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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
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(MARK ONE)
/X/ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF
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THE SECURITIES EXCHANGE ACT OF 1934 [FEE REQUIRED]
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1993
OR
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/ / TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF
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THE SECURITIES EXCHANGE ACT OF 1934 [NO FEE REQUIRED]
FOR THE TRANSITION PERIOD FROM TO
COMMISSION FILE NUMBER 1-2348
PACIFIC GAS AND ELECTRIC COMPANY
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
California 94 - 0742640
(STATE OR OTHER JURISDICTION OF (IRS EMPLOYER IDENTIFICATION NO.)
INCORPORATION OR ORGANIZATION)
77 Beale Street
P.O. Box 770000
San Francisco, California 94177
(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES) (ZIP CODE)
(415) 973-7000
(REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE)
SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:
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TITLE OF EACH CLASS WHICH REGISTERED
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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
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Redeemable:
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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%
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First and Refunding Mortgage Bonds: New York Stock Exchange
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INTEREST DATE OF INTEREST DATE OF
SERIES RATE % MATURITY SERIES RATE % MATURITY
- ------- -------- -------------- ------- -------- --------------
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HH 4-3/8 Jun. 1, 1994 JJ 4-1/2 Jun. 1, 1996
II 4-1/4 Jun. 1, 1995 KK 4-1/2 Dec. 1, 1996
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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 11, 1994 was 428,848,827. On that date the aggregate market value of the
voting stock held by nonaffiliates of the Company was approximately $14,046
million. The market values of the various classes of voting stock held by
nonaffiliates were as follows: Common Stock, $13,235 million; and First
Preferred Stock, $811 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.
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(1) Designated portions of the Annual Report to Shareholders for the Part I (Item 1)
year ended December 31, 1993...................................... Part II (Items 5, 6, 7 and 8)
Part IV (Item 14)
(2) Designated portions of the Proxy Statement relating to
the 1994 annual meeting of shareholders........................... Part III (Items 10, 11, 12 and 13)
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TABLE OF CONTENTS
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PART I
Item 1. Business..................................................................... 1
General
Corporate Structure and Business............................................. 1
Competition.................................................................. 1
California Ratemaking Mechanisms............................................. 4
General Rate Case and Attrition Mechanisms................................... 4
Electric Revenue Mechanisms.................................................. 5
Gas Revenue Mechanisms....................................................... 6
Other Rate Adjustment Mechanisms............................................. 6
Catastrophic Events Memorandum Account....................................... 7
Regulatory Reform Initiative................................................. 7
PBR.......................................................................... 7
LEMC......................................................................... 8
Accounting Implications...................................................... 8
Long-Term Gas Transportation Rates........................................... 9
Current Rate Proceedings..................................................... 9
Electric Rate Initiative..................................................... 9
1994 Revenue Changes......................................................... 10
Gas Cost Allocation Proceedings.............................................. 11
Workforce Reduction Rate Mechanism........................................... 11
CEE/DSM Programs............................................................. 12
Capital Requirements and Financing Programs.................................. 13
Electric Utility Operations
Electric Operating Statistics................................................ 15
Electric Generating and Transmission Capacity................................ 16
Electric Load Forecast and Resource Planning and Procurement................. 17
Electric Transmission Policies............................................... 18
QF Generation................................................................ 19
Electric Reasonableness Proceeding........................................... 19
Helms Pumped Storage Plant................................................... 20
Geothermal Generation........................................................ 20
Western Systems Power Pool................................................... 21
Gas Utility Operations
Gas Operations............................................................... 21
Gas Operating Statistics..................................................... 22
Natural Gas Supplies......................................................... 23
Gas Regulatory Framework..................................................... 23
Restructuring of Canadian Gas Supply Arrangements............................ 24
Former Canadian Gas Supply and Transportation Arrangements................... 24
Decontracting Plan........................................................... 24
Financial Impact of Decontracting Plan and Litigation........................ 25
Restructuring of Interstate Gas Supply Arrangements.......................... 26
New Interstate Gas Transportation and Procurement Arrangements............... 26
Recovery of Interstate Transportation Demand Charges......................... 27
Gas Reasonableness Proceedings............................................... 28
1988-1990 Record Period...................................................... 28
1991 Record Period........................................................... 29
1992 Record Period........................................................... 29
Affiliate Audit.............................................................. 30
Financial Impact of Gas Reasonableness Proceedings........................... 30
PGT/PG&E Pipeline Expansion Project.......................................... 31
Other Competitive Interstate Pipeline Projects............................... 32
Storage Service.............................................................. 32
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Diablo Canyon
Diablo Canyon Operations..................................................... 33
Diablo Canyon Settlement..................................................... 34
Nuclear Fuel Supply and Disposal............................................. 35
Decommissioning.............................................................. 35
PG&E Enterprises
Non-Utility Electric Generation.............................................. 36
Gas and Oil Exploration and Production....................................... 36
Power Plant Operating Services............................................... 36
Real Estate Development...................................................... 37
Environmental Matters and Other Regulation
Environmental Matters........................................................ 37
Environmental Protection Measures............................................ 37
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
Natural Gas Purchase Contracts Litigation.................................... 44
QF Transmission Constrained Area Litigation.................................. 44
Air District Rulemaking Proceedings.......................................... 45
Antitrust Litigation......................................................... 45
Hinkley Compressor Station Litigation........................................ 46
Item 4. Submission of Matters to a Vote of Security Holders.......................... 47
Executive Officers of the Registrant......................................... 47
PART II
Item 5. Market for the Registrant's Common Equity and Related Stockholder Matters.... 48
Item 6. Selected Financial Data...................................................... 48
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations...................................................... 48
Item 8. Financial Statements and Supplementary Data.................................. 48
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure....................................................... 48
PART III
Item 10. Directors and Executive Officers of the Registrant........................... 48
Item 11. Executive Compensation....................................................... 48
Item 12. Security Ownership of Certain Beneficial Owners and Management............... 48
Item 13. Certain Relationships and Related Transactions............................... 49
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K............. 49
Indemnification Undertaking.................................................. 54
Signatures............................................................................... 55
Report of Independent Public Accountants................................................. 56
Financial Statement Schedules............................................................ 57
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PART I
ITEM 1. BUSINESS.
GENERAL
CORPORATE STRUCTURE AND BUSINESS
Pacific Gas and Electric Company (the Company) is an operating public
utility engaged principally in the business of supplying electric and natural
gas service throughout most of Northern and Central California, a territory with
an estimated population of 12,800,000. As of December 31, 1993, the Company
served approximately 4,400,000 electric customers and 3,600,000 gas customers.
As of December 31, 1993, the Company (excluding subsidiaries) had approximately
23,000 employees.
The Company was incorporated in California in 1905. Its 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.
The Company's service territory covers 94,000 square miles, 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.
As of December 31, 1993, the Company had approximately $27 billion in
assets. The Company generated approximately $10.6 billion in operating revenues
for 1993. The Company's revenues come from three sources: traditional gas and
electric utility operations, Diablo Canyon Nuclear Power Plant (Diablo Canyon)
operations, and activities conducted through the Company's nonregulated
subsidiary, PG&E Enterprises (Enterprises). The Company's traditional utility
operations are generally regulated under the cost-based approach to ratemaking.
Diablo Canyon operations are conducted under a performance based approach to
alternative ratemaking, as a result of the Diablo Canyon rate case 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. Enterprises, a wholly owned subsidiary
of the Company, is the parent company for the nonregulated portion of the
Company's business, which includes non-utility electric generation facilities
and natural gas and oil exploration and development.
The Company serves its electric customers with power generated by eight
primarily natural gas-fueled power plants, ten combustion turbines, one nuclear
power plant, 70 hydroelectric powerhouses, one hydroelectric pumped storage
plant 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 has supply contracts of varying lengths with both Canadian and United
States suppliers. In 1993, about 55% of the Company's gas supply came from
fields in Canada, about 40% came from fields in other states (substantially all
from the U.S. Southwest) and about 5% came from fields in California.
In February 1993, the Company announced a corporate reorganization to
consolidate certain business units, operating regions and operating divisions.
As a result of the reorganization, the Company is organized into five business
units: Customer Energy Services (formerly known as the Distribution business
unit), Electric Supply, Gas Supply, Nuclear Power Generation and Enterprises.
The former Engineering and Construction business unit has been disbanded, with
its functions assumed by the remaining business units. The business units will
continue to be supported by Corporate Services departments, which provide
essential corporate services and management functions.
COMPETITION
Under traditional utility regulatory schemes, utilities have been accorded
the exclusive right to serve customers within designated areas in return for
their commitment to provide service to all who request it.
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Regulation was designed in part to take the place of competition to ensure that
utility services were provided at fair prices.
The Company is currently experiencing increasing competition in both the
gas and electric energy markets. Recent restructuring in both the gas and
electric industries has resulted in the separation of the energy supply function
from the energy services function in both the gas and electric businesses. These
changes have allowed competition to flourish in the gas supply and electric
production segments of the energy business.
As a result of regulatory changes in the gas industry, the Company no
longer provides combined purchase and transportation services to many of its
industrial and large commercial (noncore) gas customers. Instead, many noncore
customers now purchase gas supplies directly from a gas shipper or producer,
reserve interstate transportation capacity directly from an interstate pipeline,
and then purchase intrastate transportation service from the Company once their
gas arrives at the California border. In addition, an interstate pipeline
company has proposed expanding its facilities into the Company's service
territory. If approved, the expansion would allow that pipeline company to
compete directly for intrastate transportation service to the Company's noncore
customers. See "Gas Utility Operations -- Other Competitive Interstate Pipeline
Projects" below.
If, in the restructured gas industry, the Company's gas customers elect to
serve their own gas supply needs, reserve their own interstate transportation
capacity, or leave the Company's system altogether by moving to an alternative
intrastate delivery system, the Company may find that it needs to spread 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,
or other measures are taken, the price per unit would go up and remaining
customers would be asked to pay higher prices, further exacerbating the
competitive pressures.
The restructuring of the natural gas industry has already had a significant
impact on the Company's gas operations. In 1993, the Company terminated its
long-term Canadian gas purchase contracts and entered into new, more flexible
arrangements for the purchase of the Company's current lower gas supply
requirements. In addition, the Company is continuing its efforts to permanently
assign or broker its commitments for firm gas transportation capacity which it
once held for its noncore customers.
Changes in the electric utility industry are following the pattern of
change in the natural gas industry. The Company continues to perform 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, or 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).
Future additions to satisfy electric supply needs in the Company's service
territory will be determined largely through a competitive resource procurement
process, a feature of the new competitive market for electric generation. It is
expected that new power plant projects will be increasingly undertaken by IPPs
rather than utilities, and indeed, the Company has indicated a willingness to
forgo building new generation capacity in its service territory if the electric
resource procurement process is appropriately reformed. In addition, federal
regulators now have increased authority to order a utility to transport and
deliver, or "wheel," energy for any wholesale purchaser or seller of power, and
it is possible that the trend of increasing wholesale transmission access could
lead to increased pressure for state regulators to mandate wheeling to retail
customers. Whether states have authority to order retail wheeling is as yet
undetermined. If future restructuring were to include retail wheeling whereby
customers purchase energy directly from an IPP or other supplier and separately
pay the Company to wheel the purchased power, the Company's power generation
plants and resources would be subject to even greater competition from other
available supply options.
Under current regulation, customer prices are based on an allocation among
customer classes of the Company's approved cost-of-service revenue requirements.
Currently, large industrial and commercial customers are most likely to have
lower cost competitive gas supply and electric generation alternatives. If a
substantial number of these customers were to elect those alternatives and leave
the Company's system, the Company's recovery of its investment in production
sources and distribution facilities would be dependent on prices charged to
remaining customers and the Company's ability to reduce costs. This could lead
to lower
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shareholder returns. In addition, the continuing recession in California's
economy has resulted in reduced growth in demand for the Company's products and
services. California's current economic condition could also lead to increased
regulatory resistance to, and reduced customer acceptance of, higher 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 current electric prices are less competitive than its gas prices.
Although the Company's residential electric bills are at the low end of the
scale nationally, the Company's prices per kilowatt-hour (kWh) are high when
compared with national averages. The Company's prices for industrial customers
average approximately 7.3 cents per kWh, which is comparable to prices charged
by the other major California utilities, but above the industrial electric
prices in many other states. The Company's system average electric price, at
10.6 cents per kWh, is the highest in California and has increased slightly
faster than inflation over the past five years. The Company's electric prices
include the costs for generation, transmission, distribution and customer
service.
In an effort to improve its ability to succeed in the face of greater
competition, the Company has taken steps to improve service to customers, reduce
costs and lower the price of gas and electric service. To help reduce its costs
and maintain competitive prices, the Company has:
-- reduced its workforce by approximately 3,000 positions, which is
expected to result in net revenue requirement savings of approximately
$170 million during the three-year 1993 General Rate Case cycle and
annual revenue requirement savings of at least $200 million beginning in
1996 (see "Current Rate Proceedings -- Workforce Reduction Rate
Mechanism" below);
-- reduced its cost of capital by taking advantage of significantly lower
interest rates to refinance a significant portion of its long-term debt
and a portion of its preferred stock; and
-- obtained California Public Utilities Commission (CPUC) approval to
freeze current electric rates through the end of 1994 and to reduce
electric rates by $100 million for major businesses over an 18-month
period beginning in July 1993 (see "Current Rate Proceedings -- Electric
Rate Initiative" below).
The Company has also taken specific steps which will assist it in remaining
competitive in the restructured gas industry.
-- In November 1993, the Company terminated its long-term Canadian gas
purchase contracts and entered into new, more flexible arrangements for
the purchase of the Company's current lower gas supply requirements. See
"Gas Utility Operations -- Restructuring of Canadian Gas Supply
Arrangements -- Decontracting Plan" below.
-- The Company has implemented gas rate design modifications intended to
more accurately reflect the cost to serve each customer class. Although
implementation of the new rates did not result in an overall increase in
the Company's authorized revenues, upon implementation the overall gas
transportation rates for large industrial noncore customers decreased by
approximately 31% and the overall transportation rate for utilities
using gas to generate electricity decreased by approximately 20%, while
residential and smaller commercial (core) customer rates for bundled gas
service (procurement and transportation) increased by approximately 5%
compared to rates previously in effect.
-- The Company has entered into long-term gas transportation contracts
providing discounted rates for certain major industrial customers. The
CPUC has approved on an expedited basis eleven long-term contracts with
existing customers, ten of those under the Expedited Application Docket
(EAD) procedure. The eleven long-term contracts together represent
approximately 7% of the Company's noncore transportation revenues and
approximately 12% of the Company's transportation revenues from
industrial and cogeneration customers. The Company is currently
precluded from recovering in rates 25% of the revenue shortfalls
resulting from discounts given in these contracts until the CPUC adopts
final rules regarding noncore transportation pricing or approves
recovery by the Company of such amounts as part of the Company's next
gas ratemaking proceeding. See "California Ratemaking
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Mechanisms -- Gas Revenue Mechanisms" below. At that time, the CPUC is
expected to make a further determination as to the rate recovery of
revenue shortfalls attributable to EAD contracts.
-- The Company has filed for approval new long-term gas transportation
rates to be offered to its largest industrial and cogeneration
customers. See "Long-Term Gas Transportation Rates" below. Approval of
these rates will enable the Company to offer competitive long-term rates
without the burden of the contract-by-contract approval required under
the EAD procedure.
In addition, the Company is currently seeking fundamental changes in the
overall regulatory regime under which it must operate in order to allow the
Company greater flexibility to compete in today's markets and still achieve its
pricing and earnings goals. In March 1994, the Company filed an application with
the CPUC requesting it adopt the Company's Regulatory Reform Initiative (RRI).
The RRI has three components. The first, performance based ratemaking for
determining base revenues, would replace several traditional rate cases with a
framework which includes a base revenue index and financial incentives tied to
performance standards. The Company would manage its non-fuel costs in accordance
with revenue determined by an external index, instead of having its actual or
forecast costs subject to detailed CPUC review. The performance standards would
provide the Company with significant incentives to maintain its quality of
service, as well as to provide that service while lowering residential
customers' bills as much as possible. The PBR proposal provides for the sharing
between ratepayers and shareholders of earnings above or below a target utility
return on equity that would be computed annually.
The second component of the RRI involves the creation of a Large Electric
Manufacturing Class (LEMC) of customers. This proposal is intended to provide
large manufacturing customers the price certainty and tariff options they need
to be competitive, as well as the ability to negotiate customized contracts with
the Company. The Company expects that the new tariff options will influence the
LEMC customers' decisions to retain and/or expand their operations in
California, and encourage other manufacturers to establish operations in the
state. Also, the flexibility afforded by the LEMC proposal would allow a more
prompt response to the LEMC customers' existing competitive alternatives, and
thus help to avert the uneconomic bypass of the Company's electric system.
The third component involves the use of market benchmarks to evaluate gas
procurement costs. A specific proposal regarding the third component is not
included in the Company's March 1994 filing but is expected to be filed at a
later date. See "Regulatory Reform Initiative" for more details regarding the
RRI.
CALIFORNIA RATEMAKING MECHANISMS
The ratemaking mechanisms currently applied by the CPUC in setting the
Company's rates are discussed below. As noted above (see "Competition"), the
Company has filed an application with the CPUC requesting adoption of the RRI as
an alternative to the current regulatory approach to setting rates. If adopted,
the RRI would significantly alter the ratemaking mechanisms described below. In
addition, the Company implemented its electric rate initiative in 1993, which
impacted the application of certain of these ratemaking mechanisms in current
rate proceedings (see "Current Rate Proceedings" below).
GENERAL RATE CASE AND ATTRITION MECHANISMS
General Rate Case (GRC). 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 offset the Company's fuel and
fuel-related costs, are set as part of the Energy Cost Adjustment Clause
proceeding for electric operations and the Biennial Cost Allocation Proceeding
for gas operations, as discussed below.) The Company files a GRC application
once every three years, with a decision issued approximately 13 months after the
application is filed. In this proceeding, revenues and expenses are determined
on a forecast or future test-year basis, rather than on a historic-year basis. A
decision was issued in the Company's 1993 GRC in December 1992. In November
1993, the CPUC denied the petition filed in January 1993 by the CPUC's Division
of Ratepayer Advocates
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(DRA) and various special interest groups to modify the decision in the
Company's 1993 GRC so as to reduce the authorized revenue requirements. Under
the current GRC mechanism, the Company's next GRC, based on a 1996 test year,
would be filed in late 1994. Pending adoption of the RRI, the Company will
proceed to make that filing in 1994.
Attrition Rate Adjustment (ARA). The ARA adjusts base rates in the years
between GRC decisions to partially offset attrition in earnings due to changes
in 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 cost of capital, 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. Changes in fuel and
fuel-related costs are addressed in the Energy Cost Adjustment Clause proceeding
for electric operations and the Biennial Cost Allocation Proceeding for gas
operations, both of which are discussed below. The ARA improves the Company's
ability to earn its authorized rate of return for utility operations in the
years between GRCs.
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 currently in place for the Company. The petition requests that any
future attrition rate increases be considered only upon application by the
Company for such relief and only if the then current rate of inflation exceeds
6% on an annual basis. Under such circumstances, the petition recommends that
the level of any attrition rate adjustment ultimately authorized by the CPUC be
limited only to inflation above the 6% threshold level. In June 1993, the
Company filed its response to the petition stating that the current ARA
mechanism is a necessary feature of the three-year GRC cycle even during periods
of low inflation.
ELECTRIC REVENUE MECHANISMS
Energy Cost Adjustment Clause (ECAC). Starting in 1994 with the
reinstatement of the Annual Energy Rate (AER) mechanism described below, the
ECAC provides for recovery of 91% of the cost of fuel and purchased energy, fuel
oil inventory carrying costs up to an authorized level, facility charges and
certain gains or losses from the sale of fuel oil, and for collection of
performance-based Diablo Canyon revenues. The remaining 9% of the energy costs
are recoverable through the AER procedure described below. Differences between
total ECAC revenues and the sum of actual electric energy costs recoverable
through the ECAC and Diablo Canyon revenues accumulate in a balancing account,
usually with interest, and are recovered from or returned to customers through
subsequent ECAC rates. Also included in the ECAC proceeding are revenue
adjustments resulting from the Low Income Rate Assistance program and the
Electric Revenue Adjustment Mechanism described below. Recovery of costs
included in the ECAC is subject to a determination that such costs were incurred
reasonably. (Diablo Canyon costs are not subject to reasonableness review, but
are recovered pursuant to the Diablo Canyon rate case settlement. See "Diablo
Canyon -- Diablo Canyon Settlement" below.) ECAC rates are set once a year,
based on a January 1 revision date, to recover electric energy-related costs
based on a forward-looking calendar test year. ECAC rates also are subject to
adjustment effective May 1 if the required adjustment would be more than 5% of
total annual electric revenues. The Company's next ECAC application is expected
to be filed on April 1, 1994.
Annual Energy Rate (AER). The AER mechanism, which had been suspended in
August 1990, was reinstated by the CPUC in December 1993. The reinstatement of
the AER mechanism places the Company at partial risk for variations between
actual and forecasted energy expenses, since there is no specific balancing
account associated with the AER. The AER provides for recovery of 9% of
forecasted energy costs and the amounts collected under the AER will not be
adjusted if actual costs differ from the amounts authorized. To minimize the
revenue risk resulting from the potential for substantial swings in
energy-related expenses, the allowable pre-tax earnings fluctuation (up or down)
resulting from the AER procedure is limited by a 140 basis-point cap applied to
earnings on the equity portion of total rate base. To the extent that
AER-related energy expenses exceed the allowable range of fluctuation, such
expenses outside the allowable range become subject to ECAC balancing account
treatment. The AER mechanism is on the same time schedule as the ECAC mechanism.
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Electric Revenue Adjustment Mechanism (ERAM). The ERAM allows rate
adjustments to offset the effect on base revenues of changes in electric sales
from the level 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 subsequent ERAM rate adjustments. ERAM rate
adjustments are made as part of the ECAC process with a January 1 revision date.
GAS REVENUE MECHANISMS
Biennial Cost Allocation Proceeding (BCAP). The BCAP forecasts the cost of
gas, allocates costs of providing gas service to various customer classes,
including the base revenue amount approved in the GRC or ARA, and sets
associated rates. Issues considered in the BCAP include: (i) the gas
transportation forecast (throughput), purchased gas costs and transportation
revenue requirement forecast for costs other than the base amount; (ii) the
allocation of costs between core and noncore customer classes; and (iii) the
rates for procurement services for core customers and for transportation and
related services for each customer class. Core customers include all residential
customers and commercial customers that do not exceed certain volume
limitations. Noncore customers are industrial and larger commercial customers
that exceed certain volume limitations. A filing is made on August 15 of every
other year for rates to be effective on April 1 of the following year. The
Company's next BCAP application is currently scheduled to be filed in August
1994. 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
over-or under-collections in balancing accounts would change either bundled core
rates or noncore transportation rates by more than 5%.
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.
Purchased Gas Account (PGA). The PGA is a balancing account which
accumulates differences between actual cost of gas procured for the core
portfolio and revenues intended to cover those costs. Those differences
accumulate with interest, and are recovered from or returned to procurement
customers through subsequent BCAP rate adjustments.
Gas Fixed Cost Accounts (GFCAs). The GFCAs include separate core and
noncore accounts. The core GFCA is a balancing account that accumulates the
differences between most of actual transportation revenues from core customers
and the sum of the authorized core base revenue amount and core gas service
costs. The difference accumulates with interest, and is recovered from or
returned to customers through subsequent BCAP rate adjustments. The noncore GFCA
tracks 75% of the difference between most of actual transportation revenues from
noncore customers and the sum of the authorized noncore base revenues and
noncore gas service costs. This amount accumulates with interest, and is
recovered from or returned to customers through subsequent BCAP rate
adjustments.
Interstate Transition Cost Surcharge (ITCS) Account. The ITCS is a
balancing account that accumulates unrecovered demand charges for interstate
capacity acquired by a utility prior to the adoption of the CPUC's capacity
brokering rules in November 1991. Demand charges that are not fully recovered
because of the operation of the capacity brokering rules accumulate in the ITCS
account and are recovered through subsequent BCAP rate adjustments 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.
OTHER RATE ADJUSTMENT MECHANISMS
Low Income Rate Assistance (LIRA). The LIRA program was established by the
CPUC in 1989 to provide discount residential electric and gas rates for
customers who qualify under low-income criteria. LIRA
6
<PAGE> 10
program administrative costs are recovered through base rate revenues and the
direct cost of LIRA rate discounts are funded through LIRA rate adjustments made
in the ECAC and BCAP proceedings.
Customer Energy Efficiency (CEE). Under the 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 programs.
Beginning in 1994, CEE rate adjustments resulting from shareholder incentives
earned on CEE programs will be determined as part of the Annual Earnings
Assessment Proceeding (AEAP), a new 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 CEE program accomplishments.
See "CEE/DSM Programs" below. Prior to 1994, these adjustments had been made in
the ECAC proceeding.
CATASTROPHIC EVENTS MEMORANDUM ACCOUNT (CEMA)
The 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.
REGULATORY REFORM INITIATIVE
The Company has been engaged in discussions with the CPUC, customers and
other interested parties concerning various reforms to the current regulatory
approach to setting rates. On March 1, 1994, the Company filed an application
with the CPUC requesting it adopt the Company's proposed RRI and approve 1995
electric and gas base revenue requirements.
The RRI is, in part, a response to the report issued in February 1993 by
the CPUC's Division of Strategic Planning on electric industry restructuring.
That report concluded that the current regulatory approach is incompatible with
the emerging industry structure resulting from technological change, competitive
pressure and new market forces. The report indicated that the existing
cost-of-service ratemaking does not provide sufficient incentives for efficient
utility operations and disproportionately favors additions to rate base as
opposed to energy efficiency or purchased power alternatives, and that the
number and complexity of proceedings result in significant administrative costs
and burdens which threaten the quality of public participation in CPUC
proceedings. Although the report indicated the necessity for reform of the
regulatory framework, it did not ultimately recommend a specific strategy.
The Company's RRI has three components: (i) performance based ratemaking
(PBR) for determining base revenues; (ii) establishment of the LEMC, consisting
of large electric manufacturing customers; and (iii) use of market benchmarks to
evaluate gas procurement costs. A specific proposal regarding the third
component is not included in the Company's March 1, 1994 filing but is expected
to be filed at a later date.
In its filing, the Company proposes a schedule calling for technical
workshops in April, public hearings beginning in June and a final CPUC decision
by the end of 1994. The Company has requested that the RRI become effective on
January 1, 1995.
PBR
Under the Company's PBR proposal, electric and natural gas base revenues
would be determined annually by formula rather than through GRCs, ARAs and Cost
of Capital proceedings. Base revenues are the revenues intended to recover the
Company's operation and maintenance expenses (excluding costs for fuel or
fuel-related items), depreciation expense, income and other taxes, and to
provide a return on invested capital. Revenues to offset fuel and fuel-related
costs would still be determined in the ECAC proceeding for electric operations
and the BCAP for gas operations. The PBR mechanism will not apply to the base
revenue associated with Diablo Canyon, including Diablo Canyon decommissioning
costs, which will continue to be determined pursuant to the Diablo Canyon rate
case settlement. See "Diablo Canyon -- Diablo Canyon Settlement" below.
7
<PAGE> 11
The Company's proposed PBR mechanism would determine the base revenues for
a given calendar year by multiplying the base revenues authorized for the prior
calendar year by an index consisting of inflation plus customer growth less a
prescribed productivity factor. Those revenues would also be adjusted up or down
depending on the Company's achievement relative to four performance standards:
CEE programs, Energy Bills (i.e., a comparison of the Company's overall
residential electric and gas bills relative to national averages), Customer
Satisfaction and Electric Service Reliability. The positive or negative
adjustments related to the Company's performance in these four areas would be
one-time modifications to that year's base revenues as calculated under the PBR
index formula. The adjustments for CEE incentives would be determined as they
currently are under existing ratemaking procedures. The maximum adjustments that
the Company could earn related to Energy Bills and Customer Satisfaction is $25
million per year for each, and the maximum for Electric Service Reliability is
$19 million per year. Under PBR, the Company could also apply for an adjustment
to base revenues due to the occurrence of certain extraordinary events outside
the Company's control, including events that would currently qualify for
ratemaking treatment through the existing CEMA (see "California Ratemaking
Mechanisms -- Catastrophic Events Memorandum Account" above).
The PBR proposal provides for the sharing between ratepayers and
shareholders of earnings above or below a target utility return on equity (ROE)
that would be computed annually. To the extent actual ROE exceeds more than 200
basis points above or below the target ROE, the difference would be shared
equally with ratepayers through a reduction or increase in the next year's base
revenue. If actual ROE was more than 500 basis points above or below the target
ROE, then the Company and the CPUC would each have the option to initiate a
proceeding to reexamine the PBR formula.
The Company is proposing that base revenue indexing begin in 1995. However,
the Company proposes to forgo any increase in the electric base revenue for 1995
determined under the PBR mechanism. Instead, 1995 electric base revenue would be
held at the 1994 level.
In its filing, the Company proposes that the RRI remain in place
indefinitely. The Company recommends that after five years the CPUC review the
PBR mechanism and make any necessary adjustments, but not return to the use of
traditional rate cases to set rates.
LEMC
As proposed by the Company, the LEMC would consist of the Company's largest
electric accounts (having an average hourly electricity usage over a 12-month
period of at least 2,000 kilowatts) engaged in manufacturing. Currently,
approximately 120 accounts would qualify for inclusion in the LEMC.
LEMC customers would be removed from cost-of-service ratemaking. Standard
LEMC tariff rates would be determined every calendar year by an index formula,
similar to that used in the PBR mechanism, which is intended to reflect
inflation less a productivity factor. In addition, several long-term tariff
options designed to respond to these customers' competitive alternatives would
be offered to the LEMC. The Company also seeks authorization to negotiate and
enter into customized contracts with LEMC customers. In some cases, the
customized contracts would become effective without prior approval or subsequent
review by the CPUC of the contract terms.
