<CAPTION>
SHIPPER BILLING DETERMINANTS
(dth)
<S> <C>
Production Area
Gas Company of New Mexico 6,664
Navajo Tribal Utility Authority 9,275
Southern Union Gas Company 4,949
Texas
ASARCO Inc. 6,589
El Paso Electric Company 30,751
Southdown, Inc. 3
Southern Union Gas Company 70,277
New Mexico
El Paso Electric Company 0
Gas Company of New Mexico 71,618
Las Cruces, New Mexico, City of 14,578
Lordsburg, New Mexico, City of 747
Phelps Dodge Corporation 16,962
</TABLE>
<PAGE>
TF01005708112495El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03118 0 0 4P1261st Revised Original Sheet No. 118
TF04 Original Sheet No. 118
TF05Patricia A.Shelton, Vice President
TF06112295092895RM95-3-000 122495
RATE SCHEDULE FT-1
Firm Transportation Service
(Continued)
9. PROVISIONS APPLICABLE TO SHIPPERS THAT CONVERTED TO FIRM TRANSPORTATION
(Continued)
<TABLE>
<CAPTION>
SHIPPER BILLING DETERMINANTS
(dth)
Arizona
<S> <C>
Arizona Electric Power Cooperative, Inc 53,217
Arizona Public Service Company 62,364
ASARCO Inc. 3,526
Citizens Utilities Company 59,395
Cyprus Miami Mining Corporation 4,527
Magma Copper Company 14,219
Mesa, Arizona, City of 17,818
Navajo Tribal Utility Authority 2,970
PEMEX Gas y Petroquimica Basica 8,748
Phelps Dodge Corporation 4,455
Salt River Project Agricultural
Improvement and Power District 57,910
Southwest Gas Corporation 399,698
Nevada
Southwest Gas Corporation 180,000
</TABLE>
(c) Shipper, at its option, may elect to pay El Paso the annual charges so
determined from the Billing Determinants specified above allocated
with two-thirds (2/3) of the total amount divided and payable in six
(6) equal amounts for each of the winter months of November through
April and one-third (1/3) of the total amount divided and payable in
six (6) equal amounts for each of the summer months of May through
October. Shipper, in concurrence with El Paso, may elect an allocation
methodology different from that specified above if its seasonal
profile so dictates. This provision applies only to Category B
Customers as defined at Docket No. RP72-6, et al., except Southwest
Gas Corporation, Southern Union Gas Company, Gas Company of New Mexico
and Citizens Utilities Company.
<PAGE>
TF01005708112495El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03119 0 0 4P1261st Revised Original Sheet No. 119
TF04 Original Sheet No. 119
TF05Patricia A.Shelton, Vice President
TF06112295092895RM95-3-000 122495
RATE SCHEDULE FT-1
Firm Transportation Service
(Continued)
10. MAINLINE TRANSPORTATION RESERVATION CHARGE CREDIT
If during any one-year period (the first such one-year period
beginning with the effectiveness of the Stipulation and Agreement at Docket
No. RS92-60-000, et al., is in effect and the last such period or partial
period ending the day before El Paso's next general rate case is effective),
El Paso collects more than the dollar amount set forth in Article 2.7(b) of
said Stipulation and Agreement, attributable to costs allocated to
interruptible transportation service, each Shipper paying the maximum Mainline
Transportation Reservation Charge under this Rate Schedule shall be eligible
to receive a credit to its Mainline Transportation Reservation Charge.
The determination as to whether any credit is due shall be calculated
as described below:
(a) From the revenues received for interruptible mainline transportation
service under Rate Schedule IT-1, El Paso shall first deduct and retain
revenues equal to the sum of the mainline transportation usage rate
component of Rate Schedule FT-1 and all rate surcharges.
(b) El Paso shall retain all remaining interruptible transportation
revenues received under Rate Schedule IT-1 until such time as the total
dollar amount set forth in Article 2.7(b) of the Stipulation and
Agreement for the applicable one-year period or partial period has been
received.
(c) El Paso shall retain 10% of any revenues remaining after performing
steps (a) and (b) of the allocation. The remaining 90% shall be
credited to firm Shippers as follows:
(i) During the amortization period applicable to Washington Ranch
Facility costs described in Section 31 of this tariff, such
remaining 90% shall be allocated among firm Shippers paying the
maximum Mainline Transportation Reservation Charge under this
Rate Schedule based on the proportion of each Shipper's Mainline
Transportation Reservation
<PAGE>
TF01005708112495El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03120 1 0 4P126First Revised Sheet No. 120
TF04 Original Sheet No. 120
TF05Patricia A.Shelton, Vice President
TF06112295092895RM95-3-000 122495
RATE SCHEDULE FT-1
Firm Transportation Service
(Continued)
10. MAINLINE TRANSPORTATION RESERVATION CHARGE CREDIT (Continued)
revenue responsibility to the total Mainline Transportation
Reservation revenue responsibility for all such Shippers
paying the maximum Mainline Transportation Reservation
Charge; and
(ii) Commencing with the expiration of the amortization period of
the Washington Ranch Facility costs described in Section 31
of this tariff, such remaining 90% shall be allocated among
all firm Shippers, without regard to whether a Shipper is
paying the maximum Mainline Transportation Reservation
Charge, based on each such Shippers billed Transportation
Reservation Charge under this Rate Schedule in proportion to
the total Mainline Transportation Reservation Charges
billed.
The revenues to be credited as described above, if any, shall be
credited to Shippers under this Rate Schedule within ninety (90) days
following the date such revenues are received. In the event a credit amount
cannot be applied to a Shipper under Section 10(c) above, then El Paso shall
flow such amount through by means of a refund. In no event shall any Shipper
receive a credit or refund under this provision that exceeds the Mainline
Transportation Reservation Charges paid under this Rate Schedule by such
Shipper during each one-year period or partial period.
<PAGE>
TF01005708052494El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03121 0 010P126Sheet Nos. 121 through 124
TF04
TF05A.W.Clark, Vice President
TF06052394****** 070194
Reserved Sheets
Original Sheet Nos. 121 through 124 have been reserved.
<PAGE>
TF01005708052494El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03200 0 0 5P126Original Sheet No. 200
TF04
TF05A.W.Clark, Vice President
TF06052394****** 070194
TF09E2 0 0 -1 0N052494061694GT94-46-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
Table of Contents
<TABLE>
<CAPTION>
Section Description Sheet No.
<S> <C> <C>
1 Definitions 201
2 Method of Measurement 203
3 Measurement Equipment 205
4 Scheduling and Capacity Allocation 210
5 Quality 220
6 Billing and Payment 237
7 Force Majeure 242
8 Control and Possession of Natural Gas 243
9 Adverse Claims to Natural Gas 244
10 Indemnification 245
11 Odorization 246
12 Non-Waiver of Future Default 247
13 Service Conditions 248
14 Statutory Regulation 250
15 Assignments 251
16 Descriptive Headings 252
17 Taxes 253
18 Gas Research Institute General Research
Development and Demonstration Funding
Unit Adjustment Provision 254
19 Operating Provisions for Interruptible
Transportation Service 258
20 Operating Provisions for Firm Transportation
Service 272
21 Annual Charge Adjustment Provision 291
22 Take-or-Pay Buyout and Buydown Cost Recovery 292
23 Compliance Plan for Transportation Services
and Affiliate Transactions 293
24 Order No. 636 Electronic Bulletin Board 308
25 Reserved 310
26 Reserved 320
27 Unauthorized Gas 330
28 Capacity Release Program 334
29 Compliance Plan for Unbundled Sales Division 357
30 Assignment of Firm Capacity on Upstream
Pipelines 358
31 Washington Ranch Facility Stranded Investment
Cost Recovery 361
</TABLE>
<PAGE>
TF01005708052494El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03201 0 0 5P126Original Sheet No. 201
TF04
TF05A.W.Clark, Vice President
TF06052394****** 070194
TF09E2 0 0 -1 0N052494061694GT94-46-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
1. DEFINITIONS
1.1 Day - A period of twenty-four (24) consecutive hours commencing at
seven (7:00) a.m., Mountain Standard Time, or such other period as the
parties may agree upon.
1.2 Month - A period commencing on the first day of the corresponding
calendar month and ending on the first day of the next following
calendar month.
1.3 Year - A period of three hundred sixty-five (365) consecutive days
commencing on the date to be specified in the executed Transportation
Service Agreement; provided, however, that any such year which
contains the date of February 29 shall consist of three hundred sixty-
six (366) consecutive days.
1.4 British Thermal Unit ("Btu") - One (1) Btu shall mean one British
thermal unit and is defined as the amount of heat required to raise
the temperature of one (1) pound of water from fifty-nine degrees
Fahrenheit (59 degrees F) to sixty degrees Fahrenheit (60 degrees F)
at a constant pressure of fourteen and seventy-three hundredths pounds
per square inch absolute (14.73 psia). Total Btu's shall be determined
by multiplying the total volume of natural gas delivered times the gas
heating value expressed in Btu's per cubic foot of gas adjusted on a
dry basis.
1.5 Dekatherm ("dth") - One (1) dth shall mean a quantity of gas
containing one million (1,000,000) Btu's.
1.6 Heating Value - The quantity of heat, measured in Btu, produced by
combustion in air of one (1) cubic foot of anhydrous gas at a
temperature of sixty degrees Fahrenheit (60 degrees F) and a constant
pressure of fourteen and seventy-three hundredths pounds per square
inch absolute (14.73 psia), the air being at the same temperature and
pressure as the gas, after the products of combustion are cooled to
the initial temperature of the gas and air, and after condensation of
the water formed by combustion.
1.7 Operator - The person or entity that controls the flow of gas into El
Paso's system.
<PAGE>
TF01005708112995El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03202 1 0 5P126First Revised Sheet No. 202
TF04 Original Sheet No. 202
TF05Patricia A.Shelton, Vice President
TF06112895091395CP94-183-000 and 001010196
TF09E5 0 0 -1 0N112995122995RP96-52-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
1. DEFINITIONS (Continued)
1.8 Natural Gas - Any mixture of hydrocarbons or of hydrocarbons and
noncombustible gases, in a gaseous state, consisting essentially of
methane.
1.9 One Thousand Cubic Feet ("Mcf") - The quantity of natural gas
occupying a volume of one thousand (1,000) cubic feet at a temperature
of sixty degrees Fahrenheit (60 degrees F) and at a pressure of
fourteen and seventy-three hundredths pounds per square inch absolute
(14.73 psia).
1.10 El Paso System - The El Paso System is displayed on the map set forth
on Sheet No. 11 of this FERC Gas Tariff.
1.11 Interconnect - A point at which any facility, including third-party
plants and gathering systems, connects with El Paso's mainline
transmission system.
<PAGE>
TF01005708052494El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03203 0 0 5P126Original Sheet No. 203
TF04
TF05A.W.Clark, Vice President
TF06052394****** 070194
TF09E2 0 0 -1 0N052494061694GT94-46-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
2. METHOD OF MEASUREMENT
2.1 Unit of Measurement - The unit of measurement for the purpose of
receipt and delivery of natural gas for transportation shall be one
(1) dth. The number of dth's delivered shall be determined by
multiplying the number of Mcf of gas delivered by the total heating
value of such gas in Btu's per cubic foot, and multiplying the product
by 0.001.
The unit of volume for the purpose of measurement shall be one (1) Mcf
at a pressure of fourteen and seventy-three hundredths pounds per
square inch absolute (14.73 psia) and at a temperature of sixty
degrees Fahrenheit (60 degrees F). All readings and registrations of
the metering equipment shall be computed into such unit of volume.
2.2 Basis - All orifice meter volumes shall be computed in accordance with
applicable American Gas Association reports. Where measurement is by
other than orifice meters, all necessary factors for proper volume
determination shall be applied.
All orifice meter volumes shall be corrected for deviations from the
ideal gas laws (supercompressibility) in accordance with the
applicable American Gas Association reports. Where displacement meters
are used, the square of the orifice meter supercompressibility factor
shall be applied.
For the purpose of measurement, the atmospheric pressure shall be the
barometric pressure calculated for the elevation at the point of
measurement.
2.3 Determination of Heating Value - The heating value of gas shall be
determined from time to time by analysis of samples obtained from
continuous sampling devices. The samples shall be run on a recording
calorimeter, employing the Thomas principle of calorimetry, located at
the measuring station or at any other point on the pipeline where
there will be no commingling thereafter of gas, or by means of some
other recognized method. The arithmetic average heating value of the
gas during the chart period shall be used in computing any deficiency
in Btu content of gas delivered during such period.
<PAGE>
TF01005708052494El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03204 0 0 5P126Original Sheet No. 204
TF04
TF05A.W.Clark, Vice President
TF06052394****** 070194
TF09E2 0 0 -1 0N052494061694GT94-46-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
2. METHOD OF MEASUREMENT (Continued)
2.4 Determination of Flowing Temperature - The temperature of the gas
flowing through a meter station shall be obtained by the use of a
recording thermometer. The arithmetic average temperature of the gas
during the chart period shall be used in computing the delivery of gas
during such period. Where the quantities of gas metered will not be
materially affected by so doing, the temperature at delivery shall be
assumed to be sixty degrees Fahrenheit (60 degrees F) when not
regularly measured.
2.5 Determination of Specific Gravity - The specific gravity of the gas
flowing through orifice meter stations, when used, shall be determined
by taking samples of such gas by means of a recording gravitometer
located at the measuring station or at any other point on the pipeline
where there will be no commingling thereafter of gas, or by any other
recognized method which may be practical in the circumstances. The
arithmetic average specific gravity of the gas at such points during
the chart period shall be used in computing the delivery of gas during
such period at such points.
2.6 Chromatographic Analysis - If the heating value and/or the specific
gravity is determined by chromatographic analysis of the gas sample,
the values of the physical constants for the gas compounds and the
procedure for determining the gross heating value and/or the specific
gravity of the gas from them shall be as set forth in the American Gas
Association reports where available.
<PAGE>
TF01005708052494El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03205 0 0 5P126Original Sheet No. 205
TF04
TF05A.W.Clark, Vice President
TF06052394****** 070194
TF09E2 0 0 -1 0N052494061694GT94-46-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
3. MEASUREMENT EQUIPMENT
3.1 Installation and Operation of Measuring Facilities - All measuring
facilities shall be installed, if necessary, owned, maintained and
operated, at or near the Receipt Point(s) and Delivery Point(s), as
mutually agreed to by El Paso and Shipper. The parties agree that new
measurement equipment and techniques which may be developed from time
to time, including electronic flow measurement equipment and
techniques, may be utilized by either party to measure the quantity of
gas delivered to or by El Paso without additional authorization from
the other party provided such new equipment or technique is recognized
as generally acceptable for the intended purpose by recognized
industry authorities, provides audit data acceptable by El Paso, and
is installed and operated in accordance with generally accepted
industry practices. Unless otherwise agreed to between the parties,
orifice meters shall be utilized and shall employ flange taps and
shall be installed and operated in accordance with the applicable
American Gas Association reports.
3.2 Installation and Operation of Check Meters - Either party may install,
maintain and operate at its own expense, at or near the Receipt
Point(s) and the Delivery Point(s), check meters and other necessary
equipment by which the quantity of gas delivered to or by El Paso may
be measured, provided that such equipment is installed so as not to
interfere with the operation of the primary measuring facilities
provided for in Section 3.1 hereof. Unless otherwise agreed to between
the parties, orifice meters shall be utilized and shall employ flange
taps and shall be installed and operated in accordance with the
applicable American Gas Association reports.
3.3 Non-interference - Measuring equipment applying to or affecting
deliveries shall be installed in such manner as to permit an accurate
determination of the quantity of gas delivered and ready verification
of the accuracy of measurement. The parties shall exercise care in the
installation, maintenance and operation of check measuring or pressure
regulating equipment or gas compressors so as to prevent any
inaccuracy in the determination of the quantity of gas being measured.
<PAGE>
TF01005708052494El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03206 0 0 5P126Original Sheet No. 206
TF04
TF05A.W.Clark, Vice President
TF06052394****** 070194
TF09E2 0 0 -1 0N052494061694GT94-46-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
3. MEASUREMENT EQUIPMENT (Continued)
3.4 Calibration and Test of Measurement Equipment - Each party shall have
the right to have representatives present at the time of any
installing, cleaning, changing, repairing, inspecting, testing,
calibrating or adjusting done in connection with the other party's
measuring equipment, including calorimeters, used in the measurement
of deliveries of gas.
The accuracy of the measuring equipment, including calorimeters, shall
be verified at reasonable intervals but not more frequently than once
in any thirty (30) day period. In the event either party shall notify
the other that it desires a special test of said measuring equipment
or of the check measuring equipment, as the case may be, the parties
shall cooperate to secure prompt verification of the accuracy of such
equipment. Each party shall give to the other party sufficient advance
notice of the time of all such special tests so that the other party
may conveniently have its representatives present.
3.5 Charts and Records - Upon request of either party, the other shall
submit the records and charts from its measuring equipment used in the
measurement and billing of gas, including records resulting from
electronic flow measurement, chartless custody transfers or any other
improved measurement technology, together with calculations therefrom,
for inspection and verification, subject to return within thirty (30)
days after receipt.
The parties shall preserve all test data, charts and other required
data pertaining to the measurement of gas by their respective
measurement equipment for a period of three (3) years or such other
period or periods as may be prescribed with respect to them by
regulatory bodies having jurisdiction.
3.6 Correction of Metering Errors - If, upon test, the measuring equipment
is found to be in error by not more than two percent (2%), previous
recordings of such equipment shall be considered accurate in computing
deliveries, but such equipment shall be adjusted at once to record
accurately.
<PAGE>
TF01005708052494El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03207 0 0 5P126Original Sheet No. 207
TF04
TF05A.W.Clark, Vice President
TF06052394****** 070194
TF09E2 0 0 -1 0N052494061694GT94-46-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
3. MEASUREMENT EQUIPMENT (Continued)
3.6 Correction of Metering Errors (Continued)
If, upon test, the measuring equipment shall be found to be inaccurate
by an amount exceeding two percent (2%), at a recording corresponding
to the average hourly rate of flow for the period since the last
preceding test, then any previous recordings of such equipment shall
be corrected to zero error for any period that is known definitely or
agreed upon. In case the period is not known or agreed upon, such
correction shall be for a period equal to the lesser of one-half of
the time elapsed since the date of the last test or sixteen (l6) days.
3.7 Failure of Meters - In the event a meter is out of service or
registering inaccurately, the quantity of gas delivered shall be
determined:
(i) By correcting the error if the percentage of error is
ascertainable by calibration, test or mathematical
calculations; or in the absence of (i), then
(ii) By using the registration of any check meter or meters, if
installed and accurately registering; or in the absence of
both (i) and (ii), then
(iii) By estimating the quantity of delivery during periods under
similar conditions when the meter was registering
accurately.
3.8 Right-of-Way and Rural Consumers - El Paso shall install, maintain and
operate at its own expense, all main line taps and high-pressure
regulators necessary for the delivery of natural gas by El Paso to
Shipper for resale to right-of-way consumers as well as to rural
consumers situated remotely from Shipper's general distribution
system. For measurement of gas delivered by El Paso to Shipper for
resale to such right-of-way consumers, Shipper shall install, maintain
and operate at Shipper's own expense, adjacent to El Paso's pipeline,
the meters, low-pressure regulators and other equipment required.
<PAGE>
TF01005708052494El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03208 0 0 5P126Original Sheet No. 208
TF04
TF05A.W.Clark, Vice President
TF06052394****** 070194
TF09E2 0 0 -1 0N052494061694GT94-46-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
3. MEASUREMENT EQUIPMENT (Continued)
3.8 Right-of-Way and Rural Consumers (Continued)
For measurement of gas delivered by El Paso to Shipper for resale to
such rural consumers, El Paso may, at its option, require Shipper to
install, maintain and operate at Shipper's own expense, adjacent to El
Paso's high-pressure regulators, the meters, low-pressure regulators
and other equipment required.
Notwithstanding the other provisions of these General Terms and
Conditions and unless other operating arrangements mutually agreeable
to Shipper and El Paso are employed, the following arrangements shall
apply to deliveries of gas by El Paso to Shipper for resale to right-
of-way consumers as well as to deliveries of gas by El Paso to Shipper
for resale to rural consumers where, pursuant to the immediately
preceding paragraph, Shipper installs meters, low-pressure regulators
and other equipment.
Shipper will service all equipment installed by it and the consumers
served by use thereof, including handling of all complaints and/or
service calls. The reading of said meters shall be performed by the
party most conveniently able to do so as mutually agreed upon by El
Paso and Shipper. If the meters are read by Shipper, then Shipper
shall furnish a copy of the meter readings to the El Paso, all without
expense to El Paso; provided, however, that El Paso shall have the
right to read said meters at any reasonable time upon giving notice to
Shipper. All pipe, meters and other equipment shall remain the
property of the person or corporation paying for same. Shipper at its
own expense will from time to time check the accuracy of the meters
measuring said gas and shall give El Paso reasonable notice in writing
of its intention to do so. The provisions of Sections 3.6 and 3.7
hereof shall apply to the accuracy of Shipper's measuring equipment.
El Paso may at its option have a representative present at such test.
The frequency of meter reading and the billing for gas delivered by El
Paso to Shipper for resale to such right-of-way and rural consumers
shall be in accordance with such operating arrangements as may be
mutually satisfactory to El Paso and Shipper.
<PAGE>
TF01005708052494El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03209 0 0 5P126Original Sheet No. 209
TF04
TF05A.W.Clark, Vice President
TF06052394****** 070194
TF09E2 0 0 -1 0N052494061694GT94-46-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
3. MEASUREMENT EQUIPMENT (Continued)
3.9 Access to Measuring Equipment - Whenever any point of delivery
provided for is on the premises of one party, the other party shall
have the right of free use and ingress and egress at all reasonable
times for the purpose of installation, operation, repair or removal of
measuring equipment.
In the event check measuring equipment is installed, the other party
shall have access to the same at all reasonable times, but the
reading, calibration and adjusting thereof and the changing of charts
shall be done only by the party installing the check measuring
equipment.
<PAGE>
TF01005708112995El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03210 1 0 5P126First Revised Sheet No. 210
TF04 Original Sheet No. 210
TF05Patricia A.Shelton, Vice President
TF06112895091395CP94-183-000 and 001010196
TF09E5 0 0 -1 0N112995122995RP96-52-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
4. SCHEDULING AND CAPACITY ALLOCATION
This Section 4 applies to the operation of El Paso's system and sets forth the
procedures for scheduling of receipts and deliveries and allocation of
pipeline system capacity or any portion thereof among Shippers receiving
transportation service from El Paso under executed Transportation Service
Agreements pursuant to this Tariff and transportation arrangements included in
El Paso's FERC Gas Tariff, Volume No. 2.
4.1 Scheduling of Receipts and Deliveries
(a) For scheduling purposes, Day 1 shall be utilized only for
scheduling firm requests using primary receipt points and primary
delivery points and Day 2 shall be utilized, where additional
capacity exists, first for scheduling any additional firm requests
using primary receipt points and primary delivery points, secondly
for scheduling firm requests using either alternate receipt points
or alternate delivery points and third for scheduling any
interruptible requests. The following procedure shall be utilized
to schedule transportation on El Paso's system:
Day 1 - On Day 1, Shippers shall verify their requests for firm
transportation from primary receipt points to primary delivery
points and cause the Operators to make confirmations of supply. El
Paso shall utilize confirmed volumes, not to exceed requests, to
determine capacity requirements; and, where necessary, the
capacity allocation procedure set forth in Section 4.2 hereof
shall be followed. El Paso shall communicate electronically or via
facsimile to the Shippers and Operators the scheduled quantities
and any additional capacity availability. Such notification
normally shall be completed prior to the beginning of business on
Day 2.
<PAGE>
TF01005708052494El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03211 0 0 5P126Original Sheet No. 211
TF04
TF05A.W.Clark, Vice President
TF06052394****** 070194
TF09E2 0 0 -1 0N052494061694GT94-46-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
4. SCHEDULING AND CAPACITY ALLOCATION (Continued)
4.1 Scheduling of Receipts and Deliveries (Continued)
Day 2 - Where additional capacity exists, Shippers shall have the
opportunity, in accordance with the allocation procedures set
forth in Section 4.2 of this Section, to request firm
transportation for additional quantities of gas using primary
receipt points and primary delivery points, then for firm requests
using either alternate receipt points or alternate delivery
points, or both, and then for requests for interruptible
transportation. Shippers shall cause the Operator to make
corresponding confirmations of supply. Such scheduling shall apply
only to the additional capacity and shall not cause any change in
the prior sequencing of deliveries. El Paso shall then normally
communicate electronically or via facsimile the final scheduling
of gas to Shippers and Operators prior to the beginning of
business on Day 3.
Day 3 - Shippers shall cause the Operators to tender the scheduled
quantities of natural gas to El Paso at Receipt Points, plus
volumes retained by El Paso for fuel and shrinkage as provided for
in the applicable transportation rate schedule and El Paso shall
deliver the scheduled quantities of natural gas, for Shippers'
accounts, at Delivery Points. However, in the event an unexpected
capacity constraint occurs, then El Paso shall allocate capacity
in accordance with the applicable provisions of Section 4.2(d).
(b) Operating conditions may, from time to time, cause a temporary and
unintentional imbalance between the quantities (in dth's) of
natural gas that El Paso receives and the quantities of natural
gas that Shipper takes under the executed Transportation Service
Agreement. Shipper shall schedule gas attributable to imbalances
when El Paso, in its reasonable discretion and in a
nondiscriminatory manner, determines that it can practicably
receive or deliver such imbalance.
<PAGE>
TF01005708112495El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03212 1 0 5P126First Revised Sheet No. 212
TF04 Original Sheet No. 212
TF05Patricia A.Shelton, Vice President
TF06112295092895RM95-3-000 122495
TF09E4 0 0 -1 0N112495122295RP96-49-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
4. SCHEDULING AND CAPACITY ALLOCATION (Continued)
4.1 Scheduling of Receipts and Deliveries (Continued)
(c) El Paso shall not be obligated to accept, for the account of
Shipper, from any receipt point, a quantity of gas that is less
than fifteen (15) dth per day, so as to avoid measurement problems
relative to small volumes and disproportionate administrative
burdens.
(d) With respect to its own natural gas supplies, El Paso shall be
obligated to pool its supplies by basin, and schedule its own
sales gas from such pools in the same manner as it schedules gas
from pools for other Shippers.
(e) In the event that, on any day, a Shipper's initial request for
transportation on El Paso's system is unsuccessful due to lack of
access to downstream transportation at any delivery point, which
El Paso shall confirm by contacting the downstream operator, such
condition shall have no adverse effect on the scheduling of other
Shipper's rights at receipt or delivery points.
(f) In the event of any occurrence which prevents El Paso from
utilizing the process set forth above (e.g., computer failure),
for the duration of such occurrence, all scheduling shall be done
on the same day subject to the priority limitations applicable on
Day 2. Notice of the commencement and termination of any such
occurrence shall be posted on El Paso's EBB. The provisions of
Section 4.2(d) below shall not apply to occurrences subject to
this Section 4.1(f).
(g) During Day 3, a Shipper moving gas pursuant to Rate Schedule FT-1
of this Volume No. 1-A Tariff may divert scheduled volumes to a
point that is within the same rate zone or in an upstream zone. A
Releasing Shipper, as a term of release, may utilize such flow day
diversion as a means of recalling capacity on an expeditious
basis. Additionally, an Acquiring Shipper also may utilize flow
day diversion for the same day return of such recalled capacity.
Any diversion pursuant to this Section 4.1(g) is subject to the
following conditions:
<PAGE>
TF01005708112495El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03213 1 0 5P126First Revised Sheet No. 213
TF04 Original Sheet No. 213
TF05Patricia A.Shelton, Vice President
TF06112295092895RM95-3-000 122495
TF09E4 0 0 -1 0N112495122295RP96-49-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
4. SCHEDULING AND CAPACITY ALLOCATION (Continued)
4.1 Scheduling of Receipts and Deliveries (Continued)
(i) The Shipper who desires to divert gas to an alternate
delivery point must:
(1) Contact the Operator of the delivery point to which
the gas was originally scheduled and arrange for that
Operator to decrease the quantity to be received from
El Paso, and
(2) Arrange with the Operator of the alternate delivery
point to receive the gas.
(ii) The Operator of the delivery point from which the gas is to
be diverted must notify El Paso, via El Paso's electronic
scheduling system, which Shipper's gas is to be diverted and
to whom and where it is to be diverted.
(iii) The Operator of the alternate delivery point must notify El
Paso, via El Paso's electronic scheduling system, that said
Operator has agreed to receive the diverted gas and must
specify the quantities to be diverted to each delivery
point.
(iv) El Paso shall compare the notifications to verify that the
transactions correspond and shall determine if all or part
of the requested transaction can be accommodated given the
current and anticipated pipeline loading and operating
conditions. A flow day diversion shall not have the effect
of bumping a Shipper moving gas under Rate Schedule IT-1 of
this Volume No. 1-A Tariff.
(v) If all or part of the transaction can be accommodated, El
Paso shall notify the Shipper and Operators involved what
portion of the transaction has been accepted.
<PAGE>
TF01005708112995El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03214 2 0 5P126Second Revised Sheet No. 214
TF04 First Revised Sheet No. 214
TF05Patricia A.Shelton, Vice President
TF06112895091395CP94-183-000 and 001010196
TF09E5 0 0 -1 0N112995122995RP96-52-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
4. SCHEDULING AND CAPACITY ALLOCATION (Continued)
4.1 Scheduling of Receipts and Deliveries (Continued)
(vi) The volumes scheduled to be diverted shall be assumed to
have flowed such that no imbalance exists as a result of the
diversion transactions at the end of the day of flow. Any
imbalance resulting from the difference between the total
scheduled quantities (including diversion volumes) and the
actual measured volumes shall be accounted for at the
delivery point or on a transportation service agreement, as
appropriate.
(vii) As a result of the diversion, Shipper shall not experience
any change to the originally scheduled volumes and shall be
invoiced as though the gas had been delivered to the
originally scheduled point.
4.2 Capacity Allocation Procedure - If, on any day, El Paso determines
that the capacity of its pipeline system, or any portion of such
system, is insufficient to serve all transportation confirmed on Day 1
or Day 2, then El Paso will schedule transportation in accordance with
the sequencing procedures set forth below until all available capacity
at the constrained location is allocated. Capacity shall be allocated
among Shippers on a nondiscriminatory basis. Subject to the foregoing,
capacity shall be allocated among Shippers in accordance with the
following:
Firm Allocation
(a) First, Shippers receiving service under Rate Schedule FT-2 for
delivery to primary delivery point(s), shall receive their full
requirements before all other Shippers without any requirements or
restrictions as to where the gas is received. Such service shall
be based on confirmed quantities not to exceed the capacity of the
facility to receive or deliver gas; then
(b) Second, pro rata among firm transportation Shippers, including
Acquiring Shippers receiving released capacity on
<PAGE>
TF01005708102795El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03215 1 0 5P126Substitute First Revised Sheet No. 215
TF04 First Revised Sheet No. 215
TF05Patricia A.Shelton, Vice President
TF06102695101295RP88-44-052 010495
TF09R2 0 0 -1 0N102795122195RP88-44-053
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
4. SCHEDULING AND CAPACITY ALLOCATION (Continued)
4.2 Capacity Allocation Procedure (Continued)
a firm or firm recallable basis under El Paso's Capacity Release
Program, for delivery from primary receipt to primary delivery
point(s) based on confirmed quantities not to exceed any
applicable maximum contract quantities; then
(c) Third, pro rata among all other firm transportation Shippers
utilizing either an alternate receipt or an alternate delivery
point, or both, based on confirmed volumes not to exceed the
capacity of the facility to receive or deliver gas nor to exceed
any Shipper's applicable maximum contract quantities.
(d) If, on Day 3, an interruption of service occurs which requires an
allocation of previously scheduled capacity, El Paso shall
allocate pursuant to this Section 4.2, but shall treat categories
(b) and (c) above equally for allocation purposes.
(e) If any firm Shipper notifies El Paso that it is experiencing a
bona fide emergency that would result in irreparable injury to
life or property or to provide minimum plant protection absent
availability of additional pipeline capacity, El Paso shall treat
the confirmed request for additional capacity to meet the
requirements of the emergency in the same manner as it treats
confirmed requests for capacity made by Shippers identified in
Section 4.2(a). A Shipper with a Contract Demand shall not be
entitled to emergency service in excess of its Contract Demand.
The emergency capacity available to a Shipper with a full
requirements contract shall be determined as that capacity
required to serve a verifiable emergency in excess of the quantity
initially scheduled by said Shipper. The Emergency Shipper shall
not use this provision to take advantage of price differences
between production basins. El Paso shall provide service under
this provision at a receipt point causing the least amount of
interruption among its Shippers. An authorized representative of
the Shipper must provide a sworn statement to El Paso by
facsimile, within 24 hours of the original notification, that
states: (1) the details and estimated length of the emergency; (2)
that all sources of gas available to Shipper are being used; (3)
that all
<PAGE>
TF01005708112495El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03215A 1 0 5P126First Revised Sheet No. 215A
TF04 Substitute Original Sheet No. 215A
TF05Patricia A.Shelton, Vice President
TF06112295092895RM95-3-000 122495
TF09E4 0 0 -1 0N112495122295RP96-49-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
4. SCHEDULING AND CAPACITY ALLOCATION (Continued)
4.2 Capacity Allocation Procedure (Continued)
interruptible services are unavailable; and (4) that no alternate
fuel can be used. Shipper shall notify El Paso immediately upon
cessation of the emergency. Allocation of capacity pursuant to
this provision is not an authorization to confiscate or divert any
shipper's supplies. El Paso shall have no responsibility hereunder
to furnish gas supplies for such emergency nor shall El Paso have
any liability if Shipper fails to make adequate gas supplies
available for such purpose. In the event such Shipper does not
arrange for adequate supplies during the emergency, then any
overpulls attributable to the emergency shall be billed at the
rate set forth in Section 20.12(d) of this tariff and all monies
received shall be credited to qualified Shippers as provided in
Section 20.12(e) of this tariff.
(f) In the event a firm Shipper requests and receives an emergency
exemption as provided in Section 4.2(e), El Paso shall charge the
Shipper receiving emergency service ("Emergency Shipper") all
usage rates, surcharges and applicable fuel, under the applicable
rate schedule for the volumes of gas scheduled or delivered to
that Shipper. If an Emergency Shipper receives emergency service
and, as a result, another Shipper receives less than its capacity
scheduled that day, then the Emergency Shipper will also be
charged an additional reservation charge equivalent to the highest
Rate Schedule FT-1 rate plus the high load factor GRI reservation
surcharge (both on a daily equivalent basis) multiplied by the
quantity by which the Emergency Shipper exceeded its scheduled
capacity and the number of applicable days. In the next monthly
invoice after collection of the additional reservation charge and
GRI reservation surcharge from the Emergency Shipper, El Paso will
credit said additional charges actually collected from the
Emergency Shipper to those firm Shippers that received less than
their capacity scheduled for that day. Such credit shall be made
on a pro rata basis based upon the quantity of scheduled capacity
which a Shipper did not receive divided by the sum of all such
quantities for all such Shippers. This provision does not limit
the rights of a firm Shipper whose capacity was allocated to the
Emergency Shipper from seeking damages from that Shipper, where
appropriate.
<PAGE>
TF01005708081495El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03215B 0 0 5P126Original Sheet No. 215B
TF04
TF05Patricia A.Shelton, Vice President
TF06081195071495RP88-44-050, et al. 010495
TF09E4 0 0 -1 0N081495101295RP88-44-052
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
4. SCHEDULING AND CAPACITY ALLOCATION (Continued)
4.2 Capacity Allocation Procedure (Continued)
After serving all firm requirements, then capacity shall be
allocated to interruptible service as follows:
Interruptible Allocation
(a) First, pro rata among Shippers who contracted prior to October 9,
1985 for interruptible transportation service, according to the
provisions of the applicable transportation contracts; then
(b) Second, among Shippers utilizing El Paso's interruptible
transportation service on a first-come/first-served basis as set
forth in Section 19 of these General Terms and Conditions; then
(c) Pro rata among Shippers receiving scheduled overrun
transportation.
<PAGE>
TF01005708112995El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03216 1 0 5P126First Revised Sheet No. 216
TF04 Original Sheet No. 216
TF05Patricia A.Shelton, Vice President
TF06112895091395CP94-183-000 and 001010196
TF09E5 0 0 -1 0N112995122995RP96-52-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
4. SCHEDULING AND CAPACITY ALLOCATION (Continued)
4.3 Adjustments to Confirmed Volumes Received by El Paso in the Event of
Supply Underperformance
(a) If, on any day, El Paso determines in its reasonable discretion
that underdelivery of natural gas into El Paso's system (supply
underperformance), if allowed to continue, could adversely affect
system integrity, El Paso shall have the right, after providing as
much advance notice as possible, to make adjustments at such point
to Operators' Day 1 confirmations to reflect more accurately such
Operators' previous actual deliveries of supply into El Paso's
system. An adjustment pursuant to this Section 4.3 shall not
eliminate Shippers' rights pursuant to the Day 2 scheduling
procedures set forth in Section 4.1(a). The provisions of this
Section 4.3 shall apply either until the underdelivery is
eliminated or until this threat to system integrity no longer
exists.
(b) El Paso shall identify potential threats to system integrity by
utilizing criteria such as: weather forecast for the market area
and producing area; system conditions, including outages,
maintenance, equipment availability and line pack; overall
projected pressures at various locations; and storage conditions.
(c) When supply underperformance occurs and the deficient source of
supply is immediately identifiable, El Paso shall make adjustments
to that Operator's confirmed volumes. Those supplies that are
independently verifiable by El Paso and which match the Operator's
confirmation shall not be subject to the provisions of this
Section 4.3. When the deficient source of supply is not
immediately identifiable, the smallest affected area shall be
identified and these procedures apply only to that portion of the
system.
The following procedures shall be used to adjust Operators'
confirmed volumes of natural gas in the event of supply
underperformance.
<PAGE>
TF01005708112995El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03217 1 0 5P126First Revised Sheet No. 217
TF04 Original Sheet No. 217
TF05Patricia A.Shelton, Vice President
TF06112895091395CP94-183-000 and 001010196
TF09E5 0 0 -1 0N112995122995RP96-52-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
4. SCHEDULING AND CAPACITY ALLOCATION (Continued)
4.3 Adjustments to Confirmation Volumes Received by El Paso in the Event
of Supply Underperformance (Continued)
(i) Receipts from interconnects shall be monitored by El Paso on
a daily basis where real time data is available. When actual
receipts are less than confirmed volumes and the shortfall
in receipts threatens the integrity of El Paso's system, El
Paso shall notify the interconnect Operator and request the
Operator to increase deliveries or reduce confirmed volumes
prospectively.
(ii) In the event an interconnect Operator fails to make
adjustments, El Paso shall limit, on a pro rata basis,
prospective confirmed volumes to actual receipts of supply
on the day in question. Higher confirmations shall be
allowed prospectively only when the Operator increases
volumes of gas into El Paso's system.
<PAGE>
TF01005708112995El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03218 1 0 5P126First Revised Sheet No. 218
TF04 Sheet Nos. 218 and 219
TF05Patricia A.Shelton, Vice President
TF06112895091395CP94-183-000 and 001010196
TF09E5 0 0 -1 0N112995122995RP96-52-000
Reserved sheets
Second Revised Sheet No. 218 and First Revised
Sheet No. 219 have been reserved.
<PAGE>
TF01005708052494El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03220 0 0 5P126Original Sheet No. 220
TF04
TF05A.W.Clark, Vice President
TF06052394****** 070194
TF09E2 0 0 -1 0N052494061694GT94-46-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
5. QUALITY
5.1 All natural gas received by El Paso at any mainline Receipt Point(s)
shall conform to the following specifications and must be, in El
Paso's reasonable judgment, otherwise merchantable:
(a) Liquids - The gas shall be free of water and hydrocarbons in
liquid form at the temperature and pressure at which the gas is
received. The gas shall in no event contain water vapor in excess
of seven (7) pounds per million standard cubic feet.
(b) Hydrocarbon Dew Point - The hydrocarbon dew point of the gas
received shall not exceed twenty degrees Fahrenheit (20 degrees F)
at normal pipeline operating pressures.
(c) Total Sulfur - The gas shall not contain more than five (5) grains
of total sulfur per one hundred (100) standard cubic feet, which
includes hydrogen sulfide, carbonyl sulfide, carbon disulfide,
mercaptans, and mono-, di- and poly-sulfides. The gas shall also
meet the following individual specifications for hydrogen sulfide,
mercaptan sulfur or organic sulfur:
(i) Hydrogen Sulfide - The gas shall not contain more than
one-quarter (0.25) grain of hydrogen sulfide per one
hundred (100) standard cubic feet.
(ii) Mercaptan Sulfur - The mercaptan sulfur content shall
not exceed more than three-quarters (0.75) grain per
one hundred (100) standard cubic feet.
(iii) Organic Sulfur - The organic sulfur content shall not
exceed one and one-quarter (1.25) grains per one
hundred (100) standard cubic feet, which includes
mercaptans, mono-, di-and poly-sulfides, but it does
not include hydrogen sulfide, carbonyl sulfide or
carbon disulfide.
(d) Oxygen - The oxygen content shall not exceed two-tenths of one
percent (0.2%) by volume and every reasonable effort shall be made
to keep the gas delivered free of oxygen.
<PAGE>
TF01005708052494El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03221 0 0 5P126Original Sheet No. 221
TF04
TF05A.W.Clark, Vice President
TF06052394****** 070194
TF09E2 0 0 -1 0N052494061694GT94-46-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
5. QUALITY (Continued)
5.1 (Continued)
(e) Carbon Dioxide - The gas shall not have a carbon dioxide content
in excess of two percent (2%) by volume, except for gas applicable
to Sections 5.2 and 5.3.
(f) Diluents - The gas shall not at any time contain in excess of
three percent (3%) total diluents (the total combined carbon
dioxide, nitrogen, helium, oxygen, and any other diluent compound)
by volume, except for gas applicable to Sections 5.2 and 5.3.
(g) Dust, Gums and Solid Matter - The gas shall be commercially free
of dust, gums and other solid matter.
(h) Heating Value - The gas shall have a heating value of not less
than 967 Btu per cubic foot.
(i) Temperature - The gas received by El Paso shall be at temperatures
not in excess of one hundred twenty degrees Fahrenheit (120
degrees F) nor less than fifty degrees Fahrenheit (50 degrees F).
Any party tendering gas at a temperature standard less than fifty
degrees Fahrenheit (50 degrees F) shall receive a waiver of such
standard only if a test has been conducted in accordance with
procedures set forth in Section 5.12(b) hereof and the results
from such test demonstrate that the particular segment of the
pipeline tested can be safely operated below the fifty degrees
Fahrenheit (50 degrees F) temperature standard.
(j) Deleterious Substances - The gas shall not contain deleterious
substances in concentrations that are hazardous to health,
injurious to pipeline facilities or adversely affect
merchantability.
5.2 El Paso agrees that plant Receipt Points on El Paso's system, where
gas does not conform to the carbon dioxide and/or the total diluent
specification set forth in Sections 5.1(e) and (f) above, shall be
grandfathered based on the highest non-conforming monthly average
percentages of carbon dioxide and total diluents for a month during
the twelve (12) month base period ended July 31, 1990. El Paso shall
accept gas with carbon dioxide and/or total diluents at percentages up
to the non-conforming specifications at
<PAGE>
TF01005708052494El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03222 0 0 5P126Original Sheet No. 222
TF04
TF05A.W.Clark, Vice President
TF06052394****** 070194
TF09E2 0 0 -1 0N052494061694GT94-46-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
5. QUALITY (Continued)
5.2 (Continued)
volumes up to the residue volume at the plant design capacity as it
exists on July 31, 1990; provided, however, to the extent El Paso must
curtail non-conforming volumes to meet El Paso's delivery point
specifications for carbon dioxide and/or total diluents, El Paso shall
curtail volumes at these plants down to 125% of historical volumes in
accordance with Section 5.5. Historical volumes for non-conforming
plants shall be deemed to be the daily average for the highest monthly
tailgate volume delivered to El Paso during the twelve (12) month base
period ended July 31, 1990 and in the event a non-conforming plant or
plants are closed, El Paso shall transfer the applicable historical
volumes to another plant. To the extent a Shipper and/or a plant
operator can demonstrate to El Paso that the specifications and/or
historical volumes set forth below are in error or that any other
plant located on El Paso's system has not historically met the carbon
dioxide and the total diluents specifications set forth in Sections
5.1(e) and (f) above, El Paso shall either modify accordingly these
specifications and/or historical volumes set forth below or
grandfather such other plants on the same basis as the plants
identified above, as appropriate. The identification of the non-
conforming plants, the grandfathered specifications and the historical
volumes are set forth on the table below.
NON-CONFORMING PLANTS
<TABLE>
<CAPTION>
GRANDFATHERED
SPECIFICATIONS HISTORICAL
METER TOTAL DILUENTS VOLUME
LOCATION CODE CO2 MOL% MOL% (MCF/D)
<S> <C> <C> <C> <C>
Amoco Slaughter Plant
(IAMSLAUG) 77-039 - 11.89 6,915
Barnhart Plant (J.L. Davis)
(IBARNHRT) 77-002 - 3.55 6,149
Big Lake Texon Plant
(Damson Oil Corp.)
(ITEXON) 77-055 9.67 2,362
Chevron Puckett Plant
(IPUCKETT) 14-261 3.55 4.09 37,390
Conoco Ramsey Plant
(IRAMSEY) 77-095 - 6.38 4,579
</TABLE>
<PAGE>
TF01005708052494El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03223 0 0 5P126Original Sheet No. 223
TF04
TF05A.W.Clark, Vice President
TF06052394****** 070194
TF09E2 0 0 -1 0N052494061694GT94-46-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
5. QUALITY (Continued)
5.2 (Continued)
NON-CONFORMING PLANTS
(CONTINUED)
<TABLE>
<CAPTION>
GRANDFATHERED
SPECIFICATIONS HISTORICAL
METER TOTAL DILUENTS VOLUME
LOCATION CODE CO2 MOL% MOL% (MCF/D)
<S> <C> <C> <C> <C>
Exxon Snyder Plant
(Oryx Energy)
(IEXSNYDR) 77-009 - 7.42 696
Jal Complex
(IJALCPLX) 01-814 - 4.31 28,518
Jameson Plant (Oryx Energy)
(ISUNJAME) 77-078 - 7.02 2,823
Meridian Benedum Plant
(MOHI)(IHYBENDM) 02-304 - 3.18 75,585
Midkiff Plant
(IMIDKIFF) 01-079 - 4.95 39,371
Midway Lane Plant
(Apache Gas Corporation)
(IMIDWAY) 03-933 - 4.45 4,617
Permian Corp. CPD #2
(IPERTOD2) 14-082 - 6.03 6,620
Phillips Goldsmith Plant
(IPHGOLDS) 02-381 - 5.23 62,267
Phillips Lee Plant
(IPHLEE) 77-025 - 7.34 27,484
Phillips Eunice Plant
(IPHEUNIC) 77-287 - 5.15 57,672
Phillips Fullerton Plant
(IPHFULTN) 77-289 - 6.18 28,200
Phillips Spraberry Plant
(IPHSPBRY) 77-248 - 4.64 11,277
San Juan River Plant
(ISJRVPLT) 01-125 - 4.35 32,827
Shell TXL Plant (ISHTXL) 77-029 - 6.17 12,054
Shell Wasson Plant
(ISHWASON) 01-106 - 5.98 8,682
Terrell Plant
(ITERRELL) 01-596 2.89 .53 02,708
</TABLE>
<PAGE>
TF01005708052494El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03224 0 0 5P126Original Sheet No. 224
TF04
TF05A.W.Clark, Vice President
TF06052394****** 070194
TF09E2 0 0 -1 0N052494061694GT94-46-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
5. QUALITY (Continued)
5.2 (Continued)
NON-CONFORMING PLANTS
(CONTINUED)
<TABLE>
<CAPTION>
GRANDFATHERED
SPECIFICATIONS HISTORICAL
METER TOTAL DILUENTS VOLUME
LOCATION CODE CO2 MOL% MOL% (MCF/D)
<S> <C> <C> <C> <C>
Texaco Fuller
(ITEXFULR) 77-036 .66 61
Texaco Vealmoor Plant
(IVEALMOR) 77-028 .32 0,204
Tipperary Denton Plant
(J.L. Davis)(IDENTON) 77-001 - 5.02 2,554
Union of California
Dollarhide Plant
(IUTDOLHD) 77-027 - 6.42 2,056
Union Texas Perkins Plant
(IUTPERKN) 77-068 - 10.19 9,178
Val Verde
(IMOITRKA) 14-136 2.13 - 195,985
Warren Monument
(IWARMONU) 77-045 - 4.04 31,576
Warren Saunders Plant
(IWARSAUD) 77-046 - 5.75 12,421
</TABLE>
5.3 El Paso agrees that interconnect Receipt Points on El Paso's system,
where gas does not conform to the carbon dioxide and/or the total
diluent specification set forth in Sections 5.1(e) and (f) above,
shall be grandfathered based on the twelve (12) month average non-
conforming percentages of carbon dioxide and total diluents for the
twelve (12) month base period ended July 31, 1990. El Paso shall
accept gas with carbon dioxide and/or total diluents at percentages up
to the grandfathered non-conforming specifications at volumes up to
the historical volume. The historical volume is deemed to be the daily
average volume received by El Paso at each of the non-conforming
interconnect Receipt Points for the twelve (12) month base period
ended July 31, 1990. The identification of the non-conforming
interconnects, the grandfathered specifications and the historical
volumes are set forth on the following table:
<PAGE>
TF01005708112995El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03225 1 0 5P126First Revised Sheet No. 225
TF04 Original Sheet No. 225
TF05Patricia A.Shelton, Vice President
TF06112895091395CP94-183-000 and 001010196
TF09E5 0 0 -1 0N112995122995RP96-52-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
5. QUALITY (Continued)
5.3 (Continued)
NON-CONFORMING INTERCONNECTS
<TABLE>
<CAPTION>
TOTAL HISTORICAL
METER CO2 DILUENTS VOLUME
LOCATION CODE MOL% MOL% (MCF/D)
<S> <C> <C> <C> <C>
Big Blue Receipt Point
(Colorado Interstate)
(IBIGBLUE) 14-091 - 9.50 11,900
Colorado Dry Gas
(ICOLODRY) - 3.13 3.22 37,595
Howe Ranch Discharge
(Meridian) 02-721 4.12 5.20 3,480
Northern Natural Plains
(INN30PLA) 40-019 - 4.22 111,072
Plains Compressor
(Westar-Felmac)
(IW40-043) 40-043 - 4.50 8,464
</TABLE>
5.4 In addition, El Paso agrees to grandfather the sulfur specifications set
forth in Section 5.1(c) above for natural gas received at the tailgate of
the Terrell and Puckett Plants, based on the actual monthly highest
non-conforming concentrations during the twelve (12) month base period
ending July 31, 1990. The sulfur specifications El Paso shall accept for
natural gas at volumes up to the residue volume at plant design capacity
received at the tailgate of the Terrell and Puckett Plants are identified
below. To the extent a Shipper can demonstrate to El Paso that any other
plant located on El Paso's system has not historically met the sulfur
specifications set forth in Section 5.1(c) above, El Paso shall
grandfather such plant on the same basis as the Terrell and Puckett
Plants; provided, however, a plant shall not qualify if such plant has
changed the method of processing the gas in the last five (5) years.
Grandfathered Non-conforming Sulfur Specifications
(grains per 100 standard cubic feet)
<TABLE>
<CAPTION>
TOTAL HYDROGEN MERCAPTAN ORGANIC
LOCATION SULFUR SULFIDE SULFUR SULFUR
<S> <C> <C> <C> <C> <C>
Terrell Plant - 0.45 - -
Puckett Plant - 0.45 - -
</TABLE>
<PAGE>
TF01005708052494El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03226 0 0 5P126Original Sheet No. 226
TF04
TF05A.W.Clark, Vice President
TF06052394****** 070194
TF09E2 0 0 -1 0N052494061694GT94-46-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
5. QUALITY (Continued)
5.5 El Paso agrees to accept natural gas (including volumes in excess of
the volumes identified in Sections 5.2 and 5.3) which does not conform
to the quality specifications set forth in Sections 5.1(e) and (f) at
the Receipt Point(s), but only until such time as El Paso, in its
reasonable discretion and judgement, determines that such natural gas
must conform to the quality specifications set forth above to maintain
prudent operation of part or all of El Paso's system. In exercising
its discretion to discontinue accepting nonconforming natural gas
under this Section, El Paso will consider only the volume,
compositions and location of the gas, and the impact of its continued
introduction into El Paso's system on El Paso's operations and an
ability to meet its obligations to third parties, and will
appropriately document the basis for its decision. Upon determining
that it will no longer accept non-conforming volumes, El Paso will
notify Shippers and/or plant operators that all prospective deliveries
must comply with the quality specifications set forth above and that
the provisions of Section 5.8 below shall be applicable to all natural
gas tendered for transportation which does not so comply. In the event
the aforementioned occurrences cause El Paso to curtail volumes at
plant and/or interconnect Receipt Points such curtailment shall
exclude those plant and/or interconnect volumes identified in Sections
5.2 and 5.3, provided, however, if El Paso determines that it must
further curtail volumes of non-conforming gas to meet El Paso's
delivery specifications for carbon dioxide and/or total diluents, El
Paso shall curtail volumes down to 125% of the historical volumes for
those plants identified in Section 5.2 on the following basis:
(a) First, volumes of natural gas that did not meet the 967 Btu
standard would be curtailed in order of lowest Btu to highest down
to the level of 125% of historical volumes;
(b) Second, plants with pipeline interconnects in addition to El Paso
would be curtailed down to the level of 125% of historical volumes
on a pro rata basis; and
(c) Third, all other volumes would be curtailed on a pro rata basis,
based on a percentage of such volumes that are out of compliance
as to the particular substance that is causing the problem, down
to 125% of historical volumes.
<PAGE>
TF01005708112995El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03227 1 0 5P126First Revised Sheet No. 227
TF04 Original Sheet No. 227
TF05Patricia A.Shelton, Vice President
TF06112895091395CP94-183-000 and 001010196
TF09E5 0 0 -1 0N112995122995RP96-52-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
5. QUALITY (Continued)
5.5 (Continued)
Based on the curtailment procedure as documented above, El Paso will
determine the volume of gas, not to be less than 125% of historical
volumes, that will be allowed to enter El Paso's system at the
grandfathered carbon dioxide and/or total diluent specifications for
each non-conforming plant and will notify the plant operator of such
volumes. Following such initial notification to plant operators, El
Paso shall provide a written notice accompanied by a verification of
non-compliance and provide audit rights to all affected Shippers and
operators, in order to ensure compliance with the above curtailment
procedures.
5.6 This Section reserved.
5.7 This Section reserved.
(THIS SPACE INTENTIONALLY LEFT BLANK)
<PAGE>
TF01005708112995El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03228 1 0 5P126First Revised Sheet No. 228
TF04 Sheet Nos. 228 through 232
TF05Patricia A.Shelton, Vice President
TF06112895091395CP94-183-000 and 001010196
TF09E5 0 0 -1 0N112995122995RP96-52-000
Reserved Sheets
Second Revised Sheet No. 228 and First Revised
Sheet Nos. 229 through 232 have been reserved.
<PAGE>
TF01005708052494El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03233 0 0 5P126Original Sheet No. 233
TF04
TF05A.W.Clark, Vice President
TF06052394****** 070194
TF09E2 0 0 -1 0N052494061694GT94-46-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
5. QUALITY (Continued)
5.8 If, at any time, gas tendered by Shipper for transportation shall fail
to substantially conform to any of the applicable quality
specifications set forth in Section 5.1 above and El Paso notifies
Shipper of such deficiency and Shipper fails to remedy any such
deficiency within a reasonable period of time (immediately in those
situations which threaten the integrity of El Paso's system), El Paso
may, at its option, refuse to accept delivery pending correction of
the deficiency by Shipper or continue to accept delivery and make such
changes necessary to cause the gas to conform to such specifications,
in which event Shipper shall reimburse El Paso for all reasonable
expenses incurred by El Paso in effecting such changes, including
operational and gas costs associated with purging and/or venting the
pipeline. Failure by Shipper to tender quantities that conform to any
of the applicable quality specifications shall not be construed to
eliminate, or limit in any manner, the obligations of Shipper existing
under any other provisions of the executed Transportation Service
Agreement. In the event natural gas is delivered into El Paso's system
that would cause the natural gas in a portion of El Paso's pipeline to
become unmerchantable, then El Paso is permitted to act expediently to
make the gas merchantable again by any and all reasonable methods,
including, without limitation, to venting the pipeline of whatever
quantity of natural gas necessary to achieve a merchantable stream of
gas. Shipper shall reimburse El Paso for all reasonable expenses
incurred by El Paso to obtain merchantable natural gas again,
including operational and gas costs associated with venting the
pipeline. In such cases, El Paso shall promptly notify Shipper of the
non-conforming supply and any steps taken to protect the
merchantability of the gas.
5.9 After giving sufficient notice to a Shipper, El Paso shall have the
right to collect from all Shippers delivering gas to El Paso at a
common Receipt Point their volumetric pro rata share of the cost of
any additional hydrogen sulfide analysis and/or water vapor analysis
equipment which El Paso, at its reasonable discretion, determines is
required to be installed at such Receipt Point to monitor the quality
of gas delivered.
5.10 Except as otherwise provided below, all natural gas delivered by El
Paso shall conform to the following specifications:
<PAGE>
TF01005708052494El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03234 0 0 5P126Original Sheet No. 234
TF04
TF05A.W.Clark, Vice President
TF06052394****** 070194
TF09E2 0 0 -1 0N052494061694GT94-46-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
5. QUALITY (Continued)
5.10 (Continued)
(a) Liquids - The gas shall be free of water and hydrocarbons in
liquid form at the temperature and pressure at which the gas is
delivered. The gas shall in no event contain water vapor in excess
of seven (7) pounds per million standard cubic feet.
(b) Hydrocarbon Dew Point - The hydrocarbon dew point of the gas
delivered shall not exceed twenty degrees Fahrenheit (20 degrees
F) at a pressure of 600 psig.
(c) Total Sulfur - The gas shall not contain more than three-quarters
(0.75) grain of total sulfur per one hundred (100) standard cubic
feet, which includes hydrogen sulfide, carbonyl sulfide, carbon
disulfide, mercaptans, and mono-, di- and poly-sulfides. The gas
shall also meet the following individual specifications for
hydrogen sulfide, mercaptan sulfur or organic sulfur:
(i) Hydrogen Sulfide - The gas shall not contain more than one-
quarter (0.25) grain of hydrogen sulfide per one hundred
(100) standard cubic feet.
(ii) Mercaptan Sulfur - The mercaptan sulfur content shall not
exceed more than three-tenths (0.3) grain per one hundred
(100) standard cubic feet.
(iii) Organic Sulfur - The organic sulfur content shall not exceed
five-tenths (0.5) grain per one hundred (100) standard cubic
feet, which includes mercaptans, mono-, di- and poly-
sulfides, but it does not include hydrogen sulfide, carbonyl
sulfide or carbon disulfide.
(d) Oxygen - The oxygen content shall not exceed two-tenths of one
percent (0.2%) by volume and every reasonable effort shall be made
to keep the gas delivered free of oxygen.
(e) Carbon Dioxide - The gas shall not have a carbon dioxide content
in excess of three percent (3%) by volume.
<PAGE>
TF01005708052494El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03235 0 0 5P126Original Sheet No. 235
TF04
TF05A.W.Clark, Vice President
TF06052394****** 070194
TF09E2 0 0 -1 0N052494061694GT94-46-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
5. QUALITY (Continued)
5.10 (Continued)
(f) Diluents - The gas shall not at any time contain in excess of four
percent (4%) total diluents (the total combined carbon dioxide,
nitrogen, helium, oxygen, and any other diluent compound) by
volume.
(g) Dust, Gums and Solid Matter - The gas shall be commercially free
from solid matter, dust, gums, and gum forming constituents, or
any other substance which interferes with the intended purpose or
merchantability of the gas, or causes interference with the proper
and safe operation of the lines, meters, regulators, or other
appliances through which it may flow.
(h) Heating Value - The gas shall have a heating value of not less
than 967 Btu per cubic foot. For natural gas delivered at the
border between the States of Arizona and California, the gas shall
have a heating value of not less than 995 Btu per cubic foot.
(i) Temperature - The gas shall be delivered at temperatures not in
excess of one hundred five degrees Fahrenheit (105 degrees F) nor
less than fifty degrees Fahrenheit (50 degrees F) except where,
due to normal operating conditions and ambient temperatures on the
pipeline system the temperature may periodically drop below such
lower limit.
(j) Deleterious Substances - The gas shall not contain any toxic or
hazardous substance, in concentrations which, in the normal use of
the gas, may be hazardous to health, injurious to pipeline
facilities or be a limit to merchantability.
If, at any time, gas tendered for delivery by El Paso shall fail to
substantially conform to any of the specifications set forth in this
Section 5.10, Shipper or its designee agrees to notify El Paso of such
deficiency and if El Paso fails to promptly remedy any such deficiency
within a reasonable time, then Shipper or its designee may, at its
option, refuse to accept delivery pending correction of the deficiency
by El Paso or continue to accept delivery and make such changes as
necessary to cause the gas to conform to such specifications, in which
event El Paso shall reimburse Shipper or its designee for all
reasonable expenses incurred by Shipper or its designee in effecting
such changes.
<PAGE>
TF01005708112995El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03236 1 0 5P126First Revised Sheet No. 236
TF04 Original Sheet No. 236
TF05Patricia A.Shelton, Vice President
TF06112895091395CP94-183-000 and 001010196
TF09E5 0 0 -1 0N112995122995RP96-52-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
5. QUALITY (Continued)
5.11 The quality specifications set forth in Section 5.10 above shall not
apply to natural gas caused to be delivered by El Paso at delivery
points in production areas designated as "Field Gas" on Exhibits A
and/or B of an executed Transportation Service Agreement or any
delivery point in production areas receiving gas delivered by El Paso
on July 31, 1990 that did not meet the quality specifications set
forth in Section 5.10 above. Gas so designated shall be of such
quality as may exist in the delivering pipeline from time to time at
such points and El Paso makes no warranty of merchantability or
fitness for any purpose with respect to such gas.
5.12 Testing Procedures - The following test procedures shall be utilized
by El Paso.
(a) To determine whether specified sulfur compound limitations are
being met as stated under Section 5.1(c) and 5.10(c) hereof, El
Paso shall use the appropriate American Society for Testing
Materials Procedures (as revised) Volume 05.05 Gaseous Fuels; Coal
and Coke and/or accepted industry practices such as sulfur
titrators and chromatographs.
(b) To determine whether specific points on El Paso's system can
operate below the fifty degree Fahrenheit (50 degrees F) tolerance
as stated in Section 5.1(i), El Paso shall use the Charpy impact
and drop-weight tear tests in accordance with API-5L Supplemental
Requirements 5 and 6, respectively. Inasmuch as this test requires
the shutdown of the specific segment of the system being tested,
El Paso shall conduct such test only at a time when operations on
such segments are not affected or the safety of the system is not
put in jeopardy.
<PAGE>
TF01005708052494El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03237 0 0 5P126Original Sheet No. 237
TF04
TF05A.W.Clark, Vice President
TF06052394****** 070194
TF09Z2 0 0-1 0N052494061694GT94-46-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
6. BILLING AND PAYMENT
6.1 Billing - On or before the fifteenth (15th) day of each month El Paso
shall mail to Shipper an invoice evidencing the bill for services
rendered to Shipper under the executed Transportation Service
Agreement during the preceding month. When Shipper is in control of
information required by El Paso to prepare invoices, Shipper shall
cause such information to be received by El Paso on or before the
tenth (10th) day of the month immediately following the month to which
the information applies.
6.2 Payment by Wire Transfer - Payment to El Paso for services rendered
during the preceding month shall be due on the twenty-sixth (26th) day
of the calendar month next succeeding that month for which such
service was rendered and shall be paid by Shipper on or before such
due date. Subject to the provisions of Section 6.3 below, Shipper
shall make such payment to El Paso by wire transfer in immediately
available funds to a depository designated by El Paso. When the due
date falls on a day that the designated depository is not open in the
normal course of business to receive Shipper's payment, Shipper shall
cause such payment to be actually received by El Paso on or before the
first business day on which the designated depository is open after
such due date.
6.3 Payment Other Than by Wire Transfer - In the event in any month, that
Shipper does not make payment by wire transfer, then payment to El
Paso for services rendered during the preceding month shall be due on
the twenty-fifth (25th) day of the calendar month next succeeding that
month for which such service was rendered. Shipper shall cause payment
for such bill to be actually received by El Paso at its offices in El
Paso, Texas, directed to the attention of General Accounting, on or
before such due date. When the due date falls on a day that El Paso's
offices located in El Paso, Texas, are not open in the normal course
of business to receive Shipper's payment, Shipper shall cause such
payment to be actually received by El Paso on or before the last
business day on which El Paso's offices located in El Paso, Texas, are
open prior to such due date.
<PAGE>
TF01005708052494El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03238 0 0 5P126Original Sheet No. 238
TF04
TF05A.W.Clark, Vice President
TF06052394****** 070194
TF09E2 0 0 -1 0N052494061694GT94-46-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
6. BILLING AND PAYMENT (Continued)
6.4 Failure to Pay Bills - Should Shipper fail to pay all of the amount of
any bill for gas delivered under the executed Transportation Service
Agreement when such amount is due, as herein provided, Shipper shall
pay El Paso interest on the unpaid balance that shall accrue on each
calendar day from the twenty-fifth (25th) day of the month during
which payment was due at a rate equal to two percent (2%) above the
then effective prime commercial lending rate per annum announced from
time to time by The Chase Manhattan Bank (N.A.) at its principal
office in New York City, provided that for any period that such
interest exceeds any applicable maximum rate permitted by law, the
interest shall equal said applicable maximum rate. The interest
provided for by this Section 6.4 shall be compounded monthly. Unless
otherwise mutually agreed between the parties, if either principal or
interest are due, any payments thereafter received shall first be
applied to the interest due, then to the previously outstanding
principal due and, lastly, to the most current principal due. Subject
to requirements of regulatory bodies having jurisdiction and without
prejudice to any other rights and remedies available to El Paso under
the law and the executed Transportation Service Agreement, El Paso
shall have the right to suspend transportation service without
obtaining additional prior approval from the Commission if any amount
billed to Shipper remains unpaid for more than thirty (30) days after
the due date thereof; provided, however, prior to suspension El Paso
shall follow these notification procedures.
(a) First Notice: On or about ten (10) days after the due date of any
payment, El Paso shall contact Shipper by telephone or other
routine communication means to advise that unpaid bills may lead
to suspension of transportation service when more than thirty (30)
days past due;
(b) Second Notice: On or about twenty (20) days after the due date of
any payment, El Paso shall notify Shipper by written
correspondence to advise that continued failure to pay bills can
lead to suspension of transportation service when the bill becomes
more than thirty (30) days past due;
<PAGE>
TF01005708052494El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03239 0 0 5P126Original Sheet No. 239
TF04
TF05A.W.Clark, Vice President
TF06052394****** 070194
TF09E2 0 0 -1 0N052494061694GT94-46-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
6. BILLING AND PAYMENT (Continued)
6.4 Failure to Pay Bills (Continued)
(c) Final Notice: Not less than five (5) days prior to the thirtieth
(30th) day after the due date of any payment or five (5) days
before El Paso intends to suspend service under this Section 6.4,
if such suspension will occur more than thirty (30) days after the
due date, El Paso shall inform the Commission, interested State
utility regulators, and Shipper in writing and delivered by any
reliable and expeditious means available, that transportation
service shall be suspended;
provided further, however, that in the event of a bona fide dispute
between the parties concerning the amount billed of the unpaid bill,
El Paso shall not suspend transportation service under the
notification procedure outlined above when Shipper acts in a timely
manner to provide additional information and security for El Paso in
accordance with the following procedures.
(d) Identify Dispute: Within fifteen (15) days after the due date of
any payment, Shipper shall notify El Paso by written
correspondence of the amount billed that is in bona fide dispute
and of all reasons and documentation why Shipper believes full
payment is not now appropriate; and
(e) Payment Security: Within thirty (30) days after the due date of any
payment, Shipper shall either pay in full the total amount billed
without prejudice to Shipper's rights to dispute all or part of
said amount and subject to return by El Paso of the disputed amount
so identified, with interest calculated in accordance with this
Section 6.4, after resolution of that dispute in favor of Shipper,
or pay the undisputed portion of the amount billed in full and
furnish good and sufficient surety bond, guaranteeing payment to El
Paso of all amounts ultimately found due after resolution of the
dispute, including the amount now in dispute plus the estimated
interest calculated in accordance with this Section 6.4 that
accrues until resolution of the dispute, which may be reached
either by agreement or judgment of a court of competent
jurisdiction; provided, however, neither El Paso nor Shipper shall
calculate or pay interest on
<PAGE>
TF01005708052494El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03240 0 0 5P126Original Sheet No. 240
TF04
TF05A.W.Clark, Vice President
TF06052394****** 070194
TF09E2 0 0 -1 0N052494061694GT94-46-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
6. BILLING AND PAYMENT (Continued)
6.4 Failure to Pay Bills (Continued)
any amounts of less than $10,000. If resolution of the dispute is
in favor of Shipper and the Shipper furnished a surety bond
instead of paying the disputed amount, then El Paso shall refund
to Shipper the costs incurred in securing that surety bond for
this dispute. This section does not apply to ordinary adjustments
of overcharges and undercharges in accordance with Section 6.5.
6.5 Adjustment of Overcharge and Undercharge - If it shall be found that
at any time or times, within the time limits of Section 6.7 below,
Shipper has been overcharged or undercharged in any form whatsoever
under the provisions hereof as a result of an error in billing for
which El Paso is solely responsible and Shipper shall have actually
paid the bill containing such overcharge or undercharge, then, unless
mutually agreed otherwise, within thirty (30) days after the final
determination thereof, and except where otherwise required by statute,
rule, regulation or order, El Paso shall refund the amount of any such
overcharge, with interest thereon at the then effective rate computed
in the same manner as set forth in Section 6.4 above, and Shipper
shall pay the amount of any such undercharge, with interest thereon at
the then effective rate computed in the same manner as set forth in
Section 6.4 above. Interest on overcharges or undercharges shall be
calculated from the time such overcharge or undercharge was paid to
the date of refund or payment, respectively; provided, however,
neither El Paso nor Shipper shall calculate or pay interest on any
amounts of less than $10,000. This section does not apply to payments
subject to a billing dispute in accordance with Section 6.4.
6.6 Delayed Bill or Notice - If El Paso fails to render or otherwise fails
to mail any bill by the fifteenth (15th) day of the month then the
time of payment shall be extended by one (1) day for each day that the
rendering of said bill is delayed unless Shipper is responsible for
such delay. If El Paso fails to render or otherwise fails to mail any
notice within the time specified in this Billing and Payment Section,
then the time for Shipper's response to such notice shall be extended
by one (1) day for each day that the rendering of said notice is
delayed unless Shipper is responsible for such delay.
<PAGE>
TF01005708112495El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03241 1 0 5P126First Revised Sheet No. 241
TF04 Original Sheet No. 241
TF05Patricia A.Shelton, Vice President
TF06112295092895RM95-3-000 122495
TF09E4 0 0 -1 0N112495122295RP96-49-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
6. BILLING AND PAYMENT (Continued)
6.7 Adjustment of Errors - In the event an error is discovered in any
invoice that El Paso renders, such error shall be adjusted within
thirty (30) days of the determination thereof; provided, however, that
any claim for adjustment must be made within twelve (12) months from
the date of such invoice.
6.8 Fees - Shipper shall reimburse El Paso for all filing and other fees
actually paid by El Paso pursuant to the Commission's Regulations
which are attributable to an executed Transportation Service
Agreement.
6.9 Order of Discounts - If El Paso charges less than the maximum
reservation rate for transportation service provided under Rate
Schedule FT-1, El Paso will recognize discounts in the following
order. The first item of the overall reservation charge discounted
will be the GRI surcharge, followed by the base rate reservation
charge, and last the Washington Ranch Reservation Surcharge.
<PAGE>
TF01005708052494El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03242 0 0 5P126Original Sheet No. 242
TF04
TF05A.W.Clark, Vice President
TF06052394****** 070194
TF09E2 0 0 -1 0N052494061694GT94-46-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
7. FORCE MAJEURE
7.1 Effect of Force Majeure - In the event of either El Paso or Shipper
being rendered unable by force majeure to wholly or in part carry out
its obligations under the provisions of the executed Transportation
Service Agreement, it is agreed that the obligations of the party
affected by such force majeure, other than to make payments due, shall
be suspended without liability for breach of contract during the
continuance of any inability so caused but for no longer period, and
such cause shall, so far as possible, be remedied with all reasonable
dispatch. A force majeure event affecting the performance by either
party shall not relieve it of liability in the event of its concurring
negligence, where such negligence was a cause of the force majeure
event, or in the event of its failure to use reasonable diligence to
remedy the situation and remove the cause in an adequate manner and
with all reasonable dispatch, nor shall such causes or contingencies
relieve either party of liability unless such party shall give notice
and full particulars of the same in writing to the other party as soon
as possible after the occurrence relied on.
7.2 Definition of Force Majeure - The term "force majeure" as employed
herein shall mean acts of God, strikes, lockouts or other industrial
disturbances, failure of any third parties necessary to the
performance by either El Paso or Shipper under the executed
Transportation Service Agreement, inability to obtain pipe or other
material or equipment or labor, wars, riots, insurrections, epidemics,
landslides, lightning, earthquakes, fires, storms, floods, washouts,
arrests and restraint of rulers and people, interruptions by
government or court orders, present or future orders of any regulatory
body having proper jurisdiction, civil disturbances, explosions,
breakage or accident to machinery or lines of pipe, freezing of wells
or pipelines, and any other cause whether of the kind herein
enumerated or otherwise, not within the control of the party claiming
suspension and which, by the exercise of due diligence, such party is
unable to overcome. Nothing contained herein, however, shall be
construed to require either party to settle a strike against its will.
<PAGE>
TF01005708052494El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03243 0 0 5P126Original Sheet No. 243
TF04
TF05A.W.Clark, Vice President
TF06052394****** 070194
TF09E2 0 0 -1 0N052494061694GT94-46-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
8. CONTROL AND POSSESSION OF NATURAL GAS
8.1 As between El Paso and Shipper, El Paso shall be deemed to be in
control and possession of the natural gas from the time it is
delivered to El Paso at the Receipt Point(s) until it is redelivered
to Shipper at the Delivery Point(s), and Shipper shall be deemed to be
in control and possession of the natural gas at all other times.
<PAGE>
TF01005708052494El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03244 0 0 5P126Original Sheet No. 244
TF04
TF05A.W.Clark, Vice President
TF06052394****** 070194
TF09E2 0 0 -1 0N052494061694GT94-46-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
9. ADVERSE CLAIMS TO NATURAL GAS
9.1 Notwithstanding Section 10.1 herein, Shipper agrees to indemnify and
hold harmless El Paso, its officers, agents, employees and contractors
against any liability, loss or damage whatsoever, including litigation
expenses, court costs and attorneys' fees, suffered by El Paso, its
officers, agents, employees or contractors, where such liability, loss
or damage arises directly or indirectly out of any demand, claim,
action, cause of action or suit brought by any person, association or
entity, public or private, asserting ownership of or an interest in
the natural gas tendered for transportation or the proceeds resulting
from any sale of that natural gas. The receipt and delivery of natural
gas under the executed Transportation Service Agreement shall not be
construed to affect or change title to the natural gas.
<PAGE>
TF01005708052494El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03245 0 0 5P126Original Sheet No. 245
TF04
TF05A.W.Clark, Vice President
TF06052394****** 070194
TF09E2 0 0 -1 0N052494061694GT94-46-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
10. INDEMNIFICATION
10.1 Each party to the executed Transportation Service Agreement shall bear
responsibility for all of its own breaches, tortious acts, or tortious
omissions connected in any way with the executed Transportation
Service Agreement causing damages or injuries of any kind to the other
party or to any third party, unless otherwise expressly agreed in
writing between the parties. Therefore, the offending party as a
result of such offense shall hold harmless and indemnify the non-
offending party against any claim, liability, loss, or damage
whatsoever suffered by the non-offending party or by any third party.
As used herein: the term "party" shall mean a corporation or
partnership entity or individual and its officers, agents, employees
and contractors; the phrase "damages or injuries of any kind" shall
include without limitation litigation expenses, court costs, and
attorneys' fees; and the phrase "tortious acts or tortious omissions"
shall include without limitation sole or concurrent simple negligence,
gross negligence, recklessness, and intentional acts or omissions.
<PAGE>
TF01005708052494El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03246 0 0 5P126Original Sheet No. 246
TF04
TF05A.W.Clark, Vice President
TF06052394****** 070194
TF09E2 0 0 -1 0N052494061694GT94-46-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
11. ODORIZATION
11.1 As between El Paso and Shipper, El Paso shall have no obligation
whatsoever to odorize the natural gas delivered, nor to maintain any
odorant levels in such natural gas. Notwithstanding Section 10.1
herein, Shipper agrees to indemnify and hold harmless El Paso, its
officers, agents, employees and contractors against any liability,
loss or damage, including litigation expenses, court costs and
attorneys' fees, whether or not such liability, loss or damage arises
out of any demand, claim, action, cause of action, and/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 El Paso, its
officers, agents, employees and/or contractors as a direct or indirect
result of any actual or alleged sole or concurrent negligent failure
by El Paso or any actual or alleged act or omission of any nature by
Shipper to odorize the natural gas or product delivered under the
executed Transportation Service Agreement or to maintain any odorant
levels in such natural gas or product.
<PAGE>
TF01005708052494El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03247 0 0 5P126Original Sheet No. 247
TF04
TF05A.W.Clark, Vice President
TF06052394****** 070194
TF09E2 0 0 -1 0N052494061694GT94-46-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
12. NON-WAIVER OF FUTURE DEFAULT
12.1 No waiver by either El Paso or Shipper of any one or more defaults by
the other in performance of any of the provisions of the executed
Transportation Service Agreement shall operate or be construed as a
waiver of any other existing or future default or defaults, whether of
a like or of a different character.
<PAGE>
TF01005708052494El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03248 0 0 5P126Original Sheet No. 248
TF04
TF05A.W.Clark, Vice President
TF06052394****** 070194
TF09E2 0 0 -1 0N052494061694GT94-46-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
13. SERVICE CONDITIONS
13.1 Interruptible transportation service provided under this Volume No. 1-
A Tariff is subject to and conditioned upon the availability of
capacity sufficient to provide the transportation service without
detriment or disadvantage to El Paso's firm transportation customers.
13.2 El Paso and Shipper acknowledge that the executed Transportation
Service Agreement does not prohibit either party from selling or
transferring its own facilities; therefore, neither El Paso nor
Shipper shall have any obligation to provide services under the
executed Transportation Service Agreement that requires the use of any
facilities sold or transferred; provided, however, El Paso first shall
seek abandonment authorization for any jurisdictional facilities or
jurisdictional services and Shipper shall have the right to protest
such abandonment as inconsistent with the present or future public
convenience and necessity.
13.3 Unless otherwise provided in the executed Transportation Service
Agreement, in the event El Paso and Shipper agree in writing that
additional facilities are necessary in order to implement the service
provided under the executed Transportation Service Agreement, Shipper
agrees to reimburse El Paso for all expenditures associated with the
construction and installation of such facilities which shall be owned,
operated and maintained by El Paso.
13.4 Unless otherwise agreed to in writing, El Paso shall only be
responsible for the maintenance and operation of its own properties
and facilities and shall not be responsible for the maintenance or
operation of any other properties or facilities connected in any way
with the transportation of natural gas.
13.5 El Paso shall have the right to interrupt the transportation of
natural gas when necessary to test, alter, modify, enlarge or repair
any facility or property comprising a part of, or appurtent to, the El
Paso System, or otherwise related to the operation thereof. El Paso
shall endeavor to cause a minimum of inconvenience to Shipper and,
except in cases of emergency, shall give Shipper advance notice of its
intention to so interrupt the transportation of gas and of the
expected magnitude of such interruptions.
<PAGE>
TF01005708112495El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03249 1 0 5P126First Revised Sheet No. 249
TF04 Original Sheet No. 249
TF05Patricia A.Shelton, Vice President
TF06112295092895RM95-3-000 122495
TF09E4 0 0 -1 0N112495122295RP96-49-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
13. SERVICE CONDITIONS (Continued)
13.6 As a condition to providing service under Section 284.102(d) of the
Commission's Regulations for any Shipper under this Volume No. 1-A
Tariff, Shipper shall provide certification including sufficient
information to verify that its services qualify under said section.
Prior to commencing transportation service described in Section
284.102(d)(3) of the Commission's Regulations, El Paso must receive
the certification required from a local distribution company or an
intrastate pipeline pursuant to Section 284.102(d)(3).
13.7 El Paso shall construct, replace, or recondition laterals (at its own
expense) to comply with contractual commitments, or to conform to
Department of Transportation Regulations or other safety related
requirements. El Paso shall also construct laterals, as requested by a
Shipper, when that Shipper has agreed to reimburse El Paso for the
construction and related costs. For purposes of this Section 13.7,
"laterals" mean any pipeline extension (other than mainline extension)
built from an existing pipeline facility to deliver gas to one or more
customers, including new delivery points and enlargements or
replacements of existing laterals.
<PAGE>
TF01005708052494El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03250 0 0 5P126Original Sheet No. 250
TF04
TF05A.W.Clark, Vice President
TF06052394****** 070194
TF09E2 0 0 -1 0N052494061694GT94-46-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
14. STATUTORY REGULATION
14.1 The respective obligations of El Paso and Shipper under the executed
Transportation Service Agreement are subject to the laws, orders,
rules and regulations of duly constituted authorities having
jurisdiction.
<PAGE>
TF01005708052494El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03251 0 0 5P126Original Sheet No. 251
TF04
TF05A.W.Clark, Vice President
TF06052394****** 070194
TF09E2 0 0 -1 0N052494061694GT94-46-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
15. ASSIGNMENTS
15.1 Shipper shall make no sale or assignment of the executed
Transportation Service Agreement or any of the rights or obligations
thereunder unless there first shall have been obtained the written
consent thereto of El Paso; provided, however, that Shipper may,
without the necessity of obtaining the consent of El Paso, assign any
of its rights, but not its obligations thereunder to a trustee or
trustees, individual or corporate, as security for bonds or other
obligations or securities without such trustee or trustees becoming
obligated to perform the obligations of the assignor thereunder and,
if any such trustee be a corporation, without its being required to
qualify to do business in any State in which performance of the
executed Transportation Service Agreement may occur.
<PAGE>
TF01005708052494El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03252 0 0 5P126Original Sheet No. 252
TF04
TF05A.W.Clark, Vice President
TF06052394****** 070194
TF09E2 0 0 -1 0N052494061694GT94-46-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
16. DESCRIPTIVE HEADINGS
16.1 The descriptive headings of the provisions of the executed
Transportation Service Agreement and of these Transportation General
Terms and Conditions are formulated and used for convenience only and
shall not be deemed to affect the meaning or construction of any such
provision.
<PAGE>
TF01005708052494El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03253 0 0 5P126Original Sheet No. 253
TF04
TF05A.W.Clark, Vice President
TF06052394****** 070194
TF09E2 0 0 -1 0N052494061694GT94-46-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
17. TAXES
17.1 Shipper shall pay or cause to be paid all taxes and assessments
imposed on Shipper with respect to natural gas transported prior to
and including its delivery to El Paso, and El Paso shall pay or cause
to be paid all taxes and assessments imposed on El Paso with respect
to natural gas transported after its receipt by El Paso and prior to
redelivery to Shipper, provided however, that Shipper shall pay to El
Paso all taxes, levies or charges which El Paso may by law be required
to collect from Shipper by reason of all services performed for
Shipper.
17.2 Neither party shall be responsible or liable for any taxes or other
statutory charges levied or assessed against any of the facilities of
the other party used for the purpose of carrying out the provisions of
the executed Transportation Service Agreement.
<PAGE>
TF01005708053195El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03254 2 0 5P126Second Revised Sheet No. 254
TF04 First Revised Sheet No. 254
TF05Patricia A.Shelton, Vice President
TF06053095****** 070195
TF09E2 0 0 -1 0N053195061695RP95-322-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
18. GAS RESEARCH INSTITUTE GENERAL RESEARCH, DEVELOPMENT AND DEMONSTRATION
FUNDING UNIT ADJUSTMENT PROVISION
18.1 Purpose - El Paso has joined with other enterprises in the formation
of and participation in the activities and financing of the Gas
Research Institute ("GRI"), an Illinois non-profit corporation. GRI
has been organized to sponsor 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. This
Section 18 provides for a volumetric surcharge and, as specified
herein, a reservation surcharge applicable to the Program Funding
Services comprising transportation services rendered by El Paso, under
the rate schedules contained in this FERC Gas Tariff. Such surcharges
are necessary to produce revenues required to fund El Paso's allocable
pro rata share of the RD&D expenditures of GRI, as approved by the
Commission.
18.2 Applicability - This Section 18 establishes El Paso's GRI General RD&D
Funding Unit Adjustment to be included in El Paso's rates for
transportation services rendered for Shippers, except other pipeline
companies which include in their respective tariffs a charge for the
GRI funding requirement, under rate schedules contained in this FERC
Gas Tariff. This Section 18 also specifies the procedures to be
utilized in changing El Paso's GRI General RD&D Funding Unit
Adjustment under each such applicable rate schedule in order to
reflect changes in El Paso's allocable share of GRI's approved RD&D
expenditures. The GRI funding mechanism is designed to collect 50
percent of GRI's budget through reservation surcharges, and 50 percent
through usage surcharges. Under such funding mechanism, the
reservation and usage surcharges are applicable to volumes of natural
gas transported by El Paso. In the event El Paso discounts its
reservation and/or usage rates, or a Releasing Shipper releases
capacity at less than the maximum reservation charge(s) and
reservation surcharge(s), pursuant to Section 28.4, the applicable
surcharges shall be considered as the first rate increment to be
discounted for purposes of this Section 18. If the discount is less
than the reservation and/or usage surcharges, then the difference
between the reservation and/or usage surcharges and the discount shall
be remitted to GRI. The reservation surcharge is divided into two load
factor categories at two distinct rates: (1) high load
<PAGE>
TF01005708052494El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03255 0 0 5P126Original Sheet No. 255
TF04
TF05A.W.Clark, Vice President
TF06052394****** 070194
TF09E2 0 0 -1 0N052494061694GT94-46-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
18. GAS RESEARCH INSTITUTE GENERAL RESEARCH, DEVELOPMENT AND DEMONSTRATION
FUNDING UNIT ADJUSTMENT PROVISION (Continued)
18.2 Applicability (Continued)
factor Shippers and (2) low load factor Shippers. The load factor is
calculated yearly using the firm Shipper's most recent twelve (12)
month throughput divided by its annual contract demand or billing
determinant. The load factor for a new firm Shipper shall be
calculated each month based on actual throughput for each prior month
of service until a twelve (12) month history is established.
Thereafter, the new firm Shipper's load factor shall be based on its
twelve (12) month throughput consistent with other Shippers. For the
purposes of this Section only and as set forth in Section 18.7 hereof,
Shippers with a load factor exceeding 50 percent are classified as
high load factor Shippers, and those Shippers with a load factor of 50
percent or less are classified as low load factor Shippers.
18.3 The GRI General RD&D Funding Unit Adjustment - The rates charged under
each of the rate schedules applicable hereunder shall include, as
appropriate, surcharge(s) for the GRI General RD&D Funding Unit
Adjustment. Such surcharge(s) shall be that General RD&D Funding Unit
amount proposed from time to time by GRI for its RD&D expenditures and
approved by the Commission. The GRI General RD&D Funding Unit
Adjustment surcharge(s) shall be effective on the applicable
Adjustment Date provided in Section 18.4 hereof without suspension, or
refund obligations.
18.4 Adjustment Date - The Adjustment Date under this Section 18 shall be
the date as approved by the Commission. On and after the Adjustment
Date El Paso shall, in accordance with the provisions of this Section
18, increase or decrease the rate applicable to each affected rate
schedule so as to include the approved GRI General RD&D Funding Unit
Adjustment to be collected during the period preceding the next
Adjustment Date.
18.5 Time and Manner of Filing and Related Report - El Paso shall file
changes in the GRI General RD&D Funding Unit Adjustment at least
thirty (30) days prior to the proposed effective date by means of
revised tariff sheets to those rate schedules contained in this FERC
Gas Tariff. Such filing shall identify the amount of said adjustment
(i.e., the GRI General RD&D Funding Unit as approved by the
Commission) and the resulting currently effective tariff rates under
each applicable rate schedule. Such filing shall be posted
<PAGE>
TF01005708120195El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03256 2 0 5P126Second Revised Sheet No. 256
TF04 First Revised Sheet No. 256
TF05Patricia A.Shelton, Vice President
TF06113095****** 010196
TF09E3 0 0 -1 0N120195122195TM96-1-33-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued)
18. GAS RESEARCH INSTITUTE GENERAL RESEARCH, DEVELOPMENT AND DEMONSTRATION
FUNDING UNIT ADJUSTMENT PROVISION (Continued)
18.5 Time and Manner of Filing and Related Report (Continued)
as defined by the Commission and shall be served upon each of El
Paso's affected Shippers under rate schedules contained in this FERC
Gas Tariff, and upon interested state regulatory agencies.
18.6 Disposition of GRI Funding Unit Adjustment Surcharge Revenues -El Paso
shall remit to GRI the total revenues resulting from the GRI General
RD&D Funding Unit Adjustment provided by this Section 18 within
fifteen (15) days following the receipt thereof from El Paso's
affected Shippers.
18.7 Identification of High and Low Load Factor Shippers by Agreement
HIGH LOAD FACTOR (in excess of 50%) SHIPPERS
<TABLE>
<CAPTION>
Agreement
Description Code
<S> <C>
Amoco Energy Trading Corporation 97JB
Arizona Public Service Company 97ZC
ASARCO Inc. 9834
ASARCO Inc. 982A
Cyprus Miami Mining Corporation 982G
El Paso Electric Company 9827
Los Angeles Department of Water and Power 9836
Magma Copper Company 97ZU
Meridian Oil Marketing Inc 97YW
Meridian Oil Marketing Inc. 97YG
Meridian Oil Trading Inc. 97J4
Mission Energy Fuel Company 97YX
Mobil Natural Gas Inc. 97YK
PEMEX Gas y Petroquimica Basica 97ZZ
Phelps Dodge Corporation 97Z7
Saguaro Power Company 97YE
San Diego Gas and Electric Company 9844
Southern California Edison Company 97YV
Southern California Gas Company 97VT
Texaco, Inc. 97YF
U.S. Borax and Chemical Corporation 97YH
West Texas Gas, Inc. 982V
</TABLE>
<PAGE>
TF01005708120194El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03257 1 0 5P126First Revised Sheet No. 257
TF04 Original Sheet No. 257
TF05Patricia A.Shelton, Vice President
TF06113094****** 010195
TF09Z3696225694N120194122894TM95-2-33-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued)
18. GAS RESEARCH INSTITUTE GENERAL RESEARCH, DEVELOPMENT AND DEMONSTRATION
FUNDING UNIT ADJUSTMENT PROVISION (Continued)
18.7 Identification of High and Low Load Factor Shippers by Agreement
(Continued)
LOW LOAD FACTOR (50% or less) SHIPPERS
<TABLE>
<CAPTION>
Agreement
Description Code
<S> <C>
Arizona Electric Power Cooperative, Inc. 9838
Citizens Utilities Company 97ZH
Gas Company of New Mexico 97VW
Las Cruces, New Mexico, City of 982M
Lordsburg, New Mexico, City of 982N
Meridian Oil Trading Inc. 97YM
Mesa, Arizona, City of 97ZV
Natural Gas Processors Company 97YR
Navajo Tribal Utility Authority 97ZY
PEMEX Gas y Petroquimica Basica 97ZZ
Salt River Project Agricultural Improvement 826
and Power District
Southdown, Inc. (SW Portland) 982Q
Southwest Gas Corporation 97ZL
Southwest Gas Corporation 97ZK
</TABLE>
<PAGE>
TF01005708112495El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03258 2 0 5P126Second Revised Sheet No. 258
TF04 First Revised Sheet No. 258
TF05Patricia A.Shelton, Vice President
TF06112295092895RM95-3-000 122495
TF09E4 0 0 -1 0N112495122295RP96-49-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
19. OPERATING PROVISIONS FOR INTERRUPTIBLE TRANSPORTATION SERVICE
Interruptible transportation service under this FERC Gas Tariff shall
be provided when, and to the extent that, El Paso determines that capacity is
available in El Paso's existing facilities, which capacity is not subject to a
prior claim by another customer or another class of service under a
pre-existing contract, service agreement or certificate. Available
interruptible capacity shall be allocated by El Paso on a first come/first
served basis, as determined by El Paso, and interruptible transportation
service hereunder shall be provided in accordance with such allocation.
The provisions of this Section 19 shall also be applicable to
interruptible service under special rate schedules contained in El Paso's
Volume No. 2 Tariff.
19.1 A valid request for interruptible transportation service under this
FERC Gas Tariff made after the effectiveness of Section 23 hereof
shall be in accordance with, and contain the data required by the
provisions contained in such Section 23.
19.2 With respect to all requests for interruptible service by a Shipper
who had not contracted for service prior to October 9, 1985, the
provisions of Sections 19.3 through 19.6 and Section 23.5 shall
govern.
19.3 On any day that sufficient capacity is not available in El Paso's
system to provide transportation for all gas tendered under executed
Transportation Service Agreements with Shippers referred to in Section
19.2 above, El Paso shall allocate its available capacity among such
Shippers on a first come/first served basis. For purposes of
allocating such capacity, any Shipper holding an effective
Transportation Service Agreement or any Shipper who has furnished El
Paso with a valid request complying with the requirements contained in
Section 19.4 and in Section 23, when accepted by El Paso in an
executed Transportation Service Agreement, will be entitled to
priority over any Shipper furnishing El Paso with a valid request on a
later date and shall be unaffected by and shall have priority over
subsequent requests for service under Rate Schedule IT-1.
<PAGE>
TF01005708083194El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03259 1 0 5P126First Revised Sheet No. 259
TF04 Original Sheet No. 259
TF05A.W.Clark, Vice President
TF06083094****** 100194
TF09E3686227794N083194092694MT94-21-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
19. OPERATING PROVISIONS FOR INTERRUPTIBLE TRANSPORTATION SERVICE
(Continued)
19.4 Requests for transportation under this FERC Gas Tariff will be invalid
and will not be considered if service is requested to commence later
than six (6) months after the information specified in Section 23.5 of
this FERC Gas Tariff is provided to El Paso.
19.5 Upon receipt of all of the information required in Section 23 for a
valid request for transportation service, El Paso shall prepare and
tender to Shipper for execution a Transportation Service Agreement in
the form contained in this Volume No. 1-A Tariff. If Shipper fails to
execute the Transportation Service Agreement or any amendment thereto
within thirty (30) days of the date tendered, Shipper's request shall
be deemed null and void.
19.6 If a Shipper that has executed a Transportation Service Agreement
fails, on the later of the date service is to commence or fifteen (15)
days after the Shipper executes the Transportation Service Agreement,
or the completion of construction of any necessary facilities or the
issuance of any necessary certificate authorization, to nominate
pursuant to Section 4.1 of these General Terms and Conditions any
quantity of gas for transportation or fails, having nominated a
quantity of gas and El Paso having scheduled the quantity for
transportation, to tender any gas for transportation, the Shipper's
Transportation Service Agreement shall be terminated and the Shipper's
request for service shall be deemed null and void; provided, however,
that the Shipper's Transportation Service Agreement shall not be
terminated nor shall the Shipper's request for service be deemed null
and void if the Shipper's failure to nominate or tender is caused by
an event of force majeure as defined in Section 7 of these General
Terms and Conditions.
19.7 El Paso shall not be required to perform or continue service on behalf
of any Shipper that fails to comply with the terms contained in
Sections 19 and 23 and any and all terms of the applicable rate
schedule and the terms of Shipper's Transportation Service Agreement
with El Paso. El Paso shall have the right to waive any one or more
specific defaults by any Shipper under Sections 19.8 through 19.13,
inclusive, or any provision of the applicable rate schedule or
Transportation Service Agreement; provided, however, that no such
waiver shall operate or be
<PAGE>
TF01005708052494El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03260 0 0 5P126Original Sheet No. 260
TF04
TF05A.W.Clark, Vice President
TF06052394****** 070194
TF09E2 0 0 -1 0N052494061694GT94-46-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
19. OPERATING PROVISIONS FOR INTERRUPTIBLE TRANSPORTATION SERVICE
(Continued)
19.7 (Continued)
construed as a waiver of any other existing or future default or
defaults, whether of a like or different character.
19.8 Upon request of El Paso, Shipper shall from time to time submit
estimates of daily, monthly and annual quantities of gas to be
transported, including peak day requirements.
19.9 Shipper shall endeavor to deliver and receive natural gas in uniform
hourly quantities during any day with operating variations to be kept
to the minimum feasible.
19.10 El Paso shall not be required to perform or to continue interruptible
service under this FERC Gas Tariff on behalf of any Shipper who is or
has become insolvent, or fails to meet payment obligations in
accordance with Sections 6.2 or 6.3 of this FERC Gas Tariff, or who,
at El Paso's request, fails, within a reasonable period to demonstrate
creditworthiness or fails to provide adequate assurances of
performance as such are defined in the Texas version of the Uniform
Commercial Code (See, Vernon's Texas Codes Annotated, Business and
Commerce Code, Acts 1967, 60th Leg., Ch. 785, H.B. No. 293, UCC
effective September 1, 1967). However, such Shipper may receive
interruptible service under this FERC Gas Tariff if Shipper prepays
for such service or furnishes good and sufficient security, as
determined by El Paso in its reasonable discretion, an amount equal to
the cost of performing the service requested by Shipper for a three
(3) month period to include the cost of gas for permissible imbalance
quantities. For purposes of this FERC Gas Tariff, the insolvency of a
Shipper shall be evidenced by the filing by such Shipper or any parent
entity thereof (hereinafter collectively referred 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 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 or liquidation of its
affairs, with said order or
<PAGE>
TF01005708052494El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03261 0 0 5P126Original Sheet No. 261
TF04
TF05A.W.Clark, Vice President
TF06052394****** 070194
TF09E2 0 0 -1 0N052494061694GT94-46-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
19. OPERATING PROVISIONS FOR INTERRUPTIBLE TRANSPORTATION SERVICE
(Continued)
19.10 (Continued)
decree continuing unstayed and in effect for a period of sixty (60)
consecutive days. Notwithstanding the above and Section 6.4 of this
FERC Gas Tariff, El Paso shall not suspend service to any Shipper, who
is or has become insolvent, in a manner that is inconsistent with the
Federal Bankruptcy Code.
19.11 El Paso shall have no responsibility prior to its acceptance of
natural gas at the receipt point(s) and after delivery at the delivery
point(s), and Shipper shall have sole responsibility for all
arrangements necessary for delivery of natural gas to El Paso at the
receipt point(s) for transportation, and for all arrangements
necessary for receipt of natural gas for the account of Shipper at the
delivery point(s), which arrangements otherwise meet the provisions
set forth in these General Terms and Conditions.
19.12 Resolution of Imbalances
For purposes of this Section 19.12 "Shipper" shall include any party
utilizing El Paso's system and services including, without limitation,
any party tendering or receiving gas under Shipper's contract but
excluding any operator of interconnecting facilities and any volume
subject to a written assistance agreement with El Paso. El Paso and
the operator of any interconnecting facilities may cash-out
imbalances, pursuant to a written agreement between them.
(a) Imbalances Prior to Effective Date of this Provision -Imbalances
existing prior to the effective date of this provision will be
corrected in kind, as described below, unless El Paso and Shipper
agree to correct such imbalances in cash. El Paso and Shipper
shall attempt, in good faith, to agree upon the historical
imbalance and the time period to correct such historical
imbalance. If, despite such good faith efforts, El Paso and
Shipper fail to reach written agreement upon the appropriate
corrective action within six (6) months from the effectiveness of
this section, then Shipper shall be required to correct any
remaining imbalance within sixty (60) days, subject to operational
constraints on El Paso's system. El Paso shall extend the sixty
(60)
<PAGE>
TF01005708052494El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03262 0 0 5P126Original Sheet No. 262
TF04
TF05A.W.Clark, Vice President
TF06052394****** 070194
TF09E2 0 0 -1 0N052494061694GT94-46-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
19. OPERATING PROVISIONS FOR INTERRUPTIBLE TRANSPORTATION SERVICE
(Continued)
19.12 Resolution of Imbalances (Continued)
day balancing period by one (1) day for each day that El Paso is
unable to receive or deliver scheduled imbalance gas due to
operational constraints on El Paso's system. If after the sixty
(60) day balancing period or extension due to operational
constraints Shipper has not corrected the imbalance, then El Paso
shall (i) for any remaining imbalances where deliveries exceed
receipts ("negative imbalance") charge Shipper per dth based upon
the arithmetic average of the System Weighted Index Price for each
quarter of the twelve (12) months ending December 31, 1992 (the
System Weighted Index Price for each quarter shall be based on the
method set forth in Section 19.12(e)(i) below); or (ii) for any
remaining imbalances where receipts exceed deliveries ("positive
imbalance") retain the imbalance at no cost and free and clear of
any adverse claims by any party or any obligation to account for
such gas; provided however, that in the event of a bona fide
dispute by Shipper of the amount of the imbalance, El Paso shall
not take the action outlined above when Shipper acts in a timely
manner to provide additional information and security for El Paso
in accordance with the following procedures.
(i) Identify Dispute: Within fifteen (15) days after El Paso's
notification of an imbalance, Shipper shall notify El Paso
by written correspondence of the imbalance that is in bona
fide dispute and of all reasons and documentation why
Shipper believes El Paso's calculation of the imbalance is
not correct; and
(ii) Payment Security: Within thirty (30) days after El Paso's
notification of an imbalance, Shipper shall either agree to
the imbalance calculated by El Paso without prejudice to
Shipper's rights to dispute all or part of said imbalance
and subject to return of the disputed imbalance so
identified after resolution of that dispute or Shipper shall
take the necessary actions to correct the imbalances it
concedes to be correct and furnish good and sufficient
surety bond, guaranteeing the
<PAGE>
TF01005708052494El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03263 0 0 5P126Original Sheet No. 263
TF04
TF05A.W.Clark, Vice President
TF06052394****** 070194
TF09E2 0 0 -1 0N052494061694GT94-46-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
19. OPERATING PROVISIONS FOR INTERRUPTIBLE TRANSPORTATION SERVICE
(Continued)
19.12 Resolution of Imbalances (Continued)
correction of any imbalance ultimately found owed to El Paso
after resolution of the dispute, including late payment
charges which accrue until resolution of the dispute with
respect to any negative imbalances, which resolution may be
reached either by agreement or judgment of a court of
competent jurisdiction. If resolution of the dispute is in
favor of Shipper and the Shipper furnished a surety bond
then El Paso shall pay to Shipper the costs incurred in
securing that surety bond for this dispute including any
late payment charges actually paid to El Paso.
(b) Calculation of an Imbalance Subsequent to the Effectiveness of
this Provision - El Paso and Shippers shall resolve an over-
delivery or under-delivery of gas to El Paso each month in
accordance with this Section 19.12. Each month, El Paso will
calculate a percentage imbalance for each individual contract for
each Shipper by dividing the total cumulative imbalance quantities
in excess of 1,000 dth, attributable to the imbalance amount for
such contract (numerator) by the most recent calendar year monthly
average of quantities actually delivered (denominator). Such
average is derived by dividing the quantities delivered during the
calendar year by the number of months the quantities were
delivered; provided however, if no quantities have been delivered
during the last calendar year to Shipper, the monthly average
shall be Shipper's total Transportation Service Agreement Maximum
Daily Quantity multiplied by 30 days. The result of such
calculation will be included on El Paso's imbalance statement to
Shipper, or its designee, and shall serve as notification to the
Shipper of an imbalance. If an imbalance is equal to or greater
than +/-5%, the Shipper is provided additional notice on said
statement that if such imbalance continues and becomes equal to or
greater than +/-10%, the Shipper is subject to cash-out of the
imbalance pursuant to this Section 19.12; provided, however, that
in no event shall cash-out be assessed when the amount of the
imbalance does not exceed 1,000 dth, unless the parties mutually
agree otherwise; provided, further, if a verifiable imbalance is
caused by El Paso, that portion of the
<PAGE>
TF01005708052494El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03264 0 0 5P126Original Sheet No. 264
TF04
TF05A.W.Clark, Vice President
TF06052394****** 070194
TF09E2 0 0 -1 0N052494061694GT94-46-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
19. OPERATING PROVISIONS FOR INTERRUPTIBLE TRANSPORTATION SERVICE
(Continued)
19.12 Resolution of Imbalances (Continued)
imbalance shall not be considered as part of Shipper's imbalance
for purposes of initiating cash-out. In addition, cash-out of
imbalances will not be mandatory if the parties have reached
written agreement on the resolution of the imbalance provided such
agreement is final prior to the triggering of cash-out as
specified in Section 19.12(c) below. Written agreements may
consist of, but are not limited to the following provisions (i)
offsetting of imbalances; (ii) extension of a payback period
within a set time period; and (iii) negotiated price other than
the cash-out prices reflected herein.
