<PAGE> 1
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
<TABLE>
<S> <C> <C>
(MARK ONE)
/X/ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF
</TABLE>
THE SECURITIES EXCHANGE ACT OF 1934 [FEE REQUIRED]
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1994
OR
<TABLE>
<S> <C> <C>
/ / TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF
</TABLE>
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
(STATE OR OTHER JURISDICTION OF
INCORPORATION OR ORGANIZATION)
77 Beale Street
P.O. Box 770000
San Francisco, California
(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES)
94-0742640
(IRS EMPLOYER IDENTIFICATION NO.)
94177
(ZIP CODE)
(415) 973-7000
(REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE)
SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:
<TABLE>
<CAPTION>
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
</TABLE>
<TABLE>
<CAPTION>
Redeemable:
<C> <S> <C>
8.20% 7.04 % 4.80%
8% 6.875% 4.50%
7.84% 5% 4.36%
7.44% 5% Series A
Nonredeemable:
6% 5.5% 5%
</TABLE>
First and Refunding Mortgage Bonds: New York
Stock Exchange
<TABLE>
<CAPTION>
INTEREST DATE OF
SERIES RATE % MATURITY
- ------- -------- --------------
<S> <C> <C>
II 4-1/4 Jun. 1, 1995
JJ 4-1/2 Jun. 1, 1996
KK 4-1/2 Dec. 1, 1996
</TABLE>
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 the Company's Common Stock outstanding at
March 6, 1995 was 430,151,818. On that date the aggregate market value of the
voting stock held by nonaffiliates of the Company was approximately $11,511
million. The market values of the various classes of voting stock held by
nonaffiliates were as follows: Common Stock, $10,787 million; and First
Preferred Stock, $724 million. The market values of certain series of First
Preferred Stock, for which market prices were not available, were derived by
dividing the annual dividend rate of each such series of stock by the average
yield of all of the Company's Preferred Stock outstanding for which market
prices were available.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the documents listed below have been incorporated by reference
into the indicated parts of this report, as specified in the responses to the
item numbers involved.
<TABLE>
<S> <C> <C>
(1) Designated portions of the Annual Report to Shareholders for the
year ended December 31, 1994...................................... Part II (Items 5, 6, 7 and 8)
Part IV (Item 14)
(2) Designated portions of the Proxy Statement relating to
the 1995 annual meeting of shareholders........................... Part III (Items 10, 11, 12 and 13)
</TABLE>
<PAGE> 2
TABLE OF CONTENTS
<TABLE>
<CAPTION>
PAGE
-----
<S> <C> <C>
Glossary of Terms
PART I
Item 1. Business..................................................................... 1
General
Corporate Structure and Business............................................. 1
Competition and Industry Restructuring....................................... 2
Gas Industry................................................................. 2
Electric Industry............................................................ 3
The Company's Response to the New Competitive Environment.................... 3
California Ratemaking Mechanisms............................................. 5
Base Revenue Mechanisms...................................................... 5
Electric Fuel Revenue Mechanisms............................................. 5
Gas Fuel Revenue Mechanisms.................................................. 6
Other Rate Adjustment Mechanisms............................................. 7
Proposed Regulatory Reforms.................................................. 7
Electric Industry Restructuring Proposal..................................... 7
Financial Impact of the Electric Industry Restructuring Proposal............. 9
Company's Proposals.......................................................... 10
Current Rate Proceedings..................................................... 12
1995 Revenue Changes......................................................... 12
Biennial Cost Allocation Proceeding.......................................... 13
1996 General Rate Case....................................................... 14
Workforce Reduction Rate Mechanism........................................... 14
Customer Energy Efficiency/Demand Side Management Programs................... 14
Capital Requirements and Financing Programs.................................. 15
Electric Utility Operations
Electric Operating Statistics................................................ 17
Electric Generating and Transmission Capacity................................ 18
Electric Load Forecast and Resource Planning and Procurement................. 19
Electric Resources........................................................... 20
QF Generation................................................................ 20
Geothermal Generation........................................................ 21
Western Systems Power Pool................................................... 21
Electric Transmission Policies............................................... 21
Transmission Access and Pricing.............................................. 21
Regional Transmission Groups................................................. 22
Stranded Costs Rulemaking.................................................... 22
CPUC Transmission Policies................................................... 22
Electric Reasonableness Proceeding........................................... 23
Helms Pumped Storage Plant................................................... 23
Gas Utility Operations
Gas Operations............................................................... 24
Gas Operating Statistics..................................................... 25
Natural Gas Supplies......................................................... 26
Gas Regulatory Framework..................................................... 26
Restructuring of Canadian Gas Supply Arrangements............................ 27
Decontracting Plan........................................................... 27
Financial Impact of Decontracting Plan and Litigation........................ 28
Restructuring of Interstate Gas Supply Arrangements.......................... 28
Current Gas Transportation and Procurement Arrangements...................... 28
Recovery of Interstate Transportation Demand Charges......................... 28
Gas Reasonableness Proceedings............................................... 29
1988-1990 Canadian Gas Procurement Activities................................ 30
Proposed Gas Settlements..................................................... 30
Financial Impact of Gas Reasonableness Proceedings........................... 30
PGT/PG&E Pipeline Expansion Project.......................................... 31
Other Competitive Pipeline Projects.......................................... 32
Storage Service.............................................................. 32
</TABLE>
<PAGE> 3
<TABLE>
<CAPTION>
PAGE
-----
<S> <C> <C>
Diablo Canyon
Diablo Canyon Operations..................................................... 33
Diablo Settlement............................................................ 33
Nuclear Fuel Supply and Disposal............................................. 35
Insurance.................................................................... 36
Decommissioning.............................................................. 36
PG&E Enterprises
Non-Utility Electric Generation.............................................. 36
Gas and Oil Exploration and Production....................................... 37
Real Estate Development...................................................... 37
Environmental Matters and Other Regulation
Environmental Matters........................................................ 37
Environmental Protection Measures............................................ 38
Hazardous Materials and Hazardous Waste Compliance and Remediation........... 39
Electric and Magnetic Fields................................................. 42
Low Emission Vehicle Programs................................................ 42
Other Regulation............................................................. 43
California Public Utilities Commission....................................... 43
California Energy Commission................................................. 43
Federal Energy Regulatory Commission......................................... 43
FERC-Hydroelectric Licensing................................................. 43
Nuclear Regulatory Commission................................................ 44
Item 2. Properties................................................................... 44
Item 3. Legal Proceedings............................................................ 44
Antitrust Litigation......................................................... 44
Hinkley Compressor Station Litigation........................................ 45
Counties Franchise Fees Litigation........................................... 46
Cities Franchise Fees Litigation............................................. 46
Time-of-Use Meter Litigation................................................. 47
Norcen Litigation............................................................ 47
Potter Valley Hydroelectric Project.......................................... 48
PGT Unit 4C Compressor Unit Permit........................................... 48
Item 4. Submission of Matters to a Vote of Security Holders.......................... 49
Executive Officers of the Registrant......................................... 49
PART II
Item 5. Market for the Registrant's Common Equity and Related Stockholder Matters.... 50
Item 6. Selected Financial Data...................................................... 50
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations...................................................... 50
Item 8. Financial Statements and Supplementary Data.................................. 50
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure....................................................... 50
PART III
Item 10. Directors and Executive Officers of the Registrant........................... 50
Item 11. Executive Compensation....................................................... 50
Item 12. Security Ownership of Certain Beneficial Owners and Management............... 50
Item 13. Certain Relationships and Related Transactions............................... 51
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K............. 51
Indemnification Undertaking.................................................. 55
Signatures............................................................................... 56
Report of Independent Public Accountants................................................. 57
Financial Statement Schedule............................................................. 58
</TABLE>
<PAGE> 4
GLOSSARY OF TERMS
<TABLE>
<S> <C>
AEAP.................. Annual Earnings Assessment Proceeding
AER................... Annual Energy Rate
AFUDC................. allowance for funds used during construction
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 Proceeding
BTA................... best technology available
Btu................... British thermal unit
California
Superfund........... California Hazardous Substance Account Act
CARE.................. California Alternate Rates for Energy program (formerly, LIRA)
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
core customers........ All residential gas customers and smaller commercial gas customers
that do not exceed certain volume limitations
core subscription
customers........... Noncore customers who elect to receive combined gas procurement and
transportation service from the Company
CPIM.................. Core Procurement Incentive Mechanism
CPUC.................. California Public Utilities Commission
CTC................... Competition Transition Charge
DALEN................. DALEN Resources Corp.
Diablo Canyon......... Diablo Canyon Nuclear Power Plant
Diablo Settlement..... Diablo Canyon rate case settlement
DOE................... U.S. Department of Energy
DPS................... Destec Power Services
DRA................... Division of Ratepayer Advocates
DSM................... Demand Side Management
DTSC.................. California Department of Toxic Substances Control
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................... Environmental Protection Agency
ERAM.................. Electric Revenue Adjustment Mechanism
ER94.................. 1994 Electricity Report
EV.................... electric vehicle
FERC.................. Federal Energy Regulatory Commission
Geysers............... The Geysers Power Plant
GFCA.................. Gas Fixed Cost Account
GRC................... General Rate Case
</TABLE>
<PAGE> 5
<TABLE>
<S> <C>
GWh................... gigawatt-hours
Helms................. Helms Pumped Storage Project
Helms Settlement...... proposed settlement resolving the treatment of unrecovered Helms
costs
Humboldt.............. Humboldt Bay Power Plant
IPP................... independent power producer
ITCS.................. Interstate Transition Cost Surcharge
kV.................... kilovolts
kVa................... kilovolt-amperes
kW.................... kilowatts
kWh................... kilowatt-hour
LEV................... low emission vehicle
LIRA.................. Low Income Rate Assistance program (now referred to as CARE)
Makowski.............. J. Makowski Co., Inc.
Mcf................... thousand cubic feet
MMBtu/d............... million British thermal units per day
MMcf.................. million cubic feet
MMcf/d................ million cubic feet per day
Mojave................ Mojave Pipeline Company
MW.................... megawatts
NEIL.................. Nuclear Electric Insurance Limited
NGV................... natural gas vehicle
NML................... Nuclear Mutual Limited
noncore customers..... industrial and commercial gas customers that exceed certain volume
limitations
NOx................... oxides of nitrogen
NOVA.................. NOVA Corporation of Alberta
Nuclear Act........... Nuclear Waste Policy Act of 1982
OIR/OII............... Order Instituting Rulemaking and Investigation
OPA................... Oil Pollution Act of 1990
OSPRA................. Oil Spill Prevention and Response Act of 1990
PBR................... performance-based ratemaking
PCBs.................. polychlorinated biphenyls
PGA................... Purchased Gas Account
PG&E.................. Pacific Gas and Electric Company
PGT................... Pacific Gas Transmission Company
Pipeline Expansion.... The expansion of the Company's and PGT's natural gas transmission
systems which was placed in service in November 1993
Properties............ PG&E Properties, Inc.
PRP................... potentially responsible party
PURPA................. Public Utility Regulatory Policies Act of 1978
PXC................... Power Exchange Corp.
QF.................... qualifying facility
RD&D.................. research development & demonstration
RDW................... Rate Design Window
Regional Board........ Central Coast Regional Water Quality Control Board
RRI................... Regulatory Reform Initiative
RTG................... Regional Transmission Group
</TABLE>
<PAGE> 6
<TABLE>
<S> <C>
SFAS.................. Statement of Financial Accounting Standards
SoCal Gas............. Southern California Gas Company
SPCC.................. Spill Prevention Control and Countermeasure
TID................... Turlock Irrigation District
TCRM.................. Transition Cost Recovery Mechanism
Transwestern.......... Transwestern Pipeline Company
USGen................. U.S. Generating Company
USOSC................. U.S. Operating Services Company
WRTA.................. Western Regional Transmission Association
WSPP.................. Western Systems Power Pool
</TABLE>
<PAGE> 7
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 the context otherwise requires, the Company or PG&E shall
refer to Pacific Gas and Electric Company and its wholly owned and
majority-owned subsidiaries.)
The Company'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, 1994, the Company had approximately $27.8 billion in
assets. The Company generated approximately $10.4 billion in operating revenues
for 1994. As of December 31, 1994, 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 $10.2 billion in revenues in 1994 (98%
of the Company's total revenues). The Company's utility operations contributed
$2.20 of the Company's total 1994 earnings per share of $2.21. The Company's
utility assets were $26.3 billion at December 31, 1994, representing 95% 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 1994, Diablo Canyon contributed $1.9 billion of revenues
(18% of the Company's total revenues) and $1.04 in earnings per share (47% of
the Company's total 1994 earnings per share). Diablo Canyon had assets of $6.0
billion at December 31, 1994 (22% of the Company's total assets).
The Company's utility service territory covers 94,000 square miles with an
estimated population of approximately 13 million, and includes all or portions
of 48 of California's 58 counties. The area's diverse economy includes
aerospace, electronics, financial services, food processing, petroleum refining,
agriculture and tourism. At December 31, 1994, the Company served approximately
4.4 million electric customers and 3.5 million gas customers.
The Company serves its electric customers with power generated by seven
primarily natural gas-fueled steam power plants with 21 units, ten combustion
turbines, the Diablo Canyon nuclear power plant with 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. The Company also
purchases power produced by other generating entities that use a wide array of
resources and technologies, including hydroelectric, wind, solar, biomass,
geothermal and cogeneration. In addition, the Company is interconnected with
electric power systems in 14 western states and British Columbia, Canada, for
the purposes of buying, selling and transmitting power.
To ensure a diverse and competitive mix of natural gas supplies, the
Company purchases gas from both Canadian and United States suppliers. In 1994,
about 53% of the Company's gas supply came from fields in Canada, about 42% came
from fields in other states (substantially all from the U.S. Southwest) and
about 5% came from fields in California.
The Company's utility operations also include Pacific Gas Transmission
Company (PGT), a wholly owned gas pipeline subsidiary of the Company. PGT owns
and operates gas transmission pipelines and associated facilities capable of
transporting approximately 2.4 billion cubic feet per day of natural gas over
612 miles from the Canadian-U.S. border to the Oregon-California border. PGT had
assets of approximately $1.2 billion at December 31, 1994. PGT's revenues in
1994 were approximately $175 million, excluding revenues related to services
provided to the Company.
1
<PAGE> 8
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" and
"Proposed Regulatory Reforms"), a number of proposals are being considered which
would shift utility regulation from traditional cost-of-service based concepts
to concepts based upon market competition and benchmarks.
Diablo Canyon operations are 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 Enterprises (Enterprises), a wholly owned subsidiary of the Company,
is the parent company for the nonregulated portion of the Company's business.
Enterprises, through its subsidiaries and affiliates, engages in nonutility
electric generation, power plant operations and services, gas and oil
exploration and production and real estate development. Enterprises generated
approximately $250 million in revenues in 1994 and contributed $.01 of the
Company's total 1994 earnings per share of $2.21. Enterprises had assets of $1.5
billion at December 31, 1994.
COMPETITION AND INDUSTRY RESTRUCTURING
Under traditional utility regulatory schemes, utilities have been accorded
the exclusive right to serve customers within designated 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.
Recent changes in both the gas and electric industries have allowed
competition to develop in the gas supply and electric production segments of the
Company's business. A number of reforms at both the federal and state level have
been proposed. These reforms are designed to restructure regulation in the
energy supply industry and promote competition by providing electric and gas
customers with purchasing options.
GAS INDUSTRY
The current regulatory framework for natural gas service was established in
California in 1988. This framework segmented customers into core (all
residential customers and smaller commercial customers that do not exceed
certain volume limitations) and noncore (industrial and commercial customers
that exceed certain volume limitations) classes, and unbundled utilities' gas
transportation and procurement services which allowed noncore customers to
purchase gas directly from producers, aggregators and marketers and separately
negotiate transportation services. Similarly, in 1992 the Federal Energy
Regulatory Commission (FERC) instituted regulatory changes which required
interstate pipelines, including PGT, to unbundle sales services from
transportation services and established programs providing for the reallocation
of pipeline capacity.
As a result of these regulatory changes, the Company no longer provides
combined procurement and transportation services to most of its noncore
customers. Instead, many of these customers now procure their own gas supplies
and then purchase transportation service from the Company. As a result, the
Company has restructured its own gas operations to accommodate its decreased gas
supply and transportation requirements. The Company has terminated its long-term
Canadian gas purchase contracts and entered into new, more flexible arrangements
for the purchase of the Company's reduced gas supply requirement and is
continuing its efforts to permanently assign or broker its commitments for firm
gas transportation capacity on interstate pipelines which it once held to serve
its noncore customers.
The changes in the supply and transportation segments of the gas industry
will likely result in increased competition. The FERC has conditionally approved
the expansion of an interstate pipeline's existing system into the Company's
service territory. See "Gas Utility Operations -- Other Competitive Pipeline
Projects" below. If built, this pipeline will compete directly for
transportation service to the Company's noncore customers and may result in the
loss of sales on the Company's gas transportation system. If the Company's
2
<PAGE> 9
gas customers leave the Company's system by moving to an alternative intrastate
delivery system, the Company will need to recover the fixed costs of its gas
supply and delivery system over fewer units of sales. Unless costs are reduced
or imposed as transition charges on exiting customers, the price per unit for
remaining customers would go up, further exacerbating the competitive pressures.
ELECTRIC INDUSTRY
While the restructuring of the electric industry is still evolving,
recently effected and currently proposed changes at both the federal and state
levels are expected to bring increased competition into the electric generation
business. The Company performs the functions of electricity production,
transmission, distribution and customer service. However, the Company already
obtains one-third of its electrical power supply from generation sources outside
its service territory and from qualifying facilities (QFs), small power
producers or cogenerators who meet certain federal guidelines which qualify them
to supply generating capacity and electric energy to utilities, owned and
operated by independent power producers (IPPs). It is expected that new power
plant projects will be increasingly undertaken by IPPs rather than utilities. In
addition, the recently enacted National Energy Policy Act of 1992 (Energy Act)
reduces various restrictions on the operation and ownership of IPPs and provides
them and other wholesale suppliers and purchasers with increased access to
electric transmission lines throughout the United States.
At the state level, in April 1994 the California Public Utilities
Commission (CPUC) issued a proposal on electric industry restructuring which
seeks to lower energy prices and provide customers with a choice of electric
generation suppliers (known as direct access). In addition, where competition
does not exist, the CPUC proposes to move electric utilities from traditional
regulation, under which the utilities' revenues are set by regulators so as to
cover the utilities' costs and provide a fair rate of return, to
performance-based ratemaking (PBR). The shift to PBR is intended to provide
stronger incentives for efficient utility operations, management and investment.
Under its April 1994 proposal, the CPUC would unbundle electric services
and, on a phased-in basis over time, provide to electric utility retail
customers the option to choose from a range of electric generation providers,
including utilities, beginning in 1996. This plan is termed "direct access."
Utilities serving a given territory would still be obligated to provide
transmission and distribution services on a nondiscriminatory basis to customers
choosing direct access service from another generation provider, thereby
engaging in the practice known as retail wheeling. Coinciding with these
changes, the CPUC foresees development of a competitive spot market for electric
generation and an increasing need for inter-regional coordination of the
electric grid, and elimination of existing resource planning and procurement
approaches.
If as a result of restructuring a substantial number of the Company's
customers were to elect electric generation alternatives under a retail wheeling
system, the Company's recovery of its purchased power obligations to QFs and its
investment in its electric generation assets would be dependent on prices
charged to remaining customers, transition charges that may be imposed on
existing customers, and the Company's ability to reduce its costs. While the
CPUC proposal contemplates that some stranded costs of utility generating
facilities be recovered through a "competition transition charge," the CPUC has
not specified whether other costs, such as regulatory assets and QF obligations,
might be recovered through such a charge or how such charge would be allocated
to and collected from customers. See "Proposed Regulatory Reforms -- Electric
Industry Restructuring Proposal" below.
THE COMPANY'S RESPONSE TO THE NEW COMPETITIVE ENVIRONMENT
The restructuring of the electric and gas industries has led to a greater
emphasis on the Company's ability to offer its services at competitive prices.
Currently, the Company's average gas prices for residential, commercial and
industrial customers are among the lowest utility gas prices in California. The
Company's residential electric bills are at the middle of the scale nationally.
However, the Company's prices per kWh are high when compared with national
averages. The Company's prices for industrial customers average approximately
7.0 cents per kWh, which is comparable to prices charged by the other major
California
3
<PAGE> 10
utilities, but above the industrial electric prices in many other states. The
Company's electric prices include the costs for generation, transmission,
distribution and customer service.
The Company has taken several significant steps to address the issues
raised by the new competitive environment in the energy industry. These steps
include proposals to modify the existing regulatory process and to provide the
Company additional pricing flexibility for those customers with the most
competitive options. These proposals, together with various cost containment
measures implemented by the Company, are intended to help position the Company
to effectively compete in the restructured electric and gas industries. With
this goal in mind:
-- The Company has proposed to extend through 1996 its electric rate
freeze, which began in 1993.
-- The Company has announced a five-year goal of reducing its system
average electric rate to 10 cents per kWh or less, which would
constitute about a 25% reduction in the Company's system average
electric rate after adjusting for inflation.
-- In December 1994, the Company, the CPUC's Division of Ratepayer
Advocates (DRA), the California Attorney General and other parties
proposed to modify the Diablo Settlement to reduce the price paid for
electricity generated at Diablo Canyon over the next five years. See
"Diablo Canyon -- Diablo Settlement" below.
-- The Company has requested CPUC approval to implement a statewide
three-year experimental program under which California utilities would
offer certain industrial customers and other large energy users the
option to receive electricity from competitive suppliers, starting as
early as January 1, 1996.
-- The Company has proposed instituting PBR for determining base revenues,
under which electric and natural gas base revenues would be determined
annually by formula rather than through general rate cases (GRCs),
attrition rate adjustments (ARAs) and Cost of Capital proceedings. The
Company has also proposed a core gas procurement incentive mechanism
(CPIM) that would substitute for reasonableness reviews of certain
costs. The CPIM would measure the Company's gas procurement costs
against market benchmarks and would provide for the sharing between
ratepayers and shareholders of variances from a preset range around the
market benchmark.
-- The Company has reduced electric rates for certain of its largest
industrial customers through an economic stimulus rate that the Company
proposes to extend through the end of 1996.
-- The Company has planned reductions in annual spending in 1995 of
approximately $600 million from 1993 spending levels.
-- The Company has refinanced debt and preferred stock over the last three
years resulting in annual savings of approximately $97 million in
financing costs.
-- Through its wholly owned subsidiary, Enterprises, the Company has taken
steps to position itself to compete in the nonregulated energy business.
In 1994, Enterprises and Bechtel Enterprises, Inc. acquired J. Makowski
Co., Inc. (Makowski), a company engaged in the development of natural
gas-fueled power generation projects and natural gas distribution,
supply and underground storage projects. In addition, Enterprises, in
partnership with Bechtel Enterprises, Inc., is in the process of forming
a company to develop, build, own and operate international nonutility
generation projects.
While it is difficult to predict the ultimate outcome of the ongoing
changes that are taking place in the utility industry, the Company believes that
the end result will involve a fundamental change in the way it conducts its
business. The changes may impact financial operating trends and add volatility
to the Company's earnings. The Company is actively seeking regulatory and
operational changes that will allow the Company to provide energy services in a
safe, reliable and competitive manner while achieving strong financial
performance.
4
<PAGE> 11
CALIFORNIA RATEMAKING MECHANISMS
The ratemaking mechanisms currently applied by the CPUC in setting the
Company's rates are discussed below. As more fully discussed below (see
"Proposed Regulatory Reforms -- Company's Proposals"), the Company has filed
proposals with the CPUC requesting alternatives to certain aspects of the
current regulatory approach to setting rates. If adopted, those proposals would
significantly alter the existing ratemaking mechanisms. In addition, the Company
proposes to continue through 1996 its freeze on retail electric rates, first
implemented in 1993, which impacts the application of certain of these
ratemaking mechanisms in current rate proceedings (see "Current Rate
Proceedings" below).
BASE REVENUE MECHANISMS
Under the CPUC's Rate Case Plan, the CPUC sets the Company's base revenue
requirements for both electric and gas operations in the GRC proceeding. Base
revenue is revenue intended to recover the Company's fixed costs and non-fuel
variable costs and to provide a return on invested capital. (Fuel revenue
requirements, intended to recover the Company's fuel and fuel-related costs, are
set as part of the Energy Cost Adjustment Clause (ECAC) proceeding for electric
operations and the Biennial Cost Allocation Proceeding (BCAP) for gas
operations, as discussed below.) In the GRC, revenues and expenses are
determined on a forecast or future test-year basis, rather than on a
historic-year basis. The Company files a GRC application once every three years,
with a decision issued approximately 13 months after the application is filed.
The Company's current rates are based on its 1993 GRC. The Company filed its
1996 GRC application in December 1994, for rates effective January 1, 1996.
The ARA adjusts base rates in the years between GRC decisions to partially
offset attrition in earnings due to changes in non-fuel operating expenses and
capital costs. Labor expenses and nonlabor maintenance and operation expenses
are indexed, and a prescribed amount is allowed for recovery of expenses related
to changes in depreciation, income taxes, financing costs, rate base growth and
other items. The ARA improves the Company's ability to earn its authorized rate
of return for utility operations in the years between GRCs. The cost of capital
incorporated in an ARA, including authorized return on equity, 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.
In May 1993, the DRA and various special interest groups filed a joint
petition with the CPUC requesting suspension, for an indefinite period, of the
ARA mechanism. The petition requests that any future attrition rate increases be
considered only upon application for such relief and only if the then current
rate of inflation exceeds 6% on an annual basis. The petition recommends that
any attrition rate adjustment authorized in such cases be limited to inflation
above the 6% threshold level. The CPUC has not acted on the DRA's petition, but
its staff has recommended that the petitioners raise the matter in the Company's
1996 GRC.
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.
ELECTRIC FUEL REVENUE MECHANISMS
The ECAC provides for recovery of 91% of 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 (formerly known as
5
<PAGE> 12
the Low Income Rate Assistance, or LIRA, 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.
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 "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 the Company 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.
GAS FUEL REVENUE MECHANISMS
The BCAP is the major rate proceeding for the Company's natural gas
service. 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 core customers;
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, and also includes the gas base revenue
requirement set in the GRC and adjusted by the ARA mechanism.
Both the gas fuel revenue requirement and the gas transportation revenue
requirement set in the BCAP include amounts accumulated in several associated
balancing accounts. The main balancing account associated with the gas fuel
revenue requirement is the Purchased Gas Account (PGA), which accumulates
differences between the actual cost of gas procured for core customers and the
revenues intended to recover those costs. The main balancing accounts associated
with the gas transportation revenue requirement are the core and noncore Gas
Fixed Cost Accounts (GFCAs), which generally accumulate differences between the
actual transportation revenues and the authorized transportation revenue amounts
for the core and noncore customer classes, respectively. In the case of the
noncore GFCA, only 75% of any overcollection or undercollection of revenues is
included in rates.
BCAP rate adjustments may also include amounts accumulated in the
Interstate Transition Cost Surcharge (ITCS) balancing account. Demand charges
for interstate gas transportation capacity held by a utility which are not fully
recovered under the operation of the CPUC's capacity brokering rules accumulate
in the ITCS account and are recovered as authorized by the CPUC. Unrecovered
demand charges will be allocated to customers on an equal cents-per-therm-usage
basis, subject to a limit on the amount that can be allocated to core customers.
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.
Revenue allocation (also referred to as cost allocation) is based primarily on
forecasts of demand and use by each customer class. 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. An interim filing, referred to
as a trigger filing, is permitted to set new rates for the second year of the
BCAP period if amortization of accumulated overcollections or undercollections
in balancing accounts would change either bundled core rates or noncore
transportation rates by more than 5%.
6
<PAGE> 13
In December 1992, the CPUC announced proposed rules which would (i) extend
the gas ratemaking cycle from two to three years and (ii) reduce the amount of
balancing account protection provided for noncore transportation revenues. Other
than accepting comments from interested parties, the CPUC has taken no further
action on the proposed rules.
OTHER RATE ADJUSTMENT MECHANISMS
Under the Customer Energy Efficiency (CEE) ratemaking mechanism adopted in
1990, the Company 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 the Company 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.
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.
PROPOSED REGULATORY REFORMS
A number of proposals have been made by both the CPUC and the Company to
effect reforms to the current regulatory approach to setting rates for
California utilities. The most significant of these proposed reforms are
detailed below.
ELECTRIC INDUSTRY RESTRUCTURING PROPOSAL
In April 1994, the CPUC issued an order instituting a rulemaking and
investigation (OIR/OII) on electric industry restructuring. The proposal, which
is subject to comment and modification, involves two major changes in electric
industry regulation.
The first would move electric utilities from traditional ratemaking to PBR.
The second would unbundle electric services and provide electric utility retail
customers the option to choose from a range of electric generation providers,
including utilities. The CPUC characterized this approach as customer direct
access. Under the CPUC's proposal, customer direct access to power supplies
would be phased in over a six-year period from 1996 to 2002. Utilities would
still be obligated to provide transmission and distribution services to all
customers.
To ensure an orderly transition that maintains the financial integrity of
the utilities, the CPUC proposed that uneconomic costs of utility generating
assets (i.e., costs which are above market and could not be recovered under
market-based pricing) be recovered through a competition transition charge
(CTC). However, the OIR/OII did not specify which costs might be recovered
through such a transition charge or how such a charge would be allocated to and
collected from customers.
In June 1994, the Company filed its initial comments on the CPUC's
proposal. The Company's response generally supported the CPUC's direct access
approach to restructuring the energy services industry, but proposed an
implementation schedule for direct access beginning in 1996, with direct access
service available to all customers by 2008. The Company indicated that if its
proposed implementation schedule is adopted, it will request recovery of certain
incurred and committed costs through the CTC, but will not request recovery of
transition costs associated with its electric generation facilities. The Company
also indicated that it did not intend to shift costs between customer classes.
For direct access customers, the Company proposed that it be given the pricing
flexibility to compete and sell unbundled electric power while assuming the
market risk of competitive pricing. The Company indicated that its proposed
schedule, coupled with pricing flexibility, will
7
<PAGE> 14
permit the Company sufficient time to reduce its generation costs and recover
its investment in facilities built to meet its long-standing utility service
obligations.
Under the Company's proposed implementation schedule for direct access,
industrial and large commercial customers (which represented approximately 30%
of the Company's electric generation revenues in 1994) would be eligible for
direct access in the period 1996 through 2002. The remaining non-residential
customers (which represent approximately 31% of 1994 electric generation
revenues) would be eligible in the period 2003 through 2006. Residential
customers (which represent approximately 39% of 1994 electric generation
revenues) would be eligible in 2007 and 2008.
In its response, the Company proposed that unless and until a policy
decision is made to discontinue existing environmental or social benefit
programs, the costs of those programs should be allocated to all electric
customers, including those who elect direct access, and included as a separately
identified component on customers' bills. The Company also proposed to retain an
ongoing obligation to provide electric power for residential customers, but
suggested that the utility should be obligated to provide electric supply only
on a best efforts basis to non-residential direct access customers that decide
to return to the Company for their power supply and on terms of service to be
negotiated.
In November 1994, the Company filed testimony with the CPUC on uneconomic
assets and obligations which would result from the CPUC's proposed electric
industry restructuring. The Company indicated that the CTC should be permitted
to provide for three types of costs: (1) utility-owned generation assets and
obligations resulting from power purchase agreements other than contracts with
QFs, (2) QF power purchase obligations, and (3) generation-related regulatory
assets. The Company also indicated that it would not seek CTC recovery for the
first of these categories -- costs associated with utility-owned generation
assets and non-QF obligations -- if direct access is phased in over a 12-year
period consistent with the proposal made by the Company in June 1994 and if
pricing flexibility was provided to allow the Company to successfully compete to
provide energy services to direct access eligible customers.
The Company has since filed revised testimony which reflects the proposed
agreement to modify the pricing provisions of the Diablo Settlement. See "Diablo
Canyon -- Diablo Settlement" below. If the agreement is approved, it would
reduce the amount of potential transition costs associated with the Company's
generation assets.
The table below sets forth the Company's revised estimates of the CTC which
reflects the proposed settlement amounts for Diablo Canyon.
ILLUSTRATION OF PG&E'S POTENTIAL CTC*
USING PG&E'S COMPETITIVE PROXY PRICE AND REVISED DIABLO PRICING
<TABLE>
<CAPTION>
1996 PRESENT VALUE @ 9.2%
($ BILLIONS)
-------------------------------------------------------------------------------------------------------
COMPETITIVE PROXY PRICE (C/KWH)
-------------------------------------------------
DESCRIPTIONS 3.2C IN 1994 4.0C IN 1994 4.8C IN 1994
-------------------------------------------------- ------------- ------------- -------------
<S> <C> <C> <C>
PG&E Generation w/Revised Diablo Pricing.......... $5.9 $0.9 $0.0
QF Contracts...................................... $4.0 $2.9 $2.0
Generation-Related Regulatory Assets.............. $0.9-$1.3 $0.9-$1.3 $0.9-$1.3
Total CTC............................... $10.8-$11.2 $4.7-$5.1 $2.9-$3.3
</TABLE>
- ---------------
* The calculations reflected in the table are based on numerous assumptions,
variables and estimates of future prices, energy supplies and economic trends.
The CTC shown should be viewed only as preliminary estimates. The adopted CTC
could be higher or lower depending on the method and assumptions selected by
the CPUC for deriving the CTC.
These CTC estimates were determined by comparing the future revenue
requirements of generation assets (including Diablo Canyon at the proposed
modified prices) and power purchase obligations over a twenty-year and
thirty-year period, respectively, with the revenues computed at the assumed
market price.
8
<PAGE> 15
The revenue requirement for Diablo Canyon and all Company-owned generation
assets included a return on investment. The actual amount of uneconomic assets
and obligations will depend upon the final form of regulatory changes adopted by
the CPUC and the actual market price of electricity. CTC recovery less than the
amount estimated by the Company will not equate to the loss, if any, the Company
may record as a result of the electric industry restructuring. See "Financial
Impact of the Electric Industry Restructuring Proposal" below.
In December 1994, the CPUC issued an interim decision in the OIR/OII. The
decision set a schedule under which the CPUC would propose a policy decision in
March 1995, with a final policy decision effective no earlier than September
1995. However, on March 21, 1995, the CPUC announced that it was postponing
issuance of its proposed policy statement to allow additional time for analysis
of the extensive record developed in the OIR/OII. It is expected that, when it
is issued, the CPUC's proposed policy statement will be subject to hearings and
state legislative review before it can be implemented.
The CPUC's December 1994 interim decision also established a public working
group to comment on unbundling and cost recovery, social programs and resource
procurement under several different models for restructuring which involve
direct access or a supply pool for use by wholesale and/or retail purchasers of
electricity. The working group, which consisted of the energy utilities and any
other parties who joined voluntarily, submitted its report to the CPUC in
February 1995.
In an effort to allow large energy users to begin exercising choice among
electricity suppliers while public policy issues are resolved in the OIR/OII,
the Company has requested CPUC approval to implement an experimental program
under which California utilities would offer certain customers the option to
receive electricity from competitive suppliers beginning as early as January
1996. See "Company's Proposals -- Experimental Procurement Service for
Customer-Identified Electric Supply" below.
FINANCIAL IMPACT OF THE ELECTRIC INDUSTRY RESTRUCTURING PROPOSAL
The transition to a competitive market environment may affect the Company's
future revenues and cash flows. In the event that recovery of the Company's
costs and investments becomes unlikely or uncertain due to competitive pressures
or regulatory changes, it could cause the Company to write off applicable
portions of its regulatory assets. The final CPUC determination of uneconomic
costs and the method and amount of recovery could adversely affect the Company's
returns on its investments in electric generation assets. If future electric
generation revenues are insufficient to recover the Company's investments and QF
obligations, the Company would recognize a loss upon the determination of the
competitive price for electricity resulting from the electric industry
restructuring. The book value of the Company's generation assets, excluding
Diablo Canyon, is approximately $2.7 billion at December 31, 1994. The net book
value of the Company's investment in Diablo Canyon is approximately $5.2 billion
at December 31, 1994.
The Company currently accounts for the economic effects of regulation in
accordance with the provisions of Statement of Financial Accounting Standards
(SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation." As a
result of applying the provisions of SFAS No. 71, the Company has accumulated
approximately $3.7 billion of regulatory assets, including balancing accounts,
as of December 31, 1994. If the OIR/OII is adopted as proposed by the CPUC or
the Company determines that future electric generation rates will no longer be
based on cost-of-service, the Company will discontinue application of SFAS No.
71 for the electric generation portion of its operations. If such discontinuance
should occur, the Company would write off all applicable generation-related
regulatory assets to the extent that transition cost recovery is not assured.
The regulatory assets attributable to electric generation, excluding balancing
accounts of approximately $700 million which are expected to be recovered in the
near term, are estimated to be $1.6 billion at December 31, 1994. This amount
could vary depending on the allocation methods used.
The final determination of the financial impact will depend on the form of
regulation, including transition mechanisms, if any, adopted by the CPUC and the
groups of customers affected. Currently, the Company is unable to predict the
ultimate outcome of the electric industry restructuring or predict whether such
outcome will have a significant impact on its financial position or results of
operations.
9
<PAGE> 16
COMPANY'S PROPOSALS
Experimental Procurement Service for Customer-Identified Electric Supply
In February 1995, the Company requested CPUC approval to implement a
statewide three-year experimental program under which California utilities would
offer industrial customers and other large energy users the option to receive
electricity from competitive suppliers, starting as early as January 1, 1996.
The Company's proposed program would include the following key features:
-- A group of large electricity users would be permitted to enter into
individually negotiated "buy/sell" agreements with alternative suppliers
of electricity. This "buy/sell" proposal would be modeled to a large
extent after the "customer identified gas" (CIG) program implemented by
the CPUC in 1991 as part of its restructuring of the natural gas
industry. The utility would purchase electricity on behalf of each
participating customer. The electricity would be purchased from any
supplier chosen by the customer, at a price previously negotiated by the
customer. The utility then would resell the electricity to the customer
at the customer's negotiated price, as part of a bundled retail sale to
that customer. For customers who elect to purchase energy from
alternative sources located outside the Company's service territory, the
Company will agree to use a portion of its transmission capacity (up to
50 megawatts (MW) at the Oregon-California border to accommodate
purchases on behalf of customers whose suppliers deliver at that point.
The Company will accept and buy power delivered to its other points of
interconnection, and amounts in excess of 50 MW at the Oregon-California
border interconnection, only if transmission capacity is available.
-- The number of the Company's customers eligible to participate in the
experiment would increase each year. The experimental program initially
would apply in 1996 to customers with annual average demand above 7,500
kilowatts (kW) (approximately 30 customers). In 1997 customers with
annual average demand above 4,000 kW (approximately 50 additional
customers) would be eligible for the program, joined in 1998 by
customers with annual average demand above 2,000 kW (approximately 110
additional customers).
-- Utilities would be permitted to negotiate agreements with customers to
compete with alternative suppliers of electricity. Lower revenues to the
utility resulting from such individually negotiated contracts would not
be offset through rate increases to other customers, putting
shareholders at risk for any loss of revenue resulting from the
experimental program. The Company estimates that if, upon full
implementation of the experiment, all eligible customers who might find
it economic participated in the buy/sell program and were able to use
alternative suppliers to meet their entire load requirements, the
maximum annual revenues that could be lost to the Company, net of
generation costs saved as a result of customers' participation in the
buy/sell program, is approximately $21 million.
-- Customers participating in the "buy/sell" experiment would receive a
predetermined credit on their utility bills which is based on prices
paid to QFs for energy and capacity. This credit is used as a proxy for
the market price of electricity. Added to participating customers' bills
would be the cost of power they negotiated with an alternative supplier.
-- The participating customers' prices would remain fully "bundled," a full
package of services at one price. This would mean that issues such as
unbundling, recover of transition costs, funding of social and
environmental programs and resolution of state and federal
jurisdictional matters would not have to be resolved prior to
commencement of the experimental program.
-- At the conclusion of the three-year experimental program, the
information gained could be used by public policy makers to evaluate the
benefits of customer choice.
PBR
In March 1994, the Company filed an application with the CPUC requesting
that it adopt the Company's proposed Regulatory Reform Initiative (RRI). The
Company's RRI included, among other things, a PBR proposal. While the guiding
principles behind the Company's RRI proposal are not affected by the OIR/OII,
many of the specifics would change. Once the details of the CPUC's electric
industry restructuring plan are
10
<PAGE> 17
sufficiently definitive, the Company proposes to revise its RRI filing to
reflect the CPUC's plan. The Company expects to seek a revised RRI that includes
PBR for determining base revenues annually by formula rather than through GRCs,
ARAs and Cost of Capital proceedings.
CPIM
Specific proposals regarding a gas procurement mechanism were not included
in the Company's March 1994 RRI filing. However, in December 1994, the Company
filed an application for approval of the CPIM, a three-year experimental gas
procurement incentive mechanism for core procurement purchases. The CPIM
reflects an agreement with the DRA and would, among other things, replace
traditional reasonableness review of gas costs with a comparison to a
market-based benchmark.
The CPIM covers all of the Company's purchases of commodity gas and
pipeline capacity for its core and core subscription customers. (Core
subscription customers are noncore customers who elect to receive combined
procurement and transportation service from the Company.) The CPIM does not
cover any gas base costs, including amounts associated with storage operations,
gas and pipeline capacity purchased for the Company's power plants or
out-of-state pipeline capacity beyond that reserved for the core and core
subscription customers.
Under the CPIM, the reasonableness of the Company's core gas purchases is
determined by a comparison of actual costs against a market benchmark. The
Company is either rewarded or penalized depending on whether its actual incurred
costs fall below or above the benchmark and a tolerance band, or reasonableness
zone. The Company would recover all costs that fall within the reasonableness
zone; ratepayers and shareholders would share the costs or savings if actual
costs fall above or below the reasonableness zone.
The Company proposed an expedited schedule under which the CPUC would
approve the CPIM by May 1995. However, protests have been filed requesting
hearings or workshops on the Company's CPIM application, and it is not clear
when a CPUC decision will be issued.
Pricing Flexibility Proposals
The Company has filed testimony in its 1995 electric rate design window
(RDW) proceeding proposing beneficial rate options for certain industrial,
commercial and agricultural customers who might otherwise not take service from
the Company. The CPUC's GRC plan establishes the RDW as a forum for considering
certain rate design changes in years between GRCs. The Company's proposals are
narrowly focused to provide beneficial options to some customers. Specifically,
the Company proposes several standard contracts for commercial and industrial
customers which offer prices based upon the cost of the customer's alternatives
or, in some cases, specified discounts from the Company's rates. (These
contracts are similar to those contemplated in the Large Electric Manufacturing
Class proposal that was included in the Company's March 1994 RRI filing.) In
addition, the Company proposes rate options which would establish discounts from
the current rates charged to certain agricultural customers. Although the
Company's RDW filing seeks to have any revenue shortfall associated with these
rate options allocated to all customers in future revenue allocation
proceedings, in other instances in which the CPUC has approved similar rate
options, revenue shortfalls have been allocated, in whole or in part, to
shareholders.
With respect to gas service, the Company filed a petition with the CPUC in
June 1994 requesting authorization to implement an optional long-term
competitive noncore gas transportation tariff which would be offered to the
Company's largest gas transport customers under a ten-year firm service
agreement. The Company's petition indicated that its shareholders would bear the
risk of any revenue shortfalls attributable to differences between the long-term
rate option and the customer's otherwise applicable standard rate. In September
1994, the CPUC issued a decision approving the Company's proposed long-term
noncore gas transportation tariff, but subject to certain conditions that were
not contemplated by the Company's original proposal. The Company has filed a
petition for rehearing of that decision, and indicated that if the CPUC
continues to insist upon its proposed conditions as the basis for its approval
of the proposed tariff, the Company intends to decline to implement the proposed
tariff and would not voluntarily accept the tariff as modified by the CPUC.
11
<PAGE> 18
As an alternative service option, in October 1994 the Company began
offering a standard 59-month interruptible transportation service, at a rate
comparable to that requested under the noncore gas transportation tariff
proposal, to noncore customers with potential transportation alternatives. A
potential competitor of the Company has filed a complaint at the CPUC
challenging the Company's use of this service option on several grounds. The
CPUC has not yet acted on the complaint.
CURRENT RATE PROCEEDINGS
In August 1994, the Company announced that it would extend through 1995 its
freeze on retail electric rates which began in 1993. The Company also announced
that it would continue its annual $70 million economic stimulus rate reduction
through 1995 for its largest business customers. (The Company has since proposed
to extend its electric rate freeze and the economic stimulus rate reduction
through 1996.)
In December 1994, the CPUC approved the continuation of the electric rate
freeze through 1995 and issued its decisions in the Company's ARA and ECAC
proceedings. In order to accomplish the electric rate freeze, the effects of the
CPUC decisions on the Company's various electric rate proceedings were
consolidated, resulting in a net change in electric rates of zero, effective
January 1, 1995 (see "1995 Revenue Changes" below).
1995 REVENUE CHANGES
The following table summarizes the various rate case decisions that became
effective on January 1, 1995.
SUMMARY OF RATE CASE DECISIONS
EFFECTIVE JANUARY 1, 1995
(IN MILLIONS)
<TABLE>
<CAPTION>
ELECTRIC GAS TOTAL
----- ---- -----
<S> <C> <C> <C>
1995 Attrition (excluding Cost of Capital)...................... $ 0 $ 69 $ 69
1995 Cost of Capital............................................ 105 33 138
Helms Proceeding................................................ 12 -- 12
Petition to Modify 1993 GRC (reduced CEE and RD&D funding)...... (117) (33) (150)
ARA Proceeding.................................................. (158) -- (158)
ITCS............................................................ -- 31 31
ECAC/AER/ERAM/LIRA/CEE.......................................... 158 -- 158
----- ---- -----
Total Change in Revenue Requirement................... $ 0 $100 $ 100
===== ==== =====
</TABLE>
ARA Proceeding. In December 1994, the CPUC issued a resolution authorizing
the Company to implement an ARA to keep the Company's retail electric rates
unchanged through 1995, consistent with the Company's 1995 electric rate freeze.
The CPUC authorized the Company to forgo the electric rate increase of
approximately $170 million that otherwise would have occurred on January 1, 1995
as authorized in the Company's 1993 GRC. In addition, the CPUC adopted the
Company's proposal to decrease electric base revenues in an amount equal to the
increase in revenues approved by the CPUC in the Company's 1995 Cost of Capital
proceeding and ECAC proceeding (as described below), and the increase in
revenues contemplated by the proposed settlement in the Helms proceeding (see
"Electric Utility Operations -- Helms Pumped Storage Plant" below), such that
electric rates will not increase through the end of 1995. The Company is
implementing base cost reductions which are reflected in the decreased base
revenues.
The CPUC also authorized the implementation of an ARA which results in an
increase of $69 million for gas base rates. Combined with the previously
authorized increases of $33 million relating to the 1995 Cost of Capital
proceeding and $31 million for partial recovery of amounts accrued in the ITCS
balancing account (see "Gas Utility Operations -- Restructuring of Interstate
Gas Supply Arrangements -- Recovery of Interstate Transportation Demand Charges"
below), and approval of the Company's request to reduce authorized funding for
gas CEE programs in 1995 by $33 million, gas revenues increased, effective
January 1, 1995, by approximately $100 million, or 4.7% over rates previously in
effect.
12
<PAGE> 19
Also in December 1994, the CPUC granted the Company's request for
reductions of approximately $100 million in authorized funding levels for 1995
electric CEE programs and $17 million for electric research development and
demonstration (RD&D) programs. The request for such reductions was made as part
of the Company's efforts to control costs under its electric rate freeze plan.
1995 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 the Company to set rates in 1995 to provide a utility return on
common equity of 12.10%. This represents an increase from the 11.00% return on
common equity allowed in 1994. The higher return on common equity is intended to
recognize increased interest rates as well as increased risks associated with
the CPUC's OIR/OII on electric industry restructuring in California. The
decision authorizes a utility capital structure of 48.00% common equity, 5.50%
preferred stock and 46.50% long-term debt, which represents an increase from
47.50% in the current equity component of the Company's capital structure. The
combined authorized costs of debt, preferred stock and the 12.10% return on
common equity results in an overall return on rate base of 9.79% for 1995,
compared with the 9.21% authorized for 1994. The decision increased revenue
requirements by approximately $105 million for electric rates and $33 million
for gas rates, effective January 1, 1995. However, consistent with the Company's
current electric rate freeze, the electric revenue increase authorized in this
proceeding was offset by a decrease in base revenues, such that electric rates
will not increase through the end of 1995.
ECAC. In December 1994, the CPUC issued a decision in the Company's 1995
ECAC proceeding which adopted all of the Company's proposals to continue the
electric rate freeze currently in effect, including a $158 million ECAC
increase, a base rate decrease approved in the ARA proceeding described above,
an early refund of $84 million in CEE program dollars collected from ratepayers
but not spent in 1993 and 1994, and deferral of collection of approximately $444
million of ECAC costs forecasted to be undercollected as of December 31, 1995.
In granting the deferral, the decision continued imposition of the three
conditions placed on the first deferral in the 1994 ECAC proceeding: (i)
reinstatement of the AER mechanism, which places shareholders at risk for 9% of
any deviations from forecasted operations, (ii) no interest on the estimated
revenue requirement deferral, and (iii) written notification to all parties if
the Company forecasts that rates would need to rise an additional 5% or more to
amortize the undercollection.
In its decision the CPUC agreed with the Company that the forgoing of
interest on the deferral was limited to the adopted deferral amount and not to
undercollections resulting from forecast error. The decision also makes it clear
that the deferral would not be considered a transition cost in any restructuring
of the electric industry, but should be separately collected from the customers
receiving electric service during the period in which the deferred amounts were
incurred.
The ECAC decision also approved continuation of the Company's economic
stimulus rate reduction, an annual $70 million rate reduction offered to the
Company's largest business customers. The rate reduction, originally offered in
July 1993, was developed to help attract and retain major employers in Northern
and Central California.
Although the ability of the Company to recover the ECAC balancing account
undercollection has been impacted by the Company's freeze on retail electric
rates, the proposed modification of the price for Diablo Canyon power will
assist in reducing the ECAC balance. The Company currently believes that the
ECAC balance will be collected in rates over the near term.
BIENNIAL COST ALLOCATION PROCEEDING
In July 1994, the CPUC approved the Company's request for an increase of
$162 million (9.3%) in core gas rates effective July 15, 1994. The Company had
requested the increase in an interim, or trigger, filing as permitted under the
BCAP mechanism to set new rates for the second year of the BCAP period. During
the first half of the applicable BCAP period (November 1992 -- October 1993),
actual gas costs were higher than the forecasted costs used to adopt rates and
actual gas sales were less than expected, leading to unrecovered gas and related
fixed costs.
In November 1994, the Company filed an application with the CPUC in its
1995 BCAP requesting a gas rate increase of approximately $173 million annually
for the two-year test period beginning October 1, 1995, and ending September 30,
1997. The Company's request reflects a $53 million annual increase in
procurement
13
<PAGE> 20
revenues and a $120 million annual increase in transportation revenues. If the
Company's request is adopted, rates would be effective September 15, 1995. A
final CPUC decision is expected in the third quarter of 1995.
1996 GENERAL RATE CASE
The Company filed its 1996 GRC application in December 1994 for base rates
effective January 1, 1996. The application, as updated by the Company since the
original filing, requests no change in electric revenues and a $163 million
decrease in gas revenues, compared to rates in effect in 1995. The electric and
gas requests will be consolidated with other proceedings, including the BCAP,
the ECAC and the Cost of Capital proceedings, to determine the revenues to be
collected from customers in 1996. (The request included in the original
application to increase revenues by $13 million for the California, or in-state,
portion of the Pipeline Expansion (see "Gas Utility Operations -- PGT/PG&E
Pipeline Expansion Project" below) will be considered in a separate proceeding.)
Since the Company anticipates that the CPUC will have implemented the Company's
proposed PBR mechanism for determining base revenues before January 1, 1997, the
Company's GRC application does not request the adoption of an ARA for the years
1997 and 1998.
In March 1995, the DRA submitted its report on the Company's GRC
application. The DRA recommendation, which is subject to further revision,
proposes an overall revenue requirement which is significantly lower than that
requested by the Company. The DRA recommends that the Company reduce its
electric revenue requirement by $434 million (compared with the Company's
request for no change), and its gas revenue requirement by $292 million
(compared with the Company's request for a $163 million reduction). A
significant portion of the difference between the revenue requirement requested
by the Company and that recommended by the DRA relates to administrative and
general expenses and the level of wages and benefits paid to Company employees.
Hearings on the 1996 GRC are expected to begin in April 1995, with a final
decision on the application expected in December 1995.
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 the
Company's 1993 workforce reduction program, subject to a reasonableness review.
In October 1993, the Company 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, the Company's net revenue requirement
savings expected to be achieved during the 1993 GRC cycle through the workforce
reduction program are being passed on to ratepayers over a two-year period
beginning January 1, 1994. These estimated savings total approximately $156
million.
The total cost of the 1993 workforce reduction program was $264 million,
net of a curtailment gain relating to pension benefits. As a result of the
Company's freeze on electric rates in 1994, the Company expensed $190 million of
such costs relating to electric operations. The amount relating to gas
operations was deferred for future rate recovery and is being amortized as
savings are realized. At December 31, 1994, $31 million remained to be
amortized.
CUSTOMER ENERGY EFFICIENCY/DEMAND SIDE MANAGEMENT PROGRAMS
The Company has long been active in the implementation of CEE and other DSM
programs which encourage customers to implement energy-efficient measures. These
measures allow the Company 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, the Company has expended over
$1.5 billion on DSM programs, allowing the Company to avoid the need for
approximately 1,600 MW of new generating capacity.
Since 1990, the CPUC has permitted the Company 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
14
<PAGE> 21
program), the shareholder incentive is a percentage of the positive net
benefits. For certain service programs, including the Company's direct
weatherization and energy efficiency education programs, the shareholder
incentive is 5% of the cost of the programs.
In a 1993 decision, the CPUC determined that shareholder incentives on
resource programs will be based on actual measured energy savings rather than
forecasted savings, beginning with the 1994 DSM programs. The decision also
concluded that, starting with the 1994 programs, shareholder incentives will be
recovered in rates in four equal installments over a ten-year period, and the
amount recoverable will be subject to the outcome of periodic measurement and
evaluation studies. Beginning in 1994, the amount of shareholder incentives
authorized for the Company and other California utilities will be determined
annually in the AEAP. In early 1994, the Company filed the first annual AEAP
application, requesting shareholder incentives for its 1993 CEE programs. The
CPUC granted the Company's request of $14.9 million in shareholder incentives to
be recovered over a three-year period. The Company estimates that it will earn
approximately $15 million (after-tax) in shareholder incentives from the 1994
CEE programs. In accordance with the 1993 decision, the 1994 shareholder
incentive will be collected in four installments over a ten-year period, and
will be adjusted based on the results of measurement and evaluation studies.
In October 1994, the CPUC issued a decision establishing the incentive
mechanism and incentive level for DSM programs in 1995 and beyond. The
shareholder incentive level is established at 30% of the net benefits of the
resource programs. However, the utilities must guarantee the overall cost
effectiveness of their residential and non-residential portfolio of 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.
The Company plans to spend approximately $150 million on CEE programs in
1995, compared to the $235 million spent on 1994 programs. The new shareholder
incentive mechanism and the requirement of ex post measurement of energy savings
over the 10 years makes an estimate of earnings over that period difficult at
this time. The Company currently estimates it will earn approximately $57
million in shareholder incentives over the 10-year period as a result of the
1995 programs. The Company is permitted to recover, through a balancing account,
up to a maximum of 130% of the program expenses authorized for resource
programs.
CAPITAL REQUIREMENTS AND FINANCING PROGRAMS
The Company continues to require capital for improving its existing
generation, transmission and distribution facilities to maintain 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 $1.1
billion for 1994. New investments in nonregulated businesses totaled $328
million in 1994.
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 1995 through 1999.
CAPITAL REQUIREMENTS
(IN MILLIONS)
<TABLE>
<CAPTION>
1995 1996 1997 1998 1999 TOTAL
------ ------ ------ ------ ------ -------
<S> <C> <C> <C> <C> <C> <C>
Utility(1)(2)........................... $1,212 $1,276 $1,237 $1,255 $1,304 $ 6,284
Diablo Canyon(2)........................ 47 50 52 54 56 259
Enterprises(3)
DALEN Resources Company(4)............ 120 -- -- -- -- 120
U.S. Generating Company(5)............ 142 125 84 173 166 690
Other(6).............................. 23 17 200 203 198 641
------ ------ ------ ------ ------ -------
Total Capital Expenditures......... 1,544 1,468 1,573 1,685 1,724 7,994
Maturing Debt and Sinking Funds......... 477 373 369 715 317 2,251
------ ------ ------ ------ ------ -------
Total Capital Requirements......... $2,021 $1,841 $1,942 $2,400 $2,041 $10,245
====== ====== ====== ====== ====== =======
</TABLE>
(See footnotes on following page)
15
<PAGE> 22
- ---------------
(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. Utility expenditures also include
amounts relating to the expansion of PGT's pipeline system in 1995 through
1996 to provide additional deliveries in the Pacific Northwest. Capital
expenditures relating to such further expansion total approximately $34
million. PGT is also considering a further expansion of its system which, if
warranted by market demand at the time, could require capital expenditures
of approximately $180 million during 1996 and 1997, which amount is not
included in the table above.
(2) Utility expenditures include AFUDC. Expenditures for Diablo Canyon and the
in-state portion of the PGT/PG&E Pipeline Expansion (see "Gas Utility
Operations -- PGT/PG&E Pipeline Expansion Project" below) include
capitalized interest.
(3) Enterprises' actual capital expenditures may vary significantly depending on
the availability of attractive investment opportunities.
(4) In July 1994, the Company approved a plan for the disposition of DALEN
Resources Corp. (DALEN), formerly PG&E Resources Company.
(5) U.S. Generating Company's expenditures include commitments by the Company
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 $100 million and $114 million in 1995 and 1996,
respectively. There are no current commitments to make contributions in 1997
or thereafter.
(6) "Other" includes development and investment activity for international power
generation, real estate and corporate development activities.
Most of the utility capital expenditures for 1995 through 1999 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 maintain their efficiency and reliability and to comply
with environmental laws and regulations. One exception is the seismic retrofit
of part of the Company's general office complex in downtown San Francisco.
The Company estimates that, in addition to the capital expenditure
objectives referred to above, its total capital requirements for the years 1995
through 1999 will include approximately $2,251 million for payment at maturity
of outstanding long-term debt and for meeting sinking fund requirements for
debt. In January 1995, the Board of Directors authorized the Company to redeem
or repurchase up to $153 million of mortgage bonds. In addition, $85 million
remains from a previous authorization to repurchase medium-term notes. In 1994,
the Company redeemed or repurchased $135 million of mortgage bonds, medium-term
notes and Eurobonds. Redemptions and repurchases were financed in part by the
issuance in 1994 of $30 million of medium-term notes and $63 million of
redeemable preferred stock.
The funds necessary for the Company's 1995-1999 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
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.
16
<PAGE> 23
ELECTRIC UTILITY OPERATIONS
ELECTRIC OPERATING STATISTICS
The following table shows the Company's operating statistics (excluding
subsidiaries except where indicated) for electric energy, including the
classification of sales and revenues by type of service.