Generally, the Company proposes to separate the costs allocated to the LEMC
and bear the risk of their recovery if sales to these customers decline over
time. The Company's shareholders would bear the risk of LEMC costs that increase
faster than the LEMC price index.
ACCOUNTING IMPLICATIONS
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 Statement of Financial Accounting Standards (SFAS) No. 71,
"Accounting for the Effects of Certain Types of Regulation." As a result, the
Company defers recognition of costs which would otherwise be expensed when
incurred because regulators have provided mechanisms that make it probable that
the costs will be included in future rates. If the RRI is
8
<PAGE> 12
adopted, the mechanics of the rate setting process would change. However, the
Company anticipates that rates derived from the RRI would remain based on
cost-of-service, with the exception of rates for the LEMC customers and rates
established under certain other regulatory mechanisms proposed to be
discontinued upon adoption of the RRI.
If the RRI is adopted as proposed, the Company anticipates that it will
write-off certain regulatory assets, including an estimated $65 million related
to the LEMC customers and potentially additional amounts which may be affected
by the adoption of the RRI, the aggregate amount of which could have a
significant adverse impact on the Company's financial position or results of
operations. The estimated amount related to the LEMC is based on the base
revenue allocation currently used in establishing rates; the actual amount could
vary depending on the allocation method adopted by the CPUC. The final
determination of the accounting impact will be dependent upon the form of the
regulatory reform ultimately adopted.
In the event that recovery of specific costs through rates becomes unlikely
or uncertain for a portion or all of the Company's utility operations, whether
resulting from the expanding effects of competition or specific regulatory
actions which force the Company away from cost-of-service ratemaking, SFAS No.
71 would no longer apply. Discontinuation of SFAS No. 71 would cause the
write-off of the applicable portion of regulatory assets, including regulatory
balancing accounts receivable and those regulatory assets included in deferred
charges, which could have a significant adverse impact on the Company's
financial position or results of operations.
LONG-TERM GAS TRANSPORTATION RATES
On March 18, 1994, the Company filed an advice letter with the CPUC,
requesting authorization to implement an optional long-term noncore gas
transportation tariff. This tariff would be offered to the Company's largest
industrial and cogeneration gas transport customers (having an annual usage
greater than three million therms) under a standard ten-year service agreement.
The proposed rates are intended to enable the Company to more effectively
meet intensified competition by allowing it to offer a long-term competitive
rate without having to obtain CPUC approval on a contract-by-contract basis as
is currently required under the EAD procedure. The proposed rates are within the
range of rates negotiated under existing EAD contracts and will exceed the
marginal cost of serving the customers eligible for the new rates. The Company's
shareholders will bear the risk of any revenue shortfalls attributable to any
differences between the long-term rate option and the customer's otherwise
applicable rate.
The Company has requested that the requested tariff changes become
effective no later than June 1, 1994. If approved, the rates would be offered to
existing qualifying customers in a two-month open season commencing on that
date.
If its advice letter is approved, the Company anticipates that it will
discontinue application of SFAS No. 71 for the customers accepting the long-term
service agreement. This would cause a write-off of as much as approximately $25
million of regulatory assets related to those specific customers which elect to
use the new tariff. This estimated amount is based on the base revenue
allocation currently used in establishing rates; the actual amount could vary
depending on the allocation method adopted by the CPUC.
CURRENT RATE PROCEEDINGS
ELECTRIC RATE INITIATIVE
In April 1993, the Company proposed a comprehensive electric rate
initiative to freeze current retail electric rates through the end of 1994 and
to reduce electric rates by $100 million for major businesses as an economic
stimulus for those customers. In June 1993, the CPUC approved the economic
stimulus rate, effective for the period July 1993 through December 1994.
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<PAGE> 13
In December 1993, the CPUC approved the electric rate freeze and issued its
decisions in the Company's ARA and ECAC proceedings. As part of the ECAC
decision, the CPUC approved the Company's request to defer beyond 1994 recovery
of a portion of the undercollections in the ECAC balancing account. The total
undercollection at December 31, 1993 was $427 million.
Pursuant to the electric rate initiative, 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 1994 (see "1994
Revenue Changes" below).
1994 REVENUE CHANGES
The following table summarizes the various rate case decisions that became
effective on January 1, 1994.
SUMMARY OF RATE CASE DECISIONS
EFFECTIVE JANUARY 1, 1994
(IN MILLIONS)
<TABLE>
<CAPTION>
ELECTRIC GAS TOTAL
------------- ----------- -------------
<S> <C> <C> <C> <C> <C> <C>
1994 Attrition (excluding Cost of Capital)...... $ 157 $ 90 $ 247
1994 Cost of Capital............................ (116) (36) (152)
----- ---- -----
Net Attrition......................... $ 41 $ 54 $ 95
Workforce Reduction Rate Mechanism.............. (53) (25) (78)
Post-retirement Benefits Other Than Pensions.... (75) (35) (110)
Other........................................... (15) -- (15)
----- ---- -----
Total Savings......................... $(143) $(60) $(203)
Recovery of ERAM Undercollections............... 102 -- 102
ECAC/AER/ERAM/LIRA/CEE.......................... 0 4 4
----- ---- -----
Total Change in Revenue Requirement... $ 0 $ (2) $ (2)
----- ---- -----
----- ---- -----
</TABLE>
ARA Proceeding. In December 1993, the CPUC issued a resolution authorizing
the Company to implement an adjustment to base rates pursuant to the ARA
mechanism, effective January 1, 1994, which results in a net attrition increase
of $41 million for electric base rates and $54 million for gas base rates. These
adjustments incorporate the final decision in the Company's 1994 Cost of Capital
proceeding described below. As part of the Company's electric rate initiative,
the $41 million increase excludes approximately $20 million of increased taxes
attributable to the higher corporate tax rate recently adopted for which the
Company would otherwise have sought recovery through the ARA mechanism but
instead will forgo.
The CPUC's resolution also authorized the Company to reduce its 1994
electric and gas base revenues by approximately $143 million and $60 million,
respectively, primarily as a result of the net savings from the Company's
workforce reduction program and a plan change that will limit the amount the
Company will contribute toward post-retirement medical benefits. These
reductions in revenue requirements for electric operations were used to offset
the $41 million attrition increase and to reduce undercollections in the ERAM
balancing account by $102 million. Pursuant to the electric rate initiative,
electric base revenues were held constant, resulting in a consolidated net
change in electric rates of zero effective as of January 1, 1994.
1994 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 1994 designed to provide a utility
return on common equity of 11.00%. The decision authorizes a utility capital
structure of 47.50% common equity, 5.50% preferred stock and 47.00% long-term
debt, which represents an increase from 46.75% in the equity component of the
Company's capital structure. The decision states that the increase will bring
the Company in line with other comparable utilities and will better reflect the
increasingly competitive environment facing electric utilities. When combined
with the authorized costs of debt and preferred stock, the 11.00% return on
equity results in a 9.21% overall authorized utility rate of return for 1994
compared with the 10.13% authorized for 1993. The decision would decrease
revenue requirements by approximately $116 million for electric rates and $36
million for gas rates effective January 1, 1994. As proposed by the Company, the
reduction in the cost of capital was consolidated with other electric revenue
changes such that there was no net increase in electric revenue requirements
effective January 1, 1994.
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<PAGE> 14
ECAC/AER/ERAM/LIRA/CEE. In December 1993, the CPUC issued a decision
authorizing a net zero change in the Company's electric revenue requirement for
the twelve-month forecast period beginning January 1, 1994. The decision also
authorizes a gas revenue requirement increase of approximately $4 million
relating to the Company's CEE programs for the same forecast period. The new
rates are effective as of January 1, 1994.
The net zero change in the Company's overall annual electric revenue
requirement for 1994 is composed of a $112 million increase under the ECAC
balancing account, a $7 million increase under the AER mechanism, a $129 million
decrease under the ERAM, a $1 million decrease under the LIRA account and a $11
million increase for recovery of incentives earned on CEE programs.
Consistent with its electric rate initiative, the Company had requested
deferral beyond 1994 of a portion of undercollections in the ECAC balancing
accounts. The total undercollection at December 31, 1993 was $427 million. In
its decision, the CPUC approved the Company's request, but cautioned that the
CPUC does not view its action as simply a deferral with payment due in 1995.
Rather, the CPUC indicated that it expects the Company to take the necessary
measures over the year to reduce its rates. With the stated objective of
providing additional incentives for cost containment, the CPUC refused to allow
the Company to collect interest on the revenue requirement deferral and ordered
the reinstatement of the AER mechanism, which places the Company at risk for
nine percent of the variations between actual and forecasted energy expenses.
With respect to CEE, the decision authorizes the Company to recover in
rates over three years an aggregate electric and gas revenue increase of
approximately $41 million for shareholder incentives relating to CEE measures
installed in 1992, a reduction from the $59 million initially requested by the
Company. Those revenues will be recovered in equal annual amounts beginning in
1994. The electric and gas revenue increases of $11 million and $4 million,
respectively, authorized in rates for 1994 relating to CEE include one third of
the 1992 incentives as well as amounts earned in previous years. However, the
decision also provides that the $41 million allowed as shareholder incentives
shall be subject to refund pending completion of a CPUC audit of all the
Company's 1990-1992 CEE expenses. The audit is required to be completed by the
end of 1994.
GAS COST ALLOCATION PROCEEDINGS
In October 1992, the CPUC issued a decision in the Company's 1992 BCAP
which resulted in a $434 million decrease in the core gas revenue requirement
and a $3 million decrease in the noncore gas revenue requirement over a two-year
period from then current rates. The decision allocated approximately $250
million in annual revenues to be collected from the noncore transportation
customers other than the Company's electric department, with 75% balancing
account treatment for transportation revenues from all noncore customers.
In September 1993, the Company submitted an interim, or trigger, filing as
permitted under the BCAP mechanism to set new rates. The Company's filing
requests an increase of $136.7 million in the Company's core gas revenue
requirement, which would result in a 7.7% increase in core rates over rates
currently in effect. The Company requested that the proposed increase not be
implemented until May 1, 1994. The CPUC has not acted yet on the Company's
request.
WORKFORCE REDUCTION RATE MECHANISM
In February 1993, the Company announced a corporate reorganization and
workforce reduction program. In conjunction with implementing the workforce
reduction program, the Company filed an application with the CPUC to establish a
balancing account through which the labor savings, net of the related costs,
would be flowed back to the Company's customers in the form of reduced gas and
electric rates. In March 1993, the CPUC authorized the establishment of a
memorandum account to record all costs and savings incurred in connection with
the 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. In
its filing with the CPUC, the Company proposed that the revenue requirement
savings achieved during the balance of the 1993 GRC cycle through the workforce
reduction program be passed on to ratepayers over a two-year period beginning
January 1, 1994.
As of December 31, 1993, the Company had recorded net workforce reduction
program costs of $264 million. In April 1993, the Company announced a freeze on
electric rates through 1994. As a result, the
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<PAGE> 15
Company has expensed $190 million of such costs relating to electric operations.
The remaining $74 million of such costs relating to gas operations has been
deferred for future rate recovery. The amount deferred is currently being
amortized as savings are realized. The Company is currently seeking rate
recovery of all costs incurred in connection with the workforce reduction
program relating to electric and gas operations. However, in its RRI filing (see
"Regulatory Reform Initiative" above), the Company requests that if the CPUC's
review of the costs and savings associated with the workforce reduction program
is not completed and reflected in rates before PBR begins, such review not be
conducted. Under the RRI, the memorandum account established for such costs and
savings would be terminated as of January 1, 1995.
During 1994 and 1995, the Company expects to benefit from the expense
reduction attributable to the electric operations' workforce reduction. The
Company currently estimates that the workforce reduction program will result in
a net revenue requirement savings of approximately $170 million during the
three-year 1993 GRC cycle, which ends December 31, 1995. Beginning in 1996, the
workforce reduction program is expected to result in annual revenue requirement
savings of at least $200 million.
CEE/DSM PROGRAMS
The Company has long been active in the implementation of CEE and other
demand-side management (DSM) programs which provide incentives to customers to
implement energy-efficient measures. These measures allow the Company to defer
capital expenditures in connection with generating, 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 billion on DSM programs,
allowing the Company to avoid the need for approximately 1,600 megawatts (MW) of
new generating capacity.
In 1990, the CPUC issued a decision which implemented expanded CEE programs
developed through collaborative efforts by the Company, other California
utilities, regulatory agencies and environmental and consumer groups. The
decision approved an incentive mechanism intended to encourage and sustain the
Company's commitment to CEE. The mechanism adopted in 1990 provided that the
Company can recover in rates the authorized costs of DSM programs plus
shareholders incentives equal to 15% of the estimated net present value of
energy savings from specified resource, or shared savings, programs that produce
substantial net avoided capacity, transmission, distribution and energy costs
savings, and 5% of the cost of certain service programs, including the Company's
direct weatherization and energy efficiency education programs. Incentives
earned on the implementation of CEE measures were originally authorized to be
recovered in rates over the three-year period following the year in which the
recovery of those incentives was authorized in the Company's annual ECAC
proceeding.
The CPUC subsequently initiated a rulemaking proceeding on CPUC policies
related to DSM programs (DSM Proceeding), and in a February 1992 decision,
concluded that, as an interim policy beginning in 1993, shareholders' return on
DSM measures should be no greater than shareholders' return on equivalent
investments in utility constructed plants. Accordingly, in the Company's 1993
GRC, the percentage of energy savings to be earned as shareholder incentives for
1993 resource program accomplishments was reduced to 5.1% from the 15% earned in
1990, 1991 and 1992. Pending determination of a permanent shareholder incentive
mechanism in the DSM Proceeding, the percentage return applied in calculating
the shared savings incentive will be recalculated each year based on the rate of
return on utility constructed plants and the forecasted costs and benefits of
DSM programs.
In another 1993 decision, the CPUC determined that shareholder incentives
earned on shared savings 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. In addition, the decision provided that,
beginning in 1994, the amount of shareholder incentives authorized for the
Company and other California energy utilities will be determined annually in the
AEAP. See "California Ratemaking Mechanisms -- Other Rate Adjustment Mechanisms"
above.
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The CPUC held hearings in 1993 to determine whether shareholder incentives
should be continued for DSM programs beyond 1994. In September 1993, the CPUC
concluded that DSM shareholder incentives should be continued under the current
regulatory framework. Hearings will be held in 1994 to determine the appropriate
incentive mechanism and incentive level for DSM programs in 1995 and beyond.
The Company estimates that it will earn approximately $7 million
(after-tax) in shareholder incentives from the 1993 CEE programs. The Company
plans to spend approximately $260 million on CEE programs in 1994, an increase
over the $186 million spent in 1993. If the Company meets its 1994 energy
savings goals, it could earn over a ten-year period approximately $11 million
(after-tax) under the shareholder incentive mechanism. The Company is permitted
to recover, through a balancing account, up to a maximum of 130% of the amount
authorized for shared savings programs. As in the past, the Company is subject
to a penalty if actual accomplishments under a shared savings program fall below
the minimum performance standard established for the program.
CAPITAL REQUIREMENTS AND FINANCING PROGRAMS
The Company continues to require capital for additions to its facilities
and to maintain and enhance the efficiency and reliability of existing
generation, transmission and distribution facilities. Expenditures for these
purposes, including the allowance for funds used during construction (AFUDC)
were $1,883 million for 1993. New investments in nonregulated businesses totaled
$234 million in 1993.
The following table sets forth the forecasted total capital requirements,
consisting of capital expenditures for the utility functions, the expansion of
the gas pipeline from Canada to California, Diablo Canyon and the nonregulated
investments of Enterprises and amounts for maturing debt and sinking funds for
the years 1994 through 1998.
CAPITAL REQUIREMENTS
(IN MILLIONS)
<TABLE>
<CAPTION>
1994 1995 1996 1997 1998 TOTAL
------ ------ ------ ------ ------ -------
<S> <C> <C> <C> <C> <C> <C>
Utility(1)(2)............................ $1,397 $1,319 $1,369 $1,404 $1,466 $ 6,955
Diablo Canyon(2)......................... 105 87 82 76 76 426
Enterprises(3)
PG&E Resources Company(4).............. 133 -- -- -- -- 133
U.S. Generating Company(5)............. 121 144 129 95 124 613
PG&E Properties, Inc................... 6 5 8 5 4 28
------ ------ ------ ------ ------ -------
Total Capital Expenditures.......... 1,762 1,555 1,588 1,580 1,670 8,155
Maturing Debt and Sinking Funds.......... 221 514 460 369 714 2,278
------ ------ ------ ------ ------ -------
Total Capital Requirements.......... $1,983 $2,069 $2,048 $1,949 $2,384 $10,433
------ ------ ------ ------ ------ -------
------ ------ ------ ------ ------ -------
</TABLE>
- ------------
(1) Utility expenditures are shown net of reimbursed capital and include
California electric and gas operations and existing operations of the gas
pipeline from Canada to California. Utility expenditures also include any
amounts relating to the expansion of Pacific Gas Transmission Company's
(PGT) pipeline system in 1994 through 1996 to provide additional deliveries
in the Pacific Northwest. Capital expenditures relating to such further
expansion total approximately $84 million.
(2) Utility expenditures include AFUDC. Diablo Canyon expenditures include
capitalized interest.
(3) Enterprises' actual capital expenditures may vary significantly depending on
the availability of attractive investment opportunities.
(4) In January 1994, the Company approved a final plan for the disposition of
PG&E Resources Company (Resources) in 1994, if market conditions remain
favorable. In light of the planned disposition, the forecasted capital
expenditures for Resources in 1994 was recently increased to the level
indicated in the table above. If Resources is not divested in 1994, the
Company's capital expenditures would be approximately $100 million per year
in each of the years 1994 through 1998.
(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.
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<PAGE> 17
These contributions, payable upon commercial operation of the projects, are
estimated to be $95 million, $151 million and $27 million in 1994, 1995 and
1996, respectively. There are no current commitments to make contributions
in 1997, 1998 or thereafter.
Most of the utility capital expenditures for 1994 through 1998 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 improve 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 1994
through 1998 will include approximately $2,278 million for payment at maturity
of outstanding long-term debt and for meeting sinking fund requirements for
debt. In an effort to reduce financing costs, the Company redeemed or
repurchased $3,536 million of high-cost first and refunding mortgage bonds and
$267 million of redeemable preferred stock in 1993. In addition, in December
1993, the Board of Directors authorized the Company to redeem or repurchase up
to $1.2 billion of first and refunding mortgage bonds, $125 million of
medium-term notes and $175 million of redeemable preferred stock. Of those
amounts, $80 million of bonds, $40 million of medium-term notes and $75 million
of preferred stock were redeemed in February and March 1994. Redemptions and
repurchases were financed in part by the issuance in 1993 of $2,950 million of
first and refunding mortgage bonds (Series 93A through 93H), $750 million of
medium-term notes and $200 million of redeemable preferred stock. In 1993, the
Company also entered into loan agreements with the California Pollution Control
Financing Authority to borrow proceeds of $260 million of tax-exempt pollution
control bonds issued to finance sewage and solid waste disposal facilities.
The funds necessary for the Company's 1994-1998 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. These programs and the projections 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.
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<PAGE> 18
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
----------------------------------------------------------------------
1993 1992 1991 1990 1989
---------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C>
CUSTOMERS (AVERAGE FOR THE YEAR):
Residential....................................... 3,748,831 3,708,374 3,665,055 3,604,327 3,532,306
Commercial........................................ 449,612 455,480 450,789 440,670 429,973
Industrial........................................ 1,192 1,207 1,186 1,102 1,185
Agricultural...................................... 91,376 94,562 96,270 98,131 97,980
Public street and highway lighting................ 16,154 15,681 15,314 14,979 14,624
Other electric utilities.......................... 28 24 21 20 18
---------- ---------- ---------- ---------- ----------
Total....................................... 4,307,193 4,275,328 4,228,635 4,159,229 4,076,086
---------- ---------- ---------- ---------- ----------
---------- ---------- ---------- ---------- ----------
GENERATED, RECEIVED AND SOLD -- KWH (IN MILLIONS):
Generated:
Hydroelectric plants............................ 14,403 7,537 7,996 8,008 10,804
Thermal-electric plants:
Fossil fueled................................. 19,070 26,623 21,984 24,496 25,756
Geothermal.................................... 6,491 7,007 6,947 7,324 8,054
Nuclear....................................... 16,816 16,698 15,073 16,274 15,812
---------- ---------- ---------- ---------- ----------
Total thermal-electric plants............... 42,377 50,328 44,004 48,094 49,622
Wind and solar plants........................... -- -- -- -- --
Received from other sources(1).................... 48,859 46,243 48,966 46,682 39,408
---------- ---------- ---------- ---------- ----------
Total gross system output(2)................ 105,639 104,108 100,966 102,784 99,834
Delivered for interchange or exchange............. 8,848 3,912 5,391 5,281 12,055
Delivered for the account of others(1)............ 13,726 17,235 13,602 16,093 10,523
Helms pumpback energy (3)......................... 452 398 593 396 1,002
Company use, losses, etc.(4)...................... 6,960 7,278 7,184 6,957 6,488
---------- ---------- ---------- ---------- ----------
Total energy sold........................... 75,653 75,285 74,196 74,057 69,766
---------- ---------- ---------- ---------- ----------
---------- ---------- ---------- ---------- ----------
POWER PLANT FUEL SUPPLY (IN THOUSANDS):
Natural gas (equivalent barrels).................. 28,791 43,446 36,262 37,777 37,391
Fuel oil.......................................... 2,080 171 631 2,066 4,848
Nuclear (equivalent barrels)...................... 28,724 28,540 25,808 27,847 27,082
---------- ---------- ---------- ---------- ----------
Total....................................... 59,595 72,157 62,701 67,690 69,321
---------- ---------- ---------- ---------- ----------
---------- ---------- ---------- ---------- ----------
POWER PLANT FUEL COSTS (AVERAGE COST PER MILLION BTU'S):
Natural gas....................................... $2.86 $2.61 $2.75 $3.09 $2.84
Fuel oil.......................................... $3.49 $3.13 $3.00 $4.11 $2.73
Weighted average.................................. $2.90 $2.62 $2.75 $3.14 $2.83
SALES -- KWH (IN MILLIONS):
Residential....................................... 24,111 23,664 23,535 23,222 22,845
Commercial........................................ 26,258 26,246 25,758 25,867 24,723
Industrial........................................ 16,492 16,600 16,472 16,271 16,222
Agricultural...................................... 3,672 4,741 4,734 4,702 3,898
Public street and highway lighting................ 419 400 389 376 366
Other electric utilities.......................... 4,701 3,634 3,308 3,619 1,712
---------- ---------- ---------- ---------- ----------
Total energy sold........................... 75,653 75,285 74,196 74,057 69,766
---------- ---------- ---------- ---------- ----------
---------- ---------- ---------- ---------- ----------
REVENUES (IN THOUSANDS):
Residential....................................... $2,952,893 $2,790,605 $2,729,763 $2,418,250 $2,212,789
Commercial........................................ 2,914,855 2,864,817 2,745,040 2,532,655 2,289,726
Industrial........................................ 1,183,728 1,210,754 1,186,452 1,071,714 1,032,304
Agricultural...................................... 419,628 478,941 477,397 429,445 346,982
Public street and highway lighting................ 55,976 53,133 50,631 47,121 45,210
Other electric utilities.......................... 242,433 185,555 204,089 217,276 90,796
---------- ---------- ---------- ---------- ----------
Revenues from energy sales.................. 7,769,513 7,583,805 7,393,372 6,716,461 6,017,807
Miscellaneous..................................... 84,402 44,922 96,367 211,199 50,959
Other............................................. 3,589 6,794 6,813 5,839 4,806
Regulatory balancing accounts..................... 8,539 111,971 (127,912) 102,572 142,478
---------- ---------- ---------- ---------- ----------
Operating revenues.......................... $7,866,043 $7,747,492 $7,368,640 $7,036,071 $6,216,050
---------- ---------- ---------- ---------- ----------
---------- ---------- ---------- ---------- ----------
</TABLE>
- ----------
(1) Includes energy supplied through the Company's system by the City and County
of San Francisco for San Francisco's own use and for sale by San Francisco
to its customers, by the Department of Energy for government use and sale to
its customers, and by the State of California for California Water Project
pumping, as well as energy supplied by QFs and purchases from other
utilities.
(2) Includes energy output from Modesto and Turlock Irrigation Districts' own
resources.
(3) Represents energy required for pumping operations.
(4) Includes use by business units other than Electric Supply.
15
<PAGE> 19
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31
-----------------------------------------------------------------
1993 1992 1991 1990 1989
--------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C>
SELECTED STATISTICS:
Total customers (at year-end)..................... 4,400,000 4,300,000 4,300,000 4,200,000 4,100,000
Average annual residential usage (kWh)............ 6,431 6,381 6,421 6,443 6,468
Average billed revenues per kWh (c):
Residential..................................... 12.25 11.79 11.60 10.41 9.69
Commercial...................................... 11.10 10.92 10.66 9.79 9.26
Industrial...................................... 7.18 7.29 7.20 6.59 6.36
Agricultural.................................... 11.43 10.10 10.08 9.13 8.90
Net plant investment per customer ($)............. 3,436 3,428 3,445 3,443 3,474
Electric control area capability(1)(MW)........... 23,009 22,475 21,670 22,931 23,244
Electric net control area peak demand(2)(MW)...... 19,607 18,594 18,620 19,400 17,623
</TABLE>
- ------------
(1) Area net capability at time of annual peak, based on 1977 water conditions
which are the most adverse of record to date.
(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, 1993, the Company owned and operated the following
generating plants, all located in California, listed by energy source:
<TABLE>
<CAPTION>
NET
OPERATING
NUMBER CAPACITY
GENERATING PLANT COUNTY LOCATION OF UNITS KILOWATTS (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
------ ---------------
Fossil Fueled:
Contra Costa(1).................... Contra Costa 7 1,260,000
Humboldt Bay....................... Humboldt 2 105,000
Hunters Point...................... San Francisco 4 429,000
Kern(1)............................ Kern 2 180,000
Morro Bay.......................... San Luis Obispo 4 1,002,000
Moss Landing(1).................... Monterey 7 2,060,000
Oakland............................ Alameda 3 165,000
Pittsburg.......................... Contra Costa 7 2,022,000
Potrero............................ San Francisco 4 363,000
Mobile Turbines(2)................. Contra Costa and Humboldt 3 45,000
Geothermal:
The Geysers(3)..................... Sonoma and Lake 14 1,224,000
Nuclear:
Diablo Canyon...................... San Luis Obispo 2 2,160,000
------ ---------------
Thermal Subtotal................... 59 11,015,000
------ ---------------
Total...................................................... 173 14,930,100
------ ---------------
------ ---------------
</TABLE>
- ----------
(1) The following fossil fuel steam units (412 MW) were on long-term standby
reserve during 1993. The units require a 12-18 month reactivation time, and
are included as unavailable capacity in the Control Area Net Capacity table
below.
Contra Costa Unit 3 (116 MW)
Kern Unit 1 (74 MW)
Kern Unit 2 (106 MW)
Moss Landing Unit 1 (116 MW)
(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.
16
<PAGE> 20
To transport energy to load centers, the Company as of December 31, 1993,
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 33,130,000 kilovolt-amperes (kVa). Energy is
distributed to customers through approximately 104,133 circuit miles of
distribution system and distribution substations having a capacity of
approximately 24,805,000 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 1977 water conditions, which are the most adverse on record
to date) 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, 1993.
<TABLE>
<CAPTION>
CONTROL AREA
NET CAPACITY
(AT DATE OF 1993 PEAK)
--------------------
KW %
--------- -----
<S> <C> <C>
Sources of Electric Generation:
Company-Owned Plants:
Fossil Fueled.................. 7,634,000 52
Geothermal..................... 1,224,000 8
Nuclear........................ 2,160,000 15
--------- -----
Total Thermal................ 11,018,000 75
Hydroelectric (available)...... 3,695,700 25
Solar.......................... 0 0
--------- -----
Total Company-Owned Capacity..... 14,713,700 100
-----
-----
Less Unavailable Capacity...... (1,455,500)
---------
Total Company Available
Capacity....................... 13,258,200 62
Capacity Received from Others:
QF Producers (available)....... 2,987,500 14
Area Producers &
Imports...................... 5,307,300 24
--------- -----
Capacity from Others........... 8,294,800 38
--------- -----
Total Available Capacity......... 21,553,000 100
--------- -----
--------- -----
Total Area Demand(1)(2)............ 19,607,000
---------
---------
</TABLE>
<TABLE>
<CAPTION>
GENERATION
YEAR ENDED
DECEMBER 31, 1993(3)
----------------------
KWH
THOUSANDS %
------------- -----
<S> <C> <C>
Electric Generation:
Company-Owned Plants:
Fossil Fueled.................. 19,069,947 19
Geothermal..................... 6,491,142 6
Nuclear........................ 16,816,168 17
------------- ----
Total Thermal................ 42,377,257 42
Hydroelectric.................. 14,402,500 14
Solar.......................... 804 0
------------- ----
Total Company Generation......... 56,780,561 56
Helms Pumpback Energy............ (452,206) 0
------------- ----
Net Company Generation......... 56,328,355 56
Generation Received from Others:
QF Producers................... 21,302,621 22
Area Producers &
Imports...................... 22,241,951 22
------------- ----
Generation from Others......... 43,544,572 44
Total Area Generation............ 99,872,927 100
------------- ----
------------- ----
</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 1993 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 9.9% and total reserve (spinning
reserve and capability available within a short period of time) was 18.5%.
(3) Represents actual year net generation from sources shown.