(c) Triggering of Cash-Out - Except for those contracts without
activity for a period of six (6) months, as discussed in Section
19.12(d), any cumulative imbalance at the end of any month that is
within a tolerance level less than +/-5% shall not be subject to
this Section 19.12 during such month. Such imbalance shall be
forwarded to the next month's imbalance calculation. If the
cumulative imbalance for any month is equal to or greater than +/-
5%, El Paso shall notify Shipper, as indicated in Section
19.12(b), that it is approaching a cash-out situation for an
imbalance equal to or in excess of +/-10%. For any month that a
cumulative imbalance is equal to or in excess of +/-10%, cash-out
of the imbalance will take place provided Shipper has received a
minimum of two (2) consecutive monthly notices (minimum of 45 days
from date of first notice) alerting Shipper to an imbalance equal
to or in excess of +/-5%. El Paso shall extend the 45-day grace
period by one (1) day for each day that El Paso is unable to
receive or deliver requested and confirmed imbalance gas for a
given contract due to operational constraints on El Paso's system.
If the parties have not reached written agreement otherwise, the
imbalance will be reduced to +/-5% by "cash-out" the month
following the last notice, at the dollar value calculated with the
cumulative imbalance and an established monthly price, referred to
herein as the Index Price, as determined in Section 19.12(e)
below. The Index Price shall be calculated as of the month the
imbalance first equals or exceeds the +/-10% level.
<PAGE>
TF01005708052494El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03265 0 0 5P126Original Sheet No. 265
TF04
TF05A.W.Clark, Vice President
TF06052394****** 070194
TF09E2 0 0 -1 0N052494061694GT94-46-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
19. OPERATING PROVISIONS FOR INTERRUPTIBLE TRANSPORTATION SERVICE
(Continued)
19.12 Resolution of Imbalances (Continued)
(d) Six-Month Resolution of Inactive Contracts - El Paso will notify
Shipper after three (3) consecutive months of inactivity that at
the end of any six (6) month period that a contract between
Shipper and El Paso has been inactive and has maintained an
imbalance of less than +/-10%, for which no cash-out was
applicable and before the next invoice and balance statement date,
such imbalance shall be reduced to zero (0) by cash-out utilizing
the Index Price for the month after the end of six (6) month
period reflected in Section 19.12(e).
(e) Index Prices and Cash Out
(i) Cash-out shall be based on one of four calculated price
indices, depending on whether Shipper has one or more of the
three supply basins (i.e., San Juan, Permian or Anadarko
Basins) included in its agreement. A single price index
calculated only for a specific supply basin will be used if
Shipper has only that one supply basin in its agreement. A
System Weighted Index Price calculated for all supply basins
will be used if Shipper has more than one supply basin in
its agreement. The calculation of each price index is set
forth below:
(1) The Anadarko Basin Index Price shall be computed using
a simple average of reported prices as delivered to El
Paso's Mainline System at Washita, Anadarko, Oklahoma,
or the Texas Panhandle from the publications
identified in Section 19.12(e)(ii);
(2) The Permian Basin Index Price shall be computed using
a simple average of reported prices as delivered to El
Paso's Mainline System at West Texas, Permian or Waha
from the publications identified in Section
19.12(e)(ii); and
<PAGE>
TF01005708052494El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03266 0 0 5P126Original Sheet No. 266
TF04
TF05A.W.Clark, Vice President
TF06052394****** 070194
TF09E2 0 0 -1 0N052494061694GT94-46-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
19. OPERATING PROVISIONS FOR INTERRUPTIBLE TRANSPORTATION SERVICE
(Continued)
19.12 Resolution of Imbalances (Continued)
(3) The San Juan Basin Index Price shall be computed using
a simple average of reported prices as delivered to El
Paso's Mainline System at Ignacio, San Juan or New
Mexico from the publications identified in Section
19.12(e)(ii).
(4) The System Weighted Index Price shall be computed
monthly by using the weighted average of the Anadarko
Basin Index Price, the Permian Basin Index Price, and
the San Juan Basin Index Price. The weighting is based
on the volumes entering El Paso's system in each basin
during the previous quarter and will be updated
quarterly.
(ii) The four trade publications referenced above are Inside FERC
Gas Market Report (Prices of Spot Gas Delivered to
Pipelines), Natural Gas Week (Spot Prices on Natural Gas
Pipeline Systems, Delivered to Pipelines), Gas Daily
(Natural Gas Survey), and Natural Gas Intelligence Gas Price
Index (Spot Gas Prices Delivered to Pipeline, 30 Day Supply
Transactions).
In the event any of the publications cease publication or to the
extent a publication fails to report spot prices, then El Paso
shall reserve the right to substitute prices reported in a similar
independent publication or continue the pricing formula using the
average of the remaining publications. Changes in the name, format
or other method of reporting by the publications in (e) above that
do not materially affect the content shall not affect their use
hereunder.
(iii) El Paso shall post the Index Price monthly on its electronic
bulletin board on or before the 15th day of each month
applicable to the prior business month.
<PAGE>
TF01005708052494El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03267 0 0 5P126Original Sheet No. 267
TF04
TF05A.W.Clark, Vice President
TF06052394****** 070194
TF09E2 0 0 -1 0N052494061694GT94-46-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
19. OPERATING PROVISIONS FOR INTERRUPTIBLE TRANSPORTATION SERVICE
(Continued)
19.12 Resolution of Imbalances (Continued)
(iv) For any contract where total deliveries by El Paso for a
Shipper exceed the total receipts from Shipper, after
appropriate reductions, such imbalance shall be "cashed out"
based on the percentages provided below. Further, the Index
Price shall be adjusted to reflect the point at which the
imbalance is held.
(1) For any contract subject to Section 19.12(d), or by
mutual agreement any contract with an imbalance up to
and including +5%, the quantity will be invoiced at
100% of the Index Price;
(2) For any contract subject to Section 19.12(d) or any
contract with an imbalance greater than +5% but less
than or equal to +10%, the quantity in excess of +5%
will be invoiced at 110% of the Index Price;
(3) For any contract with an imbalance greater than +10%
but less than or equal to +15%, the volume in excess
of +10% will be invoiced at 120% of the Index Price;
(4) For any contract with an imbalance greater than +15%
but less than or equal to +20%, the volume in excess
of +15% will be invoiced at 130% of the Index Price;
and
(5) For any contract with an imbalance greater than +20%,
the volume in excess of +20% will be invoiced at 140%
of the Index Price.
(v) For any contract where total receipts by El Paso from a
Shipper, after appropriate reductions, exceed total
deliveries for that Shipper, such imbalance shall be "cashed
out" based on the percentages provided below. Further, the
Index Price shall be adjusted to reflect the point at which
the imbalance is held.
<PAGE>
TF01005708052494El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03268 0 0 5P126Original Sheet No. 268
TF04
TF05A.W.Clark, Vice President
TF06052394****** 070194
TF09E2 0 0 -1 0N052494061694GT94-46-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
19. OPERATING PROVISIONS FOR INTERRUPTIBLE TRANSPORTATION SERVICE
(Continued)
19.12 Resolution of Imbalances (Continued)
(1) For any contract subject to Section 19.12(d) or subject to
any other mutually agreeable terms, with an imbalance up to
and including-5%, the quantity will be purchased by El Paso
at 100% of the Index Price;
(2) For any contract subject to Section 19.12(d) or any
contract with an imbalance greater than -5% but less
than or equal to -10%, the quantity in excess of -5%
will be purchased by El Paso at 90% of the Index Price;
(3) For any contract with an imbalance greater than -10%
but less than or equal to -15%, the volume in excess
of -10% will be purchased by El Paso at 80% of the
Index Price;
(4) For any contract with an imbalance greater than -15%
but less than or equal to -20%, the volume in excess
of -15% will be purchased by El Paso at 70% of the
Index Price; and
(5) For any contract with an imbalance greater than -20%,
the volume in excess of -20% will be purchased by El
Paso at 60% of the Index Price.
(vi) At the time a Shipper is in a cash-out position requiring
payment to El Paso at the appropriate rate set forth in
Section 19.12(e)(iv) above and such Shipper also has an
Unauthorized Gas balance, as such term is defined in Section
27.1 of these General Terms and Conditions, such
Unauthorized Gas balance may be offset against the
quantities due El Paso within the same production basin and
adjusted to reflect the point at which the imbalance is
held. At the time of invoicing for the net imbalance, El
Paso shall appropriately invoice or account for any
production area charges and liquid credits applicable to the
unauthorized
<PAGE>
TF01005708112995El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03269 1 0 5P126First Revised Sheet No. 269
TF04 Original Sheet No. 269
TF05Patricia A.Shelton, Vice President
TF06112895091395CP94-183-000 and 001010196
TF09E5 0 0 -1 0N112995122995RP96-52-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
19. OPERATING PROVISIONS FOR INTERRUPTIBLE TRANSPORTATION SERVICE
(Continued)
19.12 Resolution of Imbalances (Continued)
gas used as an offset. This provision is not
applicable to the Unauthorized Gas retained as a
penalty pursuant to Section 27 of these General
Terms and Conditions.
Prior to any offsets, El Paso at its option may
first offset any under or over-deliveries between
contracts with such Shipper.
Shipper or its suppliers shall be responsible for
reporting and payment of any royalty, tax, or other
burdens on natural gas volumes received by El Paso
and El Paso shall not be obligated to account for
or pay such burdens.
(f) Crediting of Revenues - When the aggregate value received from
all sources resulting from cash-out exceeds the cost of gas plus
administrative fees, El Paso shall credit such net amount within
90 days of the payment date to Shippers on a pro rata basis in
accordance with the volumes transported for each Shipper.
(g) Netting of Contracts - For purposes of resolving an imbalance
with a Shipper, El Paso shall net gas imbalances, on a non-
discriminatory basis, adjusted to reflect a common point at which
the imbalance is held, between contracts with such Shipper
pursuant to the conditions identified below.
(i) Netting between downstream interconnect and mainline
agreement imbalances is negotiable if the agreement has the
interconnect point as a delivery point.
<PAGE>
TF01005708112995El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03270 1 0 5P126First Revised Sheet No. 270
TF04 Original Sheet No. 270
TF05Patricia A.Shelton, Vice President
TF06112895091395CP94-183-000 and 001010196
TF09E5 0 0 -1 0N112995122995RP96-52-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
19. OPERATING PROVISIONS FOR INTERRUPTIBLE TRANSPORTATION SERVICE
(Continued)
19.12 Resolution of Imbalances (Continued)
(ii) Netting between Unauthorized Gas and mainline agreement
imbalances is negotiable if both the Unauthorized Gas and
imbalance were generated in the same basin.
(iii) Netting between mainline agreement imbalances (for similar
transportation service) is negotiable.
For any specific situation not discussed above, El Paso is willing
to negotiate a transportation transaction which could have the
effect of netting imbalances.
19.13 Unauthorized Overpull Penalty
(a) A penalty shall be levied by El Paso and paid in dollars by any
receiving party (any Shipper, Local Distribution Company, Direct
Sales Customer or other party who operates the facilities that
receive the gas transported by El Paso) who exceeds the limits
specified below. Such penalty is applicable when, in times of
capacity constraints, or when, due to unforeseen circumstances
beyond El Paso's control, El Paso has determined that its ability
to maintain scheduled deliveries to all receiving parties is
materially threatened due to insufficient pressures in El Paso's
system and El Paso so notifies said receiving parties. Nothing
herein shall limit El Paso's right to take any further actions
required to maintain the integrity of its system operations.
(b) On any day El Paso determines that it is unable to deliver the
total volumes of gas scheduled for delivery for the account of
all Shippers, it shall have the right to notify all receiving
parties that an Unauthorized Overpull Penalty situation exists.
Contemporaneously with, or shortly
<PAGE>
TF01005708052494El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03271 0 0 5P126Original Sheet No. 271
TF04
TF05A.W.Clark, Vice President
TF06052394****** 070194
TF09E2 0 0 -1 0N052494061694GT94-46-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
19. OPERATING PROVISIONS FOR INTERRUPTIBLE TRANSPORTATION SERVICE
(Continued)
19.13 Unauthorized Overpull Penalty (Continued)
following such notice, El Paso shall give notice to any receiving
party who is taking volumes at a level that would subject such
party to an Unauthorized Overpull Penalty as provided below.
(c) The quantity of gas subject to such penalty is that quantity of
gas taken by the receiving party which exceeds the quantity of gas
scheduled by El Paso for delivery to such party on any day.
(d) Upon receipt of a notification from El Paso, such party shall
within twenty-four (24) hours reduce takes to a level no more than
3% above its scheduled volume for such day or 1,000 dth, whichever
is larger. Such twenty-four (24) hour notice period shall commence
at seven (7:00) a.m. Mountain Standard Time on the day after
notice is actually provided. If after the twenty-four (24) hour
notice period the receiving party continues to take volumes of gas
that exceed the foregoing threshold, an Unauthorized Overpull
Penalty shall be levied by El Paso and paid in dollars by any
receiving party as follows:
(i) A penalty of $5.00 per dth shall apply to all unauthorized
overrun volumes which exceed the 3% or 1,000 dth tolerance
level, whichever is larger, up to the first 5% of scheduled
volumes; and
(ii) A penalty of $10.00 per dth shall apply to daily
unauthorized overrun volumes in excess of 5% of scheduled
volumes.
El Paso shall notify Shippers each day during an Unauthorized
Overpull Penalty situation, via El Paso's Electronic Bulletin
Board, that the situation continues to exist. Such notice does not
constitute notification of a new penalty period pursuant to this
Section 19.13(d) and does not begin a new twenty-four (24) hour
correction period.
<PAGE>
TF01005708083194El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03272 1 0 5P126First Revised Sheet No. 272
TF04 Original Sheet No. 272
TF05A.W.Clark, Vice President
TF06083094****** 100194
TF09E3686227794N083194092694MT94-21-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
20. OPERATING PROVISIONS FOR FIRM TRANSPORTATION SERVICE
Firm transportation service under this FERC Gas Tariff shall be
provided when, and to the extent that, El Paso determines that firm
capacity is available in El Paso's existing facilities, which firm
capacity is not subject to a prior claim by another customer or another
class of service. Firm capacity which becomes available on and after
the effective date of this Section 20, other than capacity which becomes
available through the installation of new mainline transmission
facilities (other than minor tap), and which is not converted or subject
to conversion to firm transportation capacity pursuant to Section 284.10
of the Commission's Regulations, shall be made available to potential
Shippers to support new firm transportation agreements on a first
come/first served basis.
The provisions of this Section 20 shall also be applicable to firm
service under special rate schedules contained in El Paso's Volume No. 2
Tariff.
20.1 A valid request for firm transportation service under this FERC
Gas Tariff made after the effectiveness of Section 23 hereof shall
be in accordance with, and contain the data required by the
provisions contained in such Section 23.
20.2 With respect to all requests for firm transportation service by a
Shipper made on and after the effective date of this Section 20,
the provisions of Sections 20.3 through 20.5 and 23.5 shall
govern.
20.3 (a) The availability of firm capacity for contract shall be
determined by the time and date El Paso receives a valid request
for service under this FERC Gas Tariff, which conforms to
Section 20.4 below and the provisions contained in Section 23
upon effectiveness of such section. El Paso shall consider all
valid requests in the order received, and when a request for
service is accepted in writing by El Paso. Allocation of
contracted firm capacity will be on a pro rata basis.
<PAGE>
TF01005708052494El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03273 0 0 5P126Original Sheet No. 273
TF04
TF05A.W.Clark, Vice President
TF06052394****** 070194
TF09E2 0 0 -1 0N052494061694GT94-46-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
20. OPERATING PROVISIONS FOR FIRM TRANSPORTATION SERVICE (Continued)
20.3 (Continued)
(b) In the event that two or more Shippers seek to obtain the firm
capacity that one or more Shippers offer to relinquish on the
Outer Continental Shelf, such capacity shall be allocated as
follows:
(i) during the open season conducted in accordance with Order
No. 509, et seq., firm capacity will be reallocated in
accordance with Section 284.304(a) of the Commission's
Regulations; and
(ii) after the open season within ten (10) days of receiving a
complete and valid request for firm transportation, El Paso
will provide the requesting Shipper a list of all firm
Shippers under contract with El Paso. If the requesting
Shipper finds an existing Shipper willing to relinquish
voluntarily all or a portion of its firm capacity, El Paso
will reallocate that capacity on a first come/first served
basis. The relinquishing Shipper and the new Shipper shall
advise El Paso in writing of their mutual agreement. In the
event there is more than one valid request for service on a
given day, and such requests exceed the available firm
capacity, such capacity shall be allocated among the
requesting Shippers on a pro rata basis. Any capacity which
is relinquished by an existing Shipper and subsequently
assumed by the requesting Shipper must have compatible
receipt and delivery point obligations, unless El Paso has
capacity available at other requested receipt and delivery
points. In the event El Paso has uncommitted firm capacity
available, it may assign part or all of that capacity before
it reallocates the capacity of existing Shippers. Upon
execution of the new Transportation Service Agreement with
the new Shipper, El Paso shall be absolved of all service
obligations to the relinquishing Shipper and shall be deemed
to have received pregranted abandonment authorization for
such relinquishing Shipper.
<PAGE>
TF01005708112495El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03274 1 0 5P126First Revised Sheet No. 274
TF04 Original Sheet No. 274
TF05Patricia A.Shelton, Vice President
TF06112295092895RM95-3-000 122495
TF09E4 0 0 -1 0N112495122295RP96-49-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
20. OPERATING PROVISIONS FOR FIRM TRANSPORTATION SERVICE (Continued)
20.4 Requests for firm transportation hereunder shall be accompanied by a
prepayment, not to exceed $10,000.00, of the total Reservation Charge
provided by Section 4.1 of Rate Schedule FT-1 of this FERC Gas Tariff.
20.5 Upon receipt of all of the information required in Section 23 for
a valid request for transportation service, El Paso shall prepare
and tender to Shipper for execution a Transportation Service
Agreement in the form contained in this Volume No. 1-A Tariff. If
Shipper fails to execute the Transportation Service Agreement or
any amendment thereto within thirty (30) days of the date
tendered, Shipper's request shall be deemed null and void.
20.6 El Paso shall not be required to perform or continue service on
behalf of any Shipper that fails to comply with the terms
contained in Sections 20 and 23 and any and all terms of the
applicable rate schedule and the terms of Shipper's Transportation
Service Agreement with El Paso. El Paso shall have the right to
waive any one or more specific defaults by any Shipper under
Sections 20.7 through 20.12, inclusive, or any provision of the
applicable rate schedule or Transportation Service Agreement;
provided, however, that no such waiver shall operate or be
construed as a waiver of any other existing or future default or
defaults, whether of a like or different character.
20.7 Upon request of El Paso, Shipper shall from time to time submit
estimates of daily, monthly and annual quantities of gas to be
transported, including peak day requirements.
20.8 Shipper shall endeavor to deliver and receive natural gas in uniform
hourly quantities during any day with operating variations to be kept
to the minimum feasible.
20.9 El Paso shall not be required to perform or to continue firm service
under this FERC Gas Tariff on behalf of any Shipper who is or has
become insolvent, or fails to meet payment obligations in accordance
with Sections 6.2 or 6.3 of this FERC Gas Tariff, or who, at El Paso's
request, fails, within a reasonable period to demonstrate
creditworthiness or fails to provide adequate assurances of
performance as such are defined in the Texas version of the Uniform
Commercial Code (See, Vernon's Texas Codes
<PAGE>
TF01005708052494El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03275 0 0 5P126Original Sheet No. 275
TF04
TF05A.W.Clark, Vice President
TF06052394****** 070194
TF09E2 0 0 -1 0N052494061694GT94-46-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
20. OPERATING PROVISIONS FOR FIRM TRANSPORTATION SERVICE (Continued)
20.9 (Continued)
Annotated, Business and Commerce Code, Acts 1967, 60th Leg., Ch. 785,
H.B. No. 293, UCC effective September 1, 1967). However, such Shipper
may receive firm service under this FERC Gas Tariff if Shipper prepays
for such service or furnishes good and sufficient security, as
determined by El Paso in its reasonable discretion, an amount equal to
the cost of performing the service requested by Shipper for a three
(3) month period to include the cost of gas for permissible imbalance
quantities. For purposes of this FERC Gas Tariff, the insolvency of a
Shipper shall be evidenced by the filing by such Shipper or any parent
entity thereof (hereinafter collectively referred 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 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 or liquidation of its
affairs, with said order or decree continuing unstayed and in effect
for a period of sixty (60) consecutive days. Notwithstanding the above
and Section 6.4 of this FERC Gas Tariff, El Paso shall not suspend
service to any Shipper, who is or has become insolvent, in a manner
that is inconsistent with the Federal Bankruptcy Code.
20.10 El Paso shall have no responsibility prior to its acceptance of
natural gas at the receipt point(s) and after delivery at the delivery
point(s), and Shipper shall have sole responsibility for all
arrangements necessary for delivery of natural gas to El Paso at the
receipt point(s) for transportation, and for all arrangements
necessary for receipt of natural gas for the account of Shipper at the
delivery point(s), which arrangements otherwise meet the provisions
set forth in these General Terms and Conditions.
<PAGE>
TF01005708052494El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03276 0 0 5P126Original Sheet No. 276
TF04
TF05A.W.Clark, Vice President
TF06052394****** 070194
TF09E2 0 0 -1 0N052494061694GT94-46-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
20. OPERATING PROVISIONS FOR FIRM TRANSPORTATION SERVICE (Continued)
20.11 Resolution of Imbalances
For purposes of this Section 20.11 "Shipper" shall include any party
utilizing El Paso's system and services including, without limitation,
any party tendering or receiving gas under Shipper's contract but
excluding any operator of interconnecting facilities and any volume
subject to a written assistance agreement with El Paso. El Paso and
the operator of any interconnecting facilities may cash-out
imbalances, pursuant to a written agreement between them.
(a) Imbalances Prior to Effective Date of this Provision -Imbalances
existing prior to the effective date of this provision will be
corrected in kind, as described below, unless El Paso and Shipper
agree to correct such imbalances in cash. El Paso and Shipper
shall attempt, in good faith, to agree upon the historical
imbalance and the time period to correct such historical
imbalance. If, despite such good faith efforts, El Paso and
Shipper fail to reach written agreement upon the appropriate
corrective action within six (6) months from the effectiveness of
this section, then Shipper shall be required to correct any
remaining imbalance within sixty (60) days, subject to
operational constraints on El Paso's system. El Paso shall extend
the sixty (60) day balancing period by one (1) day for each day
that El Paso is unable to receive or deliver scheduled imbalance
gas due to operational constraints on El Paso's system. If after
the sixty (60) day balancing period or extension due to
operational constraints Shipper has not corrected the imbalance,
then El Paso shall (i) for any remaining imbalances where
deliveries exceed receipts ("negative imbalance") charge Shipper
per dth based upon the arithmetic average of the System Weighted
Index Price for each quarter of the twelve (12) months ending
December 31, 1992 (the System Weighted Index Price for each
quarter shall be based on the method set forth in Section
20.11(e)(i) below); or (ii) for any remaining imbalances where
receipts exceed deliveries ("positive imbalance") retain the
imbalance at no cost and free and clear of any adverse claims by
any party or any obligation to account for such gas; provided
however, that in the event of a bona fide dispute by Shipper of
<PAGE>
TF01005708052494El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03277 0 0 5P126Original Sheet No. 277
TF04
TF05A.W.Clark, Vice President
TF06052394****** 070194
TF09E2 0 0 -1 0N052494061694GT94-46-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
20. OPERATING PROVISIONS FOR FIRM TRANSPORTATION SERVICE (Continued)
20.11 Resolution of Imbalances (Continued)
the amount of the imbalance, El Paso shall not take the action
outlined above when Shipper acts in a timely manner to provide
additional information and security for El Paso in accordance
with the following procedures.
(i) Identify Dispute: Within fifteen (15) days after El Paso's
notification of an imbalance, Shipper shall notify El Paso
by written correspondence of the imbalance that is in bona
fide dispute and of all reasons and documentation why
Shipper believes El Paso's calculation of the imbalance is
not correct; and
(ii) Payment Security: Within thirty (30) days after El Paso's
notification of an imbalance, Shipper shall either agree to
the imbalance calculated by El Paso without prejudice to
Shipper's rights to dispute all or part of said imbalance
and subject to return of the disputed imbalance so
identified after resolution of that dispute or Shipper shall
take the necessary actions to correct the imbalances it
concedes to be correct and furnish good and sufficient
surety bond, guaranteeing the correction of any imbalance
ultimately found owed to El Paso after resolution of the
dispute, including late payment charges which accrue until
resolution of the dispute with respect to any negative
imbalances, which resolution may be reached either by
agreement or judgment of a court of competent jurisdiction.
If resolution of the dispute is in favor of Shipper and the
Shipper furnished a surety bond then El Paso shall pay to
Shipper the costs incurred in securing that surety bond for
this dispute including any late payment charges actually
paid to El Paso.
(b) Calculation of an Imbalance Subsequent to the Effectiveness of
this Provision - El Paso and Shippers shall resolve an over-
delivery or under-delivery of gas to El Paso each month
<PAGE>
TF01005708052494El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03278 0 0 5P126Original Sheet No. 278
TF04
TF05A.W.Clark, Vice President
TF06052394****** 070194
TF09E2 0 0 -1 0N052494061694GT94-46-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
20. OPERATING PROVISIONS FOR FIRM TRANSPORTATION SERVICE (Continued)
20.11 Resolution of Imbalances (Continued)
in accordance with this Section 20.11. Each month, El Paso will
calculate a percentage imbalance for each individual contract for
each Shipper by dividing the total cumulative imbalance
quantities in excess of 1,000 dth, attributable to the imbalance
amount for such contract (numerator) by Shipper's Transportation
Contract Demand multiplied by 30 days (denominator) or, with
respect to those Shippers with an executed Transportation Service
Agreement which requires the delivery by El Paso of "Full
Requirements," the average non-coincidental three (3) day peak
over the most recent five (5) year period multiplied by 30 days
(denominator). The result of such calculation will be included on
El Paso's imbalance statement to Shipper, or its designee, and
shall serve as notification to the Shipper of an imbalance. If an
imbalance is equal to or greater than +/-5%, the Shipper is
provided additional notice on said statement that if such
imbalance continues and becomes equal to or greater than +/-10%,
the Shipper is subject to cash-out of the imbalance pursuant to
this Section 20.11; provided, however, that in no event shall
cash-out be assessed when the amount of the imbalance does not
exceed 1,000 dth, unless the parties mutually agree otherwise;
provided, further, if a verifiable imbalance is caused by El
Paso, that portion of the imbalance shall not be considered as
part of Shipper's imbalance for purposes of initiating cash-out.
In addition, cash-out of imbalances will not be mandatory if the
parties have reached written agreement on the resolution of the
imbalance provided such agreement is final prior to the
triggering of cash-out as specified in Section 20.11(c) below.
Written agreements may consist of, but are not limited to the
following provisions (i) offsetting of imbalances; (ii) extension
of a payback period within a set time period; and (iii)
negotiated price other than the cash-out prices reflected herein.
(c) Triggering of Cash-Out - Except for those contracts without
activity for a period of six (6) months, as discussed in Section
20.11(d), any cumulative imbalance at the end of any month that
is within a tolerance level less than +/-5% shall
<PAGE>
TF01005708052494El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03279 0 0 5P126Original Sheet No. 279
TF04
TF05A.W.Clark, Vice President
TF06052394****** 070194
TF09E2 0 0 -1 0N052494061694GT94-46-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
20. OPERATING PROVISIONS FOR FIRM TRANSPORTATION SERVICE (Continued)
20.11 Resolution of Imbalances (Continued)
not be subject to this Section 20.11 during such month. Such
imbalance shall be forwarded to the next month's imbalance
calculation. If the cumulative imbalance for any month is equal to
or greater than +/-5%, El Paso shall notify Shipper, as indicated
in Section 20.11(b), that it is approaching a cash-out situation
for an imbalance equal to or in excess of +/-10%. For any month
that a cumulative imbalance is equal to or in excess of +/-10%,
cash-out of the imbalance will take place provided Shipper has
received a minimum of two (2) consecutive monthly notices (minimum
of 45 days from date of first notice) alerting Shipper to an
imbalance equal to or in excess of +/-5%. El Paso shall extend the
45-day grace period by one (1) day for each day that El Paso is
unable to receive or deliver requested and confirmed imbalance gas
for a given contract due to operational constraints on El Paso's
system. If the parties have not reached written agreement
otherwise, the imbalance will be reduced to +/-5% by "cash-out"
the month following the last notice, at the dollar value
calculated with the cumulative imbalance and an established
monthly price, referred to herein as the Index Price, as
determined in Section 20.11(e) below. The Index Price shall be
calculated as of the month the imbalance first equals or exceeds
the +/-10% level.
(d) Six-Month Resolution of Inactive Contracts - El Paso will notify
Shipper after three (3) consecutive months of inactivity that at
the end of any six (6) month period that a contract between
Shipper and El Paso has been inactive and has maintained an
imbalance of less than +/-10%, for which no cash-out was
applicable and before the next invoice and balance statement date,
such imbalance shall be reduced to zero (0) by cash-out utilizing
the Index Price for the month after the end of six (6) month
period reflected in Section 20.11(e).
(e) Index Prices and Cash Out
(i) Cash-out shall be based on one of four calculated
price indices, depending on whether Shipper has one
<PAGE>
TF01005708052494El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03280 0 0 5P126Original Sheet No. 280
TF04
TF05A.W.Clark, Vice President
TF06052394****** 070194
TF09E2 0 0 -1 0N052494061694GT94-46-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
20. OPERATING PROVISIONS FOR FIRM TRANSPORTATION SERVICE (Continued)
20.11 Resolution of Imbalances (Continued)
or more of the three supply basins (i.e., San Juan, Permian
or Anadarko Basins) included in its agreement. A single
price index calculated only for a specific supply basin will
be used if Shipper has only that one supply basin in its
agreement. A System Weighted Index Price calculated for all
supply basins will be used if Shipper has more than one
supply basin in its agreement. The calculation of each price
index is set forth below:
(1) The Anadarko Basin Index Price shall be computed using
a simple average of reported prices as delivered to El
Paso's Mainline System at Washita, Anadarko, Oklahoma,
or the Texas Panhandle from the publications
identified in Section 20.11(e)(ii);
(2) The Permian Basin Index Price shall be computed using
a simple average of reported prices as delivered to El
Paso's Mainline System at West Texas, Permian or Waha
from the publications identified in Section
20.11(e)(ii); and
(3) The San Juan Basin Index Price shall be computed using
a simple average of reported prices as delivered to El
Paso's Mainline System at Ignacio, San Juan or New
Mexico from the publications identified in Section
20.11(e)(ii).
(4) The System Weighted Index Price shall be computed
monthly by using the weighted average of the Anadarko
Basin Index Price, the Permian Basin Index Price, and
the San Juan Basin Index Price. The weighting is based
on the volumes entering El Paso's system in each basin
during the previous quarter and will be updated
quarterly.
(ii) The four trade publications referenced above are Inside
FERC Gas Market Report (Prices of Spot Gas
<PAGE>
TF01005708052494El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03281 0 0 5P126Original Sheet No. 281
TF04
TF05A.W.Clark, Vice President
TF06052394****** 070194
TF09E2 0 0 -1 0N052494061694GT94-46-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
20. OPERATING PROVISIONS FOR FIRM TRANSPORTATION SERVICE (Continued)
20.11 Resolution of Imbalances (Continued)
Delivered to Pipelines), Natural Gas Week (Spot Prices on
Natural Gas Pipeline Systems, Delivered to Pipelines), Gas
Daily (Natural Gas Survey), and Natural Gas Intelligence Gas
Price Index (Spot Gas Prices Delivered to Pipeline, 30 Day
Supply Transactions).
In the event any of the publications cease publication or to the
extent a publication fails to report spot prices, then El Paso
shall reserve the right to substitute prices reported in a similar
independent publication or continue the pricing formula using the
average of the remaining publications. Changes in the name, format
or other method of reporting by the publications in (e) above that
do not materially affect the content shall not affect their use
hereunder.
(iii) El Paso shall post the Index Price monthly on its electronic
bulletin board on or before the 15th day of each month
applicable to the prior business month.
(iv) For any contract where total deliveries by El Paso for a
Shipper exceed the total receipts from Shipper, after
appropriate reductions, such imbalance shall be "cashed out"
based on the percentages provided below. Further, the Index
Price shall be adjusted to reflect the point at which the
imbalance is held.
(1) For any contract subject to Section 20.11(d), or by
mutual agreement any contract with an imbalance up to
and including +5%, the quantity will be invoiced at
100% of the Index Price;
(2) For any contract subject to Section 20.12(d) or any
contract with an imbalance greater than +5% but less
than or equal to +10%, the quantity in excess of +5%
will be invoiced at 110% of the Index Price;
<PAGE>
TF01005708052494El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03282 0 0 5P126Original Sheet No. 282
TF04
TF05A.W.Clark, Vice President
TF06052394****** 070194
TF09E2 0 0 -1 0N052494061694GT94-46-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
20. OPERATING PROVISIONS FOR FIRM TRANSPORTATION SERVICE (Continued)
20.11 Resolution of Imbalances (Continued)
(3) For any contract with an imbalance greater than +10%
but less than or equal to +15%, the volume in excess
of +10% will be invoiced at 120% of the Index Price;
(4) For any contract with an imbalance greater than +15%
but less than or equal to +20%, the volume in excess
of +15% will be invoiced at 130% of the Index Price;
and
(5) For any contract with an imbalance greater than +20%,
the volume in excess of +20% will be invoiced at 140%
of the Index Price.
(v) For any contract where total receipts by El Paso from a
Shipper, after appropriate reductions, exceed total
deliveries for that Shipper, such imbalance shall be "cashed
out" based on the percentages provided below. Further, the
Index Price shall be adjusted to reflect the point at which
the imbalance is held.
(1) For any contract subject to Section 20.11(d) or
subject to any other mutually agreeable terms, with an
imbalance up to and including-5%, the quantity will be
purchased by El Paso at 100% of the Index Price;
(2) For any contract subject to Section 20.11(d) or any
contract with an imbalance greater than -5% but less
than or equal to -10%, the quantity in excess of -5%
will be purchased by El Paso at 90% of the Index
Price;
(3) For any contract with an imbalance greater than -10%
but less than or equal to -15%, the volume in excess
of -10% will be purchased by El Paso at 80% of the
Index Price;
<PAGE>
TF01005708052494El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03283 0 0 5P126Original Sheet No. 283
TF04
TF05A.W.Clark, Vice President
TF06052394****** 070194
TF09E2 0 0 -1 0N052494061694GT94-46-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
20. OPERATING PROVISIONS FOR FIRM TRANSPORTATION SERVICE (Continued)
20.11 Resolution of Imbalances (Continued)
(4) For any contract with an imbalance greater than -15%
but less than or equal to -20%, the volume in excess
of -15% will be purchased by El Paso at 70% of the
Index Price; and
(5) For any contract with an imbalance greater than -20%,
the volume in excess of -20% will be purchased by El
Paso at 60% of the Index Price.
(vi) At the time a Shipper is in a cash-out position requiring
payment to El Paso at the appropriate rate set forth in
Section 20.11(e)(iv) above and such Shipper also has an
Unauthorized Gas balance, as such term is defined in Section
27.1 of these General Terms and Conditions, such
Unauthorized Gas balance may be offset against the
quantities due El Paso within the same production basin and
adjusted to reflect the point at which the imbalance is
held. At the time of invoicing for the net imbalance, El
Paso shall appropriately invoice or account for any
production area charges and liquid credits applicable to the
unauthorized gas used as an offset. This provision is not
applicable to the Unauthorized Gas retained as a penalty
pursuant to Section 27 of these General Terms and
Conditions.
Prior to any offsets, El Paso at its option may first offset
any under or over-deliveries between contracts with such
Shipper.
Shipper or its suppliers shall be responsible for reporting
and payment of any royalty, tax, or other burdens on natural
gas volumes received by El Paso and El Paso shall not be
obligated to account for or pay such burdens.
(f) Crediting of Revenues - When the aggregate value received from all
sources resulting from cash-out exceeds the cost of gas plus
administrative fees, El Paso shall credit such net amount within
90 days of the payment date to Shippers on a
<PAGE>
TF01005708112995El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03284 1 0 5P126First Revised Sheet No. 284
TF04 Original Sheet No. 284
TF05Patricia A.Shelton, Vice President
TF06112895091395CP94-183-000 and 001010196
TF09E5 0 0 -1 0N112995122995RP96-52-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
20. OPERATING PROVISIONS FOR FIRM TRANSPORTATION SERVICE (Continued)
20.11 Resolution of Imbalances (Continued)
pro rata basis in accordance with the volumes transported for each
Shipper.
(g) Netting of Contracts - For purposes of resolving an imbalance with
a Shipper, El Paso shall net gas imbalances, on a non-
discriminatory basis, adjusted to reflect a common point at which
the imbalance is held, between contracts with such Shipper
pursuant to the conditions identified below.
(i) Netting between downstream interconnect and mainline
agreement imbalances is negotiable if the agreement
has the interconnect point as a delivery point.
(ii) Netting between mainline agreement imbalances (for
similar transportation service) is negotiable.
(iii) Netting between Unauthorized Gas and mainline
agreement imbalances is negotiable if both the
Unauthorized Gas and imbalance were generated in the
same basin.
For any specific situation not discussed above, El Paso is willing
to negotiate a transportation transaction which could have the
effect of netting imbalances.
20.12 Unauthorized Overpull Penalty
(a) A penalty shall be levied by El Paso and paid in dollars by any
receiving party (any Shipper, Local Distribution Company, Direct
Sales Customer or other party who operates the facilities that
receive the gas transported by El Paso) who exceeds the limits
specified below. Such penalty is applicable when, in times of
capacity constraints, or when, due to unforeseen circumstances
beyond El Paso's control, El Paso has determined that its ability
to maintain scheduled deliveries to all receiving parties is
materially
<PAGE>
TF01005708052494El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03285 0 0 5P126Original Sheet No. 285
TF04
TF05A.W.Clark, Vice President
TF06052394****** 070194
TF09E2 0 0 -1 0N052494061694GT94-46-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
20. OPERATING PROVISIONS FOR FIRM TRANSPORTATION SERVICE (Continued)
20.12 Unauthorized Overpull Penalty (Continued)
threatened due to insufficient pressures in El Paso's system and
El Paso so notifies said receiving parties. Nothing herein shall
limit El Paso's right to take any further actions required to
maintain the integrity of its system operations.
(b) On any day El Paso determines that it is unable to deliver the
total volumes of gas scheduled for delivery for the account of all
Shippers, it shall have the right to notify all receiving parties
that an Unauthorized Overpull Penalty situation exists.
Contemporaneously with, or shortly following such notice, El Paso
shall give notice to any receiving party who is taking volumes at
a level that would subject such party to an Unauthorized Overpull
Penalty as provided below.
(c) The quantity of gas subject to such penalty is that quantity of
gas taken by the receiving party which exceeds the quantity of gas
scheduled by El Paso for delivery to such party on any day.
(d) Upon receipt of a notification from El Paso, such party shall
within twenty-four (24) hours reduce takes to a level no more than
3% above its scheduled volume for such day or 1,000 dth, whichever
is larger. Such twenty-four (24) hour notice period shall commence
at seven (7:00) a.m. Mountain Standard Time on the day after
notice is actually provided. If after the twenty-four (24) hour
notice period the receiving party continues to take volumes of gas
that exceed the foregoing threshold, an Unauthorized Overpull
Penalty shall be levied by El Paso and paid in dollars by any
receiving party as follows:
(i) A penalty of $5.00 per dth shall apply to all
unauthorized overrun volumes which exceed the 3% or
1,000 dth tolerance level, whichever is larger, up to
the first 5% of scheduled volumes; and
(ii) A penalty of $10.00 per dth shall apply to daily
unauthorized overrun volumes in excess of 5% of
scheduled volumes.
<PAGE>
TF01005708052494El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03286 0 0 5P126Original Sheet No. 286
TF04
TF05A.W.Clark, Vice President
TF06052394****** 070194
TF09E2 0 0 -1 0N052494061694GT94-46-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
20. OPERATING PROVISIONS FOR FIRM TRANSPORTATION SERVICE (Continued)
20.12 Unauthorized Overpull Penalty (Continued)
El Paso shall notify Shippers each day during an Unauthorized
Overpull Penalty situation, via El Paso's Electronic Bulletin
Board, that the situation continues to exist. Such notice does not
constitute notification of a new penalty period pursuant to this
Section 20.12(d) and does not begin a new twenty-four (24) hour
correction period.
(e) El Paso shall establish an Unauthorized Overpull Penalty account
for each month that El Paso receives such penalty payments for the
benefit of all qualified Shippers as provided below:
(i) A qualified Shipper is defined as a Shipper that did
not receive its scheduled volumes due to El Paso's
inability, for any reason, to make such deliveries on
days when El Paso has provided notice that an
Unauthorized Overpull Penalty situation exists, as
defined in Section 20.12(a) above.
(ii) Payments for Unauthorized Overpull Penalties shall be
credited to the Unauthorized Overpull Penalty account.
The disposition of the total dollars paid
unconditionally to El Paso in any month, as determined
in (iii) below, shall be made on a quarterly basis as
determined in (iv) below.
(iii) The Unauthorized Overpull Penalty amounts attributable
to each day shall be allocated on a pro rata basis to
all qualified Shippers that receive less than their
scheduled quantities of gas on that day.
(iv) Each qualified Shipper shall be entitled to receive
their share of the Unauthorized Overpull Penalty
account determined in accordance with (iii) above as a
credit adjustment to the transportation service
invoice rendered by El Paso in any month in the
following calendar quarter after the penalty payment
is received by El Paso.
<PAGE>
TF01005708112495El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03287 1 0 5P126First Revised Sheet No. 287
TF04 Original Sheet No. 287
TF05Patricia A.Shelton, Vice President
TF06112295092895RM95-3-000 122495
TF09E4 0 0 -1 0N112495122295RP96-49-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
20. OPERATING PROVISIONS FOR FIRM TRANSPORTATION SERVICE (Continued)
20.13 Flexible Receipt and Delivery Point(s)
(a) Any Shipper that has a Rate Schedule FT-1 firm Transportation
Service Agreement applicable to mainline or field transportation
shall have the right to tender gas to El Paso at any designated
receipt point physically located on that part of El Paso's system
to which such Shipper's Transportation Service Agreement applies.
Shipper's Transportation Service Agreement shall designate the
"primary receipt point(s)." Any other receipt point(s) utilized by
such Shipper shall be referred to as an "alternate receipt
point(s)."
(b) In addition to a Rate Schedule FT-1 Shipper's point(s) of delivery
as established in its effective firm Transportation Service
Agreement, hereinafter referred to as the "primary delivery
point(s)," such Shipper may utilize alternate delivery point(s)
under such agreement pursuant to the following conditions:
(i) the alternate delivery point(s) on El Paso's system is
located within the same delivery zone as Shipper's
primary delivery point(s) or is located upstream of
the delivery zone containing Shipper's primary
delivery point(s), or for those contracts in which the
direction of service is counter to the flow order
specified below, the alternate delivery point(s) is
located along the route over which service is provided
and for which a reservation charge(s) is paid. The
flow order in which the delivery zones are arranged
from the furthest downstream to the furthest upstream
zones are as follows: California; Nevada; Arizona; New
Mexico; and Texas; and
(ii) the total quantity of gas transported by El Paso to
Shipper's primary delivery point(s) and alternate
delivery point(s) shall not exceed Shipper's
Transportation Contract Demand unless otherwise agreed
to by El Paso. For any Shipper who is a full
requirements Shipper, for purposes of this Section
20.13(b), such Shipper's Transportation Contract
Demand shall be deemed to be Shipper's
<PAGE>
TF01005708112495El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03288 1 0 5P126First Revised Sheet No. 288
TF04 Original Sheet No. 288
TF05Patricia A.Shelton, Vice President
TF06112295092895RM95-3-000 122495
TF09E4 0 0 -1 0N112495122295RP96-49-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
20. OPERATING PROVISIONS FOR FIRM TRANSPORTATION SERVICE (Continued)
20.13 Flexible Receipt and Delivery Point(s) (Continued)
Billing Determinant as set forth in Rate Schedule FT-1
of this FERC Gas Tariff; provided, however, such
Billing Determinant limitation shall not apply when a
full requirements Shipper utilizes only its primary
delivery point(s).
20.14 Rate Application for Alternate Receipt and Delivery Point(s) - In the
event Shipper uses an alternate receipt point(s) or delivery point(s)
located in an upstream delivery zone, Shipper shall continue to be
billed the reservation charge(s) and reservation surcharge(s)
applicable to the delivery zone in which Shipper's primary delivery
point(s) is located. In addition, Shipper shall pay the maximum usage
charge(s), unless otherwise provided, applicable to the production
basin(s) and delivery point(s) actually used for the transportation
service. Notwithstanding the applicability of any contractually
agreed-upon lower rate for services using primary receipt and delivery
points, all transportation services using either an alternate receipt
point or alternate delivery point, or both, shall be subject to the
maximum transportation rate for such service, as set forth in this
FERC Gas Tariff, unless El Paso otherwise agrees in writing at the
time the service using such alternate point(s) is requested.
20.15 Abandonment of Transportation Service - Unless otherwise provided in
the applicable Transportation Service Agreement and subject to Section
20.16 below, El Paso shall be entitled to avail itself of the
pregranted abandonment authority under Section 7(b) of the Natural Gas
Act of long-term (twelve (12) months or more) firm transportation
services, as authorized by Section 284.221(d) of the Commission's
Regulations, upon the expiration of the contractual term or upon
termination of each individual transportation arrangement and shall
seek offers from competing Shippers interested in receiving such firm
transportation service, as provided below.
<PAGE>
TF01005708052494El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03289 0 0 5P126Original Sheet No. 289
TF04
TF05A.W.Clark, Vice President
TF06052394****** 070194
TF09E2 0 0 -1 0N052494061694GT94-46-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
20. OPERATING PROVISIONS FOR FIRM TRANSPORTATION SERVICE (Continued)
20.16 Right-of-First-Refusal
(a) Upon expiration of the term of the Transportation Service
Agreement of a long term Shipper, such Shipper shall have a
"right-of-first-refusal" as prescribed in this Section 20.16. In
order to avail itself of its right-of-first-refusal, the Shipper
must give El Paso its written notice of intent to exercise such
right of first refusal not later than (i) the date of the notice
period provided for in Shipper's contract; or (ii) twelve (12)
months prior to the expiration of the term of the contract,
whichever shall first occur.
(b) El Paso shall post on its electronic bulletin board the terms and
conditions of the available capacity under the expiring contract
as follows:
(i) firm daily quantities stated in Mcf/d;
(ii) the delivery point(s) at which capacity is available
and the firm quantities at such point(s);
(iii) effective date;
(iv) term;
(v) the rate (i.e., Reservation Charge(s) and Usage
Charge(s) applicable to each delivery point);
(vi) minimum conditions; and
(vii) the criteria by which bids are to be evaluated.
(c) Capacity will be made available on a nondiscriminatory basis and
will be assigned on the basis of an open season for a period of
not less than ninety (90) days duration.
(i) Shipper(s) desiring to acquire such available capacity
shall notify El Paso, via its electronic bulletin
board, during the open season. Such notice shall be
binding once received by El Paso and shall not be
revocable by such Shipper.
<PAGE>
TF01005708052494El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03290 0 0 5P126Original Sheet No. 290
TF04
TF05A.W.Clark, Vice President
TF06052394****** 070194
TF09E2 0 0 -1 0N052494061694GT94-46-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
20. OPERATING PROVISIONS FOR FIRM TRANSPORTATION SERVICE (Continued)
20.16 Right-of-First-Refusal (Continued)
(ii) Shipper's bid must include:
(a) Shipper's legal name and, if applicable, the
contract number under which it desires to acquire
capacity;
(b) the quantity of capacity to be acquired at each
delivery point(s);
(c) the term of the acquisition (the maximum term used
for bid evaluation will be twenty (20) years); and
(d) the maximum rate Shipper is willing to pay for the
capacity.
(iii) The potential Shipper must satisfy the other
provisions of this Tariff applicable to requests for
firm transportation.
(d) El Paso shall not be obligated to accept any offer for such
capacity at less than the maximum applicable tariff rate. In the
event El Paso accepts an offer, however, El Paso shall inform the
existing Shipper of the terms of such offer. The existing Shipper
shall have seven (7) days in which to inform El Paso that it
agrees to match such offer. Such agreement shall be irrevocable.
The existing Shipper or the offering Shipper, as appropriate,
shall execute a Transportation Service Agreement containing the
terms offered or matched.
(e) In the event there are no competing offers, then the existing
Shipper shall not be entitled to continue to receive
transportation service upon the expiration of its contract except
by agreeing to pay the maximum tariff rate unless El Paso and such
Shipper shall enter into a new firm transportation service
agreement providing otherwise.
<PAGE>
TF01005708112495El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03291 1 0 5P126First Revised Sheet No. 291
TF04 Original Sheet No. 291
TF05Patricia A.Shelton, Vice President
TF06112295092895RM95-3-000 122495
TF09E4 0 0 -1 0N112495122295RP96-49-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
21. ANNUAL CHARGE ADJUSTMENT PROVISION
21.1 Purpose - This Section 21 establishes an Annual Charge Adjustment
Provision ("ACA") which will permit El Paso to recover from its
Shippers the annual charges assessed to El Paso by the Commission
under Part 382 of the Commission's Regulations.
21.2 Applicable Customers - The ACA is applicable to each rate schedule
contained in Volume Nos. 1-A and Volume No. 2 FERC Gas Tariff as
identified on Sheet Nos. 20, 23, 24, 26, 27 and 28 of Volume No. 1-A
and Sheet Nos. 1-D.2 and 1-D.3 of Volume No. 2 Tariff.
21.3 Adjustment Date - The ACA unit charge shall be filed with the
Commission by El Paso at least thirty (30) days prior to the proposed
Adjustment Date unless a shorter period is specifically requested and
permitted by the Commission. The Adjustment Date shall be October 1 of
each year or as directed by an order of the Commission. On the
Adjustment Date, El Paso shall increase or decrease the ACA unit
charge to each of the applicable rate schedules as authorized by the
Commission to be recovered by El Paso. For those rate schedules with a
two-part rate, the ACA unit charge shall only apply to the usage
component of such rate.
21.4 Effective Date - The ACA unit charge shall become effective October 1
of each year or as directed by an order of the Commission if:
(a) El Paso has paid the applicable annual charge in compliance with
Section 382.103 of the Commission's Regulations; and
(b) the ACA unit charge is not subject to suspension or refund
obligation.
21.5 Accounting for Annual Charges Paid Under Part 382 - El Paso shall
account for annual charges paid by charging the amount to Account No.
928, Regulatory Commission Expenses, of the Commission's Uniform
System of Accounts. Any annual charges recorded in Account No. 928
shall not be recovered by El Paso in a Natural Gas Act Section 4 rate
case.
<PAGE>
TF01005708052494El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03292 0 0 5P126Original Sheet No. 292
TF04
TF05A.W.Clark, Vice President
TF06052394****** 070194
TF09E2 0 0 -1 0N052494061694GT94-46-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
22. TAKE-OR-PAY BUYOUT AND BUYDOWN COST RECOVERY
The provisions for this Section 22 are contained in Section 21 of the
General Terms and Conditions of El Paso's Volume No. 1 Tariff and are
incorporated herein by reference with respect to those provisions applicable
to the Throughput Surcharge. Such Throughput Surcharge is applicable to all
Shippers subject to El Paso's mainline transportation rates and/or Rate
Schedules contained in this Volume No. 1-A Tariff.
<PAGE>
TF01005708083194El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03293 1 0 5P126First Revised Sheet No. 293
TF04 Original Sheet No. 293
TF05A.W.Clark, Vice President
TF06083094****** 100194
TF09E3686227794N083194092694MT94-21-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
23. COMPLIANCE PLAN FOR TRANSPORTATION SERVICES AND AFFILIATE TRANSACTIONS
23.1 Shared operating employees and shared operating facilities between El
Paso and its marketing affiliate(s):
None.
There are no shared operating employees between the transportation
function of (i) El Paso and the merchant function of El Paso or (ii)
El Paso and its marketing affiliate(s). Only support facilities,
including utility, telecommunication, and computer systems at the
corporate headquarters complex, are shared by El Paso and its
marketing affiliate(s). Separate books of account, records, and
computer files are maintained for El Paso and for its marketing
affiliate(s).
23.2 The information and format required from a Shipper for a valid request
for transportation service or amended service are contained in Section
23.5 of this Section 23.
23.3 The procedures used to address and resolve complaints by Shippers and
potential Shippers are as follows:
(a) Any Shipper or potential Shipper may register a telephone
complaint concerning requested and/or furnished transportation
service by calling El Paso's customer assistance toll-free number
1-800-441-3764. Telephone complaints should provide the same
information as provided in written complaints by a Shipper.
Written complaints by any Shipper or potential Shipper, clearly
stating the issue(s), facts relied on by Shipper,
<PAGE>
TF01005708083194El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03294 1 0 5P126First Revised Sheet No. 294
TF04 Original Sheet No. 294
TF05A.W.Clark, Vice President
TF06083094****** 100194
TF09E3686227794N083194092694MT94-21-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
23. COMPLIANCE PLAN FOR TRANSPORTATION SERVICES AND AFFILIATE TRANSACTIONS
(Continued)
23.3 (Continued)
and the Shipper's position, should be mailed by registered or
certified mail, or delivered by hand to:
El Paso Natural Gas Company
Post Office Box 1492
El Paso, Texas 79978
Attention: Director
Mainline Transportation Department
(Street Address: 100 N. Stanton, El Paso, Texas
79901)
Upon receipt by El Paso, a complaint will be date stamped and
recorded in the Transportation Service Complaint Log maintained by
El Paso's Mainline Transportation and Customer Services
Department.
(b) El Paso will respond initially to all complaints by the most
appropriate communication means available within 48 hours and will
respond to all complaints filed with El Paso in writing within 30
days. El Paso's written response will be mailed by registered or
certified mail to Complainant and filed in the Transportation
Service Complaint Log. The final resolution of the complaint will
be dependent upon the nature of the complaint and the time
necessary to investigate the complaint, verify the underlying
cause(s) and determine the relevant facts.
23.4 El Paso will maintain a log containing the following information on
all requests for interruptible transportation service where allocation
of capacity is based on a first come/first served priority. The log
data relating to each contract shall be maintained as long as the
contract is used to allocate capacity and for three (3) years
thereafter.
<PAGE>
TF01005708083194El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03295 1 0 5P126First Revised Sheet No. 295
TF04 Original Sheet No. 295
TF05A.W.Clark, Vice President
TF06083094****** 100194
TF09E3686227794N083194092694MT94-21-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
23. COMPLIANCE PLAN FOR TRANSPORTATION SERVICES AND AFFILIATE TRANSACTIONS
(Continued)
23.4 (Continued)
(a) The identity of the Shipper making the request for service
including designating whether the Shipper is a local distribution
company, an interstate pipeline, an intrastate pipeline, an end-
user, a producer, or a marketer;
(b) The specific affiliation of the requester with El Paso, and the
extent of El Paso's affiliation, if any, with the person to be
provided transportation service;
(c) The contract number; and
(d) The date that the request was accepted as valid.
<PAGE>
TF01005708083194El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03296 1 0 5P126First Revised Sheet No. 296
TF04 Original Sheet No. 296
TF05A.W.Clark, Vice President
TF06083094****** 100194
TF09E3686227794N083194092694MT94-21-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
23. COMPLIANCE PLAN FOR TRANSPORTATION SERVICES AND AFFILIATE TRANSACTIONS
(Continued)
23.5 Transportation Service Request Form
EL PASO NATURAL GAS COMPANY
TRANSPORTATION SERVICE REQUEST FORM
____________________________________________________________________________
Federal Energy Regulatory Commission record and reporting requirements and El
Paso's FERC Gas Tariff require prospective Shippers and existing Shippers
requesting amended service to furnish the information below prior to processing
a request.
Return this completed FORM to:
Customer Services Department
El Paso Natural Gas Company
Post Office Box 1492
El Paso, Texas 79978
Telecopy: (915) 541-2544
____________________________________________________________________________
(PLEASE TYPE OR PRINT)
SHIPPER INFORMATION
1. Legal Name of Shipper: ________________________________________________
2. Shipper's Address: P.O. Box/Zip ______________________________________
Street/Zip ___________________________________
City/State ___________________________________
3. Shipper's State of Incorporation: _____________________________________
4. Duns Number: __________________________________________________________
5. Name of Requesting Party: _____________________________________________
Title: ________________________________________________________________
Phone: ________________________________________________________________
If employed by other than Shipper, please specify Requesting Party's:
Company Name __________________________________________________________
P.O. Box/Zip __________________________________________________________
Street/Zip ____________________________________________________________
City/State ____________________________________________________________
<PAGE>
TF01005708083194El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03297 1 0 5P126First Revised Sheet No. 297
TF04 Original Sheet No. 297
TF05A.W.Clark, Vice President
TF06083094****** 100194
TF09E3686227794N083194092694MT94-21-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
23. COMPLIANCE PLAN FOR TRANSPORTATION SERVICES AND AFFILIATE TRANSACTIONS
(Continued)
6. Shipper is (check one of the following):
a. ___Interstate Pipeline e. ___End-User
b. ___Intrastate Pipeline* f. ___Producer
c. ___Local Distribution Company* g. ___Marketer
d. ___Hinshaw Pipeline* h. ___Other (Specify)______
*State(s) in which Shipper's natural gas system facilities are located:
________________________________________________________________________
7. This request is for (check one): ______ New Service
______ Amended Service Under
Contract #_________________
If the request is for new service, please skip the Amended Service Request
section.
If the request is for amended service, please complete the Affiliate
Information and Amended Service Request sections only.
SERVICE/CONTRACT INFORMATION
1. Type of Transportation Service Requested (check one):
___Firm
___Interruptible
___Other
2. Date service is requested to commence: ________________________________
Date service is requested to terminate: _______________________________
Evergreen term requested: _____ Yes _____ No
3. Maximum daily contract quantity requested (please specify both):
__________ Mcf/d __________ MMBtu/d
Total contract quantity requested over primary term of agreement (please
specify both): __________ Mcf __________ MMBtu
<PAGE>
TF01005708083194El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03298 1 0 5P126First Revised Sheet No. 298
TF04 Original Sheet No. 298
TF05A.W.Clark, Vice President
TF06083094****** 100194
TF09E3686227794N083194092694MT94-21-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
23. COMPLIANCE PLAN FOR TRANSPORTATION SERVICES AND AFFILIATE TRANSACTIONS
(Continued)
If service is requested for a term of more than 120 days, what quantities
are requested to be transported on an:
Average Day ____Mcf ____MMBtu
Annual Basis ____Mcf ____MMBtu
4. Requested Receipt Point(s) and producing area(s) that are the source(s) of
gas transported. Please list on attached Exhibit A.
5. Requested Delivery Point(s). Please list on attached Exhibit B.
6. Notices to: ___________________________________________________________
Street or P.O. Box: ___________________________________________________
City, State, Zip: _____________________________________________________
Attention of: _________________________________________________________
Telephone: ____________________________________________________________
Telecopy: _____________________________________________________________
Invoices to: __________________________________________________________
Street or P.O. Box: ___________________________________________________
City, State, Zip: _____________________________________________________
Attention of: _________________________________________________________
Telephone: ____________________________________________________________
Telecopy: _____________________________________________________________
<PAGE>
TF01005708083194El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03299 1 0 5P126First Revised Sheet No. 299
TF04 Original Sheet No. 299
TF05A.W.Clark, Vice President
TF06083094****** 100194
TF09E3686227794N083194092694MT94-21-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
23. COMPLIANCE PLAN FOR TRANSPORTATION SERVICES AND AFFILIATE TRANSACTIONS
(Continued)
7. Name of Shipper's dispatcher for 24-hour contact: _____________________
Phone: _____________________ Telecopy: ________________________
RATE INFORMATION
Contact your T&E Project Manager in the Mainline Transportation Department
for discount requests.
FINANCIAL INFORMATION
El Paso requires each Shipper to provide financial statements (to include a
balance sheet, income statement and statement of cash flow). The statements
should be the most current available as of the date they are submitted. If
audited financial statements are not available, then Shipper also should provide
an attestation by its chief financial officer that the information shown in the
unaudited statements submitted is true, correct and a fair representation of
Shipper's financial condition.
<PAGE>
TF01005708083194El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03300 1 0 5P126First Revised Sheet No. 300
TF04 Original Sheet No. 300
TF05A.W.Clark, Vice President
TF06083094****** 100194
TF09E3686227794N083194092694MT94-21-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
23. COMPLIANCE PLAN FOR TRANSPORTATION SERVICES AND AFFILIATE TRANSACTIONS
(Continued)
Based on its review of Shipper's financial statements, El Paso may agree to
waive any further credit requirements as a condition of service. Alternatively,
El Paso may request Shipper to provide additional evidence of its
creditworthiness, in which event Shipper may elect to provide one of the
following:
- a clean irrevocable letter of credit in form and substance
satisfactory to El Paso in a face amount equal to (i) the sum of the
gas cost component of El Paso's sale-for-resale rates and the
applicable unit transportation rate(s) specified in El Paso's Tariff
for the service(s) which El Paso provides Shipper, (ii) multiplied by
the maximum daily quantity specified in El Paso's Transportation
Service Agreement with Shipper, (iii) multiplied by 90; or
- a guarantee, in form and substance satisfactory to El Paso, executed
by a person whom El Paso deems creditworthy, of Shipper's performance
of its obligations to El Paso under the Transportation Service
Agreement; or
- such other form of security as Shipper may agree to provide and as may
be acceptable to El Paso.
The FERC Gas Tariff of El Paso does not require the pipeline to provide
transportation service on behalf of any Shipper who fails to demonstrate
creditworthiness.
El Paso will treat the financial statements provided by Shipper as confidential.
AFFILIATE INFORMATION
1. Is Shipper affiliated with El Paso: _____ Yes _____ No
<PAGE>
TF01005708083194El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03301 1 0 5P126First Revised Sheet No. 301
TF04 Original Sheet No. 301
TF05A.W.Clark, Vice President
TF06083094****** 100194
TF09E3686227794N083194092694MT94-21-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
23. COMPLIANCE PLAN FOR TRANSPORTATION SERVICES AND AFFILIATE TRANSACTIONS
(Continued)
2. Is the Requesting Party (if other than Shipper) affiliated with El Paso:
_____ Yes _____ No
AMENDED SERVICE REQUEST
1. Addition of Receipt Point(s) -- Add the Receipt Point(s) identified on
Exhibit A to Contract #_____________.
2. Addition of Delivery Point(s) -- Add the Delivery Point(s) identified on
Exhibit B to Contract #___________. (Note addition of new Delivery Point(s)
and end users generally will result in a new position in the first
come/first served queue.)
<PAGE>
TF01005708083194El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03302 1 0 5P126First Revised Sheet No. 302
TF04 Original Sheet No. 302
TF05A.W.Clark, Vice President
TF06083094****** 100194
TF09E3686227794N083194092694MT94-21-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
23. COMPLIANCE PLAN FOR TRANSPORTATION SERVICES AND AFFILIATE TRANSACTIONS
(Continued)
3. Increase the maximum daily contract quantity under Contract #______ to
(specify both): _________ Mcf/d _________ MMBtu/d. (Note an increase in the
maximum daily contract quantity generally will result in a new position in
the first come/first served queue.)
4. Does Shipper request that service under Contract #___________ be converted
from Subpart B to Subpart G service (check one):
_____Yes _____No
5. Other requested service change(s): ____________________________________
________________________________________________________________________
________________________________________________________________________
________________________________________________________________________
________________________________________________________________________
________________________________________________________________________
________________________________________________________________________
* * *
Shipper hereby certifies that it has title or the right to ship the gas
delivered to El Paso for transportation and has entered into or will enter into
arrangements necessary to assure all upstream and downstream transportation will
be in place prior to commencement of service.
Shipper also certifies that the information herein is complete and accurate to
the best of Shipper's knowledge, information and belief.
Legal Name of Shipper: ____________________________
By: _______________________________________________
(Name and Title)
Date: _____________________________________________
<PAGE>
TF01005708083194El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03303 1 0 5P126First Revised Sheet No. 303
TF04 Original Sheet No. 303
TF05A.W.Clark, Vice President
TF06083094****** 100194
TF09E3686227794N083194092694MT94-21-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
23. COMPLIANCE PLAN FOR TRANSPORTATION SERVICES AND AFFILIATE TRANSACTIONS
(Continued)
EL PASO NATURAL GAS COMPANY
TRANSPORTATION SERVICE REQUEST FORM
EXHIBIT A
Requested Maximum Total Volume
Receipt Point(s)* Daily Volume (Over Term)
___________ _________Mcf/d __________Mcf
_______MMBtu/d _________MMBtu
___________ _________Mcf/d __________Mcf
_______MMBtu/d _________MMBtu
___________ _________Mcf/d __________Mcf
_______MMBtu/d _________MMBtu
___________ _________Mcf/d __________Mcf
_______MMBtu/d _________MMBtu
___________ _________Mcf/d __________Mcf
_______MMBtu/d _________MMBtu
___________ _________Mcf/d __________Mcf
_______MMBtu/d _________MMBtu
* Use 8-digit EPNG Code and include meter number(s).
<PAGE>
TF01005708083194El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03304 1 0 5P126First Revised Sheet No. 304
TF04 Original Sheet No. 304
TF05A.W.Clark, Vice President
TF06083094****** 100194
TF09E3686227794N083194092694MT94-21-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
23. COMPLIANCE PLAN FOR TRANSPORTATION SERVICES AND AFFILIATE TRANSACTIONS
(Continued)
EL PASO NATURAL GAS COMPANY
TRANSPORTATION SERVICE REQUEST FORM
EXHIBIT B
Requested Maximum Total Volume
Delivery Point(s)* Daily Volume (Over Term)
___________ _________Mcf/d __________Mcf
_______MMBtu/d _________MMBtu
___________ _________Mcf/d __________Mcf
_______MMBtu/d _________MMBtu
___________ _________Mcf/d __________Mcf
_______MMBtu/d _________MMBtu
___________ _________Mcf/d __________Mcf
_______MMBtu/d _________MMBtu
___________ _________Mcf/d __________Mcf
_______MMBtu/d _________MMBtu
___________ _________Mcf/d __________Mcf
_______MMBtu/d _________MMBtu
* Use 8-digit EPNG Code and include meter number(s).
<PAGE>
TF01005708083194El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03305 1 010P126First Revised Sheet No. 305
TF04 Original Sheet No. 305
TF05A.W.Clark, Vice President
TF06083094****** 100194
TF09E3686227794N083194092694MT94-21-000
Reserved Sheets
First Revised Sheet Nos. 306 and 307 have been reserved.
<PAGE>
TF01005708052494El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03308 0 0 5P126Original Sheet No. 308
TF04
TF05A.W.Clark, Vice President
TF06052394****** 070194
TF09E2 0 0 -1 0N052494061694GT94-46-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
24. ORDER NO. 636 ELECTRONIC BULLETIN BOARD
24.1 El Paso's Electronic Bulletin Board ("EBB") is accessed through its
electronic communications service known as "Passport". Passport
provides a portfolio of electronic business services to El Paso's
customers. El Paso's EBB is available on a non-discriminatory basis to
any party that has compatible equipment for electronic transmission of
data, provided that such party has entered into a Passport Electronic
Network Agreement and has been assigned a user identification,
password and security code. Access to the EBB may be obtained by
contacting Passport Services at (915) 541-2000. There is no charge to
use the EBB.
24.2 El Paso's EBB shall provide such data as described in and shall be in
compliance with FERC Order No. 636, et seq., by providing:
(a) a means for all firm shippers to post their "grandfathered"
buy/sell transactions, for informational purposes only, for a
period of thirty (30) days identifying price, terms and conditions
and name of the parties; and
(b) a means for a releasing or acquiring Shipper electing to release
all or a portion of its firm transportation rights in accordance
with Section 28.4 and Section 28.5 contained in this Volume No. 1-
A Tariff to advertise such release.
24.3 Parties wishing to bid on released capacity or to compete with pre-
arranged offers shall post their bids through the EBB. Only those
parties who are prequalified with respect to creditworthiness in
accordance with Section 28.20 contained in El Paso's Volume No. 1-A
Tariff may submit a bid during the open season in accordance with
Section 28.9 contained in said Tariff.
24.4 The EBB shall contain information concerning the availability of
capacity:
(a) at receipt points;
(b) on the mainline;
(c) at delivery points; and
<PAGE>
TF01005708122895El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03309 1 0 5P126Substitute First Revised Sheet No. 309
TF04 Original Sheet No. 309
TF05Patricia A.Shelton, Vice President
TF06122795****** 010196
TF09P0 0 0 -1 0N122895******RP95-363-003
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
24. ORDER NO. 636 ELECTRONIC BULLETIN BOARD (Continued)
24.4 (Continued)
(d) whether the capacity is available from El Paso directly or through
El Paso's Capacity Release Program set forth in Section 28
contained in this Volume No. 1-A Tariff.
24.5 El Paso shall post on the EBB notification of any of its uncommitted
firm pipeline capacity.
24.6 El Paso shall post, daily, on the EBB notification of any unscheduled
capacity available for interruptible transportation service, with
bidding in accordance with the applicable provisions of Section 19
contained in this Volume No. 1-A Tariff.
24.7 EBB users shall have access to all the information specifically
identified in FERC Order Nos. 497 and 636. EBB access, including
historical data, shall be available to state regulatory commissions
and state consumer advocates on the same basis as any other party. El
Paso shall maintain backup copies of the data contained on its EBB for
three years, which may be archived to off-line storage. Parties may
access the on-line data directly through the EBB. In the event the
data has been archived off-line, parties may request the data from
Passport Services through Passport's electronic mail service, wherein
such data shall be made available for downloading on user's computer.
EBB users shall be allowed to download files so their contents can be
reviewed in detail without tying up access to EBB. Information on the
most recent transactions shall be listed before older information. EBB
users shall be able to split large files into smaller parts for ease
of use. On-line help shall be available to assist the EBB users along
with a search function allowing users to locate all information
concerning a specific transaction, and menus that permit users to
separately access each record in the transportation log, offers to
release capacity, capacity available directly from the pipeline, and
standards of conduct information.
24.8 El Paso's currently effective Volume No. 1-A Tariff, as revised from
time to time, is posted on El Paso's EBB. Therefore, El Paso shall
provide paper copies of the effective tariff to customers and
interested state commissions only when specifically requested.
<PAGE>
TF01005708052494El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03310 0 010P126Sheet Nos. 310 through 319
TF04
TF05A.W.Clark, Vice President
TF06052394****** 070194
TF09E2 0 0 -1 0N052494061694GT94-46-000
Reserved Sheets
Original Sheet Nos. 310 through 319 have been reserved.
<PAGE>
TF01005708052494El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03320 0 010P126Sheet Nos. 320 through 329
TF04
TF05A.W.Clark, Vice President
TF06052394****** 070194
TF09E2 0 0 -1 0N052494061694GT94-46-000
Reserved Sheets
Original Sheet Nos. 320 through 329 have been reserved.
<PAGE>
TF01005708112995El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03330 1 0 5P126First Revised Sheet No. 330
TF04 Original Sheet No. 330
TF05Patricia A.Shelton, Vice President
TF06112895091395CP94-183-000 and 001010196
TF09E5 0 0 -1 0N112995122995RP96-52-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
27. UNAUTHORIZED GAS
27.1 Definition of Unauthorized Gas - Unauthorized Gas is natural gas that
has not been scheduled as authorized to be received by El Paso, either
for its own purchase under any gas purchase agreement, or for
transportation to another market under any Transportation Service
Agreement in accordance with the provisions of El Paso's FERC Gas
Tariff.
Unauthorized Gas is distinguished from transportation imbalances which
are excess volumes of natural gas delivered into El Paso's facilities
from any source scheduled to a market in accordance with the
provisions of this FERC Gas Tariff on any day when some lesser amount
is expressly authorized to flow on that day pursuant to Section 4.1 of
the General Terms and Conditions contained in this FERC Gas Tariff.
27.2 Unauthorized Gas Causing a Critical Situation - Upon notification from
El Paso of a critical Unauthorized Gas situation, any party shall,
within twenty-four (24) hours, terminate any unauthorized flow into El
Paso's facilities. El Paso shall have the right to shut in,
physically, the source of any Unauthorized Gas. If, after the twenty-
four (24) hour notice period, any quantity of Unauthorized Gas
continues to flow into El Paso's system, El Paso shall retain at no
cost to itself and free of any obligation to account therefor in kind
or otherwise to any person claiming an interest therein, the full
quantity of Unauthorized Gas introduced into El Paso's facilities. A
critical Unauthorized Gas situation shall apply only when El Paso, in
good faith, has determined that the safety and/or integrity of its
system is threatened. Nothing herein shall limit El Paso's right to
take any other actions required to maintain the safety and integrity
of its system operations.
<PAGE>
TF01005708112995El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03331 1 0 5P126First Revised Sheet No. 331
TF04 Original Sheet No. 331
TF05Patricia A.Shelton, Vice President
TF06112895091395CP94-183-000 and 001010196
TF09E5 0 0 -1 0N112995122995RP96-52-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
27. UNAUTHORIZED GAS (Continued)
27.2 Unauthorized Gas Causing a Critical Situation (Continued)
Until El Paso notifies the party(ies), either electronically or via
facsimile, that the critical Unauthorized Gas situation has ended, the
Unauthorized Gas penalty of retention of gas remains applicable on
each subsequent day without further notification and the party(ies)
shall not resume or continue flow of Unauthorized Gas.
27.3 Notification of Unauthorized Gas Not Causing a Critical Situation -
After the end of each month El Paso shall send each operator a notice
of Unauthorized Gas flow entitled "Statement of Unauthorized Gas
Account Balances," or succeeding statement. Such notice shall include
the volume, the receipt point(s) and the time frame in which the
Unauthorized Gas was received into El Paso's system.
27.4 Unauthorized Gas Subsequent to the Effectiveness of this Section -For
any Unauthorized Gas volumes delivered to El Paso subsequent to the
effectiveness of this section, and not retained because of a critical
Unauthorized Gas situation on El Paso's system, said party shall have
until the first day of the third month following the month of El
Paso's notification ("Return Period") to resolve the Unauthorized Gas
volumes; provided however, that any such resolution must be approved
by El Paso. El Paso and the party agree to negotiate in good faith for
resolution of the Unauthorized Gas and to commit in writing during the
Return Period any mutually agreed upon resolution. If El Paso
incorrectly classifies gas as Unauthorized Gas, El Paso will transfer
such gas to the appropriate agreement and will not assess any
penalties under this Section 27 on such volumes.
27.5 Unauthorized Gas Prior to the Effectiveness of this Section - For any
Unauthorized Gas volumes delivered to El Paso prior to the
effectiveness of this section, said party shall have six (6) months
after El Paso's notification ("Extended Return Period") to resolve the
Unauthorized Gas volumes; provided however, that any such resolution
must be approved by El Paso. El Paso and the party agree to negotiate
in good faith for resolution of the Unauthorized Gas and to commit to
writing during this Extended Return Period any mutually agreed upon
resolution.
<PAGE>
TF01005708112995El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03332 1 0 5P126First Revised Sheet No. 332
TF04 Original Sheet No. 332
TF05Patricia A.Shelton, Vice President
TF06112895091395CP94-183-000 and 001010196
TF09E5 0 0 -1 0N112995122995RP96-52-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
27. UNAUTHORIZED GAS (Continued)
27.6 Disposition of Unauthorized Gas - El Paso will approve resolution of
Unauthorized Gas volumes described in Sections 27.4 and 27.5 above as
follows:
(a) With El Paso's consent, proven owners of Unauthorized Gas may sell
such Unauthorized Gas volumes to any party as long as said party
causes the gas to be transported under an effective Transportation
Service Agreement on El Paso's system. Unless waived by El Paso on
a not unduly discriminatory basis, the party agrees to pay El Paso
the Unauthorized Gas penalty of thirty cents ($.30) per dth for
the respective Unauthorized Gas volumes being purchased, plus any
applicable transportation charge including fuel for redelivery.
The penalty of thirty cents ($.30) per dth shall not be applicable
for Unauthorized Gas volumes delivered into El Paso's system prior
to the effectiveness of this section.
(b) If said Unauthorized Gas volumes are not resolved by a mutually
agreed upon plan within the Return Period or the Extended Return
Period, as appropriate, El Paso may retain such Unauthorized Gas
volumes at no cost to itself and free of any obligation to account
therefor in kind or otherwise to any person claiming an interest
therein.
El Paso shall not assess more than one Unauthorized Gas penalty for
the same infraction.
27.7 Claiming Unauthorized Gas - To claim Unauthorized Gas volumes, the
party shall submit a written plan for resolution thereof to El Paso
within the Return Period or the Extended Return Period, as
appropriate, along with proof of ownership.
27.8 Reporting and Payment of Royalty, Tax, or other Burdens - Shipper or
its suppliers shall be responsible for reporting and payment of any
royalty, tax, or other burdens on natural gas volumes received by El
Paso and El Paso shall not be obligated to account for or pay such
burdens.
<PAGE>
TF01005708052494El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03333 1 0 5P126Original Sheet No. 333
TF04
TF05A.W.Clark, Vice President
TF06052394****** 070194
TF09E2 0 0 -1 0N052494061694GT94-46-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
27. UNAUTHORIZED GAS (Continued)
27.9 Challenging El Paso's Classification of Unauthorized Gas - Any party
claiming an interest in volumes of natural gas which El Paso has
determined to be Unauthorized Gas may challenge that determination by
the first day of the month following receipt from El Paso of the
notice of Unauthorized Gas. Such challenge shall be in writing and
include all documentation upon which such party relies to substantiate
its challenge. El Paso shall hold such gas until a final determination
has been reached as to the classification of the gas in question. If
no such challenge is received by El Paso within the period specified,
then El Paso's determination that the quantities in question were
Unauthorized Gas shall be final. Upon a determination that El Paso
incorrectly classified natural gas as unauthorized, El Paso shall
correct all records and make gas available, subject to operational
conditions, within sixty (60) days of such determination.
27.10 Accounting for Retained Unauthorized Gas and Penalties - El Paso shall
record the value of the Unauthorized Gas retained (pursuant to
Sections 27.2 and 27.6(b) of this tariff) and the penalty payments
received by El Paso (pursuant to Section 27.6(a) of this tariff) in
the appropriate revenue account. The Unauthorized Gas volumes retained
shall be valued at the value determined for the month the Unauthorized
Gas enters the El Paso system. The value of such retained Unauthorized
Gas shall be based on the appropriate index price for each production
basin (Anadarko, Permian or San Juan). Such calculation shall be in
accordance with Sections 20.11(e)(i)(1), (2) or (3), respectively, of
this tariff.
Any Shipper who has a valid Transportation Service Agreement providing
for mainline transportation services shall be eligible to receive a
share of the value of the Unauthorized Gas volumes retained (less
production area charges and taxes and royalties, if applicable) and
penalty payments received by El Paso. The Shipper's share shall be
credited to the monthly transportation service invoice rendered by El
Paso not later than 90 days after the month of retention or payment of
the penalty. El Paso shall credit each Shipper, including any
Acquiring Shipper, in proportion to the mainline charges billed to
that Shipper less conditional credits pursuant to Section 28.18 of
this tariff to the mainline charges billed to all Shippers in the
month of crediting less such conditional credits.
<PAGE>
TF01005708112495El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03334 1 0 5P126First Revised Sheet No. 334
TF04 Original Sheet No. 334
TF05Patricia A.Shelton, Vice President
TF06112295092895RM95-3-000 122495
TF09E4 0 0 -1 0N112495122295RP96-49-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
28. CAPACITY RELEASE PROGRAM
28.1 Purpose - This Section 28 sets forth the specific terms and conditions
applicable to the implementation by El Paso of a Capacity Release
Program on its interstate pipeline system.
28.2 Applicability - This Section 28 is applicable to any Shipper who has a
Part 284 Transportation Service Agreement under Rate Schedule FT-1
contained in this Volume No. 1-A Tariff or an Acquired Capacity
Agreement (except for those Acquired Capacity Agreements providing for
volumetric reservation charges) and who elects to release, subject to
the Capacity Release Program set forth herein, all or a portion of its
firm transportation rights. Shipper shall have the right to release
any portion of the firm capacity rights held under a Transportation
Service Agreement or an Acquired Capacity Agreement but only to the
extent that the capacity so released is acquired by another Shipper
pursuant to the provisions of this Section 28.
(a) With respect to any full requirements Rate Schedule FT-1 Shipper
who elects to participate in this Capacity Release Program, the
total capacity rights of such Shipper shall be deemed to be
limited to the quantity representing such Shipper's Billing
Determinants underlying El Paso's rates in effect from time to
time less the quantity actually released by such Shipper. This
limitation on the capacity rights of such full requirements
Shipper shall not apply during the time all capacity released
hereunder is recalled by such Shipper. If a full requirements
Shipper under Rate Schedule FT-1 is not participating in the
Capacity Release Program, such Shipper shall be entitled to full
requirements service in accordance with its Transportation Service
Agreement.
(b) Any Rate Schedule FT-2 Shipper may release capacity under the same
conditions set forth in (a) above provided that such Shipper is
willing to convert on a temporary basis, for a minimum term of one
(1) month, to service under Rate Schedule FT-1. Notice of the
intent to convert must be given to El Paso at least one (1) week
prior to the beginning of the month(s) for which such conversion
is to be effective. For purposes of determining capacity rights of
such Shipper, El Paso will utilize either the Shipper's billing
<PAGE>
TF01005708112495El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03335 1 0 5P126First Revised Sheet No. 335
TF04 Original Sheet No. 335
TF05Patricia A.Shelton, Vice President
TF06112295092895RM95-3-000 122495
TF09E4 0 0 -1 0N112495122295RP96-49-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
28. CAPACITY RELEASE PROGRAM (Continued)
28.2 Applicability (Continued)
determinants established in the general rate proceeding applicable on
the effective date of the conversion or a billing determinant
negotiated by the parties.
28.3 Definitions - For purposes of this Section 28, the following
definitions shall apply:
(a) Releasing Shipper - any Shipper holding firm capacity rights under a
Part 284 Transportation Service Agreement under Rate Schedule FT-1
or an Acquired Capacity Agreement who desires to release such firm
capacity rights to another Shipper pursuant to this Section 28.
(b) Bidding Shipper - any Shipper who is qualified, pursuant to Section
28.20, to bid for capacity via El Paso's electronic bulletin board
and who submits a bid for such capacity.
(c) Pre-Arranged Shipper - any Shipper who is qualified, pursuant to
Section 28.20, and seeks to acquire capacity under a pre-arranged
release for which notice is given pursuant to Section 28.5.
(d) Acquiring Shipper - any Shipper who acquires released capacity
rights from a Releasing Shipper.
(e) Firm Recallable Capacity - firm capacity released subject to the
Releasing Shipper's right to recall such capacity during the term of
the release.
(f) Acquired Capacity Agreement - an agreement between El Paso and the
Acquiring Shipper setting forth rate(s) and the terms and
conditions of service for using capacity rights acquired pursuant
to this Section 28, in the form contained in Section 28.25 of this
Volume No. 1-A Tariff.
28.4 Notice by Shipper Electing to Release Capacity - A Releasing Shipper
shall deliver a notice via El Paso's electronic bulletin board that
it elects to release firm capacity. The notice shall set forth:
<PAGE>
TF01005708052494El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03336 0 0 5P126Original Sheet No. 336
TF04
TF05A.W.Clark, Vice President
TF06052394****** 070194
TF09E2 0 0 -1 0N052494061694GT94-46-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
28. CAPACITY RELEASE PROGRAM (Continued)
28.4 Notice by Shipper Electing to Release Capacity (Continued)
(a) Releasing Shipper's legal name, contract number, and the name and
title of the individual responsible for authorizing the release of
capacity;
(b) the maximum and minimum (if desired) quantity of firm daily
capacity which the Releasing Shipper desires to release, stated in
Mcf/d;
(c) the delivery point(s) at which the Releasing Shipper will release
capacity and the firm capacity to be released at each such point;
(d) whether capacity will be released on a firm or firm recallable
basis and, if on a firm recallable basis, the terms on which the
capacity can be recalled, which terms must be objectively stated,
non-discriminatory and applicable to all bidders;
(e) the requested effective date and the term of the release;
(f) whether the Releasing Shipper is willing to consider release for a
shorter time period than that specified in (e) above, and, if so,
the minimum (if desired) acceptable period of release;
(g) whether the Releasing Shipper desires bids in dollars or as a
percentage of El Paso's maximum reservation charge(s) and
reservation surcharge(s) applicable to the capacity to be released
under this Volume No. 1-A Tariff as in effect from time to time;
(h) the maximum reservation charge(s) and reservation surcharge(s)
applicable to the capacity being released as shown on El Paso's
Statement of Rates applicable to the Releasing Shipper's
Transportation Service Agreement or Acquired Capacity Agreement
and whether the Releasing Shipper is willing to consider releasing
capacity at a lower rate;
<PAGE>
TF01005708052494El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03337 0 0 5P126Original Sheet No. 337
TF04
TF05A.W.Clark, Vice President
TF06052394****** 070194
TF09E2 0 0 -1 0N052494061694GT94-46-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
28. CAPACITY RELEASE PROGRAM (Continued)
28.4 Notice by Shipper Electing to Release Capacity (Continued)
(i) whether the Releasing Shipper desires to release capacity on the
basis of a volumetric reservation charge and, if so, whether bids
shall be stated in dollars or as a percentage of El Paso's maximum
reservation charge(s) and reservation surcharge(s) in accordance
with Section 28.16 below;
(j) whether Option 1, Option 2, Option 3 or Option 4 of Section 28.10
shall be used to determine the highest bidder and, if Option 3 is
selected, the criteria by which bids are to be evaluated; whatever
evaluation option the Releasing Shipper chooses, it may establish
and post objective, non-discriminatory minimum conditions for an
acceptable bid, subject to the provisions of Section 28.4(q) set
forth below;
(k) the weight for each factor if bids will be evaluated using the
Option 1 weighted composite bid method;
(l) the method by which ties will be broken;
(m) whether the Releasing Shipper wants El Paso to market its released
capacity in accordance with Section 28.17;
(n) the duration of the open season and of the matching period if
longer than the minimums specified in Section 28.8 below;
(o) the date and time the notice is posted on the electronic bulletin
board;
(p) whether the Releasing Shipper is willing to accept contingent bids
that extend beyond the open season and, if so, any non-
discriminatory terms and conditions applicable to such
contingencies including the date by which such contingency must be
satisfied (which date shall be no later than two (2) business days
prior to the first day the Acquired Capacity Agreement is to be
effective) and whether, or for what time period, the next highest
bidder will be obligated to acquire the capacity should the
winning contingent bidder be unable to satisfy the contingency
specified in its bid; and
<PAGE>
TF01005708071495El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03338 2 0 5P126Second Revised Sheet No. 338
TF04 First Revised Sheet No. 338
TF05Patricia A.Shelton, Vice President
TF06071395****** 071095
TF09E2 0 0 -1 0N071495080295RP95-388-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
28. CAPACITY RELEASE PROGRAM (Continued)
28.4 Notice by Shipper Electing to Release Capacity (Continued)
(q) whether the Releasing Shipper's notice will state minimum
conditions or that such Shipper has revealed such minimums to El
Paso which conditions shall not be revealed during the open
season; and
(r) any other applicable conditions.
A Releasing Shipper including any Shipper with a pre-arranged release
that is subject to an open season, may withdraw such notice regardless
of whether a valid bid has been received, at any time prior to the
close of the open season set forth in Section 28.8 if such withdrawal
is due to an unanticipated need for the capacity; provided, however,
that once the notice is withdrawn, both the offer to release and any
bids received during the open season shall remain posted on the
electronic bulletin board for a period of thirty (30) days for
monitoring and control purposes.
28.5 Notice of Pre-Arranged Release - The Releasing Shipper shall deliver a
notice via El Paso's electronic bulletin board of a pre-arranged
release. The notice shall set forth all of the information on the
terms of the release called for in Section 28.4 above and all of the
information called for in Section 28.9 below required to define the
pre-arranged bid. In addition, it shall specify if the pre-arranged
bid is for the maximum applicable reservation rate, whether the
Releasing Shipper is seeking bids to compete with the non-rate
provisions of the pre-arranged bid. The Releasing Shipper shall also
designate if it is seeking bids when the release of capacity is for
thirty-one (31) days or less.
28.6 Term of Released Capacity - The term of any release of firm capacity
shall not exceed the term of the Transportation Service Agreement or
Acquired Capacity Agreement under which releasing occurs, nor shall it
be less than one (1) full gas flow day.
28.7 Availability of Released Capacity - Released capacity shall be made
available on a nondiscriminatory basis and shall be assigned on the
basis of an open season or pre-arrangement in accordance with the
procedures described in Sections 28.8 and 28.10 below.
<PAGE>
TF01005708071495El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03339 2 0 5P126Second Revised Sheet No. 339
TF04 First Revised Sheet No. 339
TF05Patricia A.Shelton, Vice President
TF06071395****** 071095
TF09E2 0 0 -1 0N071495080295RP95-388-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
28. CAPACITY RELEASE PROGRAM (Continued)
28.8 Open Season and Matching Period - The minimum term of any open season
to be held as a consequence of the posting by a Releasing Shipper of
its election to release capacity in accordance with Sections 28.4 or
28.5 hereof shall be as specified below, except that: (1) no open
season shall be required for a pre-arranged release that is for the
maximum reservation charge(s) and reservation surcharge(s) applicable
to the rate schedule pursuant to which capacity is released under this
Volume No. 1-A Tariff as in effect from time to time; and (2) no open
season shall be required for a pre-arranged release with a duration of
thirty-one (31) days or less regardless of the rate bid.
(a) Capacity released under a pre-arrangement, for a period of thirty-
one (31) days or less may not be rolled over or extended unless an
offer to release is posted on El Paso's electronic bulletin board,
prior to the effective date of the rollover or extension, treating
the extension or rollover as a pre-arranged release and initiating
the appropriate open season. A Releasing Shipper may not re-
release capacity subject to this paragraph (a) to the same
Acquiring Shipper until twenty-eight (28) days after the first
release period has ended unless such Acquiring Shipper offers to
pay the maximum reservation charge(s) and reservation surcharge(s)
and such bid meets all the terms and conditions of the subsequent
release or such Acquiring Shipper is the highest bidder for the
capacity during the open season.
(b) For capacity to be released for a term of thirty-one (31) days or
less and which is being offered subject to the Option 4 bid
evaluation procedure specified in Section 28.10 below, an open
season of at least one (1) business day shall be held commencing
at least two (2) business days prior to the effective day of the
release. If the bids are to be evaluated in accord with Options 1
or 2, the open season must commence at least two (2) business days
prior to the effective date of the release. If the capacity to be
released is subject to a pre-arranged bid, the open season must
commence at least three (3) business days prior to the effective
date of the release to allow for a minimum of one (1) business day
for the Pre-Arranged Shipper to match any bids received during the
open season. If the bids are to be
<PAGE>
TF01005708071495El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03340 2 0 5P126Second Revised Sheet No. 340
TF04 First Revised Sheet No. 340
TF05Patricia A.Shelton, Vice President
TF06071395****** 071095
TF09E2 0 0 -1 0N071495080295RP95-388-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
28. CAPACITY RELEASE PROGRAM (Continued)
28.8 Open Season and Matching Period (Continued)
evaluated pursuant to Option 3, the open season shall commence at
least three (3) business days prior to the effective date of the
release to allow for a minimum of one (1) business day for bid
evaluation.
(c) For capacity to be released for a term of more than thirty-one
(31) days but not more than three (3) calendar months, an open
season of at least five (5) business days shall be held commencing
at least nine (9) business days prior to the effective date of the
release. If the capacity to be released is subject to a pre-
arranged bid, the open season must commence at least twelve (12)
business days prior to the effective date of the release to allow
for a minimum of three (3) business days for the Pre-Arranged
Shipper to match any bids received during the open season.
(d) For capacity to be released for a term of more than three (3)
calendar months but not more than one (1) year, an open season of at
least ten (10) business days shall be held commencing at least
fourteen (14) business days prior to the effective date of the
release. If the capacity to be released is subject to a pre-arranged
bid, the open season must commence at least nineteen (19) business
days prior to the effective date of the release to allow for a
minimum of five (5) business days for the Pre-Arranged Shipper to
match any bids received during the open season.
(e) For capacity to be released for a term of more than one (1) year, an
open season of at least twenty (20) business days shall be held
commencing at least twenty four (24) business days prior to the
effective date of the release. If the capacity to be released is
subject to a pre-arranged bid, the open season must commence at
least thirty four (34) business days prior to the effective date of
the release to allow for a minimum of ten (10) business days for the
Pre-Arranged Shipper to match any bids received during the open
season.
<PAGE>
TF01005708052494El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03341 0 0 5P126Original Sheet No. 341
TF04
TF05A.W.Clark, Vice President
TF06052394****** 070194
TF09E2 0 0 -1 0N052494061694GT94-46-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
28. CAPACITY RELEASE PROGRAM (Continued)
28.8 Open Season and Matching Period (Continued)
(f) With respect to any pre-arranged release which is not subject to
an open season, the Releasing Shipper shall post notice not later
than forty-eight (48) hours after the transaction commences.
(g) If any Releasing Shipper agrees to accept a contingent bid
pursuant to Section 28.4(p) the beginning of the open season as
set forth in Sections 28.8(a), (b), (c), (d) and (e) above shall
start earlier by the number of business days so stated by the
Releasing Shipper.
28.9 Bids for Released Capacity - A bid may be submitted to El Paso by a
Bidding Shipper at any time during the open season via El Paso's
electronic bulletin board.
(a) Each bid for released capacity must include the following:
(i) Bidding Shipper's legal name, address, and the name and
title of the individual responsible for authorizing the bid;
(ii) the term of the proposed acquisition;
(iii) maximum reservation charge(s) and reservation
surcharge(s) Bidding Shipper is willing to pay for the
capacity;
(iv) the volume desired and any minimum acceptable volume;
(v) whether or not the Bidding Shipper is an affiliate of the
Releasing Shipper;
(vi) whether the bid is a contingent bid and the contingency
which must be satisfied before the date specified by the
Releasing Shipper pursuant to Section 28.4(p) above; and
(vii) all other information requested by the Releasing Shipper.
<PAGE>
TF01005708052494El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03342 0 0 5P126Original Sheet No. 342
TF04
TF05A.W.Clark, Vice President
TF06052394****** 070194
TF09E2 0 0 -1 0N052494061694GT94-46-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
28. CAPACITY RELEASE PROGRAM (Continued)
28.9 Bids for Released Capacity (Continued)
(b) Any bid received by El Paso during the open season shall be posted
on El Paso's electronic bulletin board (excluding Bidding
Shipper's name). The posting shall indicate if the bid is a
contingent bid. Any bid may be withdrawn by such Shipper at any
time prior to the close of the open season. However, once a bid is
withdrawn, such Shipper may not resubmit a bid at a lower rate but
may resubmit a bid at a higher rate. A Bidding Shipper may not
simultaneously submit multiple bids for the same package of
capacity and may not have more than one bid posted at a given time
for such package of capacity.
(c) A Bidding Shipper may not bid a reservation charge(s) less than
the minimum reservation charge(s) nor more than the sum of the
maximum reservation charge(s) and reservation surcharge(s)
specified by this Volume No. 1-A Tariff, nor may the volume or the
term of the release of such bid exceed the maximum volume or term
specified by the Releasing Shipper.
(d) Any capacity acquired on a volumetric reservation charge basis may
not be re-released.
28.10 Awarding of Released Capacity - Released capacity shall be awarded
in accordance with this Section 28.10.
(a) If Bidding Shipper submits a bid to acquire the released capacity
at the maximum reservation charge(s) and reservation surcharge(s)
and upon all the terms and conditions specified in the Releasing
Shipper's notice, then the capacity shall be awarded to such
Bidding Shipper, and the Releasing Shipper shall not be entitled
to reject such bid. Provided, however, if such bid was submitted
as a bid in an open season relating to a pre-arranged release and
the Pre-Arranged Shipper matches such offer, then the capacity
shall be awarded pursuant to Section 28.10(g) hereof. If more than
one such bid is received then the capacity shall be awarded in
accordance with Section 28.10(f) hereof. The Releasing Shipper
shall not be entitled to reject any bid so selected.
<PAGE>
TF01005708052494El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03343 0 0 5P126Original Sheet No. 343
TF04
TF05A.W.Clark, Vice President
TF06052394****** 070194
TF09E2 0 0 -1 0N052494061694GT94-46-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
28. CAPACITY RELEASE PROGRAM (Continued)
28.10 Awarding of Released Capacity (Continued)
(b) If a bid is received that exceeds the minimum but does not conform
completely to the reservation charge(s) and reservation
surcharge(s) and all the terms and conditions specified in the
Releasing Shipper's notice, then the Acquiring Shipper(s) shall be
the Bidding Shipper(s) who offer(s) the highest bid determined
under Option 1, Option 2, Option 3 or Option 4 below, as
applicable. Provided, however, if such bid was submitted as a bid
in an open season relating to a pre-arranged release and the Pre-
Arranged Shipper matches such offer, then the capacity shall be
awarded pursuant to Section 28.10(g) hereof. If bids from two or
more Bidding Shippers result in bids of equal rank then the
capacity shall be awarded in accordance with Section 28.10(f)
hereof. El Paso shall evaluate and rank all bids submitted during
the open season. If Bidding Shipper has not removed its
contingency by the date specified by the Releasing Shipper
pursuant to Section 28.4(p) hereof, such bid shall be deemed to
have been withdrawn.
(i) Default Bid Evaluation Criteria - If Releasing Shipper does
not specify otherwise, all bids will be evaluated pursuant to
Option 1 with equal weighting factors on all three criteria.
<PAGE>
TF01005708112495El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03344 1 0 5P126First Revised Sheet No. 344
TF04 Original Sheet No. 344
TF05Patricia A.Shelton, Vice President
TF06112295092895RM95-3-000 122495
TF09E4 0 0 -1 0N112495122295RP96-49-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
28. CAPACITY RELEASE PROGRAM (Continued)
28.10 Awarding of Released Capacity (Continued)
(ii) OPTION 1 - Weighted Composite Bid Calculation
Bidding
Releasing Releasing Bidding Shipper's
Shipper's Shipper's Shipper's Actual Bid
Assigned Bid Maximum Bid Actual Bid Weighting
Weighting (%) Values Values (%)
(a) (b) (c) (d) *
(1) Volume in Mcf
(2) Term Stated in
Months
(3) Reservation
Charge(s) and
Reservation
Surcharge(s)
Actual Weighted ______
Composite Bid _____%
* d = c/b x a
(iii) OPTION 2 - Net Present Value Calculation
-n
R x 1 - (1 + i) x V = present value
_____________
i
where: i = interest rate per month using the current
Commission interest rate as defined in 18 C.F.R.
Section 154.501(d)(1)
n = term of the agreement, in months
R = the Reservation Charge(s) and Reservation
Surcharge(s) bid
V = volume stated in Mcf
<PAGE>
TF01005708071495El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03345 2 0 5P126Second Revised Sheet No. 345
TF04 First Revised Sheet No. 345
TF05Patricia A.Shelton, Vice President
TF06071395****** 071095
TF09E2 0 0 -1 0N071495080295RP95-388-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
28. CAPACITY RELEASE PROGRAM (Continued)
28.10 Awarding of Released Capacity (Continued)
(iv) OPTION 3 - Releasing Shipper's Criteria
Releasing Shipper shall specify how bids are to be
evaluated to determine which is the best offer and
must include all criteria necessary to enable El Paso
to evaluate any contingent or non-contingent bids. The
criteria must be objectively stated, applicable to all
potential bidders and non-discriminatory. Such
criteria shall also include provisions describing how
capacity shall be allocated in the event two or more
bids are ranked equally.
(v) OPTION 4 - First-Come/First-Served
Capacity shall be awarded on a first-come/first-served
basis as bids are received, up to maximum capacity
specified in the notice of release, to the Acquiring
Shipper(s) who submits a bid meeting the minimum terms
and conditions of the release. Option 4 shall only
apply to capacity to be released for a term of thirty-
one (31) days or less which is not subject to a pre-
arranged release or a contingency.
(c) If Option 1 is selected by the Releasing Shipper, then such
Shipper shall specify, among the criteria listed above, those
criteria which are to be applicable in determining the highest
weighted composite bid and shall assign a relative weighting to
each such factor. At the end of the open season, El Paso shall,
for each bid received, calculate an actual weighted composite bid
by dividing the actual bid component by Releasing Shipper's
maximum bid component and multiplying the result by the Releasing
Shipper's assigned bid weighting. The results of this calculation
shall determine each bid component's actual weight. Once all bid
components are calculated, an actual composite weighting will be
determined for each bid by summing the bid weightings for each
component. The bids will then be ranked in order from the highest
to the lowest actual weighted composite score.
<PAGE>
TF01005708052494El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03346 0 0 5P126Original Sheet No. 346
TF04
TF05A.W.Clark, Vice President
TF06052394****** 070194
TF09E2 0 0 -1 0N052494061694GT94-46-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
28. CAPACITY RELEASE PROGRAM (Continued)
28.10 Awarding of Released Capacity (Continued)
(d) If Option 2 is selected by the Releasing Shipper, then, at the end
of the open season, El Paso shall calculate a Net Present Value
for each bid received, with the bids being ranked in order from
the highest to the lowest Net Present Value.
(e) If no bids are received which meet or exceed all of the minimum
conditions specified by the Releasing Shipper, no capacity shall
be awarded. If any bids are received which meet or exceed the
Releasing Shipper's minimum criteria, El Paso shall rank all such
bids in accordance with the criteria specified in the notice of
release and shall award the capacity to the successful Bidding
Shipper(s). Any Bidding Shipper who would receive less than the
minimum acceptable bid volume shall not be obligated to accept
released capacity.
(f) If bids from two or more Bidding Shippers result in bids of equal
score, the Acquiring Shipper(s) shall be determined based upon the
tie breaking method designated by the Releasing Shipper, and if
none is specified, by a lottery. The lottery shall be conducted by
El Paso on a non-discriminatory basis. Capacity shall be awarded
in accordance with the order of draw, with capacity awarded to the
first-drawn Bidding Shipper up to the volume bid by such Shipper,
and, if any released capacity remains after such award, it shall
be offered to other Bidding Shippers in the lottery in accordance
with the order of draw. Any Bidding Shipper who, by virtue of its
place in the order of draw, receives less than the minimum
acceptable bid volume shall not be obligated to accept released
capacity. The results of the lottery shall be posted on El Paso's
electronic bulletin board.
(g) If a pre-arranged release is for the maximum reservation charge(s)
and reservation surcharge(s) under this Volume No. 1-A Tariff, as
in effect from time to time, and meets all other terms and
conditions imposed by the Releasing Shipper, then the Pre-Arranged
Shipper shall become the Acquiring Shipper. Service to such
Acquiring Shipper may begin on the next scheduling day after award
of the capacity and
<PAGE>
TF01005708052494El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03347 0 0 5P126Original Sheet No. 347
TF04
TF05A.W.Clark, Vice President
TF06052394****** 070194
TF09E2 0 0 -1 0N052494061694GT94-46-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
28. CAPACITY RELEASE PROGRAM (Continued)
28.10 Awarding of Released Capacity (Continued)
execution of the Acquired Capacity Agreement described in Section
28.11 hereof if that is the effective date specified by the
Releasing Shipper. If a pre-arranged release is for less than the
maximum reservation charge(s) and reservation surcharge(s) or does
not meet all other terms and conditions required by the Releasing
Shipper, an open season is required pursuant to Section 28.8. If a
better offer is received during the open season, as determined
under Option 1, Option 2 or Option 3, the Pre-Arranged Shipper
shall have the time specified in Section 28.8 hereof to match that
offer and if the offer is matched, the Pre-Arranged Shipper shall
become the Acquiring Shipper. If the Pre-Arranged Shipper fails to
match the better offer, then the Bidding Shipper who presented the
better offer shall become the Acquiring Shipper.
(h) A Releasing Shipper shall retain all of the capacity under the
executed Transportation Service Agreement or Acquired Capacity
Agreement that is not acquired by an Acquiring Shipper as the
result of an open season or a pre-arranged release.
28.11 Execution of Agreements or Amendments
(a) Upon the award of capacity, the Acquiring Shipper obtaining
released capacity shall execute electronically an Acquired
Capacity Agreement with El Paso in the form set forth in Section
28.25 below; provided, however, such Shipper shall also return to
El Paso an executed hard copy of the Acquired Capacity Agreement
within five (5) business days of such award of capacity. Service
to be performed under the Acquired Capacity Agreement is subject
to discontinuance if the executed contract is not provided to El
Paso within such time period. Once an Acquired Capacity Agreement
has been executed, the terms of such Agreement are not subject to
amendment, except as provided in Section 28.8(a).