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31
----------------------------------------------------------------------
1994 1993 1992 1991 1990
---------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C>
CUSTOMERS (AVERAGE FOR THE YEAR):
Residential....................................... 3,788,044 3,748,831 3,708,374 3,665,055 3,604,327
Commercial........................................ 452,049 449,619 455,480 450,789 440,670
Industrial........................................ 1,260 1,243 1,207 1,186 1,102
Agricultural...................................... 90,520 91,376 94,562 96,270 98,131
Public street and highway lighting................ 16,709 16,096 15,681 15,314 14,979
Other electric utilities.......................... 29 28 24 21 20
---------- ---------- ---------- ---------- ----------
Total....................................... 4,348,611 4,307,193 4,275,328 4,228,635 4,159,229
========= ========= ========= ========= =========
GENERATED, RECEIVED AND SOLD -- KWH (IN MILLIONS):
Generated:
Hydroelectric plants............................ 7,791 14,403 7,537 7,996 8,008
Thermal-electric plants:
Fossil fueled................................. 29,543 19,070 26,623 21,984 24,496
Geothermal.................................... 6,024 6,491 7,007 6,947 7,324
Nuclear....................................... 15,265 16,816 16,698 15,073 16,274
---------- ---------- ---------- ---------- ----------
Total thermal-electric plants............... 50,832 42,377 50,328 44,004 48,094
Wind and solar plants........................... 1 -- -- -- --
Received from other sources(1).................... 47,199 48,859 46,243 48,966 46,682
---------- ---------- ---------- ---------- ----------
Total gross system output(2)................ 105,823 105,639 104,108 100,966 102,784
Delivered for interchange or exchange............. 3,275 8,848 3,912 5,391 5,281
Delivered for the account of others(1)............ 18,622 13,726 17,235 13,602 16,093
Helms pumpback energy (3)......................... 467 452 398 593 396
Company use, losses, etc.(4)...................... 7,838 6,960 7,278 7,184 6,957
---------- ---------- ---------- ---------- ----------
Total energy sold........................... 75,621 75,653 75,285 74,196 74,057
========= ========= ========= ========= =========
POWER PLANT FUEL SUPPLY (IN THOUSANDS):
Natural gas (equivalent barrels).................. 44,119 28,791 43,446 36,262 37,777
Fuel oil.......................................... 2,395 2,080 171 631 2,066
Nuclear (equivalent barrels)...................... 26,135 28,724 28,540 25,808 27,847
---------- ---------- ---------- ---------- ----------
Total....................................... 72,649 59,595 72,157 62,701 67,690
========= ========= ========= ========= =========
POWER PLANT FUEL COSTS (AVERAGE COST PER
MILLION BTU'S):
Natural gas....................................... $2.19 $2.86 $2.61 $2.75 $3.09
Fuel oil.......................................... $2.83 $3.49 $3.13 $3.00 $4.11
Weighted average.................................. $2.23 $2.90 $2.62 $2.75 $3.14
SALES -- KWH (IN MILLIONS):
Residential....................................... 24,326 24,111 23,664 23,535 23,222
Commercial........................................ 26,195 26,258 26,246 25,758 25,867
Industrial........................................ 16,010 16,492 16,600 16,472 16,271
Agricultural...................................... 4,426 3,672 4,741 4,734 4,702
Public street and highway lighting................ 418 419 400 389 376
Other electric utilities.......................... 4,246 4,701 3,634 3,308 3,619
---------- ---------- ---------- ---------- ----------
Total energy sold........................... 75,621 75,653 75,285 74,196 74,057
========= ========= ========= ========= =========
REVENUES (IN THOUSANDS):
Residential....................................... $2,980,966 $2,952,893 $2,790,605 $2,729,763 $2,418,250
Commercial........................................ 2,892,302 2,914,855 2,864,817 2,745,040 2,532,655
Industrial........................................ 1,128,561 1,183,728 1,210,754 1,186,452 1,071,714
Agricultural...................................... 477,330 419,628 478,941 477,397 429,445
Public street and highway lighting................ 55,545 55,976 53,133 50,631 47,121
Other electric utilities.......................... 201,133 242,433 185,555 204,089 217,276
---------- ---------- ---------- ---------- ----------
Revenues from energy sales.................. 7,735,837 7,769,513 7,583,805 7,393,372 6,716,461
Miscellaneous..................................... 142,771 87,991 51,716 103,180 217,038
Regulatory balancing accounts..................... 127,549 8,539 111,971 (127,912) 102,572
---------- ---------- ---------- ---------- ----------
Operating revenues.......................... $8,006,157 $7,866,043 $7,747,492 $7,368,640 $7,036,071
========= ========= ========= ========= =========
</TABLE>
- ----------
(1) Includes energy supplied through the Company's system by the City and County
of San Francisco for San Francisco's own use and for sale by San Francisco
to its customers, by the Department of Energy for government use and sale to
its customers, and by the State of California for California Water Project
pumping, as well as energy supplied by QFs and purchases from other
utilities.
(2) Includes energy output from Modesto and Turlock Irrigation Districts' own
resources.
(3) Represents energy required for pumping operations.
(4) Includes use by business units other than the Electric Supply business unit.
17
<PAGE> 24
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31
-----------------------------------------------------------------
1994 1993 1992 1991 1990
--------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C>
SELECTED STATISTICS:
Total customers (at year-end)..................... 4,400,000 4,400,000 4,300,000 4,300,000 4,200,000
Average annual residential usage (kWh)............ 6,422 6,431 6,381 6,421 6,443
Average billed revenues per kWh (c):
Residential..................................... 12.25 12.25 11.79 11.60 10.41
Commercial...................................... 11.04 11.10 10.92 10.66 9.79
Industrial...................................... 7.05 7.18 7.29 7.20 6.59
Agricultural.................................... 10.78 11.43 10.10 10.08 9.13
Net plant investment per customer ($)............. 3,362 3,436 3,428 3,445 3,443
Electric control area capability(1)(MW)........... 21,851 23,009 22,475 21,670 22,931
Electric net control area peak demand(2)(MW)...... 19,118 19,607 18,594 18,620 19,400
</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, 1994, the Company owned and operated the following
generating plants, all located in California, listed by energy source:
<TABLE>
<CAPTION>
NET
OPERATING
NUMBER CAPACITY
GENERATION TYPE COUNTY LOCATION OF UNITS KW
- ------------------------------------------ ------------------------------------ ---------
<S> <C> <C> <C>
Hydroelectric:
Conventional Plants..................... 16 counties in Northern and 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(1)......................... 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(1)......................... 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(2)...................... Contra Costa and Humboldt 3 45,000
------ ---------
Combustion Turbines Subtotal............ 10 418,000
------ ---------
Geothermal:
The Geysers(3).......................... 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) Several fossil fuel steam units (527 MW) were on long-term standby reserve
during 1994. The units require a 12-18 month reactivation time, and are
included as unavailable capacity in the Control Area Net Capacity table
below. Effective December 31, 1994, 12 units, totaling 1342 MW (including
the 527 MW on long-term standby reserve), were retired in place.
(2) Listed to show capability; subject to relocation within the system as
required.
(3) The Geysers 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
"Geothermal Generation" below.
18
<PAGE> 25
To transport energy to load centers, the Company as of December 31, 1994,
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 105,527 circuit miles of
distribution system and distribution substations having a capacity of
approximately 22,091,000 kVa.
The following table sets forth the available capacity for the control area
(the area served by the Company and various publicly owned systems in Northern
California) at the date of peak (including reduction for scheduled and forced
outages and based on actual water conditions) by various sources of generation
available to the control area and the total amount of generation provided by
these sources during the year ended December 31, 1994.
<TABLE>
<CAPTION>
CONTROL AREA
NET CAPACITY
(AT DATE OF 1994 PEAK)
--------------------
KW %
---------
<S> <C> <C>
Sources of Electric Generation:
Company-Owned Plants:
Fossil Fueled.................. 7,631,000 52
Geothermal..................... 1,224,000 8
Nuclear........................ 2,160,000 15
--------- -----
Total Thermal................ 11,015,000 75
Hydroelectric (available)...... 3,556,400 25
Solar.......................... 0 0
--------- -----
Total Company-Owned Capacity..... 14,571,400 100
====
Less Unavailable Capacity...... (913,000)
---------
Total Company Available
Capacity....................... 13,658,400 62
Capacity Received from Others:
QF Producers (available)....... 2,981,000 14
Area Producers &
Imports...................... 5,211,600 24
--------- -----
Capacity from Others........... 8,192,600 38
--------- -----
Total Available Capacity......... 21,851,000 100
========= ====
Total Area Demand(1)(2)............ 19,118,000
=========
</TABLE>
<TABLE>
<CAPTION>
GENERATION
YEAR ENDED
DECEMBER 31, 1994(3)
----------------------
KWH
THOUSANDS %
-------------
<S> <C> <C>
Electric Generation:
Company-Owned Plants:
Fossil Fueled.................. 29,542,611 28
Geothermal..................... 6,024,133 6
Nuclear........................ 15,264,977 15
------------- ----
Total Thermal................ 50,831,721 49
Hydroelectric.................. 7,791,473 8
Solar.......................... 973 --
------------- ----
Total Company Generation......... 58,624,167 57
Helms Pumpback Energy............ (466,524) --
------------- ----
Net Company Generation......... 58,157,643 57
Generation Received from Others:
QF Producers................... 21,692,229 21
Area Producers &
Imports...................... 22,913,620 22
------------- ----
Generation from Others......... 44,605,849 43
Total Area Generation............ 102,763,492 100
=========== ====
</TABLE>
- ----------
(1) The maximum control area peak demand to date was 19,607,000 kW which
occurred in August 1993.
(2) The reserve capacity margin at the time of the 1994 control area peak,
taking into account short-term firm capacity purchases from utilities
located outside the Company'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 14.3%.
(3) Represents actual year net generation from sources shown.
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.
The CEC has not yet adopted the complete 1994 Electricity Report (ER94).
However, the CEC has adopted ER94 forecasts for energy loads and peak demands.
The forecast for area electric peak demand (on a CEC area basis) indicates an
increase from approximately 16,300 MW in 1994 to approximately 21,400 MW in
2013, reflecting a compound annual growth rate of 1.4%. The forecast for area
electric energy load indicates an increase from approximately 88,600
gigawatt-hours (GWh) in 1994 to 116,100 GWh in 2013, reflecting a compound
annual growth rate of 1.4%. The Company's current energy and peak demand
forecasts after 2000 are higher than the CEC's ER94 forecast, primarily due to
the Company's more optimistic economic and demographic assumptions.
19
<PAGE> 26
For the remainder of this decade, the Company anticipates adding between
600 and 750 MW of electric resources. These resources will be comprised of (i)
up to 265 MW of new purchases or company-owned resources resulting from the 1993
BRPU solicitation, assuming a recent FERC order finding the 1993 BRPU
solicitation unlawful is not upheld, (ii) approximately 308 MW of new QF
purchases to come on line by the end of 1996, (iii) between 49 and 200 MW of
generation and DSM resources resulting from the integrated bid solicitation,
(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 the Company's existing transmission lines from the Pacific
Northwest. The Company currently plans no new major construction projects for
electric supply before the year 2000, other than projects already under
development.
The future of electric resource acquisition is being addressed in the
electric industry restructuring OIR/OII. However, future additions to satisfy
electric supply needs in the Company's service territory likely will be
determined largely through a competitive resource procurement process open to
all potential suppliers. The Company has indicated its willingness to forgo
competing in this process to build new generation resources if the CPUC grants
the Company significant flexibility in conducting the planning and procurement
process.
The CEC committee conducting proceedings relating to the CEC's ER94
expanded the proceeding to include an extensive analysis of how changes in the
structure of the electric industry may affect the achievement of California's
energy policies. It is presently unclear to what extent considerations relating
to electric industry restructuring will impact the content and timing of the
final ER94.
In 1993, the CPUC issued a decision in a DSM proceeding (see
"General -- Customer Energy Efficiency/Demand Side Management Programs" above)
which selected the Company to conduct an integrated bidding pilot program in
which both resource generation and DSM bidders compete in the procurement
process. The CPUC ordered the Company to conduct a pilot bid program for between
49 and 200 MW. The Company issued a request for bids in December 1994 and
expects to file contracts in early 1996 for approval by the CPUC.
ELECTRIC RESOURCES
QF GENERATION
Under the Public Utility Regulatory Policies Act of 1978 (PURPA), the
Company 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. A QF must meet certain
performance obligations, depending on the contract, prior to receiving capacity
payments. The total cost of both energy and capacity payments to QFs is
recoverable in rates. The Company's contracts with QFs expire on various dates
from 1995 to 2026. Under these contracts the Company is required to make
payments only when energy is supplied or when capacity commitments are met.
In 1994, the Company negotiated the early termination or temporary
suspension of seven QF contracts at
a cost of $155 million, to be paid over a six-year period beginning in 1994. The
amount has been deferred with the expectation that it will be recovered in
future rates.
Payments to QFs are expected to vary in future years. QF deliveries in the
aggregate accounted for approximately 21% of the Company's 1994 total electric
energy requirements and no single contract accounted for more than 5% of the
Company's electric energy needs.
The amount of energy received from QFs and the total energy and capacity
payments made under these agreements were:
<TABLE>
<CAPTION>
1994 1993 1992
------ ------ ------
(IN MILLIONS)
<S> <C> <C> <C>
kWh received............................................. 21,699 21,242 21,173
Energy payments.......................................... $1,196 $1,099 $1,084
Capacity payments........................................ $518 $503 $489
</TABLE>
20
<PAGE> 27
As of December 31, 1994, the Company had approximately 5,900 MW of QF
capacity under CPUC-mandated power purchase agreements. Of the 5,900 MW,
approximately 4,600 MW were operational. Development of the balance is uncertain
but it is estimated that only 300 MW of the remaining contracts will become
operational. The 5,900 MW of QF capacity consists of 3,300 MW from cogeneration
projects, 1,500 MW from wind projects and 1,100 MW from other projects,
including biomass, geothermal, solar and hydroelectric.
GEOTHERMAL GENERATION
Because of declining geothermal steam supplies, the Company's geothermal
units at The Geysers Power Plant (Geysers) are forecast to operate at reduced
capacities. The consolidated Geysers capacity factor is forecast to be
approximately 33% in 1995, which includes forced outages, scheduled overhauls
and projected steam shortage curtailments, as compared to the actual Geysers
capacity factor of 56% in 1994. The Company expects steam supplies at the
Geysers to continue to decline.
The Company has entered into new steam sale agreements with several of its
steam suppliers which allow the Company to alter the operation of its units to
more economically utilize the existing installed capacity and partially offset
the impact of the declining steam supplies at the Geysers. The new agreements
permit the steam suppliers to furnish lower pressure steam and require that they
make payments to the Company to compensate for the declining steam supply to the
Company's units.
WESTERN SYSTEMS POWER POOL
In 1991, the FERC approved an agreement among 40 utilities (including the
Company) 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 if they
waive their rights under PURPA to be paid avoided cost prices for transactions
performed within the pool. The FERC order approving the permanent WSPP agreement
was challenged in the U.S. Court of Appeals for the District of Columbia Circuit
on the basis that the cost-based ceilings were improperly calculated and that
the FERC exceeded its authority in conditioning QF participation in the pool.
The Court of Appeals affirmed the FERC's authority to set cost-based ceilings
and, at the request of the FERC, remanded the QF participation issues to the
FERC for further consideration. In February 1994, the FERC ordered WSPP to
permit QFs to participate on the same basis as other members without being
required to waive their rights under PURPA.
ELECTRIC TRANSMISSION POLICIES
Beginning in 1993, the FERC implemented the Energy Act by establishing a
number of policies with respect to transmission service, transmission pricing
and Regional Transmission Groups (RTGs).
TRANSMISSION ACCESS AND PRICING
In 1993, the FERC held that eligible entities were entitled to receive
network transmission service unless the transmitting utility was unable to
provide it. Eligible entities under the Energy Act include electric utilities,
federal power marketing agencies or any entity generating power for resale.
Network transmission service generally involves delivery from multiple
generators to multiple loads for a single charge. The FERC later held that
network service could be priced based on the ratio of the load served by the
network service to the entire load served by the transmitting utility's
transmission system.
In 1994, the FERC held that any utility providing service under an
open-access transmission tariff (i.e., a filed tariff offering transmission
service at specified rates and terms to all eligible entities) must provide
transmission service to transmission customers on the same basis on which the
utility provides transmission service to its own customers. This means the
service must be comparable in terms of price, in terms of quality,
21
<PAGE> 28
and with respect to all the uses the transmitting utility makes of its own
transmission system. The Company currently intends to file an open-access tariff
by May 1, 1995.
In October 1994, the FERC issued a policy statement on transmission
pricing. The new policy permits increased flexibility in transmission pricing
methodology and rate design in instances where the transmitting utility is
basing rates on a traditional embedded cost revenue requirement. In return
utilities must meet the comparability of service standard described above. The
FERC will also consider deviations from embedded cost revenues, but only from
entities which have already filed open-access comparable service transmission
tariffs. The FERC regards market-based pricing for transmission as disfavored,
believing transmission to be a monopoly.
Consistent with the intent of the Energy Act to promote competition in the
wholesale power markets through increasing transmission access, in December
1994, the Company filed with the FERC for its approval an agreement to provide
network transmission service to a power marketer, Destec Power Services (DPS).
Under this agreement, the Company will provide flexible wholesale network
transmission from generators who market their power through DPS. Many of these
generators will be QFs which already have power purchase agreements to sell to
the Company, but which have surplus power not covered by such agreements which
can be marketed by DPS. The FERC is expected to act on the DPS agreement
shortly. In March 1995, the Company entered into a similar agreement with
another marketer, Power Exchange Corp. (PXC), which agreement has been filed
with the FERC for approval. The services and rates under the PXC agreement are
identical to those in the DPS agreement. However, the Company will provide
transmission service under the PXC Agreement only for power bought or sold by
PXC under contracts entered into before such time as the Company's open-access
tariff has been filed and effective for two years. For all power contracts PXC
enters into after that date, it must rely on transmission service under the
Company's open-access tariff.
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. The Company was one of the
founding members of WRTA and supported FERC's approval of the bylaws. The FERC
conditionally accepted the WRTA bylaws, but added two requirements. First, the
FERC required either WRTA itself or all WRTA members to file comparable service
open access tariffs providing transmission service to all other members. Second,
the FERC required WRTA to file a single coordinated regional transmission plan
and to update that plan as necessary. WRTA has filed a revised set of bylaws
essentially accepting those conditions, which FERC will rule on within the next
few months.
STRANDED COSTS RULEMAKING
In June 1994, the FERC issued a Notice of Proposed Rulemaking relating to
stranded costs. These are fixed costs (typically for generation) which a utility
may be unable to recover because of customers leaving the system. The proposed
rules cover stranded costs for wholesale transactions and propose in the
alternative either no role for FERC regarding retail stranded costs or only a
limited role. A decision is expected sometime in 1995.
CPUC TRANSMISSION POLICIES
In September 1990, the CPUC issued an order instituting investigation into
the development of transmission policies for (i) transmission access and
allocation of transmission costs for a utility buying non-utility power; and
(ii) transmission access, cost allocation and pricing issues for non-utility
power producers who require transmission-only service from a utility. In
September 1992, the CPUC issued a decision in the first phase of the
investigation. The decision adopted certain policies and procedures on an
interim basis which permit the Company to consider the expected transmission
impacts of non-utility power purchases as it selects new QF resources through a
competitive bidding process. Among other things, the decision provided that
ratepayers, as opposed to utility shareholders, will bear prudently incurred
costs of the most cost-effective transmission upgrades necessary to accommodate
purchases from winning bidders. The recent BRPU
22
<PAGE> 29
solicitation proceeded under these rules and enabled bidders in one utility's
service territory to bid into another utility's auction.
A second phase of the investigation to consider certain broader long-term
transmission access and cost issues is currently on hold pending the outcome of
the CPUC's electric industry restructuring OIR/OII.
ELECTRIC REASONABLENESS PROCEEDING
Recovery of 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 on a historic calendar year
basis.
In August 1993, the DRA filed a report on the Company's ECAC expenses for
the 1991 record period, which questioned the Company'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 the
Company 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 and
1993 record periods, the DRA recommended disallowances of approximately $3.5
million and $3.0 million, respectively, for two of these agreements.
HELMS PUMPED STORAGE PLANT
Helms, 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,
became commercially operable in June 1984. As a result of the damage caused by
the rupture and the delay in the operational date, the Company 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 reserved by the Company 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 $104 million at December 31, 1994.
In October 1994, the Company 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 costs and $14.6 million of prior
revenue requirements to be included in the Company's rate base on January 1,
1995. However, in connection with the Company's rate freeze for 1995, the
revenue requirement for 1995 would not increase, as a result of other unrelated
base revenue reductions. 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, the Company would also agree not to seek recovery of
the costs associated with the 1982 water conduit rupture, estimated to be $72.4
million. The Company took a charge against earnings for such costs in 1990.
As noted above (see "General -- 1995 Revenue Changes"), in December 1994,
the CPUC issued a resolution authorizing the Company to implement an ARA to keep
the Company's retail electric rates unchanged through 1995. In its resolution,
the CPUC adopted the revenue requirement increase of approximately $12 million
that is contemplated by the Helms Settlement, and authorized a decrease in base
revenues. The CPUC also authorized the collection in 1995 of $2 million as part
of the amortization through ERAM of revenues lost during the time the generators
were being repaired. The CPUC noted that because the Helms Settlement is still
pending before the CPUC, the amount adopted in the resolution may be subject to
further adjustment depending upon the final decision in the Helms proceeding.
23
<PAGE> 30
GAS UTILITY OPERATIONS
GAS OPERATIONS
The Company owns and operates an integrated gas transmission, storage and
distribution system in California. At December 31, 1994, the Company's "vintage"
system consisted of approximately 5,300 miles of transmission pipelines, three
gas storage facilities and approximately 35,400 miles of gas distribution lines.
In addition, in November 1993, the Company placed in service a third
transmission pipeline of approximately 400 miles (Line 401) as the in-state
portion of the PGT/PG&E Pipeline Expansion. See "PGT/PG&E Pipeline Expansion
Project" below.
The Company's peak day send-out of gas on its integrated system in
California during the year ended December 31, 1994 was 3,801 million cubic feet
(MMcf). The total volume of gas throughput during 1994 was approximately 948,000
MMcf, of which 307,000 MMcf was sold to direct end-use or resale customers,
298,000 MMcf was transported by PG&E for its fossil-fueled electric generating
plants, and 343,000 MMcf was transported customer-owned gas.
The California Gas Report, which presents the outlook for natural gas
requirements and supplies for the State of California through the year 2010, is
prepared annually by the California electric and gas utilities as a result of a
CPUC order. The 1994 report forecasts the Company's gas demand from 1994 through
2010. (Beginning in 1996, the report will be issued biennially.)
The 1994 report forecasts growth in gas throughput served by the Company of
1.4% per year from 1994 through 2010. While this is a lower growth rate than the
1.8% shown for the same period in last year's forecast, most of the difference
is due to higher power plant gas demand in 1994 than previously forecasted, as a
result of lower than expected rainfall. Much of the forecasted growth in gas
demand, outside of utility electric generation, is related to a more optimistic
forecast of industrial output in the service territory and expected growth in
the use of natural gas vehicles as a result of the Company's natural gas vehicle
programs and state and federal clean air regulations.
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, have the ability to purchase gas directly from
gas producers, using unregulated private pipelines or interstate pipelines,
bypassing the Company's system entirely. The report forecasts a total bypass
volume of 126 billion cubic feet for 1994. The forecast assumes that bypass
which began in 1991 will change little from the 1994 level and does not include
any potential bypass from the proposed Mojave Pipeline Company expansion
project. See "Other Competitive Pipeline Projects" below.
24
<PAGE> 31
GAS OPERATING STATISTICS
The following table shows the Company's operating statistics (excluding
subsidiaries except where indicated) for gas, including the classification of
sales and revenues by type of service.
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31
-------------------------------------------------------------
1994 1993 1992 1991 1990
--------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C>
CUSTOMERS (AVERAGE FOR THE YEAR):
Residential........................................... 3,372,768 3,339,859 3,311,881 3,275,247 3,214,424
Commercial............................................ 196,509 195,815 195,689 197,029 194,596
Industrial............................................ 1,400 1,265 1,185 1,150 1,150
Other gas utilities................................... 2 4 4 4 4
--------- --------- --------- --------- ---------
Total........................................... 3,570,679 3,536,943 3,508,759 3,473,430 3,410,174
========= ========= ========= ========= =========
GAS SUPPLY -- THOUSAND CUBIC FEET (MCF) (IN THOUSANDS):
Purchased:
From Canada......................................... 319,453 329,693 321,770 345,020 372,421
From California..................................... 31,757 32,096 50,953 73,257 77,935
From other states................................... 249,733 243,058 327,272 240,141 273,981
--------- --------- --------- --------- ---------
Total purchased................................. 600,943 604,847 699,995 658,418 724,337
Net from storage (to storage)......................... 3,591 (12,234) 10,135 (6,849) 6,152
--------- --------- --------- --------- ---------
Total........................................... 604,534 592,613 710,130 651,569 730,489
Company use, losses, etc.(1).......................... 297,604 161,895 281,021 223,176 257,943
--------- --------- --------- --------- ---------
Net gas for sales............................... 306,930 430,718 429,109 428,393 472,546
========= ========= ========= ========= =========
BUNDLED GAS SALES AND TRANSPORTATION SERVICE -- MCF
(IN THOUSANDS):
Residential........................................... 214,358 206,053 190,176 210,657 204,433
Commercial............................................ 72,183 82,048 79,983 85,203 102,579
Industrial............................................ 19,495 133,178 145,356 119,916 133,930
Other gas utilities................................... 894 9,439 13,594 12,617 31,604
--------- --------- --------- --------- ---------
Total(2)........................................ 306,930 430,718 429,109 428,393 472,546
========= ========= ========= ========= =========
TRANSPORTATION SERVICE ONLY -- MCF (IN THOUSANDS):
Vintage system (Substantially all Industrial)(3)...... 142,393 101,888 103,186 207,544 168,969
In-state portion of Pipeline Expansion (Line 401)..... 200,755 20,513 -- -- --
--------- --------- --------- --------- ---------
Total........................................... 343,148 122,401 103,186 207,544 168,969
========= ========= ========= ========= =========
REVENUES (IN THOUSANDS):
Bundled gas sales and transportation service:
Residential......................................... $1,268,966 $1,152,494 $1,092,324 $1,226,094 $1,139,998
Commercial.......................................... 444,805 467,962 479,599 551,669 565,608
Industrial.......................................... 57,297 367,221 425,467 366,346 453,871
Other gas utilities................................. 2,371 25,654 38,504 43,224 84,771
--------- --------- --------- --------- ---------
Bundled gas revenues............................ 1,773,439 2,013,331 2,035,894 2,187,333 2,244,248
Transportation only revenue:
Vintage system (Substantially all Industrial)....... 132,509 56,733 75,606 133,348 106,759
In-state portion of Pipeline Expansion (Line 401)... 58,442 8,097 -- -- --
--------- --------- --------- --------- ---------
Transportation service only revenue............. 190,951 64,830 75,606 133,348 106,759
Miscellaneous......................................... 41,840 (14,925) 21,022 (59,056) 52,308
Regulatory balancing accounts......................... 11,068 138,627 36,093 (44,213) (124,606)
Subsidiaries(4)....................................... 402,077 514,502 379,981 192,067 155,312
--------- --------- --------- --------- ---------
Operating revenues.............................. $2,419,375 $2,716,365 $2,548,596 $2,409,479 $2,434,021
========= ========= ========= ========= =========
</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, the Company implemented its 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 the Company 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
in-state portion of the Pipeline Expansion of 79,749 MMcf and 7,205 MMcf
for 1994 and 1993, respectively.
(4) Includes gas transportation revenues from PGT and oil and gas revenues from
Enterprises.
25
<PAGE> 32
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31
-------------------------------------------------------------
1994 1993 1992 1991 1990
--------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C>
SELECTED STATISTICS:
Total customers (at year-end)......................... 3,500,000 3,600,000 3,500,000 3,500,000 3,500,000
Average annual residential usage (Mcf)................ 64 62 57 64 64
Heating temperature -- % of normal(1)................. 104.4 89.9 76.0 101.5 94.9
Average billed bundled gas sales revenues Mcf:
Residential......................................... $5.92 $5.59 $5.74 $5.82 $5.58
Commercial.......................................... 6.16 5.70 6.00 6.47 5.51
Industrial.......................................... 2.94 2.76 2.93 3.06 3.39
Average billed transportation only revenue per Mcf:
Vintage system...................................... 0.60 0.52 0.73 0.64 0.63
In-state portion of Pipeline Expansion (Line 401)... 0.29 0.39 -- -- --
Net plant investment per customer..................... $1,340 $1,339 $1,170 $893 $748
</TABLE>
- ------------
(1) Over 100% indicates colder than normal.
NATURAL GAS SUPPLIES
The objective of the Company's gas supply planning is to maintain a
balanced supply portfolio which provides supply reliability and contract
flexibility, minimizes costs and fosters competition among suppliers.
Under current CPUC regulations, the Company purchases natural gas from its
various suppliers based on economic considerations, consistent with regulatory,
contractual and operational constraints. During the year ended December 31,
1994, approximately 53% of the Company's total purchases of natural gas
consisted of Canadian gas purchased from various Canadian producers and
transported by PGT, a wholly owned subsidiary of the Company, approximately 5%
was purchased from various California producers, and approximately 42% 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 the Company from
these sources during each of the last five years.
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31
----------------------------------------------------------------------------------------------------------------
1994 1993 1992 1991 1990
-------------------- -------------------- -------------------- -------------------- --------------------
THOUSANDS AVG. THOUSANDS AVG. THOUSANDS AVG. THOUSANDS AVG. THOUSANDS AVG.
OF MCF PRICE(1) OF MCF PRICE(1) OF MCF PRICE(1) OF MCF PRICE(1) OF MCF PRICE(1)
--------- -------- --------- -------- --------- -------- --------- -------- --------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Canada.......... 319,453 $ 1.94 329,693 $ 2.26 321,770 $ 2.14 345,020 $ 2.34 372,421 $ 2.41
California...... 31,757 1.55 32,096 1.65 50,953 1.73 73,257 2.00 77,935 2.04
Other states
(substantially
all U.S.
Southwest).... 249,733 2.41 243,058 2.84 327,272 2.51 240,141 2.61 273,981 2.81
--------- --------- --------- --------- ---------
Total/Weighted
Average....... 600,943 $ 2.12 604,847 $ 2.46 699,995 $ 2.28 658,418 $ 2.40 724,337 $ 2.52
======== ======= ======== ======= ======== ======= ======== ======= ======== =======
</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 the Company'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 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. Under the CPUC's capacity
brokering program implemented in 1993, the Company is required to make available
for brokering all interstate pipeline capacity not reserved for its core
customers and core subscription customers. Noncore customers, marketers and
shippers, and the Company's electric department can bid for such capacity.
In addition, 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
26
<PAGE> 33
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.
The Company's compliance with these regulatory changes allowed many of the
Company's noncore customers to arrange for the purchase and transportation of
their own gas supplies. These changes resulted in a decrease in the amount of
gas required to be purchased by the Company and a related decrease in the
Company's need for firm transportation capacity, and contributed to the need to
restructure the Company's gas supply arrangements.
RESTRUCTURING OF CANADIAN GAS SUPPLY ARRANGEMENTS
DECONTRACTING PLAN
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 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. As a result of the regulatory restructuring discussed above,
negotiations were conducted to terminate A&S's contracts with Canadian gas
producers, restructure A&S's contracts with Canadian pipelines and gas
processors and settle all litigation and claims arising from such contracts.
Those negotiations resulted in the implementation of a Decontracting Plan,
effective November 1, 1993. Approximately 190 Canadian gas producers
representing nearly 100% of the total volume of the gas supply of A&S
participated in the Decontracting Plan.
Under the Decontracting Plan, 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, effective on November 1, 1993. Participating producers
released A&S, PGT and PG&E from any claims they may have had that resulted from
the termination of the former arrangements as well as any prior claims related
to these contracts. The total amount of settlement payments paid to the
producers was approximately $210 million.
As part of the overall A&S decontracting process, A&S' operations have been
significantly reduced. A&S permanently assigned substantial portions of its
commitments for transportation capacity with NOVA Corporation of Alberta (NOVA)
through October 2001 and Alberta Natural Gas Company Ltd (ANG) through October
2005 to third parties and approximately 600 MMcf per day (MMcf/d) of capacity on
each of these pipelines to PG&E for use in the servicing of PG&E's core and core
subscription customers. A&S currently holds remaining capacity of approximately
300 MMcf/d on each of these pipelines with total annual demand charges of
approximately $15 million for which it is continuing its efforts to assign or
broker. It is currently anticipated that A&S will complete the permanent
assignment to others of substantially all of its NOVA and ANG capacity by
November 1995.
The FERC has 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.
27
<PAGE> 34
In May 1994, the FERC approved PGT's application seeking recovery of $154
million under the TCRM, which is 75% of the $206 million in estimated settlement
payments expected to be paid to Canadian gas producers as of the time PGT filed
its application. PGT has also sought recovery of an additional $14 million under
the TCRM. This amount represents 75% of additional settlement payments to
producers and certain costs related to A&S' wind-down of its gas aggregation and
supply business as a result of the decontracting process. In February 1995, the
FERC held that this amount was eligible for recovery under the TCRM. The CPUC
and other parties have until April 3, 1995 to challenge the prudency of this
amount. If no such challenge is made, the amount will be recovered under the
TCRM.
In November 1993, PG&E paid PGT approximately $51 million in payment of a
direct bill charged by PGT for transition costs under the TCRM. PG&E sought
recovery in its most recent BCAP application of this amount and the volumetric
surcharges to be billed to PG&E. As part of proposed gas settlement agreements
discussed below (see "Gas Reasonableness Proceedings -- Proposed Gas
Settlements"), the DRA has agreed that it will not seek any disallowance
relating to costs incurred by PG&E in connection with its Canadian
restructuring/decontracting activities once those costs are approved by the
FERC.
FINANCIAL IMPACT OF DECONTRACTING PLAN AND LITIGATION
The Company incurred transition costs of $228 million in 1993, consisting
of settlement payments made to producers in connection with the implementation
of the Decontracting Plan and amounts incurred by A&S in reducing certain
administrative and general functions resulting from the restructuring. Of these
costs, the Company deferred $143 million for future rate recovery. In addition,
the Company recorded a reserve of $31 million in 1993 related to A&S's remaining
commitments for Canadian transportation capacity. Accordingly, the Company
expensed $93 million in 1993 and a total of $23 million in prior years.
RESTRUCTURING OF INTERSTATE GAS SUPPLY ARRANGEMENTS
CURRENT GAS TRANSPORTATION AND PROCUREMENT ARRANGEMENTS
The Company's firm transportation agreement with PGT for up to 1,066 MMcf/d
runs through October 31, 2005. The Company's firm transportation agreement with
El Paso for up to 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 the
Company's firm capacity on PGT and El Paso are approximately $50 million and
$130 million per year, respectively.
In April 1992, the Company executed firm transportation agreements with
Transwestern to transport 200 MMcf/d of San Juan basin gas supplies into the
Company's southern gas system, of which approximately 150 MMcf/d is to be used
to meet the Company's gas sales demands and approximately 50 MMcf/d is for use
by the Company's electric department. The demand charges associated with the
entire Transwestern capacity are currently approximately $30 million per year.
RECOVERY OF INTERSTATE TRANSPORTATION DEMAND CHARGES
Pursuant to FERC rules on capacity relinquishment and release and the
CPUC's capacity brokering program, the Company 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.
Under the CPUC's capacity brokering program, noncore customers, or their gas
suppliers, are able to make firm interstate transportation arrangements to
deliver gas at the Company's interconnections with the interstate pipelines.
The Company has permanently assigned portions of the capacity it no longer
uses and is continuing its efforts to assign or broker the remaining unused
capacity. During 1994, the Company has been able to broker a portion of its
unused capacity, including limited amounts of that held for its core and core
subscription customers when such capacity was not being used. Amounts brokered
have generally been on a short-term basis, most of which were at a discounted
price. Based on the current demand for Canadian gas, the Company believes it
will be able to broker or assign substantially all of its unused capacity on PGT
by the end of 1995; however, due to lower demand for Southwest pipeline
capacity, the Company cannot predict the volume or price of the capacity on El
Paso and Transwestern that will be brokered or assigned.
28
<PAGE> 35
Interstate transportation capacity which cannot be marketed at the full
rate results in unrecovered demand charges. Under the CPUC brokering rules, the
CPUC has authorized the use of the ITCS to account for unrecovered demand
charges associated with interstate pipeline obligations in existence at the time
the decision creating the ITCS was issued in November 1991. To the extent the
Company is unable to broker its firm interstate capacity above core and core
subscription reservations at the full as-billed rate, or to broker such capacity
at all, the Company has been authorized to accumulate unrecovered demand charges
for El Paso and PGT in the ITCS account for later review and allocation among
customer classes.
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, such as rates given to a customer in a negotiated discount gas
transportation contract entered into pursuant to the Company's EAD procedure.
The CPUC has indicated that if an EAD rate discount results in a shortfall in
recovery of ITCS costs contained in the otherwise applicable tariff rate, the
Company will not recover those ITCS costs from other customers.
In November 1994, the CPUC issued a decision on the Company's application
seeking recovery of amounts accumulated in the ITCS. The Company's application
sought to have $60.7 million, which represents the revenue requirement for the
estimated amount accrued in the ITCS account for the period August 1, 1993
through August 31, 1994, recovered in noncore rates over a 12-month period
beginning September 1, 1994. In its decision, the CPUC indicated that it did not
have a sufficient record to resolve contested issues regarding the total amount
of the Company's unrecovered costs of interstate pipeline capacity to allocate
to noncore customers. However, citing the fact that legitimate unrecovered costs
continue to accrue at a substantial rate, the decision authorized the Company to
increase rates to all noncore customers on December 1, 1994 through a rate
designed to collect approximately one-half of the accumulated demand charges for
unbrokered or discounted capacity on an interim basis, subject to refund should
ITCS costs prove to have been caused by improper acts of the Company. (This
amount was included in the rate adjustments effected January 1, 1995. See
"General -- Current Rate Proceedings -- 1995 Revenue Changes" above.) The CPUC
also set the matter for hearing at the earliest practicable date to consider
protests filed by El Paso. El Paso contends that the Company is inducing
customers to move from the El Paso pipeline system to the Company's Pipeline
Expansion by discounting rates on the Pipeline Expansion and recouping those
discounts through the ITCS. The Company expects to seek recovery of the balance
of the ITCS amounts originally sought in the hearing on this matter, which is
scheduled for September 1995.
Currently, the Company is not permitted to include any Transwestern firm
capacity demand charges in rates or in the ITCS account. The Company is
authorized to record costs associated with its Transwestern capacity in a
balancing account, with recovery of such costs subject to reasonableness review
proceedings, which are currently under way.
In January 1994, the DRA issued its report on the reasonableness of the
Company's gas procurement and operating activities for the 1992 record period.
In its report, the DRA argued that the Company imprudently entered into firm
transportation agreements with Transwestern in 1992 and recommended a
disallowance of the associated demand charges of approximately $18 million paid
by the Company during the record period, of which $4.5 million related to
capacity for the Company's electric department. The DRA asserted that the
Transwestern capacity was unnecessary to meet the expected needs of the
Company's core customers and that the Company should not have contracted for
such capacity. Hearings on this issue were concluded in January 1995, with a
decision expected in late 1995.
GAS REASONABLENESS PROCEEDINGS
Recovery of gas costs through the Company'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.
29
<PAGE> 36
1988-1990 CANADIAN GAS PROCUREMENT ACTIVITIES
In March 1994, the CPUC issued a final decision on the Company's Canadian
gas procurement activities during 1988 through 1990. The CPUC found that the
Company could have saved its customers money if it had bargained more
aggressively with its existing Canadian suppliers or bought cheaper gas from
other Canadian sources. The CPUC concluded that it was appropriate for the
Company to take a substantial portion (up to 700 MMcf/d) of its Canadian gas at
its then-existing price, but that the Company 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
orders 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 the Company's non-Canadian gas operations during 1988
through 1990, ordering a disallowance of $8 million.
The Company filed a request for rehearing of the CPUC's decision ordering a
disallowance in connection with the Company's Canadian gas procurement
activities in 1988-1990, which was denied in November 1994. In December 1994,
the Company 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 the Company's rights under the United States
Constitution. The complaint seeks injunctive and declaratory relief.
PROPOSED GAS SETTLEMENTS
A number of other reasonableness issues related to the Company'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
$142 million and a penalty of $50 million and indicated that it was considering
additional recommendations for pending issues. The Company and the DRA have
signed settlement agreements to resolve most of these issues for a $68 million
disallowance.
Significant issues covered by the gas settlement agreements include (i) the
Company's purchases of Canadian, Southwest and California gas for its electric
department in 1991 and 1992 and its core 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 the Company, for the period 1988 through May 1994; (iii) the effects the
Company's Canadian gas procurement costs may have had on amounts paid by the
Company for Northwest power purchases for 1988 through 1992 and for power
purchased from geothermal and QF producers during 1991 and 1992; (iv) the
Company's gas storage operations for 1991 and 1992; (v) the Company's Southwest
gas procurement activities for 1988 through 1990; and (vi) Canadian gas
restructuring transition costs billed to PG&E by PGT through FERC-approved
rates.
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
agreements are expressly conditioned upon CPUC approval. Upon such approval, the
Company would return approximately $68 million to its ratepayers.
The proposed gas settlement agreements do not resolve issues related to the
effect the Company's Canadian gas procurement costs during the 1988 through 1990
period may have had on the price the Company 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 agreements also do not resolve the
reasonableness of the Company's subscription to Transwestern pipeline capacity
or the costs accrued in the Company's ITCS account.
FINANCIAL IMPACT OF GAS REASONABLENESS PROCEEDINGS
The Company accrued approximately $135 million and $61 million in 1994 and
1993, respectively, for gas reasonableness matters including the CPUC decisions
for the years 1988 through 1990 and issues covered by
30
<PAGE> 37
the gas settlement agreements. The Company believes that the ultimate outcome of
these matters will not have a significant impact on its financial position or
results of operations.
PGT/PG&E PIPELINE EXPANSION PROJECT
In November 1993, PGT and the Company placed in service an expansion of
their natural gas transmission systems from the Canadian border into California
(Pipeline Expansion). The 840-mile combined pipeline 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. At December 31, 1994, the
Company's total investment in the Pipeline Expansion project was approximately
$1,627 million. The $1,627 million consisted of $786 million for the facilities
within California (i.e., in-state portion) and $841 million for the facilities
outside California (i.e., interstate, or PGT, portion).
The conditions of the CPUC's approval of the construction of the in-state
portion of the Pipeline Expansion place the Company at risk for its decision to
construct based on its assessment of market demand and for undersubscription and
underutilization of the facility. The CPUC required the application of a "cross-
over" ban under which volumes delivered from the incremental PGT portion of the
Pipeline Expansion must be transported at an incremental in-state expansion
rate. Incremental rate design is based on the concept that expansion shippers,
not existing ratepayers, bear the incremental costs of the expansion facilities.
Capacity on the PGT portion of the Pipeline Expansion is fully subscribed under
long-term firm transportation contracts. However, to date, shippers have only
executed long-term firm transportation contracts for approximately 40% of the
in-state capacity, and the Company continues negotiations for the remainder of
that capacity. The CPUC has authorized the Company to provide as-available
service on the in-state portion of the Pipeline Expansion, which provides
additional revenues to recover the incremental costs of the expansion.
In February 1994, the CPUC issued a decision on the Company's request for
an increase in the cost cap for the in-state portion of the Pipeline Expansion
and its interim rate filing. 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 the Company'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, the Company
was reasonable in constructing the Pipeline Expansion. The CPUC has denied
rehearing of this decision.
In September 1994, the Company filed an application with the CPUC
requesting that the CPUC find reasonable the full capital costs of the in-state
portion of the Pipeline Expansion (estimated to be $813 million) and its initial
operating expenses. The Company's request for a $13 million increase in revenues
from the in-state portion of the Pipeline Expansion, compared to rates in effect
in 1994, will also be considered in this proceeding. A decision in this
proceeding is not expected until 1996.
In its 1991 order approving 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 portion of the 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 until such time as PGT demonstrates that neither its rates or
transportation policies nor those of the Company result in unduly discriminatory
restraints. In March 1994, the FERC allowed PGT to implement, subject to refund,
an increase in the nominal return on equity to 12.75%, but reaffirmed the lower
10.13% return on equity it implemented as an incentive for PGT to seek removal
of unduly discriminating restraints.
In February 1994, PGT filed a general rate case with the FERC which
proposed, among other things, that the lower return on equity imposed by the
FERC be removed and PGT be allowed to determine rates for all of its facilities
on an equity rate of return of 13%. In March 1994, the FERC approved PGT's
proposal to determine rates based on the higher rate of return, subject to
refund, pending the outcome of hearings in PGT's rate case, and authorized the
rate change to begin in September 1994. Hearings in PGT's rate case are
scheduled to begin in April 1995.
31
<PAGE> 38
The Company believes that resolution of the rate proceedings pending at the
CPUC and FERC will not have a significant impact on its financial position or
results of operations.
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. Mojave indicated that it intends to place the proposed expansion into
service by January 1, 1996. The expansion would extend 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 provided by the proposed expansion would be
provided to customers located in the Company's service territory, with
approximately 257 MMcf/d of that amount to be used to provide gas service that
currently is not provided by the Company. The remaining 176 MMcf/d represents
service to customers currently served by the Company.
In November 1994, the FERC issued an order, approving, with conditions,
Mojave's expansion application and granting Mojave a permit to construct,
subject to further environmental review. In response to Mojave's original
application, the Company had requested that the FERC establish a mechanism to
reimburse the Company for costs arising from bypass associated with Mojave's
proposed expansion. In its order approving Mojave's expansion, the FERC rejected
the Company's claim that the Mojave expansion will result in lost revenues of
between $204 million and $223 million. Instead, the FERC estimated the amount
would not likely exceed $5 million per year for 15 years. The FERC also rejected
the Company's request to be relieved of up to $86 million in charges for El Paso
capacity to account for reduced load resulting from Mojave's proposed expansion,
concluding instead that such amount could not exceed $19.5 million. The FERC
concluded that these costs did not justify rejection of Mojave's application,
but it was unable to determine whether and what amount of compensation is owed
to the Company by Mojave. The FERC also directed the Company, Mojave and El Paso
to provide information explaining whether a connection exists between the
Company's obligation to purchase service from El Paso and Mojave's service to
the customers Mojave intends to serve within the Company's service territory,
and specifying what type and volume of load the Company will lose as a direct
result of the bypass by Mojave.
In December 1994, the Company filed its response to the FERC's order. In
its response, the Company affirmed that a direct connection exists between the
Company's obligation to purchase service from El Paso and Mojave's service to
bypassing end users. The Company included a list of current and future natural
gas customers that the Company believes might be targeted by Mojave for bypass
transportation service. The Company also updated its request for compensation as
a result of the Mojave bypass, asking the FERC to relieve the Company of up to
$66 million in El Paso capacity charges and require Mojave to pay the Company
$135 million in lost revenues associated with the proposed bypass.
In March 1994, the FERC denied several requests for rehearing of its order
approving Mojave's expansion. The FERC deferred to a subsequent order
consideration of the Company's request for relief from El Paso capacity charges
and compensation from Mojave.
The Company 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
The Company 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
32
<PAGE> 39
gas storage programs for noncore customers, and an unbundled storage program for
the Company was approved by the CPUC in May 1994. Storage service for core
customers remains bundled with procurement and transportation services.
In September 1994, the Company 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 the Company 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. To date, the Company has not offered
storage service at discounted rates.
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, 1994, Diablo Canyon Units 1 and 2
had achieved lifetime capacity factors of 78% and 80%, respectively.
The table below outlines Diablo Canyon's refueling schedule for the next
five years. This schedule 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>
1995 1996 1997 1998 1999
---------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C>
Unit 1
Refueling........... September March September
Startup............. November April November
Unit 2
Refueling........... March September March
Startup............. May November May
</TABLE>
In November 1994, the Nuclear Regulatory Commission's (NRC) Atomic Safety
and Licensing Board issued its decision approving the Company's request to
change the operating license expiration dates for both units at Diablo Canyon.
Diablo Canyon Units 1 and 2 were originally licensed to operate for 40 years
commencing on the date the construction permit for the respective unit was
issued, which occurred in April 1968 and December 1970, respectively. In 1982,
the NRC determined that the 40-year term of operation for nuclear power plants
may instead begin upon issuance of the first operating license. License
amendments were issued in March 1994 to extend the operating license expiration
date for Units 1 and 2 to September 2021 and April 2025, respectively.
DIABLO SETTLEMENT
In December 1994, the Company, the DRA, the California Attorney General and
several other parties representing energy consumers agreed to a memorandum of
understanding and draft settlement agreement to modify the pricing provisions of
the Diablo Settlement. All other terms and conditions of the Settlement
Agreement would remain unchanged. The parties have filed the proposed
modification with the CPUC and will seek expedited CPUC approval of the proposed
change.
Under the proposed modification, the price for power produced by Diablo
Canyon would be reduced from the current level and would be as shown in the
following table. Based on Diablo Canyon's current operating
33
<PAGE> 40
performance, the proposed modification would result in approximately $2.1
billion less revenue over the next five years, compared to the original pricing
provisions of the Diablo Settlement.
DIABLO CANYON PRICE (CENTS) PER KWH
<TABLE>
<CAPTION>
1995 1996 1997 1998 1999
------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C>
Original Settlement Agreement Price*............... 12.15 12.42 12.70 12.98 13.28
Proposed Price..................................... 11.00 10.50 10.00 9.50 9.00
</TABLE>
- ---------------
* Assumes 3.5% inflation
After December 31, 1999, the escalating portion of the Diablo Canyon price
will increase using the same formula specified in the Diablo Settlement. The
proposed modification provides the Company with the right to reduce the price
below the amount specified if it so chooses.
The parties to the proposed modification agree that the difference between
the Company's revenue requirement under the original terms of the Diablo
Settlement and the proposed new prices will be applied to the ECAC balancing
account until the ECAC undercollection as of December 31, 1995 (see "General --
Current Rate Proceedings -- 1995 Revenue Changes -- ECAC" above) is fully
amortized. As a result, the Diablo Canyon price reductions would help achieve
amortization of the ECAC undercollection. In addition, the parties agree that
the prices for the period through December 31, 1999 are reasonable and shall be
the basis for the recovery of the Company's ECAC revenue requirement pursuant to
the pricing of Diablo Canyon power.
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, the Company 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. The Company'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.
The settlement decision explicitly affirmed that Diablo Canyon costs and
operations no longer should be subject to CPUC reasonableness reviews. The
decision 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 settlement produces a just and reasonable result, and that
the 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 settlement, ending 2016. However, the decision states that the
CPUC cannot bind future Commissions in fixing just and reasonable rates for
Diablo Canyon.
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. As noted above,
the Company has proposed modifying the price for the years 1995 through 1999.
After 1999, the escalating component will be adjusted by the change in the
consumer price index plus 2.5%, divided by two. 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 the Company 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, the Company may
trigger an annual revenue floor provision, or under certain conditions, seek
abandonment of the plant (discussed below). Floor payments ensure that the
Company will receive some revenue, even if the plant stops producing power.
Floor payments
34
<PAGE> 41
are based on the prices set in the agreement 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, the Company must file for abandonment or explain why continued
application of the settlement is appropriate. In the event there is a prolonged
plant outage and the Company files for abandonment, the Company 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.
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.
NUCLEAR FUEL SUPPLY AND DISPOSAL
The Company 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, enrichment services and
conversion services will be satisfied through existing long-term contracts
through 1998, 1999 and 2001, respectively. The Company is also negotiating
contracts for alternative uranium supply and enrichment services through 2002.
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 the Company the flexibility to take
advantage of short-term supply opportunities. In most cases, the Company's
nuclear fuel contracts are requirements-based, with the Company's obligations
linked to the continued operation of Diablo Canyon.
Under the Nuclear Waste Policy Act of 1982 (Nuclear 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 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 Act, utilities are required to provide interim storage facilities until
permanent storage facilities are provided by the federal government. The Nuclear
Act mandates that one or more such permanent disposal sites be in operation by
1998, although DOE has indicated that such sites may not be in operation until
2010. DOE is also considering providing interim storage in a monitored
retrievable storage facility earlier than 2010. However, under DOE's current
estimated acceptance schedule for spent fuel, Diablo Canyon's spent fuel is not
likely to be accepted by DOE for interim or permanent storage before 2011, at
the earliest. At the projected level of operation for Diablo Canyon, the
Company's facilities are sufficient to store on-site all spent fuel produced
through approximately 2006 while maintaining the capability for a full-core
off-load. In the event an interim or permanent DOE storage facility is not
available for Diablo Canyon's spent fuel by 2006, the Company will examine
options for providing additional temporary spent fuel storage at Diablo Canyon
or other facilities, pending disposal or storage at a DOE facility. Such
additional temporary spent fuel storage may be necessary in order for the
Company 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 the Company), 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 Act. Action on the lawsuits has been deferred pending issuance
of a DOE policy statement on the same subject.
In July 1988, the NRC gave final approval to the Company's plan to store
radioactive waste from the Humboldt Bay Power Plant (Humboldt) at Humboldt for
20 to 30 years and, ultimately, to decommission the unit. The license amendment
issued by the NRC allows storage of spent fuel rods at Humboldt until a federal
repository is established. The Company has agreed to remove all nuclear waste as
soon as possible after the federal disposal site is available.
35
<PAGE> 42
INSURANCE
The Company 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 plant of a member utility is damaged or increased
costs for business interruption are incurred due to a prolonged accidental
outage, the Company may be subject to maximum retrospective premium assessments
of $28 million (property damage) and $7 million (business interruption), in each
case per policy period, if losses exceed premiums, reserves and other resources
of NML or NEIL.
The federal government has enacted laws that require all utilities with
nuclear generating facilities with a capacity of 100 MW or more to share in
payment of claims resulting from a nuclear incident. The Price-Anderson Act
limits industry liability for third-party claims resulting from any nuclear
incident 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
public liability claims in excess of $200 million, the Company 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 are deferred to the next
calendar year.
DECOMMISSIONING
The estimated cost of decommissioning the Company's nuclear power
facilities is recovered in base rates through an annual allowance. For the year
ended December 31, 1994, the amount recovered in rates for decommissioning costs
was $54 million. The estimated total obligation for decommissioning costs is
approximately $1.1 billion in 1994 dollars (or $4.5 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, 1994, the Company had accumulated external trust funds
with an estimated fair value of $617 million, based on quoted market prices, to
be used for the decommissioning of the Company'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 the Company'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.
To date the CPUC has not revised the funding levels initially established in
1987. However, to comply with tax law requirements, the Company anticipates that
the CPUC will revise the funding levels no later than the 1997 tax year to
reflect then-current earnings assumptions and decommissioning cost estimates.
PG&E ENTERPRISES
Enterprises is the parent company established to oversee the Company's
unregulated non-utility business activities. Enterprises was established in 1988
and is a wholly owned subsidiary of the Company. Enterprises' activities are
conducted through the entities described below.
NON-UTILITY ELECTRIC GENERATION
A wholly owned Enterprises subsidiary is a general partner in U.S.
Generating Company (USGen), a California general partnership. A subsidiary of
Bechtel Enterprises, Inc., Bechtel Generating Company, Inc., is the other
general partner of USGen. USGen develops and manages non-utility electric
generation facilities that compete in the U.S. power generation market and sell
power to utilities other than the Company. Enterprises' ownership interest in
projects developed by USGen varies by project. Profits and losses realized by
USGen are distributed in proportion to the partners' relative interests in the
project from which those
36
<PAGE> 43
profits or losses are derived. USGen is currently involved in eight operational
plants and five projects under construction. The total generating capacity of
these 13 plants is 2,238 MW. Enterprises' share of capacity from those projects
is approximately 971 MW. The projects are typically financed with a combination
of equity commitments from the project sponsors and non-recourse debt.
In August 1994, USGen negotiated and completed the acquisition of Makowski
on behalf of Enterprises and Bechtel Enterprises, Inc. Makowski is a
Boston-based company engaged in the development of natural gas-fueled power
generation projects and natural gas distribution, supply and underground storage
projects. Makowski is currently involved in five operational plants. (USGen is
also involved in one of these plants.) With the acquisition of Makowski,
Enterprises' affiliates are involved in a total of 12 plants in operation and 5
plants under construction, with total generating capacity of 3,298 MW.
Enterprises' share of capacity from all 17 plants is approximately 1,389 MW.
In addition, Enterprises is in the process of forming, in conjunction with
Bechtel Enterprises, Inc., a company to develop, build, own and operate
international nonutility generation projects.
U.S. Operating Services Company (USOSC), a California general partnership,
provides operations and maintenance services for power facilities managed by
USGen and to third parties in the independent power production business. An
Enterprises subsidiary and a subsidiary of Bechtel Group, Inc. are the general
partners of USOSC. Enterprises' economic interest in USOSC projects varies by
project.
GAS AND OIL EXPLORATION AND PRODUCTION
DALEN, a wholly owned indirect subsidiary of Enterprises, is engaged in
natural gas and oil exploration and production primarily in the Gulf Coast, east
Texas, Anadarko and Rocky Mountain regions of the U.S.
In July 1994, the Company approved a plan for the disposition of DALEN
through an initial public offering of DALEN's common stock, subject to favorable
market conditions. In February 1995, the Company confirmed its intent to sell
DALEN in 1995, either through an initial public offering or a private sale. The
Company's decision is based upon the Company's determination that oil and gas
exploration and production activities do not fit within its revised long-term
corporate strategy. In anticipation of the disposition, DALEN entered into
multiple contracts in June 1994 to sell $130 million of its oil and gas
properties, resulting in a net pretax gain of $2 million. As of December 31,
1994, DALEN had assets of approximately $490 million.
REAL ESTATE DEVELOPMENT
PG&E Properties, Inc. (Properties), a wholly owned subsidiary of
Enterprises, develops real estate in the Company's service territory, focusing
on residential lot creation. It also develops offices, industrial buildings,
retail outlets and apartments.
ENVIRONMENTAL MATTERS AND OTHER REGULATION
ENVIRONMENTAL MATTERS
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 the Company's
bulk waste handling and storage facilities.
37
<PAGE> 44
ENVIRONMENTAL PROTECTION MEASURES
The Company's estimated 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 $39 million, $93 million,
$85 million, $69 million and $66 million for 1995, 1996, 1997, 1998 and 1999,
respectively, and are included in the Company'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. In addition, PGT estimates its
capital expenditures for environmental protection will be approximately $10
million in 1995, primarily for NOx emission reduction and dry low emission
equipment, and approximately $1.8 million in 1996.
Air Quality
The Company'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 the Company 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. One rule may also require
additional expenditures of up to $1.5 million in the San Luis Obispo County Air
Pollution Control District, depending on air quality progress in that district.
The Company currently estimates that compliance with these NOx rules could
require capital expenditures of approximately $300 million over 10 years. This
estimate assumes that most of the 170 MW and smaller boilers will be retired
before the retrofits are required. Ongoing business and engineering studies
could change this estimate.
Other air districts have adopted NOx rules for the Company'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 the Company's natural gas compressor stations. The Company currently
estimates that the total cost of complying with these rules will be
approximately $25 to $55 million over five years.
In the Company's 1993 GRC, the CPUC established an Air Quality Adjustment
mechanism under which the Company may seek cost recovery in rates for NOx
reduction projects during 1994 and 1995. However, by the time the retrofits are
operational, the Company may either be subject to PBR or one of several
restructuring proposals currently under consideration by the CPUC. Therefore,
the mechanism for ratemaking treatment of these costs is uncertain at this time.
In 1990 Congress passed extensive amendments to the Federal Clean Air Act.
The Environmental Protection Agency (EPA) has issued numerous regulations for
the implementation of these amendments. The Company 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 the Company. However, stringent federal
air monitoring requirements mandated the installation of monitoring equipment to
measure emissions from the fossil fuel fired generating plants. The cost of
complying with the monitoring requirements totalled approximately $22 million in
1994.
Water Quality
The Company's existing power plants, including Diablo Canyon, are subject
to federal and state water quality standards with respect to discharge
constituents and thermal effluents. The Company's fossil fueled power plants
comply in all material respects with the discharge constituents standards and
either comply in all material respects with or are exempt from the thermal
standards. A thermal effects study at Diablo Canyon was completed in May 1988,
and has been reviewed by the Central Coast Regional Water Quality Control Board
(Regional Board). The Regional Board has not yet made a final decision on the
report and has requested that the Company continue the marine monitoring
program. In the event that Diablo Canyon does
38
<PAGE> 45
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.
A thermal effects study of the Company's Pittsburg and Contra Costa Power
Plants was submitted to the San Francisco and Central Valley Regional Water
Quality Control Boards in December 1992. In general, the study found no
significant adverse effects associated with the thermal discharge at either
plant. Additionally, several fish species listed or proposed for listing as
endangered species may be found in the waters near these 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.
Pursuant to the federal Clean Water Act, the Company is required to
demonstrate that the location, design, construction and capacity of power plant
cooling water intake structures reflect the best technology available (BTA) for
minimizing adverse environmental impacts at all existing water-cooled thermal
plants. The Company has submitted detailed studies of each power plant's intake
structure to various governmental agencies. Each plant's existing water intake
structure was found to meet the BTA requirements. However, if in the future
there are changes in available technology, these findings are subject to further
review by various agencies. Thus, construction expenditures or operational
changes may be necessary to meet a more stringent future standard.
Oil Spill Prevention
The Company operates three marine terminals, approximately 92 large
aboveground fuel tanks with a capacity of approximately 18 million barrels and
approximately 50 miles of fuel pipelines. These facilities are used for the
transport, handling and storage of residual fuel oil and diesel fuels, both of
which are used at the Company's power plants. The Company continues to assess
its need to operate oil handling and storage facilities as part of its efforts
to reduce exposure to oil handling risks and operational expenses without
sacrificing electric system reliability.
Under the federal Clean Water Act Spill Prevention Control and
Countermeasure (SPCC) regulations, many of the Company's power plants,
substations and service centers must install and maintain facilities to prevent
the release of oil and other hazardous materials to surface waters. Capitalized
SPCC project costs for 1995 and 1996 are estimated to be approximately $2
million.
In addition, activities associated with the transport, storage and handling
of petroleum products are regulated by the federal Oil Pollution Act of 1990
(OPA) and the California Oil Spill Prevention and Response Act of 1990 (OSPRA).
Under these laws, the Company is required to demonstrate $500 million of
financial responsibility, which it demonstrates through a combination of
insurance and self insurance.
Regulations under OPA and OSPRA require development of Oil Spill Emergency
Response Plans utilizing worst case planning scenarios. Plans must include
contracting for response resources to respond to the worst case scenarios. The
Company is a member of the Clean Bay, Clean Seas and Humboldt Bay oil spill
response organizations and the Marine Preservation Association through which it
can obtain the services of the Marine Spill Response Corporation, a national oil
spill response organization.
Company expenditures to comply with OPA and OSPRA requirements in 1995 and
1996 are estimated to total less than $2 million.
HAZARDOUS MATERIALS AND HAZARDOUS WASTE COMPLIANCE AND REMEDIATION
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. 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.
The EPA, the California Department of Toxic Substances Control (DTSC), and
associated regional and local agencies have comprehensive rules which regulate
the manufacture, distribution, use and disposal of
39
<PAGE> 46
polychlorinated biphenyls (PCBs). The Company has established programs and has
committed resources to achieve compliance with these rules. In 1982, the EPA
adopted new regulations greatly restricting the use of PCBs in electrical
equipment. The regulations have resulted in the early retirement and replacement
of certain equipment. Since Company operations generate PCB-contaminated waste
which requires special handling, the Company has contracted with EPA-approved
firms for the disposal or recycling of PCB waste. The Company estimates that PCB
disposal will cost approximately $8 million in 1995 and 1996.