ELECTRIC LOAD FORECAST AND RESOURCE PLANNING AND PROCUREMENT
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 twelve-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 Company forecasts area electric peak demand (on a CEC area basis) to
increase from approximately 16,100 MW in 1994 to approximately 23,000 MW in
2013, reflecting a compound annual growth rate of 1.9%. The Company forecasts
area electric energy load to increase from approximately 87,500 gigawatthours
(GWh) in 1994 to 120,900 GWh in 2013, reflecting a compound annual growth rate
of 1.7%. The Company's energy and peak demand forecasts closely approximate the
CEC staff's forecasts through 2005, and are somewhat higher than the CEC staff's
forecasts for periods thereafter, primarily due to the Company's more optimistic
economic and demographic assumptions.
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 243.5 MW of new purchases or company-owned
17
<PAGE> 21
resources resulting from the BRPU solicitation, (ii) approximately 290 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 also anticipates completing the 2,500 MW of CEE and load
management improvements initiated in 1990. The Company currently plans no new
major construction projects for electric supply before the year 2000, other than
projects already under development.
Future additions to satisfy electric supply needs in the Company's service
territory 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 CPUC is exploring the use of an integrated bidding system in which both
resource generation and DSM bidders would participate in the competitive
procurement process. In October 1993, the CPUC issued a decision in the DSM
Proceeding described above (see "General -- CEE/DSM Programs" above) which
selected the Company to conduct an integrated bidding pilot program. The CPUC
ordered the Company to conduct a pilot bid program for between 49 and 200 MW to
test the feasibility of integrated bidding. The Company is granted significant
flexibility in designing and implementing the bid program, in exchange for its
agreement not to submit a bid in the pilot program. The Company expects to issue
requests for bids in late 1994.
The CEC committee conducting proceedings relating to the CEC's 1994
Electricity Report issued orders expanding 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. The orders direct
comprehensive studies in a wide variety of areas, including wholesale wheeling
and regional integration of transmission systems, performance based ratemaking
and "maximum feasible" competitive choices for customers. Workshops and hearings
related to these orders will take place during 1994, with the committee expected
to report the results of its analysis to the CEC in early 1995.
ELECTRIC 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. The CPUC
explicitly stated that the investigation will not consider proposals for retail
transmission service and should not be construed as a challenge to the franchise
retail service territories of public utilities. The CPUC indicated that it
believed the transmission investigation was necessary at this time in order to
assure development of a competitive electricity generation sector in California.
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 second phase of the investigation could consider certain broader
long-term transmission access and cost issues. In 1993, the assigned
commissioner ruled that the scope of any future rulemaking in the second phase
of the investigation would be limited to wholesale transmission issues which are
not likely to be fully addressed by the Federal Energy Regulatory Commission
(FERC). These issues include (i) coordinated regional transmission planning,
(ii) unbundling of transmission service costs, (iii) determination of the best
access form or vehicle, (iv) use of alternative dispute resolution mechanisms,
(v) relative priority of transmission requests, and (vi) incentives for
transmitting utilities. The assigned administrative law judge
18
<PAGE> 22
(ALJ) has been ordered to commence discussions regarding procedure and schedule
in the second phase of the investigation.
On the federal level, in 1993 the FERC began implementation of the National
Energy Policy Act of 1992 (Energy Act). The Energy Act expanded the FERC's
authority to order an electric utility to provide wholesale transmission
service. The FERC may order any owner of transmission lines to provide
transmission service, subject to a public interest finding, on application of
any wholesale purchaser or seller of power. The FERC must allow the transmitting
utility to recover its costs and may not order transmission service which will
unreasonably impair system reliability. The Energy Act prohibits the FERC from
ordering retail transmission service, or wheeling, directly to an ultimate
consumer.
In 1993, the FERC issued a final rule on the transmission access
information utilities must file annually and policy statements concerning
regional transmission groups and the necessary components of a good faith
request and response for transmission access under the Energy Act. The FERC also
opened an investigation on transmission pricing.
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.
Payments to QFs are expected to vary in future years. The amount of energy
received from QFs and the total energy and capacity payments made under these
agreements were:
<TABLE>
<CAPTION>
1993 1992 1991
------ ------ ------
(IN MILLIONS)
<S> <C> <C> <C>
kWh received............................................. 21,242 21,173 19,127
Energy payments.......................................... $1,099 $1,084 $970
Capacity payments........................................ $503 $489 $450
</TABLE>
As of December 31, 1993, the Company had approximately 6,000 MW of QF
capacity under CPUC-mandated power purchase agreements. Of the 6,000 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 6,000 MW of QF capacity consists of 3,400 MW from cogeneration
projects, 1,500 MW from wind projects and 1,100 MW from other projects,
including biomass, geothermal, solar and hydroelectric.
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. The DRA indicated that it
would recommend disallowances over the 15-year term of the contracts of
approximately $80 million. In its report on ECAC expenses for the 1992 record
period, the DRA recommended a disallowance of approximately $3.5 million for two
of these agreements.
19
<PAGE> 23
The Company contested the DRA's assertions in its rebuttal testimony which
was filed in November 1993. A decision is not expected from the CPUC until
mid-1994. The Company is unable to predict the outcome of this matter, but
believes the ultimate outcome will not have a significant adverse impact on its
financial position or results of operation.
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
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 while 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 $106 million at December 31,
1993.
In August 1991, the Company filed an application with the CPUC to increase
electric base rates to allow recovery of a portion of the remaining unrecovered
costs associated with Helms. In addition to placing these costs in rate base,
the Company seeks to recover the associated revenue requirement on such costs
since 1984 and lost revenues during the time the generators were being repaired.
In June 1993, the DRA issued its report on the Company's 1991 Helms
application and recommended a disallowance of all requested costs and revenues.
As a matter of policy, the DRA recommends that ratepayers should not be held
responsible for plant costs or losses incurred by a utility due to contractor
error whether or not the utility was prudent, and cites past CPUC action for
this policy. In addition, the DRA contends that the Company acted imprudently in
the management of the project and failed to adequately oversee the engineering
and design of the generators. The DRA argues that the Company should not recover
any revenue requirements associated with the generator costs for the period
since 1984 since those revenues were not authorized previously by the CPUC and
would constitute retroactive ratemaking. With respect to the lost revenues and
related recorded interest during the time that Helms was out of service for the
modification and repair of the generators, the DRA asserts that the Company has
failed to establish that the outage was not caused by a problem first identified
during the precommercial testing program.
The Company filed its rebuttal testimony in January 1994 asserting it is
unreasonable to hold a utility responsible for all costs arising out of
contractor error in all instances without regard to the specific facts of the
case. This testimony also asserts that the Company was prudent in managing and
overseeing the project, and that various issues raised by the DRA were not based
on facts or were irrelevant to the application.
The Company has commenced discussions with the DRA in an attempt to
expeditiously resolve the treatment of Helms costs through a settlement. The
Company is uncertain whether, and to what extent, any of the remaining $106
million of costs and revenues will be recovered through the ratemaking process.
GEOTHERMAL GENERATION
Because of declining geothermal steam supplies, the Company's geothermal
units at The Geysers Power Plant (The Geysers) are forecast to operate at
reduced capacities. The consolidated Geysers capacity factor is forecast to be
approximately 55.9% in 1994, which includes forced outages, scheduled overhauls,
and projected steam shortage curtailments, as compared to the actual Geysers
capacity factor of 61.8% in 1993. 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.
20
<PAGE> 24
WESTERN SYSTEMS POWER POOL (WSPP)
In 1991, the FERC approved an agreement among 40 utilities operating in 22
states and British Columbia for a permanent 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.
GAS UTILITY OPERATIONS
GAS OPERATIONS
As of December 31, 1993, the Company owned and operated approximately 5,700
miles of gas transmission lines and approximately 35,000 miles of gas
distribution lines. The Company has three underground storage facilities. The
Company's peak day send-out of gas during the year ended December 31, 1993, was
4,002 million cubic feet (MMcf). The total volume of gas throughput during that
period was approximately 701,706 MMcf, of which 430,718 MMcf was sold to direct
end-use or resale customers, 161,895 MMcf was used by the Company principally as
fuel for fossil-fueled electric generating plants, and 109,093 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 1993 report forecasts the Company's gas demand from 1993 through
2010.
The forecast growth rate for the Company's service territory of 1.8% per
year from 1993 through 2010 is higher than the 1.3% annual forecasted growth
rate shown in last year's report for the same period for two reasons. First, a
more optimistic forecast of growth in the number of households leads to a higher
forecasted growth rate of gas sales. Second, the expected success of the
Company's natural gas vehicle program and the implementation of federal and
state clean air regulations leads to a much higher forecast of natural gas
vehicle use.
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 108 billion cubic feet for 1993. The forecast assumes that bypass
which began in 1991 will change little from the 1993 level and does not include
any potential bypass from the proposed Mojave Pipeline Company expansion
project. See "Other Competitive Interstate Pipeline Projects" below.
21
<PAGE> 25
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
-----------------------------------------------------------------
1993 1992 1991 1990 1989
--------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C>
CUSTOMERS (AVERAGE FOR THE YEAR):
Residential..................................... 3,339,859 3,311,881 3,275,247 3,214,424 3,144,667
Commercial...................................... 195,815 195,689 197,029 194,596 192,303
Industrial...................................... 2,149 1,221 2,084 2,154 2,116
Other gas utilities............................. 20 18 14 16 15
--------- --------- --------- --------- ---------
Total..................................... 3,537,843 3,508,809 3,474,374 3,411,190 3,339,101
--------- --------- --------- --------- ---------
--------- --------- --------- --------- ---------
GAS SUPPLY -- MCF (IN THOUSANDS):
Purchased:
From Canada................................... 329,693 321,770 345,020 372,421 371,137
From California............................... 32,096 50,953 73,257 77,935 88,382
From other states............................. 243,058 327,272 240,141 273,981 296,703
--------- --------- --------- --------- ---------
Total purchased........................... 604,847 699,995 658,418 724,337 756,222
Net from storage (to storage)................... (12,234) 10,135 (6,849) 6,152 6,800
--------- --------- --------- --------- ---------
Total..................................... 592,613 710,130 651,569 730,489 763,022
Company use, losses, etc.(1).................... 161,895 281,021 223,176 257,943 265,813
--------- --------- --------- --------- ---------
Net gas for sales......................... 430,718 429,109 428,393 472,546 497,209
--------- --------- --------- --------- ---------
--------- --------- --------- --------- ---------
SALES -- MCF (IN THOUSANDS):
Residential..................................... 206,053 190,176 210,657 204,433 210,116
Commercial...................................... 82,048 79,983 85,203 102,579 101,309
Industrial...................................... 133,178 145,356 119,916 133,930 144,233
Other gas utilities............................. 9,439 13,594 12,617 31,604 41,551
--------- --------- --------- --------- ---------
Total(2).................................. 430,718 429,109 428,393 472,546 497,209
--------- --------- --------- --------- ---------
--------- --------- --------- --------- ---------
TRANSPORT -- MCF (IN THOUSANDS):
Gas transport................................... 109,093 103,186 207,544 168,969 145,548
REVENUES (IN THOUSANDS):
Residential..................................... $1,152,494 $1,092,324 $1,226,094 $1,139,998 $1,108,446
Commercial...................................... 467,962 479,599 551,669 565,608 532,587
Industrial...................................... 367,221 425,467 366,346 453,871 449,526
Other gas utilities............................. 25,654 38,504 43,224 84,771 99,110
--------- --------- --------- --------- ---------
Revenues from gas sales................... 2,013,331 2,035,894 2,187,333 2,244,248 2,189,669
Gas transport................................... 56,733 75,606 133,348 106,759 73,838
Miscellaneous................................... (6,828) 21,022 (59,056) 52,308 (33,963)
Regulatory balancing accounts................... 138,627 36,093 (44,213) (124,606) (17,283)
Subsidiaries.................................... 514,502 379,981 192,067 155,312 159,953
--------- --------- --------- --------- ---------
Operating revenues........................ $2,716,365 $2,548,596 $2,409,479 $2,434,021 $2,372,214
--------- --------- --------- --------- ---------
--------- --------- --------- --------- ---------
SELECTED STATISTICS:
Total customers (at year-end)................... 3,600,000 3,500,000 3,500,000 3,500,000 3,400,000
Average annual residential usage (Mcf).......... 62 57 64 64 67
Heating temperature -- % of normal(3)........... 89.9 76.0 101.5 94.9 98.9
Average billed revenues per thousand cubic feet
(Mcf):
Residential................................... $5.59 $5.74 $5.82 $5.58 $5.28
Commercial.................................... 5.70 6.00 6.47 5.51 5.26
Industrial -- interruptible................... 2.76 2.93 3.06 3.39 3.12
Net plant investment per customer............... 1,339 1,170 893 748 705
</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 Customer Identified Gas (CIG)
Program. Sales include 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) Over 100% indicates colder than normal.
22
<PAGE> 26
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,
1993, approximately 55% of the Company's total purchases of natural gas
consisted of Canadian gas purchased from PGT, a wholly owned subsidiary of the
Company, and, following implementation of the of the Decontracting Plan
described below, from various Canadian producers and transported by PGT,
approximately 5% was purchased from various California producers, and
approximately 40% 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
----------------------------------------------------------------------------------------------------------------
1993 1992 1991 1990 1989
-------------------- -------------------- -------------------- -------------------- --------------------
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.......... 329,693 $ 2.26 321,770 $ 2.14 345,020 $ 2.34 372,421 $ 2.41 371,137 $ 2.36
California...... 32,096 1.65 50,953 1.73 73,257 2.00 77,935 2.04 88,382 1.83
Other states
(substantially
all U.S.
Southwest).... 243,058 2.84 327,272 2.51 240,141 2.61 273,981 2.81 296,703 2.58
--------- --------- --------- --------- ---------
Total/Weighted
Average....... 604,847 $ 2.46 699,995 $ 2.28 658,418 $ 2.40 724,337 $ 2.52 756,222 $ 2.38
--------- -------- --------- -------- --------- -------- --------- -------- --------- --------
--------- -------- --------- -------- --------- -------- --------- -------- --------- --------
</TABLE>
- ----------
(1) The average prices for Canadian and U.S. Southwest gas include the commodity
gas prices, interstate pipeline demand or fixed 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
Effective in May 1988, a new regulatory framework for natural gas service
was established in California. This framework (i) segmented customers into core
(all residential customers and commercial customers that do not exceed certain
volume limitations) and noncore (industrial and commercial customers that exceed
certain volume limitations) classes; (ii) unbundled utilities' gas
transportation and procurement services; (iii) allows noncore 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.
In November 1991, the CPUC issued a decision adopting a statewide capacity
brokering program, whereby noncore customers and other shippers can obtain
rights to firm interstate pipeline transportation capacity held by the local gas
distribution utilities. Under the capacity brokering program implemented August
1, 1993 for the Company's El Paso and Transwestern capacity, and November 1,
1993 for the Company's PGT capacity, 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 choosing bundled
procurement and transportation service). Noncore customers, brokers 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 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 are 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
23
<PAGE> 27
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 has allowed many of
the Company's noncore customers to arrange for the purchase and transportation
of their own gas supplies. These changes have 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
FORMER CANADIAN GAS SUPPLY AND TRANSPORTATION ARRANGEMENTS
Prior to implementation of the Decontracting Plan described below, the
Company purchased Canadian natural gas under various long-term contracts. The
gas was shipped to the U.S. border by Alberta and Southern Gas Co., Ltd. (A&S),
a wholly owned subsidiary of the Company, over the NOVA Corporation of Alberta
(NOVA) and Alberta Natural Gas Company Ltd (ANG) pipelines under an export
license from the National Energy Board of Canada (NEB), a removal permit from
the Alberta Energy Resources Conservation Board and an energy removal
certificate from the province of British Columbia. PGT purchased this Canadian
natural gas from A&S and transported it from Canada to the California border,
under authorization from the Department of Energy (DOE) to import the gas. The
gas was purchased at the California-Oregon border by the Company. A&S had been
authorized to export up to 1,126 MMcf per day (MMcf/d) and 373,500 MMcf per year
through October 31, 2005.
DECONTRACTING PLAN
The CPUC's gas procurement and capacity brokering programs and the FERC's
new regulatory structure resulted in a decrease in the amount of gas required to
be purchased by the Company. As a result, A&S was required to terminate its gas
supply arrangements with Canadian producers. A&S had commitments to purchase
minimum quantities of gas from Canadian producers under various contracts, most
of which extended through 2005. A number of Canadian gas producers had filed
lawsuits against the Company during 1991 and 1992 claiming damages of at least
Cdn. $466 million resulting from the alleged failure of A&S to meet its minimum
contractual gas purchase obligations for the 1989-1992 contract years and for
the anticipated failure of A&S to meet those obligations through 2005.
As a result of the regulatory changes 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. Gas
producers representing more than 99.9% of the total volume of the gas supply of
A&S participated in the Decontracting Plan. As a result, the Alberta provincial
government and the NEB have ended restrictions imposed in 1992 on the shipment
of gas to northern California and permitted the Decontracting Plan to be
implemented. A&S also restructured its gas transportation and processing
agreements.
Under the Decontracting Plan, the Canadian producers' contracts with A&S,
the sales agreement between A&S and PGT, and the Company's service agreement
with PGT each were terminated, effective on November 1, 1993. The termination of
the agreements relieved the parties of their obligations under those agreements
and permitted producers to decontract their reserves from the A&S supply pool.
As a result, the Company may contract on an individual basis for its
requirements directly with any producer, aggregator or marketer, whether or not
they were formerly in the A&S supply pool.
Under the Decontracting Plan, participating producers released A&S, PGT and
the Company from any claims they may have had that resulted from the termination
of the former arrangements as well as any claims
24
<PAGE> 28
for losses which arose from alleged historical shortfalls in gas taken by A&S.
The total amount of settlement payments paid to the producers is approximately
$210 million.
As part of the overall A&S decontracting process, A&S' operations have been
significantly reduced, with Pan-Alberta Gas Ltd., a major aggregator of Canadian
natural gas, acquiring A&S' restructured gas purchase contracts and its
remaining Canadian sales contracts. A&S continues to hold gas transportation
capacity on Canadian pipelines and is in the process of permanently assigning or
brokering such capacity.
As part of the Decontracting Plan, A&S permanently assigned substantial
portions of its commitments for transportation capacity with NOVA through
October 2001 and ANG through October 2005 to third parties. A&S also assigned
approximately 600 MMcf/d of capacity on each of these pipelines to the Company
for use in the servicing of the Company's core and core subscription customers.
A&S currently holds remaining capacity of approximately 450 MMcf/d with annual
demand charges of approximately $25 million for which it is continuing its
efforts to assign or broker. There is uncertainty about the ability of A&S to
assign or broker this remaining capacity. To the extent others do not take this
capacity, A&S will remain obligated to pay for the related demand charges.
In July 1993, FERC approved a transition cost recovery mechanism (TCRM) for
PGT under which most costs which were incurred to restructure, reform or
terminate the sales arrangements between A&S and PGT and underlying A&S gas
supply contracts, or to resolve claims by gas suppliers related to past or
future liabilities or obligations of PGT or A&S, are eligible for recovery in
PGT's rates. The TCRM precludes most objections to the eligibility and prudence
of such costs; prudence challenges may be made only on the grounds that the
payment is unreasonably high in light of the damages claimed. Disposition of
approved transition costs will be as follows: (1) 25% of such costs will be
absorbed by PGT; (2) 25% will be recovered by PGT through direct bills
(substantially all to the Company as PGT's principal customer); and (3) 50% will
be 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.
In October 1993, PGT filed an application at the FERC for recovery of
payments made under settlement agreements with 140 producers, representing
approximately 97% of the volumes dedicated to A&S. The application seeks
recovery of $154 million under the TCRM, which is 75% of the $206 million paid
to such producers as of the time of the filing. PGT intends to submit further
applications with the FERC for recovery of transition costs incurred under
settlement agreements entered into after October 15. In November 1993, the FERC
issued an order accepting the filing, with rates effective on November 15, but
subject to refund to the extent not ultimately approved by the FERC. In December
1993, the CPUC filed a limited challenge to the costs. In its filing the CPUC
decided not to challenge the prudence of the transition costs filed by PGT, but
did challenge the eligibility for recovery under the TCRM of PGT's settlement
payment to BC Gas Utility of $2.4 million. The CPUC also requested a technical
conference or hearing to determine if other payments made by PGT are consistent
with the TCRM.
In September 1993, the Company requested that the CPUC approve a memorandum
account to track the direct bills charged to the Company by PGT for transition
costs. In response, the DRA indicated that while it does not protest the
Company's request to record the direct bills to a memorandum account, it does
believe that these costs are unreasonable and that they should not be passed on
to ratepayers. The DRA also urged that the CPUC investigate any gas supply
restructuring costs that PGT attempts to pass on to the Company and to take into
account these costs in its final decisions in the 1988-1990, 1991, 1992 and 1993
gas reasonableness proceedings. See "Gas Reasonableness Proceedings" below. In
November 1993, the Company paid PGT approximately $51 million in payment of the
direct bill charged by PGT for transition costs under the TCRM. The Company
expects to seek recovery in its next BCAP application of this amount and
volumetric surcharges to be billed to the Company.
FINANCIAL IMPACT OF DECONTRACTING PLAN AND LITIGATION
The Company incurred transition costs of $228 million, consisting of
settlement payments made to producers in connection with the implementation of
the Decontracting Plan and amounts incurred by A&S in
25
<PAGE> 29
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 due to the
uncertainty of A&S's ability to assign or broker its remaining commitments for
Canadian transportation capacity. Accordingly, the Company expensed $93 million
in 1993 and a total of $23 million in prior years.
PGT and the Company are seeking recovery of all transition costs eligible
for recovery under the TCRM other than the 25% of such costs to be absorbed by
PGT. While such transition costs are still subject to challenges at the FERC
level and the recovery of such costs paid by the Company as a shipper of gas on
PGT will depend on the recovery mechanism adopted by the CPUC, the Company
believes that it will ultimately recover the deferred transition costs.
RESTRUCTURING OF INTERSTATE GAS SUPPLY ARRANGEMENTS
NEW INTERSTATE GAS TRANSPORTATION AND PROCUREMENT ARRANGEMENTS
The Company's contract for firm sales service from PGT had entitled the
Company to purchase up to 1,066 MMcf/d from PGT at Malin, Oregon. Effective
November 1, 1993, the Company converted its firm sales service contract to firm
transportation service of up to 1,066 MMcf/d. The firm transportation agreement
runs through October 31, 2005. The firm transportation demand charge associated
with the Company's firm capacity on PGT is approximately $50 million per year.
To procure Canadian gas, the Company may contract on an individual basis for gas
supply directly with any Canadian producer, aggregator or marketer. The Company
currently purchases substantially all of its Canadian gas under flexible,
short-term arrangements.
Following FERC approval of PGT's Order 636 compliance filing and pursuant
to FERC rules on capacity relinquishment and release, the Company commenced
capacity release on PGT's pipeline effective November 1, 1993. The Company
retained approximately 610 MMcf/d on the PGT pipeline to support its service to
core and core subscription customers. The Company made amounts not needed for
core or core subscription service available for capacity release. The Company's
release of its PGT capacity is also subject to the CPUC's capacity brokering
program.
The Company's contract for firm sales service from El Paso had entitled the
Company to purchase up to 1,140 MMcf/d from El Paso at Topock, Arizona. On
September 1, 1991, the Company converted its firm sales service contract to firm
transportation service of up to 1,140 MMcf/d. The firm transportation agreement
runs through 1997. The firm transportation reservation charge associated with
the Company's firm capacity on El Paso is approximately $130 million per year.
The Company may contract on an individual basis for gas supply directly with any
producer, aggregator or marketer of Southwest gas and currently purchases
substantially all of its Southwest gas under flexible, short-term arrangements.
Pursuant to FERC rules on capacity relinquishment and release, the Company
began brokering its capacity on the El Paso system effective August 1, 1993. The
Company retained approximately 610 MMcf/d on the El Paso system to support its
core and core subscription customers. The Company made amounts not needed for
core or core subscription service available for capacity release. The Company's
brokering of its El Paso capacity is also subject to the CPUC's capacity
brokering program. During the period from August 1, 1993 to November 1, 1993,
partial capacity brokering under the CPUC rules occurred. During this period,
noncore customers who took assignment of the Company's brokered El Paso capacity
received unbundled rates for intrastate service on the Company's system. The
unbundled rates excluded the costs for the Company's El Paso and PGT capacity.
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 150 MMcf/d is to be used to meet the
Company's gas demands and 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, effective November 1, 1993.
26
<PAGE> 30
RECOVERY OF INTERSTATE TRANSPORTATION DEMAND CHARGES
Beginning November 1, 1993, when capacity release on both the PGT and El
Paso systems was under way, full capacity brokering under the CPUC program went
into effect. Under the full capacity brokering program, the Company's costs for
interstate capacity on El Paso and PGT were unbundled from all the Company's
rates for all noncore transportation service on its system. Noncore customers,
or their gas suppliers, became responsible for the interstate transportation
arrangements necessary to deliver gas at the Company's interconnections with the
interstate pipelines. Under full capacity brokering, the Company continues to
make its firm capacity on El Paso and PGT above the core and core subscription
reservations, as well as capacity reserved for core and core subscription
customers that is not being used to serve such customers' requirements at any
given time, available for brokering to other potential shippers.
Interstate transportation service which cannot be marketed at the full
rates 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. The Company has not succeeded in marketing its firm PGT or El
Paso capacity above the core and core subscription reservations at the full cost
of the capacity (the as-billed rate). The Company also has not been able to
market all the El Paso and PGT capacity it has made available for brokering.
Pursuant to the CPUC's ITCS mechanism, the Company has accumulated unrecovered
demand charges for El Paso and PGT capacity in the ITCS.
Ultimate recovery of unrecovered interstate pipeline demand charges
accumulated in the ITCS will be subject to CPUC ratemaking mechanisms. 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. Also, as
described above (see "General -- Long-Term Gas Transportation Rates"), the
Company has requested authorization to implement an optional long-term noncore
gas transportation tariff. Under the Company's proposal, shareholders will bear
the risk of any revenue shortfalls attributable to any differences between the
long-term rate option and the customer's otherwise applicable rate. Accordingly,
shareholders may bear the costs of any shortfall in recovery of ITCS costs
contained in the otherwise applicable rate.
In July 1992, the CPUC issued a decision in its capacity brokering
proceeding which denied the Company the authority to recover in gas rates at
that time costs associated with 150 MMcf/d of Transwestern capacity prior to a
prudence determination by the CPUC. Instead, those costs may be entered into a
balancing account, subject to reasonableness review proceedings. The July 1992
decision did not address the Company's use of 50 MMcf/d on behalf of the
electric department. The issue of the inclusion of the costs associated with the
electric department's subscription to Transwestern capacity was raised in the
Company's 1992 ECAC proceeding, but as a result of a settlement with the DRA,
final resolution of the issue was deferred to a later reasonableness review
proceeding. In the interim, the CPUC's decision in the ECAC case authorized the
Company to record the demand charges incurred by the electric department in its
ECAC balancing account, but such costs will not be recovered in electric rates
until the CPUC makes a determination in a future reasonableness proceeding that
the commitment to subscribe to the Transwestern capacity was prudent. Currently,
the Company is not permitted to include any Transwestern firm capacity demand
charges in the ITCS account.
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 electric department. The DRA asserted that the incremental
27
<PAGE> 31
interstate 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
on account of noncore customers.
The Company is continuing its efforts to broker or assign its remaining
interstate transportation capacity that is not used. Since the latter half of
1993 when implementation of capacity brokering began on interstate pipelines,
including El Paso, PGT and Transwestern, the Company has been able to broker a
significant portion of the unused capacity, including limited amounts of the
capacity held for its core and core subscription customers when such capacity
was not being used to serve those customers. Amounts brokered have been on a
short-term basis, most of which were at a discounted price. The average monthly
demand charges associated with the Company's unused interstate capacity have
been approximately $10 million, of which the Company has been able to recover
approximately 40% through capacity brokering during the past few months. Because
the success of the Company's brokering efforts will depend on market demand, the
Company cannot predict the volume or the price of the capacity that will be
brokered in the future.
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.
1988-1990 RECORD PERIOD
The CPUC has consolidated its review of the reasonableness of gas system
costs for 1988 through 1990.
In September 1991, the DRA issued its report on the Company's Canadian gas
procurement activities during 1988 through 1990. The DRA recommended that the
Company refund approximately $392 million for the approximately three-year
period from February 1988 to December 1990, based on its contention that the
Company should have purchased 50% of its Canadian supplies on the spot market
instead of almost totally relying on long-term contracts.
In addition to the recommendation on Canadian gas procurement, the DRA
proposed a $37 million disallowance related to gas operations. The DRA contended
that the Company should have withdrawn gas from storage in the winter of
1989-1990 and December 1990 instead of burning fuel oil, which was more
expensive.
On March 16, 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 about 70% of its daily customer demand for gas from its
then-existing Canadian gas suppliers, but that the Company could have met the
remainder of its daily demand 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. The decision finds that the Company should
have withdrawn more gas from storage during December 1990 for the electric
department's generation and orders a disallowance of $8 million. The Company
intends to file requests for rehearing of this decision and the decision on the
Canadian gas procurement activities described above.
The decisions described above do not address an additional $18 million
disallowance recommended by the DRA in connection with the Company's purchased
power expenses for Pacific Northwest purchases during 1989 and 1990. In its
September 1991 report on the Company's Canadian gas procurement activities
during 1988 through 1990, the DRA noted that the Company purchased electric
energy when it was cheaper than its incremental fossil fuel generation costs.
However, the DRA argues that if cheaper Canadian gas supplies had been used then
the Company's incremental fossil fuel generation costs would have been lower
than the purchased power costs. The DRA has also sought permission to file
additional testimony on the
28
<PAGE> 32
effects of any imprudently incurred Canadian gas costs on certain of the
Company's electric operations costs during the 1988 through 1990 record periods.