<PAGE>
TF01005708112495El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03348 1 0 5P126First Revised Sheet No. 348
TF04 Original Sheet No. 348
TF05Patricia A.Shelton, Vice President
TF06112295092895RM95-3-000 122495
TF09E4 0 0 -1 0N112495122295RP96-49-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
28. CAPACITY RELEASE PROGRAM (Continued)
28.11 Execution of Agreements or Amendments (Continued)
(b) Where capacity has been released for the entire remaining term of
the Releasing Shipper's Transportation Service Agreement, the
Releasing Shipper may request El Paso to amend its Transportation
Service Agreement to reflect the release of capacity. Absent
agreement by El Paso to such amendment, which may be conditioned
on exit fees or other terms and conditions, the Releasing Shipper
shall remain bound by and liable for payment of the reservation
charge(s) and reservation surcharge(s) under the Transportation
Service Agreement.
To the extent that capacity is released for the remaining term of
the Releasing Shipper's Transportation Service Agreement and the
Acquiring Shipper has agreed to pay the maximum reservation
charge(s) and reservation surcharge(s) for such capacity,
Releasing Shipper's contract shall be amended so as to relieve
such shipper of any further liability for payment of the
reservation charge(s) and reservation surcharge(s) applicable to
the capacity released under the Transportation Service Agreement.
In the event the Releasing Shipper's Transportation Service
Agreement is amended to reflect the release of capacity, El Paso
shall enter into a Transportation Service Agreement with the
Acquiring Shipper in the form prescribed for service under Rate
Schedule FT-1 but containing the rates and terms and conditions
established for the acquired capacity pursuant to this Section 28.
28.12 Notice of Completed Transactions - Within five (5) business days after
capacity has been awarded pursuant to Section 28.10, El Paso shall
post the information identified below regarding each transaction on
its electronic bulletin board for a period of five (5) business days.
(a) term;
(b) reservation charge(s) and reservation surcharge(s) as bid;
(c) delivery points;
<PAGE>
TF01005708052494El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03349 0 0 5P126Original Sheet No. 349
TF04
TF05A.W.Clark, Vice President
TF06052394****** 070194
TF09E2 0 0 -1 0N052494061694GT94-46-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
28. CAPACITY RELEASE PROGRAM (Continued)
28.12 Notice of Completed Transactions (Continued)
(d) volume in Mcf;
(e) whether the capacity is firm or firm recallable;
(f) all conditions, including any minimums, concerning the release;
(g) the names of the Releasing Shipper and the Acquiring Shipper; and
(h) whether or not the Acquiring Shipper is an affiliate of the
Releasing Shipper or El Paso.
28.13 Effective Date of Release and Acquisition - The effective date of the
release by a Releasing Shipper and acquisition by an Acquiring Shipper
shall be on the date so designated in the Acquired Capacity Agreement
or Transportation Service Agreement referenced in Section 28.11 above.
28.14 Notice by El Paso of Uncommitted Firm Capacity - In the event El Paso
determines that it has any uncommitted firm capacity on its system, El
Paso shall post on its electronic bulletin board a notice of the
availability of such capacity, setting forth the same information as
prescribed in Section 28.4 or Section 28.5, as applicable. The
capacity shall be awarded using the procedures specified by Sections
28.8 and 28.10. Any pre-arranged transaction for uncommitted or
expansion firm capacity shall be subject to the posting and bidding
procedures of this Section 28 regardless of the term or rate. Tied
bids will be resolved by the tie-breaking method specified in Section
28.10(f) with no preference given to any Shipper involved in a pre-
arranged transaction. El Paso shall not be obligated to accept any bid
for uncommitted capacity that is for less than the maximum reservation
charge(s) and reservation surcharge(s) specified in this Volume No. 1-
A Tariff as in effect from time to time.
28.15 Notice of Offer to Purchase Capacity - In the event a party desires to
purchase capacity on El Paso's system, it may post a notice of offer
to purchase capacity on El Paso's electronic bulletin board or, if
such party is not currently authorized to access the electronic
bulletin board and elects to provide El Paso
<PAGE>
TF01005708052494El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03350 0 0 5P126Original Sheet No. 350
TF04
TF05A.W.Clark, Vice President
TF06052394****** 070194
TF09E2 0 0 -1 0N052494061694GT94-46-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
28. CAPACITY RELEASE PROGRAM (Continued)
28.15 Notice of Offer to Purchase Capacity (Continued)
with the information in some other form, El Paso shall post such offer
on its electronic bulletin board within twenty-four (24) hours of
receipt of such offer. The offering party may furnish all data for
posting which it deems appropriate but at a minimum such data shall
include the following:
(i) offering party's legal name, address, and person to contact
for additional information;
(ii) the term of the proposed purchase;
(iii) the maximum reservation charge(s) and reservation
surcharge(s) the party is willing to pay for the capacity;
(iv) the volume desired; and
(v) the delivery points.
28.16 Rates - The reservation charge(s) and reservation surcharge(s) for any
released firm capacity shall be the reservation charge(s) and
reservation surcharge(s) bid by the Acquiring Shipper, but in no event
shall such reservation charge(s) and reservation surcharge(s) be less
than El Paso's minimum or more than El Paso's maximum reservation
charge(s) and reservation surcharge(s) under the applicable rate
schedule as in effect from time to time. In addition, Acquiring
Shipper shall pay the maximum usage charge as well as all other
applicable charges and surcharge(s) for the service rendered unless
discounted by El Paso. For a volumetric reservation charge, the sum of
the reservation charge(s) and reservation surcharge(s) shall be
converted to a daily rate by dividing by the number of days in the
month.
28.17 Marketing Fee - When a Releasing Shipper requests that El Paso
actively market the capacity to be released, the Releasing Shipper and
El Paso shall negotiate the terms of the marketing service to be
provided by El Paso and the marketing fee to be charged therefor.
28.18 Billing - El Paso shall bill the Acquiring Shipper the rate(s)
specified in the Acquired Capacity Agreement or the Transportation
<PAGE>
TF01005708052494El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03351 0 0 5P126Original Sheet No. 351
TF04
TF05A.W.Clark, Vice President
TF06052394****** 070194
TF09E2 0 0 -1 0N052494061694GT94-46-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
28. CAPACITY RELEASE PROGRAM (Continued)
28.18 Billing (Continued)
Service Agreement and any other applicable charges and such Acquiring
Shipper shall pay the billed amounts directly to El Paso. Further, the
Acquiring Shipper who has acquired capacity on a volumetric
reservation rate basis shall be billed the daily reservation rate(s)
plus the usage rate(s) and all applicable surcharges times the volumes
actually transported. Releasing Shipper shall be billed the
reservation charge(s) and reservation surcharge(s) associated with the
released capacity pursuant to its contract, with a concurrent
conditional credit for payment of the reservation charge(s) and
reservation surcharge(s) due from the Acquiring Shipper. This bill
shall include an itemization of credits and adjustments associated
with each Acquired Capacity Agreement. Releasing Shipper shall also be
billed a marketing fee, if applicable, pursuant to the provisions of
Section 28.17. An Acquiring Shipper who re-releases acquired capacity
shall pay to El Paso a marketing fee, if applicable. If an Acquiring
Shipper does not make payment to El Paso of the reservation charge(s)
and reservation surcharge(s) due as set forth in Section 6 of this
Volume No. 1-A Tariff, El Paso shall notify the Releasing Shipper of
the amount due, including all applicable late charges authorized by
Section 6.4 of this Tariff, and such amount shall be paid by the
Releasing Shipper. In addition, Releasing Shipper may terminate the
release of capacity to an Acquiring Shipper if such Shipper fails to
pay all of the amount of any bill for gas delivered under the executed
Acquired Capacity Agreement when such amount is due, in accordance
with said Section 6.4. Once terminated, capacity and all applicable
charges shall revert to the Releasing Shipper. Notwithstanding the
provisions of Section 6.4, all payments received from an Acquiring
Shipper shall first be applied to the reservation charge(s) due for
transportation service and then to any reservation surcharges(s),
including late charges related solely to such reservation charge(s),
then to any penalty due, then to usage charges, and last to late
charges not related to any reservation charge(s) due.
28.19 Nominations and Scheduling - An Acquiring Shipper shall nominate and
schedule natural gas for transportation service hereunder directly
with El Paso in accordance with the applicable procedures set forth in
this Volume No. 1-A Tariff. Releasing Shipper shall give El Paso and
the Acquiring Shipper(s) notice of any recall no
<PAGE>
TF01005708052494El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03352 0 0 5P126Original Sheet No. 352
TF04
TF05A.W.Clark, Vice President
TF06052394****** 070194
TF09E2 0 0 -1 0N052494061694GT94-46-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
28. CAPACITY RELEASE PROGRAM (Continued)
28.19 Nominations and Scheduling (Continued)
later than the close of Day 1 scheduling for the day on which the
recall is to take effect. Releasing Shipper, when returning recalled
capacity to the Acquiring Shipper(s), shall give El Paso and such
Acquiring Shipper(s) notice prior to the close of Day 1 scheduling for
the day on which the capacity is to revert to the Acquiring
Shipper(s).
28.20 Qualification for Participation in the Capacity Release Program -Any
Shipper wishing to become a Bidding Shipper, or a potential Pre-
Arranged Shipper, must satisfy the creditworthiness requirements of El
Paso's transportation tariff by pre-qualifying prior to submitting a
bid for capacity or prior to becoming a party to a pre-arranged
release. Once a Shipper becomes an Acquiring Shipper, such Shipper can
be subject to an annual credit review with respect to its eligibility
to make additional bids on other offers of released capacity. A
Shipper cannot bid for services which exceed its qualified level of
creditworthiness. Notwithstanding such qualification to participate in
the open season, El Paso does not guarantee the payment of any
outstanding amounts by an Acquiring Shipper.
28.21 Compliance by Acquiring Shipper - By acquiring released capacity, an
Acquiring Shipper agrees that it will comply with the terms and
conditions of El Paso's certificate of public convenience and
necessity authorizing this Capacity Release Program and all applicable
Commission orders and regulations, including Part 284 thereof. Such
Acquiring Shipper also agrees to be responsible to El Paso for
compliance with all terms and conditions of El Paso's Volume No. 1-A
Tariff, as well as the terms and conditions of the Acquired Capacity
Agreement. End user lists shall not be required.
28.22 Obligations of Releasing Shipper - The Releasing Shipper shall
continue to be liable and responsible for all reservation charge(s)
and reservation surcharge(s) associated with the released capacity up
to the maximum reservation charge(s) and reservation surcharge(s)
specified in such Releasing Shipper's Transportation Service Agreement
or Acquired Capacity Agreement. Re-releases by an Acquiring Shipper
shall not relieve the original or any subsequent Releasing Shipper of
its obligations under this section.
<PAGE>
TF01005708052494El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03353 0 0 5P126Original Sheet No. 353
TF04
TF05A.W.Clark, Vice President
TF06052394****** 070194
TF09E2 0 0 -1 0N052494061694GT94-46-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
28. CAPACITY RELEASE PROGRAM (Continued)
28.23 Flexible Receipt and Delivery Point(s) - Shipper(s) using Acquired
Capacity Agreements may utilize alternate receipt and delivery
point(s) pursuant to the conditions contained in Section 20.13 of this
Volume No. 1-A Tariff which is incorporated herein.
28.24 Refunds - In the event that the Commission orders refunds of any rates
charged by El Paso, El Paso shall flow-through refunds to any
Acquiring Shipper to the extent that such Shipper has paid a rate in
excess of El Paso's just and reasonable, applicable maximum rates.
28.25 Acquired Capacity Agreement -
Acquired Capacity Agreement
Between
El Paso Natural Gas Company
and
___________________________
THIS AGREEMENT is made and entered into as of this _______ day of
_______, by and between EL PASO NATURAL GAS COMPANY, a Delaware corporation,
hereinafter referred to as "El Paso," and _______________________________, a
_______________ corporation, hereinafter referred to as "Acquiring Shipper."
WHEREAS, El Paso and _________________, hereinafter referred to as
"Releasing Shipper," are parties to a ______________________ Agreement under
Rate Schedule ____ contained in El Paso's FERC Gas Tariff, First Revised
Volume No. 1-A, dated _____________ (contract code ________);
WHEREAS, Acquiring Shipper desires to acquire all or a portion of
the firm capacity rights to be released from said ______________ Agreement.
NOW THEREFORE, in consideration of the promises and premises
hereinafter set forth, El Paso and Acquiring Shipper agree as follows:
<PAGE>
TF01005708052494El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03354 0 0 5P126Original Sheet No. 354
TF04
TF05A.W.Clark, Vice President
TF06052394****** 070194
TF09E2 0 0 -1 0N052494061694GT94-46-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
28. CAPACITY RELEASE PROGRAM (Continued)
28.25 Acquired Capacity Agreement (Continued)
1. Acquiring Shipper agrees to comply with the terms and conditions
of El Paso's certificate of public convenience and necessity
issued by the Commission authorizing El Paso's Capacity Release
Program and with Section 28 of the General Terms and Conditions
contained in El Paso's Volume No. 1-A Tariff. In addition,
Acquiring Shipper agrees to comply with all other terms and
conditions of said Volume No. 1-A Tariff as well as the terms and
conditions set forth herein.
2. The following capacity rights, which are released through the
Capacity Release Program, are acquired at the Receipt Point(s) and
Delivery Point(s) designated below:
Receipt Point(s): Those Receipt Point(s) set forth in the
_____________ Agreement.
Delivery Point(s):
The Delivery Point(s) as specified in the Notice posted pursuant
to Sections 28.4 or 28.5 of El Paso's Volume No. 1-A Tariff. If
the Releasing Shipper does not limit the Acquiring Shipper's
rights to the primary Delivery Point(s) specified in the Notice,
then the Acquiring Shipper may designate any primary Delivery
Point(s) within the same zone as the Releasing Shipper's primary
Delivery Point(s), or within any upstream zone through which the
released capacity passes, to the extent that capacity is available
at such point(s).
Contract Volume _______ Mcf (for billing the reservation charge(s)
and reservation surcharge(s), this volume shall be converted to
dekatherms)
3. Capacity acquired hereunder is released through the Capacity
Release Program on a (firm or firm recallable) basis.
The Acquiring Shipper acknowledges notice of and agrees to be
bound by the terms of the Notice posted pursuant to Sections 28.4
or 28.5 of El Paso's Volume No. 1-A Tariff, as regards to the
terms on which this capacity can be recalled by the Releasing
Shipper. Releasing Shipper is responsible for exercising such
recall, in accordance with the
<PAGE>
TF01005708052494El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03355 0 0 5P126Original Sheet No. 355
TF04
TF05A.W.Clark, Vice President
TF06052394****** 070194
TF09E2 0 0 -1 0N052494061694GT94-46-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
28. CAPACITY RELEASE PROGRAM (Continued)
28.25 Acquired Capacity Agreement (Continued)
provisions of Section 28.19 of El Paso's Volume No. 1-A Tariff.
(The foregoing paragraph shall be applicable to Acquiring Shipper(s)
who acquire firm recallable capacity.)
4. For capacity acquired hereunder, Acquiring Shipper shall pay
El Paso each month the charges set forth below:_____________
_________________________________________________________________.
5. This Agreement shall become effective on ____________ and continue
in full force and effect through ___________ unless terminated
pursuant to Section 28.18 of El Paso's Volume No. 1-A Tariff.
6. Other terms:
As specified in the Notice posted pursuant to Sections 28.4 or
28.5 of El Paso's Volume No. 1-A Tariff.
7. Any formal notice, request or demand that either party gives to
the other respecting this Agreement, shall be in writing and shall
be mailed by registered or certified mail or delivered by hand to
the following address of the other party:
El Paso: El Paso Natural Gas Company
Post Office Box 1492
El Paso, Texas 79978
Attention: Director, Mainline Transportation
and Customer Services Department
Acquiring Shipper:
Notices regarding recall rights shall also be delivered by
telephone, facsimile, or El Paso's electronic system.
8. Acquiring Shipper hereby certifies that it has title or the right
to ship the gas delivered to El Paso for transportation and has
entered into or will enter into arrangements necessary to assure
all upstream and downstream transportation will be in place prior
to commencement of service.
<PAGE>
TF01005708052494El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03356 0 0 5P126Original Sheet No. 356
TF04
TF05A.W.Clark, Vice President
TF06052394****** 070194
TF09E2 0 0 -1 0N052494061694GT94-46-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
28. CAPACITY RELEASE PROGRAM (Continued)
28.25 Acquired Capacity Agreement (Continued)
IN WITNESS HEREOF, the parties have caused this Agreement to be executed in
two (2) original counterparts, by their duly authorized officers, the day and
year first set forth herein.
ATTEST: EL PASO NATURAL GAS COMPANY
By______________________ By_________________________
(Title) (Title)
ATTEST: ___________________________
(Acquiring Shipper)
By______________________ By_________________________
(Title) (Title)
<PAGE>
TF01005708112995El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03357 2 0 5P126Second Revised Sheet No. 357
TF04 First Revised Sheet No. 357
TF05Patricia A.Shelton, Vice President
TF06112895091395CP94-183-000 and 001010196
TF09E5 0 0 -1 0N112995122995RP96-52-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
29. COMPLIANCE PLAN FOR UNBUNDLED SALES DIVISION
29.1 El Paso will organize its unbundled sales and transportation operating
employees so that they function independently of each other to the
maximum extent practicable.
29.2 El Paso Gas Marketing Company, a separate and independently operated
corporate affiliate, is designated as El Paso's agent for purposes of
conducting El Paso's gas merchant function. Eastex Energy Inc., a
separate and independently operated corporate affiliate, is primarily
engaged in the marketing of natural gas. El Paso, El Paso Gas
Marketing Company and Eastex Energy Inc. will conduct their business
in conformance with the standards of conduct set forth in Section
161.3 and Section 284.286 of the Commission's Regulations and other
applicable requirements of Order No. 497, et. seq., and Order No. 566,
et. seq.
29.3 El Paso will not provide a preference in any pipeline services to a
Shipper because that Shipper also purchases natural gas from El Paso
or from its marketing affiliate, or to a marketing affiliate of El
Paso, over Shippers who purchase natural gas from another merchant.
29.4 El Paso will provide nondiscriminatory access to all sources of supply
in accordance with Part 284 of the Commission's regulations and will
not give shippers of its gathering affiliate undue preference over
shippers of nonaffiliated gatherers or other customers in scheduling,
transportation, storage or curtailment priority.
29.5 El Paso will not condition or tie its agreement to provide
transportation service to an agreement by the producer, customer, end-
user, or shipper relating to any service by any gathering affiliate,
any services by it on behalf of its gathering affiliate, or any
services in which its gathering affiliate is involved.
<PAGE>
TF01005708052494El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03358 0 0 5P126Original Sheet No. 358
TF04
TF05A.W.Clark, Vice President
TF06052394****** 070194
TF09E2 0 0 -1 0N052494061694GT94-46-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
30. ASSIGNMENT OF FIRM CAPACITY ON UPSTREAM PIPELINES
30.1 Purpose - This Section 30 sets forth the terms and conditions under
which El Paso shall assign, in whole or in part, the rights and
obligations under contracts held by El Paso for firm capacity on
upstream jurisdictional pipelines.
30.2 Applicability - This Section 30 shall apply to any firm Shipper who
accepts assignment of any or all of El Paso's firm transportation
capacity rights described in Section 30.1 above.
30.3 Availability of Capacity - El Paso's firm upstream capacity shall be
made available on a nondiscriminatory basis and shall be assigned on
the basis of an open season in accordance with the procedures
described in Section 30.6 below.
30.4 Permanent Assignment - All assignments pursuant to this Section 30
shall be for the entire remaining term of El Paso's contract with such
upstream pipeline.
30.5 Rate - The rate for such assigned capacity shall be as established by
the tariff of such upstream pipeline or as otherwise negotiated
between the Shipper and upstream pipeline. El Paso shall not charge
any fee in connection with the assignment of its capacity on the
upstream pipeline.
30.6 Open Season - Upon the effectiveness of this Section 30, El Paso shall
conduct an open season for a period of fifteen (15) days by posting a
notice of such availability on its electronic bulletin board. In order
for a Shipper to participate in this open season, Shipper shall submit
to El Paso a completed bid in the form set forth in Section 30.9
below.
If Shippers' requests for capacity exceed the available firm capacity
during the open season, such capacity shall be allocated among the
requesting Shippers based on a lottery. After the open season, El Paso
will allocate all requests for available capacity on a first-
come/first-served basis.
30.7 Qualifications for Assignment - Shipper must satisfy any applicable
requirements of the upstream pipeline's tariff, including
creditworthiness.
<PAGE>
TF01005708052494El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03359 0 0 5P126Original Sheet No. 359
TF04
TF05A.W.Clark, Vice President
TF06052394****** 070194
TF09E2 0 0 -1 0N052494061694GT94-46-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
30. ASSIGNMENT OF FIRM CAPACITY ON UPSTREAM PIPELINES (Continued)
30.8 Reporting Requirements - El Paso and any Shipper accepting assignment
of capacity obtained from El Paso pursuant to this Section 30 shall
file with the Commission the following information:
(1) the name, address, and telephone number of the assignee;
(2) the corporate affiliation between the assignor and the assignee,
if any; and
(3) a description of the specific rights assigned, including term,
receipt and delivery points, and volume.
30.9 Bid Form -
1. Company Name _______________________________________________
2. Mailing Address ____________________________________________
3. Name of Company
Contact/Title ______________________________________________
4. Phone & FAX No. Phone _____________FAX______________________
5. Upstream Contract __________________________________________
6. Contract Quantity __________________________________________
7. Receipt Point(s) ___________________________________________
____________________________________________
____________________________________________
Delivery Point(s) __________________________________________
____________________________________________
____________________________________________
8. Requested Begin
Date ____________________________________________
<PAGE>
TF01005708052494El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03360 0 0 5P126Original Sheet No. 360
TF04
TF05A.W.Clark, Vice President
TF06052394****** 070194
TF09E2 0 0 -1 0N052494061694GT94-46-000
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
30. ASSIGNMENT OF FIRM CAPACITY ON UPSTREAM PIPELINES (Continued)
30.9 Bid Form (Continued)
Shipper represents that all information submitted with this bid is correct and
is submitted by its authorized representative. Bids are binding only when a
fully executed Assignment Agreement has been returned to El Paso.
9. Signature __________________________________________________
10. Print Name _________________________________________________
11. Title ______________________________________________________
12. Date _______________________________________________________
<PAGE>
TF01005708112495El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03361 1 0 5P126First Revised Sheet No. 361
TF04 Original Sheet No. 361
TF05Patricia A.Shelton, Vice President
TF06112295092895RM95-3-000 122495
TF09E4 0 0 -1 0N112495122295RP96-49-000
GENERAL TERMS AND CONDITIONS
(Continued)
31. WASHINGTON RANCH FACILITY STRANDED INVESTMENT COST RECOVERY
This Section 31 applies to those Shippers having an executed Transportation
Service Agreement with El Paso for firm forward haul service subject to
either Rate Schedule FT-1 or Rate Schedule FT-2. In addition to other
charges otherwise due under such Rate Schedules, Shipper shall pay the
Reservation Surcharge pursuant to this Section 31.
31.1 Purpose - This Section 31 establishes the procedures which will permit
El Paso to recover from its Shippers one hundred percent (100%) of
stranded investment costs associated with the Washington Ranch
Facility. Such costs shall be allocated to El Paso's Rate Schedule FT-
1 and FT-2 firm forward haul Shippers based on each Shipper's
reservation revenue responsibility, as established in the Settlement
at Docket No. RP92-214-000, et al., for the period termed "Prospective
Period."
31.2 Effectiveness - Commencing with the effective date of El Paso's
Stipulation and Agreement at Docket No. RP92-214-000, et al., El Paso
shall be entitled to bill and collect the Washington Ranch Facility
stranded investment costs. Such costs will accrue interest effective
February 1, 1993 and shall be fully amortized by December 31, 1996.
31.3 Definitions - The definition of terms applicable to this Section 31
are as follows:
(a) Recovery Period - The period beginning on the effective date any
new rates become effective under this Section 31 and ending on the
day prior to the effective date of any succeeding rate change
under this Section. The initial recovery period shall begin upon
the effectiveness of the Settlement at Docket No. RP92-214-000, et
al., and end on the day prior to the effective date of the second
recovery period. The subsequent recovery periods shall be the six
(6) month periods commencing each January 1 and July 1 until all
amounts have been amortized and interest thereon has been
recovered.
(b) Monthly Amortized Amounts - The Monthly Amortized Amounts shall be
allocated to El Paso's firm forward haul Shippers based on each
Shipper's forward haul reservation dollar allocation as
established at Docket No. RP92-214-000, et al., "Prospective
Period." The Monthly Amortized Amounts
<PAGE>
TF01005708122895El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03362 1 0 5P126Substitute First Revised Sheet No. 362
TF04 1st Revised Original Sheet No. 362
TF05Patricia A.Shelton, Vice President
TF06122795****** 010196
TF09P0 0 0 -1 0N122895******RP95-363-003
GENERAL TERMS AND CONDITIONS
(Continued)
31. WASHINGTON RANCH FACILITY STRANDED INVESTMENT COST RECOVERY (Continued)
31.3 Definitions (Continued)
are the total estimated stranded investment costs, less previously
amortized amounts divided by the number of months remaining in the
Amortization Period, plus interest for the applicable Recovery
Period. The Monthly Amortized Amounts shall be in effect until
adjusted in accordance with Section 31.4(b).
(c) Reservation Surcharge - A reservation surcharge rate for each
Shipper shall be determined as set forth in Section 31.4(a) below.
The Reservation Surcharges shall be selectively adjusted by El
Paso; provided, however, that such adjusted Reservation Surcharges
shall not exceed the applicable Maximum Rate nor shall it be less
than the Minimum Rate in effect from time to time.
(d) Billing Determinants - The Billing Determinants underlying the
currently effective rates and identified on Statement of Rates
Sheet Nos. 30, 31, and 32 of this FERC Gas Tariff shall apply to
those firm forward haul Shippers of El Paso for the purposes of
Sections 31.3(e) and 31.4(a). The Billing Determinants at Docket
No. RS92-60-000, et al. (which are used to allocate cost
responsibility to each applicable shipper) are identified in
Section 31.6 below.
(e) Monthly Billed Amount - The monthly amount billed each Shipper as
described in Section 31.4(b) below shall be the Reservation
Surcharge multiplied by the Billing Determinant as reflected on
Statement of Rates Sheet Nos. 30, 31, and 32 of this FERC Gas
Tariff.
(f) Interest Rate - The quarterly interest rate published by the
Commission and computed in accordance with Section 154.501(d)(1)
of the Commission's Regulations.
31.4 Determination of the Reservation Surcharge and Monthly Amortized
Amount - El Paso shall determine the Reservation Surcharge and Monthly
Amortization by the following procedures:
(a) The Reservation Surcharge rate(s) shall be determined utilizing
the Monthly Amortized Amount for each Shipper divided by the
Billing Determinants for such Shipper. The Monthly Billed Amount,
Billing Determinants, and Surcharges for each Shipper are
reflected on the Statement of Rates Sheets contained in this
Volume No. 1-A Tariff.
<PAGE>
TF01005708052494El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03363 0 0 5P126Original Sheet No. 363
TF04
TF05A.W.Clark, Vice President
TF06052394****** 070194
TF09E2 0 0 -1 0N052494061694GT94-46-000
GENERAL TERMS AND CONDITIONS
(Continued)
31. WASHINGTON RANCH FACILITY STRANDED INVESTMENT COST RECOVERY (Continued)
31.4 Determination of the Reservation Surcharge and Monthly Amortized
Amount (Continued)
(b) El Paso shall adjust the Monthly Amortized Amount for interest
calculated on the unrecovered balance of El Paso's stranded
investment costs as set forth below. Interest shall commence to
accrue with respect to El Paso's stranded investment costs
effective February 1, 1993.
(i) Effective with the Settlement at Docket No. RP92-214-000, et
al., El Paso shall include the actual accrued interest from
February 1, 1993 through the effective date and estimated
interest through December 31, 1993 utilizing the actual
Interest Rate (if the actual Interest Rate is unknown the
interest rate shall be estimated), divided by the number of
months remaining in 1993 to derive the interest adjustment
to the Monthly Amortized Amount.
(ii) Effective for the six (6) months commencing January 1, 1994,
El Paso shall reflect any differences resulting from the use
of estimated versus actual accrued interest for the period
February 1, 1993 through December 31, 1993. Any resulting
difference shall be added to or deducted from the estimated
interest for the six (6) month period commencing January 1,
1994. The total interest shall be divided by six (6) to
determine the monthly interest for such Recovery Period.
(iii) At the end of each six (6) month period following June 30,
1994 through the termination of the Amortization Period, El
Paso shall calculate an estimate for the projected interest
expense for the next six (6) month Recovery Period. At the
same time, El Paso shall calculate the actual interest
expense that would have accrued during the previous Recovery
Period. This actual interest amount will be compared to the
previously estimated interest amount for such period and any
resulting difference shall be added to or deducted from the
next six (6)
<PAGE>
TF01005708052494El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03364 0 0 5P126Original Sheet No. 364
TF04
TF05A.W.Clark, Vice President
TF06052394****** 070194
TF09E2 0 0 -1 0N052494061694GT94-46-000
GENERAL TERMS AND CONDITIONS
(Continued)
31. WASHINGTON RANCH FACILITY STRANDED INVESTMENT COST RECOVERY (Continued)
31.4 Determination of the Reservation Surcharge and Monthly Amortized
Amount (Continued)
month interest projection, divided by six (6) months to derive
the interest for the applicable Recovery Period.
(iv) Effective the third month following the end of the Amortization
Period, El Paso shall calculate the actual interest for any
past period of estimated interest utilizing the appropriate
Interest Rate, and shall make a one time adjustment to reflect
the appropriate amount to each Shipper's invoice.
(c) In the event the Transportation Service Agreement of any existing
Shipper terminates during any Recovery Period, the unamortized
portion of the costs inclusive of interest allocated to such
Shipper under this Section 31.4 will be due within thirty (30) days
or such other period as mutually agreed to by El Paso and Shipper,
not to extend beyond the termination of the Amortization Period.
(d) Each Shipper subject to this Section 31 shall have the option of
paying the amount allocated to it in a lump sum or over a shorter
Amortization Period if desired, with an appropriate interest
adjustment.
31.5 True-up of Actual Versus Estimated Loss or Gain Realized from the Sale
of Washington Ranch Gas Inventory - El Paso shall adjust the remaining
unamortized balance to reflect the difference between the actual gain
or loss and the previously estimated gain or loss from the sale of gas
inventory from the Washington Ranch Facility. Such adjustment shall be
reflected in El Paso's earliest semi-annual filing following one
year's effectiveness of this Section 31. Such adjustment shall be
reflected in the balance as of February 1, 1993 for interest accrual
purposes.
<PAGE>
TF01005708122895El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03365 0 0 5P126Substitute Original Sheet No. 365
TF04 Original Sheet No. 365
TF05Patricia A.Shelton, Vice President
TF06122795****** 010196
TF09P0 0 0 -1 0N122895******RP95-363-003
GENERAL TERMS AND CONDITIONS
(Continued)
31. WASHINGTON RANCH FACILITY STRANDED INVESTMENT COST RECOVERY (Continued)
31.6 Docket No. RS92-60-000, et al., Billing Determinants - The Billing
Determinants underlying the rates at Docket No. RS92-60-000, et al.,
"Prospective Period," are displayed below.
RS92-60-000
et al.
Settlement
Billing
Shipper Determinant
(dth)
<TABLE>
<CAPTION>
PRODUCTION AREA
<S> <C>
Denver City, Texas, City of 1,271
Goldsmith, Texas, City of 75
Grandfalls, Texas, City of 75
Ignacio, Colorado, City of 472
Jal Gas Company, Inc. 485
McLean, Texas, City of 436
Morton, Texas, City of 753
North Bailey Gas Farmers' 97
Cooperative Society of
Muleshoe, Texas
Navajo Tribal Utility Authority 9,275
Plains, Texas, City of 397
Rimrock Gas Company 61
Spur, Texas, City of 313
Sterling Natural Gas, Inc. 146
Southern Union Gas Company 4,949
Texola, Town of 12
West Texas Gas, Inc. 1,030
Whiteface, Texas, City of 181
TEXAS
Dumas, Texas, City of 5
El Paso Electric Company 30,751
Natural Gas Processing Company 5,150
Southdown, Inc. 3
Southern Union Gas Company 70,277
</TABLE>
<PAGE>
TF01005708122895El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03366 0 0 5P126Substitute Original Sheet No. 366
TF04 Original Sheet No. 366
TF05Patricia A.Shelton, Vice President
TF06122795****** 010196
TF09P0 0 0 -1 0N122895******RP95-363-003
GENERAL TERMS AND CONDITIONS
(Continued)
31. WASHINGTON RANCH FACILITY STRANDED INVESTMENT COST RECOVERY (Continued)
31.6 Docket No. RS92-60-000, et al., Billing Determinants (Continued)
RS92-60-000
et al.
Settlement
Billing
Shipper Determinant
(dth)
<TABLE>
<CAPTION>
NEW MEXICO
<S> <C>
Corona, New Mexico, Village of 56
Deming, New Mexico, City of 2,513
EMW Gas Association 1,859
Lordsburg, New Mexico, City of 747
Mountainair, New Mexico, Town of 250
Phelps Dodge Corporation 16,962
Socorro, New Mexico, City of 1,688
ARIZONA
Arizona Electric Power Cooperative, 53,217
Inc.
Ajo Improvement Company 227
Apache Nitrogen Products 1,673
Arizona Public Service Company 62,364
Benson, Arizona, City of 933
Black Mountain Gas Company 847
Citizens Utilities Company 59,395
(formerly Southern Union AZ)
Duncan Rural Services Corporation 457
Graham County Utilities, Inc. 1,753
Mesa, Arizona, City of 17,818
Navajo Tribal Utility Authority 2,970
PEMEX Gas y Petroquimica Basica 8,748
Phelps Dodge Corporation 4,455
Safford, Arizona, City of 1,888
Salt River Project Agricultural 57,910
Improvement and Power District
Southwest Gas Corporation 399,698
Willcox, Arizona, City of 895
</TABLE>
<PAGE>
TF01005708122895El Paso Natural Gas Company
TF02 1A 2Second Revised Volume No. 1-A
TF03367 0 0 5P126Substitute Original Sheet No. 367
TF04 Original Sheet No. 367
TF05Patricia A.Shelton, Vice President
TF06122795****** 010196
TF09P0 0 0 -1 0N122895******RP95-363-003
GENERAL TERMS AND CONDITIONS
(Continued)
31. WASHINGTON RANCH FACILITY STRANDED INVESTMENT COST RECOVERY (Continued)
31.6 Docket No. RS92-60-000, et al., Billing Determinants (Continued)
RS92-60-000
et al.
Settlement
Billing
Shipper Determinant
(dth)
<TABLE>
<CAPTION>
NEVADA
<S> <C>
Southwest Gas Corporation 180,000
CALIFORNIA
Los Angeles Department of Water 37,080
and Power
Meridian Oil Marketing Inc. 85,490
Meridian Oil Marketing Inc. 103,000
Mission Energy Fuel Company 7,210
Mobil Natural Gas Inc. 20,600
Saguaro Power Company 20,600
San Diego Gas & Electric Company 10,300
Southern California Edison Company 206,000
Southern California Gas Company 1,493,500
Texaco, Inc. 180,250
</TABLE>
<PAGE>
SETTLEMENT AGREEMENT
This Settlement Agreement (Agreement) is made among the Agricultural
Energy Consumers Association, the California Department of General Services, the
California Farm Bureau Federation, the California Large Energy Consumers
Association, the California Manufacturers Association, the Department of the
Navy on behalf of the Federal Executive Agencies, the Division of Ratepayer
Advocates (DRA) of the California Public Utilities Commission (CPUC), Industrial
Users, Pacific Gas and Electric Company (PG&E), and the Attorney General of the
State of California, collectively referred to as the "Parties." This Agreement,
if approved and adopted by the CPUC, would modify the prices for Diablo Canyon
Nuclear Power Plant (Diablo Canyon) power as provided in Paragraphs 3 and 4 of
Appendix C and Paragraph 4 of Appendix D of Decision 88-12-083. With the
exception of the pricing modifications made herein, Appendices C and D of
Decision 88-12-083 remain in full effect.
1. The Parties agree that the prices for Diablo Canyon power shall be reduced
in the following manner:
a) The fixed price portion of the Diablo Canyon price shall remain at the
current level of 3.15 cents/kwh.
b) The escalating price portion of the Diablo Canyon price shall be no
greater than:
<TABLE>
<CAPTION>
<S> <C>
January 1, 1995 7.85 cents/kwh
January 1, 1996 7.35 cents/kwh
January 1, 1997 6.85 cents/kwh
January 1, 1998 6.35 cents/kwh
January 1, 1999 5.85 cents/kwh
</TABLE>
Diablo Canyon Settlement
Page 1
<PAGE>
c) After December 31, 1999, the escalating price portion of the Diablo
Canyon price will increase using the same formula specified in D.88-
12-083, Appendix D, Paragraph 4.
d) PG&E may reduce the fixed and/or escalating price portions of the
Diablo Canyon price at any time at its sole discretion. Such a
reduction of the Diablo Canyon price below the fixed and escalating
price ceilings specified in Paragraph 1 above shall be excluded from
all reasonableness reviews.
2. The difference between PG&E's revenue requirements under the original
Diablo Canyon prices and the new prices specified in this Agreement will be
applied to the Energy Cost Adjustment Clause (ECAC) balancing account until
the undercollection as of December 31, 1995, is fully amortized.
3. This Agreement resolves all issues relating to the reasonableness of the
pricing of Diablo Canyon power raised in DRA's Petition to Modify Decision
93-03-075 in Application Nos. 84-06-014 and 85-08-025, dated August 26,
1994.
4. The Parties agree that the prices for the period through December 31, 1999,
as provided in Paragraphs l.a and l.b, are reasonable and shall be the
basis for the recovery of PG&E's ECAC revenue requirements pursuant to the
pricing of Diablo Canyon power.
Diablo Canyon Settlement
Page 2
<PAGE>
5. The Parties shall jointly request, and use their best efforts to obtain,
prompt Commission approval of the Agreement, without change.
6. If the Commission conditions approval of the Agreement on a change,
modification, severance, deletion or new term to the Agreement, the Parties
agree to promptly negotiate in good faith to achieve a resolution
acceptable to all Parties and to promptly seek Commission approval of the
resolution so achieved. Failure to resolve such change, modification,
severance, deletion or new term to this Agreement to the satisfaction of
all Parties shall terminate this Agreement.
7. The Parties agree that nothing contained in this Agreement shall serve as
precedent in future proceedings.
8. This Agreement represents the complete understanding and agreement of the
Parties with respect to the pricing of Diablo Canyon power as described
herein.
9. Pending a final and unappealable order by the CPUC approving and adopting
it, this Agreement may be amended or changed only by a written agreement
signed by all Parties.
DATED: December 16, 1994 AGRICULTURAL ENERGY CONSUMERS
--
ASSOCIATION
By MICHAEL BOCCADORO
---------------------------
Michael Boccadoro
Diablo Canyon Settlement
Page 3
<PAGE>
DATED: December 14, 1994 CALIFORNIA DEPARTMENT OF
--
GENERAL SERVICES
By DOUGLAS M. GRANDY
---------------------------
Douglas M. Grandy, Chief, Office
of Energy Assessment
DATED: December 22, 1994 CALIFORNIA FARM BUREAU FEDERATION
--
By STEVEN GERINGER
---------------------------
Steven Geringer, Attorney
DATED: December 14, 1994 CALIFORNIA LARGE ENERGY
--
CONSUMERS ASSOCIATION
By WILLIAM H. BOOTH
------------------------------
William Booth, Attorney
DATED: December 19, 1994 CALIFORNIA MANUFACTURERS
--
ASSOCIATION
By GORDON E. DAVIS
---------------------------
Gordon Davis, Attorney
DATED: December 15, 1994 DEPARTMENT OF THE NAVY for
--
FEDERAL EXECUTIVE AGENCIES
By NORMAN FURUTA
---------------------------
Norman Furuta, Attorney
DATED: December 14, 1994 DIVISION OF RATEPAYER ADVOCATES
--
By EDMUND J. TEXEIRA
---------------------------
Edmund J. Texeira, Director
Diablo Canyon Settlement
Page 4
<PAGE>
DATED: December 15, 1994 INDUSTRIAL USERS
--
By PHILIP A. STOHR
--------------------------
for Ronald Liebert, Attorney
DATED: December 16, 1994 DANIEL E. LUNGREN
--
ATTORNEY GENERAL
By MARK J. URBAN
---------------------------
Mark J. Urban, Dep. Atty. Gen.
DATED: December 13, 1994 PACIFIC GAS AND ELECTRIC COMPANY
--
By STANLEY T. SKINNER
---------------------------
Stanley T. Skinner, President and
Chief Executive Officer
Diablo Canyon Settlement
Page 5
<PAGE>
All contributions withheld by the EMPLOYER from COVERED COMPENSATION are paid
over to the TRUSTEE, unconditionally credited to the
Exh. 10.6
THE PACIFIC GAS AND ELECTRIC COMPANY
SAVINGS FUND PLAN
FOR NON-UNION EMPLOYEES
____________________________________
This is the controlling and definitive statement of the Pacific Gas and
Electric Company Savings Fund Plan for Non-Union EMPLOYEES /1/ in effect on and
after January 1, 1996. The PLAN, which covers ELIGIBLE EMPLOYEES of the COMPANY
and other EMPLOYERS, is a further revision of the one originally placed in
effect by the COMPANY as of April 1, 1959. It has since been amended from time
to time. The PLAN as amended may be further amended retroactively in order to
meet applicable rules and regulations of the Internal Revenue Service, the
United States Department of Labor and all other applicable rules and
regulations.
The PLAN is maintained for the exclusive benefit of participants or their
BENEFICIARIES, and contributions or benefits under the PLAN do not discriminate
in favor of HIGHLY COMPENSATED EMPLOYEES.
ELIGIBILITY AND PARTICIPATION
-----------------------------
1. Eligibility
-----------
A non-union EMPLOYEE becomes an ELIGIBLE EMPLOYEE upon completion of one
year of SERVICE. Once eligibility occurs it continues as long as the
EMPLOYEE remains a non-union EMPLOYEE and SERVICE continues.
2. Participation
-------------
To become a participant, an ELIGIBLE EMPLOYEE must provide NOTICE to the
PLAN ADMINISTRATOR of the ELIGIBLE EMPLOYEE'S election to participate and
to be bound by the terms of the PLAN. Through such NOTICE, the ELIGIBLE
EMPLOYEE shall:
(a) authorize the EMPLOYER to reduce his COVERED COMPENSATION by a stated
percentage and to contribute such amount to the PLAN as a (S) 401(k)
CONTRIBUTION; and/or
(b) elect to make NON-(S) 401(k) CONTRIBUTIONS, if any, to the PLAN; and
(c) instruct the PLAN ADMINISTRATOR as to the manner in which EMPLOYEE
contributions and matching EMPLOYER CONTRIBUTIONS are to be invested.
CONTRIBUTIONS
-------------
3. EMPLOYEE Contributions
----------------------
To become a contributing participant, an ELIGIBLE EMPLOYEE must make (S)
401(k) CONTRIBUTIONS, NON-(S) 401(k) CONTRIBUTIONS, or a combination of
both to the PLAN through payroll deduction.
______________________________
/1/ Words in all capitals are defined in Section 30.
-1-
<PAGE>
All contributions withheld by the EMPLOYER from COVERED COMPENSATION are
paid over to the TRUSTEE, unconditionally credited to the participant's
account and invested in accordance with the participant's instructions.
(a) (S) 401(k) CONTRIBUTIONS. A (S) 401(k) CONTRIBUTION is an election to
defer the receipt of a specified whole percentage of COVERED
COMPENSATION which would otherwise be currently payable to a
participant. The EMPLOYER shall reduce the participant's COVERED
COMPENSATION by an amount equal to the percentage of the (S) 401(k)
CONTRIBUTION elected by the participant. Under current law, (S)
401(k) CONTRIBUTIONS deferred by a participant under the PLAN are not
subject to federal or state income tax until actually withdrawn or
distributed from the PLAN.
(b) FLEXDOLLARS. By giving NOTICE, a participant in the COMPANY'S Flex
Plan may elect to have any unused FLEXDOLLARS contributed to this
PLAN. Any FLEXDOLLARS contributed to this PLAN shall be deemed (S)
401(k) CONTRIBUTIONS and shall be subject to all restrictions and
limitations applicable to (S) 401(k) CONTRIBUTIONS. FLEXDOLLAR
contributions shall not be eligible for matching EMPLOYER
CONTRIBUTIONS as described in Section 4.
(c) NON-(S) 401(k) CONTRIBUTIONS. NON-(S) 401(k) CONTRIBUTIONS differ
from (S) 401(k) CONTRIBUTIONS in that a participant has already paid
taxes on the amounts contributed to the PLAN. All EMPLOYEE
Contributions made to the PLAN as it existed prior to October 1, 1984,
are considered to be NON-(S) 401(k) CONTRIBUTIONS and are so recorded
in the accounts maintained by the PLAN ADMINISTRATOR.
NON-(S) 401(k) CONTRIBUTIONS must be made in whole percentages of
COVERED COMPENSATION, and the sum of all (S) 401(k) CONTRIBUTIONS and
NON-(S) 401(k) CONTRIBUTIONS made by a participant may not exceed 15
percent of the participant's COVERED COMPENSATION.
(d) CHANGING CONTRIBUTIONS. By giving NOTICE to the PLAN ADMINISTRATOR,
a participant may direct the PLAN ADMINISTRATOR to cease or resume
making contributions, or to change the rate of contributions. Any
such change shall become effective within 30 days of receipt by the
PLAN ADMINISTRATOR of such NOTICE.
4. Employer Contributions
----------------------
(a) Each and every time that participants make (S) 401(k) or non-(S)
401(K) CONTRIBUTIONS to the PLAN eligible for matching EMPLOYER
CONTRIBUTIONS, the COMPANY shall make a matching EMPLOYER CONTRIBUTION
to the PLAN in cash or in whole shares of COMPANY STOCK, or partly in
both. Matching EMPLOYER CONTRIBUTIONS shall be limited to an amount
equal to three-quarters of the aggregate participant contributions
eligible for matching EMPLOYER CONTRIBUTIONS under the provisions of
Subsection 4(a)(1). The COMPANY shall charge to each EMPLOYER its
appropriate share of matching EMPLOYER CONTRIBUTIONS.
(1) (S) 401(k) and NON-(S) 401(k) CONTRIBUTIONS Eligible for Matching
EMPLOYER CONTRIBUTIONS. Although a participant may elect to
defer up to 15 percent of COVERED COMPENSATION to the PLAN, the
maximum amount of a
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participant's contributions eligible for matching EMPLOYER
CONTRIBUTIONS shall be one of the following percentages of
COVERED COMPENSATION:
(i) up to 3 percent, with at least one but less than three years
of SERVICE; or
(ii) up to 6 percent, with at least three years of SERVICE.
(iii) for a participant who is absent from work and receiving
temporary compensation under any state Worker's Compensation
Law or under the COMPANY'S LONG TERM DISABILITY PLAN, the
larger of:
a) the maximum percentage calculated under (i) or (ii),
whichever is applicable; or
b) the dollar amount which was eligible for matching
EMPLOYER CONTRIBUTIONS immediately before the
participant's absence began.
(b) Investment of EMPLOYER CONTRIBUTIONS. All EMPLOYER CONTRIBUTIONS
made to the PLAN shall be invested by the TRUSTEE in accordance with a
participant's INVESTMENT FUND directions.
5. Limitations
-----------
(a) Average Deferral Percentage Limitation. In any PLAN YEAR, the average
rate of (S) 401(k) CONTRIBUTIONS as a percentage of compensation for
all participating HIGHLY COMPENSATED ELIGIBLE EMPLOYEES shall not
exceed the larger of:
(1) the average rate of (S) 401(k) CONTRIBUTIONS as a percentage of
compensation for all other participating ELIGIBLE EMPLOYEES
multiplied by 1.25 percent; or
(2) the lesser of:
(i) the average rate of (S) 401(k) CONTRIBUTIONS as a percentage
of compensation for all other participating ELIGIBLE
EMPLOYEES multiplied by 2; or
(ii) the average rate of (S) 401(k) CONTRIBUTIONS as a percentage
of compensation for all other participating ELIGIBLE
EMPLOYEES plus 2 percentage points, or such lesser amount as
the Secretary of the Treasury may prescribe in order to
prevent the multiple use of this alternative limitation
with respect to any HIGHLY COMPENSATED participant. If
multiple use of the alternative limitation occurs with
respect to the Average Deferral Percentage Limitation and
Average Contribution Percentage Limitation in this PLAN, it
will be corrected by reducing the actual contribution
percentage of HIGHLY COMPENSATED participants in the manner
described in Section 5(c), below.
The average rate of (S) 401(k) CONTRIBUTIONS for a PLAN YEAR for a
designated group of ELIGIBLE EMPLOYEES shall be the average of the
ratios, calculated separately for each par-
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<PAGE>
ticipating ELIGIBLE EMPLOYEE in the group, of the amount of (S) 401(k)
CONTRIBUTIONS made by each EMPLOYEE for the PLAN YEAR, to the
EMPLOYEE'S compensation for such PLAN YEAR. As used in this
subsection, compensation shall mean compensation paid by an EMPLOYER
to the participant during the PLAN YEAR which is required to be
reported as wages on the par ticipant's form W-2 and shall also
include compensation which is not currently includable in the
participant's gross income by reason of the application of CODE
Sections 125 and 402(e)(3).
For purposes of this subsection, the ratio of the amount of (S) 401(k)
CONTRIBUTIONS to a participant's compensation for any participant who
is HIGHLY COMPENSATED for the PLAN YEAR and who is eligible to have
elective deferrals or qualified employer deferral contributions
allocated to his account under two or more plans or arrangements
described in Section 401(k) of the CODE that are maintained by an
employer or affiliated employer shall be determined as if all such (S)
401(k) CONTRIBUTIONS, elective deferrals and qualified employer
deferral contributions were made under a single arrangement.
For purposes of determining the ratio of the amount of (S) 401(k)
CONTRIBUTIONS to a participant's compensation for a participant who is
HIGHLY COMPENSATED by reason of being one of the ten highest-paid
EMPLOYEES or a 5 percent owner of the controlled group of
corporations, as defined in Section 414 of the CODE, the (S) 401(k)
CONTRIBUTIONS and compensation of such participant shall include the
(S) 401(k) CONTRIBUTIONS and compensation of the participant's family
members, as defined in Section 414 of the CODE, and such family
members shall be disregarded in determining the average rate of (S)
401(k) CONTRIBUTIONS for non-HIGHLY COMPENSATED participants.
The determination and treatment of (S) 401(k) CONTRIBUTIONS of any
participant shall satisfy such other requirements as may be prescribed
by the Secretary of the Treasury.
(b) Average Contribution Percentage Limitation. In any PLAN YEAR, the
average rate of NON-(S) 401(k) CONTRIBUTIONS and EMPLOYER
CONTRIBUTIONS as a percentage of compensation for all participating
HIGHLY COMPENSATED ELIGIBLE EMPLOYEES shall not exceed the larger of:
(1) the average rate of NON-(S) 401(k) CONTRIBUTIONS and EMPLOYER
CONTRIBUTIONS as a percentage of compensation for all other
participating ELIGIBLE EMPLOYEES multiplied by 1.25; or
(2) the lesser of:
(i) the average rate of NON-(S) 401(k) CONTRIBUTIONS and
EMPLOYER CONTRIBUTIONS as a percentage of compensation for
all other participating ELIGIBLE EMPLOYEES multiplied by 2;
or
(ii) the average rate of NON-(S) 401(k) CONTRIBUTIONS and
EMPLOYER CONTRIBUTIONS for all other participating ELIGIBLE
EMPLOYEES plus 2 percentage points, or such lesser amount as
the Secretary of the Treasury may prescribe in order to
prevent the multiple use of this alternative limi-
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<PAGE>
tation with respect to any HIGHLY COMPENSATED participant.
If multiple use of the alternative limitation occurs with
respect to the Average Deferral Percentage Limitation and
Average Contribution Percentage Limitation in this PLAN, it
will be corrected by reducing the actual contribution
percentage of HIGHLY COMPENSATED participants in the manner
described in Section 5(c), below.
The average rate of NON-(S) 401(k) CONTRIBUTIONS and EMPLOYER
CONTRIBUTIONS for a PLAN YEAR for a designated group of ELIGIBLE
EMPLOYEES shall be the average of the ratios, calculated separately
for each participating ELIGIBLE EMPLOYEE in the group, of the amount
of NON-(S) 401(k) CONTRIBUTIONS and EMPLOYER CONTRIBUTIONS made by
and on behalf of each EMPLOYEE for the PLAN YEAR, to the EMPLOYEE'S
compensation for such PLAN YEAR. As used in this subsection,
compensation shall mean compensation paid by an EMPLOYER to the
participant during the PLAN YEAR which is required to be reported as
wages on the participant's form W-2 and shall also include
compensation which is not currently includable in the participant's
gross income by reason of the application of CODE Sections 125 and
402(e)(3).
For purposes of this subsection, the ratio of the amount of NON-(S)
401(k) CONTRIBUTIONS and EMPLOYER CONTRIBUTIONS to a participant's
compensation for any participant who is HIGHLY COMPENSATED for the
PLAN YEAR and who is eligible to have elective deferrals or qualified
employer deferral contributions allocated to his account under two or
more plans or arrangements described in Section 401(k) of the CODE
that are maintained by an employer or affiliated employer shall be
determined as if all such NON-(S) 401(k) CONTRIBUTIONS and EMPLOYER
CONTRIBUTIONS, elective deferrals and qualified employer deferral
contributions were made under a single arrangement.
For purposes of determining the ratio of the amount of NON-(S) 401(k)
CONTRIBUTIONS and EMPLOYER CONTRIBUTIONS to a participant's
compensation for a participant who is HIGHLY COMPENSATED by reason of
being one of the ten highest-paid EMPLOYEES or a 5 percent owner of
the controlled group of corporations, as defined in Section 414 of the
CODE, the NON-(S) 401(k) CONTRIBUTIONS and EMPLOYER CONTRIBUTIONS and
compensation of such participant shall include the NON-(S) 401(k)
CONTRIBUTIONS and EMPLOYER CONTRIBUTIONS and compensation of the
participant's family members, as defined in Section 414 of the CODE,
and such family members shall be disregarded in determining the
average rate of NON-(S) 401(k) CONTRIBUTIONS and EMPLOYER
CONTRIBUTIONS for non-HIGHLY COMPENSATED participants.
The determination and treatment of NON-(S) 401(k) CONTRIBUTIONS and
EMPLOYER CONTRIBUTIONS of any participant shall satisfy such other
requirements as may be prescribed by the Secretary of the Treasury.
(c) In the event that the EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE, in
its sole and absolute discretion, determines that the rate of (S)
401(k) CONTRIBUTIONS, and/or the rate of NON-(S) 401(k) CONTRIBUTIONS
and EMPLOYER CONTRIBUTIONS will exceed either or both of the maximum
limitations contained in subsections 5(a) and 5(b), the EMPLOYEE
BENEFIT ADMINIS-
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<PAGE>
TRATIVE COMMITTEE shall instruct the PLAN ADMINISTRATOR to reduce the
rate of contributions made by HIGHLY COMPENSATED participants so that
the limitations will be met.
The PLAN ADMINISTRATOR shall first determine the maximum average rate
of contributions which can be made by the HIGHLY COMPENSATED
participants. The contributions made by HIGHLY COMPENSATED
participants shall then be reduced, on a prospective basis, until the
limitations are met. Any necessary reduction shall be made by first
reducing the highest rate of (S) 401(k) CONTRIBUTIONS or NON-(S)
401(k) CONTRIBUTIONS and EMPLOYER CONTRIBUTIONS as may be appropriate,
currently authorized by participants, with such rate to be reduced in
one percent increments until the maximum permissible average rate of
contributions is met.
Notwithstanding any other provision of the PLAN, if, as of the end of
a PLAN YEAR, the PLAN fails to meet either or both of the tests
described in subsections 5(a) or 5(b), the PLAN ADMINISTRATOR shall,
on or before December 31 of the following PLAN YEAR distribute to each
HIGHLY COMPENSATED participant, beginning with the participant having
the higher ratio, such excess portion of the participant's (S) 401(k)
CONTRIBUTIONS, and/or NON-(S) 401(k) CONTRIBUTIONS and EMPLOYER
CONTRIBUTIONS (and any income allocable to such portion), until the
PLAN satisfies both of the tests. Distributions made to satisfy the
limitations described in subsection 5(b) shall include both NON-(S)
401(k) CONTRIBUTIONS and related matching EMPLOYER CONTRIBUTIONS in
accordance with the requirements of Treasury Regulation
(S) 1.401(m)-l(e)(4). If there is a loss allocable to such excess
amount, the amount of the distribution shall in no event be less than
the lesser of the (i) participant's account or (ii) the participant's
(S) 401(k) CONTRIBUTIONS, or NON-(S) 401(k) CONTRIBUTIONS and EMPLOYER
CONTRIBUTIONS, as appropriate, for the PLAN YEAR.
For the PLAN YEARS 1987, 1988, 1989, 1990 and 1991 only, the PLAN
ADMINISTRATOR may elect to make qualified non-elective employer
contributions within the meaning of Section 401(m)(4)(c) of the CODE,
on behalf of such non-HIGHLY COMPENSATED participants who are
EMPLOYEES of Pacific Service Employees Association as will cause the
PLAN to meet the appropriate limits set forth in subsections 5(a) and
5(b). For purposes of PLAN withdrawals qualified non-elective
employer contributions shall be treated as (S) 401(k) CONTRIBUTIONS.
For purposes of determining whether the PLAN meets either or both of
the limits set forth in subsections 5(a) and 5(b), the PLAN
ADMINISTRATOR may elect to make the look-back year calculation as
provided in Regulation 1.414(q)-ITA-14(b)(1) for any determination
year on the basis of the calendar year ending with the applicable
determination year.
(d) Annual (S) 401(k) Limitation. Effective as of January 1, 1987, no
participant shall be permitted to make (S) 401(k) CONTRIBUTIONS to the
PLAN during any PLAN YEAR in excess of $7,000, multiplied by the
adjustment factor prescribed by the Secretary of the Treasury under
Section 415(d) of the CODE for years beginning after December 31,
1987, as applied to elective deferrals. A participant who is unable
to make (S) 401(k) CONTRIBUTIONS which would have been eligible for
matching EMPLOYER CONTRIBUTIONS because of the limitation
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<PAGE>
contained in this subsection 5(d), shall be entitled to make NON-(S)
401(k) CONTRIBUTIONS in an amount equal to the amount of (S) 401(k)
CONTRIBUTIONS that could have been made but for the subsection 5(d)
limitation. Such NON-(S) 401(k) CONTRIBUTIONS shall be eligible for
matching EMPLOYER CONTRIBUTIONS as though they were (S) 401(k)
CONTRIBUTIONS, subject to the limitations contained in Section 5.
(e) Section 415 Limitation. Anything herein to the contrary
notwithstanding, in no event shall the annual additions to a
participant's accounts in a YEAR exceed the lesser of (1) 25 percent
of the participant's compensation (as defined in subparagraph 5(e)(1),
below) for the YEAR or (2) $30,000, or, if greater, one-fourth of the
defined benefit dollar limitation set forth Section 415(b)(1) of the
CODE as in effect for the PLAN YEAR. For purposes of applying the
limitations of Section 415 of the CODE, the annual additions which
must be kept within the limits set forth above, shall mean the sum
credited to a participant's account for any PLAN YEAR of (i) EMPLOYER
CONTRIBUTIONS and (S) 401(k) CONTRIBUTIONS, (ii) NON-(S) 401(k)
CONTRIBUTIONS, and (iii) any amounts allocated to an individual
medical account, as defined in Sections 415(l)(2) and 419A(d)(2) of
the CODE. The compensation limitation percentage referred to above
shall not apply to (i) any contribution for medical benefits, as
defined in Section 419A(f)(2) of the CODE, after a participant's
separation from SERVICE which is otherwise treated as an annual
addition, or (ii) any amount which is otherwise treated as an annual
addition under Section 415(l)(1) of the CODE.
(1) Solely for purposes of applying the Section 415 limitations,
compensation shall include all of a participant's wages,
salaries, fees for professional service, and other amounts
received for personal services actually rendered in the course of
employment with an EMPLOYER (including, but not limited to,
commissions paid to salesmen, compensation for services on the
basis of a percentage of profits, commissions on insurance
premiums, tips, and bonuses). For purposes of applying the
Section 415 limitations, compensation shall not include any of
the following:
a) Contributions made by an EMPLOYER to a plan of deferred
compensation to the extent that, before the application of
the Section 415 limitations to that plan, the contributions
are not includable in the gross income of the participant
for the taxable year in which contributed. Any
distributions from a plan of deferred compensation are not
considered as compensation for Section 415 purposes,
regardless of whether such amounts are includable in the
gross income of the EMPLOYEE when distributed. However, any
amounts received by a participant pursuant to an unfunded,
nonqualified plan may be considered as compensation for
Section 415 purposes in the year such income is includable
in the gross income of the EMPLOYEE.
b) Amounts realized from the exercise of a non-qualified stock
option, or when restricted stock (or property) held by a
participant either be-
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<PAGE>
comes freely transferable or is no longer subject to a
substantial risk of forfeiture.
c) Amounts realized from the sale, exchange, or other
disposition of stock acquired under a qualified stock
option.
d) Other amounts which receive special tax benefits such as
premiums for group term life insurance (but only to the
extent that the premiums are not includable in the gross
income of the participant).
In the event that the annual additions to a participant's
accounts would exceed the Section 415 Limitations, the PLAN
ADMINISTRATOR shall first reduce the participant's NON-(S)
401(k) CONTRIBUTIONS until the Section 415 limitations are
met.
(f) If a participant of this PLAN is also a participant in the COMPANY'S
RETIREMENT PLAN, Section 415 of the CODE imposes a combined benefit
limitation. Contributions to this PLAN will nevertheless be permitted
to the maximum extent permitted by Section 415 of the CODE and the
terms of the PLAN. If the combined maximum benefit permitted would be
exceeded, the benefit from the COMPANY'S RETIREMENT PLAN shall be
reduced so that the limitation will be met. The combined maximum
benefit for a participant shall be determined pursuant to the
provisions of Section 415(e) of the CODE.
At the election of the PLAN ADMINISTRATOR, special transitional rules
may apply for both the defined benefit fraction and the defined
contribution fraction for EMPLOYEES who were participants as of
December 31, 1982.
(g) Top Heavy Provisions. In the event that the PLAN is or becomes "Top
Heavy", as that term is defined in Section 416(g) of the CODE, the
provision contained in Special Provision A shall supersede any
conflicting provision of the PLAN.
(h) For purposes of determining all benefits under the PLAN, for PLAN
YEARS beginning after 1988 and before 1994, the maximum compensation
of each EMPLOYEE that may be taken into account each PLAN YEAR shall
not exceed $200,000 (as adjusted by the Secretary of the Treasury
under Section 401(a)(17) of the CODE. For purposes of determining all
benefits under the PLAN, for PLAN YEARS beginning after 1993, the
maximum compensation of each EMPLOYEE that may be taken into account
each PLAN YEAR shall not exceed $150,000 (as adjusted by the Secretary
of the Treasury under Section 401(a)(17) of the CODE). In determining
the compensation of a HIGHLY COMPENSATED EMPLOYEE for purposes of
this limitation, the rules of Section 414(q)(6) of the CODE shall
apply, except that the term "family" shall include only the spouse of
the EMPLOYEE and any lineal descendants of the EMPLOYEE who have not
attained age 19 before the close of the YEAR. If the aggregate
compensation of family members exceeds the applicable compensation
limit of compensation as limited by Section 401(a)(17) of the CODE,
then the amount of compensation considered under the PLAN for each
family member is pro-portionately reduced so that the total equals the
applicable
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<PAGE>
compensation limitation under Section 401(a)(17) of the CODE.
SELECTION OF INVESTMENT FUNDS
-----------------------------
6. (a) (S) 401(k) CONTRIBUTIONS, NON-(S) 401(k) CONTRIBUTIONS, and
EMPLOYER CONTRIBUTIONS. By giving NOTICE, a participant shall
instruct the PLAN ADMINISTRATOR to invest his (S) 401(k)
CONTRIBUTIONS, NON-(S) 401(k) CONTRIBUTIONS, and EMPLOYER
CONTRIBUTIONS in one or more INVESTMENT FUNDS. The minimum amount
which can be invested in any single INVESTMENT FUND shall be one
percent of a participant's current contributions to the PLAN. A
participant may elect to invest more than the minimum amount in any
INVESTMENT FUND, provided that any such increase must be in increments
of one percent.
(b) CHANGE OF INVESTMENT FUND ALLOCATIONS. By giving NOTICE to the PLAN
ADMINISTRATOR, a participant may (1) change the percentage levels of
future contributions which are to be allocated to any INVESTMENT FUND
or FUNDS or, (2) change the INVESTMENT FUNDS in which his future
contributions are to be invested. Each election regarding investment
of future contributions shall be effective with the next deposit of
contributions.
THE INVESTMENT FUNDS
--------------------
7. Company Stock Fund
------------------
This FUND is invested primarily in Common Stock of the COMPANY, with a
small portion invested in cash or cash equivalents. The FUND also holds
COMPANY STOCK and the earnings thereon attributable to EMPLOYER
CONTRIBUTIONS and participant contributions made to the Basic Fund of the
PLAN as it existed prior to April 1, 1983, as well as all COMPANY STOCK
which has been transferred to this PLAN from the TRASOP and PAYSOP Plan.
All cash dividends received by the TRUSTEE on COMPANY STOCK are reinvested
in the FUND.
(a) Investment Generally. Whenever the TRUSTEE invests cash in COMPANY
STOCK, the EMPLOYEE BENEFIT FINANCE COMMITTEE shall direct the TRUSTEE
to purchase the COMPANY STOCK either (i) at a public sale on a
recognized stock exchange, (ii) directly from the COMPANY at a price
equal to that day's closing price for COMPANY STOCK on the New York
Stock Exchange, or (iii) from a private source at a price no higher
than the price that would have been payable under (i).
(b) Voting of COMPANY STOCK. Each and every time shareholders who are not
participants in the PLAN are entitled to vote COMPANY STOCK,
participants shall have an absolute right to vote COMPANY STOCK.
Whenever participants are given the opportunity to vote COMPANY STOCK,
the TRUSTEE shall inform each participant of all relevant material
received by the TRUSTEE with a written request for confidential voting
instructions. The TRUSTEE is required to vote the COMPANY STOCK
credited to a participant's account as the participant directs. If
the participant does not give such instructions within the required
time, the TRUSTEE may not vote any COMPANY STOCK credited to a
---
participant's account.
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<PAGE>
(c) Cost of UNITS. The cost of a UNIT shall be the current value of a
UNIT as determined by the TRUSTEE as of the valuation date immediately
preceding the date that the TRUSTEE invests contributions in the
COMPANY STOCK FUND.
(d) Value of UNITS. The value of a UNIT is the value of the COMPANY STOCK
held in the FUND at the closing price on the New York Stock Exchange
plus the cash held in the FUND, as determined by the TRUSTEE each
BUSINESS DAY, less any fees or other expenses which are charged to the
FUND which shall reduce the earnings of that fund, divided by the
number of UNITS. Each payment into the COMPANY STOCK FUND of
contributions shall increase, and each payment out of the COMPANY
STOCK FUND shall decrease, the number of UNITS by a number equal to
the amount of the payment divided by the last UNIT value determination
immediately preceding the date of payment.
8. United States Bond Fund
-----------------------
This FUND was maintained for the purpose of investing EMPLOYEE
contributions in United States BONDS. This FUND also holds all BONDS
attributable to participant contributions made to the Basic Fund of the
PLAN as it existed prior to April 1, 1983. Income from BONDS is reflected
in the greater redemption values of the BONDS. BONDS held in this FUND
cannot be transferred to another INVESTMENT FUND under the transfer
provisions of Section 14.
Effective July 1, 1991, the U.S. BOND FUND no longer accepts EMPLOYEE
contributions. BONDS purchased to date with EMPLOYEE contributions will
continue to be held in the PLAN until a distribution is requested by the
EMPLOYEE in accordance with current PLAN provisions.
9. Diversified Equity Fund (DEF)
-----------------------
This FUND is maintained for the purpose of investing in a diversified
portfolio consisting principally of common stock and securities
convertible into common stock. However, at no time shall the DEF be
invested in securities issued or guaranteed by the COMPANY or any of its
subsidiaries, except to the extent that any such securities are held in a
commingled account invested in by the DEF INVESTMENT MANAGER. The DEF
INVESTMENT MANAGER directs the day-to-day investment of the FUND.
Contributions to this FUND are paid over to the TRUSTEE and invested in
accordance with instructions received from the DEF INVESTMENT MANAGER. A
participant's account is credited with the number of DEF UNITS purchased
with contributions allocated to his account. All Diversified Invest ment
Fund Units attributable to participant contributions made to the PLAN as it
existed prior to April 1, 1983 are held in this FUND under the new
designation of DEF UNITS.
(a) Cost of DEF UNITS. The cost of a DEF UNIT shall be the current value
of a UNIT as determined by the DEF INVESTMENT MANAGER as of the
valuation date immediately preceding the date that the TRUSTEE invests
contributions in the DEF.
(b) Value of DEF UNITS. The value of a DEF UNIT is the value of the FUND
assets, as determined each BUSINESS DAY by the TRUSTEE, less any
liabilities (other than the interests of participants in the FUND),
divided by the number of DEF UNITS. Each payment into the FUND of
contributions shall increase, and each payment out of the FUND shall
decrease, the number of FUND UNITS by a number equal to the amount of
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the payment divided by the last UNIT value determination immediately
preceding the date of the payment.
10. Utility Stock Fund (USF)
------------------
This FUND is maintained for the purpose of investing in an index fund
consisting of common stocks of publicly traded electric utility companies
that are members of the Edison Electric Institute. However, at no time
shall the FUND be invested in securities issued or guaranteed by the
COMPANY or any of its subsidiaries, except to the extent that any such
securities are held in a commingled account invested in by the USF
INVESTMENT MANAGER. The FUND seeks to provide investment results that
correspond to the price and yield performance of common stocks of selected
utilities engaged in the generation, transmission, or distribution of
electric energy, as represented by an index comprising the common stocks of
companies that are members of the Edison Electric Institute. Stocks in
the FUND's portfolio are generally held in the same proportions that each
stock has within the index. Seeking to duplicate the index as closely as
possible, the portfolio is monitored and adjusted by computer; no attempt
is made to manage the portfolio in the traditional sense using economic,
financial, and market analyses.
Contributions to the USF are paid to the TRUSTEE and invested in accordance
with the instructions from the USF INVESTMENT MANAGER. A participant's
account is credited with the number of USF UNITS purchased with
contributions allocated to his account.
(a) Cost of USF UNITS. The cost of a USF UNIT shall be the current value
of a UNIT as determined by the TRUSTEE as of the valuation date
immediately preceding the date that the TRUSTEE invests contributions
in the USF.
(b) Value of USF UNITS. The value of a USF UNIT is the value of the
assets, as determined each BUSINESS DAY by the TRUSTEE, less any
liabilities (other than interests of participants in the USF), divided
by the number of USF UNITS. Each payment into the USF of
contributions shall increase, and each payment out of the USF shall
decrease the number of USF UNITS by a number equal to the amount of
the payment divided by the last UNIT value determination immediately
preceding the date of payment.
11. Guaranteed Income Fund (GIF)
----------------------
This FUND is designed to provide participants with a stable and consistent
rate of return. The FUND is made up of investment contracts with a
diversified group of insurance companies, banks, and other financial
institutions which provide for credited interest rates and terms that are
negotiated at the time of purchase.
Contributions made to the GIF are invested in a portfolio of investment
contracts. The GIF INVESTMENT MANAGER directs the day-to-day investment of
the FUND. The blended interest earned on all contracts held in the
portfolio is posted daily to the participant's account.
(a) COST OF GIF UNITS. The cost of a GIF UNIT shall be the current value
of a UNIT as determined by the TRUSTEE as of the valuation date
immediately preceding the date that the TRUSTEE invests contributions
in the GIF.
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(b) VALUE OF GIF UNITS. The value of a GIF UNIT is the value of the GIF
assets, as determined each BUSINESS DAY by the TRUSTEE, less any
liabilities (other than the interests of participants in the GIF),
divided by the number of GIF UNITS. Each payment into the GIF of
contributions shall increase, and payments out of the GIF shall
decrease, the number of GIF UNITS by a number equal to the amount of
the payment divided by the last UNIT value determination immediately
preceding the date of payment.
12. Bond Index Fund (BIF)
---------------
The BIF is maintained for the purpose of investing in a diversified
portfolio consisting principally of marketable fixed-income securities. At
no time shall the BIF be invested in securities issued or guaranteed by the
COMPANY or any of its subsidiaries, except to the extent that any such
securities are held in a commingled account invested in by the BIF
INVESTMENT MANAGER. The BIF INVESTMENT MANAGER directs the day-to-day
investment of the BIF.
Contributions to the BIF are paid over to the TRUSTEE and invested in
accordance with instructions received from the BIF INVESTMENT MANAGER. A
participant's account is credited with the number of BIF UNITS purchased
with contributions allocated to his account.
(a) Cost of BIF UNITS. The cost of a BIF UNIT shall be the current value
of a UNIT as determined by the TRUSTEE as of the valuation date
immediately preceding the date that the TRUSTEE invests contributions
in the FUND.
(b) Value of BIF UNITS. The value of a BIF UNIT is the value of the BIF
assets, as determined each BUSINESS DAY by the TRUSTEE, less any
liabilities (other than the interests of participants in the BIF),
divided by the number of BIF UNITS. Each payment into the BIF of
contributions shall increase, and each payment out of the BIF shall
decrease, the number of BIF UNITS by a number equal to the amount of
the payment divided by the last UNIT value determination immediately
preceding the date of payment.
13. Stock and Bond Fund (SBF)
-------------------
The SBF is maintained for the purpose of investing in a diversified
portfolio consisting principally of U.S. equities and U.S. fixed income
investments. At no time shall the SBF be invested in securities issued or
guaranteed by the COMPANY or any of its subsidiaries, except to the extent
that any such securities are held in a commingled account invested in by
the SBF INVESTMENT MANAGER. The SBF INVESTMENT MANAGER directs the day-to-
day investment of the SBF.
Contributions to the SBF are paid over to the TRUSTEE and invested in
accordance with instructions from the SBF INVESTMENT MANAGER. A
participant's account is credited with the number of SBF UNITS purchased
with contributions allocated to his account.
(a) Cost of SBF UNITS. The cost of an SBF UNIT shall be the current value
of a UNIT as determined by the TRUSTEE as of the valuation date
immediately preceding the date that the TRUSTEE invests contributions
in the SBF.
(b) Value of SBF UNITS. The value of an SBF UNIT is the value of the
assets, as determined each BUSINESS DAY by the TRUST-
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EE, less any liabilities (other than the interests of participants in
the SBF), divided by the number of SBF UNITS. Each payment into the
SBF of contributions shall increase, and each payment out of the SBF
shall decrease, the number of SBF UNITS by a number equal to the
amount of the payment divided by the last UNIT value determination
immediately preceding the date of payment.
14. Transfer of Investment Fund Balances
------------------------------------
(a) By giving NOTICE to the PLAN ADMINISTRATOR, a participant may elect to
transfer any portion of the contributions held in his account, plus
the earnings thereon, from any INVESTMENT FUND to another INVESTMENT
FUND or FUNDS. A transfer shall be effective and shall be valued on
the day it is made, if such day is a BUSINESS DAY, and the participant
provides NOTICE of such transfer prior to the closing time of the New
York Stock Exchange. All other transfers shall be effective and
valued as of the next BUSINESS DAY.
Upon receipt of a transfer NOTICE, the TRUSTEE shall value the UNITS
to be transferred from the FUND and convert the UNITS to cash. The
FUND account of the participant shall be debited with the number of
UNITS transferred from that FUND and the TRUSTEE shall purchase with
the cash proceeds realized from the converted UNITS, UNITS in the
appropriate FUND or FUNDS, as designated by the participant. The cost
of the UNITS purchased shall be the value of the FUND UNITS as
determined on the date of transfer, and the number of UNITS purchased
shall be credited to the appropriate INVESTMENT FUND account of the
participant.
(b) COMPANY STOCK FUND -- Overall Limitation. Anything herein to the
contrary notwithstanding, if, as of any single month, the TRUSTEE is
required, as a result of the transfer provisions of this Section 14,
to sell on the open market more than one percent of the number of
outstanding shares of COMPANY STOCK, then the TRUSTEE shall
immediately so advise the EMPLOYEE BENEFIT FINANCE COMMITTEE. The
EMPLOYEE BENEFIT FINANCE COMMITTEE may, in its sole discretion,
limit, prorate, or temporarily suspend further sales of COMPANY STOCK
by the PLAN or take whatever steps necessary to ensure an orderly
market in COMPANY STOCK. The percentage limitation set forth in this
subsection shall be applied to the excess of shares sold on the open
market less shares purchased to meet Section 14 requirements for the
applicable period.
PARTICIPANT'S INTEREST IN THE PLAN
----------------------------------
15. Participant Accounts
--------------------
The PLAN ADMINISTRATOR maintains a separate account for each PLAN
participant which records the participant's interest in each of the
INVESTMENT FUNDS, together with EMPLOYER CONTRIBUTIONS made on his behalf.
Each account is charged with participant transfers and withdrawals and
credited with its appropriate share of FUND income. The account maintained
by the PLAN ADMINISTRATOR for each participant also records separately the
participant's (S) 401(k) CONTRIBUTIONS and NON-(S) 401(k) CONTRIBUTIONS,
the UNITS purchased therewith, and the earnings thereon. All Basic
Contributions and Supplemental Contributions made to the PLAN as it existed
prior to
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October 1, 1984, are recorded as NON-(S) 401(k) CONTRIBUTIONS on the
records maintained by the PLAN ADMINISTRATOR.
Whenever UNITS attributable to a participant's (S) 401(k) CONTRIBUTIONS
are transferred to another FUND OR FUNDS, the resulting UNITS are also
recorded as attributable to (S) 401(k) CONTRIBUTIONS. Similarly, UNITS
attributable to NON-(S) 401(k) CONTRIBUTIONS which are transferred to
another FUND or FUNDS are also recorded as NON-(S) 401(k) CONTRIBUTIONS. A
participant is at all times fully vested in his own contributions and all
EMPLOYER CONTRIBUTIONS credited to his account, together with income
attributable thereto.
16. Account Statements
------------------
As soon as practicable after the end of each CALENDAR QUARTER, all
participants will receive from the ADMINISTRATOR a statement of their
interest in the PLAN.
PLAN WITHDRAWALS
----------------
17. Withdrawal During Service
-------------------------
Except as provided in this Section, withdrawals of any part of a
participant's interest in the PLAN are not permitted as long as SERVICE
continues. A participant may never replace in the TRUST FUND any UNITS or
cash which have been withdrawn. By submitting a withdrawal Form, a
participant may make withdrawals as provided below.
(a) (S) 401(k) CONTRIBUTIONS.
(1) A participant may withdraw all or part of the UNITS, including
income thereon and including additional UNITS attributable
thereto, bought with the participant's (S) 401(k) CONTRIBUTIONS
upon the occurrence of any of the following events:
(a) the participant is disabled and is receiving benefits under
the LONG TERM DISABILITY PLAN; or
(b) the participant has attained age 59 1/2.
(2) A participant may withdraw an amount equal to his (S) 401(k)
CONTRIBUTIONS, as well as any income and UNITS attributable to
income accrued thereon prior to January 1, 1989, upon receipt of
satisfactory proof by the PLAN ADMINISTRATOR that the withdrawal
is required to meet immediate and heavy financial needs of the
participant which constitute a valid hardship as defined under
the CODE and regulations issued by the Secretary of the Treasury.
A request for a withdrawal for one of the following reasons will
be deemed to be on account of a valid hardship:
(a) To cover medical expenses (as defined in Section 213(d) of
the CODE) of the participant, the participant's spouse or
dependents (as defined in Section 152 of the CODE);
(b) The purchase of a participant's principal place of
residence, but not including mortgage payments;
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(c) To meet tuition payments for the next semester or quarter of
post-secondary education for the participant, his spouse,
children or dependents; or
(d) To prevent the eviction of the participant from his
principal place of residence, or to prevent a foreclosure of
the mortgage on the participant's principal place of
residence.
A request for a withdrawal under this subsection 17(a)(2) will
not be deemed to be for immediate and heavy financial needs
unless the participant represents that the need cannot be met
from the following resources:
(a) through reimbursement or compensation by insurance or
otherwise,
(b) by reasonable liquidation of the participant's resources,
(c) by cessation of contributions to the PLAN, or
(d) by other distributions, withdrawals or nontaxable loans
from any plans maintained by an EMPLOYER, or by borrowing
from commercial sources on reasonable commercial terms.
For purposes of this Subsection 17(a)(2), a participant's
resources shall be deemed to include any assets of his spouse and
minor children that are reasonably available to the participant.
In addition, withdrawals under Subsection 17(a)(2) may not
exceed the amount actually required to meet the participant's
immediate financial needs.
(3) A participant who withdraws UNITS under Subsection 17(a) will
automatically be suspended from the PLAN and will not be
permitted to resume making contributions to the PLAN for six
months following the date upon which the withdrawal Form is
processed by the PLAN ADMINISTRATOR. After suspension ends,
contributions may be resumed by giving NOTICE to the PLAN
ADMINISTRATOR.
(b) NON-(S) 401(k) CONTRIBUTIONS. A participant may at any time elect to
withdraw all or any part of the UNITS including income thereon and
including additional UNITS attributable thereto, bought with the
participant's NON-(S) 401(k) CONTRIBUTIONS to the PLAN. Such an
election will not cause suspension from the PLAN.
(c) EMPLOYER CONTRIBUTIONS.
(1) A participant may withdraw all or any part of the UNITS,
including the income attributable thereto, bought with EMPLOYER
CONTRIBUTIONS which were made to the PLAN at anytime prior to the
second YEAR preceding the current YEAR. For example, UNITS,
including the income attributable thereto, purchased with
EMPLOYER CONTRIBUTIONS made in 1981 and prior years may be
withdrawn in 1984 or anytime thereafter. Such an election will
not cause suspension from the PLAN.
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<PAGE>
(2) UNITS, including the income attributable thereto, bought with
EMPLOYER CONTRIBUTIONS which would not be withdrawable under
Subsection 17(c)(1), shall nonethe-less be withdrawable upon the
occurrence of any of the following events:
(a) the participant is disabled and is receiving benefits under
the LONG TERM DISABILITY PLAN;
(b) the participant attains 59-1/2; or
(c) the participant has requested and is entitled to receive a
hardship distribution which meets the requirements of
Subsection 17(a)(2) but only if all amounts distributable
under Subsection 17(a) have been exhausted.
Anything herein to the contrary notwithstanding, if as of any single
month, the TRUSTEE is required as a result of the withdrawal
provisions of this Subsection 17(c), to sell on the open market more
than one percent of the outstanding shares of COMPANY STOCK, then the
TRUSTEE shall immediately so advise the EMPLOYEE BENEFIT FINANCE
COMMITTEE. The EMPLOYEE BENEFIT FINANCE COMMITTEE may, in its sole
discretion, limit, prorate, or temporarily suspend further sales of
COMPANY STOCK by the PLAN or take whatever steps necessary to ensure
an orderly market in COMPANY STOCK.
A participant shall submit the appropriate Form to the SAVINGS FUND PLAN
directing the PLAN ADMINISTRATOR as to the amount of the withdrawal.
Distribution will be made as soon as practicable after receipt of the
withdrawal Form. Upon each withdrawal, the UNITS credited to the
appropriate FUND or FUNDS will be reduced by the number of UNITS withdrawn.
Withdrawals from the BOND FUND can only be made in United States BONDS.
Withdrawals from the COMPANY STOCK FUND may be made in cash or whole shares
of stock at the election of the participant. Withdrawals of DEF, USF, BIF,
SBF, or GIF UNITS will be made in cash at the then current value of the
UNITS; or, at the election of the participant, the UNITS will be
transferred to the COMPANY STOCK FUND pursuant to Section 14 and
distribution will be made in whole shares of COMPANY STOCK.
(d) Ordering of Withdrawals. Whenever the PLAN ADMINISTRATOR is required
to make a distribution under this Section 17 or Section 18, the PLAN
ADMINISTRATOR shall first withdraw UNITS and earnings thereon
attributable to a participant's NON-(S) 401(k) CONTRIBUTIONS made
prior to 1987, followed by UNITS and earnings thereon attributable to
NON-(S) 401(k) CONTRIBUTIONS made after 1986, followed by UNITS
withdrawable under Subsection 17(c)(1) followed by UNITS withdrawable
under Subsection 17(c)(2), but only if available for withdrawal under
that subsection, followed by UNITS and earnings thereon attributable
to a participant's (S) 401(k) CONTRIBUTIONS, but only to the extent
that such UNITS can be withdrawn by the participant under Subsection
17(a).
18. Termination of Participation
----------------------------
Participation in the PLAN ends as of the date that a participant ceases to
be an ELIGIBLE EMPLOYEE. Although a former participant may elect to have
an account balance held in the PLAN under Section 19 after participation
ends, a former participant may not contribute to the PLAN, except that
contributions to the PLAN will be accepted with respect to retroactive wage
payments. A former
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<PAGE>
participant who has an account balance in the PLAN may make withdrawals
from the account balance, and transfer from one or more FUNDS to another
FUND or FUNDS pursuant to the terms of the PLAN.
Upon the death of a participant, the PLAN ADMINISTRATOR shall distribute
the participant's account balance to the participant's BENEFICIARY within a
reasonable time but not later than 60 days after receipt of a completed
withdrawal form or 180 days after the PLAN ADMINISTRATOR receives NOTICE of
the participant's death. If the BENEFICIARY does not complete a withdrawal
form within the time periods set forth above, the distribution shall be in
cash and paid directly to the BENEFICIARY.
19. Distribution of Plan Benefits
-----------------------------
(a) Upon termination of participation, a distribution shall be made of the
balances allocated to a participant's accounts if the value of the
participant's account is $3,500 or less. Such distribution shall be
made no later than the 60th day following the close of the PLAN YEAR
in which participation terminates, unless the participant elects to
receive distribution at an earlier date. If the value of a
participant's account exceeds $3,500, distribution will be made upon
receipt by the PLAN ADMINISTRATOR of the written distribution request
of the participant. Distribution will therefore be made within 60
days of the receipt of such distribution request. Any provision of
the PLAN notwithstanding, if participation continues beyond the end
of the YEAR in which the participant attains age 70-1/2, distribution
of the participant's entire interest in the PLAN shall be made no
later than April 1 of the YEAR following the YEAR in which the
participant attains age 70-1/2.
All distributions due under the PLAN shall be payable only out of the
PLAN's assets as directed by the ADMINISTRATOR. Unless a cash
distribution is requested the TRUSTEE will distribute a certificate
for the whole shares of COMPANY STOCK, the United States BONDS, and
the TRUSTEE'S check for the then current value of all other UNITS
credited to the participant's account, plus any uninvested cash.
Alternatively, at the direction of the participant, FUND UNITS other
than U.S. SAVINGS BONDS UNITS may be transferred to the COMPANY STOCK
FUND pursuant to Section 14 and distribution will be made in whole
shares of COMPANY STOCK.
If a participant elects a cash distribution, upon receipt of the
appropriate Form requesting such distribution, the TRUSTEE will
distribute the then current value of the INVESTMENT FUND UNITS and
uninvested cash. Until the TRUSTEE converts INVESTMENT FUND UNITS to
cash, all UNITS shall continue to share in investment gains and
losses. Distributions from the BOND FUND can only be made in United
States BONDS.
(b) Any provision of the PLAN notwithstanding:
Unless the participant otherwise elects, distribution to such
participant shall be made (or shall commence) not later than the 60th
day after the close of the PLAN YEAR in which occurs the latest of the
following events:
(1) The participant attains age 65;
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<PAGE>
(2) The participant attains the 10th anniversary of the date on which
he or she became a participant under the PLAN; or
(3) The participant's termination of employment with the EMPLOYER.
(c) Distributions hereunder will be made in accordance with Section
401(a)(9) of the CODE and the regulations thereunder, including
Treasury regulation Section 1.401(a)(9)-2, which are incorporated by
reference herein.
20. Direct Rollovers
----------------
Notwithstanding any provision of the PLAN to the contrary that would
otherwise limit a participant's election under this section, effective
January 1, 1993, a participant or BENEFICIARY who is a surviving spouse may
elect, at the time and in the manner prescribed by the PLAN ADMINISTRATOR,
to have any portion of an eligible rollover distribution, as defined below,
paid directly to an eligible retirement plan, as defined below, specified
by the participant or BENEFICIARY who is a surviving spouse in a direct
rollover. Any taxable portion of an eligible rollover distribution that
is not transferred directly to an eligible retirement plan will be subject
to mandatory federal income tax withholding.
(a) An eligible rollover distribution shall mean any distribution of all
or any portion of the balance to the credit of the participant, except
that an eligible rollover distribu tion does not include any
distribution that is one of a series of substantially equal periodic
payments (not less frequently than annually) made for the life (or
life expectancy) of the participant or the joint lives (joint life
expectancies) of the participant and his or her designated
BENEFICIARY, or for a specified period of 10 years or more; any
distribution to the extent such distribution is required under Section
401(a)(9) of the CODE; and the portion of any distribution that is not
includable in gross income (determined without regard to the
exclusion for net unrealized appreciation with respect to employer
securities).
(b) An eligible retirement plan shall mean an individual retirement
account described in Section 408(a) of the CODE, an individual
retirement annuity described in Section 408(b) of the CODE, an annuity
plan described in Section 403(a) of the CODE, or a qualified trust
described in Section 401(a) of the CODE, that accepts the
participant's eligible rollover distribution. However, in the case of
an eligible rollover distribution to the surviving spouse, an eligible
retirement plan is an individual retirement account or individual
retirement annuity.
ADMINISTRATIVE PROVISIONS
-------------------------
21. Company's Powers and Duties
---------------------------
The COMPANY, acting through its BOARD OF DIRECTORS or Executive Committee,
reserves to itself the exclusive power to amend, suspend or terminate the
PLAN as provided below and to appoint and remove from time to time:
(a) The individuals comprising the EMPLOYEE BENEFIT FINANCE COMMITTEE;
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(b) The individuals comprising the EMPLOYEE BENEFIT ADMINISTRATIVE
COMMITTEE; and
(c) The EMPLOYERS whose EMPLOYEES may participate in the PLAN.
All powers and duties not reserved to the COMPANY are delegated to the
EMPLOYEE BENEFIT FINANCE COMMITTEE and to the EMPLOYEE BENEFIT
ADMINISTRATIVE COMMITTEE. Action of either committee shall be by vote of a
majority of the members of the committee at a meeting, or in writing
without a meeting and evidenced by the signature of any member who is so
authorized by the committee. The COMPANY indemnifies each member of each
committee against any personal liability or expense arising out of any
action or inaction of the committee or of any member of the committee or of
such individual, except that due to his own willful misconduct.
22. Funding and Investment Provisions
---------------------------------
The EMPLOYEE BENEFIT FINANCE COMMITTEE appointed by the COMPANY'S BOARD OF
DIRECTORS to serve at its pleasure has the express powers and duties
described in this section.
(a) Appointments. The EMPLOYEE BENEFIT FINANCE COMMITTEE has the sole
power and duty from time to time to appoint and remove the TRUSTEE,
the INVESTMENT MANAGER, actuaries, accountants and such other advisors
and consultants as may be needed for the proper financial
administration and investment of the assets of the PLAN.
Supplementing such appointments, the EMPLOYEE BENEFIT FINANCE
COMMITTEE may enter into appropriate agreements with each TRUSTEE,
INVESTMENT MANAGER or other advisors appointed under this paragraph
and delegate to them appropriate powers and duties. The EMPLOYEE
BENEFIT FINANCE COMMITTEE may appoint and delegate to one or more
individuals the power and duty to handle the day-to-day financial
administration of the PLAN. Such individuals need not be members of
the committee and shall serve at the pleasure of the committee.
(b) Investment Policy. The funding policy is set forth in Sections 3 and
4. The EMPLOYEE BENEFIT FINANCE COMMITTEE has the sole power and duty
to establish the investment policy and to review and revise it from
time to time as the committee shall determine in its sole discretion.
A copy of the current investment policy will be available for
participants' review in the ADMINISTRATOR'S office. Any revision of
the investment policy shall not be an amendment of the PLAN.
23. Administration
--------------
The EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE, appointed by the COMPANY'S
BOARD OF DIRECTORS to serve at its pleasure, is the ADMINISTRATOR of the
PLAN and is responsible for the overall administration of the PLAN. The
ADMINISTRATOR has the sole power and duty to establish, and from time to
time revise, such rules and regulations as may be necessary to administer
the PLAN in a nondiscriminatory manner for the exclusive benefit of
participants and all other persons entitled to benefits under the PLAN.
The ADMINISTRATOR shall also maintain such records and make such
computations, interpretations and decisions as may be necessary or
desirable for the proper administration of the PLAN. The ADMINISTRATOR
shall maintain for participants' inspection copies of the
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PLAN, TRUST AGREEMENT, investment policy, each agreement with an INVESTMENT
MANAGER, the latest annual report, PLAN description and summary description
and any amendments or changes in any of these documents. On written
request, participants may obtain from the ADMINISTRATOR a copy of any of
these documents at a cost established by the ADMINISTRATOR from time to
time.
The ADMINISTRATOR may appoint and delegate to one or more individuals the
power and duty to handle the day-to-day administration of the PLAN. Such
individuals need not be members of the committee and shall serve at the
pleasure of the committee.
The EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE shall serve as the final
review committee under the PLAN, to determine conclusively for all parties
any and all questions arising from the administration of the PLAN and
shall have sole and complete discretionary authority and control to manage
the operation and administration of the PLAN, including, but not limited
to, the determination of all questions relating to eligibility for
participation and benefits, interpretation of all PLAN provisions,
determination of the amount and kind of benefits payable to any participant
or BENEFICIARY, and construction of disputed or doubtful terms. Such
decisions shall be conclusive and binding on all parties and not subject to
further review.
24. Claims and Appeals Procedure
----------------------------
If a claim is denied in whole or in part, the ADMINISTRATOR shall furnish
to the claimant a written notice setting forth:
(a) Specific reason(s) for the denial,
(b) The PLAN provision(s) on which the denial is based,
(c) A description of any material or information, if any, necessary for
the claimant to perfect the claim, and an explanation of why such
material or information is necessary, and
(d) Information concerning the steps to be taken if claimant wishes to
submit a claim for review.
The above information shall be furnished to the claimant within 90 days
after the claim is received by the ADMINISTRATOR.
If a claimant is not satisfied with the written NOTICE described in the
preceding paragraph, such claimant may request a full and fair review by so
notifying the ADMINISTRATOR in writing within 90 days after receiving such
notice. If a review is requested the claimant shall also be entitled, upon
written request, to review pertinent documents and to submit issues and
comments in writing. The EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE shall
furnish the claimant with a written final decision within 60 days after
receipt of the request for review.
25. Qualified Domestic Relations Orders
-----------------------------------
The EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE shall apply the provisions of
this section with regard to a Domestic Relations Order (as defined below)
to the extent not inconsistent with Section 414(p) of the CODE.
The EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE shall establish procedures,
consistent with Section 414(p) of the CODE, to determine the qualified
status of any Domestic Relations Order, to
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administer distributions under any Qualified Domestic Relations Order (as
defined below), and to provide to the Participant and the Alternate
Payee(s) (as defined below) all notices required under Section 414(p) of
the CODE with respect to any Domestic Relations Order.
Within a reasonable period of time after the receipt of a Domestic
Relations Order (or any modification thereof), the EMPLOYEE BENEFIT
ADMINISTRATIVE COMMITTEE shall determine whether such order is a Qualified
Domestic Relations Order.
For purposes of this section:
(a) Alternate Payee shall mean any spouse, former spouse, child, or other
dependent of a participant who is recognized by a Domestic Relations
Order as having a right to receive all, or a portion of, the benefits
payable under the PLAN with respect to such Participant.
(b) Domestic Relations Order shall mean any judgment, decree, or order
(including approval of a property settlement agreement) which:
(1) relates to the provision of child support, alimony payments, or
marital property rights to a spouse, former spouse, child, or
other dependent of a participant; and
(2) is made pursuant to a state domestic relations law (including a
community property law).
(c) Qualified Domestic Relations Order shall mean a Domestic Relations
Order which meets the requirements of Section 414(p)(1) of the CODE.
26. Lost Participant or Beneficiary
-------------------------------
If, after three years, the ADMINISTRATOR cannot locate a participant or
BENEFICIARY who is entitled to a distribution from an account, the UNITS,
cash or COMPANY stock in the account shall be applied to reduce the amount
of future EMPLOYER CONTRIBUTIONS payable to the PLAN. A participant or
BENEFICIARY who is entitled to a distribution from an account which has
previously been applied to reduce EMPLOYER CONTRIBUTIONS under this Section
24 shall, upon filing a written claim, have the account reinstated in full
and upon such reinstatement shall receive a distribution of the balance in
the reinstated account, with interest at the prevailing legal rate accrued
from the date his account was applied to reduce EMPLOYER CONTRIBUTIONS.
27. Benefits Are Not Assignable
---------------------------
Except as may be required by law, a participant's interest in the PLAN and
that of a participant's BENEFICIARY or spouse shall not be subject in any
manner to assignment, anticipation, alienation, sale, transfer, pledge,
encumbrance or charge, whether voluntary or involuntary, and any attempt to
so assign, anticipate, sell, transfer, pledge, encumber or charge the same
shall be void.
28. Facility of Payment
-------------------
If the ADMINISTRATOR determines that any individual entitled to any payment
under the PLAN is physically or mentally incompetent and no guardian or
conservator has been appointed to receive such
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payment, the ADMINISTRATOR may cause all payments thereafter becoming due
to such individual to be applied for and on behalf of and for the benefit
of such individual. Payments made pursuant to this provision shall
completely discharge the EMPLOYER, the ADMINISTRATOR, the TRUSTEE and all
fiduciaries of all further responsibility with respect to such individual.
29. Future of the Plan
------------------
If participation in the PLAN is ended because a substantial portion of an
EMPLOYER'S property is sold or otherwise disposed of or because an EMPLOYER
withdraws from the PLAN, a participant's interest is determined in
accordance with the provisions of the next paragraphs as if the PLAN itself
has been terminated.
The COMPANY hopes and expects to continue this PLAN indefinitely, but
because future conditions cannot be foreseen, its BOARD OF DIRECTORS
necessarily reserves the right to amend or terminate the PLAN at any time.
However, no amendment, merger or consolidation of the PLAN may be made
which would reduce the right that any individual may then have with respect
to the PLAN'S assets then being held under the PLAN or permit any funds to
revert to an EMPLOYER or to be used for any purpose except for the
exclusive benefit of participants, spouses and BENEFICIARIES.
If the PLAN is terminated, all contributions to the PLAN shall cease but
the PLAN shall continue to operate in all other respects until all of the
TRUST assets have been distributed in accordance with the provisions of the
PLAN in effect on the date of its termination. In the event of a merger or
consolidation with, or transfer of assets or liabilities to any other plan,
if such other plan is then terminated, participant shall receive a benefit
immediately after such merger, consolidation, or transfer which is equal to
or greater than the benefit which participant would have received had the
PLAN terminated immediately prior to such merger, consolidation, or
transfer.
30. Definitions
-----------
Administrator: Employee Benefit Administrative Committee,
-------------
245 Market Street,
3d Floor, Mail Code N3X,
P.O. Box 770000, San Francisco,
California 94177
BIF: The Bond Index Fund.
---
Beneficiary: The person or persons entitled to receive any
-----------
distribution due under the Plan in the event of a
participant's death. For a married participant,
the participant's spouse shall automatically be
the Beneficiary unless the participant, with the
written consent of his spouse, elects to designate
another person or persons to be Beneficiary. The
consent of the spouse shall be in writing, shall
acknowledge the effect of the consent, and shall
be witnessed by a notary public or Plan
representative. A participant designates a
Beneficiary on a Designation of Beneficiary Form
available
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from the Plan Administrator. In the event an
unmarried participant does not designate a
Beneficiary, the participant's estate shall be
deemed to be the Beneficiary.
Board of Directors: The Board of Directors of Pacific Gas and Electric
------------------
Company.
Bond Fund: A fund invested in United States Savings Bonds.
---------
(See Section 8)
Bond Index Fund: A fund invested in marketable fixed-income
---------------
securities. (See Section 12)
Bonds: Series "EE" Savings Bonds issued by the United
-----
States Treasury. If the issuance of Series "EE"
Bonds is discontinued, Bonds will refer to any
other Bond issued by the United States Treasury
which the Employee Benefit Finance Committee
selects for purchase under the Plan.
Business Day: Any day that the New York Stock Exchange is
------------
open for business.
Calendar Quarter: The three month period commencing on January 1,
----------------
April 1, July 1 or October 1.
Code: The Internal Revenue Code of 1986, as amended from
----
time to time.
Company: Pacific Gas and Electric Company.
-------
Company Stock: The common stock issued by Company.
-------------
Company Stock Fund: A fund invested in the common stock issued by the
------------------
Company. (See Section 7)
Covered Compensation: Earnings from an Employer, including straight-time
--------------------
pay for hours worked, shift and nuclear premiums
at the straight-time rate, straight-time pay for
temporary upgrades, vacation pay (including
vacation pay upon retirement), inclement weather
pay, sick leave pay, holiday pay, differential
pay for military training, pay for other time off
with permission carrying full pay, temporary
compensation under any state Worker's
Compensation Law, payments under the Long Term
Disability Plan, or supplemental benefits for
industrial injury. Covered Compensation shall
not include pay or shift and nuclear premiums for
more than 40 hours per week, overtime bonuses,
vacation or holiday pay requests other special
fees or allowances,
-23-
<PAGE>
per diem allowances, payments, other than
temporary compensation, made under any
Workers' Compensation Law, voluntary wage
benefit or state disability plans, or any
other bene fit plan. For Plan Years beginning
after 1988 and before 1994, the maximum
Covered Compensation of each Employee that may
be taken into account each Plan Year shall not
exceed $200,000 (as adjusted by the Secretary
of the Treasury under Section 401(a)(17) of
the Code. For Plan Years beginning after 1993,
the maximum Covered Compensation of each
Employee that may be taken into account each
Plan Year shall not exceed $150,000 (as
adjusted by the Secretary of the Treasury
under Section 401(a)(17) of the Code). In
determining the Covered Compensation of a
Highly Compensated Employee for purposes of
this limitation, the rules of Section
414(q)(6) of the Code shall apply, except that
the term "family" shall include only the
spouse of the Employee and any lineal
descendants of the Employee who have not
attained age 19 before the close of the Year.
If the aggregate Covered Compensation of
family mem bers exceeds the applicable compen
sation limit as limited by Section 401(a)(17)
of the Code, then the amount of Covered
Compensation considered under the Plan for
each family member is proportionately reduced
so that the total equals the applicable
compensation limitation under Section
401(a)(17) of the Code.
DEF: The Diversified Equity Fund.
---
Diversified Equity Fund: A fund invested in a diversified portfolio of
-----------------------
securities. (See Section 9)
Eligible Employee: One entitled to become a contributing
-----------------
participant, provided, however, a "leased
employee," as defined in Section 414(n)(2) of
the Code shall not be entitled to become an
Eligible Employee.
Employee: An Employee of an Employer who is not
--------
represented by a union.
Employee Benefit The Employee Benefit Administrative
----------------
Administrative Committee: Committee referred to in Section 23.
------------------------
Employee Benefit Finance The Employee Benefit Finance
------------------------
Committee referred to in Section 22.
Committee:
---------
-24-
<PAGE>
Employer: Pacific Gas and Electric Company,
--------
Pacific Service Employees Associa tion, and
any other company, association, or credit
union designated by the Board of Directors as
eligible to participate in this Plan as an
Employer.
Employer Contributions: Any contributions to the Plan by Company.
----------------------
FlexDollars: Amounts which a participant elects pursuant
-----------
to the Company's Flex Plan to contribute as
(S) 401(k) Contributions. Rules governing
FlexDollars are contained in the Company's
Flex Plan; rules governing the treatment of
FlexDollars under this Plan are contained in
Subsection 3(b).
Fund: The Company Stock Fund, the U.S. Bond Fund,
----
the Diversified Equity Fund, the Guaranteed
Income Fund, the Bond Index Fund, the Stock
and Bond Fund, and the Utility Stock Fund, or
any of them.
GIF: The Guaranteed Income Fund.