The Company 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. As part of this
general compliance effort, the Company has initiated programs to address three
specific environmental issues: (i) wastewater holding ponds, (ii) underground
storage tanks, and (iii) historic hazardous waste sites, including former
manufactured gas plant sites.
Wastewater evaporation ponds contain materials such as compressor cooling
water blowdown from gas compressor stations. The Company has replaced the old
ponds with new evaporation ponds that meet new standards for leak monitoring,
detection and containment. Capital expenditures for this work in 1995 are
estimated to be approximately $0.9 million. Closure and post-closure
expenditures for these ponds, including groundwater remediation, health risk
assessments and management plans, may approximate $30 million for a 30-year
period.
Underground storage tanks are the subject of federal and California
regulatory programs directed at identifying and eliminating the possibility of
leaks. The Company has approximately 270 underground tanks, some of which must
be upgraded to meet new standards. The tanks contain hazardous materials such as
gasoline, waste automotive crankcase oil, transformer fluid or oily wastewater.
The Company has an ongoing program to improve leak monitoring, test each tank
for leakage and, if necessary, sample soil and water from the surrounding area
and remediate any contamination detected. Costs for testing, remediation and
tank replacement in 1995 and 1996 are estimated to be approximately $4.6
million.
A third 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 the Company 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), the Company's manufactured gas plants were
removed from service. The residues which may remain at some sites contain
chemical compounds which now are classified as hazardous. The Company has
identified and reported to federal and California environmental agencies 96
manufactured gas plant sites which the Company operated in its service
territory. The Company owns all or a portion of 29 of these manufactured gas
plant sites. The Company 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 the Company owns. The Company
currently estimates that this program may result in expenditures of
approximately $30 million over the period 1995 through 1996. 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 the Company is found to be responsible for clean up at sites it does not
currently own.
Manufactured gas plant sites at which the Company 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. The Company will perform a groundwater remedial action at its
former Sacramento manufactured gas plant site during 1995 at a cost of up to $3
million. The DTSC must approve the groundwater remedial action design plan
proposed for this site before it is implemented. The Company has accrued a $7.3
million liability at December 31, 1994 for the Sacramento gas plant site.
In addition to the manufactured gas plant sites, the Company may be
required to take remedial action at certain other disposal sites if they are
determined to present a significant threat to human health and the
40
<PAGE> 47
environment because of an actual or potential release of hazardous substances.
The Company has been designated as a PRP under CERCLA (the federal Superfund
law) with respect to the Purity Oil Sales site in Malaga, California, the
Jibboom Junkyard site in Sacramento, California, the Industrial Waste Processing
site near Fresno, California, and the Lorentz Barrel and Drum site in San Jose,
California. The Purity Oil Sales site is a former used oil recycling facility at
which the Company is one of nine PRPs named in an EPA order requiring
groundwater remediation at the site. The Company has also entered into an
Administrative Order with the EPA to address soil contamination at the site. The
Company has accrued a $6.4 million liability at December 31, 1994 for the Purity
Oil Sales site. Although the Company has not been named as a PRP with respect to
the Casmalia site near Santa Maria, California, the EPA has notified the Company
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. The
Company is working with other alleged generators to evaluate measures which may
need to be taken at the site. The Company has accrued a $1.9 million liability
for the Casmalia site. Although the Company has not been formally designated a
PRP with respect to the Geothermal Industries, Incorporated site in Lake County,
California, the Central Valley Regional Water Quality Control Board and the
California Attorney General's office have directed the Company and other parties
to initiate measures with respect to the study and remediation of that site. The
Company has accrued a liability of $9.8 million for the Geothermal Industries,
Incorporated site.
In addition to the sites discussed above, the Company 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. The Company has also received a
demand from the California Attorney General seeking reimbursement of cleanup
costs incurred by the State of California at the Company's former Jibboom Street
power plant in Sacramento, California. In addition, the Company has been named
as a defendant in several civil lawsuits in which plaintiffs allege that the
Company is responsible for performing or paying for remedial action at sites the
Company no longer owns or never owned.
The overall costs of the hazardous materials and hazardous waste compliance
and remediation activities described above are difficult to estimate due to
uncertainty concerning the extent of environmental risks and the Company's
responsibility, the complexity of environmental laws and regulations and the
selection of compliance alternatives. However, based on the information
currently available, the Company has an accrued liability as of December 31,
1994 of $95 million for hazardous waste remediation costs. The ultimate amount
of such costs may be as much as $235 million if, among other things, the Company
is held responsible for cleanup at additional sites, other PRPs are not
financially able to contribute to these costs, or further investigation
indicates that the extent of contamination and affected natural resources is
greater than anticipated at sites for which the Company is responsible.
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 the Company 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.
The mechanism provides that 70% of the ratepayer portion of the Company's
cleanup costs is attributed to its gas department and 30% is attributed to its
electric department. The Company can seek to recover hazardous substance cleanup
costs under the new mechanism in any rate proceeding it deems most appropriate.
The final decision in the SoCal Gas proceeding permits the Company to seek
recovery under the new mechanism of environmental cleanup costs previously
recorded in balancing accounts under the old recovery mechanism. Accordingly, in
its 1995 BCAP, the Company is seeking recovery of $10.5 million in environmental
cleanup costs under the new mechanism, which amount represents the gas
department's allocation of such previously recorded cleanup costs.
41
<PAGE> 48
To the extent that hazardous waste compliance and remediation costs are not
recovered through insurance or by other means, the Company 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, 1994, the Company has a deferred charge of $83 million for
hazardous waste remediation costs, which represents the minimum amount of such
costs expected to be recovered under the current ratemaking mechanisms. The
Company believes that the ultimate outcome of these matters will not have a
significant adverse impact on its financial position or results of operations.
In December 1992, the Company filed a complaint in San Francisco County
Superior Court against more than 100 of its domestic and foreign insurers,
seeking damages and declaratory relief for remediation and other costs
associated with hazardous waste mitigation. The Company 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, the Company's carriers neither admitted nor denied coverage, but requested
additional information from the Company. 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 Commission 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.
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 will be 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 over the next four years.
As part of its effort to educate the public about EMF, the Company provides
interested customers with information regarding the EMF exposure issue. The
Company 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.
The Company and other utilities are involved in litigation concerning EMFs.
The Company is named as a defendant in three pending civil lawsuits. Plaintiffs
allege personal injury resulting from exposure to EMFs and diminution in
property value due to the presence of EMFs from nearby high voltage lines.
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, the Company
may be required to take mitigation measures at its facilities. The costs of such
mitigation measures cannot be estimated with any certainty at this time.
However, such costs could be significant depending on the particular mitigation
measures undertaken, especially if relocation of existing power lines is
ultimately required.
LOW EMISSION VEHICLE PROGRAMS
In 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 (NGVs) and electric
vehicles (EVs). Hearings in Phase I of the LEV proceeding were conducted in
August 1992, and examined long-term utility involvement in LEV programs in
relation to California's environmental, energy and
42
<PAGE> 49
transportation goals. The Company generally proposed that its long-term role in
the LEV market be that of a fuel supplier, transporter and distributor.
In July 1993, the CPUC issued a decision in Phase I of the LEV proceeding.
The decision recognized a significant role for the Company in the LEV market and
directed the Company to file a request for funding for a six-year program
(1995-2000). In August 1994, the Company requested approximately $41 million in
funding for the Company's fleet and market development activities for NGVs and
EVs over the six-year period. Joint hearings on all utilities' LEV funding
requests were held in the fall of 1994, with a Phase II decision expected by
mid-1995.
As noted above (see "Proposed Regulatory Reforms -- Company's
Proposals -- PBR"), the Company proposes to revise its RRI filing to reflect the
CPUC's electric industry restructuring plan once the details of the CPUC's plan
are sufficiently definitive. The Company anticipates that in its revised filing
it will recommend that LEV program costs be funded as part of environmental and
social benefit programs generally, with LEV funding included in the rate
component related to such programs.
The decision in the Company's 1993 GRC extended NGV funding of $8.5 million
per year pending a final decision in the LEV proceeding described above, and
authorized $1.8 million for EV programs. The Company is using the NGV funds to
install additional natural gas refueling facilities, to purchase or convert
additional NGVs for the Company's fleet, and to provide incentives and
assistance in converting additional customer vehicles to NGVs. The Company and
its customers currently operate nearly 2,700 NGVs.
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 the Company and its subsidiaries and affiliates.
CALIFORNIA ENERGY COMMISSION
The Company also is subject to the jurisdiction of the CEC. The CEC has
developed programs for forecasting peak demands and energy requirements, is
encouraging and requiring 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. The Governor of California is
currently in the process of submitting to the California State Legislature a
plan to reorganize the CEC. Under that plan, the CEC would be consolidated into
the existing Department of Conservation to create a new Department of Energy and
Conservation, the head of which would be appointed by the Governor.
FEDERAL ENERGY REGULATORY COMMISSION
The Company is subject to regulation by the FERC under the Federal Power
Act as a "public utility" as defined in the Act. The FERC has authority, among
other things, to regulate the Company'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 the Company 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.
FERC-HYDROELECTRIC LICENSING
Most of the Company's hydroelectric facilities are subject to licenses
issued 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,
43
<PAGE> 50
they become susceptible to competition for a new license. In the years prior to
1986, several governmentally run utilities, claiming a statutory "preference" in
their favor superior to the Company, had filed competing applications for four
of the Company's projects. Federal legislation enacted in 1986 eliminated any
preference for governmentally run utilities in hydroelectric relicensing
proceedings commenced after 1986.
The 1986 law provided options for resolving relicensing competitions. The
Company elected to pay the competing applicants for the four projects a
"reasonable" settlement consisting of their costs incurred to pursue the
licenses and a potential additional amount ranging from 0% to 100% of the
Company's remaining net investment in the relevant project. In return, the
competing applicants are required to withdraw their competing license
applications. The FERC approved the settlement agreement for two projects. In
October 1992, the FERC issued an order requiring the Company to pay compensation
of $1.9 million to the competing applicants for the remaining two projects,
representing the costs incurred preparing their applications. The FERC declined
to award the competing applicants any additional compensation. In December 1993,
the Company paid the amount called for in the FERC order, and in October 1994,
the U.S. Court of Appeals affirmed that order. The Company expects to recover
the costs of all FERC-awarded compensation through rates.
NUCLEAR REGULATORY COMMISSION
The Company also is subject to the jurisdiction of the NRC as to operation
of its nuclear generating plants.
ITEM 2. PROPERTIES.
Information concerning the Company's electric generation units, gas
transmission facilities, and electric and gas distribution facilities is
included in response to Item 1. All real properties and substantially all
personal properties of the Company are subject to the lien of an indenture which
provides security to the holders of the Company'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, the
Company 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 the Company, filed a complaint in the U.S. District
Court, Eastern District of California, against the Company and PGT, on behalf of
themselves and purportedly as a class action on behalf of all natural gas
customers of the Company during the period of February 1988 through October
1993. The complaint alleges that the purchase of natural gas in Canada was
accomplished in violation of various antitrust laws which resulted in increased
prices of natural gas for the Company's customers.
The complaint alleges that the Company could have purchased as much as 50%
of the Canadian gas on the spot market instead of relying on long-term contracts
and that the damage to the class members is at least as much as the price
differential multiplied by the replacement volume of gas, an amount estimated in
the complaint as potentially exceeding $800 million. In addition, the complaint
indicates that the damages to the class could include over $150 million paid by
the Company to terminate the contracts with the Canadian gas producers in
November 1993. The complaint seeks recovery of three times the amount of the
actual damages pursuant to the antitrust laws.
In August 1994, the federal district court issued a decision granting the
Company's motion to dismiss the federal and state antitrust claims and the state
unfair practices claims against the Company and PGT. The only remaining claims
did not seek monetary damages. In addition, the Court granted plaintiffs' motion
seeking class certification.
44
<PAGE> 51
In dismissing the antitrust claims, the Court determined that the prices
the Company paid for Canadian gas had been filed with, reviewed and approved as
reasonable by various federal and state regulatory authorities, and as a result,
the plaintiffs were barred from claiming that those rates were too high. The
Court also held that the CPUC's oversight of the Company's gas acquisition costs
constitutes state action which immunizes the Company from a private antitrust
lawsuit such as this one.
In September 1994, plaintiffs filed an amended complaint with the Court.
A&S, the Company's wholly owned Canadian gas purchasing subsidiary, is added as
a defendant in the amended complaint. In essence, the amended complaint restates
the claims in the original complaint, and in addition alleges that the
defendants, through anticompetitive practices, foreclosed access over the PGT
pipeline to alternative sources of gas in Canada by certain customers of the
Company. A new motion to dismiss was filed by the Company in November 1994.
The Company believes that the ultimate outcome of the antitrust litigation
will not have a significant 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 the Company's Hinkley Compressor Station,
located along the Company'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 the Company discharged
Chromium VI-contaminated wastewater into unlined ponds, which led to chromium
percolating into the groundwater of surrounding property. The plaintiffs further
allege that the Company disposed of the chromium in those ponds to avoid costly
alternatives. In 1987, the Company undertook an extensive project to remediate
potential groundwater chromium contamination. The Company 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, the Company will continue to
monitor the affected area and periodically perform environmental assessments.
The Company 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, the Company 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 the Company against any additional losses the Company 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 January 1995, ten representative cases began arbitration before two
judges. At the conclusion of the arbitration, the parties began a process of
mediation in an attempt to settle the remaining 625 cases, based on the results
of the arbitration. If the mediation is not successful, the parties will proceed
to arbitrate another 25 to 30 more cases. Following that, the parties will
attempt to mediate the remaining cases. This process will continue until all
cases are arbitrated or settled.
As of December 31, 1994, the Company had a remaining reserve of $50 million
against any future potential liability in this case. The Company believes the
ultimate outcome of this matter will not have a significant adverse impact on
its financial position or results of operations.
45
<PAGE> 52
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 the Company on behalf of
themselves and purportedly as a class action on behalf of 47 counties with which
the Company has gas or electric franchise contracts. Franchise contracts require
the Company 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, the Company 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 the
Company 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 the
Company.
The parties agreed to stipulate to this case proceeding as a class action
lawsuit regarding the issue of the correct payment methodology to be applied in
calculating the franchise fees due to the plaintiffs. On March 14, 1995, the
Superior Court granted the Company's motion for summary judgment in the class
action lawsuit. The plaintiffs may appeal that ruling. Consistent with the
agreement between the parties noted above, the plaintiffs refiled a separate
action covering just the issue of whether the Company properly computed its
franchise payments, assuming that the Company 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,
the Company's annual system-wide 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 $28
million as of December 31, 1994).
The Company believes that the ultimate outcome of this matter will not have
a significant 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 the Company on behalf of itself and purportedly as
a class action on behalf of 107 cities with which the Company has certain
electric franchise contracts. The complaint alleges that, since at least 1988,
the Company has intentionally underpaid its franchise fees to the cities in an
unspecified amount.
The complaint alleges that the Company 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
the Company'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 the Company 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. The case is in
discovery and no trial date has been set.
Should the cities prevail on the issue of franchise fee calculation
methodology, the Company's annual system-wide city electric franchise fees could
increase by approximately $17 million. Damages for alleged underpayments in
prior years could be as much as $114 million (exclusive of interest, estimated
to be $23 million as of December 31, 1994).
The Company believes that the ultimate outcome of this matter will not have
a significant adverse impact on its financial position or results of operations.
46
<PAGE> 53
TIME-OF-USE METER 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 the Company on behalf of themselves and purportedly as a
class action on behalf of all of the Company's customers, for "refund of
unlawfully charged fees." The complaint has been amended to broaden the alleged
class to include customers of the Turlock Irrigation District (TID), which
purchases power from the Company, on the theory that TID customers' rates have
been affected by the Company's alleged failure to notify its customers of the
best available rate.
The complaint alleges that the Company improperly failed to notify its
customers of the most favorable rates available to each particular customer. The
complaint focuses on the "time-of-use" billing option, which allows customers to
save money by shifting their electricity use to off-peak hours when electricity
is cheaper. Plaintiffs contend that all customers could have saved an average of
$50-$75 per month per customer had they been placed on time-of-use rates. The
complaint seeks damages estimated to be in excess of $16 billion. The amended
complaint also includes a claim for $100 billion in "exemplary" damages,
alleging that the Company's failure to properly advise customers of the
"time-of-use" billing option and other rates was "wilful."
The Company believes that the ultimate outcome of this matter will not have
a significant adverse impact on its financial position or results of operations.
NORCEN LITIGATION
On March 17, 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 the Company and PGT.
Norcen Marketing signed a 30-year Firm Service Agreement with PGT for
transportation of 47,022 million Btus per day (MMBtu/d) on the PGT portion of
the Pipeline Expansion. The annual demand charges under the contract currently
are approximately $8.1 million. Norcen Energy is a guarantor of the 30-year
transportation contract between PGT and Norcen Marketing.
The complaint alleges that PGT and the Company wrongfully induced Norcen
Energy and Norcen Marketing to enter into the 30-year contract by concealing
legal action taken by the Company 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 further alleges breach of
representations to plaintiffs that the Company would not "unreasonably" build
its Pipeline Expansion with less than "sufficient" firm subscription. The
complaint also alleges breach of an agreement between PGT and a Norcen
predecessor named Bonus Gas Processors Corp. (Bonus) relating to the
installation of additional capacity. The complaint generally charges the Company
with monopolizing the capacity on the original PGT facilities from Kingsgate to
Malin and wrongfully preventing Norcen Energy and Norcen Marketing (apparently
based on rights allegedly acquired from Bonus) from utilizing the existing PG&E
transmission system to provide gas to customers in Northern California.
The complaint alleges various antitrust, contractual, and other claims
against the defendants and seeks rescission, restitution and recovery of
unspecified damages. In a pleading filed in June 1994, the plaintiffs indicate a
claim for $140 million (before trebling) based on defendants' allegedly
exclusionary business behavior, as well as an unspecified amount of contract
damages. Based on available information, plaintiffs' out-of-pocket contract
damages appear to be less than $10 million.
On September 19, 1994, the U.S. District Court, Northern District of
California, granted PGT's and the Company's motion to dismiss all federal
antitrust claims in the complaint in this case, and dismissed the remaining
state antitrust and contract claims for lack of jurisdiction. On October 18,
1994, Norcen filed an amended complaint. The amended complaint reasserted part
of the original complaint's antitrust claims, asserted new antitrust claims
based on the same facts and specifically alleged diversity jurisdiction for the
state
47
<PAGE> 54
law contract claims. On November 18, 1994, PGT and the Company filed motions to
dismiss the amended complaint.
The Company believes that the ultimate outcome of this matter will not have
a significant adverse impact on its financial position or results of operations.
POTTER VALLEY HYDROELECTRIC PROJECT
On January 19, 1995, the FERC issued a decision finding that the Company
had not violated the FERC's April 1994 order relating to a fish screen and
bypass facility for the Company's Potter Valley Hydroelectric Project, reversing
the compliance order issued by the FERC in September 1994 indicating such a
violation had occurred. Accordingly, no fines will be imposed in connection with
the matters cited in the September compliance order.
PGT UNIT 4C COMPRESSOR UNIT PERMIT
PGT owns and operates the 4C Solar Mars compressor unit near Sandpoint,
Idaho (Unit 4C). In connection with an upgrade of Unit 4C in 1986, PGT applied
for and received a construction permit from the State of Idaho Department of
Environmental Quality. At the time PGT received the construction permit, it was
determined that no permit for the modification was needed under the federal
Prevention of Significant Deterioration (PSD) program, then being administered
in Idaho by the State.
In the process of applying for a permit under the 1990 Clean Air Act, PGT
conducted a review of its environmental permits and discovered information which
now causes it to question whether a construction permit incorporating PSD
requirements may have been required prior to the 1986 upgrade. PGT is in the
process of discussing this information with the State of Idaho. If it is finally
determined that such a permit was required, PGT may be required to apply for and
obtain a PSD permit for Unit 4C and/or to retrofit Unit 4C. PGT may also 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 significant adverse impact on its financial position or results of operations.
48
<PAGE> 55
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
Not applicable.
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 the Company are as
follows:
<TABLE>
<CAPTION>
AGE AT
DECEMBER 31,
NAME 1994 POSITION EFFECTIVE DATE
-------------------- -------------- ---------------------- ------------------
<S> <C> <C> <C>
R. A. Clarke................. 64 Chairman of the Board July 1, 1994
S. T. Skinner................ 57 President and Chief Executive Officer July 1, 1994
R. D. Glynn, Jr.............. 52 Executive Vice President July 1, 1994
J. D. Shiffer................ 56 Executive Vice President November 1, 1991
R. J. Haywood................ 50 Senior Vice President and General Manager, December 21, 1994
Customer Energy Services
J. F. Jenkins-Stark.......... 43 Senior Vice President and General Manager, Gas August 1, 1993
Supply Business Unit
V. G. Rose................... 48 Senior Vice President and General Manager, January 1, 1994
Electric Supply Business Unit
G. M. Rueger................. 44 Senior Vice President and General Manager, November 1, 1991
Nuclear Power Generation Business Unit
T. W. High................... 47 Vice President and Assistant to the Chief July 1, 1994
Executive Officer
G. N. Horne.................. 63 Vice President--Corporate Communications July 1, 1983
J. Pfannenstiel.............. 47 Vice President--Corporate Planning February 1, 1987
G. R. Smith.................. 46 Vice President and Chief Financial Officer November 1, 1991
B. Coull Williams............ 42 Vice President--Human Resources February 1, 1993
B. R. Worthington............ 45 Vice President and General Counsel December 21, 1994
</TABLE>
All officers serve at the pleasure of the Board of Directors. All executive
officers have been employees of the Company 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>
R. A. Clarke........... Chairman of the Board and Chief Executive May 1, 1986 to June 30, 1994
Officer
S. T. Skinner.......... President and Chief Operating Officer November 1, 1991 to June 30, 1994
Vice Chairman of the Board May 1, 1986 to October 31, 1991
J. D. Shiffer.......... Senior Vice President and General Manager, February 1, 1990 to October 31, 1991
Nuclear Power Generation Business Unit
Vice President--Nuclear Power Generation October 1, 1984 to January 31, 1990
R. D. Glynn, Jr........ Senior Vice President and General Manager, January 1, 1994 to June 30, 1994
Customer Energy Services Business Unit
Senior Vice President and General Manager, November 1, 1991 to December 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 and Contracts April 20, 1988 to February 21, 1993
J. F. Jenkins-Stark.... Vice President and Treasurer January 15, 1992 to July 31, 1993
Treasurer November 1, 1987 to January 14, 1992
V. G. Rose............. Senior Vice President and General Manager, February 22, 1993 to December 31, 1993
Customer Energy Services Business Unit
Senior Vice President and General Manager, September 1, 1988 to February 21, 1993
Distribution Business Unit
G. M. Rueger........... Senior Vice President and General Manager January 1, 1988 to October 31, 1991
Electric Supply Business Unit
T. W. High............. Vice President and Assistant to November 1, 1991-June 30, 1994
the Chairman of the Board
Vice President and Corporate Secretary May 1, 1986 to October 31, 1991
G. R. Smith............ Vice President--Finance and Rates November 1, 1987 to October 31, 1991
B. Coull Williams...... Division Manager, San Francisco Division April 13, 1992 to January 31, 1993
Division Manager, North Bay Division July 1, 1989 to April 12, 1992
B. R. Worthington...... Chief Counsel--Corporate January 10, 1991-December 20, 1994
Attorney June 10, 1974-January 9, 1991
</TABLE>
49
<PAGE> 56
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 43 under the heading
"Quarterly Consolidated Financial Data" in the Company's 1994 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 the Company's 1994 Annual Report to Shareholders, which
information is hereby incorporated by reference and filed as part of Exhibit 13
to this report.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS.
A discussion of the Company's results of operations and liquidity and
capital resources is set forth on pages 13 through 20 under the heading
"Management's Discussion and Analysis of Consolidated Results of Operations and
Financial Condition" in the Company's 1994 Annual Report to Shareholders, which
discussion is hereby incorporated by reference and filed as part of Exhibit 13
to this report.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
Information responding to Item 8 is contained in the Company's 1994 Annual
Report to Shareholders on page 44 and pages 21 through 43 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 and Preferred Stock," "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 the Company is included in a
separate item captioned "Executive Officers of the Registrant" contained on page
47 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 1995 Proxy
Statement relating to the 1995 Annual Meeting of Shareholders, which information
is hereby incorporated by reference.
ITEM 11. EXECUTIVE COMPENSATION.
Information responding to Item 11 is included on page 7 under the heading
"Compensation of Directors" and on pages 11 through 18 under the heading
"Executive Compensation" in the 1995 Proxy Statement relating to the 1995 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 and 19 under the
headings "Security Ownership of Management" and "Principal Shareholders" in the
1995 Proxy Statement relating to the 1995 Annual Meeting of Shareholders, which
information is hereby incorporated by reference.
50
<PAGE> 57
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
Information responding to Item 13 is included on page 7 under the heading
"Certain Relationships and Related Transactions" in the 1995 Proxy Statement
relating to the 1995 Annual Meeting of Shareholders, which information is hereby
incorporated by reference.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K.
(A) THE FOLLOWING DOCUMENTS ARE FILED AS A PART OF THIS REPORT:
1. The following consolidated financial statements, schedules of
consolidated segment information, supplemental information and report
of independent public accountants contained in the 1994 Annual Report
to Shareholders, are incorporated by reference in this report:
Statement of Consolidated Income for the Years Ended December 31,
1994, 1993 and 1992.
Consolidated Balance Sheet at December 31, 1994 and 1993.
Statement of Consolidated Cash Flows for the Years Ended December 31,
1994, 1993 and 1992.
Statement of Consolidated Common Stock Equity and Preferred Stock for
the Years Ended December 31, 1994, 1993 and 1992.
Statement of Consolidated Capitalization at December 31, 1994 and
1993.
Schedule of Consolidated Segment Information for the Years Ended
December 31, 1994, 1993 and 1992.
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, 1994, 1993 and 1992.
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.
51
<PAGE> 58
4. Exhibits required to be filed by Item 601 of Regulation S-K:
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 January 1, 1995.
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 T-3, and general terms
and conditions.
10.3 Diablo Canyon Settlement Agreement 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)
and portions of the California Public Utilities Commission
Decision No. 88-12-083, dated December 19, 1988, interpreting
the Settlement Agreement (Form 10-K for fiscal year 1988 (File
No. 1-2348), Exhibit 10.4).
*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 September
21, 1994, effective April 1, 1995.
*10.7 Performance Incentive Plan of Pacific Gas and Electric Company
(Form 10-K for fiscal year 1993 (File No. 1-2348), Exhibit
10.10).
*10.8 The Pacific Gas and Electric Company Retirement Plan applicable
to non-union employees, as amended September 21, 1994, effective
January 1, 1995.
*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
effective as of September 16, 1992 (Form 10-K for fiscal year
1993 (File No. 1-2348), Exhibit 10.13).
*10.11 Pacific Gas and Electric Company Performance Unit Plan (Form
10-K for fiscal year 1991 (File No. 1-2348), Exhibit 10.13).
*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).
- ---------------
* 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.
52
<PAGE> 59
*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
(Form 10-K for fiscal year 1991 (File No. 1-2348), Exhibit
10.21).
11. Computation of Earnings Per Common Share (Form 8-K dated March
2, 1995 (File No. 1-2348), Exhibit 11).
12.1 Restated Computation of Ratios of Earnings to Fixed Charges.
12.2 Restated Computation of Ratios of Earnings to Combined Fixed
Charges and Preferred Stock Dividends.
13. 1994 Annual Report to Shareholders (portions of the 1994 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 and Preferred Stock," "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 1994 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(v) 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 March 2, 1995 (File No.
102348), 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.
- ---------------
* 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.
53
<PAGE> 60
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.
(B) REPORTS ON FORM 8-K
Reports on Form 8-K during the quarter ended December 31, 1994 and through
the date hereof:
1. October 13, 1994
Item 5. Other Events
-- Helms Pumped Storage Plant -- Proposed Settlement
2. October 21, 1994
Item 5. Other Events
-- Diablo Canyon Nuclear Power Plant -- Diablo Canyon Rate Case
Settlement
-- Performance Incentive Plan -- Year-to-Date Financial Results
3. October 28, 1994
Item 5. Other Events
-- California Public Utilities Commission Proceedings
-- 1995 Cost of Capital Proceeding
-- Long-Term Noncore Gas Transportation Tariff/Gas Transmission
Jurisdiction
4. November 17, 1994
Item 5. Other Events
-- Diablo Canyon Nuclear Power Plant -- Diablo Canyon Rate Case
Settlement
5. November 23, 1994
Item 5. Other Events
-- California Public Utilities Commission Proceedings
-- Electric Industry Restructuring
-- Restructuring of Gas Supply Arrangements -- Recovery of
Interstate Transportation Demand Charges
-- Energy Cost Adjustment Clause
-- 1995 Cost of Capital Proceeding
-- PGT/PG&E Pipeline Expansion Project -- Other Competitive
Interstate Pipeline Projects
-- Diablo Canyon Nuclear Power Plant
-- Diablo Canyon Rate Case Settlement
-- Diablo Canyon License Amendment
6. December 5, 1994
Item 5. Other Events
-- Proposed Modification of Diablo Canyon Pricing Mechanism
7. December 19, 1994
-- California Public Utilities Proceedings
-- Electric Industry Restructuring
-- 1996 General Rate Case
54
<PAGE> 61
8. January 4, 1995
Item 5. Other Events
-- Performance Incentive Plan -- 1995 Target
-- California Public Utilities Commission Proceedings
-- 1995 Electric Rate Stabilization/Attrition Rate Adjustment
-- ECAC
-- 1988 - 1990 Gas Reasonableness Proceedings
9. January 19, 1995
Item 5. Other Events
-- Performance Incentive Plan -- 1994 Financial Results
-- 1994 Consolidated Earnings (unaudited)
-- Common Stock Dividend
-- California Public Utilities Commission Proceedings -- Core
Procurement Incentive Mechanism
10. February 21, 1995
Item 5. Other Events
-- California Public Utilities Commission Proceedings--Experimental
Procurement Service for Customer-Identified Electric Supply
11. March 2, 1995
Item 7. Financial Statements, Pro Forma Information and Exhibits
-- 1994 Financial Statements
-- Ratios of Earnings to Fixed Charges and Ratios of Earnings to
Combined Fixed Charges and Preferred Dividends
-- Exhibits
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 Securities Act of 1933 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.
55
<PAGE> 62
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 27TH DAY OF MARCH, 1995.
PACIFIC GAS AND ELECTRIC COMPANY
(Registrant)
By GARY P. ENCINAS
-----------------------------------
(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 President and Chief Executive March 27, 1995
Officer and Director
B. PRINCIPAL FINANCIAL OFFICER
*GORDON R. SMITH Vice President and March 27, 1995
Chief Financial Officer
C. CONTROLLER OR PRINCIPAL ACCOUNTING
OFFICER
*THOMAS C. LONG Controller March 27, 1995
D. DIRECTORS
* RICHARD A. CLARKE
* H. M. CONGER
* WILLIAM S. DAVILA
* MELVIN B. LANE
* DAVID M. LAWRENCE
* LESLIE L. LUTTGENS
* RICHARD B. MADDEN
* GEORGE A. MANEATIS Directors March 27, 1995
* MARY S. METZ
* WILLIAM F. MILLER
* JOHN B. M. PLACE
* SAMUEL T. REEVES
* CARL E. REICHARDT
* JOHN C. SAWHILL
* ALAN SEELENFREUND
* BARRY LAWSON WILLIAMS
</TABLE>
* By GARY P. ENCINAS
---------------------------------
(Gary P. Encinas,
Attorney-in-Fact)
56
<PAGE> 63
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 6, 1995. Our report on the 1994
consolidated financial statements includes an explanatory paragraph that
describes the uncertainties regarding the ultimate outcome of the electric
industry restructuring, as discussed in note 2 to the consolidated financial
statements. In addition, our report includes an explanatory paragraph indicating
that, effective January 1, 1993, the Company changed its method of accounting
for postretirement benefits other than pensions and for income taxes as
discussed in notes 1 and 9 to the consolidated financial statements.
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
ARTHUR ANDERSEN LLP
San Francisco, California
February 6, 1995
57
<PAGE> 64
SCHEDULE II
PACIFIC GAS AND ELECTRIC COMPANY
SCHEDULE II -- CONSOLIDATED VALUATION AND
QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 1994, 1993 AND 1992
<TABLE>
<CAPTION>
COLUMN C
COLUMN B ADDITIONS
BALANCE ------------------- COLUMN E
AT CHARGED BALANCE
BEGINNING TO COSTS CHARGED COLUMN D AT
COLUMN A OF AND TO OTHER DEDUC- END OF
DESCRIPTION PERIOD EXPENSES ACCOUNTS TIONS PERIOD
------------------ (IN THOUSANDS)-------------------
<S> <C> <C> <C> <C> <C>
VALUATION AND QUALIFYING ACCOUNTS
DEDUCTED FROM ASSETS:
1994:
Reserve for impairment of oil and gas
properties........................... $ 7,924 $ 4,565 $ -- $ 8,148 (3) $ 4,341
========= ======== ======== ========= =========
Reserve for deferred project costs...... $18,689 $ 7,111 $ -- $ -- $25,800
========= ======== ======== ========= =========
Allowance for uncollectible accounts.... $23,647 $14,010 $ -- $ 7,888 (5) $29,769
========= ======== ======== ========= =========
Reserve for land costs.................. $ 6,154 $ -- $ -- $ 194 $ 5,960
========= ======== ======== ========= =========
1993:
Reserve for investment in Alaska Natural
Gas Transportation System............ $152,517 $ -- $ -- $152,517(1) $ 0
========= ======== ======== ========= =========
Reserve for impairment of oil and gas
properties........................... $10,417 $ 7,165 $ -- $ 9,658 (3) $ 7,924
========= ======== ======== ========= =========
Reserve for deferred project costs...... $ 9,207 $11,086 $ -- $ 1,604 (4) $18,689
========= ======== ======== ========= =========
Allowance for uncollectible accounts.... $23,806 $ 1,907 $ -- $ 2,066 (5) $23,647
========= ======== ======== ========= =========
Reserve for land costs.................. $ 1,724 $ 4,749 $ -- $ 319 $ 6,154
========= ======== ======== ========= =========
1992:
Reserve for investment in Alaska Natural
Gas Transportation System............ $132,893 $19,624 $ -- $ -- $152,517(2)
========= ======== ======== ========= =========
Reserve for impairment of oil and gas
properties........................... $10,835 $ 4,857 $ -- $ 5,275 (3) $10,417
========= ======== ======== ========= =========
Reserve for deferred project costs...... $ 4,627 $ 4,580 $ -- $ -- $ 9,207
========= ======== ======== ========= =========
Allowance for uncollectible accounts.... $16,677 $13,664 $ -- $ 6,535 (5) $23,806
========= ======== ======== ========= =========
Reserve for land costs.................. $ 1,724 $ -- $ -- $ -- $ 1,724
========= ======== ======== ========= =========
</TABLE>
- ---------------
(1) Company disposed of its investment in Alaska Natural Gas Transportation
System in January 1993.
(2) Construction on the gas transportation system was discontinued in 1983. The
Company accrued and reserved AFUDC through January 1993, at which time the
Company's subsidiary that was a partner in the partnership organized to
build and operate the gas transportation system withdrew from that
partnership.
(3) Deductions consist principally of write-offs of expired leaseholds on
reserved property.
(4) Primarily due to development cost for power projects.
(5) Deductions consist principally of write-offs, net of collections of
receivables considered uncollectible.
58
<PAGE> 65
================================================================================
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
EXHIBITS
TO
FORM 10-K
FOR THE YEAR ENDED DECEMBER 31, 1994
------------------
PACIFIC GAS AND ELECTRIC COMPANY
------------------
================================================================================
<PAGE> 66
INDEX TO EXHIBITS
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION OF EXHIBITS
- ------- ------------------------------------------------------------------------------------
<S> <C>
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 January 1, 1995.
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 T-3, and general terms and
conditions.
10.3 Diablo Canyon Settlement Agreement 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) and
portions of the California Public Utilities Commission Decision No. 88-12-083, dated
December 19, 1988, interpreting the Settlement Agreement (Form 10-K for fiscal year
1988 (File No. 1-2348), Exhibit 10.4).
*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 September 21, 1994, effective April 1, 1995.
*10.7 Performance Incentive Plan of Pacific Gas and Electric Company (Form 10-K for fiscal
year 1993 (File No. 1-2348), Exhibit 10.10).
*10.8 The Pacific Gas and Electric Company Retirement Plan applicable to non-union
employees, as amended September 21, 1994, effective January 1, 1995.
*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 effective as of
September 16, 1992 (Form 10-K for fiscal year 1993 (File No. 1-2348), Exhibit
10.13).
*10.11 Pacific Gas and Electric Company Performance Unit Plan (Form 10-K for fiscal year
1991 (File No. 1-2348), Exhibit 10.13).
*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).
*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 (Form 10-K for fiscal
year 1991 (File No. 1-2348), Exhibit 10.21).
</TABLE>
<PAGE> 67
INDEX TO EXHIBITS--(CONTINUED)
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION OF EXHIBITS
- ------- ------------------------------------------------------------------------------------
<S> <C>
11. Computation of Earnings Per Common Share (Form 8-K dated March 2, 1995 (File No.
1-2348), Exhibit 11).
12.1 Restated Computation of Ratios of Earnings to Fixed Charges.
12.2 Restated Computation of Ratios of Earnings to Combined Fixed Charges and Preferred
Stock Dividends.
13. 1994 Annual Report to Shareholders (portions of the 1994 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 and Preferred Stock," "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 1994 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(v) 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 March 2, 1995 (File No. 102348), 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.
<PAGE> 1
EXHIBIT 3.2
BYLAWS
OF
PACIFIC GAS AND ELECTRIC COMPANY
AS AMENDED JANUARY 1, 1995
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> 2
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 seventeen
(17) 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> 3
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.
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
[3]
<PAGE> 4
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.
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.
[4]
<PAGE> 5
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.
4. EMPLOYEE'S STOCK PURCHASE PLAN. Subject to any limitation
contained in the Articles of Incorporation, the Board of Directors may in its
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
[5]
<PAGE> 6
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 Employees 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> 1
Pacific Gas Transmission Company
FERC Gas Tariff First Revised Sheet No. 12
First Revised Volume No. 1-A Superseding
Original Sheet No. 12
EXHIBIT 10.1
RATE SCHEDULE FTS-1
FIRM TRANSPORTATION SERVICE
1. AVAILABILITY
This rate schedule is available to any party (hereinafter called "Shipper")
qualifying for service pursuant to the Commission's Regulations contained
in 18 CFR Part 284, and who has executed a Firm Transportation Service
Agreement with PGT in the form contained in this FERC Gas Tariff First
Revised Volume No. 1-A.
2. APPLICABILITY AND CHARACTER OF SERVICE
This rate schedule shall apply to firm gas transportation services
performed by PGT for Shipper pursuant to the executed Firm Transportation
Service Agreement between PGT and Shipper. PGT shall receive from Shipper
such daily quantities of gas up to the Shipper's Maximum Daily Quantity as
specified in the executed Firm Transportation Service Agreement between PGT
and Shipper plus the required quantity of gas for fuel and line loss
associated with service under this Rate Schedule FTS-1 and redeliver an
amount equal to the quantity received less the required quantity of gas for
fuel and line loss. This transportation service shall be firm and not
subject to curtailment or interruption except as provided in the
Transportation General Terms and Conditions.
Firm transportation service shall be subject to all provisions of the
executed Firm Transportation Service Agreement between PGT and Shipper and
the applicable Transportation General Terms and Conditions.
3. RATES
Shipper shall pay PGT each month the sum of the Reservation Charge,
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> 2
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> 3
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> 4
Pacific Gas Transmission Company
FERC Gas Tariff Substitute Original 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. 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. RP94-24-000OP , dated NOVEMBER 12, 1993
<PAGE> 5
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> 6
Pacific Gas Transmission Company
FERC Gas Tariff Original Sheet No. 16A
First Revised Volume No. 1-A
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 equal to the product obtained by multiplying (i) that
Shipper's Reservation Charge divided by 30.4 times (ii) that Shipper's
Confirmed Daily Nomination for that Credit Day less the actual
quantity of gas delivered by PGT to PG&E at Malin for Shipper's
account for that 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 28, 1994 Effective: APRIL 01, 1994
<PAGE> 7
Pacific Gas Transmission Company
FERC Gas Tariff Original Sheet No. 16B
First Revised Volume No. 1-A
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 equal to the product obtained by multiplying (i) that
Shipper's Reservation Charge divided by 30.4 times (ii) that Shipper's
Confirmed Daily Nomination for that Credit Day less the actual
quantity of gas delivered by PGT to a Shipper's primary delivery
point(s) (other than Malin) for Shipper's account for that 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 28, 1994 Effective: APRIL 01, 1994
<PAGE> 8
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> 9
Pacific Gas Transmission Company
FERC Gas Tariff Fifth Revised Sheet No. 4
First Revised Volume No. 1-A Superseding Fourth Revised Sheet No. 4
STATEMENT OF EFFECTIVE RATES AND CHARGES FOR
TRANSPORTATION OF NATURAL GAS (a)
($/MMBtu)
<TABLE>
<CAPTION>
Rate Schedule Base Tariff Rates GSR (h) GRI (b) FERC (c)
and Type of Charge (f) Minimum Maximum Surcharge Adjustment Annual Charge
Load Factor
High Low
<S> <C> <C> <C> <C> <C> <C>
FTS-1 Firm Transportation Service (e)
Reservation Charge 0.000000 0.006929 ---- 0.218 0.134 ----
Reservation Surcharge for (g):
T-2 Converting Shippers 0.000000 0.005968 ---- ---- ---- ----
T-3 Converting Shippers 0.000000 0.016639 ---- ---- ---- ----
Delivery Rate 0.000031 0.000031 0.000194 0.0085 0.0085 0.0024
Delivery Rate Surcharge for:
T-2 Converting Shippers 0.000000 (0.000004) ---- ---- ---- ----
T-3 Converting Shippers 0.000000 (0.000029) ---- ---- ---- ----
Authorized Overruns 0.000015 0.000473 0.000194 0.0085 0.0085 0.0024
ITS-1 Interruptible Transportation
Service (d) 0.000015 0.000473 0.000194 0.0085 0.0085 0.0024
Backhaul Service 0.000015 0.000473 0.000194 0.0085 0.0085 0.0024
</TABLE>
NOTES:
(a) The Base Tariff Rates and Gas Supply Restructuring (GSR) Surcharge are
applied per pipeline mile, to gas transported by PGT for delivery to
Shipper. The pipeline mileage distance shall be measured from the point of
receipt by PGT to Shipper-designated point of delivery. Consult PGT system
map on Sheet 3 for delivery points and milepost designations. The rates
posted on this Statement of Effective Rates and Charges for Transportation
of Natural Gas consist entirely of transportation-related cost components.
These rates do not include any storage or gathering charges.
Issued by: P.G.Rosput, Senior Vice President
Issued on: SEPTEMBER 01, 1994 Effective: OCTOBER 01, 1994
<PAGE> 10
Pacific Gas Transmission Company
FERC Gas Tariff Sixth Revised Sheet No. 5
First Revised Volume No. 1-A Superseding Fifth Revised Sheet No. 5
STATEMENT OF EFFECTIVE RATES AND CHARGES FOR
TRANSPORTATION OF NATURAL GAS (a)
($/MMBtu)
(Continued)
Notes (Continued)
(b) In accordance with Paragraph 2 of the Transportation General Terms and
Conditions of this FERC Gas Tariff First Revised Volume No. 1-A, all
Shippers that are not members of GRI shall pay a GRI funding unit
adjustment as set forth on effective Sheet No. 4. This adjustment shall be
in addition to the Base Tariff Rate(s) specified above.
(c) In accordance with Paragraph 22 of the Transportation General Terms and
Conditions of this FERC Gas Tariff First Revised Volume No. 1-A, all
Shippers shall pay an ACA unit adjustment of $0.0024 per MMBtu. This
adjustment shall be in addition to the Base Tariff Rate(s) specified above.
(d) The maximum ITS-1 transportation charges calculated from the product of the
rates above and the pipeline mileage distances for the following routes
are:
<TABLE>
<S> <C>
Kingsgate, B.C. to Spokane, WA 0.051221/MMBtu
Kingsgate, B.C. to Stanfield, OR 0.131196/MMBtu
Kingsgate, B.C. to Malin, OR 0.289694/MMBtu
</TABLE>
(e) For Shippers who release capacity either through a primary release or a
secondary release, a marketing of capacity fee may be added (if applicable)
to the otherwise applicable rates and charges pursuant to Paragraph 28 of
the Transportation General Terms and Conditions of this FERC Gas Tariff
First Revised Volume No. 1-A.
(f) Fuel Use: Shipper shall furnish gas used 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 in an amount equal to the
sum of the current fuel and line loss percentage and the fuel and line loss
percentage surcharge in accordance with Paragraph 37 of this tariff,
multiplied by the distance in pipeline miles transported from the receipt
point to the delivery point multiplied by the transportation quantities of
gas delivered to Shipper under these rate schedules. The current fuel and
line loss percentage shall be adjusted each month between the maximum rate
of 0.0041% per MMBtu per pipeline mile and the minimum rate of 0.0000% per
MMBtu per mile. The fuel and line loss percentage surcharge is 0.0008% per
MMBtu per pipeline mile. No fuel use charges will be assessed for backhaul
service.
(g) Shippers who convert from Section 7(c) service under Rate Schedules T-2 or
T-3 to Part 284 service under Rate Schedule FTS-1 shall pay monthly
Reservation Surcharges as provided in Paragraph 3.4 of Rate Schedule FTS-1.
(h) Gas Supply Restructuring (GSR) Transition Cost Surcharge shall apply
pursuant to the provisions of Paragraph 30 of the Transportation General
Terms and Conditions and Paragraph 3.6 of Rate Schedule FTS-1 and Paragraph
3.3 of Rate Schedule ITS-1. Washington Natural Gas Company shall pay a GSR
surcharge of $0.000089 per MMBtu-mile.
(Continued)
Issued by: P.G.Rosput, Senior Vice President
Issued on: DECEMBER 01, 1994 Effective: JANUARY 01, 1995
<PAGE> 11
Pacific Gas Transmission Company
FERC Gas Tariff Fourth Revised Sheet No. 51
First Revised Volume No. 1-A Superseding
Third 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 Scheduling of Receipts and Deliveries 67
19 Operating Provisions for Interruptible Transportation Service 69
20 Operating Provisions for Firm Transportation Service 70
21 Operating Provisions for Interruptible and Firm
Transportation Service 72
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 for Transportation 87
26 Market Centers 88
27 Planned PGT Capacity Curtailments and Interruptions 88
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
36 Capacity Relinquishment 139
37 Fuel, Line Loss and Other Unaccounted For Gas Adjustment 140
38 Crediting of Parking and Authorized Imbalance Revenues 142
39 Sales of Excess Gas 143
(Continued)
</TABLE>
Issued by: P.G.Rosput, Senior Vice President
Issued on: APRIL 08, 1994 Effective: APRIL 22, 1994
<PAGE> 12
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 (60o) 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 (60o)
Fahrenheit, saturated with water vapor, and at an absolute
pressure equivalent to thirty (30) inches of mercury at
thirty-two degrees (32o) 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> 13
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> 14
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> 15
Pacific Gas Transmission Company
FERC Gas Tariff Original Sheet No. 55
First Revised Volume No. 1-A
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 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 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> 16
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 61,316
(1993) this Paragraph 2 establishes a GRI Funding Unit which
shall be collected for quantities of gas transported under
PGT's rate schedules provided, however, such charge shall not
be applicable to discounted transactions except where the
discounted rate is less than the GRI Funding Unit. In this
instance PGT shall remit that portion of the GRI Funding Unit
actually collected. For purposes of discounted transactions,
any GRI Funding Unit shall be considered to be the first
component of rates discounted. The GRI Funding Unit may be
discounted to zero and shall not be applied to the same
quantity of gas more than once.
(Continued)
Issued by: P.G.Rosput, Senior Vice President
Issued on: JANUARY 10, 1994 Effective: JANUARY 01, 1994
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. TM94-2-86-000, dated DECEMBER 30, 1993
<PAGE> 17
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 (15o) 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 (110o)
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> 18
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, 1884 Effective: APRIL 01 1994
<PAGE> 19
Pacific Gas Transmission Company
FERC Gas Tariff Original Sheet No. 58
First Revised Volume No. 1-A
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
3. QUALITY OF GAS (Continued)
3.2 Quality Tests (Continued)
(c) Tests shall be made to determine the total sulphur,
hydrogen sulfide, carbon dioxide and oxygen content of
the gas, by approved standard methods in general use in
the gas industry, and to determine the hydrocarbon
dew-point and water vapor content of such gas by methods
satisfactory to the parties. Tests shall be made
frequently enough to ensure that the gas is conforming
continuously to the quality requirements. Shipper shall
have the right to require PGT to have remedied any
deficiency in quality of the gas and, in the event such
deficiency is not remedied, the right, in addition to all
other remedies available to it by law, to refuse to
accept such deficient gas until such deficiency is
remedied.
4. MEASURING EQUIPMENT
4.1 Installation: Unless PGT and Shippers agree otherwise, all gas
volume measuring equipment, devices and materials at the
point(s) of receipt and/or delivery shall be furnished and
installed by PGT at Shipper's expense including the tax-on-tax
effect. All such equipment, devices and materials shall be
owned, maintained and operated by PGT. Shipper may install and
operate check measuring equipment provided it does not
interfere with the use of PGT's equipment.
4.2 Testing Meter Equipment: The accuracy of either PGT's or
Shippers measuring equipment shall be verified by test, using
means and methods acceptable to the other party, at intervals
mutually agreed upon, and at other times upon request. Notice
of the time and nature of each test shall be given by the
entity conducting the test to the other entity sufficiently in
advance to permit convenient arrangement for the presence of
the representative of the other entity. If, after notice, the
other entity fails to have a representative present, the
results of the test shall nevertheless be considered accurate
until the next test. If any of the measuring equipment is
found to be registering inaccurately in any percentage, it
shall be adjusted at once to read as accurately as possible.
All tests of such measuring equipment shall be made at the
expense of the entity conducting the same, except that the
other entity shall bear the expense of tests made at its
request if the inaccuracy is found to be two percent (2%) or
less.
(Continued)
Issued by: P.G.Rosput, Senior Vice President
Issued on: AUGUST 02, 1993 Effective: NOVEMBER 01, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-46-000, et al., dated JULY 12, 1993
<PAGE> 20
Pacific Gas Transmission Company
FERC Gas Tariff Original Sheet No. 59
First Revised Volume No. 1-A
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
4. MEASURING EQUIPMENT (Continued)
4.3 Correction and Adjustment: If at any time any of the measuring
equipment is registering inaccurately by an amount exceeding
two percent (2%) at a reading corresponding to the average
hourly rate of flow, the previous readings of such equipment
shall be corrected to zero error for any period definitely
known or agreed upon, or if not so known or agreed upon,
one-half (1/2) of the elapsed time since the last test. If the
measuring equipment is out-of-service, the volume of gas
delivered during such period shall be determined:
(a) By using the data recorded by any check measuring
equipment accurately registering; or
(b) If such check measuring equipment is not registering
accurately but the percentage of error is ascertainable
by a calibration test, by using the data recorded,
corrected to zero error; or
(c) If neither of the methods provided in (a) and (b) above
can be used, by estimating the quantity delivered, by
reference to deliveries under similar conditions during a
period when the equipment was registering accurately.
No correction shall be made in the recorded volumes of
gas delivered hereunder for measuring equipment
inaccuracies of two percent (2%) or less, and in no event
shall inaccuracies less than 25 Mcf be considered for
adjustment.
(Continued)
Issued by: P.G.Rosput, Senior Vice President
Issued on: AUGUST 02, 1993 Effective: NOVEMBER 01, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-46-000, et al., dated JULY 12, 1993
<PAGE> 21
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> 22
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> 23
Pacific Gas Transmission Company
FERC Gas Tariff First Revised Sheet No. 62
First Revised Volume No. 1-A Superseding
Original 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 San Francisco, California,
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: P.G.Rosput, Senior Vice President
Issued on: FEBRUARY 24, 1994 Effective: MARCH 27, 1994
<PAGE> 24
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> 25
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> 26
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> 27
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: NOVEBER 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> 28
Pacific Gas Transmission Company
FERC Gas Tariff First Revised Sheet No. 67
First Revised Volume No. 1-A Superseding
Original 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 Control Department
East 5105 3rd Avenue
P.O. Box 4389
Spokane, Washington 99212
Phone - 509-534-0657
Fax - 509-671-2225
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: P.G.Rosput, Senior Vice President
Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994
<PAGE> 29
Pacific Gas Transmission Company
FERC Gas Tariff First Revised Sheet No. 68
First Revised Volume No. 1-A Superseding
Original Sheet No. 68
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
18. OPERATING PROVISIONS (Continued)
18.1 Firm Service (Continued)
For capacity that becomes available other than the
circumstances identified in Paragraphs 28 and 33, requests for
firm capacity shall be accommodated in the following manner and
subject to the following conditions and limitations:
(a) In order to be eligible for firm capacity, a party
requesting service (requestor) must be deemed
credit-worthy per Paragraph 18.3 and submit a valid
request in accordance with the provisions herein.
(b) PGT will post on Pacific Trail, PGT's Electronic Bulletin
Board (EBB), available capacity. A requestor that submits
a valid request may submit a bid via the EBB for the
available capacity subsequent to PGT's posting of such
capacity on the EBB. The Bid Period will be 5 business
days, during which time other requestors with valid
requests may submit a bid. All bids not withdrawn prior
to the close of the Bidding Period shall be binding. At
the end of the Bidding Period, PGT will evaluate the bids
and determine the bid(s) having the greatest economic
value as determined in Paragraph 18.1(c) below.
(c) After the close of the Bidding Period, PGT may tender a
Service Agreement for execution to the requestor(s)
submitting the bid(s) having the greatest economic value
for the capacity available, subject to the provisions of
Paragraph 18.1(e). The criteria for determining which
requestor(s) has submitted the bid(s) with the greatest
economic value shall be the Net Present Value (NPV) of
the reservation charge as calculated at Paragraph 28 that
requestor(s) would pay at the rates requestor(s) has bid,
which shall not be less than the Minimum Rate nor greater
than the Maximum Rate, as stated on the currently
effective Statement of Rates and Charges governing such
service, over the term of service specified in the
request. If the economic values of separate bids are
equal, then service shall be offered to such requestors
on a pro-rata basis.
(Continued)
Issued by: P.G.Rosput, Senior Vice President
Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994
<PAGE> 30
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> 31
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> 32
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> 33
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> 34
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> 35
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> 36
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> 37
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> 38
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> 39
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> 40
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. Section
284.102. To enable PGT to verify that the requested transportation
service will qualify under 18 C.F.R. Section 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> 41
Pacific Gas Transmission Company
FERC Gas Tariff First Revised Sheet No. 79
First Revised Volume No. 1_A Superseding
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> 42
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> 43
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> 44
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> 45
Pacific Gas Transmission Company
FERC Gas Tariff First Revised Sheet No. 81B
First Revised Volume No. 1-A Superseding
Original 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.
(Continued)
Issued by: P.G.Rosput, Senior Vice President
Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994
<PAGE> 46
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> 47
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> 48
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> 49
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> 50
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> 51
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
assessed to PGT by the Federal Energy Regulatory Commission for
budgetary expenses pursuant to Section 154.38(d)(6) of the
Commission's regulations and Order No. 472 issued May 29,
1987. PGT shall recover this charge by means of an Annual
Charge Adjustment (ACA); a per unit rate equivalent to the
unit rate assessed against PGT by the Commission shall be
included in PGT's transportation rates. (During the period
that this ACA provision is in effect, PGT shall not recover in
a Natural Gas Act Section 4 rate case annual charges recorded
in FERC Account No. 928 assessed to PGT by the Commission
pursuant to Order No. 472.)
22.2 Filing Procedure: The notice period and proposed effective
date of filings pursuant to this paragraph shall be as
permitted under Section 4 of the Natural Gas Act; provided,
however, that any such filing shall not become effective
unless they become effective without suspension or refund
obligation.
22.3 ACA Unit Rate Adjustment: PGT's ACA unit rate shall be the
unit rate used by the Commission to determine the annual
charge assessment to PGT, and shall be reflected in the
Statement of Effective Rates and Charges of this FERC Gas
Tariff First Revised Volume No. 1-A.
22.4 Affected Rate Schedules: The ACA provision shall apply to all
rate schedules contained in PGT's FERC Gas Tariff First
Revised Volume No. 1-A.
23. SHARED OPERATING PERSONNEL AND FACILITIES
PGT and its marketing affiliate do not share any operating personnel.
PGT does not share any facilities with its marketing affiliate. To
the extent PG&E elects service under Rate Schedule USS-1, PGT
employees involved with the implementation of USS-1 service will
operate independently from PGT's pipeline operating employees.
(Continued)
Issued by: P.G.Rosput, Senior Vice President
Issued on: AUGUST 02, 1993 Effective: NOVEMBER 01, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-46-000, et al., dated JULY 12, 1993
<PAGE> 52
Pacific Gas Transmission Company
FERC Gas Tariff Original Sheet No. 86
First Revised Volume No. 1-A
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 Control, telephone (509) 534-0657. Written
complaints should be sent via registered or certified mail,
facsimile (FAX No. (509) 536-2735), or hand delivered to:
Pacific Gas Transmission Company
East 5105 3rd Avenue
P.O. Box 4389
Spokane, WA 99212
Attention: Gas Control Manager
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 Control
Department located in Spokane. 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: 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> 53
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
160 Spear Street, Suite 1919
San Francisco, CA 94105-1570
Telephone: (415) 973-6169
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
1-800-238-2781. 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 21 of these Transportation
General Terms and Conditions.
(Continued)
Issued by: P.G.Rosput, Senior Vice President
Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994
<PAGE> 54
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> 55
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> 56
Pacific Gas Transmission Company
FERC Gas Tariff Substitute Original Sheet No. 89
First Revised Volume No. 1-A Superseding
Original Sheet No. 89
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
28. CAPACITY RELEASE
28.1 Eligibility to Release
Any firm Shipper which contracts for firm
transportation service under Part 284 of the
Commission's regulations (Releasing Shipper) is
eligible to release all or part of its capacity
(Parcel) for use by another party (Replacement
Shipper). Any Replacement Shipper which has
previously contracted for a Parcel may also release
its capacity to another party as a secondary release
subject to the terms and conditions described herein.
Upon releasing a Parcel, consistent with the terms
and conditions described herein, all Releasing
Shippers shall remain ultimately liable for all
reservation charges billable for the originally
contracted service. The Releasing Shipper, whether a
primary or secondary capacity holder, must post the
capacity it seeks to release on PGT's Electronic
Bulletin Board (EBB) prior to the close of the
Posting Period defined herein.
A Releasing Shipper may release all 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 31, 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> 57
Pacific Gas Transmission Company
FERC Gas Tariff First Revised Sheet No. 90
First Revised Volume No. 1-A Superseding
Original 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 - one month 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 one calendar month . This type
of release is prearranged and does not require bidding. 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 30 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 one month 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: P.G.Rosput, Senior Vice President
Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994
<PAGE> 58
Pacific Gas Transmission Company
FERC Gas Tariff First Revised Sheet No. 91
First Revised Volume No. 1-A 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> 59
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, 1993
<PAGE> 60
Pacific Gas Transmission Company
FERC Gas Tariff Original Sheet No. 93
First Revised Volume No. 1-A
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: NVEMBER 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> 61
Pacific Gas Transmission Company
FERC Gas Tariff Substitute Original Sheet No. 94
First Revised Volume No. 1-A Superseding
Original Sheet No. 94
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
28. CAPACITY RELEASE (Continued)
28.4 Marketing of Capacity Fee
PGT may act as a facilitator between a Releasing
Shipper and a Replacement Shipper(s) that wishes to
contract for that Releasing Shipper's capacity. All
such Parcels must be posted on the EBB initially. A
posting of a Parcel facilitated by PGT will include
both the Parcel by the Releasing Shipper and the bid
by the Prearranged Shipper. A marketing of capacity
fee shall be negotiated between PGT and Releasing
Shipper in a nondiscriminatory manner. Such a fee
will apply when: a Releasing Shipper requests PGT to
market released capacity, PGT actively markets such
capacity beyond posting on the EBB, and such
marketing results in capacity being released to a
Replacement Shipper.
28.5 Posting of a Parcel
The posting of a Parcel constitutes an offer to
release the capacity provided a willing Replacement
Shipper submits a valid bid consistent with PGT's
Transportation General Terms and Conditions. The
posting must contain the information contained in
Paragraph 28.3. Any specific conditions posted by
the Releasing Shipper must be operationally feasible,
nondiscriminatory to other shippers, and in
conformance with PGT's tariffs. If the Parcel is
being released as a secondary release, then any
recall provisions included in the primary release
which may affect the re-release of this capacity must
be included in the terms and conditions of the
secondary release. Each Parcel will be reviewed by
PGT prior to posting on the EBB for bidding. The
receipt of a valid release will be acknowledged by
the issuance of a release confirmation to the
Releasing Shipper's EBB mailbox by PGT.
It is the Releasing Shipper's sole responsibility to
provide release and Prearranged Shipper bid
information in advance of the close of the Posting
Period.