On March 7, 1994, the ALJ granted the DRA's motion requesting the right to file
testimony concerning prices for energy purchased from QFs and geothermal steam
prices. The ALJ's ruling combines these issues with the outstanding Pacific
Northwest purchased power issues into a separate phase of the reasonableness
proceeding. Hearings on these issues have not yet been scheduled.
1991 RECORD PERIOD
In September 1992, the Company filed testimony to establish the
reasonableness of its gas procurement and operating activities for 1991. In
March 1993, the DRA issued its report on the reasonableness of those activities
and recommended that the Company refund approximately $116 million in costs for
that period.
The major recommended disallowance relates to the DRA's contention that the
Company failed to pursue least-cost purchasing alternatives in acquiring
Canadian gas supplies during the 1991 record period. The DRA calculated that the
Company would have saved $105 million in gas costs if it had purchased 50% of
its Canadian gas supply at spot market prices, and accordingly recommended that
amount be disallowed. The DRA also asserted that the Company's electric
department's procurement policies and decisions were strongly influenced by the
Company's Canadian gas affiliate arrangements. The DRA indicated that although
the electric department's excess costs are subsumed in the $105 million
recommended disallowance for Canadian gas procurement activities, it recommended
a disallowance of $15.8 million in electric department gas costs even if the
Canadian gas costs are not deemed unreasonable, given the electric department's
alleged failure to pursue least-cost procurement alternatives.
The DRA recommended an additional disallowance of approximately $2.4
million in connection with the Company's Southwest gas procurement activities
during the 1991 record period. The DRA asserted that the Company imprudently
incurred these additional costs by purchasing amounts in excess of minimum
contract requirements at contract prices which were higher than spot market
prices.
In addition, the DRA recommended an $8.5 million disallowance related to
the Company's gas inventory operations. The DRA contended that the Company's
operating assumptions regarding the quantity of gas to be reserved in storage
for potential needs of residential customers under extreme weather conditions
resulted in the electric department incurring excess costs as it had to burn
higher priced fuel oil to generate electricity during the record period.
Hearings on the 1991 record period are scheduled for May 1994.
1992 RECORD PERIOD
In January 1994, the DRA issued its report on the reasonableness of the
Company's gas procurement and operating activities for 1992 and recommended a
disallowance of approximately $92 million in costs for that period.
The major recommended disallowance relates to the DRA's contention that the
Company failed to pursue least-cost purchasing alternatives in acquiring
Canadian gas supplies during the 1992 record period. The DRA calculated that the
Company would have saved $60.5 million in gas costs if it had purchased 50% of
its Canadian gas supply at spot market prices, and accordingly recommended that
amount be disallowed. In addition, the DRA recommended a disallowance of
approximately $5.1 million in connection with the Company's Southwest gas
procurement activities during a three-month period in 1992 and a disallowance of
$8.2 million related to the Company's gas inventory operations.
In its report, the DRA also 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 electric department. The DRA asserted that the incremental
interstate 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
on account of noncore customers.
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AFFILIATE AUDIT
In addition to challenging the prudence of the gas costs incurred by the
Company under its Canadian gas supply arrangements, in 1992 the DRA also
initiated an audit of the non-gas costs incurred by the Company's present and
former Canadian affiliates.
In September 1993, the DRA distributed a report on its audit of A&S for the
1988 through 1991 period. The DRA report recommends that the CPUC impose a $50
million penalty on the Company and disallow approximately $6.2 million of
primarily non-gas and administrative costs in 1991. The DRA has filed a motion
asking that recommendations for the 1992 record period be made in a subsequent
report. No action has been taken on this motion. In addition, the DRA has
indicated that it will be filing in June 1994 a supplemental report addressing
matters relating to the profitability of the Cochrane liquids extraction plant
operated by the Company's former affiliate, ANG. The DRA has stated that the
report will address the implications, if any, of ANG's status as an affiliate of
the Company. In a previous report, the DRA had noted that a substantial portion
of ANG's profits were derived from the operation of the Cochrane plant and that
in part as a result of that profitability the Company had a pre-tax profit of
$49 million from the sale of its ANG shares in 1992.
The DRA's proposed $50 million penalty relates primarily to its contention
that the Company has committed serious lapses in the oversight of A&S. In
particular, the DRA alleges that the Company failed to prevent A&S from passing
through allegedly excessive and improper transportation and non-gas and
administrative costs in A&S' cost of service. Based on its calculations, the DRA
alleges that A&S contracted for excessive Canadian pipeline capacity on the
pipeline systems of NOVA and ANG relative to the capacity necessary to service
the Company's ratepayers. The DRA further argues that A&S misallocated its cost
of service between the Company and its other customers resulting in
cross-subsidies of Canadian customers by the Company's ratepayers. The Company
filed its rebuttal testimony in March 1994. Hearings are scheduled in May 1994.
In December 1993, the ALJ denied a motion filed by the Company which had
asked the CPUC to dismiss the penalty and disallowance because prior federal
rulings approved such costs and thus preempt the issue.
In January 1994, the DRA filed with the CPUC a report on alleged conflicts
of interest which discusses the stock holdings of certain officers and directors
of A&S in companies from which A&S contracted for gas supplies that eventually
flowed to California. In its report, the DRA indicates that it did not discover
specific transactions resulting from the stock ownership which caused
identifiable harm to California ratepayers. However, the DRA concluded that the
stock ownership created the appearance of impropriety and that the interests may
have created a disincentive for those officers to aggressively seek
opportunities to drive down the price for gas paid to producers. The DRA's
report also criticizes the Company for not taking sufficient action to ensure
that A&S's conflicts threshold was as stringent as that which the Company
employed in evaluating possible conflicts of interest of its employees.
The DRA's report does not request any specific disallowance associated with
the conflicts of interest discussed in the report. Rather, the DRA argues that
the Company's lack of oversight in this respect provides further evidence to
support the $50 million penalty recommended in its September 1993 report on
Canadian non-gas costs.
FINANCIAL IMPACT OF GAS REASONABLENESS PROCEEDINGS
The Company recorded reserves of $61 million in 1993 and will accrue
approximately an additional $90 million in the first quarter of 1994 as a result
of the CPUC's disallowance in the 1988-1990 gas reasonableness proceedings and
the Company's assessment of gas procurement activities in the periods 1991
through 1993.
The Company currently is unable to estimate the ultimate outcome of the gas
reasonableness proceedings, including the affiliate audit, discussed above or
predict whether such outcome will have a significant adverse impact on its
financial position or results of operations.
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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.
The 840-mile combined pipeline will provide an additional 148 MMcf/d of firm
capacity to the Pacific Northwest and an additional 755 MMcf/d of firm capacity
to Northern and Southern California. At December 31, 1993, the Company's total
investment in the project was approximately $1,587 million. The $1,587 million
consisted of $767 million for the facilities within California (i.e., intrastate
portion) and $820 million for the facilities outside California (i.e.,
interstate portion).
The construction of facilities within the state of California has been
certificated by the CPUC. The conditions of the certificate place the Company at
risk for its decision to construct based on its assessment of market demand and
for any potential underutilization of the facility. The certificate requires the
application of a "cross-over" ban under which volumes delivered from the
incremental interstate (PGT) expansion must be transported at an incremental
intrastate 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 interstate portion 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 intrastate capacity, and the Company continues negotiations for the
remaining capacity. The CPUC has authorized the Company to provide as-available
service on the expansion project, which can provide additional revenues to
recover the incremental costs of the expansion.
The CPUC certificate issued in December 1990 established a cost cap of $736
million for the California portion, which 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. In October 1993, the CPUC issued a
decision granting the Company's motion to put in place temporary interim rates
based on the existing cost cap of $736 million. The decision authorized the
temporary interim rates to become effective on the date of commercial operation,
November 1, 1993, and remain in effect for five months or until interim rates
are established by the CPUC.
In February 1994, the CPUC announced a decision on the Company's request
for an increase in the California portion of the expansion project's cost cap
and its interim rate filing. 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 expansion project. In its decision, the CPUC also
approved a one percentage point increase in the return on equity over the
authorized return on utility operations in order to reflect the risk associated
with the additional leverage of a capital structure of 70% debt and 30% equity
for the California portion of the expansion project. The decision rejects
assignment of unused capacity costs on other pipelines (or the Company's
intrastate facilities) to the expansion project as previously proposed by an
ALJ's proposed decision.
The FERC issued an order in October 1991 approving the interstate portion
of the expansion project. However, concluding that PGT had not sufficiently
demonstrated that shippers would not be subject to discriminatory restraints on
access into California or on the interstate portion of the project as a result
of the "cross-over" ban imposed by the CPUC, the FERC reduced PGT's approved
rate of return on equity to 10.13% (from the 12.5% return previously approved)
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 1993, the FERC authorized an increase in the nominal return on equity to
12.75% from 12.5%, but reaffirmed the lower 10.13% return on equity it
implemented as an incentive for PGT to seek removal of unduly discriminating
restraints.
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Based upon the current status of the cost cap and interim rate case at the
CPUC and market demand, the Company believes it will recover its investment in
the expansion project.
OTHER COMPETITIVE INTERSTATE PIPELINE PROJECTS
In 1992, several new gas pipeline projects were completed to serve the
enhanced oil recovery market in Southern California and other customers. In
March 1992, projects sponsored by Kern and the Mojave Pipeline Company (Mojave)
commenced commercial operations. The projects involved construction of Kern's
700 MMcf/d pipeline from Wyoming to California, Mojave's 400 MMcf/d pipeline
from Arizona border interconnection points with the El Paso and Transwestern
systems to a point of interconnection with the Kern project in California, and a
pipeline, jointly owned by Kern and Mojave, from the point of interconnection to
the Bakersfield area. Also in 1992, 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 PGT/PG&E expansion project. Some of the gas available from the
U.S. Southwest over these projects is priced equal to or lower than the current
price of Canadian gas available over the PGT/PG&E expansion project, due in part
to federal tax credits available for certain San Juan gas production.
Altamont Gas Transmission Company (Altamont) has proposed to build a
pipeline that would transport gas from Alberta, Canada, to Wyoming, where it
would interconnect with the Kern project. However, in July 1992, Altamont
announced a one-year delay (to late 1994) in the scheduled completion of its
proposed pipeline project.
In March 1993, Mojave 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 at Bakersfield, California, through
California's Central Valley to Sacramento and the San Francisco Bay Area.
Mojave's filing indicates that 433 MMcf/d of the firm service capacity provided
by the proposed expansion will 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 April 1993, the CPUC issued a resolution asserting jurisdiction over the
rates and services of Mojave and the facilities used by Mojave to transport gas
received by Mojave in California and ultimately consumed in California. The CPUC
also filed with the FERC a protest and motion to dismiss Mojave's application.
The Company also filed a protest and motion to dismiss Mojave's application,
arguing that the FERC should dismiss Mojave's application because the CPUC, and
not the FERC, has jurisdiction to review Mojave's proposed expansion. The
Company indicated in its filing that Mojave's proposed expansion would bypass
the Company's existing gas network, taking business from the Company and
requiring the Company to spread costs over a smaller customer base. The Company
contended that Mojave's project would cost over $330 million (net present value)
more than if the Company served the targeted customers, while reducing the
economic welfare of the Company's remaining customers by over $325 million in
present value terms.
In December 1993, the FERC held hearings in response to the Company's and
the CPUC's requests to dismiss Mojave's pending pipeline expansion application.
In February 1994, the FERC issued a decision asserting jurisdiction over
Mojave's pending application. In March 1994, both the Company and the CPUC filed
requests for a rehearing in this matter, arguing that the FERC erred in
asserting jurisdiction. In addition, the Company requested that, if the FERC
denies rehearing on the jurisdictional issues, the FERC hold a hearing to review
the merits of Mojave's proposal and to establish a mechanism to reimburse the
Company for costs arising from bypass associated with Mojave's proposed
expansion.
STORAGE SERVICE
The Company has generally provided natural gas storage service only in
conjunction with its procurement and transportation services. In an open season
ending in January 1993, noncore customers indicated an interest
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in obtaining unbundled storage service. In February 1993, the CPUC adopted
policies and rules for permanent unbundled gas storage programs for noncore
customers, and ordered the Company to submit a storage proposal in compliance
with those policies. The Company's proposal regarding an unbundled storage
program was submitted to the CPUC in July 1993 and hearings on the proposal were
held in October and November 1993. CPUC authorization of an unbundled storage
program for the Company is expected in the second quarter of 1994. Following
authorization, the Company will hold an open season offering noncore customers
short-term storage services from existing facilities and long-term storage
services from expanded facilities.
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, 1993, 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 nine 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>
1994 1995 1996 1997 1998
---------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C>
Unit 1
Refueling........... March September March September
Startup............. May November May November
Unit 2
Refueling........... September March September
Startup............. November May November
</TABLE>
On July 9, 1992, the Company filed a license amendment request with the
Nuclear Regulatory Commission (NRC) to change the operating license expiration
dates for both units at Diablo Canyon. Diablo Canyon Units 1 and 2 are currently
licensed to operate for 40 years commencing on the date the construction permit
for the respective unit was issued, which occurred in 1968 and 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. The Company's request seeks to utilize that policy change, and if
granted, would extend the operating license expiration date for Unit 1's license
from April 2008 to September 2021 and the expiration date for Unit 2's license
from December 2010 to April 2025.
In August 1992, a group intervened in opposition to the license amendment
and requested hearings at the NRC. In October 1992, the intervenor group
supplemented its petition with a request that eleven contentions be admitted for
hearing. The Company and the NRC staff responded to the intervention petition
and its supplement, asserting that the intervenors lack standing and none of the
contentions are admissible. In January 1993, an NRC licensing board issued its
order granting the intervenors standing and admitting for hearings two of the
eleven contentions filed by the intervenors. The two admitted contentions relate
to the Company's maintenance program for Diablo Canyon and the adequacy of the
Company's implementation of certain compensatory measures approved by the NRC to
address issues relating to a fire-barrier material known as Thermo-Lag pending
NRC/industry resolution of those issues. Hearings were completed in August 1993.
In February 1994, the intervenor group filed a motion to reopen the record in
the proceeding in order to take evidence on an NRC inspection issue which the
intervenor group alleges represents significant new information regarding
deficiencies in the Company's maintenance of the plant's auxiliary saltwater
system. Both the Company and the NRC staff have replied to the motion, urging it
be rejected. A decision by the NRC licensing board on the motion to reopen is
expected in the next few months, and a decision on the Company's license
amendment request is expected in 1994.
The Company is a member of Nuclear Mutual Limited (NML) and Nuclear
Electric Insurance Limited (NEIL I and II). 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
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assessments of $21 million (property damage) or $7 million (business
interruption), in each case per policy period, if losses exceed premiums,
reserves and other resources of NML, NEIL I or NEIL II.
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 $9.4 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.
DIABLO CANYON SETTLEMENT
The Diablo Canyon rate case settlement adopts 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 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. Total prices for the years
1993 through 1994, effective January 1 of each year, are 11.16 cents and 11.89
cents per kWh, respectively. For 1995 through 2016, 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 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.
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The settlement provides that certain Diablo Canyon costs, including
decommissioning costs, be recovered over the term of the settlement, including a
full return on such costs through base rates.
In March 1993, the CPUC denied a petition filed in September 1992 by a
consumer advocacy group seeking to modify the CPUC's 1988 decision that adopted
the Diablo Canyon rate case settlement. The petition contended that the Company
has made unreasonably high profits because of the better-than-expected operating
performance of Diablo Canyon. The petition did not propose any specific change
to the Diablo Canyon rate provisions, but requested that the CPUC reopen the
Diablo Canyon settlement to consider mechanisms for sharing with ratepayers
additional benefits of Diablo Canyon's performance.
The CPUC found that there had been no failure in the underlying assumptions
of the settlement and that reopening the settlement would be contrary to the
public policy in favor of settlements. Although all four CPUC Commissioners
voted to deny the petition, CPUC President Fessler indicated in his concurring
opinion that he was concerned about the high electricity rates paid by all
classes of ratepayers and would consider reopening the settlement if the Company
does not reduce its rates within a year.
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 1994, 1996 and 1998, respectively. The Company is currently negotiating
contracts for 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 (the Act), the DOE is
responsible for the transportation and ultimate long-term disposal of spent
nuclear fuel and high-level waste. The 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 Act, utilities are required to
provide interim storage facilities until permanent storage facilities are
provided by the federal government. The 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 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.
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, 1993, the amount recovered in rates for
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<PAGE> 39
decommissioning costs was $54 million. The estimated total obligation for
decommissioning costs is approximately $1 billion in 1993 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, 1993, the Company had accrued $537 million in
accumulated depreciation and decommissioning and had accumulated that amount in
external trust funds, to be used for the decommissioning of the Company's
nuclear facilities. 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
principal non-utility unregulated 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
the Bechtel Group, Inc. is the other general partner of USGen. USGen develops
and manages non-utility electric generation facilities which 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 profits or losses are derived. USGen is currently involved in
seven operational plants and eight projects under construction or in advanced
stages of development (with power sales agreements). Enterprises' share of
capacity from those projects is approximately 1,515 MW. The projects are
typically financed with a combination of equity commitments from the project
sponsors and non-recourse debt. USGen also manages Enterprises' 39.9% limited
partnership interest in Sycom Enterprises, which offers energy conservation
services.
GAS AND OIL EXPLORATION AND PRODUCTION
Resources, 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 January 1994, the Company approved a final plan for the disposition of
Resources in 1994 if market conditions remain favorable. The Company has
retained Goldman, Sachs & Co. to advise it with respect to possible alternatives
for the divestiture of Resources. In February 1994, Resources filed with the
Securities and Exchange Commission a proposed S-1 registration statement with
respect to one of these options. This option involves an initial public offering
of all of the stock of Resources' parent holding company, PG&E Resources
Holdings Company, which would be renamed Dalen Resources Corp. prior to the
offering. Such an offering would be preceded by the transfer of Resources'
non-strategic properties to a newly-formed subsidiary of Enterprises for
disposition by sale. As of December 31, 1993, Resources had assets of
approximately $680 million.
POWER PLANT OPERATING SERVICES
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
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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.
REAL ESTATE DEVELOPMENT
PG&E Properties, Inc. (Properties) develops real estate in the Company's
service territory, focusing on residential lot creation. It also develops
offices, industrial buildings, retail outlets and apartments. Properties is
wholly owned by Enterprises.
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.
ENVIRONMENTAL PROTECTION MEASURES
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 $50 million, $50 million,
$75 million, $95 million and $75 million for 1994, 1995, 1996, 1997 and 1998,
respectively, and are included in the Company's five-year projection 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.
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 have adopted final rules to reduce NOx emissions from
these plants.
The three agencies that have adopted utility boiler NOx rules are the
Monterey Bay Unified Air Pollution Control District (Rule 431 adopted September
15, 1993), the San Luis Obispo County Air Pollution Control District (Rule 429
adopted November 16, 1993) and the Bay Area Air Quality Management District
(Regulation 9, Rule 11 adopted February 16, 1994). These rules prescribe
emission limitations for the Company's Contra Costa, Hunters Point, Moss
Landing, Morro Bay, Pittsburg and Potrero power plants. In each district, other
NOx rules have been or will be adopted to regulate other NOx sources.
Because the Company's power plants operate as a system, the three agencies
coordinated their NOx rulemakings. Together, the rules require a reduction in
NOx emissions of approximately 90% from the power plants by 2004 (with numerous
interim compliance deadlines). The first major retrofit is scheduled to begin in
1996. Certain retrofits will not be required if the smaller generating units are
operated for emergency purposes only after 2000. Rule 431 also requires the
Company to provide a total of $7 million to the Monterey Bay Unified Air
Pollution Control District in 1994 and 1995 for emission reduction projects not
related to Company sources. Rule 429 may 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.
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The Company currently estimates that compliance with these NOx rules could
require capital expenditures of approximately $300 million to $500 million over
10 years, depending on assumptions about fuel use and unit retirement. Ongoing
business and engineering studies could change this estimate. In the Company's
1993 GRC, the CPUC authorized NOx related plant additions of approximately $70
million for 1993, and established an Air Quality Adjustment (AQA) mechanism
under which the Company may seek cost recovery in rates for NOx reduction
projects beyond January 1, 1994. However, in its RRI filing (see "General --
Regulatory Reform Initiative" above) the Company has proposed that the AQA
mechanism be terminated as of January 1, 1995.
In the San Luis Obispo County Air Pollution Control District, the Company
obtained permits to install the first phase of NOx emission reductions at the
Morro Bay Power Plant, thereby commencing implementation of NOx reductions in
that district. The Company spent $48 million for the first phase of this NOx
reduction project, which has been completed.
The Company operates both reciprocating engine and gas turbine drivers at
its natural gas compressor stations. They are located in local air districts
whose attainment plans call for reductions in emissions of exhaust pollutants
over the next few years. On December 20, 1993, the Mojave Desert Air Quality
Management District adopted a rule that will require a reduction in NOx
emissions of approximately 90% from the Hinkley Compressor Station by January 1,
1998. The Topock Compressor Station is currently exempt from this rule. The San
Joaquin Valley Unified Air Pollution Control District expects to adopt a similar
rule during 1994 that would require a reduction in NOx emissions of
approximately 90% from the Kettleman Compressor Station by January 1, 1999. The
Company currently estimates that compliance with these NOx rules could require
capital expenditures of approximately $55 million over five years.
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, which must be met by January 1, 1995, are being
incorporated in local air quality rules. The air monitoring rules will require
the installation of monitoring equipment to measure emissions from the fossil
fuel fired generating plants. The Company currently estimates that the cost of
complying with the monitoring requirements will total approximately $29 million
in 1994 and 1995.
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 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
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available (BTA) for minimizing adverse environmental impacts at all existing
water-cooled thermal plants. The Company 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 two offshore moorings, three docks, approximately 103
large aboveground fuel tanks with a capacity of approximately 16,000,000 barrels
and approximately 45 miles of fuel pipelines. These facilities are used for the
transport, handling and storage of residual fuel oil and diesel, both of which
are used at the Company's power plants and facilities.
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 1994 and 1995 are estimated to be approximately $4
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 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 co-ops 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 1994 and
1995 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 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 1994 and 1995.
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.
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Wastewater evaporation ponds contain materials such as compressor cooling
water blowdown from gas compressor stations. The Company either is upgrading the
existing ponds or closing the old ponds and building new evaporation ponds that
meet new standards for leak monitoring, detection and containment. Capital
expenditures for this work in the years 1994 and 1995 are estimated to be
approximately $9.9 million. Closure and post-closure expenditures for these
ponds, including remediation and cost contingencies, may approximate $20 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 1994 and 1995 are estimated to be approximately $4.8
million.
A third program is aimed at assessing whether and to what extent remedial
action may be necessary to mitigate potential hazards posed by 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 30 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 $15.5 million over the period 1994 through 1995. The full
long-term costs cannot be determined accurately until a closer study of each
site or facility 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.
The Company may be required to take remedial action at certain disposal
sites and retired manufactured gas plant sites if they are determined to present
a significant threat to human health or the environment because of an actual or
potential release of hazardous substances. The Company has been designated as a
potentially responsible party (PRP) under CERCLA, the federal Superfund law,
with respect to the Purity Oil Sales site in Malaga, California; the 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 Company has been named as a PRP under the California Hazardous
Substance Account Act (California Superfund law) with respect to the Martin
Service Center former gas plant site and the Midway/Bayshore sites in Daly City,
California; the Berman Steel site in Salinas, California; the Emeryville Service
Center site in Emeryville, California; the GBF Land Fill at Pittsburg,
California; the former Sacramento gas plant site in Sacramento, California; the
former San Rafael gas plant site in San Rafael, California; and the former
Monterey gas plant site in Monterey, California. Although the Company has not
been formally designated a PRP with respect to the Geothermal, Incorporated site
in Lake County, California, the Central Valley Regional Water Quality Control
Board and the California Attorney General's office have directed the Company and
other parties to initiate measures with respect to the study and remediation of
that site. 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 Company will perform a groundwater remedial action at its former
Sacramento manufactured gas plant site during 1994, at a cost of up to $4
million. The DTSC must approve the groundwater remedial action design plan
proposed for this site before it is implemented.
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
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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, 1993, of $60 million for hazardous waste remediation costs. The
ultimate amount of such costs may be significantly higher 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
Generally, the Company seeks recovery of hazardous waste compliance costs
in the GRC. However, as part of the Company's 1987 GRC, the CPUC established a
separate procedure through which the Company may receive ratepayer recovery of
reasonable hazardous waste remediation costs incurred at certain historic
hazardous waste sites. The CPUC indicated that it was establishing this
procedure because the amount and timing of certain hazardous waste remediation
expenditures was difficult to forecast in the context of the GRC. This procedure
entails obtaining CPUC approval by advice letter prior to incurring any costs,
as well as filing an application periodically with the CPUC for recovery of the
amounts expended, subject to a review of the reasonableness of the expenditures.
The Company currently has received approval of advice letters totaling
approximately $22.5 million, has filed two additional advice letters for
approval, and expects to file additional requests for specific projects in 1994
and 1995. Amounts authorized by advice letters and subsequently spent by the
Company may be collected from ratepayers only after a reasonableness review of
the associated projects.
In November 1992, the CPUC issued a decision in Southern California Gas
Company's (SoCal Gas) environmental reasonableness proceeding deferring a
decision on rate recovery of remediation costs incurred by SoCal Gas and instead
requesting comments on incentive and/or cost sharing mechanisms for the
ratemaking treatment of hazardous waste remediation costs as an alternative to
the current reasonableness review of such expenses.
In response to the CPUC's request and as a result of a collaborative
effort, in November 1993, the Company and various interested parties, including
the DRA and other California utilities, filed a report with the CPUC in
connection with the SoCal proceeding, which proposes a cost sharing mechanism
for the ratemaking treatment of hazardous waste remediation costs. The proposed
mechanism would assign 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 would have the opportunity to recover the shareholder
portion of the cleanup costs from insurance carriers. The parties supporting the
proposed mechanism, including the Company, also filed a settlement, requesting
that the mechanism be adopted only in its entirety. A special interest group
opposes the proposed mechanism. The CPUC has authority to adopt the proposed
mechanism, reject it, suggest certain changes to the proposed mechanism,
schedule hearings on the issues it considers relevant, or send the parties back
for further negotiations until they reach a consensus. On March 10, 1994, the
assigned ALJ issued a proposed decision adopting the settlement and proposed
mechanism. A final CPUC decision is expected in 1994.
The CPUC has put all parties on notice that the mechanism adopted for SoCal
Gas may be applied to other utilities. Accordingly, a final decision in this
proceeding is expected to establish the method by which the CPUC addresses
similar issues in the Company's pending environmental reasonableness proceeding,
which has been postponed indefinitely pending a decision in the SoCal Gas case.
In the Company's environmental reasonableness proceeding, the Company seeks to
recover approximately $10.2 million in costs for two environmental
projects -- the Antioch Service Center site and the Sacramento Gas Plant site.
However, in its RRI filing (see "General -- Regulatory Reform Initiative"
above), the Company requests to withdraw its participation in the collaborative
report and recommendation, the pending settlement and the Company's pending
environmental reasonableness application if the CPUC approves the Company's RRI
application.
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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. However,
under the Company's proposed RRI, the specific rate mechanism for recovery of
these costs would be discontinued at the end of 1994. As of December 31, 1993,
the Company has a deferred charge of $61 million for most 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, the CPUC created a
17-member EMF Consensus Group, with representatives from government, utilities
(including a representative from the Company), organized labor and the public.
The Consensus Group submitted to the CPUC its recommendations for a CPUC interim
policy on EMF, which were considered during evidentiary hearings held in
December 1992. 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 commerical buildings.
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.
LOW EMISSION VEHICLE (LEV) PROGRAMS
In October 1991, the CPUC issued an Order Instituting Investigation/Order
Instituting Rulemaking on 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 the LEV proceeding were conducted in August 1991, and examined long-term
utility involvement in LEV
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programs in relation to California's environmental, energy and 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 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 November 1993, the Company filed an application for
approximately $200 million in funding for the Company's fleet and market
development activities for NGVs and EVs over the six-year period. However, in
its RRI filing (see "General -- Regulatory Reform Initiative" above), the
Company requests permission to withdraw the funding request portion of its LEV
application if the CPUC approves the Company's RRI proposal.
In July 1991, the CPUC approved the implementation of the Company's NGV
market development program as proposed by the Company, and authorized initial
funding for the program. 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 2,000 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.
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.
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 2026 and involving a total normal operating capability of 2,684 MW.
Helms adds an additional capacity of 1,212 MW. As the initial licenses for these
projects expire, they become susceptible to competition for a new license. 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 three of the Company's projects. Federal legislation
enacted in 1986 has eliminated any preference for governmentally-run utilities
in the relicensing of hydroelectric projects.
The 1986 law requires the Company to pay these challengers 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 projects. In return, the challengers are required to
withdraw their competing license applications. The FERC has approved the
settlement agreement for one project. The
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challengers for the other two projects have filed with the FERC to assert claims
amounting to approximately $100 million, including 100% of the Company's net
investment in the projects of approximately $89 million. In October 1991, the
FERC approved a partial settlement agreement between the Company and one of the
challengers which, among other things, required the Company to provide
additional load following services under a power sale agreement and pay
approximately $2 million to settle the challenger's claims related to both
projects of approximately $40 million. In October 1992, the FERC issued an order
requiring the Company to pay compensation of $1.9 million to the remaining
challengers for the two projects, representing the costs incurred preparing
their applications. The FERC declined to award the remaining challengers any
additional compensation. In December 1992, the challengers filed with FERC a
request for rehearing of the compensation order. In February 1993, the FERC
reaffirmed the award and rejected the challengers' request for additional
compensation. The challengers have appealed FERC's order to the U.S. Court of
Appeals. The Company expects to recover the costs of FERC-awarded compensation
and the partial settlement 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.