---
Guaranteed Income Fund: A fund invested in fixed rate, fixed term
----------------------
contracts. (See Section 11)
Highly Compensated: Whether an Eligible Employee is Highly
------------------
Compensated shall be determined using the
simplified method under Code Section
414(q)(12) as described in applicable
Treasury regulations or other guidance issued
by the Internal Revenue Service.
Investment Fund: The Company Stock Fund, the U.S. Bond Fund,
---------------
the Diversified Equity Fund, the Guaranteed
Income Fund, the Bond Index Fund, the Stock
and Bond Fund, and the Utility Stock Fund, or
any of them.
Investment Manager: 1. Diversified Equity Fund.
------------------
J. P. Morgan, 522 Fifth Avenue, New
York, NY 10036, or such other firm or
individual as may be selected from time
to time by the Employee Benefit Finance
Committee.
2. Guaranteed Income Fund.
PRIMCO Capital Management, Inc., 101
South Fifth Street, Louisville, Kentucky
40202, or such other firm or individual
as may be selected from time to time by
the Employee Benefit Finance Committee.
-25-
<PAGE>
3. Bond Index Fund.
The Vanguard Group, Vanguard Financial
Center, Valley Forge, Pennsylvania
19482, or such other firm or
individual as may be selected from
time to time by the Employee Benefit
Finance Committee.
4. Stock and Bond Fund.
Columbia Trust Company, 1301 S.W.
Fifth Avenue, P.O. Box 1350, Portland,
Oregon 97207, or such other firm or
individual as may be selected from
time to time by the Employee Benefit
Finance Committee.
5. Utility Stock Fund.
Wells Fargo Nikko Investment Advisors,
45 Fremont Street, San Francisco,
California 94105, or such other firm
or individual as may be selected from
time to time by the Employee Benefit
Finance Committee.
Long Term Disability Plan: Part B of the Group Life Insurance and Long
-------------------------
Term Disability Plan of Pacific Gas and
Electric Company as amended January 1, 1991.
Non-(S) 401(k) Contributions: Employee contributions to the Plan as
----------------------------
described in Subsection 3(c) and all
Employee Contributions made prior to October
1, 1984. Non-(S) 401(k) Contributions are
made with after-tax dollars.
Notice: Any method of communication, whether
------
electronic, telephonic, written or other,
provided that the Plan Administrator has
communicated in writing to participants any
such method and its format as appropriate
and acceptable.
Plan: This Company's Savings Fund Plan for Non-
-----
Union
Employees, as amended, revised and set forth
herein.
Retirement Plan: The Company's Retirement Plan as revised
---------------
from time to time.
SBF: The Stock and Bond Fund.
---
Savings Fund Plan Office: 245 Market Street, 3d Floor
------------------------
Mail Code N3X
P.O. Box 770000
San Francisco, CA 94177
(S) 401(k) Contributions: Amounts deferred from a Participant's
------------------------
Covered Compensation as described in
Subsection 3(a).
-26-
<PAGE>
(S) 401(k) Contributions are made with pre-
tax dollars.
Service: The period of time commencing with
-------
the first day of employment or reemployment
for an Employer and ending on participant's
Severance from Service Date. If an Employee
with less than one year of Service is
rehired after a period of severance which
extends for 12 months or more, the Employee
shall be treated as a new Employee for all
purposes, and the Service and compensation
before the Severance from Service Date shall
not be recognized for any purpose of the
Plan. Participants who have a period of
severance after they have completed at least
one year of Service and who are later
rehired, immediately become Eligible
Employees entitled to contribute in
accordance with their total years of
Service.
Service shall also include all years of
Service with:
(a) Any corporation which is a member of
the same controlled group of
corporations as the Company or of any
other Employer (within the meaning of
Section 414(b) of the Code);
(b) Any trade or business under the common
control of the Company or of any other
Employer (within the meaning of
Section 414(c) of the Code);
(c) Any service organization which is a
member of the same affiliated service
group as the Company or of any other
Employer (within the meaning of
Section 414(m) of the Code).
Severance From Service A. The date on which an Employee
----------------------
Date: quits, retires, is discharged or
----
dies; or
B. The first anniversary of the first
date of a period in which a
participant remains absent from work
for an Employer for any reason other
than resignation, retirement,
discharge, or death.
C. For the purpose of determining the
Severance from Service Date, the
following periods shall not be
considered as
-27-
<PAGE>
absences from work for an Employer:
(1) Absence on a leave of absence
authorized by an Employer.
(2) Absence because of illness or
injury as long as the participant
is entitled to receive sick leave
pay or is entitled to receive
benefits under the provisions of
the Voluntary Wage Benefit Plan,
a state disability plan, the
Long Term Disability Plan, or a
Workers' Compensation Law.
(3) Absence for military service or
service in the Merchant Marines
so long as reemployment rights
are protected by law.
(4) Absence caused by layoff for lack
of work of less than 12
continuous months for a
Participant who has less than
five years of service, or 24
continuous months for a
Participant who has five or more
years of ser vice.
Stock and Bond Fund: A fund invested in U.S. equities and U.S. fixed-
-------------------
income investments. (See Section 13)
Trust: The Trust into which all contributions are
-----
deposited and from which all distributions are
made.
Trustee: State Street Bank and Trust Company, 225 Franklin
-------
Street, Boston, Massachusetts 02101, or such
other bank or trust company selected by the
Employee Benefit Finance Committee which agrees to
act as Trustee or successor Trustee of the Trust
pursuant to the Trust Agreement.
Trust Agreement: The agreement between the Company and the Trustee.
---------------
Unit: A measurement of participant's interest in the
----
Investment Funds. For purposes of the Bond Fund,
a unit shall be a United States Bond.
-28-
<PAGE>
USF: The Utility Stock Fund.
---
Utility Stock Fund: An index fund invested in common stocks
------------------
of companies engaged in the generation,
transmission or distribution of electric energy
(See Section 10).
Year: The calendar year beginning January 1 and ending
----
December 31.
-29-
<PAGE>
SPECIAL PROVISION A
TOP HEAVY PROVISIONS
--------------------
(a) General Rule
------------
For any PLAN YEAR for which this PLAN is a "top-heavy plan" as defined in
subsection (g) below, any other provisions of this PLAN to the contrary
notwithstanding, this PLAN shall be subject to the following provisions:
(1) The minimum contribution provisions of subsection (b).
(2) The limitation on contribution set by subsection (d).
(b) Minimum Contribution Provisions
-------------------------------
Each participant who (i) is a non-key EMPLOYEE (as defined in sub-section
(i) below) and (ii) is employed on the last day of the PLAN YEAR, even if such
individual is excluded from the PLAN for failing to make mandatory contributions
to the PLAN, shall be entitled to have contributions allocated to his account of
not less than three percent (the "minimum contribution percentage") of the
participant's compensation (within the meaning of Section 415 of the CODE). In
determining the minimum contribution percentage to be allocated to an EMPLOYEE'S
account, a key EMPLOYEE'S (S) 401(k) CONTRIBUTIONS shall be considered as an
EMPLOYER CONTRIBUTION. However, (S) 401(k) CONTRIBUTIONS on behalf of EMPLOYEES
other than key EMPLOYEES will not be considered as EMPLOYER CONTRIBUTIONS.
The minimum contribution percentage set forth above shall be reduced for
any PLAN YEAR in which the percentage at which contributions are made (or
required to be made) under the PLAN for the PLAN YEAR for the key EMPLOYEE for
whom such percentage is the highest for such PLAN YEAR is less than three
percent. For this purpose, the percentage with respect to a key EMPLOYEE (as
defined in subsection (g) below) shall be determined by dividing the
contributions (including forfeitures and (S) 401(k) CONTRIBUTIONS) made for such
key EMPLOYEES by so much of his total compensation for the PLAN YEAR.
Contributions taken into account under the immediately preceding sentence
shall include contributions under this PLAN and under all other defined
contribution plans required to be included in an aggregation group (as defined
in subsection (f)(2) below) but shall not include any plan required to be
included in such aggregation group if such plan enables a defined contribution
plan required to be included in such group to meet the requirements of the CODE
prohibiting discrimination as to contributions or benefits in favor of EMPLOYEES
who are officers, shareholders or the highly-compensated or prescribing the
minimum participation standards.
Contributions taken into account under this subsection (b) shall not
include any contributions under the Social Security Act or any other Federal or
State law.
(c) Limitations on Contributions
----------------------------
In the event that the EMPLOYER also maintains a defined benefit PLAN
providing benefits on behalf of participants in this PLAN, one of the two
following provisions shall apply:
(1) If for the PLAN YEAR this PLAN would not be a "top-heavy PLAN" as
defined in subsection (a)(2) above if "90 percent"
-30-
<PAGE>
were substituted for "60 percent," then subsection (b) shall apply for
such PLAN YEAR as if amended so that "four percent" were substituted
for "three percent".
(2) If for the PLAN YEAR this PLAN would continue to be a "top-heavy PLAN"
as defined in subsection (f) below if "90 percent" were substituted
for "60 percent," then the denominator of both the defined
contribution PLAN fraction and the defined benefit PLAN fraction shall
be calculated as set forth in Section 415 (e) of the CODE for the
limitation year ending in such PLAN YEAR by substituting "1.0" for
"1.25" in each place such figure appears, except with respect to any
individual for whom there are no EMPLOYER CONTRIBUTIONS allocated or
any accruals for such individual under the defined benefit PLAN.
Furthermore, the transitional rule set forth in Section 415 (e) of the
CODE shall be applied by substituting "$41,500" for "$51,875".
(d) Coordination with Other Plans
-----------------------------
In the event that another defined contribution or defined benefit plan
maintained by the EMPLOYER provides contributions or benefits on behalf of
participants in this PLAN, such other plan shall be treated as a part of this
PLAN pursuant to applicable principles (such as Rev. Rul. 81-202 or any
successor ruling or regulations) in determining whether this PLAN satisfies the
requirements of subsection (b), (c) and (d). Such determination shall be made
upon the advice of counsel by the EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE.
(e) Top-Heavy Plan Definition
-------------------------
This PLAN shall be a "top-heavy plan" for any PLAN YEAR if, as of the
determination date (as defined in subsection (f)(1) below), the aggregate of the
accounts under the PLAN and any required aggregation group or permissive
aggregation group of plans for participants (including former participants) who
are key EMPLOYEES (as defined in subsection (g) below but not including accounts
of individuals excluded under section 416(g)(4)(E) of the CODE) exceeds 60
percent of the present value of the aggregate of the accounts for all
participants, excluding former key EMPLOYEES, or if this PLAN is required to be
in an aggregate group (as defined in subsection (f)(3) below) which for such
PLAN YEAR is a top-heavy group (as defined in subsection (f)(4) below).
(1) "Determination date" means for any PLAN YEAR the last day of the
immediately preceding PLAN YEAR.
(2) "Valuation date" means the last day of each PLAN YEAR.
(3) "Aggregation group" means the group of plans, if any, that includes
both the group of plans that are required to be aggregated and the
group of plans that are permitted to be aggregated.
(A) The group of plans that are required to be aggregated (the
"required aggregation group") includes
(i) Each plan of the EMPLOYER (as defined in subsection (i)
below) in which a key EMPLOYEE is a participant, including
collectively-bargained plans, and
(ii) Each other plan, including collectively-bargained plans of
the EMPLOYER (as defined in subsection (i) below) which
enables a plan in
-31-
<PAGE>
which a key EMPLOYEE is a participant to meet the
requirements of the CODE prohibiting discrimination as to
contributions or benefits in favor of EMPLOYEES who are
officers, shareholders or the highly-compensated or
prescribing the minimum participation standards.
(B) The group of plans that are permitted to be aggregated (the
"permissive aggregation group") includes the required aggregation
group plus one or more plans of the EMPLOYER (as defined in
subsection (i) below) that is not part of the required
aggregation group and that the EMPLOYEE BENEFIT ADMINISTRATIVE
COMMITTEE certifies as constituting a plan within the permissive
aggregation group. Such plan or plans may be added to the
permissive aggregation group only if, after the addition, the
aggregation group as a whole continues not to discriminate as to
contributions or benefits in favor of officers, shareholders or
the highly-compensated and to meet the minimum participation
standards under the CODE.
(4) "Top-heavy group" means the aggregation group, if as of the applicable
determination date, the sum of the present value of the cumulative
accrued benefits for key EMPLOYEES under all defined benefit plans
included in the aggregation group plus the aggregate of the accounts
of key EMPLOYEES under all defined contribution plans included in the
aggregation group exceeds 60% of the sum of the present value of the
cumulative accrued benefits for all EMPLOYEES, excluding former key
EMPLOYEES, under all such defined benefit plans plus the aggregate
accounts for all EMPLOYEES, excluding former key EMPLOYEES, under such
defined contribution plans. If the aggregation group that is a top-
heavy group is a required aggregation group, each plan in the group
will be top heavy. If the aggregation group that is a top-heavy group
is a permissive aggregation group, only those plans that are part of
the required aggregation group will be treated as top-heavy. If the
aggregation group is not a top-heavy group, no plan within such group
will be top-heavy.
(5) In determining whether this PLAN constitutes a "top-heavy plan," the
EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE (or its agent) shall make
the following adjustments in connection therewith:
(A) When more than one plan is aggregated, the EMPLOYEE BENEFIT
ADMINISTRATIVE COMMITTEE shall determine separately for each plan
as of each plan's determina tion date the present value of the
accrued benefits or account balance. The results shall then be
aggregated separately by adding the results of each plan as of
the determination dates for such plans that fall with the same
calendar year.
(B) In determining the present value of the cumulative accrued
benefit or the amount of the account of any EMPLOYEE, such
present value or account shall include the amount in dollar value
of the aggregate distributions made to such EMPLOYEE under the
applicable plan during the five-year period ending on the
determination date, unless reflected in the value of the accrued
benefit or account balance as of the most recent
-32-
<PAGE>
valuation date. Such amounts shall include distributions to
EMPLOYEES which represented the entire amount credited to their
accounts under the applicable plan.
(C) Further, in making such determination, in any case where an
individual is a "non-key EMPLOYEE" as defined in subsection (h)
below, with respect to an applicable plan, but was a key EMPLOYEE
with respect to such plan for any prior PLAN YEAR, any accrued
benefit and any account of such EMPLOYEE shall be altogether
disregarded. For this purpose, to the extent that a key EMPLOYEE
is deemed to be a key EMPLOYEE if he or she met the definition of
key EMPLOYEE within any of the four preceding PLAN YEARS, this
provision shall apply following the end of such period of time.
(f) Key EMPLOYEE
------------
The term "key EMPLOYEE" means any EMPLOYEE or former EMPLOYEE under this
PLAN who, at any time during the PLAN YEAR containing the determination date or
during any of the four preceding PLAN YEARS, is or was one of the following:
(1) An officer of the EMPLOYER having an annual compensation greater than
50 percent of the amount in effect under Section 415(b)(1)(A) of the
CODE for such PLAN YEAR. Whether an individual is an officer shall be
determined by the EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE on the
basis of all the facts and circumstances, such as an individual's
authority, duties and term of office, not on the mere fact that the
individual has the title of officer. For any such PLAN YEAR, these
shall be treated as officers no more than the lesser of:
(A) 50 EMPLOYEES, or
(B) the greater of three EMPLOYEES or 10 percent of the EMPLOYEES.
For this purpose, if there are more than 50 officers, the 50 highest-
paid officers shall be the key EMPLOYEES.
(2) One of the ten EMPLOYEES owning (or considered as owning, within the
meaning of the constructive ownership rules of the CODE) the largest
interests in the EMPLOYER (as defined in subsection (i)). An EMPLOYEE
who has some ownership interest is considered to be one of the top ten
owners unless at least ten other EMPLOYEES own a greater interest than
that EMPLOYEE. However, an EMPLOYEE will not be considered a top ten
owner for a PLAN YEAR if the EMPLOYEE earns an amount equal to or less
than the maximum dollar limitation on contributions and other annual
additions to a participant's account in a defined contribution PLAN
under the CODE as in effect for the calendar year in which the
determination date falls.
(3) Any person who owns (or is considered as owning within the meaning of
the constructive ownership rules of the CODE) more than five percent
of the outstanding stock of the EMPLOYER or stock possessing more than
five percent of the combined total voting power of all stock of the
EMPLOYER.
(4) A one percent owner of the EMPLOYER having an annual compensation
from the EMPLOYER of more than $150,000, and who owns
-33-
<PAGE>
more than one percent of the outstanding stock of the EMPLOYER or
stock possessing more than one percent of the combined total voting
power of all stock of the EMPLOYER. For purposes of this subsection,
compensation means all items includable as compensation for purposes
of applying the limitations on contributions and other annual
additions to a participant's account in a defined contribution plan
and the maximum benefit payable under a defined benefit plan under the
CODE.
For purposes of parts (1), (2), (3) and (4) of this definition, a
BENEFICIARY of a key EMPLOYEE shall be treated as a key EMPLOYEE. For
purposes of parts (3) and (4), each EMPLOYER is treated separately
(without regard to the definition in subsection (i)) in determining
ownership percentages; but, in determining the amount of
compensation, the definition of EMPLOYER in subsection (i) is taken
into account.
(g) Non-key EMPLOYEE
----------------
The term "non-key EMPLOYEE" means any EMPLOYEE (and any beneficiary or an
EMPLOYEE) who is not a key EMPLOYEE.
(h) Employer
--------
The term "employer" as defined in Section 30 of this PLAN.
-34-
<PAGE>
-------------------------
I, Leslie H. Everett, do hereby certify that I am the Corporate Secretary
of the PACIFIC GAS AND ELECTRIC COMPANY, a corporation organized and existing
under the laws of the State of California, and that the above and foregoing is a
full, true and correct copy of the Pacific Gas and Electric Company SAVINGS FUND
PLAN FOR NON-UNION EMPLOYEES as the same exists at the date of this
certification.
WITNESS my hand and the seal of the said corporation hereunto affixed this
day of
Leslie H. Everett
Corporate Secretary of
PACIFIC GAS AND ELECTRIC COMPANY
-35-
<PAGE>
Exh.10.7
SHORT-TERM INCENTIVE PLAN
FOR OFFICERS OF
THE PACIFIC GAS AND ELECTRIC COMPANY
____________________________________
This is the controlling and definitive statement of the Short-Term
Incentive Plan for Officers ("PLAN"/1/) of the Pacific Gas and Electric Company
and participating subsidiaries, affiliates, and associations. The purpose of the
PLAN is to benefit ratepayers and shareholders by rewarding employees for
overall COMPANY performance and for UNIT and individual achievements. The PLAN,
as set forth herein, is effective January 1, 1996, and is an amended restated
version of the Performance Incentive Plan which was first adopted in 1983. The
COMPANY reserves the right to amend, suspend, or terminate the PLAN in its sole
discretion at any time.
ARTICLE I
DEFINITIONS
-----------
1.01 Committee shall mean the Nominating and Compensation Committee of the
---------
Board of Directors of the COMPANY.
1.02 Company shall mean the Pacific Gas and Electric Company, a California
-------
corporation.
1.03 Officer shall mean any officer of the COMPANY at the vice
-------
presidential level or above and the Controller, Treasurer, and Secretary, and
such other employees of the Company or of a subsidiary, affiliate, or
association as may be designated by the COMMITTEE.
1.04 Plan shall mean the Short-Term Incentive Plan for Officers, as set
----
forth herein and as may be amended from time to time.
1.05 Plan Administrator shall mean the Committee
------------------
or such individual or individuals as the Committee may appoint to handle the
day-to-day affairs of the PLAN and to issue the annual PLAN Administrative
Guidelines.
1.06 Plan Participant shall mean each individual who, under the PLAN
----------------
Administrative Guidelines adopted by the PLAN ADMINISTRATOR, is eligible to
receive a PLAN award for the YEAR.
____________________
/1/ Words in all capitals are defined in Article I.
<PAGE>
1.07 Unit shall mean each of the separate organizational units of the
----
COMPANY as defined by the Chief Executive Officer before the beginning of the
PLAN YEAR.
1.08 Year shall mean a calendar year.
----
ARTICLE II
ELIGIBILITY
-----------
2.01 At the beginning of each YEAR, the PLAN ADMINISTRATOR will issue PLAN
Administrative Guidelines which will set forth the criteria for receiving awards
under the PLAN. The PLAN Administrative Guidelines will contain rules for
determining PLAN eligibility including, but not limited to, eligibility for
individuals who are newly hired, promoted, on leaves of absence, deceased, or
retired. The PLAN Administrative Guidelines shall also specify the conditions
under which awards will be prorated and which elements of pay will be included
in the calculation of a PLAN Award. The PLAN Administrative Guidelines shall be
attached hereto and made a part hereof and shall be available for review at the
request of PLAN PARTICIPANTS.
ARTICLE III
ANNUAL PERFORMANCE MEASURES
---------------------------
3.01 Each YEAR the COMMITTEE shall determine the criteria used to measure
the COMPANY's annual performance. The COMMITTEE shall determine the performance
measures for the Chief Executive Officer for each YEAR. The Chief Executive
Officer, in conjunction with the senior officer of each UNIT, shall set the
performance measures for each UNIT for the YEAR. The Chief Executive Officer
shall determine the performance measures for those executive officers who are
not included in a UNIT. Performance measures for each YEAR shall be attached to
the PLAN and are made a part of hereof.
3.02 As soon as practicable after the beginning of each YEAR, the Chief
Executive Officer shall determine the individual performance measures for PLAN
PARTICIPANTS and shall assign weightings for each performance measure applicable
to each PARTICIPANT.
2
<PAGE>
3.03 Each YEAR the Board of Directors shall approve the individual target
participation rate for the Chief Executive Officer. The COMMITTEE shall
determine the annual individual target participation rates applicable to all
other PLAN PARTICIPANTS. A schedule of the individual target participation rates
for each YEAR shall be attached to the PLAN and are made a part hereof.
3.04 The COMMITTEE retains the right to adjust or modify any of the
performance measures to reflect extraordinary events which may affect the
COMPANY, or if in its sole opinion, application of any of the performance
measures substantially overstates or understates actual COMPANY performance.
ARTICLE IV
PLAN AWARDS
-----------
4.01 As soon as practicable after the end of the YEAR, the actual
performance of the COMPANY and, to the extent applicable, the UNIT and
individual performance will be measured against the appropriate performance
measures adopted for the YEAR.
4.02 The PLAN award for any PLAN PARTICIPANT will be the sum of the
amounts produced under Section 4.01 for each applicable performance measure,
further modified by the agreed-upon weightings assigned to each performance
measure. Individual awards under the PLAN will be made prior to the end of the
first quarter of the year.
4.03 The COMMITTEE retains the right to terminate the PLAN at any time
prior to the payment of any award which may be earned under the PLAN.
ARTICLE V
ADMINISTRATIVE PROVISIONS
-------------------------
5.01 Administration. The PLAN shall be administered by the PLAN
--------------
ADMINISTRATOR who shall have the authority to interpret the PLAN and make such
rules as it deems appropriate. The PLAN ADMINISTRATOR shall have the duty and
responsibility of maintaining records, making the requisite calculations, and
disbursing payments hereunder. The PLAN ADMINISTRATOR's interpretations,
determinations, rules, and calculations shall be final and binding on all
persons and parties concerned.
3
<PAGE>
EXHIBIT 10.8
THE PACIFIC GAS AND ELECTRIC COMPANY
RETIREMENT PLAN
<PAGE>
PART I
------
TABLE OF CONTENTS
-----------------
RETIREMENT PLAN
---------------
<TABLE>
<CAPTION>
Page
----
<S> <C> <C>
1. Introduction........................................................ 1
2. Eligibility and Participation....................................... 2
3. Service............................................................. 2
4. Break in Service and Reemployment................................... 2
5. Normal Retirement Date.............................................. 3
6. Basic Pension Benefit Formula....................................... 3
7. Early Retirement Pension Benefit Formula............................ 4
8. Pensions Where Employment Ends Before Age 55........................ 5
9. Deferred Retirement................................................. 6
10. Forms of Pension.................................................... 6
11. Spouse's Pension.................................................... 8
12. Withdrawal of Participant Contributions on Termination of Employment 9
13. Death Benefits...................................................... 9
14. Facility of Payment................................................. 9
15. Benefits Are Not Assignable......................................... 10
16. Employer Contributions.............................................. 10
17. Company's Powers and Duties......................................... 11
18. Funding and Investment Provisions................................... 11
19. Administration...................................................... 12
20. Claims Procedure.................................................... 12
21. Qualified Domestic Relations Orders................................. 13
22. Amendment, Termination, and Merger.................................. 13
23. Definitions and Cross-References.................................... 14
SPECIAL PROVISIONS A, B, C, D, E, F, G, H, I, J, K, M and N.............. 21-78
</TABLE>
<PAGE>
RETIREMENT PLAN
---------------
1. Introduction
------------
This is the controlling and definitive statement of the Pacific Gas
and Electric Company Retirement PLAN /1/ which, with certain exceptions,
-
is effective on and after January 1, 1996, for EMPLOYEES who are employed
by Pacific Gas and Electric Company and other EMPLOYERS.
This PLAN is a further revision of the PLAN, originally placed in
effect by the COMPANY January 1, 1937, which has been amended from time to
time in the intervening years. Rights of PARTICIPANTS in this PLAN will
not be less than rights of PARTICIPANTS under COMPANY'S PLAN as it existed
before 1996.
The purpose of this PLAN is to distribute the corpus and income of
accumulated PENSION trust funds in accordance with the PLAN. Under no
circumstances shall contributions or benefits under this PLAN discriminate
in favor of a "highly compensated EMPLOYEE," as that term is defined using
the simplified method under CODE Section 414(q)(12) as described in
applicable Treasury regulations or other guidance issued by the Internal
Revenue Service. Forfeitures of nonvested accrued benefits under the PLAN
shall not be applied to increase benefits any EMPLOYEE could otherwise
receive under the terms of the PLAN.
Except for pension adjustments provided for in Special Provision G,
PARTICIPANTS who retire or terminate employment before the effective date
of any amendment are not affected or benefited by such amendments.
Since final regulations governing many statutory requirements of the
Employee Retirement Income Security Act of 1974 (ERISA) have not yet been
issued, the COMPANY reserves the right to retroactively modify the final
language of the revised PLAN to conform to these requirements.
As provided for in Section 414(f) of the CODE, the PLAN has elected to
be treated as a single employer plan.
This PLAN consists of Part I and Part II. Part I applies solely to
EMPLOYEES not covered by a collective bargaining agreement, and Part II
applies solely to EMPLOYEES whose benefits are the subject of collective
bargaining with a union representing EMPLOYEES of the COMPANY. /2/
-
__________________
/1/ Words in all capitals are defined in Section 23.
-
/2/ For PLAN YEARS prior to January 1, 1995, only management EMPLOYEES were
-
PARTICIPANTS in Part I of the PLAN; prior to January 1, 1995, weekly-paid,
non-union EMPLOYEES participated in Part II.
-1-
<PAGE>
PART I
------
2. Eligibility and Participation
-----------------------------
An EMPLOYEE automatically becomes a PARTICIPANT in the PLAN on the
first day of work for an EMPLOYER, and participation continues until the
PARTICIPANT's SERVICE is terminated.
3. Service
-------
(a) The SERVICE of a PARTICIPANT on any date shall consist of the sum
of the following:
(1) Any CREDITED SERVICE as of December 31, 1975, as defined
under the PLAN prior to the January 1, 1976, amendment and reproduced in
Special Provision F, and
(2) The elapsed time from the first day of employment with an
EMPLOYER (but not earlier than January 1, 1976) to the PARTICIPANT's
SEVERANCE FROM SERVICE DATE, excluding any periods of BREAK IN SERVICE and
any SERVICE cancelled by the operation of Sections 4 and 13.
(b) For EMPLOYEES who attain PART-TIME status at any time on or after
January 1, 1991, service benefit accruals will be based on the following
SERVICE:
(i) Paragraph (a) of this Section will apply to all SERVICE
prior to January 1, 1991;
(ii) All SERVICE after December 31, 1990 in which the EMPLOYEE is
designated as a PART-TIME EMPLOYEE shall be prorated for
purposes of benefit accruals based on the ratio of actual
straight-time hours worked in the calendar year to the full-
time hourly equivalent (2,080 per calendar year) rounded to
the nearest month.
4. Break in Service and Reemployment
---------------------------------
Upon reemployment with an EMPLOYER after a BREAK IN SERVICE, prior
SERVICE earned under the PLAN will be treated for eligibility, vesting
and/or benefit accrual as follows:
(a) If a PARTICIPANT has a BREAK IN SERVICE starting on or after
January 1, 1989, the SERVICE of such PARTICIPANT prior to the BREAK IN
SERVICE will be cancelled unless such prior SERVICE was at least five years
or, in the event that such prior SERVICE was less than five years, if the
period of the BREAK IN SERVICE was less than the prior SERVICE.
(b) If a PARTICIPANT has a BREAK IN SERVICE starting on or after
January 1, 1985, but before January 1, 1989, the SERVICE of such
PARTICIPANT prior to the BREAK IN SERVICE will be cancelled unless such
prior SERVICE was at least 10 years or, in the event that such prior
SERVICE was less than 10 years, such prior SERVICE will be cancelled if the
period of the BREAK IN SERVICE is equal to or exceeds the greater of (i)
five years or (ii) the period of SERVICE prior to the BREAK IN SERVICE.
(c) If a PARTICIPANT has a BREAK IN SERVICE starting on or after
January 1, 1976, but before January 1, 1985, the SERVICE of such
PARTICIPANT prior to the BREAK IN SERVICE will be cancelled unless such
prior SERVICE was at least 10 years or, in the event that such prior
SERVICE was less than 10 years, if the period of the BREAK IN SERVICE
-2-
<PAGE>
was less than the prior SERVICE. If the PARTICIPANT's contributions to the
PLAN have been withdrawn, restoration of the PARTICIPANT's prior SERVICE
will be in accordance with the provisions of Section 12.
(d) EMPLOYEES who were PARTICIPANTS in the PLAN prior to January 1,
1976, and whose prior SERVICE would not be restored under the provisions of
(a) of this Section, but would have been restored under the provisions of
the PLAN prior to the January 1, 1976, amendment, shall continue to be
eligible to have their prior SERVICE restored under the rules of the PLAN
prior to the January 1, 1976, amendment. Such rules are set forth in
Special Provision E.
5. Normal Retirement Date
----------------------
NORMAL RETIREMENT DATE is the first day of the month following a
PARTICIPANT's 65th birthday.
6. Basic Pension Benefit Formula
-----------------------------
A PARTICIPANT whose SERVICE continues to NORMAL RETIREMENT DATE or
beyond /3/ is entitled to a BASIC PENSION payable on ACTUAL RETIREMENT DATE
-
and on the first day of each month thereafter as long as the PARTICIPANT
lives. /4/
-
(a) The monthly amount of the BASIC PENSION for a PARTICIPANT whose
entire SERVICE is accrued as a PARTICIPANT in Part I of this PLAN shall be
a monthly amount equal to 1.6 percent of the PARTICIPANT's average BASIC
MONTHLY SALARY for the final 36 consecutive months of SERVICE, /5/
-
multiplied by the number of whole and fractional years of SERVICE. The
amount so determined shall take the place of all other retirement income to
which a PARTICIPANT might otherwise have been entitled under any suspended
plan of an EMPLOYER or predecessor company.
(b) The monthly amount of the BASIC PENSION for a PARTICIPANT whose
classification is changed and who has accrued SERVICE under both Part I and
Part II of this PLAN shall be the larger of (1) or (2) below:
(1) The amount produced by computing all years of SERVICE
pursuant to the applicable formula for the new
classification.
(2) The amount equal to the sum of (i) a pension benefit for
SERVICE prior to the change in classification, computed
pursuant to the applicable formula for the PARTICIPANT's old
classification in effect at the time of the change in
classification; and (ii) a pension benefit for SERVICE after
the change in classification, computed pursuant to the
formula applicable for
_________________
/3/ See Section 9 for the conditions under which this may occur.
-
/4/ See Section 10 for the conditions under which other forms of pension may
-
be substituted for the BASIC PENSION.
/5/ A married PARTICIPANT'S EARLY RETIREMENT PENSION shall be in the form of a
-
MARITAL PENSION, computed as provided in Section 10b. In lieu of a MARITAL
PENSION, a PARTICIPANT may elect any of the alternative forms of the EARLY
RETIREMENT PENSION described in Section 10b. and subject to the rules
contained therein.
-3-
<PAGE>
the PARTICIPANT's new job classification. Each portion of
the BASIC PENSION calculated under (i) and (ii) above shall
be subject to all the applicable reductions imposed in PART
I and PART II with respect to age and early retirement,
joint pensions, marital pensions, and the election of an
alternative spouse's pension.
(c) The monthly amount of the BASIC PENSION for a PARTICIPANT
receiving LONG TERM DISABILITY PLAN benefits on ACTUAL RETIREMENT DATE
shall be computed under (1) or (2) below, as applicable:
(1) For EMPLOYEES receiving LONG TERM DISABILITY PLAN benefits
on January 1, 1988, a monthly benefit equal to 1.6 percent
of the larger of (i) the PARTICIPANT'S BASIC MONTHLY SALARY
for the last month of active SERVICE or (ii) the
PARTICIPANT'S LONG TERM DISABILITY PLAN benefit for the
month immediately preceding ACTUAL RETIREMENT DATE. The
result obtained in (i) or (ii) shall be multiplied by the
number of whole or fractional years of SERVICE.
(2) For EMPLOYEES who start receiving LONG TERM DISABILITY PLAN
benefits after January 1, 1988, a monthly benefit equal to
1.6 percent of the larger of (i) the average BASIC MONTHLY
SALARY for the final consecutive 36 months of active SERVICE
or (ii) the PARTICIPANT'S LONG TERM DISABILITY PLAN benefit
for the month immediately preceding ACTUAL RETIREMENT DATE.
The result obtained in (a) or (b) shall be multiplied by the
number of whole and fractional years of SERVICE.
7. Early Retirement Pension Benefit Formula
----------------------------------------
If a PARTICIPANT's SERVICE ends after the first day of the month
following said PARTICIPANT's 55th birthday, and before NORMAL RETIREMENT
DATE or death, the PARTICIPANT shall elect to receive either:
a. A BASIC PENSION computed as provided in Section 6, or a MARITAL
PENSION computed as provided in Section 10b., whichever is
applicable
b. An EARLY RETIREMENT PENSION with payments to begin on the
PARTICIPANT's EARLY RETIREMENT DATE and to continue on the first day
of each month thereafter so long as PARTICIPANT lives. EARLY
RETIREMENT DATE is the date selected by the PARTICIPANT for
commencement of payment of retirement benefits. This date must be the
first day of any month after the termination of SERVICE and before the
PARTICIPANT's 65th birthday. To elect an EARLY RETIREMENT PENSION,
PARTICIPANT must notify the EMPLOYER in writing at least 30 days
before the EARLY RETIREMENT DATE the PARTICIPANT selects. The monthly
amount of the PARTICIPANT's EARLY RETIREMENT PENSION /6/ will be as
follows:
-
______________________
/6/ A married PARTICIPANT'S EARLY RETIREMENT PENSION shall be in the form of a
MARITAL PENSION, computed as provided in Section 10b and Section 7. In lieu
of a MARITAL PENSION, a PARTICIPANT may elect any of the alternative forms
of the EARLY RETIREMENT PENSION described in Section 10b. and subject to
the rules contained therein.
<PAGE>
(1) If PARTICIPANT has less than 15 years of SERVICE on the EARLY
RETIREMENT DATE, the amount of the BASIC PENSION shall be reduced
by one-fourth of one percent for each month (three percent per
year) between PARTICIPANT's NORMAL RETIREMENT DATE and
PARTICIPANT's EARLY RETIREMENT DATE; or
(2) If PARTICIPANT has at least 15 but less than 30 years of SERVICE
and is 62 years of age or older on the EARLY RETIREMENT DATE, the
amount shall be the PARTICIPANT's BASIC PENSION computed to the
PARTICIPANT's EARLY RETIREMENT DATE; or
(3) If PARTICIPANT has at least 15 but less than 25 years of SERVICE
and is less than 62 years of age on the EARLY RETIREMENT DATE,
the amount of the BASIC PENSION shall be reduced by one-fourth of
one percent for each month (three percent per year) by which
PARTICIPANT's EARLY RETIREMENT DATE precedes PARTICIPANT's 62nd
birthday, and further reduced by 1/12th of one percent for each
month (one percent per year) by which PARTICIPANT's EARLY
RETIREMENT DATE precedes PARTICIPANT's 60th birthday; or
(4) If PARTICIPANT has at least 25 but less than 30 years of SERVICE
and is less than 62 years of age on the EARLY RETIREMENT DATE,
the amount of the BASIC PENSION shall be reduced by one-fourth of
one percent for each month (three percent per year) by which
PARTICIPANT's EARLY RETIREMENT DATE precedes PARTICIPANT's 62nd
birthday; or
(5) If a PARTICIPANT has at least 30 years of SERVICE and is less
than 60 years of age on the EARLY RETIREMENT DATE, the amount of
the BASIC PENSION shall be reduced by one- half of one percent
for each month (up to a maximum of 12 months or six percent) by
which PARTICIPANT'S EARLY RETIREMENT DATE precedes PARTICIPANT's
60th birthday, and further reduced by one-fourth of one percent
for each month (three percent per year) by which PARTICIPANT'S
EARLY RETIREMENT DATE precedes PARTICIPANT's 59th birthday; or
(6) If PARTICIPANT has at least 30 years of SERVICE and is 60 years
of age or older on the EARLY RETIREMENT DATE, the amount shall be
the PARTICIPANT's BASIC PENSION computed to the PARTICIPANT's
EARLY RETIREMENT DATE.
(7) If a PARTICIPANT has at least 35 years of SERVICE and is 55 years
of age or older on EARLY RETIREMENT DATE, and such PARTICIPANT
was formerly a PARTICIPANT on December 31, 1994, in Part II of
the PLAN, the amount shall be the PARTICIPANT'S BASIC PENSION
computed to the PARTICIPANT'S EARLY RETIREMENT DATE.
See Special Provision B for a table of EARLY RETIREMENT reductions.
8. Pensions Where Employment Ends Before Age 55
--------------------------------------------
Until January 1, 1989, a PARTICIPANT with at least 10 years of SERVICE
will be designated as a former EMPLOYEE rather than a retired EMPLOYEE if
such PARTICIPANT's SERVICE ends before the first day of the month which
follows the PARTICIPANT's 55th birthday. Effective January 1, 1989, any
PARTICIPANT with at least five years of SERVICE will be designated as a
former EMPLOYEE if such PARTICIPANT's SERVICE ends before the first day of
the month which follows the PARTICIPANT's 55th birthday. Such former
EMPLOYEE has a vested right to receive a PENSION
-5-
<PAGE>
with the same rights of election and in the same amounts as provided in
Section 7, provided that the earliest election date for commencement of
PENSION payments is the first day of the month after the PARTICIPANT's 55th
birthday and the latest shall be April 1 of the year following the year in
which the PARTICIPANT attains age 70 1/2. Such a PARTICIPANT is also
entitled to the elections provided in Sections 10 (Forms of Pension), 12
(Withdrawal of Participant Contributions on Termination of Employment), 13
(Death Benefits in Certain Cases), and 15 (Facility of Payment).
9. Deferred Retirement
-------------------
An EMPLOYEE may continue in employment beyond the NORMAL RETIREMENT
DATE only at the request of an EMPLOYER or as may be required by law. A
PARTICIPANT whose employment continues beyond NORMAL RETIREMENT DATE shall
not be entitled to a pension until PARTICIPANT's ACTUAL RETIREMENT DATE.
Any provision of the PLAN notwithstanding, distributions from the PLAN
shall comply with the requirements of CODE Section 401(a)(9) and the
regulations thereunder. The amount of the PENSION payable shall be the
PENSION benefit accrued as of the April 1 following the end of the year in
which the EMPLOYEE attains age 70 1/2, adjusted for any elections made by
the PARTICIPANT and any forms of PENSION required under Section 10.
Pursuant to CODE Section 401(a)(9)(A)(ii), if an EMPLOYEE continues
employment beyond the end of the year in which the EMPLOYEE attains age 70
1/2, a PENSION shall be distributed, commencing not later than April 1 of
the calendar year following the calendar year in which the EMPLOYEE attains
age 70 1/2, over the life of the EMPLOYEE or over the joint lives of the
EMPLOYEE and the EMPLOYEE'S SPOUSE or other JOINT PENSIONER.
If an EMPLOYEE dies after the distribution of the EMPLOYEE'S interest
in the PLAN has begun, then, in accordance with CODE Section
401(a)(9)(B)(i), the remaining portion of the EMPLOYEE'S accrued PENSION
benefit, if any, will be distributed at least as rapidly as under the
method of distributions being used as of the date of his or her death. If
an EMPLOYEE dies before the ACTUAL RETIREMENT DATE, then the EMPLOYEE'S
SPOUSE may elect to postpone receiving distributions under the SPOUSE'S
PENSION, but postponement of receipt of benefits shall not extend beyond
the date that the EMPLOYEE would have attained age 70 1/2. Death benefits
provided under the PLAN shall be no more than incidental, within the
meaning of the CODE, to the PLAN'S primary purpose of providing retirement
benefits to EMPLOYEES.
10. Forms of Pension
----------------
(a) Joint Pension With Non-Spouse
-----------------------------
For a PARTICIPANT who is unmarried on the ACTUAL RETIREMENT DATE, the
normal form of a PENSION shall be a BASIC PENSION or an EARLY
RETIREMENT PENSION which terminates on the PARTICIPANT'S death. A
MARITAL PENSION, as described in 10(b) below, is the normal form of
PENSION for PARTICIPANTS who are married on the ACTUAL RETIREMENT
DATE. However, any PARTICIPANT, whether married or unmarried, who
wishes to have the PENSION continued in whole or in part after the
PARTICIPANT'S death for the life of a non-spouse JOINT PENSIONER, may
elect to have the applicable normal form of PENSION paid as a JOINT
PENSION by giving the EMPLOYER at least 30 days' advance written
notice prior to the PARTICIPANT'S ACTUAL RETIREMENT DATE.
-6-
<PAGE>
If such an election is made, the PARTICIPANT will receive a reduced
BASIC or EARLY RETIREMENT PENSION for life and, upon the PARTICIPANT'S
death, the non-spouse JOINT PENSIONER designated by the PARTICIPANT
will receive that proportion of such reduced PENSION, up to 100
percent, which the PARTICIPANT has elected, for the remainder of the
JOINT PENSIONER'S life.
Non-spouse JOINT PENSIONS shall be determined in accordance with an
actuarial formula which is set forth in Special Provision C.
(b) Joint Pension With Spouse
-------------------------
For a PARTICIPANT who is married on the ACTUAL RETIREMENT DATE, the
normal form of PENSION shall be a MARITAL PENSION, reducing the amount
of the PARTICIPANT'S BASIC PENSION and providing that on the
PARTICIPANT'S death one-half of such MARITAL PENSION will be continued
to the SPOUSE for the remainder of the SPOUSE'S life.
In lieu of the MARITAL PENSION, a married PARTICIPANT, by making a
QUALIFIED ELECTION prior to ACTUAL RETIREMENT DATE, may elect one of
the following options:
(1) a JOINT PENSION with SPOUSE which provides that an amount equal
to either 25, 75 or 100 percent of a reduced BASIC or EARLY
RETIREMENT PENSION will, upon the PARTICIPANT'S death, be
continued for the remainder of the SPOUSE'S life, or
(2) a SPECIAL JOINT PENSION with SPOUSE which provides an amount of
one-half or 100 percent of a reduced BASIC or EARLY RETIREMENT
PENSION that, upon the PARTICIPANT'S death, will be continued for
the remainder of the SPOUSE'S life. However, if the SPOUSE
predeceases the PARTICIPANT, future PENSION payments will be
restored to the amount of the full BASIC or EARLY RETIREMENT
PENSION that the PARTICIPANT would be entitled to receive if no
SPECIAL JOINT PENSION with SPOUSE had been elected.
MARITAL PENSIONS and JOINT PENSIONS with SPOUSE shall be determined
in accordance with an actuarial formula which is set forth in Special
Provision D. Special Provision D also includes tables of factors
which apply to typical options which may be elected.
SPECIAL JOINT PENSIONS with SPOUSE shall also be determined in
accordance with the actuarial formula which is set forth in Special
Provision D, but actuarially adjusted further to reflect the value of
the restoration feature. Provision D also includes tables of the
factors which apply to SPECIAL JOINT PENSION options that may be
elected.
(c) Basic or Early Retirement Pension Terminating Upon The Death Of The
---
Participant
-------------------------------------------------------------------
Under this option, no additional PENSION payments are made to anyone
after the PARTICIPANT'S death.
(d) Conditions Applicable To All Forms Of Pensions
----------------------------------------------
The CONSENT of the SPOUSE is required whenever a QUALIFIED ELECTION is
made which would provide benefits to a surviving SPOUSE less than
those provided by a MARITAL PENSION.
-7-
<PAGE>
The SPOUSE of a PARTICIPANT may not receive a benefit under any
provisions of this Section if a larger SPOUSE'S PENSION is payable
under Section 11.
11. Spouse's Pension
----------------
(a) If a married PARTICIPANT dies while employed by an EMPLOYER and prior
to the ACTUAL RETIREMENT DATE, or within 30 days thereafter, the
PARTICIPANT's surviving SPOUSE will be eligible to receive a SPOUSE's
PENSION if, at the time of the PARTICIPANT'S death, (i) the
PARTICIPANT was at least 55 years of age, or (ii) the sum of the
PARTICIPANT's age and years of SERVICE equaled 70 or more. (69.5 or
more is rounded to 70.)
The amount of the SPOUSE's PENSION is one-half of the PENSION that the
PARTICIPANT would have been entitled to receive, and will be
calculated as if:
(1) the PARTICIPANT had elected a BASIC PENSION under Section
10(b)(3),
(2) the first day of the month following the PARTICIPANT's death had
been the PARTICIPANT's ACTUAL RETIREMENT DATE, and
(3) The PARTICIPANT had in fact retired on that date without
reduction for early retirement. However, if the SPOUSE is more
than 10 years younger than the PARTICIPANT, the amount of the
SPOUSE's PENSION shall be reduced 1/20th of one percent for each
full month in excess of 120 months' difference in their ages,
except that such reduction shall not result in a SPOUSE's PENSION
lower than would have been payable if the PARTICIPANT had retired
as of the date of death and elected an optional form providing
for continuation of 50 percent to a named JOINT PENSIONER with
SPOUSE the same sex and age of the SPOUSE, under the provisions
of Section 10(b)(1). The SPOUSE's PENSION is payable to the
PARTICIPANT's surviving SPOUSE on the first day of the month
following the PARTICIPANT's death and the first day of each month
thereafter so long as the SPOUSE lives.
(b) The surviving SPOUSE of a PARTICIPANT or of a former EMPLOYEE who dies
prior to actual retirement date shall be entitled to receive a
SPOUSE's PENSION under this Section 11(b) if, at the time of the death
of the PARTICIPANT or former EMPLOYEE, (i) the PARTICIPANT or former
EMPLOYEE had at least five years of SERVICE, and (ii) the surviving
SPOUSE does not qualify for a SPOUSE's PENSION under Section 11(a),
above.
A SPOUSE's PENSION under this Section 11(b) shall be payable on the
first day of the month following the later of (i) the date of death or
(ii) the month in which the deceased PARTICIPANT or former EMPLOYEE
would have attained his 55th birthday. By submitting an election
form to the PLAN ADMINISTRATOR, a SPOUSE may elect to begin receiving
a SPOUSE's PENSION at a specified later date.
Unless a vested PARTICIPANT or vested former EMPLOYEE and his or her
SPOUSE have elected otherwise pursuant to a QUALIFIED ELECTION, if a
PARTICIPANT dies on or before age 55, the PARTICIPANT'S or FORMER
EMPLOYEE'S surviving SPOUSE (if any) will receive the same benefit
that would have been payable if the PARTICIPANT or former EMPLOYEE
had:
-8-
<PAGE>
(1) separated from SERVICE on the date of death (or date of
separation from SERVICE, if earlier),
(2) survived to age 55,
(3) retired with a MARITAL PENSION at age 55,
(4) died on the day of retirement, and begun to receive benefit
payments at the date as of which the PARTICIPANT or former
EMPLOYEE would have attained age 55.
Unless a surviving SPOUSE elects otherwise, the surviving SPOUSE will
begin to receive payments at the date as of which the PARTICIPANT or
former EMPLOYEE would have attained age 55. Benefits commencing after
this date will be the ACTUARIAL EQUIVALENT of the benefit to which the
surviving SPOUSE would have been entitled if benefits had commenced at
this date.
A PARTICIPANT's SPOUSE may not receive both a SPOUSE's PENSION under this
Section and a MARITAL or JOINT PENSION under Section 10. If the
PARTICIPANT dies within 30 days after the PARTICIPANT's ACTUAL RETIREMENT
DATE, the SPOUSE will receive the larger of the monthly Pensions under this
Section and Section 3.10, but not both.
12. Withdrawal of Participant Contributions on Termination of Employment
--------------------------------------------------------------------
A PARTICIPANT's contributions to the PLAN may not be withdrawn prior
to ACTUAL RETIREMENT DATE or other termination of SERVICE. After a
PARTICIPANT's SERVICE is terminated, the PARTICIPANT, by written notice to
the PARTICIPANT's EMPLOYER at least 30 days before the date the PENSION
begins, may elect to have such CONTRIBUTIONS PLUS INTEREST returned.
If a PARTICIPANT elects to withdraw such CONTRIBUTIONS PLUS INTEREST,
the PENSION the PARTICIPANT would otherwise be entitled to at the NORMAL or
EARLY RETIREMENT DATE shall be reduced by an amount that reflects the
actuarial value of the contributions withdrawn. The factors used to reduce
the PENSION of a PARTICIPANT who has withdrawn his contributions shall
comply with CODE Sections 411(a)(7)(D) and 411(c)(2)(B) and are contained
in the table set forth in Special Provision I.
13. Death Benefits
--------------
If a PARTICIPANT with contributions on deposit in the PLAN dies before
receiving payments from the PLAN equal to the amount of the PARTICIPANT's
CONTRIBUTIONS PLUS INTEREST, the difference between the payments made and
the CONTRIBUTIONS PLUS INTEREST will be paid to the named BENEFICIARY,
unless a PENSION is payable to the PARTICIPANT's surviving SPOUSE or JOINT
PENSIONER. If a PENSION is payable after such PARTICIPANT's death, and if
upon the death of the SPOUSE or JOINT PENSIONER the total combined amount
paid to the PARTICIPANT and the SPOUSE or JOINT PENSIONER does not equal
the amount of the PARTICIPANT's CONTRIBUTIONS PLUS INTEREST, the difference
between the total amount paid and the PARTICIPANT's CONTRIBUTIONS PLUS
INTEREST will be paid to the BENEFICIARY of the SPOUSE or JOINT PENSIONER.
14. Facility of Payment
-------------------
(a) If the present value of all PENSION benefits payable under the
PLAN to any individual is less than $3,500.00 as of the date of SEVERANCE
FROM SERVICE or ACTUAL RETIREMENT DATE, the equivalent value shall be paid
in a lump sum, as directed by the ADMINISTRATOR. For
-9-
<PAGE>
PARTICIPANTS terminating before age 55, present value means the ACTUARIAL
EQUIVALENT of the normal retirement benefit commencing at NORMAL RETIREMENT
DATE. For PARTICIPANTS retiring at or after age 55, present value means
the ACTUARIAL EQUIVALENT of the early, normal or deferred retirement
benefit commencing at ACTUAL RETIREMENT DATE. In determining the present
value, the PLAN ADMINISTRATOR shall use the Unisex Mortality Table for 1984
(UP-84) and the interest rates set, as of the first day of the PLAN YEAR in
which the lump sum payment is made, by the Pension Benefit Guaranty
Corporation for the purpose of determining the present value of a lump sum
distribution on PLAN termination.
(b) If the ADMINISTRATOR determines that any individual entitled to
any payment under the PLAN is physically or mentally incompetent to handle
the payment and no guardian or conservator has been appointed to receive
such payment, the ADMINISTRATOR may cause all payments thereafter becoming
due to such individual to be applied for and on behalf of and for the
benefit of such individual. Payments made pursuant to this provision shall
completely discharge the EMPLOYER, the ADMINISTRATOR, the Trustee, and all
fiduciaries of all further responsibility with respect to such individual.
(c) If the distributee of any eligible rollover distribution (as
defined below) elects to have the distribution paid directly to an eligible
retirement plan (as defined below), and if the distributee specified,
according to the manner specified by the PLAN, the eligible retirement plan
to which such distribution is to be paid, then the distribution shall be
made in the form of a direct trustee-to-trustee transfer to the eligible
retirement plan specified by the distributee. The trustee-to-trustee
transfer shall be made available only if the distribution from the PLAN
would be subject to federal income taxation.
The term "eligible rollover distribution" shall mean any distribution
to a PARTICIPANT or former EMPLOYEE of all or part of the balance to the
credit of the PARTICIPANT or former EMPLOYEE in the PLAN. The term shall
not, however, include any distribution which is one of a series of
"substantially equal periodic payments" (as defined at CODE Section
402(c)(4)(A), or any distribution that is required under CODE Section
401(a)(9).
The term "eligible retirement plan" means an individual retirement
account described in CODE Section 408(a), an individual retirement annuity
described in CODE Section 408(b) (other than an endowment contract), an
annuity plan described in CODE Section 403(a), or a qualified defined
contribution plan, the terms of which permit the acceptance of rollover
distributions.
15. Benefits Are Not Assignable
---------------------------
Except as may be required by law, a PARTICIPANT's interest in the
PLAN, either before or after retirement, and that of a PARTICIPANT's
SPOUSE, JOINT PENSIONER, or BENEFICIARY shall not be subject to assignment,
anticipation, sale, transfer, pledge, encumbrance, or charge, whether
voluntary or involuntary, and any attempt to so assign, anticipate, sell,
transfer, pledge, encumber, or charge shall be void.
16. Employer Contributions
----------------------
The COMPANY shall contribute to the PLAN such amount of EMPLOYER
CONTRIBUTIONS as the EMPLOYEE BENEFIT FINANCE COMMITTEE, with the advice of
the actuary, shall determine is necessary to keep the PLAN funded in
accordance with the Funding Policy and to satisfy any minimum funding
standard required by the Internal Revenue SERVICE or the Department of
Labor. The EMPLOYEE BENEFIT FINANCE COMMITTEE shall determine and
-10-
<PAGE>
charge to each EMPLOYER its share of the EMPLOYER contributions made by the
COMPANY.
17. Company's Powers and Duties
---------------------------
The COMPANY, acting through its Board of Directors or Executive
Committee, reserves to itself the exclusive power to amend, suspend, or
terminate the PLAN as provided below and to appoint and remove from time to
time:
(a) The individuals comprising the EMPLOYEE BENEFIT FINANCE
COMMITTEE;
(b) The individuals comprising the EMPLOYEE BENEFIT ADMINISTRATIVE
COMMITTEE;
(c) The EMPLOYERS whose EMPLOYEES may participate in the PLAN.
(d) Except as provided in Section 20, the appropriate committees
established by the COMPANY shall serve as the final review committees,
under the PLAN, to determine conclusively for all parties any and all
questions arising from the administration of the PLAN and shall have sole
and complete discretionary authority and control to manage the operation
and administration of the PLAN, including, but not limited to, the
determination of all questions relating to eligibility for participation
and benefits, interpretation of all PLAN provisions, determination of the
amount and kind of benefits payable to any PARTICIPANT, SPOUSE or
beneficiary, and construction of disputed or doubtful terms. Such
decisions shall be conclusive and binding on all parties and not subject to
further review.
All powers and duties not reserved to the COMPANY are delegated to the
EMPLOYEE BENEFIT FINANCE COMMITTEE and to the EMPLOYEE BENEFIT
ADMINISTRATIVE COMMITTEE. Action of either committee shall be by vote of a
majority of the members of the committee at a meeting, or in writing
without a meeting, and evidenced by the signature of any member who is so
authorized by the committee. The COMPANY indemnifies each member of each
committee against any personal liability or expense arising out of any
action or inaction of the committee or of any member of the committee or of
such individual, except that due to his own willful misconduct.
18. Funding and Investment Provisions
---------------------------------
The EMPLOYEE BENEFIT FINANCE COMMITTEE appointed by the COMPANY's
Board of Directors to serve at its pleasure has the express powers and
duties described in this Section.
(a) Appointments. The EMPLOYEE BENEFIT FINANCE COMMITTEE has the
------------
sole power and duty from time to time to appoint and remove the Funding
Agents, the Investment Manager, actuaries, accountants, and such other
advisors and consultants as may be needed for the proper financial
administration and investment of the assets of the PLAN. Supplementing such
appointments, the EMPLOYEE BENEFIT FINANCE COMMITTEE may enter into
appropriate agreements with each Trustee, Investment Manager or other
advisors appointed under this paragraph and delegate to them appropriate
powers and duties. The EMPLOYEE BENEFIT FINANCE COMMITTEE may appoint and
delegate to one or more individuals the power and duty to handle the day-
to-day financial administration of the PLAN. Such individuals need not be
members of the committee and shall serve at the pleasure of the committee.
-11-
<PAGE>
(b) Funding Policy. The EMPLOYEE BENEFIT FINANCE COMMITTEE has the
--------------
sole power and duty to establish a funding policy and an investment policy
and to review and revise it from time to time as the committee shall
determine in its sole discretion. All EMPLOYER contributions to the PLAN
shall be paid to Funding Agents which may be one or more insurance
companies or corporate trustees, or to any combination thereof, as the
EMPLOYEE BENEFIT FINANCE COMMITTEE may determine from time to time. These
contributions, and all previous contributions of PARTICIPANTS and
EMPLOYERS, together with the proceeds of their investment, shall be held
and administered by these Funding Agents pursuant to the agreements between
the COMPANY and the Funding Agents. All of the PLAN'S assets held by
Funding Agents are available to pay benefits on behalf of all PARTICIPANTS
covered by this PLAN.
19. Administration
--------------
The EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE, appointed by the
COMPANY's Board of Directors to serve at its pleasure, is the ADMINISTRATOR
of the PLAN and is responsible for the overall administration of the PLAN.
The ADMINISTRATOR has the sole power and duty to establish, and from time
to time revise, such rules and regulations as may be necessary to
administer the PLAN in a nondiscriminatory manner for the exclusive benefit
of PARTICIPANTS and all other persons entitled to benefits under the PLAN.
The ADMINISTRATOR shall also maintain such records and make such
computations, interpretations, and decisions as may be necessary or
desirable for the proper administration of the PLAN. The ADMINISTRATOR may
demand such proof of age of any PARTICIPANT, JOINT PENSIONER, or SPOUSE as
it considers necessary, and it may adjust any PENSION or other payment or
payments thereafter due under the PLAN as it deems appropriate and
equitable to correct any factual error or misrepresentation. The
ADMINISTRATOR shall maintain for PARTICIPANTS' inspection copies of the
PLAN, trust agreement, investment policy, each agreement with an Investment
Manager, the latest annual report, PLAN description, and summary
description, and any amendments or changes in any of these documents. On
written request, PARTICIPANTS may obtain from the ADMINISTRATOR a copy of
any of these documents at a cost established by the ADMINISTRATOR from time
to time.
All expenses of administration may be paid out of the PLAN's assets
upon authorization by the appropriate committee, unless paid by the
COMPANY. Such expenses shall include any expenses incident to the
functioning of the ADMINISTRATOR, including, but not limited to, fees for
accountants, actuaries, counsel, investment managers and other specialists
and their agents, and other costs of administering the PLAN.
20. Claims Procedure
----------------
If a claim is denied in whole or in part, the ADMINISTRATOR shall
furnish to the claimant a written notice setting forth:
(a) Specific reason(s) for the denial,
(b) The PLAN provision(s) on which the denial is based,
(c) A description of any material or information, if any, necessary
for the claimant to perfect the claim, and an explanation of why such
material or information is necessary, and
(d) Information concerning the steps to be taken if claimant wishes
to submit a claim for review.
-12-
<PAGE>
The above information shall be furnished to the claimant within 90 days
after the claim is received by the ADMINISTRATOR.
If a claimant is not satisfied with the written notice described in
the preceding paragraph, such claimant may request a full and fair review
by so notifying the ADMINISTRATOR in writing within 90 days after receiving
such notice. If a review is requested the claimant shall also be entitled,
upon written request, to review pertinent documents and to submit issues
and comments in writing. The EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE
shall furnish the claimant with a written final decision within 60 days
after receipt of the request for review.
21. Qualified Domestic Relations Orders
-----------------------------------
The EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE shall apply the provisions of
this section with regard to a Domestic Relations Order (as defined below)
to the extent not inconsistent with Section 414(p) of the CODE.
The EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE shall establish procedures,
consistent with Section 414(p) of the CODE, to determine the qualified
status of any Domestic Relations Order, to administer distributions under
any Qualified Domestic Relations Order (as defined below), and to provide
to the PARTICIPANT and the Alternate Payee(s) (as defined below) all
notices required under Section 414(p) of the CODE with respect to any
Domestic Relations Order.
Within a reasonable period of time after the receipt of a Domestic
Relations Order (or any modification thereof), the EMPLOYEE BENEFIT
ADMINISTRATIVE COMMITTEE shall determine whether such order is a Qualified
Domestic Relations Order.
For purposes of this section:
(a) Alternate Payee shall mean any SPOUSE, former SPOUSE, child, or other
dependent of a PARTICIPANT who is recognized by a Domestic Relations
Order as having a right to receive all, or a portion of, the benefits
payable under the PLAN with respect to such PARTICIPANT.
(b) Domestic Relations Order shall mean any judgment, decree, or order
(including approval of a property settlement) which:
(1) relates to the provision of child support, alimony payments, or
marital property rights to a SPOUSE, former SPOUSE, child, or
other dependent of a PARTICIPANT; and
(2) is made pursuant to a state domestic relations law (including a
community property law).
(c) Qualified Domestic Relations Order shall mean a Domestic Relations
Order which meets the requirements of Section 414(p)(1) of the CODE.
22. Amendment, Termination, and Merger
----------------------------------
The COMPANY hopes and expects to continue this PLAN indefinitely but,
because future conditions cannot be foreseen, its Board of Directors
necessarily reserves the right to change, suspend, or terminate the PLAN at
any time. However, no change can be made which would adversely affect the
rights which any PARTICIPANT, retired EMPLOYEE, former EMPLOYEE, SPOUSE,
JOINT PENSIONER, or BENEFICIARY may then have with respect to funds then
being held under the PLAN by any Funding Agent or permit any such funds to
revert to an EMPLOYER or be used for any
-13-
<PAGE>
purpose except for the exclusive benefit of PARTICIPANTS, Pensioners, and
their SPOUSES, JOINT PENSIONERS, and BENEFICIARIES.
In the event the PLAN is partially terminated, terminated or
suspended, all EMPLOYER contributions with respect to the affected
PARTICIPANTS shall cease and the accrued benefits of the affected
PARTICIPANTS shall become nonforfeitable. Subject to applicable
requirements of notice to the Pension Benefit Guaranty Corporation
governing termination of PENSION benefit plans, the funds held under the
PLAN by the Funding Agents shall be applied to provide the PENSIONS,
benefits and refunds accrued to the date of termination or suspension and
to the extent funded. Such provision shall be made in such manner as the
ADMINISTRATOR shall direct, including the purchase of paid-up annuities,
distribution in installments, or lump-sum distributions and shall be in
conformance with the requirements and priorities established by various
governmental agencies to oversee PLAN suspensions and terminations.
Notwithstanding any contrary provisions of the PLAN, after its termination
and after all liabilities for the payment of PENSIONS, benefits and refunds
to the date of termination have been satisfied or provided for in
accordance with the foregoing, any funds remaining with the Funding Agents
shall be returned to the COMPANY.
This PLAN shall not be merged into or consolidated with any other
PLAN, nor shall any of its assets or liabilities be transferred to any
other PLAN, unless each PARTICIPANT in this PLAN would (if such other PLAN
then terminated) receive a benefit immediately after the merger,
consolidation, or transfer which is equal to or greater than the benefit
such PARTICIPANT would have been entitled to receive immediately before the
merger, consolidation, or transfer (if this PLAN had then terminated).
23. Definitions and Cross-References
--------------------------------
Actual Retirement Date: The date of one of the following, whichever is
----------------------
applicable:
(a) The date on which an EARLY RETIREMENT
PENSION begins, or
(b) The PARTICIPANT's Normal Retirement Date,
or
(c) If the PARTICIPANT continues in the employ
of an EMPLOYER beyond Normal Retirement
Date, the first day of the month following
termination of SERVICE.
Actuarial Equivalent or For purposes of determining actuarially
Actuarial Equivalence: equivalent benefits under this PLAN, the
---------------------
provisions of Special Provision D shall apply.
Administrator: The EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE
-------------
referred to in Section 20, 201 Mission Street,
19th Floor, Mail Code P19A, P.O. Box 770000, San
Francisco, California 94177.
Basic Monthly Salary: The rate of pay used to calculate the monthly
--------------------
earnings from an EMPLOYER, adjusted to reflect
nuclear premium payments, if
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<PAGE>
any, but excluding payments from the LONG TERM
DISABILITY PLAN and all other bonuses, premiums,
special allowances, overtime pay, or any other
payments. For a PARTICIPANT who is paid weekly
or bi-weekly, BASIC MONTHLY SALARY shall be equal
to the PARTICIPANT'S weekly pay rate multiplied
by 4.33, rounded up to the nearest Five Dollars.
For purposes of calculating a PARTICIPANT'S
accrued benefit under this PLAN, the compensation
limitations of CODE Section 401(a)(17) shall be
applicable. For purposes of calculating accruals
after December 31, 1993, the amount of a
PARTICIPANT'S compensation taken into account
shall not exceed $150,000, or such greater amount
permitted by the Secretary of the Treasury. For
purposes of calculating accruals after December
31, 1988, and before January 1, 1994, the amount
of compensation taken into account shall not
exceed $200,000, or such greater amount permitted
by the Secretary of the Treasury.
Unless otherwise provided under this PLAN, each
CODE Section 401(a)(17) employee's accrued
benefit under this PLAN will be the greater of
the accrued benefit determined for the employee
under 1 or 2 below:
1. The employee's accrued benefit determined
with respect to the benefit formula
applicable for the PLAN YEAR beginning on
or after January 1, 1994, as applied to the
employee's total years of SERVICE taken
into account under the PLAN for the
purposes of benefit accruals, or
2. The sum of:
(a) the employee's accrued benefit as of
the last day of the last PLAN YEAR
beginning before January 1, 1994,
frozen in accordance with CODE Section
1.401(a)(4)-13, and
(b) the employee's accrued benefit
determined under the benefit formula
applicable for the PLAN YEAR beginning
on or after January 1, 1994, as
applied to the employee's years of
service credited to the employee for
PLAN YEARS beginning on or after
January 1, 1994, for purposes of
benefit accruals.
-15-
<PAGE>
A CODE Section 401(a)(17) employee means an
employee whose current accrued benefit as of a
date on or after the first day of the first PLAN
YEAR beginning on or after January 1, 1994, is
based on compensation for a year beginning prior
to the first day of the first PLAN YEAR beginning
on or after January 1, 1994, that exceeded
$150,000.
Basic Pension: The PENSION due at the later of NORMAL RETIREMENT
-------------
DATE or ACTUAL RETIREMENT DATE and unreduced
because of marital status. See Sections 6 and
10b.
Beneficiary: The individual or individuals or inter-vivos
-----------
trust or trusts that a PARTICIPANT, SPOUSE, or
JOINT PENSIONER designates to receive any death
benefits due pursuant to Section 13. Such
designation must be made on forms provided by the
EMPLOYER and filed with the ADMINISTRATOR. A
PARTICIPANT, or the PARTICIPANT's SPOUSE (if
receiving a SPOUSE's PENSION), or the
PARTICIPANT's JOINT PENSIONER (if receiving a
Joint PENSION), may change the designated
Beneficiary from time to time by filing an
appropriate written notice with the
ADMINISTRATOR. In the absence of a designation,
the Beneficiary shall be the estate of the person
entitled to make the designation. There were no
employee contributions after December 31, 1972.
Therefore, EMPLOYEES who first became
Participants in the PLAN after said date were not
required or permitted to name a Beneficiary.
Break in Service: A BREAK IN SERVICE occurs 12 months after the
----------------
SEVERANCE FROM SERVICE DATE if during such 12-
month period an EMPLOYEE does not work for an
EMPLOYER. Once a Break in Service occurs, it
continues until an EMPLOYEE is reemployed by an
EMPLOYER.
Code: CODE shall mean the Internal Revenue CODE of
----
1986, as amended from time to time.
Company: Pacific Gas and Electric Company.
-------
Consent: The CONSENT by a SPOUSE that is required for a
-------
QUALIFIED ELECTION. Any such CONSENT shall be
effective only with respect to such SPOUSE. A
CONSENT permitting designation by the PARTICIPANT
without further CONSENT from the SPOUSE must
acknowledge that the SPOUSE has the right to
limit CONSENT to a specific BENEFICIARY and also
to a specific benefit form, and that the SPOUSE
voluntarily elects to relinquish either or both
of such rights. A revocation of a prior QUALIFIED
ELECTION may be made by a PARTICIPANT without the
CONSENT of the SPOUSE at any time prior to
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<PAGE>
the commencement of benefits. An unlimited
number of revocations shall be permitted. No
CONSENT obtained under this provision shall be
valid unless the PARTICIPANT has received proper
NOTICE.
Contributions Plus The cumulative total of contributions made by
Interest:
------------------ a PARTICIPANT to the PLAN under Section 13;
paragraph (b) of Special Provision F; and to the
COMPANY's Retirement PLAN as it existed before
1969, plus interest at two percent per year on a
PARTICIPANT's contributions made after 1953,
compounded annually to 1976, together with
interest at five percent compounded annually
after 1975 on all contributions and previous
interest.
Credited Service: See Special Provision F.
----------------
Early Retirement Date: See Section 7.
---------------------
Early Retirement Pension: See Section 7.
------------------------
Employee: An EMPLOYEE of an EMPLOYER who is not covered by
--------
a collective bargaining agreement. A "leased
employee," as defined in Section 414(n) of the
CODE, shall not be considered an EMPLOYEE
eligible to become a PARTICIPANT in the PLAN.
Notwithstanding any other provisions in the
PLAN, solely for purposes of CODE Section
414(n)(3), the term EMPLOYEE shall, to the extent
required by CODE Section 414, include leased
EMPLOYEES.
Employee Benefit
Administrative Committee: The EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE
------------------------
referred to in Section 19.
The Employee Benefit
Finance Committee: The EMPLOYEE BENEFIT FINANCE COMMITTEE referred
--------------------
to in Section 18.
Employer: Pacific Gas and Electric Company, Pacific Service
--------
Employees Association, and any other company,
association, or credit union designated by the
Board of Directors as eligible to participate in
this PLAN is an EMPLOYER.
Joint Pension: See Section 10.
-------------
Joint Pensioner: The individual designated by a PARTICIPANT upon
---------------
the election of a JOINT PENSION who will be
entitled upon the PARTICIPANT's death to receive
a PENSION, as explained in Section 10.
Long Term Disability Part B of the Pacific Gas and Electric
Plan:
-------------------- Company's Group Life Insurance and Long Term
Disability Plan.
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<PAGE>
Marital Pension: See Section 10(b).
---------------
Maximum Pension: See Special Provision H.
---------------
Normal Retirement Date: The first of the month following the
----------------------
PARTICIPANT's 65th birthday.
Notice: The NOTICE that is required by this PLAN pursuant
------
to CODE Section 417 in order to waive the MARITAL
PENSION.
In the case of MARITAL PENSION, the PLAN shall
provide to each PARTICIPANT, and to each vested
former EMPLOYEE, no less than 30 days and no more
than 90 days prior to the annuity starting date a
written explanation of: (i) the terms and
conditions of the MARITAL PENSION, (ii) the right
to make and the effect of an election to waive
the MARITAL PENSION, (iii) the rights of the
PARTICIPANT'S or the former EMPLOYEE'S SPOUSE,
(iv) the right to make an election to waive the
MARITAL PENSION and the effect of revoking a
previous election to waive the MARITAL PENSION,
and (v) the relative values of the various
optional forms of benefit under the PLAN.
Participant: See Section 2.
-----------
Part-Time Employee: An EMPLOYEE whose regularly scheduled work week
------------------
is less than 40 hours.
Pension: Retirement income payable under the PLAN.
-------
Plan: The Company's Retirement Plan as amended, revised
----
and set forth herein.
Plan Year: The PLAN YEAR shall be the calendar year which
---------
shall also be the limitation year for purposes of
applying the annual benefit limitations of CODE
Section 415.
Qualified Election: An election qualifying under CODE Section 417(a)
------------------
to waive either, or both, of the 50 percent
spousal survivor annuities that are based on the
MARITAL PENSION and that are described in
Sections 10(b) or 11(b) of the PLAN. Any such
waiver shall not be considered a QUALIFIED
ELECTION unless: (a) the PARTICIPANT'S SPOUSE
furnishes written CONSENT to the election, (b)
the election designates a specific alternate
BENEFICIARY, including any class of BENEFICIARIES
or any contingent BENEFICIARIES, which may not be
changed without spousal CONSENT (or the SPOUSE
expressly permits designations by the PARTICIPANT
without any further spousal CONSENT, (c) the
SPOUSE'S CONSENT acknowledges the effect of the
election, and (d) the SPOUSE'S CONSENT is
witnessed by a PLAN representative or a notary
public. A PARTICIPANT'S
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<PAGE>
waiver of the survivor annuity will not
constitute a QUALIFIED ELECTION unless the form
of benefit payment may not be changed without
spousal CONSENT, or the SPOUSE expressly permits
designations by the PARTICIPANT without any
further spousal CONSENT. If it is established to
the satisfaction of the PLAN representative that
such written CONSENT may not be obtained because
there is no SPOUSE or the SPOUSE cannot be
located, then a waiver will be deemed a QUALIFIED
ELECTION.
Service: For full-time EMPLOYEES, the period of time
-------
commencing with the first day of work for an
EMPLOYER and ending on PARTICIPANT's SEVERANCE
FROM SERVICE Date. For periods of PART-TIME and
intermittent employment, SERVICE for purposes of
benefit accrual is prorated based on the ratio of
actual hours worked in the calendar year to the
full-time equivalent (2,080 per calendar year)
rounded to the nearest month. Such proration is
applicable for any employment period beginning
with initiation of PART-TIME or intermittent
status on or after January 1, 1991, and ending
on the earlier of Participant's return to full
time status or the PARTICIPANT'S SEVERANCE FROM
SERVICE DATE. The method of computing SERVICE is
described in Section 3.
Severance from Service
----------------------
Date: (i) The date prior to NORMAL RETIREMENT DATE
----
on which an EMPLOYEE quits, retires, is
discharged or dies, or the ACTUAL
RETIREMENT DATE; or
(ii) The first anniversary of the first date of
a period in which a PARTICIPANT remains
absent from work for an EMPLOYER for any
reason other than a quit, retirement,
discharge, or death.
For the purpose of determining the Severance
from SERVICE Date, the following periods shall
not be considered as absences from work for an
EMPLOYER:
(a) Absence on a leave of absence authorized by
an EMPLOYER.
(b) Absence because of illness or injury as
long as the PARTICIPANT is entitled to
receive sick leave pay or is entitled to
receive benefits under the provisions of
the Voluntary Wage Benefit Plan, a state
disability plan, Part B of the Group Life
Insurance and Long Term Disability Plan,
or a Workers' Compensation Law.
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<PAGE>
(c) Absence for military service or service in
the Merchant Marines so long as
reemployment rights are protected by law.
(d) Absence caused by layoff for lack of work
of less than 12 continuous months for a
PARTICIPANT who has less than five years of
SERVICE, or 24 continuous months for a
PARTICIPANT who has five years or more of
SERVICE.
Special Joint Pension: See Section 10.
---------------------
Spouse: (a) If a PARTICIPANT dies in SERVICE, SPOUSE
------
shall mean the PARTICIPANT's wife or
husband at the time of the PARTICIPANT's
death.
(b) If a PARTICIPANT dies after ACTUAL
RETIREMENT DATE, SPOUSE shall mean the
PARTICIPANT's wife or husband at the time
of the PARTICIPANT's Actual Retirement.
Spouse's Pension: See Section 11.
----------------
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<PAGE>
SPECIAL PROVISION A
Payment of all PENSIONS to PARTICIPANTS which commenced before January 1,
1969, under the Retirement Plan of the COMPANY, its Past Service Plan, its
Supplemental Benefits and under any applicable retirement plan of a predecessor
company shall continue to be made under the PLAN, without regard to the separate
sources from which such pensions were previously paid.
SPECIAL PROVISION B
EARLY RETIREMENT REDUCTIONS IN PERCENTAGE POINTS
------------------------------------------------
Years Of Service At Early Retirement Date
---------------------------------------------------
<TABLE>
<CAPTION>
Age at Less Than 15 But Less 25 But Less 30 Years
Retirement 15 Years Than 25 Years Than 30 Years And Above
- ---------- --------- ------------- ------------- ---------
<S> <C> <C> <C> <C>
64 3 0 0 0
63 6 0 0 0
62 9 0 0 0
61 12 3 3 0
60 15 6 6 0
59 18 10 9 6
58 21 14 12 9
57 24 18 15 12
56 27 22 18 15
55 30 26 21 18
</TABLE>
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<PAGE>
SPECIAL PROVISION C
JOINT PENSION WITH NON-SPOUSE
(Entire Provision Amended 1/1/88)
The amount of non-spouse JOINT PENSION shall be determined by the use of
Actuarial Tables which provide 12%, 16%, 25%, 33-1/3%, 50%, 66-2/3%, 75% and
100% of the JOINT PENSION to a non-spouse JOINT PENSIONER who survives the death
of the PARTICIPANT.
Partial Actuarial Tables of 50% and 100% have been attached.
The following tables illustrate the factors to be applied for typical
options which may be elected for 50% and 100%.
EXAMPLE: Assume the PARTICIPANT is age 62 and elects a 50% or 100% option with
a non-spouse age 50. Also assume that the PARTICIPANT's BASIC PENSION
is $1,000 per month.
<TABLE>
<CAPTION>
Non- Non- Non-Spouse's Pension
Spouse's Option Basic Reduced Spouse's In Event of
Option Factor Pension Pension Portion Participant's Death
- -------- ------ ------- ------- -------- --------------------
<S> <C> <C><C> <C><C> <C><C> <C><C>
50% .861 X $1,000. = $861. X .50 = $430.50
100% .756 X $1,000. = $756. X 1.00 = $756.00
</TABLE>
Tables for 12%, 16%, 33-1/3%, 66-2/3%, or 75% are available upon request.
Tables for Beneficiary's Age at Pensioner's Retirement of less than 25 years or
greater than 84 years are also available upon request.
-22-
<PAGE>
SPECIAL PROVISION C
FACTORS TO BE APPLIED TO EMPLOYEE'S RETIREMENT INCOME TO DETERMINE INCOME UNDER
CONTINGENT
ANNUITANT OPTION IF 50% OF SUCH INCOME IS CONTINUED TO CONTINGENT ANNUITANT
<TABLE>
<CAPTION>
BENEFICIARY'S BENEFICIARY'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 RETIREMENT
- ---------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- -----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
25 .844 .836 .827 .817 .807 .797 .786 .775 .763 .751 .738 .725 .711 .697 .682 .667 25
26 .847 .838 .829 .819 .809 .799 .788 .777 .765 .753 .740 .727 .713 .699 .684 .669 26
27 .849 .840 .831 .821 .811 .801 .790 .779 .767 .755 .742 .729 .715 .701 .686 .671 27
28 .851 .842 .833 .824 .814 .803 .793 .781 .769 .757 .745 .731 .718 .703 .689 .674 28
29 .853 .844 .835 .826 .816 .806 .795 .784 .772 .760 .747 .734 .720 .706 .691 .676 29
30 .855 .847 .838 .828 .818 .808 .797 .786 .774 .762 .750 .736 .723 .708 .694 .679 30
31 .858 .849 .840 .831 .821 .811 .800 .789 .777 .765 .752 .739 .725 .711 .696 .681 31
32 .860 .852 .843 .833 .824 .813 .803 .792 .780 .768 .755 .742 .728 .714 .699 .684 32
33 .863 .854 .846 .836 .826 .816 .806 .794 .783 .771 .758 .745 .731 .717 .702 .687 33
34 .866 .857 .848 .839 .829 .819 .809 .797 .786 .774 .761 .748 .734 .720 .705 .690 34
35 .868 .860 .851 .842 .832 .822 .812 .801 .789 .777 .764 .751 .737 .723 .708 .693 35
36 .871 .863 .854 .845 .835 .825 .815 .804 .792 .780 .768 .754 .741 .727 .712 .697 36
37 .874 .866 .857 .848 .839 .829 .818 .807 .796 .784 .771 .758 .744 .730 .715 .700 37
38 .877 .869 .860 .851 .842 .832 .821 .811 .799 .787 .775 .761 .748 .734 .719 .704 38
39 .880 .872 .864 .855 .845 .835 .825 .814 .803 .791 .778 .765 .752 .737 .723 .708 39
40 .884 .875 .867 .858 .849 .839 .829 .818 .806 .795 .782 .769 .756 .741 .727 .712 40
41 .887 .879 .870 .862 .852 .843 .832 .822 .810 .798 .786 .773 .760 .746 .731 .716 41
42 .890 .882 .874 .865 .856 .846 .836 .826 .814 .803 .790 .777 .764 .750 .735 .720 42
43 .893 .886 .877 .869 .860 .850 .840 .830 .818 .807 .794 .782 .768 .754 .740 .725 43
44 .897 .889 .881 .873 .864 .854 .844 .834 .823 .811 .799 .786 .773 .759 .744 .729 44
45 .900 .893 .885 .876 .868 .858 .848 .838 .827 .816 .803 .791 .777 .764 .749 .734 45
46 .904 .896 .889 .880 .872 .862 .853 .842 .832 .820 .808 .795 .782 .768 .754 .739 46
47 .907 .900 .892 .884 .876 .867 .857 .847 .836 .825 .813 .800 .787 .774 .759 .744 47
48 .911 .904 .896 .888 .880 .871 .861 .851 .841 .830 .818 .805 .792 .779 .764 .750 48
49 .914 .907 .900 .892 .884 .875 .866 .856 .846 .835 .823 .811 .798 .784 .770 .755 49
</TABLE>
-23-
<PAGE>
SPECIAL PROVISION C
FACTORS TO BE APPLIED TO EMPLOYEE'S RETIREMENT INCOME TO DETERMINE INCOME UNDER
CONTINGENT
ANNUITANT OPTION IF 50% OF SUCH INCOME IS CONTINUED TO CONTINGENT ANNUITANT
<TABLE>
<CAPTION>
BENEFICIARY'S BENEFICIARY'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 RETIREMENT
- ----------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- -------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
50 .918 .911 .904 .896 .888 .880 .870 .861 .850 .840 .828 .816 .803 .790 .775 .761 50
51 .921 .915 .908 .900 .892 .884 .875 .866 .855 .845 .833 .821 .808 .795 .781 .767 51
52 .925 .918 .912 .904 .897 .888 .880 .870 .860 .850 .839 .827 .814 .801 .787 .773 52
53 .928 .922 .916 .908 .901 .893 .884 .875 .865 .855 .844 .832 .820 .807 .793 .779 53
54 .932 .926 .919 .913 .905 .897 .889 .880 .870 .860 .849 .838 .826 .813 .799 .785 54
55 .935 .929 .923 .917 .909 .902 .894 .885 .876 .866 .855 .844 .832 .819 .806 .792 55
56 .938 .933 .927 .921 .914 .906 .898 .890 .881 .871 .861 .849 .838 .825 .812 .798 56
57 .942 .936 .931 .925 .918 .911 .903 .895 .886 .876 .866 .855 .844 .831 .819 .805 57
58 .945 .940 .934 .928 .922 .915 .908 .900 .891 .882 .872 .861 .850 .838 .825 .812 58
59 .948 .943 .938 .932 .926 .920 .912 .905 .896 .887 .878 .867 .856 .844 .832 .819 59
60 .951 .947 .942 .936 .930 .924 .917 .910 .902 .893 .883 .873 .863 .851 .839 .826 60
61 .954 .950 .945 .940 .934 .928 .922 .914 .907 .898 .889 .879 .869 .858 .846 .833 61
62 .957 .953 .948 .944 .938 .932 .926 .919 .912 .904 .895 .885 .875 .864 .853 .840 62
63 .960 .956 .952 .947 .942 .937 .931 .924 .917 .909 .901 .891 .882 .871 .860 .848 63
64 .963 .959 .955 .951 .946 .941 .935 .929 .922 .914 .906 .897 .888 .878 .867 .855 64
65 .965 .962 .958 .954 .949 .944 .939 .933 .927 .920 .912 .903 .894 .884 .874 .862 65
66 .968 .965 .961 .957 .953 .948 .943 .938 .931 .925 .917 .909 .900 .891 .881 .870 66
67 .970 .967 .964 .960 .956 .952 .947 .942 .936 .930 .923 .915 .907 .897 .888 .877 67
68 .972 .970 .967 .963 .960 .955 .951 .946 .940 .934 .928 .920 .913 .904 .894 .884 68
69 .975 .972 .969 .966 .963 .959 .955 .950 .945 .939 .933 .926 .918 .910 .901 .891 69
70 .977 .974 .972 .969 .966 .962 .958 .954 .949 .944 .938 .931 .924 .916 .908 .898 70
71 .979 .976 .974 .971 .968 .965 .961 .957 .953 .948 .942 .936 .930 .922 .914 .905 71
72 .980 .978 .976 .974 .971 .968 .965 .961 .957 .952 .947 .941 .935 .928 .920 .912 72
73 .982 .980 .978 .976 .973 .971 .968 .964 .960 .956 .951 .946 .940 .933 .926 .918 73
74 .984 .982 .980 .978 .976 .973 .970 .967 .964 .960 .955 .950 .945 .939 .932 .925 74
</TABLE>
-24-
<PAGE>
SPECIAL PROVISION C
FACTORS TO BE APPLIED TO EMPLOYEE'S RETIREMENT INCOME TO DETERMINE INCOME UNDER
CONTINGENT
ANNUITANT OPTION IF 50% OF SUCH INCOME IS CONTINUED TO CONTINGENT ANNUITANT
<TABLE>
<CAPTION>
BENEFICIARY'S BENEFICIARY'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 RETIREMENT
- ------------ ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- -------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
75 .985 .984 .982 .980 .978 .976 .973 .970 .967 .963 .959 .954 .949 .944 .937 .931 75
76 .987 .985 .984 .982 .980 .978 .976 .973 .970 .966 .963 .958 .954 .948 .943 .936 76
77 .988 .987 .985 .984 .982 .980 .978 .975 .973 .970 .966 .962 .958 .953 .948 .942 77
78 .989 .988 .987 .985 .984 .982 .980 .978 .975 .972 .969 .966 .962 .957 .952 .947 78
79 .990 .989 .988 .987 .985 .984 .982 .980 .978 .975 .972 .969 .965 .961 .957 .952 79
80 .991 .990 .989 .988 .987 .985 .984 .982 .980 .978 .975 .972 .969 .965 .961 .956 80
81 .992 .991 .990 .989 .988 .987 .986 .984 .982 .980 .978 .975 .972 .969 .965 .961 81
82 .993 .992 .991 .991 .990 .988 .987 .986 .984 .982 .980 .978 .975 .972 .968 .964 82
83 .994 .993 .992 .992 .991 .990 .989 .987 .986 .984 .982 .980 .978 .975 .972 .968 83
84 .995 .994 .993 .993 .992 .991 .990 .989 .987 .986 .984 .982 .980 .978 .975 .972 84
</TABLE>
-25-
<PAGE>
SPECIAL PROVISION C
FACTORS TO BE APPLIED TO EMPLOYEE'S RETIREMENT INCOME TO DETERMINE INCOME UNDER
CONTINGENT
ANNUITANT OPTION IF 50% OF SUCH INCOME IS CONTINUED TO CONTINGENT ANNUITANT
<TABLE>
<CAPTION>
BENEFICIARY'S BENEFICIARY'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 70 71 72 73 74 75 76 77 78 79 80 81 82 83 84 85 RETIREMENT
- ------------ ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- -------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
25 .667 .652 .636 .620 .603 .586 .569 .551 .533 .515 .497 .479 .461 .442 .424 .406 25
26 .669 .654 .638 .622 .605 .588 .571 .553 .535 .517 .499 .481 .462 .444 .426 .407 26
27 .671 .656 .640 .624 .607 .590 .573 .555 .537 .519 .501 .483 .464 .446 .427 .409 27
28 .674 .658 .642 .626 .609 .592 .575 .557 .539 .521 .503 .485 .466 .448 .429 .411 28
29 .676 .661 .645 .628 .612 .595 .577 .560 .542 .524 .505 .487 .468 .450 .431 .413 29
30 .679 .663 .647 .631 .614 .597 .580 .562 .544 .526 .507 .489 .470 .452 .433 .414 30
31 .681 .666 .650 .633 .617 .600 .582 .564 .546 .528 .510 .491 .473 .454 .435 .417 31
32 .684 .669 .653 .636 .619 .602 .585 .567 .549 .531 .512 .494 .475 .456 .437 .419 32
33 .687 .671 .655 .639 .622 .605 .588 .570 .552 .533 .515 .496 .477 .459 .440 .421 33
34 .690 .675 .659 .642 .625 .608 .591 .573 .555 .536 .518 .499 .480 .461 .442 .423 34
35 .693 .678 .662 .645 .628 .611 .594 .576 .558 .539 .520 .502 .483 .464 .445 .426 35
36 .697 .681 .665 .649 .632 .614 .597 .579 .561 .542 .524 .505 .486 .467 .448 .429 36
37 .700 .685 .669 .652 .635 .618 .600 .582 .564 .545 .527 .508 .489 .470 .451 .431 37
38 .704 .688 .672 .656 .639 .621 .604 .586 .567 .549 .530 .511 .492 .473 .454 .434 38
39 .708 .692 .676 .659 .643 .625 .607 .589 .571 .552 .534 .515 .495 .476 .457 .438 39
40 .712 .696 .680 .663 .647 .629 .611 .593 .575 .556 .537 .518 .499 .480 .460 .441 40
41 .716 .700 .684 .668 .651 .633 .616 .597 .579 .560 .541 .522 .503 .483 .464 .444 41
42 .720 .705 .689 .672 .655 .638 .620 .602 .583 .564 .545 .526 .507 .487 .468 .448 42
43 .725 .709 .693 .677 .660 .642 .624 .606 .588 .569 .550 .530 .511 .491 .472 .452 43
44 .729 .714 .698 .681 .664 .647 .629 .611 .592 .573 .554 .535 .515 .495 .476 .456 44
45 .734 .719 .703 .686 .669 .652 .634 .616 .597 .578 .559 .539 .520 .500 .480 .460 45
46 .739 .724 .708 .691 .674 .657 .639 .621 .602 .583 .564 .544 .524 .505 .485 .465 46
47 .744 .729 .713 .697 .680 .662 .644 .626 .607 .588 .569 .549 .529 .509 .489 .469 47
48 .750 .734 .718 .702 .685 .668 .650 .631 .613 .594 .574 .554 .535 .515 .494 .474 48
49 .755 .740 .724 .708 .691 .673 .655 .637 .618 .599 .580 .560 .540 .520 .500 .479 49
</TABLE>
-26-
<PAGE>
SPECIAL PROVISION C
FACTORS TO BE APPLIED TO EMPLOYEE'S RETIREMENT INCOME TO DETERMINE INCOME UNDER
CONTINGENT
ANNUITANT OPTION IF 50% OF SUCH INCOME IS CONTINUED TO CONTINGENT ANNUITANT
<TABLE>
<CAPTION>
BENEFICIARY'S BENEFICIARY'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 70 71 72 73 74 75 76 77 78 79 80 81 82 83 84 85 RETIREMENT
- ---------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- -------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
50 .761 .746 .730 .713 .697 .679 .661 .643 .624 .605 .585 .566 .546 .525 .505 .485 50
51 .767 .752 .736 .720 .703 .685 .667 .649 .630 .611 .591 .572 .551 .531 .511 .490 51
52 .773 .758 .742 .726 .709 .692 .674 .655 .637 .617 .598 .578 .558 .537 .517 .496 52
53 .779 .764 .748 .732 .715 .698 .680 .662 .643 .624 .604 .584 .564 .543 .523 .502 53
54 .785 .770 .755 .739 .722 .705 .687 .669 .650 .631 .611 .591 .571 .550 .529 .508 54
55 .792 .777 .762 .746 .729 .712 .694 .676 .657 .638 .618 .598 .578 .557 .536 .515 55
56 .798 .784 .768 .753 .736 .719 .701 .683 .664 .645 .625 .605 .585 .564 .543 .522 56
57 .805 .790 .775 .760 .743 .726 .709 .691 .672 .653 .633 .613 .592 .571 .550 .529 57
58 .812 .798 .783 .767 .751 .734 .717 .699 .680 .661 .641 .621 .600 .579 .558 .537 58
59 .819 .805 .790 .775 .759 .742 .725 .707 .688 .669 .649 .629 .608 .587 .566 .545 59
60 .826 .812 .798 .783 .767 .750 .733 .715 .696 .677 .658 .638 .617 .596 .575 .553 60
61 .833 .820 .805 .790 .775 .758 .741 .724 .705 .686 .667 .646 .626 .605 .584 .562 61
62 .840 .827 .813 .799 .783 .767 .750 .733 .714 .695 .676 .656 .635 .614 .593 .571 62
63 .848 .835 .821 .807 .792 .776 .759 .742 .724 .705 .685 .665 .645 .624 .602 .581 63
64 .855 .843 .829 .815 .800 .785 .768 .751 .733 .715 .695 .675 .655 .634 .612 .591 64
65 .862 .850 .837 .824 .809 .794 .778 .761 .743 .725 .705 .686 .665 .644 .623 .601 65
66 .870 .858 .845 .832 .818 .803 .787 .770 .753 .735 .716 .696 .676 .655 .634 .612 66
67 .877 .866 .854 .841 .827 .812 .797 .780 .763 .745 .727 .707 .687 .666 .645 .623 67
68 .884 .873 .862 .849 .836 .821 .806 .790 .774 .756 .738 .718 .698 .678 .657 .635 68
69 .891 .881 .870 .858 .845 .831 .816 .801 .784 .767 .749 .730 .710 .690 .668 .647 69
70 .898 .888 .878 .866 .853 .840 .826 .811 .795 .778 .760 .741 .722 .702 .681 .659 70
71 .905 .896 .885 .874 .862 .849 .836 .821 .805 .789 .771 .753 .734 .714 .693 .672 71
72 .912 .903 .893 .882 .871 .859 .845 .831 .816 .800 .783 .765 .746 .727 .706 .685 72
73 .918 .910 .900 .890 .879 .868 .855 .841 .826 .811 .794 .777 .759 .739 .719 .698 73
74 .925 .917 .908 .898 .888 .876 .864 .851 .837 .822 .806 .789 .771 .752 .732 .712 74
</TABLE>
-27-
<PAGE>
SPECIAL PROVISION C
FACTORS TO BE APPLIED TO EMPLOYEE'S RETIREMENT INCOME TO DETERMINE INCOME UNDER
CONTINGENT
ANNUITANT OPTION IF 50% OF SUCH INCOME IS CONTINUED TO CONTINGENT ANNUITANT
<TABLE>
<CAPTION>
BENEFICIARY'S BENEFICIARY'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 70 71 72 73 74 75 76 77 78 79 80 81 82 83 84 85 RETIREMENT
- ---------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- -------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
75 .931 .923 .915 .906 .896 .885 .873 .861 .847 .833 .817 .801 .784 .765 .746 .726 75
76 .936 .929 .921 .913 .904 .893 .882 .870 .858 .844 .829 .813 .796 .778 .759 .740 76
77 .942 .935 .928 .920 .911 .902 .891 .880 .868 .854 .840 .825 .808 .791 .773 .754 77
78 .947 .941 .934 .927 .918 .909 .900 .889 .877 .865 .851 .836 .821 .804 .786 .768 78
79 .952 .946 .940 .933 .925 .917 .908 .898 .887 .875 .862 .848 .833 .817 .800 .782 79
80 .956 .951 .945 .939 .932 .924 .916 .906 .896 .885 .872 .859 .845 .829 .813 .795 80
81 .961 .956 .951 .945 .938 .931 .923 .914 .905 .894 .883 .870 .856 .842 .826 .809 81
82 .964 .960 .955 .950 .944 .937 .930 .922 .913 .903 .892 .881 .868 .854 .839 .823 82
83 .968 .964 .960 .955 .950 .943 .937 .929 .921 .912 .902 .891 .879 .866 .851 .836 83
84 .972 .968 .964 .960 .955 .949 .943 .936 .928 .920 .911 .900 .889 .877 .863 .849 84
</TABLE>
-28-
<PAGE>
SPECIAL PROVISION C
FACTORS TO BE APPLIED TO EMPLOYEE'S RETIREMENT INCOME TO DETERMINE INCOME UNDER
CONTINGENT
ANNUITANT OPTION IF 100% OF SUCH INCOME IS CONTINUED TO CONTINGENT ANNUITANT
<TABLE>
<CAPTION>
BENEFICIARY'S BENEFICIARY'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 RETIREMENT
- ---------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- -------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
25 .731 .718 .704 .691 .676 .662 .647 .632 .617 .601 .585 .568 .551 .535 .518 .500 25
26 .734 .721 .707 .694 .679 .665 .650 .635 .619 .603 .587 .571 .554 .537 .520 .503 26
27 .737 .724 .710 .697 .683 .668 .653 .638 .622 .606 .590 .574 .557 .540 .523 .505 27
28 .740 .727 .714 .700 .686 .671 .656 .641 .625 .609 .593 .576 .560 .543 .525 .508 28
29 .744 .731 .717 .703 .689 .675 .660 .644 .629 .613 .596 .580 .563 .545 .528 .511 29
30 .747 .734 .721 .707 .693 .678 .663 .648 .632 .616 .599 .583 .566 .549 .531 .514 30
31 .751 .738 .725 .711 .696 .682 .667 .651 .636 .619 .603 .586 .569 .552 .534 .517 31
32 .755 .742 .728 .715 .700 .686 .671 .655 .639 .623 .607 .590 .573 .555 .538 .520 32
33 .759 .746 .732 .719 .704 .690 .675 .659 .643 .627 .610 .593 .576 .559 .541 .523 33
34 .763 .750 .737 .723 .708 .694 .679 .663 .647 .631 .614 .597 .580 .562 .545 .527 34
35 .768 .754 .741 .727 .713 .698 .683 .667 .651 .635 .618 .601 .584 .566 .549 .531 35
36 .772 .759 .746 .732 .717 .703 .687 .672 .656 .639 .623 .606 .588 .570 .553 .535 36
37 .777 .764 .750 .736 .722 .707 .692 .677 .661 .644 .627 .610 .593 .575 .557 .539 37
38 .781 .768 .755 .741 .727 .712 .697 .681 .665 .649 .632 .615 .597 .579 .561 .543 38
39 .786 .773 .760 .746 .732 .717 .702 .687 .670 .654 .637 .620 .602 .584 .566 .548 39
40 .791 .779 .765 .751 .737 .723 .707 .692 .676 .659 .642 .625 .607 .589 .571 .552 40
41 .797 .784 .771 .757 .743 .728 .713 .697 .681 .665 .648 .630 .612 .594 .576 .557 41
42 .802 .789 .776 .762 .748 .734 .719 .703 .687 .670 .653 .636 .618 .600 .581 .563 42
43 .807 .795 .782 .768 .754 .740 .724 .709 .693 .676 .659 .642 .624 .605 .587 .568 43
44 .813 .800 .788 .774 .760 .746 .731 .715 .699 .682 .665 .648 .630 .611 .593 .574 44
45 .819 .806 .793 .780 .766 .752 .737 .721 .705 .689 .671 .654 .636 .618 .599 .580 45
46 .824 .812 .799 .786 .773 .758 .743 .728 .712 .695 .678 .660 .642 .624 .605 .586 46
47 .830 .818 .806 .793 .779 .765 .750 .734 .718 .702 .685 .667 .649 .631 .612 .593 47
48 .836 .824 .812 .799 .785 .771 .757 .741 .725 .709 .692 .674 .656 .638 .619 .600 48
49 .842 .830 .818 .805 .792 .778 .764 .748 .732 .716 .699 .681 .663 .645 .626 .607 49
</TABLE>
-29-
<PAGE>
SPECIAL PROVISION C
FACTORS TO BE APPLIED TO EMPLOYEE'S RETIREMENT INCOME TO DETERMINE INCOME UNDER
CONTINGENT
ANNUITANT OPTION IF 100% OF SUCH INCOME IS CONTINUED TO CONTINGENT ANNUITANT
<TABLE>
<CAPTION>
BENEFICIARY'S BENEFICIARY'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 RETIREMENT
- ---------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- -------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
50 .848 .837 .825 .812 .799 .785 .771 .756 .740 .723 .706 .689 .671 .652 .633 .614 50
51 .854 .843 .831 .819 .806 .792 .778 .763 .747 .731 .714 .697 .679 .660 .641 .622 51
52 .860 .849 .838 .826 .813 .799 .785 .770 .755 .739 .722 .705 .687 .668 .649 .630 52
53 .866 .855 .844 .832 .820 .807 .793 .778 .763 .747 .730 .713 .695 .676 .657 .638 53
54 .872 .862 .851 .839 .827 .814 .800 .786 .771 .755 .738 .721 .703 .685 .666 .646 54
55 .878 .868 .857 .846 .834 .821 .808 .794 .779 .763 .747 .730 .712 .693 .674 .655 55
56 .884 .874 .864 .853 .841 .829 .816 .802 .787 .771 .755 .738 .721 .702 .683 .664 56
57 .890 .880 .870 .860 .848 .836 .823 .810 .795 .780 .764 .747 .730 .712 .693 .673 57
58 .895 .886 .877 .866 .855 .844 .831 .818 .804 .789 .773 .756 .739 .721 .702 .683 58
59 .901 .893 .883 .873 .863 .851 .839 .826 .812 .798 .782 .766 .749 .731 .712 .693 59
60 .907 .898 .890 .880 .870 .859 .847 .834 .821 .806 .791 .775 .758 .741 .722 .703 60
61 .912 .904 .896 .887 .877 .866 .855 .842 .829 .815 .800 .785 .768 .751 .733 .714 61
62 .918 .910 .902 .893 .884 .873 .862 .851 .838 .824 .810 .794 .778 .761 .743 .725 62
63 .923 .916 .908 .900 .890 .881 .870 .859 .846 .833 .819 .804 .788 .772 .754 .736 63
64 .928 .921 .914 .906 .897 .888 .878 .867 .855 .842 .829 .814 .799 .782 .765 .747 64
65 .933 .926 .919 .912 .904 .895 .885 .875 .863 .851 .838 .824 .809 .793 .776 .758 65
66 .937 .931 .925 .918 .910 .902 .892 .882 .872 .860 .847 .833 .819 .803 .787 .770 66
67 .942 .936 .930 .924 .916 .908 .900 .890 .880 .868 .856 .843 .829 .814 .798 .781 67
68 .946 .941 .935 .929 .922 .915 .906 .897 .888 .877 .865 .853 .839 .825 .809 .793 68
69 .950 .946 .940 .934 .928 .921 .913 .905 .895 .885 .874 .862 .849 .835 .820 .804 69
70 .954 .950 .945 .939 .933 .927 .920 .912 .903 .893 .883 .871 .859 .845 .831 .816 70
71 .958 .954 .949 .944 .939 .932 .926 .918 .910 .901 .891 .880 .868 .855 .842 .827 71
72 .962 .958 .953 .949 .944 .938 .932 .925 .917 .908 .899 .889 .878 .865 .852 .838 72
73 .965 .961 .957 .953 .948 .943 .937 .931 .923 .916 .907 .897 .887 .875 .863 .849 73
74 .968 .965 .961 .957 .953 .948 .942 .936 .930 .922 .914 .905 .895 .884 .873 .860 74
</TABLE>
-30-
<PAGE>
SPECIAL PROVISION C
FACTORS TO BE APPLIED TO EMPLOYEE'S RETIREMENT INCOME TO DETERMINE INCOME UNDER
CONTINGENT
ANNUITANT OPTION IF 100% OF SUCH INCOME IS CONTINUED TO CONTINGENT ANNUITANT
<TABLE>
<CAPTION>
BENEFICIARY'S BENEFICIARY'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 RETIREMENT
- ---------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- -------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
75 .971 .968 .965 .961 .957 .952 .948 .942 .936 .929 .921 .913 .904 .893 .882 .870 75
76 .974 .971 .968 .965 .961 .957 .952 .947 .941 .935 .928 .920 .912 .902 .892 .880 76
77 .976 .974 .971 .968 .965 .961 .957 .952 .947 .941 .934 .927 .919 .910 .900 .890 77
78 .979 .976 .974 .971 .968 .965 .961 .957 .952 .946 .940 .934 .926 .918 .909 .899 78
79 .981 .979 .976 .974 .971 .968 .965 .961 .956 .952 .946 .940 .933 .926 .917 .908 79
80 .983 .981 .979 .977 .974 .971 .968 .965 .961 .956 .951 .946 .939 .932 .925 .916 80
81 .985 .983 .981 .979 .977 .974 .971 .968 .965 .961 .956 .951 .945 .939 .932 .924 81
82 .986 .985 .983 .981 .979 .977 .975 .972 .968 .965 .961 .956 .951 .945 .939 .931 82
83 .988 .986 .985 .983 .982 .980 .977 .975 .972 .969 .965 .961 .956 .951 .945 .938 83
84 .989 .988 .987 .985 .984 .982 .980 .978 .975 .972 .969 .965 .961 .958 .951 .945 84
</TABLE>
-31-
<PAGE>
SPECIAL PROVISION C
FACTORS TO BE APPLIED TO EMPLOYEE'S RETIREMENT INCOME TO DETERMINE INCOME UNDER
CONTINGENT
ANNUITANT OPTION IF 100% OF SUCH INCOME IS CONTINUED TO CONTINGENT ANNUITANT
<TABLE>
<CAPTION>
BENEFICIARY'S BENEFICIARY'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 70 71 72 73 74 75 76 77 78 79 80 81 82 83 84 85 RETIREMENT
- ---------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- -------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
25 .500 .483 .466 .449 .432 .414 .397 .380 .364 .347 .331 .315 .299 .284 .269 .254 25
26 .503 .486 .468 .451 .434 .416 .399 .382 .365 .349 .333 .316 .301 .285 .270 .256 26
27 .505 .488 .471 .453 .436 .419 .401 .384 .367 .351 .334 .318 .302 .287 .272 .257 27
28 .508 .491 .473 .456 .438 .421 .403 .386 .369 .353 .336 .320 .304 .288 .273 .258 28
29 .511 .493 .476 .458 .441 .423 .406 .388 .371 .355 .338 .322 .306 .290 .275 .260 29
30 .514 .496 .478 .461 .443 .426 .408 .391 .374 .357 .340 .324 .307 .292 .276 .261 30
31 .517 .499 .481 .464 .446 .428 .411 .393 .376 .359 .342 .326 .309 .294 .278 .263 31
32 .520 .502 .484 .466 .449 .431 .413 .396 .378 .361 .344 .328 .311 .295 .280 .265 32
33 .523 .505 .488 .470 .452 .434 .416 .398 .381 .364 .347 .330 .314 .298 .282 .267 33
34 .527 .509 .491 .473 .455 .437 .419 .401 .384 .366 .349 .332 .316 .300 .284 .269 34
35 .531 .513 .494 .476 .458 .440 .422 .404 .387 .369 .352 .335 .318 .302 .286 .271 35
36 .535 .516 .498 .480 .462 .443 .425 .407 .390 .372 .355 .337 .321 .304 .288 .273 36
37 .539 .520 .502 .484 .465 .447 .429 .411 .393 .375 .357 .340 .323 .307 .291 .275 37
38 .543 .525 .506 .488 .469 .451 .432 .414 .396 .378 .361 .343 .326 .310 .293 .277 38
39 .548 .529 .511 .492 .473 .455 .436 .418 .400 .382 .364 .346 .329 .312 .296 .280 39
40 .552 .534 .515 .496 .478 .459 .440 .422 .403 .385 .367 .350 .332 .315 .299 .283 40
41 .557 .539 .520 .501 .482 .463 .445 .426 .407 .389 .371 .353 .336 .319 .302 .286 41
42 .563 .544 .525 .506 .487 .468 .449 .430 .412 .393 .375 .357 .339 .322 .305 .289 42
43 .568 .549 .530 .511 .492 .473 .454 .435 .416 .397 .379 .361 .343 .326 .309 .292 43
44 .574 .555 .536 .517 .497 .478 .459 .440 .421 .402 .383 .365 .347 .329 .312 .295 44
45 .580 .561 .542 .522 .503 .483 .464 .445 .425 .406 .388 .369 .351 .333 .316 .299 45
46 .586 .567 .548 .528 .509 .489 .469 .450 .431 .411 .392 .374 .355 .337 .320 .303 46
47 .593 .573 .554 .534 .515 .495 .475 .455 .436 .417 .397 .379 .360 .342 .324 .307 47
48 .600 .580 .561 .541 .521 .501 .481 .461 .442 .422 .403 .384 .365 .346 .328 .311 48
49 .607 .587 .567 .548 .528 .507 .487 .467 .447 .428 .408 .389 .370 .351 .333 .315 49
</TABLE>
-32-
<PAGE>
SPECIAL PROVISION C
FACTORS TO BE APPLIED TO EMPLOYEE'S RETIREMENT INCOME TO DETERMINE INCOME UNDER
CONTINGENT
ANNUITANT OPTION IF 100% OF SUCH INCOME IS CONTINUED TO CONTINGENT ANNUITANT
<TABLE>
<CAPTION>
BENEFICIARY'S BENEFICIARY'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 70 71 72 73 74 75 76 77 78 79 80 81 82 83 84 85 RETIREMENT
- ---------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- -------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
50 .614 .594 .575 .555 .534 .514 .494 .474 .454 .434 .414 .394 .375 .356 .338 .320 50
51 .622 .602 .582 .562 .542 .521 .501 .480 .460 .440 .420 .400 .381 .362 .343 .325 51
52 .630 .610 .590 .570 .549 .529 .508 .487 .467 .446 .426 .406 .387 .367 .348 .330 52
53 .638 .618 .598 .577 .557 .536 .515 .495 .474 .453 .433 .413 .393 .373 .354 .335 53
54 .646 .626 .606 .586 .565 .544 .523 .502 .481 .461 .440 .419 .399 .379 .360 .341 54
55 .655 .635 .615 .594 .574 .553 .532 .510 .489 .468 .447 .426 .406 .386 .366 .347 55
56 .664 .644 .624 .603 .582 .561 .540 .519 .497 .476 .455 .434 .413 .393 .373 .353 56
57 .673 .654 .633 .613 .592 .570 .549 .528 .506 .484 .463 .442 .421 .400 .380 .360 57
58 .683 .663 .643 .622 .601 .580 .558 .537 .515 .493 .472 .450 .429 .408 .387 .367 58
59 .693 .673 .653 .632 .611 .590 .568 .546 .524 .502 .481 .459 .437 .416 .395 .374 59
60 .703 .684 .663 .643 .622 .600 .578 .556 .534 .512 .490 .468 .446 .424 .403 .382 60
61 .714 .694 .674 .654 .632 .611 .589 .567 .545 .522 .500 .478 .455 .434 .412 .391 61
62 .725 .705 .685 .665 .644 .622 .600 .578 .556 .533 .510 .488 .465 .443 .421 .400 62
63 .736 .716 .697 .676 .655 .634 .612 .589 .567 .644 .521 .499 .476 .453 .431 .409 63
64 .747 .728 .708 .688 .667 .646 .624 .601 .579 .556 .533 .510 .487 .464 .441 .419 64
65 .758 .740 .720 .700 .679 .658 .636 .614 .591 .568 .545 .522 .498 .475 .452 .430 65
66 .770 .751 .732 .712 .692 .671 .649 .627 .604 .581 .557 .534 .511 .487 .464 .441 66
67 .781 .763 .745 .725 .705 .684 .662 .640 .617 .594 .571 .547 .523 .500 .476 .453 67
68 .793 .775 .757 .738 .718 .697 .676 .653 .631 .608 .584 .560 .537 .513 .489 .465 68
69 .804 .787 .769 .751 .731 .711 .689 .667 .645 .622 .598 .574 .550 .526 .502 .478 69
70 .816 .799 .782 .764 .744 .724 .703 .682 .659 .636 .613 .589 .565 .540 .516 .492 70
71 .827 .811 .794 .777 .758 .738 .718 .696 .674 .651 .628 .604 .580 .555 .531 .506 71
72 .838 .823 .807 .790 .771 .752 .732 .711 .689 .666 .643 .619 .595 .571 .546 .521 72
73 .849 .835 .819 .802 .785 .766 .746 .726 .704 .682 .659 .635 .611 .586 .562 .536 73
74 .860 .846 .831 .815 .798 .780 .761 .741 .720 .698 .675 .651 .627 .603 .578 .553 74
</TABLE>
-33-
<PAGE>
SPECIAL PROVISION C
FACTORS TO BE APPLIED TO EMPLOYEE'S RETIREMENT INCOME TO DETERMINE INCOME UNDER
CONTINGENT
ANNUITANT OPTION IF 100% OF SUCH INCOME IS CONTINUED TO CONTINGENT ANNUITANT
<TABLE>
<CAPTION>
BENEFICIARY'S BENEFICIARY'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 70 71 72 73 74 75 76 77 78 79 80 81 82 83 84 85 RETIREMENT
- ---------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- -------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
75 .870 .857 .843 .828 .811 .794 .775 .756 .735 .714 .691 .668 .644 .620 .595 .569 75
76 .880 .868 .854 .840 .824 .807 .790 .771 .751 .730 .708 .685 .661 .637 .612 .587 76
77 .890 .878 .865 .852 .837 .821 .804 .785 .766 .746 .724 .702 .679 .654 .630 .605 77
78 .899 .888 .876 .863 .849 .834 .818 .800 .781 .762 .741 .719 .696 .672 .648 .623 78
79 .908 .898 .886 .874 .861 .847 .831 .814 .797 .778 .757 .736 .714 .690 .666 .641 79
80 .916 .907 .896 .885 .873 .859 .844 .828 .811 .793 .774 .753 .731 .709 .685 .660 80
81 .924 .915 .906 .895 .884 .871 .857 .842 .826 .808 .790 .770 .749 .727 .704 .680 81
82 .931 .923 .915 .905 .894 .882 .869 .855 .840 .823 .806 .787 .766 .745 .723 .699 82
83 .938 .931 .923 .914 .904 .893 .881 .868 .853 .838 .821 .803 .784 .763 .741 .718 83
84 .945 .938 .931 .922 .913 .903 .892 .880 .866 .852 .836 .819 .800 .781 .760 .738 84
</TABLE>
-34-
<PAGE>
SPECIAL PROVISION D
MARITAL PENSIONS, JOINT PENSIONS WITH SPOUSES AND
SPECIAL JOINT PENSIONS WITH SPOUSES
MARITAL PENSIONS and JOINT PENSIONS with SPOUSES shall be determined by
multiplying factors calculated in accordance with the 1951 Male Group Annuity
Table at 5% interest, with the following modifications:
(i) PARTICIPANT's mortality rates shall be determined by adding 41% of the
rates at PARTICIPANT's ages to 59% of the rates at ages five years lower.