(Continued)
Issued by: P.G.Rosput, Senior Vice President
Issued on: OCTOBER 13, 1993 Effective: NOVEMBER 01, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-46-000, et al., dated OCTOBER 01, 1993
<PAGE> 62
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> 63
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> 64
Pacific Gas Transmission Company
FERC Gas Tariff Original Sheet No. 97
First Revised Volume No. 1-A
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
28. CAPACITY RELEASE (Continued)
28.6 Bidding for a Parcel (Continued)
(a) Preliminary Qualification (Continued)
The execution of the FTS-1 service agreement
for capacity release is to be signed
"electronically" by the Replacement Shipper.
The Replacement Shipper shall execute the
FTS-1 service agreement for capacity release
(exhibits excluded) through the use of an
authorization code procedure on the EBB.
Upon notification by PGT of an award of a
Parcel, PGT shall complete Exhibit R with the
particulars of the awarded Parcel and
Replacement Shipper shall execute,
electronically, Exhibit R to the FTS-1
service agreement for capacity release.
A hard copy of the FTS-1 service agreement
for capacity release, including Exhibit R
(signed by hand by PGT and Replacement
Shipper), will follow subsequent to the
awarding of a Parcel.
A Replacement Shipper that subsequently
obtains additional Parcels is not required to
execute an additional FTS-1 service agreement
for capacity release; rather, for each such
additional Parcel obtained, an additional
Exhibit R (designated sequentially "Exhibit
R-2", "Exhibit R-3", etc.) will be executed
and amended to such Replacement Shipper's
FTS-1 service agreement for capacity release.
Once the Replacement Shipper has met PGT's
preliminary contractual and credit
requirements, PGT will amend the Replacement
Shipper's authorization to add access to the
bidding and releasing portions of PGT's
capacity release program on its EBB. This
authorization, in combination with the
Replacement Shipper's password, which will be
unique and known only by the Replacement
Shipper, will entitle the
(Continued)
Issued by: P.G.Rosput, Senior Vice President
Issued on: AUGUST 02, 1993 Effective: NOVEMBER 01, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-46-000, et al., dated JULY 12, 1993
<PAGE> 65
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> 66
Pacific Gas Transmission Company
FERC Gas Tariff Original Sheet No. 99
First Revised Volume No. 1-A
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
28. CAPACITY RELEASE (Continued)
28.6 Bidding for a Parcel (Continued)
(b) Submitting a Bid (Continued)
A valid bid to contract for a Parcel must
contain the following information:
(1) Replacement Shipper's legal name,
address, telephone and fax numbers and
the name and title of the individual
responsible for authorizing the bid.
(2) The identification of the Parcel bid on.
(3) Term of service requested. The term of
service must not exceed the term included
in the Parcel.
(4) Percentage of the applicable maximum
rate, as identified in the Parcel, that
Replacement Shipper is willing to pay. A
Replacement Shipper may not bid below the
minimum applicable charge or rate nor
above the maximum authorized charge or
rate for the Parcel.
(5) The quantity desired not to exceed the
quantity contained in the Parcel,
expressed on a MMBtu/d delivered basis
and greater than the minimum quantity
acceptable to Replacement Shipper.
(6) Under Options 1 or 2 acceptance or
rejection of all recall provisions and
special nondiscriminatory terms and
conditions of service associated with the
release. Rejection of any terms results
in an invalid bid.
(7) Whether or not Replacement Shipper is an
affiliate of the Releasing Shipper.
(8) A statement as to whether or not
Replacement Shipper is affiliated with
PGT.
(Continued)
Issued by: P.G.Rosput, Senior Vice President
Issued on: AUGUST 02, 1993 Effective: NOVEMBER 01, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-46-000, et al., dated JULY 12, 1993
<PAGE> 67
Pacific Gas Transmission Company
FERC Gas Tariff Original Sheet No. 100
First Revised Volume No. 1-A
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
28. CAPACITY RELEASE (Continued)
28.6 Bidding for a Parcel (Continued)
(b) Submitting a Bid (Continued)
(9) An affirmative statement that
Replacement Shipper agrees to be
bound by the terms and conditions of
Rate Schedule FTS-1 and PGT's
capacity release provisions in its
tariff.
(10) Whether the bid is a contingent bid
and the contingencies which must be
satisfied by the date specified by
the Releasing Shipper in its posting
of the Parcel.
(c) Confirmation of Bids
The receipt of a valid bid by PGT will be
acknowledged by the issuance of a bid
confirmation to the Replacement Shipper's EBB
mailbox by PGT. It is the Replacement
Shipper's sole responsibility to verify the
correctness of the submitted bid and to take
any corrective action necessary by
resubmitting a bid when notified of an
invalid or incomplete bid by PGT via the EBB.
This must be done before the close of the Bid
Period.
(d) Withdrawn or Revision of Bids
A previously submitted bid may be withdrawn
or revised and resubmitted at any time prior
to the close of the Bid Period with no
obligation on the Replacement Shipper's part.
Resubmitted bids must be equal to or greater
in value than the initial bids. Lower valued
bids will be invalid.
(Continued)
Issued by: P.G.Rosput, Senior Vice President
Issued on: AUGUST 02, 1993 Effective: NOVEMBER 01, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-46-000, et al., dated JULY 12, 1993
<PAGE> 68
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:
Present Value per unit =
n
(1 + i) -1
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> 69
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> 70
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> 71
Pacific Gas Transmission Company
FERC Gas Tariff Original Sheet No. 104
First Revised Volume No. 1-A
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
28. CAPACITY RELEASE (Continued)
28.7 Allocation of Parcels (Continued)
(d) Confirmation of Allocation
Upon each completion of an allocation, the
successful Replacement Shipper(s) will be
notified of the terms under which they have
contracted for the awarded Parcel. The
notification will be provided in the form of
a notice in the Replacement Shipper's EBB
mailbox. The notice will include an Exhibit
R to the Replacement Shipper's Rate Schedule
FTS-1 service agreement for capacity release
which specifies the pertinent terms of the
Replacement Shipper's bid as well as any
additional terms specified by the Releasing
Shipper. The Releasing Shipper will be
notified of the terms under which its Parcel
has been awarded. The notification will be
provided in the form of a notice in the
Releasing Shipper's EBB mailbox. The
notification will include an Exhibit C to the
Releasing Shipper's service agreement which
specifies the pertinent terms of the credit
to be applied to the Releasing Shipper as a
result of the awarding of Parcel to the
Replacement Shipper(s). In the case of
multiple Replacement Shippers and Parcels, an
Exhibit C to the Releasing Shippers' service
agreement will be generated for each Parcel
and Replacement Shipper. The Exhibit C's
shall be numbered sequentially as Exhibit
C-1, C-2, etc.
(e) Purging of Expired Bids
All unfulfilled bids, as well as any
unfulfilled portions of bids which receive a
partial award, will become ineffective as of
the completion of bid reconciliation and the
close of the Bid Period. Each unsuccessful
Replacement Shipper which has bid shall
receive a notice in its EBB mailbox
indicating the ineffectiveness of the bid.
(Continued)
Issued by: P.G.Rosput, Senior Vice President
Issued on: AUGUST 02, 1993 Effective: NOVEMBER 01, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-46-000, et al., dated JULY 12, 1993
<PAGE> 72
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> 73
Pacific Gas Transmission Company
FERC Gas Tariff First Revised Sheet No. 106
First Revised Volume No. 1-A Superseding
Original 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 one calendar month.
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 one
month 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: P.G.Rosput, Senior Vice President
Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994
<PAGE> 74
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> 75
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> 76
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, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-46-000, et al., dated JULY 12, 1993
<PAGE> 77
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> 78
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 TIMELINES
STANDARD RELEASE
(GREATER THAN OR EQUAL TO ONE DAY)
[GRAPH]
Issued by: P.G.Rosput, Senior Vice President
Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994
<PAGE> 79
Pacific Gas Transmission Company
FERC 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 RELEASE
(EQUAL TO OR LESS THAN ONE MONTH)
Issued by: P.G.Rosput, Senior Vice President
Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994
<PAGE> 80
Pacific Gas Transmission Company
FERC Gas Tariff First Revised Sheet No. 113
First Revised Volume No. 1-A Superseding
Original Sheet No. 113
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
28. CAPACITY RELEASE (Continued)
CAPACITY RELEASE TIMELINES
PRE-ARANGED DEAL A
(LESS THAN ONE CALENDAR MONTH)
Issued by: P.G.Rosput, Senior Vice President
Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994
<PAGE> 81
Pacific Gas Transmission Company
FERC Gas Tariff First Revised Sheet No. 114
First Revised Volume No. 1-A Superseding
Original 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 ONE MONTH AT HIGHEST VALUE BID)
Issued by: P.G.Rosput, Senior Vice President
Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994
<PAGE> 82
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)
[GRAPH]
Issued by: P.G.Rosput, Senior Vice President
Issued on: FEBRUARY 28, 1994 Effective: APRIL 01, 1994
<PAGE> 83
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> 84
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> 85
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> 86
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> 87
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> 88
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> 89
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, et al., dated NOVEMBER 12, 1993
<PAGE> 90
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> 91
Pacific Gas Transmission Company
FERC Gas Tariff Substitute Original Sheet No. 126
First Revised Volume No. 1-A Superseding
Original Sheet No. 126
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
30. GAS SUPPLY RESTRUCTURING TRANSITION COSTS (Continued)
30.5 Transition Cost Recovery Mechanism (Continued)
(e) Carrying Charges -- Carrying charges shall accrue
beginning on the effective date of PGT's filing to
recover GSR costs or the date PGT initiates payment
for GSR costs, whichever is later. Carrying charges
shall be calculated in accordance with Section 154.67
of the Commission's regulations.
30.6 Reconciliation
(a) At the conclusion of the Initial GSR Cost Collection
Period, PGT will determine its GSR Costs and the
actual amounts of GSR Transition Cost Surcharge
revenues.
(b) If PGT's collections hereunder shall equal or exceed
its GSR Costs, PGT shall file to terminate further
collections hereunder. The amount of any excess
collected shall be repaid to all Shippers affected
hereby in proportion to the principal amount of GSR
Transition Cost Surcharge payments they have provided
pursuant to this Paragraph 30. Within ninety (90)
days of the termination of collections pursuant to
this Paragraph 30, PGT will submit a report to the
Commission setting out a comparison of its GSR costs
and the amounts collected hereunder and any
repayments to be provided hereunder. Within thirty
(30) days of the Commission's approval of such
report, repayments, with applicable carrying charges,
shall be paid.
(c) If PGT's collections hereunder are less than its GSR
Costs, PGT shall be permitted to recover such
deficiency, including carrying charges, during the
Carryover GSR Cost Collection Period by filing with
the Commission GSR Transition Cost Surcharges within
ninety (90) days of the conclusion of the Initial GSR
Cost Collection Period. The GSR Transition Cost
Surcharge will be determined by dividing the
remaining GSR costs by the applicable quantities
underlying PGT's then-effective rates. The GSR
Transition Cost Surcharge shall be effective on the
first day of the month following Commission approval
of such filing.
(Continued)
Issued by: P.G.Rosput, Senior Vice President
Issued on: OCTOBER 13, 1993 Effective: NOVEMBER 01, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-46-000, et al., dated OCTOBER 01, 1993
<PAGE> 92
Pacific Gas Transmission Company
FERC Gas Tariff Original Sheet No. 127
First Revised Volume No. 1-A
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 or refunded to PGT, as the
case may be and which have not been reflected in
PGT's deferred account prior to application of this
Paragraph 31. The Prior Period Adjustment component
shall be limited to a nine-month period which shall
commence on the effective date of this tariff.
(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> 93
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> 94
Pacific Gas Transmission Company
FERC Gas Tariff Original Sheet No. 129
First Revised Volume No. 1-A
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
31. FORMER BUYER'S OBLIGATION FOR UNRECOVERED ACCOUNT NO. 191 AMOUNTS
(Continued)
31.5 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. The filing made
twelve (12) months after the effective date of this
Paragraph 31 shall constitute PGT's final flowthrough
of the Prior Period Adjustment component.
(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: 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> 95
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> 96
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> 97
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> 98
Pacific Gas Transmission Company
FERC Gas Tariff Substitute Original 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> 99
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> 100
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> 101
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> 102
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> 103
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> 104
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> 105
Pacific Gas Transmission Company
FERC Gas Tariff Original Sheet No. 140
First Revised Volume No. 1-A
GENERAL TERMS AND CONDITIONS
(Continued)
37. ADJUSTMENT MECHANISM FOR FUEL, LINE LOSS, AND OTHER UNACCOUNTED FOR GAS
PERCENTAGES
The effective fuel and line loss percentages under Rate Schedules FTS-1 and
ITS-1 shall be adjusted downward to reflect reductions and may be adjusted
upward to reflect increases in fuel usage and line loss in accordance with
this Section 37.
37.1 Computation of Effective Fuel and Line Loss Percentage
The effective fuel and line loss percentage shall be the sum of the
current fuel and line loss percentage and the fuel and line loss
surcharge percentage.
37.2 The Current Fuel and Line Loss Percentage
(a) For each month, the current fuel and line loss percentage
shall be determined in accordance with Section 37.2(c) hereof.
The current fuel and line loss shall be effective from the
first day of such month and shall remain in effect for the
month.
(b) The current fuel and line loss percentage to be applicable for
the month shall be posted on PGT's Electronic Bulletin Board
not less than seven (7) days prior to the beginning of the
month.
(c) The current fuel and line loss percentage for the month shall
be determined on the basis of (1) the estimated quantities of
gas to be delivered by PGT for the account of Shippers during
such month and (ii) the projected quantities of gas that shall
be required for fuel and line loss during such month, adjusted
for overrecoveries or underrecoveries of fuel and line loss
during such month preceding the month in which the current
fuel and line loss percentage is posted; provided, that the
percentage shall not exceed the maximum current fuel and line
loss percentage and shall not be less than the minimum current
fuel and line loss percentage set forth on the Statement of
Effective Rates and Charges.
(Continued)
Issued by: P.G.Rosput, Senior Vice President
Issued on: DECEMBER 22, 1993 Effective: JANUARY 22, 1994
<PAGE> 106
Pacific Gas Transmission Company
FERC Gas Tariff Substittute Original Sheet No. 141
First Revised Volume No. 1-A Superseding
Original Sheet No. 141
GENERAL TERMS AND CONDITIONS
(Continued)
37. ADJUSTMENT MECHANISM FOR FUEL, LINE LOSS AND OTHER UNACCOUNTED FOR GAS
PERCENTAGES (Continued)
37.2 The Current Fuel and Line Loss Percentage (Continued)
(d) At least thirty (30) days prior to July 1 and January 1, PGT
shall file with the Commission schedules supporting the
current fuel and line loss percentages applicable during the
six (6) months ending April 30 and October 31, respectively.
37.3 The Fuel and Line Loss Surcharge Percentage
(a) For each six (6) month period beginning July 1 and January 1,
the fuel and line loss surcharge percentage shall be
determined in accordance with Section 37.3(c) hereof. The
fuel and line loss surcharge percentage shall become effective
on July 1 and January 1 and shall remain in effect for the six
(6) month period ending December 31 and June 30, respectively.
(b) At least thirty (30) days prior to each July 1 and January 1,
PGT shall file with the Commission and post, as defined by
Section 154.16 of the Commission's regulations, the fuel and
line loss surcharge percentage, together with supporting
documentation.
(c) The fuel and line loss percentage shall be computed by (i)
determining PGT's actual fuel and line loss for the six (6)
month period ending April 30, if the effective date is July 1,
or October 31, if the effective date is January 1, (ii)
subtracting the actual quantities retained by PGT during such
six (6) month period, and (iii) dividing the result by the
estimated quantities of gas to be delivered by PGT for the
account of Shippers during the six month period beginning with
the effective date of the fuel and line loss surcharge
percentage. If the percentage so determined is 0.0001% or
less, the fuel and line loss surcharge percentage shall be
deemed to be zero.
Issued by: P.G.Rosput, Senior Vice President
Issued on: JANUARY 10, 1994 Effective: JANUARY 22, 1994
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. TM94-2-86-000, dated DECEMBER 30, 1993
<PAGE> 107
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> 108
Pacific Gas Transmission Company
FERC Gas Tariff First 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 sell gas as required to dispose of excess
linepack volumes to the extent necessary to manage system pressure and
maintain system integrity. The purchaser shall be responsible for the
transportation of gas from the point of sale.
Issued by: P.G.Rosput, Senior Vice President
Issued on: APRIL 08,1994 Effective: APRIL 22, 1994
<PAGE> 109
Graphic Appendix List to Exhibit 10.1 of the Form 10-K
DESCRIPTION
The substantive information conveyed by the Capacity Release Timeline Standard
Release (greater than or Equal to One Day) graph (appearing in Paragraph 28) is
described in the body of the electronic document in Paragraph 28.2 and Paragraph
28.8 as permitted by Item 304 of Regulation S-T.
The substantive information conveyed by the Capacity Release Timeline Rapid
Release (equal to or less than one month) graph (appearing in Paragraph 28) is
described in the body of the electronic document in Paragraph 28.2 and Paragraph
28.8 as permitted by Item 304 of Regulation S-T.
The substantive information conveyed by the Capacity Release Timeline
Pre-Arranged Deal A (less than one calendar month) graph (appearing in Paragraph
28) is described in the body of the electronic document in Paragraph 28.2 and
Paragraph 28.8 as permitted by Item 304 of Regulation S-T.
The substantive information conveyed by the Capacity Release Timeline
Pre-Arranged Deal B (equal to or greater than one month at highest value bid)
graph (appearing in Paragraph 28) is described in the body of the electronic
document in Paragraph 28.2 and Paragraph 28.8.
The substantive information conveyed the Capacity Release Timeline Pre-Arranged
Deal C (greater than or equal to one day) graph (appearing in Paragraph 28) is
described in the body of the electronic document in Paragraph 28.2 and Paragraph
28.8.
<PAGE> 1
EXHIBIT 10.2
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
Second Revised Volume No. 1-A Original Sheet No. 110
RATE SCHEDULE T-3
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 Shippers 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 Shippers 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.
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 2
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 111
Second Revised Volume No. 1-A
RATE SCHEDULE T-3
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 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.
(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,
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 3
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 112
Second Revised Volume No. 1-A
RATE SCHEDULE T-3
Firm Transportation Service
(Continued)
4. RATE (Continued)
4.1 Transportation Charges (Continued)
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 No. 23 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. 23 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. 23 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.
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.
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 4
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 113
Second Revised Volume No. 1-A
RATE SCHEDULE T-3
Firm Transportation Service
(Continued)
4. RATE (Continued)
4.2 Field Transportation Usage Charges: In addition to the
maximum "Mainline Transportation Usage Charges," Mainline
Shorthaul Usage Charge," or "Mainline Backhaul Usage Charge,"
the maximum "Field Transportation Usage Charges," unless
otherwise provided, applicable to deliveries either onshore or
offshore as set forth on Sheet No. 24 of this volume No. 1-A
Tariff, or superseding tariff, will be charged if the natural
gas received at the Receipt Point(s) requires field
transportation services. The quantity of natural gas to which
these charges shall apply is determined at the end of the
field transportation system, or the products extraction plant
inlet, when applicable.
4.3 Production Area Charges: In addition to the applicable
charges set forth in Sections 4.1 and 4.2 above, if the
natural gas received at the Receipt Point(s) receives any
production area services, Shipper shall pay El Paso an amount
determined as the maximum charge for "Dehydration,"
"Purification," and/or "Products Extraction," unless otherwise
provided, as set forth on Sheet No. 24 of this Volume No. 1-A
Tariff, or superseding tariff, multiplied by the quantity of
natural gas receiving such service(s). The quantity of
natural gas to which these charges shall apply is determined
at the end of the field transportation system, or the products
extraction plant inlet, when applicable. All volumes
receiving production area services in the Jal Plant Complex
(consisting of El Paso's Jal Plants, the Sid Richardson Plant,
the Warren Eunice Plant, the Warren Monument Plant and the
Texaco Eunice Plant) shall pay the applicable production area
charge specified herein for any services received,
irrespective of which plant provides such service, plus a pro
rata share of any charge, whether in cash or in-kind, assessed
by a third-party plant operator in the Jal Complex.
Such production area charges shall not apply if a Shipper
provides to El Paso, fifteen (15) days before initial
deliveries of natural gas under an executed Transportation
Service Agreement and thereafter fifteen (15) days before each
annual anniversary date of such initial deliveries, the
results from tests conducted within the previous thirty (30)
days by an independent testing firm demonstrating that the gas
is in conformance ("conformance gas") with El Paso's quality
specifications set forth in Section 5.1 of the Transportation
General Terms and-Conditions contained
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 5
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 114
Second Revised Volume No. 1-A
RATE SCHEDULE T-3
Firm Transportation Service
(Continued)
4. RATE (Continued)
4.3 Production Area Charges (Continued)
in this Volume No. 1-A Tariff. Shipper may have subsequent
tests conducted anytime after its gas fails the annual
conformance test. In the event the results of such test
proves conformance with the applicable quality Specifications
of El Paso's tariff and are provided to El Paso fifteen (15)
days prior to the first day of any calendar month, then
production area charges shall not apply effective the first
day of the following calendar month after El Paso receives
such notice. Additionally, if the purification and/or
products extraction charge(s) are applicable but such test
results demonstrate that the gas is being dehydrated to
conform to said Section 5.1, then no dehydration charge shall
apply. However, if El Paso, through independent field
inspections, verifies that the dehydrator is not operating,
then the Shipper either shall install and pay for real time
measurement and communication equipment enabling El Paso to
monitor continuously such source or, at Shipper's election,
shall pay the dehydration charge for all gas received by El
Paso from that source. In the event conformance gas is
processed at an extraction plant or other facility operated by
a third party, Shipper shall pay any charge assessed against
Shipper's conformance gas by such third party in accordance
with the provisions of this paragraph. If there is
insufficient capacity available at any production area service
facility for all gas scheduled for such facility, then
conformance and non-conformance gas shall be curtailed pro
rata on a non-discriminatory basis based on Shipper's
scheduled conformance and non-conformance gas to the total
scheduled gas.
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.
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
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 6
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 115
Second Revised Volume No. 1-A
RATE SCHEDULE T-3
Firm Transportation Service
(Continued)
4. RATE (Continued)
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. MINIMUM MONTHLY BILL
The Reservation Charge(s) for the month.
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 and fuel for any excess
quantity shall be equivalent to the maximum "Mainline Transportation
Charges" 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 T-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.
7. FUEL AND/OR SHRINKAGE
In addition to the payments made pursuant to Section 4 of this
Rate Schedule, Shipper shall provide fuel and be responsible for
shrinkage that occurs in transporting natural gas and rendering
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 7
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 116
Second Revised Volume No. 1-A
RATE SCHEDULE T-3
Firm Transportation Service
(Continued)
7. FUEL AND/OR SHRINKAGE (Continued)
other services provided pursuant to Shippers executed Transportation
Service Agreement as set forth below:
(a) Mainline Transportation - 5% of quantity received
Fuel for shorthaul and backhaul transportation may be
discounted by El Paso between O% and 5%; however, the
discounted percentage applied shall not be less than
actual.
(b) Field Transportation ) actual fuel/shrinkage as
(c) Dehydration ) calculated at the end of
(d) Purification ) the production month
(e) Products Extraction )
Prior to the beginning of each month, El Paso shall
post estimated fuel and shrinkage factors for
individual wellheads, gathering systems and plant
complexes based on historical values for use by
Shippers in the scheduling process. The actual fuel
and/or shrinkage allocable to each Shipper's
Transportation Service Agreement shall be determined
after the end of the production month and shall be
reflected in Shipper's accounting statements.
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, at al., shall be
entitled to receive firm transportation of the quantities
specified by its Transportation Service Agreement with El Paso
for a period, unless
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 8
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 117
Second Revised Volume No. 1-A
RATE SCHEDULE T-3
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>
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 9
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 118
Second Revised Volume No. 1-A
RATE SCHEDULE T-3
Firm Transportation Service
(Continued)
9. PROVISIONS APPLICABLE TO SHIPPERS THAT CONVERTED TO FIRM
TRANSPORTATION (Continued)
<TABLE>
<CAPTION>
SHIPPER BILLING DETERMINANTS
(dth)
<S> <C>
Arizona
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.
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 10
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 119
Second Revised Volume No. 1-A
RATE SCHEDULE T-3
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 T-1, El
Paso shall first deduct and retain revenues equal to
the sum of the mainline transportation usage rate
component of Rate Schedule T-3 and all rate
surcharges.
(b) El Paso shall retain all remaining interruptible
transportation revenues received under Rate Schedule
T-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
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 11
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 120
Second Revised Volume No. 1-A
RATE SCHEDULE T-3
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.
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 12
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet Nos. 121 through 124
Second Revised Volume No. 1-A
Reserved Sheets
Original Sheet Nos. 121 through 124 have been reserved.
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 13
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 200
Second Revised Volume 1-A
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>
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 14
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 201
Second Revised Volume No. 1-A
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
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 F) to sixty degrees
Fahrenheit (60 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 (l,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
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.
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 15
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 202
Second Revised Volume No. 1-A
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 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.
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 16
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 203
Second Revised Volume No. 1-A
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.
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 17
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 204
Second Revised Volume 1-A
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.
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 18
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 205
Second Revised Volume 1-A
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.
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 19
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 206
Second Revised Volume 1-A
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.
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 20
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 207
Second Revised Volume 1-A
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 (16)
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.
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 21
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 208
Second Revised Volume 1-A
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 prevent 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.
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 22
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 209
Second Revised Volume 1-A
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.
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 23
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 210
Second Revised Volume 1-A
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.
However, when the confirmation from the last well
causes the total confirmation to exceed the request,
El Paso shall alter the confirmation on the last well
as required for the total confirmation to equal
requested volumes in accordance with the prioritized
list of wells, if any, provided by each Shipper. El
Paso shall then 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.
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 24
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 211
Second Revised Volume 1-A
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.
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 25
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 212
Second Revised Volume 1-A
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 T-3 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:
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 26
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 213
Second Revised Volume 1-A
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 in 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 T-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.
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 27
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 214
Second Revised Volume 1-A
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. Priority to capacity on
the mainline system controls priority to the capacity upstream
of any mainline receipt point. Further, 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
FTS-S 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
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 28
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 215
Second Revised Volume 1-A
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.
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.
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 29
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 216
Second Revised Volume 1-A
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), from a
gathering system or other receipt point, 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 by wellhead, gathering system,
interconnect or residue plant, 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.
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 30
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 217
Second Revised Volume 1-A
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) Wellhead Nonperformance - El Paso shall
reduce to zero (0) a well's confirmed volume
on Day 1 when El Paso determines that such
well is not producing. The confirmation
shall be restored after El Paso determines
that the well is producing.
(ii) Gathering System Underperformance - If supply
underperformance exists, gathering system
monitoring shall be performed by El Paso on a
daily basis utilizing the most current data
available. El Paso shall compare the most
recent total actual production to Operators'
confirmed volumes for each gathering system.
When supply in expected to be less than
Operator confirmations and the shortfall in
receipts threatens the integrity of El Paso's
system, El Paso shall notify Operators
promptly and attempt to attain balancing in
the affected gathering system. After being
notified by El Paso, Operators may
voluntarily reduce confirmed volumes to the
actual supply level. If Operators volunteer
collectively to reduce confirmations to the
actual supply level, thereby eliminating the
supply underperformance, no further action
will be required by El Paso. However, if
Operators collectively fail to eliminate the
supply underperformance, then performance
factors shall be used by El Paso to adjust
the otherwise confirmed volumes as set forth
below.
(1) Calculation of Performance Factors -
El Paso shall calculate performance
factors applicable to each Operator
in each gathering system based on a
history of actual performance versus
final scheduled volumes. When there
is no history on which to calculate
an Operator's performance factor in
a particular gathering system, such
Operator shall be included in the
provisions contained
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 31
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 218
Second Revised Volume 1-A
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)
in this Section 4.3(c)(ii) with a
factor that does not indicate
underperformance, until such time as
data become available. El Paso
shall use the three most current
available months of data. The
absolute value of the difference
between final scheduled volumes and
actual received volumes for such
three (3) month period shall be
divided by each Operator's final
scheduled volumes, as adjusted for
any past system change data
available, to arrive at that
Operator's gross performance factor.
El Paso shall reduce each Operator's
performance factor by 2 percentage
points.
(2) Application of Performance Factors -
The following procedure shall be
used by El Paso to calculate an
Operator's expected underperformance
and allocate its share of supply
shortfall for the targeted gathering
system. El Paso shall apply the
adjusted performance factor against
an Operator's confirmed volumes to
estimate the Operator's expected
volume underperformance. The
Operator's expected volume
underperformance shall be compared
with the sum of all Operators
expected volume underperformance to
determine each Operator's
proportionate share (percentage) of
the total expected volume
underperformance. Each Operators
proportionate share shall be applied
against the total supply shortfall
for the gathering system to
determine the adjustment to each
Operator's confirmed volumes. El
Paso shall communicate all adjusted
confirmed volumes
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 32
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 219
Second Revised Volume 1-A
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)
that have been scheduled to the
appropriate parties in accordance
with Section 4.1(a) of this FERC Gas
Tariff. El Paso shall make
available electronically to each
Operator its applicable performance
factor within each gathering system
prior to each month.
(iii) Interconnection or Residue Plant
Underperformance Receipts from
interconnecting pipelines and third party
plants 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
and plant Operators and request Operators to
increase deliveries or reduce confirmed
volumes prospectively.
In the event interconnect or third party
plant Operators fail 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.
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 33
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 220
Second Revised Volume 1-A
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.
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 34
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
Original Sheet No. 221
Second Revised Volume 1-A
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 it
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
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 35
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 222
Second Revised Volume 1-A
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.
<TABLE>
<CAPTION>
NON-CONFORMING PLANTS
GRANDFATHERED
LOCATION METER SPECIFICATIONS HISTORICAL
CODE CO2 MOL % TOTAL DILUENTS VOLUME
MOL % (MCF/D)
<S> <C> <C> <C> <C>
Amoco Slaughter Plant 77-039 - 11.89 6,915
(IAMSLAUG)
Barnhart Plant (J.L. Davis) 77-002 - 3.55 6,149
(IBARNHRT)
Big Lake Texon Plant 77-055 - 9.67 2,362
(Damson Oil Corp.)
(ITEXON)
Chevron Puckett Plant 14-261 3.55 4.09 37,390
(IPUCKETT)
Conoco Ramsey Plant 77-095 - 6.38 4,579
(IRAMSEY)
</TABLE>
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 36
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 223
Second Revised Volume 1-A
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
5. QUALITY (Continued)
<TABLE>
<CAPTION>
5.2 (Continued)
NON-CONFORMING PLANTS (continued)
GRANDFATHERED
SPECIFICATIONS
LOCATION METER TOTAL DILUENTS HISTORICAL
CODE CO2 MOL % MOL % VOLUME
(MCF/D)
<S> <C> <C> <C> <C>
Exxon Snyder Plant 77-009 - 7.42 696
(Oryx Energy)
(IEXSNYDR)
Jal Complex 01-814 - 4.31 28,518
(IJALCPLX)
Jameson Plant (Oryx Energy) 77-078 - 7.02 2,823
(ISUNJAME)
Meridian Benedum Plant 02-304 - 3.18 75,585
(MOHI)(IHYBENDM)
Midkiff Plant 01-079 - 4.95 39,371
(IMIDKIFF)
Midway Lane Plant 03-933 - 4.45 4,617
(Apache Gas Corporation)
(IMIDWAY)
Permian Corp. CPD #2 14-082 - 6.03 6,620
(IPERTOD2)
Phillips Goldsmith Plant 02-381 - 5.23 62,267
(IPHGOLDS)
Phillips Lee Plant 77-025 - 7.34 27,484
(IPHLEE)
Phillips Eunice Plant 77-287 - 5.15 57,672
(IPHEUNIC)
Phillips Fullerton Plant 77-289 - 6.18 28,200
(IPHFULTN)
Phillips Spraberry Plant 77-248 - 4.64 11,277
(IPHSPBRY)
San Juan River Plant 01-125 - 4.35 32,827
(ISJRVPLT)
Shell TXL Plant (ISHTXL) 77-029 - 6.17 12,054
Shell Wasson Plant 01-106 - 5.98 8,682
(ISHWASON)
Terrell Plant 01-596 2.89 4.53 102,708
(ITERRELL)
</TABLE>
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 37
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 224
Second Revised Volume 1-A
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
5. QUALITY (Continued)
5.2 (Continued)
<TABLE>
<CAPTION>
NON-CONFORMING PLANTS (continued)
GRANDFATHERED
SPECIFICATIONS
LOCATION METER TOTAL DILUENTS HISTORICAL
CODE CO2 MOL % MOL % VOLUME
(MCF/D)
<S> <C> <C> <C> <C>
Texaco Fuller 77-036 - 7.66 661
(ITEXFULR)
Texaco Vealmoor Plant 77-028 - 6.32 10,204
(IVEALMOR)
Tipperary Denton Plant 77-001 - 5.02 2,554
(J.L. Davis)
(IDENTON)
Union of California 77-027 - 6.42 2,056
Dollarhide Plant
(IUTDOLHD)
Union Texas Perkins Plant 77-068 - 10.19 9,178
(IUTPERKDI)
Val Verde 14-136 2.13 - 195,985
(IMOITRKA)
Warren Monument 77-045 - 4.04 31,576
(IWARMONU)
Warren Saunders Plant 77-046 - 5.75 12,421
(IWARSAUD)
</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:
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 38
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 225
Second Revised Volume 1-A
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
5. QUALITY (Continued)
5.3 (Continued)
<TABLE>
<CAPTION>
NON-CONFORMING INTERCONNECTS TOTAL
LOCATION METER DILUENTS HISTORICAL
CODE CO2 MOL % MOL % VOLUME
(MCF/D)
<S> <C> <C> <C> <C>
Big Blue Receipt Point 14-091 - 9.50 11,900
(Colorado Interstate)
(IBIG8IFUE)
Howe Ranch Discharge 02-721 4.12 5.20 3,480
(Meridian)
Northern Natural Plains 40-019 - 4.22 111,072
(INN30PLA)
Plains Compressor 40-043 - 4.50 8,464
(Westar-Felmac)
(IW40-043)
</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 basin 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.
<TABLE>
<CAPTION>
Grandfathered Non-conforming Sulfur Specifications
(grains per 100 standard cubic feet)
LOCATION TOTAL HYDROGEN MERCAPTAN ORGANIC
SULFUR SULFIDE SULFUR SULFUR
<S> <C> <C> <C> <C>
Terrell Plant - 0.45 - -
Puckett Plant - 0.45 - -
</TABLE>
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 39
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 226
Second Revised Volume 1-A
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 or
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.
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 40
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 227
Second Revised Volume 1-A
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 Gas delivered to El Paso at Receipt Point(s) which receives
any Production Area services shall conform to those
specifications established herein.
5.7 The quality specifications for each gathering system connected
to El Paso's mainline system shall be no more stringent than
those specifications set forth in Section 5.1. All natural gas
received at a gathering system Receipt Point shall conform to
the specifications set forth in the table below:
(Gathering System Specifications shall be waived
by El Paso on a non-discriminatory basis)
(THIS SPACE INTENTIONALLY LEFT BLANK)
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 41
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 228
Second Revised Volume 1-A
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
5. QUALITY (Continued)
<TABLE>
<CAPTION>
Total Sulfur
Water Hydro- H2S Mercaptan Sulfur Total
Vapor carbons GR/100 Organic Sulfur 3/ CO2 Diluents Oxygen
Location #/MMCF Dew Point Scf GR/100 Scf MOL # MOL # #
<S> <C> <C> <C> <C> <C> <C> <C>
San Juan Basin Sweet Gas
(GSANJUAN) 25 1/ 0.25 5/.75/1.25 2 3 .2
La Jara
(ILAJARA) 25 1/ 0.25 5/.75/1.25 2 3 .2
Tapacito Field
(ITAPACIT) 25 1/ 0.25 5/.75/1.25 2 3 .2
Kutz
(Exchange Point No. 13) 25 1/ 0.25 5/.75/1.25 2 3 .2
(IEXCPT13)
Kutz
(Exchange Point No. 18) 25 1/ 0.25 5/.75/1.25 2 3 .2
(IEXCPT18)
Gas Company of New Mexico
(Exchange Point No. 47) 25 1/ 0.25 5/.75/1.25 2 3 .2
(IEXCPT47)
San Juan Ignacio Dry
(GIGNACIO) 25 20 degrees F 0.25 5/.75/1.25 2 3 .2
Bondad (West Gas)
(IBONDAD) 25 20 degrees F 0.25 5/.75/1.25 2 3 .2
</TABLE>
<TABLE>
<CAPTION>
Dust, Minimum
Gums & Heating
Solid Value
Location Matter Btu Temperature
<S> <C> <C> <C>
San Juan Basin Sweet Gas Max 120 degrees F
(GSANJUAN) Free of 967 Min 50 degrees F
La Jara Max 120 degrees F
(ILAJARA) Free of 967 Min 50 degrees F
Tapacito Field Max 120 degrees F
(ITAPACIT) Free of 967 Min 50 degrees F
Kutz Max 120 degrees F
(Exchange Point No. 13) Free of 967 Min 50 degrees F
(IEXCPT13)
Kutz Max 120 degrees F
(Exchange Point No. 18) Free of 967 Min 50 degrees F
(IEXCPT18)
Gas Company of New Mexico Max 120 degrees F
(Exchange Point No. 47) Free of 967 Min 50 degrees F
(IEXCPT47)
San Juan Ignacio Dry Max 120 degrees F
(GIGNACIO) Free of 967 Min 50 degrees F
Bondad (West Gas) Max 120 degrees F
(IBONDAD) Free of 967 Min 50 degrees F
</TABLE>
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 42
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 229
Second Revised Volume 1-A
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
5. QUALITY (Continued)
<TABLE>
<CAPTION>
Total Sulfur
Water Hydro- H2S Mercaptan Sulfur Total
Vapor carbons GR/100 Organic Sulfur 3/ CO2 Diluents Oxygen
Location #/MMCF Dew Point Scf GR/100 Scf MOL # MOL # #
<S> <C> <C> <C> <C> <C> <C> <C>
WestGas
(IWESTGAS) 25 20 degrees F 0.25 5/.75/1.25 2 3 .2
Lockridge
(GLOCKRID) 20 20 degrees F 2/ 4/ 5/ 3 6/ .2
Worsham
(GWORSHAM) 20 20 degrees F 2/ 4/ 5/ 3 6/ .2
Waha
(GWAHA) 20 20 degrees F 2/ 4/ 5/ 3 6/ .2
West Waha
(GWSTWAHA) 20 20 degrees F 2/ 4/ 5/ 3 6/ .2
Gomez
(GGOMEZ) 20 20 degrees F 2/ 4/ 5/ 3 6/ .2
Toro
(GTORO) 20 20 degrees F 2/ 4/ 5/ 3 6/ .2
Rojo Caballos
(GROJOCAB) 20 20 degrees F 2/ 4/ 5/ 3 6/ .2
Carlsbad
(GCARLSBAD) 7 20 degrees F 0.25 5/.75/1.25 2 3 .2
Beckham County
(GBECKHAM) 7 20 degrees F 0.25 5/.75/1.25 2 3 .2
</TABLE>
<TABLE>
<CAPTION>
Dust, Minimum
Gums & Heating
Solid Value
Location Matter Btu Temperature
<S> <C> <C> <C>
WestGas Max 120 degrees F
(IWESTGAS) Free of 967 Min 50 degrees F
Lockridge Max 120 degrees F
(GLOCKRID) Free of 967 Min 50 degrees F
Worsham Max 120 degrees F
(GWORSHAM) Free of 967 Min 50 degrees F
Waha Max 120 degrees F
(GWAHA) Free of 967 Min 50 degrees F
West Waha Max 120 degrees F
(GWSTWAHA) Free of 967 Min 50 degrees F
Gomez Max 120 degrees F
(GGOMEZ) Free of 967 Min 50 degrees F
Toro Max 120 degrees F
(GTORO) Free of 967 Min 50 degrees F
Rojo Caballos Max 120 degrees F
(GROJOCAB) Free of 967 Min 50 degrees F
Carlsbad Max 120 degrees F
(GCARLSBAD) Free of 967 Min 50 degrees F
Beckham County Max 120 degrees F
(GBECKHAM) Free of 967 Min 50 degrees F
</TABLE>
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 43
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 230
Second Revised Volume 1-A
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
5. QUALITY (Continued)
<TABLE>
<CAPTION>
Total Sulfur
Water Hydro- H2S Mercaptan Sulfur Total
Vapor carbons GR/100 Organic Sulfur 3/ CO2 Diluents Oxygen
Location #/MMCF Dew Point Scf GR/100 Scf MOL # MOL # #
<S> <C> <C> <C> <C> <C> <C> <C>
San Juan Mainline
(GSJMNLIN) 7 20 degrees F 0.25 5/.75/1.25 2 3 .2
26" Eunice to Pecos
(GEU-PECS) 7 20 degrees F 0.25 5/.75/1.25 2 3 .2
Plains to San Juan
(GSJXOVER) 7 20 degrees F 0.25 5/.75/1.25 2 3 .2
Terrell to Puckett
(GTER-PUK) 7 20 degrees F 0.25 5/.75/1.25 2 3 .2
20" Goldsmith to Plains
(G20GO-PL) 7 20 degrees F 0.25 5/.75/1.25 2 3 .2
16" C Line
(G16C-LIN) 7 20 degrees F 0.25 5/.75/1.25 2 3 .2
McKay Creek
(GMCKAYCR) 7 20 degrees F 0.25 5/.75/1.25 2 3 .2
20" Sonora to Benedum
(GSON-BEN) 7 20 degrees F 0.25 5/.75/1.25 2 3 .2
Hobart (Phillips)
(GHOBART) 7 20 degrees F 0.25 5/.75/1.25 2 3 .2
Hobart - Zybach
(GHOB-ZYB) 7 20 degrees F 0.25 5/.75/1.25 2 3 .2
</TABLE>
<TABLE>
<CAPTION>
Dust, Minimum
Gums & Heating
Solid Value
Location Matter Btu Temperature
<S> <C> <C> <C>
San Juan Mainline Max 120 degrees F
(GSJMNLIN) Free of 967 Min 50 degrees F
26" Eunice to Pecos Max 120 degrees F
(GEU-PECS) Free of 967 Min 50 degrees F
Plains to San Juan Max 120 degrees F
(GSJXOVER) Free of 967 Min 50 degrees F
Terrell to Puckett Max 120 degrees F
(GTER-PUK) Free of 967 Min 50 degrees F
20" Goldsmith to Plains Max 120 degrees F
(G20GO-PL) Free of 967 Min 50 degrees F
16" C Line Max 120 degrees F
(G16C-LIN) Free of 967 Min 50 degrees F
McKay Creek Max 120 degrees F
(GMCKAYCR) Free of 967 Min 50 degrees F
20" Sonora to Benedum Max 120 degrees F
(GSON-BEN) Free of 967 Min 50 degrees F
Hobart (Phillips) Max 120 degrees F
(GHOBART) Free of 967 Min 50 degrees F
Hobart - Zybach Max 120 degrees F
(GHOB-ZYB) Free of 967 Min 50 degrees F
</TABLE>
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 44
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 231
Second Revised Volume 1-A
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
5. QUALITY (Continued)
<TABLE>
<CAPTION>
Total Sulfur
Water Hydro- H2S Mercaptan Sulfur Total
Vapor carbons GR/100 Organic Sulfur 3/ CO2 Diluents Oxygen
Location #/MMCF Dew Point Scf GR/100 Scf MOL # MOL # #
<S> <C> <C> <C> <C> <C> <C> <C>
ANR No. 1
(IANR#1AN) 7 20 degrees F 0.25 5/.75/1.25 2 3 .2
ANR No. 2
(IANR#2AN) 7 20 degrees F 0.25 5/.75/1.25 2 3 .2
BP Gas Transmission
(Roger Mills County) 7 20 degrees F 0.25 5/.75/1.25 2 3 .2
(ICHEY-CP)
NGPL Beckham #3
(INGPLB#3) 7 20 degrees F 0.25 5/.75/1.25 2 3 .2
</TABLE>
<TABLE>
<CAPTION>
Dust, Minimum
Gums & Heating
Solid Value
Location Matter Btu Temperature
<S> <C> <C> <C>
ANR No. 1 Max 120 degrees F
(IANR#1AN) Free of 967 Min 50 degrees F
ANR No. 2 Max 120 degrees F
(IANR#2AN) Free of 967 Min 50 degrees F
BP Gas Transmission Max 120 degrees F
(Roger Mills County) Free of 967 Min 50 degrees F
(ICHEY-CP)
NGPL Beckham #3 Max 120 degrees F
(INGPLB#3) Free of 967 Min 50 degrees F
</TABLE>
___________________________
1/ Free of hydrocarbons in liquid form.
2/ El Paso will accept natural gas with hydrogen sulfide at levels above
0.25 grains per 100 Scf in these gathering systems. The hydrogen
sulfide level will be used as a basis to curtail gas in these
gathering systems only if the treating plant facilities are limited as
a result of, but not limited to, the following reasons; treating
capacity limitation, sulfur emissions limitations, high residue gas
hydrogen sulfide concentration.
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 45
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 232
Second Revised Volume 1-A
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
5. QUALITY (Continued)
___________________________
3/ El Paso shall accept a total sulfur, mercaptan sulfur, and organic
sulfur as specified in Sections 5.1(c), 5.1(c)(ii) and 5.1(c)(iii)
above until such time that El Paso cannot blend the gas to conform to
El Paso's delivery point specifications set forth in Section 5.10. In
the event such situation occurs, El Paso will refuse acceptance of gas
received by curtailing quantities commencing with the quantities of
gas containing the highest total sulfur, mercaptan sulfur or organic
sulfur down to a level that would permit El Paso to deliver gas at
specifications required at the delivery points.
4/ El Paso will accept natural gas with total sulfur at levels above 5
grains per 100 Scf, mercaptans at levels above 0.75 grains per 100 Scf
and organic sulfur at levels above 1.25 grains per 100 Scf only to the
extent that the processing plant operations is not adversely impacted
by these sulfur compounds and the residue gas from these processing
plants meets the sulfur specifications listed under Section 5.1(c)
above.
5/ El Paso will accept natural gas with carbon dioxide at levels above 2%
in these gathering systems. The carbon dioxide level will be used as
a basis to curtail gas in these gathering systems only if the treating
plant facilities are limited as a result of, but not limited to, the
following reasons; treating capacity limitation, carbon dioxide
emissions limitations, high residue gas carbon dioxide concentration.
6/ El Paso will accept natural gas in these gathering systems that
exceeds the total diluent percentage listed in the table only if the
gas at the tailgate of the treating plant where the gas is processed
does not exceed the total diluent percentage listed in the table.
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 46
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 233
Second Revised Volume 1-A
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
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:
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 47
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 234
Second Revised Volume 1-A
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.
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 48
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 235
Second Revised Volume 1-A
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.
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 49
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 236
Second Revised Volume 1-A
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 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 an may exist in El
Paso's 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 chromatography.
(b) To determine whether specific points on El Paso's system can
operate below the fifty degree Fahrenheit (5O 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.
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 50
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 237
Second Revised Volume 1-A
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.
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 51
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 238
Second Revised Volume 1-A
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;
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 52
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 239
Second Revised Volume 1-A
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
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 53
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 240
Second Revised Volume 1-A
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 6.1 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.
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 54
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 241
Second Revised Volume 1-A
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.
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 55
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 242
Second Revised Volume 1-A
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, prevent 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.
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 56
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 243
Second Revised Volume 1-A
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 in
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.
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 57
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 244
Second Revised Volume 1-A
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.
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 58
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 245
Second Revised Volume 1-A
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.
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 59
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 246
Second Revised Volume 1-A
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.
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 60
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 247
Second Revised Volume 1-A
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.
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 61
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 248
Second Revised Volume 1-A
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.
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 62
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 249
Second Revised Volume 1-A
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).
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 63
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 250
Second Revised Volume 1-A
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.
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 64
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 251
Second Revised Volume 1-A
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.
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 65
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 252
Second Revised Volume 1-A
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.
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 66
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 253
Second Revised Volume 1-A
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.
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 67
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Sheet No. 254
Second Revised Volume No. 1-A
Superseding
Original Sheet No. 254
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, 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
Issued by: Patricia A. Shelton, Vice President
Issued on: NOVEMBER 30, 1994 Effective: January 01, 1995
<PAGE> 68
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 255
Second Revised Volume 1-A
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
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 69
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff First Revised Sheet No. 256
Second Revised Volume No. 1-A Superseding
Original Sheet No. 256
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
Meridian Oil Trading Inc. 97J5
Mission Energy Fuel Company 97YX
Mobil Natural Gas Inc. 97YK
Pacific Gas and Electric Company 97VU
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
Southern Union Gas Company 97VX
Sunrise Energy Company 97YL
Texaco, Inc. 97YF
U.S. Borax and Chemical Corporation 97YH
West Texas Gas, Inc. 982V
</TABLE>
Issued by: Patricia A. Shelton, Vice President
Issued on: NOVEMBER 30, 1994 Effective: JANUARY 01, 1995
<PAGE> 70
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff First Revised Sheet No. 257
Second Revised Volume No. 1-A Superseding
Original Sheet No. 257
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 9826
and Power District
Southdown, Inc. (SW Portland) 982Q
Southwest Gas Corporation 97ZL
Southwest Gas Corporation 97ZK
</TABLE>
Issued by: Patricia A. Shelton, Vice President
Issued on: NOVEMBER 30, 1994 Effective: JANUARY 01, 1995
<PAGE> 71
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff First Revised Sheet No. 258
Second Revised Volume No. 1-A Superseding
Original Sheet No. 258
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 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 T-1.
Issued by: A. W. Clark, Vice President
Issued on: AUGUST 30, 1994 Effective: OCTOBER 01, 1994
<PAGE> 72
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff First Revised Sheet No. 259
Second Revised Volume No. 1-A Superseding
Original Sheet No. 259
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 Shippers 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
Issued by: A. W. Clark, Vice President
Issued on: AUGUST 30, 1994 Effective: OCTOBER 01, 1994
<PAGE> 73
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 260
Second Revised Volume 1-A
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
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 74
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 261
Second Revised Volume 1-A
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)
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 75
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 262
Second Revised Volume 1-A
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
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 76
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 263
Second Revised Volume 1-A
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 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
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 77
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 264
Second Revised Volume 1-A
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 actual 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.
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 78
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 265
Second Revised Volume 1-A
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 (O) 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 sample 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'" Mainline System at West
Texas, Permian or Waha from the
publications identified in Section
19.12(e)(ii); and
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 79
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 266
Second Revised Volume 1-A
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.
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 80
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 267
Second Revised Volume 1-A
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.
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 81
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 268
Second Revised Volume 1-A
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
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 82
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 269
Second Revised Volume 1-A
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 gathering and pooling agreement imbalances
is negotiable as long as the imbalances were generated in
the same basin.
(ii) Netting between upstream interconnects and pooling
agreements is negotiable if the pooling agreement has that
interconnect point as a receipt point.
(iii) Netting between downstream interconnect and mainline
agreement imbalances is negotiable if the agreement has the
interconnect point as a delivery point.
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 83
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 270
Second Revised Volume 1-A
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
19. OPERATING PROVISIONS FOR INTERRUPTIBLE TRANSPORTATION SERVICE Continued)
19.12 Resolution of Imbalances (Continued)
(iv) Netting between Unauthorized Gas and mainline or
pooling/gathering agreement imbalances is negotiable if
both the Unauthorized Gas and imbalance were generated
in the same basin.
(v) Netting between mainline agreement imbalances (for
similar transportation service) is negotiable.
(vi) Netting between gathering/pooling and mainline
agreements is negotiable if the gathering/pooling basin
is a receipt point on the mainline agreement.
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
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 84
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 271
Second Revised Volume 1-A
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.
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 85
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff First Revised Sheet No. 272
Second Revised Volume No. 1-A Superseding
Original Sheet No. 272
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.
Issued by: A. W. Clark, Vice President
Issued on: AUGUST 30, 1994 Effective: OCTOBER 01, 1994
<PAGE> 86
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 273
Second Revised Volume 1-A
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 five 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.
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 87
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 274
Second Revised Volume 1-A
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 T-3 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
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 88
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 275
Second Revised Volume 1-A
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.
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 89
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 276
Second Revised Volume 1-A
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
imbalances) 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
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 90
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 277
Second Revised Volume 1-A
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
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 91
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 278
Second Revised Volume 1-A
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 provision (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
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 92
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 279
Second Revised Volume 1-A
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 (O) 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
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 93
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 280
Second Revised Volume 1-A
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 pulications
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
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 94
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 281
Second Revised Volume 1-A
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 Surrey), 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;
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 95
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 282
Second Revised Volume 1-A
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 Unbalance
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 Prices;
(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;
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 96
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 283
Second Revised Volume 1-A
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 if 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
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 97
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 284
Second Revised Volume 1-A
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
20. OPERATING PROVISIONS FOR FIRS 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 gathering/pooling and
mainline agreements is negotiable if the
gathering/pooling basin is a receipt point on
the mainline agreement.
(iv) Netting between Unauthorized Gas and mainline
or pooling/gathering 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
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 98
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 285
Second Revised Volume 1-A
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.
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 99
EL PASO NATURAL GAS COMPANY
ERC Gas Tariff Original Sheet No. 286
Second Revised Volume 1-A
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.
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 100
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 287
Second Revised Volume 1-A
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 T-3 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 T-3 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
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 101
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 288
Second Revised Volume 1-A
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
T-3 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 Shippers
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.
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 102
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 289
Second Revised Volume 1-A
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
terms of the contract, whichever shall first occur.
(b) El Paso sboard 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 electroniSuch notice shall be binding
open season. once received by El Paso and
shall not be revocable by such Shipper.
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 103
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 290
Second Revised Volume 1-A
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) Shippers 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.
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 104
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 291
Second Revised Volume 1-A
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, and 25, and
Sheet Nos. 1-D.2 and 1-D.3.
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.
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 105
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 292
Second Revised Volume 1-A
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
22. TARE-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.
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 106
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff First Revised Sheet No. 293
Second Revised Volume No. 1-A Superseding
Original Sheet No. 293
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,
Issued by: A. W. Clark, Vice President
Issued on: August 30, 1994 Effective: October 01, 1994
<PAGE> 107
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff First Revised Sheet No. 294
Second Revised Volume No. 1-A Superseding
Original Sheet No. 294
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.
Issued by: A. W. Clark, Vice President
Issued on: August 30, 1994 Effective: October 01, 1994
<PAGE> 108
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff First Revised Sheet No. 295
Second Revised Volume No. 1-A Superseding
Original Sheet No. 295
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.
Issued by: A. W. Clark, Vice President
Issued on: August 30, 1994 Effective: October 01, 1994
<PAGE> 109
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff First Revised Sheet No. 296
Second Revised Volume No. 1-A Superseding
Original Sheet No. 296
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___________________________________________________________________
Issued by: A. W. Clark, Vice President
Issued on: August 30, 1994 Effective: October 01, 1994
<PAGE> 110
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff First Revised Sheet No. 297
Second Revised Volume No. 1-A Superseding
Original Sheet No. 297
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
23. COMPLIANCE PLAN FOR TRANSPORTATION SERVICES AND AFFILIATE TRANSACTIONS
(Continued)
6. Shipper is (check one of the following):
<TABLE>
<S> <C>
a. ____ Interstate Pipeline e. ____ End-User
b. ____ Intrastate Pipeline* f. ____ Producer
c. ____ Local Distribution Company* g. ____ Marketer
d. ____ Hinshaw Pipeline* h. ____ Other (Specify)_______
</TABLE>
*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 __________ MMBtu/d.
Total contract quantity requested over primary term of agreement
(please specify both):
__________ Mcf/d MMBtu/d __________ MMBtu/d.
Issued by: A. W. Clark, Vice President
Issued on: August 30, 1994 Effective: October 01, 1994
<PAGE> 111
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff First Revised Sheet No. 298
Second Revised Volume No. 1-A Superseding
Original Sheet No. 298
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:______________________________________________________________
Issued by: A. W. Clark, Vice President
Issued on: August 30, 1994 Effective: October 01, 1994
<PAGE> 112
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff First Revised Sheet No. 299
Second Revised Volume No. 1-A Superseding
Original Sheet No. 299
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.
Issued by: A. W. Clark, Vice President
Issued on: August 30, 1994 Effective: October 01, 1994
<PAGE> 113
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff First Revised Sheet No. 300
Second Revised Volume No. 1-A Superseding
Original Sheet No. 300
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 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
Issued by: A. W. Clark, Vice President
Issued on: August 30, 1994 Effective: October 01, 1994
<PAGE> 114
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff First Revised Sheet No. 301
Second Revised Volume No. 1-A Superseding
Original Sheet No. 301
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.)
Issued by: A. W. Clark, Vice President
Issued on: August 30, 1994 Effective: October 01, 1994
<PAGE> 115
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff First Revised Sheet No. 302
Second Revised Volume No. 1-A Superseding
Original Sheet No. 302
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: _______________________________________________
Issued by: A. W. Clark, Vice President
Issued on: August 30, 1994 Effective: October 01, 1994
<PAGE> 116
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff First Revised Sheet No. 303
Second Revised Volume No. 1-A Superseding
Original Sheet No. 303
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
<TABLE>
<CAPTION>
Requested Maximum Total Volume
Receipt Point(s)* Daily Volume (Over Term)
<S> <C> <C>
_________________ ____________Mcf/d ____________Mcf/d
__________MMBtu/d ___________MMBBtu
_________________ ____________Mcf/d ____________Mcf/d
__________MMBtu/d ___________MMBBtu
_________________ ____________Mcf/d ____________Mcf/d
__________MMBtu/d ___________MMBBtu
_________________ ____________Mcf/d ____________Mcf/d
__________MMBtu/d ___________MMBBtu
_________________ ____________Mcf/d ____________Mcf/d
__________MMBtu/d ___________MMBBtu
_________________ ____________Mcf/d ____________Mcf/d
__________MMBtu/d ___________MMBBtu
</TABLE>
Use 8-digit EPNG Code and include meter number(s).
Issued by: A. W. Clark, Vice President
Issued on: August 30, 1994 Effective: October 01, 1994
<PAGE> 117
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff First Revised Sheet No. 304
Second Revised Volume No. 1-A Superseding
Original Sheet No. 304
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
<TABLE>
<CAPTION>
Requested Maximum Total Volume
Receipt Point(s)* Daily Volume (Over Term)
<S> <C> <C>
_________________ ____________Mcf/d _____________Mcf/d
__________MMBtu/d ____________MMBBtu
_________________ ____________Mcf/d _____________Mcf/d
__________MMBtu/d ____________MMBBtu
_________________ ____________Mcf/d _____________Mcf/d
__________MMBtu/d ____________MMBBtu
_________________ ____________Mcf/d _____________Mcf/d
__________MMBtu/d ____________MMBBtu
_________________ ____________Mcf/d _____________Mcf/d
__________MMBtu/d ____________MMBBtu
_________________ ____________Mcf/d _____________Mcf/d
__________MMBtu/d ____________MMBBtu
</TABLE>
Use 8-digit EPNG Code and include meter number(s).
Issued by: A. W. Clark, Vice President
Issued on: August 30, 1994Effective: October 01, 1994
<PAGE> 118
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff First Revised Sheet No. 305
Second Revised Volume No. 1-A Superseding
Sheet Nos. 305 through 307
Reserved Sheets
Sheet Nos. 305 through 307 have been reserved
Issued by: A. W. Clark, Vice President
Issued on: August 30, 1994 Effective: October 01, 1994
<PAGE> 119
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 306
Second Revised Volume 1-A
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
<TABLE>
<CAPTION>
Producing Area
Requested Maximum Total Volume Area Source
Receipt Point(s)* Daily Volume (Over Term) of Gas
<S> <C> <C> <C>
______________ ____________Mcf/d _____________Mcf/d ______________
__________MMBtu/d ____________MMBBtu
______________ ____________Mcf/d _____________Mcf/d ______________
__________MMBtu/d ____________MMBBtu
______________ ____________Mcf/d _____________Mcf/d ______________
__________MMBtu/d ____________MMBBtu
______________ ____________Mcf/d _____________Mcf/d ______________
__________MMBtu/d ____________MMBBtu
______________ ____________Mcf/d _____________Mcf/d ______________
__________MMBtu/d _____________MMBBtu
______________ ____________Mcf/d _____________Mcf/d ______________
__________MMBtu/d _____________MMBBtu
</TABLE>
* Use 8-digit EPNG Code and include meter number(s). Also, identify the name
of the pipeline, gatherer or other entity delivering the gas into El
Paso's system.
** Enter 2-digit code from attached list applicable to the producing area
where the field or well producing the gas to be transported is located.
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 120
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 307
Second Revised Volume 1-A
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
<TABLE>
<CAPTION>
Requested Maximum Total Volume
Receipt Point(s)* Daily Volume (Over Term)
<S> <C> <C>
_________________ ____________Mcf/d ____________Mcf/d
__________MMBtu/d ___________MMBBtu
_________________ ____________Mcf/d ____________Mcf/d
__________MMBtu/d ___________MMBBtu
_________________ ____________Mcf/d ____________Mcf/d
__________MMBtu/d ___________MMBBtu
_________________ ____________Mcf/d ____________Mcf/d
__________MMBtu/d ___________MMBBtu
_________________ ____________Mcf/d ____________Mcf/d
__________MMBtu/d ___________MMBBtu
_________________ ____________Mcf/d ____________Mcf/d
__________MMBtu/d ___________MMBBtu
</TABLE>
* Use 8-digit EPNG Code and include meter number(s). Also, identify the
name of the pipeline, local distribution company or other entity receiving
the gas downstream of El Paso.