NATURAL GAS PURCHASE CONTRACTS LITIGATION
In connection with the implementation of the Decontracting Plan described
above (see "Gas Utility Operations -- Restructuring of Canadian Supply
Arrangements -- Decontracting Plan") in November 1993, the Canadian gas
producers party to the Decontracting Plan released A&S, PGT and the Company from
any claims they may have had that resulted from the termination of A&S' former
Canadian gas purchase arrangements as well as any claims for losses which arose
from alleged historical shortfalls in gas taken by A&S. Accordingly, the
lawsuits filed by Amoco Canada Petroleum Company Ltd. and Amoco Canada Resources
Ltd. (Amoco), Shell Canada Limited (Shell), Chevron Canada Resources (Chevron),
Gulf Canada Resources Limited and Gulf Canada Frontier Exploration Limited
(Gulf), and Scurry-Rainbow Oil Limited, Opinac Exploration Limited, Norco
Resources Limited and Hershey Oil Corporation (North Coleman Producers) were
each discontinued under Canadian Law.
QF TRANSMISSION CONSTRAINED AREA LITIGATION
The Company was a defendant in three lawsuits concerning the existence,
nature and extent of transmission constraints in the northern portion of the
Company's service area, and whether the Company improperly used those
transmission constraints and adopted policies and practices to defeat QF
development. The plaintiffs all signed power purchase agreements with the
Company for the sale of power from proposed projects that were to have been
located in the northern portion of the Company's system. All of the power
purchase agreements contained a provision stating that they would terminate if
energy deliveries from the proposed projects did not begin within five years of
the execution date of the agreement. None of the plaintiffs delivered power
within those deadlines.
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The first case was filed in Fresno County Superior Court by Griswold Creek
Joint Power Authority, Tranquility Irrigation District, Thermalito Irrigation
District, Table Mountain Irrigation District and Concow Power Authority
(collectively, Griswold Creek). The second and third cases were filed in San
Francisco County Superior Court by Pacific Oroville Power, Inc. (POPI) and
Robert F. Tamaro, doing business as Power Project Ventures (Tamaro),
respectively. The three cases had been coordinated in the San Francisco County
Superior Court by order of the California Judicial Council, at the Company's
request, with trial set for September 1993.
The September trial date was suspended while the parties pursued settlement
discussion. The Griswold Creek and Tamaro cases were settled in October and
November 1993, respectively. Trial of the POPI case, which commenced November 1,
1993, is expected to continue for at least six months.
Plaintiff in the POPI case contends that: the Company misrepresented to the
CPUC and to QFs its transmission capacity; the existence of transmission
constraints extends the five-year deadline in the agreements; the Company was
obligated to build transmission upgrades at utility (non-QF) expense which it
failed to build; and the Company had a general goal of trying to stifle QF
development. The POPI suit alleges breach of contract, negligent
misrepresentation, misrepresentation, breach of the implied covenant of good
faith and fair dealing, unfair business practices and negligent interference
with prospective economic advantage, and seeks declaratory relief, damages,
injunctive relief and relief from forfeiture. The POPI complaint seeks
compensatory damages "according to proof," together with interest, attorneys'
fees and costs of suit. While the complaint makes no mention of any dollar
amount of compensatory damages, the plaintiff's damage expert has given a
preliminary estimate of damages sought of $67 million. POPI also seeks an
unspecified amount of punitive damages.
If the trial of the POPI case results in an outcome adverse to the Company,
there are other similarly-situated QFs which might choose to file similar
complaints. How many such additional complaints might be filed will likely
depend on the basis for any adverse decision in the POPI case. The Company
believes that the matter has no merit and that the ultimate outcome of this
matter will not have a significant adverse impact on its financial position or
results of operations.
AIR DISTRICT RULEMAKING PROCEEDINGS
See "Environmental Matters and Other Regulations -- Environmental
Matters -- Environmental Protection Measures" above for a description of
proceedings pending before local air districts in California relating to NOx
emission reduction requirements.
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.
The Company believes the case is without merit and has filed a motion to
dismiss the complaint. The Company believes that the ultimate outcome of the
antitrust litigation will not have a significant adverse impact on its financial
position.
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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 add additional individuals for a total
of 178 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.
In November 1993, the parties engaged in private mediation sessions. On
December 20, 1993, the plaintiffs filed an offer to compromise and settle their
claims against the Company for $250 million.
The Company is unable to estimate the ultimate outcome of this matter, but
such outcome could have a significant adverse impact on the Company's results of
operations. The Company believes that the ultimate outcome of this matter will
not have a significant adverse impact on its financial position.
46
<PAGE> 50
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 1993 POSITION EFFECTIVE DATE
----------------------------------------------------------------------------------------------
<S> <C> <C> <C>
R. A. Clarke................... 63 Chairman of the Board and Chief Executive Officer May 1, 1986
S. T. Skinner.................. 56 President and Chief Operating Officer November 1, 1991
J. R. McLeod................... 58 Executive Vice President November 1, 1991
J. D. Shiffer.................. 55 Executive Vice President November 1, 1991
R. D. Glynn, Jr................ 51 Senior Vice President and General Manager,
Customer Energy Services Business Unit January 1, 1994
J. F. Jenkins-Stark............ 42 Senior Vice President and General Manager, Gas
Supply Business Unit August 1, 1993
V. G. Rose..................... 47 Senior Vice President and General Manager,
Electric Supply Business Unit January 1, 1994
G. M. Rueger................... 43 Senior Vice President and General Manager, Nuclear
Power Generation Business Unit November 1, 1991
H. V. Golub.................... 48 Vice President and General Counsel January 1, 1987
T. W. High..................... 46 Vice President and Assistant to the Chairman of
the Board November 1, 1991
G. N. Horne.................... 62 Vice President--Corporate Communications July 1, 1983
J. E. Koehn.................... 61 Vice President--Community and Governmental
Relations March 1, 1987
J. Pfannenstiel................ 46 Vice President--Corporate Planning February 1, 1987
G. R. Smith.................... 45 Vice President and Chief Financial Officer November 1, 1991
B. Coull Williams.............. 41 Vice President--Human Resources February 1, 1993
</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>
S. T. Skinner............ Vice Chairman of the Board May 1, 1986 to October 31, 1991
J. R. McLeod............. Executive Vice President and General Manager, April 1, 1989 to October 31, 1991
Gas Supply Business Unit
Executive Vice President February 1, 1989 to March 31, 1989
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, November 1, 1991 to December 31, 1993
Electric Supply Business Unit
Vice President--Power Generation January 1, 1988 to October 31, 1991
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 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
Project Manager, Human Resources November 23, 1988 to June 30, 1989
</TABLE>
47
<PAGE> 51
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 47 under the heading
"Quarterly Consolidated Financial Data" in the Company's 1993 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 1993 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 24 under the heading
"Management's Discussion and Analysis of Consolidated Results of Operations and
Financial Condition" in the Company's 1993 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 1993 Annual
Report to Shareholders on page 48 and pages 25 through 47 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 1994 Proxy
Statement relating to the 1994 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 17 under the heading
"Executive Compensation" in the 1994 Proxy Statement relating to the 1994 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 18 under the
headings "Security Ownership of Management" and "Principal Shareholders" in the
1994 Proxy Statement relating to the 1994 Annual Meeting of Shareholders, which
information is hereby incorporated by reference.
48
<PAGE> 52
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 1994 Proxy Statement
relating to the 1994 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 1993 Annual Report
to Shareholders, are incorporated by reference in this report:
Statement of Consolidated Income for the Years Ended December 31,
1993, 1992 and 1991.
Consolidated Balance Sheet as of December 31, 1993 and 1992.
Statement of Consolidated Cash Flows for the Years Ended December 31,
1993, 1992 and 1991.
Statement of Consolidated Common Stock Equity and Preferred Stock for
the Years Ended December 31, 1993, 1992 and 1991.
Statement of Consolidated Capitalization as of December 31, 1993 and
1992.
Schedule of Consolidated Segment Information for the Years Ended
December 31, 1993, 1992 and 1991.
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:
V -- Consolidated Property, Plant and Equipment for the Years
Ended December 31, 1993, 1992 and 1991.
VI -- Accumulated Depreciation of Consolidated Plant in Service for
the Years Ended December 31, 1993, 1992 and 1991.
VIII -- Consolidated Valuation and Qualifying Accounts for the Years
Ended December 31, 1993, 1992 and 1991.
IX -- Consolidated Short-term Borrowings for the Years Ended
December 31, 1993, 1992 and 1991.
X -- Consolidated Supplementary Income Statement Information for
the Years Ended December 31, 1993, 1992 and 1991.
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.
49
<PAGE> 53
4. Exhibits required to be filed by Item 601 of Regulation S-K:
3.1 Restated Articles of Incorporation effective as of November
18, 1992 (Form 8-K dated March 25, 1994 (File No. 1-2348),
Exhibit 4.1).
3.2 Certificate of Determination of Preferences of 7.04%
Redeemable First Preferred Stock (Form 8-K dated March 25,
1994 (File No. 1-2348), Exhibit 4.2).
3.3 Certificate of Determination of Preferences of 6 7/8%
Redeemable First Preferred Stock (Form 8-K dated March 25,
1994 (File No. 1-2348), Exhibit 4.3).
3.4 Certificate of Decrease in Number of Shares of Certain
Series of First Preferred Stock (Form 8-K dated March 25,
1994 (File No. 1-2348), Exhibit 4.4).
3.5 Certificate of Determination of Preferences of 6.30%
Redeemable First Preferred Stock (Form 8-K dated March 25,
1994 (File No. 1-2348), Exhibit 4.5).
3.6 By-Laws dated October 1, 1993.
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 Master Agreement for the Assignment of Service between the
Company and NOVA Corporation of Alberta dated September 1, 1993
and schedule A.
10.2 Service Agreement Rate Schedule FS between the Company and NOVA
Corporation of Alberta dated October 1, 1993, rate schedule FS,
and general terms and conditions.
10.3 Service Agreement Applicable to Firm Transportation Service
Under Rate Schedule FS-1 between the Company and Alberta
Natural Gas Company LTD dated September 22, 1993, statement of
effective rates and charges effective November 1, 1993, service
schedule FS-1, and general terms and conditions.
10.4 Firm Transportation Service Agreement between the Company and
Pacific Gas Transmission Company dated October 26, 1993, rate
schedule FTS-1, and general terms and conditions.
10.5 Transportation Service Agreement as Amended and Restated
Between the Company and El Paso Natural Gas Company dated
November 1, 1993, rate schedule T-3, and general terms and
conditions.
10.6 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).
*10.7 Pacific Gas and Electric Company Deferred Compensation Plan
for Directors (Form 10-K for fiscal year 1992 (File No.
1-2348), Exhibit 10.5).
*10.8 Pacific Gas and Electric Company Deferred Compensation Plan
for Officers (Form 10-K for fiscal year 1991 (File No.
1-2348), Exhibit 10.6).
*10.9 Savings Fund Plan for Employees of Pacific Gas and Electric
Company applicable to management employees, effective
January 1, 1994.
- ---------------
* 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.
50
<PAGE> 54
*10.10 Performance Incentive Plan of Pacific Gas and Electric
Company.
*10.11 The Pacific Gas and Electric Company Retirement Plan
applicable to management employees, effective January 1,
1994.
*10.12 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).
*10.13 Pacific Gas and Electric Company Stock Option Plan, as
amended effective as of September 16, 1992.
*10.14 Pacific Gas and Electric Company Performance Unit Plan (Form
10-K for fiscal year 1991 (File No. 1-2348), Exhibit 10.13).
*10.15 Pacific Gas and Electric Company Relocation Assistance
Program for Officers (Form 10-K for fiscal year 1989 (File
No. 1-2348), Exhibit 10.16).
*10.16 Pacific Gas and Electric Company Executive Flexible
Perquisites Program.
*10.17 Management Contract with Jerry R. McLeod (Form 10-K for
fiscal year 1989 (File No. 1-2348), Exhibit 10.18).
*10.18 PG&E Postretirement Life Insurance Plan (Form 10-K for
fiscal year 1991 (File No. 1-2348), Exhibit 10.16).
*10.19 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).
*10.20 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).
*10.21 Contract For Performance of Work Between George A. Maneatis
and Pacific Gas and Electric Company (Form 10-K for fiscal
year 1991 (File No. 1-2348), Exhibit 10.20).
*10.22 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, 1994 (File No. 1-2348), Exhibit 11).
12.1 Computation of Ratios of Earnings to Fixed Charges (Form 8-K
dated March 2, 1994 (File No. 1-2348), Exhibit 12.1).
12.2 Computation of Ratios of Earnings to Combined Fixed Charges and
Preferred Stock Dividends (Form 8-K dated March 2, 1994 (File
No. 1-2348), Exhibit 12.2).
13. 1993 Annual Report to Shareholders (portions of the 1993 Annual
Report to Shareholders under the headings "Selected Financial
Data," "Management's Discussion and Analysis of Consolidated
Results of Operations and Financial Information," "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 1993 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 & Co.
24.1 Resolution of the Board of Directors authorizing the execution
of the Form 10-K.
24.2 Powers of Attorney.
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.
51
<PAGE> 55
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, 1993 and through
the date hereof:
1. October 14, 1993
Item 5. Other Events.
-- Restructuring of Canadian Gas Purchase Obligations
-- California Public Utilities Commission (CPUC) Proceedings
Canadian Affiliates Audit
Workforce Reduction Memorandum Account
1994 Attrition Rate Adjustment
Electric Reasonableness Proceeding
-- PGT/PG&E Pipeline Expansion Project
2. October 25, 1993
Item 5. Other Events.
-- Performance Incentive Plan -- Year-to-Date Financial Results
-- Regulatory Reform Initiative
-- Medium-Term Note Program
Item 7. Financial Statements, Pro Forma Financial Information
and Exhibits.
3. November 4, 1993
Item 5. Other Events.
-- Restructuring of Canadian Gas Purchase Obligations
-- California Public Utilities Commission Proceedings
1994 Cost of Capital Proceeding
CPUC Denial of Petition to Modify General Rate Case
-- PGT/PG&E Pipeline Expansion Project
4. November 17, 1993
Item 5. Other Events.
-- Performance Incentive Plan -- Year-to-Date Financial Results
-- California Public Utilities Commission Proceeding --
1988-1990 Reasonableness Proceeding
-- QF Constrained Area Litigation
5. December 7, 1993
Item 5. Other Events.
-- Antitrust Litigation
-- California Public Utilities Commission Proceeding
1994 Cost of Capital Proceeding
Hazardous Materials and Hazardous Waste Compliance and
Remediation
52
<PAGE> 56
6. December 23, 1993
Item 5. Other Events.
-- Performance Incentive Plan -- Year-to-Date Financial Results
7. January 10, 1994
Item 5. Other Events.
-- Performance Incentive Plan -- 1994 Target
-- California Public Utilities Commission Proceedings
Electric Fuel and Sales Balancing Accounts
1994 Attrition Rate Adjustment
8. January 24, 1994
Item 5. Other Events.
-- Performance Incentive Plan -- 1993 Financial Results
-- 1993 Consolidated Earnings (unaudited)
-- Common Stock Dividend
-- Potential Sale of PG&E Resources Company
-- Hinkley Compressor Station Litigation
9. March 2, 1994
Item 5. Other Events.
-- California Public Utilities Commission Proceedings
PGT-PG&E Expansion Project
1992 Reasonableness Proceeding-DRA Recommendation
1988-1990 Reasonableness Proceeding -- Non-Canadian Gas
Phase
Item 7. Financial Statements, Pro Forma Information and
Exhibits.
-- 1993 Financial Statements
-- Ratios of Earnings to Fixed Charges
-- Ratios of Earnings to Combined Fixed Charges and Preferred
Dividends
-- Exhibits
10. March 11, 1994
Item 5. Other Events.
-- Performance Incentive Plan -- Year-to-Date Financial Results
-- California Public Utilities Commission Proceedings
Regulatory Reform Initiative
1988-1990 Reasonableness Proceeding -- Canadian Issues
1988-1990 Reasonableness Proceeding -- Non-Canadian
Issues
11. March 25, 1994
Item 5. Other Events.
-- California Public Utilities Commission Proceedings -- Gas
Reasonableness Proceedings
-- Preferred Stock Offering
Item 7. Financial Statements, Pro Forma Financial Information
and Exhibits
53
<PAGE> 57
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.
54
<PAGE> 58
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 28TH DAY OF MARCH, 1994.
PACIFIC GAS AND ELECTRIC COMPANY
(Registrant)
By BRUCE R. WORTHINGTON
(Bruce R. Worthington,
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
*RICHARD A. CLARKE Chairman of the Board, March 28, 1994
Chief Executive Officer
and Director
B. PRINCIPAL FINANCIAL OFFICER
*GORDON R. SMITH Vice President and March 28, 1994
Chief Financial Officer
C. CONTROLLER OR PRINCIPAL ACCOUNTING
OFFICER
*THOMAS C. LONG Controller March 28, 1994
D. DIRECTORS
* STANLEY T. SKINNER Directors March 28, 1994
* LESLIE L. LUTTGENS
* H. M. CONGER
* WILLIAM F. MILLER
* MARY S. METZ
* MELVIN B. LANE
* RICHARD B. MADDEN
* JOHN C. SAWHILL
* WILLIAM S. DAVILA
* ALAN SEELENFREUND
* SAMUEL T. REEVES
* BARRY LAWSON WILLIAMS
* CARL E. REICHARDT
* JOHN B. M. PLACE
* GEORGE A. MANEATIS
</TABLE>
* By BRUCE R. WORTHINGTON
(Bruce R. Worthington,
Attorney-in-Fact)
55
<PAGE> 59
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 16, 1994. Our report on the 1993
consolidated financial statements includes explanatory paragraphs that describe
the uncertainties regarding the ultimate outcome of the gas reasonableness
proceedings, the recovery of certain Helms costs and revenues and the Hinkley
litigation, as discussed in notes 2 and 11 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 and income taxes as discussed in notes 1 and 7 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 schedules listed in Part
IV, Item 14. (a)(3) of this Annual Report on Form 10-K are the responsibility of
the Company's management and are presented for the purpose of complying with the
Securities and Exchange Commission's rules and are not part of the consolidated
financial statements. These supplemental schedules have 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 state 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 & CO.
ARTHUR ANDERSEN & CO.
San Francisco, California
February 16, 1994
56
<PAGE> 60
SCHEDULE V
PACIFIC GAS AND ELECTRIC COMPANY
SCHEDULE V -- CONSOLIDATED PROPERTY, PLANT AND EQUIPMENT
FOR THE YEAR ENDED DECEMBER 31, 1993
<TABLE>
<CAPTION>
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E COLUMN F
<S> <C> <C> <C> <C> <C>
OTHER
BALANCE AT CHANGES(3) BALANCE AT
BEGINNING ADDITIONS RETIRE- ADD END OF
CLASSIFICATION OF PERIOD AT COST MENTS (DEDUCT) PERIOD
------------------------ (IN THOUSANDS) --------------------------
ELECTRIC:
Tangible:
Production............ $10,591,336 $ 219,593 $ 27,530 $ (749) $10,782,650
Transmission.......... 2,031,201 64,519 9,731 8 2,085,997
Distribution.......... 7,718,394 431,845 131,620 303 8,018,922
General............... 1,894,718 155,725 299,542 468,692 2,219,593
---------- --------- -------- --------- ----------
Total(1)............ 22,235,649 871,682 468,423 468,254 23,107,162
Intangible............... 43,894 1,135 -- (6) 45,023
---------- --------- -------- --------- ----------
Total............ 22,279,543 872,817 468,423 468,248 23,152,185
---------- --------- -------- --------- ----------
GAS:
Tangible:
Production............ 11,609 629 8,891 (31) 3,316
Storage............... 224,854 15,093 5,546 -- 234,401
Gas stored
underground......... 53,688 2,195 -- -- 55,883
Transmission.......... 1,488,577 1,642,455 25,563 50 3,105,519
Distribution.......... 2,917,009 182,319 27,789 4 3,071,543
General............... 753,367 26,303 109,225 -- 670,445
---------- --------- -------- --------- ----------
Total............... 5,449,104 1,868,994 177,014 23 7,141,107
Intangible............... 4,980 654 -- -- 5,634
---------- --------- -------- --------- ----------
Total............ 5,454,084 1,869,648 177,014 23 7,146,741
---------- --------- -------- --------- ----------
TOTAL PLANT IN
SERVICE.................. 27,733,627 2,742,465 645,437 468,271 30,298,926
CONSTRUCTION WORK IN
PROGRESS(2).............. 1,534,578 (914,391) -- -- 620,187
OIL AND GAS
PROPERTIES............... 591,544 110,030 695 (127,356) 573,523
---------- --------- -------- --------- ----------
TOTAL.......... $29,859,749 $1,938,104 $646,132 $ 340,915 $31,492,636
---------- --------- -------- --------- ----------
---------- --------- -------- --------- ----------
</TABLE>
- ------------
<TABLE>
<C> <S> <C>
(1) Electric tangible cost at December 31, 1993 includes approximately $6.5 billion related
to the Diablo Canyon Nuclear Power Plant, substantially all in electric production.
(2) Additions are net of transfers of property to plant in service.
(3) Substantially all other changes consist of:
Adoption of Statement of Financial Accounting Standards No. 109........ $ 490,266
Amortization, net of retirements, of oil and gas properties............ (149,123)
</TABLE>
57
<PAGE> 61
SCHEDULE V
PACIFIC GAS AND ELECTRIC COMPANY
SCHEDULE V -- CONSOLIDATED PROPERTY, PLANT AND EQUIPMENT
FOR THE YEAR ENDED DECEMBER 31, 1992
<TABLE>
<CAPTION>
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E COLUMN F
<S> <C> <C> <C> <C> <C>
OTHER
BALANCE AT CHANGES(3) BALANCE AT
BEGINNING ADDITIONS RETIRE- ADD END OF
CLASSIFICATION OF PERIOD AT COST MENTS (DEDUCT) PERIOD
------------------------- (IN THOUSANDS) -------------------------
ELECTRIC:
Tangible:
Production............ $10,408,912 $ 227,369 $ 44,945 $ -- $10,591,336
Transmission.......... 1,944,674 94,008 4,936 (2,545) 2,031,201
Distribution.......... 7,237,992 515,576 34,688 (486) 7,718,394
General............... 1,718,133 196,885 20,276 (24) 1,894,718
---------- --------- -------- --------- ----------
Total(1)............ 21,309,711 1,033,838 104,845 (3,055) 22,235,649
Intangible............... 48,354 (4,460) -- -- 43,894
---------- --------- -------- --------- ----------
Total............ 21,358,065 1,029,378 104,845 (3,055) 22,279,543
---------- --------- -------- --------- ----------
GAS:
Tangible:
Production............ 15,026 964 2,195 (2,186) 11,609
Storage............... 215,752 13,868 4,763 (3) 224,854
Gas stored
underground......... 53,688 -- -- -- 53,688
Transmission.......... 1,426,566 66,511 4,500 -- 1,488,577
Distribution.......... 2,685,075 239,572 7,638 -- 2,917,009
General............... 673,011 88,998 8,632 (10) 753,367
---------- --------- -------- --------- ----------
Total............... 5,069,118 409,913 27,728 (2,199) 5,449,104
Intangible............... 4,879 101 -- -- 4,980
---------- --------- -------- --------- ----------
Total............ 5,073,997 410,014 27,728 (2,199) 5,454,084
---------- --------- -------- --------- ----------
TOTAL PLANT IN
SERVICE.................. 26,432,062 1,439,392 132,573 (5,254) 27,733,627
CONSTRUCTION WORK IN
PROGRESS(2).............. 711,509 823,069 -- -- 1,534,578
OIL AND GAS
PROPERTIES............... 632,811 98,775 1,926 (138,116) 591,544
---------- --------- -------- --------- ----------
TOTAL.......... $27,776,382 $2,361,236 $134,499 $(143,370) $29,859,749
---------- --------- -------- --------- ----------
---------- --------- -------- --------- ----------
</TABLE>
- ------------
<TABLE>
<C> <S> <C>
(1) Electric tangible cost at December 31, 1992 includes approximately $6.0
billion related to the Diablo Canyon Nuclear Power Plant, substantially all
in electric production.
(2) Additions are net of transfers of property to plant in service.
(3) Other changes consist of:
Amortization, net of retirements, of oil and gas properties.................. $(138,116)
Costs transferred from plant held for future use to nonutility plant......... (3,068)
Foreign exchange adjustment.................................................. (2,186)
</TABLE>
58
<PAGE> 62
SCHEDULE V
PACIFIC GAS AND ELECTRIC COMPANY
SCHEDULE V -- CONSOLIDATED PROPERTY, PLANT AND EQUIPMENT
FOR THE YEAR ENDED DECEMBER 31, 1991
<TABLE>
<CAPTION>
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E COLUMN F
<S> <C> <C> <C> <C> <C>
OTHER
BALANCE AT CHANGES(4) BALANCE AT
BEGINNING ADDITIONS RETIRE- ADD END OF
CLASSIFICATION OF PERIOD AT COST MENTS (DEDUCT) PERIOD
------------------------ (IN THOUSANDS) -------------------------
ELECTRIC:
Tangible:
Production............ $10,195,447 $ 220,563 $ 7,098 $ -- $10,408,912
Transmission.......... 1,855,920 92,028 3,274 -- 1,944,674
Distribution.......... 6,687,093 612,971 62,072 -- 7,237,992
General............... 1,464,111 262,273 8,251 -- 1,718,133
---------- --------- -------- -------- ----------
Total(1)............ 20,202,571 1,187,835 80,695 -- 21,309,711
Intangible............... 41,916 6,438 -- -- 48,354
---------- --------- -------- -------- ----------
Total............ 20,244,487 1,194,273 80,695 -- 21,358,065
---------- --------- -------- -------- ----------
GAS:
Tangible:
Production............ 9,305 5,721 -- -- 15,026
Storage............... 187,776 28,271 295 -- 215,752
Gas stored
underground......... 44,041 9,647 -- -- 53,688
Transmission.......... 1,378,268 52,475 4,177 -- 1,426,566
Distribution.......... 2,447,920 244,941 7,786 -- 2,685,075
General............... 571,615 104,720 3,324 -- 673,011
---------- --------- -------- -------- ----------
Total............... 4,638,925 445,775 15,582 -- 5,069,118
Intangible............... 4,390 496 7 -- 4,879
---------- --------- -------- -------- ----------
Total............ 4,643,315 446,271 15,589 -- 5,073,997
---------- --------- -------- -------- ----------
TOTAL PLANT IN
SERVICE.................. 24,887,802 1,640,544 96,284 -- 26,432,062
CONSTRUCTION WORK IN
PROGRESS(2).............. 655,202 69,167 -- (12,860) 711,509
OIL AND GAS
PROPERTIES(3)............ 255,146 434,935 9,191 (48,079) 632,811
---------- --------- -------- -------- ----------
TOTAL.......... $25,798,150 $2,144,646 $105,475 $(60,939) $27,776,382
---------- --------- -------- -------- ----------
---------- --------- -------- -------- ----------
</TABLE>
- ---------------
(1) Electric tangible cost at December 31, 1991 includes approximately $5.9
billion related to the Diablo Canyon Nuclear Power Plant, substantially all
in electric production.
(2) Additions are net of transfers of property to plant in service.
<TABLE>
<S> <C>
(3) Additions include acquisition of Tex/Con Oil & Gas Company..................... $388,662
</TABLE>
(4) Other changes consist of:
<TABLE>
<S> <C>
Amortization, net of retirements, of oil and gas properties........... $(48,079)
Project costs transferred from construction work in progress:
Recorded in deferred charges..................................... (6,786)
Charged to income................................................ (6,074)
</TABLE>
59
<PAGE> 63
SCHEDULE VI
PACIFIC GAS AND ELECTRIC COMPANY
SCHEDULE VI -- ACCUMULATED DEPRECIATION OF CONSOLIDATED PLANT IN SERVICE
FOR THE YEAR ENDED DECEMBER 31, 1993
<TABLE>
<CAPTION>
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E COLUMN F
ADDITIONS OTHER
BALANCE AT CHARGED TO CHANGES(2) BALANCE AT
BEGINNING COSTS AND RETIRE- ADD END OF
DESCRIPTION OF PERIOD EXPENSES MENTS (DEDUCT) PERIOD
<S> <C> <C> <C> <C> <C>
------------------------ (IN THOUSANDS) --------------------------
ELECTRIC:
Tangible:
Production............ $ 3,547,901 $ 430,143 $ 29,561 $ 30,282 $ 3,978,765
Transmission.......... 817,416 60,681 10,220 -- 867,877
Distribution.......... 2,893,990 282,553 104,631 -- 3,071,912
General............... 720,664 164,331 295,857 127,545 716,683
----------- ----------- -------- ---------- -----------
Total(1)......... 7,979,971 937,708 440,269 157,827 8,635,237
----------- ----------- -------- ---------- -----------
GAS:
Tangible:
Production............ 4,298 3,182 5,238 205 2,447
Storage............... 80,678 7,539 6,308 -- 81,909
Transmission.......... 783,869 44,376 25,533 -- 802,712
Distribution.......... 1,372,286 147,505 31,729 -- 1,488,062
General............... 286,458 56,419 112,489 (5,236) 225,152
----------- ----------- -------- ---------- -----------
Total............ 2,527,589 259,021 181,297 (5,031) 2,600,282
----------- ----------- -------- ---------- -----------
TOTAL.......... $10,507,560 $ 1,196,729 $621,566 $ 152,796 $11,235,519
----------- ----------- -------- ---------- -----------
----------- ----------- -------- ---------- -----------
</TABLE>
- ------------
<TABLE>
<C> <S> <C>
(1) Electric accumulated depreciation at December 31, 1993 includes approximately
$1.9 billion related to the Diablo Canyon Nuclear Power Plant, substantially
all in electric production.