(ii) SPOUSE's mortality rates shall be determined by adding 59% of the rates at
SPOUSE's ages to 41% of the rates at ages five years lower.
(iii) For MARITAL PENSIONS, the factors shall be calculated taking into account
only one-half of the costs of the benefits to surviving SPOUSES.
(iv) When the proportions of the JOINT PENSIONS to be continued to SPOUSES
exceed 50%, the factors shall be calculated in such a way that the values
of such JOINT PENSIONS are equal to the values of corresponding MARITAL
PENSION.
(v) When the proportions of the JOINT PENSIONS to be continued to SPOUSES are
less than 50%, the factors shall be calculated taking into account only
one-half of the costs to surviving SPOUSES.
(vi) Whenever a factor calculated for a MARITAL or JOINT PENSION with SPOUSE is
smaller than the corresponding factor for a non- spouse JOINT PENSION, the
non-spouse JOINT PENSION factor shall be substituted for the calculated
factor.
The following tables illustrate the factors to be applied for typical
options which may be elected between 25% and 100%.
EXAMPLE: Assume the PARTICIPANT is age 62 and Spouse age 60. Also assume that
the PARTICIPANT's BASIC PENSION is $1,000 per month.
<TABLE>
<CAPTION>
Spouse's Pension
Spouse's Option Basic Reduced Spouse's In Event of
Option Factor Pension Pension Portion Participant's Death
- ---------- ------ ------- ------- -------- -------------------
<S> <C> <C><C> <C><C> <C><C> <C><C>
25% .976 X $1,000. = $976. X .25 = $244.00
50% .955 X $1,000. = $955. X .50 = $477.50
75% .914 X $1,000. = $914. X .75 = $685.50
100% .876 X $1,000. = $876. X 1.00 = $876.00
</TABLE>
SPECIAL JOINT PENSIONS with SPOUSES shall be determined using the same
actuarial assumptions described above and are illustrated in the tables
following the JOINT PENSION tables.
-35-
<PAGE>
SPECIAL PROVISION D
FACTORS USED TO DETERMINE THE REDUCED ANNUAL RATE
OF RETIREMENT ANNUITY PAYABLE TO JOINT PENSIONERS
WHO ELECT VARIOUS OPTIONS WITH THEIR ELIGIBLE SPOUSE
25% OPTION ELECTION
-------------------
<TABLE>
<CAPTION>
SPOUSE'S SPOUSE'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 RETIREMENT
- ------------ ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ----- ---- ---- -----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
40 .969 .967 .964 .962 .959 .956 .953 .950 .946 .943 .939 .935 .930 .926 .921 .916 40
41 .970 .968 .965 .963 .960 .957 .954 .951 .948 .944 .940 .936 .932 .927 .922 .917 41
42 .971 .969 .966 .964 .961 .958 .955 .952 .949 .945 .941 .937 .933 .929 .924 .919 42
43 .972 .970 .967 .965 .962 .960 .957 .953 .950 .947 .943 .939 .934 .930 .925 .920 43
44 .973 .971 .968 .966 .963 .961 .958 .955 .951 .948 .944 .940 .936 .931 .927 .922 44
45 .974 .972 .969 .967 .965 .962 .959 .956 .953 .949 .946 .942 .937 .933 .928 .923 45
46 .975 .973 .970 .968 .966 .963 .960 .957 .954 .951 .947 .943 .939 .935 .930 .925 46
47 .976 .974 .972 .969 .967 .964 .962 .959 .955 .952 .948 .945 .940 .936 .932 .927 47
48 .977 .975 .973 .970 .968 .966 .963 .960 .957 .953 .950 .946 .942 .938 .933 .928 48
49 .978 .976 .974 .972 .969 .967 .964 .961 .958 .955 .951 .948 .944 .939 .935 .930 49
50 .979 .977 .975 .973 .970 .968 .965 .963 .960 .956 .953 .949 .945 .941 .937 .932 50
51 .980 .978 .976 .974 .972 .969 .967 .964 .961 .958 .955 .951 .947 .943 .939 .934 51
52 .980 .979 .977 .975 .973 .970 .968 .965 .962 .959 .956 .953 .949 .945 .940 .936 52
53 .981 .980 .978 .976 .974 .972 .969 .967 .964 .961 .958 .954 .951 .947 .942 .938 53
54 .982 .981 .979 .977 .975 .973 .971 .968 .965 .962 .959 .956 .952 .948 .944 .940 54
55 .983 .982 .980 .978 .976 .974 .972 .969 .967 .964 .961 .958 .954 .950 .946 .942 55
56 .984 .983 .981 .979 .977 .975 .973 .971 .968 .966 .963 .959 .956 .952. .948 .944 56
57 .985 .984 .982 .980 .979 .977 .975 .972 .970 .967 .964 .961 .958 .954 .950 .946 57
58 .986 .984 .983 .981 .980 .978 .976 .974 .971 .969 .966 .963 .959 .956 .952 .948 58
59 .987 .985 .984 .982 .981 .979 .977 .975 .973 .970 .967 .964 .961 .958 .954 .950 59
</TABLE>
NOTE: Factors for additional age combinations are available from the
Administrator.
-36-
<PAGE>
SPECIAL PROVISION D
FACTORS USED TO DETERMINE THE REDUCED ANNUAL RATE
OF RETIREMENT ANNUITY PAYABLE TO JOINT PENSIONERS
WHO ELECT VARIOUS OPTIONS WITH THEIR ELIGIBLE SPOUSE
25% OPTION ELECTION
-------------------
(Continued)
<TABLE>
<CAPTION>
SPOUSE'S SPOUSE'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 RETIREMENT
- ------------ ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- -----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
60 .987 .986 .985 .984 .982 .980 .978 .976 .974 .972 .969 .966 .963 .960 .956 .952 60
61 .988 .987 .986 .985 .983 .981 .980 .978 .976 .973 .971 .968 .965 .962 .958 .954 61
62 .989 .988 .987 .985 .984 .983 .981 .979 .977 .975 .972 .970 .967 .964 .960 .957 62
63 .990 .989 .988 .986 .985 .984 .982 .980 .978 .976 .974 .971 .969 .966 .962 .959 63
64 .990 .990 .988 .987 .986 .985 .983 .981 .980 .978 .975 .973 .970 .967 .964 .961 64
65 .991 .990 .989 .988 .987 .986 .984 .983 .981 .979 .977 .975 .972 .969 .966 .963 65
66 .992 .991 .990 .989 .988 .987 .985 .984 .982 .980 .978 .976 .974 .971 .968 .965 66
67 .992 .992 .991 .990 .989 .988 .986 .985 .983 .982 .980 .978 .975 .973 .970 .967 67
68 .993 .992 .992 .991 .990 .989 .987 .986 .985 .983 .981 .979 .977 .975 .972 .969 68
69 .994 .993 .992 .991 .990 .989 .988 .987 .986 .984 .983 .981 .979 .976 .974 .971 69
70 .994 .993 .993 .992 .991 .990 .989 .988 .987 .985 .984 .982 .980 .978 .976 .973 70
71 .995 .994 .993 .993 .992 .991 .990 .989 .988 .987 .985 .984 .982 .980 .978 .975 71
72 .995 .995 .994 .993 .993 .992 .991 .990 .989 .988 .986 .985 .983 .981 .979 .977 72
73 .995 .995 .995 .994 .993 .993 .992 .991 .990 .989 .987 .986 .985 .983 .981 .979 73
74 .996 .995 .995 .994 .994 .993 .992 .992 .991 .990 .989 .987 .986 .984 .982 .980 74
</TABLE>
NOTE: Factors for additional age combinations are available from the
Administrator.
-37-
<PAGE>
SPECIAL PROVISION D
FACTORS USED TO DETERMINE THE REDUCED ANNUAL RATE
OF RETIREMENT ANNUITY PAYABLE TO JOINT PENSIONERS
WHO ELECT VARIOUS OPTIONS WITH THEIR ELIGIBLE SPOUSE
50% OPTION ELECTION
-------------------
<TABLE>
<CAPTION>
SPOUSE'S SPOUSE'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 RETIREMENT
- ---------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
40 .942 .938 .934 .929 .924 .919 .914 .909 .903 .897 .891 .885 .878 .871 .863 .856 40
41 .943 .939 .935 .931 .926 .921 .916 .911 .905 .899 .893 .887 .880 .873 .865 .858 41
42 .945 .941 .937 .933 .928 .923 .918 .913 .907 .901 .895 .889 .882 .875 .868 .860 42
43 .947 .943 .939 .934 .930 .925 .920 .915 .909 .903 .897 .891 .884 .877 .870 .862 43
44 .948 .945 .941 .936 .932 .927 .922 .917 .911 .906 .899 .893 .886 .879 .872 .865 44
45 .950 .946 .942 .938 .934 .929 .924 .919 .914 .908 .902 .895 .889 .882 .875 .867 45
46 .952 .948 .944 .940 .936 .931 .926 .921 .916 .910 .904 .898 .891 .884 .877 .870 46
47 .954 .950 .946 .942 .938 .933 .929 .923 .918 .912 .906 .900 .894 .887 .880 .872 47
48 .955 .952 .948 .944 .940 .935 .931 .926 .920 .915 .909 .903 .896 .889 .882 .875 48
49 .957 .954 .950 .946 .942 .938 .933 .928 .923 .917 .911 .905 .899 .892 .885 .878 49
50 .959 .956 .952 .948 .944 .940 .935 .930 .925 .920 .914 .908 .901 .895 .888 .880 50
51 .961 .957 .954 .950 .946 .942 .938 .933 .928 .922 .917 .911 .904 .898 .891 .883 51
52 .962 .959 .956 .952 .948 .944 .940 .935 .930 .925 .919 .913 .907 .900 .894 .886 52
53 .964 .961 .958 .954 .950 .946 .942 .938 .933 .927 .922 .916 .910 .903 .897 .889 53
54 .966 .963 .960 .956 .953 .949 .945 .940 .935 .930 .925 .919 .913 .906 .900 .893 54
55 .968 .965 .962 .958 .955 .951 .947 .942 .938 .933 .927 .922 .916 .909 .903 .896 55
56 .969 .966 .963 .960 .957 .953 .949 .945 .940 .936 .930 .925 .919 .913 .906 .899 56
57 .971 .968 .965 .962 .959 .955 .952 .947 .943 .938 .933 .928 .922 .916 .909 .902 57
58 .972 .970 .967 .964 .961 .958 .954 .950 .946 .941 .936 .931 .925 .919 .913 .906 58
59 .974 .972 .969 .966 .963 .960 .956 .952 .948 .944 .939 .934 .928 .922 .916 .909 59
</TABLE>
NOTE: Factors for additional age combinations are available from the
Administrator.
-38-
<PAGE>
SPECIAL PROVISION D
FACTORS USED TO DETERMINE THE REDUCED ANNUAL RATE
OF RETIREMENT ANNUITY PAYABLE TO JOINT PENSIONERS
WHO ELECT VARIOUS OPTIONS WITH THEIR ELIGIBLE SPOUSE
50% OPTION ELECTION
-------------------
(Continued)
<TABLE>
<CAPTION>
SPOUSE'S SPOUSE'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 RETIREMENT
- ------------ ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- -----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
60 .976 .973 .971 .968 .965 .962 .959 .955 .951 .946 .942 .937 .931 .926 .919 .913 60
61 .977 .975 .973 .970 .967 .964 .961 .957 .953 .949 .945 .940 .934 .929 .923 .916 61
62 .979 .976 .974 .972 .969 .966 .963 .960 .956 .952 .947 .943 .938 .932 .926 .920 62
63 .980 .978 .976 .974 .971 .968 .965 .962 .958 .955 .950 .946 .941 .936 .930 .924 63
64 .981 .979 .977 .975 .973 .970 .967 .964 .961 .957 .953 .949 .944 .939 .933 .928 64
65 .983 .981 .979 .977 .975 .972 .970 .967 .963 .960 .956 .952 .947 .942 .937 .931 65
66 .984 .982 .980 .979 .976 .974 .972 .969 .966 .962 .959 .955 .950 .945 .940 .935 66
67 .985 .984 .982 .980 .978 .976 .974 .971 .968 .965 .961 .957 .953 .949 .944 .939 67
68 .986 .985 .983 .982 .980 .978 .975 .973 .970 .967 .964 .960 .956 .952 .947 .942 68
69 .987 .986 .985 .983 .981 .979 .977 .975 .972 .970 .966 .963 .959 .955 .951 .946 69
70 .988 .987 .986 .984 .983 .981 .979 .977 .974 .972 .969 .966 .962 .958 .954 .949 70
71 .989 .988 .987 .986 .984 .983 .981 .979 .976 .974 .971 .968 .965 .961 .957 .953 71
72 .990 .989 .988 .987 .985 .984 .982 .980 .978 .976 .973 .971 .967 .964 .960 .956 72
73 .991 .990 .989 .988 .987 .985 .984 .982 .980 .978 .976 .973 .970 .967 .963 .959 73
74 .992 .991 .990 .989 .988 .987 .985 .984 .982 .980 .978 .975 .972 .969 .966 .962 74
</TABLE>
NOTE: Factors for additional age combinations are available from the
Administrator. -39-
<PAGE>
SPECIAL PROVISION D
FACTORS USED TO DETERMINE THE REDUCED ANNUAL RATE
OF RETIREMENT ANNUITY PAYABLE TO JOINT PENSIONERS
WHO ELECT VARIOUS OPTIONS WITH THEIR ELIGIBLE SPOUSE
75% OPTION ELECTION
-------------------
<TABLE>
<CAPTION>
SPOUSE'S SPOUSE'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 RETIREMENT
- ------------ ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- -----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
40 .890 .883 .875 .868 .859 .851 .842 .833 .824 .814 .803 .793 .782 .771 .760 .748 40
41 .893 .886 .878 .871 .863 .854 .845 .836 .827 .817 .807 .796 .785 .774 .763 .751 41
42 .896 .889 .881 .874 .866 .857 .849 .840 .830 .820 .810 .800 .789 .778 .766 .754 42
43 .899 .892 .885 .877 .869 .861 .852 .843 .834 .824 .814 .803 .792 .781 .770 .758 43
44 .902 .895 .888 .880 .872 .864 .856 .847 .837 .827 .817 .807 .796 .785 .773 .762 44
45 .905 .898 .891 .884 .876 .868 .859 .850 .841 .831 .821 .811 .800 .789 .777 .765 45
46 .908 .901 .894 .887 .879 .871 .863 .854 .845 .835 .825 .814 .804 .792 .781 .769 46
47 .911 .905 .898 .891 .883 .875 .867 .858 .849 .839 .829 .819 .808 .797 .785 .773 47
48 .915 .908 .901 .894 .887 .879 .870 .862 .853 .843 .833 .823 .812 .801 .789 .778 48
49 .918 .911 .905 .898 .890 .883 .874 .866 .857 .847 .837 .827 .816 .805 .794 .782 49
50 .921 .915 .908 .901 .894 .886 .878 .870 .861 .851 .842 .831 .821 .810 .798 .786 50
51 .924 .918 .912 .905 .898 .890 .882 .874 .865 .856 .846 .836 .825 .814 .803 .791 51
52 .927 .922 .915 .909 .902 .894 .887 .878 .869 .860 .851 .840 .830 .819 .808 .796 52
53 .931 .925 .919 .912 .906 .898 .891 .883 .874 .865 .855 .845 .835 .824 .813 .801 53
54 .934 .928 .922 .916 .910 .902 .895 .887 .878 .869 .860 .850 .840 .829 .818 .806 54
55 .937 .932 .926 .920 .913 .906 .899 .891 .883 .874 .865 .855 .845 .834 .823 .811 55
56 .940 .935 .930 .924 .917 .911 .903 .896 .887 .879 .870 .860 .850 .839 .828 .817 56
57 .943 .938 .933 .927 .921 .915 .908 .900 .892 .884 .875 .865 .855 .845 .834 .822 57
58 .946 .942 .936 .931 .925 .919 .912 .905 .897 .888 .880 .870 .860 .850 .839 .828 58
59 .949 .945 .940 .935 .929 .923 .916 .909 .901 .893 .885 .876 .866 .856 .845 .834 59
</TABLE>
NOTE: Factors for additional age combinations are available from the
Administrator. -40-
<PAGE>
SPECIAL PROVISION D
FACTORS USED TO DETERMINE THE REDUCED ANNUAL RATE
OF RETIREMENT ANNUITY PAYABLE TO JOINT PENSIONERS
WHO ELECT VARIOUS OPTIONS WITH THEIR ELIGIBLE SPOUSE
75% OPTION ELECTION
-------------------
(Continued)
<TABLE>
<CAPTION>
SPOUSE'S SPOUSE'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 RETIREMENT
- ------------ ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- -----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
60 .952 .948 .943 .938 .933 .927 .920 .914 .906 .898 .890 .881 .871 .861 .851 .840 60
61 .955 .951 .946 .942 .936 .931 .925 .918 .911 .903 .895 .886 .877 .867 .857 .846 61
62 .958 .954 .950 .945 .940 .935 .929 .922 .915 .908 .900 .892 .883 .873 .863 .852 62
63 .961 .957 .953 .948 .944 .939 .933 .927 .920 .913 .905 .897 .888 .879 .869 .858 63
64 .963 .960 .956 .952 .947 .942 .937 .931 .925 .918 .910 .902 .894 .885 .875 .865 64
65 .966 .962 .959 .955 .951 .946 .941 .935 .929 .923 .916 .908 .900 .891 .881 .871 65
66 .968 .965 .962 .958 .954 .950 .945 .939 .934 .927 .921 .913 .905 .897 .887 .878 66
67 .971 .968 .964 .961 .957 .953 .948 .943 .938 .932 .925 .918 .911 .902 .894 .884 67
68 .973 .970 .967 .964 .960 .956 .952 .947 .942 .936 .930 .924 .916 .908 .900 .891 68
69 .975 .972 .970 .967 .963 .960 .956 .951 .946 .941 .935 .929 .922 .914 .906 .897 69
70 .977 .975 .972 .969 .966 .963 .959 .955 .950 .945 .940 .933 .927 .920 .912 .903 70
71 .979 .977 .974 .972 .969 .966 .962 .958 .954 .949 .944 .938 .932 .925 .918 .910 71
72 .981 .979 .976 .974 .971 .968 .965 .962 .958 .953 .948 .943 .937 .930 .923 .916 72
73 .982 .980 .978 .976 .974 .971 .968 .965 .961 .957 .952 .947 .942 .936 .929 .922 73
74 .984 .982 .980 .978 .976 .974 .971 .968 .964 .960 .956 .951 .946 .940 .934 .927 74
</TABLE>
NOTE: Factors for additional age combinations are available from the
Administrator. -41-
<PAGE>
SPECIAL PROVISION D
FACTORS USED TO DETERMINE THE REDUCED ANNUAL RATE
OF RETIREMENT ANNUITY PAYABLE TO JOINT PENSIONERS
WHO ELECT VARIOUS OPTIONS WITH THEIR ELIGIBLE SPOUSE
100% OPTION ELECTION
--------------------
<TABLE>
<CAPTION>
SPOUSE'S SPOUSE'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 RETIREMENT
- ------------ ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- -----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
40 .844 .834 .824 .814 .803 .792 .781 .769 .757 .744 .732 .719 .705 .692 .678 .664 40
41 .847 .838 .828 .818 .807 .796 .785 .773 .761 .748 .736 .723 .709 .696 .682 .668 41
42 .851 .842 .832 .822 .811 .800 .789 .777 .765 .753 .740 .727 .713 .700 .686 .672 42
43 .855 .846 .836 .826 .816 .805 .793 .782 .770 .757 .744 .731 .718 .704 .690 .676 43
44 .860 .850 .841 .831 .820 .809 .798 .786 .774 .762 .749 .736 .722 .709 .695 .680 44
45 .864 .855 .845 .835 .825 .814 .803 .791 .779 .766 .754 .740 .727 .713 .699 .685 45
46 .868 .859 .850 .840 .829 .819 .807 .796 .784 .771 .759 .745 .732 .718 .704 .690 46
47 .873 .864 .854 .844 .834 .824 .812 .801 .789 .776 .764 .750 .737 .723 .709 .695 47
48 .877 .868 .859 .849 .839 .829 .817 .806 .794 .782 .769 .756 .742 .728 .714 .700 48
49 .881 .873 .864 .854 .844 .834 .823 .811 .799 .787 .774 .761 .748 .734 .719 .705 49
50 .886 .877 .868 .859 .849 .839 .828 .817 .805 .793 .780 .767 .753 .739 .725 .711 50
51 .890 .882 .873 .864 .854 .844 .833 .822 .810 .798 .786 .772 .759 .745 .731 .716 51
52 .895 .887 .878 .869 .860 .850 .839 .828 .816 .804 .791 .778 .765 .751 .737 .722 52
53 .899 .892 .883 .874 .865 .855 .845 .834 .822 .810 .797 .784 .771 .757 .743 .728 53
54 .904 .896 .888 .879 .870 .860 .850 .839 .828 .816 .804 .791 .777 .763 .749 .735 54
55 .908 .901 .893 .884 .876 .866 .856 .845 .834 .822 .810 .797 .784 .770 .756 .741 55
56 .913 .906 .898 .890 .881 .872 .862 .851 .840 .829 .816 .804 .791 .777 .763 .748 56
57 .917 .910 .903 .895 .886 .877 .868 .857 .846 .835 .823 .810 .797 .784 .770 .755 57
58 .922 .915 .908 .900 .892 .883 .873 .863 .853 .842 .830 .817 .804 .791 .777 .762 58
59 .926 .919 .912 .905 .897 .888 .879 .870 .859 .848 .837 .824 .811 .798 .784 .770 59
</TABLE>
NOTE: Factors for additional age combinations are available from the
Administrator. -42-
<PAGE>
SPECIAL PROVISION D
FACTORS USED TO DETERMINE THE REDUCED ANNUAL RATE
OF RETIREMENT ANNUITY PAYABLE TO JOINT PENSIONERS
WHO ELECT VARIOUS OPTIONS WITH THEIR ELIGIBLE SPOUSE
100% OPTION ELECTION
--------------------
(Continued)
<TABLE>
<CAPTION>
SPOUSE'S SPOUSE'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 RETIREMENT
- ------------ ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
60 .930 .924 .917 .910 .902 .894 .885 .876 .866 .855 .843 .831 .819 .805 .792 .777 60
61 .934 .928 .922 .915 .908 .900 .891 .882 .872 .861 .850 .839 .826 .813 .799 .785 61
62 .938 .933 .926 .920 .913 .905 .897 .888 .878 .868 .857 .846 .834 .821 .807 .793 62
63 .942 .937 .931 .925 .918 .911 .903 .894 .885 .875 .864 .853 .841 .829 .815 .802 63
64 .946 .941 .935 .929 .923 .916 .908 .900 .891 .882 .871 .860 .849 .837 .824 .810 64
65 .950 .945 .940 .934 .928 .921 .914 .906 .897 .888 .878 .868 .857 .845 .832 .819 65
66 .953 .949 .944 .938 .933 .926 .919 .912 .904 .895 .885 .875 .864 .853 .840 .827 66
67 .957 .952 .948 .943 .937 .931 .925 .918 .910 .901 .892 .882 .872 .860 .848 .836 67
68 .960 .956 .951 .947 .942 .936 .930 .923 .916 .908 .899 .890 .879 .868 .857 .844 68
69 .963 .959 .955 .951 .946 .941 .935 .928 .921 .914 .906 .897 .887 .876 .865 .853 69
70 .966 .962 .959 .955 .950 .945 .940 .934 .927 .920 .912 .903 .894 .884 .873 .862 70
71 .969 .965 .962 .958 .954 .949 .944 .939 .932 .926 .918 .910 .901 .892 .881 .870 71
72 .971 .968 .965 .962 .958 .953 .949 .943 .938 .931 .924 .917 .908 .899 .889 .879 72
73 .974 .971 .968 .965 .961 .957 .953 .948 .943 .937 .930 .923 .915 .906 .897 .887 73
74 .976 .974 .971 .968 .965 .961 .957 .952 .947 .952 .936 .929 .921 .913 .904 .895 74
</TABLE>
NOTE: Factors for additional age combinations are available from the
Administrator. -43-
<PAGE>
SPECIAL PROVISION D
SPECIAL JOINT PENSION WITH SPOUSE
FACTORS USED TO DETERMINE THE REDUCED ANNUAL RATE
OF RETIREMENT ANNUITY PAYABLE TO JOINT PENSIONERS
WHO ELECT THE SPECIAL JOINT PENSION OPTION WITH THEIR SPOUSE
50% OPTION ELECTION
-------------------
<TABLE>
<CAPTION>
SPOUSE'S SPOUSE'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 RETIREMENT
- ------------ ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
20 .966 .964 .961 .959 .956 .953 .950 .947 .944 .940 .937 .933 .929 .926 .921 .917 20
21 .967 .964 .962 .959 .957 .954 .951 .948 .945 .941 .938 .934 .930 .926 .922 .918 21
22 .967 .965 .963 .960 .957 .955 .952 .949 .945 .942 .938 .935 .931 .927 .923 .919 22
23 .968 .966 .963 .961 .958 .955 .952 .949 .946 .943 .939 .936 .932 .928 .924 .920 23
24 .969 .966 .964 .961 .959 .956 .953 .950 .947 .944 .940 .937 .933 .929 .925 .921 24
25 .969 .967 .965 .962 .960 .957 .954 .951 .948 .944 .941 .937 .934 .930 .926 .921 25
26 .970 .968 .965 .963 .960 .958 .955 .952 .949 .945 .942 .938 .935 .931 .927 .922 26
27 .971 .969 .966 .964 .961 .959 .956 .953 .950 .946 .943 .939 .936 .932 .928 .923 27
28 .971 .969 .967 .965 .962 .959 .957 .954 .950 .947 .944 .940 .936 .933 .929 .924 28
29 .972 .970 .968 .965 .963 .960 .957 .954 .951 .948 .945 .941 .937 .934 .930 .925 29
30 .973 .971 .969 .966 .964 .961 .958 .955 .952 .949 .946 .942 .939 .935 .931 .927 30
31 .974 .972 .969 .967 .965 .962 .959 .956 .953 .950 .947 .943 .940 .936 .932 .928 31
32 .974 .972 .970 .968 .965 .963 .960 .957 .954 .951 .948 .944 .941 .937 .933 .929 32
33 .975 .973 .971 .969 .966 .964 .961 .958 .955 .952 .949 .945 .942 .938 .934 .930 33
34 .976 .974 .972 .970 .967 .965 .962 .959 .956 .953 .950 .947 .943 .939 .935 .931 34
35 .977 .975 .973 .970 .968 .966 .963 .960 .957 .954 .951 .948 .944 .940 .937 .933 35
36 .977 .975 .973 .971 .969 .967 .964 .961 .958 .955 .952 .949 .945 .942 .938 .934 36
37 .978 .976 .974 .972 .970 .968 .965 .962 .960 .957 .953 .950 .947 .943 .939 .935 37
38 .979 .977 .975 .973 .971 .969 .966 .963 .961 .958 .955 .951 .948 .944 .940 .937 38
39 .980 .978 .976 .974 .972 .970 .967 .964 .962 .959 .956 .952 .949 .946 .942 .938 39
</TABLE>
NOTE: Factors for additional age combinations are available from the
Administrator. -44-
<PAGE>
SPECIAL PROVISION D
SPECIAL JOINT PENSION WITH SPOUSE
FACTORS USED TO DETERMINE THE REDUCED ANNUAL RATE
OF RETIREMENT ANNUITY PAYABLE TO JOINT PENSIONERS
WHO ELECT THE SPECIAL JOINT PENSION OPTION WITH THEIR SPOUSE
50% OPTION ELECTION
-------------------
(continued)
<TABLE>
<CAPTION>
SPOUSE'S SPOUSE'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 RETIREMENT
- ------------ ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
40 .980 .979 .977 .975 .973 .970 .968 .966 .963 .960 .957 .954 .950 .947 .943 .939 40
41 .981 .979 .978 .976 .974 .971 .969 .967 .964 .961 .958 .955 .952 .948 .945 .941 41
42 .982 .980 .978 .977 .975 .972 .970 .968 .965 .962 .959 .956 .953 .950 .946 .942 42
43 .983 .981 .979 .977 .975 .973 .971 .969 .966 .963 .961 .958 .954 .951 .947 .944 43
44 .983 .982 .980 .978 .976 .974 .972 .970 .967 .965 .962 .959 .956 .952 .949 .945 44
45 .984 .982 .981 .979 .977 .975 .973 .971 .968 .966 .963 .960 .957 .954 .950 .947 45
46 .985 .983 .982 .980 .978 .976 .974 .972 .969 .967 .964 .961 .958 .955 .952 .948 46
47 .985 .984 .982 .981 .979 .977 .975 .973 .971 .968 .965 .963 .960 .957 .953 .950 47
48 .986 .984 .983 .981 .980 .978 .976 .974 .972 .969 .967 .964 .961 .958 .955 .951 48
49 .986 .985 .984 .982 .981 .979 .977 .975 .973 .970 .968 .965 .962 .959 .956 .953 49
50 .987 .986 .984 .983 .981 .980 .978 .976 .974 .971 .969 .966 .964 .961 .958 .954 50
51 .988 .986 .985 .984 .982 .981 .979 .977 .975 .973 .970 .968 .965 .962 .959 .956 51
52 .988 .987 .986 .984 .983 .981 .980 .978 .976 .974 .971 .969 .966 .963 .961 .957 52
53 .989 .988 .986 .985 .984 .982 .980 .979 .977 .975 .972 .970 .968 .965 .962 .959 53
54 .989 .988 .987 .986 .984 .983 .981 .980 .978 .976 .974 .971 .969 .966 .963 .960 54
55 .990 .989 .988 .986 .985 .984 .982 .980 .979 .977 .975 .972 .970 .968 .965 .962 55
56 .990 .989 .988 .987 .986 .984 .983 .981 .980 .978 .976 .974 .971 .969 .966 .963 56
57 .991 .990 .989 .988 .987 .985 .984 .982 .981 .979 .977 .975 .973 .970 .968 .965 57
58 .991 .990 .989 .988 .987 .986 .985 .983 .981 .980 .978 .976 .974 .971 .969 .966 58
59 .992 .991 .990 .989 .988 .987 .985 .984 .982 .981 .979 .977 .975 .973 .970 .968 59
</TABLE>
NOTE: Factors for additional age combinations are available from the
Administrator. -45-
<PAGE>
SPECIAL PROVISION D
SPECIAL JOINT PENSION WITH SPOUSE
FACTORS USED TO DETERMINE THE REDUCED ANNUAL RATE
OF RETIREMENT ANNUITY PAYABLE TO JOINT PENSIONERS
WHO ELECT THE SPECIAL JOINT PENSION OPTION WITH THEIR SPOUSE
50% OPTION ELECTION
-------------------
(continued)
<TABLE>
<CAPTION>
SPOUSE'S SPOUSE'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 RETIREMENT
- ------------ ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
60 .992 .991 .990 .989 .988 .987 .986 .985 .983 .981 .980 .978 .976 .974 .972 .969 60
61 .993 .992 .991 .990 .989 .988 .987 .985 .984 .982 .981 .979 .977 .975 .973 .971 61
62 .993 .992 .991 .991 .990 .988 .987 .986 .985 .983 .982 .980 .978 .976 .974 .972 62
63 .993 .993 .992 .991 .990 .989 .988 .987 .985 .984 .983 .981 .979 .977 .975 .973 63
64 .994 .993 .992 .991 .991 .990 .989 .987 .986 .985 .983 .982 .980 .978 .976 .974 64
65 .994 .993 .993 .992 .991 .990 .989 .988 .987 .986 .984 .983 .981 .979 .978 .976 65
66 .994 .994 .993 .992 .992 .991 .990 .989 .988 .986 .985 .984 .982 .980 .979 .977 66
67 .995 .994 .994 .993 .992 .991 .990 .989 .988 .987 .986 .984 .983 .981 .980 .978 67
68 .995 .994 .994 .993 .993 .992 .991 .990 .989 .988 .987 .985 .984 .982 .981 .979 68
69 .995 .995 .994 .994 .993 .992 .991 .990 .989 .988 .987 .986 .985 .983 .982 .980 69
70 .996 .995 .995 .994 .993 .993 .992 .991 .990 .989 .988 .987 .986 .984 .983 .981 70
71 .996 .995 .995 .994 .994 .993 .992 .991 .991 .990 .989 .987 .986 .985 .984 .982 71
72 .996 .996 .995 .995 .994 .993 .993 .992 .991 .990 .989 .988 .987 .986 .985 .983 72
73 .996 .996 .996 .995 .994 .994 .993 .992 .992 .991 .990 .989 .988 .987 .985 .984 73
74 .997 .996 .996 .995 .995 .994 .994 .993 .992 .991 .990 .989 .988 .987 .986 .985 74
75 .997 .996 .996 .996 .995 .995 .994 .993 .993 .992 .991 .990 .989 .988 .987 .986 75
76 .997 .997 .996 .996 .995 .995 .994 .994 .993 .992 .992 .991 .990 .989 .988 .987 76
77 .997 .997 .997 .996 .996 .995 .995 .994 .993 .993 .992 .991 .990 .989 .988 .987 77
78 .997 .997 .997 .996 .996 .996 .995 .994 .994 .993 .992 .992 .991 .990 .989 .988 78
79 .998 .997 .997 .997 .996 .996 .995 .995 .994 .994 .993 .992 .991 .991 .990 .989 79
</TABLE>
NOTE: Factors for additional age combinations are available from the
Administrator. -46-
<PAGE>
SPECIAL PROVISION D
SPECIAL JOINT PENSION WITH SPOUSE
FACTORS USED TO DETERMINE THE REDUCED ANNUAL RATE
OF RETIREMENT ANNUITY PAYABLE TO JOINT PENSIONERS
WHO ELECT THE SPECIAL JOINT PENSION OPTION WITH THEIR SPOUSE
50% OPTION ELECTION
-------------------
(continued)
<TABLE>
<CAPTION>
SPOUSE'S SPOUSE'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 RETIREMENT
- ------------ ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
80 .998 .997 .997 .997 .997 .996 .996 .995 .995 .994 .993 .993 .992 .991 .990 .990 80
81 .998 .998 .997 .997 .997 .996 .996 .995 .995 .994 .994 .993 .993 .992 .991 .990 81
82 .998 .998 .998 .997 .997 .997 .996 .996 .995 .995 .994 .994 .993 .992 .992 .991 82
83 .998 .998 .998 .997 .997 .997 .996 .996 .996 .995 .995 .994 .993 .993 .992 .991 83
84 .998 .998 .998 .998 .997 .997 .997 .996 .996 .995 .995 .994 .994 .993 .993 .992 84
85 .998 .998 .998 .998 .998 .997 .997 .997 .996 .996 .995 .995 .994 .994 .993 .992 85
86 .999 .998 .998 .998 .998 .997 .997 .997 .996 .996 .996 .995 .995 .994 .994 .993 86
87 .999 .998 .998 .998 .998 .998 .997 .997 .997 .996 .996 .995 .995 .995 .994 .993 87
88 .999 .999 .998 .998 .998 .998 .998 .997 .997 .997 .996 .996 .995 .995 .994 .994 88
89 .999 .999 .999 .998 .998 .998 .998 .997 .997 .997 .996 .996 .996 .995 .995 .994 89
</TABLE>
NOTE: Factors for additional age combinations are available from the
Administrator.
-47-
<PAGE>
SPECIAL PROVISION D
SPECIAL JOINT PENSION WITH SPOUSE
FACTORS USED TO DETERMINE THE REDUCED ANNUAL RATE
OF RETIREMENT ANNUITY PAYABLE TO JOINT PENSIONERS
WHO ELECT THE SPECIAL JOINT PENSION OPTION WITH THEIR SPOUSE
50% OPTION ELECTION
-------------------
<TABLE>
<CAPTION>
SPOUSE'S SPOUSE'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 RETIREMENT
- ------------ ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
20 .917 .913 .908 .903 .898 .893 .888 .882 .876 .870 .864 .857 .850 .843 .836 .828 20
21 .918 .913 .909 .904 .899 .894 .888 .883 .877 .871 .865 .858 .851 .844 .837 .829 21
22 .919 .914 .910 .905 .900 .895 .889 .884 .878 .872 .865 .859 .852 .845 .838 .830 22
23 .920 .915 .911 .906 .901 .896 .890 .885 .879 .873 .866 .860 .853 .846 .838 .831 23
24 .921 .916 .912 .907 .902 .897 .891 .886 .880 .874 .867 .861 .854 .847 .839 .832 24
25 .921 .917 .912 .908 .903 .898 .892 .887 .881 .875 .868 .862 .855 .848 .840 .833 25
26 .922 .918 .913 .909 .904 .899 .893 .888 .882 .876 .869 .863 .856 .849 .841 .834 26
27 .923 .919 .914 .910 .905 .900 .894 .889 .883 .877 .870 .864 .857 .850 .842 .835 27
28 .924 .920 .916 .911 .906 .901 .895 .890 .884 .878 .871 .865 .858 .851 .844 .836 28
29 .925 .921 .917 .912 .907 .902 .896 .891 .885 .879 .873 .866 .859 .852 .845 .837 29
30 .927 .922 .918 .913 .908 .903 .898 .892 .886 .880 .874 .867 .860 .853 .846 .838 30
31 .928 .923 .919 .914 .909 .904 .899 .893 .887 .881 .875 .868 .862 .855 .847 .840 31
32 .929 .925 .920 .915 .911 .905 .900 .895 .889 .883 .876 .870 .863 .856 .849 .841 32
33 .930 .926 .921 .917 .912 .907 .901 .896 .890 .884 .878 .871 .864 .857 .850 .842 33
34 .931 .927 .923 .918 .913 .908 .903 .897 .891 .885 .879 .873 .866 .859 .851 .844 34
35 .933 .928 .924 .919 .915 .909 .904 .899 .893 .887 .881 .874 .867 .860 .853 .845 35
36 .934 .930 .925 .921 .916 .911 .906 .900 .894 .888 .882 .876 .869 .862 .854 .847 36
37 .935 .931 .927 .922 .917 .912 .907 .902 .896 .890 .884 .877 .870 .863 .856 .849 37
38 .937 .932 .928 .924 .919 .914 .909 .903 .897 .892 .885 .879 .872 .865 .858 .850 38
39 .938 .934 .930 .925 .920 .915 .910 .905 .899 .893 .887 .880 .874 .867 .859 .852 39
</TABLE>
NOTE: Factors for additional age combinations are available from the
Administrator. -48-
<PAGE>
SPECIAL PROVISION D
SPECIAL JOINT PENSION WITH SPOUSE
FACTORS USED TO DETERMINE THE REDUCED ANNUAL RATE
OF RETIREMENT ANNUITY PAYABLE TO JOINT PENSIONERS
WHO ELECT THE SPECIAL JOINT PENSION OPTION WITH THEIR SPOUSE
50% OPTION ELECTION
-------------------
(continued)
<TABLE>
<CAPTION>
SPOUSE'S SPOUSE'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 RETIREMENT
- ------------ ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
40 .939 .935 .931 .927 .922 .917 .912 .906 .901 .895 .889 .882 .875 .868 .861 .854 40
41 .941 .937 .933 .928 .924 .919 .914 .908 .903 .897 .890 .884 .877 .870 .863 .856 41
42 .942 .938 .934 .930 .925 .920 .915 .910 .904 .898 .892 .886 .879 .872 .865 .858 42
43 .944 .940 .936 .931 .927 .922 .917 .912 .906 .900 .894 .888 .881 .874 .867 .860 43
44 .945 .941 .937 .933 .929 .924 .919 .914 .908 .902 .896 .890 .883 .876 .869 .862 44
45 .947 .943 .939 .935 .930 .926 .921 .915 .910 .904 .898 .892 .885 .878 .871 .864 45
46 .948 .944 .941 .936 .932 .927 .922 .917 .912 .906 .900 .894 .887 .880 .873 .866 46
47 .950 .946 .942 .938 .934 .929 .924 .919 .914 .908 .902 .896 .889 .883 .876 .868 47
48 .951 .948 .944 .940 .936 .931 .926 .921 .916 .910 .904 .898 .892 .885 .878 .871 48
49 .953 .949 .946 .942 .937 .933 .928 .923 .918 .912 .907 .900 .894 .887 .880 .873 49
50 .954 .951 .947 .943 .939 .935 .930 .925 .920 .915 .909 .903 .896 .890 .883 .875 50
51 .956 .953 .949 .945 .941 .937 .932 .927 .922 .917 .911 .905 .899 .892 .885 .878 51
52 .957 .954 .951 .947 .943 .939 .934 .929 .924 .919 .913 .907 .901 .895 .888 .880 52
53 .959 .956 .952 .949 .945 .941 .936 .932 .927 .921 .916 .910 .904 .897 .890 .883 53
54 .960 .957 .954 .950 .947 .943 .938 .934 .929 .924 .918 .912 .906 .900 .893 .886 54
55 .962 .959 .956 .952 .948 .945 .940 .936 .931 .926 .920 .915 .909 .902 .896 .889 55
56 .963 .960 .957 .954 .950 .946 .942 .938 .933 .928 .923 .917 .911 .905 .898 .891 56
57 .965 .962 .959 .956 .952 .948 .944 .940 .935 .931 .925 .920 .914 .908 .901 .894 57
58 .966 .964 .961 .957 .954 .950 .946 .942 .938 .933 .928 .922 .917 .910 .904 .897 58
59 .968 .965 .962 .959 .956 .952 .948 .944 .940 .935 .930 .925 .919 .913 .907 .900 59
</TABLE>
NOTE: Factors for additional age combinations are available from the
Administrator. -49-
<PAGE>
SPECIAL PROVISION D
SPECIAL JOINT PENSION WITH SPOUSE
FACTORS USED TO DETERMINE THE REDUCED ANNUAL RATE
OF RETIREMENT ANNUITY PAYABLE TO JOINT PENSIONERS
WHO ELECT THE SPECIAL JOINT PENSION OPTION WITH THEIR SPOUSE
50% OPTION ELECTION
-------------------
(continued)
<TABLE>
<CAPTION>
SPOUSE'S SPOUSE'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 RETIREMENT
- ------------ ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
60 .969 .967 .964 .961 .958 .954 .950 .946 .942 .938 .933 .927 .922 .916 .910 .903 60
61 .971 .968 .965 .962 .959 .956 .952 .949 .944 .940 .935 .930 .925 .919 .913 .906 61
62 .972 .969 .967 .964 .961 .958 .954 .951 .947 .942 .938 .933 .927 .922 .916 .909 62
63 .973 .971 .968 .966 .963 .960 .956 .953 .949 .945 .940 .935 .930 .924 .919 .912 63
64 .974 .972 .970 .967 .965 .962 .958 .955 .951 .947 .942 .938 .933 .927 .922 .916 64
65 .976 .974 .971 .969 .966 .963 .960 .957 .953 .949 .945 .940 .935 .930 .925 .919 65
66 .977 .975 .973 .970 .968 .965 .962 .959 .955 .951 .947 .943 .938 .933 .928 .922 66
67 .978 .976 .974 .972 .969 .967 .964 .961 .957 .954 .950 .945 .941 .936 .930 .925 67
68 .979 .977 .975 .973 .971 .968 .966 .963 .959 .956 .952 .948 .943 .939 .933 .928 68
69 .980 .978 .977 .975 .972 .970 .967 .964 .961 .958 .954 .950 .946 .941 .936 .931 69
70 .981 .980 .978 .976 .974 .971 .969 .966 .963 .960 .956 .953 .948 .944 .939 .934 70
71 .982 .981 .979 .977 .975 .973 .971 .968 .965 .962 .959 .955 .951 .947 .942 .937 71
72 .983 .982 .980 .978 .976 .974 .972 .970 .967 .964 .961 .957 .953 .949 .945 .940 72
73 .984 .983 .981 .979 .978 .976 .974 .971 .969 .966 .963 .959 .956 .952 .947 .943 73
74 .985 .984 .982 .981 .979 .977 .975 .973 .970 .968 .965 .961 .958 .954 .950 .946 74
75 .986 .985 .983 .982 .980 .978 .976 .974 .972 .969 .967 .963 .960 .956 .953 .948 75
76 .987 .985 .984 .983 .981 .980 .978 .976 .973 .971 .968 .965 .962 .959 .955 .951 76
77 .987 .986 .985 .984 .982 .981 .979 .977 .975 .973 .970 .967 .964 .961 .957 .954 77
78 .988 .987 .986 .985 .983 .982 .980 .978 .976 .974 .972 .969 .966 .963 .960 .956 78
79 .989 .988 .987 .986 .984 .983 .981 .980 .978 .976 .974 .971 .968 .965 .962 .959 79
</TABLE>
NOTE: Factors for additional age combinations are available from the
Administrator. -50-
<PAGE>
SPECIAL PROVISION D
SPECIAL JOINT PENSION WITH SPOUSE
FACTORS USED TO DETERMINE THE REDUCED ANNUAL RATE
OF RETIREMENT ANNUITY PAYABLE TO JOINT PENSIONERS
WHO ELECT THE SPECIAL JOINT PENSION OPTION WITH THEIR SPOUSE
50% OPTION ELECTION
-------------------
(continued)
<TABLE>
<CAPTION>
SPOUSE'S SPOUSE'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 RETIREMENT
- ------------ ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- -----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
80 .990 .989 .988 .986 .985 .984 .983 .981 .979 .977 .975 .973 .970 .967 .964 .961 80
81 .990 .989 .988 .987 .986 .985 .984 .982 .980 .979 .977 .974 .972 .969 .966 .963 81
82 .991 .990 .989 .988 .987 .986 .985 .983 .982 .980 .978 .976 .974 .971 .968 .965 82
83 .991 .991 .990 .989 .988 .987 .986 .984 .983 .981 .979 .978 .975 .973 .970 .968 83
84 .992 .991 .990 .990 .989 .988 .987 .985 .984 .982 .981 .979 .977 .975 .972 .970 84
85 .992 .992 .991 .990 .989 .988 .987 .986 .985 .984 .982 .980 .978 .976 .974 .972 85
86 .993 .992 .992 .991 .990 .989 .988 .987 .986 .985 .983 .982 .980 .978 .976 .973 86
87 .993 .993 .992 .992 .991 .990 .989 .988 .987 .986 .984 .983 .981 .979 .977 .975 87
88 .994 .993 .993 .992 .991 .991 .990 .989 .988 .987 .985 .984 .983 .981 .979 .977 88
89 .994 .994 .993 .993 .992 .991 .991 .990 .989 .988 .987 .985 .984 .982 .980 .978 89
</TABLE>
NOTE: Factors for additional age combinations are available from the
Administrator. -51-
<PAGE>
SPECIAL PROVISION D
SPECIAL JOINT PENSION WITH SPOUSE
FACTORS USED TO DETERMINE THE REDUCED ANNUAL RATE
OF RETIREMENT ANNUITY PAYABLE TO JOINT PENSIONERS
WHO ELECT THE SPECIAL JOINT PENSION OPTION WITH THEIR SPOUSE
100% OPTION ELECTION
--------------------
<TABLE>
<CAPTION>
SPOUSE'S SPOUSE'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 RETIREMENT
- ------------ ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
20 .904 .898 .892 .885 .879 .872 .864 .856 .849 .840 .832 .823 .815 .805 .796 .787 20
21 .906 .900 .894 .887 .880 .873 .866 .858 .850 .842 .834 .825 .816 .807 .798 .788 21
22 .908 .902 .896 .889 .882 .875 .868 .860 .852 .844 .836 .827 .818 .809 .800 .790 22
23 .909 .904 .897 .891 .884 .877 .870 .862 .854 .846 .838 .829 .820 .811 .802 .792 23
24 .911 .905 .899 .893 .886 .879 .872 .864 .856 .848 .840 .831 .822 .813 .804 .794 24
25 .913 .907 .901 .895 .888 .881 .874 .866 .858 .850 .842 .833 .824 .815 .806 .796 25
26 .915 .909 .903 .897 .890 .883 .876 .868 .860 .852 .844 .835 .826 .817 .808 .798 26
27 .917 .911 .905 .899 .892 .885 .878 .870 .862 .854 .846 .837 .829 .820 .810 .801 27
28 .919 .913 .907 .901 .894 .887 .880 .872 .865 .857 .848 .840 .831 .822 .813 .803 28
29 .921 .915 .909 .903 .896 .889 .882 .875 .867 .859 .851 .842 .833 .824 .815 .805 29
30 .923 .917 .911 .905 .899 .892 .885 .877 .869 .861 .853 .845 .836 .827 .817 .808 30
31 .925 .919 .913 .907 .901 .894 .887 .880 .872 .864 .856 .847 .838 .829 .820 .811 31
32 .927 .921 .916 .909 .903 .896 .889 .882 .874 .866 .858 .850 .841 .832 .823 .813 32
33 .929 .923 .918 .912 .905 .899 .892 .884 .877 .869 .861 .852 .844 .835 .825 .816 33
34 .931 .926 .920 .914 .908 .901 .894 .887 .879 .872 .864 .855 .846 .838 .828 .819 34
35 .933 .928 .922 .916 .910 .904 .897 .890 .882 .874 .866 .858 .849 .840 .831 .822 35
36 .935 .930 .924 .919 .913 .906 .899 .892 .885 .877 .869 .861 .852 .843 .834 .825 36
37 .937 .932 .927 .921 .915 .909 .902 .895 .888 .880 .872 .864 .855 .846 .837 .828 37
38 .939 .934 .929 .923 .917 .911 .905 .898 .890 .883 .875 .867 .858 .850 .840 .831 38
39 .941 .936 .931 .926 .920 .914 .907 .900 .893 .886 .878 .870 .861 .853 .844 .834 39
</TABLE>
NOTE: Factors for additional age combinations are available from the
Administrator. -52-
<PAGE>
SPECIAL PROVISION D
SPECIAL JOINT PENSION WITH SPOUSE
FACTORS USED TO DETERMINE THE REDUCED ANNUAL RATE
OF RETIREMENT ANNUITY PAYABLE TO JOINT PENSIONERS
WHO ELECT THE SPECIAL JOINT PENSION OPTION WITH THEIR SPOUSE
100% OPTION ELECTION
--------------------
(continued)
<TABLE>
<CAPTION>
SPOUSE'S SPOUSE'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 RETIREMENT
- ------------ ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
40 .943 .939 .934 .928 .922 .916 .910 .903 .896 .889 .881 .873 .865 .856 .847 .838 40
41 .945 .941 .936 .930 .925 .919 .913 .906 .899 .892 .884 .876 .868 .859 .850 .841 41
42 .947 .943 .938 .933 .927 .921 .915 .909 .902 .895 .887 .879 .871 .863 .854 .845 42
43 .949 .945 .940 .935 .930 .924 .918 .912 .905 .898 .890 .883 .874 .866 .857 .848 43
44 .951 .947 .942 .937 .932 .927 .921 .914 .908 .901 .893 .886 .878 .869 .861 .852 44
45 .953 .949 .945 .940 .935 .929 .923 .917 .911 .904 .897 .889 .881 .873 .864 .856 45
46 .955 .951 .947 .942 .937 .932 .926 .920 .914 .907 .900 .892 .885 .876 .868 .859 46
47 .957 .953 .949 .944 .939 .934 .929 .923 .916 .910 .903 .896 .888 .880 .872 .863 47
48 .959 .955 .951 .946 .942 .937 .931 .925 .919 .913 .906 .899 .891 .884 .875 .867 48
49 .960 .957 .953 .949 .944 .939 .934 .928 .922 .916 .909 .902 .895 .887 .879 .871 49
50 .962 .959 .955 .951 .946 .941 .936 .931 .925 .919 .912 .906 .898 .891 .883 .875 50
51 .964 .960 .957 .953 .948 .944 .939 .934 .928 .922 .916 .909 .902 .894 .887 .878 51
52 .965 .962 .959 .955 .951 .946 .941 .936 .931 .925 .919 .912 .905 .898 .890 .882 52
53 .967 .964 .960 .957 .953 .948 .944 .939 .933 .928 .922 .915 .909 .902 .894 .886 53
54 .969 .966 .962 .959 .955 .951 .946 .941 .936 .931 .925 .918 .912 .905 .898 .890 54
55 .970 .967 .964 .960 .957 .953 .948 .944 .939 .933 .928 .922 .915 .909 .901 .894 55
56 .971 .969 .966 .962 .959 .955 .951 .946 .941 .936 .931 .925 .919 .912 .905 .898 56
57 .973 .970 .967 .964 .961 .957 .953 .948 .944 .939 .933 .928 .922 .915 .909 .902 57
58 .974 .972 .969 .966 .962 .959 .955 .951 .946 .941 .936 .931 .925 .919 .912 .905 58
59 .975 .973 .970 .967 .964 .961 .957 .953 .949 .944 .939 .934 .928 .922 .916 .909 59
</TABLE>
NOTE: Factors for additional age combinations are available from the
Administrator. -53-
<PAGE>
SPECIAL PROVISION D
SPECIAL JOINT PENSION WITH SPOUSE
FACTORS USED TO DETERMINE THE REDUCED ANNUAL RATE
OF RETIREMENT ANNUITY PAYABLE TO JOINT PENSIONERS
WHO ELECT THE SPECIAL JOINT PENSION OPTION WITH THEIR SPOUSE
100% OPTION ELECTION
--------------------
(continued)
<TABLE>
<CAPTION>
SPOUSE'S SPOUSE'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 RETIREMENT
- ------------ ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- -----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
60 .977 .974 .972 .969 .966 .963 .959 .955 .951 .946 .942 .937 .931 .925 .919 .913 60
61 .978 .976 .973 .971 .968 .964 .961 .957 .953 .949 .944 .939 .934 .929 .923 .917 61
62 .979 .977 .975 .972 .969 .966 .963 .959 .955 .951 .947 .942 .937 .932 .926 .920 62
63 .980 .978 .976 .974 .971 .968 .965 .961 .958 .954 .949 .945 .940 .935 .929 .924 63
64 .981 .979 .977 .975 .972 .970 .967 .963 .960 .956 .952 .947 .943 .938 .933 .927 64
65 .982 .981 .978 .976 .974 .971 .968 .965 .962 .958 .954 .950 .945 .941 .936 .930 65
66 .983 .982 .980 .978 .975 .973 .970 .967 .964 .960 .956 .952 .948 .944 .939 .934 66
67 .984 .983 .981 .979 .977 .974 .971 .969 .965 .962 .959 .955 .951 .946 .942 .937 67
68 .985 .984 .982 .980 .978 .976 .973 .970 .967 .964 .961 .957 .953 .949 .945 .940 68
69 .986 .985 .983 .981 .979 .977 .974 .972 .969 .966 .963 .959 .955 .952 .947 .943 69
70 .987 .985 .984 .982 .980 .978 .976 .973 .971 .968 .965 .961 .958 .954 .950 .946 70
71 .988 .986 .985 .983 .981 .979 .977 .975 .972 .970 .967 .963 .960 .956 .953 .948 71
72 .988 .987 .986 .984 .983 .981 .979 .976 .974 .971 .968 .965 .962 .959 .955 .951 72
73 .989 .988 .987 .985 .984 .982 .980 .978 .975 .973 .970 .967 .964 .961 .957 .954 73
74 .990 .989 .987 .986 .985 .983 .981 .979 .977 .974 .972 .969 .966 .963 .960 .956 74
75 .990 .989 .988 .987 .986 .984 .982 .980 .978 .976 .973 .971 .968 .965 .962 .959 75
76 .991 .990 .989 .988 .986 .985 .983 .981 .979 .977 .975 .972 .970 .967 .964 .961 76
77 .992 .991 .990 .989 .987 .986 .984 .983 .981 .979 .976 .974 .972 .969 .966 .963 77
78 .992 .991 .990 .989 .988 .987 .985 .984 .982 .980 .978 .976 .973 .971 .968 .965 78
79 .993 .992 .991 .990 .989 .988 .986 .985 .983 .981 .979 .977 .975 .972 .970 .967 79
</TABLE>
NOTE: Factors for additional age combinations are available from the
Administrator. -54-
<PAGE>
SPECIAL PROVISION D
SPECIAL JOINT PENSION WITH SPOUSE
FACTORS USED TO DETERMINE THE REDUCED ANNUAL RATE
OF RETIREMENT ANNUITY PAYABLE TO JOINT PENSIONERS
WHO ELECT THE SPECIAL JOINT PENSION OPTION WITH THEIR SPOUSE
100% OPTION ELECTION
--------------------
(continued)
<TABLE>
<CAPTION>
SPOUSE'S SPOUSE'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 RETIREMENT
- ------------ ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- -----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
80 .993 .992 .992 .991 .990 .988 .987 .986 .984 .982 .980 .978 .976 .974 .972 .969 80
81 .994 .993 .992 .991 .990 .989 .988 .987 .985 .983 .982 .980 .978 .976 .973 .971 81
82 .994 .993 .993 .992 .991 .990 .989 .987 .986 .985 .983 .981 .979 .977 .975 .973 82
83 .995 .994 .993 .992 .992 .991 .990 .988 .987 .986 .984 .982 .981 .979 .977 .975 83
84 .995 .994 .994 .993 .992 .991 .990 .989 .988 .986 .985 .983 .982 .980 .978 .976 84
85 .995 .995 .994 .994 .993 .992 .991 .990 .989 .987 .986 .985 .983 .981 .980 .978 85
86 .996 .995 .995 .994 .993 .992 .992 .991 .989 .988 .987 .986 .984 .983 .981 .979 86
87 .996 .995 .995 .994 .994 .993 .992 .991 .990 .989 .988 .987 .985 .984 .982 .981 87
88 .996 .996 .995 .995 .994 .994 .993 .992 .991 .990 .989 .988 .986 .985 .983 .982 88
89 .996 .996 .996 .995 .995 .994 .993 .993 .992 .991 .990 .988 .987 .986 .985 .983 89
</TABLE>
NOTE: Factors for additional age combinations are available from the
Administrator. -55-
<PAGE>
SPECIAL PROVISION D
SPECIAL JOINT PENSION WITH SPOUSE
FACTORS USED TO DETERMINE THE REDUCED ANNUAL RATE
OF RETIREMENT ANNUITY PAYABLE TO JOINT PENSIONERS
WHO ELECT THE SPECIAL JOINT PENSION OPTION WITH THEIR SPOUSE
100% OPTION ELECTION
--------------------
<TABLE>
<CAPTION>
SPOUSE'S SPOUSE'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 RETIREMENT
- ----------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- -----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
20 .787 .777 .767 .757 .746 .736 .725 .714 .702 .691 .679 .667 .654 .642 .629 .617 20
21 .788 .779 .769 .759 .748 .737 .726 .715 .704 .692 .680 .668 .656 .643 .631 .618 21
22 .790 .781 .771 .760 .750 .739 .728 .717 .705 .694 .682 .670 .657 .645 .632 .620 22
23 .792 .782 .772 .762 .752 .741 .730 .719 .707 .695 .683 .671 .659 .646 .634 .621 23
24 .794 .784 .774 .764 .754 .743 .732 .721 .709 .697 .685 .673 .661 .648 .635 .623 24
25 .796 .787 .776 .766 .756 .745 .734 .723 .711 .699 .687 .675 .662 .650 .637 .624 25
26 .798 .789 .779 .768 .758 .747 .736 .725 .713 .701 .689 .677 .664 .652 .639 .626 26
27 .801 .791 .781 .771 .760 .749 .738 .727 .715 .703 .691 .679 .666 .653 .641 .628 27
28 .803 .793 .783 .773 .762 .751 .740 .729 .717 .705 .693 .681 .668 .655 .643 .630 28
29 .805 .796 .786 .775 .765 .754 .743 .731 .719 .708 .695 .683 .670 .658 .645 .632 29
30 .808 .798 .788 .778 .767 .756 .745 .734 .722 .710 .698 .685 .673 .660 .647 .634 30
31 .811 .801 .791 .780 .770 .759 .748 .736 .724 .712 .700 .688 .675 .662 .649 .636 31
32 .813 .803 .793 .783 .772 .761 .750 .739 .727 .715 .703 .690 .677 .664 .651 .638 32
33 .816 .806 .796 .786 .775 .764 .753 .741 .730 .718 .705 .693 .680 .667 .654 .641 33
34 .819 .809 .799 .789 .778 .767 .756 .744 .732 .720 .708 .695 .682 .669 .656 .643 34
35 .822 .812 .802 .792 .781 .770 .759 .747 .735 .723 .711 .698 .685 .672 .659 .646 35
36 .825 .815 .805 .795 .784 .773 .762 .750 .738 .726 .714 .701 .688 .675 .662 .648 36
37 .828 .818 .808 .798 .787 .776 .765 .753 .742 .729 .717 .704 .691 .678 .665 .651 37
38 .831 .821 .811 .801 .791 .780 .768 .757 .745 .733 .720 .707 .694 .681 .668 .654 38
39 .834 .825 .815 .805 .794 .783 .772 .760 .748 .736 .723 .711 .698 .684 .671 .657 39
</TABLE>
NOTE: Factors for additional age combinations are available from the
Administrator. -56-
<PAGE>
SPECIAL PROVISION D
SPECIAL JOINT PENSION WITH SPOUSE
FACTORS USED TO DETERMINE THE REDUCED ANNUAL RATE
OF RETIREMENT ANNUITY PAYABLE TO JOINT PENSIONERS
WHO ELECT THE SPECIAL JOINT PENSION OPTION WITH THEIR SPOUSE
100% OPTION ELECTION
--------------------
(continued)
<TABLE>
<CAPTION>
SPOUSE'S SPOUSE'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 RETIREMENT
- ---------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- -----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
40 .838 .828 .818 .808 .797 .787 .775 .764 .752 .739 .727 .714 .701 .688 .674 .661 40
41 .841 .832 .822 .812 .801 .790 .779 .767 .755 .743 .730 .718 .704 .691 .678 .664 41
42 .845 .835 .825 .815 .805 .794 .783 .771 .759 .747 .734 .721 .708 .695 .681 .667 42
43 .848 .839 .829 .819 .808 .798 .786 .775 .763 .751 .738 .725 .712 .698 .685 .671 43
44 .852 .843 .833 .823 .812 .802 .790 .779 .767 .755 .742 .729 .716 .702 .689 .675 44
45 .856 .846 .837 .827 .816 .806 .794 .783 .771 .759 .746 .733 .720 .706 .693 .679 45
46 .859 .850 .841 .831 .820 .810 .799 .787 .775 .763 .750 .737 .724 .711 .697 .683 46
47 .863 .854 .845 .835 .825 .814 .803 .791 .780 .767 .755 .742 .728 .715 .701 .687 47
48 .867 .858 .849 .839 .829 .818 .807 .796 .784 .772 .759 .746 .733 .719 .705 .691 48
49 .871 .862 .853 .843 .833 .823 .812 .800 .789 .776 .764 .751 .738 .724 .710 .696 49
50 .875 .866 .857 .847 .837 .827 .816 .805 .793 .781 .769 .756 .742 .729 .715 .701 50
51 .878 .870 .861 .852 .842 .832 .821 .810 .798 .786 .773 .761 .747 .734 .720 .706 51
52 .882 .874 .865 .856 .846 .836 .825 .814 .803 .791 .778 .766 .752 .739 .725 .711 52
53 .886 .878 .869 .860 .851 .841 .830 .819 .808 .796 .784 .771 .757 .744 .730 .716 53
54 .890 .882 .874 .865 .855 .845 .835 .824 .813 .801 .789 .776 .763 .749 .735 .721 54
55 .894 .886 .878 .869 .860 .850 .840 .829 .818 .806 .794 .781 .768 .755 .741 .727 55
56 .898 .890 .882 .873 .864 .855 .845 .834 .823 .812 .799 .787 .774 .760 .747 .732 56
57 .902 .894 .886 .878 .869 .860 .850 .839 .828 .817 .805 .793 .780 .766 .752 .738 57
58 .905 .898 .890 .882 .874 .864 .855 .845 .834 .822 .811 .798 .785 .772 .758 .744 58
59 .909 .902 .895 .887 .878 .869 .860 .850 .839 .828 .816 .804 .791 .778 .764 .750 59
</TABLE>
NOTE: Factors for additional age combinations are available from the
Administrator. -57-
<PAGE>
SPECIAL PROVISION D
SPECIAL JOINT PENSION WITH SPOUSE
FACTORS USED TO DETERMINE THE REDUCED ANNUAL RATE
OF RETIREMENT ANNUITY PAYABLE TO JOINT PENSIONERS
WHO ELECT THE SPECIAL JOINT PENSION OPTION WITH THEIR SPOUSE
100% OPTION ELECTION
--------------------
(continued)
<TABLE>
<CAPTION>
SPOUSE'S SPOUSE'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 RETIREMENT
- ------------ ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- -----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
60 .913 .906 .899 .891 .883 .874 .865 .855 .844 .834 .822 .810 .797 .784 .771 .757 60
61 .917 .910 .903 .895 .887 .879 .870 .860 .850 .839 .828 .816 .803 .790 .777 .763 61
62 .920 .914 .907 .900 .892 .884 .875 .865 .855 .845 .834 .822 .810 .797 .784 .770 62
63 .924 .917 .911 .904 .896 .888 .880 .870 .861 .850 .839 .828 .816 .803 .790 .776 63
64 .927 .921 .915 .908 .901 .893 .884 .876 .866 .856 .845 .834 .822 .810 .797 .783 64
65 .930 .925 .918 .912 .905 .897 .889 .881 .871 .862 .851 .840 .828 .816 .803 .790 65
66 .934 .928 .922 .916 .909 .902 .894 .886 .877 .867 .857 .846 .835 .823 .810 .797 66
67 .937 .931 .926 .920 .913 .906 .899 .891 .882 .873 .863 .852 .841 .829 .817 .804 67
68 .940 .935 .929 .924 .917 .911 .903 .895 .887 .878 .868 .858 .847 .836 .824 .811 68
69 .943 .938 .933 .927 .921 .915 .908 .900 .892 .883 .874 .864 .854 .842 .830 .818 69
70 .946 .941 .936 .931 .925 .919 .912 .905 .897 .889 .880 .870 .860 .849 .837 .825 70
71 .948 .944 .939 .934 .929 .923 .916 .909 .902 .894 .885 .876 .866 .855 .844 .832 71
72 .951 .947 .942 .938 .932 .927 .921 .914 .907 .899 .890 .881 .872 .861 .851 .839 72
73 .954 .950 .945 .941 .936 .931 .925 .918 .911 .904 .896 .887 .878 .868 .857 .846 73
74 .956 .952 .948 .944 .939 .934 .929 .922 .916 .909 .901 .893 .884 .874 .864 .853 74
75 .959 .955 .951 .947 .943 .938 .932 .927 .920 .913 .906 .898 .889 .880 .870 .859 75
76 .961 .958 .954 .950 .946 .941 .936 .931 .924 .918 .911 .903 .895 .886 .876 .866 76
77 .963 .960 .957 .953 .949 .944 .940 .934 .929 .922 .916 .908 .900 .892 .882 .873 77
78 .965 .962 .959 .955 .952 .948 .943 .938 .933 .927 .920 .913 .906 .897 .888 .879 78
79 .967 .964 .961 .958 .954 .951 .946 .942 .936 .931 .925 .918 .911 .903 .894 .885 79
</TABLE>
NOTE: Factors for additional age combinations are available from the
Administrator. -58-
<PAGE>
SPECIAL PROVISION D
SPECIAL JOINT PENSION WITH SPOUSE
FACTORS USED TO DETERMINE THE REDUCED ANNUAL RATE
OF RETIREMENT ANNUITY PAYABLE TO JOINT PENSIONERS
WHO ELECT THE SPECIAL JOINT PENSION OPTION WITH THEIR SPOUSE
100% OPTION ELECTION
--------------------
(continued)
<TABLE>
<CAPTION>
SPOUSE'S SPOUSE'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 RETIREMENT
- ------------ ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- -----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
80 .969 .967 .964 .961 .957 .953 .949 .945 .940 .935 .929 .923 .916 .908 .900 .891 80
81 .971 .969 .966 .963 .960 .956 .952 .948 .944 .939 .933 .927 .920 .913 .906 .897 81
82 .973 .970 .968 .965 .962 .959 .955 .951 .947 .942 .937 .931 .925 .918 .911 .903 82
83 .975 .972 .970 .967 .965 .961 .958 .954 .950 .946 .941 .936 .930 .923 .916 .909 83
84 .976 .974 .972 .969 .967 .964 .961 .957 .953 .949 .945 .939 .934 .928 .921 .914 84
85 .978 .976 .974 .971 .969 .966 .963 .960 .956 .952 .948 .943 .938 .932 .926 .919 85
86 .979 .977 .975 .973 .971 .968 .966 .963 .959 .956 .951 .947 .942 .937 .931 .924 86
87 .981 .979 .977 .975 .973 .971 .968 .965 .962 .958 .955 .950 .946 .941 .935 .929 87
88 .982 .980 .979 .977 .975 .973 .970 .967 .965 .961 .958 .954 .949 .945 .939 .934 88
89 .983 .982 .980 .978 .976 .974 .972 .970 .967 .964 .961 .957 .953 .948 .943 .938 89
</TABLE>
NOTE: Factors for additional age combinations are available from the
Administrator. -59-
<PAGE>
SPECIAL PROVISION E
As in Effect Prior to January 1, 1976
A PARTICIPANT who is rehired after a BREAK IN SERVICE shall be treated as a
new PARTICIPANT for all purposes, and the PARTICIPANT's SERVICE and compensation
before the BREAK IN SERVICE shall not be recognized for any purpose of the PLAN,
except as follows:
(a) Upon either the death or retirement of a PARTICIPANT with broken
SERVICE, the last period of CREDITED SERVICE immediately preceding the
PARTICIPANT's latest employment date by EMPLOYER shall be counted as
SERVICE provided:
(1) The PARTICIPANT has accrued at least five years of SERVICE
since last re-employed by EMPLOYER, and
(2) The PARTICIPANT was last re-employed by EMPLOYER within five
years of the date the PARTICIPANT's latest previous employment was
terminated; and
(3) The PARTICIPANT had accrued at least five years of CREDITED
SERVICE prior to the date the PARTICIPANT's last previous employment
with EMPLOYER terminated.
(b) All other periods of prior employment with EMPLOYER, if any,
shall not be counted as SERVICE.
SPECIAL PROVISION F
CREDITED SERVICE
(a) As in effect prior to January 1, 1976:
All SERVICE prior to ACTUAL RETIREMENT DATE, provided the
PARTICIPANT joined the PLAN on the date when the PARTICIPANT first became
eligible and participated therein continuously thereafter. An EMPLOYEE who
first became eligible to join the COMPANY's Retirement PLAN prior to
January 1, 1969, was permitted a grace period of six months beyond the
EMPLOYEE'S eligibility date. An EMPLOYEE who first became eligible to join
the PLAN on or after January 1, 1969, was permitted a grace period of 60
days beyond the EMPLOYEE'S eligibility date. Subject to these grace
periods, if an EMPLOYEE did not become a PARTICIPANT when first eligible
the EMPLOYEE'S CREDITED SERVICE did not begin until the EMPLOYEE became a
PARTICIPANT. If a PARTICIPANT suspended contributions at any time between
January 1, 1969, and December 31, 1972, inclusive. CREDITED SERVICE did
not accrue to the PARTICIPANT after the date of such suspension of
contributions. CREDITED SERVICE did not include any time for which a
vacation allowance may be paid subsequent to an EMPLOYEE'S NORMAL
RETIREMENT DATE.
(b) Effective April 1, 1981:
An EMPLOYEE who first became eligible to join the PLAN prior to
January 1, 1973, but who for any reason did not do so, shall, except those
EMPLOYEES who have had their CREDITED SERVICE previously adjusted by action
of the EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE (EBAC), be allowed the
opportunity to have such lost CREDITED SERVICE restored. An EMPLOYEE'S
CREDITED SERVICE shall not be adjusted or restored except as follows:
-60-
<PAGE>
(1) Prior to April 1, 1982, any EMPLOYEE described above shall,
upon application to EBAC, be permitted to buy back any portion of the
five years of lost CREDITED SERVICE immediately preceding the latest
date on which an EMPLOYEE became a member of the PLAN. Such restored
CREDITED SERVICE shall not, in combination with current SERVICE,
exceed PARTICIPANT's actual COMPANY SERVICE. The cost for restoring
such CREDITED SERVICE shall be computed at the rate of five percent of
an EMPLOYEE'S current monthly wage rate for each month of restored
CREDITED SERVICE.
(2) In addition to the above, and prior to April 1, 1982, any
EMPLOYEE described above shall, upon application to EBAC, be permitted
to buy back any portion of the lost CREDITED SERVICE which is in
excess of the five years permitted in (1) above. The cost for
restoring such excess CREDITED SERVICE shall be computed at the rate
of ten percent of an EMPLOYEE'S current monthly wage rate for each
month of restored excess CREDITED SERVICE.
For the purpose of applying Section 13 (Withdrawal of PARTICIPANT
Contributions on Termination of Employment) only that portion of the
payment made above, for restoration of lost CREDITED SERVICE, which
the EMPLOYEE would have contributed had the EMPLOYEE participated in
the PLAN at that time will be considered as CONTRIBUTIONS.
SPECIAL PROVISION G
PENSION AND LTD ADJUSTMENTS
---------------------------
(a) Effective December 31, 1993, the PENSION of any PARTICIPANT who
retired or the PENSION of a person receiving a SPOUSE's PENSION or a JOINT
PENSION, will be increased as follows:
<TABLE>
<CAPTION>
Increase
--------
<S> <C>
Retired on or before 12/31/73 9.0%
Retired between 1/1/74 and 12/31/83 5.0%
Retired between 1/1/84 and 12/31/89 2.5%
Retired between 1/1/88 and 12/31/88 2.5%
</TABLE>
A minimum monthly increase of $50 will be provided to retirees with at
least 30 years of SERVICE, and a retirement date at or after normal
retirement age. A minimum monthly increase of $25 will be provided to
surviving SPOUSES of such retirees.
(b) The above adjustments shall apply to those Participants who are
receiving Long Term Disability Benefit payments.
(c) By Company resolutions dated June 17, 1964, February 25, 1969,
April 9, 1974, September 20, 1977, March 4, 1980, July 15, 1981, and
December 21, 1983, the amounts of pensions received by certain pensioners
were increased in accordance with the provisions of said resolutions. The
money required to fund these additional payments is based on actuarial
factors and the required contributions are paid into the Plan. The Company
intends to continue making these additional payments out of Plan assets and
on the same basis as it has done in the past.
-61-
<PAGE>
SPECIAL PROVISION H
MAXIMUM PENSION
This PLAN incorporates by reference the benefit limitations imposed by CODE
Section 415.
The annual benefit amount otherwise payable to a former EMPLOYEE at any
time will not exceed the maximum permissible amount under CODE Section 415. For
purposes of determining compliance with the Section 415 benefit limitations, the
limitation year shall be the PLAN YEAR. If the benefit the PARTICIPANT would
otherwise accrue in a limitation year would produce an annual benefit in excess
of the maximum permissible amount under CODE Section 415, then the rate of
accrual will be reduced so that the annual benefit will equal the maximum
permissible amount.
If a PARTICIPANT in this PLAN also participates in any defined contribution
plan maintained by an EMPLOYER, the sum of the PARTICIPANT'S "Defined Benefit
Fraction" and the PARTICIPANT'S "Defined Contribution Fraction" shall not exceed
1.0. In the event that in any PLAN YEAR the sum of the PARTICIPANT'S Defined
Benefit Fraction and the PARTICIPANT'S Defined Contribution Fraction exceed 1.0,
then the PENSION payable under this PLAN shall be reduced so that the sum of
such fractions in respect of that PARTICIPANT will not exceed 1.0."
For purposes of determining the PLAN'S compliance with CODE Section 415,
the annual benefit is a retirement benefit payable under the PLAN in the form of
a straight life annuity. Except as provided below, a benefit payable in a form
other than a straight life annuity must be adjusted to an actuarially equivalent
straight life annuity before applying the limitations of Section 415. The
interest rate assumption used to determine actuarial equivalence will be the
greater of rate used in Special Provision D or 5 percent. No actuarial
adjustment to the benefit is required for the value of a qualified joint and
survivor annuity, the value of benefits that are not directly related to
retirement benefits (such as the qualified disability benefit, pre-retirement
death benefits, and post-retirement medical benefits), and the value of post-
retirement cost-of-living increases made in accordance with 415(d) of the CODE.
The annual benefit does not include any benefits attributable to EMPLOYEE
contributions or rollover contributions or the assets transferred from a
qualified plan not maintained by the COMPANY.
Compensation, for purposes of determining the PLAN'S compliance with
Section 415 of the CODE, shall mean all of each PARTICIPANT'S wages, tips, and
other Box 10 compensation on the PARTICIPANT'S Form W-2.
SPECIAL PROVISION I
If prior to 1989 SERVICE terminates with at least ten years of SERVICE, or
with at least five years of SERVICE after 1988, the PENSION the PARTICIPANT
would otherwise be entitled to receive shall be reduced because of the
withdrawal.
If the withdrawal occurs prior to age 55, the yearly PENSION payable at the
NORMAL RETIREMENT DATE, prior to reduction for EARLY RETIREMENT (if any), shall
be reduced by the product of the amount withdrawn and the applicable factor
selected from the following table:
-62-
<PAGE>
<TABLE>
<CAPTION>
Age Last Age Last
Birthday At Birthday At
Refund Date Factor Refund Date Factor
- ----------- ------ ----------- ------
<S> <C> <C> <C>
25 .6705 40 .3225
26 .6385 41 .3072
27 .6081 42 .2925
28 .5792 43 .2786
29 .5516 44 .2653
30 .5253 45 .2527
31 .5003 46 .2407
32 .4765 47 .2292
33 .4538 48 .2183
34 .4321 49 .2079
35 .4116 50 .1980
36 .3920 51 .1886
37 .3733 52 .1796
38 .3556 53 .1710
39 .3386 54 .1629
</TABLE>
If the withdrawal occurs after age 55, the yearly PENSION payable at the
ACTUAL RETIREMENT DATE, after reduction for EARLY RETIREMENT (if any), shall be
reduced by the product of the amount withdrawn and the applicable factor
selected from the following table:
<TABLE>
<CAPTION>
Age Last
Birthday At
Refund Date Factor
----------- ------
<S> <C>
55 .0775
56 .0792
57 .0810
58 .0829
59 .0849
60 .0871
61 .0894
62 .0919
63 .0946
64 .0975
65 .1000
66 .1039
67 .1074
68 .1111
69 .1151
70 .1192
</TABLE>
Notwithstanding the foregoing, in no event will the PENSION be reduced by
more than one-third.
The monthly reduction is computed by multiplying the appropriate factor
times the PARTICIPANT'S contributions including interest and dividing that
amount by twelve months.
-63-
<PAGE>
<TABLE>
<CAPTION>
EXAMPLE:
- -------
<S> <C> <C>
Assumptions: Age 60
Basic Pensions = $1,500.00/month
Contributions = $6,000.00
Interest = 3,000.00
--------
Total = $9,000.00 - 65.33*
-------
</TABLE>
Pension with contributions = $1,434.67/month
plus interest withdrawn
_______________________
*Calculation: (Contributions + Interest x Age 60 Refund Factor) : 12 Months
($9,000 x .0871 : 12 Months = $65.33)
-64-
<PAGE>
SPECIAL PROVISION J
TOP HEAVY PROVISIONS
--------------------
(a) General Rule
------------
For any PLAN YEAR for which this PLAN is a "top-heavy plan" as defined in
subsection (g) below, any other provisions of this PLAN to the contrary
notwithstanding, this PLAN shall be subject to the following provisions:
(1) The vesting provisions of subsection (b).
(2) The minimum benefit provisions of subsection (c).
(3) The limitation on compensation set by subsection (d).
(4) The limitation on benefits set by subsection (e).
If any individual has not performed SERVICE for an EMPLOYER at any time
during the five-year period ending on the last day of the preceding PLAN YEAR,
any accrued benefit for such individual shall not be taken into account for
purposes of determining whether the PLAN is a "top-heavy plan." For purposes of
determining whether the PLAN is top-heavy, a non-key EMPLOYEE'S accrued benefit
must be determined as if it is accrued not more rapidly than the slowest accrual
rate permitted under CODE Section 411(b)(1)(C) (i.e., the "fractional rule").
(b) Vesting Provisions
------------------
Each PARTICIPANT who (i) has completed an hour of SERVICE during any PLAN
YEAR in which the PLAN is top heavy and (ii) has completed the number of years
of credited SERVICE specified in the following table shall have a nonforfeitable
right to the percentage of the benefit accrued under this PLAN derived from
EMPLOYER contributions correspondingly specified in the following table:
<TABLE>
<CAPTION>
Years of Percentage of
credited service: nonforfeitable
benefit:
<S> <C>
2 20
3 40
4 60
5 80
6 or more 100
</TABLE>
"Credited service" as used in this subsection (b) shall constitute SERVICE
as defined in Section 22 of this PLAN.
Each PARTICIPANT's nonforfeitable accrued benefit shall not be less than
his nonforfeitable accrued benefit determined as of the last day of the last
PLAN YEAR in which the PLAN was a top-heavy PLAN. If the PLAN ceases to be top-
heavy, each PARTICIPANT with five or more years of SERVICE, whether or not
consecutive, shall have his nonforfeitable accrued benefit determined in
accordance with this Section and Section 3. Each such PARTICIPANT shall have
the right to elect the applicable schedule within 60 days after the day the
PARTICIPANT is issued written notice by the EMPLOYEE BENEFIT ADMINISTRATIVE
COMMITTEE, or as otherwise provided in accordance with regulations issued under
the provision of the Internal Revenue CODE of 1954, as amended, relating to
changes in the vesting schedule.
-65-
<PAGE>
This provision shall apply without regard to contributions or benefits
under Social Security or any other Federal or State law.
(c) Minimum Benefit Provisions
--------------------------
Each PARTICIPANT who (i) is a non-key employee (as defined in subsection
(i) below) and (ii) has completed 1,000 hours of SERVICE during any PLAN YEAR
shall be entitled to an accrued benefit in the form of an annual retirement
benefit (as defined in paragraph (1) below) that shall be not less than the
applicable percentage (as defined in paragraph (2) below) of the PARTICIPANT's
average annual compensation for years in the testing period (as defined in
paragraph (3) below).
(1) "Annual retirement benefit" means a benefit payable annually in the
form of a single life annuity (with no ancillary benefits) beginning
at NORMAL RETIREMENT DATE as defined in Section 22 of this PLAN or its
actuarial equivalent.
(2) "Applicable percentage" means the lesser of two percent multiplied by
the number of top-heavy PLAN YEARs of service (as defined in paragraph
(4) below) of 20 percent.
(3) "Testing period" means, with respect to a PARTICIPANT, the period of
consecutive years (not exceeding five) of SERVICE during which the
PARTICIPANT had the greatest aggregate compensation from the EMPLOYER.
The testing period shall not include any year of SERVICE not included
as a year of SERVICE as defined in paragraph (4) below. The testing
period shall also not include any year of SERVICE that ends in a PLAN
YEAR beginning before January 1, 1984 or during which the PLAN was not
a top-heavy plan.
(4) "Years of service" means SERVICE as defined in Section 3 of this PLAN.
Benefits taken into account under this Subsection shall not include any
benefits payable under the Social Security Act or any other Federal or State
law.
(d) Limitation on Benefits
----------------------
In the event that the EMPLOYER also maintains a defined contribution PLAN
providing contributions on behalf of PARTICIPANTS in this PLAN, one of the two
following provisions shall apply:
(1) If for the PLAN YEAR this PLAN would not be a "top-heavy plan" as
defined in subsection (g) below if "90 percent" were substituted for
"60 percent," then subsection (c) shall apply for such PLAN YEAR as if
amended so that the "applicable percentage" means the lesser of three
percent multiplied by the number of years of SERVICE (as defined in
paragraph (4) of subsection (c)) during which the PLAN would be top-
heavy (as defined in subsection (g)) and the overall applicable
percentage does not exceed the lesser of 30% or 20% plus 1% for each
year the PLAN is taken into account under this subsection ((e)(1)).
(2) If for the PLAN YEAR this PLAN would continue to be a "top-heavy plan"
as defined in subsection (g) below if "90 percent" were substituted
for "60 percent," then the denominator of both the defined
contribution PLAN fraction and the defined benefit plan fraction shall
be calculated as set forth in Special Provision H for the limitation
year ending in such PLAN YEAR by substituting "1.0" for "1.25," except
with respect to any individual for whom there are no EMPLOYER
contributions, forfeitures or voluntary
-66-
<PAGE>
nondeductible contributions allocated or any accruals for such
individual under the defined benefit PLAN. Furthermore, the
transitional rule set forth in CODE Section 415 shall be applied by
substituting "$41,500" for $51,875".
(e) Coordination with Other Plans
-----------------------------
In the event that another defined contribution or defined benefit PLAN
maintained by the EMPLOYER provides contributions or benefits on behalf of
PARTICIPANTS in this PLAN, such other PLAN shall be treated as a part of this
PLAN pursuant to applicable principles (such as Rev. Rul. 81-202 or any
successor ruling) in determining whether this PLAN satisfies the requirements of
subsection (b), (c) and (d). Such determination shall be made upon the advice
of counsel by the EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE.
(f) Top-heavy Plan Definition
-------------------------
This PLAN shall be a "top-heavy plan" for any PLAN YEAR if, as of the
determination date (as defined in subsection (g)(1) below), the present value
(as determined in subsection (g)(2) below) of the cumulative accrued benefits
under the PLAN for participants (including former participants) who are key
employees (as defined in subsection (h) below) exceeds 60 percent of the present
value of the cumulative accrued benefits under the PLAN for all participants,
excluding former key employees, or if this PLAN is required to be in a
aggregation group (as defined in subsection (g)(3) below) which for such PLAN
YEAR is a top-heavy group (as defined in subsection (g)(4) below).
(1) "Determination date" means for any PLAN YEAR the last day of the
immediately preceding PLAN YEAR.
(2) The present value shall be determined as of the most recent valuation
date that is within the twelve-month period ending on the
determination date and as described in the regulations under the
Internal Revenue CODE as of 1954, as amended.
(3) "Aggregation group" means the group of plans, if any, that includes
both the group of plans that are required to be aggregated and the
group of plans that are permitted to be aggregated.
(A) The group of plans that are required to be aggregated (the
"required aggregation group") includes
(i) Each plan of the EMPLOYER (as defined in subsection (j)
below) in which a key employee is a PARTICIPANT, including
collectively-bargained plans, and
(ii) Each other plan, including collectively-bargained plans of
the EMPLOYER (as defined in subsection (j) below) which
enables a plan in which a key employee is a PARTICIPANT to
meet the requirements of the Internal Revenue CODE of 1954,
as amended, prohibiting discrimination as to contributions
or benefits in favor of employees who are officers,
shareholders or the highly-compensated or prescribing the
minimum participation standards.
(B) The group of plans that are permitted to be aggregated (the
"permissive aggregation group") includes the required aggregation
group plus one or more plans of the EMPLOYER (as defined in subsection
(j) below) that is not part of the required aggregation group and that
the EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE certifies as
constituting a plan within the permissive aggregation group. Such
plan or plans may be added to the permissive aggrega-
-67-
<PAGE>
tion group only if, after the addition, the aggregation group as a
whole continue not to discriminate as to contributions or benefits in
favor of officers, shareholders or the highly-compensated and to meet
the minimum participation standards under the Internal Revenue CODE of
1954, as amended.
(4) "Top-heavy group" means the aggregation group, if as of the applicable
determination date, the sum of the present value of the cumulative accrued
benefits for key employees under all defined benefit plans included in the
aggregation group plus the aggregate of the accounts of key employees under
all defined contribution plans included in the aggregation group exceeds
60% of the sum of the present value of the cumulative accrued benefits for
all employees, excluding former key employees, under all such defined
benefit plans plus the aggregate accounts for all employees, excluding
former key employees, under such defined contribution plans. If the
aggregation group that is a top-heavy group is a required aggregation
group, each Plan in the group will be top heavy. If the aggregation group
that is a top-heavy group is a permissive aggregation group, only those
plans that are part of the required aggregation group will be treated as
top-heavy. If the aggregation group is not a top-heavy group, no plan
within such group will be top-heavy.
(5) In determining whether this PLAN constitutes a "top-heavy plan", the
EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE (or its agent) shall make the
following adjustments in connection therewith:
(A) When more than one plan is aggregated, the EMPLOYEE BENEFIT
ADMINISTRATIVE COMMITTEE shall determine separately for each plan as
of each plan's determination date the present value of the accrued
benefits or account balance. The results shall then be aggregated by
adding the results of each plan as of the determination dates for
such plans that fall within the same calendar year.
(B) In determining the present value of the cumulative accrued benefit or
the amount of the account of any employee, such present value or
account shall include the amount in dollar value of the aggregate
distributions made to such employee under the applicable plan during
the five-year period ending on the determination date, unless
reflected in the value of the accrued benefit or account balance as of
the most recent valuation date. Such amounts shall include
distributions to employees which represented the entire amount
credited to their accounts under the applicable plan.
(B) Further, in making such determination, in any case where an individual
is a "non-key employee" as defined in subsection (h) below, with
respect to an applicable plan, but was a key employee with respect to
such plan for any prior PLAN YEAR, any accrued benefit and any account
of such employee shall be altogether disregarded. For this purpose,
to the extent that a key employee is deemed to be a key employee if he
met the definition of key employee within any of the four preceding
PLAN YEARS, this provision shall apply following the end of such
period of time.
(g) Key Employee
------------
The term "key employee" means any employee or former employee under this
PLAN who, at any time during the PLAN YEAR containing the determination date or
during any of the four preceding PLAN YEARS, is or was one of the following:
(1) An officer of the EMPLOYER (as defined in subsection (j)). Whether an
individual is an officer shall be determined by the
-68-
<PAGE>
EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE on the basis of all the
facts and circumstances, such as an individual's authority, duties and
term of office, not on the mere fact that the individual has the title
of an officer. For any such PLAN YEAR, there shall be treated as
officers no more than the lesser of:
(A) 50 employees, or
(B) the greater of three employees or 10 percent of the employees.
For this purpose, the highest-paid officers shall be selected.
Business organizations other than corporations shall be deemed to have
no officers.
(2) One of the ten employees owning (or considered as owning, within the
meaning of the constructive ownership rules of the Internal Revenue
CODE of 1954, as amended) the largest interests in the EMPLOYER (as
defined in subsection (j)). An employee who has some ownership
interest is considered to be one of the top ten owners unless at least
ten other employees own a greater interest than that employee.
However, an employee will not be considered a top ten owner for a PLAN
YEAR if the employee earns less than the maximum dollar limitation on
contributions and other annual additions to a PARTICIPANT's account in
a defined contribution plan under the Internal Revenue CODE of 1954,
as amended, as in effect for the calendar year in which the
determination date falls.
(3) Any person who owns (or is considered as owning within the meaning of
the constructive ownership rules of the CODE more than five percent of
the outstanding stock of the EMPLOYER or stock possessing more than
five percent of the combined total voting power of all stock of the
EMPLOYER.
(4) A one percent owner of the EMPLOYER having an annual compensation from
the EMPLOYER of more than $150,000, and possessing more than five
percent of the combined total voting power of all stock of the
EMPLOYER. For purposes of this subsection, compensation means all
items includable as compensation for purposes of applying the
limitations on contributions and other annual additions to a
PARTICIPANT's account in a defined contribution plan and the maximum
benefit payable under a defined plan under the Internal Revenue CODE
of 1954, as amended.
For purposes of parts (1), (2), (3) and (4) of this definition, a
beneficiary of a key employee shall be treated as a key employee. For
purposes of parts (3) and (4), each EMPLOYER is treated separately
(without regard to the definition in subsection (j)) in determining
ownership percentages; but, in determining the amount of compensation,
the definition of EMPLOYER in subsection (j) is taken into account.
(h) Non-Key Employee
----------------
The term "non-key employee" means any employee (and any beneficiary of an
employee) who is not a key employee.
(i) Employer
--------
The term "employer" means EMPLOYER as defined in Section 22 of this PLAN.
-69-
<PAGE>
(j) Collective Bargaining Rules
---------------------------
The provisions of subsection (b), (c) and (d) above do not apply with
respect to any employee included in a unit of employees covered by a collective
bargaining agreement unless the application of such subsections has been agreed
upon with the collective bargaining agent.
(k) Distributions to Key Employees
------------------------------
Any other provisions of this PLAN to the contrary notwithstanding,
distribution of the entire interest in this PLAN of each PARTICIPANT who is or
any time has been a key employee shall commence no later than the end of the
taxable year of the PARTICIPANT in which the PARTICIPANT attains age 70 1/2.
SPECIAL PROVISION K
I. Introduction
------------
This Special Provision K, an amendment to the COMPANY'S RETIREMENT
PLAN, adopted by the COMPANY'S Board of Directors on December 17, 1986, is
the controlling and definitive statement of the Voluntary Retirement
Incentive program ("VRI"). The purpose of the VRI is to reduce a surplus
--- ---
of COMPANY employees in certain designated operations. The VRI is a part
---
of the RETIREMENT PLAN, and except as otherwise provided in this Special
Provision K, shall be administered in accordance with and subject to the
terms of the RETIREMENT PLAN. Terms in all capitals are defined in Section
22 of the RETIREMENT PLAN. Terms underlined are defined in Section VII of
Special Provision K.
The decision of an Eligible Employee to elect to participate in the
-------- --------
VRI is wholly voluntary, and an election not to participate in the VRI
--- ---
shall in no way affect benefits under the RETIREMENT PLAN to which an
Eligible Employee might otherwise be entitled.
-------- --------
II. Eligibility to Participate in the VRI
-------------------------------------
Eligible Employees shall be any full-time active employee of the
COMPANY or of a Participating Employer, born on or before January 1, 1937,
------------- --------
who has at least 15 years of SERVICE on January 1, 1987. For purposes of
this VRI only, the term active employee shall not include an employee of
---
the COMPANY or a Participating Employer, (i) who, on January 1, 1987, is
------------- --------
presently receiving benefits under Part B of the Group Life Insurance and
Long Term Disability Plan; (ii) who, as of January 1, 1987, is on personal
or medical leave, with or without pay; or (iii) who is a former employee
whose ACTUAL RETIREMENT DATE was November 1, 1986, or earlier.
Anything herein to the contrary notwithstanding, an Eligible Employee
-------- --------
who (i) elects not to participate in the VRI and (ii) prior to January 1,
---
1988, is severed under the Company's Corporate Severance Program, shall be
entitled to receive a Basic VRI Benefit under this Special Provision K.
---
Such Basic VRI Benefit shall be in lieu of any benefits to which the
----- --- -------
Eligible EMPLOYEE would otherwise be entitled to receive under the
-------- --------
Corporate Severance Program. For purposes of calculating the Basic VRI
----- ---
Benefit under this provision, the VRI Retirement Date shall be the first of
------- --- ---------- ----
the month following the month in which the employee is severed.