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 121
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 308
Second Revised Volume 1-A
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
prearranged 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 capacities
(a) at receipt points;
(b) on the mainline;
(c) at delivery points; and
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 122
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
Second Revised Volume 1-A Original Sheet No. 309
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.
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 123
EL PASO NATURAL GAS COMPANY Sheet Nos. 310 through 319
FERC Gas Tariff
Second Revised Volume No. 1-A
Reserved Sheets
Original Sheet Nos. 310 through 319 have been reserved.
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 124
EL PASO NATURAL GAS COMPANY Sheet Nos. 320 through 329
FERC Gas Tariff
Second Revised Volume No. 1-A
Reserved Sheets
Original Sheet Nos. 320 through 329 have been reserved.
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 125
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 330
Second Revised Volume 1-A
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. In addition, when a
well, with two or more designated markets is scheduled but one
or more markets fail to materialize, El Paso shall continue to
schedule the volumes confirmed for that part of the well's
production that has a market, but that portion for which the
market has failed to materialize will be classified as
unauthorized, unless this is the last well to be confirmed.
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, including excess volumes from the last well
to be confirmed by contract that results in volumes in excess
of the confirmed volumes, 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. Such excess scheduled volumes from the last well to
be confirmed shall be subject to Sections 19.12 or 20.11 of
said General Terms and Conditions.
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, except for
partial market wells that have been classified as
unauthorized, 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.
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 126
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 331
Second Revised Volume 1-A
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(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 from a well, plant or interconnected
pipeline or gathering facility.
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 Periods) 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
Periods) 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.
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 127
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 332
Second Revised Volume 1-A
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 or for partial market
wells that have been classified as unauthorized.
(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.
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 128
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 333
Second Revised Volume 1-A
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. 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)(l), (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.
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 129
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 334
Second Revised Volume 1-A
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 T-3 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 T-3
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 T-3 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 FTS-S 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
T-3. Notice of the intent to convert must be given to El Paso
at least one (l) 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
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 130
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 335
Second Revised Volume 1-A
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 T-3 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 prearranged
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:
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 131
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 336
Second Revised Volume 1-A
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 rates;
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 132
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 337
Second Revised Volume 1-A
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;
(1) 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 the 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
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 133
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 338
Second Revised Volume 1-A
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 seasons and
(r) any other applicable conditions.
A Releasing Shipper including any Shipper with a prearranged
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
prearranged 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 prearranged bid is for the
maximum applicable reservation rate, whether the Releasing
Shipper is seeking bids to compete with the non-rate
provisions of the prearranged bid. The Releasing Shipper
shall also designate if it is seeking bids when the release of
capacity is for less than one (1) month.
28.6 Terms 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.
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 134
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 339
Second Revised Volume 1-A
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 prearranged 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 less than one month
regardless of the rate bid.
(a) Capacity released under a prearrangement, for a
period of less than one (1) month 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 prearranged 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 thirty (30) 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 less than
one (1) calendar month 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 prearranged
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
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 135
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 340
Second Revised Volume 1-A
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 at least
one (1) calendar month 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.
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 136
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 341
Second Revised Volume 1-A
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
28. CAPACITY RELEASE PROGRAM (Continued)
28.8 Open Season and Matching Period (Continued)
(f) With respect to any prearranged 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) the 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
volumes
(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.
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 137
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 342
Second Revised Volume 1-A
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.
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 138
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 343
Second Revised Volume 1-A
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 prearranged release and the Prearranged
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.
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 139
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 344
Second Revised Volume 1-A
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
<TABLE>
<CAPTION>
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)
<S> <C> <C> <C> <C>
(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
</TABLE>
(iii) OPTION 2 - Net Present Value Calculation
R x 1 - (1 + i)-n 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
154.67(c)(2)(iii)(A)
n = term of the agreement, in months
R = the Reservation Charge(s) and Reservation Surcharge(s)
bid
V = sold stated in Mcf
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 140
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 345
Second Revised Volume 1-A
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 less than one (1)
calendar month 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 components
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.
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 141
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 346
Second Revised Volume 1-A
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 prearranged 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
Prearranged Shipper shall become the Acquiring
Shipper. Service to such Acquiring Shipper may begin
on the next scheduling day after award of the
capacity and
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 142
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 347
Second Revised Volume 1-A
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).
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 143
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 348
Second Revised Volume 1-A
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 T-3 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;
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 144
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 349
Second Revised Volume 1-A
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
Shippers; 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
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 145
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 350
Second Revised Volume 1-A
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
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 146
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 351
Second Revised Volume 1-A
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
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 147
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 352
Second Revised Volume 1-A
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 credit
worthiness 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.
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 148
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 353
Second Revised Volume 1-A
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
_____________________________, 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:
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 149
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 354
Second Revised Volume 1-A
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. l-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 Paint(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
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 150
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 355
Second Revised Volume 1-A
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 Tariffs
6. Other terms
As specified in the Notice posted pursuant to
Sections 28.4 or 28.5 of El Paso's Volume No. l-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.
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 151
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 356
Second Revised Volume 1-A
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)
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 152
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 357
Second Revised Volume 1-A
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.
El Paso and El Paso Gas Marketing Company as agent for El Paso
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 Nos. 497 and 497-A.
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.
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 153
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 358
Second Revised Volume 1-A
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 credit worthiness.
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 154
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 359
Second Revised Volume 1-A
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 Data ______________________________
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 155
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 360
Second Revised Volume 1-A
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 __________________________________________
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 156
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 361
Second Revised Volume 1-A
TRANSPORTATION 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 T-3 or Rate Schedule FTS-S.
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 T-3 and FTS-S 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, at al., "Prospective
Period." The Monthly Amortized Amounts
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 157
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 362
Second Revised Volume 1-A
TRANSPORTATION 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
shall be determined as set forth in Section 31.4(a)
below. The Reservation Surcharge shall be
selectively adjusted by El Paso; provided, however,
that such adjusted Reservation Surcharge 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 rates at Docket No. RS92-60-000 et
al., "Prospective Period," and identified on
Statement of Rates Sheet Nos. 27, 28, and 29 of this
FERC Gas Tariff shall apply to those firm forward
haul Shippers of El Paso for the purpose of this
Section.
(e) Monthly Billed Amount - The monthly amount billed
each Shipper as reflected on Statement of Rates Sheet
Nos. 27, 28, and 29 of the FERC Gas Tariff as
described in Section 31.4(b) below shall be the
Reservation Surcharge multiplied by the Billing
Determinant.
(f) Interest Rate - The quarterly interest rate published
by the Commission and computed in accordance with
Section 154.67(c)(2)(iii) 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 total Monthly Amortized Amount within
each rate zone divided by the total of the Billing
Determinants for that zone, and is reflected on the
Statement of Rates Sheet contained in this Volume No.
1-A Tariff.
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 158
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 363
Second Revised Volume 1-A
TRANSPORTATION 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 was stranded investment costs effective February
1, 1993.
(i) Effective with the Settlement at Docket No.
RP92-214-000, at 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)
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 159
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Original Sheet No. 364
Second Revised Volume 1-A
TRANSPORTATION 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 protection, 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 Parody 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.
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 160
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Sheet Nos. 365 through 399
Second Revised Volume 1-A
Reserved Sheets
Original Sheet Nos. 365 through 399 have been reserved.
Issued by: A. W. Clark, Vice President
Issued on: May 23, 1994 Effective: July 01, 1994
<PAGE> 1
Exhibit 10.6
THE PACIFIC GAS AND ELECTRIC COMPANY
SAVINGS FUND PLAN
FOR NON-UNION EMPLOYEES
This is the controlling and definitive statement of the Pacific Gas
and Electric Company Savings Fund Plan for Non-Union EMPLOYEES1/ in effect on
and after April 1, 1995. 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 Section 401(k) CONTRIBUTION; and/or
(b) elect to make NON-Section 401(k) CONTRIBUTIONS, if any, to the
PLAN; and
(c) instruct the PLAN ADMINISTRATOR as to the manner in which
EMPLOYEE contributions and matching EMPLOYER CONTRIBUTIONS are
to be invested.
CONTRIBUTIONS
3. EMPLOYEE Contributions
To become a contributing participant, an ELIGIBLE EMPLOYEE must make
Section 401(k) CONTRIBUTIONS, NON-Section 401(k) CONTRIBUTIONS, or a
combination of both to the PLAN through payroll deduction.
__________________________________
1/ Words in all capitals are defined in Section 30.
-1-
<PAGE> 2
All contributions withheld by the EMPLOYER from COVERED COMPENSATION
are paid over to the TRUSTEE, unconditionally credited to the
participant's account and invested in accordance with the
participant's instructions.
(a) Section 401(k) CONTRIBUTIONS. A Section 401(k) CONTRIBUTION
is an election to defer the receipt of a specified whole
percentage of COVERED COMPENSATION which would otherwise be
currently payable to a participant. The EMPLOYER shall reduce
the participant's COVERED COMPENSATION by an amount equal to
the percentage of the Section 401(k) CONTRIBUTION elected by
the participant. Under current law, Section 401(k)
CONTRIBUTIONS deferred by a participant under the PLAN are not
subject to federal or state income tax until actually
withdrawn or distributed from the PLAN.
(b) FLEXDOLLARS. By giving NOTICE, a participant in the COMPANY'S
Flex Plan may elect to have any unused FLEXDOLLARS contributed
to this PLAN. Any FLEXDOLLARS contributed to this PLAN shall
be deemed Section 401(k) CONTRIBUTIONS and shall be subject to
all restrictions and limitations applicable to Section 401(k)
CONTRIBUTIONS. FLEXDOLLAR contributions shall not be eligible
for matching EMPLOYER CONTRIBUTIONS as described in Section 4.
(c) NON-Section 401(k) CONTRIBUTIONS. NON-Section 401(k)
CONTRIBUTIONS differ from Section 401(k) CONTRIBUTIONS in that
a participant has already paid taxes on the amounts
contributed to the PLAN. All EMPLOYEE Contributions made to
the PLAN as it existed prior to October 1, 1984, are
considered to be NON-Section 401(k) CONTRIBUTIONS and are so
recorded in the accounts maintained by the PLAN ADMINISTRATOR.
NON-Section 401(k) CONTRIBUTIONS must be made in whole
percentages of COVERED COMPENSATION, and the sum of all
Section 401(k) CONTRIBUTIONS and NON-Section 401(k)
CONTRIBUTIONS made by a participant may not exceed 15 percent
of the participant's COVERED COMPENSATION.
(d) CHANGING CONTRIBUTIONS. By giving NOTICE to the PLAN
ADMINISTRATOR, a participant may direct the PLAN ADMINISTRATOR
to cease or resume making contributions, or to change the rate
of contributions. Any such change shall become effective
within 30 days of receipt by the PLAN ADMINISTRATOR of such
NOTICE.
4. Employer Contributions
(a) Each and every time that participants make Section 401(k) or
non-Section 401(K) CONTRIBUTIONS to the PLAN eligible for
matching EMPLOYER CONTRIBUTIONS, the COMPANY shall make a
matching EMPLOYER CONTRIBUTION to the PLAN in cash or in whole
shares of 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) Section 401(k) and NON-Section 401(k) CONTRIBUTIONS
Eligible for Matching EMPLOYER CONTRIBUTIONS.
Although a participant may elect to defer up to 15
percent of COVERED COMPENSATION to the PLAN, the
maximum amount of a
-2-
<PAGE> 3
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 Section 401(k) CONTRIBUTIONS as a percentage
of compensation for all participating HIGHLY COMPENSATED
ELIGIBLE EMPLOYEES shall not exceed the larger of:
(1) the average rate of Section 401(k) CONTRIBUTIONS as a
percentage of compensation for all other
participating ELIGIBLE EMPLOYEES multiplied by 1.25
percent; or
(2) the lesser of:
(i) the average rate of Section 401(k)
CONTRIBUTIONS as a percentage of compensation
for all other participating ELIGIBLE
EMPLOYEES multiplied by 2; or
(ii) the average rate of Section 401(k)
CONTRIBUTIONS as a percentage of compensation
for all other participating ELIGIBLE
EMPLOYEES plus 2 percentage points, or such
lesser amount as the Secretary of the
Treasury may prescribe in order to prevent
the multiple use of this alternative
limitation with respect to any HIGHLY
COMPENSATED participant.
The average rate of Section 401(k) CONTRIBUTIONS for a PLAN
YEAR for a designated group of ELIGIBLE EMPLOYEES shall be the
average of the ratios, calculated separately for each
participating ELIGIBLE EMPLOYEE in the group, of the amount of
Section 401(k) CONTRIBUTIONS made by each EMPLOYEE for the
PLAN YEAR, to the EMPLOYEE'S compensation for such PLAN YEAR.
As used in this subsection, compensation shall mean
compensation paid by an EMPLOYER to the participant during the
PLAN YEAR which is required to be reported as wages on the
participant's form W-2 and shall also include compensation
-3-
<PAGE> 4
which is not currently includable in the participant's gross
income by reason of the application of CODE Sections 125 and
402(e)(3).
For purposes of this subsection, the ratio of the amount of
Section 401(k) CONTRIBUTIONS to a participant's compensation
for any participant who is HIGHLY COMPENSATED for the PLAN
YEAR and who is eligible to have elective deferrals or
qualified employer deferral contributions allocated to his
account under two or more plans or arrangements described in
Section 401(k) of the CODE that are maintained by an employer
or affiliated employer shall be determined as if all such
Section 401(k) CONTRIBUTIONS, elective deferrals and qualified
employer deferral contributions were made under a single
arrangement.
For purposes of determining the ratio of the amount of Section
401(k) CONTRIBUTIONS to a participant's compensation for a
participant who is HIGHLY COMPENSATED by reason of being one
of the ten highest-paid EMPLOYEES or a 5 percent owner of the
controlled group of corporations, as defined in Section 414 of
the CODE, the Section 401(k) CONTRIBUTIONS and compensation of
such participant shall include the Section 401(k)
CONTRIBUTIONS and compensation of the participant's family
members, as defined in Section 414 of the CODE, and such
family members shall be disregarded in determining the average
rate of Section 401(k) CONTRIBUTIONS for non-HIGHLY
COMPENSATED participants.
The determination and treatment of Section 401(k)
CONTRIBUTIONS of any participant shall satisfy such other
requirements as may be prescribed by the Secretary of the
Treasury.
(b) Average Contribution Percentage Limitation. In any PLAN YEAR,
the average rate of NON-Section 401(k) CONTRIBUTIONS and
EMPLOYER CONTRIBUTIONS as a percentage of compensation for all
participating HIGHLY COMPENSATED ELIGIBLE EMPLOYEES shall not
exceed the larger of:
(1) the average rate of NON-Section 401(k) CONTRIBUTIONS
and EMPLOYER CONTRIBUTIONS as a percentage of
compensation for all other participating ELIGIBLE
EMPLOYEES multiplied by 1.25; or
(2) the lesser of:
(i) the average rate of NON-Section 401(k)
CONTRIBUTIONS and EMPLOYER CONTRIBUTIONS as a
percentage of compensation for all other
participating ELIGIBLE EMPLOYEES multiplied
by 2; or
(ii) the average rate of NON-Section 401(k)
CONTRIBUTIONS and EMPLOYER CONTRIBUTIONS for
all other participating ELIGIBLE EMPLOYEES
plus 2 percentage points, or such lesser
amount as the Secretary of the Treasury may
prescribe in order to prevent the multiple
use of this alternative limitation with
respect to any HIGHLY COMPENSATED
participant.
The average rate of NON-Section 401(k) CONTRIBUTIONS and
EMPLOYER CONTRIBUTIONS for a PLAN YEAR for a designated group
of ELIGIBLE EMPLOYEES shall be the average of the ratios,
calculated separately for each participating ELIGIBLE EM-
-4-
<PAGE> 5
PLOYEE in the group, of the amount of NON-Section 401(k)
CONTRIBUTIONS and EMPLOYER CONTRIBUTIONS made by and on behalf
of each EMPLOYEE for the PLAN YEAR, to the EMPLOYEE'S
compensation for such PLAN YEAR. As used in this subsection,
compensation shall mean compensation paid by an EMPLOYER to
the participant during the PLAN YEAR which is required to be
reported as wages on the participant's form W-2 and shall also
include compensation which is not currently includable in the
participant's gross income by reason of the application of
CODE Sections 125 and 402(e)(3).
For purposes of this subsection, the ratio of the amount of
NON-Section 401(k) CONTRIBUTIONS and EMPLOYER CONTRIBUTIONS to
a participant's compensation for any participant who is HIGHLY
COMPENSATED for the PLAN YEAR and who is eligible to have
elective deferrals or qualified employer deferral
contributions allocated to his account under two or more plans
or arrangements described in Section 401(k) of the CODE that
are maintained by an employer or affiliated employer shall be
determined as if all such NON-Section 401(k) CONTRIBUTIONS and
EMPLOYER CONTRIBUTIONS, elective deferrals and qualified
employer deferral contributions were made under a single
arrangement.
For purposes of determining the ratio of the amount of
NON-Section 401(k) CONTRIBUTIONS and EMPLOYER CONTRIBUTIONS to
a participant's compensation for a participant who is HIGHLY
COMPENSATED by reason of being one of the ten highest-paid
EMPLOYEES or a 5 percent owner of the controlled group of
corporations, as defined in Section 414 of the CODE, the NON-
Section 401(k) CONTRIBUTIONS and EMPLOYER CONTRIBUTIONS and
compensation of such participant shall include the NON-
Section 401(k) CONTRIBUTIONS and EMPLOYER CONTRIBUTIONS and
compensation of the participant's family members, as defined
in Section 414 of the CODE, and such family members shall be
disregarded in determining the average rate of NON-Section
401(k) CONTRIBUTIONS and EMPLOYER CONTRIBUTIONS for non-HIGHLY
COMPENSATED participants.
The determination and treatment of NON-Section 401(k)
CONTRIBUTIONS and EMPLOYER CONTRIBUTIONS of any participant
shall satisfy such other requirements as may be prescribed by
the Secretary of the Treasury.
(c) In the event that the EMPLOYEE BENEFIT ADMINISTRATIVE
COMMITTEE, in its sole and absolute discretion, determines
that the rate of Section 401(k) CONTRIBUTIONS, and/or the rate
of NON-Section 401(k) CONTRIBUTIONS and EMPLOYER CONTRIBUTIONS
will exceed either or both of the maximum limitations
contained in subsections 5(a) and 5(b), the EMPLOYEE BENEFIT
ADMINISTRATIVE COMMITTEE shall instruct the PLAN ADMINISTRATOR
to reduce the rate of contributions made by HIGHLY COMPENSATED
participants so that the limitations will be met.
The PLAN ADMINISTRATOR shall first determine the maximum
average rate of contributions which can be made by the HIGHLY
COMPENSATED participants. The contributions made by HIGHLY
COMPENSATED participants shall then be reduced, on a
prospective basis, until the limitations are met. Any
necessary reduction shall be made by first reducing the
highest rate of Section 401(k) CONTRIBUTIONS or NON-Section
401(k) CONTRIBUTIONS and EMPLOYER CONTRIBUTIONS as may be
appropriate, currently authorized by participants, with such
rate to
-5-
<PAGE> 6
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 Section 401(k)
CONTRIBUTIONS, and/or NON-Section 401(k) CONTRIBUTIONS and
EMPLOYER CONTRIBUTIONS (and any income allocable to such
portion), until the PLAN satisfies both of the tests. If
there is a loss allocable to such excess amount, the amount of
the distribution shall in no event be less than the lesser of
the (i) participant's account or (ii) the participant's
Section 401(k) CONTRIBUTIONS, or NON-Section 401(k)
CONTRIBUTIONS and EMPLOYER CONTRIBUTIONS, as appropriate, for
the PLAN YEAR.
For the PLAN YEARS 1987, 1988, 1989, 1990 and 1991 only, the
PLAN ADMINISTRATOR may elect to make qualified non-elective
employer contributions within the meaning of Section
401(m)(4)(c) of the CODE, on behalf of such non-HIGHLY
COMPENSATED participants who are EMPLOYEES of Pacific Service
Employees Association as will cause the PLAN to meet the
appropriate limits set forth in subsections 5(a) and 5(b).
For purposes of PLAN withdrawals qualified non-elective
employer contributions shall be treated as Section 401(k)
CONTRIBUTIONS.
For purposes of determining whether the PLAN meets either or
both of the limits set forth in subsections 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 Section 401(k) Limitation. Effective as of January 1,
1987, no participant shall be permitted to make Section 401(k)
CONTRIBUTIONS to the PLAN during any PLAN YEAR in excess of
$7,000, multiplied by the adjustment factor prescribed by the
Secretary of the Treasury under Section 415(d) of the CODE for
years beginning after December 31, 1987, as applied to
elective deferrals. A participant who is unable to make
Section 401(k) CONTRIBUTIONS which would have been eligible
for matching EMPLOYER CONTRIBUTIONS because of the limitation
contained in this subsection 5(d), shall be entitled to make
NON-Section 401(k) CONTRIBUTIONS in an amount equal to the
amount of Section 401(k) CONTRIBUTIONS that could have been
made but for the subsection 5(d) limitation. Such NON-Section
401(k) CONTRIBUTIONS shall be eligible for matching EMPLOYER
CONTRIBUTIONS as though they were Section 401(k)
CONTRIBUTIONS, subject to the limitations contained in Section
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
-6-
<PAGE> 7
which must be kept within the limits set forth above, shall
mean the sum credited to a participant's account for any PLAN
YEAR of (i) EMPLOYER CONTRIBUTIONS and Section 401(k)
CONTRIBUTIONS, (ii) NON-Section 401(k) CONTRIBUTIONS, and
(iii) any amounts allocated to an individual medical account,
as defined in Sections 415(l)(2) and 419A(d)(2) of the CODE.
The compensation limitation percentage referred to above shall
not apply to (i) any contribution for medical benefits, as
defined in Section 419A(f)(2) of the CODE, after a
participant's separation from SERVICE which is otherwise
treated as an annual addition, or (ii) any amount which is
otherwise treated as an annual addition under Section
415(l)(1) of the CODE.
(1) Solely for purposes of applying the Section 415
limitations, compensation shall include all of a
participant's wages, salaries, fees for professional
service, and other amounts received for personal
services actually rendered in the course of
employment with an EMPLOYER (including, but not
limited to, commissions paid to salesmen,
compensation for services on the basis of a
percentage of profits, commissions on insurance
premiums, tips, and bonuses). For purposes of
applying the Section 415 limitations, compensation
shall not include any of the following:
a) Contributions made by an EMPLOYER to a plan
of deferred compensation to the extent that,
before the application of the Section 415
limitations to that plan, the contributions
are not includable in the gross income of the
participant for the taxable year in which
contributed. Any distributions from a plan
of deferred compensation are not considered
as compensation for Section 415 purposes,
regardless of whether such amounts are
includable in the gross income of the
EMPLOYEE when distributed. However, any
amounts received by a participant pursuant to
an unfunded, nonqualified plan may be
considered as compensation for Section 415
purposes in the year such income is
includable in the gross income of the
EMPLOYEE.
b) Amounts realized from the exercise of a
nonqualified stock option, or when restricted
stock (or property) held by a participant
either becomes freely transferable or is no
longer subject to a substantial risk of
forfeiture.
c) Amounts realized from the sale, exchange, or
other disposition of stock acquired under a
qualified stock option.
d) Other amounts which receive special tax
benefits such as premiums for group term life
insurance (but only to the extent that the
premiums are not includable in the gross
income of the participant).
In the event that the annual additions to a
participant's accounts would exceed the
Section 415 Limitations, the PLAN
ADMINISTRATOR shall first reduce the
participant's NON-Section 401(k)
-7-
<PAGE> 8
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 compen-
sation considered under the PLAN for each family member is
proportionately reduced so that the total equals the
applicable compensation limitation under Section 401(a)(17) of
the CODE.
SELECTION OF INVESTMENT FUNDS
6. (a) Section 401(k) CONTRIBUTIONS, NON-Section 401(k)
CONTRIBUTIONS, and EMPLOYER CONTRIBUTIONS. By giving NOTICE,
a participant shall instruct the PLAN ADMINISTRATOR to invest
his Section 401(k) CONTRIBUTIONS, NON-Section 401(k)
CONTRIBUTIONS, and EMPLOYER CONTRIBUTIONS in one or more
INVESTMENT FUNDS. The minimum amount which can be invested in
any single INVESTMENT FUND shall be one percent of a
participant's current contributions to the PLAN. A
participant may elect to invest more than the minimum amount
in any INVESTMENT FUND, provided that any such increase must
be in increments of one percent.
-8-
<PAGE> 9
(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.
(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.
-9-
<PAGE> 10
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 Investment 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 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
-10-
<PAGE> 11
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.
(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
-11-
<PAGE> 12
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 TRUSTEE,
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
-12-
<PAGE> 13
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 Section 401(k) CONTRIBUTIONS
and NON-Section 401(k) CONTRIBUTIONS, the UNITS purchased therewith,
and the earnings thereon. All Basic Contributions and Supplemental
Contributions made to the PLAN as it existed prior to October 1, 1984,
are recorded as NON-Section 401(k) CONTRIBUTIONS on the records
maintained by the PLAN ADMINISTRATOR.
Whenever UNITS attributable to a participant's Section 401(k)
CONTRIBUTIONS are transferred to another FUND OR FUNDS, the resulting
UNITS are also recorded as attributable to Section 401(k)
CONTRIBUTIONS. Similarly, UNITS attributable to NON-Section 401(k)
CONTRIBUTIONS which are transferred to another FUND or FUNDS are also
recorded as NON-Section 401(k) CONTRIBUTIONS. A participant is at all
times fully vested in his own contributions and all EMPLOYER
CONTRIBUTIONS credited to his account, together with income
attributable thereto.
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.
-13-
<PAGE> 14
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) Section 401(k) CONTRIBUTIONS.
(1) A participant may withdraw all or part of the UNITS,
including income thereon and including additional
UNITS attributable thereto, bought with the
participant's Section 401(k) CONTRIBUTIONS upon the
occurrence of any of the following events:
(a) the participant is disabled and is receiving
benefits under the LONG TERM DISABILITY PLAN;
or
(b) the participant has attained age 59 1/2.
(2) A participant may withdraw an amount equal to his
Section 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;
(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,
-14-
<PAGE> 15
(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-Section 401(k) CONTRIBUTIONS. A participant may at any
time elect to withdraw all or any part of the UNITS including
income thereon and including additional UNITS attributable
thereto, bought with the participant's NON-Section 401(k)
CONTRIBUTIONS to the PLAN. Such an election will not cause
suspension from the PLAN.
(c) EMPLOYER CONTRIBUTIONS.
(1) A participant may withdraw all or any part of the
UNITS, including the income attributable thereto,
bought with EMPLOYER CONTRIBUTIONS which were made to
the PLAN at anytime prior to the second YEAR
preceding the current YEAR. For example, UNITS,
including the income attributable thereto, purchased
with EMPLOYER CONTRIBUTIONS made in 1981 and prior
years may be withdrawn in 1984 or anytime thereafter.
Such an election will not cause suspension from the
PLAN.
(2) UNITS, including the income attributable thereto,
bought with EMPLOYER CONTRIBUTIONS which would not be
withdrawable under Subsection 17(c)(1), shall
nonetheless be withdrawable upon the occurrence of
any of the following events:
(a) the participant is disabled and is receiving
benefits under the LONG TERM DISABILITY PLAN;
(b) the participant attains 59-1/2; or
(c) the participant has requested and is entitled
to receive a hardship distribution which
meets the requirements of Subsection 17(a)(2)
but only if all amounts distributable under
Subsection 17(a) have been exhausted.
-15-
<PAGE> 16
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-Section
401(k) CONTRIBUTIONS made prior to 1987, followed by
UNITS and earnings thereon attributable to NON-
Section 401(k) CONTRIBUTIONS made after 1986,
followed by UNITS 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
Section 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 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.
-16-
<PAGE> 17
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;
(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.
-17-
<PAGE> 18
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 distribution
does not include any distribution that is one of a series of
substantially equal periodic payments (not less frequently
than annually) made for the life (or life expectancy) of the
participant or the joint lives (joint life expectancies) of
the participant and his or her designated BENEFICIARY, or for
a specified period of 10 years or more; any distribution to
the extent such distribution is required under Section
401(a)(9) of the CODE; and the portion of any distribution
that is not includable in gross income (determined without
regard to the exclusion for net unrealized appreciation with
respect to employer securities).
(b) An eligible retirement plan shall mean an individual
retirement account described in Section 408(a) of the CODE, an
individual retirement annuity described in Section 408(b) of
the CODE, an annuity plan described in Section 403(a) of the
CODE, or a qualified trust described in Section 401(a) of the
CODE, that accepts the participant's eligible rollover
distribution. However, in the case of an eligible rollover
distribution to the surviving spouse, an eligible retirement
plan is an individual retirement account or individual
retirement annuity.
ADMINISTRATIVE PROVISIONS
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;
(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
-18-
<PAGE> 19
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 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.
-19-
<PAGE> 20
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 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:
-20-
<PAGE> 21
(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 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
-21-
<PAGE> 22
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
-----------
<TABLE>
<S> <C>
Administrator: Employee Benefit Administrative Committee,
------------- 201 Mission Street,
l9th Floor, Mail Code P19A,
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 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 Director: The Board of Directors of Pacific Gas and Electric Company.
-----------------
Bond Fund: A fund invested in United States Savings Bonds. (See Section 8)
---------
</TABLE>
-22-
<PAGE> 23
<TABLE>
<S> <C>
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, per diem allowances, payments, other than
temporary compensation, made under any Workers' Compensation Law,
voluntary wage benefit or state disability plans, or any other
benefit plan. For Plan Years beginning after 1988 and before 1994,
the maximum Covered Compensation of each Employee that may be taken
into account each Plan Year shall not exceed $200,000 (as adjusted
by the Secretary of the Treasury under Sec-
</TABLE>
-23-
<PAGE> 24
<TABLE>
<S> <C>
tion 401(a)(17) of the Code. For Plan Years beginning after 1993,
the maximum Covered Compensation of each Employee that may be taken
into account each Plan Year shall not exceed $150,000 (as adjusted
by the Secretary of the Treasury under Section 401(a)(17) of the
Code). In determining the Covered Compensation of a Highly
Compensated Employee for purposes of this limitation, the rules of
Section 414(q)(6) of the Code shall apply, except that the term
"family" shall include only the spouse of the Employee and any
lineal descendants of the Employee who have not attained age 19
before the close of the Year. If the aggregate Covered Compensation
of family members exceeds the applicable compensation limit as
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,
----------------- 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 Committee referred to in
Administrative Committee: Section 23.
------------------------
Employee Benefit Finance The Employee Benefit Finance Committee referred to in Section 22.
Committee:
---------
Employer: Pacific Gas and Electric Company, Pacific Service Employees
-------- Association, and any other company, association, or credit union
designated by the Board of Directors as eligible to participate in
this Plan as an Employer.
Employer Contributions: Any contributions to the Plan by Company.
----------------------
</TABLE>
-24-
<PAGE> 25
<TABLE>
<S> <C>
FlexDollars: Amounts which a participant elects pursuant to the Company's Flex
----------- Plan to contribute as Section 401(k) Contributions. Rules governing
FlexDollars are contained in the Company's Flex Plan; rules
governing the treatment of FlexDollars under this Plan are contained
in Subsection 3(b).
Fund: The Company Stock Fund, the 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.
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
</TABLE>
-25-
<PAGE> 26
<TABLE>
<S> <C>
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-Section 401(k) Contributions: Employee contributions to the Plan as described in Subsection 3(c)
-------------------------------- and all Employee Contributions made prior to October 1, 1984.
Non-Section 401(k) Contributions are made with after-tax dollars.
Notice: Any method of communication, whether electronic, telephonic, written
------ or other, provided that the Plan Administrator has communicated in
writing to participants any such method and its format as
appropriate and acceptable.
Plan: This Company's Savings Fund Plan for Non-Union Employees, as
---- amended, revised and set forth herein.
Retirement Plan: The Company's Retirement Plan as revised from time to time.
---------------
SBF: The Stock and Bond Fund.
---
Savings Fund Plan Office: 201 Mission Street, l9th Floor
------------------------ Mail Code P19A
P.O. Box 770000
San Francisco, CA 94177
Section 401(k) Contribution: Amounts deferred from a Participant's Covered Compensation as
--------------------------- described in Subsection 3(a). Section 401(k) Contributions
are made with pre-tax dollars.
Service: The period of time commencing with the first day of employment or
------- reemployment for an Employer and ending on participant's Severance
from Service Date. If an Employee with less than one year of
Service is rehired after a period of severance which extends for
12 months or more, the Employee shall be treated as a new Employee
for all purposes, and
</TABLE>
-26-
<PAGE> 27
<TABLE>
<S> <C>
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 quits, retires, is discharged
Date: or dies; or
----
B. The first anniversary of the first date of a period in
which a participant remains absent from work for an
Employer for any reason other than resignation, retirement,
discharge, or death.
C. For the purpose of determining the Severance from Service
Date, the following periods shall not be considered as
absences from work for an Employer:
(1) Absence on a leave of absence authorized by an
Employer.
(2) Absence because of illness or injury as long as the
participant is entitled to receive sick leave pay
or is entitled to receive benefits
</TABLE>
-27-
<PAGE> 28
<TABLE>
<S> <C>
under the provisions of the Voluntary Wage Benefit
Plan, a state disability plan, the Long Term
Disability Plan, or a Workers' Compensation Law.
(3) Absence for military service or service in the
Merchant Marines so long as reemployment rights are
protected by law.
(4) Absence caused by layoff for lack of work of less
than 12 continuous months for a Participant who has
less than five years of service, or 24 continuous
months for a Participant who has five or more years
of service.
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.
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.
---
</TABLE>
-28-
<PAGE> 29
SPECIAL PROVISION A
TOP HEAVY PROVISIONS
(a) General Rule
For any PLAN YEAR for which this PLAN is a "top-heavy plan" as defined
in subsection (g) below, any other provisions of this PLAN to the contrary
notwithstanding, this PLAN shall be subject to the following provisions:
(1) The minimum contribution provisions of subsection (b).
(2) The limitation on contribution set by subsection (d).
(b) Minimum Contribution Provisions
Each participant who (i) is a non-key EMPLOYEE (as defined in
subsection (i) below) and (ii) is employed on the last day of the PLAN YEAR,
even if such individual is excluded from the PLAN for failing to make mandatory
contributions to the PLAN, shall be entitled to have contributions allocated to
his account of not less than three percent (the "minimum contribution
percentage") of the participant's compensation (within the meaning of Section
415 of the CODE). In determining the minimum contribution percentage to be
allocated to an EMPLOYEE'S account, a participant's Section 401(k)
CONTRIBUTIONS shall 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) 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" were
substituted for "60 percent," then subsection (b) shall
-29-
<PAGE> 30
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 which a key EMPLOYEE is a
participant to meet
-30-
<PAGE> 31
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
determination date the present value of the accrued
benefits or account balance. The results shall then
be aggregated separately by adding the results of
each plan as of the determination dates for such
plans that fall with the same calendar year.
(B) In determining the present value of the cumulative
accrued benefit or the amount of the account of any
EMPLOYEE, such present value or account shall include
the amount in dollar value of the aggregate
distributions made to such EMPLOYEE under the
applicable plan during the five-year period ending on
the determination date, unless reflected in the value
of the accrued benefit or account balance as of the
most recent valuation date. Such amounts shall
include distribu-
-31-
<PAGE> 32
tions 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 more than one percent of the outstanding stock of the EM-
-32-
<PAGE> 33
PLOYER 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.
-33-
<PAGE> 34
-------------------------
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
-34-
<PAGE> 1
EXHIBIT 10.8
THE PACIFIC GAS AND ELECTRIC COMPANY
RETIREMENT PLAN
<PAGE> 2
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> 3
RETIREMENT PLAN
1. Introduction
This is the controlling and definitive statement of the
Pacific Gas and Electric Company Retirement PLAN1/ which,
with certain exceptions, is effective on and after Janu-
ary 1, 1994, 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 1994.
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 guid-
ance 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 re-
quirements 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 EMPLOY-
EES 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> 4
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 partici-
pation continues until the PARTICIPANT's SERVICE is termi-
nated.
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 em-
ployment 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> 5
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 RETIRE-
MENT DATE or beyond3/ is entitled to a BASIC PENSION pay-
able 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 clas-
sification, 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> 6
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, payable beginning with NORMAL
RETIREMENT DATE; or
b. An EARLY RETIREMENT PENSION with payments to begin on
the PARTICIPANT's EARLY RETIREMENT DATE and to continue
on the first day of each month thereafter so long as
PARTICIPANT lives. EARLY RETIREMENT DATE is the date
selected by the PARTICIPANT for commencement of payment
of retirement benefits. This date must be the first
day of any month after the termination of SERVICE and
before the PARTICIPANT's 65th birthday. To elect an
EARLY RETIREMENT PENSION, PARTICIPANT must notify the
EMPLOYER in writing at least 30 days before the EARLY
RETIREMENT DATE the PARTICIPANT selects. The monthly
amount of the PARTICIPANT's EARLY RETIREMENT
PENSION6/ 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.
-4-
<PAGE> 7
(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 RE-
TIREMENT 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 RETIRE-
MENT 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 SER-
VICE 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> 8
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 PARTICI-
PANT is also entitled to the elections provided in
Sections 10 (Forms of Pension), 12 (Withdrawal of Partici-
pant 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 enti-
tled to a pension until PARTICIPANT's ACTUAL RETIREMENT
DATE. Any provision of the PLAN notwithstanding, distribu-
tions 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 EM-
PLOYEE 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 calen-
dar 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 accor-
dance 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 EMPLOY-
EES.
10. Forms of Pension
(a) Joint Pension With Non-Spouse
For a PARTICIPANT who is unmarried on the ACTUAL RE-
TIREMENT 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 EM-
PLOYER at least 30 days' advance written notice prior
to the PARTICIPANT'S ACTUAL RETIREMENT DATE.
-6-
<PAGE> 9
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 accor-
dance 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 RETIRE-
MENT DATE, the normal form of PENSION shall be a MARI-
TAL 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 contin-
ued 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 RETIRE-
MENT 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 elect-
ed.
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 deter-
mined in accordance with the actuarial formula which is
set forth in Special Provision D, but actuarially
adjusted further to reflect the value of the restora-
tion 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 QUALI-
FIED ELECTION is made which would provide benefits to a
surviving SPOUSE less than those provided by a MARITAL
PENSION.
-7-
<PAGE> 10
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 PEN-
SION shall be reduced 1/20th of one percent for
each full month in excess of 120 months' differ-
ence 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 speci-
fied 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> 11
(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 re-
ceive 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 surviv-
ing 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 termina-
tion of SERVICE. After a PARTICIPANT's SERVICE is terminat-
ed, the PARTICIPANT, by written notice to the PARTICIPANT's
EMPLOYER at least 30 days before the date the PENSION be-
gins, 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 CONTRIBU-
TIONS 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> 12
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 ACTUAR-
IAL EQUIVALENT of the early, normal or deferred retirement
benefit commencing at ACTUAL RETIREMENT DATE. In determin-
ing 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 individu-
al 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 fiducia-
ries of all further responsibility with respect to such
individual.
(c) If the distributee of any eligible rollover dis-
tribution (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 distribu-
tion shall be made in the form of a direct trustee-to-trust-
ee 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 "sub-
stantially 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 BENEFI-
CIARY 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> 13
charge to each EMPLOYER its share of the EMPLOYER contribu-
tions 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 con-
clusively 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 beneficia-
ry, 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 COM-
MITTEE has the sole power and duty from time to time to
appoint and remove the Funding Agents, the Investment Manag-
er, actuaries, accountants, and such other advisors and
consultants as may be needed for the proper financial admin-
istration and investment of the assets of the PLAN. Supple-
menting 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> 14
(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 combi-
nation 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 avail-
able to pay benefits on behalf of all PARTICIPANTS covered
by this PLAN.
19. Administration
The EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE, appoint-
ed by the COMPANY's Board of Directors to serve at its
pleasure, is the ADMINISTRATOR of the PLAN and is responsi-
ble for the overall administration of the PLAN. The ADMIN-
ISTRATOR 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 consid-
ers necessary, and it may adjust any PENSION or other pay-
ment 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 agree-
ment, 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 docu-
ments 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 commit-
tee, unless paid by the COMPANY. Such expenses shall in-
clude any expenses incident to the functioning of the ADMIN-
ISTRATOR, including, but not limited to, fees for accoun-
tants, actuaries, counsel, investment managers and other
specialists and their agents, and other costs of administer-
ing the PLAN.
20. Claims Procedure
If a claim is denied in whole or in part, the ADMINIS-
TRATOR shall furnish to the claimant a written notice set-
ting 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 neces-
sary, and
(d) Information concerning the steps to be taken if
claimant wishes to submit a claim for review.
-12-
<PAGE> 15
The above information shall be furnished to the claimant
within 90 days after the claim is received by the ADMINIS-
TRATOR.
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 ADMINIS-
TRATOR in writing within 90 days after receiving such no-
tice. If a review is requested the claimant shall also be
entitled, upon written request, to review pertinent docu-
ments 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 incon-
sistent with Section 414(p) of the CODE.
The EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE shall estab-
lish 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 PARTICI-
PANT.
(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 Domes-
tic 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 fore-
seen, 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> 16
purpose except for the exclusive benefit of PARTICIPANTS,
Pensioners, and their SPOUSES, JOINT PENSIONERS, and BENEFI-
CIARIES.
In the event the PLAN is partially terminated, termi-
nated or suspended, all EMPLOYER contributions with respect
to the affected PARTICIPANTS shall cease and the accrued
benefits of the affected PARTICIPANTS shall become nonfor-
feitable. Subject to applicable requirements of notice to
the Pension Benefit Guaranty Corporation governing termina-
tion of PENSION benefit plans, the funds held under the PLAN
by the Funding Agents shall be applied to provide the PEN-
SIONS, benefits and refunds accrued to the date of termina-
tion 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, distri-
bution 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 re-
funds to the date of termination have been satisfied or
provided for in accordance with the foregoing, any funds
remaining with the Funding Agents shall be returned to the
COMPANY.
This PLAN shall not be merged into or consolidated with
any other PLAN, nor shall any of its assets or liabilities
be transferred to any other PLAN, unless each PARTICIPANT in
this PLAN would (if such other PLAN then terminated) receive
a benefit immediately after the merger, consolidation, or
transfer which is equal to or greater than the benefit such
PARTICIPANT would have been entitled to receive immediately
before the merger, consolidation, or transfer (if this PLAN
had then terminated).
23. Definitions and Cross-References
<TABLE>
<S> <C>
Actual Retirement Date: The date of one of the following, whichever
is applicable:
(a) The date on which an EARLY RETIREMENT
PENSION begins, or
(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
</TABLE>
-14-
<PAGE> 17
<TABLE>
<S> <C>
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.
</TABLE>
-15-
<PAGE> 18
<TABLE>
<S> <C>
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 pro-
vided 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 desig-
nation 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 be made by a
PARTICIPANT without the CONSENT of the
SPOUSE at any time prior to
</TABLE>
-16-
<PAGE> 19
<TABLE>
<S> <C>
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 Interest: The cumulative total of contributions made
by a PARTICIPANT to the PLAN under Section
13; paragraph (b) of Special Provision F;
and to the COMPANY's Retirement PLAN as it
existed before 1969, plus interest at two
percent per year on a PARTICIPANT's
contributions made after 1953, compounded
annually to 1976, together with interest
at five percent compounded annually after
1975 on all contributions and previous
interest.
Credited Service: See Special Provision F.
Early Retirement Date: See Section 7.
Early Retirement Pension: See Section 7.
Employee: An EMPLOYEE of an EMPLOYER who is not
covered by a collective bargaining agree-
ment. 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
Gas Transmission Company, Pacific Service
Employees Association, and any other
company, association, or credit union
designated by the Board of Directors as
eligible to participate in this PLAN is
an EMPLOYER.
Joint Pension: See Section 10.
Joint Pensioner: The individual designated by a PARTICIPANT
upon the election of a JOINT PENSION who
will be entitled upon the PARTICIPANT's
death to receive a PENSION, as explained in
Section 10.
Long Term Disability Plan: Part B of the Pacific Gas and Electric
Company's Group Life Insurance and Long
Term Disability Plan.
</TABLE>
-17-
<PAGE> 20
<TABLE>
<S> <C>
Marital Pension: See Section 10(b).
Maximum Pension: See Special Provision H.
Normal Retirement Date: The first of the month following the PARTI-
CIPANT'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 expla-
nation 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 consi-
dered 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 acknow-
ledges the effect of the election, and
(d) the SPOUSE'S CONSENT is witnessed by a
PLAN representative or a notary public. A
PARTICIPANT'S
</TABLE>
-18-
<PAGE> 21
<TABLE>
<S> <C>
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 satis-
faction 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 Partici-
pant'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 enti-
tled 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.
</TABLE>
-19-
<PAGE> 22
<TABLE>
<S> <C>
(c) Absence for military service or
service in the Merchant Marines so
long as reemployment rights are pro-
tected 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.
</TABLE>
-20-
<PAGE> 23
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>
-21-
<PAGE> 24
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> 25
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> 26
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> 27
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>
<PAGE> 28
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> 29
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> 30
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> 31
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> 32
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> 33
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> 34
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> 35
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> 36
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> 37
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> 38
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> 39
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> 40
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> 41
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> 42
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> 43
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> 44
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> 45
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> 46
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> 47
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> 48
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> 49
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> 50
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 availavble from the
Administrator.
-48-
<PAGE> 51
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> 52
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> 53
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> 54
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> 55
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> 56
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> 57
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> 58
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> 59
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> 60
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> 61
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> 62
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> 63
(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> 64
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> 65
<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> 66
EXAMPLE:
Assumptions: Age 60
Basic Pensions = $1,500.00/month
Contributions = $6,000.00
Interest = 3,000.00
---------
Total = $9,000.00 - 65.33*
---------
Pension with contributions = $1,434.67/month
plus interest withdrawn
_______________________
*Calculation: (Contributions + Interest x Age 60 Refund Factor) : 12 Months
($9,000 x .0871 : 12 Months = $65.33)
-64-
<PAGE> 67
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> 68
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> 69
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> 70
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> 71
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> 72
(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> 73
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> 74
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,
-72-
<PAGE> 75
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.
-73-
<PAGE> 76
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> 77
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 Communi-
cations 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> 78
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> 79
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> 80
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> 1
EXHIBIT 12.1
PACIFIC GAS AND ELECTRIC COMPANY AND SUBSIDIARIES
RESTATED COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------------------------------------
1994 1993 1992 1991 1990
---------- ---------- ---------- ---------- ----------
(DOLLARS IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
Earnings:
Net income......................... $1,007,450 $1,065,495 $1,170,581 $1,026,392 $ 987,170
Adjustments for losses of
consolidated less than 100%
owned affiliates and the
Company's equity in
undistributed loss (earnings) of
unconsolidated affiliates....... (2,764) 6,895 (3,349) 26,671 (2,799)
Income tax expense................. 836,767 901,890 895,126 851,534 881,647
Net fixed charges.................. 730,965 821,166 802,198 776,682 812,568
---------- ---------- ---------- ---------- ----------
Total Earnings.................. $2,572,418 $2,795,446 $2,864,556 $2,681,279 $2,678,586
========= ========= ========= ========= =========
Fixed Charges:
Interest on long-term debt......... $ 651,912 $ 731,610 $ 739,279 $ 697,185 $ 699,849
Interest on short-term debt........ 77,295 87,819 61,182 77,760 110,982
Interest on capital leases......... 1,758 1,737 1,737 1,737 1,737
Capitalized Interest............... 2,660 46,055 6,511 6,107 7,214
---------- ---------- ---------- ---------- ----------
Total Fixed Charges............. $ 733,625 $ 867,221 $ 808,709 $ 782,789 $ 819,782
========= ========= ========= ========= =========
Ratios of Earnings to Fixed
Charges............................ 3.51 3.22 3.54 3.43 3.27
</TABLE>
- ---------------
Note: For the purpose of computing the Company's ratios of earnings to fixed
charges, "earnings" represent net income adjusted for losses of
consolidated less than 100% owned affiliates, the Company's equity in
undistributed earnings or loss of unconsolidated affiliates, income taxes
and fixed charges (excluding capitalized interest). "Fixed charges"
consist of interest on short-term and long-term debt (including amounts
capitalized and amortization of bond premium, discount and expense; and
excluding interest on decommissioning trust funds [for which an equal
amount of interest income is recorded]) and interest on capital leases.
<PAGE> 1
EXHIBIT 12.2
PACIFIC GAS AND ELECTRIC COMPANY AND SUBSIDIARIES
RESTATED COMPUTATION OF RATIOS OF EARNINGS TO COMBINED FIXED CHARGES AND
PREFERRED STOCK DIVIDENDS
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------------------------------------------------
1994 1993 1992 1991 1990
---------- ---------- ---------- ---------- ----------
(DOLLARS IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
Earnings:
Net income................. $1,007,450 $1,065,495 $1,170,581 $1,026,392 $ 987,170
Adjustments for losses of
consolidated less than
100% owned affiliates
and the Company's equity
in undistributed loss
(earnings) of
unconsolidated
affiliates.............. (2,764) 6,895 (3,349) 26,671 (2,799)
Income tax expense......... 836,767 901,890 895,126 851,534 881,647
Net fixed charges.......... 730,965 821,166 802,198 776,682 812,568
---------- ---------- ---------- ---------- ----------
Total Earnings..... $2,572,418 $2,795,446 $2,864,556 $2,681,279 $2,678,586
========= ========= ========= ========= =========
Fixed Charges:
Interest on long-term
debt.................... $ 651,912 $ 731,610 $ 739,279 $ 697,185 $ 699,849
Interest on short-term
debt.................... 77,295 87,819 61,182 77,760 110,982
Interest on capital
leases.................. 1,758 1,737 1,737 1,737 1,737
Capitalized Interest....... 2,660 46,055 6,511 6,107 7,214
---------- ---------- ---------- ---------- ----------
Total Fixed
Charges.......... 733,625 867,221 808,709 782,789 819,782
---------- ---------- ---------- ---------- ----------
Preferred Stock Dividends:
Tax deductible dividends... 4,672 4,814 5,136 5,136 5,136
Pretax earnings required to
cover non-tax deductible
preferred stock dividend
requirements............ 96,039 108,937 130,147 154,404 175,881
---------- ---------- ---------- ---------- ----------
Total Preferred
Stock
Dividends........ 100,711 113,751 135,283 159,540 181,017
---------- ---------- ---------- ---------- ----------
Total Combined Fixed Charges
and Preferred Stock
Dividends.................. $ 834,336 $ 980,972 $ 943,992 $ 942,329 $1,000,799
========= ========= ========= ========= =========
Ratios of Earnings to
Combined Fixed Charges and
Preferred Stock
Dividends.................. 3.08 2.85 3.03 2.85 2.68
</TABLE>
- ---------------
Note: For the purpose of computing the Company's ratios of earnings to combined
fixed charges and preferred stock dividends, "earnings" represent net
income adjusted for losses of consolidated less than 100% owned
affiliates, the Company's equity in undistributed earnings or loss of
unconsolidated affiliates, income taxes and fixed charges (excluding
capitalized interest). "Fixed charges" consist of interest on short-term
and long-term debt (including amounts capitalized and amortization of bond
premium, discount and expense; and excluding interest on decommissioning
trust funds [for which an equal amount of interest income is recorded])
and interest on capital leases. "Preferred stock dividends" represent the
sum of requirements for preferred stock dividends that are deductible for
federal income tax purposes and requirements for preferred stock dividends
that are not deductible for federal income tax purposes increased to an
amount representing pretax earnings which would be required to cover
such dividend requirements.
<PAGE> 1
Exhibit 13
Pacific Gas and Electric Company
SELECTED FINANCIAL DATA
(in thousands, except per share amounts)
<TABLE>
<CAPTION>
1994 1993 1992 1991 1990
<S> <C> <C> <C> <C> <C>
FOR THE YEAR
Operating revenues $10,447,351 $10,582,408 $10,296,088 $ 9,778,119 $ 9,470,092
Operating income 1,633,359 1,762,930 1,833,441 1,713,079 1,706,136
Net income 1,007,450 1,065,495 1,170,581 1,026,392 987,170
Earnings per common share 2.21 2.33 2.58 2.24 2.10
Dividends declared per common
share 1.96 1.88 1.76 1.64 1.52
AT YEAR END
Book value per common share $20.07 $19.77 $19.41 $18.40 $17.86
Common stock price per share 24.38 35.13 33.13 32.63 25.00
Total assets 27,809,133 27,162,526 24,188,159 22,900,670 21,958,397
Long-term debt and preferred stock
with mandatory redemption
provision (excluding current
portions) 8,812,591 9,367,100 8,525,948 8,341,310 7,902,409
</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> 2
Pacific Gas and Electric Company
MANAGEMENT'S DISCUSSION AND ANALYSIS OF CONSOLIDATED RESULTS OF OPERATIONS AND
FINANCIAL CONDITION
Pacific Gas and Electric Company (PG&E) and its wholly owned and majority-owned
subsidiaries (collectively, the Company) have three types of operations:
utility, Diablo Canyon Nuclear Power Plant (Diablo Canyon) and nonregulated
through PG&E Enterprises (Enterprises). The Company is engaged principally in
the business of supplying electric and natural gas service throughout most of
Northern and Central California. The Company's operations are regulated by the
California Public Utilities Commission (CPUC) and the Federal Energy Regulatory
Commission (FERC), among others.
Competition and Changing Regulatory Environment:
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
proposed. These reforms are designed to restructure regulation in the energy
supply industry and promote competition by providing electric and gas customers
with purchasing options.
As a result of the restructuring of the natural gas industry, the Company no
longer provides combined purchase and transportation services to many of its
industrial and large commercial gas customers. Instead, most of these customers
now procure their gas supplies from a source other than the Company while
purchasing transportation service from the Company. These customers can also
use alternative transportation services available within the Company's service
territory.
In November 1994, the FERC approved the expansion of a competing company's
natural gas pipeline into the Company's service territory. This pipeline could
compete directly for transportation service to several of the Company's large
customers as soon as January 1, 1996, and may result in the loss of sales on
the Company's gas transportation system.
While the restructuring of the electric industry is still evolving,
proposals being considered are expected to bring increased competition into the
electric generation business. At the federal level, the National Energy Policy
Act of 1992 (Energy Act) reduces various restrictions on the operation and
ownership of independent power producers and provides them and other wholesale
suppliers and purchasers with increased access to electric transmission lines
throughout the United States.
At the state level, in April 1994, the CPUC issued a proposal on electric
industry restructuring which seeks to lower energy prices and provide customers
with a choice of electric generation suppliers (known as direct access). This
proposal involves two key strategies: One, phase in direct access to electric
generation for all customers over a six-year period beginning in 1996; two,
where competition does not exist, replace traditional cost-of-service
regulation with performance-based regulation (PBR). To ensure a transition that
maintains the financial integrity of the utilities, the CPUC proposed that
uneconomic costs of utility generating assets resulting from its proposal be
recovered through a "competition transition charge." However, the CPUC
proposal did not specify which costs might be recovered through such a
transition charge or how such a charge would be allocated to and collected from
customers.
The Company has filed a response to the CPUC proposal embracing the
objective of lower prices and supporting increased competition, but
recommending a longer phase-in period to direct access to permit an orderly
transition. Based on market prices of $.048 and $.032 per kilowatthour (kWh),
the Company estimated that its uneconomic generating assets and obligations are
approximately $3 billion and $11 billion, respectively, resulting from the
restructuring as proposed by the CPUC. The Company identified three categories
of uneconomic assets: utility-owned generation assets and power purchase
commitments, power purchase obligations relating to qualifying facilities (QFs)
and generation-related regulatory assets. The estimates of uneconomic assets
were determined by comparing the future revenue requirements of generation
assets and power purchase obligations over a twenty-year and thirty-year
period, respectively, with revenues computed at the assumed market price.
Diablo Canyon was included in the revenue requirement calculation using the
proposed pricing modifications to the Diablo Canyon settlement. (See Operating
Revenues.) The revenue requirement for Diablo Canyon and all Company-owned
generation assets included a return on investment. The actual amount of
uneconomic assets and obligations will depend upon the final regulation and the
actual market price of electricity. The Company intends to seek recovery of its
uneconomic assets and obligations through the competition transition charge.
(See Note 2 of Notes to Consolidated Financial Statements.)
In addition to working with the CPUC on this proposal, the Company has made
several proposals to modify existing regulatory processes and to provide
additional pricing flexibility to those customers with the most competitive
options. The Company has proposed instituting PBR for determining nonfuel
revenues, under which electric and natural gas
13
<PAGE> 3
revenues would be determined annually by formula rather than through general
rate cases (GRCs), attrition rate adjustments and cost of capital proceedings.
The Company has also proposed a gas procurement incentive mechanism that would
replace after-the-fact reasonableness reviews of certain costs. This proposed
mechanism would measure the Company's gas procurement costs against market
benchmarks and would provide for the sharing, between ratepayers and
shareholders, of variances from a preset range around the market benchmark.
The shifting of utility regulation from traditional cost-of-service based
concepts to concepts based upon market competition and benchmarks will place
greater emphasis on the Company's ability to provide valued products and
services at competitive prices. The Company has announced a five-year goal of
reducing its system-wide average electric rates. In addition, the Company has
taken several significant actions to position itself to effectively compete in
the restructured electric and gas industries. Specifically, the Company has:
- Extended through 1995 its electric rate freeze which began in 1993.
- Proposed a modification of the Diablo Canyon settlement to reduce the
price paid for electricity generated at Diablo Canyon over the next five
years.
- Reduced electric rates for certain of its largest industrial customers
through an economic stimulus rate that will extend through the end of
1995.
- Planned reductions in annual spending in 1995 of approximately $600
million from 1993 spending levels.
- Refinanced debt and preferred stock over the last three years resulting
in annual savings of approximately $97 million in financing costs.
The Company cannot predict the ultimate outcome of the ongoing changes that
are taking place in the utility industry. However, management believes the end
result will involve a fundamental change in the way the Company conducts its
business. These changes may impact financial operating trends and add
volatility to the Company's earnings. Management is actively seeking regulatory
and operational changes that will allow the Company to provide energy services
in a safe, reliable and competitive manner while achieving strong financial
performance.
Accounting for the Effects of Regulation:
The transition to a competitive market environment may affect the Company's
future revenues and cash flows. In the event that recovery of the Company's
costs and investments becomes unlikely or uncertain due to competitive
pressures or regulatory changes, it could cause the Company to write off
applicable portions of its regulatory assets. The final CPUC determination of
uneconomic costs and the method of recovery could adversely affect the Company's
returns on its investments in electric generation assets. If future electric
generation revenues are insufficient to recover the Company's investments and
QF obligations, the Company would recognize a loss.
The Company currently accounts for the economic effects of regulation in
accordance with the provisions of Statement of Financial Accounting Standards
(SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation." As
a result of applying the provisions of SFAS No. 71, the Company has accumulated
approximately $3.7 billion of regulatory assets, including balancing accounts,
at December 31, 1994. As discussed further in Note 2 of Notes to Consolidated
Financial Statements, if the CPUC's electric industry restructuring proposal is
adopted as proposed or the Company determines that future electric generation
rates will no longer be based on cost-of-service, the Company will discontinue
application of SFAS No. 71 for the electric generation portion of its
operations. If such discontinuance should occur, the Company would write off
all applicable electric generation-related regulatory assets to the extent that
transition cost recovery is not assured. The regulatory assets attributable to
electric generation, excluding balancing accounts of approximately $700 million
which are expected to be recovered in the near term, are estimated to be $1.6
billion at December 31, 1994.
The final determination of the financial impact will depend on the form of
regulation, including transition mechanisms, if any, adopted by the CPUC and
the groups of customers affected. Currently, the Company is unable to predict
the ultimate outcome of the electric industry restructuring or predict whether
such outcome will have a significant impact on its financial position or
results of operations.
Proposed Accounting Standard:
The Financial Accounting Standards Board (FASB) has proposed a new accounting
standard, "Accounting for the Impairment of Long-Lived Assets," which is
expected to be issued in early 1995. The Company would be required to adopt the
new standard beginning January 1, 1996, but may elect to adopt it earlier.
If issued by the FASB as proposed, the new standard would require, among
other things, that regulatory assets recorded as a result of SFAS No. 71
continue to be probable of recovery in
14
<PAGE> 4
rates at all times, rather than only at the time the regulatory asset is
recorded. As such, regulatory assets currently recorded may require adjustment
in the future if recovery is no longer probable. Under the current ratemaking,
the Company does not believe there would be any immediate significant impact of
adopting the standard, as proposed.
Results of Operations
The Company's results of operations for the three years ended December 31,
1994, are reflected in the following table and discussed below.