(2) Substantially all other changes consist of:
Impact of adoption of Statement of Financial Accounting Standards No. 109.... $103,766
Nuclear decommissioning trust fund interest income accounted for as a credit
to accumulated depreciation in accordance with Federal Energy Regulatory
Commission guidelines..................................................... 30,282
Capitalized depreciation relating to transportation and construction
equipment................................................................. 18,904
</TABLE>
See Note 1 of Notes to Consolidated Financial Statements in the 1993 Annual
Report to Shareholders for the accounting policy with respect to plant in
service and depreciation.
60
<PAGE> 64
SCHEDULE VI
PACIFIC GAS AND ELECTRIC COMPANY
SCHEDULE VI -- ACCUMULATED DEPRECIATION OF CONSOLIDATED PLANT IN SERVICE
FOR THE YEAR ENDED DECEMBER 31, 1992
<TABLE>
<CAPTION>
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E COLUMN F
ADDITIONS OTHER
BALANCE AT CHARGED TO CHANGES(2) BALANCE AT
BEGINNING COSTS AND RETIRE- ADD END OF
DESCRIPTION OF PERIOD EXPENSES MENTS (DEDUCT) PERIOD
<S> <C> <C> <C> <C> <C>
----------------------- (IN THOUSANDS) --------------------------
ELECTRIC:
Tangible:
Production............. $3,132,255 $ 401,491 $ 46,009 $ 60,164 $ 3,547,901
Transmission........... 763,515 60,911 7,010 -- 817,416
Distribution........... 2,642,599 294,705 43,314 -- 2,893,990
General................ 615,760 109,599 18,952 14,257 720,664
---------- ----------- -------- ---------- -----------
Total(1).......... 7,154,129 866,706 115,285 74,421 7,979,971
---------- ----------- -------- ---------- -----------
GAS:
Tangible:
Production............. 6,890 629 2,051 (1,170) 4,298
Storage................ 77,748 8,134 5,204 -- 80,678
Transmission........... 746,217 43,468 5,816 -- 783,869
Distribution........... 1,242,610 142,196 12,520 -- 1,372,286
General................ 244,987 43,717 8,089 5,843 286,458
---------- ----------- -------- ---------- -----------
Total............. 2,318,452 238,144 33,680 4,673 2,527,589
---------- ----------- -------- ---------- -----------
TOTAL........... $9,472,581 $ 1,104,850 $148,965 $ 79,094 $10,507,560
---------- ----------- -------- ---------- -----------
---------- ----------- -------- ---------- -----------
</TABLE>
- ------------
<TABLE>
<C> <S> <C>
(1) Electric accumulated depreciation at December 31, 1992 includes approximately
$1.5 billion related to the Diablo Canyon Nuclear Power Plant, substantially all
in electric production.
(2) Substantially all other changes consist of:
Nuclear decommissioning trust fund interest income accounted for as a credit
to accumulated depreciation in accordance with Federal Energy Regulatory
Commission guidelines...................................................... $30,231
Net book value of plant retirement transferred to deferred charges............ 30,200
Capitalized depreciation relating to transportation and construction
equipment.................................................................. 20,100
</TABLE>
See Note 1 of Notes to Consolidated Financial Statements in the 1993 Annual
Report to Shareholders for the accounting policy with respect to plant in
service and depreciation.
61
<PAGE> 65
SCHEDULE VI
PACIFIC GAS AND ELECTRIC COMPANY
SCHEDULE VI -- ACCUMULATED DEPRECIATION OF CONSOLIDATED PLANT IN SERVICE
FOR THE YEAR ENDED DECEMBER 31, 1991
<TABLE>
<CAPTION>
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E COLUMN F
ADDITIONS OTHER
BALANCE AT CHARGED TO CHANGES(2) BALANCE AT
BEGINNING COSTS AND RETIRE- ADD END OF
DESCRIPTION OF PERIOD EXPENSES MENTS (DEDUCT) PERIOD
<S> <C> <C> <C> <C> <C>
------------------------ (IN THOUSANDS) ----------------------
ELECTRIC:
Tangible:
Production.............. $2,695,543 $ 422,316 $ 9,715 $ 24,111 $ 3,132,255
Transmission............ 709,216 58,865 4,566 -- 763,515
Distribution............ 2,437,143 276,339 70,883 -- 2,642,599
General................. 510,668 95,705 4,299 13,686 615,760
---------- ---------- -------- -------- ----------
Total(1)........... 6,352,570 853,225 89,463 37,797 7,154,129
---------- ---------- -------- -------- ----------
GAS:
Tangible:
Production.............. 6,613 647 536 166 6,890
Storage................. 70,913 7,168 333 -- 77,748
Transmission............ 707,889 41,720 3,392 -- 746,217
Distribution............ 1,125,830 130,972 14,192 -- 1,242,610
General................. 203,535 37,627 1,722 5,547 244,987
---------- ---------- -------- -------- ----------
Total.............. 2,114,780 218,134 20,175 5,713 2,318,452
---------- ---------- -------- -------- ----------
TOTAL............ $8,467,350 $1,071,359 $109,638 $ 43,510 $9,472,581
---------- ---------- -------- -------- ----------
---------- ---------- -------- -------- ----------
</TABLE>
- ------------
(1) Electric accumulated depreciation at December 31, 1991 includes
approximately $1.2 billion related to the Diablo Canyon Nuclear Power Plant,
substantially all in electric production.
<TABLE>
<C> <S> <C>
(2) Substantially all other changes consist of:
Nuclear decommissioning trust fund interest income accounted for as a credit
to accumulated depreciation in accordance with Federal Energy Regulatory
Commission guidelines...................................................... $24,111
Capitalized depreciation relating to transportation and construction
equipment.................................................................. 19,233
</TABLE>
See Note 1 of the Notes to Consolidated Financial Statements in the 1993 Annual
Report to Shareholders for the accounting policy with respect to plant in
service and depreciation.
62
<PAGE> 66
SCHEDULE VIII
PACIFIC GAS AND ELECTRIC COMPANY
SCHEDULE VIII -- CONSOLIDATED VALUATION AND
QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991
<TABLE>
<CAPTION>
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E
ADDITIONS
BALANCE -------------------
AT CHARGED BALANCE
BEGINNING TO COSTS CHARGED AT
OF AND TO OTHER DEDUC- END OF
DESCRIPTION PERIOD EXPENSES ACCOUNTS TIONS PERIOD
<S> <C> <C> <C> <C> <C>
----------------- (IN THOUSANDS) ------------------
VALUATION AND QUALIFYING
ACCOUNTS DEDUCTED FROM
ASSETS:
1993:
Reserve for investment in Alaska Natural
Gas Transportation System............ $152,517 $ 0 $ -- $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
-------- -------- -------- -------- --------
-------- -------- -------- -------- --------
1991:
Reserve for investment in Alaska Natural
Gas Transportation System............ $115,842 $ 17,051 $ -- $ -- $132,893(2)
-------- -------- -------- -------- --------
-------- -------- -------- -------- --------
Reserve for impairment of oil and gas
properties........................... $ 15,179 $ 3,861 $ -- $ 8,205(3) $ 10,835
-------- -------- -------- -------- --------
-------- -------- -------- -------- --------
Reserve for deferred project costs...... $ 817 $ 3,810 $ -- $ -- $ 4,627
-------- -------- -------- -------- --------
-------- -------- -------- -------- --------
Allowance for uncollectible accounts.... $ 16,664 $ 23,030 $ -- $ 23,017(5) $ 16,677
-------- -------- -------- -------- --------
-------- -------- -------- -------- --------
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.
63
<PAGE> 67
SCHEDULE IX
PACIFIC GAS AND ELECTRIC COMPANY
SCHEDULE IX -- CONSOLIDATED SHORT-TERM BORROWINGS
FOR THE YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991
<TABLE>
<CAPTION>
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E COLUMN F
WEIGHTED
MAXIMUM AVERAGE AVERAGE
BALANCE WEIGHTED AMOUNT AMOUNT INTEREST
AT AVERAGE OUTSTANDING OUTSTANDING RATE
CATEGORY OF AGGREGATE END OF INTEREST DURING THE DURING THE DURING THE
SHORT-TERM BORROWINGS(1) PERIOD RATE PERIOD PERIOD(2) PERIOD(2)
<S> <C> <C> <C> <C> <C>
----------------(IN THOUSANDS, EXCEPT PERCENTAGES) ------------------
1993:
Commercial paper........ $764,163 3.4% $1,302,410 $ 807,679 3.3%
Bank loans.............. -- -- 135,336 53,546 3.4
1992:
Commercial paper........ $916,044 3.7% $1,019,904 $ 743,222 4.0%
Bank loans.............. 215,080 3.9 215,080 65,366 4.1
1991:
Commercial paper........ $833,312 5.2% $ 889,510 $ 691,940 6.8%
Bank loans.............. 176,599 5.0 176,599 29,127 6.0
</TABLE>
- ------------
(1) The general terms of aggregate short-term borrowings are described in Note 6
of Notes to Consolidated Financial Statements in the 1993 Annual Report to
Shareholders.
(2) Calculated using a monthly average.
64
<PAGE> 68
SCHEDULE X
PACIFIC GAS AND ELECTRIC COMPANY
SCHEDULE X--CONSOLIDATED SUPPLEMENTARY INCOME STATEMENT INFORMATION
FOR THE YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991
<TABLE>
<CAPTION>
COLUMN A COLUMN B
<S> <C>
CHARGED TO
COSTS AND
ITEM EXPENSES
---- ------------
(IN
THOUSANDS)
TAXES, OTHER THAN PAYROLL AND
INCOME TAXES:
1993:
Property................................................................. $203,094
------------
------------
1992:
Property................................................................. $203,340
------------
------------
1991:
Property................................................................. $203,620
------------
------------
</TABLE>
- ------------
Amounts charged to expense for royalties, advertising costs, and miscellaneous
taxes are not set forth inasmuch as such items do not exceed one percent of
total revenues as shown in the related Statement of Consolidated Income.
Amounts charged to expense for maintenance and repairs and depreciation and
amortization of intangible assets, preoperating costs, and similar deferrals are
not set forth inasmuch as the information is included in the Consolidated
Financial Statements or Notes thereto.
65
<PAGE> 69
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
EXHIBITS
TO
FORM 10-K
FOR THE YEAR ENDED DECEMBER 31, 1993
------------------
PACIFIC GAS AND ELECTRIC COMPANY
------------------
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
<PAGE> 70
INDEX TO EXHIBITS
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION OF EXHIBITS
-------
<S> <C>
3.1 Restated Articles of Incorporation effective as of November 18, 1992
(Form 8-K dated March 25, 1994 (File No. 1-2348), Exhibit 4.1).
3.2 Certificate of Determination of Preferences of 7.04% Redeemable First
Preferred Stock (Form 8-K dated March 25, 1994 (File No. 1-2348), Exhibit
4.2).
3.3 Certificate of Determination of Preferences of 6 7/8% Redeemable First
Preferred Stock (Form 8-K dated March 25, 1994 (File No. 1-2348), Exhibit
4.3).
3.4 Certificate of Decrease in Number of Shares of Certain Series of First
Preferred Stock (Form 8-K dated March 25, 1994 (File No. 1-2348), Exhibit
4.4).
3.5 Certificate of Determination of Preferences of 6.30% Redeemable First
Preferred Stock (Form 8-K dated March 25, 1994 (File No. 1-2348), Exhibit
4.5).
3.6 By-Laws dated October 1, 1993.
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 Master Agreement for the Assignment of Service between the Company and
NOVA Corporation of Alberta dated September 1, 1993 and schedule A.
10.2 Service Agreement Rate Schedule FS between the Company and NOVA
Corporation of Alberta dated October 1, 1993, rate schedule FS, and
general terms and conditions.
10.3 Service Agreement Applicable to Firm Transportation Service Under Rate
Schedule FS-1 between the Company and Alberta Natural Gas Company LTD
dated September 22, 1993, statement of effective rates and charges
effective November 1, 1993, service schedule FS-1, and general terms and
conditions.
10.4 Firm Transportation Service Agreement between the Company and Pacific Gas
Transmission Company dated October 26, 1993, rate schedule FTS-1, and
general terms and conditions.
10.5 Transportation Service Agreement as Amended and Restated Between the
Company and El Paso Natural Gas Company dated November 1, 1993, rate
schedule T-3, and general terms and conditions.
10.6 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).
*10.7 Pacific Gas and Electric Company Deferred Compensation Plan for Directors
(Form 10-K for fiscal year 1992 (File No. 1-2348), Exhibit 10.5).
*10.8 Pacific Gas and Electric Company Deferred Compensation Plan for Officers
(Form 10-K for fiscal year 1991 (File No. 1-2348), Exhibit 10.6).
*10.9 Savings Fund Plan for Employees of Pacific Gas and Electric Company
applicable to management employees, effective January 1, 1994.
*10.10 Performance Incentive Plan of Pacific Gas and Electric Company.
*10.11 The Pacific Gas and Electric Company Retirement Plan applicable to
management employees, effective January 1, 1994.
</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> 71
INDEX TO EXHIBITS--(CONTINUED)
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION OF EXHIBITS
-------
<S> <C>
*10.12 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).
*10.13 Pacific Gas and Electric Company Stock Option Plan, as amended effective
as of September 16, 1992.
*10.14 Pacific Gas and Electric Company Performance Unit Plan (Form 10-K for
fiscal year 1991 (File No. 1-2348), Exhibit 10.13).
*10.15 Pacific Gas and Electric Company Relocation Assistance Program for
Officers (Form 10-K for fiscal year 1989 (File No. 1-2348), Exhibit
10.16).
*10.16 Pacific Gas and Electric Company Executive Flexible Perquisites Program.
*10.17 Management Contract with Jerry R. McLeod (Form 10-K for fiscal year 1989
(File No. 1-2348), Exhibit 10.18).
*10.18 PG&E Postretirement Life Insurance Plan (Form 10-K for fiscal year 1991
(File No. 1-2348), Exhibit 10.16).
*10.19 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).
*10.20 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).
*10.21 Contract For Performance of Work Between George A. Maneatis and Pacific
Gas and Electric Company (Form 10-K for fiscal year 1991 (File No.
1-2348), Exhibit 10.20).
*10.22 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, 1994
(File No. 1-2348), Exhibit 11).
12.1 Computation of Ratios of Earnings to Fixed Charges (Form 8-K dated March
2, 1994 (File No. 1-2348), Exhibit 12.1).
12.2 Computation of Ratios of Earnings to Combined Fixed Charges and Preferred
Stock Dividends (Form 8-K dated March 2, 1994 (File No. 1-2348), Exhibit
12.2).
13. 1993 Annual Report to Shareholders (portions of the 1993 Annual Report to
Shareholders under the headings "Selected Financial Data," "Management's
Discussion and Analysis of Consolidated Results of Operations and
Financial Information," "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 1993 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 & Co.
24.1 Resolution of the Board of Directors authorizing the execution of the
Form 10-K.
24.2 Powers of Attorney.
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 3.6
Bylaws
of
Pacific Gas and Electric Company
as amended October 1, 1993
--------------------------
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.
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
<PAGE> 2
three to attend the meeting and cast votes for his shares. The authority
of agents must be evidenced by a written proxy signed by the shareholder
designating the agents authorized to attend the meeting and be delivered to
the Secretary of the Corporation prior to the commencement of the meeting.
5. No Cumulative Voting. No shareholder of the Corporation shall be
entitled to cumulate his or her voting power.
Article II.
DIRECTORS.
1. Number. The Board of Directors shall consist of sixteen (16)
directors.
2. Powers. The Board of Directors shall exercise all the powers of
the Corporation except those which are by law, or by the Articles of
Incorporation of this Corporation, or by the Bylaws conferred upon or
reserved to the shareholders.
3. Executive Committee. There shall be an Executive Committee of
the Board of Directors consisting of the Chairman of the Committee, the
Chairman of the Board, if these offices be filled, the President, and four
Directors who are not officers of the Corporation. The members of the
Committee shall be elected, and may at any time be removed, by a two-thirds
vote of the whole Board.
The Executive Committee, subject to the provisions of law, may
exercise any of the powers and perform any of the duties of the Board of
Directors; but the Board may by an affirmative vote of a majority of its
members withdraw or limit any of the powers of the Executive Committee.
The Executive Committee, by a vote of a majority of its members, shall
fix its own time and place of meeting, and shall prescribe its own rules of
procedure. A quorum of the Committee for the transaction of business shall
consist of three members.
4. Time and Place of Directors' Meetings. Regular meetings of the
Board of Directors shall be held on such days and at such times and at such
locations as shall be fixed by resolution of the Board, or designated by
the Chairman of the Board or, in his absence, the Vice Chairman of the
Board, or the President of the Corporation and contained in the notice of
any such meeting. Notice of meetings shall be delivered personally or sent
by mail or telegram at least seven days in advance.
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.
<PAGE> 3
6. Quorum. A quorum for the transaction of business at any meeting
of the Board of Directors shall consist of six members.
7. Action by Consent. Any action required or permitted to be taken by
the Board of Directors may be taken without a meeting if all Directors
individually or collectively consent in writing to such action. Such
written consent or consents shall be filed with the minutes of the
proceedings of the Board of Directors.
8. Meetings by Conference Telephone. Any meeting, regular or special,
of the Board of Directors or of any committee of the Board of Directors,
may be held by conference telephone or similar communication equipment,
provided that all Directors participating in the meeting can hear one
another.
Article III.
OFFICERS.
1. Officers. The officers of the Corporation shall be a
Chairman of the Board, a Vice Chairman of the Board, a Chairman of the
Executive Committee (whenever the Board of Directors in its discretion
fills these offices), a President, one or more Vice Presidents, a Secretary
and one or more Assistant Secretaries, a Treasurer and one or more
Assistant Treasurers, a General Counsel, a General Attorney (whenever the
Board of Directors in its discretion fills this office), and a Controller,
all of whom shall be elected by the Board of Directors. The Chairman of
the Board, the Vice Chairman of the Board, the Chairman of the Executive
Committee, and the President shall be members of the Board of Directors.
2. Chairman of the Board. The Chairman of the Board, if that office
be filled, shall preside at all meetings of the shareholders, of the
Directors, and of the Executive Committee in the absence of the Chairman of
that Committee. He shall be the chief executive officer of the Corporation
if so designated by the Board of Directors. He shall have such duties and
responsibilities as may be prescribed by the Board of Directors or the
Bylaws. The Chairman of the Board shall have authority to sign on behalf
of the Corporation agreements and instruments of every character, and in
the absence or disability of the President, shall exercise his duties and
responsibilities.
3. Vice Chairman of the Board. The Vice Chairman of the Board, if
that office be filled, shall have such duties and responsibilities as may
be prescribed by the Board of Directors, the Chairman of the Board, or the
Bylaws. He shall be the chief executive officer of 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
<PAGE> 4
of every character.
4. Chairman of the Executive Committee. The Chairman of the
Executive Committee, if that office be filled, shall preside at all
meetings of the Executive Committee. He shall aid and assist the other
officers in the performance of their duties and shall have such other
duties as may be prescribed by the Board of Directors or the Bylaws.
5. President. The President shall have such duties and
responsibilities as may be prescribed by the Board of Directors, the
Chairman of the Board, or the Bylaws. He shall be the chief executive
officer of the Corporation if so designated by the Board of Directors. If
there be no Chairman of the Board, the President shall also exercise the
duties and responsibilities of that office. The President shall have
authority to sign on behalf of the Corporation agreements and instruments
of every character.
6. Vice Presidents. Each Vice President shall have such duties and
responsibilities as may be prescribed by the Board of Directors, the
Chairman of the Board, the Vice Chairman of the Board, the President, or
the Bylaws. Each Vice President's authority to sign agreements and
instruments on behalf of the Corporation shall be as prescribed by the
Board of Directors. The Board of Directors, the Chairman of the Board, the
Vice Chairman of the Board, or the President may confer a special title
upon any Vice President.
7. Secretary. The Secretary shall attend all meetings of the
Board of Directors and the Executive Committee, and all meetings of the
shareholders, and he shall record the minutes of all proceedings in books
to be kept for that purpose. He shall be responsible for maintaining a
proper share register and stock transfer books for all classes of shares
issued by the Corporation. He shall give, or cause to be given, all
notices required either by law or the Bylaws. He shall keep the seal of
the Corporation in safe custody, and shall affix the seal of the
Corporation to any instrument requiring it and shall attest the same by his
signature.
The Secretary shall have such other duties as may be prescribed by the
Board of Directors, the Chairman of the Board, the Vice Chairman of the
Board, the President, or the Bylaws.
The Assistant Secretaries shall perform such duties as may be assigned
from time to time by the Board of Directors, the Chairman of the Board, the
Vice Chairman of the Board, the President, or the Secretary. In the
absence or disability of the Secretary, his duties shall be performed by an
Assistant Secretary.
8. Treasurer. The Treasurer shall have custody of all moneys
and funds of the Corporation, and shall cause to be kept full and accurate
records of receipts and disbursements of the Corporation. He shall deposit
all moneys and other valuables of the Corporation in the name and to the
credit of the Corporation in such depositaries as may be designated by the
Board of Directors or any employee of the Corporation designated by the
Board of Directors. He shall disburse such funds of the Corporation as
<PAGE> 5
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. The General Counsel shall be responsible for handling on behalf
of the Corporation all proceedings and matters of a legal nature. He shall
render advice and legal counsel to the Board of Directors, officers, and
employees of the Corporation, as necessary to the proper conduct of the
business. He shall keep the management of the Corporation informed of all
significant developments of a legal nature affecting the interests of the
Corporation.
The General Counsel shall have such other duties as may from time to
time be prescribed by the Board of Directors, the Chairman of the Board,
the Vice Chairman of the Board, the President, or the Bylaws.
10. Controller. The Controller shall be responsible for
maintaining the accounting records of the Corporation and for preparing
necessary financial reports and statements, and he shall properly account
for all moneys and obligations due the Corporation and all properties,
assets, and liabilities of the Corporation. He shall render to the
officers such periodic reports covering the result of operations of the
Corporation as may be required by them or any one of them.
The Controller shall have such other duties as may from time to time
be prescribed by the Board of Directors, the Chairman of the Board, the
Vice Chairman of the Board, the President, or the Bylaws.
Article IV.
MISCELLANEOUS.
1. Record Date. The Board of Directors may fix a time in the
future as a record date for the determination of the shareholders entitled
to notice of and to vote at any meeting of shareholders, or entitled to
receive any dividend or distribution, or allotment of rights, or to
exercise rights in respect to any change, conversion, or exchange of
shares. The record date so fixed shall be not more than sixty nor less
than ten days prior to the date of such meeting nor more than sixty days
prior to any other action for the purposes for which it is so fixed. When
a record date is so fixed, only shareholders of record on that date are
entitled to notice of and to vote at the meeting, or entitled to receive
any dividend or distribution, or allotment of rights, or to exercise the
<PAGE> 6
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 it
discretion, from time to time, authorize the issue and sale of shares of
capital stock of this Corporation to employees, pursuant to an employee's stock
purchase plan, for such consideration as the Board shall determine to be
reasonable. Such plan may provide for payment for such shares by installments
over a period of time fixed by the Board. In any such plan, the Board may
provide for interest on any installment payments, and that an employee may
cancel his agreement to purchase all or part of the shares thereunder. The
Board may fix such other terms and conditions for any such plan as it shall
deem, in its discretion, to be in the best interests of this Corporation. Any
such plan may include employees of: This Corporation's subsidiaries and
affiliates; Pacific Service Employees Association; Pacific Service 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.
<PAGE> 1
Exhibit 10.1
MASTER AGREEMENT FOR THE ASSIGNMENT OF SERVICE
Master Agreement for the Assignment of Service ("Assignment Agreement") between
NOVA Corporation of Alberta ("Company") and Pacific Gas and Electric Company
("Customer").
Whereas Company and Customer are parties to one or more Service Agreements for
Service under Company's Gas Transportation Tariff as amended, revised or
replaced from time to time (the "Tariff") and
Whereas from time to time Customer will be a party to assignments of Service,
as assignee or assignor.
In consideration of the terms and conditions contained in this Assignment
Agreement and the Tariff, Company and Customer agree as follows:
1. Terms used in this Assignment Agreement shall have the same
meanings as are ascribed to them in the Tariff unless otherwise
defined herein. If there is any conflict between this Assignment
Agreement and the Tariff, the Tariff shall govern.
2. Each assignment ("Assignment") of Service occurring on or after the
effective date of this Assignment Agreement shall be carried out in
accordance with and governed by this Assignment Agreement and the
Tariff.
3(a). Subject to paragraph 3(b), for each Assignment approved by Company
a schedule ("Assignment Schedule") will be prepared by Company in
the form attached as Schedule "A" for permanent assignments or
Schedule "B" temporary assignments.
3(b). In the case of multiple Assignments at one time, Company shall not
be required to prepare an Assignment Schedule for each Assignment
but may instead prepare an appendix to the Assignment Schedule
("Appendix 1") detailing the Assignments. The Assignment Schedule
shall apply to each Assigned Service listed in the Appendix 1 and
the Appendix 1 shall be incorporated into, and form part of, the
Assignment Schedule to which it is attached.
4. Fully executed Assignment Schedules shall be incorporated in and
form part of this Assignment Agreement.
5. Upon executing an Assignment Schedule, Company consents to the
assignment of the Assigned Service and releases Assignor from any
obligations and liabilities
-1-
<PAGE> 2
under the Assignor Service Agreement relating to the Assigned
Service which arise or accrue after the Effective Time, and in
the case of a temporary assignment, before the Reversion Time.
The terms "Assigned Service," "Assignor," "Assignor Service
Agreement," "Effective Time" and "Reversion Time" used in this
paragraph shall have the meaning ascribed to them in the
Assignment Schedule in question.
6. Company may from time to time amend this Assignment Agreement by
providing written notice to Customer. The effective date of
amendment shall be the date of receipt by Customer of the notice.
Any such amendment shall only apply to Assignment Schedules
executed after the effective date of the amendment.
7. Company and Customer shall perform such further acts, execute such
further documents and give such further assurances as may be
reasonably required to give effect to this Assignment Agreement.
8. Company may request that Customer as assignee provide Company with
a performance bond, irrevocable Letter of Credit or other security
acceptable to Company (the "security") as a condition precedent to
Company approving any Assignment.
9. Customer shall not assign this Assignment Agreement or any
Assignment Schedule without the prior written consent of Company.
10. Assignment Schedules may be executed in counterparts and may be
provided to Company by fax. If an Assignment Schedule is provided
to Company by fax an original copy shall be provided as soon
thereafter as reasonably possible and if there are any differences
between the two, the fax copy shall govern.
11. Notices by Customer or Company under this Assignment Agreement
shall be provided in accordance with Customer's Service Agreement.
12. This Assignment Agreement shall enure to the benefit of and be
binding upon Company and its successors and assigns and Customer
and its successors and permitted assigns.
-2-
<PAGE> 3
In witness whereof the parties hereto have executed this Assignment Agreement
by their proper signing officers duly authorized in that behalf all as of the
first day of September, 1993.
Pacific Gas and Electric NOVA Corporation of Alberta
Company
Per: Daniel Thomas Per: R. A. Green
Per:_______________ Per: Klaus Exner
-3-
<PAGE> 4
SCHEDULE "A"
93-32975-1 (A&S)
93-35628-0 (PACIFIC)
Assignor: ALBERTA AND SOUTHERN GAS CO. LTD.
Assignor Service Agreement: June 14, 1960
Assignor Assignment Agreement: February 1, 1993
Assignee: PACIFIC GAS AND ELECTRIC COMPANY
Assignee Service Agreement: October 1, 1993
Assignee Assignment Agreement: October 1, 1993
Effective Time: 08:00 MST on November 1, 1993
DESCRIPTION OF ASSIGNED SERVICE:
<TABLE>
<CAPTION>
MAXIMUM SURCHARGE
SCHEDULE RECEIPT/ RECEIPT MAXIMUM DAILY (per 10(3)M(3)/d OF
OF DELIVERY DELIVERY RECEIPT/DELIVERY SERVICE RECEIPT POINT
SERVICE POINT & LEGAL PRESSURE VOLUME TERMINATION CONTRACT DEMAND
NO. STATION NO. DESCRIPTION (kPa) (10(3)M(3)/d) DATE QUANTITY)
<S> <C> <C> <C> <C> <C> <C>
93-34739-1 Alberta-BC NW 11-008-05 N/A 17275.0 October 31, 2001 N/A
Border #2001 WSM
</TABLE>
THE ASSIGNED SERVICE IS SUBJECT TO THE ADDITIONAL CONDITIONS ATTACHED AS
APPENDIX 1. N/A
ASSIGNOR AND ASSIGNEE AGREE AS FOLLOWS:
1. Subject to the reservations, limitations, and conditions relating to the
Assigned Service and the terms and conditions hereof, Assignor assigns to
Assignee, and Assignee accepts the assignment from the Assignor of, the
Assigned Service as of the Effective Time.
2. Assignee acknowledges that from and after the Effective Time Assignee shall
be bound by and be subject to all of the terms and conditions of the Assigned
Service as set out in the Schedule of Service and the Assigned Service shall be
deemed to be gas transportation service under the Assignee Service Agreement.
3. Assignor and Assignee acknowledge that, from and after the Effective Time,
the Schedule of Service for the Assigned Service shall be deemed to have been
detached from and no longer form part of the Assignor Service Agreement and
shall be deemed to have been attached to and form part of the Assignee Service
Agreement.
4. Upon execution by Company, this Assignment Schedule shall be incorporated
in and form part of the Assignor Assignment Agreement and the Assignee
Assignment Agreement.