-70-
<PAGE>
III. Election to Participate
-----------------------
An Eligible EMPLOYEE must elect to participate in the VRI by
-------- -------- ---
submitting a completed and signed VRI enrollment form which is received by
---
a designated COMPANY representative no later than January 30, 1987, except
that Eligible Employees who are employed by Pacific Gas Transmission
-------- ---------
Company will have until the close of business, September 30, 1987, to
submit their completed and signed VRI enrollment form to a designated
---
employer representative. An Eligible EMPLOYEE who fails to submit a timely
-------- --------
enrollment form shall be deemed to have elected not to participate in the
VRI. The election of an Eligible Employee not to participate in the VRI,
--- -------- -------- ---
whether through failure to timely submit a VRI election form or otherwise,
---
shall be conclusive and binding on the employee, employee's spouse, heirs,
and assigns.
IV. VRI Benefit
-----------
A. Basic VRI Benefit. An Eligible Employee who elects in a timely manner
----- --- ------- -------- --------
to participate in the VRI shall be entitled to receive a Basic VRI
--- ----- ---
Benefit under the RETIREMENT PLAN equal to the BASIC PENSION benefit
-------
formula calculated under Subsection 6(a)(1), with the following
adjustments:
1. BASIC MONTHLY SALARY shall mean the PARTICIPANT'S BASIC MONTHLY
SALARY on January 1, 1986, increased by 5 percent;
2. SERVICE shall mean the PARTICIPANT'S SERVICE as of the VRI
---
Retirement Date selected by the PARTICIPANT, increased by five
---------- ----
years; and
3. The EARLY RETIREMENT PENSION reduction provisions of Subsection
7(b) shall not apply to any Basic VRI Benefit payable under this
----- --- -------
Special Provision K.
B. A Basic VRI Benefit shall be payable as of the VRI Retirement Date
----- --- ------- --- ---------- ----
selected by the Eligible Employee and shall be paid as soon as
-------- --------
practicable after the applicable VRI Retirement Date. Eligible
--- ---------- ---- --------
Employees who elect to participate in the VRI shall not be subject to
--------- ---
the age 55 requirement contained in Section 8.
C. Section 10 of the RETIREMENT PLAN shall control the conditions under
which other forms of pension may be substituted for the Basic VRI
----- ---
Benefit. Thus, although a PARTICIPANT is entitled to receive a Basic
------- -----
VRI Benefit, if the PARTICIPANT is married, Section 10(b) of the
--- -------
RETIREMENT PLAN requires that the Basic VRI Benefit be converted to a
----- --- -------
MARITAL PENSION, unless the PARTICIPANT'S spouse CONSENTS to an
alternative form of pension.
D. The Basic VRI Benefit payable under this Special Provision K shall be
----- --- -------
in lieu of any benefit which might otherwise be payable under the
RETIREMENT PLAN.
E. A participant who elects to participate in VRI shall also be entitled
---
to make the elections provided in Sections 10 (Forms of Pension), 12
(Withdrawal of Participant Contributions on Termination of
Employment), 13 (Death Benefits), and 14 (Facility of Payment).
-71-
<PAGE>
V. VRI Retirement Dates
--------------------
At such time as an employee elects to participate in the VRI, he shall
---
select a VRI Retirement Date. For purposes of this Special Provision K, a
--- ---------- ----
VRI Retirement Date shall mean one of the following:
--- ---------- ----
A. For Eligible Employees other than Eligible Employees employed by
-------- --------- -------- ---------
Pacific Gas Transmission Company:
1. February 1, 1987, provided, however, that eligible participants
have completed all necessary VRI enrollment procedures prior to
---
January 15, 1987;
2. March 1, 1987;
3. April 1, 1987; or
4. The first of any month during the period commencing with March 1,
1987, and ending with and including October 1, 1987. This
Subsection V.A.4. shall only apply in the event that the COMPANY
or the Participating Employer, as the case may be, has a
------------- --------
demonstrated business need which requires the retention of the
Eligible Employee. Should the business needs of the COMPANY or
-------- --------
of a Participating Employer require the retention of an Eligible
------------- -------- --------
Employee beyond October 1, 1987, the VRI Retirement Date shall be
-------- --- ---------- ----
the first of any month during the period subsequent to October 1,
1987, and ending with and including July 1, 1988. The selection
of any such VRI Retirement Date subsequent to October 1, 1987,
--- ---------- ----
shall be made by the COMPANY, or Participating Employer, through
------------- --------
an appropriate member of the COMPANY's Management Committee.
B. For Eligible Employees employed by Pacific Gas Transmission Company:
-------- ---------
1. October 1, 1987, provided, however, that eligible participants
have completed all necessary VRI enrollment procedures prior to
---
September 15, 1987;
2. November 1, 1987; or
3. The first of any month during the period commencing with December
1, 1987, and ending with and including June 1, 1988. This
Subsection V.B.3. shall only apply in the event that Pacific Gas
Transmission Company has a demonstrated need which requires the
retention of the Eligible Employee.
-------- --------
The VRI Retirement Date selected shall also be the date as of
--- ---------- ----
which an Eligible Employee ceases to be an employee of the COMPANY or
-------- --------
a Participating Employer, as the case may be.
------------- --------
VI. Revocation of Election
----------------------
An Eligible Employee who has elected to participate in the VRI may
-------- -------- ---
revoke his election, provided, however, that any such revocation shall only
be effective if received by the COMPANY on or before January 30, 1987, for
those Eligible Employees who elected a VRI Retirement Date of February 1,
-------- --------- --- ---------- ----
1987; February 15, 1987, for those Eligible Employees who elected a VRI
-------- --------- ---
Retirement Date of March 1, 1987, or later; September 30, 1987, for those
---------- ----
Eligible Employees of Pacific Gas Transmission Company who elected a VRI
-------- --------- ---
Retirement Date of October 1, 1987; or October 15,
---------- ----
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<PAGE>
1987, for those Eligible Employees of Pacific Gas Transmission Company who
-------- ---------
elected a VRI Retirement Date of November 1, 1987, or later.
--- ---------- ----
VII. Definitions
-----------
A. Basic VRI Benefit: The benefit calculated under Section IV of this
----- --- -------
Special Provision K.
B. Eligible Employee: An employee of the COMPANY or of a Participating
-------- --------
Employer who has met the eligibility criteria as set forth in Section
II on January 1, 1987. For purposes of this Special Provision K only,
Eligible Employee shall not include any COMPANY Officer at the vice
presidential level, or above.
C. Participating Employer: Natural Gas Corporation, Pacific Gas
------------- --------
Transmission Company, and Pacific Service Employees Association.
D. VRI: The COMPANY's Voluntary Retirement Incentive program as set
---
forth in this Special Provision K.
E. VRI Retirement Date: The date selected by an Eligible Employee under
--- ---------- ----
Section V of this Special Provision K.
SPECIAL PROVISION M
I. Introduction
------------
This Special Provision M, an amendment to the COMPANY'S RETIREMENT
PLAN, adopted by the COMPANY'S Board of Directors on February 17, 1993, is
the controlling and definitive statement of the Voluntary Retirement
Incentive program ("VRI"). The purpose of the VRI is to reduce a surplus
--- ---
of COMPANY employees in certain designated operations. The VRI is a part
---
of the RETIREMENT PLAN, and except as otherwise provided in this Special
Provision M, shall be administered in accordance with and subject to the
terms of the RETIREMENT PLAN. Terms in all capitals are defined in Section
22 of the RETIREMENT PLAN. Terms underlined are defined in Section VII of
Special Provision M.
The decision of an Eligible Employee to elect to participate in the
-------- --------
VRI is wholly voluntary, and an election not to participate in the VRI
--- ---
shall in no way affect benefits under the RETIREMENT PLAN to which an
Eligible Employee might otherwise be entitled.
-------- --------
II. Eligibility to Participate in the VRI
-------------------------------------
An Eligible Employee shall be any active employee of the COMPANY whose
-------- --------
base job classification on February 17, 1993, is in a Targeted Organization
-------- ------------
and who was born on or before December 31, 1942, and has at least 15 years
of SERVICE on December 31, 1992. For purposes of this VRI only, the term
---
active employee shall not include an employee of the COMPANY (i) who, on
February 17, 1993, is presently receiving benefits under Part B of the
Group Life Insurance and Long Term Disability Plan; (ii) who is on a leave
of absence, with or without pay, which began on or prior to August 17,
1992; or (iii) who is a former employee whose ACTUAL RETIREMENT DATE was
February 1, 1993, or earlier.
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<PAGE>
III. Election to Participate
-----------------------
An Eligible Employee must elect to participate in the VRI by
-------- -------- ---
submitting a completed and signed VRI enrollment form which is received by
---
a designated COMPANY representative no later than April 23, 1993. An
Eligible Employee who fails to submit a timely enrollment form shall be
-------- --------
deemed to have elected not to participate in the VRI. The election of an
---
Eligible Employee not to participate in the VRI, whether through failure to
-------- -------- ---
submit a timely VRI election form or otherwise, shall be conclusive and
---
binding on the employee, employee's spouse, heirs, and assigns.
IV. VRI Benefit
-----------
A. Basic VRI Benefit. An Eligible Employee who elects in a timely manner
----- --- ------- -------- --------
to participate in the VRI shall be entitled to receive a Basic VRI
--- ----- ---
Benefit under the RETIREMENT PLAN equal to the BASIC PENSION benefit
-------
formula calculated under Subsection 6(a)(1), with the following
adjustments:
1. SERVICE shall mean the PARTICIPANT'S SERVICE as of last VRI
---
Retirement Date for such Eligible Employee, increased by three
---------- ---- -------- --------
years; and
2. The EARLY RETIREMENT PENSION reduction provisions of Subsection
7(b) shall not apply to any Basic VRI Benefit payable under this
----- --- -------
Special Provision M.
B. A Basic VRI Benefit shall be payable as of the VRI Retirement Date
----- --- ------- --- ---------- ----
selected by the Eligible Employee and shall be paid as soon as
-------- --------
practicable after the applicable VRI Retirement Date. Eligible
--- ---------- ---- --------
Employees who elect to participate in the VRI shall not be subject to
--------- ---
the age 55 requirement contained in Section 8.
C. Section 10 of the RETIREMENT PLAN shall control the conditions under
which other forms of pension may be substituted for the Basic VRI
----- ---
Benefit. Thus, although a PARTICIPANT is entitled to receive a Basic
------- -----
VRI Benefit, if the PARTICIPANT is married, Section 10(b) of the
--- -------
RETIREMENT PLAN requires that the Basic VRI Benefit be converted to a
----- --- -------
MARITAL PENSION, unless the PARTICIPANT'S spouse CONSENTS to an
alternative form of pension.
D. The Basic VRI Benefit payable under this Special Provision M shall be
----- --- -------
in lieu of any benefit which might otherwise be payable under the
RETIREMENT PLAN.
E. A participant who elects to participate in VRI shall also be entitled
---
to make the elections provided in Sections 10 (Forms of Pension), 12
(Withdrawal of Participant Contributions on Termination of
Employment), 13 (Death Benefits), and 14 (Facility of Payment).
V. VRI Retirement Dates
--------------------
At such time as an employee elects to participate in the VRI, he shall
---
select a VRI Retirement Date. For purposes of this Special Provision M, a
--- ---------- ----
VRI Retirement Date shall mean one of the following:
--- ---------- ----
A. May 1, 1993;
B. June 1, 1993; or
-74-
<PAGE>
C. The first of any month during the period commencing with July 1, 1993,
and ending with and including June 1, 1994. This Subsection C shall
only apply in the event that the COMPANY has a demonstrated business
need which requires the retention of the Eligible Employee. The
-------- --------
selection of any such VRI Retirement Date subsequent to June 1, 1993,
--- ---------- ----
can be made only with the written approval of both of the Company's
Executive Vice Presidents.
The VRI Retirement Date selected shall also be the date as of which an
--- ---------- ----
Eligible Employee ceases to be an employee of the COMPANY.
-------- --------
VI. Revocation of Election
----------------------
An Eligible Employee who has elected to participate in the VRI may
-------- -------- ---
revoke his election, provided, however, that any such revocation shall only
be effective if received by the COMPANY on or before April 23, 1993, for
those Eligible Employees who elected a VRI Retirement Date of May 1, 1993;
-------- --------- --- ---------- ----
or April 30, 1993, for those Eligible Employees who elected a VRI
-------- --------- ---
Retirement Date of June 1, 1993, or later.
---------- ----
VII. Definitions
-----------
A. Basic VRI Benefit: The benefit calculated under Section IV of this
----- --- -------
Special Provision M.
B. Eligible Employee: An employee of the COMPANY who has met the
-------- --------
eligibility criteria as set forth in Section II. For purposes of this
Special Provision M only, Eligible Employee shall not include any
COMPANY Officer.
C. Targeted Organization: Distribution Business Unit; Engineering and
---------------------
Construction Business Unit; Gas Supply Business Unit except the Gas
Dispatch Department and except employees with job levels of 32 and
above; Nuclear Operations Support Department; Nuclear Safety and
Regulatory Affairs Department; Nuclear Engineering and Construction
Services Department; Nuclear Business and Financial Management
Department; Nuclear Documentation and Support Department; Quality
Assurance Department; human resources departments, including business
unit human resources organizations being consolidated with corporate
human resources; computer and telecommunication services departments,
including business unit and corporate services organizations being
consolidated with corporate computer and telecommunication services
departments; Corporate Communications departments, including business
unit media and employee communications units being consolidated with
Corporate Communications departments; community and governmental
relations departments including regional public affairs units being
consolidated with corporate governmental relations departments; and
the Economics and Forecasting Department.
D. VRI: The COMPANY's Voluntary Retirement Incentive program as set
---
forth in this Special Provision M.
E. VRI Retirement Date: The date selected by an Eligible Employee under
--- ---------- ----
Section V of this Special Provision M.
-75-
<PAGE>
SPECIAL PROVISION N
I. Introduction
This Special Provision N, an amendment to the COMPANY'S RETIREMENT
PLAN, authorized by the COMPANY'S Board of Directors on September 21, 1994,
is the controlling and definitive statement of the Voluntary Retirement
Incentive program ("VRI"). The purpose of the VRI is to reduce a surplus
--- ---
of COMPANY EMPLOYEES. The VRI is a part of the RETIREMENT PLAN, and
---
except as otherwise provided in this Special Provision N, shall be
administered in accordance with and subject to the terms of the RETIREMENT
PLAN. Terms in all capitals are defined in Section 22 of the RETIREMENT
PLAN. Terms underlined are defined in Section VII of Special Provision N.
The decision of an Eligible Employee to elect to participate in the
-------- --------
VRI is wholly voluntary, and an election not to participate in the VRI
--- ---
shall in no way affect benefits under the RETIREMENT PLAN to which an
Eligible Employee might otherwise be entitled.
-------- --------
II. Eligibility to Participate in the VRI
---
An Eligible Employee shall be any active EMPLOYEE of the COMPANY who
-------- --------
was born on or before September 30, 1944, and has at least 15 years of
SERVICE on September 30, 1994. For purposes of this VRI only, the term
---
active EMPLOYEE shall not include an EMPLOYEE of the COMPANY (i) who, on
September 30, 1994, is presently receiving benefits under Part B of the
Group Life Insurance and Long Term Disability Plan; (ii) who is on a leave
of absence, with or without pay, which began on or prior to March 30, 1994;
(iii) who elected to retire under Special Provision M of Part I of the
RETIREMENT PLAN or Special Provision N of Part II of the RETIREMENT PLAN;
(iv) who has received or is scheduled to receive severance benefits under
the COMPANY'S Workforce Management Program, Letter Agreement No. 93-42-PGE
and Letter Agreement No. 93-23esc, or under any other written agreement
between the COMPANY and the EMPLOYEE in which the EMPLOYEE has received
benefits in connection with the termination of such EMPLOYEE'S employment;
(v) who is a former EMPLOYEE who was terminated for cause; or (vi) who is a
former EMPLOYEE whose ACTUAL RETIREMENT DATE was July 1, 1994, or earlier.
III. Election to Participate
-----------------------
An Eligible Employee must elect to participate in the VRI by
-------- -------- ---
completing and signing the VRI enrollment and waiver and release forms
---
provided by the COMPANY and returning the completed forms to a designated
COMPANY representative no later than November 21, 1994. An Eligible
--------
Employee who fails to submit timely both enrollment and waiver and
--------
release forms shall be deemed to have elected not to participate in the
VRI. The election of an Eligible Employee not to participate in the VRI,
--- -------- --------
whether through failure to timely submit VRI election and waiver and
---
release forms or otherwise, shall be conclusive and binding on the
EMPLOYEE, EMPLOYEE'S spouse, heirs, and assigns.
IV. VRI Benefit
---
A. Basic VRI Benefit. An Eligible Employee who elects in a timely manner
----- --- ------- -------- --------
to participate in the VRI shall be entitled to receive a Basic VRI
--- ----- ---
Benefit under the RETIREMENT PLAN equal to the BASIC PENSION benefit
-------
formula calculated under Subsection 6(a)(1) with the following
adjustments:
-76-
<PAGE>
1. SERVICE shall mean the PARTICIPANT'S SERVICE as of the VRI
---
Retirement Date for such Eligible Employee, increased by three
---------- ---- -------- --------
years; and
2. The EARLY RETIREMENT PENSION reduction provisions of Subsection
7(b) shall not apply to any Basic VRI Benefit payable under this
----- --- -------
Special Provision N.
B. A Basic VRI Benefit shall be payable as of the VRI Retirement Date and
----- --- ------- --- ---------- ----
shall be paid as soon as practicable after the applicable VRI
---
Retirement Date. Eligible Employees who elect to participate in the
---------- ---- -------- ---------
VRI shall not be subject to the age 55 requirement contained in
---
Section 8.
C. Section 10 of the RETIREMENT PLAN shall control the conditions under
which other forms of pension may be substituted for the Basic VRI
----- ---
Benefit. Thus, although a PARTICIPANT is entitled to receive a Basic
------- -----
VRI Benefit, if the PARTICIPANT is married, Subsection 10(b) of the
--- -------
RETIREMENT PLAN requires that the Basic VRI Benefit be converted to a
----- --- -------
MARITAL PENSION, unless the PARTICIPANT'S spouse consents to an
alternative form of pension.
D. The Basic VRI Benefit payable under this Special Provision N shall be
----- --- -------
in lieu of any benefit which might otherwise be payable under the
RETIREMENT PLAN.
E. A PARTICIPANT who elects to participate in VRI shall also be entitled
---
to make the elections provided in Sections 10 (Forms of Pension), 12
(Withdrawal of Participant Contributions on Termination of
Employment), 13 (Death Benefits), and 14 (Facility of Payment).
V. VRI Retirement Dates
--- ---------- -----
At such time as an EMPLOYEE elects to participate in the VRI, he shall
---
select a VRI Retirement Date. For purposes of this Special Provision N, a
--- ---------- ----
VRI Retirement Date shall mean one of the following:
--- ---------- ----
A. January 1, 1995; or
B. The first of any month during the period commencing with February 1,
1995, and ending with and including January 1, 1996. This Subsection
B shall only apply in the event that the COMPANY has a demonstrated
business need which requires the retention of the Eligible Employee.
-------- --------
The selection of any such VRI Retirement Date subsequent to January 1,
--- ---------- ----
1995, can be made only with the written approval of the COMPANY'S
Chief Executive Officer.
The VRI Retirement Date selected shall also be the date as of which an
--- ---------- ----
Eligible Employee ceases to be an EMPLOYEE of the COMPANY.
-------- --------
VI. Revocation of Election
An Eligible Employee who has elected to participate in the VRI may
-------- -------- ---
revoke his election, provided, however, that any such revocation shall only
be effective if received by the COMPANY on or before November 28, 1994.
-77-
<PAGE>
VII. Definitions
A. Basic VRI Benefit: The benefit calculated under
----- --- -------
Section IV of this Special Provision N.
B. Eligible Employee: An EMPLOYEE of the COMPANY who has met the
-------- --------
eligibility criteria as set forth in Section II. EMPLOYEES of Pacific
Gas Transmission Company, PG&E Enterprises, Pacific Service Employees
Association, and any other subsidiary or affiliate of the COMPANY are
not Eligible Employees for purposes of this VRI.
-------- --------- ---
C. VRI: The COMPANY's Voluntary Retirement Incentive program as set
---
forth in this Special Provision N.
D. VRI Retirement Date: The date selected by an Eligible Employee under
--- ---------- ---- -------- --------
Section V of this Special Provision N.
-78-
<PAGE>
PACIFIC GAS AND ELECTRIC COMPANY
STOCK OPTION PLAN
(As amended and restated effective as of January 1, 1996)*
1. Purpose of the Plan
-------------------
This is the controlling and definitive statement of the Pacific Gas
and Electric Company Stock Option Plan, as amended and restated herein
(hereinafter called the PLAN/1/). The purpose of the PLAN is to advance the
interests of the COMPANY by providing ELIGIBLE PARTICIPANTS with financial
incentives to promote the success of its long-term (five to ten years) business
objectives, and to increase their proprietary interest in the success of the
COMPANY. It is the intent of the COMPANY to reward those ELIGIBLE PARTICIPANTS
who have a significant impact on improved long-term corporate achievements.
Inasmuch as the PLAN is designed to encourage financial performance and to
improve the value of shareholders' investment in PG&E, the costs of the PLAN
will be funded from corporate earnings.
2. Plan Administration
-------------------
The PLAN shall be administered by the COMMITTEE, which shall be
constituted in such a manner as to comply with the rules governing a plan
intended to qualify as a discretionary plan under RULE 16b-3.
Subject to the provisions of the PLAN, the COMMITTEE shall have full
and final authority, in its sole discretion:
(a) to determine the ELIGIBLE PARTICIPANTS to whom OPTIONS shall be
granted and the number of shares of COMMON STOCK to be awarded under each
OPTION, based on the recommendation of the CHIEF EXECUTIVE OFFICER (except that
awards to the CHIEF EXECUTIVE OFFICER shall be shall be based on the
recommendation of the BOARD OF DIRECTORS); provided, however, that the number of
shares of COMMON STOCK to be awarded under each OPTION shall be subject to the
limitations specified in Section 5 hereof;
(b) to determine the time or times at which OPTIONS shall be granted;
(c) to designate the OPTIONS being granted as ISOS or NON-QUALIFIED
STOCK OPTIONS;
- ------------------
/1/ Capitalized words are defined in Section 20 hereof.
* Subject to shareholder approval at the 1996 annual meeting, scheduled for
April 17, 1996.
<PAGE>
(d) to vary the OPTION vesting schedule described in Section 11
hereof;
(e) to determine the terms and conditions, not inconsistent with the
terms of the PLAN, of any OPTION granted hereunder (including, but not limited
to, the consideration and method of payment for shares purchased upon the
exercise of an OPTION, and any vesting acceleration or exercisability provisions
in the event of a CHANGE IN CONTROL or TERMINATION), based in each case on such
factors as the COMMITTEE shall deem appropriate;
(f) to approve forms of agreement for use under the PLAN;
(g) to construe and interpret the PLAN and any related OPTION
agreement and to define the terms employed herein and therein;
(h) except as provided in Section 18 hereof, to modify or amend any
OPTION or to waive any restrictions or conditions applicable to any OPTION or
the exercise thereof;
(i) except as provided in Section 18 hereof, to prescribe, amend and
rescind rules, regulations and policies relating to the administration of the
PLAN;
(j) except as provided in Section 18 hereof, to suspend, terminate,
modify or amend the PLAN;
(k) to delegate to one or more agents such administrative duties as
the COMMITTEE may deem advisable, to the extent permitted by applicable law; and
(l) to make all other determinations and take such other action with
respect to the PLAN and any OPTION granted hereunder as the COMMITTEE may deem
advisable, to the extent permitted by applicable law.
Notwithstanding the provisions contained in the foregoing paragraph,
the CHIEF EXECUTIVE OFFICER shall have the authority, in his sole discretion:
(a) to grant OPTIONS to any ELIGIBLE PARTICIPANT who, at the time of the OPTION
grant, (i) is not an officer of the COMPANY or a DIRECTOR, and (ii) if such
ELIGIBLE PARTICIPANT is an EMPLOYEE, is receiving an annual salary which is
below the level which requires approval by the COMMITTEE; (b) to determine the
time or times at which OPTIONS shall be granted to such ELIGIBLE PARTICIPANTS;
(c) to designate the OPTIONS being granted to such ELIGIBLE PARTICIPANTS as ISOS
or NON-QUALIFIED STOCK OPTIONS; and (d) to vary the OPTION vesting schedule
described in Section 11 hereof for the OPTIONS granted to such ELIGIBLE
PARTICIPANTS; provided, however, that (x) all grants of OPTIONS by the CHIEF
EXECUTIVE OFFICER shall conform to the guidelines previously approved by the
2
<PAGE>
COMMITTEE, and (y) the number of shares of COMMON STOCK to be awarded under each
OPTION shall be subject to the limitations specified in Section 5 hereof.
3. Shares of Stock Subject to the Plan
-----------------------------------
There shall be reserved for use under the PLAN and for the grant of
any other incentive awards pursuant to the PROGRAM (subject to the provisions of
Section 14 hereof) a total of 23,389,230 shares of COMMON STOCK, which shares
may be authorized but unissued shares of COMMON STOCK or issued shares of COMMON
STOCK which shall have been reacquired by PG&E.
If any OPTION expires or terminates for any reason without having been
exercised in full, then any unexercised, shares which were subject to such
OPTION (except shares as to which a related TANDEM SAR has been exercised) shall
again be available for the future grant of OPTIONS under the PLAN (unless the
PLAN has terminated). In addition, shares may be reused or added back to the
PLAN to the extent permitted by applicable law.
4. Eligibility
-----------
OPTIONS will be granted only to ELIGIBLE PARTICIPANTS. ISOS will be
granted only to EMPLOYEES. The COMMITTEE, in its sole discretion, may grant
OPTIONS to an ELIGIBLE PARTICIPANT who is a resident or citizen of a foreign
country, with such modifications as the COMMITTEE may deem advisable to reflect
the laws, tax policy or customs of such foreign country.
The PLAN shall not confer upon any OPTIONEE any right to continuation
of employment, service as a DIRECTOR or consulting relationship with the
COMPANY; nor shall it interfere in any way with the right of the OPTIONEE or the
COMPANY to terminate such employment, service as a DIRECTOR or consulting
relationship at any time, with or without cause.
5. Limitation on Options and SARs Awarded to Any Eligible Participant
------------------------------------------------------------------
The aggregate number of shares of COMMON STOCK with respect to which
any ELIGIBLE PARTICIPANT may be granted OPTIONS and SARS under the PLAN during
any calendar year shall in no event exceed two percent (2%) of the total number
of shares reserved for use under the PLAN.
6. Designation of Options
----------------------
At the time of the grant of each OPTION under the PLAN, the COMMITTEE
(or the CHIEF EXECUTIVE OFFICER, in the case of OPTIONS granted by the CHIEF
EXECUTIVE OFFICER to certain ELIGIBLE PARTICIPANTS pursuant to Section 2 hereof)
shall determine whether such OPTION is to be designated as an ISO or a NON-
QUALIFIED STOCK OPTION; provided, however,
3
<PAGE>
that ISOS may be granted only to EMPLOYEES.
Notwithstanding such designation, to the extent that the aggregate
FAIR MARKET VALUE (determined for each share as of the date of grant of the
OPTION covering each share) of the shares with respect to which OPTIONS
designated as ISOS become exercisable for the first time by any OPTIONEE during
any calendar year exceeds $100,000, such OPTIONS shall be treated as NON-
QUALIFIED STOCK OPTIONS.
OPTIONS shall be awarded at no cost to the OPTIONEE.
7. Option Price
------------
The OPTION PRICE of the COMMON STOCK under each OPTION issued shall be
the FAIR MARKET VALUE of the COMMON STOCK on the date of grant.
8. Stock Appreciation Rights
-------------------------
At the discretion of the COMMITTEE, an OPTION may be granted with or
without a TANDEM SAR which permits the OPTIONEE to surrender unexercised an
OPTION or portion thereof and to receive in exchange a payment having a value
equal to the difference between (x) the FAIR MARKET VALUE of the COMMON STOCK
covered by the surrendered portion of the OPTION on the date the SAR is
exercised and (y) the OPTION PRICE for such COMMON STOCK. The SAR is subject to
the same terms and conditions as the related OPTION, except that (i) the SAR may
be exercised only when there is a positive spread (i.e., when the FAIR MARKET
VALUE of the COMMON STOCK subject to the OPTION exceeds the OPTION PRICE), (ii)
in accordance with Section 9 hereof, payment of the DEA (if any) to the OPTIONEE
may be restricted, and (iii) if the OPTIONEE is a SECTION 16 OFFICER, DIRECTOR
or other person whose transactions in the COMMON STOCK are subject to Section
16(b) of the EXCHANGE ACT, the SAR may be exercised only during the period
beginning on the third (3rd) business day following the date of release of the
COMPANY'S quarterly or annual statement of earnings and ending on the twelfth
(12th) business day following such date. Upon the exercise of a SAR, the number
of shares subject to exercise under the related OPTION shall be automatically
reduced by the number of shares represented by the OPTION or portion thereof
surrendered. No payment will be required from the OPTIONEE upon the exercise of
a SAR, except that any amount necessary to satisfy applicable federal, state or
local tax requirements shall be withheld.
9. Dividend Equivalent Account
---------------------------
At the discretion of the COMMITTEE, an OPTION may be granted with or
without TANDEM DIVIDEND EQUIVALENTS. When an OPTION is granted with TANDEM
DIVIDEND EQUIVALENTS,
4
<PAGE>
a Dividend Equivalent Account ("DEA") shall be established for the OPTIONEE.
This DEA shall be credited quarterly on each dividend record date with dividends
which would have been paid on the COMMON STOCK subject to the unexercised
portion of the OPTION (including any portion which has not yet vested on the
record date), if such portion had been exercised. Except as provided in Section
12(d) hereof, at the time the OPTION or any related SAR is exercised, the
OPTIONEE shall receive all funds which have accumulated in the DEA with respect
to the shares of COMMON STOCK for which the OPTION or SAR is being exercised;
provided, however, that if the OPTIONEE exercises a SAR, such DEA funds shall
only be paid to the OPTIONEE if (i) the percentage increase in the FAIR MARKET
VALUE of the COMMON STOCK over the OPTION PRICE averages at least five percent
(5%) per year for the first five (5) years after the grant, or (ii) in the case
of OPTIONS held for longer than five (5) years from the date of grant, such FAIR
MARKET VALUE has increased by at least twenty-five percent (25%) over the OPTION
PRICE.
10. Terms of Options
----------------
The term of each ISO shall be for ten (10) years from the date of
grant, subject to earlier termination as provided in Section 12 hereof. The
term of each NON-QUALIFIED STOCK OPTION shall be ten (10) years and one (1) day
from the date of grant, subject to earlier termination as provided in Section 12
hereof. Any provision of the PROGRAM to the contrary notwithstanding, no OPTION
shall be exercised after the time limitations stated in this Section 10.
11. Limitations on Exercise
-----------------------
(a) Each OPTION granted under the PROGRAM shall become exercisable and
vested only to the following extent: (i) up to one-third (1/3) of the OPTIONS
granted may be exercised on or after the second (2nd) anniversary of the date of
grant; (ii) up to two-thirds (2/3) of the OPTIONS granted may be exercised on or
after the third (3rd) anniversary of the date of grant; and (iii) up to one
hundred percent (100%) of the OPTIONS granted may be exercised on or after the
fourth (4th) anniversary of the date of grant.
(b) No OPTION under the PROGRAM designated by the COMMITTEE as an ISO
and granted before January 1, 1987 may be exercised while there is outstanding
in the hands of the OPTIONEE any ISO which was granted before the granting of
the ISO hereunder sought to be exercised. For this purpose an ISO shall be
treated as outstanding until such OPTION is (i) exercised in full, (ii)
surrendered in full by exercising SARS pursuant to Section 8 hereof, or (iii)
rendered void by reason of lapse of time.
5
<PAGE>
12. Termination of Employment or Relationship with the Company
----------------------------------------------------------
(a) In the event of a TERMINATION by reason of a discharge or
TERMINATION FOR CAUSE, any unexercised OPTIONS theretofore granted to an
OPTIONEE under the PROGRAM shall forthwith terminate.
(b) In the event of a TERMINATION by reason of RETIREMENT, all OPTIONS
held by the OPTIONEE, to the extent that such OPTIONS have not previously
expired or been exercised, shall become fully exercisable and vested,
notwithstanding the provisions of Section 11(a) hereof, and the OPTIONEE shall
have the right to exercise such OPTIONS in full at any time within their
respective terms or within five (5) years after such RETIREMENT, whichever is
shorter. This five-year period shall be extended if an OPTIONEE remains on the
BOARD OF DIRECTORS after RETIREMENT. In such case, the OPTIONS may be exercised
as long as the OPTIONEE remains a DIRECTOR and for a period of six (6) months
thereafter, or within five (5) years after RETIREMENT, whichever is longer;
provided, however, that no OPTION may be exercised after the expiration of its
term. Notwithstanding the foregoing, any ISOS held by the OPTIONEE may be
exercised only within their respective terms or within three (3) months after
RETIREMENT, whichever is shorter.
(c) In the event of a TERMINATION by reason of disability or death,
all OPTIONS held by the OPTIONEE, to the extent that such OPTIONS have not
previously expired or been exercised, shall become fully exercisable and vested,
notwithstanding the provisions of Section 11(a) hereof, and the OPTIONEE (or the
OPTIONEE'S estate or a person who acquired the right to exercise such OPTIONS by
bequest or inheritance) shall have the right to exercise such OPTIONS at any
time within their respective terms or within one (1) year after the date of such
TERMINATION, whichever is shorter. The term "disability" shall, for the
purposes of the PLAN, be defined in Section 22(e)(3) of the CODE.
(d) In the event of a TERMINATION by reason of a divestiture or change
in control of a subsidiary of PG&E, which divestiture or change in control
results in such subsidiary no longer qualifying as a subsidiary corporation
under Section 424(f) of the CODE, all OPTIONS held by the OPTIONEE, to the
extent that such OPTIONS have not previously expired or been exercised, shall
become fully exercisable and vested, notwithstanding the provisions of Section
11(a) hereof, and the OPTIONEE shall have the right to exercise such OPTIONS in
full at any time within their respective terms or within three (3) years after
such TERMINATION, whichever is shorter. This three-year period shall be
extended if an OPTIONEE remains on the BOARD OF DIRECTORS after such
TERMINATION. In such case, the OPTIONS may be exercised as long as the OPTIONEE
remains a DIRECTOR
6
<PAGE>
and for a period of six (6) months thereafter, or within three (3) years after
such TERMINATION, whichever is longer; provided, however, that no OPTION may be
exercised after the expiration of its term. Notwithstanding the foregoing, any
ISOS held by the OPTIONEE may be exercised only within their respective terms or
within three (3) months after such TERMINATION, whichever is shorter.
(e) In the event of a TERMINATION for any reason other than those
specified in subparagraphs (a) through (d) above, (i) any unexercised OPTION or
OPTIONS granted under the PROGRAM shall be deemed cancelled and terminated
forthwith, except that the OPTIONEE may exercise any unexercised OPTIONS
theretofore granted which are otherwise exercisable and vested within the
provisions of Section 11(a) hereof, during the balance of their respective terms
or within thirty (30) days of such TERMINATION, whichever is shorter, and (ii)
the DEA (if any) shall not be credited with any dividends paid after the date of
such TERMINATION.
(f) Notwithstanding the provisions of subparagraphs (a) through (e)
above, the COMMITTEE may, in its sole discretion, establish different terms and
conditions pertaining to the effect of TERMINATION, to the extent permitted by
applicable federal and state law.
13. Payment for Shares Upon Exercise of Options
-------------------------------------------
The exercise of any OPTION shall be contingent upon receipt by the
COMPANY of (i) cash (including any DEA funds payable to the OPTIONEE in
connection with the exercise of such OPTION), (ii) check, (iii) shares of COMMON
STOCK, (iv) an executed exercise notice together with irrevocable instructions
to a broker to either sell the shares subject to the OPTION or hold such shares
as collateral for a margin loan and to promptly deliver to the COMPANY the
amount of sale or loan proceeds required to pay the OPTION PRICE, (v) any
combination of the foregoing in an amount equal to the full OPTION PRICE of the
shares being purchased, or (vi) such other consideration and method of payment,
other than a note from the OPTIONEE, as the COMMITTEE, in its sole discretion,
may allow (which, in the case of an ISO shall be determined at the time of
grant), to the extent permitted by applicable law. For purposes of this
paragraph, shares of COMMON STOCK that are delivered in payment of the OPTION
PRICE must have been previously owned by the OPTIONEE for a minimum of one year,
and shall be valued at their FAIR MARKET VALUE as of the date of the exercise of
the OPTION. The COMPANY shall not make loans to any OPTIONEE for the purpose of
exercising OPTIONS.
7
<PAGE>
14. Adjustments Upon Changes in Number or Value of Shares of Common Stock
---------------------------------------------------------------------
If there are any changes in the number or value of
shares of COMMON STOCK by reason of stock dividends, stock splits, reverse stock
splits, recapitalizations, mergers, consolidations or other events that
materially increase or decrease the number or value of issued and outstanding
shares of COMMON STOCK, the COMMITTEE may make such adjustments as it shall deem
appropriate, in order to prevent dilution or enlargement of rights.
15. Non-Transferability of Options
------------------------------
An OPTION shall not be transferable by the OPTIONEE otherwise than by
will or the laws of descent and distribution, or pursuant to a qualified
domestic relations order as defined by the CODE, Title I of ERISA or the rules
thereunder. During the lifetime of the OPTIONEE, an OPTION may be exercised
only by the OPTIONEE or by an alternate payee under a qualified domestic
relations order.
16. Change in Control
-----------------
Upon the occurrence of a CHANGE IN CONTROL (as defined below):
(a) Any time periods relating to the exercise of any OPTION granted
hereunder shall be accelerated so that such OPTION may be immediately exercised
in full; and
(b) The COMMITTEE may offer any OPTIONEE the option of having the
COMPANY purchase his or her OPTION for an amount of cash which could have been
attained upon the exercise of such OPTION had it been fully exercisable;
unless the COMMITTEE in its sole discretion determines that such
CHANGE IN CONTROL will not adversely impact the OPTIONEES of OPTIONS hereunder
and is in the best interests of the shareholders of PG&E. The COMMITTEE may
make such further provisions with respect to a CHANGE IN CONTROL as it shall
deem equitable and in the best interests of the shareholders of PG&E. Such
provision may be made in any agreement relating to any OPTION granted hereunder,
by amendment to any such agreement or by resolution of the COMMITTEE.
The phrase "CHANGE IN CONTROL" shall have such meaning as ascribed
thereto from time to time by the COMMITTEE and set forth in any agreement
relating to any OPTION granted hereunder or by resolution of the COMMITTEE;
provided, however, that, notwithstanding the foregoing, a "CHANGE IN CONTROL"
shall be deemed to have occurred if:
(a) any "person" (as such term is used in Sections 13(d) and 14(d)(2)
of the EXCHANGE ACT, but excluding any benefit plan for EMPLOYEES or any
trustee, agent or other fiduciary for any such plan acting in such person's
capacity as such fiduciary), directly or indirectly, becomes the beneficial
owner of securities of PG&E representing twenty percent (20%) or more of the
combined voting power of PG&E's then outstanding securities;
8
<PAGE>
(b) during any two consecutive years, individuals who at the beginning
of such a period constitute the BOARD OF DIRECTORS cease for any reason to
constitute at least a majority of the BOARD OF DIRECTORS, unless the election,
or the nomination for election by the shareholders of PG&E, of each new DIRECTOR
was approved by a vote of at least two-thirds (2/3) of the DIRECTORS then still
in office who were DIRECTORS at the beginning of the period; or
(c) the shareholders of PG&E shall have approved (i) any consolidation
or merger of PG&E in which PG&E is not the continuing or surviving corporation
or pursuant to which shares of COMMON STOCK are converted into cash, securities
or other property, other than a merger of PG&E in which the holders of the
COMMON STOCK immediately prior to the merger have the same proportionate
ownership of common stock of the surviving corporation immediately after the
merger, (ii) any sale, lease, exchange or other transfer (in one transaction or
a series of related transactions) of all or substantially all of the assets of
the COMPANY, or (iii) any plan or proposal for the liquidation or dissolution of
PG&E.
Notwithstanding the foregoing, the phrase "CHANGE IN CONTROL" shall
not apply to any reorganization or merger initiated voluntarily by PG&E in which
PG&E is the continuing surviving entity.
17. Listing and Registration of Shares
----------------------------------
Each OPTION shall be subject to the requirement that if at any time
the COMMITTEE shall determine, in its discretion, that the listing, registration
or qualification of the shares covered thereby under any securities exchange or
under any state or federal law or the consent or approval of any governmental
regulatory body, including the California Public Utilities Commission, is
necessary or desirable as a condition of, or in connection with, the granting of
such OPTION or the issue or purchase of shares thereunder, such OPTION may not
be exercised in whole or in part unless and until such listing, registration,
qualification, consent or approval shall have been effected or obtained free of
any conditions not acceptable to the COMMITTEE.
18. Amendment and Termination of the Plan and Options
-------------------------------------------------
The BOARD OF DIRECTORS or the COMMITTEE may at any time suspend,
terminate, modify or amend the PLAN in any respect; provided, however, that, to
the extent necessary and desirable to comply with RULE 16b-3 or with Section 422
of the CODE (or any other applicable law or regulation, including the
requirements of any stock exchange on which the COMMON STOCK is listed or
quoted), shareholder approval of any PLAN amendment shall be obtained in such a
manner and to such a degree as is required by the applicable law or regulation.
9
<PAGE>
No suspension, termination, modification or amendment of the PLAN may,
without the consent of the OPTIONEE, adversely affect his or her rights under
OPTIONS theretofore granted to such OPTIONEE. In the event of amendments to the
CODE or applicable rules or regulations relating to ISOS subsequent to the date
hereof, the COMPANY may amend the PLAN, and the COMPANY and OPTIONEES holding
OPTION agreements may agree to amend outstanding OPTION agreements, to conform
to such amendments.
The COMMITTEE may make such amendments or modifications in the terms
and conditions of any OPTION as it may deem advisable, or cancel or annul any
grant of an OPTION; provided, however, that no such amendment, modification,
cancellation or annulment may, without the consent of the OPTIONEE, adversely
affect his or her rights under such OPTION; and provided further the COMMITTEE
may not reduce the OPTION PRICE or purchase price of any OPTION or OPTION below
the original OPTION PRICE or purchase price.
Notwithstanding the foregoing, the COMMITTEE reserves the right, in
its sole discretion, to (i) convert any outstanding ISOS to NON-QUALIFIED STOCK
OPTIONS, (ii) to require a OPTIONEE to forfeit any unexercised or unpurchased
OPTIONS, any shares received or purchased pursuant to an OPTION, or any gains
realized by virtue of the receipt of an OPTION in the event that such OPTIONEE
competes against the COMPANY, and (iii) to cancel or annul any grant of an
OPTION in the event of a OPTIONEE'S TERMINATION FOR CAUSE. For purposes of the
PROGRAM, "TERMINATION FOR CAUSE" shall include, but not be limited to,
termination because of dishonesty, criminal offense or violation of a work rule,
and shall be determined by, and in the sole discretion of, the COMMITTEE.
19. Effective Date of the Plan and Duration
---------------------------------------
The PLAN first became effective as of January 1, 1992. It has since
been amended and restated. The amended and restated PLAN shall become effective
as of January 1, 1996, provided the amended and restated PROGRAM is approved by
the shareholders of PG&E within twelve (12) months following the date of
adoption by the BOARD OF DIRECTORS. Unless terminated sooner pursuant to
Section 18 hereof, the PLAN shall terminate on December 31, 2005.
20. Definitions
-----------
a. BOARD OF DIRECTORS means the Board of Directors of PG&E.
------------------
b. CHANGE IN CONTROL has the meaning set forth in Section 16 hereof.
-----------------
c. CHIEF EXECUTIVE OFFICER means the Chief Executive Officer of PG&E.
-----------------------
10
<PAGE>
d. CODE means the Internal Revenue Code of 1986, as amended from time to
----
time.
e. COMMITTEE means the Nominating and Compensation Committee of the
---------
BOARD OF DIRECTORS or any successor to such committee.
f. COMMON STOCK means common shares of PG&E with a par value of $5.00
------------
per share and any class of common shares into which such common
shares hereafter may be converted.
g. COMPANY means PG&E, and any parent corporation (as defined in Section
424(e) of the CODE) or subsidiary corporation (as defined in Section
424(f) of the CODE).
h. CONSULTANT means any person, including an advisor, who is engaged by
----------
the COMPANY to render services.
i. DEA means a Dividend Equivalent Account described in Section 9
---
hereof.
j. DIRECTOR means any person who is a member of the BOARD OF DIRECTORS
--------
or the Board of Directors of any parent corporation (as defined in
Section 424(e) of the CODE) which may hereafter be established,
including an advisory, emeritus or honorary director.
k. DIVIDEND EQUIVALENT means a right that entitles the OPTIONEE to
-------------------
receive cash or COMMON STOCK based on the dividends
declared on the COMMON STOCK covered by such right.
l. ELIGIBLE PARTICIPANT means any KEY EMPLOYEE. It also means, if so
--------------------
identified by the COMMITTEE (or by the CHIEF EXECUTIVE OFFICER, in
the case of OPTIONS granted by the CHIEF EXECUTIVE OFFICER to
certain ELIGIBLE PARTICIPANTS pursuant to Section 2 hereof), other
EMPLOYEES, DIRECTORS, CONSULTANTS, employees or consultants of any
affiliates of PG&E, and other persons whose participation in the
PROGRAM is deemed by the COMMITTEE (or by the CHIEF EXECUTIVE
OFFICER, in the case of OPTIONS granted by the CHIEF EXECUTIVE
OFFICER to certain ELIGIBLE PARTICIPANTS pursuant to Section 2
hereof) to be in the best interests of the COMPANY; provided,
however, that DIRECTORS who are not EMPLOYEES shall not be ELIGIBLE
PARTICIPANTS for purposes of the PLAN.
11
<PAGE>
m. EMPLOYEE means any person who is employed by the COMPANY. The
--------
payment of a director's fee or consulting fee by the COMPANY shall
not be sufficient to constitute "employment" by the COMPANY.
n. ERISA means the Employee Retirement Income Security Act of 1974, as
-----
amended.
o. EXCHANGE ACT means the Securities Exchange Act of 1934, as
------------
amended.
p. FAIR MARKET VALUE means the closing price of the COMMON STOCK
-----------------
reported on the New York Stock Exchange Composite Transactions for
the date specified for determining such value.
q. ISO means an OPTION intended to qualify as an incentive stock
---
option under Section 422 of the CODE.
r. KEY EMPLOYEE means the Corporate Secretary, Treasurer, Vice
------------
Presidents and other executive officers of PG&E above the rank of
Vice President. It also means, if so identified by the COMMITTEE
(or by the CHIEF EXECUTIVE OFFICER, in the case of OPTIONS granted
by the CHIEF EXECUTIVE OFFICER to certain ELIGIBLE PARTICIPANTS
pursuant to Section 2 hereof), executive officers of wholly-owned
subsidiaries of PG&E (including subsidiaries which become such
after adoption of the PROGRAM) and any other key management
employee of PG&E or any wholly-owned subsidiary of PG&E.
s. NON-EMPLOYEE DIRECTOR means a DIRECTOR who is not an EMPLOYEE.
---------------------
t. NON-QUALIFIED STOCK OPTION means any OPTION which is not an ISO.
--------------------------
u. OPTION means an option to purchase shares of COMMON STOCK granted
------
under the PLAN.
v. OPTIONEE means the ELIGIBLE PARTICIPANT receiving the OPTION, or
--------
his or her legal representative, legatees, distributees or
alternate payees, as the case may be.
12
<PAGE>
w. OPTION PRICE means the purchase price for the COMMON STOCK
------------
upon exercise of an OPTION.
x. PG&E means Pacific Gas and Electric Company, a California
----
corporation.
y. PLAN means this Stock Option Plan as amended and restated herein
----
and as may be amended from time to time, or any successor plan
which the COMMITTEE may adopt from time to time with respect to the
grant of OPTIONS under the PROGRAM.
z. PROGRAM means the Pacific Gas and Electric Company Long-Term
-------
Incentive Program, as amended and restated effective as of January
1, 1996 and as may be amended from time to time, pursuant to which
the PLAN is adopted.
aa. RETIREMENT means the Actual Retirement Date under the PG&E
----------
Retirement Plan.
ab. RULE 16b-3 means Rule 16b-3 under the EXCHANGE ACT or any successor
----------
to Rule 16b-3, as in effect when discretion is being exercised with
respect to the PLAN.
ac. SAR means a stock appreciation right whose value is based on the
---
increase in the FAIR MARKET VALUE of the COMMON STOCK covered by
such right.
ad. SECTION 16 OFFICER means any person who is designated by the BOARD
------------------
OF DIRECTORS as an executive officer of PG&E and any other person
who is designated as an officer of PG&E for purposes of Section 16
of the EXCHANGE ACT.
ae. TANDEM refers to a DIVIDEND EQUIVALENT or SAR (as the case may be)
------
granted in conjunction with an OPTION.
af. TERMINATION occurs when an EMPLOYEE ceases to be employed by the
-----------
COMPANY as a common law employee, when a DIRECTOR ceases to be a
member of the BOARD OF DIRECTORS or the Board of Directors of any
parent corporation which may hereafter be established (as the case
may be), or when the relationship between the COMPANY and a
CONSULTANT or other ELIGIBLE PARTICIPANT terminates, as the case
may be.
ag. TERMINATION FOR CAUSE has the meaning set forth in Section 12
---------------------
hereof.
13
<PAGE>
PERFORMANCE UNIT PLAN
OF
THE PACIFIC GAS AND ELECTRIC COMPANY*
_____________________________________
This is the controlling and definitive statement of the Performance Unit
Plan ("PLAN"/1/) for ELIGIBLE EMPLOYEES of Pacific Gas and Electric Company
("COMPANY") and such other companies, affiliates, subsidiaries, or associations
as the BOARD OF DIRECTORS may designate from time to time. The PLAN was first
adopted by the BOARD in 1989 and was effective January 1, 1990. It has since
been amended from time to time.
ARTICLE I
DEFINITIONS
-----------
1.01 Board of Directors or Board shall mean the BOARD OF DIRECTORS of the
------------------
COMPANY or, when appropriate, any committee of the BOARD which has been
delegated the authority to take action with respect to the PLAN.
1.02 Committee shall mean the Nominating and Compensation Committee of the
---------
BOARD OF DIRECTORS.
1.03 Company shall mean the Pacific Gas and Electric Company, a California
-------
corporation.
1.04 Eligible Employee shall mean employees of the COMPANY who are
-----------------
officers at the vice presidential level or above, the corporate secretary, the
controller, and the treasurer of the COMPANY, and such other employees of the
COMPANY, other companies, affiliates, subsidiaries, or associations as may be
designated by the COMMITTEE.
1.05 Performance Targets shall mean the annual COMPANY financial and
-------------------
operational goals adopted by the COMMITTEE to be used in determining awards
under the PLAN.
1.06 Plan shall mean the Performance Unit Plan ("PUP") as set forth herein
----
and as may be amended from time to time.
- --------------
/1/Words in all capitals are defined in Article I.
* As amended and restated effective as of January 1, 1996, subject to
shareholder approval at the 1996 annual meeting, scheduled for April 17,
1996.
<PAGE>
1.07 Plan Administrator shall mean the COMMITTEE or such individual or
------------------
individuals as that COMMITTEE may appoint to handle the day-to-day affairs of
the PLAN.
1.08 Price shall mean the average market price of STOCK for the last 30-
-----
day period of the YEAR preceding the YEAR in which UNITS are payable.
1.09 PUP Units shall mean the units granted to ELIGIBLE EMPLOYEES who
---------
participate in the PLAN. A PUP UNIT has the equivalent value of the current
market price of a share of STOCK at the time of grant.
1.10 Stock shall mean the common stock of the COMPANY and any class of
-----
common shares into which such STOCK hereafter may be converted.
1.11 Vesting Period shall mean the three calendar YEARS commencing with
--------------
the YEAR in which PUP UNITS are granted.
1.12 Year shall mean a calendar year.
----
ARTICLE II
2.01 Prior to the beginning of each YEAR, the COMMITTEE shall determine
whether PUP UNITS will be granted for such YEAR, the ELIGIBLE EMPLOYEES to whom
PUP UNITS will be granted, and the number of PUP UNITS to be granted to each
ELIGIBLE EMPLOYEE. Employees who become ELIGIBLE EMPLOYEES after the beginning
of a YEAR shall be entitled to a prorata grant of PUP UNITS.
2.02 At the same time that the COMMITTEE makes its determination as to the
granting of PUP UNITS, it shall also establish PERFORMANCE TARGETS. Although it
is intended that PERFORMANCE TARGETS will not change in the course of the YEAR,
the COMMITTEE reserves the right to modify or adjust a previously set
PERFORMANCE TARGET if, in its sole discretion, extraordinary events warrant such
modification or adjustment; provided, however, that no such modification or
adjustment shall increase the amount of any payment that would otherwise be due
based upon performance as measured against the original PERFORMANCE TARGET.
2.03 Each grant of PUP UNITS shall have its own VESTING PERIOD. Subject
to modification as measured against a given YEAR's applicable PERFORMANCE
TARGET, each grant of PUP UNITS shall be payable as follows:
a. One-third after the end of the first YEAR of the VESTING PERIOD;
b. One-third after the end of the second YEAR of the VESTING PERIOD; and
c. One-third after the end of the third YEAR of the VESTING PERIOD.
2
<PAGE>
2.04 To determine the number of PUP UNITS earned, the applicable
PERFORMANCE TARGET shall be the PERFORMANCE TARGET for the YEAR in which the PUP
UNITS vest. Performance as measured against the applicable PERFORMANCE TARGET
for a YEAR shall modify all PUP UNITS that vest at the end of such YEAR. The
PERFORMANCE TARGETS established by the COMMITTEE may modify the number of UNITS
earned from 0% to 200% of the number of vested UNITS.
2.05 ELIGIBLE EMPLOYEES shall receive a cash payment as soon as
practicable following the YEAR PUP UNITS vest pursuant to the schedule set forth
in Section 2.03. The amount of the payment shall be equal to the product of the
number of PUP UNITS earned multiplied by the PRICE of STOCK.
2.06 Each time that the COMPANY declares a dividend on its STOCK, an
amount equal to the dividend multiplied by an ELIGIBLE EMPLOYEE's outstanding,
but unearned PUP UNITS, shall be accrued on behalf of each ELIGIBLE EMPLOYEE.
As soon as practicable following the end of each YEAR, ELIGIBLE EMPLOYEES shall
receive a cash payment of the dividends accrued for that YEAR, modified by
performance for that YEAR as measured under Section 2.04.
2.07 An ELIGIBLE EMPLOYEE may elect to defer the payment of PUP UNITS
and/or dividends paid on PUP UNITS by making a timely election under the
Deferred Compensation Plan. Deferrals of benefits payable under this Plan shall
be subject to the rules contained in the Deferred Compensation Plan governing
elections to defer and receipt of deferred amounts.
ARTICLE III
3.01 Retirement. Upon retirement under the terms of the COMPANY's
----------
Retirement Plan, all outstanding PUP UNITS continue to be payable according to
the terms of the PLAN. Thus, the number of UNITS eventually earned by a retired
employee is still subject to modification depending on the extent to which
applicable PERFORMANCE TARGETS are met during the YEAR preceding the January in
which UNITS become payable under the schedule of Section 2.03. A retired
employee is not entitled to receive grants of PUP UNITS after normal or early
retirement date, as those terms are defined under the COMPANY's Retirement Plan.
3.02 Disability. If an ELIGIBLE EMPLOYEE is both disabled and entitled to
----------
receive benefits under the COMPANY's Long Term Disability Plan, UNITS granted
prior to the date of disability shall continue to be payable according to the
terms of this PLAN. An ELIGIBLE EMPLOYEE is not entitled to receive grants of
PUP UNITS after the date of disability as determined under the provisions of the
Long Term Disability Plan. If an ELIGIBLE EMPLOYEE ceases to be an ELIGIBLE
EMPLOYEE because of disability and is not entitled to receive benefits under the
3
<PAGE>
COMPANY's Long Term Disability Plan, all outstanding grants of PUP UNITS become
vested and payable as soon as practicable in the YEAR following the YEAR in
which the ELIGIBLE EMPLOYEE ceases to be an ELIGIBLE EMPLOYEE. All of the UNITS
payable shall be subject to modification based upon performance as measured
against the PERFORMANCE TARGET for the YEAR in which the ELIGIBLE EMPLOYEE
ceases to be an ELIGIBLE EMPLOYEE.
3.03 Death. In the event of the death of an ELIGIBLE EMPLOYEE, all
-----
outstanding grants of PUP UNITS held by the ELIGIBLE EMPLOYEE at the date of
death shall become vested and payable as soon as practicable in the YEAR
following the YEAR of death. All of the UNITS payable after an ELIGIBLE
EMPLOYEE's death shall be subject to modification based upon performance as
measured against the PERFORMANCE TARGET for the YEAR in which the death of the
ELIGIBLE EMPLOYEE occurs.
3.04 Termination. If an ELIGIBLE EMPLOYEE ceases to be an ELIGIBLE
-----------
EMPLOYEE for any reason other than retirement as defined under the COMPANY's
Retirement Plan, disability, or death, all outstanding grants of PUP UNITS shall
be canceled as of the date that the ELIGIBLE EMPLOYEE ceases to be an ELIGIBLE
EMPLOYEE.
ARTICLE IV
ADMINISTRATIVE PROVISIONS
-------------------------
4.01 Administration. The PLAN shall be administered by the PLAN
--------------
ADMINISTRATOR who shall have the authority to interpret the PLAN and make such
rules as it deems appropriate. The PLAN ADMINISTRATOR shall have the duty and
responsibility of maintaining records, making the requisite calculations, and
disbursing payments hereunder. The PLAN ADMINISTRATOR's interpretations,
determinations, rules, and calculations shall be final and binding on all
persons and parties concerned.
4.02 Amendment and Termination. The COMPANY may amend or terminate the
-------------------------
PLAN at any time, provided, however, that no such amendment or termination shall
adversely affect PUP UNITS which an ELIGIBLE EMPLOYEE has earned prior to the
date of such amendment or termination. PUP UNITS outstanding but unearned at
the date of any such amendment or termination may, in the sole discretion of the
COMPANY, be canceled, and the COMPANY shall have no obligation to provide a
substitute benefit of lesser, equal, or greater value.
4.03 Nonassignability of Benefits. The benefits payable under this PLAN
----------------------------
or the right to receive future benefits under this PLAN may not be anticipated,
alienated, pledged, encumbered, or subject to any charge or legal process, and
if any attempt is
4
<PAGE>
made to do so, or a person eligible for any benefits becomes bankrupt, the
interest under the PLAN of the person affected may be terminated by the PLAN
ADMINISTRATOR which, in its sole discretion, may cause the same to be held if
applied for the benefit of one or more of the dependents of such person or make
any other disposition of such benefits that it deems appropriate.
4.04 No Guarantee of Employment. Nothing contained in this PLAN shall be
--------------------------
construed as a contract of employment between the COMPANY or the ELIGIBLE
EMPLOYEE, or as a right of the ELIGIBLE EMPLOYEE to be continued in the employ
of the COMPANY, to remain as an officer of the COMPANY, or as a limitation on
the right of the COMPANY to discharge any of its employees, with or without
cause.
4.05 Benefits Unfunded and Unsecured. The benefits under this PLAN are
-------------------------------
unfunded, and the interest under this PLAN of any ELIGIBLE EMPLOYEE and such
ELIGIBLE EMPLOYEE's right to receive a distribution of benefits under this PLAN
shall be an unsecured claim against the general assets of the COMPANY.
4.06 Applicable Law. All questions pertaining to the construction,
--------------
validity, and effect of the PLAN shall be determined in accordance with the laws
of the United States, and to the extent not preempted by such laws, by the laws
of the State of California.
5
<PAGE>
PACIFIC GAS AND ELECTRIC COMPANY
LONG-TERM INCENTIVE PROGRAM
(As amended and restated effective as of January 1, 1996)*
1. Purpose of the Program
----------------------
This is the controlling and definitive statement of the Pacific Gas
and Electric Company Long-Term Incentive Program, as amended and restated herein
(hereinafter called the PROGRAM/1/). The purpose of the PROGRAM is to advance
the interests of the COMPANY by providing ELIGIBLE PARTICIPANTS with financial
incentives to promote the success of its long-term (five to ten years) business
objectives, and to increase their proprietary interest in the success of the
COMPANY. It is the intent of the COMPANY to reward those ELIGIBLE PARTICIPANTS
who have a significant impact on improved long-term corporate achievements.
Inasmuch as the PROGRAM is designed to encourage financial performance and to
improve the value of shareholders' investment in PG&E, the costs of the PROGRAM
will be funded from corporate earnings.
2. Program Administration
----------------------
The PROGRAM shall be administered by the COMMITTEE, which shall be
constituted in such a manner as to comply with the rules governing a plan
intended to qualify as a discretionary plan under RULE 16b-3.
Subject to the provisions of the PROGRAM, the COMMITTEE shall have
full and final authority, in its sole discretion:
(a) to determine the ELIGIBLE PARTICIPANTS to whom INCENTIVE AWARDS
shall be granted and the number of shares of COMMON STOCK to be awarded under
each INCENTIVE AWARD, based on the recommendation of the CHIEF EXECUTIVE OFFICER
(except that awards to the CHIEF EXECUTIVE OFFICER shall be based on the
recommendation of the BOARD OF DIRECTORS);
(b) to determine the time or times at which INCENTIVE AWARDS shall be
granted;
(c) to designate the types of INCENTIVE AWARD being granted;
(d) to vary the OPTION vesting schedule described in the STOCK OPTION
PLAN;
- ------------
/1/ Capitalized words are defined in Section 20 hereof.
* Subject to shareholder approval at the 1996 annual meeting, scheduled for
April 17, 1996.
<PAGE>
(e) to determine the terms and conditions, not inconsistent with the
terms of the PROGRAM, of any INCENTIVE AWARD granted hereunder (including, but
not limited to, the consideration and method of payment for shares purchased
upon the exercise of an INCENTIVE AWARD, and any vesting acceleration or
exercisability provisions in the event of a CHANGE IN CONTROL or TERMINATION),
based in each case on such factors as the COMMITTEE shall deem appropriate;
(f) to approve forms of agreement for use under the PROGRAM;
(g) to construe and interpret the PROGRAM and any related INCENTIVE
AWARD agreement and to define the terms employed herein and therein;
(h) except as provided in Section 18 hereof, to modify or amend any
INCENTIVE AWARD or to waive any restrictions or conditions applicable to any
INCENTIVE AWARD or the exercise or realization thereof;
(i) except as provided in Section 18 hereof, to prescribe, amend and
rescind rules, regulations and policies relating to the administration of the
PROGRAM;
(j) except as provided in Section 18 hereof, to
suspend, terminate, modify or amend the PROGRAM;
(k) to delegate to one or more agents such administrative duties as
the COMMITTEE may deem advisable, to the extent permitted by applicable law; and
(l) to make all other determinations and take such other action with
respect to the PROGRAM and any INCENTIVE AWARD granted hereunder as the
COMMITTEE may deem advisable, to the extent permitted by applicable law.
Notwithstanding the provisions contained in the foregoing paragraph,
the CHIEF EXECUTIVE OFFICER shall have the authority, in his sole discretion:
(a) to grant INCENTIVE AWARDS to any ELIGIBLE PARTICIPANT who, at the time of
the INCENTIVE AWARD grant, (i) is not an officer of the COMPANY or a DIRECTOR,
and (ii) if such ELIGIBLE PARTICIPANT is an EMPLOYEE, is receiving an annual
salary which is below the level which requires approval by the COMMITTEE; (b) to
determine the time or times at which INCENTIVE AWARDS shall be granted to such
ELIGIBLE PARTICIPANTS; (c) to designate the types of INCENTIVE AWARD being
granted to such ELIGIBLE PARTICIPANTS; and (d) to vary the OPTION vesting
schedule described in the STOCK OPTION PLAN for the OPTIONS granted to such
ELIGIBLE PARTICIPANTS; provided, however, that all grants of INCENTIVE AWARDS by
the CHIEF EXECUTIVE OFFICER shall conform to the guidelines previously approved
by the COMMITTEE.
2
<PAGE>
3. Shares of Stock Subject to the Program
--------------------------------------
There shall be reserved for use under the PROGRAM (subject to the
provisions of Section 13 hereof) a total of 23,389,230 shares of COMMON STOCK,
which shares may be authorized but unissued shares of COMMON STOCK or issued
shares of COMMON STOCK which shall have been reacquired by PG&E. Such shares
consist of (i) 13,000,000 shares of COMMON STOCK originally reserved for use
under the PROGRAM at the time it first became effective on January 1, 1992, (ii)
389,230 shares of COMMON STOCK remaining under the 1986 OPTION PLAN and carried
over to the PROGRAM, and (iii) 10,000,000 shares of COMMON STOCK added to the
PROGRAM effective as of January 1, 1996.
If (i) any INCENTIVE AWARD expires or terminates for any reason
without having been exercised or purchased in full, (ii) an INCENTIVE AWARD is
surrendered in exchange for one or more other INCENTIVE AWARDS, or (iii) any
RESTRICTED STOCK is forfeited, then, in each such case, any unexercised,
unpurchased, surrendered or forfeited shares which were subject to such
INCENTIVE AWARD (except shares as to which a related TANDEM SAR has been
exercised) shall again be available for the future grant of INCENTIVE AWARDS
under the PROGRAM (unless the PROGRAM has terminated). In addition, shares may
be reused or added back to the PROGRAM to the extent permitted by applicable
law.
4. Eligibility
-----------
INCENTIVE AWARDS will be granted only to ELIGIBLE PARTICIPANTS. ISOS
will be granted only to EMPLOYEES. NON-EMPLOYEE DIRECTORS will only be eligible
to be granted DIRECTOR RESTRICTED STOCK. The COMMITTEE, in its sole discretion,
may grant INCENTIVE AWARDS to an ELIGIBLE PARTICIPANT who is a resident or
citizen of a foreign country, with such modifications as the COMMITTEE may deem
advisable to reflect the laws, tax policy or customs of such foreign country.
The PROGRAM shall not confer upon any RECIPIENT any right to
continuation of employment, service as a DIRECTOR or consulting relationship
with the COMPANY; nor shall it interfere in any way with the right of the
RECIPIENT or the COMPANY to terminate such employment, service as a DIRECTOR or
consulting relationship at any time, with or without cause.
5. Designation of Incentive Awards
-------------------------------
At the time of the grant of each INCENTIVE AWARD under the Program,
the COMMITTEE (or the CHIEF EXECUTIVE OFFICER, in the case of INCENTIVE AWARDS
granted by the CHIEF EXECUTIVE OFFICER to certain ELIGIBLE PARTICIPANTS pursuant
to Section 2 hereof) shall determine whether such INCENTIVE AWARD is to be
designated as an ISO, NON-QUALIFIED STOCK OPTION, SAR, DIVIDEND EQUIVALENT,
PERFORMANCE UNIT, stock grant, RESTRICTED STOCK, LSAR, PHANTOM STOCK or other
3
<PAGE>
STOCK-BASED AWARD; provided, however, that (i) ISOS may be granted only to
EMPLOYEES, and (ii) NON-EMPLOYEE DIRECTORS will only be eligible to be granted
DIRECTOR RESTRICTED STOCK.
Notwithstanding such designation, to the extent that the aggregate
FAIR MARKET VALUE (determined for each share as of the date of grant of the
OPTION covering each share) of the shares with respect to which OPTIONS
designated as ISOS become exercisable for the first time by any RECIPIENT during
any calendar year exceeds $100,000, such OPTIONS shall be treated as NON-
QUALIFIED STOCK OPTIONS.
INCENTIVE AWARDS shall be awarded at no cost to the RECIPIENT. Any
INCENTIVE AWARD may be granted alone, contingent upon, in addition to or in
TANDEM with one or more other INCENTIVE AWARDS granted under the PROGRAM. In
addition, except as provided in Section 12 hereof, any INCENTIVE AWARD may be
granted in exchange for one or more other INCENTIVE AWARDS.
6. Stock Options, Tandem Stock Appreciation Rights and Tandem Dividend
-------------------------------------------------------------------
Equivalents
-----------
Except as provided in Section 9 below (relating to grants of INCENTIVE
AWARDS to NON-EMPLOYEE DIRECTORS), the COMMITTEE, in its sole discretion, may
grant ISOS, NON-QUALIFIED STOCK OPTIONS, TANDEM SARS and TANDEM DIVIDEND
EQUIVALENTS to ELIGIBLE PARTICIPANTS, subject to the terms and conditions set
forth in the STOCK OPTION PLAN attached hereto as Exhibit A.
7. Performance Units
-----------------
Except as provided in Section 9 below (relating to grants of INCENTIVE
AWARDS to NON-EMPLOYEE DIRECTORS), the COMMITTEE, in its sole discretion, may
grant PERFORMANCE UNITS to ELIGIBLE PARTICIPANTS, subject to the terms and
conditions set forth in the PERFORMANCE UNIT PLAN attached hereto as Exhibit B.
8. Other Incentive Awards
----------------------
Except as provided in Section 9 below (relating to grants of INCENTIVE
AWARDS to NON-EMPLOYEE DIRECTORS), the COMMITTEE, in its sole discretion, may
grant other INCENTIVE AWARDS (including, but not limited to, SARS granted
without OPTIONS, DIVIDEND EQUIVALENTS granted without OPTIONS, stock grants,
RESTRICTED STOCK, LSARS, PHANTOM STOCK or other STOCK-BASED AWARDS) to ELIGIBLE
PARTICIPANTS, subject to such terms and conditions as the COMMITTEE shall deem
appropriate.
4
<PAGE>
9. Grants of Incentive Awards to Non-Employee Directors
----------------------------------------------------
NON-EMPLOYEE DIRECTORS will only be eligible to be granted DIRECTOR
RESTRICTED STOCK; NON-EMPLOYEE DIRECTORS will not be eligible to receive any
other form of INCENTIVE AWARD. Any grants of DIRECTOR RESTRICTED STOCK to NON-
EMPLOYEE DIRECTORS under the PROGRAM will be made strictly in accordance with,
and subject to the terms and conditions contained in, the NON-EMPLOYEE DIRECTOR
RESTRICTED STOCK PLAN RULES attached hereto as Exhibit C.
10. Termination of Employment or Relationship with the Company
----------------------------------------------------------
The COMMITTEE may, in its sole discretion, establish terms and
conditions pertaining to the effect of TERMINATION on INCENTIVE AWARDS granted
to a RECIPIENT prior to TERMINATION, to the extent permitted by applicable law.
11. Tax Withholding
---------------
When a RECIPIENT incurs tax liability in connection with the exercise
of an INCENTIVE AWARD or the receipt of shares of COMMON STOCK pursuant to an
INCENTIVE AWARD, which tax liability is subject to tax withholding under
applicable tax laws, and the RECIPIENT is obligated to pay the COMPANY an amount
required to be withheld under applicable tax laws, the RECIPIENT may satisfy the
withholding tax obligation by (i) electing to have the COMPANY withhold such
amount from his or her current compensation through payroll deductions, or (ii)
making a direct payment to the COMPANY in cash or by check.
The COMMITTEE may, in its sole discretion, permit a RECIPIENT to
satisfy all or part of his or her withholding tax obligations by having the
COMPANY withhold from the shares to be issued to the RECIPIENT that number of
shares having a FAIR MARKET VALUE equal to the amount required to be withheld
determined on the date when taxes otherwise would be withheld in cash. The
payment of withholding taxes in this manner, if permitted by the COMMITTEE,
shall be subject to such restrictions as the COMMITTEE may impose, including any
restrictions required by rules of the Securities and Exchange Commission.
12. Replacement of Grants
---------------------
The COMMITTEE may, in its sole discretion, offer a RECIPIENT the
option of surrendering an unexercised OPTION or other INCENTIVE AWARD in
exchange for another INCENTIVE AWARD of the same type or for a different type of
INCENTIVE AWARD; provided, however, that no OPTION or INCENTIVE AWARD may be
exchanged for a new OPTION or INCENTIVE AWARD having an OPTION PRICE or purchase
price that is lower than the OPTION PRICE or purchase price of the original
OPTION or INCENTIVE AWARD.
5
<PAGE>
13. Deferral of Payments
--------------------
The COMMITTEE may, in its sole discretion, approve a RECIPIENT'S
deferral of any cash payments which may become due under the PROGRAM. Such
deferrals shall be subject to any conditions, restrictions or requirements as
the COMMITTEE may determine.
14. Adjustments Upon Changes in Number or Value of Shares of Common Stock
---------------------------------------------------------------------
If there are any changes in the number or value of shares of COMMON
STOCK by reason of stock dividends, stock splits, reverse stock splits,
recapitalizations, mergers, consolidations or other events that materially
increase or decrease the number or value of issued and outstanding shares of
COMMON STOCK, the COMMITTEE may make such adjustments as it shall deem
appropriate, in order to prevent dilution or enlargement of rights.
15. Non-Transferability of Incentive Awards
---------------------------------------
An INCENTIVE AWARD shall not be transferable by the RECIPIENT
otherwise than by will or the laws of descent and distribution, or pursuant to a
qualified domestic relations order as defined by the CODE, Title I of ERISA or
the rules thereunder. During the lifetime of the RECIPIENT, an INCENTIVE AWARD
may be exercised only by the RECIPIENT or by an alternate payee under a
qualified domestic relations order.
16. Change in Control
-----------------
Upon the occurrence of a CHANGE IN CONTROL (as defined below):
(a) Any time periods relating to the exercise or realization of any
INCENTIVE AWARD granted hereunder shall be accelerated so that such INCENTIVE
AWARD may be immediately exercised or realized in full;
(b) All shares of RESTRICTED STOCK granted hereunder shall immediately
cease to be forfeitable;
(c) All conditions relating to the realization of any STOCK-BASED
AWARD granted hereunder shall immediately terminate; and
6
<PAGE>
(d) The COMMITTEE may offer any RECIPIENT the option of having the
COMPANY purchase his or her INCENTIVE AWARD for an amount of cash which could
have been attained upon the exercise or realization of such INCENTIVE AWARD had
it been fully exercisable or realizable;
unless the COMMITTEE in its sole discretion determines that such CHANGE IN
CONTROL will not adversely impact the RECIPIENTS of INCENTIVE AWARDS hereunder
and is in the best interests of the shareholders of PG&E. The COMMITTEE may make
such further provisions with respect to a CHANGE IN CONTROL as it shall deem
equitable and in the best interests of the shareholders of PG&E. Such provision
may be made in any agreement relating to any INCENTIVE AWARD granted hereunder,
by amendment to any such agreement or by resolution of the COMMITTEE.
The phrase "CHANGE IN CONTROL" shall have such meaning as ascribed
thereto from time to time by the COMMITTEE and set forth in any agreement
relating to any INCENTIVE AWARD granted hereunder or by resolution of the
COMMITTEE; provided, however, that, notwithstanding the foregoing, a "CHANGE IN
CONTROL" shall be deemed to have occurred if:
(a) any "person" (as such term is used in Sections 13(d) and 14(d)(2)
of the EXCHANGE ACT, but excluding any benefit plan for EMPLOYEES or any
trustee, agent or other fiduciary for any such plan acting in such person's
capacity as such fiduciary), directly or indirectly, becomes the beneficial
owner of securities of PG&E representing twenty percent (20%) or more of the
combined voting power of PG&E's then outstanding securities;
(b) during any two consecutive years, individuals who at the beginning
of such a period constitute the BOARD OF DIRECTORS cease for any reason to
constitute at least a majority of the BOARD OF DIRECTORS, unless the election,
or the nomination for election by the shareholders of PG&E, of each new DIRECTOR
was approved by a vote of at least two-thirds (2/3) of the DIRECTORS then still
in office who were DIRECTORS at the beginning of the period; or
(c) the shareholders of PG&E shall have approved (i) any consolidation
or merger of PG&E in which PG&E is not the continuing or surviving corporation
or pursuant to which shares of COMMON STOCK are converted into cash, securities
or other property, other than a merger of PG&E in which the holders of the
COMMON STOCK immediately prior to the merger have the same proportionate
ownership of common stock of the surviving corporation immediately after the
merger, (ii) any sale, lease, exchange or other transfer (in one transaction or
a series of related transactions) of all or substantially all of the assets of
the COMPANY, or (iii) any plan or proposal for the liquidation or dissolution of
PG&E.
7
<PAGE>
Notwithstanding the foregoing, the phrase "CHANGE IN CONTROL" shall
not apply to any reorganization or merger initiated voluntarily by PG&E in which
PG&E is the continuing surviving entity.
17. Listing and Registration of Shares
----------------------------------
Each INCENTIVE AWARD shall be subject to the requirement that if at
any time the COMMITTEE shall determine, in its discretion, that the listing,
registration or qualification of the shares covered thereby under any securities
exchange or under any state or federal law or the consent or approval of any
governmental regulatory body, including the California Public Utilities
Commission, is necessary or desirable as a condition of, or in connection with,
the granting of such INCENTIVE AWARD or the issue or purchase of shares
thereunder, such INCENTIVE AWARD may not be exercised in whole or in part unless
and until such listing, registration, qualification, consent or approval shall
have been effected or obtained free of any conditions not acceptable to the
COMMITTEE.
18. Amendment and Termination of the Program and Incentive Awards
-------------------------------------------------------------
The BOARD OF DIRECTORS or the COMMITTEE may at any time suspend,
terminate, modify or amend the PROGRAM in any respect; provided, however, that
(i) to the extent necessary and desirable to comply with RULE 16b-3 or with
Section 422 of the CODE (or any other applicable law or regulation, including
the requirements of any stock exchange on which the COMMON STOCK is listed or
quoted), shareholder approval of any PROGRAM amendment shall be obtained in such
a manner and to such a degree as is required by the applicable law or
regulation, and (ii) any provisions contained in the PROGRAM or in the NON-
EMPLOYEE DIRECTOR RESTRICTED STOCK PLAN RULES stating the amount or price of
INCENTIVE AWARDS to be granted to NON-EMPLOYEE DIRECTORS or specifying the
timing of such awards, or any provisions setting forth a formula that determines
the amount, price or timing, shall not be amended more than once every six
months, other than to comport with changes in the CODE, ERISA or the rules
thereunder.
No suspension, termination, modification or amendment of the PROGRAM
may, without the consent of the RECIPIENT, adversely affect his or her rights
under INCENTIVE AWARDS theretofore granted to such RECIPIENT. In the event of
amendments to the CODE or applicable rules or regulations relating to ISOS
subsequent to the date hereof, the COMPANY may amend the PROGRAM, and the
COMPANY and RECIPIENTS holding OPTION agreements may agree to amend outstanding
OPTION agreements, to conform to such amendments.
The COMMITTEE may make such amendments or modifications in the terms
and conditions of any INCENTIVE AWARD as it may deem advisable, or cancel or
annul any grant of an INCENTIVE AWARD; provided, however, that no such
amendment, modification, cancellation or annulment may, without the consent of
8
<PAGE>
the RECIPIENT, adversely his or her rights under such INCENTIVE AWARD; and
provided further the COMMITTEE may not reduce the OPTION PRICE or purchase price
of any OPTION or INCENTIVE AWARD below the original OPTION PRICE or purchase
price.
Notwithstanding the foregoing, the COMMITTEE reserves the right, in
its sole discretion, to (i) convert any outstanding ISOS to NON-QUALIFIED STOCK
OPTIONS, (ii) to require a RECIPIENT to forfeit any unexercised or unpurchased
INCENTIVE AWARDS, any shares received or purchased pursuant to an INCENTIVE
AWARD, or any gains realized by virtue of the receipt of an INCENTIVE AWARD in
the event that such RECIPIENT competes against the COMPANY, and (iii) to cancel
or annul any grant of an INCENTIVE AWARD in the event of a RECIPIENT'S
TERMINATION FOR CAUSE. For purposes of the PROGRAM, "TERMINATION FOR CAUSE"
shall include, but not be limited to, termination because of dishonesty,
criminal offense or violation of a work rule, and shall be determined by, and in
the sole discretion of, the COMMITTEE.
19. Effective Date of the Program and Duration
------------------------------------------
The Program first became effective as of January 1, 1992. It has
since been amended and restated. The amended and restated PROGRAM shall become
effective as of January 1, 1996, provided it is approved by the shareholders of
PG&E within twelve (12) months following the date of adoption by the BOARD OF
DIRECTORS. Unless terminated sooner pursuant to Section 16 hereof, the PROGRAM
shall terminate on December 31, 2005.
20. Definitions
-----------
a. BOARD OF DIRECTORS means the Board of Directors of PG&E.
------------------
b. CHANGE IN CONTROL has the meaning set forth in Section 16 hereof.
-----------------
c. CHIEF EXECUTIVE OFFICER means the Chief Executive Officer of PG&E.
-----------------------
d. CODE means the Internal Revenue Code of 1986, as amended from time to
----
time.
e. COMMITTEE means the Nominating and Compensation Committee of the BOARD
---------
OF DIRECTORS or any successor to such committee.
9
<PAGE>
f. COMMON STOCK means common shares of PG&E with a par value of $5.00
------------
per share and any class of common shares into which such common shares
hereafter may be converted.
g. COMPANY means PG&E, and any parent corporation (as defined in Section
-------
424(e) of the CODE) or subsidiary corporation (as defined in Section
424(f) of the CODE).
h. CONSULTANT means any person, including an advisor, who is engaged by
----------
the COMPANY to render services.
i. DIRECTOR means any person who is a member of the BOARD OF DIRECTORS
--------
or the Board of Directors of any parent corporation (as defined in
Section 424(e) of the CODE) which may hereafter be established,
including an advisory, emeritus or honorary director.
j. DIRECTOR RESTRICTED STOCK means RESTRICTED STOCK granted to a NON-
-------------------------
EMPLOYEE DIRECTOR under the NON-EMPLOYEE DIRECTOR RESTRICTED STOCK
PLAN.
k. DIVIDEND EQUIVALENT means a right that entitles the RECIPIENT to
-------------------
receive cash or COMMON STOCK based on the dividends declared on the
COMMON STOCK covered by such right.
l. ELIGIBLE PARTICIPANT means any KEY EMPLOYEE. It also means, if so
--------------------
identified by the COMMITTEE (or by the CHIEF EXECUTIVE OFFICER, in the
case of INCENTIVE AWARDS granted by the CHIEF EXECUTIVE OFFICER to
certain ELIGIBLE PARTICIPANTS pursuant to Section 2 hereof), other
EMPLOYEES, DIRECTORS, CONSULTANTS, employees or consultants of any
affiliates of PG&E, and other persons whose participation in the
PROGRAM is deemed by the COMMITTEE (or by the CHIEF EXECUTIVE OFFICER,
in the case of INCENTIVE AWARDS granted by the CHIEF EXECUTIVE OFFICER
to certain ELIGIBLE PARTICIPANTS pursuant to Section 2 hereof) to be
in the best interests of the COMPANY.
m. EMPLOYEE means any person who is employed by the COMPANY. The
--------
payment of a director's fee or consulting fee by the COMPANY shall not
be sufficient to constitute "employment" by the COMPANY.
n. ERISA means the Employee Retirement Income Security Act of 1974, as
-----
amended.
10
<PAGE>
o. EXCHANGE ACT means the Securities Exchange Act of 1934, as amended.
------------
p. FAIR MARKET VALUE means the closing price of the COMMON STOCK reported
-----------------
on the New York Stock Exchange Composite Transactions for the date
specified for determining such value.
q. INCENTIVE AWARD means any ISO, NON-QUALIFIED STOCK OPTION, SAR,
---------------
DIVIDEND EQUIVALENT, PERFORMANCE UNIT or other STOCK-BASED AWARD
granted under the PROGRAM.
r. ISO means an OPTION intended to qualify as an incentive stock option
---
under Section 422 of the CODE.
s. KEY EMPLOYEE means the Corporate Secretary, Treasurer, Vice
------------
Presidents and other executive officers of PG&E above the rank of Vice
President. It also means, if so identified by the COMMITTEE (or by the
CHIEF EXECUTIVE OFFICER, in the case of INCENTIVE AWARDS granted by
the CHIEF EXECUTIVE OFFICER to certain ELIGIBLE PARTICIPANTS pursuant
to Section 2 hereof), executive officers of wholly-owned subsidiaries
of PG&E (including subsidiaries which become such after adoption of
the PROGRAM) and any other key management employee of PG&E or any
wholly-owned subsidiary of PG&E.
t. LSAR means a limited stock appreciation right which is exercisable
----
only in the event of a CHANGE IN CONTROL.
u. 1986 OPTION PLAN means the Pacific Gas and Electric Company 1986
----------------
Stock Option Plan, as amended to date.
v. NON-EMPLOYEE DIRECTOR means a DIRECTOR who is not an EMPLOYEE.
--------------------
w. NON-EMPLOYEE DIRECTOR RESTRICTED STOCK PLAN RULES means the
-------------------------------------------------
Restricted Stock Plan for Non-Employee Directors attached hereto as
Exhibit C or any successor rules which the COMMITTEE may adopt from
time to time with respect to the grant of DIRECTOR RESTRICTED STOCK to
NON-EMPLOYEE DIRECTORS under the PROGRAM.
x. NON-QUALIFIED STOCK OPTION means any OPTION which is not an ISO.
--------------------------
y. OPTION means an option to purchase shares of COMMON STOCK granted
------
under the STOCK OPTION PLAN.
z. OPTION PRICE means the purchase price for the COMMON STOCK upon
------------
exercise of an OPTION.
11
<PAGE>
aa. PERFORMANCE UNIT means a performance unit granted under the
----------------
PERFORMANCE UNIT PLAN.
ab. PERFORMANCE UNIT PLAN means the Performance Unit Plan Rules attached
---------------------
hereto as Exhibit B or any successor rules which the COMMITTEE may
adopt from time to time with respect to the grant of PERFORMANCE UNITS
under the PROGRAM.
ac. PG&E means Pacific Gas and Electric Company, a California corporation.
----
ad. PHANTOM STOCK means allocated hypothetical shares of COMMON STOCK that
-------------
can be converted at a future date into cash or stock.
ae. PROGRAM means the Pacific Gas and Electric Company Long-Term
-------
Incentive Program as amended and restated herein and as may be
amended from time to time.
af. RECIPIENT means the ELIGIBLE PARTICIPANT receiving the INCENTIVE
---------
AWARD, or his or her legal representative, legatees, distributees
or alternate payees, as the case may be.
ag. RESTRICTED STOCK means COMMON STOCK that is subject to forfeiture by
----------------
the RECIPIENT to the COMPANY under such circumstances as may be
specified by the COMMITTEE in its sole discretion.
ah. RETIREMENT means the Actual Retirement Date under the PG&E
----------
Retirement Plan.
ai. RULE 16b-3 means Rule 16b-3 under the EXCHANGE ACT or any successor
----------
to Rule 16b-3, as in effect when discretion is being exercised with
respect to the Plan.
aj. SAR means a stock appreciation right whose value is based on the
---
increase in the FAIR MARKET VALUE of the COMMON STOCK covered by
such right.
12
<PAGE>
ak. SECTION 16 OFFICER means any person who is designated by the BOARD OF
------------------
DIRECTORS as an executive officer of PG&E and any other person who is
designated as an officer of PG&E for purposes of Section 16 of the
EXCHANGE ACT.
al. STOCK-BASED AWARD means any award that is valued in whole or in part
-----------------
by reference to, or is otherwise based on, the COMMON STOCK,
including, but not limited to, stock grants, RESTRICTED
STOCK, LSARS and PHANTOM STOCK.
am. STOCK OPTION PLAN means the Stock Option Plan Rules attached hereto
-----------------
as Exhibit A or any successor rules which the COMMITTEE may adopt
from time to time with respect to the grant of OPTIONS under the
PROGRAM.
an. TANDEM refers to an INCENTIVE AWARD granted in conjunction with
------
another INCENTIVE AWARD.
ao. TERMINATION occurs when an EMPLOYEE ceases to be employed by the
-----------
COMPANY as a common law employee, when a DIRECTOR ceases to be a
member of the BOARD OF DIRECTORS or the Board of Directors of any
parent corporation which may hereafter be established (as the case may
be), or when the relationship between the COMPANY and a CONSULTANT or
other ELIGIBLE PARTICIPANT terminates, as the case may be.
ap. TERMINATION FOR CAUSE has the meaning set forth in Section 18 hereof.
---------------------
13
<PAGE>
PACIFIC GAS AND ELECTRIC COMPANY
RESTRICTED STOCK PLAN FOR NON-EMPLOYEE DIRECTORS
(As adopted effective as of January 1, 1996)*
1. Purpose of the Plan
-------------------
This is the controlling and definitive statement of the Pacific Gas
and Electric Company Restricted Stock Plan for Non-Employee Directors
(hereinafter called the PLAN/1/). The purpose of the PLAN is to advance the
interests of the COMPANY by providing NON-EMPLOYEE DIRECTORS with financial
incentives to promote the success of its long-term (five to ten years) business
objectives, and to increase their proprietary interest in the success of the
COMPANY. Inasmuch as the PLAN is designed to encourage financial performance
and to improve the value of shareholders' investment in PG&E, the costs of the
PLAN will be funded from corporate earnings.
2. Restricted Stock Grants to Non-Employee Directors
-------------------------------------------------
(a) All grants of DIRECTOR RESTRICTED STOCK under the PLAN shall be
automatic and non-discretionary, and shall be made strictly in accordance with
the provisions contained herein. No person shall have any discretion to select
which NON-EMPLOYEE DIRECTORS shall be granted DIRECTOR RESTRICTED STOCK or to
determine the number of shares of DIRECTOR RESTRICTED STOCK granted.
(b) As soon as practicable following the receipt of all required
shareholder and regulatory approvals in 1996 and on the first business day of
each calendar year thereafter during the duration of the PLAN, each person who
is a NON-EMPLOYEE DIRECTOR on the first business day of the applicable calendar
year shall receive a grant of DIRECTOR RESTRICTED STOCK in an amount to be
determined in accordance with the formula set forth in this Section 2(b). The
number of shares of DIRECTOR RESTRICTED STOCK to be granted to each NON-EMPLOYEE
DIRECTOR each calendar year shall be determined by (i) dividing ten thousand
dollars ($10,000) by the FAIR MARKET VALUE of the COMMON STOCK on the first
business day of the applicable calendar year, and (ii) rounding the resulting
number down to the nearest whole share. No person shall receive more than one
(1) grant of DIRECTOR RESTRICTED STOCK during any calendar year.
(c) Any provisions contained in the PROGRAM or in the PLAN stating the
amount or price of INCENTIVE AWARDS to be granted to NON-EMPLOYEE DIRECTORS and
specifying the timing of such awards, or any provisions setting forth a formula
that determines the amount, price or timing of such awards, shall not be amended
more than once every six (6) months, other than to comport with changes in the
CODE, ERISA or the rules thereunder.
- ---------------
/1/ Capitalized words are defined in Section 12 hereof.
* Subject to shareholder approval at the 1996 annual meeting, scheduled for
April 17, 1996.
<PAGE>
3. Shares of Stock Subject to the Plan
-----------------------------------
There shall be reserved for use under the PLAN and for the grant of
any other incentive awards pursuant to the PROGRAM (subject to the provisions of
Section 7 hereof) a total of 23,289,230 shares of COMMON STOCK, which shares may
be authorized but unissued shares of COMMON STOCK or issued shares of COMMON
STOCK which shall have been reacquired by PG&E.
4. Vesting of Director Restricted Stock
------------------------------------
(a) Shares of DIRECTOR RESTRICTED STOCK shall vest cumulatively as
follows: (i) twenty percent (20%) of such shares on the first (1st) anniversary
of the date of grant; (ii) forty percent (40%) of such shares on the second
(2nd) anniversary of the date of grant; (iii) sixty percent (60%) of such shares
on the third (3rd) anniversary of the date of grant; (iv) eighty percent (80%)
of such shares on the fourth (4th) anniversary of the date of grant; and (v) one
hundred percent (100%) of such shares on the fifth (5th) anniversary of the date
of grant. Solely for purposes of determining the vesting of shares of DIRECTOR
RESTRICTED STOCK granted in 1996, the date of grant of such shares shall be
deemed to be the first business day of 1996. For all other purposes under the
PLAN, the date of grant of such shares shall be the actual date on which such
shares were granted.
(b) Shares of DIRECTOR RESTRICTED STOCK may not be resold or otherwise
transferred by a GRANTEE until such shares are vested in accordance with the
provisions of this Section 4.
5. Dividend, Voting and Other Shareholder Rights
---------------------------------------------
Except as otherwise provided in the PLAN, each GRANTEE shall have all
of the rights of a shareholder of PG&E with respect to all outstanding shares of
DIRECTOR RESTRICTED STOCK registered in his or her name, whether or not such
shares are vested, including the right to receive dividends and other
distributions paid or made with respect to such shares and the right to vote
such shares.
6. Termination of Status as a Non-Employee Director
------------------------------------------------
(a) In the event of a TERMINATION by reason of disability or death,
all shares of DIRECTOR RESTRICTED STOCK held by the GRANTEE shall become fully
vested, notwithstanding the provisions of Section 4(a) hereof, and the GRANTEE
(or the GRANTEE'S estate or a person who acquired the shares of DIRECTOR
RESTRICTED STOCK by bequest or inheritance) shall have the right to resell or
transfer such shares at any time. The term "disability" shall, for the purposes
of the PLAN, be defined in Section 22(e)(3) of the CODE.
2
<PAGE>
(b) In the event of a TERMINATION by reason of MANDATORY RETIREMENT,
all shares of DIRECTOR RESTRICTED STOCK held by the GRANTEE shall become fully
vested, notwithstanding the provisions of Section 4(a) hereof, and the GRANTEE
shall have the right to resell or transfer such shares at any time.
(c) In the event of a TERMINATION for any reason other than those
specified in subparagraphs (a) and (b) above, (i) any unvested shares of
DIRECTOR RESTRICTED STOCK granted hereunder shall be forfeited; (ii) the GRANTEE
shall return to the COMPANY for cancellation any stock certificates representing
such forfeited shares; (iii) all such forfeited shares shall be deemed to be
cancelled and no longer outstanding as of the date of TERMINATION; and (vi) from
and after the date of TERMINATION, the GRANTEE shall cease to be a shareholder
with respect to such forfeited shares and shall have no dividend, voting or
other rights with respect thereto.
(d) Notwithstanding the provisions of subparagraphs (a) through (c)
above, the COMMITTEE may, in its sole discretion, establish different terms and
conditions pertaining to the effect of TERMINATION, to the extent permitted by
applicable federal and state law.
7. Adjustments Upon Changes in Number or Value of Shares of Common Stock
---------------------------------------------------------------------
If there are any changes in the number or value of shares of COMMON
STOCK by reason of stock dividends, stock splits, reverse stock splits,
recapitalizations, mergers, consolidations or other events that materially
increase or decrease the number or value of issued and outstanding shares of
COMMON STOCK, the COMMITTEE may make such adjustments as it shall deem
appropriate, in order to prevent dilution or enlargement of rights.
8. Non-Transferability of Unvested Director Restricted Stock
---------------------------------------------------------
Shares of DIRECTOR RESTRICTED STOCK that have not vested in accordance
with the provisions of Section 4(a) hereof shall not be transferable by the
GRANTEE otherwise than by will or the laws of descent and distribution, or
pursuant to a qualified domestic relations order as defined by the CODE, Title I
of ERISA or the rules thereunder.
3
<PAGE>
9. Change in Control
-----------------
Upon the occurrence of a CHANGE IN CONTROL (as defined below), any
time periods relating to the vesting of any shares if DIRECTOR RESTRICTED STOCK
granted hereunder shall be accelerated so that all such shares immediately
become fully vested, unless the COMMITTEE in its sole discretion determines that
such CHANGE IN CONTROL will not adversely impact the GRANTEES of DIRECTOR
RESTRICTED STOCK hereunder and is in the best interests of the shareholders of
PG&E. The COMMITTEE may make such further provisions with respect to a CHANGE
IN CONTROL as it shall deem equitable and in the best interests of the
shareholders of PG&E. Such provision may be made in any agreement relating to
any DIRECTOR RESTRICTED STOCK granted hereunder, by amendment to any such
agreement or by resolution of the COMMITTEE.
The phrase "CHANGE IN CONTROL" shall have such meaning as ascribed
thereto from time to time by the COMMITTEE and set forth in any agreement
relating to any DIRECTOR RESTRICTED STOCK granted hereunder or by resolution of
the COMMITTEE; provided, however, that, notwithstanding the foregoing, a "CHANGE
IN CONTROL" shall be deemed to have occurred if:
(a) any "person" (as such term is used in Sections 13(d) and 14(d)(2)
of the EXCHANGE ACT, but excluding any benefit plan for EMPLOYEES or any
trustee, agent or other fiduciary for any such plan acting in such person's
capacity as such fiduciary), directly or indirectly, becomes the beneficial
owner of securities of PG&E representing twenty percent (20%) or more of the
combined voting power of PG&E's then outstanding securities;
(b) during any two consecutive years, individuals who at the beginning
of such a period constitute the BOARD OF DIRECTORS cease for any reason to
constitute at least a majority of the BOARD OF DIRECTORS, unless the election,
or the nomination for election by the shareholders of PG&E, of each new DIRECTOR
was approved by a vote of at least two-thirds (2/3) of the DIRECTORS then still
in office who were DIRECTORS at the beginning of the period; or
(c) the shareholders of PG&E shall have approved (i) any consolidation
or merger of PG&E in which PG&E is not the continuing or surviving corporation
or pursuant to which shares of COMMON STOCK are converted into cash, securities
or other property, other than a merger of PG&E in which the holders of the
COMMON STOCK immediately prior to the merger have the same proportionate
ownership of common stock of the surviving corporation immediately after the
merger, (ii) any sale, lease, exchange or other transfer (in one transaction or
a series of related transactions) of all or substantially all of the assets of
the COMPANY, or (iii) any plan or proposal for the liquidation or dissolution of
PG&E.
4
<PAGE>
Notwithstanding the foregoing, the phrase "CHANGE IN CONTROL" shall
not apply to any reorganization or merger initiated voluntarily by PG&E in which
PG&E is the continuing surviving entity.
10. Amendment and Termination of the Plan
-------------------------------------
Except as provided in Section 2(c) hereof, the BOARD OF DIRECTORS or
the COMMITTEE may at any time suspend, terminate, modify or amend the PLAN in
any respect; provided, however, that, to the extent necessary and desirable to
comply with RULE 16b-3 or with the CODE (or any other applicable law or
regulation, including the requirements of any stock exchange on which the COMMON
STOCK is listed or quoted), shareholder approval of any PLAN amendment shall be
obtained in such a manner and to such a degree as is required by the applicable
law or regulation.
No suspension, termination, modification or amendment of the PLAN may,
without the consent of the GRANTEE, adversely affect his or her rights with
respect to DIRECTOR RESTRICTED STOCK theretofore granted to such GRANTEE.
Except as provided in Section 2(c) hereof, the COMMITTEE may make such
amendments or modifications in the terms and conditions of any grant of DIRECTOR
RESTRICTED STOCK as it may deem advisable, or cancel or annul any grant of
DIRECTOR RESTRICTED STOCK; provided, however, that no such amendment,
modification, cancellation or annulment may, without the consent of the GRANTEE,
adversely affect his or her rights with respect to such grant.
11. Effective Date of the Plan and Duration
---------------------------------------
This PLAN shall become effective as of January 1, 1996, provided the
amended and restated PROGRAM is approved by the shareholder of PG&E within
twelve (12) months following the date of adoption by the BOARD OF DIRECTORS.
Unless terminated sooner pursuant to Section 10 hereof, the PLAN shall terminate
on December 31, 2005.
12. Definitions
-----------
a. BOARD OF DIRECTORS means the Board of Directors of PG&E.
------------------
b. CHANGE IN CONTROL has the meaning set forth in Section 9 hereof.
-----------------
c. CODE means the Internal Revenue Code of 1986, as amended from time to
----
time.
d. COMMITTEE means the Nominating and Compensation Committee of the BOARD
---------
OF DIRECTORS or any successor to such committee.
5
<PAGE>
e. COMMON STOCK means common shares of PG&E with a par value of $5.00 per
------------
share and any class of common shares into which such common shares
hereafter may be converted.
f. COMPANY means PG&E, and any parent corporation (as defined in Section
-------
424(e) of the CODE) or subsidiary corporation (as defined in Section
424(f) of the CODE).
g. DIRECTOR means any person who is a member of the BOARD OF DIRECTORS or
--------
the Board of Directors of any parent corporation (as defined in Section
424(e) of the CODE) which may hereafter be established, including an
advisory, emeritus or honorary director.
h. DIRECTOR RESTRICTED STOCK means RESTRICTED STOCK granted to a NON-
-------------------------
EMPLOYEE DIRECTOR under the PLAN.
i. EMPLOYEE means any person who is employed by the COMPANY. The payment
--------
of a director's fee or consulting fee by the COMPANY shall not be
sufficient to constitute "employment" by the COMPANY.
j. ERISA means the Employee Retirement Income Security Act of 1974, as
-----
amended.
k. EXCHANGE ACT means the Securities Exchange Act of 1934, as amended.
------------
l. FAIR MARKET VALUE means the closing price of the COMMON STOCK reported
-----------------
on the New York Stock Exchange Composite Transactions for the date
specified for determining such value.
m. GRANTEE means the NON-EMPLOYEE DIRECTOR receiving the DIRECTOR
-------
RESTRICTED STOCK, or his or her legal representative, legatees,
distributees or alternate payees, as the case may be.
n. MANDATORY RETIREMENT means retirement as a DIRECTOR at age 70 or at such
--------------------
other age as may be specified in the retirement policy for the BOARD OF
DIRECTORS or the Board of Directors of any parent corporation which may
hereafter be established (as the case may be), as in effect at the time
of a NON-EMPLOYEE DIRECTOR'S TERMINATION.
o. NON-EMPLOYEE DIRECTOR means a DIRECTOR who is not an EMPLOYEE.
---------------------
6
<PAGE>
p. PG&E means Pacific Gas and Electric Company, a California corporation.
----
q. PLAN means this Restricted Stock Plan for Non-Employee Directors, as may
----
be amended from time to time, or any successor plan which the COMMITTEE
may adopt from time to time with respect to the grant of DIRECTOR
RESTRICTED STOCK under the PROGRAM.
r. PROGRAM means the Pacific Gas and Electric Company Long-Term Incentive
-------
Program, as amended and restated effective as of January 1, 1996 and as
may be amended from time to time, pursuant to which this PLAN is
adopted.
s. RESTRICTED STOCK means COMMON STOCK that is subject to forfeiture by the
----------------
GRANTEE to the COMPANY under such circumstances as may be specified by
the COMMITTEE.
t. RULE 16b-3 means Rule 16b-3 under the EXCHANGE ACT or any successor to
----------
Rule 16b-3, as in effect when discretion is being exercised with respect
to the PLAN.
u. TERMINATION occurs when a NON-EMPLOYEE DIRECTOR ceases to be a member of
-----------
the BOARD OF DIRECTORS or the Board of Directors of any parent
corporation which may hereafter be established (as the case may be).
7
<PAGE>
Appendix I
Pacific Gas and Electric Company
Selected Financial Data
<TABLE>
<CAPTION>
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) 1995 1994 1993 1992 1991
----------- ----------- ----------- ----------- -----------
<S> <C> <C> <C> <C> <C>
FOR THE YEAR
Operating revenues $ 9,621,765 $10,350,230 $10,550,002 $10,315,713 $ 9,823,137
Operating income 2,762,985 2,423,786 2,560,235 2,699,824 2,550,334
Net income 1,338,885 1,007,450 1,065,495 1,170,581 1,026,392
Earnings per common share 2.99 2.21 2.33 2.58 2.24
Dividends declared per common share 1.96 1.96 1.88 1.76 1.64
AT YEAR END
Book value per common share $ 20.77 $ 20.07 $ 19.77 $ 19.41 $ 18.40
Common stock price per share 28.38 24.38 35.13 33.13 32.63
Total assets 26,850,290 27,708,564 27,145,899 24,188,159 22,900,670
Long-term debt and preferred stock
and preferred securities with
mandatory redemption provisions
(excluding current portions) 8,486,046 8,812,591 9,367,100 8,525,948 8,341,310
</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 Consolidated Financial Statements.
12
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
CONSOLIDATED RESULTS OF OPERATIONS AND FINANCIAL CONDITION
PACIFIC GAS AND ELECTRIC COMPANY
Pacific Gas and Electric Company (PG&E) and its wholly owned and controlled
subsidiaries (collectively, the Company) are engaged principally in the business
of supplying electric and natural gas services. PG&E is a regulated public
utility which provides generation, procurement, transmission and distribution of
electricity and natural gas to customers throughout most of Northern and Central
California. Pacific Gas Transmission Company (PGT), a wholly owned subsidiary,
transports gas from the Canadian border to the California border and the Pacific
Northwest. The Company's operations are regulated by the California Public
Utilities Commission (CPUC), the Federal Energy Regulatory Commission (FERC) and
the Nuclear Regulatory Commission (NRC), among others.