<TABLE>
<CAPTION>
Diablo
(in millions, except per share amounts) Utility Canyon (1) Enterprises Total
<S> <C> <C> <C> <C>
1994
Operating revenues $ 8,329 $1,870 $ 248 $10,447
Operating expenses 7,281 1,252 281 8,814
------- ------ ------ -------
Operating income (loss) $ 1,048 $ 618 $ (33) $ 1,633
======= ====== ====== =======
Net income $ 541 $ 461 $ 5 $ 1,007
======= ====== ====== =======
Earnings per common share $ 1.16 $ 1.04 $ .01 $ 2.21
======= ====== ====== =======
Total assets at year end $20,303 $5,978 $1,528 $27,809
======= ====== ====== =======
1993
Operating revenues $ 8,398 $1,933 $ 251 $10,582
Operating expenses 7,335 1,225 259 8,819
------- ------ ------ -------
Operating income (loss) $ 1,063 $ 708 $ (8) $ 1,763
======= ====== ====== =======
Net income $ 552 $ 496 $ 17 $ 1,065
======= ====== ====== =======
Earnings per common share $ 1.18 $ 1.11 $ .04 $ 2.33
======= ====== ====== =======
Total assets at year end $19,870 $6,250 $1,043 $27,163
======= ====== ====== =======
1992
Operating revenues $ 8,306 $1,781 $ 209 $10,296
Operating expenses 7,125 1,118 220 8,463
------- ------ ------ -------
Operating income (loss) $ 1,181 $ 663 $ (11) $ 1,833
======= ====== ====== =======
Net income (loss) $ 738 $ 443 $ (10) $ 1,171
======= ====== ====== =======
Earnings (loss) per common share $ 1.61 $ .99 $ (.02) $ 2.58
======= ====== ====== =======
Total assets at year end $17,759 $5,494 $ 935 $24,188
======= ====== ====== =======
</TABLE>
(1) See Note 4 of Notes to Consolidated Financial Statements for discussion
of allocations.
Earnings Per Common Share:
Earnings per common share were $2.21, $2.33 and $2.58 for 1994, 1993 and 1992,
respectively. 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 special charges for
workforce reductions, gas reasonableness matters, contingencies related to gas
transportation commitments and an increase in litigation reserves which in the
aggregate totaled approximately $434 million. Special charges in 1993 totaled
approximately $410 million and included charges for workforce reductions, gas
decontracting, gas reasonableness matters, contingencies related to gas
transportation commitments and the impact of increasing the federal income
tax rate to 35 percent.
Earnings per common share for 1993 were lower than for 1992 due to charges
against earnings discussed above. These charges were partially offset by higher
Diablo Canyon revenues due to the annual increase in the price per kWh as
provided in the Diablo Canyon settlement.
Since the Diablo Canyon settlement in 1988, Diablo Canyon has made an
increasing contribution to the Company's total earnings per share. For the year
ended December 31, 1994, Diablo Canyon contributed $1.04 (47 percent) to the
total earnings per share of $2.21. The proposed modification of the price for
power produced by Diablo Canyon, discussed below, will likely cause a decrease
in the Diablo Canyon earnings per share contribution.
On a consolidated basis, the Company earned an 11.1 percent, 11.9 percent
and 13.7 percent return on average common stock equity for the years ended
December 31, 1994, 1993 and 1992, respectively. For 1995, the CPUC has
authorized a return on average common stock equity of 12.1 percent for the
Company's utility operations.
Common Stock Dividend:
In January 1995, the Board of Directors (Board) declared a quarterly dividend
of $.49 per share which corresponds to an annualized dividend of $1.96 per
share. The Company's common stock dividend is based on a number of financial
considerations, including sustainability, financial flexibility and
competitiveness with investment opportunities of similar risk. The Company 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, the
restructuring of the electric industry will have on the Company's ability to
increase its dividends in the future.
15
<PAGE> 5
Operating Revenues:
Electric revenues increased $162 million, $119 million and $378 million in
1994, 1993 and 1992, respectively, compared to the preceding year. Despite the
rate freeze, electric revenues increased due to higher energy costs in 1994
reflected in the electric energy cost balancing account. The higher revenues
from the energy cost balancing account were offset by the 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 Company will
continue through the end of 1995 its freeze on electric rates which began in
1993.
The increase in 1993 electric revenues was due to rate increases associated
with general increases in operating expenses and a higher electric rate base on
which PG&E is allowed to earn a return. This increase was offset by a decrease
in revenues resulting from a decrease in the cost of electric energy. In
addition, Diablo Canyon revenues, which are included in the electric revenues
discussed above, increased due to the annual increase in the price per kWh as
provided in the Diablo Canyon settlement.
The 1992 increase in electric revenues was primarily due to one scheduled
refueling outage at Diablo Canyon as compared with two scheduled refueling
outages in 1991, and the annual increase in the price per kWh as provided in
the Diablo Canyon settlement.
The Diablo Canyon settlement, which became effective July 1988, bases
revenues for the plant 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
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.
As discussed further in Note 4 of Notes to Consolidated Financial
Statements, in December 1994, the Company, a consumer advocacy branch of the
CPUC staff (the Division of Ratepayer Advocates (DRA)), the California Attorney
General and several other parties representing energy consumers have agreed to
modify the pricing provisions of the Diablo Canyon settlement, subject to CPUC
approval. Under the proposed modification, the price for power produced by
Diablo Canyon would be reduced from what it would have been under the original
terms of the Diablo Canyon settlement.
The Diablo Canyon capacity factors for 1994, 1993 and 1992 were 81 percent,
89 percent and 88 percent, respectively, reflecting the scheduled refueling
outages for Units 1 and 2 in 1994, Unit 2 in 1993 and Unit 1 in 1992. The 1994
capacity factors were also impacted by 24 days of extended unscheduled outages.
There were no extended unscheduled outages in 1993 or 1992. Through December
31, 1994, the lifetime capacity factor for Diablo Canyon was 79 percent. The
Company will report significantly lower revenues for Diablo Canyon during any
extended outages, including refueling outages. Refueling outages, the length of
which depend on the scope of the work, typically occur for each unit every
eighteen months. The next refueling outages for Unit 1 and Unit 2 are scheduled
to begin in September 1995 and March 1996, respectively, and each is planned to
last about six weeks.
Under the proposed modification to the prices prescribed in the Diablo
Canyon settlement, each Diablo Canyon unit will contribute approximately $2.9
million in revenues per day at full operating power in 1995. The daily revenues
could decline each year for the next five years.
Gas revenues decreased $297 million in 1994 compared to the preceding year
primarily due to a decrease in revenues received from our industrial and large
commercial customers, who are now arranging for the purchase of their own gas
supplies, with the Company providing only transportation service partially
offset by revenues generated from the natural gas transmission expansion
project. (See Regulatory Matters.)
Gas revenues increased $168 million and $140 million in 1993 and 1992,
respectively, compared to the preceding year. The 1993 increase was primarily
due to rate increases associated with general increases in operating expenses
and a higher gas rate base on which PG&E is allowed to earn a return, as well
as increased revenues from Enterprises reflecting increases in the price and
production of gas.
The 1992 increase in gas revenues was primarily due to revenues resulting
from the December 1991 acquisition of Tex/Con Oil & Gas Company by DALEN
Resources Corp. (DALEN), a wholly owned subsidiary of Enterprises.
16
<PAGE> 6
Operating Expenses:
Operating expenses in 1994 remained constant as compared to 1993. The 1994
operating expenses include a charge against earnings of $249 million related to
the workforce reductions that commenced in 1994. In comparison, the Company
expensed $190 million related to the 1993 workforce reductions. As a result of
the 1993 workforce reductions, administrative and general expense was less in
1994 as compared to 1993. The cost of electric energy was $312 million greater
in 1994 as compared to 1993 primarily due to less favorable hydro conditions
and an increase in the cost per kWh of purchased power. These unfavorable
variances were offset by a favorable variance of $365 million in the cost of
gas as a result of the Company no longer procuring gas for certain customers.
Income tax expense has declined due to lower operating income in 1994.
In 1993 and 1992, the Company's operating expenses increased $357 million
and $398 million, respectively, over the preceding year. The 1993 increase was
due to the charge related to the Company's 1993 workforce reductions and
increases in administrative and general expense, income tax expense, and
depreciation and decommissioning expense, partially offset by a decrease in the
cost of electric energy. Most of the $114 million increase in administrative
and general expense was due to an increase in litigation costs and an increase
in employee benefit costs upon adoption of SFAS No. 106, "Employers' Accounting
for Postretirement Benefits Other Than Pensions." The $100 million increase in
income tax expense was primarily due to the increase in the federal income tax
rate to 35 percent. The $166 million decrease in the cost of electric energy
was a result of improved hydro conditions and reflects a decline in the cost
per kWh for purchased power.
The 1992 increase in operating expenses was primarily due to increases in
the cost of gas, the cost of electric energy, and depreciation and
decommissioning expense.
Other Income and (Income Deductions):
Other--net includes charges in 1994 and 1993 related to gas issues. The 1994
charges consist of accruals for gas reasonableness matters, including proposed
settlement agreements and contingencies related to transportation capacity
commitments. (See Note 3 of Notes to Consolidated Financial Statements.) The
1993 charges include accruals for gas reasonableness matters and contingencies
related to transportation capacity commitments as well as charges associated
with restructuring the Company's Canadian gas supply arrangements.
Regulatory Matters:
In addition to the CPUC electric industry restructuring proposal, discussed
further in Note 2 of Notes to Consolidated Financial Statements, during 1994
the Company received CPUC decisions in proceedings on revenues and energy costs
and filed applications which will impact rates in 1995 and beyond. The most
significant of these are discussed below.
The CPUC has approved the Company's request to freeze retail electric rates
through the end of 1995. In order to accomplish the rate freeze, rate increases
attributable to energy costs and the increase in the authorized rate of return
were offset by base revenue reductions. The Company is implementing base cost
reductions which are reflected in the decreased base revenues.
Gas rates for commodity, transportation and base costs have increased as a
result of two decisions during 1994. In July, the CPUC approved a $162 million
increase for recovery of previously deferred gas and transportation costs. In
December, a $100 million increase in revenue was approved reflecting an
increase in the cost of capital, balancing accounts adjustments and
inflationary increases in costs.
In addition, the Company filed an application with the CPUC requesting a gas
rate increase of approximately $173 million annually for the two-year period
beginning in October 1, 1995. The Company's request reflects an increase in gas
and transportation costs and the collection of amounts previously deferred in
balancing accounts. If the Company's request is adopted, rates would be
effective September 15, 1995.
In January 1995, the Company updated its 1996 GRC application to reflect
CPUC decisions that went into effect on January 1, 1995. In the GRC, the
Company is seeking a $162 million decrease for electric revenues and a $92
million decrease for gas revenues, compared to rates in effect in 1994.
(Compared to rates in effect in 1995, there would be no change for electric
revenues and a $162 million decrease for gas revenues.) Revenues to be
collected from customers in 1996 may also be affected by future requests
related to energy costs and cost of capital.
In November 1993, the Company placed in service an expansion of its natural
gas transmission system from the Canadian border into California. The pipeline
provides
17
<PAGE> 7
additional firm capacity to the Pacific Northwest and to Northern and
Southern California. The total cost of construction is approximately $1.7
billion. The Company has filed applications with the FERC (for the interstate
portion) and the CPUC (for the portion within California) requesting that
capital and operating costs be found reasonable. Revenues are currently being
collected under rates approved by the FERC and the CPUC, subject to refund. The
Company believes the final decisions on these applications will not have a
significant impact on its financial position or results of operations.
In accordance with mechanisms established by the CPUC, the Company
accumulates the difference between actual costs of generating electricity and
the revenues designed to recover such costs. To the extent costs exceed
revenues, the undercollection accumulates in the electric energy cost balancing
account. Over the past few years, the Company has experienced a significant
increase in the level of balancing account undercollection related to its
electric energy costs. The increase primarily results from Diablo Canyon's
generation exceeding that forecasted in the annual electric energy cost
proceeding, increased fuel costs, the use of higher-cost energy sources to
compensate for less than normal hydro conditions and the deferred recovery of
undercollected balances. At December 31, 1994, the electric energy cost
balancing account undercollection was approximately $716 million.
In order to accomplish its freeze on retail electric rates, the Company will
be deferring the recovery of $444 million of the electric energy cost
undercollection beyond 1995 and will also forgo collection of interest on these
deferred costs. Recovery of these deferred costs will depend on a number of
factors. However, the Company currently believes that the amount deferred will
be collected through rates over the near term. The modification of the price
for Diablo Canyon power will assist in reducing the undercollected energy cost
balance.
Nonregulated Operations:
The Company, through its wholly owned subsidiary, Enterprises, has taken steps
to position itself to compete in the nonregulated energy business. Enterprises
contributed $.01, $.04 and $(.02) per share to the Company's total earnings per
share for the years ended December 31, 1994, 1993 and 1992, respectively.
Enterprises makes the majority of its investments in nonregulated energy
projects through a joint venture, U.S. Generating. Enterprises in partnership
with Bechtel Enterprises, Inc. is in the process of forming a company to
develop, build, own and operate international nonutility generation projects.
In August 1994, Enterprises and Bechtel Enterprises, Inc. completed their
acquisition of J. Makowski Co., Inc. (JMC), a Boston-based company engaged in
the development of natural gas-fueled power generation projects and natural gas
distribution, supply and underground storage projects. The final purchase price
was approximately $250 million. Enterprises' effective ownership share of JMC
is approximately 80 percent.
In July 1994, the Company's Board approved a plan for the disposition of
DALEN, formerly PG&E Resources Company, through an initial public offering of
DALEN's common stock, as DALEN no longer fits Enterprises' business strategy.
The disposition, if completed, is not anticipated to have a significant impact
on the Company's financial position or results of operations.
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 capital
structure provides financial flexibility and access to capital markets at
reasonable rates, ensuring the Company's ability to meet all of its capital
requirements. Proceeds from the issuance of securities are used for capital
expenditures, refundings and other general corporate purposes.
Debt: In 1994, the Company issued $30 million of medium-term notes and
redeemed or repurchased $135 million of mortgage bonds, medium-term notes and
Eurobonds. In 1993, the Company issued $4.0 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.
In January 1995, the Board authorized the Company to redeem or repurchase up
to $153 million of mortgage bonds. In addition, $85 million remains from a
previous authorization to repurchase medium-term notes.
The Company 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, 1994
and 1993, the Company had $525 million and $764
18
<PAGE> 8
million, respectively, of commercial paper outstanding. In addition, the
Company has a $1 billion short-term credit facility to support the sale of
commercial paper and other corporate purposes. There were no borrowings under
this facility in 1994, 1993 or 1992.
Equity: In 1994 and 1993, the Company received $274 million and $264 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 July 1993, the Board authorized the Company to reinstate its common stock
repurchase program and repurchase up to $1 billion of common stock on the open
market or in negotiated transactions. This program is funded by internally
generated funds. Shares will be repurchased to manage the overall balance of
common stock in the Company's capital structure. Through December 31, 1994, the
Company had repurchased approximately $435 million of its common stock under
this program.
In 1994, the Company issued $63 million of preferred stock with a mandatory
redemption provision and redeemed $75 million of the Company's higher-cost
preferred stock.
In 1993, the Company issued $200 million of redeemable preferred stock.
Proceeds were used to finance a portion of the redemption of $267 million of
the Company's higher-cost preferred stock.
Capital Requirements:
The Company's estimated capital requirements for the next three years are shown
below:
<TABLE>
<CAPTION>
Year ended December 31,
-------------------------
(in millions) 1995 1996 1997
<S> <C> <C> <C>
Utility $1,212 $1,276 $1,237
Diablo Canyon 47 50 52
Enterprises 285 142 284
------ ------ ------
Total capital expenditures 1,544 1,468 1,573
Maturing debt and sinking funds 477 373 369
------ ------ ------
Total capital requirements $2,021 $1,841 $1,942
====== ====== ======
</TABLE>
Utility and Diablo Canyon expenditures will be primarily for improvements to
the Company's facilities to maintain their efficiency and reliability, to
extend their useful lives and to comply with environmental laws and
regulations.
Enterprises' estimated expenditures include oil and gas exploration and
development activities by DALEN of approximately $120 million for 1995, 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.
Risk Management:
The Company uses a number of techniques to mitigate its financial risk
including the purchase of commercial insurance, the maintenance of systems of
internal control and the selected use of financial instruments. The extent to
which these techniques are used depends on the risk of loss and the cost to
employ such techniques. These techniques do not eliminate financial risk to the
Company.
The majority of the Company's financing is done on a fixed-term basis
thereby eliminating the financial risk associated with fluctuating interest
rates. The Company has used financial instruments to eliminate the effects of
fluctuations in interest rates and foreign currency exchange rates on certain
of its debt. At December 31, 1994, the Company, through a series of interest
rate swap transactions, had converted $639 million of a subsidiary's debt from
a floating rate to a fixed rate through July 31, 1999. The Company, through
foreign exchange contracts, has agreed to pay fixed interest and principal
payments in U.S. dollars on $67 million of Swiss Franc debentures.
In addition, DALEN periodically enters into crude oil and natural gas
hedging transactions to minimize the risk of price fluctuations. The net gains
and losses associated with these transactions have not been material.
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 $39 million, $93 million and $85
million for 1995, 1996 and 1997, respectively, and are included in the
19
<PAGE> 9
Company's three-year table in the Capital Requirements section above.
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 the Company 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 $355 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. Although the ultimate
amount of costs that will be incurred by the Company in connection with its
compliance and remediation activities is difficult to estimate, the Company has
an accrued liability at December 31, 1994, of $95 million for hazardous waste
remediation costs. The costs could be as much as $235 million, due to
uncertainty concerning the Company's responsibility and the extent of
contamination, the complexity of environmental laws and regulations and the
selection of compliance alternatives. (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 are litigated or settled
with no significant impact on either the Company's results of operations or
financial position.
There are several significant litigation cases which are discussed in Note
13 of Notes to Consolidated Financial Statements. These cases include claims
for personal injury and property damage, as well as punitive damages, allegedly
suffered as a result of exposure to chromium near the Company's Hinkley
Compressor Station, antitrust claims for damages as a result of Canadian
natural gas purchases by one of the Company's wholly owned subsidiaries and two
claims that the Company 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 response to these questions, the FASB has
agreed to review the accounting for removal costs, including decommissioning.
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. The
Company does not believe that such changes, if required, would have an adverse
effect on its results of operations due to its current ability to recover
decommissioning costs through rates.
20
<PAGE> 10
Pacific Gas and Electric Company
STATEMENT OF CONSOLIDATED INCOME
<TABLE>
<CAPTION>
Year Ended December 31,
- ----------------------------------------
(in thousands, except per share amounts) 1994 1993 1992
<S> <C> <C> <C>
OPERATING REVENUES
Electric $ 8,027,976 $ 7,866,043 $ 7,747,492
Gas 2,419,375 2,716,365 2,548,596
----------- ----------- -----------
Total operating revenues 10,447,351 10,582,408 10,296,088
----------- ----------- -----------
OPERATING EXPENSES
Cost of electric energy 2,561,778 2,250,209 2,416,554
Cost of gas 574,894 939,572 907,945
Distribution 229,640 226,975 219,082
Transmission 293,995 319,022 339,099
Customer accounts and services 433,603 403,560 421,990
Maintenance 456,889 442,939 484,751
Depreciation and decommissioning 1,397,470 1,315,524 1,221,490
Administrative and general 973,302 1,041,453 927,316
Workforce reduction costs 249,097 190,200 -
Income taxes 924,620 1,006,774 906,845
Property and other taxes 296,911 297,495 295,164
Other 421,793 385,755 322,411
----------- ----------- -----------
Total operating expenses 8,813,992 8,819,478 8,462,647
----------- ----------- -----------
OPERATING INCOME 1,633,359 1,762,930 1,833,441
----------- ----------- -----------
OTHER INCOME AND (INCOME DEDUCTIONS)
Interest income 108,092 85,642 87,244
Allowance for equity funds used during
construction 19,046 41,531 39,368
Other--net (8,344) (53,524) (3,006)
----------- ----------- -----------
Total other income and (income deductions) 118,794 73,649 123,606
----------- ----------- -----------
INCOME BEFORE INTEREST EXPENSE 1,752,153 1,836,579 1,957,047
----------- ----------- -----------
INTEREST EXPENSE
Interest on long-term debt 651,912 731,610 739,279
Other interest charges 105,744 118,100 91,404
Allowance for borrowed funds used during
construction (12,953) (78,626) (44,217)
----------- ----------- -----------
Total interest expense 744,703 771,084 786,466
----------- ----------- -----------
NET INCOME 1,007,450 1,065,495 1,170,581
Preferred dividend requirement 57,603 63,812 78,887
----------- ----------- -----------
EARNINGS AVAILABLE FOR COMMON STOCK $ 949,847 $ 1,001,683 $ 1,091,694
=========== =========== ===========
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING 429,846 430,625 422,714
EARNINGS PER COMMON SHARE $2.21 $2.33 $2.58
DIVIDENDS DECLARED PER COMMON SHARE $1.96 $1.88 $1.76
</TABLE>
The accompanying Notes to Consolidated Financial Statements are an integral
part of this statement.
21
<PAGE> 11
Pacific Gas and Electric Company
CONSOLIDATED BALANCE SHEET
<TABLE>
<CAPTION>
December 31,
----------------------------
(in thousands) 1994 1993
<S> <C> <C>
ASSETS
PLANT IN SERVICE
Electric
Nonnuclear $ 17,045,247 $ 16,633,772
Diablo Canyon 6,647,162 6,518,413
Gas 7,447,879 7,146,741
------------ ------------
Total plant in service (at original cost) 31,140,288 30,298,926
Accumulated depreciation and decommissioning (12,269,377) (11,235,519)
------------ ------------
Net plant in service 18,870,911 19,063,407
------------ ------------
CONSTRUCTION WORK IN PROGRESS 527,867 620,187
OTHER NONCURRENT ASSETS
Oil and gas properties 437,352 573,523
Nuclear decommissioning funds 616,637 536,544
Investment in nonregulated projects 761,355 304,223
Other assets 137,325 193,466
------------ ------------
Total other noncurrent assets 1,952,669 1,607,756
------------ ------------
CURRENT ASSETS
Cash and cash equivalents 136,900 61,066
Accounts receivable
Customers 1,413,185 1,264,907
Other 98,035 123,255
Allowance for uncollectible accounts (29,769) (23,647)
Regulatory balancing accounts receivable 1,345,669 992,477
Inventories
Materials and supplies 197,394 239,856
Gas stored underground 136,326 170,345
Fuel oil 67,707 109,615
Nuclear fuel 140,357 134,411
Prepayments 33,251 56,062
------------ ------------
Total current assets 3,539,055 3,128,347
------------ ------------
DEFERRED CHARGES
Income tax-related deferred charges 1,155,421 1,276,532
Diablo Canyon costs 401,110 419,775
Unamortized loss net of gain on reacquired debt 382,862 395,659
Workers' compensation and disability claims recoverable 247,209 192,203
Other 732,029 458,660
------------ ------------
Total deferred charges 2,918,631 2,742,829
------------ ------------
TOTAL ASSETS $ 27,809,133 $ 27,162,526
============ ============
</TABLE>
The accompanying Notes to Consolidated Financial Statements are an integral
part of this statement.
22
<PAGE> 12
Pacific Gas and Electric Company
CONSOLIDATED BALANCE SHEET
<TABLE>
<CAPTION>
December 31,
----------------------------
(in thousands) 1994 1993
<S> <C> <C>
CAPITALIZATION AND LIABILITIES
CAPITALIZATION
Common stock $ 2,151,213 $ 2,136,095
Additional paid-in capital 3,806,508 3,666,455
Reinvested earnings 2,677,304 2,643,487
----------- -----------
Total common stock equity 8,635,025 8,446,037
Preferred stock without mandatory redemption provisions 732,995 807,995
Preferred stock with mandatory redemption provisions 137,500 75,000
Long-term debt 8,675,091 9,292,100
----------- -----------
Total capitalization 18,180,611 18,621,132
----------- -----------
OTHER NONCURRENT LIABILITIES
Customer advances for construction 152,384 152,872
Workers' compensation and disability claims 221,200 157,000
Other 644,233 246,950
----------- -----------
Total other noncurrent liabilities 1,017,817 556,822
----------- -----------
CURRENT LIABILITIES
Short-term borrowings 524,685 764,163
Long-term debt 477,047 221,416
Accounts payable
Trade creditors 414,291 472,985
Other 337,726 389,065
Accrued taxes 436,467 303,575
Deferred income taxes 432,026 315,584
Interest payable 84,805 82,105
Dividends payable 210,903 203,923
Other 643,779 487,809
----------- -----------
Total current liabilities 3,561,729 3,240,625
----------- -----------
DEFERRED CREDITS
Deferred income taxes 3,902,645 3,978,950
Deferred investment tax credits 391,455 410,969
Noncurrent balancing account liabilities 226,844 112,533
Other 528,032 241,495
----------- -----------
Total deferred credits 5,048,976 4,743,947
----------- -----------
COMMITMENTS AND CONTINGENCIES
(Notes 2, 3, 12 and 13)
----------- -----------
TOTAL CAPITALIZATION AND LIABILITIES $27,809,133 $27,162,526
=========== ===========
</TABLE>
23
<PAGE> 13
Pacific Gas and Electric Company
STATEMENT OF CONSOLIDATED CASH FLOWS
<TABLE>
<CAPTION>
Year ended December 31,
----------------------------------------
(in thousands) 1994 1993 1992
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 1,007,450 $ 1,065,495 $ 1,170,581
Adjustments to reconcile net income to net cash
provided by operating activities
Depreciation and decommissioning 1,397,470 1,315,524 1,221,490
Amortization 49,671 135,808 121,795
Gain on sale of investment in Alberta Natural
Gas Company Ltd - - (48,722)
Deferred income taxes and investment tax
credits--net 15,312 319,198 164,457
Allowance for equity funds used during
construction (19,046) (41,531) (39,368)
Other deferred charges 32,740 (158,725) 8,147
Other noncurrent liabilities 301,842 50,279 31,374
Other deferred credits 105,262 110,145 73,259
Net effect of changes in operating assets
and liabilities
Accounts receivable (116,936) 64,790 39,922
Regulatory balancing accounts receivable (353,192) (218,553) (215,195)
Inventories 112,443 23,097 (7,161)
Accounts payable (110,033) (39,422) (102,559)
Accrued taxes 132,892 44,638 128,243
Other working capital 181,481 108,873 (36,117)
Other--net 210,331 13,184 49,891
----------- ----------- -----------
Net cash provided by operating activities 2,947,687 2,792,800 2,560,037
----------- ----------- -----------
CASH FLOWS FROM INVESTING ACTIVITIES
Construction expenditures (1,094,495) (1,763,024) (2,307,318)
Allowance for borrowed funds used during
construction (12,953) (78,626) (44,217)
Nonregulated expenditures (328,266) (234,221) (148,226)
Proceeds from sale of investment in Alberta
Natural Gas Company Ltd - - 97,251
Other--net (29,914) 9,992 82,352
---------- ----------- -----------
Net cash used by investing activities (1,465,628) (2,065,879) (2,320,158)
---------- ----------- -----------
CASH FLOWS FROM FINANCING ACTIVITIES
Common stock issued 274,269 264,489 296,653
Common stock repurchased (181,558) (257,780) (5,410)
Preferred stock issued 62,312 200,001 195,451
Preferred stock redeemed (83,275) (302,640) (276,806)
Long-term debt issued 60,907 4,584,548 1,676,513
Long-term debt matured or reacquired (436,673) (4,002,704) (1,409,337)
Short-term debt issued (redeemed)--net (239,478) (366,961) 121,213
Dividends paid (891,850) (857,515) (809,108)
Other--net 29,121 (24,885) (28,736)
---------- ----------- -----------
Net cash used by financing activities (1,406,225) (763,447) (239,567)
---------- ----------- -----------
NET CHANGE IN CASH AND CASH EQUIVALENTS 75,834 (36,526) 312
CASH AND CASH EQUIVALENTS AT JANUARY 1 61,066 97,592 97,280
---------- ----------- -----------
CASH AND CASH EQUIVALENTS AT DECEMBER 31 $ 136,900 $ 61,066 $ 97,592
========== =========== ===========
Supplemental disclosures of cash flow information
Cash paid for
Interest (net of amounts capitalized) $ 674,758 $ 642,712 $ 694,512
Income taxes 712,777 542,827 682,809
</TABLE>
The accompanying Notes to Consolidated Financial Statements are an integral
part of this statement.
24
<PAGE> 14
Pacific Gas and Electric Company
STATEMENT OF CONSOLIDATED COMMON STOCK EQUITY AND PREFERRED STOCK
<TABLE>
<CAPTION>
Preferred Preferred
Stock Stock
Total Without With
Additional Common Mandatory Mandatory
(dollars in thousands) Common Paid-in Reinvested Stock Redemption Redemption
Stock Capital Earnings Equity Provisions Provisions(1)
<S> <C> <C> <C> <C> <C> <C>
BALANCE DECEMBER 31, 1991 $2,087,859 $3,287,313 $2,306,152 $7,681,324 $ 894,897 $104,632
---------- ---------- ---------- ---------- --------- --------
Net income--1992 1,170,581 1,170,581
Common stock issued
(9,453,353 shares) 47,267 249,386 296,653
Common stock repurchased
(179,610 shares) (898) (2,450) (2,062) (5,410)
Preferred stock issued
(8,000,000 shares) (4,549) (4,549) 125,000 75,000
Preferred stock redeemed
(9,365,449 shares) (12,638) (14,940) (27,578) (229,106) (20,122)
Cash dividends declared
Preferred stock (81,393) (81,393)
Common stock (744,277) (744,277)
Other (2,214) (2,214)
---------- ---------- ---------- ---------- --------- --------
Net change 46,369 229,749 325,695 601,813 (104,106) 54,878
---------- ---------- ---------- ---------- --------- --------
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
========== ========== ========== ========== ========= ========
</TABLE>
(1) Includes current portion.
The accompanying Notes to Consolidated Financial Statements are an integral
part of this statement.
25
<PAGE> 15
Pacific Gas and Electric Company
STATEMENT OF CONSOLIDATED CAPITALIZATION
<TABLE>
<CAPTION>
December 31,
----------------------------
(dollars in thousands, except per share amounts) 1994 1993
<S> <C> <C>
COMMON STOCK EQUITY
Common stock, par value $5 per share
(authorized 800,000,000 shares, issued and
outstanding 430,242,687 and 427,219,205 $ 2,151,213 $ 2,136,095
Additional paid-in capital 3,806,508 3,666,455
Reinvested earnings 2,677,304 2,643,487
----------- -----------
Common stock equity 8,635,025 8,446,037
----------- -----------
PREFERRED STOCK
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 8.2%--23,534,958 and 26,534,958 shares outstanding 588,374 663,374
----------- -----------
Total preferred stock without mandatory redemption
provision 732,995 807,995
----------- -----------
Preferred stock with mandatory redemption provision
Par value $25 per share (1)
6.30%--2,500,000 and none outstanding 62,500 -
6.57%--3,000,000 shares outstanding 75,000 75,000
Par value $100 per share (authorized 10,000,000 shares) - -
----------- -----------
Total preferred stock with mandatory redemption
provision 137,500 75,000
----------- -----------
Preferred stock 870,495 882,995
----------- -----------
LONG-TERM DEBT
PG&E long-term debt
First and refunding mortgage bonds
Maturity Interest rates
1994-1999 4.25% to 6.875% 714,074 724,610
2000-2005 5.875% to 8.75% 1,658,749 1,739,649
2006-2012 6.25% to 8.875% 477,870 477,870
2013-2019 7.5% to 12.75% 136,030 140,900
2020-2026 5.85% to 9.30% 2,902,945 2,947,428
----------- -----------
Principal amounts outstanding 5,889,668 6,030,457
Unamortized discount net of premium (66,198) (71,817)
----------- -----------
Total mortgage bonds 5,823,470 5,958,640
Unsecured debentures, 10.81% to 12%, due 1994-2000 124,939 221,523
Pollution control loan agreements, variable rates,
due 2008-2016 925,000 925,000
Unsecured medium-term notes, 4.13% to 10.10% due 1994-2014 1,443,800 1,542,625
Unamortized discount related to unsecured medium-term notes (2,428) (3,459)
Other long-term debt 22,209 24,127
----------- -----------
Total PG&E long-term debt 8,336,990 8,668,456
Long-term debt of subsidiaries 815,148 845,060
----------- -----------
Total long-term debt of PG&E and subsidiaries 9,152,138 9,513,516
Less long-term debt--current portion 477,047 221,416
----------- -----------
Long-term debt 8,675,091 9,292,100
----------- -----------
TOTAL CAPITALIZATION $18,180,611 $18,621,132
=========== ===========
</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.
26
<PAGE> 16
Pacific Gas and Electric Company
SCHEDULE OF CONSOLIDATED SEGMENT INFORMATION
<TABLE>
<CAPTION>
Diversified
Operations Intersegment
(in thousands) Electric Gas (4) Eliminations Total
<S> <C> <C> <C> <C> <C>
1994
Operating revenues $ 8,006,157 $2,194,870 $ 246,324 $ - $10,447,351
Intersegment revenues (1) 12,852 85,341 1,695 (99,888) -
----------- ---------- ---------- --------- -----------
Total operating revenues $ 8,019,009 $2,280,211 $ 248,019 $ (99,888) $10,447,351
=========== ========== ========== ========= ===========
Depreciation and
decommissioning $ 982,859 $ 295,979 $ 118,632 $ - $ 1,397,470
Operating income before
income taxes (2) 2,213,518 381,078 (33,390) (3,227) 2,557,979
Construction
expenditures (3) 834,494 292,000 - - 1,126,494
Identifiable assets (3) $19,471,121 $6,433,984 $1,436,128 $ - $27,341,233
Corporate assets 467,900
-----------
Total assets at end of year $27,809,133
===========
1993
Operating revenues $ 7,866,043 $2,466,788 $ 249,577 $ - $10,582,408
Intersegment revenues (1) 15,369 223,443 5,079 (243,891) -
----------- ---------- ---------- --------- -----------
Total operating revenues $ 7,881,412 $2,690,231 $ 254,656 $(243,891) $10,582,408
=========== ========== ========== ========= ===========
Depreciation and
decommissioning $ 925,673 $ 251,490 $ 138,361 $ - $ 1,315,524
Operating income before
income taxes (2) 2,344,796 440,323 (7,375) (8,040) 2,769,704
Construction
expenditures (3) 929,065 954,116 - - 1,883,181
Identifiable assets (3) $19,125,555 $6,467,424 $1,053,027 $ - $26,646,006
Corporate assets 516,520
-----------
Total assets at end of year $27,162,526
===========
1992
Operating revenues $ 7,747,492 $2,342,202 $ 206,394 $ - $10,296,088
Intersegment revenues (1) 15,150 410,014 28,191 (453,355) -
----------- ---------- ---------- --------- -----------
Total operating revenues $ 7,762,642 $2,752,216 $ 234,585 $(453,355) $10,296,088
=========== ========== ========== ========= ===========
Depreciation and
decommissioning $ 856,124 $ 231,443 $ 133,923 $ - $ 1,221,490
Operating income before
income taxes (2) 2,308,828 441,612 (9,808) (346) 2,740,286
Construction
expenditures (3) 1,124,368 1,266,535 - - 2,390,903
Identifiable assets (3) $17,658,656 $5,068,213 $ 996,860 $ - $23,723,729
Corporate assets 464,430
-----------
Total assets at end of year $24,188,159
===========
</TABLE>
(1) Intersegment electric and gas revenues are accounted for at tariff rates
prescribed by the CPUC.
(2) Income taxes and general corporate expenses are allocated in accordance
with the FERC Uniform System of Accounts and requirements of the CPUC.
Operating income in the Statement of Consolidated Income is net of utility
income taxes.
(3) Includes an allocation of common plant in service and allowance for funds
used during construction.
(4) Includes the nonregulated operations of wholly owned subsidiaries, including
PG&E Enterprises, Mission Trail Insurance Ltd. (liability insurance),
Pacific Gas Properties Company (real estate development) and Pacific
Conservation Services Company (conservation loans).
The accompanying Notes to Consolidated Financial Statements are an integral
part of this statement.
27
<PAGE> 17
Pacific Gas and Electric Company
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1: Summary of Significant Accounting Policies
Regulation:
Pacific Gas and Electric Company (PG&E) is regulated by the California Public
Utilities Commission (CPUC) and the Federal Energy Regulatory Commission
(FERC). PG&E's consolidated financial statements reflect the ratemaking
policies of these commissions in conformity with generally accepted accounting
principles for rate-regulated enterprises. In the Notes to Consolidated
Financial Statements, regulated operations other than the Diablo Canyon Nuclear
Power Plant (Diablo Canyon) are referred to as the utility.
Principles of Consolidation:
The consolidated financial statements include PG&E and its wholly owned and
majority-owned subsidiaries (collectively, the Company). All significant
intercompany transactions have been eliminated.
Major subsidiaries, all of which are wholly owned, are: Pacific Gas
Transmission Company (PGT)--transports natural gas from the U.S./Canadian
border to the California border; Alberta and Southern Gas Co. Ltd. (A&S)--
prior to November 1, 1993, bought gas in Canada and arranged its transport to
the U.S. border (see Note 3 for discussion of the restructuring of A&S's
operations); Pacific Energy Fuels Company--finances the purchase of nuclear
fuel through issuance of its commercial paper; PG&E Enterprises (Enterprises)--
the parent company for nonregulated subsidiaries, including DALEN Resources
Corp. (DALEN), formerly PG&E Resources Company, which engages in exploration,
development and production of oil and natural gas, and PG&E Generating Company
which through a joint venture (U.S. Generating) develops, builds, owns and
operates independent power projects.
Alberta Natural Gas Company Ltd (ANG), a 49.98% owned affiliate of PGT which
transports natural gas, was sold in June 1992. Prior to the sale of ANG, the
Company's investment in ANG was accounted for by the equity method of
accounting.
Revenues:
Revenues are recorded primarily for delivery of gas and electric energy to
customers. These revenues give rise to receivables from a diversified base of
customers including residential, commercial and industrial customers primarily
in Northern and Central California.
The CPUC has established mechanisms known as balancing accounts which help
stabilize the Company'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 cost of debt and equity funds used to
finance the construction of new facilities. Financing costs of capital
additions for Diablo Canyon, the California portion of the PGT-PG&E Pipeline
Expansion Project (Pipeline Expansion), and other nonregulated projects are
calculated under Statement of Financial Accounting Standards (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 the Company's nuclear power facilities
is recovered in base rates through an annual allowance. For the years ended
December 31, 1994, 1993 and 1992, the amount recovered in rates for
decommissioning costs was $54 million each year. The estimated total obligation
for nuclear decommissioning costs is approximately $1.1 billion in 1994 dollars
(or $4.5 billion in future dollars); this obligation is being recognized
ratably over the facilities' lives. 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 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. The average annualized escalation rate and the
assumed return on qualified trust assets used to calculate the decommissioning
obligation and annual expense are approximately 5.5 percent and 5.25 percent
(6.25 percent on
28
<PAGE> 18
nonqualified trust assets), respectively. (See Note 8 for
further discussion of nuclear decommissioning funds.)
As required by federal law, the U.S. Department of Energy (DOE) is
responsible for the future storage and disposal of spent nuclear fuel. No
permanent storage site has been identified and the DOE has indicated that the
storage site will not be available until after 2010. The Company pays a
one-tenth of one cent fee on each nuclear kilowatthour (kWh) sold to fund DOE
storage and disposal activities.
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. Investment tax credits are deferred and amortized to income
over the life of the related property.
Effective January 1, 1993, the Company adopted SFAS No. 109, "Accounting for
Income Taxes," which established new financial accounting standards for income
taxes. SFAS No. 109 prohibits net-of-tax accounting, requires that deferred tax
liabilities and assets be adjusted for enacted changes in the income tax rates
and requires the use of the liability method of accounting for income taxes.
Under the liability method, the deferred tax liability represents the tax
effect of temporary differences between the financial statement and income tax
bases of assets and liabilities at current income tax rates.
The effect of the adoption of SFAS No. 109, as of January 1, 1993, was an
increase of $1.8 billion in consolidated liabilities as a result of recording
additional deferred taxes; consolidated assets also increased $1.8 billion,
consisting of a $1.5 billion increase in deferred charges (income tax-related
deferred charges and Diablo Canyon costs) and a $300 million increase in net
plant in service. These adjustments relate to temporary differences, which
prior to adoption of SFAS No. 109 were not recorded as deferred taxes,
consistent with the ratemaking process. Due to regulatory treatment, the
adoption of SFAS No. 109 did not have a significant impact on the Company's
results of operations.
Debt Premium, Discount and Related Expenses:
Long-term debt premium, discount and related expenses are amortized over the
life of each issue. Gains and losses on reacquired debt allocated to the
utility are amortized over the remaining original lives of the debt reacquired,
consistent with ratemaking; gains and losses on debt allocated to Diablo Canyon
and the California portion of the Pipeline Expansion are recognized in income,
and if material as an extraordinary item, at the time such debt is reacquired.
Occasionally, the Company uses interest rate swap agreements and foreign
currency contracts to hedge fluctuations in interest rates and foreign currency
exchange rates. The Company defers any gains or losses on these transactions
and records interest expense adjusted for the effects of the agreements.
Oil and Gas Properties:
DALEN uses the successful-efforts method of accounting for oil and gas
properties.
Inventories:
Nuclear fuel inventory is stated at the lower of average cost or market.
Amortization of 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.
Reclassifications:
Certain amounts in the prior years' consolidated financial statements have been
reclassified to conform to the 1994 presentation.
Note 2: COMPETITION AND REGULATION
In April 1994, the CPUC issued an order instituting a rulemaking and an
investigation (OIR/OII) on electric industry restructuring. The proposal, which
is subject to comment and modification, involves two major changes in electric
industry regulation in California.
The first would move electric utilities from traditional ratemaking to
performance-based ratemaking. The second would unbundle electric services and
provide electric utility retail customers with the option to choose from a
range of electric generation providers, including utilities (direct access).
Direct access would be phased in over a six-year period beginning in 1996.
Utilities would still be obligated to provide transmission and distribution
services to all customers.
To ensure an orderly transition that maintains the financial integrity of
the utilities, the CPUC proposed that uneconomic costs of utility generating
assets be recovered through a "competition transition charge" (CTC). However,
the OIR/OII did not specify which costs might be recovered through such a
transition charge or how such a charge would be allocated to and collected from
customers.
In June 1994, the Company filed its initial comments on the CPUC's proposal.
The Company's response proposed an implementation schedule for direct access
beginning in
29
<PAGE> 19
1996, with direct access service available to all customers by
2008. For direct access customers, the Company proposed that it be given the
pricing flexibility to compete and sell unbundled electric power while assuming
the market risk of competitive pricing.
In November 1994, the Company filed testimony with the CPUC on its plan for
recovering uneconomic assets and obligations which would result from the
restructuring of the electric industry as proposed by the CPUC. The Company's
testimony, among other things, identifies and defines the costs proposed to be
included in the CTC, provides preliminary estimates of the transition costs and
discusses options for allocating and recovering those costs. Based on market
prices of $.048 and $.032 per kWh, the Company estimated that its uneconomic
generating assets and obligations are approximately $3 billion and $11 billion,
respectively, resulting from the restructuring as proposed by the CPUC. The
Company identified three categories of uneconomic assets: utility-owned
generation assets and power purchase commitments, power purchase obligations
relating to Qualifying Facilities (QFs), and generation-related regulatory
assets. The estimates of uneconomic assets were determined by comparing future
revenue requirements of generation assets and power purchase obligations, over
a twenty-year and thirty-year period, respectively, with revenues computed at
assumed market prices. Diablo Canyon was included in the revenue requirement
calculation using the proposed pricing modification to the Diablo Canyon
settlement. (See Note 4.) The revenue requirement for Diablo Canyon and all
Company-owned generation assets included a return on investment. The actual
amount of uneconomic assets and obligations will depend on the final regulation
and the actual market price of electricity.
Under the Company's proposal for a longer phase-in period to direct access,
the Company would not seek recovery of the transition costs associated with its
own generation assets and power purchase commitments, except for commitments to
purchase power from QFs. Based on this assumption and the market price
assumptions referred to above, the uneconomic assets and obligations are
approximately $3 billion and $5 billion, respectively. If the CPUC adopts a
shorter phase-in period, the Company indicated that it would seek recovery of
all uneconomic assets and obligations resulting from the restructuring through
the CTC.
In December 1994, the CPUC issued an interim decision in the OIR/OII. The
decision sets a schedule under which the CPUC will propose a policy decision in
March 1995, with a final policy decision to be effective no earlier than
September 1995. The CPUC's proposed policy statement will be subject to
hearings and state legislative review before it can be implemented. The CPUC
also established a public working group to comment on unbundling and transition
cost recovery, social programs and resource procurement, under several
different models for restructuring which include direct access and a supply
pool for use by wholesale and/or retail purchasers of electricity.
Financial Impact of the Electric Industry Restructuring Proposal:
Based on the regulatory framework in which it operates, the Company currently
accounts for the economic effects of regulation in accordance with the
provisions of SFAS No. 71, "Accounting for the Effects of Certain Types of
Regulation." As a result of applying the provisions of SFAS No. 71, the Company
has accumulated approximately $3.7 billion of regulatory assets, including
balancing accounts, at December 31, 1994.
In the event that recovery of specific costs through rates becomes unlikely
or uncertain for all or a portion of the Company's utility operations, whether
resulting from the expanding effects of competition or specific regulatory
actions, it could cause the Company to write off applicable portions of its
regulatory assets.
If the OIR/OII is adopted as proposed, or the Company determines that future
electric generation rates will no longer be based on cost-of-service, the
Company will discontinue application of SFAS No. 71 for the electric generation
portion of its operations. The Company continues to evaluate the current
regulatory and competitive environment to determine whether and when such a
discontinuance would be appropriate. If such discontinuance should occur, the
Company would write off all applicable generation-related regulatory assets to
the extent that transition cost recovery is not assured. The regulatory assets
attributable to electric generation, excluding balancing accounts of
approximately $700 million which are expected to be recovered in the near term,
were approximately $1.6 billion at December 31, 1994. This amount could vary
depending on the allocation methods used.
The final CPUC determination of uneconomic costs and the method of recovery
could adversely affect the Company's returns on its investments in electric
generation assets. If future electric generation revenues are insufficient to
recover the Company's investments and QF obligations, the Company would
recognize a loss.
The final determination of the financial impact will depend on the form of
regulation, including transition mechanisms, if any, adopted by the CPUC and
the groups of customers affected. Currently, the Company is unable to predict
the ultimate outcome of the electric industry restructuring or predict whether
such outcome will have a significant impact on its financial position or
results of operations.
30
<PAGE> 20
Note 3: Natural Gas Matters
Regulatory Restructuring:
Beginning August 1, 1993, PG&E implemented the CPUC's capacity brokering
program which requires PG&E to make available for brokering all interstate gas
pipeline capacity which is not held for its residential and smaller commercial
(core) customers, and industrial and large commercial customers who choose
bundled gas services (core subscription customers). PG&E's industrial and large
commercial (noncore) customers, producers, aggregators, marketers and the
Company's electric department can bid for such capacity.
In addition, beginning November 1, 1993, PGT implemented the FERC's Order No.
636, which requires interstate pipelines to restructure their services. This
order unbundled sales, transportation and storage services, instituted capacity
release programs and provided for recovery of transition costs related to the
restructuring of services.
The Company's compliance with these regulatory changes allowed more of the
Company's noncore customers to arrange for the purchase and transportation of
their own gas supplies. As a result, the Company's gas purchase requirements
and related need for firm transportation capacity for its gas purchases
decreased, contributing to the Company's need to restructure its gas supply
arrangements.
Decontracting Plan:
Until November 1993, PG&E purchased Canadian natural gas from PGT which in turn
purchased such gas from A&S. A&S had commitments to purchase natural gas from
approximately 190 Canadian gas producers under various long-term contracts,
most of which extended through 2005. As a result of the regulatory
restructuring discussed above, A&S, PGT, PG&E and approximately 190 Canadian
gas producers entered into agreements (collectively, the Decontracting Plan)
which terminated A&S's contracts with these Canadian gas producers effective
November 1, 1993.
Under the Decontracting Plan, producers released A&S, PGT and PG&E from any
claims they may have had that resulted from the termination of the former
arrangements as well as any prior claims related to these contracts. The total
amount of settlement payments paid to producers was approximately $210 million.
As part of the overall decontracting process, A&S's operations have been
significantly reduced. A&S permanently assigned significant portions of its
commitments for transportation capacity with NOVA Corporation of Alberta (NOVA)
through October 2001 and ANG through October 2005 to third parties. In
addition, A&S assigned approximately 600 million cubic feet per day (MMcf/d) of
capacity on each of these pipelines to PG&E for use in the servicing of PG&E's
core and core subscription customers. With the permanent assignments of its
capacity made through the end of 1994, A&S holds remaining capacity of
approximately 300 MMcf/d on each of the pipelines with total annual demand
charges of approximately $15 million for which it is continuing its efforts to
assign or broker. A&S believes it will be able to permanently assign
substantially all of its remaining capacity by the end of 1995. To the extent
others do not take this capacity, A&S will remain obligated to pay for the
related demand charges.
The FERC approved a transition cost recovery mechanism for PGT under which
most costs incurred to restructure, reform or terminate the sales arrangements
between A&S and PGT and the 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 arising out of the former contracts, are treated as transition
costs. Twenty-five percent of the transition costs was absorbed by PGT.
Twenty-five percent of the transition costs was recovered by PGT through direct
bills (substantially all to PG&E as PGT's principal customer). The final fifty
percent of the transition costs is being 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.
Financial Impact of Decontracting Plan:
The Company incurred transition costs of $228 million in 1993, consisting of
settlement payments made to producers in connection with the implementation of
the Decontracting Plan and amounts incurred by A&S in reducing certain
administrative and general functions resulting from the restructuring. Of these
costs, the Company deferred $143 million for future rate recovery. In addition,
the Company recorded a charge of $31 million in 1993 related to A&S's remaining
commitments for Canadian transportation capacity. Accordingly, the Company
expensed $93 million in 1993 and a total of $23 million in prior years.
Transportation Commitments:
The Company 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 the Company will pay each year may change due to changes in tariff
rates and may be offset to the extent the Company can broker or permanently
assign any unused capacity. In addition to demand charges, the Company is
required to pay transportation charges for actual quantities shipped. The
Company's total demand and transportation charges paid under these agreements
(excluding agreements with PGT) were approximately $225 million in 1994, $280
million in 1993 and $300 million in 1992.
31
<PAGE> 21
The following table summarizes the approximate capacity held by the Company
on various pipelines and the related annual demand charges as of December 31,
1994:
<TABLE>
<CAPTION>
Total
Firm Capacity Annual Demand
Pipeline Held Charges Contract
Company (MMcf/d) (in millions) Expiration
- ------------------------- ------------- ------------- ----------
<S> <C> <C> <C>
El Paso 1,140 $130 December 1997
Transwestern 200 $ 30 March 2007
NOVA 870 $ 25 October 2001
ANG 890 $ 15 October 2005
</TABLE>
Regulatory changes have resulted in a decrease in the Company's need for
firm transportation capacity for its own gas purchases. PG&E holds
approximately 600 MMcf/d of firm capacity on each of the pipelines owned by El
Paso Natural Gas Company (El Paso), NOVA and ANG, and 150 MMcf/d on the
pipeline owned by Transwestern Pipeline Company (Transwestern) to service its
core and core subscription customers. In addition, PG&E holds for its electric
department approximately 50 MMcf/d on Transwestern. The Company is continuing
its efforts to broker or assign any remaining unused capacity including certain
amounts of that held for its core and core subscription customers when such
capacity is not being used.
Based on the current demand for Canadian pipeline capacity, the Company
believes it will be able to broker or assign substantially all of its unused
capacity on NOVA and ANG; however, due to lower demand for Southwest pipeline
capacity, the Company cannot predict the volume or price of the capacity on El
Paso and Transwestern that will be brokered or assigned. Substantially all
demand charges incurred by the Company for pipeline capacity, including charges
for capacity that is not brokered or brokered at a discount, are eligible for
rate recovery subject to a reasonableness review.
The Division of Ratepayer Advocates (DRA), a consumer advocacy branch of the
CPUC staff, and others have challenged recovery of all demand charges for the
Company's Transwestern capacity and of certain other demand charges for
capacity not brokered or brokered at a discount. In November 1994, the CPUC
approved an interim increase in gas rates, subject to refund, designed to
collect approximately one-half of the demand charges for unbrokered or
discounted El Paso and PGT capacity. The decision set hearings on the issue,
and acknowledged that significant reasonable costs continue to accrue. The
Company believes that the ultimate resolution of these matters will not have a
significant adverse impact on its financial position or results of operations.
Gas Reasonableness Proceedings:
Recovery of energy costs through the Company'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.
In March 1994, the CPUC issued decisions covering the years 1988 through
1990, ordering disallowances of $90 million of gas costs, plus accrued interest
of approximately $25 million through 1993 for the Company's Canadian gas
procurement activities, and $8 million for gas inventory operations. The
Company has filed a lawsuit in a federal district court challenging the CPUC
decision on Canadian gas costs.
The CPUC decision on the Company's Canadian gas procurement activities found
that the Company could have saved its customers money if it had bargained more
aggressively with its then-existing Canadian suppliers or bought lower-priced
gas from other Canadian sources. The CPUC concluded that it was appropriate for
the Company to take a substantial portion of its Canadian gas (up to 700
MMcf/d) at the actual price charged under its then-existing Canadian gas supply
contracts, but that the Company could have met the remainder of its Canadian
gas requirement with lower-priced gas, either under those same contracts or
with purchases from other Canadian natural gas sources.
A number of other reasonableness issues related to the Company'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 recommended disallowances of $142 million and a penalty of $50
million and indicated that it was considering additional recommendations for
pending issues. The Company and the DRA have signed settlement agreements to
resolve most of these issues for a $68 million disallowance.
Significant issues covered by the settlement agreements include (1) the
Company's purchases of Canadian, Southwest and California gas for its electric
department in 1991 and 1992 and its core customers from 1991 through May 1994;
(2) the investigation by the DRA of A&S and proposed investigation of ANG for
the period 1988 through May 1994; (3) the effects of Canadian gas prices on
amounts paid by the Company for Northwest power purchases for 1988 through 1992
and power from QFs and geothermal producers for 1991 and 1992; (4) the
Company's gas storage operations for 1991 and 1992; (5) the Company's
Southwest gas procurement activities for 1988 through 1990; and (6) Canadian
gas restructuring transition costs billed to PG&E by PGT.
Agreements with the DRA do not constitute a CPUC decision and are subject to
modification by the CPUC in its final decisions.
32
<PAGE> 22
Financial Impact of Reasonableness Proceedings:
The Company accrued approximately $135 million and $61 million in 1994 and
1993, respectively, for gas reasonableness matters including the CPUC decisions
for the years 1988 through 1990 and issues covered by the settlement
agreements. The Company believes the ultimate outcome of these matters will not
have a significant impact on its financial position or results of operations.
Note 4: Diablo Canyon
Rate Case Settlement:
The 1988 Diablo Canyon rate case settlement (Diablo Canyon settlement) bases
revenues primarily on the amount of electricity generated by the plant, rather
than on traditional cost-based ratemaking. In approving the settlement, the
CPUC explicitly affirmed that Diablo Canyon costs and operations should no
longer be subject to CPUC reasonableness reviews.
The Diablo Canyon settlement provides that only certain Diablo Canyon costs
be recovered through base rates over the term of the Diablo Canyon settlement,
including a full return on such costs. The related revenues to recover these
costs are included in Diablo Canyon operating revenues for reporting purposes.
Other than these and decommissioning costs, Diablo Canyon no longer meets the
criteria for application of SFAS No. 71. Consequently, application of this
statement was discontinued for Diablo Canyon effective July 1988.
Pricing:
In December 1994, the Company, the DRA, the California Attorney
General and several other parties representing energy consumers agreed to
modify the pricing provisions of the Diablo Canyon settlement. The
modification, which is subject to CPUC approval, calls for a reduction in the
price paid for electricity generated by Diablo Canyon over the next five years.
Under the Diablo Canyon settlement, the price per kWh of electricity
generated by Diablo Canyon consists of a fixed and an escalating component. The
total prices for 1994, 1993 and 1992 were 11.89 cents, 11.16 cents and 10.34
cents per kWh, respectively. Under the proposed modification, the price for
power produced by Diablo Canyon would be reduced from the current level as
shown in the following table. Under the proposed pricing, at full operating
power each Diablo Canyon unit would contribute approximately $2.9 million in
revenues per day in 1995.
<TABLE>
<CAPTION>
Diablo Canyon Price (cents) per kWh
-----------------------------------
1995 1996 1997 1998 1999
<S> <C> <C> <C> <C> <C>
Original Settlement Price* 12.15 12.42 12.70 12.98 13.28
Proposed Price 11.00 10.50 10.00 9.50 9.00
</TABLE>
- ----------------
* assumes 3.5% inflation
After December 31, 1999, the escalating portion of the Diablo Canyon price
would increase using the same formula specified in the original Diablo Canyon
settlement. The proposed modification provides the Company with the right to
reduce the price below the amount specified.
The parties to the proposed modification have agreed that the difference
between the Company's revenue requirement under the original Diablo Canyon
settlement prices and the proposed prices would be applied to the energy cost
balancing account until the undercollection in that account is fully amortized.
Financial Information:
Selected financial information for Diablo Canyon is shown below:
<TABLE>
<CAPTION>
Year ended December 31,
---------------------------
(in millions) 1994 1993 1992
<S> <C> <C> <C>
Operating revenues $1,870 $1,933 $1,781
Operating income 618 708 663
Net income 461 496 443
</TABLE>
In determining operating results of Diablo Canyon, operating revenues were
specifically identified pursuant to the Diablo Canyon settlement. The majority
of operating expenses were also specifically identified, including income tax
expense. Administrative and general expense, principally labor costs, is
allocated based on a study of labor costs. Interest is charged to Diablo Canyon
based on an allocation of corporate debt.
Note 5: Preferred Stock
Nonredeemable preferred stock ($25 par value) consists of 5%, 5.5% and 6%
series, which have rights to annual dividends per share of $1.25, $1.375 and
$1.50, respectively.
Redeemable preferred stock without mandatory redemption provisions (4.36
percent to 8.2 percent, $25 par value) is subject to redemption at the
Company's option, in whole or in part, if the Company pays the specified
redemption price plus accumulated and unpaid dividends through the redemption
date. Annual dividends and redemption prices per share range from $1.09 to
$2.05, and from $25.75 to $28.125, respectively.
The 6.30% (due 2004 to 2009) and the 6.57% (due 2002 to 2007) series of
preferred stock are subject to mandatory redemption provisions and are entitled
to sinking funds providing for the retirement of stock outstanding, beginning
on January 31, 2004, and July 31, 2002, respectively, at par value plus
accumulated and unpaid dividends through the redemption date. In addition, the
6.30% and 6.57% series may be redeemed at the Company's option at par value
plus
33
<PAGE> 23
accumulated and unpaid dividends on or after January 31, 2004, and July
31, 2002, respectively. The estimated fair value of the Company's preferred
stock with mandatory redemption provisions at December 31, 1994 and 1993, was
approximately $117 million and $81 million, respectively, based primarily on
matrix pricing models.
During 1994, the Company issued $63 million of 6.30% redeemable preferred
stock and redeemed the 8.16% redeemable preferred stock with a par value of $75
million.
During 1993, the Company issued $125 million of 6 7/8% redeemable preferred
stock and $75 million of 7.04% redeemable preferred stock. Proceeds were used
to finance a portion of the 1993 redemption of the Company's 9.00%, 9.30%,
9.48% and 10.17% redeemable preferred stock with an aggregate par value of $267
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 the Company, holders of the 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.
Note 6: Long-term Debt
Mortgage Bonds:
The Company's First and Refunding Mortgage Bonds are issued in series, and at
December 31, 1994, bear annual interest rates ranging from 4.25 percent to
12.75 percent and mature from 1995 to 2026. The Company had $5.9 billion and
$6.0 billion of mortgage bonds outstanding at December 31, 1994 and 1993,
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.
The Board of Directors (Board) may increase the amount authorized, subject to
CPUC approval. The indenture requires that net earnings excluding depreciation
and interest be equal to or greater than 1.75 times the annual interest charges
on the Company's mortgage bonds outstanding. All real properties and
substantially all personal properties of PG&E are subject to the lien of the
indenture.
The Company 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. Bonds of any
series, with certain exceptions, may be used to satisfy this requirement. In
addition, holders of series 84D bonds maturing in 2017 have an option to
redeem their bonds in 1995.
In conjunction with the Company's focus on reducing the levels of
higher-cost debt, the Company redeemed or repurchased $80 million and $3,536
million of higher-cost mortgage bonds in 1994 and 1993, respectively. Interest
rates on the bonds redeemed or repurchased ranged from 7.50 percent to 12.75
percent. In January 1995, the Board authorized the Company to redeem or
repurchase up to $153 million of mortgage bonds.
Included in the total of outstanding mortgage bonds are First and Refunding
Mortgage Bonds issued by the Company 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), who
arranged these financings, and are in addition to the Pollution Control Loan
Agreements discussed below. At December 31, 1994 and 1993, the Company 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 the Company's mortgage
bonds (described above), the Company had loans totaling $925 million at
December 31, 1994 and 1993, from the CPCFA to finance air and water pollution
control and sewage and solid waste disposal facilities. 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
the Company's option. Average annual interest rates on these loans for 1994
ranged from 2.79 percent to 2.98 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.
Medium-term Notes:
The Company had $1,444 million of unsecured medium-term notes outstanding at
December 31, 1994 with interest rates ranging from 4.13 percent to 9.90 percent
and maturities from 1995 to 2014. At December 31, 1994, the Company has
remaining $85 million on a previous authorization to repurchase medium-term
notes. Holders of Series B medium-term notes maturing in 2004 have an option to
redeem their notes in 1995.
34
<PAGE> 24
Long-term Debt of Subsidiaries:
PGT obtained long-term debt financing from a consortium of banks pursuant to a
loan agreement dated April 30, 1993. Under the loan agreement, PGT borrowed
$673 million to finance the pipeline expansion and its existing pipeline
system. The debt is initially guaranteed by PG&E. The weighted average rate of
interest on this loan during 1994 was 6.4 percent.