5. This assignment is subject to the following terms and conditions: n/a
<TABLE>
<S> <C> <C>
Alberta and Southern Gas Pacific Gas and NOVA Corporation of
Co. Ltd. Electric Company Alberta
Per: A. Nawata Per:________________ Per: R. A. Green
Per:________________ Per:________________ Per: Klaus Exner
</TABLE>
-1-
<PAGE> 1
EXHIBIT 10.2
SERVICE AGREEMENT
RATE SCHEDULE FS
BETWEEN:
NOVA Corporation of Alberta, a body corporate having an office
in the City of Calgary, in the Province of Alberta
(hereinafter referred to as "Company")
- and -
Pacific Gas and Electric Company, a body corporate having an
office in the City of Calgary in the Province of Alberta
(hereinafter referred to as "Customer")
IN CONSIDERATION of the premises and the covenants and agreements herein
contained, the parties hereto covenant and agree as follows:
1. Customer acknowledges receipt of a current copy of Company's Gas
Transportation Tariff (the "Tariff").
2. The terms used herein shall have the same meanings as are ascribed to
corresponding terms in the General Terms and Conditions contained in
the Tariff, unless otherwise defined herein.
3. Customer hereby requests, and Company agrees to provide, Service
pursuant to Rate Schedule FS in accordance with the attached Schedules
of Service, such Service to commence on the Billing Commencement Date
and to terminate, subject to the provisions hereof, on the Service
Termination Date. Company shall include on Customer's Index of
Service for Rate Schedule FS the Service to be provided hereunder and
Customer agrees to acknowledge such Index of Service from time to time
at Company's request.
4. Customer agrees to pay the rates, tolls and charges fixed or varied by
Company, from time to time, in respect of each month, and portion
thereof, that Service is rendered hereunder.
5. Customer shall provide such assurances and information as Company may
reasonably require respecting any Service to be provided pursuant to
this Rate Schedule FS including, without limiting the generality of
the foregoing, an assurance that necessary arrangements
-1-
<PAGE> 2
have been made among Customer, producers of gas for Customer,
purchasers of gas from Customer and any other Person relating to such
Service, including all gas purchase, gas sale, operating, processing
and common stream arrangements. Further, at Company's request
Customer shall provide Company with an assurance that Customer has
provided the Person operating facilities upstream of any Receipt Point
in respect of which Customer has the right to receive Service with all
authorizations necessary to enable such Person to provide Company with
all data and information reasonably requested by Company for the
purpose of allocating volumes of gas delivered to Company among
Company's Customers and to bind Customer in respect of all such data
and information provided. If Customer fails to provide such
assurances and information forthwith following request by Company,
from time to time, Company may at its option, to be exercised by
notice to Customer, suspend the Service to which such assurances and
information relate until such time as Customer provides the assurances
and information requested, provided however that any such suspension
of Service shall not relieve Customer from any obligation to pay any
minimum charge, demand charge, basic charge, Surcharge, or any other
charge payable to Company.
6. Customer acknowledges that the Facilities have been designed to
provide for the transportation of the aggregate gas supply that is
forecast to be received at Receipt Points on the NOVA system, as
described each year in NOVA's Annual Plan, and that interruption and
curtailment of Service may occur if the aggregate gas supply actually
received at such Receipt Points is greater than forecast.
7. Every notice, request, demand, statement or bill provided for in Rate
Schedule FS, this Service Agreement and the General Terms and
Conditions, or any notice which either Company or Customer may desire
to give to the other, shall be in writing and each of them and every
payment provided for shall be directed to the Person to whom given,
made or delivered at such Person's address as follows:
Customer:
Pacific Gas and Electric Company
Rm. 1611, 77 Beale Street
Gas Services Department, B16A
P.O. Box 770000
San Francisco, California USA
94177
-2-
<PAGE> 3
Attention: Mr. H. O. LaFlash
Manager, Gas Services
Fax: (415) 942-6002
Company:
NOVA Corporation of Alberta
P.O. Box 2535, Station "M"
801 Seventh Avenue, S.W.
Calgary, Alberta
T2P 2N6
Attention: Vice President for Customer Service
Transportation Services FAX: (403) 290-6370
Any notice may be given by personal delivery or by mailing the same,
postage pre-paid, in an envelope properly addressed to the Person to
whom the notice is to be given and shall be deemed to be given four
(4) business days after the mailing thereof, Saturdays, Sundays and
statutory holidays excepted. Any notice may also be given by pre-paid
telegram, fax, or other telecommunication addressed to the Person to
whom such notice is to be given at such Person's address for notice as
set forth above, and any notice so given shall be deemed to have been
given twenty-four (24) hours after transmission of same, Saturdays,
Sundays and statutory holidays excepted. Any notice may also be given
by telephone followed immediately by letter, fax, telegram or other
telecommunication and any notice so given shall be deemed to have been
given as of the date and time of the telephone notice. In the event
of disruption of regular mail every payment shall be personally
delivered and every notice, request, demand, statement or bill shall
be given by one of the alternative means set out herein.
8. The terms and conditions of Rate Schedule FS and the General Terms and
Conditions are by this reference incorporated into and made a part of
this Service Agreement. Notwithstanding anything contained herein,
the terms and conditions hereof shall be subject to the terms and
conditions contained in Rate Schedule FS and the provisions of the
General Terms and Conditions.
-3-
<PAGE> 4
IN WITNESS WHEREOF the parties hereto have executed this Service Agreement by
their proper signing officers duly authorized in that behalf all as of the
first of October, 1993.
Pacific Gas and Electric NOVA Corporation
Company of Alberta
Per: Daniel Thomas Per: R. A. Green
Per:_______________ Per: Klaus Exner
-4-
<PAGE> 5
[NOVA LOGO] Page 1
RATE SCHEDULE FS
1. DEFINITIONS
The terms used herein shall have the same meanings as are ascribed to
corresponding terms in the General Terms and Conditions unless
otherwise defined herein.
2. AVAILABILITY
Service under Rate Schedule FS is available to any Customer requiring
firm Service for the transportation of natural gas within Alberta
involving the receipt of quantities of gas at designated Receipt
Points and the delivery of such quantities of gas at designated
Delivery Points provided that Customer has executed a Service
Agreement, or Schedule of Service in relation thereto, for Service
under this Rate Schedule FS.
3. SERVICE DESCRIPTION
Subject to the terms and conditions applicable to Service under this
Rate Schedule FS, Service hereunder shall consist of:
(i) the receipt of gas from Customer at Customer's Receipt Points;
(ii) the transportation of gas through the Facilities; and
(iii) the delivery of gas to Customer at Customer's Delivery Points.
Effective Date: November 1, 1993
<PAGE> 6
[NOVA LOGO] Page 2
4. CHARGE FOR SERVICE
4.1 ANNUAL FS COST OF SERVICE
Prior to December 31 in each calendar year Company shall prepare an
estimate of the Total Cost of Service for the following calendar year.
Such estimate of the Total Cost of Service, less an amount equal to
the revenue Company estimates it will receive in such following
calendar year from all Customers forecast to receive Service under all
Rate Schedules, other than Rate Schedule FS, shall be referred to in
this paragraph 4 as the "Estimated Annual FS Cost of Service". The
estimate of the costs and expenses for lubricants, Gas Used, Gas Lost
and the variable component of compressor station operating costs
included in the Estimated Annual FS Cost of Service shall be referred
to in this paragraph 4 as the "Variable Component". Estimated Annual
FS Cost of Service less the Variable Component shall be referred to in
this paragraph 4 as the "Fixed Component".
4.2 MONTHLY DEMAND CHARGE
4.2.1 FS DEMAND RATE
Prior to December 31 in each calendar year Company shall calculate
what in this paragraph 4 shall be referred to as the "FS Demand Rate"
which shall be used in the calculation of Customer's monthly demand
charge for each Billing Month in the following calendar year. The FS
Demand Rate shall be calculated by the application of the following
formula:
FDR = (FC / A) 1
---
12
where:
Effective Date: November 1, 1993
<PAGE> 7
[NOVA LOGO] Page 3
"FDR" is the FS Demand Rate;
"FC" is the Fixed Component; and
"A" is Company's forecast for the following calendar year of the
aggregate of the Receipt Point Contract Demand Quantities and
Export Delivery Point Contract Demand Quantities, for all
Customers receiving Service under Rate Schedule FS, less the
quotient obtained when Company's forecast for such following
calendar year of Gas Used and Gas Lost is divided by 365.
4.2.2 CUSTOMER'S MONTHLY DEMAND CHARGE
Customer's monthly demand charge for a Billing Month for Service under
Rate Schedule FS shall be calculated by the application of the
following formula:
MDC = FDR x B
where:
"MDC" is the Customer's monthly demand charge;
"FDR" is the FS Demand Rate; and
"B" is the difference between:
(i) the quotient obtained when the aggregate of the
products obtained, where each Receipt Point Contract
Demand Quantity and Export Delivery Point Contract
Demand Quantity in effect for such Customer in such
Billing Month in respect of this Rate Schedule FS is
multiplied by the number of Days in such Billing
Month that the Receipt Point Contract Demand
Effective Date: November 1, 1993
<PAGE> 8
[NOVA LOGO] Page 4
Quantity or Export Delivery Point Contract Demand
Quantity was in effect, is divided by the number of
Days in such Billing Month; and
(ii) the quotient obtained when the volume of gas
allocated to such Customer in the month preceding
such Billing Month for Gas Used and Gas Lost, in
respect of this Rate Schedule FS, is divided by the
number of Days in the month preceding such Billing
Month.
4.3 MONTHLY COMMODITY CHARGE
4.3.1 FS COMMODITY RATE
Prior to December 31 in each calendar year Company shall calculate
what in this paragraph 4 shall be referred to as the "FS Commodity
Rate" which shall be used in the calculation of Customer's monthly
commodity charge for each Billing Month in the following calendar
year. The FS Commodity Rate shall be calculated by the application of
the following formula:
FS CR = VC / C
where:
"FS CR" is the FS Commodity Rate;
"VC" is the annual Variable Component; and
"C" is Company's forecast of the aggregate volume of gas
to be received by Company from all Customers
receiving Service under Rate Schedule FS in such
following calendar year, less Company's forecast for
the following
Effective Date: November 1, 1993
<PAGE> 9
[NOVA LOGO] Page 5
calendar year of Gas Used and Gas Lost to be
allocated to Customers receiving Service under this
Rate Schedule FS.
4.3.2 CUSTOMER'S MONTHLY COMMODITY CHARGE
Customer's monthly commodity charge for a Billing Month for a Customer
receiving Service under Rate Schedule FS shall be calculated by the
application of the following formula:
MCC = (FS CR) D
where:
"MCC" is the Customer's monthly commodity charge;
"FS CR" is the FS Commodity Rate; and
"D" is the lesser of:
(i) the aggregate volume of gas received by Company from such
Customer for transportation under Rate Schedules FS, IT-1 and
IT-2 in the month preceding such Billing Month; and
(ii) the aggregate of the products obtained where each Receipt
Point Contact Demand Quantity in effect for such Customer
under this Rate Schedule FS, in the month preceding such
Billing Month, is multiplied by the number of days in the
month the Receipt Point Contract Demand Quantity was in
effect,
less, in the case of (i), the volume of gas allocated to such Customer
in the month preceding the Billing Month for Gas Used and Gas Lost in
respect of Rate Schedules
Effective Date: November 1, 1993
<PAGE> 10
[NOVA LOGO] Page 6
FS, IT-1 and IT-2 and less, in the case of (ii), the volume of gas
allocated to such Customer in the month preceding its Billing Month
for Gas Used and Gas Lost in respect of Rate Schedule FS.
4.4 SURCHARGE
The Surcharge, under this Rate Schedule FS, applicable to each Receipt
Point for any Billing Month shall be the charge set forth opposite
such Receipt Point in the column under the heading "Surcharge" in the
Index of Service for Rate Schedule FS.
4.5 CHARGE FOR OVER-RUN GAS
4.5.1 In the event that Company determines in respect of a Billing Month
that Customer has tendered for transportation, and Company has
transported for Customer, in the month preceding such Billing Month, a
volume of gas at any Receipt Point in excess of the aggregate of the
products obtained when each of the Maximum Daily Receipt Volumes in
effect for Customer in respect of this Rate Schedule FS, in the month
preceding such Billing Month, is multiplied by the number of Days in
such month that such Maximum Daily Receipt Volume was in effect,
Customer shall pay to Company an amount equal to the product of a
volume equal to such excess and:
(i) the rate applicable to Service under Rate Schedule IT-1 if
Customer has a Service Agreement under Rate Schedule IT-1
applicable to such Receipt Point; or
(ii) the rate applicable to Service under Rate Schedule IT-2 if
Customer does not have a Service Agreement under Rate Schedule
IT-1 applicable to such Receipt Point.
4.5.2 In the event that Company determines in respect of a Billing Month
that Company has delivered to Customer, in the month preceding such
Billing Month, a volume of gas at
Effective Date: November 1, 1993
<PAGE> 11
[NOVA LOGO] Page 7
any Export Delivery Point in excess of the aggregate of the products
obtained when each of the Export Delivery Point Contract Demand
Quantities in effect for Customer in respect of this Rate Schedule FS,
in the month preceding such Billing Month, is multiplied by the number
of Days in such month that such Export Delivery Point Demand Quantity
was in effect, Customer shall pay to Company an amount equal to the
product of a volume equal to such excess and the rate applicable to
Service under Rate Schedule IT-2.
4.5.3 The calculation of Customer's charge for Over-Run Gas under this
subparagraph 4.5 shall not take into account Customer's inventory
position for the month preceding the Billing Month.
4.6 MONTHLY BILLING ADJUSTMENT
Each month Company shall calculate the difference, in this
subparagraph 4.6 referred to as the "difference", between the
aggregate amount billed in respect of the Billing Month, excluding any
adjustment pursuant to this subparagraph 4.6, in this subparagraph 4.6
referred to as the "amount billed", to all Customers receiving Service
under Rate Schedules FS, IT-1 and IT-2 in the Billing Month and the
actual Transportation Cost of Service for the Billing Month, in this
subparagraph 4.6 referred to as the "amount incurred". The difference
shall be allocated to each Customer receiving Service under Rate
Schedule FS in the Billing Month in an amount equal to the product of
the difference and a fraction the numerator of which is the sum of the
products of each of Customer's Receipt Point Contract Demand
Quantities and Export Delivery Point Contract Demand Quantities under
this Rate Schedule FS and the number of Days in the Billing Month that
each such Receipt Point Contract Demand Quantity and Export Delivery
Point Contract Demand Quantity was in effect and the denominator of
which is the sum of the products for all Customer's Receipt Point
Contract Demand Quantities and Export Delivery Point Contract Demand
Quantities under this Rate Schedule FS and the number of Days in the
Billing Month that each such Receipt Point Contract
Effective Date: November 1, 1993
<PAGE> 12
[NOVA LOGO] Page 8
Demand Quantity and Export Delivery Point Contract Demand Quantity was
in effect. If the amount billed exceeds the amount incurred the
allocated portion of the difference shall be a credit to Customer's
bill and if the amount billed is less than the amount incurred the
allocated portion of the difference shall be added to Customer's bill.
4.7 AGGREGATE CHARGE FOR SERVICE
Customer shall pay in respect of each Billing Month the sum of the
amounts calculated for the Billing Month in accordance with
subparagraphs 4.2.2, 4.3.2, 4.4 and 4.5, such sum to be adjusted as
provided for in subparagraph 4.6.
4.8 ALLOCATION OF GAS RECEIVED
Notwithstanding any other provision of this Rate Schedule, any Service
Agreement or the General Terms and Conditions of this Tariff, and
without regard to how gas may have been nominated, the aggregate
volume of gas received from Customer at a Receipt Point shall be
allocated for billing purposes first to Service to Customer under Rate
Schedule FS to a maximum of such Customer's Maximum Daily Receipt
Volume for such Receipt Point under Rate Schedule FS, then to Service
to Customer under Rate Schedule IT-1 to a maximum of such Customer's
Maximum Daily Receipt Volume for such Receipt Point under Rate
Schedule IT-1 and finally to Service to Customer under Rate Schedule
IT-2 to a maximum of such Customer's Maximum Daily Receipt Volume for
such Receipt Point under Rate Schedule IT-2.
4.9 ALLOCATION OF GAS DELIVERED
Notwithstanding any other provision of this Rate Schedule, any Service
Agreement or the General Terms and Conditions of this Tariff, and
without regard to how gas may have been nominated, the aggregate
volume of gas delivered to Customer at a Delivery Point shall be
allocated for billing purposes first to Service to Customer under Rate
Schedule
Effective Date: November 1, 1993
<PAGE> 13
[NOVA LOGO] Page 9
FS to a maximum of such Customer's Maximum Daily Delivery Volume for
such Delivery Point under Rate Schedule FS and then to Service to
Customer under Rate Schedule IT-2.
5. TERM OF SERVICE AGREEMENT
5.1 The term of a Service Agreement under Rate Schedule FS shall be equal
to the greater of any Receipt Point Obligation or Delivery Point
Obligation applicable to Service under such Service Agreement.
5.2 The Receipt Point Obligation for Service at any Receipt Point shall be
a period equal to:
(i) a minimum of twelve (12) consecutive months where no new
Facilities are required to be constructed at any Receipt Point
to provide the Service requested; or
(ii) the number of years of Service Company calculates is necessary
in order that the cumulative present value forecast of revenue
in respect of the new Facilities required at any Receipt Point
for the Service requested equals the cumulative present value
cost of service in respect of the Service requested, provided
that if the number of years calculated exceeds fifteen (15)
years the term shall be fixed at fifteen (15) years and a
Surcharge calculated by Company shall be applied in respect of
such Service, and provided further that Company shall perform
the foregoing calculation in respect of the new Facilities
constructed at any Receipt Point whenever another Customer
commences to use the new Facilities for Service under Rate
Schedule FS and prior to the commencement of each year of
Service and Company shall adjust Customer's Surcharge in
accordance with the result of such calculation.
Effective Date: November 1, 1993
<PAGE> 14
[NOVA LOGO] Page 10
5.3 The Delivery Point Obligation for Service at any Delivery Point shall
be a period equal to:
(i) a minimum of twelve (12) consecutive months where no new
Facilities (other than any new Facilities at any Receipt
Point) are required to be constructed to provide the Service
requested; or
(ii) a minimum of fifteen (15) consecutive years, or such other
minimum period that Company agrees to, where new Facilities
(other than new Facilities at any Receipt Point) are required
to be constructed to provide the Service requested.
6. TRANSPORTATION DURING TEST PERIODS
Provided that Customer has first satisfied Company that it is a
requirement under the terms of a gas purchase contract that Customer
tender to Company for the purpose of a test a volume of gas at a
Receipt Point in excess of Customer's Maximum Daily Receipt Volume for
such Receipt Point, and provided further that Company has determined
in its sole judgement that it can receive and transport such volume
for such period without adversely affecting the operation of the
Facilities or Service to any other Customer receiving Service under
this Rate Schedule FS, Customer may tender, for a month once in any
calendar year, such volume and Company will receive and transport such
volume pursuant to the terms and conditions applicable to this Rate
Schedule FS and the rate applicable to Service under Rate Schedule
IT-2 shall apply to such volumes. Notwithstanding the provisions of
this paragraph, Company may interrupt or terminate the test at any
time during the test period.
Effective Date: November 1, 1993
<PAGE> 15
[NOVA LOGO] Page 11
7. STORAGE
In the event that Customer makes use of any gas storage facility which
is not part of the Facilities in connection with the Service received
by Customer under Rate Schedule FS, Customer undertakes to cause the
operator of every such gas storage facility to provide to Company,
when requested by Company, the following information:
(i) the cumulative total of the volume of gas delivered from the
Facilities into such storage facility for Customer; and
(ii) the cumulative total of the volume of gas delivered from such
storage facility into the Facilities for Customer.
If the operator of a gas storage facility fails to provide Company
with the information requested with respect to any month within the
time provided by Company for a response to Company's request, the
volume of gas delivered from such gas storage facility to the
Facilities for Customer for such month shall be deemed to have been
transported for Customer from the gas storage facility to the Delivery
Point under Rate Schedule IT-1 and the rate applicable to Service
under Rate Schedule IT-1 shall apply to such volume of gas.
8. RELIEF
If Customer desires relief from its obligation to pay all or any
portion of its charges under Rate Schedule FS which are based on
Customer's Receipt Point Contract Demand Quantity or Export Delivery
Point Contract Demand Quantity Customer shall notify Company of its
request for relief specifying the particular Receipt Point or Delivery
Point and the Receipt Point Contract Demand Quantity or Export
Delivery Point Contract Demand Quantity available to any other Person
who requires Service under Rate Schedule FS. Company assumes no
obligation to find any Person to assume the Receipt Point Contract
Demand Quantity or Export Delivery Point Contract Demand Quantity
Customer proposes to make available. If after notice is given to
Company a Person is found who agrees to assume the
Effective Date: November 1, 1993
<PAGE> 16
[NOVA LOGO] Page 12
Receipt Point Contract Demand Quantity or Export Delivery Point
Contract Demand Quantity Customer proposes to make available, together
with any applicable Surcharge, Company may grant relief to Customer,
on terms and conditions satisfactory to Company, by reducing
Customer's Receipt Point Contract Demand Quantity or Export Delivery
Point Contract Demand Quantity specified with respect to the
particular Receipt Point or Delivery Point by an amount equal to the
Receipt Point Contract Demand Quantity or Export Delivery Point
Contract Demand Quantity specified in a Service Agreement or in a
Schedule of Service, as the case may be, executed by Company and such
Person. Notwithstanding any granting of relief by Company, Customer
shall at Company's sole option either:
(i) continue to pay any Surcharge until the Service Termination
Date as described in the applicable Index of Service (unless
any other Person acceptable to Company has agreed to pay such
Surcharge); or
(ii) in the event that Company retires any Facilities required to
provide such Service, pay to Company an amount, as determined
by Company, equal to the net book value of such Facilities
adjusted for all costs and expenses associated with such
retirement.
9. RELIEF FOR MAINLINE RESTRICTIONS
Company may grant relief to a Customer entitled to Service under Rate
Schedule FS in circumstances where Company determines that such
Service can not be made available as a result of a capacity
restriction within a mainline portion of the Facilities necessary to
provide the Service. Company may from time to time determine the
circumstances, if any, under which relief may be granted and the
method of calculating such relief.
Effective Date: November 1, 1993
<PAGE> 17
[NOVA LOGO] Page 13
10. TRANSFER OF FIRM SERVICE BETWEEN RECEIPT POINTS
If Customer desires to transfer all or any portion of any Service
under Rate Schedule FS from one Receipt Point to another Receipt
Point, Customer shall notify Company of its request for such transfer
specifying the particular Receipt Points and the Service that Customer
wishes to transfer. Company is under no obligation to permit the
transfer requested, but may permit such transfer if Company determines
that sufficient capacity for Service under Rate Schedule FS exists
within the Facilities required to provide the Service requested.
11. DAILY INVENTORY TRANSFERS
A Customer entitled to receive Service under Rate Schedule FS may
transfer a quantity of gas that has been received by Company under a
Service Agreement for Rate Schedule FS on Customer's behalf into, but
not delivered out of, the Facilities (the quantity of gas that has
been received into but not delivered out of the Facilities being
referred to in this paragraph as "inventory") to any other Customer
entitled to receive Service. Customer's transfer of inventory to
another Customer shall be subject to procedures established by Company
from time to time respecting daily inventory transfers.
12. EXTENSION OF SERVICE
Provided that Customer shall have given Company notice advising
Company that Customer desires to extend the term of any Service
provided to Customer under this Rate Schedule FS for the period of
time specified in such notice at least three (3) months prior to the
expiry of the current term for which Company had agreed to provide
such Service, Customer shall be entitled to an extension of such
Service and Company and Customer shall forthwith execute an extension
agreement for such term and in such form as Company may prescribe from
time to time.
Effective Date: November 1, 1993
<PAGE> 18
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13. APPLICATION FOR SERVICE
Applications for Service under this Rate Schedule FS shall be in such
form as Company may prescribe from time to time.
14. GENERAL TERMS AND CONDITIONS
The General Terms and Conditions of this Tariff and the provisions of
any Service Agreement for Service under Rate Schedule FS are
applicable to Rate Schedule FS to the extent that such terms and
conditions and provisions are not inconsistent with this Rate
Schedule.
Effective Date: November 1, 1993
<PAGE> 19
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PAGES 22 THROUGH 29
RESERVED FOR FUTURE REVISIONS
TO RATE SCHEDULE FS
Effective Date: November 1, 1993
<PAGE> 20
[NOVA LOGO] Page 120
GENERAL TERMS AND CONDITIONS
<TABLE>
<CAPTION>
ARTICLE TITLE PAGE
<S> <C> <C>
1 Definitions 121
2 Measuring Equipment 140
3 Quality of Gas 143
4 Measurement 146
5 Billing and Payment 148
6 Possession and Control 151
7 Pressures of Gas 152
8 Gas Used, Gas Lost and Measurement Variance 153
9 Delivery Obligation 155
10 Financial Information and Security 157
11 Interruptions and Curtailments 158
12 Force Majeure 159
13 Indemnification 162
14 Exchange of Information 163
15 Miscellaneous Provisions 164
</TABLE>
Effective Date: November 1, 1993
<PAGE> 21
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GENERAL TERMS AND CONDITIONS
1.0 DEFINITIONS
The following terms and abbreviations, when used in these General
Terms and Conditions, the Rate Schedules and the Service Agreements,
shall have the following meanings ascribed thereto:
1.1 The term "Act" shall mean the NOVA Corporation of Alberta Act, being
Chapter N-12 of the Revised Statutes of Alberta, 1980, as amended.
1.2 The term "Billing Commencement Date" shall mean the earlier of:
(a) the Ready for Service Date; and
(b) the date Company commences to provide Service to Customer
pursuant to a Service Agreement.
1.3 The term "Billing Month" shall mean that month which immediately
precedes the month in which Company is required to send a bill for
Service.
1.4 The term "Company" shall mean NOVA Corporation of Alberta.
1.5 The term "Cubic Metre of Gas" shall mean that quantity of gas which,
at a temperature of fifteen (15) degrees Celsius and at an absolute
pressure of one hundred one and three hundred twenty-five thousandths
kilopascals (101.325 kPa) occupies one cubic metre.
1.6 The term "Customer" shall mean any Person named as a Customer in an
Index of Service or Schedule of Service.
Effective Date: November 1, 1993
<PAGE> 22
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1.7 The term "Customer's Inventory" shall mean, in respect of the Billing
Month, the aggregate of the amounts for all months from and including
the month Customer first commenced to receive Service from Company
under any agreement with Company to and including the Billing Month,
where such amount is determined each month in accordance with the
following formula:
INV = (A + B + C) - (D + E + F)
where:
"INV" is Customer's Inventory for the Billing Month;
"A" is the energy equivalent of the volume of gas delivered by
Customer to Company in the month at all of Customer's Receipt
Points;
"B" is the Line Pack Gas at the beginning of the month;
"C" is the share of Measurement Variance, expressed as an energy
equivalent, apportioned to Customer for the month;
"D" is the energy equivalent of the volume of gas delivered by
Company to Customer in the month at all of Customer's Delivery
Points;
"E" is the Line Pack Gas at the end of the month; and
"F" is the share of the aggregate of the Gas Used and Gas Lost,
expressed as an energy equivalent, apportioned to Customer in
the month.
1.8 The term "Day" shall mean a period of twenty-four (24) consecutive
hours, beginning and ending at eight hours (08:00) Mountain Standard
Time.
Effective Date: November 1, 1993
<PAGE> 23
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1.9 The term "Delivery Point" shall mean for each Customer the point at
which gas is delivered within any of the geographical locations as set
forth in the column under the heading "Delivery Point" in an Index of
Service.
1.10 The term "Delivery Point Obligation" shall have the meaning attributed
to it in paragraph 5.3 of Rate Schedule FS.
1.11 The Term "Export Delivery Point" shall mean any of the following
Delivery Points where gas is delivered to a Customer for removal from
the Province of Alberta:
Empress Border No. 1958
McNeill Border No. 6404
Alberta-British Columbia Border No. 2000
Alberta-Montana Border No. 2002
Gordondale Border No. 3886
Boundary Lake Border No. 3002
Cold Lake Border No. 1417
Unity Border No. 1250
1.12 The Term "Export Delivery Point Contract Demand Quantity" shall mean,
relative to a Customer and in respect to an Export Delivery Point,
Customer's Maximum Daily Delivery Volume applicable to such Export
Delivery Point;
1.13 The term "Facilities" shall mean Company's pipelines and other
facilities or any part or parts thereof for the gathering, treating,
transporting, storing, distributing, exchanging, handling or delivery
of any gas.
1.14 The term "FS Commodity Rate" shall have the meaning attributed to it
in paragraph 4.3.1 of Rate Schedule FS.
Effective Date: November 1, 1993
<PAGE> 24
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1.15 The term "FS Demand Rate" shall have the meaning attributed to it in
paragraph 4.2.1 of Rate Schedule FS.
1.16 The term "Gas" or "gas" shall mean all natural gas both before and
after it has been subjected to any treatment or process by absorption,
purification, scrubbing or otherwise, and includes all fluid
hydrocarbons other than hydrocarbons that can be recovered from a pool
in liquid form by ordinary production methods.
1.17 The term "GIA" shall mean the Electricity and Gas Inspection Act,
being Chapter E-4 of the Revised Statutes of Canada, 1985, as amended,
and all applicable regulations issued pursuant thereto.
1.18 The term "Gas Lost" shall mean for any period that volume of gas
determined by Company to be the total volume of gas lost as a result
of a rupture or disaster.
1.19 The term "Gas Used" shall mean for any period that volume of gas
determined by Company to be the total volume of gas used by Company in
the operation, the maintenance and the construction of Facilities.
1.20 The term "Gas Year" shall mean a period of time beginning at eight
hours (08:00) Mountain Standard Time on the first day of November in
any year and ending at eight hours (08:00) Mountain Standard Time on
the first day of November of the next year.