Building on its expertise in the energy industry, the Company is also
expanding its diversified operations, principally through its wholly owned
subsidiary, PG&E Enterprises (Enterprises). Enterprises, through its
subsidiaries and affiliates, develops, owns and operates electric projects
around the world, as discussed further in the Diversified Operations section.
The following discussion includes some forward looking information.
Importantly, the ultimate impact of increased competition and the changing
regulatory environment on future results is uncertain but is expected to cause
fundamental changes in the way PG&E conducts its business and to make earnings
more volatile. This outcome 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: Under traditional utility
regulation, utilities have been accorded the right to serve customers within
designated areas in return for their commitment to provide service to all who
request it. Regulation was designed in part to take the place of competition to
ensure that utility services were provided at fair prices. However, recent
changes in both the gas and electric industries have allowed competition to
develop in the gas supply and electric generation segments of PG&E's business,
resulting in fundamental changes in the way PG&E's various services are
regulated and managed.
ELECTRIC INDUSTRY: PG&E currently performs the functions of electric generation,
transmission, distribution and customer service. However, competition from
nonutility and nonregulated electric suppliers and self-generation and
cogeneration have provided some major utility customers with alternative sources
to satisfy their electric supply needs. Currently, PG&E obtains a portion of its
electric supply from generation sources outside its service territory and from
qualifying facilities, or QFs (small power producers or cogenerators that meet
certain federal guidelines qualifying them to supply generating capacity and
electric energy to utilities), owned and operated by independent power producers
(IPPs).
Regulatory changes enacted at the federal level and those contemplated at
the state level have transformed and will continue to transform the electric
transmission function by promoting open access to nonutility suppliers. At the
federal level, the National Energy Policy Act of 1992 reduced various
restrictions on the operation and ownership of IPPs and provided them and other
wholesale suppliers and purchasers with increased access to electric
transmission lines throughout the United States.
The FERC has established a Notice of Proposed Rulemaking (NOPR) on open
access. The NOPR requires that all utilities offer open access wholesale
transmission service that is comparable to the wholesale transmission service
that utilities provide themselves. In addition, the FERC accepted, subject to
refund and the outcome of the NOPR, PG&E's proposed open access wholesale
electric transmission tariffs, effective July 1, 1995. These tariffs generally
conform to the FERC NOPR.
On December 20, 1995, the CPUC issued a decision calling for the
restructuring of California's electric industry. The CPUC's goal is to provide a
structure that will ultimately allow California consumers to choose among
competing suppliers of electricity. In summary, the decision would (1)
simultaneously create a wholesale power pool (the Exchange) and allow direct
access for certain customers to contract directly with electric generation
providers beginning in 1998; (2) establish an Independent System Operator (ISO)
to manage and control the transmission
13
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
CONSOLIDATED RESULTS OF OPERATIONS AND FINANCIAL CONDITION
PACIFIC GAS AND ELECTRIC COMPANY
system; and (3) provide recovery of utilities' stranded costs (costs which are
above-market and could not be recovered under market-based pricing) through a
surcharge, or competition transition charge (CTC), to be imposed on all
customers taking retail electric services as of or after December 20, 1995. The
decision, while effective immediately, provides a 100-day period for legislative
review and sets out an ambitious schedule for various implementation filings and
comments over the period ending in September 1996.
Under the restructuring decision, investor-owned utilities (IOUs) would
continue to provide distribution, generation and procurement functions for those
customers choosing to take bundled service from utilities, all of which would be
regulated under performance-based ratemaking. The decision requires the IOUs to
file proposals to establish performance-based ratemaking for the generation and
distribution functions. The decision provides that by January 1, 1998, a
representative number of customers from all customer groups, individually or in
the aggregate, will be able to participate in the first phase of direct access
which will last one year, with the balance of customers phased in to direct
access within five years. Ultimately, it is contemplated that all customers will
have the choice of buying electricity from their utility, the Exchange or
directly from electric generation providers through direct access bilateral
contracts.
The decision requires the three largest IOUs, in conjunction with other
interested parties, to work together to prepare a joint proposal for the
creation of the Exchange which will be separate from and independent of the ISO.
The Exchange would manage bids for energy, set the market clearing price and
then submit its delivery schedule to the ISO for dispatch. The IOUs would be
required to bid all their generation output into the Exchange and purchase all
their energy from the Exchange during the five-year transition period to full
direct access. Participation in the Exchange would be voluntary for all other
market participants.
The decision also requires the three largest IOUs to develop a detailed
proposal for submission to the FERC for creation of the ISO. The decision
contemplates that the IOUs, after approvals from the FERC and the CPUC, turn
over control, but not ownership, of their transmission systems to the ISO. The
ISO will control the power dispatch and transmission system and provide
transmission service on a nondiscriminatory basis.
The CPUC concluded that market power issues associated with the electric
industry restructuring almost certainly mandate that the IOUs divest themselves
of a substantial portion of their fossil fuel generation assets. Accordingly,
the decision requires that the three IOUs file plans to voluntarily divest
themselves of at least 50 percent of their fossil fuel generation assets. To
encourage divestiture, for each ten percent of fossil fuel generation capacity
divested, the decision proposes an increase of up to ten basis points in the
equity return on the undepreciated net book value of fossil fuel generation
assets. The decision also directs the IOUs to file comments within 90 days on
the feasibility, timing and consequences of a corporate restructuring to
separate their operations and assets between the generation, transmission and
distribution functions, including the option of forming a holding company
structure. In response, PG&E is considering a range of possible alternatives,
including the possible divestiture of a substantial portion of its generation
assets.
The decision provides for the collection of transition costs through the
imposition of a non-bypassable CTC applied to transmission and distribution
rates. Transition cost recovery shall not increase rates beyond the rate levels
in effect as of January 1, 1996. A transition cost account will be established
for each utility. Transition costs associated with regulatory assets will be
included in the account as authorized by the CPUC. The account will be adjusted
annually for the difference between authorized revenues associated with the
generation assets and actual revenues earned in the market as well as after a
generation asset receives its market valuation. Valuation of above-market
generation assets will be completed by 2003. Utility nonnuclear generation
assets will be valued through sale, spin-off
14
<PAGE>
or market appraisal. The CTC will include the undepreciated book value of a
utility's fossil fuel generation assets as reflected in rate base at a reduced
return on equity equal to ten percent below the utility's embedded cost of debt.
For hydroelectric and geothermal generation assets, the CTC will be the above-
or below-market portion of the revenue requirement for those facilities derived
through a performance-based ratemaking method.
Transition costs resulting from the operation of nuclear generation
facilities and electricity purchases under existing wholesale and QF contracts
will also be recorded in this account. Transition costs for these resources will
be calculated annually over the terms of the contracts or until the authorized
transition cost recovery has been completed. Except for existing QF generation
contracts with contractual payments beyond 2003, all transition costs will be
collected by 2005.
With respect to recovery of costs associated with Diablo Canyon Nuclear
Power Plant (Diablo Canyon) and the Diablo Canyon rate case settlement (Diablo
Settlement), the decision confirms that the CPUC will continue to honor
regulatory commitments regarding the recovery of nuclear generation costs. The
decision provides that transition costs associated with Diablo Canyon will be
calculated over the term of the Diablo Settlement as the difference between the
revised Diablo Settlement price and the market price as determined by the
Exchange and the ISO will schedule power from Diablo Canyon on a must-take
basis, consistent with the Diablo Settlement. The decision requires PG&E to file
a proposal for pricing Diablo Canyon generation at market prices by 2003 and for
completing recovery of Diablo Canyon CTC by 2005 while assuring no overall rate
increase over January 1, 1996, levels. If PG&E retains ownership of Diablo
Canyon, decommissioning costs will also be included in the transition cost
account. The CPUC requires that at least one of the alternatives presented in
PG&E's proposal shall be structured to accelerate recovery of the undepreciated
portion of Diablo Canyon, at a significantly reduced return tied to the embedded
cost of debt, and to include performance-based ratemaking for recovery of
operating costs and prospective capital additions.
Two commissioners voted for a minority proposal which differed from the
decision in the following significant respects: (1) phase-in of direct access
for all customers would be over a twelve-month period; (2) participation in the
wholesale power pool would be voluntary for all participants; and (3)
withholding of ten percent of total allowable transition costs would be used as
a disincentive for utilities to retain the current level of generation ownership
until such time that 50 percent of current utility-owned generation, excluding
nuclear plants, is divested.
FINANCIAL IMPACT OF THE ELECTRIC INDUSTRY RESTRUCTURING: In December 1994, in
response to one of the proceedings leading to the decision, PG&E estimated the
revenue requirements of its owned generation assets and power purchase
obligations to be above market by $3 billion and $11 billion at assumed market
prices of $.040 and $.032 per kilowatt-hour (kWh), respectively. These market
prices were used to provide a range of possible transition costs and do not
represent a forecast of expected market prices. These above-market estimates
were determined by comparing future revenue requirements of generation assets
and power purchase obligations, over a 20-year and 30-year period, respectively,
with revenues computed at assumed market prices. The revenue requirements for
Diablo Canyon and all PG&E-owned generation assets included a return on
investment. Diablo Canyon was included in the revenue requirements calculation
using the revised pricing included in the modified Diablo Settlement. (See Note
4 of Notes to Consolidated Financial Statements.) The above-market revenue
requirements for Diablo Canyon included above were $4 billion and $6 billion at
assumed market prices of $.040 and $.032 per kWh, respectively. At this time,
PG&E has not completed a more current estimate of its above-market revenue
requirements. However, market prices could be less than $.032 per kWh. The
actual amounts of above-market revenue requirements may differ materially from
those indicated above and will depend on the final regulations and the actual
market prices of electricity or a definitive market valuation.
15
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
CONSOLIDATED RESULTS OF OPERATIONS AND FINANCIAL CONDITION
PACIFIC GAS AND ELECTRIC COMPANY
The CPUC electric industry restructuring decision establishes an account to
track the accumulation of transition costs and their recovery. While the
decision provides an opportunity for recovery of all above-market costs, actual
recovery of the CTC will be limited to an amount that does not increase the
customers' aggregate rates above those in effect on January 1, 1996. Recent CPUC
decisions effective on January 1, 1996, including PG&E's General Rate Case
(GRC), have resulted in an average electric system rate of 9.9 cents per kWh.
PG&E's ability to recover its transition costs will be dependent on achieving
overall reductions in costs such that it can recover its ongoing operating
costs, capital costs and transition costs at the 1996 rate level and on
continuing to collect CTC for the duration of the recovery period.
As a result of applying the provisions of Statement of Financial Accounting
Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of
Regulation" (see Note 1 of Notes to Consolidated Financial Statements), PG&E has
accumulated approximately $2.6 billion of electric regulatory assets, including
balancing accounts, at December 31, 1995. The regulatory assets attributable to
electric generation, excluding balancing accounts of $248 million which are
expected to be recovered in the near term, were approximately $1.5 billion at
December 31, 1995. When generation rates are no longer based on cost of service,
as ultimately contemplated under the decision, PG&E will discontinue application
of SFAS No. 71 for that portion of its business. However, PG&E expects to
recover its regulatory assets as transition costs through the CTC and does not
expect a material loss from the discontinuance of SFAS No. 71. PG&E's
transmission and distribution businesses are expected to remain on
cost-of-service rates.
In addition, the adoption of SFAS No. 121, "Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to Be Disposed Of," in 1996 will
require that regulatory assets continue to be probable of recovery in rates. In
the event that this criterion can no longer be met, whether due to changing
regulation or PG&E's inability to collect these costs, applicable portions of
any regulatory assets would be written off. The transition cost account will be
a regulatory asset also subject to the criteria of SFAS No. 121.
The CPUC decision provides a structure for full recovery of PG&E's
generation investments and costs through market prices and the CTC. However,
market pricing of Diablo Canyon by 2003, possible divestiture of generation
assets and lower returns on a portion of its investments in fossil fuel
generation assets will adversely impact PG&E's future returns on its generation
investments. The Diablo Canyon investment and the related Diablo Settlement will
represent a major portion of PG&E's transition costs. Current recovery of this
investment is occurring through 2015, the period of the Diablo Settlement.
Adjusting Diablo Canyon generation to market prices by 2003 would require an
acceleration in recovery of undepreciated plant costs. The net book value of
PG&E's investment in Diablo Canyon was approximately $4.8 billion at December
31, 1995. The net book value of the remaining PG&E-owned generation assets,
including an allocation of common plant, was approximately $3.1 billion at
December 31, 1995.
Because of the expected transition cost recovery as provided in the
decision, PG&E does not anticipate a material impairment loss on its investment
in generation assets due to electric industry restructuring. However, should
final regulations differ significantly from the CPUC decision or should full
recovery of generation assets and obligations not be achieved due to changing
costs or limitations imposed by the market, a material loss could occur.
The Company cannot predict the ultimate outcome of the ongoing changes that
are taking place in the electric utility industry or predict whether such
outcome will have a material impact on its financial position or results of
operations. However, the Company believes the end result will involve a
fundamental change in the way it conducts business. These changes will impact
financial operating trends, resulting in greater earnings volatility.
16
<PAGE>
GAS INDUSTRY: Restructuring of the natural gas industry has given customers
greater options in meeting their gas supply needs. Industrial and large
commercial (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. In the latter half of 1993, even greater numbers of noncore
customers began purchasing their own gas with the implementation of FERC Order
636 and the CPUC's capacity brokering program. FERC Order 636 required
interstate pipeline companies, including PGT, to unbundle their services into
separate sales, transportation and storage services. The CPUC's capacity
brokering program required California utilities to release firm capacity on
interstate pipelines that they no longer needed. These changes have made it
easier for customers to purchase gas directly from suppliers.
Certain customers can also use alternative transportation services provided
by competing companies. The FERC has approved the expansion of a competing
company's natural gas pipeline into PG&E's service territory. If this expansion
takes place, this pipeline could compete directly for transportation service to
several of PG&E's large customers and result in the loss of sales on PG&E's gas
transportation system.
While noncore customers have had options in the gas marketplace, residential
and smaller commercial (core) customers have had more limited opportunities in
choosing their gas suppliers. Currently, substantially all core customers
receive bundled services from PG&E. PG&E purchases and delivers gas to these
customers and prices such service as a package.
In an effort to promote competition and increase options for all customers,
as well as to position itself for success in the competitive marketplace, PG&E
is actively pursuing changes in the California gas industry. In October 1995,
PG&E presented a proposal, called the "Gas Accord," to numerous parties active
in the California gas marketplace, including consumer groups, industrial
customers, shippers and marketers. PG&E has invited these parties to join it in
a collaborative effort to develop a restructuring of the California gas
marketplace.
The Gas Accord proposes three broad initiatives:
(1) Increased Customer Choice -- Under the Gas Accord, PG&E proposes to give
all customers greater ability to choose their gas suppliers in the future. PG&E
has formed an advisory group to help it design a program that will facilitate
opening the core market for full competition.
(2) Separation of Transmission and Distribution Service and Rates -- PG&E
proposes to charge separately for, or unbundle, its gas transmission and
distribution services. This would give noncore customers and gas suppliers more
flexibility with respect to the purchase of gas transportation services. The
proposed unbundled gas transmission and distribution rates would continue to
recover PG&E's cost of service. Accordingly, PG&E believes it would be able to
continue the application of SFAS No. 71 for a majority of its gas business.
(3) Resolution of Existing Regulatory Issues -- PG&E also proposes to settle
several outstanding gas regulatory issues that are currently pending at the CPUC
in separate proceedings. These issues include recovery of costs related to
PG&E's capacity commitments with Transwestern Pipeline Company, PG&E's capacity
commitments with El Paso Natural Gas Company and PGT related to its noncore
customers, and the PG&E portion of the PGT/PG&E Pipeline Expansion Project
(Pipeline Expansion). (See Note 3 of Notes to Consolidated Financial
Statements.)
Negotiations on the Gas Accord began in October 1995. Any agreement reached
by PG&E and other parties must be approved by the CPUC before it may be
implemented. The Company believes the ultimate outcome of the Gas Accord
negotiations, including resolution of gas regulatory issues, will not have a
material impact on its financial position or results of operations.
17
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
CONSOLIDATED RESULTS OF OPERATIONS AND FINANCIAL CONDITION
PACIFIC GAS AND ELECTRIC COMPANY
HOLDING COMPANY STRUCTURE: In October 1995, the Board of Directors (Board) of
PG&E authorized management to seek appropriate shareholder and regulatory
approvals for the formation of a holding company structure. Under such
structure, the holders of common stock of PG&E would become the holders of
common stock of a new holding company which, in turn, would own all the common
stock of PG&E. PG&E would become a subsidiary of the new holding company. The
debt and preferred stock of PG&E would remain outstanding at the PG&E level and
would not become obligations or securities of the holding company.
This transaction would not result in any change in PG&E's ownership of
California utility operations, which currently are conducted by PG&E and
represent substantially all of the assets, revenues and earnings of the
consolidated group. It is intended that PG&E's ownership interest in PGT and
Enterprises would be transferred to the holding company. These two wholly owned
subsidiaries represented approximately eight percent of the Company's
consolidated assets and four percent of the Company's consolidated net income at
December 31, 1995.
The Company believes that the formation of a holding company will help the
Company to respond more effectively and efficiently to competitive changes
taking place in the utility industry and to new business opportunities that may
arise from those changes. This structure should enhance the financial separation
of the Company's California utility business from its other businesses and also
provide greater financing flexibility.
The Company will be seeking approval of the transaction from the CPUC, the
FERC and the NRC. Shareholders will be asked to approve the transaction at the
annual meeting in April 1996. The Company intends to form the holding company
structure by the end of 1996. However, approval from the regulatory agencies
could have an effect on the timing.
UTILITY REVENUE MATTERS: In addition to the CPUC decision on electric industry
restructuring (discussed above and in Note 2 of Notes to Consolidated Financial
Statements) and various gas proceedings (see Note 3 of Notes to Consolidated
Financial Statements), there are other regulatory matters with respect to
revenues and costs which will affect PG&E's rates in 1996 and beyond. In
December 1995, the CPUC issued its decision in PG&E's 1996 GRC. (See below for
further discussion.) Based on the GRC decision and the consolidation of the
electric rate cases that became effective January 1, 1996, including the energy
cost, cost of capital and various other proceedings, PG&E's electric revenue
will decrease by $443 million from rates in effect in 1995. The GRC decision and
various gas proceedings will also result in an overall gas revenue decrease of
$211 million. The more significant of these gas and electric proceedings are
discussed below.
The 1996 GRC decision for base rates effective January 1, 1996, authorized
electric and gas base revenue decreases of approximately $300 million and $270
million, respectively, compared to rates in effect in 1995. The $570 million
revenue decrease is attributable to declining capital expenditures, lower cost
of capital and reductions in expense levels, principally relating to workforce
reductions.
The GRC proceeding has been held open to consider, among other things,
PG&E's response to outages caused by recent storms and a study to determine the
cost effectiveness of the Helms pumped storage facility (Helms). The study will
consider changes in rate recovery for the plant which will include, among other
things, the option of retirement with recovery of the investment without a
return. Helms had a net book value of $631 million at December 31, 1995.
In December 1995, PG&E's service territory experienced severe storms and
winds which caused approximately 1.7 million electric service interruptions. The
assigned commissioner in the 1996 GRC subsequently issued a ruling which ordered
hearings on various issues arising out of PG&E's response to those wind storms.
The hearings will
18
<PAGE>
also address potential remedies, including reparations to customers for reduced
reliability, penalties, disallowances and damages to customers for property
loss.
In December 1995, the CPUC issued its decision in PG&E's 1996 electric
energy cost proceeding authorizing a revenue decrease of $112 million due
primarily to lower gas costs, lower Diablo Canyon generation costs, lower QF
expenses and lower estimated undercollections in the energy cost and electric
revenue balancing accounts.
In December 1995, the CPUC approved an increase in gas revenues for PG&E of
approximately $60 million in addition to the changes resulting from the GRC and
other gas proceedings discussed above. The revenue increase reflects an increase
in transportation costs and the collection of amounts previously deferred in
balancing accounts. This decision also ordered a one-time refund, to be made
during the first half of 1996, of approximately $162 million, which represents
an overcollection in certain gas procurement balancing accounts.
In its November 1995 decision, the CPUC adopted the following 1996 cost of
capital for PG&E:
<TABLE>
<CAPTION>
Capital Weighted
Ratio Cost/Return Cost/Return
- ------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Common equity 48.00% 11.60% 5.57%
Long-term debt 46.50% 7.52% 3.49%
Preferred stock and preferred securities 5.50% 7.79% 0.43%
----
Total return on average utility rate base 9.49%
----
</TABLE>
The revenue decrease as a result of this decision has been reflected in the GRC
revenue decreases discussed above.
DIVERSIFIED OPERATIONS: The Company, through its wholly owned subsidiary,
Enterprises, has taken steps to position itself to compete in the nonregulated
energy business. Enterprises contributed $.03, $.01 and $.04 per common share to
the Company's total earnings per common share for the years ended December 31,
1995, 1994 and 1993, respectively.
Enterprises in partnership with Bechtel Enterprises, Inc. (Bechtel) has made
the majority of its investments in nonregulated energy projects through a joint
venture, U.S. Generating Company (USGen). USGen and its affiliates develop, own
and operate power plants in the United States. As the utility business continues
to change, Enterprises is pursuing emerging opportunities, including electric
and gas transmission and distribution opportunities throughout the world. In
1995, Enterprises in partnership with Bechtel formed another joint venture,
International Generating Company, Ltd. (InterGen). InterGen and its affiliates
develop, own and operate international electric generation projects. Also,
Enterprises formed Vantus Energy Corporation to assist customers outside of
PG&E's service territory to locate the most cost-effective electric and gas
products and services.
In June 1995, Enterprises completed its sale of DALEN Corporation (DALEN),
formerly DALEN Resources. 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.
In August 1994, Enterprises and Bechtel acquired J. Makowski Company, Inc.
(JMC), a Boston-based company engaged primarily in the development of natural
gas-fueled electric generation projects. The purchase price was approximately
$250 million. Enterprises' effective ownership share of JMC is approximately 90
percent.
RESULTS OF OPERATIONS
The Company's revenues are derived from three types of operations: utility
(excluding Diablo Canyon and including PGT), Diablo Canyon and diversified
operations (principally
19
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
CONSOLIDATED RESULTS OF OPERATIONS AND FINANCIAL CONDITION
PACIFIC GAS AND ELECTRIC COMPANY
Enterprises). The results of operations for these areas for 1995, 1994 and 1993
are reflected in the following table and discussed below.
<TABLE>
<CAPTION>
DIABLO DIVERSIFIED
UTILITY CANYON(1) OPERATIONS TOTAL
------- --------- ----------- -------
<S> <C> <C> <C> <C>
(in millions, except per share amounts)
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
------- ------- ------- -------
1993
Operating revenues $ 8,366 $ 1,933 $ 251 $10,550
Operating expenses 6,921 810 259 7,990
------- ------- ------- -------
Operating income (loss) before income taxes $ 1,445 $ 1,123 $ (8) $ 2,560
------- ------- ------- -------
Net income $ 524 $ 496 $ 45(2) $ 1,065
------- ------- ------- -------
Earnings per common share $ 1.12 $ 1.11 $ .10 $ 2.33
------- ------- ------- -------
Total assets at year end $19,843 $ 6,250 $ 1,053 $27,146
------- ------- ------- -------
</TABLE>
(1) See Note 4 of Notes to Consolidated Financial Statements for discussion of
allocations.
(2) Includes nonoperating income resulting from property sales, partnership
earnings and investment income.
EARNINGS PER COMMON SHARE: Earnings per common share were $2.99, $2.21 and $2.33
for 1995, 1994 and 1993, respectively. Earnings per common share for 1995 were
higher than 1994 due to fewer one-time charges against earnings than in 1994. In
addition, there was only one scheduled refueling outage at Diablo Canyon in
1995, compared with two in 1994.
Earnings per common share for 1994 were lower than for 1993 primarily due to
the refueling of both units of Diablo Canyon in 1994 compared to only one unit
in 1993. In 1994, the Company recorded charges for workforce reductions, gas
reasonableness matters, contingencies related to gas transportation commitments
and increased litigation reserves which in the aggregate equaled approximately
$.60 per common share. Similar charges and the impact of increasing the federal
income tax rate to 35 percent in 1993 equaled, in the aggregate, approximately
$.61 per common share. Partially offsetting the 1993 charges was a gain of $.05
per common share from diversified operations resulting from the sale of an
investment held by Mission Trail Insurance Ltd.
On a consolidated basis, the Company earned 14.6 percent, 11.1 percent and
11.9 percent returns on average common stock equity for the years ended December
31, 1995, 1994 and 1993, respectively.
COMMON STOCK DIVIDEND: In January 1996, the Board declared a quarterly dividend
of $.49 per common share which corresponds to an annualized dividend of $1.96
per common share. PG&E's common stock dividend is based on a number of financial
considerations, including sustainability, financial flexibility and
competitiveness with investment opportunities of similar risk. PG&E has a
long-term objective of reducing its dividend payout ratio (dividends declared
divided by earnings available for common stock) to reflect the increased
business risk in the utility industry.
At this time, the Company is unable to determine the impact, if any, changes
in regulation will have on its dividend level in the future.
20
<PAGE>
OPERATING REVENUES: Electric utility revenues decreased $635 million in 1995
compared to the preceding year primarily due to the decrease in electric energy
costs caused by favorable hydro conditions and lower natural gas prices. In
addition, Diablo Canyon operating revenues decreased due to a decrease in the
price per kWh as provided in the modified pricing provisions of the Diablo
Settlement. This decrease was partially offset by favorable operating revenues
from Diablo Canyon resulting from fewer refueling days in 1995.
Electric utility revenues increased $145 million in 1994 as compared to the
preceding year. Despite the rate freeze, electric utility revenues increased due
to higher energy costs in 1994 reflected in increased electric energy cost
balancing account revenues. The higher revenues from the energy cost balancing
account were offset by a decrease in revenues from Diablo Canyon resulting from
the refueling of both units of the nuclear power plant in 1994 as compared with
only one unit in 1993.
The Diablo Settlement, which became effective July 1988, bases revenues for
Diablo Canyon primarily on the amount of electricity generated, rather than on
traditional cost-based ratemaking. Under this performance-based approach, the
Company assumes a significant portion of the operating risk of Diablo Canyon
because the extent and timing of the recovery of actual operating costs,
depreciation and a return on the investment in Diablo Canyon primarily depend on
the amount of power produced and the level of costs incurred.
As discussed further in Note 4 of Notes to Consolidated Financial
Statements, the CPUC approved a modification to the Diablo Settlement under
which the price for power produced by Diablo Canyon was reduced from the level
originally set in 1988. PG&E has the right to reduce the price below the amount
specified. All other terms and conditions of the Diablo Settlement remain
unchanged.
Under the modified pricing, each Diablo Canyon operating unit will
contribute approximately $2.7 million in revenues per day at full operating
power in 1996.
The Diablo Canyon capacity factors for 1995, 1994 and 1993 were 86 percent,
81 percent and 89 percent, respectively, reflecting the refueling outages for
Unit 1 in 1995, Units 1 and 2 in 1994 and Unit 2 in 1993. Through December 31,
1995, the lifetime capacity factor for Diablo Canyon was 80 percent. Because of
the nature of the Diablo Settlement, the Company will report significantly lower
revenues for Diablo Canyon during any extended outages, including refueling
outages. In the past, refueling outages, the length of which depend on the scope
of the work, typically occurred for each unit every 18 months. Beginning in
1996, refueling outages will be planned every 21 months as allowed under Diablo
Canyon's current NRC operating license. PG&E intends to seek licensing authority
from the NRC to extend the time between refueling outages to 24 months beginning
in 2001. The next refueling outages for Unit 1 and Unit 2 are scheduled to begin
in May 1997 and April 1996, respectively, and each is planned to last
approximately six weeks.
Gas utility revenues decreased $341 million in 1994 as compared to the
preceding year primarily due to a decrease in revenues received from noncore
customers, who are now arranging for the purchase of their own gas supplies,
with PG&E providing transportation service only. This decrease was partially
offset by higher revenues generated from the Pipeline Expansion. (See Note 3 of
Notes to Consolidated Financial Statements for further discussion.)
Revenues from diversified operations decreased $71 million in 1995 compared
to the preceding year primarily due to the sale of DALEN in June 1995. (See the
Diversified Operations section above for further discussion.)
OPERATING EXPENSES: Operating expenses decreased $1,068 million in 1995 as
compared to the preceding year primarily due to decreased electric costs caused
by favorable hydro conditions, decreased natural gas prices and no workforce
reduction charges in 1995. (See Note 10 of Notes to Consolidated Financial
Statements.)
21
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
CONSOLIDATED RESULTS OF OPERATIONS AND FINANCIAL CONDITION
PACIFIC GAS AND ELECTRIC COMPANY
Operating expenses in 1994 remained constant as compared to 1993. The 1994
and 1993 operating expenses included workforce reduction charges against
earnings of $249 million and $190 million, respectively. The cost of electric
energy was $321 million greater in 1994, primarily due to less favorable hydro
conditions and an increase in the cost of purchased power. These unfavorable
1994 variances were offset by a favorable variance of $369 million in the cost
of gas as a result of PG&E no longer procuring gas for certain customers.
Budgeted 1996 operating expenses are approximately $250 million greater than
the amount adopted by the CPUC for setting rates in the 1996 GRC. The greater
expense level is primarily attributable to several projects related to
distribution system reliability, improved customer service and public
information systems. To the extent that additional cost reductions do not offset
the greater expense level, PG&E's authorized return on equity will be adversely
impacted.
LIQUIDITY AND CAPITAL RESOURCES
SOURCES OF CAPITAL: The Company's capital requirements are funded from cash
provided by 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. Proceeds from the issuance of securities are used for
capital expenditures, refundings and other general corporate purposes.
DEBT: In 1995, PG&E issued no debt, while PGT issued $400 million of bonds and
$70 million of medium-term notes. All other debt issued during the year by PGT
was commercial paper, which is classified as long-term debt and which had a
balance outstanding at December 31, 1995, of $109 million. Substantially all of
the proceeds of PGT's debt issued were used to refinance outstanding PGT debt.
Also in 1995, PG&E redeemed or repurchased $114 million of mortgage bonds in an
effort to reduce the levels of higher-cost debt.
In 1994, PG&E issued $30 million of medium-term notes and redeemed or
repurchased $135 million of mortgage bonds, medium-term notes and Eurobonds. In
1993, PG&E issued $4 billion of mortgage bonds, pollution control revenue bonds
and medium-term notes. Substantially all these proceeds were used to redeem or
repurchase higher-cost mortgage bonds to accomplish a reduction in financing
costs.
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, 1995 and 1994, PG&E
had $796 million and $525 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 also can be used for general corporate purposes.
There were no borrowings under this facility in 1995, 1994 or 1993.
EQUITY: In 1995 and 1994, PG&E received $140 million 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. Proceeds were used for capital expenditures and other general
corporate purposes.
In 1993, the Board authorized PG&E to reinstate its common stock repurchase
program. Since that time, the Board has authorized PG&E to repurchase up to $2
billion of its common stock on the open market or in negotiated transactions.
This program is funded by internally generated funds. Shares are being
repurchased to manage the overall balance of common stock in PG&E's capital
structure. Through December 31, 1995, PG&E had repurchased approximately $1
billion of its common stock under this program.
In 1994 and 1993, PG&E issued $62 million and $200 million, respectively, of
preferred stock. In 1995, 1994 and 1993, PG&E redeemed or repurchased $331
million, $75 million and $267 million, respectively, of its higher-cost
preferred stock.
22
<PAGE>
OTHER CAPITAL: In 1995, PG&E through its wholly owned subsidiary, PG&E Capital
I, issued $300 million of cumulative quarterly income preferred securities.
CAPITAL REQUIREMENTS: The Company's estimated capital requirements for the next
three years are shown below:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, 1996 1997 1998
------ ------ ------
<S> <C> <C> <C>
(IN MILLIONS)
Utility $1,291 $1,220 $1,283
Diablo Canyon 36 37 39
Diversified operations 162 153 332
------ ------ ------
Total capital expenditures 1,489 1,410 1,654
Maturing debt and sinking
funds 304 322 668
------ ------ ------
Total capital requirements $1,793 $1,732 $2,322
------ ------ ------
</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.
Diversified operations consist substantially of Enterprises whose estimated
expenditures include project development expenditures for power and real estate
projects and equity commitments associated with generating facility projects.
In addition to these capital requirements, the Company has other commitments
as discussed in Notes 3 and 12 of Notes to Consolidated Financial Statements.
NEW ACCOUNTING STANDARD: The Company will adopt SFAS No. 121 effective January
1, 1996. The general provisions of SFAS No. 121 require, among other things,
that the existence of an impairment be evaluated whenever events or changes in
circumstances indicate that the carrying amount of an asset may not be fully
recoverable and prescribe standards for the recognition and measurement of
impairment losses. In addition, SFAS No. 121 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.
Based on the expected CTC recovery set forth in the CPUC decision on
electric industry restructuring discussed in Note 2 of Notes to Consolidated
Financial Statements, the Company currently does not anticipate a material
impairment of its assets. However, the CPUC decision is subject to legislative
review. Should final regulations differ significantly from the CPUC decision or
should full recovery of generation assets and obligations not be achieved due to
changing costs or limitations imposed by the market, a material loss could
occur.
RISK MANAGEMENT: Due to the changing regulatory environment, the Company's
exposure to price risk is expected to increase. To manage this risk, in December
1995, the Company adopted a risk management policy and created a committee of
officers to oversee the implementation of the policy, approve each price risk
management program and monitor compliance with the policy.
This action established policies and guidelines for cost effective risk
management programs designed to mitigate financial exposure to changes in the
price of energy commodities, interest rates and currencies. These programs may
include the use of financial derivatives that are designed to offset changes in
the value of an underlying asset, obligation, instrument, contract or index on a
one-for-one basis. This policy prohibits the use of financial derivatives whose
payment formula includes a multiple of some underlying asset. It also prohibits
engaging in speculative financial derivatives trading or adopting compensation
policies that encourage such speculative trading. The Company had no open
positions in derivative financial instruments at December 31, 1995.
The Company also uses other techniques to manage its financial risk
including the purchase of commercial insurance and the maintenance of systems of
internal control. The extent to which these techniques are used depends on the
risk of loss and the cost to employ such techniques.
23
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
CONSOLIDATED RESULTS OF OPERATIONS AND FINANCIAL CONDITION
PACIFIC GAS AND ELECTRIC COMPANY
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 $65
million, $68 million and $121 million for 1996, 1997 and 1998, respectively.
Expenditures during these years will be primarily for nitrogen oxide (NOx)
emission reduction projects for the Company's fossil fuel fired generating
plants and natural gas compressor stations. Pursuant to federal and state
legislation, local air districts have adopted rules that require reductions in
NOx emissions from company facilities. Final rules have yet to be adopted in all
local air districts in which PG&E operates and these rules continue to be
modified. The Company currently estimates that compliance with NOx rules likely
to be in place could require capital expenditures of up to $415 million over the
next ten years.
The Company assesses, on an ongoing basis, measures that may need to be
taken to comply with laws and regulations related to hazardous materials and
hazardous waste compliance and remediation activities. The Company has an
accrued liability at December 31, 1995, of $122 million for hazardous waste
remediation costs at those sites where such costs are probable and quantifiable.
The costs may be as much as $287 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, 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. (See
Note 13 of Notes to Consolidated Financial Statements.)
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 impact on either the Company's results of
operations or financial position.
Significant litigation cases are discussed in Note 13 of Notes to
Consolidated Financial Statements. These cases involve claims for personal
injury, and property and punitive damages allegedly suffered as a result of
exposure to chromium near PG&E's Hinkley Compressor Station, anti-trust claims
for damages as a result of Canadian natural gas purchases by one of the
Company's wholly owned subsidiaries and a claim that PG&E underpaid franchise
fees.
ACCOUNTING FOR DECOMMISSIONING EXPENSE: The staff of the Securities and Exchange
Commission has questioned certain current accounting practices of the electric
utility industry, regarding the recognition, measurement and classification of
decommissioning costs for nuclear generating stations in the financial
statements of electric utilities. In response to these questions, the Financial
Accounting Standards Board has agreed to review the accounting for closure and
removal costs, including decommissioning of nuclear power plants. If current
electric utility industry accounting practices for such decommissioning are
changed: (1) annual expense for decommissioning could increase and (2) the
estimated total cost for decommissioning could be recorded as a liability rather
than accrued over time as accumulated depreciation, with recognition of an
increase in the cost of the related nuclear power plant. The Company does not
believe that such changes, if required, would have an adverse effect on its
results of operations due to its current and future ability to recover
decommissioning costs through rates. (See Note 2 of Notes to Consolidated
Financial Statements for discussion of electric industry restructuring.)
24
<PAGE>
PACIFIC GAS AND ELECTRIC COMPANY
STATEMENT OF CONSOLIDATED INCOME
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, 1995 1994 1993
- ----------------------------------------------------------------------------------------------------------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<S> <C> <C> <C>
OPERATING REVENUES
Electric utility $ 7,386,307 $ 8,021,547 $ 7,876,925
Gas utility 2,059,117 2,081,062 2,421,733
Diversified operations 176,341 247,621 251,344
------------ ------------ ------------
Total operating revenues 9,621,765 10,350,230 10,550,002
------------ ------------ ------------
OPERATING EXPENSES
Cost of electric energy 2,116,840 2,570,723 2,250,209
Cost of gas 333,280 583,356 952,510
Maintenance and other operating 1,799,781 1,855,585 1,942,376
Depreciation and decommissioning 1,360,118 1,397,470 1,315,524
Administrative and general 971,576 973,302 1,041,453
Workforce reduction costs (18,195) 249,097 190,200
Property and other taxes 295,380 296,911 297,495
------------ ------------ ------------
Total operating expenses 6,858,780 7,926,444 7,989,767
------------ ------------ ------------
OPERATING INCOME 2,762,985 2,423,786 2,560,235
------------ ------------ ------------
OTHER INCOME AND (INCOME DEDUCTIONS)
Interest income 72,524 79,643 55,361
Allowance for equity funds used during construction 20,039 19,046 41,531
Other--net 58,564 37,996 51,061
------------ ------------ ------------
Total other income and (income deductions) 151,127 136,685 147,953
------------ ------------ ------------
INCOME BEFORE INTEREST EXPENSE 2,914,112 2,560,471 2,708,188
------------ ------------ ------------
INTEREST EXPENSE
Interest on long-term debt 629,548 651,912 731,610
Other interest charges 61,033 77,295 87,819
Allowance for borrowed funds used during construction (10,643) (12,953) (78,626)
------------ ------------ ------------
Total interest expense 679,938 716,254 740,803
------------ ------------ ------------
PRETAX INCOME 2,234,174 1,844,217 1,967,385
------------ ------------ ------------
INCOME TAXES 895,289 836,767 901,890
------------ ------------ ------------
NET INCOME 1,338,885 1,007,450 1,065,495
Preferred dividend requirement and redemption premium 70,288 57,603 63,812
------------ ------------ ------------
EARNINGS AVAILABLE FOR COMMON STOCK $ 1,268,597 $ 949,847 $ 1,001,683
------------ ------------ ------------
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING 423,692 429,846 430,625
EARNINGS PER COMMON SHARE $ 2.99 $ 2.21 $ 2.33
DIVIDENDS DECLARED PER COMMON SHARE $ 1.96 $ 1.96 $ 1.88
</TABLE>
THE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS ARE AN INTEGRAL
PART OF THIS STATEMENT.
25
<PAGE>
PACIFIC GAS AND ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEET
<TABLE>
<CAPTION>
DECEMBER 31, 1995 1994
------------ ------------
(IN THOUSANDS)
<S> <C> <C>
ASSETS
PLANT IN SERVICE
Electric
Nonnuclear $ 17,513,830 $ 17,045,247
Diablo Canyon 6,646,853 6,647,162
Gas 7,732,681 7,447,879
------------ ------------
Total plant in service (at original cost) 31,893,364 31,140,288
Accumulated depreciation and decommissioning (13,308,596) (12,269,377)
------------ ------------
Net plant in service 18,584,768 18,870,911
------------ ------------
CONSTRUCTION WORK IN PROGRESS 333,263 527,867
OTHER NONCURRENT ASSETS
Oil and gas properties -- 437,352
Nuclear decommissioning funds 769,829 616,637
Investment in nonregulated projects 869,674 761,355
Other assets 130,128 137,325
------------ ------------
Total other noncurrent assets 1,769,631 1,952,669
------------ ------------
CURRENT ASSETS
Cash and cash equivalents 734,295 136,900
Accounts receivable
Customers 1,238,549 1,413,185
Other 65,907 98,035
Allowance for uncollectible accounts (35,520) (29,769)
Regulatory balancing accounts receivable 746,344 1,245,100
Inventories
Materials and supplies 181,763 197,394
Gas stored underground 146,499 136,326
Fuel oil 40,756 67,707
Nuclear fuel 175,957 140,357
Prepayments 47,025 33,251
------------ ------------
Total current assets 3,341,575 3,438,486
------------ ------------
DEFERRED CHARGES
Income tax-related deferred charges 1,079,673 1,155,421
Diablo Canyon costs 382,445 401,110
Unamortized loss net of gain on reacquired debt 392,116 382,862
Workers' compensation and disability claims recoverable 297,266 247,209
Other 669,553 732,029
------------ ------------
Total deferred charges 2,821,053 2,918,631
------------ ------------
TOTAL ASSETS $ 26,850,290 $ 27,708,564
------------ ------------
</TABLE>
THE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS ARE AN INTEGRAL
PART OF THIS STATEMENT.
26
<PAGE>
PACIFIC GAS AND ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEET
<TABLE>
<CAPTION>
DECEMBER 31, 1995 1994
----------- -----------
(IN THOUSANDS)
<S> <C> <C>
CAPITALIZATION AND LIABILITIES
CAPITALIZATION
Common stock $ 2,070,128 $ 2,151,213
Additional paid-in capital 3,716,322 3,806,508
Reinvested earnings 2,812,683 2,677,304
----------- -----------
Total common stock equity 8,599,133 8,635,025
Preferred stock without mandatory redemption provision 402,056 732,995
Preferred stock with mandatory redemption provision 137,500 137,500
Company obligated mandatorily redeemable preferred securities of trust holding
solely PG&E subordinated debentures 300,000 --
Long-term debt 8,048,546 8,675,091
----------- -----------
Total capitalization 17,487,235 18,180,611
----------- -----------
OTHER NONCURRENT LIABILITIES
Customer advances for construction 146,191 152,384
Workers' compensation and disability claims 271,000 221,200
Other 815,960 819,893
----------- -----------
Total other noncurrent liabilities 1,233,151 1,193,477
----------- -----------
CURRENT LIABILITIES
Short-term borrowings 829,947 524,685
Long-term debt 304,204 477,047
Accounts payable
Trade creditors 413,972 414,291
Other 387,747 337,726
Accrued taxes 274,093 436,467
Deferred income taxes 227,782 432,026
Interest payable 70,179 84,805
Dividends payable 205,467 210,903
Other 504,973 468,119
----------- -----------
Total current liabilities 3,218,364 3,386,069
----------- -----------
DEFERRED CREDITS
Deferred income taxes 3,933,765 3,902,645
Deferred tax credits 393,255 391,455
Noncurrent balancing account liabilities 185,647 226,844
Other 398,873 427,463
----------- -----------
Total deferred credits 4,911,540 4,948,407
----------- -----------
COMMITMENTS AND CONTINGENCIES (Notes 1, 2, 3, 12 and 13)
----------- -----------
TOTAL CAPITALIZATION AND LIABILITIES $26,850,290 $27,708,564
----------- -----------
</TABLE>
27
<PAGE>
PACIFIC GAS AND ELECTRIC COMPANY
STATEMENT OF CONSOLIDATED CASH FLOWS
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, 1995 1994 1993
- --------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
(IN THOUSANDS)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 1,338,885 $ 1,007,450 $ 1,065,495
Adjustments to reconcile net income to net cash provided by
operating activities
Depreciation and decommissioning 1,360,118 1,397,470 1,315,524
Amortization 89,353 95,331 135,808
Gain on sale of DALEN (13,107) -- --
Deferred income taxes and tax credits--net (116,069) 15,312 319,198
Allowance for equity funds used during construction (20,039) (19,046) (41,531)
Other deferred charges 61,700 32,740 (158,725)
Other noncurrent liabilities (17,218) 181,902 50,279
Noncurrent balancing account liabilities and other deferred credits (69,787) 316,920 124,189
Net effect of changes in operating assets and liabilities
Accounts receivable 212,515 (116,936) 64,790
Regulatory balancing accounts receivable 498,756 (269,250) (232,597)
Inventories 32,409 66,783 23,097
Accounts payable 49,702 (110,033) (39,422)
Accrued taxes (162,374) 132,892 44,638
Other working capital 8,304 5,821 108,873
Other--net 83,569 210,331 13,184
----------- ----------- -----------
Net cash provided by operating activities 3,336,717 2,947,687 2,792,800
----------- ----------- -----------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (931,908) (1,094,495) (1,763,024)
Allowance for borrowed funds used during construction (10,643) (12,953) (78,626)
Diversified operations (180,941) (328,266) (234,221)
Proceeds from sale of DALEN 340,000 -- --
Other--net (122,913) (29,914) 9,992
----------- ----------- -----------
Net cash used by investing activities (906,405) (1,465,628) (2,065,879)
----------- ----------- -----------
CASH FLOWS FROM FINANCING ACTIVITIES
Common stock issued 139,595 274,269 264,489
Common stock repurchased (601,360) (181,558) (257,780)
Preferred stock issued -- 62,312 200,001
Preferred stock redeemed or repurchased (358,212) (82,875) (302,640)
Company obligated mandatorily redeemable preferred securities issued 300,000 -- --
Long-term debt issued 591,160 60,907 4,584,548
Long-term debt matured, redeemed or repurchased (1,296,549) (436,673) (4,002,704)
Short-term debt issued (redeemed)--net 305,262 (239,478) (366,961)
Dividends paid (891,270) (891,850) (857,515)
Other--net (21,543) 28,721 (24,885)
----------- ----------- -----------
Net cash used by financing activities (1,832,917) (1,406,225) (763,447)
----------- ----------- -----------
NET CHANGE IN CASH AND CASH EQUIVALENTS 597,395 75,834 (36,526)
CASH AND CASH EQUIVALENTS AT JANUARY 1 136,900 61,066 97,592
----------- ----------- -----------
CASH AND CASH EQUIVALENTS AT DECEMBER 31 $ 734,295 $ 136,900 $ 61,066
----------- ----------- -----------
Supplemental disclosures of cash flow information
Cash paid for
Interest (net of amounts capitalized) $ 647,151 $ 674,758 $ 642,712
Income taxes 1,125,635 712,777 542,827
</TABLE>
THE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS ARE AN INTEGRAL PART
OF THIS STATEMENT.
28
<PAGE>
PACIFIC GAS AND ELECTRIC COMPANY
STATEMENT OF CONSOLIDATED COMMON STOCK EQUITY, PREFERRED STOCK AND PREFERRED
SECURITIES
<TABLE>
<CAPTION>
PREFERRED PREFERRED
STOCK STOCK
TOTAL WITHOUT WITH
ADDITIONAL COMMON MANDATORY MANDATORY
COMMON PAID-IN REINVESTED STOCK REDEMPTION REDEMPTION
(DOLLARS IN THOUSANDS) STOCK CAPITAL EARNINGS EQUITY PROVISION PROVISION(1)
---------- ---------- ---------- ---------- ---------- ------------
<S> <C> <C> <C> <C> <C> <C>
BALANCE DECEMBER 31, 1992 $2,134,228 $3,517,062 $2,631,847 $8,283,137 $790,791 $159,510
---------- ---------- ---------- ---------- -------- --------
Net income--1993 1,065,495 1,065,495
Common stock issued
(7,708,512 shares) 38,541 225,948 264,489
Common stock repurchased
(7,334,876 shares) (36,674) (63,180) (157,926) (257,780)
Preferred stock issued
(8,000,000 shares) 200,001
Preferred stock redeemed
(8,156,968 shares) (13,375) (21,958) (35,333) (182,797) (84,510)
Cash dividends declared
Preferred stock (62,521) (62,521)
Common stock (811,196) (811,196)
Other (254) (254)
---------- ---------- ---------- ---------- -------- --------
Net change 1,867 149,393 11,640 162,900 17,204 (84,510)
---------- ---------- ---------- ---------- -------- --------
BALANCE DECEMBER 31, 1993 2,136,095 3,666,455 2,643,487 8,446,037 807,995 75,000
---------- ---------- ---------- ---------- -------- --------
Net income--1994 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)
---------- ---------- ---------- ---------- -------- --------
Net change 15,118 140,053 33,817 188,988 (75,000) 62,500
---------- ---------- ---------- ---------- -------- --------
BALANCE DECEMBER 31, 1994 2,151,213 3,806,508 2,677,304 8,635,025 732,995 137,500
---------- ---------- ---------- ---------- -------- --------
Net income--1995 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 securites issued(2)
(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
---------- ---------- ---------- ---------- -------- --------
Net change (81,085) (90,186) 135,379 (35,892) (330,939) 300,000
---------- ---------- ---------- ---------- -------- --------
BALANCE DECEMBER 31, 1995 $2,070,128 $3,716,322 $2,812,683 $8,599,133 $402,056 $437,500
---------- ---------- ---------- ---------- -------- --------
</TABLE>
(1) Includes current portion.
(2) Relates to company obligated mandatorily redeemable preferred securities of
trust holding solely PG&E subordinated debentures.
THE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS ARE AN INTEGRAL PART
OF THIS STATEMENT.
29
<PAGE>
PACIFIC GAS AND ELECTRIC COMPANY
STATEMENT OF CONSOLIDATED CAPITALIZATION
<TABLE>
<CAPTION>
DECEMBER 31, 1995 1994
- ---------------------------------------------------------------------------------------------------------------
<S> <C> <C>
(DOLLARS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
COMMON STOCK EQUITY
Common stock, par value $5 per share (authorized 800,000,000 shares, issued and
outstanding 414,025,586 and 430,242,687) $ 2,070,128 $ 2,151,213
Additional paid-in capital 3,716,322 3,806,508
Reinvested earnings 2,812,683 2,677,304
----------- -----------
Common stock equity 8,599,133 8,635,025
PREFERRED STOCK AND PREFERRED SECURITIES
Preferred stock without mandatory redemption provision
Par value $25 per share(1)
Nonredeemable
5% to 6%--5,784,825 shares outstanding 144,621 144,621
Redeemable
4.36% to 8.20%--10,297,404 and 23,534,958 shares outstanding 257,435 588,374
----------- -----------
Total preferred stock without mandatory redemption provision 402,056 732,995
----------- -----------
Preferred stock with mandatory redemption provision
Par value $25 per share(1)
6.30% to 6.57%--5,500,000 shares outstanding 137,500 137,500
Par value $100 per share (authorized 10,000,000 shares) -- --
----------- -----------
Total preferred stock with mandatory redemption provision 137,500 137,500
----------- -----------
Preferred stock 539,556 870,495
Company obligated mandatorily redeemable preferred securities of trust holding
solely PG&E subordinated debentures
7.90%--12,000,000 shares outstanding 300,000 --
----------- -----------
LONG-TERM DEBT
PG&E long-term debt
First and refunding mortgage bonds
Maturity Interest rates
1995-2000 4.25% to 6.875% 816,249 823,823
2001-2005 5.875% to 8.75% 1,549,000 1,549,000
2006-2012 6.25% to 8.875% 477,870 477,870
2013-2019 7.5% to 12.75% 105,000 136,030
2020-2026 5.85% to 9.30% 2,749,651 2,902,945
----------- -----------
Principal amounts outstanding 5,697,770 5,889,668
Unamortized discount net of premium (55,802) (66,198)
----------- -----------
Total mortgage bonds 5,641,968 5,823,470
Debentures, 10.81% to 12%, due 1995-2000 57,539 124,939
Pollution control loan agreements, variable rates, due 2008-2016 925,000 925,000
Unsecured medium-term notes, 4.13% to 9.9%, due 1995-2014 1,096,400 1,443,800
Unamortized discount related to unsecured medium-term notes (1,652) (2,428)
Other long-term debt 20,298 22,209
----------- -----------
Total PG&E long-term debt 7,739,553 8,336,990
Long-term debt of subsidiaries 613,197 815,148
----------- -----------
Total long-term debt of PG&E and subsidiaries 8,352,750 9,152,138
Less long-term debt--current portion 304,204 477,047
----------- -----------
Long-term debt 8,048,546 8,675,091
----------- -----------
TOTAL CAPITALIZATION $17,487,235 $18,180,611
=========== ===========
</TABLE>
(1) Authorized 75,000,000 shares in total (both with and without mandatory
redemption provisions).
THE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS ARE AN INTEGRAL PART
OF THIS STATEMENT.
30
<PAGE>
PACIFIC GAS AND ELECTRIC COMPANY
SCHEDULE OF CONSOLIDATED SEGMENT INFORMATION
<TABLE>
<CAPTION>
ELECTRIC GAS DIVERSIFIED INTERSEGMENT
(IN THOUSANDS) UTILITY UTILITY OPERATIONS(4) ELIMINATIONS TOTAL
- -------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
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 -- -- 962,590
Identifiable assets(3) $18,402,373 $6,272,833 $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 -- -- 1,126,494
Identifiable assets(3) $19,464,080 $6,340,456 $1,436,128 $ -- $27,240,664
Corporate assets 467,900
-----------
Total assets at year end $27,708,564
-----------
1993
Operating revenues $ 7,876,925 $2,421,733 $ 251,344 $ -- $10,550,002
Intersegment revenues(1) 15,369 223,443 -- (238,812) --
----------- ---------- ---------- --------- -----------
Total operating revenues $ 7,892,294 $2,645,176 $ 251,344 $(238,812) $10,550,002
----------- ---------- ---------- --------- -----------
Depreciation and decommissioning $ 925,673 $ 251,490 $ 138,361 $ -- $ 1,315,524
Operating income before
income taxes(2) 2,328,241 247,846 (7,812) (8,040) 2,560,235
Capital expenditures(3) 929,065 954,116 -- -- 1,883,181
Identifiable assets(3) $19,124,964 $6,451,388 $1,053,027 $ -- $26,629,379
Corporate assets 516,520
-----------
Total assets at year end $27,145,899
-----------
</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 Pacific Gas Properites Company (real estate development).
THE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS ARE AN INTEGRAL PART
OF THIS SCHEDULE.
31
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PACIFIC GAS AND ELECTRIC COMPANY
NOTE 1: SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Pacific Gas and Electric Company (PG&E) and its wholly owned and controlled
subsidiaries (collectively, the Company) are engaged principally in the business
of supplying electric and natural gas 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.
A significant component of PG&E's electric generation is its operation of the
Diablo Canyon Nuclear Power Plant (Diablo Canyon), as discussed in Note 4.
PG&E's diversified operations, conducted primarily through its wholly owned
subsidiary, PG&E Enterprises (Enterprises), include nonutility electric
generation and power plant operations and services.
Major subsidiaries, all of which are wholly owned, are Pacific Gas
Transmission Company (PGT) -- an interstate pipeline company that transports
natural gas from the U.S./Canadian border to the California border and
Enterprises -- the parent company for substantially all of PG&E's diversified
operations, including PG&E Generating Company which through a joint venture
(U.S. Generating Company) develops, owns and operates power plants. DALEN
Corporation, a wholly owned subsidiary of Enterprises engaged in exploration,
development and production of oil and natural gas, was sold in June 1995.
The consolidated financial statements include PG&E and its wholly owned and
controlled subsidiaries. All significant intercompany transactions have been
eliminated. Certain amounts in the prior years' consolidated financial
statements have been reclassified to conform to the 1995 presentation.
REGULATION: The operations of the utility and Diablo Canyon are regulated by the
California Public Utilities Commission (CPUC), the Federal Energy Regulatory
Commission (FERC) and the Nuclear Regulatory Commission, among others. The
consolidated financial statements reflect the ratemaking policies of the CPUC
and the FERC in accordance with Statement of Financial Accounting Standards
(SFAS)No. 71, "Accounting for the Effects of Certain Types of Regulation." SFAS
No. 71 requires a cost-of-service based, rate-regulated enterprise to reflect
the impact of regulatory decisions in its financial statements. As a result,
certain costs are deferred as regulatory assets when recovery through rates is
not currently provided but is expected in the future. As a result of applying
the provisions of SFAS No. 71, PG&E has accumulated approximately $3.2 billion
of net regulatory assets, including balancing accounts, at December 31, 1995.
The CPUC has established mechanisms known as balancing accounts which help
stabilize PG&E's earnings. 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 these balancing accounts is subject to a
reasonableness review by the CPUC. (See Note 3 for further discussion of gas
costs.)
PLANT IN SERVICE: The cost of plant additions and replacements is capitalized.
Cost includes labor, materials, construction overhead and an allowance for funds
used during construction (AFUDC). AFUDC is the estimated cost of debt and equity
funds used to finance the construction of new facilities. Financing costs of
capital additions for Diablo Canyon, the PG&E portion of the PGT/PG&E Pipeline
32
<PAGE>
Expansion Project (Pipeline Expansion) and other nonregulated projects are
calculated in accordance with SFAS No. 34, "Capitalization of Interest Cost."
The original cost of retired plant plus removal costs less salvage value are
charged to accumulated depreciation. Maintenance, repairs and minor
replacements and additions are charged to maintenance expense.
DEPRECIATION AND NUCLEAR DECOMMISSIONING COSTS: Depreciation of plant in service
is computed using a straight-line remaining-life method.
The estimated cost of decommissioning PG&E's nuclear power facilities is
recovered in base rates through an annual allowance. For the years ended
December 31, 1995, 1994 and 1993, the amount recovered in rates for
decommissioning costs was $54 million each year. Based on a 1994 site study of
decommissioning costs, the amount to be recovered in rates in 1996 will be $36
million. It is assumed that this amount will be recovered annually in rates up
to the commencement of decommissioning. However, this amount will again be
reviewed in PG&E's future rate proceedings. Also, based on this study, the
estimated total obligation for nuclear decommissioning costs is approximately
$1.2 billion in 1995 dollars (or $5.9 billion in future dollars, an increase of
$1.4 billion from the 1991 site study resulting primarily from lengthening the
decommissioning period); this obligation is being recognized ratably over the
facilities' lives. The decommissioning period for Diablo Canyon Unit 1 is 2015
through 2034 and 2016 through 2034 for Diablo Canyon Unit 2. This estimate
considers the total cost (including labor, materials and other costs) of
decommissioning and dismantling plant systems and structures and includes a
contingency factor for possible changes in regulatory requirements and waste
disposal cost increases. The average annualized escalation rate and the assumed
after-tax annualized rate of return on qualified trust assets used to calculate
the decommissioning obligation and annual expense are 6.00 percent and 6.20
percent (5.75 percent on nonqualified trust assets), respectively. (See Note 8
for further discussion of nuclear decommissioning funds.) The actual
decommissioning costs are expected to vary from the above estimates because of
changes in assumed dates of decommissioning, regulatory requirements, technology
and costs of labor, materials and equipment.
The decommissioning method selected for Diablo Canyon anticipates that the
equipment, structures and portions of the facility and site containing
radioactive contaminants will be removed or decontaminated to a level that
permits the property to be released for unrestricted use. Humboldt Bay Power
Plant is being decommissioned under a method that consists of placing and
maintaining the facility in protective storage until some future time when
dismantling can be initiated.
As required by federal law, the U.S. Department of Energy (DOE) is
responsible for the selection and development of repositories for, and the
disposal of, spent nuclear fuel and high-level radioactive waste. PG&E, as
required by federal law, has signed a contract with the DOE to provide for the
disposal of spent nuclear fuel and high-level radioactive waste from its nuclear
generation stations beginning not later than January 1998; however, this
delivery schedule is expected to be delayed. It is not certain when the DOE will
accept high-level radioactive waste from PG&E and other owners of nuclear power
plants. Extended delays or a default by the DOE would lead to consideration of
costly alternatives involving serious siting and environmental issues. PG&E pays
a one-tenth of one cent fee on each nuclear kilowatt-hour (kWh) sold to fund DOE
storage and disposal activities. PG&E has primary responsibility for the interim
storage of its spent nuclear fuel.
33
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PACIFIC GAS AND ELECTRIC COMPANY
GAINS AND LOSSES ON REACQUIRED DEBT: Gains and losses on reacquired debt charged
to the utility are amortized over the remaining original lives of the debt
reacquired, consistent with ratemaking treatment. Gains and losses on reacquired
debt charged to Diablo Canyon and the PG&E portion of the Pipeline Expansion are
recognized in income at the time such debt is reacquired.
INVENTORIES: Nuclear fuel inventory is stated at the lower of average cost or
market. Amortization of nuclear fuel in the reactor is 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.
STATEMENT OF CONSOLIDATED CASH FLOWS: Cash and cash equivalents (valued at cost
which approximates market) include special deposits, working funds and
short-term investments with original maturities of three months or less.
USE OF ESTIMATES: The preparation of financial statements in conformity with
generally accepted accounting principles requires management to make estimates
and assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates.
NEW ACCOUNTING STANDARD: SFAS No. 121, "Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to Be Disposed Of," effective
January 1, 1996, 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.
Based on the expected competition transition charge (CTC) recovery set forth
in the CPUC decision on electric industry restructuring discussed in Note 2, the
Company currently does not anticipate a material impairment of its assets and,
specifically, its generation-related regulatory assets and investments in
electric generation assets. However, the CPUC decision is subject to
legislative review. Should final regulations differ significantly from the CPUC
decision or should full recovery of generation assets and obligations not be
achieved due to changing costs or limitations imposed by the market, a material
loss could occur.
NOTE 2: ELECTRIC INDUSTRY RESTRUCTURING
On December 20, 1995, the CPUC issued a decision calling for the restructuring
of California's electric industry. The CPUC's goal is to provide a structure
that will ultimately allow California consumers to choose among competing
suppliers of electricity. In summary, the decision would (1) simultaneously
create a wholesale power pool (the Exchange) and allow direct access for certain
customers to contract directly with electric generation providers beginning in
1998 with all customers phased in within five years; (2) establish an
Independent System Operator (ISO) to manage and control the transmission system;
and (3) provide recovery of utilities' stranded costs (costs which are
above-market and could not be recovered under market-based pricing) through a
surcharge, or CTC, to be imposed on all customers. The decision, while effective
immediately, provides a 100-day period for legislative review.
Under the restructuring decision, PG&E would continue to provide
distribution, generation and procurement functions for those customers choosing
to take bundled service, all of which would be regulated under performance-based
ratemaking. The decision requires PG&E to file proposals to
34
<PAGE>
establish performance-based ratemaking for its generation and distribution
functions.
The CPUC concluded that market power issues associated with the electric
industry restructuring almost certainly mandate that the investor-owned
utilities (IOUs) divest themselves of a substantial portion of their fossil fuel
generation assets. Accordingly, the decision requires PG&E to file a plan to
voluntarily divest itself of at least 50 percent of its fossil fuel generation
assets.
The decision provides for the collection of transition costs through the
imposition of a non-bypassable CTC. Transition cost recovery shall not increase
rates beyond the rate levels in effect as of January 1, 1996. A transition cost
account will be established for each utility. Transition costs associated with
regulatory assets will be included in the account as authorized by the CPUC. The
account will be adjusted annually for the difference between authorized revenues
associated with the generation assets and actual revenues earned in the market
as well as after a generation asset receives its market valuation. Valuation of
above-market generation assets will be completed by 2003. Utility nonnuclear
generation assets will be valued through sale, spin-off or market appraisal.
Transition costs resulting from the operation of nuclear generation
facilities and electricity purchases under existing wholesale and qualifying
facility (QF) contracts will also be recorded in this account. Transition costs
for these resources will be calculated annually over the terms of the contracts
or until the authorized transition cost recovery has been completed. Except for
existing QF generation contracts with contractual payments beyond 2003, all
transition costs will be collected by 2005.
With respect to recovery of costs associated with Diablo Canyon and the
Diablo Canyon rate case settlement (Diablo Settlement), the decision confirms
that the CPUC will continue to honor regulatory commitments regarding the
recovery of nuclear generation costs. Diablo Canyon transition costs will be
calculated over the term of the Diablo Settlement. The decision requires PG&E to
file a proposal for pricing Diablo Canyon generation at market prices by 2003
and for completing recovery of Diablo Canyon CTC by 2005 while assuring no
overall rate increase over January 1, 1996, levels. If PG&E retains ownership of
Diablo Canyon, decommissioning costs will also be included in the transition
cost account.
FINANCIAL IMPACT OF THE ELECTRIC INDUSTRY RESTRUCTURING: In December 1994, in
response to one of the proceedings leading to the decision, PG&E estimated the
revenue requirements of its owned generation assets and power purchase
obligations to be above market by $3 billion and $11 billion at assumed market
prices of $.040 and $.032 per kWh, respectively. These market prices were used
to provide a range of possible transition costs and do not represent a forecast
of expected market prices. These above-market estimates were determined by
comparing future revenue requirements of generation assets and power purchase
obligations, over a 20-year and 30-year period, respectively, with revenues
computed at assumed market prices. The revenue requirements for Diablo Canyon
and all PG&E-owned generation assets included a return on investment. Diablo
Canyon was included in the revenue requirements calculation using the revised
pricing included in the modified Diablo Settlement. (See Note 4.) The
above-market revenue requirements for Diablo Canyon included above were $4
billion and $6 billion at assumed market prices of $.040 and $.032 per kWh,
respectively. At this time, PG&E has not completed a more current estimate of
its above-market revenue requirements. However, market prices could be less than
$.032 per kWh. The actual amounts of above-market revenue requirements may
differ materially from those indicated above and will depend on the final
regulations and the actual market prices of electricity or a definitive market
valuation.
35
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PACIFIC GAS AND ELECTRIC COMPANY
The CPUC electric industry restructuring decision establishes an account to
track the accumulation of transition costs and their recovery. While the
decision provides an opportunity for recovery of all above-market costs, actual
recovery will occur through a CTC applied to transmission and distribution
rates. The level of CTC will be limited to an amount that does not increase the
customers' aggregate rates above those in effect January 1, 1996. Recent CPUC
decisions effective on January 1, 1996, including PG&E's General Rate Case
(GRC), have resulted in an average electric system rate of 9.9 cents per kWh.
PG&E's ability to recover its transition costs will be dependent on achieving
overall reductions in costs such that it can recover its ongoing operating
costs, capital costs and transition costs at the 1996 rate level and on
continuing to collect CTC for the duration of the recovery period.
As a result of applying the provisions of SFAS No. 71 (see Note 1), PG&E has
accumulated approximately $2.6 billion of electric regulatory assets, including
balancing accounts, at December 31, 1995. The regulatory assets attributable to
electric generation, excluding balancing accounts of $248 million which are
expected to be recovered in the near term, were approximately $1.5 billion at
December 31, 1995. When generation rates are no longer based on cost of service,
as ultimately contemplated under the decision, PG&E will discontinue application
of SFAS No. 71 for that portion of its business. However, PG&E expects to
recover its regulatory assets as transition costs through the CTC and does not
expect a material loss from the discontinuance of SFAS No. 71. PG&E's
transmission and distribution businesses are expected to remain on
cost-of-service rates.
In addition, the adoption of SFAS No. 121 in 1996 will require that all
regulatory assets continue to be probable of recovery in rates. In the event
that this criterion can no longer be met, whether due to changing regulation or
PG&E's inability to collect these costs, applicable portions of any regulatory
assets would be written off. The transition cost account will be a regulatory
asset also subject to the criteria of SFAS No. 121.
The net book value of PG&E's investment in Diablo Canyon was approximately
$4.8 billion at December 31, 1995. The net book value of the remaining
PG&E-owned generation assets, including an allocation of common plant, was
approximately $3.1 billion at December 31, 1995.
Because of the expected transition cost recovery as provided in the
decision, PG&E does not anticipate a material impairment loss on its investment
in generation assets due to electric industry restructuring. However, should
final regulations differ significantly from the CPUC decision or should full
recovery of generation assets and obligations not be achieved due to changing
costs or limitations imposed by the market, a material loss could occur.
The Company cannot predict the ultimate outcome of the ongoing changes that
are taking place in the electric utility industry or predict whether such
outcome will have a material impact on its financial position or results of
operations.
NOTE 3: NATURAL GAS MATTERS
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 decisions covering the years 1988 through 1990,
ordering disallowances of approximately $90 million of gas costs, plus accrued
interest of
36
<PAGE>
approximately $25 million through 1993 for PG&E's Canadian gas procurement
activities, and $8 million for gas inventory operations. PG&E has filed a
lawsuit in a federal district court challenging the CPUC decision on Canadian
gas costs. In September 1995, the federal court denied a motion filed by the
CPUC to dismiss the lawsuit.
During 1995, the CPUC approved settlement agreements between the CPUC's
Division of Ratepayer Advocates (DRA) and PG&E which resolve $25 million of
disallowances recommended by the DRA relating to certain non-Canadian gas issues
arising from the 1991 and 1992 record periods. Pursuant to these agreements,
PG&E will refund $1.1 million to ratepayers.
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 are still under review by the CPUC. The DRA had
recommended disallowances of approximately $79 million and a penalty of $50
million and indicated that it was considering additional recommendations for
pending issues. PG&E and the DRA have signed a settlement agreement to resolve
these issues for a $67 million disallowance.
As of December 31, 1995, PG&E has accrued approximately $208 million for the
CPUC decisions for the years 1988 through 1992 and issues covered by the
settlement agreements described above. The Company believes the ultimate outcome
of these matters will not have a material impact on its financial position or
results of operations.
Settlement of certain other unresolved gas issues is being negotiated as
part of the Gas Accord negotiations discussed below.
PIPELINE EXPANSION: In November 1993, the Company placed in service an expansion
of its natural gas transmission system from the Canadian border into California.
The Pipeline Expansion provides additional firm transportation capacity to
Northern and Southern California and the Pacific Northwest. The total cost of
construction was approximately $1.7 billion; $813 million for the PG&E or
California portion and $852 million for the PGT or interstate portion.
PG&E has filed an application with the CPUC requesting that capital and
operating costs for the PG&E portion of the Pipeline Expansion be found
reasonable. In that CPUC proceeding, the DRA recommended that $100 million in
capital costs be disallowed for recovery in rates while two intervenors jointly
recommended a $223 million disallowance. An order issued by a CPUC
Administrative Law Judge (ALJ) has also reopened the 1993 PG&E Pipeline
Expansion Rate Case to allow reconsideration of issues regarding the decision to
construct the PG&E Pipeline Expansion.
In January 1996, a CPUC ALJ ordered consolidation of the market impact phase
of the PG&E Pipeline Expansion reasonableness proceeding and the Interstate
Transition Cost Surcharge (ITCS) proceeding discussed below.
If the CPUC were to reverse its previous decision finding PG&E was
reasonable in constructing the PG&E Pipeline Expansion, the ultimate outcome
could have an impact on PG&E's ability to recover its cost for unused capacity
on other pipelines as well as on its own intrastate facilities.
For the interstate portion of the Pipeline Expansion, PGT included the total
capital cost in its 1994 GRC filing with the FERC; no parties contested these
costs. Decisions in these three proceedings are expected in 1996. Revenues are
currently being collected under interim rates approved by the FERC and the CPUC,
subject to adjustment.
37
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PACIFIC GAS AND ELECTRIC COMPANY
TRANSPORTATION COMMITMENTS: PG&E has gas transportation service agreements with
various Canadian and interstate pipeline companies. These agreements include
provisions for 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 and may be offset to the extent PG&E can broker or
permanently assign any unused capacity. In addition to demand charges, PG&E is
required to pay transportation charges for actual quantities shipped. The total
demand and transportation charges paid by PG&E under these agreements (excluding
agreements with PGT) were approximately $175 million in 1995, $225 million in
1994 and $280 million in 1993.
The following table summarizes the approximate capacity held by PG&E on
various pipelines and the related annual demand charges as of December 31, 1995:
<TABLE>
<CAPTION>
TOTAL
FIRM ANNUAL
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 $28 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
industrial and large commercial (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 its residential and smaller commercial (core)
customers and noncore customers who choose bundled service (core subscription
customers). In order to service 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) and Alberta Natural Gas
Company Ltd (ANG).
PG&E is continuing its efforts to broker or assign any remaining unused
capacity including that held for its core and core subscription customers when
such capacity is not being used. 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,
including charges for capacity formerly used to service noncore customers which
cannot be brokered or brokered at a discount, are eligible for rate recovery,
subject to a reasonableness review. However, certain groups, including the DRA
and intervenors, have challenged the recovery of certain 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 subscribe for
transportation capacity with Transwestern. The decision concluded that PG&E was
unable to prove the benefits of such capacity during 1992 and denied recovery
of the $18 million of Transwestern charges for that year. The decision further
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. PG&E is seeking rehearing of this decision.
The recovery of demand charges associated with capacity which was formerly
used to service PG&E's noncore customers will be decided by the CPUC in the
ITCS proceeding. Pending a final decision in the ITCS proceeding, the CPUC has
approved collection in rates of approximately one-half of the demand charges for
unbrokered or discounted El Paso and PGT capacity which was formerly used to
service PG&E's noncore customers, subject to refund.
38
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PACIFIC GAS AND ELECTRIC COMPANY
In October 1995, PG&E presented a proposal, called the Gas Accord, to
numerous parties active in the California gas marketplace, in an effort to
restructure the California gas market. As part of the Gas Accord negotiations,
PG&E is pursuing the resolution of existing regulatory issues pending in
separate CPUC proceedings. Regulatory issues being negotiated as part of the Gas
Accord include PG&E's capacity commitments with Transwestern, recovery of the
costs for unbrokered capacity commitments under the ITCS mechanism and the
reasonableness proceedings for the PG&E portion of the Pipeline Expansion. The
Company believes the ultimate resolution of past and future Transwestern costs,
the ITCS proceeding and the PG&E portion of the Pipeline Expansion proceedings,
either through settlement negotiations or ongoing proceedings, will not have a
material adverse impact on its financial position or results of operations.
NOTE 4: DIABLO CANYON
RATE CASE SETTLEMENT: The Diablo Settlement bases revenues primarily on the
amount of electricity generated by the plant, rather than on traditional
cost-based ratemaking. The Diablo Settlement provides that Diablo Canyon costs
and operations should no longer be subject to CPUC reasonableness reviews and
that only certain Diablo Canyon costs be recovered through base rates over the
term of the Diablo Settlement, including a full return on such costs. The
related revenues to recover these costs are included in Diablo Canyon operating
revenues reported below. Other than for these and decommissioning costs, Diablo
Canyon no longer meets the criteria for application of SFAS No. 71, which was
discontinued for Diablo Canyon effective July 1988.
PRICING: In May 1995, the CPUC approved a modification to the pricing provisions
of the Diablo Settlement. Under the modification, the prices for power produced
by Diablo Canyon for 1996 through 1999 are 10.5 cents, 10.0 cents, 9.5 cents and
9.0 cents per kWh, respectively, effective January 1. PG&E has the right to
reduce the price below the amount specified. All other terms and conditions of
the Diablo Settlement remain unchanged.
The modification provides that the difference between PG&E's revenue
requirement under the original Diablo Settlement prices and the modified prices
be applied to PG&E's energy cost balancing account until the undercollection in
that account as of December 31, 1995, is fully amortized.
Under the modified pricing, at full operating power each Diablo Canyon unit
would contribute approximately $2.7 million in revenues per day in 1996.
The prices per kWh of electricity generated by Diablo Canyon for 1995, 1994
and 1993 were 11.00 cents, 11.89 cents and 11.16 cents per kWh, respectively.
FINANCIAL INFORMATION: Selected financial information for Diablo Canyon is shown
below:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, 1995 1994 1993
---- ---- ----
(IN MILLIONS)
<S> <C> <C> <C>
Operating revenues $1,845 $1,870 $1,933
Operating income before
income taxes 1,029 956 1,123
Net income 507 461 496
</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 corporate debt.
39
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PACIFIC GAS AND ELECTRIC COMPANY
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, 1995, 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, 1995, 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, 1995. These series of
preferred stock are subject to mandatory redemption provisions entitling them to
sinking funds providing for the retirement of stock outstanding or 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, 1995 and 1994, was approximately $139 million and
$117 million, respectively, based primarily on matrix pricing models.
During 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
6 7/8%, 7.04% and 7.44% redeemable preferred stock through a tender offer. The
aggregate par value of these redemptions and repurchases was $331 million.
During 1994, PG&E issued $63 million of series 6.30% redeemable preferred
stock and redeemed its series 8.16% redeemable preferred stock with a par value
of $75 million.
Dividends on 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: In November 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
only assets of the Trust are the deferrable interest 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. 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. Net proceeds from the QUIPS
offering and the issuance of the common securities were used by the Trust to
purchase the subordinated debentures. Proceeds to PG&E from the sale of the
subordinated debentures are being used to refinance higher-cost preferred stock.
40
<PAGE>
NOTE 6: LONG-TERM DEBT
(See the Statement of Consolidated Capitalization for additional information.)
MORTGAGE BONDS: PG&E had $5.7 billion and $5.9 billion of mortgage bonds
outstanding at December 31, 1995 and 1994, respectively. Additional bonds may be
issued, subject to CPUC approval, up to a maximum total amount outstanding of
$10 billion, assuming compliance with indenture covenants for earnings coverage
and property available as security. All real properties and substantially all
personal properties of PG&E are subject to the lien of the indenture.
PG&E is required by the indenture to make semi-annual sinking fund payments
on February 1 and August 1 of each year for the retirement of the bonds. These
payments equal .5 percent of the aggregate bonded indebtedness outstanding on
the preceding November 30 and May 31, respectively. Mortgage bonds, with certain
exceptions, may be used to satisfy the sinking fund requirement.
In conjunction with PG&E's focus on reducing the levels of higher-cost debt,
PG&E redeemed or repurchased $114 million and $80 million of higher-cost
mortgage bonds in 1995 and 1994, respectively. Interest rates on the bonds
redeemed or repurchased ranged from 8.875 percent to 12.75 percent.
Included in the total of outstanding mortgage bonds are First and Refunding
Mortgage Bonds issued by PG&E to finance air and water pollution control and
sewage and solid waste disposal facilities. These mortgage bonds are held in
trust for the California Pollution Control Financing Authority (CPCFA), which
arranged these financings, and are in addition to the Pollution Control Loan
Agreements discussed below. At December 31, 1995 and 1994, PG&E had outstanding
$768 million of mortgage bonds held in trust for the CPCFA with interest rates
ranging from 5.85 percent to 8.875 percent and maturity dates from 2007 to 2023.
POLLUTION CONTROL LOAN AGREEMENTS: In addition to the pollution control loans
secured by PG&E's mortgage bonds (described above), PG&E had loans totaling $925
million at December 31, 1995 and 1994, from the CPCFA, issued for similar
purposes. Interest rates on the loans vary depending upon whether the loans are
in a daily, weekly, commercial paper or fixed rate mode. Conversions from one
mode to another take place at PG&E's option. Average annual interest rates on
these loans for 1995 ranged from 3.77 percent to 3.90 percent. These loans are
subject to redemption on demand by the holder under certain circumstances and
are secured by irrevocable letters of credit which mature as early as 1997.
LONG-TERM DEBT OF SUBSIDIARIES: In 1995, PGT, a wholly owned subsidiary of PG&E,
completed the sale of $470 million of debt securities through a $700 million
shelf registration. Additionally, PGT issued commercial paper, $109 million of
which was outstanding at December 31, 1995. This commercial paper is classified
as long-term based upon the availability of committed credit facilities expiring
in 2000 and management's intent to maintain such amounts in excess of one year.
Substantially all of the proceeds from the debt offering and sale of commercial
paper were used to refinance $600 million of outstanding PGT debt.
REPAYMENT SCHEDULE: At December 31, 1995, the Company's combined aggregate
amount of maturing long-term debt and sinking fund requirements, for the years
1996 through 2000, are $304 million, $322 million, $668 million, $271 million
and $447 million, respectively.
FAIR VALUE: The estimated fair value of the Company's total long-term debt of
$8.4 billion and $9.2 billion at December 31, 1995 and 1994, respectively, was
approximately $8.7 billion and $8.6 billion, respectively. The estimated
41
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PACIFIC GAS AND ELECTRIC COMPANY
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., matrix pricing
models or the present value of future cash flows).
NOTE 7: SHORT-TERM BORROWINGS
Substantially all short-term borrowings consist of commercial paper. The usual
maturity for commercial paper is one to ninety days. Commercial paper
outstanding at December 31, 1995 and 1994, was $796 million with a weighted
average interest rate of 5.92 percent and $525 million with a weighted average
interest rate of 6.18 percent, respectively. The carrying amount of short-term
borrowings approximates fair value.
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 also can be used for general corporate purposes. There
were no borrowings under this facility in 1995 or 1994. This credit facility
expires in November 2000; however, it may be extended annually for additional
one-year periods upon mutual agreement among PG&E and the banks.
NOTE 8: INVESTMENTS IN DEBT AND EQUITY SECURITIES
Effective January 1, 1994, the Company adopted SFAS No. 115, "Accounting
for Certain Investments in Debt and Equity Securities," which established new
financial accounting and reporting standards for investments in debt and equity
securities. All of PG&E's investments in debt and equity securities are
included in Nuclear Decommissioning Funds and are classified as
available-for-sale. These securities are held in external trust funds to be
used for the decommissioning of PG&E's nuclear facilities and are reported at
fair value. Unrealized gains and losses are recorded to Accumulated
Depreciation and Decommissioning, net of tax. Funds may not be released from
the external trust funds until authorized by the CPUC.
The proceeds received during 1995 and 1994 from the sale of securities held
as available-for-sale were approximately $1.5 billion and $1 billion,
respectively. During 1995 and 1994, the gross realized gains on sales of
securities held as available-for-sale were $9 million and $10 million,
respectively, and the gross realized losses on sales of securities held as
available-for-sale were $22 million and $12 million, respectively. The cost of
equity securities sold is determined by specific identification. The cost of
debt securities sold is based on a first-in-first-out method.
The following tables provide a summary of amortized cost and fair value by
major security type:
<TABLE>
<CAPTION>
GROSS GROSS
UNREALIZED UNREALIZED
DECEMBER 31, AMORTIZED HOLDING HOLDING FAIR
1995 COST GAINS LOSSES VALUE
--------- ---------- ---------- ---------
(IN THOUSANDS)
<S> <C> <C> <C> <C>
Debt of U.S.
Treasury and
other federal
entities $ 332,847 $ 21,157 $ -- $ 354,004
State and local
obligations 45,086 2,716 (97) 47,705
Equity
securities 277,460 93,767 (2,759) 368,468
Other
securities and
adjustments (377) 33 (4) (348)
--------- --------- --------- ---------
Total nuclear
decommis-
sioning funds $ 655,016 $ 117,673 $ (2,860) $ 769,829
--------- --------- --------- ---------
</TABLE>
42
<PAGE>
<TABLE>
<CAPTION>
GROSS GROSS
UNREALIZED UNREALIZED
DECEMBER 31, AMORTIZED HOLDING HOLDING FAIR
1994 COST GAINS LOSSES VALUE
--------- ---------- ---------- --------
<S> <C> <C> <C> <C>
(IN THOUSANDS)
Debt of U.S.
Treasury and
other federal
entities $290,511 $ 20 $ (7,972) $282,559
State and local
obligations 94,899 1,268 (2,485) 93,682
Equity
securities 184,954 18,556 (9,261) 194,249
Other
securities and
adjustments 46,398 24 (275) 46,147
-------- -------- -------- --------
Total nuclear
decommis-
sioning funds $616,762 $ 19,868 $(19,993) $616,637
-------- -------- -------- --------
</TABLE>
At December 31, 1995 and 1994, investments in debt securities maturing
within ten years totaled $275 million and $293 million, respectively, and
investments in debt securities with maturities in excess of ten years totaled
$146 million and $114 million, respectively.
NOTE 9: EMPLOYEE BENEFIT PLANS
RETIREMENT PLAN: PG&E provides a noncontributory defined benefit pension plan
covering substantially all employees. Retirement benefits are based on years of
service and the employee's base salary. PG&E'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. Other than for voluntary
retirement incentive (VRI) benefits, PG&E last funded the retirement plan in
1992, consistent with amounts recovered in rates.
At December 31, 1995, plan assets exceeded the projected benefit obligation
by $739 million. The plan's funded status was:
<TABLE>
<CAPTION>
DECEMBER 31, 1995 1994
----------- -----------
(IN THOUSANDS)
<S> <C> <C>
Actuarial present value of
benefit obligations
Vested benefits $(3,464,782) $(3,079,045)
Nonvested benefits (182,503) (131,489)
----------- -----------
Accumulated benefit
obligation (3,647,285) (3,210,534)
Effect of projected future
compensation increases (548,743) (441,951)
----------- -----------
Projected benefit obligation (4,196,028) (3,652,485)
Plan assets at market value 4,935,267 4,169,516
----------- -----------
Plan assets in excess of
projected benefit obligation 739,239 517,031
Unrecognized prior service
cost 90,496 93,425
Unrecognized net gain (1,074,347) (908,485)
Unrecognized net transition
obligation 97,348 108,800
----------- -----------
Accrued pension liability $ (147,264) $ (189,229)
----------- -----------
</TABLE>
Plan assets are primarily 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 amortized over approximately 18 years, beginning in
1987.
The vested benefit obligation is the actuarial present value of vested
benefits to which employees are currently entitled based on their expected
termination dates.
43
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PACIFIC GAS AND ELECTRIC COMPANY
The cost of this plan is recorded to expense and, on a funding basis, to
plant in service. Net pension cost or income, using the projected unit credit
actuarial cost method, was:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, 1995 1994 1993
--------- --------- ---------
(IN THOUSANDS)
<S> <C> <C> <C>
Service cost for
benefits earned $ 82,814 $ 109,132 $ 129,166
Interest cost 290,563 272,932 268,698
Actual (return) loss
on plan assets (968,126) 20,358 (511,526)
Net amortization
and deferral 586,350 (412,547) 177,597
--------- --------- ---------
Net pension
(income) cost $ (8,399) $ (10,125) $ 63,935
--------- --------- ---------
</TABLE>
Actuarial assumptions used in accounting for the pension plan were:
<TABLE>
<CAPTION>
December 31, 1995 1994 1993
---- ---- ----
<S> <C> <C> <C>
Discount rate 7.25% 8% 7%
Rate of future compensation
increases 5% 5% 5%
Expected long-term rate of
return on plan assets 9% 9% 9%
</TABLE>
Net pension cost or income is determined using assumptions at the beginning
of the year. Funded status is determined using assumptions at the end of the
year.
The decrease in net pension cost in 1994 compared to 1993 was primarily due
to changes in the assumed rates of future compensation increases and turnover to
better reflect actual and expected rates.
Net pension cost or income 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 pension cost or income. In 1995 and 1993, 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 accounting for rate-regulated enterprises, regulatory
adjustments have been recorded in the income statement and balance sheet for the
difference between utility pension cost determined for accounting purposes and
that for ratemaking, which is based on a funding approach.
SAVINGS FUND PLAN: PG&E sponsors a defined contribution pension plan. Employees
with at least one year of service may contribute up to 15 percent of their
covered compensation on a pretax or after-tax basis. These contributions, up to
a maximum of six percent of covered compensation, are eligible for matching PG&E
contributions at specified rates. The cost of PG&E contributions was charged to
expense and to plant in service and totaled $33 million, $35 million and $36
million for 1995, 1994 and 1993, respectively.
POSTRETIREMENT BENEFITS OTHER THAN PENSIONS: PG&E provides a contributory
defined benefit medical plan for retired employees and their eligible dependents
and a non-contributory defined benefit life insurance plan 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 PG&E's retirees. The cost of these plans is charged to
expense and to plant in service.
The CPUC has authorized recovery of these benefits for 1993 and beyond,
within certain guidelines, at a level equal to the annual accounting cost, based
on amortization of the transition obligation over 20 years, limited by the
44
<PAGE>
amount which can be contributed annually on a tax-deductible basis to
appropriate trusts. PG&E's policy for postretirement medical and life insurance
benefits is to fund each year an amount consistent with the basis for rate
recovery.
In 1993, PG&E implemented a plan change that will limit the amount it will
contribute toward postretirement medical benefits beginning in 2001. This change
reduced the accumulated postretirement benefit obligation at July 1, 1993, by
approximately $450 million.
At December 31, 1995, the accumulated postretirement benefit obligation
exceeded plan assets by $422 million. The medical and life insurance plans'
funded status was:
<TABLE>
<CAPTION>
DECEMBER 31, 1995 1994
--------- ---------
(IN THOUSANDS)
<S> <C> <C>
Accumulated postretirement
benefit obligation
Retirees $(528,367) $(497,889)
Other fully eligible participants (123,615) (104,865)
Other active plan participants (309,405) (219,639)
--------- ---------
Total accumulated postretirement
benefit obligation (961,387) (822,393)
Plan assets at market value 538,905 394,939
--------- ---------
Accumulated postretirement
benefit obligation in excess of
plan assets (422,482) (427,454)
Unrecognized prior service cost 23,761 25,377
Unrecognized net gain (104,167) (115,249)
Unrecognized transition obligation 449,647 462,082
--------- ---------
Accrued postretirement
benefit liability $ (53,241) $ (55,244)
--------- ---------
</TABLE>
Plan assets are primarily 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 amortized over 20 years, beginning in 1993.
Net postretirement medical and life insurance cost, using the projected unit
credit actuarial cost method, was:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, 1995 1994 1993
--------- --------- ---------
(IN THOUSANDS)
<S> <C> <C> <C>
Service cost for
benefits earned $ 17,004 $ 23,617 $ 38,496
Interest cost 64,776 64,872 73,502
Actual return on
plan assets (108,932) (1,232) (23,999)
Amortization of
unrecognized prior
service cost 1,616 1,711 --
Amortization of
transition obligation 26,533 28,913 39,620
Net amortization
and deferral 70,070 (29,804) (3,390)
--------- --------- ---------
Net postretirement
benefit cost $ 71,067 $ 88,077 $ 124,229
--------- --------- ---------
</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 1995, 1994 and 1993 were the same as those used
for the pension plan. The assumed health care cost trend rate for 1996 is
approximately 10.5 percent, grading down to an ultimate rate in 2005 of
approximately 6 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, 1995, by
approximately $117 million and the 1995 aggregate service and interest costs by
approximately $12 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. The
decrease in cost in 1994 compared to 1993 was primarily due to the plan change
implemented July 1, 1993, that will limit PG&E's contributions toward
postretirement medical benefits.
45
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PACIFIC GAS AND ELECTRIC COMPANY
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 1995, actual return on plan assets
exceeded expected return. In 1994 and 1993, actual return on plan assets was
less than expected.
WORKFORCE REDUCTIONS: The effects of workforce reductions announced by PG&E in
1994 and 1993 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 implemented a Long-term Incentive Program
(Program) in 1992. The Program allows eligible participants to be granted stock
options with or without associated stock appreciation rights, dividend
equivalents and/or performance-based units. The Program incorporates those
shares previously authorized under PG&E's 1986 Stock Option Plan. As of December
31, 1995, a total of 14.5 million shares of common stock have been authorized
for award under the Program and the 1986 Stock Option Plan. During 1995, an
additional 10 million common shares were authorized for award under the Program,
subject to shareholder approval. At December 31, 1995, stock options on
2,761,290 shares, granted at option prices ranging from $16.75 to $34.25, were
outstanding. During 1995, 570,500 options were granted at an option price of
$24.38, 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 basis at one-third each year
commencing two years from the date of grant. In 1995, 1994 and 1993, stock
options on 235,568, 52,143 and 174,387 shares, respectively, were exercised at
option prices ranging from $16.75 to $33.13, $24.75 to $32.13 and $16.75 to
$33.13, respectively. At December 31, 1995, stock options on 1,337,196 shares
were exercisable.
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 and $52 million for other postretirement benefits both extended
in connection with the VRI as well as $61 million of estimated severance costs.
The majority of the severances were in generation and transmission funtions.
PG&E will 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 order to accelerate maintenance on its system in light of the
severity of the damage caused by storms in the winter 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 $18.2 million in 1995.
The total cost of the 1993 workforce reductions was $264 million. Included
in this amount was $151 million for additional pension benefits and $22 million
for other postretirement benefits extended in connection with the VRI. As a
result of a freeze on electric rates, PG&E expensed $190 million of costs
relating to electric operations. The amount relating to gas operations was
deferred and amortized over the period 1993-1995.
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 deferred and amortized to income over the life
of the related property.
46
<PAGE>
The significant components of income tax expense were:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, 1995 1994 1993
----------- ----------- -----------
(IN THOUSANDS)
<S> <C> <C> <C>
Current $ 1,011,358 $ 821,455 $ 582,692
Deferred (97,864) 34,657 339,608
Tax credits--net (18,205) (19,345) (20,410)
----------- ----------- -----------
Total income tax
expense $ 895,289 $ 836,767 $ 901,890
----------- ----------- -----------
</TABLE>
The significant components of net deferred income tax liabilities were:
<TABLE>
<CAPTION>
DECEMBER 31, 1995 1994
---------- ----------
(IN THOUSANDS)
<S> <C> <C>
Deferred income tax assets:
Deferred income taxes--
current $ 195,510 $ 173,357
Deferred income taxes--
noncurrent 1,008,471 959,459
---------- ----------
Total deferred income tax assets 1,203,981 1,132,816
---------- ----------
Deferred income tax liabilities:
Deferred income taxes--current
Regulatory balancing
accounts 385,604 559,750
Other 37,688 45,633
---------- ----------
Total deferred income
taxes--current 423,292 605,383
---------- ----------
Deferred income taxes--noncurrent
Plant in service 3,552,974 3,627,294
Income tax-related deferred
charges(1) 443,152 474,242
Other 946,110 760,568
---------- ----------
Total deferred income
taxes--noncurrent 4,942,236 4,862,104
---------- ----------
Total deferred income tax
liabilities 5,365,528 5,467,487
---------- ----------
Total net deferred income taxes $4,161,547 $4,334,671
---------- ----------
Classification of net deferred income taxes:
Included in current liabilities $ 227,782 $ 432,026
Included in deferred credits 3,933,765 3,902,645
---------- ----------
Total net deferred income taxes $4,161,547 $4,334,671
---------- ----------
</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, 1995 1994 1993
---- ---- ----
<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) 4.8 8.3 6.5
Effect of regulatory
treatment of
depreciation
differences 3.2 3.7 4.5
Tax credits--net (.8) (1.1) (1.0)
Other--net (2.1) (.5) .8
---- ---- ----
Effective tax rate 40.1% 45.4% 45.8%
---- ---- ----
</TABLE>
NOTE 12: COMMITMENTS
CAPITAL PROJECTS: Capital expenditures for 1996 are estimated to be
approximately $1,489 million, consisting of $1,291 million for utility
expenditures, $36 million for Diablo Canyon expenditures and $162 million for
expenditures from diversified operations.
At December 31, 1995, Enterprises had firm commitments totaling $143 million
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 $114 million in 1996 and $29 million in 1997.
QUALIFYING FACILITIES: Under the Public Utility Regulatory Policies Act of 1978,
PG&E is required to purchase electric energy and capacity provided by QFs. The
CPUC established a series of power purchase agreements which set the applicable
terms, conditions and price options. The total cost of
47
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PACIFIC GAS AND ELECTRIC COMPANY
prudently incurred energy and capacity payments to QFs is recoverable in rates.
PG&E's contracts with QFs expire on various dates from 1996 to 2026. Under these
contracts, PG&E is required to make payments only when energy is supplied or
when capacity commitments are met. Payments to QFs are expected to vary in
future years, with a decline in payments expected in the years 1998 through 2000
under the terms of the QF contracts.
In 1995 and 1994, PG&E negotiated early termination or suspension of certain
QF contracts at a cost of $142 million and $155 million, respectively, to be
paid through 1999. These amounts are expected to be recovered in rates. At
December 31, 1995, $159 million remained to be paid to QFs for early termination
or suspension.
QF deliveries in the aggregate account for approximately 20 percent of
PG&E's 1995 electric energy requirements, and no single contract accounted for
more than 5 percent of PG&E's energy needs. QF deliveries in 1995 represented
approximately 83 percent of the QFs' plant output, in the aggregate. The amount
of energy received from QFs and the total energy and capacity payments made
under these agreements were:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, 1995 1994 1993
------- ------- -------
(IN MILLIONS)
<S> <C> <C> <C>
Kilowatt-hours received 20,496 21,699 21,242
Energy payments $ 1,140 $ 1,196 $ 1,099
Capacity payments $ 484 $ 518 $ 503
</TABLE>
OTHER POWER PURCHASES: PG&E has contracts with various irrigation districts and
water agencies to purchase hydroelectric power. The contracts expire on various
dates from 2004 to 2031. 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. Additional variable
payments for operation and maintenance costs incurred by the providers are also
required to be made under the contracts. The total cost of these payments is
recoverable in rates. At December 31, 1995, the undiscounted future minimum
payments under these contracts are $34 million for each of the years 1996
through 2000 and a total of $417 million for periods thereafter. Total payments
under these contracts were $50 million, $49 million and $45 million in 1995,
1994 and 1993, respectively.
NOTE 13: CONTINGENCIES
NUCLEAR INSURANCE: PG&E is a member of Nuclear Mutual Limited (NML) and Nuclear
Electric Insurance Limited (NEIL). Under these policies, if the nuclear
generating facility of a member utility suffers a property damage loss or a
business interruption loss due to a prolonged accidental outage, PG&E may be
subject to maximum assessments of $26 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.
Federal law requires all utilities with nuclear generating facilities to
share in payment for claims resulting from a nuclear incident and limits
industry liability for third-party claims to $8.9 billion per incident. Coverage
of the first $200 million is provided by a pool of commercial insurers. 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 records its environmental liabilities
when site assessments and/or remedial actions are 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,
48
<PAGE>
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 probable amount, the Company
records the lower end of this reasonably likely range of costs (classified as
other noncurrent liabilities). The Company may be required to pay for remedial
action at sites where the Company has been or may be a potentially responsible
party under the Comprehensive Environmental Response, Compensation and Liability
Act (CERCLA; federal Superfund law) or the California Hazardous Substance
Account Act (California Superfund law). 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 substances.
Under CERCLA, the Company's financial responsibilities may include remediation
of hazardous wastes, even if the Company did not deposit those wastes on the
site.
The overall costs of the hazardous materials and hazardous waste compliance
and remediation activities ultimately undertaken by the Company are difficult to
estimate, and 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, 1995, of $122
million for hazardous waste remediation costs at those sites where such costs
are probable and quantifiable. The costs may be as much as $287 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, 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.
The Company will seek recovery of prudently incurred hazardous waste
compliance and remediation costs through ratemaking procedures approved by the
CPUC, through insurance and through other recoveries from third-parties. While
the Company has numerous insurance policies that it believes may provide
coverage for some of these liabilities, it does not recognize insurance or
third-party recoveries in its financial statements until they are realized. 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 book value of $631 million at
December 31, 1995. As part of the 1996 GRC decision in December 1995, the CPUC
directed PG&E to perform a cost-effectiveness study of Helms, to be submitted in
July 1996. The study will consider changes in rate recovery for the plant which
will include, among other things, the option of retirement with recovery of the
investment without a return.
PG&E is currently unable to predict whether there will be a change in rate
recovery resulting from the study. 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.
49
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PACIFIC GAS AND ELECTRIC COMPANY
LEGAL MATTERS:
STANISLAUS LITIGATION: A lawsuit was filed by the County of Stanislaus,
California, and a residential customer of PG&E, 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 lawsuit alleged that the purchase of natural gas in
Canada by Alberta and Southern Gas Co. Ltd., a subsidiary of PG&E, was
accomplished in violation of various antitrust laws and sought damages of as
much as $950 million, before trebling.
In December 1995, a federal district court dismissed the lawsuit. The
plaintiffs have the right to appeal the dismissal to 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.
HINKLEY LITIGATION: In 1993, a complaint was filed in a state superior court on
behalf of individuals seeking recovery of an unspecified amount of damages for
personal injuries and property damage allegedly suffered as a result of exposure
to chromium near PG&E's Hinkley Compressor Station, as well as punitive damages.
The original complaint has been amended, and additional complaints have been
filed to include additional plaintiffs.
The plaintiffs contend that PG&E discharged chromium-contaminated wastewater
into unlined ponds to avoid costly alternatives, which led to chromium
percolating into the groundwater of surrounding property.
PG&E has reached an agreement with plaintiffs pursuant to which those
plaintiffs' actions will be submitted to binding arbitration for resolution of
issues concerning the cause and extent of any damages suffered by plaintiffs as
a result of the alleged chromium contamination. Under the terms of the
agreement, PG&E will pay an aggregate amount of no more than $400 million in
settlement of such plaintiffs' claims. In turn, those plaintiffs, and their
attorneys, agree to indemnify PG&E against any additional losses PG&E may incur
with respect to related claims pursued by the identified plaintiffs who do not
agree to this settlement or by other third parties who may be sued by the
plaintiffs in connection with the alleged chromium contamination.
As of December 31, 1995, PG&E has paid $50 million to escrow and recorded an
additional $150 million reserve against any future potential liability in this
case. The Company believes the ultimate outcome of this matter will not have a
material adverse impact on its financial position or results of operations.
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 fees at different
rates from other cities.
In September 1995, the Court certified the class of 107 cities in this
action and approved the City of Santa Cruz as the class representative. In
January 1996, the Court granted PG&E's motion for summary judgment against
certain plaintiffs and various motions effectively eliminating a major portion
of the class action. The Court's rulings do not resolve the case completely.
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 $17 million and damages for alleged underpayments for
the years 1987 to 1995 could be as much as $131 million (exclusive of interest,
estimated to be $31 million as of December 31, 1995). If the Court's January
1996 rulings become final, PG&E's annual systemwide city electric franchise fees
for the remaining class member cities could increase by approximately $5.3
million and damages for alleged underpayments for the years 1987 to 1995 could
be as much as $39.1 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.
50
<PAGE>
QUARTERLY CONSOLIDATED FINANCIAL DATA (UNAUDITED)
PACIFIC GAS AND ELECTRIC COMPANY
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.
PG&E recorded an increase of $50 million in litigation reserves in the first
and third quarters of 1995.
In the first quarter of 1994, PG&E took a charge against earnings of
approximately $90 million as a result of the CPUC disallowances in the gas
reasonableness proceedings for 1988 through 1990 and PG&E's assessment of open
reasonableness issues. In the second quarter of 1994, PG&E increased its
litigation reserves by $50 million. In the fourth quarter of 1994, PG&E took a
charge against earnings of $249 million related to 1994 workforce reductions.
PG&E's common stock is traded on the New York, Pacific, London, Amsterdam,
Basel and Zurich stock exchanges. There were approximately 220,000 common
shareholders of record at December 31, 1995. Dividends are paid on a quarterly
basis, and there are no significant restrictions on the present ability of PG&E
to pay dividends.
<TABLE>
<CAPTION>
QUARTER ENDED DECEMBER 31 SEPTEMBER 30 JUNE 30 MARCH 31
------------- ------------- ------------- -------------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<S> <C> <C> <C> <C>
1995
Operating revenues(1) $ 2,227,224 $ 2,637,653 $ 2,448,641 $ 2,308,247
Operating income(1) 451,674 781,912 820,370 709,029
Net income 227,085 377,593 405,520 328,687
Earnings per common share(2) .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
1994
Operating revenues(1) $ 2,619,484 $ 2,840,962 $ 2,444,457 $ 2,445,327
Operating income(1) 306,270 889,658 611,901 615,957
Net income 103,500 425,633 241,365 236,952
Earnings per common share(2) .21 .96 .53 .52
Dividends declared per common share .49 .49 .49 .49
Common stock price per share
High 25.25 25.13 29.75 35.00
Low 21.38 22.00 22.50 28.50
</TABLE>
(1) Operating revenues and operating income have been reclassified to conform
with the 1995 presentation of the Statement of Consolidated Income.
(2) Includes Diablo Canyon scheduled refueling outages which impacted earnings
per common share for the fourth quarter in 1995 and all quarters in 1994. In
addition, Diablo Canyon experienced unscheduled outages in the third and
fourth quarters of 1995 and in the second quarter of 1994.
51
<PAGE>
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
PACIFIC GAS AND ELECTRIC COMPANY
TO THE SHAREHOLDERS AND THE BOARD OF DIRECTORS OF PACIFIC GAS AND ELECTRIC
COMPANY:
We have audited the accompanying consolidated balance sheet and the statement of
consolidated capitalization of Pacific Gas and Electric Company (a California
corporation) and subsidiaries as of December 31, 1995 and 1994, 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, 1995.
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 schedule 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 Pacific Gas and Electric Company
and subsidiaries as of December 31, 1995 and 1994, and the results of their
operations and cash flows for each of the three years in the period ended
December 31, 1995, in conformity with generally accepted accounting principles.
ARTHUR ANDERSEN LLP
San Francisco, California
February 12, 1996
52
<PAGE>
RESPONSIBILITY FOR CONSOLIDATED FINANCIAL STATEMENTS
PACIFIC GAS AND ELECTRIC COMPANY
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 have
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,
effective internal controls and unbiased, 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.