The interest rate on the PGT debt (which ranged from 4.0 percent to 8.1
percent in 1994) is a floating rate subject to periodic determination in
accordance with the terms of the loan agreement and may vary depending on the
nature and the length of the borrowings, but is generally tied to the banks'
base rate, domestic certificate of deposit rates, or the applicable London
Interbank Offered Rates (LIBOR) for maturities ranging from one to twelve
months. In 1994, PGT executed a series of interest rate swap transactions
which converted $639 million of the floating rate debt to a fixed rate through
July 31, 1999. The interest rate on the remaining debt outstanding, which is
due in 1995, was fixed by utilizing options available to PGT under the loan
agreement.
At December 31, 1994, PGT had outstanding ten interest rate swap agreements
with commercial banks with a total notional principal amount of $639 million.
These swap agreements effectively change PGT's interest rate on its floating
rate debt to a fixed rate of 8.4 percent. The interest rate swap agreements
mature in July 1999. At December 31, 1994, the fair market value of these swap
agreements represented an unrealized gain of $25.7 million.
DALEN has a two-year revolving loan agreement expiring February 1997 which
provides for maximum borrowings of $200 million at a variable interest rate.
The revolving loan may be extended annually by consent of the banks and may be
converted to a five-year term loan at DALEN's option. At December 31, 1994,
approximately $115 million was outstanding at an effective interest rate of
approximately 7 percent. The loan is secured by DALEN's oil and gas
investments.
Repayment Schedule:
At December 31, 1994, the Company's combined aggregate amount of maturing
long-term debt and sinking fund requirements, for the years 1995 through 1999,
are $477 million, $373 million, $369 million, $715 million and $317 million,
respectively.
Fair Value:
The estimated fair value of the Company's total long-term debt of $9.2 billion
and $9.5 billion at December 31, 1994 and 1993, respectively, was approximately
$8.6 billion (including the $25.7 million unrealized gain attributable to the
PGT interest rate swap agreements) and $9.9 billion, respectively. The
estimated fair value of long-term debt was determined based on quoted market
prices, where available. Where quoted market prices were not available, the
estimated fair value was determined using other valuation techniques (e.g.,
matrix pricing models or the present value of future cash flows).
Note 7: Short-term Borrowings
Short-term borrowings consist of commercial paper with a weighted average
interest rate of 6.18 percent at December 31, 1994. The usual maturity for
commercial paper is one to ninety days. Commercial paper outstanding at
December 31, 1994 and 1993, was $525 million and $764 million, respectively.
The carrying amount of short-term borrowings approximates fair value.
The Company has a $1 billion revolving credit facility with various banks to
support the sale of commercial paper and for other corporate purposes. There
were no borrowings under this facility in 1994, 1993 or 1992. This credit
facility expires in November 1999; however, it may be extended annually for
additional one-year periods upon mutual agreement between the Company 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 the Company'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 the Company'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 1994 from the sale of securities held as
available-for-sale were approximately $1 billion. During 1994, the gross
realized gains and losses on sales of securities held as available-for-sale
were $9.9 million and $11.9 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.
35
<PAGE> 25
The following table provides a summary of amortized cost and fair value by
major security type:
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------------------------
(in thousands) December 31, 1994
- ------------------------------------------------------------------------------------------------
Gross Gross
unrealized unrealized
Amortized holding holding Fair
cost gains losses value
--------- ---------- ---------- ---------
<S> <C> <C> <C> <C>
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 46,398 24 (275) 46,147
-------- ------- -------- --------
Total investments in securities $616,762 $19,868 $(19,993) $616,637
======== ======= ======== ========
</TABLE>
Investments in debt securities maturing within ten years totaled $293
million, and investments in debt securities with maturities in excess of ten
years totaled $114 million.
At December 31, 1993, the cost and estimated fair value of the
decommissioning funds was $537 million and $576 million, respectively.
Note 9: Employee Benefit Plans
Retirement Plan:
The Company provides a noncontributory defined benefit pension plan covering
substantially all employees. The retirement benefits are based on years of
service and the employee's base salary. The Company's funding policy is to
contribute each year not more than the maximum amount deductible for federal
income tax purposes and not less than the minimum contribution required under
the Employee Retirement Income Security Act of 1974.
At December 31, 1994, plan assets exceeded the projected benefit obligation
by $517 million. The plan's funded status was:
<TABLE>
<CAPTION>
December 31,
-------------------------
(in thousands) 1994 1993
<S> <C> <C>
Actuarial present value of benefit obligations
Vested benefits $(3,079,045) $(3,203,408)
Nonvested benefits ( 131,489) (154,349)
----------- -----------
Accumulated benefit obligation (3,210,534) (3,357,757)
Effect of projected future compensation increases ( 441,951) (577,926)
----------- -----------
Projected benefit obligation (3,652,485) (3,935,683)
Plan assets at market value 4,169,516 4,376,110
----------- -----------
Plan assets in excess of projected benefit obligation 517,031 440,427
Unrecognized prior service cost 93,425 117,312
Unrecognized net gain (908,485) (759,690)
Unrecognized net transition obligation 108,800 120,253
----------- -----------
Accrued pension liability $ (189,229) $ (81,698)
=========== ===========
</TABLE>
Plan assets consist substantially of common stocks and fixed-income
securities. The unrecognized prior service cost is amortized over approximately
16 years. The unrecognized net 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.
Assumptions used to calculate the projected benefit obligation to determine
the plan's funded status were:
<TABLE>
<CAPTION>
December 31,
----------------------
1994 1993
<S> <C> <C>
Weighted average discount rate 8% 7%
Average rate of projected future compensation increases 5% 5%
</TABLE>
The cost of this plan is charged to expense and to plant in service through
construction work in progress. Net pension cost, using the projected unit
credit actuarial cost method, was:
<TABLE>
<CAPTION>
Year ended December 31,
----------------------------------
(in thousands) 1994 1993 1992
<S> <C> <C> <C>
Service cost for benefits earned $ 109,132 $ 129,166 $ 127,388
Interest cost 272,932 268,698 248,674
Actual loss (return) on plan assets 20,358 (511,526) (204,576)
Net amortization and deferral (412,547) 177,597 (78,560)
--------- --------- ---------
Net pension (income) cost $ (10,125) $ 63,935 $ 92,926
========= ========= =========
</TABLE>
The decrease in net pension cost in 1994 compared to 1993 was primarily due
to changes in the assumed rates of projected compensation increases and
turnover to better reflect actual and expected rates. The decrease in net
pension cost in 1993 compared to 1992 was primarily due to a change in the
expected long-term rate of return on plan assets to better reflect actual and
expected earnings on the funds invested.
The expected long-term rate of return on plan assets used to calculate
pension cost was nine percent for 1994 and 1993 and eight percent for 1992.
Net pension 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
pension cost. In 1994, the plan experienced a negative rather
36
<PAGE> 26
than an expected positive investment return on plan assets, due to weak
performance in domestic equities and bonds. In 1993, actual return on plan
assets exceeded expected return whereas, in 1992, actual return on plan
assets was less than expected.
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 contribution approach.
Savings Fund Plan:
The Company sponsors a defined contribution pension plan to which employees
with at least one year of service may make contributions. Employees 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 Company contributions at specified
rates. The cost of Company contributions was charged to expense and to plant in
service through construction work in progress and totaled $35 million, $36
million and $35 million for 1994, 1993 and 1992, respectively.
Long-term Incentive Program:
The Company 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 the Company's 1986 Stock Option Plan.
A total of 14.5 million shares of common stock have been authorized for
award under the Program and the 1986 Stock Option Plan. Costs associated with
the Program, which have not been significant, are not recoverable in rates.
At December 31, 1994, stock options on 2,496,356 shares, granted at option
prices ranging from $16.75 to $34.25, were outstanding. During 1994, 597,000
options were granted at an option price of $34.25, which was the market price
per share on the date of grant.
Outstanding stock options expire ten years and one day after the date of
grant and become exercisable on a cumulative basis at one-third each year
commencing two years from the date of grant. Stock options also become
exercisable within certain time limitations upon the optionee's termination due
to retirement, disability or death, and upon certain changes in control of the
Company.
In 1994, 1993 and 1992, stock options on 52,143, 174,387 and 157,446 shares,
respectively, were exercised at option prices ranging from $24.75 to $32.13,
$16.75 to $33.13 and $16.75 to $26.63, respectively. At December 31, 1994,
stock options on 940,076 shares were exercisable.
Postretirement Benefits Other Than Pensions:
The Company provides a contributory defined benefit medical plan for retired
employees and their eligible dependents and a noncontributory 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 the Company's retirees.
In 1993, the Company implemented a plan change that will limit the amount it
will contribute toward postretirement medical benefits. This limitation will
take effect for all retirees beginning in 2001.
The Company's funding policy for the medical and life insurance benefits is
to contribute each year the amount provided for in rates. Life insurance
benefits which are not funded are provided through an insurance company at a
cost based on total current claims paid plus administrative fees. The cost of
these plans is charged to expense and to plant in service through construction
work in progress.
Effective January 1, 1993, the Company adopted SFAS No. 106, "Employers'
Accounting for Postretirement Benefits Other Than Pensions," which requires
accrual of the expected cost of these benefits during the employees' years of
service. The assumptions and calculations involved in determining the accrual
closely parallel pension accounting requirements. The Company previously
recognized these costs as benefits were paid and funded, which was consistent
with ratemaking.
In December 1992, the CPUC issued a decision on the ratemaking treatment for
these benefits in 1993 and beyond. The decision authorized recovery of these
benefits, within certain guidelines, at a level equal to the lesser of the
annual SFAS No. 106 cost, based on amortization of the transition obligation
over 20 years, or the amount which can be contributed annually on a
tax-deductible basis to appropriate trusts. Due to this regulatory treatment,
adoption of SFAS No. 106 did not have a significant impact on the Company's
financial position or results of operations.
37
<PAGE> 27
At December 31, 1994, the accumulated postretirement benefit obligation
exceeded plan assets by $427 million, principally due to recent adoption of
SFAS No. 106. The medical and life insurance plans' funded status was:
<TABLE>
<CAPTION>
(in thousands) December 31,
-------------------------------
1994 1993
<S> <C> <C>
Accumulated postretirement benefit obligation
Retirees $(497,889) $(384,706)
Other fully eligible participants (104,865) (148,018)
Other active plan participants (219,639) (365,786)
--------- ---------
Total accumulated postretirement benefit obligation (822,393) (898,510)
Plan assets at market value 394,939 345,938
--------- ---------
Accumulated postretirement benefit obligation
in excess of plan assets (427,454) (552,572)
Unrecognized prior service cost 25,377 -
Unrecognized net (gain) loss (115,249) 21,481
Unrecognized transition obligation 462,082 543,939
--------- ---------
(Accrued) prepaid postretirement benefit liability $ (55,244) $ 12,848
========= =========
</TABLE>
The unrecognized prior service cost in 1994 reflects a plan amendment which
provides an increase in benefits to certain retirees. It is amortized over
approximately 18 years.
Plan assets consist substantially of common stocks and fixed-income
securities. In accordance with SFAS No. 106, the Company elected to amortize
the actuarially-determined transition obligation over 20 years beginning in
1993. The plan change implemented in 1993 that will limit the Company's
contributions toward postretirement medical benefits reduced the accumulated
postretirement benefit obligation at July 1, 1993 by approximately $450
million.
The assumptions used to calculate the benefit obligations included a
weighted average discount rate of eight percent for 1994 and seven percent for
1993, and an average rate of projected future compensation increases of five
percent for 1994 and 1993. The assumed health care cost trend rate for 1995 is
approximately 11 percent, grading down to an ultimate rate in 2005 of
approximately six 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, 1994, by
approximately $110 million and the 1994 aggregate service and interest costs by
approximately $13 million.
Net postretirement medical and life insurance cost, using the projected unit
credit actuarial cost method, was:
<TABLE>
<CAPTION>
Year ended December 31,
---------------------------
(in thousands) 1994 1993
<S> <C> <C>
Service cost for benefits earned $ 23,617 $ 38,496
Interest cost 64,872 73,502
Actual return on plan assets (1,232) (23,999)
Amortization of unrecognized prior service cost 1,711 -
Amortization of transition obligation 28,913 39,620
Net amortization and deferral (29,804) (3,390)
-------- --------
Net postretirement benefit cost $ 88,077 $124,229
======== ========
</TABLE>
The decrease in net postretirement benefit cost in 1994 compared to 1993 was
primarily due to the plan change implemented July 1, 1993 that will limit the
Company's contributions toward postretirement medical benefits.
The expected long-term rate of return on plan assets used to calculate
postretirement medical and life insurance benefit costs was nine percent for
1994 and 1993.
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 1994 and 1993, actual
return on plan assets was less than expected return.
For 1992, the cost of postretirement medical and life insurance benefits was
based on benefits paid and funded and totaled $98 million.
Workforce Reductions:
The effects of workforce reductions announced by the Company in 1994 and 1993
are reflected in the pension and postretirement benefits funded status tables
above and the costs are discussed in Note 10.
Postemployment Benefits:
Effective January 1, 1994, the Company adopted SFAS No. 112, "Employers'
Accounting for Postemployment Benefits," which requires employers to adopt
accrual accounting for benefits provided to former or inactive employees and
their beneficiaries and covered dependents, after employment but before
retirement. For the Company, such benefits consist primarily of long-term
disability, workers' compensation, and continuation of medical and life
insurance coverage. Due to current regulatory treatment, adoption of SFAS No.
112 did not have a significant impact on the Company's financial position or
results of operations. Adoption of SFAS No. 112 resulted in an increase of
approximately $90 million in noncurrent liabilities and deferred charges as of
January 1, 1994.
38
<PAGE> 28
Note 10: Workforce Reductions
In 1994, the Company announced workforce reductions which when combined with
the 3,000 positions eliminated in 1993 will result in the elimination of
approximately 6,000 positions by the end of 1995. The majority of the
reductions have occurred through voluntary retirement incentives (VRI) for
employees 50 years of age with at least 15 years of service. Remaining
reductions will be accomplished by severances and attrition in 1995.
In December 1994, the Company expensed the total cost of the 1994 workforce
reductions of $249 million and recorded a corresponding liability for benefits
to be funded or paid. This amount consists of $136 million for additional
pension benefits and $52 million for other postretirement benefits extended in
connection with the VRI, and $61 million of estimated severance costs for
approximately 1,500 severances. Most of these severances will be in the
Customer Energy Services and Electric Supply business units, in functions that
the Company has determined to be not absolutely necessary for safe, reliable
and responsive service, including construction and certain staff and support
services. The Company does not plan to seek rate recovery for the cost of the
1994 workforce reductions as it did with the 1993 workforce reductions.
The total cost of the 1993 workforce reductions was $264 million, net of a
curtailment gain relating to pension benefits. 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, the Company expensed $190 million of workforce
reduction costs relating to electric operations. The amount relating to gas
operations was deferred for future rate recovery and is being amortized as
savings are realized. At December 31, 1994, $31 million remained to be
amortized.
The Company recorded the costs and savings incurred in connection with the
1993 workforce reductions in a memorandum account authorized by the CPUC, with
the recovery of such costs subject to a CPUC reasonableness review.
Note 11: Income Taxes
The current and deferred components of income tax expense were:
<TABLE>
<CAPTION>
Year ended December 31,
-----------------------------------
(in thousands) 1994 1993 1992
<S> <C> <C> <C>
Current
Federal $ 606,885 $ 417,558 $536,774
State 214,570 165,134 193,895
--------- ---------- --------
Total current 821,455 582,692 730,669
--------- ---------- --------
Deferred (substantially all federal)
Depreciation 174,600 207,690 165,944
Regulatory balancing accounts 96,881 77,515 85,210
Workforce reduction (102,975) 24,765 -
Gas reasonableness (47,952) (25,037) -
(Gain) loss on reacquired debt (6,374) 42,405 15,959
Other--net (79,523) 12,270 (78,783)
--------- ---------- --------
Total deferred 34,657 339,608 188,330
--------- ---------- --------
Investment tax credits--net (19,345) (20,410) (23,873)
--------- ---------- --------
Total income tax expense $ 836,767 $ 901,890 $895,126
========= ========== ========
Classification of income tax expense:
Included in operating expenses $ 924,620 $1,006,774 $906,845
Included in other--net (87,853) (104,884) (11,719)
--------- ---------- --------
Total income tax expense $ 836,767 $ 901,890 $895,126
========= ========== ========
</TABLE>
The significant components of net deferred income tax liabilities are as
follows:
<TABLE>
<CAPTION>
December 31,
------------------------------------
(in thousands) 1994 1993
- -----------------------------------------------------------------------------------------
<S> <C> <C>
Deferred income taxes assets:
Deferred income taxes--current $ 173,357 $ 160,177
Deferred income taxes--noncurrent 959,459 647,018
---------- ----------
Total deferred income tax assets 1,132,816 807,195
========== ==========
Deferred income tax liabilities:
Deferred income taxes--current
Regulatory balancing accounts 559,750 449,216
Other 45,633 26,545
---------- ----------
Total deferred income taxes--current 605,383 475,761
---------- ----------
Deferred income taxes-noncurrent
Plant in service 3,627,294 3,386,122
Income tax-related deferred charges (1) 474,242 523,953
Other 760,568 715,893
---------- ----------
Total deferred income taxes--noncurrent 4,862,104 4,625,968
---------- ----------
Total deferred income tax liabilities 5,467,487 5,101,729
========== ==========
Total net deferred income taxes $4,334,671 $4,294,534
========== ==========
Classification of net deferred income taxes:
Included in current liabilities $ 432,026 $ 315,584
Included in deferred credits 3,902,645 3,978,950
---------- ----------
Total net deferred income taxes $4,334,671 $4,294,534
========== ==========
</TABLE>
(1) Represents the portion of the deferred income tax liability related to the
revenues required to recover future income taxes.
39
<PAGE> 29
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,
-------------------------------
1994 1993 1992
<S> <C> <C> <C>
Federal statutory income tax rate 35.0% 35.0% 34.0%
Increase (decrease) in income tax rate
resulting from
State income tax (net of federal benefit) 8.3 6.5 6.7
Effect of regulatory treatment of
depreciation differences 3.7 4.5 5.0
Investment tax credits (1.1) (1.0) (1.2)
Other--net (.5) .8 (1.2)
---- ---- ----
Effective tax rate 45.4% 45.8% 43.3%
==== ==== ====
</TABLE>
Note 12: Commitments
Capital Projects:
Capital expenditures for 1995 are estimated to be approximately $1,544 million,
consisting of $1,212 million for utility expenditures, $47 million for Diablo
Canyon expenditures and $285 million for nonregulated expenditures. At December
31, 1994, Enterprises had firm commitments totaling $214 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 $100 million in 1995 and $114 million in 1996.
QFs:
Under the Public Utility Regulatory Policies Act of 1978, the Company 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. QFs must meet certain performance
obligations, depending on the contract, prior to receiving capacity payments.
The total cost of both energy and capacity payments to QFs is recoverable in
rates. The Company's contracts with QFs expire on various dates from 1995 to
2026. Under these contracts, the Company 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.
In 1994, the Company negotiated early termination or suspension of certain
QF contracts at a cost of $155 million to be paid over a six-year period
beginning in 1994. This amount was deferred and is expected to be recovered in
future rates.
QF deliveries in the aggregate account for approximately 21 percent of the
Company's 1994 electric energy requirements and no single contract accounted
for more than five percent of the Company's energy needs. QF deliveries in 1994
represented approximately 86 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,
-----------------------------
(in millions) 1994 1993 1992
<S> <C> <C> <C>
Kilowatthours received 21,699 21,242 21,173
Energy payments $ 1,196 $ 1,099 $ 1,084
Capacity payments $ 518 $ 503 $ 489
</TABLE>
Irrigation Districts and Water Agencies:
The Company 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, the Company must make specified
semi-annual minimum payments whether or not any energy is supplied, subject to
the provider's retention of the FERC's authorization. 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, 1994, the future minimum payments under
these contracts are $34 million for each of the years 1995 through 1999 and a
total of $451 million for periods thereafter. Total payments under these
contracts were $49 million, $45 million and $54 million in 1994, 1993 and 1992,
respectively.
Note 13: Contingencies
Helms Pumped Storage Plant (Helms):
Helms, a three-unit hydroelectric combined generating and pumped storage
facility, completion of which was delayed due to a water conduit rupture in
1982 and various start-up problems related to the plant's generators, became
commercially operable in 1984. As a result of the damage caused by the rupture
and the delay in the operational date, the Company incurred additional costs
which are currently excluded from rate base and lost revenues during the period
while the plant was under repair.
In October 1994, the Company signed a settlement with the DRA regarding the
recovery of Helms costs not currently in rate base and prior-year revenue
requirements related to these costs. The settlement provides for recovery of
substantially all of the remaining net unrecovered costs (after adjustment for
depreciation) and revenues. The settlement has been submitted to the CPUC for
approval.
40
<PAGE> 30
The Company cannot predict whether the settlement will be approved by the
CPUC. However, the Company does not believe the ultimate outcome of the matter
will have a significant impact on its financial position or results of
operations.
Nuclear Insurance:
The Company is a member of Nuclear Mutual Limited (NML) and Nuclear Electric
Insurance Limited (NEIL). Under these policies, if the nuclear plant of a
member utility is damaged or the member incurs costs beyond those covered by
insurance for business interruption due to a prolonged accidental outage, the
Company may be subject to maximum assessments of $28 million (property damage)
and $7 million (business interruption), in each case per policy period, in the
event losses exceed the resources of NML or NEIL.
The federal government has enacted laws that require all utilities with
nuclear generating facilities to share in payment for claims resulting from a
nuclear incident. The Price-Anderson Act limits industry liability for
third-party claims resulting from any nuclear incident 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 public liability claims
in excess of $200 million, the Company 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 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 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 the
Company 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 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,
1994, of $95 million for hazardous waste remediation costs. The costs may be as
much as $235 million if, among other things, the Company is held responsible
for cleanup at additional sites, 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.
The Company will seek recovery of prudently incurred hazardous waste
compliance and remediation costs through ratemaking procedures approved by the
CPUC. The Company believes the ultimate outcome of these matters will not have
a significant adverse impact on its financial position or results of
operations.
Legal Matters:
Stanislaus Litigation: In 1993, a lawsuit was filed on behalf of the County of
Stanislaus, California and a residential customer of the Company and
purportedly as a class action on behalf of all natural gas customers of the
Company during the period of February 1988 through October 1993. The lawsuit
alleged that the purchase of natural gas in Canada by A&S was accomplished in
violation of various antitrust laws resulting in increased prices of natural
gas for PG&E's customers. Damages to the class members were estimated as
potentially exceeding $800 million. The complaint indicated that the damages
to the class could include over $150 million paid by the Company to terminate
the contracts with the Canadian gas producers in November 1993.
In August 1994, a federal district court granted the Company's motion to
dismiss the federal and state antitrust claims and the state unfair practices
claims against the Company and PGT. The court also granted the plaintiffs'
motion seeking class certification.
In September 1994, the plaintiffs filed an amended complaint in which A&S
has been added as a defendant. The amended complaint restates the claims in the
original complaint and alleges that the defendants, through anticompetitive
practices, precluded certain customers of the Company access to alternative
sources of gas in Canada over the PGT pipeline. A new motion to dismiss was
filed by the Company in early November 1994. The Company believes that the
ultimate outcome of this matter will not have a significant adverse impact on
its financial position.
41
<PAGE> 31
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 the Company'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 the Company discharged chromium-contaminated
wastewater into unlined ponds, which led to chromium percolating into the
groundwater of surrounding property. The plaintiffs further allege that the
Company discharged the chromium into those ponds to avoid costly alternatives.
The Company 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, the Company 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 the Company against any additional losses the Company 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.
At December 31, 1994, the Company has a remaining reserve of $50 million
against any future potential liability in this case. The Company believes the
ultimate outcome of this matter will not have a significant adverse impact on
its financial position or results of operations.
County Franchise Fees Litigation: In March 1994, Santa Clara and Alameda
counties filed a class action suit in a state superior court against the
Company on behalf of themselves and 45 other counties in the Company's service
area. This lawsuit alleges that the Company underpaid franchise fees to the
counties for the right to use or occupy public streets or roads as a result of
incorrectly computing these payments. Should the counties prevail, the amount
of damages for alleged underpayments for the years 1987 through 1994 could be
as high as $145 million, including interest, at Decmeber 31, 1994. The Company
believes that the ultimate outcome of this matter will not have a significant
adverse impact on its financial position or results of operations.
City Franchise Fees Litigation: In May 1994, the City of Santa Cruz filed a
class action suit in a state superior court against the Company on behalf of
itself and 106 other cities in the Company's service area. The complaint
alleges that the Company has underpaid electric franchise fees to the cities by
calculating fees at different rates from other cities. Should the cities
prevail, the amount of damages for alleged underpayments for the years 1987
through 1994 could be as high as $137 million, including interest, at December
31, 1994. The Company believes that the ultimate outcome of this matter will
not have a significant adverse impact on its financial position or results of
operations.
42
<PAGE> 32
Pacific Gas and Electric Company
Quarterly Consolidated Financial Data (Unaudited)
Quarterly Financial Data:
Due to the seasonal nature of the utility business and the scheduled refueling
outages for Diablo Canyon, operating revenues, operating income and net income
are not generated evenly by quarter during the year.
In the first quarter of 1994, the Company 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 the Company's assessment
of open reasonableness issues. In the second quarter of 1994, the Company
increased its litigation reserves by $50 million. In the fourth quarter of
1994, the Company took a charge against earnings of $249 million related to
1994 workforce reductions.
In the second quarter of 1993, the Company took a charge against earnings of
$141 million related to the workforce reductions for management employees. In
the third quarter of 1993, the Company's earnings reflected charges of $144
million resulting from the Company's workforce reductions, termination of
Canadian gas contracts and an increase in the federal income tax rate. The
fourth quarter of 1993 reflected charges against earnings of $126 million for
Canadian gas costs incurred by the Company for 1988 through 1990 and for
commitments for gas transportation capacity.
The Company's common stock is traded on the New York, Pacific, London,
Amsterdam, Basel and Zurich stock exchanges. There were approximately 230,000
common shareholders of record at December 31, 1994. Dividends are paid on a
quarterly basis, and there are no significant restrictions on the present
ability of the Company to pay dividends.
<TABLE>
<CAPTION>
Quarter ended
----------------------------------------------------
(in thousands, except per share amounts) December 31 September 30 June 30 March 31
<S> <C> <C> <C> <C>
1994
Operating revenues $2,638,179 $2,855,221 $2,439,680 $2,514,271
Operating income 238,286 584,694 395,705 414,674
Net income 103,500 425,633 241,365 236,952
Earnings per common share (1) .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
1993
Operating revenues $2,707,171 $2,947,294 $2,464,125 $2,463,818
Operating income 428,914 525,981 387,707 420,328
Net income 208,382 356,099 245,350 255,664
Earnings per common share (1) .45 .79 .53 .56
Dividends declared per common share .47 .47 .47 .47
Common stock price per share
High 36.75 36.63 35.38 35.75
Low 33.50 33.13 31.75 31.75
</TABLE>
(1) Includes Diablo Canyon scheduled refueling outages which impacted earnings
per common share for all quarters in 1994 and for the first and second
quarters of 1993. In addition, Diablo Canyon experienced unscheduled
outages in the second quarter of 1994.
43
<PAGE> 33
Pacific Gas and Electric Company
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
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, 1994 and 1993, and
the related statements of consolidated income, cash flows, common stock equity
and preferred stock, and the schedule of consolidated segment information for
each of the three years in the period ended December 31, 1994. 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 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, 1994 and 1993, and the results of their
operations and cash flows for each of the three years in the period ended
December 31, 1994 in conformity with generally accepted accounting principles.
As discussed in Note 2 of Notes to Consolidated Financial Statements, in
1994, the California Public Utilities Commission (CPUC) issued a proposal to
restructure the electric industry in California which could significantly alter
the ratemaking applied to the Company. If this proposal is adopted or if
electric generation rates are no longer based on cost of service, the Company
would discontinue the application of Statement of Financial Accounting
Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of
Regulation" for a portion of its operations. The CPUC's proposal could also
impact the recovery of certain costs, including power purchase obligations and
investments in related electric generation assets. Currently, the Company is
unable to predict the ultimate outcome of the electric industry restructuring
or predict whether such outcome will have a significant impact on its financial
position or results of operations.
As explained in Notes 1 and 9 of Notes to Consolidated Financial Statements,
effective January 1, 1993, the Company changed its method of accounting for
postretirement benefits other than pensions and for income taxes.
ARTHUR ANDERSEN LLP
ARTHUR ANDERSEN LLP
San Francisco, California
February 6, 1995
44
<PAGE> 34
Pacific Gas and Electric Company
RESPONSIBILITY FOR FINANCIAL STATEMENTS
The responsibility for the integrity of the financial information included in
this report rests with management. Such information has been prepared in
accordance with generally accepted accounting principles appropriate in the
circumstances, and is 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 financial information. 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.
45
<PAGE> 1
Exhibit 23
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation
by reference of our reports dated February 6, 1995, included or incorporated by
reference in this Form 10-K, into the Company's previously filed registration
statements as follows: (1) Form S-3 Registration Statement File No. 33-7542
(relating to the Company's Common Stock Shelf Program); (2) Form S-3
Registration Statement File No. 33-54469 (relating to the Company's Dividend
Reinvestment Plan); (3) 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); (4) 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); (5) Form S-3
Registration Statement File No. 33-38334 (relating to 2,414,892 shares of the
Company's Common Stock); (6) Form S-8 Registration Statement File No. 33-50601
(relating to the Company's Savings Fund Plan for Employees); (7) Form S-8
Registration Statement File No. 33-23692 (relating to the Company's 1986 Stock
Option Plan); and (8) Form S-3 Registration Statement File No. 33-62488
(relating to 10,000,000 shares of the Company's Redeemable First Preferred
Stock).
ARTHUR ANDERSEN LLP
ARTHUR ANDERSEN LLP
San Francisco, California
March 27, 1995
<PAGE> 1
Exhibit 24.1
RESOLUTION OF THE
BOARD OF DIRECTORS OF
PACIFIC GAS AND ELECTRIC COMPANY
March 15, 1995
BE IT RESOLVED that each of LESLIE H. EVERETT, LINDA Y. H. CHENG,
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 President
and Chief Executive Officer, Vice President and Chief Financial Officer, and
Controller of this corporation the Form 10-K Annual Report for the year ended
December 31, 1994, 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 thereto with
regard to said Form 10-K Annual Report.
<PAGE> 2
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 15,
1995, 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
23 day of March, 1995.
KATHLEEN RUEGER
Kathleen Rueger
Assistant Corporate Secretary
PACIFIC GAS AND ELECTRIC COMPANY
CORPORATE SEAL
<PAGE> 1
Exhibit 24.2
POWER OF ATTORNEY
Each of the undersigned Directors of Pacific Gas and Electric Company
hereby constitutes and appoints LESLIE H. EVERETT, LINDA Y. H. CHENG, 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, 1994, 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 15th day of
March, 1995.
Richard A. Clarke David M. Lawrence
- ------------------------------ ------------------------------
Stanley T. Skinner Alan Seelenfreund
- ------------------------------ ------------------------------
Leslie L. Luttgens Barry Lawson Williams
- ------------------------------ ------------------------------
H.M. Conger Carl E. Reichardt
- ------------------------------ ------------------------------
William F. Miller John B. M. Place
- ------------------------------ ------------------------------
Mary S. Metz Richard B. Madden
- ------------------------------ ------------------------------
Melvin B. Lane George A. Maneatis
- ------------------------------ ------------------------------
John C. Sawhill
- ------------------------------ ------------------------------
William S. Davilla
- ------------------------------ ------------------------------
<PAGE> 2
POWER OF ATTORNEY
STANLEY T. SKINNER, the undersigned, President and Chief
Executive Officer and Director of Pacific Gas and Electric Company, hereby
constitutes and appoints LESLIE H. EVERETT, LINDA Y. H. CHENG, KATHLEEN RUEGER,
GARY P. ENCINAS or JULIE C. GAVIN his attorneys in fact with full power of
substitution to sign with the Securities and Exchange Commission in his
capacity as President and Chief Executive Officer and Director of said
corporation the Form 10-K Annual Report for the year ended December 31, 1994,
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 15th day
of March, 1995.
STANLEY T. SKINNER
------------------
STANLEY T. SKINNER
<PAGE> 3
POWER OF ATTORNEY
GORDON R. SMITH, the undersigned, Vice President and Chief Financial
Officer of Pacific Gas and Electric Company, hereby constitutes and appoints
LESLIE H. EVERETT, LINDA Y. H. CHENG, 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 Vice President
and Chief Financial Officer of said corporation the Form 10-K Annual Report for
the year ended December 31, 1994, 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 15th day of
March, 1995.
GORDON R. SMITH
---------------
GORDON R. SMITH
<PAGE> 4
POWER OF ATTORNEY
THOMAS C. LONG, the undersigned, Controller of Pacific Gas and
Electric Company, hereby constitutes and appoints LESLIE H. EVERETT, LINDA Y.
H. CHENG, 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 Controller of said corporation the Form
10-K Annual Report for the year ended December 31, 1994, 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 15th day
of March, 1995.
THOMAS C. LONG
--------------
THOMAS C. LONG
<PAGE> 1
Exhibit 99
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 the fiscal year ended December 31, 1994
A. Full titled 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> 2
The financial statements of the Savings Fund Plan Master Trust
and the Savings Fund Plan Parts I, II and III (Plans) as of December 31, 1994
and 1993, the related statements of net assets as of December 31, 1994 and 1993,
and changes in net assets of the Plans for the year ended December 31, 1994, and
the Savings Fund Plan Master Trust schedules of assets held for investment
purposes of as of December 31, 1994, and of reportable transactions for year
ended December 31, 1994 together with the report of Arthur Andersen LLP,
independent accountants, are presented herewith.
<PAGE> 3
[ARTHUR ANDERSEN LLP LOGO]
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,
1994 and 1993, and the related statement of changes in net assets for the year
ended December 31, 1994. 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.
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, 1994 and
1993, and the changes in net assets for the year ended December 31, 1994, in
conformity with generally accepted accounting principles.
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.
Our audits were made for 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, 1994, and reportable transactions for
the year ended December 31, 1994, 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.
ARTHUR ANDERSEN LLP
Arthur Andersen LLP
San Francisco, California,
March 10, 1995
<PAGE> 4
[ARTHUR ANDERSEN LLP LOGO]
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, 1994 and 1993, and the related statement of changes in net assets
available for benefits for the year ended December 31, 1994. 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, 1994 and 1993, and the changes in its net assets available for
benefits for the year ended December 31, 1994, in conformity with generally
accepted accounting principles.
ARTHUR ANDERSEN LLP
Arthur Andersen LLP
San Francisco, California,
March 10, 1995
<PAGE> 5
[ARTHUR ANDERSEN LLP LOGO]
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, 1994 and 1993, and the related statement of changes in net assets
available for benefits for the year ended December 31, 1994. 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, 1994 and 1993, and the changes in its net assets available for
benefits for the year ended December 31, 1994, in conformity with generally
accepted accounting principles.
ARTHUR ANDERSEN LLP
Arthur Andersen LLP
San Francisco, California,
March 10, 1995
<PAGE> 6
[ARTHUR ANDERSEN LLP LOGO]
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 III (the Plan) as
of December 31, 1994 and 1993, and the related statement of changes in net
assets available for benefits for the year ended December 31, 1994. 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 audit 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.
As further discussed in Note 1 to the financial statements, the Plan was
terminated in conjunction with the transfer of its remaining net assets to
related plans.
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, 1994 and 1993, and the changes in its net assets available for
benefits for the year ended December 31, 1994, in conformity with generally
accepted accounting principles.
ARTHUR ANDERSEN LLP
Arthur Andersen LLP
San Francisco, California,
March 10, 1995
<PAGE> 7
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, 1994 and 1993
Statement of Changes in Net Assets for the Year Ended December 31, 1994
Notes to Financial Statements - December 31, 1994
SCHEDULES
Schedule I: Item 27(a) - Schedule of Assets Held for Investment
Purposes - December 31, 1994
Schedule II: Item 27(d) - Schedule of Reportable Transactions for the
Year Ended December 31, 1994
<PAGE> 8
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
Stock Bond Equity Income
Fund Fund Fund Fund
------- ------ ------------ ----------
---------------------In Thousands-----------------
<S> <C> <C> <C> <C>
ASSETS
Investments, at fair value
Pacific Gas and Electric Company
common stock $1,131,413 $ - $ - $ -
United States Government securities - 4,616 553 -
Corporate stocks - preferred - - 1,048 -
Corporate stocks - common - - 340,032 -
Corporate debt instruments - - - 53,210
Insurance company general accounts - - - 151,704
Registered investment companies
Vanguard Bond Market Fund - - - -
Columbia Balanced Fund - - - -
Dreyfus Utility Stock Fund - - - -
Interest bearing accounts 163 12,254 60,228
---------- ------ -------- --------
Total Investments 1,131,576 4,616 353,887 265,142
---------- ------ -------- --------
Receivables
Dividends and interest 22,830 - 993 2,560
Other receivables - - 6,293 -
---------- ------ -------- --------
Total Receivables 22,830 - 7,286 2,560
---------- -------- --------
Total Assets 1,154,406 4,616 361,173 267,702
---------- ------ -------- --------
LIABILITIES 36 - 11,371 -
---------- ------ -------- --------
Total Liabilities 36 - 11,371 -
---------- -------- --------
NET ASSETS $1,154,370 $4,616 $349,802 $267,702
========== ====== ======== ========
</TABLE>
<TABLE>
<CAPTION>
Fund Information
----------------------------------------------------------------
Bond Stock and Utility
Index Bond Stock PAYSOP
Fund Fund Fund Fund Total
----- --------- ------- ------ -----
---------------------------In Thousands--------------------------
<S> <C> <C> <C> <C> <C>
ASSETS
Investments, at fair value
Pacific Gas and Electric Company
common stock $ - $ - $ - $ - $1,131,413
United States Government securities - - - - 5,169
Corporate stocks - preferred - - - - 1,048
Corporate stocks - common - - - - 340,032
Corporate debt instruments - - - - 53,210
Insurance company general accounts - - - - 151,704
Registered investment companies
Vanguard Bond Market Fund 23,632 - - - 23,632
Columbia Balanced Fund - 102,861 - - 102,861
Dreyfus Utility Stock Fund - - 45,458 - 45,458
Interest bearing accounts - - - - 72,645
------- -------- ------- ------- ----------
Total Investments 23,632 102,861 45,458 - 1,927,172
------- -------- ------- ------- ----------
Receivables
Dividends and interest 138 - 844 - 27,365
Other receivables - - - - 6,293
------- -------- ------- ------- ----------
Total Receivables 138 - 844 - 33,658
------- -------- ------- ------- ----------
Total Assets 23,770 102,861 46,302 - 1,960,830
------- -------- ------- ------- ----------
LIABILITIES - - - - 11,407
------- -------- ------- ------- ----------
Total Liabilities - - - - 11,407
------- -------- ------- ------- ----------
NET ASSETS $23,770 $102,861 $46,302 $ - $1,949,423
======= ======== ======= ======= ==========
</TABLE>
The accompanying Notes to Financial Statements are an integral part
of these statements.
1
<PAGE> 9
PACIFIC GAS AND ELECTRIC COMPANY
SAVINGS FUND PLAN MASTER TRUST
STATEMENT OF NET ASSETS
December 31, 1993
<TABLE>
<CAPTION>
Fund Information
--------------------------------------------------
United
Company States Diversified Guaranteed
Stock Bond Equity Income
Fund Fund Fund Fund
-------- ------- ------------ ----------
------------------In Thousands--------------------
<S> <C> <C> <C> <C>
ASSETS
Investments, at fair value
Pacific Gas and Electric Company
common stock $1,569,458 $ - $ - $ -
United States Government securities - 4,562 178 -
Corporate stocks - preferred - - 1,299 -
Corporate stocks - common - - 300,039 -
Corporate debt instruments - - - 41,099
Insurance company general accounts - - - 188,421
Registered investment companies
Vanguard Bond Market Fund - - - -
Columbia Balanced Fund - - - -
Dreyfus Utility Stock Fund - - - -
Interest bearing accounts 110 24 5,135 1,328
---------- ------ -------- --------
Total Investments 1,569,568 4,586 306,651 230,848
---------- ------ -------- --------
Receivables
Dividends and interest 21,132 - 767 2,821
Other receivables - - 1,168 -
---------- ------ -------- --------
Total Receivables 21,132 - 1,935 2,821
---------- ------ -------- --------
Total Assets 1,590,700 4,586 308,586 233,669
---------- ------ -------- --------
LIABILITIES - - 1,197 -
---------- ------ -------- --------
Total Liabilities - - 1,197 -
---------- ------ -------- --------
NET ASSETS $1,590,700 $4,586 $307,389 $233,669
========== ====== ======== ========
</TABLE>
<TABLE>
<CAPTION>
Fund Information
------------------------------------------------------------------
Bond Stock and Utility
Index Bond Stock PAYSOP
Fund Fund Fund Fund Total
------ ---------- ------- ------ -----
--------------------------In Thousands---------------------------
<S> <C> <C> <C> <C> <C>
ASSETS
Investments, at fair value
Pacific Gas and Electric Company
common stock $ - $ - $ - $10,116 $1,579,574
United States Government securities - - - - 4,740
Corporate stocks - preferred - - - - 1,299
Corporate stocks - common - - - - 300,039
Corporate debt instruments - - - - 41,099
Insurance company general accounts - - - - 188,421
Registered investment companies
Vanguard Bond Market Fund 28,740 - - - 28,740
Columbia Balanced Fund - 104,083 - - 104,083
Dreyfus Utility Stock Fund - - 75,336 - 75,336
Interest bearing accounts - - - - 6,597
------- -------- ------- ------- ----------
Total Investments 28,740 104,083 75,336 10,116 2,329,928
------- -------- ------- ------- ----------
Receivables
Dividends and interest - - - 136 24,856
Other receivables - - - - 1,168
------- -------- ------- ------- ----------
Total Receivables - - - 136 26,024
------- -------- ------- ------- ----------
Total Assets 28,740 104,083 75,336 10,252 2,355,952
------- -------- ------- ------- ----------
LIABILITIES - - - - 1,197
------- -------- ------- ------- ----------
Total Liabilities - - - - 1,197
------- -------- ------- ------- ----------
NET ASSETS $28,740 $104,083 $75,336 $10,252 $2,354,755
======= ======== ======= ======= ==========
</TABLE>
The accompanying Notes to Financial Statements are an integral part of
these statements.
2
<PAGE> 10
PACIFIC GAS AND ELECTRIC COMPANY
SAVINGS FUND PLAN MASTER TRUST
STATEMENT OF CHANGES IN NET ASSETS
For the Year Ended December 31, 1994
<TABLE>
<CAPTION>
Fund Information
----------------------------------------------------------------------
United
Company States Diversified Guaranteed Bond Stock and
Stock Bond Equity Income Index Bond
Fund Fund Fund Fund Fund Fund
---------- ------ ----------- ---------- -------- --------
------------------------------ In Thousands--------------------------
<S> <C> <C> <C> <C> <C> <C>
BALANCE, JANUARY 1, 1994 $1,590,700 $4,586 $307,389 $233,669 $28,740 $104,083
---------- ------ ------- ------- -------- --------
ADDITIONS
Participating plans contributions
Participant 52,679 - 23,489 5,749 1,282 6,458
Employer 24,393 - 4,421 1,102 350 1,689
---------- ------ ------- ------- -------- --------
Total participating plans contributions 77,072 - 27,910 6,851 1,632 8,147
---------- ------ ------- ------- -------- --------
Earnings from investments
Interest
Interest bearing accounts 56 - 397 478 - -
United States Government securities - 289 - - - -
Fixed income investments - - - 11,373 - -
---------- ------ ------- ------- -------- --------
Total interest 56 289 397 11,851 - -
Dividends - common stock 89,489 - 8,975 - - -
Registered investment company
dividends - - - - 1,725 -
Other income 5 - 25 50 - -
---------- ------ ------- ------- ------- -------
Total earnings
from investments 89,550 289 9,397 11,901 1,725 -
---------- ------ ------ ------- ------- -------
Gain (loss) on securities
Realized on sale or distribution 47,181 - 10,965 - (378) 1,337
Unrealized appreciation (depreciation)
in fair value of securities held (527,262) - (9,011) - (2,131) (1,277)
Gains (losses) on futures contracts (545)
Net appreciation (depreciation) in fair
value of assets held (480,081) - 1,409 - (2,509) 60
---------- ------ ------- ------- ------- -------
Total additions (reductions) (313,459) 289 38,716 18,752 848 8,207
---------- ------ ------- ------- ------- -------
<CAPTION>
Fund Information
-------------------------------
Utility
Stock PAYSOP
Fund Fund Total
------- ------- ---------
----------In Thousands---------
<S> <C> <C> <C>
BALANCE, JANUARY 1, 1994 $75,336 $10,252 $2,354,755
------- ------- ----------
ADDITIONS
Participating plans contributions
Participant 4,685 - 94,342
Employer 1,258 - 33,213
------- ------- ----------
Total participating plans contributions 5,943 - 127,555
------- ------- ----------
Earnings from investments
Interest
Interest bearing accounts - - 931
United States Government securities - - 289
Fixed income investments - - 11,373
------- ------- ----------
Total interest - - 12,593
Dividends - common stock - 426 98,890
Registered investment company
dividends 3,312 - 5,037
Other income - 2 82
------- ------- ----------
Total earnings
from investments 3,312 428 116,602
------- ------- ----------
Gain (loss) on securities
Realized on sale or distribution (4,656) 73 54,522
Unrealized appreciation (depreciation)
in fair value of securities held (8,424) (4,008) (552,113)
Gains (losses) on futures contracts (545)
Net appreciation (depreciation) in fair
value of assets held (13,080) (3,935) (498,136)
------- ------- ----------
Total additions (reductions) (3,825) (3,507) (253,979)
------- ------- ----------
</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, 1994
<TABLE>
<CAPTION>
Fund Information
---------------------------------------------------------------------
United
Company States Diversified Guaranteed Bond Stock and
Stock Bond Equity Income Index Bond
Fund Fund Fund Fund Fund Fund
--------- ------ ----------- ---------- ------- --------
------------------------In Thousands---------------------------------
<S> <C> <C> <C> <C> <C> <C>
DEDUCTIONS
Withdrawals paid to participating plans
for benefit payments $74,557 $235 $17,733 $ 43,562 $1,512 $8,558
Expenses 266 - 2 - - 519
---------- ------ -------- -------- ------- --------
Total deductions 74,823 235 17,735 43,562 1,512 9,077
---------- ------ -------- -------- ------- --------
TRANSFERS between investment funds (48,048) (24) 21,432 58,843 (4,306) (352)
---------- ------ -------- -------- ------- --------
CHANGE IN NET ASSETS (436,330) 30 42,413 34,033 (4,970) (1,222)
---------- ------ -------- -------- ------- --------
BALANCE, DECEMBER 31, 1994 $1,154,370 $4,616 $349,802 $267,702 $23,770 $102,861
========== ====== ======== ======== ======= ========
<CAPTION>
Fund Information
-------------------------------------
Utility
Stock PAYSOP
Fund Fund Total
------- ------ --------
--------------In Thousands-----------
<S> <C> <C> <C>
DEDUCTIONS $4,088 $314 $ 150,559
Withdrawals paid to participating plans 7 - 794
for benefit payments ------- ------- ----------
Expenses 4,095 314 151,353
------- ------- ----------
Total deductions (21,114) (6,431) -
------- ------- ----------
TRANSFERS between investment funds (29,034) (10,252) (405,332)
------- ------- ----------
CHANGE IN NET ASSETS $46,302 $ $1,949,423
======= ======= ==========
BALANCE, DECEMBER 31, 1994
</TABLE>
The accompanying Notes to Financial Statements are an integral part of these
statements.
4
<PAGE> 11
PACIFIC GAS AND ELECTRIC COMPANY
SAVINGS FUND PLAN MASTER TRUST
NOTES TO FINANCIAL STATEMENTS
December 31,1994
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
certain defined contribution retirement plans sponsored by Pacific Gas and
Electric Company (the Company). Pacific Service Employees Association also
participates in the Master Trust. The Master Trust is administered by Pacific
Gas and Electric Company's Employee Benefit Administrative Committee, and State
Street Bank and Trust Company is the trustee (the Trustee).
Interest income, dividends, investment fees, and the net appreciation
(depreciation) in the fair value of investments held by the Master Trust are
allocated to the individual participating plans each week 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.
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. 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.
Investments in the Guaranteed Income Fund are valued at cost which
approximates fair value. Generally, all other investments held by the Master
Trust are stated at fair value based on published market quotations.
NOTE 3: FEDERAL INCOME TAXES
The Internal Revenue Service 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.
5
<PAGE> 12
PACIFIC GAS AND ELECTRIC COMPANY
SAVINGS FUND PLAN MASTER TRUST
NOTES TO FINANCIAL STATEMENTS
December 31, 1994
NOTE 4: INVESTMENTS
The Trustee invests a significant portion of the contributions from the
participating plans in the common stock of the Company. Purchases of this
stock are 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. Investment management fees are netted
against the performance of the Stock and Bond Fund and Bond Index Fund, and are
paid by the Company in connection with 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 once each calendar
quarter. 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 participant's interest in the investment funds is measured in
"units". For investments in the common stock of the Company and in
United States Savings Bonds, a unit is a share of common stock and a
United States Savings Bond, respectively.
6
<PAGE> 13
PACIFIC GAS AND ELECTRIC COMPANY
SAVINGS FUND PLAN MASTER TRUST
NOTES TO FINANCIAL STATEMENTS
December 31, 1994
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 depreciation 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 assets held,
sold or distributed.
The net depreciation in the fair value of investments by major investment
category for the year ended December 31, 1994 is as follows:
<TABLE>
<CAPTION>
---In Thousands---
<S> <C>
Pacific Gas and Electric Company
Common Stock Fund $(480,081)
PAYSOP Fund (3,935)
DEF 1,409
BIF (2,509)
SBF 60
USF (13,080)
----------
Total depreciation $(498,136)
==========
</TABLE>
FINANCIAL INVESTMENTS WITH OFF-BALANCE SHEET RISK
The DEF fund investment manager routinely enters into Standard and Poor's
(S&P 500) futures contracts as a hedge against future price increases in S&P
stocks. At each balance sheet date, these contracts are marked to fair value,
and the resulting appreciation (depreciation) in the contracts' value is
recorded. As of December 31, 1994, there were 31 Future Buy S&P March 1995
contracts valued at approximately $7 million, and a decline of approximately
$545,000 in the value of the contracts was recorded. The collateral (included
in interest bearing accounts) with respect to these contracts consisted of a
$440,000 U.S. treasury bill which will mature on April 6, 1995 and a $120,000
U.S. treasury bill which matured on February 23, 1995.