53
<PAGE>
Exhibit 23
[LOGO OF ARTHUR ANDERSEN LLP]
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation by
reference of our reports dated February 12, 1996, included or incorporated by
reference in this Form 10-K, into (1) the Company's previously filed
registration statements as follows : (a) Form S-3 Registration Statement File
No. 33-7542 (relating to the Company's Common Stock Shelf Program); (b) Form S-
3 Registration Statement File No. 33-54469 (relating to the Company's Dividend
Reinvestment Plan); (c) Form S-3 Registration Statement File No. 33-64136
(relating to $2,000,000,000 aggregate principal amount of the Company's First
and Refunding Mortgage Bonds and Medium-Term Notes); (d) Form S-3 Registration
Statement File No. 33-50707 (relating to $1,500,000,000 aggregate principal
amount of the Company's First and Refunding Mortgage Bonds); (e) Form S-3
Registration Statement File No. 33-38334 (relating to 2,414,892 shares of the
Company's Common Stock); (f) Form S-8 Registration Statement File No. 33-50601
(relating to the Company's Savings Fund Plan for Employees); (g) Form S-8
Registration Statement File No. 33-23692 (relating to the Company's 1986 Stock
Option Plan); (h) Form S-3 Registration Statement File No. 33-62488 (relating
to 10,000,000 shares of the Company's Redeemable First Preferred Stock); and (i)
Form S-3 Registration Statement File No. 33-61959 (relating to $335,000,000
aggregate liquidation value of Cumulative Quarterly Income Preferred
Securities); and (2) the PG&E Parent Co., Inc.'s previously filed Form S-4
Registration Statement File No. 333-01103 (relating to 430,000,000 shares of
common stock of PG&E Parent Co., Inc.).
Arthur Andersen LLP
San Francisco, California
March 29, 1996
<PAGE>
RESOLUTION OF THE
-----------------
BOARD OF DIRECTORS OF
---------------------
PACIFIC GAS AND ELECTRIC COMPANY
--------------------------------
March 20, 1996
--------------
BE IT RESOLVED that each of LESLIE H. EVERETT, 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, Senior Vice President and Chief Financial
Officer, and principal accounting officer of this corporation the Form 10-K
Annual Report for the year ended December 31, 1995, 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 dully 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 March 20,
1996, 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
29th day of March, 1996.
KATHLEEN RUEGER
Kathleen Rueger
Assistant Corporate Secretary
PACIFIC GAS AND ELECTRIC COMPANY
CORPORATE SEAL
<PAGE>
POWER OF ATTORNEY
Each of the undersigned Directors of Pacific Gas and Electric Company
hereby constitutes and appoints LESLIE H. EVERETT, ERIC MONTIZAMBERT, KATHLEEN
RUEGER, GARY P. ENCINAS or JULIE C. GAVIN 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, 1995, 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 20th day of March,
1996.
Stanley T. Skinner Rebecca Q. Morgan
_______________________________ ______________________________
Robert D. Glynn, Jr. C. Lee Cox
_______________________________ ______________________________
Richard A. Clarke Alan Seelenfreund
_______________________________ ______________________________
H.M. Conger Samuel T. Reeves
_______________________________ ______________________________
Mary S. Metz Carl E. Reichardt
_______________________________ ______________________________
John C. Sawhill Barry Larson Williams
_______________________________ ______________________________
William S. Davila Richard B. Madden
_______________________________ ______________________________
David M. Lawrence
_______________________________
<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, ERIC MONTIZAMBERT, KATHLEEN RUEGER, GARY P. ENCINAS
or JULIE C. GAVIN 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, 1995,
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 20th day of
March, 1996.
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, ERIC MONTIZAMBERT, KATHLEEN RUEGER, GARY P. ENCINAS
or JULIE C. GAVIN his attorneys in fact with full power of substitution to sign
and file with the Securities and Exchange Commission in his capacities as Senior
Vice President and Chief Financial Officer (principal financial officer) and
principal accounting officer of said corporation the Form 10-K Annual Report for
the year ended December 31, 1995, 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 20th day of
March, 1996.
GORDON R. SMITH
______________________________
GORDON R. SMITH
<PAGE>
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
--------
INFORMATION REQUIRED BY
FORM 11-K
ANNUAL REPORT
PURSUANT TO SECTION 15 (d) OF THE
SECURITIES EXCHANGE ACT OF 1934
for fiscal year ended December 31, 1995
A. Full title of the plan and the address of the
plan, if different from that of the issuer named below:
SAVINGS FUND PLAN FOR EMPLOYEES OF
PACIFIC GAS AND ELECTRIC COMPANY
B. Name of issuer of the securities held pursuant to
the plan and the address of its principal executive office:
PACIFIC GAS AND ELECTRIC COMPANY
77 Beale Street
P.O. Box 770000
San Francisco, CA 94177
<PAGE>
The financial statements of the Savings Fund Plan Master Trust and the
Savings Fund Plan Parts I and II as of December 31, 1995 and 1994, the
statements of net assets as of December 31, 1995 and 1994, the related
statements of changes in the net assets of the Plans for the year ended December
31, 1995, and the Savings Fund Plan Master Trust schedule of assets held for
investment purposes as of December 31, 1995 and schedule of reportable
transactions for the year ended December 31, 1995, together with the reports
of Arthur Andersen LLP, independent accountants, are presented herewith.
<PAGE>
[LETTERHEAD OF ARTHUR ANDERSEN LLP]
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Employee Benefit Finance Committee
of Pacific Gas and Electric Company and
Participants in the Savings Fund Plans:
We have audited the accompanying statements of net assets of Pacific Gas and
Electric Company Savings Fund Plan Master Trust (the Trust) as of December 31,
1995 and 1994, and the related statement of changes in net assets for the year
ended December 31, 1995. These financial statements and the schedules referred
to below are the responsibility of the Trust's management. Our responsibility
is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
The accompanying statements are those of the Trust established under the Pacific
Gas and Electric Company Savings Fund Plan Master Trust. These statements do
not purport to present the financial statements of the individual employee
benefit plans and do not contain disclosures necessary for a fair presentation
of the financial statements of the individual employee benefit plans in
conformity with generally accepted accounting principles. Furthermore, these
statements do not purport to satisfy the Department of Labor's Rules and
Regulations for Reporting and Disclosure under the Employee Retirement Income
Security Act of 1974 relating to financial statements of employee benefit plans.
Reference should be made to the Form 5500s and related financial statements of
the individual employee benefit plans that have been prepared and filed pursuant
to these reporting rules and regulations.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the net assets of the Trust as of December 31, 1995 and
1994, and the changes in net assets for the year ended December 31,1995, in
conformity with generally accepted accounting principles.
Our audits were made of the purpose of forming an opinion on the basic financial
statements taken as a whole. The supplemental schedules of assets held for
investment purposes as of December 31, 1995, and reportable transactions for the
year ended December 31, 1995, are presented for purposes of additional analysis
and are not a required part of the basic financial statements but are
supplementary information required by the Department of Labor's Rules and
Regulations for Reporting and Disclosure under the Employee Retirement Income
Security Act of 1974. The fund information in the statements of net assets and
changes in net assets is presented for purposes of additional analysis rather
than to present the net assets and changes in net assets of each fund. The
supplemental schedules and fund information have been subjected to the auditing
procedures applied in the audit of the basic financial statements and, in our
opinion, are fairly stated in all material respects in relation to the basic
financial statements taken as a whole.
/s/ Arthur Andersen LLP
San Francisco, California,
March 5, 1996
<PAGE>
[LETTERHEAD OF ARTHUR ANDERSEN LLP]
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Employee Benefit Finance Committee
of Pacific Gas and Electric Company and
Participants in the Savings Fund Plan:
We have audited the accompanying statements of net assets available for benefits
of Pacific Gas and Electric Company Savings Fund Plan - Part I (the Plan) as of
December 31, 1995 and 1994, and the related statement of changes in net assets
available for benefits for the year ended December 31, 1995. These financial
statements are the responsibility of the Plan's management. Our responsibility
is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the net assets available for benefits of the Plan as of
December 31, 1995 and 1994, and the changes in its net assets available for
benefits for the year ended December 31, 1995, in conformity with generally
accepted accounting principles.
/s/ Arthur Andersen LLP
San Francisco, California,
March 5, 1996
<PAGE>
[LETTERHEAD OF ARTHUR ANDERSEN LLP]
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Employee Benefit Finance Committee
of Pacific Gas and Electric Company and
Participants in the Savings Fund Plan:
We have audited the accompanying statements of net assets available for benefits
of Pacific Gas and Electric Company Savings Fund Plan - Part II (the Plan) as of
December 31, 1995 and 1994, and the related statement of changes in net assets
available for benefits for the year ended December 31, 1995. These financial
statements are the responsibility of the Plan's management. Our responsibility
is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the net assets available for benefits of the Plan as of
December 31, 1995 and 1994, and the changes in its net assets available for
benefits for the year ended December 31, 1995, in conformity with generally
accepted accounting principles.
/s/ Arthur Andersen LLP
San Francisco, California,
March 5, 1996
<PAGE>
PACIFIC GAS AND ELECTRIC COMPANY
SAVINGS FUND PLAN MASTER TRUST
FINANCIAL STATEMENTS
TABLE OF CONTENTS
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
FINANCIAL STATEMENTS
Statements of Net Assets - December 31, 1995 and 1994
Statement of Changes in Net Assets for the Year Ended December 31, 1995
Notes to Financial Statements - December 31, 1995
SCHEDULES
Schedule I: Item 27(a) - Schedule of Assets Held for Investment Purposes -
December 31, 1995
Schedule II: Item 27(d) - Schedule of Reportable Transactions for the Year
Ended December 31, 1995
<PAGE>
PACIFIC GAS AND ELECTRIC COMPANY
SAVINGS FUND PLAN MASTER TRUST
STATEMENT OF NET ASSETS
December 31, 1995
<TABLE>
<CAPTION>
Fund Information
----------------------------------------------------------------------------------
United
Company States Diversified Guaranteed Bond Stock and Utility
Stock Bond Equity Income Index Bond Stock
Fund Fund Fund Fund Fund Fund Fund Total
---------- ---------- ---------- ---------- ---------- ---------- ---------- ----------
-----------------------------------------In Thousands-----------------------------------------
<C> <C> <C> <C> <C> <C> <C> <C>
ASSETS
Investments, at fair value
Pacific Gas and Electric
Company - common stock $1,161,205 $ - $ - $ - $ - $ - $ - $1,161,205
United States government
securities - 4,424 1,042 - - - - 5,466
Corporate stocks - common - - 503,528 - - - - 503,528
Corporate debt instruments - - - 63,540 - - - 63,540
Insurance company general accounts - - - 146,976 - - - 146,976
Registered investment companies
Vanguard Bond Market Fund - - - - 26,394 - - 26,394
Columbia Balanced Fund - - - - - 127,992 - 127,992
Dreyfus Utility Stock Fund - - - - - - 49,284 49,284
Interest bearing accounts 25,082 - 20,205 10,297 - - - 55,584
---------- ---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Investments 1,186,287 4,424 524,775 220,813 26,394 127,992 49,284 2,139,969
---------- ---------- ---------- ---------- ---------- ---------- ---------- ----------
Receivables
Dividends and interest 20,369 - 1,137 1,051 141 - - 22,698
Other receivables 3,354 - 22 8 - - - 3,384
---------- ---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Receivables 23,723 - 1,159 1,059 141 - 0 26,082
---------- ---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Assets 1,210,010 4,424 525,934 221,872 26,535 127,992 49,284 2,166,051
---------- ---------- ---------- ---------- ---------- ---------- ---------- ----------
LIABILITIES - - - - - - - -
---------- ---------- ---------- ---------- ---------- ---------- ---------- ----------
NET ASSETS $1,210,010 $4,424 $525,934 $221,872 $26,535 $127,992 $49,284 $2,166,051
========== ========== ========== ========== ========== ========== ========== ==========
</TABLE>
The accompanying Notes to Financial Statements are an integral part of these
statements.
1
<PAGE>
PACIFIC GAS AND ELECTRIC COMPANY
SAVINGS FUND PLAN MASTER TRUST
STATEMENT OF NET ASSETS
December 31, 1994
<TABLE>
<CAPTION>
Fund Information
----------------------------------------------------------------------------------
United
Company States Diversified Guaranteed Bond Stock and Utility
Stock Bond Equity Income Index Bond Stock
Fund Fund Fund Fund Fund Fund Fund Total
---------- ---------- ---------- ---------- ---------- ---------- ---------- ----------
-----------------------------------------In Thousands-----------------------------------------
<C> <C> <C> <C> <C> <C> <C> <C>
ASSETS
Investments, at fair value
Pacific Gas and Electric
Company - common stock $1,131,413 $ - $ - $ - $ - $ - $ - $1,131,413
United States government
securities - 4,616 553 - - - - 5,169
Corporate stocks - preferred - - 1,048 - - - - 1,048
Corporate stocks - common - - 340,032 - - - - 340,032
Corporate debt instruments - - - 53,210 - - - 53,210
Insurance company general
accounts - - - 151,704 - - - 151,704
Registered investment companies
Vanguard Bond Market Fund - - - - 23,632 - - 23,632
Columbia Balanced Fund - - - - - 102,861 - 102,861
Dreyfus Utility Stock Fun - - - - - - 45,458 45,458
Interest bearing accounts 163 - 12,254 60,228 - - - 72,645
---------- ---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Investments 1,131,576 4,616 353,887 265,142 23,632 102,861 45,458 1,927,172
---------- ---------- ---------- ---------- ---------- ---------- ---------- ----------
Receivables
Dividends and interest 22,830 - 993 2,560 138 - 844 27,365
Other receivables - - 6,293 - - - - 6,293
---------- ---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Receivables 22,830 - 7,286 2,560 138 - 844 33,658
---------- ---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Assets 1,154,406 4,616 361,173 267,702 23,770 102,861 46,302 1,960,830
---------- ---------- ---------- ---------- ---------- ---------- ---------- ----------
LIABILITIES 36 - 11,371 - - - - 11,407
---------- ---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Liabilities 36 - 11,371 - - - - 11,407
---------- ---------- ---------- ---------- ---------- ---------- ---------- ----------
NET ASSETS $1,154,370 $4,616 $349,802 $267,702 $23,770 $102,861 $46,302 $1,949,423
========== ========== ========== ========== ========== ========== ========== ==========
</TABLE>
The accompanying Notes to Financial Statements are an integral part of these
statements.
2
<PAGE>
PACIFIC GAS AND ELECTRIC COMPANY
SAVINGS FUND PLAN MASTER TRUST
STATEMENT OF CHANGES IN NET ASSETS
For the Year Ended December 31, 1995
<TABLE>
<CAPTION>
Fund Information
----------------------------------------------------------------------------------
United
Company States Diversified Guaranteed Bond Stock and Utility
Stock Bond Equity Income Index Bond Stock
Fund Fund Fund Fund Fund Fund Fund Total
---------- ---------- ---------- ---------- ---------- ---------- ---------- ----------
-----------------------------------------In Thousands-----------------------------------------
<C> <C> <C> <C> <C> <C> <C> <C>
BALANCE, JANUARY 1, 1995 $1,154,370 $4,616 $349,802 $267,702 $23,770 $102,861 $46,302 $1,949,423
---------- ---------- ---------- ---------- ---------- ---------- ---------- ----------
ADDITIONS
Participating plans contributions
Participant 43,443 - 24,255 5,292 1,121 5,960 2,799 82,870
Employer 16,636 - 7,399 1,692 403 2,019 878 29,027
---------- ---------- ---------- ---------- ---------- ---------- ---------- ----------
Total participating plans
contributions 60,079 - 31,654 6,984 1,524 7,979 3,677 111,897
---------- ---------- ---------- ---------- ---------- ---------- ---------- ----------
Earnings from investments
Interest
Interest bearing accounts 2,154 - 764 719 - - - 3,637
United States government
securities - 63 - - - - - 63
Fixed income investments - - - 11,386 - - - 11,386
---------- ---------- ---------- ---------- ---------- ---------- ---------- ----------
Total interest 2,154 63 764 12,105 - - - 15,086
Dividends - common stock 82,251 - 10,154 - - - - 92,405
Registered investment company
dividends - - - - 1,604 - 2,457 4,061
Other income - - 38 2 - - - 40
---------- ---------- ---------- ---------- ---------- ---------- ---------- ----------
Total earnings
from investments 84,405 63 10,956 12,107 1,604 - 2,457 111,592
---------- ---------- ---------- ---------- ---------- ---------- ---------- ----------
Net appreciation in fair value
of assets held 169,483 - 124,845 - 2,378 24,065 8,914 329,685
---------- ---------- ---------- ---------- ---------- ---------- ---------- ----------
Total additions 313,967 63 167,455 19,091 5,506 32,044 15,048 553,174
---------- ---------- ---------- ---------- ---------- ---------- ---------- ----------
</TABLE>
The accompanying Notes to Financial Statements are an integral part of these
statements.
3
<PAGE>
PACIFIC GAS AND ELECTRIC COMPANY
SAVINGS FUND PLAN MASTER TRUST
STATEMENT OF CHANGES IN NET ASSETS (Continued)
For the Year Ended December 31, 1995
<TABLE>
<CAPTION>
Fund Information
----------------------------------------------------------------------------------
United
Company States Diversified Guaranteed Bond Stock and Utility
Stock Bond Equity Income Index Bond Stock
Fund Fund Fund Fund Fund Fund Fund Total
---------- ---------- ---------- ---------- ---------- ---------- ---------- ----------
-----------------------------------------In Thousands-----------------------------------------
<C> <C> <C> <C> <C> <C> <C> <C>
DEDUCTIONS
Withdrawals paid to participating
plans for benefit payments $151,802 $228 $40,527 $95,573 $3,438 $13,328 $6,146 $311,042
Transfer to separate plan -
PGT members 11,170 27 6,252 3,164 742 1,682 2,467 25,504
---------- ---------- ---------- ---------- ---------- ---------- ---------- ----------
Total deductions 162,972 255 46,779 98,737 4,180 15,010 8,613 336,546
---------- ---------- ---------- ---------- ---------- ---------- ---------- ----------
TRANSFERS between investment
funds (95,355) - 55,456 33,816 1,439 8,097 (3,453) -
---------- ---------- ---------- ---------- ---------- ---------- ---------- ----------
CHANGE IN NET ASSETS 55,640 (192) 176,132 (45,830) 2,765 25,131 2,982 216,628
---------- ---------- ---------- ---------- ---------- ---------- ---------- ----------
BALANCE, DECEMBER 31, 1995 $1,210,010 $4,424 $525,934 $221,872 $26,535 $127,992 $49,284 $2,166,051
========== ========== ========== ========== ========== ========== ========== ==========
</TABLE>
The accompanying Notes to Financial Statements are an integral part of these
statements.
4
<PAGE>
PACIFIC GAS AND ELECTRIC COMPANY
SAVINGS FUND PLAN MASTER TRUST
NOTES TO FINANCIAL STATEMENTS
December 31, 1995
NOTE 1: Master Trust Description
The Pacific Gas and Electric company established the Savings Fund Plan
Master Trust (the Master Trust) on January 1, 1988 to hold the assets of the
Pacific Gas and Electric Company (the Company) Savings Fund Plans. Pacific
Service Employees Association also participates in the Master Trust. The Master
Trust is administered by Pacific Gas and Electric Companys Employee Benefit
Administrative Committee and Employee Benefit Finance Committee, and State
Street Bank and Trust Company is the trustee (the Trustee).
Interest income, dividends, investment fees, and the net appreciation or
depreciation in the fair value of investments held by the Master Trust are
allocated to the individual participating plans each day based upon their
proportional share of the individual fund balances.
Although the Company has not expressed any intent to do so, its Board of
Directors reserves the right to amend or terminate the Master Trust at any time
by giving written notice to the Trustee. If the Master Trust is terminated, the
Master Trust assets shall be paid out to each separate participating plan in
proportion to its interest in the Master Trust.
As of January 1, 1995, Pacific Gas Transmission Company (PGT), a subsidiary
of the Company, formed a separate savings fund plan on behalf of its employees.
Accordingly, these participants no longer participate in the Companys Master
Trust. During January 1995, $25.5 million of net assets relating to PGT
participants were transferred to a separate plan.
NOTE 2: Summary of Significant Accounting Policies
Basis of Accounting
The financial statements of the Master Trust are prepared in conformity
with generally accepted accounting principles. The preparation of financial
statements in conformity with generally accepted accounting principles requires
management to make estimates and assumptions that affect the reported amounts of
assets and liabilities and disclosure of contingent assets and liabilities at
the date of the financial statements and the reported amounts of revenues and
expenses during the reporting period. Actual results could differ from those
estimates. These financial statements do not purport to present the net assets
available for benefits or the change in net assets available for benefits of any
of the individual participating retirement plans and do not include all
disclosures necessary for a fair presentation of the financial statements of the
individual participating plans in conformity with generally accepted accounting
principles.
NOTE 3: Federal Income Taxes
The Company received favorable tax determination letters from the Internal
Revenue Service (IRS) in November of 1995, and the IRS has ruled that the Master
Trust is exempt under Section 501(a). Accordingly, no provision for federal
income taxes has been made in the financial statements. The
5
<PAGE>
PACIFIC GAS AND ELECTRIC COMPANY
SAVINGS FUND PLAN MASTER TRUST
NOTES TO FINANCIAL STATEMENTS
December 31, 1995
NOTE 3: Federal Income Taxes (Continued)
Plan sponsor believes that the Plan continues to be designed and operated in
accordance with IRS requirements.
NOTE 4: Investments
The Trustee invests a significant portion of the contributions from the
participating plans in the common stock of the Company. In 1995, purchases of
this stock were made on the open market, while in previous years these stock
purchases were made directly from the Company. The Company pays all costs of
administering the Master Trust, including fees and expenses of the Trustee.
However, customary brokerage fees and commissions due to transfers, withdrawals,
and distributions are paid by the plans. The Company pays investment management
fees for the Diversified Equity Fund and the Guaranteed Income Fund.
Individual plan participants designate the way in which their contributions
are invested and may change their investment designation at any time.
Participants may elect to have their contributions invested in one or more of
the following funds:
- Company Stock Fund, invested in Pacific Gas and Electric
Company common stock;
- Diversified Equity Fund (DEF), invested in a diversified
portfolio of common stock of other companies;
- Guaranteed Income Fund (GIF), invested in contracts which
offer a fixed rate of interest for a specified period of
time;
- Bond Index Fund (BIF), invested in Vanguard Bond Market Fund,
a diversified portfolio consisting of marketable
fixed-income securities;
- Stock and Bond Fund (SBF), invested in Columbia Balanced
Fund, a diversified portfolio of marketable equity
securities and marketable fixed-income securities.
- Utility Stock Fund (USF), invested in Dreyfus Utility Stock
Fund, a portfolio of marketable equity securities of electric
utility companies that are members of the Edison Electric
Institute, including Pacific Gas and Electric Company.
A participants interest in the investment funds is represented by
participation units allocated on the basis of contributions and assigned a unit
value on the basis of the total value in each fund. The Company Stock Fund and
the Guaranteed Income Fund converted to unitization in April 1995 to accommodate
daily valuation. For investments in the United States Savings Bond Fund , a
unit is one bond.
6
<PAGE>
PACIFIC GAS AND ELECTRIC COMPANY
SAVINGS FUND PLAN MASTER TRUST
NOTES TO FINANCIAL STATEMENTS
December 31, 1995
NOTE 4: Investments (Continued)
Valuation of Investments
All investments (other than GIF) held by the Master Trust are stated at
fair value based on published market quotations. Investments in the GIF are
valued at cost which approximates fair value.
The net appreciation in fair value of investments in the accompanying
statement of changes in net assets reflects the net difference between fair
value and cost of investments bought during the year and the net difference
between fair value and the beginning of the year fair value of the assets held,
sold or distributed.
The net appreciation in the fair value of investments by major investment
category for the year ended December 31, 1995 is as follows:
<TABLE>
<CAPTION>
--- In Thousands ---
<S> <C>
Pacific Gas and Electric Company
Common Stock Fund $169,483
DEF 124,845
BIF 2,378
SBF 24,065
USF 8,914
--------
Total appreciation $329,685
========
</TABLE>
Financial Investments with Off-Balance Sheet Risk
The Employee Benefit Finance Committee has adopted a Position Statement on
Risk Management and the Use of Derivatives which applies to the Master Trust.
This statement recognizes that derivatives may be used by the Master Trusts
investment managers to achieve their investment objectives. However, the Master
Trust assets will not be exposed to risks via derivatives that would be
inappropriate in their absence. J.P. Morgan, the investment manager for the
DEF, uses S&P 500 index futures contracts to maintain unleveraged stock market
exposure while providing the liquidity necessary to accommodate participant
cashflows.
J.P. Morgan routinely enters into unleveraged Standard and Poors (S&P)
futures contracts for trading purposes. A margin position is taken on these
contracts on a daily basis, with a resulting appreciation or depreciation in the
fair value of assets held. As of December 31, 1995, there were 61 S&P 500 index
futures contracts valued at approximately $19 million, with settlement dates
from March 14 through March 16, 1996. The net appreciation recorded as of
December 31, 1995 on these contracts was approximately $133,000. The collateral
(included in interest bearing accounts) with respect to these contracts
consisted of a $500,000 U.S. treasury bill which will mature on April 4, 1996,
and a $550,000 U.S. treasury bill which matured on January 11, 1996. The U.S
treasury bill which matured in January
7
<PAGE>
PACIFIC GAS AND ELECTRIC COMPANY
SAVINGS FUND PLAN MASTER TRUST
NOTES TO FINANCIAL STATEMENTS
December 31, 1995
NOTE 4: Investments (Continued)
1996 was rolled over to a new $500,000 U.S. treasury bill that will mature on
April 4, 1996.
NOTE 5: Subsequent Event
The market price of Pacific Gas and Electric Company common stock declined
by 7.9% between December 31, 1995 and March 5, 1996. This represents a decrease
of approximately $92 million in the fair value of the Company Stock Fund.
8
<PAGE>
SAVINGS FUND PLAN
FOR EMPLOYEES OF PACIFIC GAS AND ELECTRIC COMPANY
ITEM 27a - SCHEDULE OF ASSETS HELD FOR INVESTMENT PURPOSES
December 31, 1995
<TABLE>
<CAPTION>
NUMBER OF SHARES
OR U.S. SAVINGS
BONDS HELD AT
NAME OF ISSUER AND DESCRIPTION CLOSE OF PERIOD COST CURRENT VALUE
- -------------------------------------------------------------------------------------------------------------
--------IN THOUSANDS-------
<S> <C> <C> <C> <C> <C>
PACIFIC GAS + ELECTRIC COMPANY
*COMMON STOCK FUND 40,923,522 $970,185 $1,161,205
INTEREST BEARING ACCOUNTS
*STATE STREET BANK & TRUST CO 24,827,309 24,827 24,827
*STATE STREET BANK & TRUST CO 254,981 255 255
------------ ------------ ------------
TOTAL PACIFIC GAS AND ELECTRIC
COMPANY COMMON STOCK 66,005,812 $995,267 $1,186,287
============ ============ ============
UNITED STATES BOND FUND
UNITED STATES SAVINGS BONDS, SERIES E
(UNITS OF $18.75 COST AND $25.00 MATURITY) 5,927 111 425
UNITED STATES SAVINGS BONDS, SERIES EE
(UNITS OF $25.00 COST AND $50.00 MATURITY) 82,183 2,055 3,397
UNITED STATES SAVINGS BONDS, SERIES E
(UNITS OF $50.00 COST AND $100.00 MATURITY) 9,245 462 602
------------ ------------ ------------
TOTAL UNITED STATES BOND FUND 97,355 $2,628 $4,424
============ ============ ============
DIVERSIFIED EQUITY FUND
ABBOTT LABS 26,300 749 1,098
ADOBE SYS INC 6,500 361 403
ADVANCED MICRO DEVICES INC 14,600 498 241
AETNA LIFE + CAS CO 12,300 573 852
AHMANSON H F AND CO 13,600 221 360
AIR PRODS + CHEMS INC 5,900 312 311
AIRTOUCH COMMUNICATIONS INC 84,800 2,283 2,396
ALBEMARLE CORP 10,500 144 203
ALLEGHENY LUDLUM CORP 14,200 255 263
ALLEGHENY POWER SYSTEMS INC 14,500 352 415
ALLIED SIGNAL INC 84,000 2,729 3,990
ALLSTATE CORP 51,400 1,814 2,114
ALTERA CORP 7,300 335 363
ALUMINUM CO AMER 53,000 1,778 2,802
ALZA CORP 12,300 402 304
AMBAC INC 4,000 167 188
AMERICAN ELEC PWR INC 1,400 45 57
AMERICAN GEN CORP 24,900 741 869
AMERICAN HOME PRODUCTS CORP 59,400 4,098 5,762
AMERICAN INTL GROUP INC 62,200 3,320 5,754
AMERITECH CORP 17,800 507 1,050
AMOCO CORP 19,000 1,001 1,366
AMP INC 36,600 1,360 1,405
AMR CORP DEL 11,000 654 817
ANADARKO PETE CORP 9,400 369 509
ANHEUSER BUSCH COS INC 47,700 2,640 3,190
APPLE COMPUTER 15,300 617 488
APRIA HEALTHCARE GROUP INC 14,200 348 401
ASHLAND INC 9,700 329 341
</TABLE>
9
<PAGE>
SAVINGS FUND PLAN
FOR EMPLOYEES OF PACIFIC GAS AND ELECTRIC COMPANY
ITEM 27a - SCHEDULE OF ASSETS HELD FOR INVESTMENT PURPOSES
December 31, 1995
<TABLE>
<CAPTION>
NUMBER OF SHARES
OR U.S. SAVINGS
BONDS HELD AT
NAME OF ISSUER AND DESCRIPTION CLOSE OF PERIOD COST CURRENT VALUE
- -------------------------------------------------------------------------------------------------------------
--------IN THOUSANDS-------
<S> <C> <C> <C> <C> <C>
AT + T CORP 211,200 10,424 13,675
ATLANTIC RICHFIELD CO 33,200 3,530 3,677
AUTODESK INCORPORATED 6,900 250 237
AVNET INC 2,900 131 130
AVON PRODS INC 13,600 806 1,025
BAKER HUGHES INC 29,200 571 712
BALTIMORE GAS + ELEC CO 17,800 402 507
BANC ONE CORP 55,400 1,738 2,092
BANK NEW YORK INC 27,000 1,061 1,316
BANK OF BOSTON CORP 13,100 434 606
BANK SOUTH CORP 29,600 866 899
BANKAMERICA CORP 56,600 2,732 3,665
BANKERS TR NY CORP 12,800 831 851
BARD C R INC 9,300 258 300
BARNETT BKS INC 13,200 636 779
BAUSCH + LOMB INC 11,800 493 468
BAXTER INTL INC 67,800 1,992 2,839
BAY NETWORKS INC 24,300 616 999
BAYBANKS INC 3,100 290 305
BEAR STEARNS COS INC 15,300 303 304
BELL ATLANTIC CORP 57,500 3,131 3,846
BELLSOUTH CORP 91,000 2,548 3,959
BENEFICIAL CORP 7,000 354 326
BETHLEHAM STL CORP 13,900 250 195
BLACK + DECKER CORPORATION 47,200 854 1,664
BOEING CO 72,100 3,455 5,651
BOISE CASCADE CORP 9,300 385 322
BOWATER INC 7,500 370 266
BOYD GAMING CORP 6,900 113 80
BRINKER INTL INC 15,700 334 238
BRISTOL MYERS SQUIBB CO 20,600 1,276 1,769
BRODERBUND SOFTWARE INC 900 65 55
BROWNING FERRIS INDS INC 92,800 2,743 2,738
BURLINGTON NORTHN SANTA FE 18,900 1,226 1,474
CAMPBELL SOUP CO 39,800 1,835 2,388
CARNIVAL CORP 28,500 557 695
CATERPILLAR INC 52,100 1,476 3,061
CENTRAL + SOUTH WEST CORP 22,500 496 627
CHAMPION INTL CORP 20,600 1,056 865
CHASE MANHATTAN CORP 25,700 1,546 1,558
CHEMICAL BKG CORP 31,100 1,318 1,827
CHEVRON CORP 119,900 5,136 6,295
CHRYSLER CORP 29,701 1,473 1,645
CHUBB CORP 9,600 838 929
CIGNA CORP 9,000 736 929
CINERGY CORP 17,800 454 545
CIRCUS CIRCUS ENTERPRISES INC 21,200 724 591
CITICORP 54,300 1,818 3,652
CMS ENERGY CORP 10,300 232 308
COCA COLA CO 100,700 4,278 7,477
COCA COLA ENTERPRISES INC 20,600 441 551
COLGATE PALMOLIVE CO 25,300 1,699 1,777
COLTEC INDS INC 10,900 218 127
COLUMBIA / HCA HEALTHCARE CORP 97,000 4,100 4,923
COMCAST CORP 32,700 510 595
</TABLE>
10
<PAGE>
SAVINGS FUND PLAN
FOR EMPLOYEES OF PACIFIC GAS AND ELECTRIC COMPANY
ITEM 27a - SCHEDULE OF ASSETS HELD FOR INVESTMENT PURPOSES
December 31, 1995
<TABLE>
<CAPTION>
NUMBER OF SHARES
OR U.S. SAVINGS
BONDS HELD AT
NAME OF ISSUER AND DESCRIPTION CLOSE OF PERIOD COST CURRENT VALUE
- -------------------------------------------------------------------------------------------------------------
--------IN THOUSANDS-------
<S> <C> <C> <C> <C> <C>
COMERICA INC 13,700 418 550
COMPAQ COMPUTER CORP 41,000 1,379 1,968
CONRAIL INC 9,500 506 665
CONSOLIDATED EDISON CO NY INC 31,800 912 1,018
CONSOLIDATED NAT GAS CO 3,700 149 168
COOPER CAMERON CORP 8,781 171 196
COOPER INDS INC 20,800 897 764
COOPER TIRE + RUBBER 9,500 231 234
CORESTATES FINL CORP 19,600 561 742
CPC INTL INC 34,100 1,652 2,340
CRACKER BARREL OLD CTRY STORE 14,300 385 247
CROWN CORK + SEAL INC 43,600 1,665 1,820
CSX CORP 29,600 1,040 1,351
CUMMINS ENGINE INC 2,800 119 104
DANA CORP 14,300 354 418
DAYTON HUDSON CORP 19,800 1,181 1,485
DEAN WITTER DISCOVER + CO 19,400 670 912
DELL COMPUTER CORP 15,400 481 533
DETROIT EDISON CO 22,400 777 773
DISNEY WALT CO 101,800 3,998 6,006
DOMINION RES INC VA 21,100 776 870
DONNELLEY R R + SONS CO 33,500 960 1,319
DOW CHEM CO 40,900 2,503 2,878
DRESSER INDS INC 24,400 571 595
DU PONT E I DE NEMOURS + CO 86,500 4,281 6,044
DURACELL INTL INC 23,200 1,167 1,201
EATON CORP 14,500 644 778
EL PASO NAT GAS CO 4,500 170 128
EMERSON ELEC CO 24,000 1,674 1,962
ENRON CORP 52,300 1,624 1,994
ENTERGY CORP 28,800 902 842
EXIDE CORP 6,700 303 307
EXXON CORP 100,800 5,794 8,077
FEDERAL EXPRESS CORP 5,600 354 414
FEDERAL HOME LN MTG CORP 24,400 1,311 2,037
FEDERAL NATL MTG ASSN 41,300 3,061 5,126
FIRST CHICAGO NBD CORP 44,000 1,274 1,738
FIRST EMPIRE ST CORP 400 69 87
FIRST FIDELITY BANCORP NEW 20,900 1,269 1,575
FIRST INTST BANCORP 2,300 299 314
FIRST TENN NATL CORP 3,900 184 236
FIRST UN CORP 19,800 916 1,101
FIRST USA INC 6,400 220 284
FIRST VA BKS INC 4,100 164 171
FIRSTAR CORP NEW 7,300 228 289
FLEET FINL GROUP INC 43,400 1,324 1,769
FORD MTR CO DEL 138,700 3,272 4,022
FOREST LABS INC 5,800 267 262
FPL GROUP INC 27,000 901 1,252
FREEPORT MCMORAN COPPER + GOLD 24,900 589 700
FRUIT OF THE LOOM INC 19,100 560 466
GATEWAY 2000 INC 10,500 260 257
GENERAL DYNAMICS CORP 9,500 331 562
GENERAL ELEC CO 147,300 6,049 10,606
GENERAL INSTRUMENT CORP 11,700 362 273
</TABLE>
11
<PAGE>
SAVINGS FUND PLAN
FOR EMPLOYEES OF PACIFIC GAS AND ELECTRIC COMPANY
ITEM 27a - SCHEDULE OF ASSETS HELD FOR INVESTMENT PURPOSES
December 31, 1995
<TABLE>
<CAPTION>
NUMBER OF SHARES
OR U.S. SAVINGS
BONDS HELD AT
NAME OF ISSUER AND DESCRIPTION CLOSE OF PERIOD COST CURRENT VALUE
- -------------------------------------------------------------------------------------------------------------
--------IN THOUSANDS-------
<S> <C> <C> <C> <C> <C>
GENERAL MLS INC 5,200 300 300
GENERAL MTRS CORP 99,500 4,018 5,261
GENERAL MTRS CORP 17,700 665 920
GENERAL MTRS CORP 57,500 2,322 2,825
GENERAL PUB UTILS CORP 13,600 370 462
GENERAL SIGNAL CORP 6,900 209 223
GEORGIA GULF CORP 600 16 18
GEORGIA PAC CORP 17,700 1,146 1,215
GILLETTE CO 75,000 2,326 3,909
GOLDEN WEST FINL CORP DEL 4,100 196 227
GOODYEAR TIRE AND RUBBER 20,200 750 917
GRAINGER W W INC 9,200 510 610
GREAT WESTN FINL CORP 19,900 318 507
GTE CORP 149,300 5,427 6,569
HARRAHS ENTMT INC 19,100 555 463
HARRIS CORP DEL 6,000 322 328
HEALTH MGMT ASSOC 21,500 440 562
HEWLETT PACKARD CO 83,000 2,988 6,951
HOME DEPOT INC 101,500 4,205 4,859
HOUSTON INDS INC 31,400 547 761
HUMANA INC 39,900 838 1,092
ILLINOVA CORP 4,500 94 135
INGERSOLL RAND CO 20,300 701 713
INLAND STL INDS INC 12,900 325 324
INTEGRA FINL CORP 6,900 377 435
INTEL CORP 48,300 1,726 2,741
INTERNATIONAL BUSINESS MACHS 89,400 5,183 8,202
INTERNATIONAL FLAVOURS 20,500 963 984
INTERNATIONAL GAME TECHNOLOGY 29,200 603 318
INTERNATIONAL PAPER CO 62,500 1,494 2,367
INTERPUBLIC GROUP COS INC 15,400 592 668
ITT CORP NEW 32,800 0 1,738
ITT HARTFORD GROUP INC 32,800 0 1,587
ITT INDS INC 32,800 2,135 787
JAMES RIV CORP VA 15,900 521 384
JOHNSON + JOHNSON 38,000 1,897 3,254
JOHNSON CTLS INC 18,300 996 1,258
KEYCORP NEW 31,400 1,100 1,138
LEHMAN BROTHERS HLDGS INC 14,300 314 304
LILLY ELI + CO 109,200 3,806 6,143
LIMITED INC 74,200 1,658 1,289
LINCOLN NATL CORP IN 11,700 491 629
LIZ CLAIBORNE 16,400 382 455
LOCKHEED MARTIN CORP 30,300 1,037 2,394
LORAL CORP 26,500 371 937
LOUISIANA PAC CORP 400 13 10
LOWES COS INC 27,500 852 921
LYONDELL PETROCHEMICAL CO 3,200 77 73
MALLINCKRODT GROUP INC 18,300 652 666
MANOR CARE INC 19,400 576 679
MARSHALL + ILSLEY CORP 7,400 176 192
MASCO CORP 3,300 87 104
MBIA INC 3,800 236 285
MCDONALDS CORP 23,100 712 1,042
MCDONNELL DOUGLAS CORP 9,000 226 828
</TABLE>
12
<PAGE>
SAVINGS FUND PLAN
FOR EMPLOYEES OF PACIFIC GAS AND ELECTRIC COMPANY
ITEM 27a - SCHEDULE OF ASSETS HELD FOR INVESTMENT PURPOSES
December 31, 1995
<TABLE>
<CAPTION>
NUMBER OF SHARES
OR U.S. SAVINGS
BONDS HELD AT
NAME OF ISSUER AND DESCRIPTION CLOSE OF PERIOD COST CURRENT VALUE
- -------------------------------------------------------------------------------------------------------------
--------IN THOUSANDS-------
<S> <C> <C> <C> <C> <C>
MCI COMMUNICATIONS CORP 98,900 2,062 2,584
MEAD CORP 11,600 622 606
MELLON BK CORP 17,700 617 951
MELVILLE CORPORATION 20,500 959 630
MERCANTILE BANCORPORATION INC 2,600 97 120
MERCK + CO INC 166,500 6,062 10,947
MERCURY FIN CO 22,100 291 293
MERIDIAN BANCORP INC 6,600 293 307
MERRILL LYNCH + CO INC 22,400 1,175 1,142
MICROSOFT CORP 35,600 1,700 3,124
MIRAGE RESORTS INC 22,400 524 773
MOBIL CORP 27,600 2,210 3,091
MODINE MFG CO 7,000 211 168
MOLEX INC 7,300 216 224
MONSANTO CO 16,600 1,193 2,034
MORGAN STANLEY GROUP INC 800 67 65
MORTON INTL INC IND 18,700 553 671
MOTOROLA INC 99,100 5,295 5,649
NABISCO HLDGS CORP 7,200 215 235
NATIONAL CITY CORP 10,100 308 335
NATIONAL SEMICONDUCTOR CORP 18,900 445 421
NATIONAL SVC INDS INC 24,700 642 800
NATIONSBANK CORP 37,800 1,855 2,632
NEW ENGLAND ELEC SYS 7,300 243 289
NIAGARA MOHAWK PWR CORP 12,600 185 121
NINE WEST GROUP INC 7,600 319 285
NORDSTROM INC 4,500 181 182
NORTHEAST UTILS 20,900 486 509
NORTHERN STS PWR CO MN 8,800 410 432
NORTHERN TELECOM LTD 38,900 1,417 1,673
NORTHERN TRUST CORP 5,200 217 291
NORTHROP GRUMMAN CORP 300 9 19
NOVELL INC 65,500 1,611 933
NUCOR CORP 25,200 1,465 1,440
OCCIDENTAL PETE CORP 55,400 1,077 1,184
OGDEN CORP 8,700 193 186
OLSTEN CORP 2,400 93 95
OMNICOM GROUP 13,800 449 514
ORACLE SYS CORP 73,000 1,424 3,093
ORYX ENERGY CO 10,600 182 142
OWENS CORNING 17,200 583 772
P P + L RES INC 23,100 533 578
PACCAR INC 5,400 282 227
PACIFIC TELESIS GROUP 66,000 2,003 2,219
PAGING NETWORK INC 9,500 133 232
PAINE WEBBER GROUP INC 7,400 147 148
PANHANDLE EASTN CORP 23,900 510 666
PARKER HANNIFIN CORP 11,000 383 377
PECO ENERGY CO 34,200 1,007 1,030
PENNEY J C INC 49,800 2,309 2,372
PEPSICO INC 138,500 5,416 7,739
PFIZER INC 54,700 1,523 3,446
PHELPS DODGE CORP 16,900 811 1,052
PHILIP MORRIS COS INC 122,400 8,997 11,077
PHILLIPS PETE CO 50,400 1,579 1,720
</TABLE>
13
<PAGE>
SAVINGS FUND PLAN
FOR EMPLOYEES OF PACIFIC GAS AND ELECTRIC COMPANY
ITEM 27a - SCHEDULE OF ASSETS HELD FOR INVESTMENT PURPOSES
December 31, 1995
<TABLE>
<CAPTION>
NUMBER OF SHARES
OR U.S. SAVINGS
BONDS HELD AT
NAME OF ISSUER AND DESCRIPTION CLOSE OF PERIOD COST CURRENT VALUE
- -------------------------------------------------------------------------------------------------------------
--------IN THOUSANDS-------
<S> <C> <C> <C> <C> <C>
PINNACLE WEST CAP CORP 10,100 212 290
PNC BK CORP 51,200 1,042 1,651
PORTLAND GEN CORP 3,000 63 87
POTOMAC ELEC PWR CO 23,600 558 620
PPG INDS INC 29,300 932 1,340
PRAXAIR INC 22,900 384 770
PRICE COSTCO INC 10,900 182 166
PROCTER + GAMBLE CO 104,400 3,844 8,665
PROGRESSIVE CORP OHIO 2,500 101 122
PROVIDIAN CORP 15,800 562 644
PUBLIC SVC ENTERPRISE GROUP 29,900 790 916
RALSTON PURINA CO 20,800 1,036 1,297
RAYCHEM CORP 21,000 1,104 1,194
RAYTHEON CO 21,400 691 1,011
READ RITE CORP 1,500 35 35
REPUBLIC NY CORP 6,100 282 379
REYNOLDS METALS CO 16,300 801 923
ROCKWELL INTL CORP 20,100 791 1,063
ROHM + HAAS CO 9,400 553 605
ROYAL DUTCH PETE CO 77,200 5,623 10,895
RUBBERMAID INC 26,200 719 668
RYDER SYS INC 5,300 128 131
S + P 500 INDEX MAR FUTURES 61 0 0
SAFECO CORP 10,400 276 359
SARA LEE CORP 88,200 2,578 2,811
SBC COMMUNICATIONS INC 49,900 2,063 2,869
SCECORP 65,100 1,275 1,155
SCHERING PLOUGH CORP 23,900 1,323 1,309
SCHLUMBERGER LTD 5,600 384 388
SERVICE CORP INTL 21,300 464 937
SILICON GRAPHICS INC 23,300 579 641
SONAT INC 31,400 668 1,119
SOUTHERN NATL CORP N C 13,600 304 357
SOUTHTRUST CORP 8,500 161 218
SOUTHWEST AIRLS CO 18,900 431 439
SPRINT CORP 53,800 1,660 2,145
SPS TRANSACTION SVCS INC 6,500 211 193
ST PAUL COS INC 37,100 982 2,064
STANDARD FED BANCORPORATION 200 5 8
STATE STREET BOSTON CORP 11,300 369 509
SUN INC 14,500 387 397
SUN MICROSYSTEMS INC 31,400 504 1,433
SUNDSTRAND CORP 900 60 63
SYBASE INC 8,600 240 310
TANDEM COMPUTERS INC 8,400 116 89
TELE COMMUNICATIONS INC NEW 112,700 1,796 2,240
TENET HEALTHCARE CORP 58,600 1,042 1,216
TENNECO INC 68,900 2,787 3,419
TEXACO INC 52,300 3,422 4,105
TEXAS INSTRS INC 28,900 1,824 1,495
TEXAS UTILS CO 48,100 1,621 1,978
TIME WARNER INC 69,500 2,582 2,632
TJX COS INC NEW 14,200 320 268
TORCHMARK INC 3,200 181 145
TOYS R US INC 60,400 2,154 1,314
</TABLE>
14
<PAGE>
SAVINGS FUND PLAN
FOR EMPLOYEES OF PACIFIC GAS AND ELECTRIC COMPANY
ITEM 27a - SCHEDULE OF ASSETS HELD FOR INVESTMENT PURPOSES
December 31, 1995
<TABLE>
<CAPTION>
NUMBER OF SHARES
OR U.S. SAVINGS
BONDS HELD AT
NAME OF ISSUER AND DESCRIPTION CLOSE OF PERIOD COST CURRENT VALUE
- -------------------------------------------------------------------------------------------------------------
--------IN THOUSANDS-------
<S> <C> <C> <C> <C> <C>
TRIBUNE CO NEW 12,000 661 733
TURNER BROADCASTING SYS INC 35,800 952 931
TYCO INT LTD 67,600 1,780 2,408
U S HEALTHCARE INC 15,600 642 725
U S WEST INC 68,700 1,695 2,456
U S WEST INC 92,800 1,584 1,763
UJB FINL CORP 1,700 47 61
UNICOM CORP 26,300 609 861
UNION CARBIDE CORP 26,800 488 1,005
UNION ELEC CO 13,800 498 576
UNION PAC CORP 41,300 1,528 2,726
UNION TEX PETE HLDGS INC 11,400 222 221
UNITED HEALTHCARE CORP 49,500 2,355 3,242
UNOCAL CORP 50,900 1,409 1,482
UNUM CORP 7,600 369 418
USG CORP 15,000 419 450
USX U S STL 18,300 580 563
V F CORP 17,700 879 934
VIACOM INC 71,400 3,314 3,381
WABASH NATL CORP 1,300 53 29
WAL MART STORES INC 359,500 9,751 8,044
WARNACO GROUP INC 7,400 180 185
WARNER LAMBERT CO 27,700 2,175 2,690
WASHINGTON FED INC 6,700 158 172
WASHINGTON MUT INC 9,800 223 283
WESTERN RES INC 6,700 229 224
WHEELABRATOR TECHNOLOGIES INC 41,400 714 693
WHIRLPOOL CORP 24,800 1,306 1,321
WISCONSIN ENERGY CORP 14,500 387 444
WMX TECHNOLOGIES INC 18,000 14 16
WMX TECHNOLOGIES INC 136,900 4,319 4,089
WORTHINGTON INDS IN 20,100 378 418
XILINX INC 11,000 270 335
3COM CORP 27,200 996 1,268
------------ ------------ ------------
TOTAL COMMON STOCKS 10,532,143 384,606 503,528
INTEREST BEARING ACCOUNTS
*STATE STREET BANK & TRUST CO 20,205,299 20,205 20,205
UNITED STATES TREAS BILLS 550,000 549 549
UNITED STATES TREAS BILLS 500,000 493 493
------------ ------------ ------------
TOTAL INTEREST BEARING ACCOUNTS 21,255,299 21,247 21,247
TOTAL DIVERSIFIED EQUITY FUND 31,787,442 $405,853 $524,775
============ ============ ============
GUARANTEED INCOME FUND (1)
CORPORATE DEBT INSTRUMENTS
BANKERS TRUST 07/97 5.02% N/A 9,579 9,579
CAISSE DES DEPOTS 06/98 6.22% N/A 4,000 4,000
CAISSE DES DEPOTS 06/98 7.11% N/A 4,042 4,042
</TABLE>
15
<PAGE>
SAVINGS FUND PLAN
FOR EMPLOYEES OF PACIFIC GAS AND ELECTRIC COMPANY
ITEM 27a - SCHEDULE OF ASSETS HELD FOR INVESTMENT PURPOSES
December 31, 1995
<TABLE>
<CAPTION>
NUMBER OF SHARES
OR U.S. SAVINGS
BONDS HELD AT
NAME OF ISSUER AND DESCRIPTION CLOSE OF PERIOD COST CURRENT VALUE
- -------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
--------IN THOUSANDS-------
CAISSE DES DEPOTS (DC) 09/00 6.15% N/A 3,984 3,984
CDC INVESTMENT MGMT CORP 06/98 7.11% N/A 4,023 4,023
CDC INVESTMENT MGMT CORP 12/99 6.19% N/A 3,017 3,017
UNION BANK OF SWITZERLAND 10/98 5.63% N/A 10,268 10,268
UNION BANK OF SWITZERLAND 03/00 4.62% N/A 10,310 10,310
UNION BANK OF SWITZERLAND 03/00 5.15% N/A 6,574 6,574
UNION BANK OF SWITZERLAND 08/97 1.00% N/A 7,098 7,098
UNITED OF OMAHA LIFE INS 09/96 4.40% N/A 645 645
------------ ------------ ------------
TOTAL CORPORATE DEBT INSTRUMENTS N/A 63,540 63,540
INSURANCE COMPANY GENERAL ACCOUNTS
ALLSTATE LIFE INSURANCE CO 02/02 5.71% N/A 6,027 6,027
ALLSTATE LIFE INSURANCE CO 10/98 6.80% N/A 3,033 3,033
ALLSTATE LIFE INSURANCE CO 11/99 8.28% N/A 5,396 5,396
CONFEDERATION LIFE ASSUR CO 03/96 8.58% N/A 1,067 1,067
CONTINENTAL ASSURN CO 06/96 5.80% N/A 2,522 2,522
CROWN LIFE INS CO GIC 9005871 03/98 4.21% N/A 1,039 1,039
HANCOCK JOHN MUTUAL LIFE 09/96 5.34% N/A 4,708 4,708
HANCOCK JOHN MUTUAL LIFE 7201 10/97 4.82% N/A 7,722 7,722
MASS MUTUAL LIFE INS 11/03 5.95% N/A 18,856 18,856
MET LIFE INS GAC 12700 08/99 7.42% N/A 12,658 12,658
NEW YORK LIFE INS CO 12/98 6.19% N/A 7,541 7,541
NEW YORK LIFE INS CO 12/99 5.50% N/A 9,766 9,766
NEW YORK LIFE INS CO GA 06206 05/96 8.40% N/A 1,567 1,567
PEOPLES SECURITY LIFE 06/96 4.69% N/A 1,512 1,512
PEOPLES SECURITY LIFE 09/96 4.10% N/A 1,311 1,311
PEOPLES SECURITY LIFE 09/97 5.11% N/A 5,190 5,190
PEOPLES SECURITY LIFE 07/98 5.50% N/A 5,971 5,971
PEOPLES SECURITY LIFE 06/97 4.74% N/A 14,027 14,027
PEOPLES SECURITY LIFE 01/98 5.42% N/A 2,814 2,814
PEOPLES SECURITY LIFE 09/98 5.63% N/A 3,225 3,225
PEOPLES SECURITY LIFE 03/99 5.30% N/A 4,992 4,992
PROVIDENT LIFE + ACCIDENT 03/99 6.57% N/A 21,197 21,197
PRUDENTIAL INS CO AMERICA 11/95 6.11% N/A 1,595 1,595
PRUDENTIAL INS CO OF AMER 09/98 6.11% N/A 1,843 1,843
PRUDENTIAL INS GA 6769 211 04/96 8.04% N/A 1,397 1,397
------------ ------------ ------------
TOTAL INSURANCE COMPANY GENERAL ACCOUNTS N/A 146,976 146,976
INTEREST BEARING ACCOUNTS
*STATE STREET BANK + TRUST CO 10,296,945 10,297 10,297
------------ ------------ ------------
TOTAL GUARANTEED INCOME FUND $10,296,945 $220,813 $220,813
============ ============ ============
BOND INDEX FUND
VANGUARD BOND INDEX FUND INC 2,602,945 $25,791 $26,394
============ ============ ============
STOCK AND BOND FUND
</TABLE>
16
<PAGE>
SAVINGS FUND PLAN
FOR EMPLOYEES OF PACIFIC GAS AND ELECTRIC COMPANY
ITEM 27a - SCHEDULE OF ASSETS HELD FOR INVESTMENT PURPOSES
December 31, 1995
<TABLE>
<CAPTION>
NUMBER OF SHARES
OR U.S. SAVINGS
BONDS HELD AT
NAME OF ISSUER AND DESCRIPTION CLOSE OF PERIOD COST CURRENT VALUE
- -------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
--------IN THOUSANDS-------
COLUMBIA BALANCED FUND INC 15,812,777 $96,482 $127,992
============ ============ ============
UTILITY STOCK FUND
DREYFUS EDISON ELEC INDEX FD 3,566,108 $47,798 $49,284
============ ============ ============
TOTAL INVESTMENTS $1,794,632 $2,139,969
============ ============
</TABLE>
(1) The Guaranteed Income Fund is not measured in number of shares and is not
applicable (N/A)
* A party-in-interest as defined by ERISA.
17
<PAGE>
<TABLE>
<CAPTION>
Item 27(d) - Schedule of Reportable Transactions for
the year Ended December 31, 1995
3751 PACIFIC GAS & ELECTRIC SAVINGS PAGE: 1
BENEFIT PLAN SERVICES
ERISA 5500 SCHEDULE OF 5% REPORTABLE SERIES OF TRANSACTIONS
FROM DATE: 01/01/95 TO DATE: 12/31/95
BEGINNING NET ASSET VALUE: 1,154,261,695.21
5% OF ASSET VALUE: 57,713,084.76
====================================================================================================================================
ASSET ID SECURITY DESCRIPTION RATE MAT DATE
# PURCHASES PURCHASE COST # SALES SALE PROCEEDS 5500 GAIN/LOSS TOTAL # TOTAL COST/PROCEEDS
- ------------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
COMMON AND PREFERRED
- --------------------
694308107 PACIFIC GAS + ELEC CO
88 106,093,927.58 228 245,784,163.95 15,544,844.10 316 351,878,091.53
COMMON AND PREFERRED TOTALS
- ---------------------------
88 106,093,927.58 228 245,784,163.95 15,544,844.10 316 351,878,091.53
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Item 27(d) - Schedule of Reportable Transactions for
the year Ended December 31, 1995
3751 PACIFIC GAS & ELECTRIC SAVINGS PAGE: 2
BENEFIT PLAN SERVICES
ERISA 5500 SCHEDULE OF 5% REPORTABLE SERIES OF TRANSACTIONS
FROM DATE: 01/01/95 TO DATE: 12/31/95
BEGINNING NET ASSET VALUE: 1,154,261,695.21
5% OF ASSET VALUE: 57,713,084.76
====================================================================================================================================
ASSET ID SECURITY DESCRIPTION RATE MAT DATE
# PURCHASES PURCHASE COST # SALES SALE PROCEEDS 5500 GAIN/LOSS TOTAL # TOTAL COST/PROCEEDS
- ------------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
FIXED INCOME
- ------------
8611249M9 STATE STREET BANK + TRUST CO 1.000 12/31/2000
99 215,208,786.87 140 190,400,196.58 0.00 239 405,608,983.45
FIXED INCOME TOTALS
- -------------------
99 215,208,786.87 140 190,400,196.58 0.00 239 405,608,983.45
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Item 27(d) - Schedule of Reportable Transactions for
the year Ended December 31, 1995
3751 PACIFIC GAS & ELECTRIC SAVINGS PAGE: 3
BENEFIT PLAN SERVICES
ERISA 5500 SCHEDULE OF 5% REPORTABLE SERIES OF TRANSACTIONS
FROM DATE: 01/01/95 TO DATE: 12/31/95
BEGINNING NET ASSET VALUE: 1,154,261,695.21
5% OF ASSET VALUE: 57,713,084.76
====================================================================================================================================
ASSET ID SECURITY DESCRIPTION RATE MAT DATE
# PURCHASES PURCHASE COST # SALES SALE PROCEEDS 5500 GAIN/LOSS TOTAL # TOTAL COST/PROCEEDS
- ------------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
SHORT TERM
- ----------
SHORT TERM TOTALS
- -----------------
0 0.00 0 0.00 0.00 0 0.00
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Item 27(d) - Schedule of Reportable Transactions for
the year Ended December 31, 1995
3751 PACIFIC GAS & ELECTRIC SAVINGS PAGE: 4
BENEFIT PLAN SERVICES
ERISA 5500 SCHEDULE OF 5% REPORTABLE SERIES OF TRANSACTIONS
FROM DATE: 01/01/95 TO DATE: 12/31/95
BEGINNING NET ASSET VALUE: 1,154,261,695.21
5% OF ASSET VALUE: 57,713,084.76
====================================================================================================================================
ASSET ID SECURITY DESCRIPTION RATE MAT DATE
# PURCHASES PURCHASE COST # SALES SALE PROCEEDS 5500 GAIN/LOSS TOTAL # TOTAL COST/PROCEEDS
- ------------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
COMMON AND PREFERRED
- --------------------
88 106,093,927.58 228 245,784,163.95 15,544,844.10 316 351,878,091.53
FIXED INCOME
- ------------
99 215,208,786.87 140 190,400,196.58 0.00 239 405,608,983.45
SHORT TERM
- ----------
0 0.00 0 0.00 0.00 0 0.00
REPORTABLE TRANSACTION TOTALS
- -----------------------------
187 321,302,714.45 368 436,184,360.53 15,544,844.10 555 757,487,074.98
NON-REPORTABLE TRANSACTION TOTALS
- ---------------------------------
0 0.00 0 0.00 0.00 0 0.00
</TABLE>
RUN DATE: 02/14/96
<PAGE>
<TABLE>
<CAPTION>
Item 27(d) - Schedule of Reportable Transactions for
the year Ended December 31, 1995
3757 PACIFIC GAS & ELECTRIC SAVINGS PAGE: 1
VANGUARD BOND MARKET FUND
ERISA 5500 SCHEDULE OF 5% REPORTABLE SERIES OF TRANSACTIONS
FROM DATE: 01/01/95 TO DATE: 12/31/95
BEGINNING NET ASSET VALUE: 23,769,672.86
5% OF ASSET VALUE: 1,888,483.64
====================================================================================================================================
ASSET ID SECURITY DESCRIPTION RATE MAT DATE
# PURCHASES PURCHASE COST # SALES SALE PROCEEDS 5500 GAIN/LOSS TOTAL # TOTAL COST/PROCEEDS
- ------------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
COMMON AND PREFERRED
- --------------------
921937108 VANGUARD BD INDEX FD INC
123 8,998,587.09 101 8,614,408.36 366,385.81 224 17,612,995.45
COMMON AND PREFERRED TOTALS
- ---------------------------
123 8,998,587.09 101 8,614,408.36 366,385.81 224 17,612,995.45
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Item 27(d) - Schedule of Reportable Transactions for
the year Ended December 31, 1995
3757 PACIFIC GAS & ELECTRIC SAVINGS PAGE: 2
VANGUARD BOND MARKET FUND
ERISA 5500 SCHEDULE OF 5% REPORTABLE SERIES OF TRANSACTIONS
FROM DATE: 01/01/95 TO DATE: 12/31/95
BEGINNING NET ASSET VALUE: 23,769,672.86
5% OF ASSET VALUE: 1,888,483.64
====================================================================================================================================
ASSET ID SECURITY DESCRIPTION RATE MAT DATE
# PURCHASES PURCHASE COST # SALES SALE PROCEEDS 5500 GAIN/LOSS TOTAL # TOTAL COST/PROCEEDS
- ------------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
FIXED INCOME
- ------------
FIXED INCOME TOTALS
- -------------------
0 0.00 0 0.00 0.00 0 0.00
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Item 27(d) - Schedule of Reportable Transactions for
the year Ended December 31, 1995
3757 PACIFIC GAS & ELECTRIC SAVINGS PAGE: 3
VANGUARD BOND MARKET FUND
ERISA 5500 SCHEDULE OF 5% REPORTABLE SERIES OF TRANSACTIONS
FROM DATE: 01/01/95 TO DATE: 12/31/95
BEGINNING NET ASSET VALUE: 23,769,672.86
5% OF ASSET VALUE: 1,888,483.64
====================================================================================================================================
ASSET ID SECURITY DESCRIPTION RATE MAT DATE
# PURCHASES PURCHASE COST # SALES SALE PROCEEDS 5500 GAIN/LOSS TOTAL # TOTAL COST/PROCEEDS
- ------------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
SHORT TERM
- ----------
SHORT TERM TOTALS
- -----------------
0 0.00 0 0.00 0.00 0 0.00
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Item 27(d) - Schedule of Reportable Transactions for
the year Ended December 31, 1995
3757 PACIFIC GAS & ELECTRIC SAVINGS PAGE: 4
VANGUARD BOND MARKET FUND
ERISA 5500 SCHEDULE OF 5% REPORTABLE SERIES OF TRANSACTIONS
FROM DATE: 01/01/95 TO DATE: 12/31/95
BEGINNING NET ASSET VALUE: 23,769,672.86
5% OF ASSET VALUE: 1,888,483.64
====================================================================================================================================
ASSET ID SECURITY DESCRIPTION RATE MAT DATE
# PURCHASES PURCHASE COST # SALES SALE PROCEEDS 5500 GAIN/LOSS TOTAL # TOTAL COST/PROCEEDS
- ------------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
COMMON AND PREFERRED
- --------------------
123 8,998,587.09 101 8,614,408.36 366,385.81 224 17,612,995.45
FIXED INCOME
- ------------
0 0.00 0 0.00 0.00 0 0.00
SHORT TERM
- ----------
0 0.00 0 0.00 0.00 0 0.00
REPORTABLE TRANSACTION TOTALS
- -----------------------------
123 8,998,587.09 101 8,614,408.36 366,385.81 224 17,612,995.45
NON-REPORTABLE TRANSACTION TOTALS
- ---------------------------------
0 0.00 0 0.00 0.00 0 0.00
</TABLE>
RUN DATE: 02/14/96
<PAGE>
<TABLE>
<CAPTION>
Item 27(d) - Schedule of Reportable Transactions for
the year Ended December 31, 1995
3758 PACIFIC GAS & ELECTRIC SAVINGS PAGE: 1
COLUMBIA BALANCED FUND
ERISA 5500 SCHEDULE OF 5% REPORTABLE SERIES OF TRANSACTIONS
FROM DATE: 01/01/95 TO DATE: 12/31/95
BEGINNING NET ASSET VALUE: 102,860,838.26
5% OF ASSET VALUE: 5,143,041.91
====================================================================================================================================
ASSET ID SECURITY DESCRIPTION RATE MAT DATE
# PURCHASES PURCHASE COST # SALES SALE PROCEEDS 5500 GAIN/LOSS TOTAL # TOTAL COST/PROCEEDS
- ------------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
COMMON AND PREFERRED
- --------------------
197216104 COLUMBIA BALANCED FUND INC
129 23,690,735.57 94 23,143,474.90 1,604,719.38 223 46,834,210.47
COMMON AND PREFERRED TOTALS
- ---------------------------
129 23,690,735.57 94 23,143,474.90 1,604,719.38 223 46,834,210.47
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Item 27(d) - Schedule of Reportable Transactions for
the year Ended December 31, 1995
3758 PACIFIC GAS & ELECTRIC SAVINGS PAGE: 2
COLUMBIA BALANCED FUND
ERISA 5500 SCHEDULE OF 5% REPORTABLE SERIES OF TRANSACTIONS
FROM DATE: 01/01/95 TO DATE: 12/31/95
BEGINNING NET ASSET VALUE: 102,860,838.26
5% OF ASSET VALUE: 5,143,041.91
====================================================================================================================================
ASSET ID SECURITY DESCRIPTION RATE MAT DATE
# PURCHASES PURCHASE COST # SALES SALE PROCEEDS 5500 GAIN/LOSS TOTAL # TOTAL COST/PROCEEDS
- ------------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
FIXED INCOME
- ------------
FIXED INCOME TOTALS
- -------------------
0 0.00 0 0.00 0.00 0 0.00
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Item 27(d) - Schedule of Reportable Transactions for
the year Ended December 31, 1995
3758 PACIFIC GAS & ELECTRIC SAVINGS PAGE: 3
COLUMBIA BALANCED FUND
ERISA 5500 SCHEDULE OF 5% REPORTABLE SERIES OF TRANSACTIONS
FROM DATE: 01/01/95 TO DATE: 12/31/95
BEGINNING NET ASSET VALUE: 102,860,838.26
5% OF ASSET VALUE: 5,143,041.91
====================================================================================================================================
ASSET ID SECURITY DESCRIPTION RATE MAT DATE
# PURCHASES PURCHASE COST # SALES SALE PROCEEDS 5500 GAIN/LOSS TOTAL # TOTAL COST/PROCEEDS
- ------------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
SHORT TERM
- ----------
SHORT TERM TOTALS
- -----------------
0 0.00 0 0.00 0.00 0 0.00
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Item 27(d) - Schedule of Reportable Transactions for
the year Ended December 31, 1995
3758 PACIFIC GAS & ELECTRIC SAVINGS PAGE: 4
COLUMBIA BALANCED FUND
ERISA 5500 SCHEDULE OF 5% REPORTABLE SERIES OF TRANSACTIONS
FROM DATE: 01/01/95 TO DATE: 12/31/95
BEGINNING NET ASSET VALUE: 102,860,838.26
5% OF ASSET VALUE: 5,143,041.91
====================================================================================================================================
ASSET ID SECURITY DESCRIPTION RATE MAT DATE
# PURCHASES PURCHASE COST # SALES SALE PROCEEDS 5500 GAIN/LOSS TOTAL # TOTAL COST/PROCEEDS
- ------------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
COMMON AND PREFERRED
- --------------------
129 23,690.735.57 94 23,143,474.90 1,604,719.38 223 46,834,210.47
FIXED INCOME
- ------------
0 0.00 0 0.00 0.00 0 0.00
SHORT TERM
- ----------
0 0.00 0 0.00 0.00 0 0.00
REPORTABLE TRANSACTION TOTALS
- -----------------------------
129 23,690,735.57 94 23,143,474.90 1,604,719.38 223 46,834,210.47
NON-REPORTABLE TRANSACTION TOTALS
- ---------------------------------
0 0.00 0 0.00 0.00 0 0.00
</TABLE>
RUN DATE- 02/14/96
<PAGE>
<TABLE>
<CAPTION>
Item 27(d) - Schedule of Reportable Transactions for
the year Ended December 31, 1995
3759 PACIFIC GAS & ELECTRIC SAVINGS PAGE: 1
DREYFUS UTILITY STOCK FUND
ERISA 5500 SCHEDULE OF 5% REPORTABLE SERIES OF TRANSACTIONS
FROM DATE: 01/01/95 TO DATE: 12/31/95
BEGINNING NET ASSET VALUE: 46,302,255.11
5% OF ASSET VALUE: 2,315,112.76
====================================================================================================================================
ASSET ID SECURITY DESCRIPTION RATE MAT DATE
# PURCHASES PURCHASE COST # SALES SALE PROCEEDS 5500 GAIN/LOSS TOTAL # TOTAL COST/PROCEEDS
- ------------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
COMMON AND PREFERRED
- --------------------
261893101 DREYFUS EDISON ELEC INDEX FD
105 15,529,320.41 123 20,611,959.84 1,511,137.52 228 36,147,280.25
COMMON AND PREFERRED TOTALS
- ---------------------------
105 15,529,320.41 123 20,611,959.84 1,511,137.52 228 36,147,280.25
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Item 27(d) - Schedule of Reportable Transactions for
the year Ended December 31, 1995
3759 PACIFIC GAS & ELECTRIC SAVINGS PAGE: 2
DREYFUS UTILITY STOCK FUND
ERISA 5500 SCHEDULE OF 5% REPORTABLE SERIES OF TRANSACTIONS
FROM DATE: 01/01/95 TO DATE: 12/31/95
BEGINNING NET ASSET VALUE: 46,302,255.11
5% OF ASSET VALUE: 2,315,112.76
====================================================================================================================================
ASSET ID SECURITY DESCRIPTION RATE MAT DATE
# PURCHASES PURCHASE COST # SALES SALE PROCEEDS 5500 GAIN/LOSS TOTAL # TOTAL COST/PROCEEDS
- ------------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
FIXED INCOME
- ------------
FIXED INCOME TOTALS
- -------------------
0 0.00 0 0.00 0.00 0 0.00
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Item 27(d) - Schedule of Reportable Transactions for
the year Ended December 31, 1995
3759 PACIFIC GAS & ELECTRIC SAVINGS PAGE: 3
DREYFUS UTILITY STOCK FUND
ERISA 5500 SCHEDULE OF 5% REPORTABLE SERIES OF TRANSACTIONS
FROM DATE: 01/01/95 TO DATE: 12/31/95
BEGINNING NET ASSET VALUE: 46,302,255.11
5% OF ASSET VALUE: 2,315,112.76
====================================================================================================================================
ASSET ID SECURITY DESCRIPTION RATE MAT DATE
# PURCHASES PURCHASE COST # SALES SALE PROCEEDS 5500 GAIN/LOSS TOTAL # TOTAL COST/PROCEEDS
- ------------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
SHORT TERM
- ----------
SHORT TERM TOTALS
- -----------------
0 0.00 0 0.00 0.00 0 0.00
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Item 27(d) - Schedule of Reportable Transactions for
the year Ended December 31, 1995
3759 PACIFIC GAS & ELECTRIC SAVINGS PAGE: 4
DREYFUS UTILITY STOCK FUND
ERISA 5500 SCHEDULE OF 5% REPORTABLE SERIES OF TRANSACTIONS
FROM DATE: 01/01/95 TO DATE: 12/31/95
BEGINNING NET ASSET VALUE: 46,302,255.11
5% OF ASSET VALUE: 2,315,112.76
====================================================================================================================================
ASSET ID SECURITY DESCRIPTION RATE MAT DATE
# PURCHASES PURCHASE COST # SALES SALE PROCEEDS 5500 GAIN/LOSS TOTAL # TOTAL COST/PROCEEDS
- ------------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
COMMON AND PREFERRED
- --------------------
105 15,529,320.41 123 20,617,959.84 1,511,137.52 228 36,147,280.25
FIXED INCOME
- ------------
0 0.00 0 0.00 0.00 0 0.00
SHORT TERM
- ----------
0 0.00 0 0.00 0.00 0 0.00
REPORTABLE TRANSACTION TOTALS
- -----------------------------
105 15,529,320.41 123 20,617,959.84 1,511,137.52 228 36,147,280.25
NON-REPORTABLE TRANSACTION TOTALS
- ---------------------------------
0 0.00 0 0.00 0.00 0 0.00
</TABLE>
RUN DATE: 02/14/96
<PAGE>
PACIFIC GAS AND ELECTRIC COMPANY
SAVINGS FUND PLAN - PART I
FINANCIAL STATEMENTS
TABLE OF CONTENTS
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
FINANCIAL STATEMENTS
Statements of Net Assets Available for Benefits - December 31, 1995
and 1994
Statement of Changes in Net Assets Available for Benefits for the Year
Ended December 31, 1995
Notes to Financial Statements - December 31, 1995
<PAGE>
PACIFIC GAS AND ELECTRIC COMPANY
SAVINGS FUND PLAN - PART I
STATEMENTS OF NET ASSETS AVAILABLE FOR BENEFITS
December 31, 1995 AND 1994
<TABLE>
<CAPTION>
1995 1994
---------- ----------
------In Thousands-----
<S> <C> <C>
ASSETS:
Investment in Pacific Gas and Electric
Company Master Trust, at fair value $1,000,595 $839,081
Participant contributions receivable - 1
---------- ----------
Total assets 1,000,595 839,082
LIABILITIES - 43
---------- ----------
NET ASSETS AVAILABLE FOR BENEFITS 1,000,595 839,039
========== ==========
</TABLE>
The accompanying Notes to Financial Statements are an integral part of these
statements.
1
<PAGE>
PACIFIC GAS AND ELECTRIC COMPANY
SAVINGS FUND PLAN - PART I
STATEMENT OF CHANGES IN NET ASSETS AVAILABLE FOR BENEFITS
For the Year Ended December 31, 1995
<TABLE>
<CAPTION>
------In Thousands-----
<S> <C>
ADDITIONS:
Participant contributions $ 34,426
Employer contributions 15,531
Interplan transfer from Savings Fund Plan - Part II 105,709
Net investment gain from Pacific Gas
and Electric Company Master Trust 152,023
---------
Total Additions 307,689
---------
DEDUCTIONS:
Benefits paid directly to participants or beneficiaries 136,570
Transfer to separate plan - PGT members 9,563
---------
Total Deductions 146,133
---------
Increase in Net Assets Available for Benefits 161,556
NET ASSETS AVAILABLE FOR BENEFITS
Beginning of the year 839,039
---------
End of the year 1,000,595
=========
</TABLE>
The accompanying Notes to Financial Statements are an integral part of these
statements.
2
<PAGE>
PACIFIC GAS AND ELECTRIC COMPANY
SAVINGS FUND PLAN - PART I
NOTES TO FINANCIAL STATEMENTS
December 31, 1995
NOTE 1: Plan Description
The Pacific Gas and Electric Company Savings Fund Plan - Part I (the Plan)
is a defined contribution plan and is subject to the provisions of the Employee
Retirement Income Security Act of 1974. The Plan covers all eligible non-union
employees of Pacific Gas and Electric Company (the Company), and the non-union
employees of any other entity designated by the Company's Board of Directors.
The Plan participates in the Pacific Gas and Electric Company Savings Fund Plan
Master Trust (the Master Trust), and is administered by the Employee Benefit
Administrative Committee and the Employee Benefit Finance Committee. Although
the Company has not expressed any intent to do so, its Board of Directors
reserves the right to amend or terminate the Plan at any time. Participants
should refer to the Plan document for a complete description of the Plan's
provisions. In addition, the financial statements of the Master Trust provide
information regarding the activities and transactions of the various investment
options offered by the Plan.
All participants'contributions and their share of all employer
contributions, and the earnings and losses resulting from such contributions are
immediately vested and nonforfeitable.
Employees are eligible to participate in the Plan upon completion of one
year of service. Employee contributions, up to a maximum of 6% of covered
compensation, as defined, and depending on length of service, are matched by
employer contributions at a 75% rate.
Eligible employees may elect to contribute to the Plan up to 15% of their
covered compensation on a pre-tax or after-tax basis. This amount may be
deferred compensation (401(k)), or after-tax contributions (non-401(k)). 401(k)
contributions are not subject to federal or state income tax until withdrawn or
distributed from the Plan.
All contributions made to the Plan prior to October 1, 1984, are considered
to be non-401(k) contributions. As provided under the Tax Reform Act of 1986,
employee 401(k) contributions may not exceed $9,240 for 1995, and total
contributions to a participant's account may not exceed the lesser of 25% of
compensation or $30,000 a year. The annual 401(k) limitation is adjusted each
year to reflect changes in the cost of living.
Eligible employees may elect to contribute to the Plan any excess funds
from the FLEX benefits program, which is a cafeteria plan qualified under
Section 125 of the Internal Revenue Code (IRC). These funds, which are invested
in the participant's account once a year in December, are considered 401(k)
contributions, but are not eligible for matching employer contributions.
As of January 1, 1995, Pacific Gas Transmission Company (PGT), a subsidiary
of the Company, formed a separate savings fund plan on behalf of its employees.
Accordingly, these participants no longer participate in the Company's Master
Trust. During January 1995, $9.6 million of net assets relating to the PGT
participants were transferred to a separate plan.
On January 1, 1995, all non-union, non-management employees were removed as
participants in the Savings Fund Plan - Part II, and became participants of the
Plan. In connection with this new
3
<PAGE>
PACIFIC GAS AND ELECTRIC COMPANY
SAVINGS FUND PLAN - PART I
NOTES TO FINANCIAL STATEMENTS
December 31, 1995
NOTE 1: Plan Description (Continued)
participant structure, approximately $106 million in assets were transferred
from the Savings Fund Plan - Part II to the Plan on that date.
NOTE 2: Summary of Significant Accounting Policies
Basis of Accounting
The financial statements of the Plan are prepared in conformity with
generally accepted accounting principles. The preparation of financial
statements in conformity with generally accepted accounting principles requires
management to make estimates and assumptions that affect the reported amounts of
assets and liabilities and disclosure of contingent assets and liabilities at
the date of the financial statements and the reported amounts of revenues and
expenses during the reporting period. Actual results could differ from those
estimates.
The Plan's interest in the Master Trust is stated at fair value based on
the Plan's prorated interest in the Master Trust. The Master Trust values
investments in the Guaranteed Income Fund at cost which approximates fair value.
Generally, all other investments are stated at fair value based on published
market quotations.
Interest income, dividends, investment fees, and the net appreciation or
depreciation in the fair value of the investments held by the Master Trust are
allocated to the individual participating plans each day based upon their
proportional share of the fund balances.
Benefits are recorded when paid.
NOTE 3: Federal Income Taxes
The Internal Revenue Service (IRS) has ruled that the Plan is a qualified
tax-exempt plan under Section 401(a) and Section 409(a) of the IRC and the trust
forming a part thereof is exempt under Section 501(a) . Accordingly, no
provision for federal income taxes has been made in the financial statements.
Furthermore, participating employees are not liable for federal income tax on
amounts allocated to their accounts attributable to: (1) employee 401(k)
contributions, (2) dividends, earnings, and interest income on both 401(k)
contributions and non-401(k) contributions, or (3) employer contributions,
until the time that they withdraw such amounts from the Plan.
The Company received favorable tax determination letters from the IRS in
November of 1995. Accordingly, the Plan sponsor believes that the Plan
continues to be designed and operated in accordance with IRS requirements.
4
<PAGE>
PACIFIC GAS AND ELECTRIC COMPANY
SAVINGS FUND PLAN - PART I
NOTES TO FINANCIAL STATEMENTS
December 31, 1995
NOTE 4: Investments
The Plan has a prorated interest in the net assets of the Master Trust.
The Master Trust Agreement allows the Company's Savings Fund Plans and the
Pacific Service Employees Association, to participate in the Master Trust.
The Plan and Master Trust trustee, State Street Bank and Trust Company,
invests a significant portion of the contributions to the Plan in common stock
of the Company. In 1995, purchases of this stock were made on the open market,
while in previous years these stock purchases were made directly from the
Company.
The Company pays all costs of administering the Plan, including fees and
expenses of the trustee. However, customary brokerage fees and commissions due
to transfers, withdrawals and distributions are paid by the Plan. The Company
pays the investment management fees for the Diversified Equity Fund and the
Guaranteed Income Fund.
Participants designate the way in which their contributions are invested
and may change their investment designation at any time. Participants may elect
to have their contributions invested in one or more of the following funds held
by the Master Trust:
- Company Stock Fund, invested in Pacific Gas and Electric
Company common stock;
- Diversified Equity Fund (DEF), invested in a diversified
portfolio of common stock of other companies;
- Guaranteed Income Fund (GIF), invested in contracts which
offer a fixed rate of interest for a specified period of
time;
- Bond Index Fund (BIF), invested in Vanguard Bond Market
Fund, a diversified portfolio consisting of marketable
fixed-income securities;
- Stock and Bond Fund (SBF), invested in Columbia Balanced
Fund, a diversified portfolio of marketable equity securities
and marketable fixed-income securities;
- Utility Stock Fund (USF), invested in Dreyfus Utility Stock
Fund, a portfolio of marketable equity securities of electric
utility companies that are members of the Edition Electric
Institute, including Pacific Gas and Electric Company.
Participants should refer to the separate master trust financial statements
or their individual quarterly Savings Fund Plan account statements for
information relating to the activity in each of the investment options.
5
<PAGE>
PACIFIC GAS AND ELECTRIC COMPANY
SAVINGS FUND PLAN - PART I
NOTES TO FINANCIAL STATEMENTS
December 31, 1995
NOTE 4: Investments (Continued)
A participant's interest in the investment funds is represented by
participation units allocated on the basis of contributions and assigned a unit
value on the basis of the total value in each fund. The Company Stock Fund and
the Guaranteed Income Fund converted to unitization in April 1995 to accommodate
daily valuation. For investments in the United States Savings Bond Fund , a
unit is one bond.
6
<PAGE>
PACIFIC GAS ELECTRIC COMPANY
SAVINGS FUND PLAN - PART I
NOTES TO FINANCIAL STATEMENTS
December 31, 1995
NOTE 4: Investments (Continued)
The following summarizes the net assets and related investment gain of the
Master Trust and the Plan's allocated share of such amounts:
<TABLE>
<CAPTION>
------In Thousands-----
1995 1994
<S> <C> <C>
Investments, at fair value:
Company Stock Fund
Pacific Gas and Electric Company common stock $1,161,205 $1,131,413
United States government securities 5,466 5,169
DEF
Corporate stocks - preferred - 1,048
Corporate stocks - common 503,528 340,032
GIF
Corporate debt intruments 63,540 53,210
Insurance company general accounts 146,976 151,704
Registered investment companies
Vanguard Bond Market Fund 26,394 23,632
Columbia Balanced Fund 127,992 102,861
Dreyfus Utility Stock Fund 49,284 45,458
Interest bearing accounts 55,584 72,645
---------- ----------
Total investments 2,139,969 1,927,172
---------- ----------
Receivables:
Dividends and interest 22,698 27,365
Other receivables 3,384 6,293
---------- ----------
Total receivables 26,082 33,658
---------- ----------
Total assets 2,166,051 1,960,830
---------- ----------
LIABILITIES - 11,407
---------- ----------
NET ASSETS $2,166,051 $1,949,423
========== ==========
Allocated to the Plan $1,000,595 $ 839,081
Allocated to other plans 1,165,456 1,110,342
---------- ----------
$2,166,051 $1,949,423
========== ==========
</TABLE>
7
<PAGE>
PACIFIC GAS ELECTRIC COMPANY
SAVINGS FUND PLAN - PART I
NOTES TO FINANCIAL STATEMENTS
December 31, 1995
NOTE 4: Investments (Continued)
<TABLE>
<CAPTION>
The composition of the Master Trust investment gain for the year ended December
31, 1995 is follows:
-In Thousands-
<S> <C>
Interest income
Interest bearing accounts $ 3,637
United States government securities 63
Fixed income investments 11,386
--------
Total interest income 15,086
--------
Dividend income
Common stock 92,405
Registered investment companies 4,061
--------
Total dividend income 96,466
--------
Other income 40
Net appreciation in value of investments 329,685
Total investment gain $441,277
========
Allocated to the Plan 152,023
Allocated to other plans 289,254
--------
$441,277
========
</TABLE>
8
<PAGE>
PACIFIC GAS ELECTRIC COMPANY
SAVINGS FUND PLAN - PART I
NOTES TO FINANCIAL STATEMENTS
December 31, 1995
NOTE 4: Investments (Continued)
The net appreciation in fair value of investments of the Master Trust by major
investment category for the year ended December 31, 1995 is as follows:
<TABLE>
<CAPTION>
-In Thousands-
<S> <C>
Pacific Gas and Electric Company Common Stock Fund $169,483
Diversified Equity Fund 124,845
Bond Index Fund 2,378
Stock and Bond Fund 24,065
Utility Stock Fund 8,914
--------
Total appreciation 329,685
========
Allocated to the Plan 110,524
Allocated to other plans 219,161
--------
$329,685
=========
</TABLE>
9
<PAGE>
PACIFIC GAS AND ELECTRIC COMPANY
SAVINGS FUND PLAN - PART I
NOTES TO FINANCIAL STATEMENTS
December 31, 1995
NOTE 4: Investments (Continued)
The net asset value per unit of the Company Stock Fund, DEF, BIF, SBF, and USF
is determined by dividing the fair value of fund assets by the number of fund
units outstanding. The total number of units held by the Plan and the value per
unit of the Company Stock Fund, DEF, GIF, BIF, SBF, and USF for the four
quarters ended December 31, 1995 and 1994 are as follows:
<TABLE>
<CAPTION>
1995
----------
March 31 June 30 September 30 December 31
- ------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Company Stock Fund *
Number of units N/A 38,060,709 36,582,070 34,556,057
Value per unit N/A $11.99 $12.53 $12.13
DEF
Number of units 3,002,943 2,937,324 3,095,153 3,264,636
Value per unit $78.95 $86.73 $93.48 $100.10
GIF**
Number of units 111,411,797 115,607,468 113,229,996 111,679,180
Value per unit $1.00 $1.01 $1.03 $1.04
BIF
Number of units 1,335,076 1,326,316 1,370,682 1,333,643
Value per unit $12.32 $12.99 $13.30 $13.89
SBF
Number of units 10,987,970 10,665,946 11,073,905 11,538,598
Value per unit $6.61 $7.03 $7.39 $7.77
USF
Number of units 1,879,041 1,659,091 1,574,548 1,661,633
Value per unit $13.27 $14.14 $15.12 $16.5
- ------------------------------------------------------------------------------------------
</TABLE>
* The Company Stock Fund converted to a unitized fund in April 1995.
** The GIF Fund converted to a unitized fund in April 1995 and the unit value
was no longer fixed at $1.00.
10
<PAGE>
PACIFIC GAS AND ELECTRIC COMPANY
SAVINGS FUND PLAN - PART I
NOTES TO FINANCIAL STATEMENTS
December 31, 1995
NOTE 4: Investments (Continued)
<TABLE>
<CAPTION>
1994
----------
March 31 June 30 September 30 December 31
- ------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Company Stock Fund *
Number of units N/A N/A N/A N/A
Value per unit N/A N/A N/A N/A
DEF
Number of units 2,850,195 2,937,324 2,994,629 3,019,934
Value per unit $67.27 $67.91 $71.5 $71.72
GIF**
Number of units 105,879,138 102,091,554 104,479,607 127,731,989
Value per unit $1.00 $1.00 $1.00 $1.00
BIF
Number of units 1,630,823 1,548,151 1,474,848 1,396,372
Value per unit $11.61 $11.63 $11.68 $11.75
SBF
Number of units 12,120,202 12,177,328 12,060,386 11,622,737
Value per unit $6.11 $6.06 $6.21 $6.21
USF
Number of units 2,590,033 2,313,483 2,189,934 1,927,519
Value per unit $12.98 $11.89 $12.24 $12.73
- ------------------------------------------------------------------------------------------
</TABLE>
* The Company Stock Fund converted to a unitized fund in April 1995.
** The GIF Fund converted to a unitized fund in April 1995 and the unit value
was no longer fixed at $1.00.
11
<PAGE>
PACIFIC GAS AND ELECTRIC COMPANY
SAVINGS FUND PLAN - PART I
NOTES TO FINANCIAL STATEMENTS
December 31, 1995
NOTE 5: Subsequent Event
The market price of Pacific Gas and Electric Company common stock declined
by 7.9% between December 31, 1995 and March 5, 1996. This represents a decrease
of approximately $92 million in the fair value of the Company Stock Fund.
12
<PAGE>
PACIFIC GAS AND ELECTRIC COMPANY
SAVINGS FUND PLAN - PART II
FINANCIAL STATEMENTS
TABLE OF CONTENTS
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
FINANCIAL STATEMENTS
Statements of Net Assets Available for Benefits - December 31, 1995
and 1994
Statement of Changes in Net Assets Available for Benefits for the Year
Ended December 31, 1995
Notes to Financial Statements - December 31, 1995
<PAGE>
PACIFIC GAS AND ELECTRIC COMPANY
SAVINGS FUND PLAN - PART II
STATEMENTS OF NET ASSETS AVAILABLE FOR BENEFITS
December 31, 1995 AND 1994
<TABLE>
1995 1994
---------- ----------
------In Thousands-----
<S> <C> <C>
ASSETS:
Investment in Pacific Gas and Electric
Company Master Trust, at fair value $1,159,330 $1,105,628
---------- ----------
Total assets 1,159,330 1,105,628
LIABILITIES - 42
---------- ----------
NET ASSETS AVAILABLE FOR BENEFITS 1,159,330 1,105,586
========== ==========
</TABLE>
The accompanying Notes to Financial Statements are an integral part of these
statements.
1
<PAGE>
PACIFIC GAS AND ELECTRIC COMPANY
SAVINGS FUND PLAN - PART II
STATEMENT OF CHANGES IN NET ASSETS AVAILABLE FOR BENEFITS
For the Year Ended December 31, 1995
<TABLE>
<CAPTION>
----In Thousands----
<S> <C>
ADDITIONS:
Participant contributions $ 48,247
Employer contributions 13,641
Net investment gain from Pacific Gas
and Electric Company Master Trust 287,336
--------
Total Additions 349,224
--------
DEDUCTIONS:
Benefits paid directly to participants or beneficiaries 173,830
Interplan transfer to Savings Fund Plan - Part I 105,709
Transfer to separate plan - PGT members 15,941
--------
Total Deductions 295,480
--------
Increase in Net Assets Available for Benefits 53,744
NET ASSETS AVAILABLE FOR BENEFITS
Beginning of the year 1,105,586
---------
End of the year 1,159,330
=========
</TABLE>
The accompanying Notes to Financial Statements are an integral part of these
statements.
2
<PAGE>
PACIFIC GAS AND ELECTRIC COMPANY
SAVINGS FUND PLAN - PART II
NOTES TO FINANCIAL STATEMENTS
December 31, 1995
NOTE 1: Plan Description
The Pacific Gas and Electric Company Savings Fund Plan - Part II (the Plan)
is a defined contribution plan and is subject to the provisions of the Employee
Retirement Income Security Act of 1974. The Plan covers all union-represented
employees of Pacific Gas and Electric Company (the Company), and the union
employees of any other entity designated by the Company's Board of Directors.
The Plan participates in the Pacific Gas and Electric Company Savings Fund Plan
Master Trust (the Master Trust) and is administered by the Employee Benefit
Administrative Committee and the Employee Benefit Finance Committee. Although
the Company has not expressed any intent to do so, its Board of Directors
reserves the right to amend or terminate the Plan at any time. Participants
should refer to the Plan document for a complete description of the Plan's
provisions. In addition, the financial statements of the Master Trust provide
information regarding the activities and transactions of the various investment
options offered by the Plan.
All participants' contributions and their share of all employer
contributions, and the earnings and losses resulting from such contributions are
immediately vested and nonforfeitable.
Employees are eligible to participate in the Plan upon completion of one
year of service. Employee contributions, up to a maximum of 6% of covered
compensation, as defined, and depending on length of service, are matched by
employer contributions at a 50% rate.
Eligible employees may elect to contribute to the Plan up to 15% of their
covered compensation on a pre-tax or after-tax basis. This amount may be
deferred compensation (401(k)), or after-tax contributions (non-401(k)). 401(k)
contributions are not subject to federal or state income tax until withdrawn or
distributed from the Plan.
All contributions made to the Plan prior to October 1, 1984, are considered
to be non-401(k) contributions. As provided under the Tax Reform Act of 1986,
employee 401(k) contributions may not exceed $9,240 for 1995, and total
contributions to a participant's account may not exceed the lesser of 25% of
compensation or $30,000 a year. The annual 401(k) limitation is adjusted each
year to reflect changes in the cost of living.
Eligible employees may elect to contribute to the Plan any excess funds
from the FLEX benefits program, which is a cafeteria plan qualified under
Section 125 of the Internal Revenue Code (IRC). These funds, which are invested
in the participant's account once a year in December, are considered 401(k)
contributions, but are not eligible for matching employer contributions.
As of January 1, 1995, Pacific Gas Transmission Company (PGT), a subsidiary
of the Company, formed a separate savings fund plan on behalf of its employees.
Accordingly, these participants no longer participate in the Company's Master
Trust. During January 1995, $15.9 million of net assets relating to the PGT
participants were transferred to a separate plan.
On January 1, 1995, all non-union, non-management employees were removed as
participants in the Plan, and became participants of the Savings Fund Plan -
Part I. In connection with this new
3
<PAGE>
PACIFIC GAS AND ELECTRIC COMPANY
SAVINGS FUND PLAN - PART II
NOTES TO FINANCIAL STATEMENTS
December 31, 1995
NOTE 1: Plan Description (Continued)
participant structure, approximately $106 million in assets were transferred
from the Plan to the Savings Fund Plan - Part I on that date.
NOTE 2: Summary of Significant Accounting Policies
Basis of Accounting
The financial statements of the Plan are prepared in conformity with
generally accepted accounting principles. The preparation of financial
statements in conformity with generally accepted accounting principles requires
management to make estimates and assumptions that affect the reported amounts of
assets and liabilities and disclosure of contingent assets and liabilities at
the date of the financial statements and the reported amounts of revenues and
expenses during the reporting period. Actual results could differ from those
estimates.
The Plan's interest in the Master Trust is stated at fair value based on
the Plan's prorated interest in the Master Trust. The Master Trust values
investments in the Guaranteed Income Fund at cost which approximates fair value.
Generally, all other investments are stated at fair value based on published
market quotations.
Interest income, dividends, investment fees, and the net appreciation or
depreciation in the fair value of the investments held by the Master Trust are
allocated to the individual participating plans each day based upon their
proportional share of the fund balances.
Benefits are recorded when paid.
NOTE 3: Federal Income Taxes
The Internal Revenue Service (IRS) has ruled that the Plan is a qualified
tax-exempt plan under Section 401(a) and Section 409(a) of the IRC and the trust
forming a part thereof is exempt under Section 501(a) . Accordingly, no
provision for federal income taxes has been made in the financial statements.
Furthermore, participating employees are not liable for federal income tax on
amounts allocated to their accounts attributable to: (1) employee 401(k)
contributions, (2) dividends, earnings, and interest income on both 401(k)
contributions and non-401(k) contributions, or (3) employer contributions,
until the time that they withdraw such amounts from the Plan.
The Company received favorable determination letters from the IRS in
November of 1995. Accordingly, the Plan sponsor believes that the Plan continues
to be designed and operated in accordance with IRS requirements.
4
<PAGE>
PACIFIC GAS AND ELECTRIC COMPANY
SAVINGS FUND PLAN - PART II
NOTES TO FINANCIAL STATEMENTS
December 31, 1995
NOTE 4: Investments
The Plan has a prorated interest in the net assets of the Master Trust.
The Master Trust Agreement allows the Company's Savings Fund Plans and the
Pacific Service Employees Association, to participate in the Master Trust.
The Plan and Master Trust trustee, State Street Bank and Trust Company,
invests a significant portion of the contributions to the Plan in common stock
of the Company. In 1995, purchases of this stock were made on the open market,
while in previous years these stock purchases were made directly from the
Company.
The Company pays all costs of administering the Plan, including fees and
expenses of the trustee. However, customary brokerage fees and commissions due
to transfers, withdrawals and distributions are paid by the Plan. The Company
pays the investment management fees for the Diversified Equity Fund and the
Guaranteed Income Fund.
Participants designate the way in which their contributions are invested
and may change their investment designation at any time. Participants may elect
to have their contributions invested in one or more of the following funds held
by the Master Trust:
- Company Stock Fund, invested in Pacific Gas and Electric
Company common stock;
- Diversified Equity Fund (DEF), invested in a diversified
portfolio of common stock of other companies;
- Guaranteed Income Fund (GIF), invested in contracts which
offer a fixed rate of interest for a specified period of
time;
- Bond Index Fund (BIF), invested in Vanguard Bond Market Fund,
a diversified portfolio consisting of marketable fixed-income
securities;
- Stock and Bond Fund (SBF), invested in Columbia Balanced
Fund, a diversified portfolio of marketable equity securities
and marketable fixed-income securities;
- Utility Stock Fund (USF), invested in Dreyfus Utility Stock
Fund, a portfolio of marketable equity securities of electric
utility companies that are members of the Edition Electric
Institute, including Pacific Gas and Electric Company.
Participants should refer to the separate master trust financial statements
or their individual quarterly Savings Fund Plan account statements for
information relating to the activity in each of the investment options.
5
<PAGE>
PACIFIC GAS AND ELECTRIC COMPANY
SAVINGS FUND PLAN - PART II
NOTES TO FINANCIAL STATEMENTS
December 31, 1995
NOTE 4: Investments (Continued)
A participant's interest in the investment funds is represented by
participation units allocated on the basis of contributions and assigned a unit
value on the basis of the total value in each fund. The Company Stock Fund and
the Guaranteed Income Fund converted to unitization in April 1995 to accommodate
daily valuation. For investments in the United States Savings Bond Fund , a
unit is one bond.
6
<PAGE>
PACIFIC GAS ELECTRIC COMPANY
SAVINGS FUND PLAN - PART II
NOTES TO FINANCIAL STATEMENTS
December 31, 1995
NOTE 4: Investments (Continued)
The following summarizes the net assets and related investment gain of the
Master Trust and the Plan's allocated share of such amounts:
<TABLE>
<CAPTION>
----------In Thousands---------
1995 1994
<S> <C> <C>
Investments, at fair value:
Company Stock Fund
Pacific Gas and Electric Company common stock $1,161,205 $1,131,413
United States government securities 5,466 5,169
DEF
Corporate stocks - preferred - 1,048
Corporate stocks - common 503,528 340,032
GIF
Corporate debt intruments 63,540 53,210
Insurance company general accounts 146,976 151,704
Registered investment companies
Vanguard Bond Market Fund 26,394 23,632
Columbia Balanced Fund 127,992 102,861
Dreyfus Utility Stock Fund 49,284 45,458
Interest bearing accounts 55,584 72,645
---------- ----------
Total investments 2,139,969 1,927,172
---------- ----------
Receivables:
Dividends and interest 22,698 27,365
Other receivables 3,384 6,293
---------- ----------
Total receivables 26,082 33,658
---------- ----------
Total assets 2,166,051 1,960,830
---------- ----------
LIABILITIES - 11,407
---------- ----------
NET ASSETS $2,166,051 $1,949,423
========== ==========
Allocated to the Plan $1,159,330 $1,105,628
Allocated to other plans 1,006,721 843,795
---------- ----------
$2,166,051 $1,949,423
========== ==========
</TABLE>
7
<PAGE>
PACIFIC GAS ELECTRIC COMPANY
SAVINGS FUND PLAN - PART II
NOTES TO FINANCIAL STATEMENTS
December 31, 1995
NOTE 4: Investments (Continued)
The composition of the Master Trust investment gain for the year ended
December 31, 1995 is as follows:
<TABLE>
<CAPTION>
-In Thousands-
<S> <C>
Interest income
Interest bearing accounts $ 3,637
United States government securities 63
Fixed income investments 11,386
--------
Total interest income 15,086
--------
Dividend income
Common stock 92,405
Registered investment companies 4,061
--------
Total dividend income 96,466
--------
Other income 40
Net appreciation in value of investments 329,685
--------
Total investment gain $441,277
========
Allocated to the Plan 287,336
Allocated to other plans 153,941
--------
$441,277
========
</TABLE>
8
<PAGE>
PACIFIC GAS ELECTRIC COMPANY
SAVINGS FUND PLAN - PART II
NOTES TO FINANCIAL STATEMENTS
December 31, 1995
NOTE 4: Investments (Continued)
The net appreciation in fair value of investments of the Master Trust by major
investment category for the year ended December 31, 1995 is as follows:
<TABLE>
<CAPTION>
-In Thousands-
<S> <C>
Pacific Gas and Electric Company Common Stock Fund $169,483
Diversified Equity Fund 124,845
Bond Index Fund 2,378
Stock and Bond Fund 24,065
Utility Stock Fund 8,914
--------
Total appreciation 329,685
========
Allocated to the Plan 217,927
Allocated to other plans 111,758
--------
$329,685
========
</TABLE>
9
<PAGE>
PACIFIC GAS ELECTRIC COMPANY
SAVINGS FUND PLAN I
NOTES TO FINANCIAL STATEMENTS
December 31, 1995
NOTE 4: Investments (continued)
The net asset value per unit of the DEF, BIF, SBF, and USF is determined by
dividing the fair value of Fund assets by the number of Fund units outstanding.
The net asset value per unit of the GIF is $1.00 of contributions or interest
earned represents one unit. The total number of units held by the Plan and the
value per unit of the DEF, GIF, BIF, SBF and ISF for the quarters ended December
31, 1995 and 1994 are as follows:
<TABLE>
<CAPTION>
1995
----
March 31 June 30 September 30 December 31
- --------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Company Stock Fund*
Number of units N/A 68,143,409 66,801,849 65,031,629
Value per unit N/A $11.99 $12.53 $12.13
DEF
Number of units 2,850,195 2,937,324 2,994,629 3,019,934
Value per unit $67.27 $67.91 $71.50 $71.72
GIF**
Number of units 89,579,744 94,675,847 97,616,222 99,953,495
Value per unit $1.00 $1.01 $1.03 $1.04
BIF
Number of units 463,904 520,133 548,113 587,137
Value per unit $12.32 $12.99 $13.30 $13.89
SBF
Number of units 4,070,259 4,201,058 4,402,379 4,934,990
Value per unit $6.61 $7.03 $7.39 $7.77
USF
Number of units 1,317,434 1,286,634 1,249,692 1,326,902
Value per unit $13.27 $14.14 $15.12 $16.50
- --------------------------------------------------------------------------------
</TABLE>
* The Company Stock Fund converted to a unitized fund in April 1995.
** The GIF Fund converted to a unitized fund in April 1995 and the unit value
was no longer fixed at $1.00.
10
<PAGE>
PACIFIC GAS ELECTRIC COMPANY
SAVINGS FUND PLAN I
NOTES TO FINANCIAL STATEMENTS
December 31, 1995
NOTE 4: Investments (continued)
<TABLE>
<CAPTION>
1994
----
March 31 June 30 September 30 December 31
- --------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Company Stock Fund*
Number of units N/A N/A N/A N/A
Value per unit N/A N/A N/A N/A
DEF
Number of units 1,753,173 1,806,766 1,842,015 1,857,851
Value per unit $67.27 $67.91 $71.50 $71.72
GIF**
Number of units 115,940,854 111,793,335 114,408,326 139,870,385
Value per unit $1.00 $1.00 $1.00 $1.00
BIF
Number of units 731,690 694,599 661,711 626,501
Value per unit $11.61 $11.63 $11.68 $11.75
SBF
Number of units 5,151,085 5,175,363 5,125,664 4,939,662
Value per unit $6.11 $6.06 $6.21 $6.21
USF
Number of units 2,296,953 2,051,696 1,942,128 1,709,406
Value per unit $12.98 $11.89 $12.24 $12.73
- --------------------------------------------------------------------------------
</TABLE>
* The Company Stock Fund converted to a unitized fund in April 1995.
** The GIF Fund converted to a unitized fund in April 1995 and the unit value
was no longer fixed at $1.00.
11
<PAGE>
PACIFIC GAS AND ELECTRIC COMPANY
SAVINGS FUND PLAN - PART II
NOTES TO FINANCIAL STATEMENTS
December 31, 1995
NOTE 5: Subsequent Event
The market price of Pacific Gas and Electric Company common stock declined
by 7.9% between December 31, 1995 and March 5, 1996. This represents a decrease
of approximately $92 million in the fair value of the Company Stock Fund.
12