7
<PAGE> 14
SAVINGS FUND PLAN
FOR EMPLOYEES OF PACIFIC GAS AND ELECTRIC COMPANY
ITEM 27a - SCHEDULE OF ASSETS HELD FOR INVESTMENT PURPOSES
December 31, 1994
<TABLE>
<CAPTION>
Number of
Shares or
U.S. Savings
Bonds Held at (e) Current
(a) (b) Name of Issuer and (c) Description Close of Period (d) Cost Value
------------------------------------------------- --------------- -------------- ---------------
------In Thousands------
<S> <C> <C> <C>
Pacific Gas and Electric Company
common stock funds
* Pacific Gas and Electric Company Stock Fund 46,416,948 $1,029,874 $1,131,413
Interest bearing accounts N/A 163 163
---------- ---------- ----------
Total Pacific Gas and Electric
Company common stock 46,416,948 $1,030,037 $1,131,576
========== ========== ==========
United States Bond Fund
United States Savings Bonds, Series E
(units of $18.75 cost and $25.00 maturity) 6,721 $126 $467
United States Savings Bonds, Series EE
(units of $25.00 cost and $50.00 maturity) 90,124 2,253 3,536
United States Savings Bonds, Series EE
(units of $50.00 cost and $100.00 maturity) 10,088 504 613
---------- ---------- ----------
Total United States Bond Fund 106,933 $2,883 $4,616
========== ========== ==========
DEF
Corporate stocks - common
AMR Corp. Del. 7,600 $ 448 $ 405
AT&T Corp. 184,300 8,728 9,261
Abbott Labs 137,900 3,790 4,499
Adobe Sys Inc. 3,100 60 92
Advanced Micro Devices Inc. 10,100 245 251
Aetna Life & Cas. Co. 11,900 532 561
Ahmanson H F & Co. 13,100 203 211
Air Prods & Chems. Inc. 7,300 309 326
Albermarle Corp. 10,100 135 140
Allegheny Ludlum Corp. 13,100 230 246
Allegheny Power Systems Inc. 14,000 338 305
Allied Signal Inc. 67,800 1,985 2,305
Allstate Corp. 46,600 1,126 1,101
Aluminum Co. America 25,500 1,636 2,209
Alza Corp. 11,800 395 212
Ambac Inc. 4,200 175 156
American Elec. Pwr. Inc. 20,000 645 657
American Gen. Corp. 15,700 435 444
American Home Products Corp. 44,700 2,807 2,805
American Intl. Group Inc. 39,900 3,045 3,910
Ameritech Corp. 64,900 1,732 2,620
Amoco Corp. 18,400 952 1,088
Amsouth Bancorporation 4,500 143 116
Anadarko Pete Corp. 9,000 348 347
Aon Corp. 7,500 247 240
Armstrong World Inds. Inc. 4,400 173 169
Ashland Oil Inc. 9,300 317 321
Atlantic Richfield Co. 19,000 1,953 1,933
Autodesk Incorporated 5,200 189 206
</TABLE>
8
<PAGE> 15
SAVINGS FUND PLAN
FOR EMPLOYEES OF PACIFIC GAS AND ELECTRIC COMPANY
ITEM 27a - SCHEDULE OF ASSETS HELD FOR INVESTMENT PURPOSES
December 31, 1994
<TABLE>
<CAPTION>
Number of
Shares or
U.S. Savings
Bonds Held at (e) Current
(a) (b) Name of Issuer and (c) Description Close of Period (d) Cost Value
------------------------------------------------- --------------- --------------- --------------
------In Thousands------
<S> <C> <C> <C>
Avnet Inc. 2,100 $ 91 $ 78
Avon Prods. Inc. 13,100 763 783
Baker Hughes Inc. 19,000 438 347
Baltimore Gas & Electric Co. 17,100 381 378
Banc One Corp. 46,600 1,456 1,182
Bank of Boston Corp. 9,800 228 254
BankAmerica Corp. 42,300 1,908 1,671
Bankers Tr. N.Y. Corp. 12,200 789 676
Barnett Bks. Inc. 11,600 488 445
Bausch & Lomb Inc. 11,400 480 386
Baxter Intl. Inc. 49,200 1,269 1,390
Bay Networks Inc. 12,200 450 360
Bear Stearns Cos. Inc. 13,400 280 206
Bell Atlantic Corp. 52,100 2,573 2,592
Bellsouth Corp. 59,300 3,146 3,210
Beneficial Corp. 3,200 116 125
Bethleham Stl. Corp. 23,100 422 416
Black & Decker Corporation 45,400 765 1,078
Bowater Inc. 100 2 3
Boyd Gaming Corp. 7,200 118 77
Brinker Intl. Inc. 15,100 329 274
Bristol Myers Squibb Co. 19,800 1,204 1,146
Browning Ferris Inds. Inc. 39,100 954 1,109
Burlington Northn. Inc. 9,800 532 472
CBS Inc. 14,600 689 809
CMS Energy Corp. 9,900 220 226
CPC Intl. Inc. 32,900 1,550 1,752
CSX Corp. 14,200 985 989
Campbell Soup Co. 32,000 1,310 1,412
Carnival Corp. 27,400 525 582
Carolina Pwr. & Lt. Co. 1,800 46 48
Caterpillar Inc. 50,200 1,318 2,767
Central & South West Corp. 21,700 472 491
Champion Intl. Corp. 13,800 370 504
Charming Shoppes Inc. 19,200 294 127
Chase Manhattan Corp. 21,500 577 739
Chemical Bkg. Corp. 27,600 1,103 990
Chemical Waste Mgmt. Inc. 1,700 33 16
Chevron Corp. 99,900 4,130 4,458
Chiron Corp. 4,900 323 394
Chrysler Corp. 16,300 693 799
Chubb Corp. 4,900 348 379
Cincinnati Milacron Inc. 1,100 25 26
Cinergy Corp. 10,100 250 236
Circus Circus Enterprises Inc. 20,400 709 474
Citicorp 84,900 1,885 3,513
Coca Cola Co. 168,000 6,755 8,652
Colgate Palmolive Co. 19,800 1,050 1,255
Coltec Inds. Inc. 10,400 210 178
Columbia/HCA Healthcare Corp. 68,800 2,842 2,511
Comcast Corp. 16,100 266 253
Comerica Inc. 13,200 397 322
</TABLE>
9
<PAGE> 16
SAVINGS FUND PLAN
FOR EMPLOYEES OF PACIFIC GAS AND ELECTRIC COMPANY
ITEM 27a - SCHEDULE OF ASSETS HELD FOR INVESTMENT PURPOSES
December 31, 1994
<TABLE>
<CAPTION>
Number of
Shares or
U.S. Savings
Bonds Held at (e) Current
(a) (b) Name of Issuer and (c) Description Close of Period (d) Cost Value
------------------------------------------------- --------------- --------------- -------------
-----------In Thousands--------
<S> <C> <C> <C>
Compaq Computer Corp. 31,300 $ 962 $1,236
Connor Peripherals Inc. 1,600 30 15
Conrail Inc. 3,900 183 197
Consolidated Edison Co. NY Inc. 1,900 47 49
Cooper Inds. Inc. 24,100 1,057 822
Cooper Tire & Rubber 8,800 214 208
Corestates Finl. Corp. 13,000 336 338
Cracker Barrel Old Ctry. Store 13,800 380 255
Crestar Finl. Corp. 2,200 101 83
Crown Cork & Seal Inc. 19,400 734 732
Cummins Engine Inc. 3,400 140 154
Dayton Hudson Corp. 23,400 1,370 1,656
Dean Witter Discover & Co. 18,700 620 633
Deere & Co. 12,200 531 808
Dell Computer Corp. 4,400 186 180
Delta Air Lines Inc. DE 5,300 306 268
Detroit Edison Co. 12,000 424 314
Dillard Dept Stores Inc. 15,300 591 409
Disney, Walt Co. 98,100 3,713 4,525
Dominion Res. Inc. VA 20,300 742 726
Donnelley R R & Sons Inc. 32,300 900 953
Dover Corp. 7,000 397 361
Dow Chemical Company 35,600 2,120 2,394
Du Pont E I De Nemours and Co. 95,800 4,629 5,389
Duke Power Co. 400 15 15
E Sys. Inc. 3,500 136 146
Eastman Kodak Co. 51,200 2,068 2,445
Eaton Corp. 9,200 357 455
El Paso Nat. Gas Co. 4,400 169 134
Electronic Arts 5,900 193 114
Emerson Elec. Co. 3,600 206 225
Enron Corp. 38,900 1,142 1,186
Entergy Corp. 27,700 877 606
Equifax Inc. 14,600 424 385
Ethyl Corp. 20,200 248 194
Exxon Corp. 109,300 6,139 6,640
FPL Group Inc. 20,500 621 720
Federal Home Ln. Mtg. Corp. 20,500 1,017 1,035
Federal Natl. Mtg. Assn. 39,800 2,853 2,900
Fifth Third Bancorp. 4,000 193 192
First Chicago Corp. 8,400 286 401
First Data Corp. 25,500 1,010 1,208
First Empire St. Corp. 200 30 27
First Fidelity Bancorp. New 4,900 211 220
First Tenn. Natl. Corp. 3,700 172 151
First Union Corp. 19,100 875 790
First USA Inc. 6,100 201 201
First VA Bks. Inc. 3,900 156 125
Firstar Corp. New 7,100 219 191
Fleet Finl. Group Inc. 13,900 416 452
Ford Motor Co. Del. 97,400 2,055 2,727
Forest Labs Inc. 5,500 255 256
</TABLE>
10
<PAGE> 17
SAVINGS FUND PLAN
FOR EMPLOYEES OF PACIFIC GAS AND ELECTRIC COMPANY
ITEM 27a - SCHEDULE OF ASSETS HELD FOR INVESTMENT PURPOSES
December 31, 1994
<TABLE>
<CAPTION>
Number of
Shares or
U.S. Savings
Bonds Held at (e) Current
(a) (b) Name of Issuer and (c) Description Close of Period (d) Cost Value
------------------------------------------------- --------------- --------------- ------------
---------In Thousands---------
<S> <C> <C> <C>
Freeport McMoran Copper & Gold 7,200 $ 176 $ 153
Fruit of the Loom Inc. 18,500 556 500
GTE Corp. 113,100 3,959 3,435
Gap Inc. 25,000 804 762
Gateway 2000 Inc. 7,400 166 160
General Dynamics Corp. 9,800 323 426
General Electric Co. 209,200 8,199 10,669
General Mills Inc. 29,200 1,877 1,664
General Mtrs. Corp. 98,500 3,787 4,162
General Mtrs. Corp. 30,800 1,005 1,186
General Pub. Utils. Corp. 13,100 352 344
General Signal Corp. 6,600 200 210
Gensia Inc. 5,700 152 24
George Gulf Corp. 600 16 23
Georgia Pacific Corp. 13,100 714 937
Gillette Co. 36,100 2,137 2,698
Golden West Finl. Corp. Del. 7,300 289 257
Goodyear Tire and Rubber 12,700 414 427
Grainger W W Inc. 8,800 483 508
Great Western Finl. Corp. 19,200 295 307
Harley Davidson Inc. 20,000 520 560
Harris Corp. Del. 1,800 76 77
Healthcare Compare Corp. 3,000 89 102
Health Mgmt. Assoc. 7,600 180 190
Hewlett Packard Co. 34,700 1,868 3,466
Home Depot Inc. 76,900 3,237 3,537
Honeywell Inc. 31,100 771 980
Household Intl. Corp. 8,800 242 327
Houston Inds. Inc. 15,100 514 538
Hubbell Inc. 1,100 60 59
Humana Inc. 30,900 601 699
Huntington Bancshares Inc. 14,200 301 245
ITT Corp. 31,700 1,930 2,809
Illinois Cent. Corp. 5,600 175 172
Illinova Corp. 4,400 90 96
Inco Ltd. 20,900 492 598
Ingersoll Rand Co. 3,700 119 117
Intel Corp. 44,400 2,412 2,836
International Business Machs. 78,700 4,030 5,784
International Game Technology 29,000 610 450
International Paper Company 30,100 1,373 2,269
Johnson & Johnson 33,500 1,433 1,834
Johnson Ctls. Inc. 8,100 386 397
KU Energy Corp. 300 8 8
Kellogg Co. 32,500 2,003 1,889
Keycorp New 26,300 840 657
Kimberly Clark Corp. 19,900 1,005 1,005
Knight Ridder Inc. 9,700 513 490
Lilly Eli & Co. 42,000 2,755 2,756
Limited Inc. 71,500 1,613 1,296
Lincoln Natl. Corp. IN 1,100 44 39
Linear Technology Corp. 3,300 107 163
</TABLE>
11
<PAGE> 18
SAVINGS FUND PLAN
FOR EMPLOYEES OF PACIFIC GAS AND ELECTRIC COMPANY
ITEM 27a - SCHEDULE OF ASSETS HELD FOR INVESTMENT PURPOSES
December 31, 1994
<TABLE>
<CAPTION>
Number of
Shares or
U.S. Savings
Bonds Held at (e) Current
(a) (b) Name of Issuer and (c) Description Close of Period (d) Cost Value
------------------------------------------------- --------------- --------------- --------------
------In Thousands------
<S> <C> <C> <C>
Liz Claiborne 20,500 $471 $349
Lockheed Corp. 9,800 511 712
Loral Corp. 13,000 334 492
Louisiana Pacific Corp. 14,700 478 401
MBIA Inc. 3,600 220 202
MCI Communications Corp. 74,600 1,443 1,371
Manor Care Inc. 9,000 221 246
Marshall & Ilsley Corp. 11,400 232 217
Martin Marietta Corp. New 15,000 473 666
Masco Corp. 61,400 1,610 1,389
May Dept. Stores Co. 30,000 1,178 1,012
McDonalds Corp. 132,100 3,974 3,864
McDonnell Douglas Corp. 2,900 184 412
Medtronic Inc. 16,400 534 912
Mellon Bk. Corp. 17,000 573 521
Melville Corporation 19,700 944 608
Mercantile Bancorporation Inc. 4,900 180 153
Mercantile Bankshares Corp. 100 2 2
Merck & Co. Inc. 179,800 6,217 6,855
Mercury Finl. Co. 13,500 210 176
Meridian Bancorp. Inc. 6,600 192 176
Merrill Lynch & Co. Inc. 11,700 427 418
Microsoft Corp. 65,300 2,901 3,991
Mirage Resorts Inc. 21,600 492 443
Mobil Corp. 60,800 4,741 5,122
Monsanto Co. 16,000 1,112 1,128
Motorola Inc. 62,600 3,032 3,623
NBD Bancorp. Inc. 9,200 265 252
NIPSCO Inds. Inc. 7,400 203 220
National Svc. Inds. Inc. 23,800 611 610
Nationsbank Corp. 30,900 1,450 1,394
New England Elec. Sys. 7,100 233 228
Niagara Mohawk Pwr. Corp. 12,100 181 172
Nine West Group Inc. 2,400 66 68
Noram Energy Corp. 15,500 150 83
Norfolk Southern Corp. 14,700 857 891
Northern Telecom Ltd. 30,100 1,095 1,005
Northern Trust Corp. 5,100 211 179
Northrop Grumman Corp. 300 9 13
Norwest Corp. 38,400 953 898
Novell Inc. 63,100 1,584 1,081
Nucor Corp. 18,400 1,169 1,021
Occidental Pete Corp. 48,100 904 926
Ogden Corp. 3,000 56 56
Oracle Sys. Corp. 36,200 582 1,597
Oryx Energy Co. 7,100 149 84
Owens Corning Fiberglass Corp. 17,600 582 563
PNC Bk. Corp. 49,300 972 1,041
PPG Inds. Inc. 28,200 870 1,047
Paccar Inc. 5,300 279 235
Pacific Telesis Group 48,100 1,432 1,371
Paine Webber Group Inc. 500 7 8
</TABLE>
12
<PAGE> 19
SAVINGS FUND PLAN
FOR EMPLOYEES OF PACIFIC GAS AND ELECTRIC COMPANY
ITEM 27a - SCHEDULE OF ASSETS HELD FOR INVESTMENT PURPOSES
December 31, 1994
<TABLE>
<CAPTION>
Number of
Shares or
U.S. Savings
Bonds Held at (e) Current
(a) (b) Name of Issuer and (c) Description Close of Period (d) Cost Value
------------------------------------------------- --------------- --------------- --------------
----------In Thousands--------
<S> <C> <C> <C>
Panhandle Eastern Corp. 22,900 $ 479 $ 452
Parker Hannifin Corp. 7,100 297 323
Penney, J.C. Inc. 3,200 136 143
Pepsico Inc. 133,400 5,075 4,836
Pfizer Inc. 47,400 2,224 3,662
Phelps Dodge Corp. 16,300 762 1,009
Philip Morris Cos. Inc. 117,900 8,554 6,779
Pinnacle West Cap Corp. 9,800 202 194
Portland Gen. Corp. 400 7 8
Potomac Elec. Pwr. Co. 12,600 279 232
Praxair Inc. 22,100 354 453
Premier Indl. Corp. 9,100 233 215
Proctor & Gamble Company 98,100 3,187 6,082
Providian Corp. 10,700 350 330
Public Svc. Enterprise Group 26,600 670 705
Ralston Pruina Co. 13,800 611 616
Raytheon Co. 10,800 679 690
Republic N.Y. Corp. 5,800 261 262
Reynolds Metals Co. 15,800 771 774
Rockwell Intl. Corp. 17,600 670 629
Royal Dutch Pete Co. 70,700 4,669 7,600
SCECorp 48,300 997 706
SPS Transaction Svcs. Inc. 6,200 204 163
Safeco Corp. 6,900 329 359
St. Paul Cos. Inc. 35,800 867 1,602
Schlumberger Ltd. 37,400 2,148 1,884
Schwab, Charles Corp. 6,400 177 223
Scott Paper Co. 9,700 601 671
Service Corp. Intl. 20,500 417 569
Shamut National Corp. 13,900 241 228
Silicon Graphics Inc. 12,600 177 389
Sonat Inc. 55,900 1,144 1,565
Southern Co. 68,800 1,464 1,376
Southtrust Corp. 8,200 152 148
Southwest Airlines Co. 16,700 559 280
Southwestern Bell Corp. 71,700 2,801 2,895
Sprint Corp. 38,700 1,079 1,069
Standard Fed. Bk. Troy, Mich. 200 5 5
State Street Boston Corp. 4,700 151 135
Sun Microsystems Inc. 15,100 444 536
Sundstrand Corp. 1,900 75 86
Superior Inds. Intl. Inc. 1,600 51 42
Sybase Inc. 6,100 173 317
Synovus Finl. Corp. 4,200 79 76
TJX Cos. Inc. New 13,700 318 214
TRW Inc. 19,500 1,280 1,287
Tele Communications Inc. New 85,400 1,750 1,857
Tenneco Inc. 52,600 2,028 2,235
Texaco Inc. 38,900 2,531 2,329
Texas Instrs. Inc. 9,700 670 726
Texas Utils. Co. 46,400 1,556 1,485
Time Warner Inc. 16,900 584 594
</TABLE>
13
<PAGE> 20
SAVINGS FUND PLAN
FOR EMPLOYEES OF PACIFIC GAS AND ELECTRIC COMPANY
ITEM 27a - SCHEDULE OF ASSETS HELD FOR INVESTMENT PURPOSES
December 31, 1994
<TABLE>
<CAPTION>
Number of
Shares or
U.S. Savings
Bonds Held at (e) Current
(a) (b) Name of Issuer and (c) Description Close of Period (d) Cost Value
------------------------------------------------- --------------- -------------- -------------
----------In Thousands--------
<S> <C> <C> <C>
Torchmark Inc. 6,600 $ 380 $ 230
Toys R Us Inc. 47,600 1,835 1,452
Transamerica Corp. 5,000 268 249
Tribune Co. New 11,600 632 635
Tyco Int. Ltd. 18,100 799 860
UAL Corp. 1,200 99 105
UJB Finl. Corp. 3,300 90 80
UNUM Corp. 7,400 357 279
UNICOM Corp. 25,300 569 607
Union Carbide Corp. 25,800 432 758
Union Elec. Co. 300 11 11
Union Pac. Corp. 39,800 1,387 1,816
Union Texas Pete Hldgs. Inc. 11,000 215 228
U.S. West Inc. 49,200 1,911 1,753
United Technologies Corp. 25,300 1,421 1,591
V. F. Corp. 17,000 844 827
Viacom Inc. 29,300 826 1,190
WMX Technolgies Inc. 93,800 3,180 2,462
Wabash Natl. Corp. 1,200 50 47
Wal Mart Stores Inc. 315,900 8,767 6,713
Warner Lambert Co. 6,300 414 485
Washington Mut. Inc. 9,400 212 159
West One Bancorp. 200 5 5
Western Res. Inc. 6,400 219 183
Weyerhauser Co. 19,400 760 727
Wheelabrator Technologies Inc. 31,000 561 457
Whirlpool Corp. 1,800 106 91
Wisconsin Energy Corp. 6,400 165 166
Woolworth Corp. 18,400 355 276
Worthington Inds. In. 10,100 201 202
---------- ---------- ----------
Total common stocks 8,386,100 $311,785 $340,032
---------- ---------- ----------
Corporate stocks - preferred
Chrysler Corp. 7,700 $1,167 $1,048
---------- ---------- ----------
Interest bearing accounts
* State Street Bank & Trust Co. 12,253,620 $12,254 $12,254
U.S. Treasury Bills 560,000 553 553
---------- ---------- ----------
Total interest bearing accounts 12,813,620 $12,807 $12,807
Total DEF 21,207,420 $325,759 $353,887
========== ========== ==========
</TABLE>
<TABLE>
<CAPTION>
<S> <C> <C> <C> <C> <C>
GIF (1)
Fixed Income
Allstate Life Insurance Co. - 10/98, 6.80% N/A $3,075 $3,075
Allstate Life Insurance Co. - 11/99, 8.28% N/A 5,011 5,011
Bankers Trust Basic - 07/96, 6.36% N/A 1,246 1,246
Bankers Trust Basic - 07/97, 5.02% N/A 9,655 9,655
</TABLE>
14
<PAGE> 21
SAVINGS FUND PLAN
FOR EMPLOYEES OF PACIFIC GAS AND ELECTRIC COMPANY
ITEM 27a - SCHEDULE OF ASSETS HELD FOR INVESTMENT PURPOSES
December 31, 1994
<TABLE>
<CAPTION>
Number of
Shares or
U.S. Savings
Bonds Held at (e) Current
(a) (b) Name of Issuer and (c) Description Close of Period (d) Cost Value
------------------------------------------------- -------------- --------------- -------------
---------In Thousands----------
<S> <C> <C> <C> <C> <C>
CDC Investment Mgmt. Corp. - 06/98, 7.11% N/A $4,023 $4,023
CDC Investment Mgmt. Corp. - 10/99, 7.59% N/A 3,020 3,020
Canada Life Assurance - 11/95, 4.30% N/A 5,009 5,009
Canada Life Assurance - 12/95, 4.34% N/A 4,011 4,011
Confederated Life Assurance - 03/96, 8.58% N/A 1,000 1,000
Continental Assurance Co. - 06/96, 5.80% N/A 3,560 3,560
Continental Assurance Co. - 08/94, 6.52% N/A 0 0
Crown Life - 03/98, 1.00% N/A 1,163 1,163
Hancock John Mutual Life - 09/96, 5.34% N/A 4,470 4,470
Hancock John Mutual Life - 10/97, 4.82% N/A 7,367 7,367
Hartford - 12/95, 6.52% N/A 2,990 2,990
IBM CR Corp - 02/95, 6.56% N/A 1,016 1,016
Mass Mutual Life Ins - 11/03, 5.95% N/A 18,010 18,010
Met Life Ins. - 08/99, 7.42% N/A 4,944 4,944
New York Life Ins. Co. - 05/96, 8.40% N/A 1,567 1,567
New York Life Ins. Co. - 12/98, 1.00% N/A 9,482 9,482
New York Life Ins. Co. - 12/99, 1.00% N/A 9,845 9,845
Peoples Security Life - 01/98, 5.42% N/A 2,825 2,825
Peoples Security Life - 03/99, 5.30% N/A 4,993 4,993
Peoples Security Life - 06/96, 4.69% N/A 2,500 2,500
Peoples Security Life - 06/97, 1.00% N/A 9,989 9,989
Peoples Security Life - 07/94, 8.47% N/A 1,127 1,127
Peoples Security Life - 07/96, 4.15% N/A 3,699 3,699
Peoples Security Life - 07/98, 5.50% N/A 5,967 5,967
Peoples Security Life - 09/96, 4.10% N/A 3,616 3,616
Peoples Security Life - 09/97, 5.11% N/A 4,969 4,969
Peoples Security Life - 09/98, 5.63% N/A 3,219 3,219
Provident Mutual Life Ins. Co. - 05/95, 6.34% N/A 4,659 4,659
Prudential Ins. Co. - 03/95, 4.22% N/A 3,000 3,000
Prudential Ins. Co. - 04/96, 8.04% N/A 1,748 1,748
Prudential Ins. Co. - 09/98, 1.00% N/A 4,455 4,455
Prudential Ins. Co. - 11/95, 6.11% N/A 4,623 4,623
Union Bank of Switzerland - 08/97, 1.00% N/A 7,097 7,097
Union Bank of Switzerland - 03/00, 4.62% N/A 10,310 10,310
Union Bank of Switzerland - 03/00, 5.15% N/A 6,575 6,575
Union Bank of Switzerland - 10/98, 5.63% N/A 10,268 10,268
United of Omaha Life - 07/95, 8.35% N/A 2,067 2,067
United of Omaha Life - 08/95, 5.30% N/A 3,567 3,567
United of Omaha Life - 09/95, 5.00% N/A 2,017 2,017
United of Omaha Life - 09/96, 4.40% N/A 1,160 1,160
---------- ---------- ----------
Total fixed income N/A $204,914 $204,914
---------- ---------- ----------
</TABLE>
15
<PAGE> 22
SAVINGS FUND PLAN
FOR EMPLOYEES OF PACIFIC GAS AND ELECTRIC COMPANY
ITEM 27a - SCHEDULE OF ASSETS HELD FOR INVESTMENT PURPOSES
December 31, 1994
<TABLE>
<CAPTION>
Number of
Shares or
U.S. Savings
Bonds Held at (e) Current
(a) (b) Name of Issuer and (c) Description Close of Period (d) Cost Value
------------------------------------------------- --------------- --------------- --------------
-----------In Thousands--------
<S> <C> <C> <C>
Interest bearing accounts
Chevron Oil Finance Co. N/A $ 12,899 $ 12,899
Exxon Funding B.V. N/A 9,955 9,955
Federal Natl. Mtg. Assn. Disc. Nts. N/A 9,967 9,967
General Elec. Cap. Corp. N/A 12,848 12,848
Rabobank USA Financial Corp. N/A 12,366 12,366
* State Street Bank & Trust Co. N/A 2,193 2,193
---------- ---------- ----------
N/A $ 60,228 $ 60,228
---------- ---------- ----------
Total GIF N/A $ 265,142 $ 265,142
========== ========== ==========
BIF
Vanguard Bond Market Fund 2,577,091 $ 25,649 $ 23,632
========== ========== ==========
SBF
Columbia Balanced Fund 15,950,137 $ 92,198 $ 102,861
========== ========== ==========
USF
Dreyfus Utility Stock Fund 4,029,936 $ 54,941 $ 45,458
========== ========== ==========
Total Investments $1,796,609 $1,927,172
========== ==========
</TABLE>
(1) The GIF is not measured in number of shares and is not applicable (N/A).
* Party-in-interest.
16
<PAGE> 23
ITEM 27(D) - SCHEDULE OF
REPORTABLE TRANSACTIONS FOR
THE YEAR ENDED DECEMBER 31, 1994
3751 PACIFIC GAS & ELECTRIC SAVINGS
BENEFIT PLAN SERVICES
ERISA 5500 SCHEDULE OF 5% REPORTABLE SERIES OF TRANSACTIONS
FROM DATE: 01/01/94 TO DATE: 12/31/94
BEGINNING NET ASSET VALUE: 1,590,603,374.79
5% OF ASSET VALUE: 79,530,168.74
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------------------------------------------------------------
ASSET ID SECURITY DESCRIPTION RATE MAT DATE
# PURCHASES PURCHASE COST # SALES SALES PROCEEDS 5500 GAIN/LOSS TOTAL # TOTAL COST/PROCEEDS
- ------------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
COMMON AND PREFERRED
202 186,794,661.04 257 144,611,684.23 -45,878,079.66 459 331,406,309.27
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
202 186,794,661.04 257 144,611,648.23 -45,878,079.66 459 331,406,309.27
NON REPORTABLE TRANSACTION TOTALS
133 95,034,004.11 77 95,029,926.22 0.00 210 190,063,930.33
</TABLE>
[State Street LOGO]
<PAGE> 24
ITEM 27 (D) - SCHEDULE OF
REPORTABLE TRANSACTIONS FOR
THE YEAR ENDED DECEMBER 31, 1994
3757 PACIFIC GAS & ELECTRIC SAVINGS
BENEFIT PLAN SERVICES
ERISA 5500 SCHEDULE OF 5% REPORTABLE SERIES OF TRANSACTIONS
FROM DATE: 01/01/94 TO DATE: 12/31/94
BEGINNING NET ASSET VALUE: 28,739,630.44
5% OF ASSET VALUE: 1,436,981.52
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------------------------------------------------------------
ASSET ID SECURITY DESCRIPTION RATE MAT DATE
# PURCHASES PURCHASE COST # SALES SALES PROCEEDS 5500 GAIN/LOSS TOTAL # TOTAL COST/PROCEEDS
- ------------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
COMMON AND PREFERRED
96 3,691,830.66 44 6,290,311.85 -402,572.17 140 9,982,142.51
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
96 3,691,830.66 44 6,290,311.85 -402,572.17 140 9,982,142.51
NON REPORTABLE TRANSACTION TOTALS
0 0.00 0 0.00 0.00 0 0.00
</TABLE>
[State Street LOGO]
<PAGE> 25
ITEM 27(D) - SCHEDULE OF
REPORTABLE TRANSACTIONS FOR
THE YEAR ENDED DECEMBER 31, 1994
3758 PACIFIC GAS & ELECTRIC SAVINGS
COLUMBUS BALANCED FUND
ERISA 5500 SCHEDULE OF 5% REPORTABLE SERIES OF TRANSACTIONS
FROM DATE: 01/01/94 TO DATE: 12/31/94
BEGINNING NET ASSET VALUE: 104,083,308.36
5% OF ASSET VALUE: 5,204,165.42
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------------------------------------------------------------
ASSET ID SECURITY DESCRIPTION RATE MAT DATE
# PURCHASES PURCHASE COST # SALES SALES PROCEEDS 5500 GAIN/LOSS TOTAL # TOTAL COST/PROCEEDS
- ------------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
COMMON AND PREFERRED
99 11,800,644.25 44 13,083,212.89 -54,318.06 143 24,883,857.14
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
99 11,800,644.25 44 13,083,212.89 -54,318.06 143 24,883,857.14
NON REPORTABLE TRANSACTION TOTALS
0 0.00 0 0.00 0.00 0 0.00
</TABLE>
[State Street LOGO]
<PAGE> 26
ITEM 27(D) - SCHEDULE OF
REPORTABLE TRANSACTIONS FOR
THE YEAR ENDED DECEMBER 31, 1994
3759 PACIFIC GAS & ELECTRIC SAVINGS
DREFUS UTILITY STOCK FUND
ERISA 5500 SCHEDULE OF 5% REPORTABLE SERIES OF TRANSACTIONS
FROM DATE: 01/01/94 TO DATE: 12/31/94
BEGINNING NET ASSET VALUE: 75,336,398.43
5% OF ASSET VALUE: 3,766,819.92
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------------------------------------------------------------
ASSET ID SECURITY DESCRIPTION RATE MAT DATE
# PURCHASES PURCHASE COST # SALES SALES PROCEEDS 5500 GAIN/LOSS TOTAL # TOTAL COST/PROCEEDS
- ------------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
COMMON AND PREFERRED
83 8,796,613.55 52 25,594,505.39 -4,268,225.41 135 34,391,118.94
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
83 8,796,613.55 52 25,594,505.39 -4,268,225.41 135 34,391,118.94
NON REPORTABLE TRANSACTION TOTALS
0 0.00 0 0.00 0.00 0 0.00
</TABLE>
[State Street LOGO]
<PAGE> 27
ITEM 27(D) - SCHEDULE OF
REPORTABLE TRANSACTIONS FOR
THE YEAR ENDED DECEMBER 31, 1994
3760 PACIFIC GAS & ELECTRIC SAVINGS
BENEFIT PLAN SERVICES
ERISA 5500 SCHEDULE OF 5% REPORTABLE SERIES OF TRANSACTIONS
FROM DATE: 01/01/94 TO DATE: 12/31/94
BEGINNING NET ASSET VALUE: 10,252,015.50
5% OF ASSET VALUE: 512,600.78
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------------------------------------------------------------
ASSET ID SECURITY DESCRIPTION RATE MAT DATE
# PURCHASES PURCHASE COST # SALES SALES PROCEEDS 5500 GAIN/LOSS TOTAL # TOTAL COST/PROCEEDS
- ------------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
COMMON AND PREFERRED
28 568,437.35 88 6,749,679.50 -3,934,582.23 116 7,318,116.85
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
28 568,437.35 88 6,749,679.50 -3,934,582.23 116 7,318,116.85
NON REPORTABLE TRANSACTION TOTALS
34 230,700.24 34 230,938.30 0.00 68 461,638.54
</TABLE>
[State Street LOGO]
<PAGE> 28
ITEM 27(D) - SCHEDULE OF
REPORTABLE TRANSACTIONS FOR
THE YEAR ENDED DECEMBER 31, 1994
3757 PACIFIC GAS & ELECTRIC SAVINGS
VANGUARD BOND MARKET FUND
ERISA 5500 SCHEDULE OF 5% REPORTABLE SERIES OF TRANSACTIONS
FROM DATE: 01/01/94 TO DATE: 12/31/94
BEGINNING NET ASSET VALUE: 28,739,630.44
5% OF ASSET VALUE: 1,436,981.52
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------------------------------------------------------------
ASSET ID SECURITY DESCRIPTION RATE MAT DATE
# PURCHASES PURCHASE COST # SALES SALES PROCEEDS 5500 GAIN/LOSS TOTAL # TOTAL COST/PROCEEDS
- ------------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
COMMON AND PREFERRED
921937108 VANGUARD BD INDEX FD INC
96 3,691,830.66 44 6,290,311.85 -402,572.17 140 9,982,142.51
COMMON AND PREFERRED TOTALS
96 3,691,830.66 44 6,290,311.85 -402,572.17 140 9,982,142.51
</TABLE>
[State Street LOGO]
<PAGE> 29
ITEM 27(D) - SCHEDULE OF
REPORTABLE TRANSACTIONS FOR
THE YEAR ENDED DECEMBER 31, 1994
3751 PACIFIC GAS & ELECTRIC SAVINGS
BENEFIT PLAN SERVICES
ERISA 5500 SCHEDULE OF 5% REPORTABLE SERIES OF TRANSACTIONS
FROM DATE: 01/01/94 TO DATE: 12/31/94
BEGINNING NET ASSET VALUE: 1,590,603,374.79
5% OF ASSET VALUE: 79,530,168.74
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------------------------------------------------------------
ASSET ID SECURITY DESCRIPTION RATE MAT DATE
# PURCHASES PURCHASE COST # SALES SALES PROCEEDS 5500 GAIN/LOSS TOTAL # TOTAL COST/PROCEEDS
- ------------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
COMMON AND PREFERRED
694308107 PACIFIC GAS & ELEC CO
202 186,794,661.04 257 144,611,648.23 -45,878,079.66 459 331,406,309.27
COMMON AND PREFERRED TOTALS
-45,878,079.66
202 186,794,661.04 257 144,611,648.23 459 331,406,309.27
</TABLE>
[State Street LOGO]
<PAGE> 30
ITEM 27(D) - SCHEDULE OF
REPORTABLE TRANSACTIONS FOR
THE YEAR ENDED DECEMBER 31, 1994
3758 PACIFIC GAS & ELECTRIC SAVINGS
COLUMBIA BALANCED FUND
ERISA 5500 SCHEDULE OF 5% REPORTABLE SERIES OF TRANSACTIONS
FROM DATE: 01/01/94 TO DATE: 12/31/94
BEGINNING NET ASSET VALUE: 104,083,308.36
5% OF ASSET VALUE: 5,204,165.42
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------------------------------------------------------------
ASSET ID SECURITY DESCRIPTION RATE MAT DATE
# PURCHASES PURCHASE COST # SALES SALES PROCEEDS 5500 GAIN/LOSS TOTAL # TOTAL COST/PROCEEDS
- ------------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
COMMON AND PREFERRED
197216104 COLUMBIA BALANCED FUND INC
99 11,800,644.25 44 13,083,212.89 -54,318.06 143 24,883,857.14
COMMON AND PREFERRED TOTALS
99 11,800,644.25 44 13,083,212.89 -54,318.06 143 24,883,857.14
</TABLE>
[State Street LOGO]
<PAGE> 31
ITEM 27(D) - SCHEDULE OF
REPORTABLE TRANSACTIONS FOR
THE YEAR ENDED DECEMBER 31, 1994
3759 PACIFIC GAS & ELECTRIC SAVINGS
DREYFUS UTILITY STOCK FUND
ERISA 5500 SCHEDULE OF 5% REPORTABLE SERIES OF TRANSACTIONS
FROM DATE: 01/01/94 TO DATE: 12/31/94
BEGINNING NET ASSET VALUE: 75,336,398.43
5% OF ASSET VALUE: 3,766,819.92
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------------------------------------------------------------
ASSET ID SECURITY DESCRIPTION RATE MAT DATE
# PURCHASES PURCHASE COST # SALES SALES PROCEEDS 5500 GAIN/LOSS TOTAL # TOTAL COST/PROCEEDS
- ------------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
COMMON AND PREFERRED
261893101 DREYFUS EDISON ELEC INDEX FD
83 8,796,613.55 52 25,594,505.39 -4,268,225.41 135 34,391,118.94
COMMON AND PREFERRED TOTALS
83 8,796,613.55 52 25,594,505.39 -4,268,225.41 135 34,391,118.94
</TABLE>
[State Street LOGO]
<PAGE> 32
ITEM 27(D) - SCHEDULE OF
REPORTABLE TRANSACTIONS FOR
THE YEAR ENDED DECEMBER 31, 1994
3760 PACIFIC GAS & ELECTRIC SAVINGS
BENEFIT PLAN SERVICES
ERISA 5500 SCHEDULE OF 5% REPORTABLE SERIES OF TRANSACTIONS
FROM DATE: 01/01/94 TO DATE: 12/31/94
BEGINNING NET ASSET VALUE: 10,252,015.50
5% OF ASSET VALUE: 512,600.78
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------------------------------------------------------------
ASSET ID SECURITY DESCRIPTION RATE MAT DATE
BROKER PURCHASE PRICE SALES PRICE EXPENSES 5500 GAIN/LOSS COST/PROCEEDS 550 GAIN/LOSS
- ------------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
COMMON AND PREFERRED
0.00 6,430,879.39
10,287.419.09 -3,856,539.70
FIXED INCOME
0.00 0.00
0.00 0.00
SHORT TERM
0.00 0.00
0.00 0.00
REPORTABLE TRANSACTION TOTALS
0.00 6,430,879.39
10,287.419.09 -3,856,539.70
</TABLE>
[State Street LOGO]
<PAGE> 33
ITEM 27(D) - SCHEDULE OF
REPORTABLE TRANSACTIONS FOR
THE YEAR ENDED DECEMBER 31, 1994
3760 PACIFIC GAS & ELECTRIC SAVINGS
BENEFIT PLAN SERVICES
ERISA 5500 SCHEDULE OF 5% REPORTABLE SERIES OF TRANSACTIONS
FROM DATE: 01/01/94 TO DATE: 12/31/94
BEGINNING NET ASSET VALUE: 10,252,015.50
5% OF ASSET VALUE: 512,600.78
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------------------------------------------------------------
ASSET ID SECURITY DESCRIPTION RATE MAT DATE
# PURCHASES PURCHASE COST # SALES SALES PROCEEDS 5500 GAIN/LOSS TOTAL # TOTAL COST/PROCEEDS
- ------------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
COMMON AND PREFERRED
694308107 PACIFIC GAS & ELEC CO
28 568,437.35 88 6,749,679.50 -3,934,582.23 116 7,318,116.85
COMMON AND PREFERRED TOTALS
28 568,437.35 88 6,749,679.50 -3,934,582.23 116 7,318,116.85
</TABLE>
[State Street LOGO]
<PAGE> 34
ITEM 27(D) - SCHEDULE OF
REPORTABLE TRANSACTIONS FOR
THE YEAR ENDED DECEMBER 31, 1994
3760 PACIFIC GAS & ELECTRIC SAVINGS
BENEFIT PLAN SERVICES
ERISA 5500 SCHEDULE OF 5% REPORTABLE SERIES OF TRANSACTIONS
FROM DATE: 01/01/94 TO DATE: 12/31/94
BEGINNING NET ASSET VALUE: 10,252,015.50
5% OF ASSET VALUE: 512,600.78
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------------------------------------------------------------
ASSET ID SECURITY DESCRIPTION RATE MAT DATE
BROKER PURCHASE PRICE SALES PRICE EXPENSES 5500 COST COST/PROCEEDS 550 GAIN/LOSS
- ------------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
COMMON AND PREFERRED
694308107 PACIFIC GAS & ELEC CO
DIRECT ISS 21.56 0.00 10,287.419.09 6,430,879.39 -3,856,539.70
COMMON AND PREFERRED TOTALS
0.00 6,430,879.39
10,287.419.09 -3,856,539.70
</TABLE> [State Street LOGO]
<PAGE> 35
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, 1994
AND 1993
STATEMENT OF CHANGES IN NET ASSETS AVAILABLE FOR BENEFITS
FOR THE YEAR ENDED DECEMBER 31, 1994
NOTES TO FINANCIAL STATEMENTS -- DECEMBER 31, 1994
<PAGE> 36
PACIFIC GAS AND ELECTRIC COMPANY
SAVINGS FUND PLAN - PART I
STATEMENTS OF NET ASSETS AVAILABLE FOR BENEFITS
December 31, 1994 AND 1993
<TABLE>
<CAPTION>
1994 1993
------ ------
----------------In Thousands-----------
<S> <C> <C>
ASSETS:
Investment in Pacific Gas and Electric
Company Master Trust, at fair value $839,081 $960,671
Participant contributions receivable 1 220
Employer contributions receivable _ 88
------- -------
Total assets 839,082 960,979
LIABILITIES 43 38
------- -------
NET ASSETS AVAILABLE FOR BENEFITS $839,039 $960,941
======= =======
</TABLE>
The accompanying Notes to Financial Statements are an integral part of these
statements.
1
<PAGE> 37
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, 1994
<TABLE>
<CAPTION>
-----In Thousands----
<S> <C>
ADDITIONS:
Participant contributions $ 36,071
Employer contributions 16,679
Interplan transfers 2,163
-------
Total Additions 54,913
-------
DEDUCTIONS:
Net investment loss from Pacific Gas
and Electric Company Master Trust 118,414
Benefits paid directly to participants
or beneficiaries 57,941
Expenses 460
-------
Total Deductions 176,815
-------
Decrease in Net Assets Available for Benefits (121,902)
NET ASSETS AVAILABLE FOR BENEFITS
Beginning of the year 960,941
-------
End of the year $839,039
=======
</TABLE>
The accompanying Notes to Financial Statements are an integral part of these
statements.
2
<PAGE> 38
PACIFIC GAS AND ELECTRIC COMPANY
SAVINGS FUND PLAN - PART I
NOTES TO FINANCIAL STATEMENTS
December 31, 1994
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
management employees of Pacific Gas and Electric Company (the Company), Pacific
Gas Transmission Company, and any other entity designated by the Company's
Board of Directors. 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. The Plan is administered by the Employee Benefit Administrative
Committee and the Employee Benefit Finance Committee. Participants should
refer to the Plan document for a complete description of the Plan's provisions.
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, 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 1994, 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.
NOTE 2: Summary of Significant Accounting Policies
The financial statements of the Plan are prepared in conformity with
generally accepted accounting principles.
The Plan's interest in the Pacific Gas and Electric Company Savings Fund
Plan Master Trust (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 upon
published market quotations.
3
<PAGE> 39
PACIFIC GAS AND ELECTRIC COMPANY
SAVINGS FUND PLAN - PART I
NOTES TO FINANCIAL STATEMENTS
December 31, 1994
NOTE 2: Summary of Significant Accounting Policies (Continued)
Interest income, dividends, investment fees, and the net appreciation
(depreciation) in the fair value of the investments held by the Master Trust
are allocated to the individual participating plans each week 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 Plan has obtained a favorable tax determination letter from the IRS and
the Plan sponsor believes that the Plan continues to be designed and operated
in accordance with IRS requirements.
NOTE 4: Investments
The Plan has a prorated interest in the net assets of the Master Trust. The
Master Trust Agreement allows certain of 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. Purchases of this stock are 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. Investment
management fees are netted against the performance of the Stock and Bond Fund,
Utility Stock Fund, and Bond Index Fund and are paid by the Company in
connection with the Diversified Equity Fund and the Guaranteed Income Fund.
4
<PAGE> 40
PACIFIC GAS AND ELECTRIC COMPANY
SAVINGS FUND PLAN - PART I
NOTES TO FINANCIAL STATEMENTS
December 31, 1994
NOTE 4: Investments (Continued)
Participants designate the way in which their contributions are invested and
may change their investment designation once each calendar quarter.
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 the Company.
A participant's interest in the investment funds is measured in "units".
For investments in the common stock of the Company and in United States Savings
Bonds, a unit is a share of common stock and a United States Savings Bond,
respectively.
5
<PAGE> 41
PACIFIC GAS AND ELECTRIC COMPANY
SAVINGS FUND PLAN - PART I
NOTES TO FINANCIAL STATEMENTS
December 31, 1994
NOTE 4: Investments (Continued)
The following summarizes the net assets and related investment loss of the
Master Trust and the Plan's allocated share of such amounts:
<TABLE>
<CAPTION>
----In Thousands----
1994 1993
----------------- -----------------
<S> <C> <C>
Investments, primarily at fair value:
Company Stock Fund
Pacific Gas and Electric Company
common stock $1,131,413 $1,569,458
United States Bond Fund
United States Government securities 5,169 4,740
DEF
Corporate stocks - preferred 1,048 1,299
Corporate stocks - common 340,032 300,039
GIF
Corporate debt instruments 53,210 41,099
Insurance company general accounts 151,704 188,421
Registered investment companies
Vanguard Bond Market Fund 23,632 28,740
Columbia Balanced Fund 102,861 104,083
Dreyfus Utility Stock Fund 45,458 75,336
PAYSOP Fund
Pacific Gas and Electric Company
common stock 0 10,116
Interest bearing accounts 72,645 6,597
--------- ---------
Total investments 1,927,172 2,329,928
--------- ---------
Receivables:
Dividends and interest 27,365 24,856
Other receivables 6,293 1,168
--------- ---------
Total receivables 33,658 26,024
--------- ---------
Total assets 1,960,830 2,355,952
--------- ---------
LIABILITIES 11,407 1,197
--------- ---------
NET ASSETS $1,949,423 $2,354,755
========= =========
Allocated to the Plan $ 839,081 $ 960,671
Allocated to other plans 1,110,342 1,394,084
--------- ---------
$1,949,423 $2,354,755
========= =========
</TABLE>
6
<PAGE> 42
PACIFIC GAS AND ELECTRIC COMPANY
SAVINGS FUND PLAN - PART I
NOTES TO FINANCIAL STATEMENTS
December 31, 1994
NOTE 4: Investments (Continued)
The composition of the Master Trust investment loss for the year ended
December 31, 1994 is as follows:
<TABLE>
<CAPTION>
-In Thousands-
<S> <C>
Interest income
Interest bearing accounts $ 931
United States Government securities 289
Fixed income investments 11,373
---------
Total interest income 12,593
---------
Dividend income
Common stock 98,890
Registered investment companies 5,037
---------
Total dividend income 103,927
---------
Net depreciation in fair value of investments (498,136)
Expenses, net of other income (712)
---------
Total investment loss ($382,328)
=========
Allocated to the Plan ($118,414)
Allocated to other plans (263,914)
---------
($382,328)
=========
</TABLE>
7
<PAGE> 43
PACIFIC GAS AND ELECTRIC COMPANY
SAVINGS FUND PLAN - PART I
NOTES TO FINANCIAL STATEMENTS
December 31, 1994
NOTE 4: Investments (Continued)
The net depreciation in fair value of investments of the Master Trust by
major investment category for the year ended December 31, 1994 is as follows:
<TABLE>
<CAPTION>
-In Thousands-
<S> <C>
Pacific Gas and Electric Company
Common Stock Fund ($480,081)
PAYSOP Fund (3,935)
Diversified Equity Fund 1,409
Bond Index Fund (2,509)
Stock and Bond Fund 60
Utility Stock Fund (13,080)
---------
Total depreciation ($498,136)
=========
Allocated to the Plan ($162,982)
Allocated to other plans (335,154)
---------
($498,136)
=========
</TABLE>
8
<PAGE> 44
PACIFIC GAS AND ELECTRIC COMPANY
SAVINGS FUND PLAN - PART I
NOTES TO FINANCIAL STATEMENTS
December 31, 1994
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, whereby each
$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 USF for the four quarters ended December 31, 1994 and 1993 are as
follows:
<TABLE>
<CAPTION>
1994
----------
March 31 June 30 September 30 December 31
-------- ------- ------------ -----------
<S> <C> <C> <C> <C>
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 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>
9
<PAGE> 45
PACIFIC GAS AND ELECTRIC COMPANY
SAVINGS FUND PLAN - PART I
NOTES TO FINANCIAL STATEMENTS
December 31, 1994
NOTE 4: Investments (Continued)
<TABLE>
<CAPTION>
1993
----------
March 31 June 30 September 30 December 31
-------- ------- ------------ -----------
<S> <C> <C> <C> <C>
DEF
Number of units 2,593,090 2,799,854 2,664,331 2,725,851
Value per unit $65.07 $65.44 $67.25 $69.44
GIF
Number of units 108,940,209 150,749,436 110,606,418 109,282,898
Value per unit $1.00 $1.00 $1.00 $1.00
BIF
Number of units 1,668,168 1,802,675 1,690,981 1,679,963
Value per unit $11.44 $11.70 $12.08 $12.06
SBF
Number of units 9,435,637 11,400,946 11,199,558 11,917,450
Value per unit $5.83 $5.96 $6.17 $6.23
USF
Number of units 1,815,171 2,264,729 2,504,277 2,683,123
Value per unit $14.41 $14.72 $15.39 $14.60
</TABLE>
10
<PAGE> 46
PACIFIC GAS AND ELECTRIC COMPANY
SAVINGS FUND PLAN - PART I
NOTES TO FINANCIAL STATEMENTS
December 31, 1994
NOTE 5: Reconciliation of Financial Statements to Form 5500
The following is a reconciliation of net assets available for benefits per
the financial statements to the Form 5500:
<TABLE>
<CAPTION>
--In Thousands--
December 31
-----------
1994 1993
---- ----
<S> <C> <C>
Net assets available for benefits per the financial statements $839,039 $960,941
Amounts allocated to withdrawing participants (1,330) (5,275)
------- -------
Net assets available for benefits per the Form 5500 $837,709 $955,666
======= =======
</TABLE>
The following is a reconciliation of benefits paid to participants per
the financial statements to the Form 5500:
<TABLE>
<CAPTION>
--In Thousands--
Year ended
December 31, 1994
-----------------
<S> <C>
Benefits paid to participants per the financial statements $57,941
Add: Amounts allocated to withdrawing participants at
December 31, 1994 1,330
Less: Amounts allocated to withdrawing participants at
December 31, 1993 (5,275)
------
Benefits paid to participants per the Form 5500 $53,996
======
</TABLE>
11
<PAGE> 47
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, 1994 AND 1993
STATEMENT OF CHANGES IN NET ASSETS AVAILABLE FOR BENEFITS
FOR THE YEAR ENDED DECEMBER 31, 1994
NOTES TO FINANCIAL STATEMENTS -- DECEMBER 31, 1994
<PAGE> 48
PACIFIC GAS AND ELECTRIC COMPANY
SAVINGS FUND PLAN - PART II
STATEMENTS OF NET ASSETS AVAILABLE FOR BENEFITS
December 31, 1994 AND 1993
<TABLE>
<CAPTION>
1994 1993
-------- --------
----------------In Thousands---------------
<S> <C> <C>
ASSETS:
Investment in Pacific Gas and Electric
Company Master Trust, at fair value $1,105,628 $1,378,240
Participant contributions receivable -- 287
Employer contributions receivable -- 60
--------- ---------
Total assets 1,105,628 1,378,587
LIABILITIES 42 76
--------- ---------
NET ASSETS AVAILABLE FOR BENEFITS $1,105,586 $1,378,511
========= =========
</TABLE>
The accompanying Notes to Financial Statements are an integral part of these
statements.
1
<PAGE> 49
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, 1994
<TABLE>
<CAPTION>
-----In Thousands----
<S> <C>
ADDITIONS:
Participant contributions $ 57,543
Employer contributions 16,306
Interplan transfers 4,212
---------
Total Additions 78,061
---------
DEDUCTIONS:
Net investment loss from Pacific Gas
and Electric Company Master Trust 258,784
Benefits paid directly to participants
or beneficiaries 91,900
Expenses 302
---------
Total Deductions 350,986
---------
Decrease in Net Assets Available for Benefits (272,925)
NET ASSETS AVAILABLE FOR BENEFITS
Beginning of the year 1,378,511
---------
End of the year $1,105,586
=========
</TABLE>
The accompanying Notes to Financial Statements are an integral part of these
statements.
2
<PAGE> 50
PACIFIC GAS AND ELECTRIC COMPANY
SAVINGS FUND PLAN PART - PART II
NOTES TO FINANCIAL STATEMENTS
December 31, 1994
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 eligible
non-management employees of Pacific Gas and Electric Company (the Company),
Pacific Gas Transmission Company, and any other entity designated by the
Company's Board of Directors. 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. The Plan is administered by the Employee
Benefit Administrative Committee and the Employee Benefit Finance Committee.
Participants should refer to the Plan document for a complete description of
the Plan's provisions.
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, 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
1994 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.
Non-management non-bargaining unit 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.
NOTE 2: Summary of Significant Accounting Policies
The financial statements of the Plan are prepared in conformity with
generally accepted accounting principles.
The Plan's interest in the Pacific Gas and Electric Company Savings Fund
Plan Master Trust (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. All other investments are stated at fair value based upon published
market quotations.
3
<PAGE> 51
PACIFIC GAS AND ELECTRIC COMPANY
SAVINGS FUND PLAN PART - PART II
NOTES TO FINANCIAL STATEMENTS
December 31, 1994
NOTE 2: Summary of Significant Accounting Policies (Continued)
Interest income, dividends, investment fees, and the net appreciation
(depreciation) in the fair value of the investments held by the Master Trust
are allocated to the individual participating plans each week 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 Plan has obtained a favorable tax determination letter from the IRS and
the Plan sponsor believes that the Plan continues to be designed and operated
in accordance with IRS requirements.
NOTE 4: Investments
The Plan has a prorated interest in the net assets of the Master Trust. The
Master Trust Agreement allows certain of 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. Purchases of this stock are 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 Plan participants.
Investment management fees are netted against the performance of the Stock and
Bond Fund, Utility Stock Fund and Bond Index Fund and are paid by the Company
in connection with the Diversified Equity Fund and the Guaranteed Income Fund.
4
<PAGE> 52
PACIFIC GAS AND ELECTRIC COMPANY
SAVINGS FUND PLAN PART - PART II
NOTES TO FINANCIAL STATEMENTS
December 31, 1994
NOTE 4: Investments (Continued)
Participants designate the way in which their contributions are invested and
may change their investment designation once each calendar quarter.
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 the Company.
A participant's interest in the investment funds is measured in "units".
For investments in the common stock of the Company and in United States Savings
Bonds, a unit is a share of common stock and a United States Savings Bond,
respectively.
5
<PAGE> 53
PACIFIC GAS AND ELECTRIC COMPANY
SAVINGS FUND PLAN - PART II
NOTES TO FINANCIAL STATEMENTS
December 31, 1994
NOTE 4: Investments (Continued)
The following summarizes the net assets and related investment loss of the
Master Trust and the Plan's allocated share of such amounts:
<TABLE>
<CAPTION>
----In Thousands----
1994 1993
-------------------------------
<S> <C> <C>
Investments, primarily at fair value:
Company Stock Fund
Pacific Gas and Electric Company
common stock $1,131,413 $1,569,458
United States Bond Fund
United States Government securities 5,169 4,740
DEF
Corporate stocks - preferred 1,048 1,299
Corporate stocks - common 340,032 300,039
GIF
Corporate debt instruments 53,210 41,099
Insurance company general accounts 151,704 188,421
Registered investment companies
Vanguard Bond Market Fund 23,632 28,740
Columbia Balanced Fund 102,861 104,083
Dreyfus Utility Stock Fund 45,458 75,336
PAYSOP Fund
Pacific Gas and Electric Company
common stock 0 10,116
Interest bearing accounts 72,645 6,597
--------- ---------
Total investments 1,927,172 2,329,928
--------- ---------
Receivables:
Dividends and interest 27,365 24,856
Other receivables 6,293 1,168
--------- ---------
Total receivables 33,658 26,024
--------- ---------
Total assets 1,960,830 2,355,952
--------- ---------
LIABILITIES 11,407 1,197
--------- ---------
NET ASSETS $1,949,423 $2,354,755
========= =========
Allocated to the Plan $1,105,628 $1,378,240
Allocated to other plans 843,795 976,515
--------- ---------
$1,949,423 $2,354,755
========= =========
</TABLE>
6
<PAGE> 54
PACIFIC GAS AND ELECTRIC COMPANY
SAVINGS FUND PLAN - PART II
NOTES TO FINANCIAL STATEMENTS
December 31, 1994
NOTE 4: Investments (Continued)
The composition of the Master Trust investment loss for the year ended
December 31, 1994 is as follows:
<TABLE>
<CAPTION>
-In Thousands-
<S> <C>
Interest income
Interest bearing accounts $ 931
United States Government securities 289
Fixed income investments 11,373
---------
Total interest income 12,593
---------
Dividend income
Common stock 98,890
Registered investment companies 5,037
---------
Total dividend income 103,927
---------
Net depreciation in fair value of investments (498,136)
Expenses, net of other income (712)
---------
Total investment loss ($382,328)
=========
Allocated to the Plan ($258,784)
Allocated to other plans (123,544)
---------
($382,328)
=========
</TABLE>
7
<PAGE> 55
PACIFIC GAS AND ELECTRIC COMPANY
SAVINGS FUND PLAN - PART II
NOTES TO FINANCIAL STATEMENTS
December 31, 1994
NOTE 4: Investments (Continued)
The net depreciation in fair value of investments of the Master Trust by
major investment category for the year ended December 31, 1994 is as follows:
<TABLE>
<CAPTION>
-In Thousands-
<S> <C>
Pacific Gas and Electric Company
Common Stock Fund ($480,081)
PAYSOP Fund (3,935)
Diversified Equity Fund 1,409
Bond Index Fund (2,509)
Stock and Bond Fund 60
Utility Stock Fund (13,080)
---------
Total depreciation ($498,136)
=========
Allocated to the Plan ($330,117)
Allocated to other plans (168,019)
---------
($498,136)
=========
</TABLE>
8
<PAGE> 56
PACIFIC GAS AND ELECTRIC COMPANY
SAVINGS FUND PLAN - PART II
NOTES TO FINANCIAL STATEMENTS
December 31, 1994
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, whereby each
$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,
and USF for the four quarters ended December 31, 1994 and 1993 are as follows:
<TABLE>
<CAPTION>
1994
---------
March 31 June 30 September 30 December 31
-------- ------- ------------ -----------
<S> <C> <C> <C> <C>
DEF
Number of units 1,753,173 1,806,766 1,842,015 1,857,851
Value per units $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 units $1.00 $1.00 $1.00 $1.00
BIF
Number of units 731,690 694,599 661,711 626,501
Value per units $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 units $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 units $12.98 $11.89 $12.24 $12.73
</TABLE>
9
<PAGE> 57
PACIFIC GAS AND ELECTRIC COMPANY
SAVINGS FUND PLAN - PART II
NOTES TO FINANCIAL STATEMENTS
December 31, 1994
NOTE 4: Investments (Continued)
<TABLE>
<CAPTION>
1993
--------
March 31 June 30 September 30 December 31
-------- ------- ------------ -----------
<S> <C> <C> <C> <C>
DEF
Number of units 1,511,663 1,696,161 1,747,731 1,700,987
Value per units $65.07 $65.44 $67.25 $69.44
GIF
Number of units 75,908,115 91,144,285 169,591,270 124,388,496
Value per units $1.00 $1.00 $1.00 $1.00
BIF
Number of units 674,034 712,355 860,340 703,276
Value per units $11.44 $11.70 $12.08 $12.06
SBF
Number of units 3,000,210 3,972,889 4,599,099 4,785,165
Value per units $5.83 $5.96 $6.17 $6.23
USF
Number of units 1,213,254 1,806,882 2,308,411 2,475,717
Value per units $14.41 $14.72 $15.39 $14.60
</TABLE>
10
<PAGE> 58
PACIFC GAS AND ELECTRIC COMPANY
SAVINGS FUND PLAN - PART II
NOTES TO FINANCIAL STATEMENTS
December 31, 1994
NOTE 5: Reconciliation of Financial Statements to Form 5500
The following is a reconciliation of net assets available for benefits per
the financial statements to the Form 5500:
<TABLE>
<CAPTION>
--In Thousands--
December 31
-----------
1994 1993
---- ----
<S> <C> <C>
Net assets available for benefits per the financial statements $1,105,586 $1,378,511
Amounts allocated to withdrawing participants (1,634) (7,321)
--------- ---------
Net assets available for benefits per the Form 5500 $1,103,952 $1,371,190
========= =========
</TABLE>
The following is a reconciliation of benefits paid to participants per
the financial statements to the Form 5500:
<TABLE>
<CAPTION>
--In Thousands--
Year ended
December 31, 1994
-----------------
<S> <C>
Benefits paid to participants per the financial statements $91,900
Add: Amounts allocated to withdrawing participants at
December 31, 1994 1,634
Less: Amounts allocated to withdrawing participants at
December 31, 1993 (7,321)
------
Benefits paid to participants per the Form 5500 $86,213
======
</TABLE>
11
<PAGE> 59
PACIFIC GAS AND ELECTRIC COMPANY
SAVINGS FUND PLAN - PART III
FINANCIAL STATEMENTS
TABLE OF CONTENTS
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
FINANCIAL STATEMENTS
STATEMENTS OF NET ASSETS AVAILABLE FOR BENEFITS
DECEMBER 31, 1994 AND 1993
STATEMENT OF CHANGES IN NET ASSETS AVAILABLE FOR BENEFITS
FOR THE YEAR ENDED DECEMBER 31, 1994
NOTES TO FINANCIAL STATEMENTS -- DECEMBER 31, 1994
<PAGE> 60
PACIFIC GAS AND ELECTRIC COMPANY
SAVINGS FUND PLAN - PART III
STATEMENTS OF NET ASSETS AVAILABLE FOR BENEFITS
December 31, 1994 AND 1993
<TABLE>
<CAPTION>
1994 1993
-------- --------
--------In Thousands--------
<S> <C> <C>
ASSETS:
Investment in Pacific Gas and Electric
Company Master Trust, at fair value - $10,252
------- ------
NET ASSETS AVAILABLE FOR BENEFITS $ - $10,252
======= ======
</TABLE>
The accompanying Notes to Financial Statements are an integral part of these
statements.
1
<PAGE> 61
PACIFIC GAS AND ELECTRIC COMPANY
SAVINGS FUND PLAN - PART III
STATEMENT OF CHANGES IN NET ASSETS AVAILABLE FOR BENEFITS
For the Year Ended December 31, 1994
<TABLE>
<CAPTION>
-----In Thousands-----
<S> <C>
DEDUCTIONS:
Net investment loss from Pacific Gas and
Electric Company Master Trust $ 3,507
Benefits paid directly to participants
or beneficiaries 314
-------
Total Deductions 3,821
-------
Interplan transfers (6,431)
-------
Decrease in Net Assets Available for Benefits (10,252)
NET ASSETS AVAILABLE FOR BENEFITS
Beginning of the year $ 10,252
-------
End of the year $ -
=======
</TABLE>
The accompanying Notes to Financial Statements are an integral part of these
statemen
2
<PAGE> 62
PACIFIC GAS AND ELECTRIC COMPANY
SAVINGS FUND PLAN - PART III
NOTES TO FINANCIAL STATEMENTS
December 31, 1994
NOTE 1: Plan Description
The Pacific Gas and Electric Company Savings Fund Plan - Part III (the Plan)
is a Payroll Based Employee Stock Ownership Plan (PAYSOP). The Plan is subject
to the provisions of the Employee Retirement Income Security Act of 1974. The
Plan covers all eligible employees of Pacific Gas and Electric Company (the
Company), Pacific Gas Transmission Company, and any other entity designated by
the Company's Board of Directors. The Plan is administered by the Employee
Benefit Administrative Committee and the Employee Benefit Finance Committee.
Participants should refer to the Plan document for a complete description of
the Plan's provisions.
Effective January 1, 1983, the Economic Recovery Tax Act of 1981 permitted
the Company to claim a tax credit if it contributed Company common stock or
money to purchase Company common stock to the PAYSOP Fund equal to .5 percent
of eligible employee covered compensation. Company stock held by the PAYSOP
Fund became fully vested and nonforfeitable. The PAYSOP tax credit was
eliminated by the Tax Reform Act of 1986 for the tax years beginning January 1,
1987. For the PAYSOP Fund, the tax year concides with the calendar year.
Contributions to the PAYSOP Fund cannot be withdrawn until 84 months after
the month in which the stock was purchased. After the 84th month, the stock
and the earnings attributable to that stock are transferred to the Company
Stock Fund in the Master Trust. The last Company contribution to the PAYSOP
Fund was made in 1987 based upon compensation earned by participants in tax
year 1986. After the 84 month time requirement was met in 1994, the Plan was
terminated effective December 31, 1994. The remaining net assets were
transfered to the other related retirement plans maintained by the Company.
NOTE 2: Summary of Significant Accounting Policies
The financial statements of the Plan are prepared in conformity with
generally accepted accounting principles.
The Plan's interest in the Pacific Gas and Electric Company Savings Fund
Plan Master Trust (the Master Trust) is stated at fair value based on the
Plan's prorated interest in the Master Trust. Generally, the Master Trust
values investments at fair value based upon published market quotations.
The net assets of the Master Trust are allocated initially to the individual
participating plans based upon the relative values of assets contributed to the
Master Trust. In addition, interest income, dividends, investment fees, and
the net appreciation (depreciation) in the fair value of the investments held
by the Master Trust are allocated to the individual participating plans each
week based upon their relative market values.
Benefits are recorded when paid.
3
<PAGE> 63
PACIFIC GAS AND ELECTRIC COMPANY
SAVINGS FUND PLAN - PART III
NOTES TO FINANCIAL STATEMENTS
December 31, 1994
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.
The Plan has obtained a favorable tax determination letter from the IRS and
while the Plan was in existence the Plan sponsor believes that the Plan
continued to be designed and operated in accordance with IRS requirements.
NOTE 4: Investments
The Plan has a prorated interest in the net assets of the Master Trust. The
Master Trust Agreement allows certain of the Company 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,
invested all of the contributions to the Plan in common stock of the Company.
Purchases of this stock are 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.
4
<PAGE> 64
PACIFIC GAS AND ELECTRIC COMPANY
SAVINGS FUND PLAN - PART III
NOTES TO FINANCIAL STATEMENTS
December 31, 1994
NOTE 4: Investments (Continued)
The following summarizes the net assets and related investment loss of the
Master Trust and the Plan's allocated share of such amounts:
<TABLE>
<CAPTION>
----In Thousands----
1994 1993
---------- ----------
<S> <C> <C>
Investments, primarily at fair value:
Company Stock Fund
Pacific Gas and Electric Company
common stock $1,131,413 $1,569,458
United States Bond Fund
United States Government securities 5,169 4,740
DEF
Corporate stocks - preferred 1,048 1,299
Corporate stocks - common 340,032 300,039
GIF
Corporate debt instruments 53,210 41,099
Insurance company general accounts 151,704 188,421
Registered investment companies
Vanguard Bond Market Fund 23,632 28,740
Columbia Balanced Fund 102,861 104,083
Dreyfus Utility Stock Fund 45,458 75,336
PAYSOP Fund
Pacific Gas and Electric Company
common stock 0 10,116
Interest bearing accounts 72,645 6,597
--------- ---------
Total investments 1,927,172 2,329,928
--------- ---------
Receivables:
Dividends and interest 27,365 24,856
Other receivables 6,293 1,168
--------- ----------
Total receivables 33,658 26,024
--------- ---------
Total assets 1,960,830 2,355,952
--------- ---------
LIABILITIES 11,407 1,197
--------- ---------
NET ASSETS $1,949,423 $2,354,755
========= =========
Allocated to the Plan $ 0 $ 10,252
Allocated to other plans 1,949,423 2,344,503
--------- ---------
$1,949,423 $2,354,755
========= =========
</TABLE>
5
<PAGE> 65
PACIFIC GAS AND ELECTRIC COMPANY
SAVINGS FUND PLAN - PART III
NOTES TO FINANCIAL STATEMENTS
December 31, 1994
NOTE 4: Investments (Continued)
The composition of the Master Trust investment loss for the year ended
December 31, 1994 is as follows:
<TABLE>
<CAPTION>
-In Thousands-
<S> <C>
Interest income
Interest bearing accounts $ 931
United States Government securities 289
Fixed income investments 11,373
---------
Total interest income 12,593
---------
Dividend income
Common stock 98,890
Registered investment companies 5,037
---------
Total dividend income 103,927
---------
Net depreciation in fair value of investments (498,136)
---------
Expenses, net of other income (712)
---------
Total investment loss ($382,328)
=========
Allocated to the Plan ($3,507)
Allocated to other plans (378,821)
---------
($382,328)
=========
</TABLE>
6
<PAGE> 66
PACIFIC GAS AND ELECTRIC COMPANY
SAVINGS FUND PLAN - PART III
NOTES TO FINANCIAL STATEMENTS
December 31, 1994
NOTE 4: Investments (Continued)
The net depreciation in fair value of investments of the Master Trust by
major investment category for the year ended December 31, 1994 is as follows:
<TABLE>
<CAPTION>
-In Thousands-
<S> <C>
Pacific Gas and Electric Company
Common Stock Fund ($480,081)
PAYSOP Fund (3,935)
Diversified Equity Fund 1,409
Bond Index Fund (2,509)
Stock and Bond Fund 60
Utility Stock Fund (13,080)
---------
Total depreciation ($498,136)
=========
Allocated to the Plan ($3,935)
Allocated to other plans (494,201)
---------
($498,136)
=========
</TABLE>
7
<PAGE> 67
PACIFIC GAS AND ELECTRIC COMPANY
SAVINGS FUND PLAN - PART III
NOTES TO FINANCIAL STATEMENTS
December 31, 1994
NOTE 5: Reconciliation of Financial Statements to Form 5500
The following is a reconciliation of net assets available for benefits per
the financial statements to the Form 5500:
<TABLE>
<CAPTION>
--In Thousands--
December 31
-----------
1994 1993
---- ----
<S> <C> <C>
Net assets available for benefits per the financial statements $ 0 $10,252
Amounts allocated to withdrawing participants 0 (32)
------- ------
Net assets available for benefits per the Form 5500 $ 0 $10,220
======= ======
</TABLE>
The following is a reconciliation of benefits paid to participants per
the financial statements to the Form 5500:
<TABLE>
<CAPTION>
--In Thousands--
Year ended
December 31, 1994
-----------------
<S> <C>
Benefits paid to participants per the financial statements $ 314
Add: Amounts allocated to withdrawing participants at
December 31, 1994 0
Less: Amounts allocated to withdrawing participants at
December 31, 1993 (32)
-----
Benefits paid to participants per the Form 5500 $ 282
=====
</TABLE>
8