1.21 The term "Gross Heating Value" shall mean the total megajoules
obtained by complete combustion of one cubic metre of gas with air,
the gas to be free of all water vapour and the gas, air and products
of combustion to be at standard conditions of fifteen (15) degrees
Celsius and one hundred one and three hundred twenty-five thousandths
(101.325) kPa and all water vapour formed by the combustion reaction
condensed to the liquid state.
Effective Date: November 1, 1993
<PAGE> 25
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1.22 The term "Index of Service" shall mean the schedule identified as the
"Index of Service" for each Customer attached to and forming part of
each Rate Schedule, as such Rate Schedules may be varied from time to
time by Company.
1.23 The term "kPa" shall mean kilopascals of pressure (gauge) unless
otherwise specified.
1.24 The term "Line Pack Gas" shall mean at any point in time that volume
of gas determined by Company to be the total volume of gas contained
in the Facilities.
1.25 The term "Maximum Daily Delivery Volume" shall mean relative to a
Delivery Point the maximum volume of gas Company may be required to
deliver to Customer at such Delivery Point on any Day, as set forth in
the column under the heading "Maximum Daily Delivery Volume" in an
Index of Service or Schedule of Service.
1.26 The term "Maximum Daily Receipt Volume" shall mean relative to a
Receipt Point the maximum volume of gas Company may be required to
receive from Customer at such Receipt Point on any Day, as set forth
in the column under the heading "Maximum Daily Receipt Volume" in an
Index of Service or Schedule of Service.
1.27 The term "Maximum Delivery Pressure" shall mean relative to a Delivery
Point the maximum pressure at which Company may deliver gas to
Customer, as set forth in the column under the heading "Maximum
Delivery Pressure" in such Customer's Index of Service on Schedule of
Service.
1.28 The term "Maximum Receipt Pressure" shall mean relative to a Receipt
Point the maximum pressure at which Company may require Customer to
deliver gas, as set forth in the column under the heading "Maximum
Receipt Pressure" in an Index of Service or Schedule of Service.
1.29 The term "Measurement Variance" shall mean, for any period, after
taking into account
Effective Date: November 1, 1993
<PAGE> 26
[NOVA LOGO] Page 126
any adjustment made in accordance with the provisions of paragraph 2.6
of these General Terms and Conditions, the result obtained by applying
the following formula:
MV = (A + B + C) - (D + E)
where:
"MV" is the Measurement Variance;
"A" is the volume of gas determined by Company to have been
delivered to all Customers during the period;
"B" is the aggregate of the Gas Lost and Gas Used during the
period;
"C" is the Line Pack Gas at the end of the period;
"D" is the volume of gas determined by Company to have been
received from all Customers during the period; and
"E" is Line Pack Gas at the beginning of the period;
1.30 The term "Month" or "month" shall mean a period of time beginning at
eight hours (08:00) Mountain Standard Time on the first day of a
calendar month and ending at eight hours (08:00) Mountain Standard
Time on the first day of the next calendar month.
1.31 The term "Over-Run Gas" shall mean, in respect of a Customer in a
month, the aggregate volume of gas for which an amount for over-run
gas is payable by Customer in the Billing Month.
1.32 The term "Person" shall mean and include Company, a Customer, a
corporation, a
Effective Date: November 1, 1993
<PAGE> 27
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company, a partnership, an association, a joint venture, a trust, an
unincorporated organization, a government, or department of a
government or a section, branch, or division of a department of a
government.
1.33 The term "Prime Rate" shall mean the rate of interest, expressed as an
annual rate of interest, announced from time to time by the main
branch of the Bank of Nova Scotia, Calgary, Alberta as the reference
rate then in effect for determining interest rates on Canadian dollar
commercial loans in Canada.
1.34 The term "Rate Schedule" shall mean any of the schedules identified as
a "Rate Schedule" included in the Tariff.
1.35 The term "Rates, Tolls and Other Charges" shall mean the rates, tolls
and charges set forth in the Tariff and such other rates, tolls and
other charges fixed or varied from time to time by Company pursuant to
the provisions of the Act and any regulation in effect with respect
thereto.
1.36 The term "Ready for Service Date" shall mean the Day designated as
such by Company by written notice to Customer stating that Company has
Facilities which are ready for and are capable of rendering the
Service applied for.
1.37 The term "Receipt Point" shall mean for each Customer the point at
which gas is received within any of the geographical locations as set
forth in the column under the heading "Receipt Point" in an Index of
Service.
1.38 The term "Receipt Point Contract Demand Quantity" shall mean, relative
to a Customer and in respect of a Receipt Point, Customer's Maximum
Daily Receipt Volume applicable to such Receipt Point.
1.39 The term "Receipt Point Obligation" shall have the meaning attributed
to it in paragraph
Effective Date: November 1, 1993
<PAGE> 28
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5.2 of Rate Schedule FS.
1.40 The term "Schedule of Service" shall mean the schedule attached to a
Service Agreement for Service under any Rate Schedule and designated
as "Schedule of Service".
1.41 The term "Service" shall mean and include the provision of Facilities,
the use of Facilities or the provision and use of Facilities.
1.42 The term "Service Agreement" shall mean an agreement between Company
and Customer respecting Service to be provided under any Rate
Schedule.
1.43 The term "Service Termination Date" shall mean the Day upon which
Service shall terminate, as set forth in a Schedule of Service or
under the column under the heading "Service Termination Date" in an
Index of Service.
1.44 The term "Surcharge" shall mean an amount set forth in the column
under the heading "Surcharge" in an Index of Service or in a Schedule
of Service.
1.45 The term "Tariff" shall mean this Gas Transportation Tariff, including
the Rate Schedules, the Service Agreements and these General Terms and
Conditions.
1.46 The term "Thousand Cubic Metres" or "10(3)m(3)" shall mean one
thousand (1000) Cubic Metres of Gas.
1.47 The term "Total Cost of Service" shall mean, with respect to any
period of time, the total for that period of sums determined by
Company, on an actual or estimated basis, for its operating expenses,
including gains or losses on foreign exchange, depreciation and
amortization, return on Company's rate base and income taxes and any
other kinds or types of taxes, for the gathering, treating,
transporting, storing, distributing, commingling, exchanging, handling
and delivering of gas carried by Company's Facilities or any part or
Effective Date: November 1, 1993
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parts thereof and for any service performed by Company in relation to
the gathering, treating, transporting, storing, distributing,
exchanging, handling or delivering of any gas.
1.48 The term "Transportation Cost of Service", which may be either an
estimated or actual amount, shall mean, if estimated, the result
obtained by deducting the aggregate revenues including Surcharges
estimated for all Customers receiving Service under all Rate
Schedules, other than Rate Schedules FS, IT-1 and IT-2, from the
estimate of the Total Cost of Service or, if actual, the result
obtained by deducting the aggregate amount including Surcharges billed
to Customers receiving Service under all Rate Schedules, other than
Rate Schedules FS, IT-1 and IT-2, from the actual Total Cost of
Service.
Effective Date: November 1, 1993
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PAGES 130 THROUGH 139
RESERVED FOR FUTURE REVISIONS
TO DEFINITIONS
Effective Date: November 1, 1993
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2.0 MEASURING EQUIPMENT
2.1 INSTALLATION
Company, at its option, shall furnish, install, maintain and operate
all measuring equipment located at each Receipt Point, or Delivery
Point or other point where gas is measured.
2.2 COMPLIANCE WITH STANDARDS
Company may use such measuring equipment as it deems appropriate
provided that all measuring equipment shall comply with all applicable
requirements under the GIA.
2.3 CHECK MEASURING EQUIPMENT
Customer may install and operate check measuring equipment provided
that such equipment does not interfere with the operation of the
Facilities.
2.4 PULSATION DAMPENING
Customer shall provide or cause to be provided such pulsation
dampening equipment as may be necessary to ensure that any facilities
upstream of a Receipt Point do not interfere with the operation of the
Facilities.
2.5 VERIFICATION
The accuracy of Company's measuring equipment shall be tested and
verified by Company at such intervals as may be appropriate for such
equipment. Reasonable notice of the time and nature of each test
shall be given to Customer to permit Customer to arrange for a
representative to observe the test and any adjustments
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resulting from such test. If, after notice, Customer fails to have a
representative present, the results of the test shall nevertheless
be considered accurate.
2.6 CORRECTION
If at any time any of the measuring equipment is found to be out of
service or registering inaccurately with the result that a significant
measurement error has occurred, such equipment shall be adjusted as
soon as practicable to read as accurately as possible and the readings
of such equipment shall be adjusted to correct for such significant
error for a period definitely known or agreed upon, or if not known or
agreed upon, one-half (1/2) of the elapsed time since the last test.
The measurement during the appropriate period shall be determined by
Company on the basis of the best data available using the most
appropriate of the following methods:
(a) by using the data recorded by any check measuring equipment if
installed and accurately registering;
(b) by making the appropriate correction if the deviation from the
accurate reading is ascertainable by calibration test or
mathematical calculation;
(c) by estimating based on producer measurements; or
(d) by estimating based on deliveries under similar conditions
during a period when the equipment was measuring accurately.
2.7 EXPENSE OF ADDITIONAL TESTS
If Customer requests a test in addition to the tests provided for by
paragraph 2.5 and if upon testing the deviation from the accurate
reading is found to be less than two (2) percent, Customer shall bear
the expense of the additional test.
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2.8 INSPECTION OF EQUIPMENT AND RECORDS
Company and Customer shall have the right to inspect measuring
equipment installed or furnished by the other, and the charts and
other measurement or test data of the other at all times during normal
business hours upon reasonable notice, but the reading, calibration
and adjustment of such equipment and the changing of the charts shall
be done only by the Person installing and furnishing same.
2.9 QUALITY EQUIPMENT AND TESTS
(a) Company may furnish, install, maintain and operate such
equipment as it considers necessary to ensure that gas
received by Company conforms to the quality requirements set
forth in paragraph 3.0.
(b) Company may establish and utilize such reasonable methods,
procedures and equipment as Company determines are necessary
in order to determine whether gas received by Company conforms
with the quality requirements set forth in these General Terms
and Conditions.
Effective Date: November 1, 1993
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3.0 QUALITY OF GAS
3.1 QUALITY REQUIREMENTS
The following quality requirements shall apply to all gas received at
Receipt Points.
Gas received at a Receipt Point:
(a) shall be free, at the pressure and temperature in the
Facilities at the Receipt Point, from sand, dust, gums, crude
oil, contaminants, impurities or other objectionable
substances which will render the gas unmerchantable, cause
injury, cause damage to or interfere with the operation of the
Facilities;
(b) shall not have a hydrocarbon dew point in excess of minus ten
(-10) degrees Celsius at operating pressures;
(c) shall not contain more than twenty-three (23) milligrams of
hydrogen sulphide per one (1) cubic metre;
(d) shall not contain more than one hundred and fifteen (115)
milligrams of total sulphur per one (1) cubic metre;
(e) shall not contain more than two (2) percent by volume of
carbon dioxide;
(f) shall not contain more than sixty-five (65) milligrams of
water vapour per one (1) cubic metre;
(g) shall not have a water dew point in excess of minus ten (-10)
degrees Celsius at operating pressures greater than eight
thousand two hundred seventy five (8275) kPa;
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(h) shall not exceed forty-nine (49) degrees Celsius in
temperature;
(i) shall be as free of oxygen as practicable and shall not in any
event contain more than four-tenths of one (0.4) percent by
volume of oxygen; and
(j) shall have a Gross Heating Value of not less than thirty-six
(36) megajoules per cubic metre.
3.2 NONCONFORMING GAS
(a) If gas received by Company fails at any time to conform with
any of the quality requirements set forth in paragraph 3.1
above, then Company shall notify Customer of such failure and
Company may, at Company's option, refuse to accept such gas
pending the remedying of such failure to conform to quality
requirements. If the failure to conform is not promptly
remedied, Company may accept such gas and may take such steps
as Company determines are necessary to ensure that such gas
conforms with the quality requirements and Customer shall
reimburse Company for any reasonable costs and expenses
incurred by Company.
(b) Notwithstanding paragraph 3.2 (a), if gas received by Company
fails to conform to the quality requirements set forth in
paragraph 3.1, Company may at its option immediately suspend
the receipt of gas, provided however that any such suspension
shall not relieve Customer from any obligation to pay any
minimum charge, demand charge, basic charge, Surcharge or any
other charge payable to Company.
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3.3 QUALITY STANDARD OF GAS DELIVERED AT DELIVERY POINTS
Gas which Company delivers at Delivery Points shall have the quality
that results from gas having been transported and commingled in the
Facilities.
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4.0 MEASUREMENT
4.1 METHOD OF MEASUREMENT
Company may make such measurements and calculations and use such
procedures as it deems appropriate in determining volume, provided
that the measurements and calculations made and the procedures used
comply with any applicable requirements under the GIA.
4.2 UNIT OF MEASUREMENT
The unit of volume for purposes of measurement hereunder shall be one
thousand (1000) Cubic Metres of Gas.
4.3 ATMOSPHERIC PRESSURE
For the purpose of measurement atmospheric pressure shall be
determined by a recognized formula applied to the nearest one
hundredth (0.01) kPa absolute and deemed to be constant at the time
and location of measurement.
4.4 FLOWING TEMPERATURE
The temperature of flowing gas shall be determined by means of a
recording thermometer or other equipment appropriate for the
determination of temperature.
4.5 DETERMINATION OF GAS CHARACTERISTICS
The gas characteristics including, without limiting the generality of
the foregoing, Gross Heating Value, relative density, nitrogen and
carbon dioxide content of gas shall be
Effective Date: November 1, 1993
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determined by continuous recording equipment, laboratory equipment or
through computer modelling.
4.6 EXCHANGE OF MEASUREMENT INFORMATION
Company and Customer shall make available to the other, as soon as
practicable following written request, all measurement and test
charts, measurement data and measurement information pertaining to the
Service being provided to Customer.
4.7 PRESERVATION OF MEASUREMENT RECORDS
Company and Customer shall preserve all measurement test data,
measurement charts and other similar records for a minimum period of
six (6) years or such longer period as may be required by record
retention rules of any duly constituted regulatory body having
jurisdiction.
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5.0 BILLING AND PAYMENT
5.1 BILLING
On or before the twentieth (20th) day of each month, Company shall
render a bill to Customer for Service rendered during the Billing
Month. Customer shall furnish such information to Company as Company
may require for billing on or before the twentieth (20th) day of the
Billing Month.
5.2 PAYMENT
Customer shall make payment to Company in Canadian dollars of its bill
on or before the last day of the month following the Billing Month.
5.3 LATE BILLING
If Company renders a bill after the twentieth (20th) day of a month,
then the date for payment shall be that day which is ten (10) days
after the day that such bill was rendered.
5.4 INTEREST ON UNPAID AMOUNTS
Company shall have the right to charge interest on the unpaid portion
of any bill commencing with the date payment was due and continuing
until the date payment is actually made. The initial rate of interest
to be charged by Company shall be the rate of interest which is two
(2) percent over and above the Prime Rate in effect on the first day
of the quarter during which such unpaid portion of the bill becomes
due. The first day of a quarter during each year shall be deemed to
be the first day of January, April, July and October, as the case may
be. The rate of interest in effect during a prior quarter, with
respect to any amounts owing in such prior quarter which remain
outstanding in the
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following quarter, shall be adjusted effective the first day of the
following quarter to the interest rate which is two (2) percent over
and above the Prime Rate in effect on the first day of such following
quarter.
5.5 ADJUSTMENT WHERE BILL ESTIMATED
Information used for billing may be actual or estimated. If actual
information necessary for billing is unavailable to Company
sufficiently in advance of the twentieth (20th) day of the month to
permit the use of such information in the preparation of a bill,
Company shall use estimated information. In the month that actual
information becomes available respecting a previous month where
estimated information was used, the bill for the month in which the
actual information became available shall be adjusted to reflect the
difference between the actual and estimated information as if such
information related to such later month. Neither Company nor Customer
shall be entitled to interest on any adjustment.
5.6 CORRECTIONS
Notwithstanding any provision contained in this Tariff to the
contrary, the correction of an error in a bill, other than in the case
of a disputed bill, for Service rendered in a prior month shall be
made to the bill for the month in which the error is discovered by
adjusting the bill for such month to correct for the error as follows:
(a) if the volume of gas, or any portion thereof, in respect of
which the correction relates was in excess of the Receipt
Point Contract Demand Quantity or Export Delivery Point
Contract Demand Quantity, as the case may be, applicable at
the time the Service was provided, the correction shall be
made in respect of such volume or portion thereof in the month
in which bill is corrected in accordance with the appropriate
provision of this Tariff in effect at the time that the error
was made regarding the charge applicable to over-run gas: and
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(b) if the volume of gas, or any portion thereof, in respect of
which the correction relates was not in excess of the Receipt
Point Contract Demand Quantity, or Export Delivery Point
Contract Demand Quantity, as the case may be, applicable at
the time the Service was provided, the correction shall be
made in respect of such volume or portion thereof in the month
in which the bill is corrected in accordance with the
appropriate provision of this Tariff in effect at the time the
error was made regarding the charge applicable to the relevant
Service.
5.7 DISPUTED BILLS
5.7.1 In the event Customer disputes any part of a bill, Customer shall
nevertheless pay to Company the full amount of the bill when payment
is due.
5.7.2 In the event Customer fails to pay the full amount of any bill within
thirty (30) days after payment is due, Company, in addition to any
other remedy it may have, may suspend receipt and delivery of gas
until full payment is made. Such suspension shall not relieve
Customer from any obligation to pay any minimum charge, demand charge,
basic charge, Surcharge or any other charge payable to Company.
5.7.3 In the event that it is finally determined that Customer's monthly
bill was incorrect and that an overpayment has been made, Company
shall make reimbursement of such overpayment. Company shall pay
interest on the overpayment to Customer commencing with date such
overpayment was made and continuing until the date reimbursement is
actually made. The rate of interest shall be calculated and adjusted
in the manner provided for in paragraph 5.4 of these General Terms and
Conditions except that the initial rate of interest shall be the rate
of interest which is two (2) percent over and above the Prime Rate in
effect on the first day of the quarter during which the overpayment is
made.
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6.0 POSSESSION AND CONTROL
6.1 CONTROL
Gas received by Company for transportation shall be deemed to be in
the custody and under the control of Company from the time it is
received into the Facilities until it is delivered out of the
Facilities.
6.2 WARRANTY
Customer warrants and represents it has the right to tender and have
transported all gas delivered to Company.
Effective Date: November 1, 1993
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7.0 PRESSURES OF GAS
7.1 THE PRESSURE OF GAS AT RECEIPT POINTS
The pressure of gas tendered by Customer to Company at any Receipt
Point shall be the pressure, up to the Maximum Receipt Pressure, that
Company requires such gas to be tendered, from time to time, at that
Receipt Point.
7.2 PRESSURE PROTECTION
Customer shall provide or cause to be provided suitable pressure
relief devices, or pressure limiting devices, to protect the
Facilities as may be necessary to ensure that the pressure of gas
delivered by Customer to Company at any Receipt Point will not exceed
one hundred ten (110%) percent of the Maximum Receipt Pressure.
7.3 THE PRESSURE OF GAS AT DELIVERY POINTS
The pressure of gas delivered by Company at any Delivery Point shall
be the pressure available from the Facilities at that Delivery Point,
provided that such pressure shall not exceed the Maximum Delivery
Pressure.
Effective Date: November 1, 1993
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8.0 GAS USED, GAS LOST AND MEASUREMENT VARIANCE
8.1 COMPANY'S GAS REQUIREMENTS
Company may, at its option, either:
(a) take from all Customers a volume of gas having an energy
content equal to the aggregate energy content of any or all
Gas Used, Gas Lost and Measurement Variance for any period; or
(b) arrange with a Customer or Customers or any other Persons to
take and pay for a volume of gas having an energy content
equal to the aggregate energy content of any or all Gas Used,
Gas Lost and Measurement Variance for any period.
8.2 ALLOCATION OF GAS TAKEN
If Company in any period exercises its option to take a volume of gas
as provided for in paragraph 8.1 (a), each Customer's share of the
volume of such gas taken in such period will be a volume equal to the
product of the volume of such gas taken in such period and a fraction
the numerator of which shall be the energy content of the aggregate
volume of gas received by Company from Customer in such period at all
of Customer's Receipt Points and the denominator of which shall be the
energy content of the aggregate volume of gas received by Company from
all Customers in such period at all Receipt Points.
For billing purposes under Rate Schedule FS, IT-1 and IT-2, Customer's
share of the volume of gas taken, determined in accordance with this
paragraph 8.2, shall be allocated to such Customer's Service under
each of Rate Schedule FS, IT-1 and IT-2 in the same proportion that
the aggregate volume of gas received from such Customer under Service
Agreements, for Service rendered to such Customer under Rate Schedules
FS, IT-1 and
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IT-2, was allocated for billing purposes to such Customer under each
such Rate Schedule is to the aggregate volume of gas received from
such Customer under Service Agreements for Service rendered under Rate
Schedules FS, IT-1 and IT-2.
8.3 COST OF GAS TAKEN AND PAID FOR
If Company in any period exercises its option to take and pay for gas
as provided for in paragraph 8.1 (b), Company shall include the cost
of such gas in the calculation of the Total Cost of Service.
8.4 GAS RECEIVED FROM STORAGE FACILITIES
Notwithstanding anything contained in this Article 8, any gas received
into the Facilities from a gas storage facility that was previously
delivered into the gas storage facility through the Facilities shall
not be included in any calculation, and shall not be taken into
account in any allocation, of Company's gas requirements.
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9.0 DELIVERY OBLIGATION
9.1 Subject to paragraph 9.2, Company's delivery obligation for any period
where Company has exercised its option as provided for in paragraph
8.1 (a), shall be to deliver to Customer at all of Customer's Delivery
Points the volume of gas which has the aggregate energy content of the
aggregate volume of gas Company determines was received from Customer
in such period at all of Customer's Receipt Points, less Customer's
share as determined under paragraph 8.2, and Company's delivery
obligation, for any period where Company has exercised its option to
purchase gas as provided for in paragraph 8.1 (b), shall be to deliver
to Customer at all of Customer's Delivery Points the volume of gas
which has the aggregate energy content of all gas received from
Customer, other than gas taken from such Customer and paid for
pursuant to paragraph 8.1 (b), in such period at all of Customer's
Receipt Points.
9.2 Due to variations in operating conditions, the aggregate daily and
monthly volumes of gas delivered to Customer at all of Customer's
Delivery Points, adjusted as provided for in paragraph 9.1, will
differ from the aggregate of the corresponding daily and monthly
volumes of gas received from Customer. Customer and Company shall
co-operate to keep such differences to the minimum permitted by
operating conditions and to balance out such differences as soon as
practicable.
9.3 Company may enter into agreements and other operating arrangements
with any operator ("downstream operator") of a downstream pipeline
facility interconnecting with the Facilities respecting the balancing
of gas quantities to be delivered by Company and to be received by the
downstream operator on any Day at the interconnection of the
downstream facility and the Facilities (the "interconnection point"),
including agreements and operating arrangements providing that for any
Day a quantity of gas nominated by a Customer for delivery at the
interconnection point may be deemed to have been delivered by Company
and received by the downstream operator regardless of the actual flow
of gas at the interconnection point on the Day.
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9.4 The gas delivered by Company to Customer at any of Customer's Delivery
Points shall have the energy content and quality that results from the
gas having been transported and commingled in the Facilities.
9.5 Each Customer receiving Service is responsible for ensuring that their
Customer Inventory is at all times at a zero balance. If Company
determines that the Customer Inventory for any Customer is other than
at a zero balance, Company may, upon notice, suspend all, or any
portion of, Service to Customer until Customer brings its Customer
Inventory to a zero balance, provided however that no such suspension
shall relieve Customer of its obligation to pay any minimum charge,
demand charge, basic charge, Surcharge or any other amount payable to
Company.
9.6 Company may from time to time establish procedures respecting (i) the
obtaining of data and information from any Person operating facilities
upstream or downstream of any of the Facilities, (ii) the allocation
among Company's Customers, on a daily or other basis, of gas volumes
received into and delivered out of the Facilities, (iii) the revision
of any allocation of gas volumes provided to Company in respect of any
prior period and the reallocation of such volumes among Company's
Customers, (iv) any request for Service from a Customer who fails to
balance, within criteria and parameters established by Company from
time to time, the flow of its gas into the Facilities with the flow of
its gas out of the Facilities and (v) the suspension of all, or any
portion of, Service to any Customer whose Customer Inventory is other
than at a zero balance.
9.7 Company shall be obligated to provide only such Service as can be
provided through Company's operation of the existing Facilities
pursuant to the terms and conditions of the Tariff.
9.8 All deliveries of gas to Company at a Receipt Point shall be made in
uniform hourly quantities to the extent practicable.
Effective Date: November 1, 1993
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10.0 FINANCIAL INFORMATION AND SECURITY
10.1 FINANCIAL INFORMATION
Customer shall provide Company with any financial information Company
reasonably requests prior to Company providing Service in order that
Company may establish Customer's credit worthiness.
10.2 SECURITY FOR PERFORMANCE OF OBLIGATIONS
Company may request that Customer at any time and from time to time
provide Company with a performance bond, irrevocable letter of credit
or other security acceptable to Company (the "security") in an amount
and in form and substance satisfactory to Company. If Customer fails
to provide such security to Company within ten (10) days of Company's
request, Company may at its option immediately suspend any or all
Service being or to be provided to Customer provided however that any
such suspension shall not relieve Customer from any obligation to pay
any minimum charge, demand charge, basic charge, Surcharge or any
other charge payable to Company.
Effective Date: November 1, 1993
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11.0 INTERRUPTIONS AND CURTAILMENTS
11.1 Provided that Company shall have given Customer at least forty-eight
(48) hours notice, Company may interrupt, curtail or reduce Service
for such periods of time as it may reasonably require for the purpose
of effecting any repairs, maintenance, replacement or upgrading or
other work related to the Facilities.
11.2 Notwithstanding paragraph 11.1, in the event of unforeseen
circumstances Company may interrupt, curtail or reduce Service for
such periods of time as it may reasonably require without giving
Customer the notice provided for in paragraph 11.1 provided that
Company shall give notice of such interruption, curtailment or
reduction as soon as is reasonably possible.
11.3 Customer and Company shall give each other as much notice as is
reasonably possible in the circumstances of expected temporary changes
in the rates of delivery or receipt of gas, pressures or other
operating conditions, together with the expected duration and the
reason for such expected temporary changes.
11.4 During periods of interruption and curtailment Company may firstly
reduce all Service under Rate Schedule IT-2 to nil, secondly reduce
all Service under Rate Schedule IT-1 to nil and thirdly prorate all
Service under Rate Schedule FS.
11.5 Notwithstanding any other provision herein, Customer agrees and
acknowledges that any interruption and curtailment shall not under any
circumstances suspend or relieve Customer from the obligation to pay
any minimum bill, demand charge, basic charge, Surcharge or any other
amount payable to Company.
Effective Date: November 1, 1993
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12.0 FORCE MAJEURE
12.1 In the event that either Company or Customer is rendered unable by
reason of force majeure to perform in whole or in part any covenant or
obligation set forth in any Rate Schedule, any Service Agreement or
these General Terms and Conditions, the performance of such covenant
or obligation shall be suspended during the continuance of such force
majeure, except as provided for in paragraph 12.3, upon the following
terms and conditions:
(a) the party claiming suspension shall give written notice to the
other party specifying full particulars of such force majeure
as soon as is reasonably possible;
(b) the party claiming suspension shall as far as possible remedy
such force majeure as soon as is reasonably possible; and
(c) the party claiming suspension shall give written notice to the
other party as soon as is reasonably possible after such force
majeure has been remedied.
12.2 For the purposes of these General Terms and Conditions, the term
"force majeure" shall mean any cause not reasonably within the control
of the party claiming suspension which by the exercise of due
diligence such party is unable to prevent or overcome, including but
without limiting the generality of the foregoing:
(a) lightning, storms, earthquakes, landslides, floods, washouts,
and other acts of God;
(b) fires, explosions, ruptures, breakages of or accidents to the
Facilities;
(c) freezing of pipelines or wells, hydrate obstructions of
pipelines or appurtenances thereto, temporary failure of gas
supply;
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(d) shortages of necessary labour, strikes, lockouts or other
industrial disturbances;
(e) civil disturbances, sabotage, acts of public enemies, war,
blockades, insurrections, vandalism, riots, epidemics;
(f) arrests and restraints of governments and people;
(g) the order of any court, government body or regulatory body;
(h) inability to obtain or curtailment of supplies of electric
power, water, fuel or other utilities or services;
(i) inability to obtain or curtailment of supplies of any other
materials or equipment;
(j) inability to obtain or revocation or amendment of any permit,
licence, certificate or authorization of any governmental or
regulatory body, unless the revocation or amendment of such
permit, licence, certificate or authorization was caused by
the violation of the terms thereof or consented to by the
party holding the same;
(k) the failure for any reason of a supplier of gas to Customer or
a purchaser of gas from Customer to supply and deliver gas to
Customer or to purchase and take delivery of gas from
Customer;
(l) any claim by any third party that any covenant or obligation
of such third party is suspended by reason of force majeure,
including without limiting the generality of the foregoing any
such claim by any transporter of gas to, from or for Company
or Customer; and
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(m) any other cause, whether herein enumerated or otherwise, not
reasonably within the control of the party claiming suspension
which by the exercise of due diligence such party is unable to
prevent or overcome.
12.3 Notwithstanding any other provision herein, Customer acknowledges and
agrees that the occurrence of an event of force majeure shall not
under any circumstances suspend or relieve Customer from the
obligation to pay any minimum charge, demand charge, basic charge,
Surcharge or any other amount payable to Company.
12.4 Notwithstanding any other provision herein, Company and Customer agree
that a lack of funds or other financial cause shall not under any
circumstances be an event of force majeure.
12.5 Notwithstanding any other provision herein, Company and Customer agree
that the settlement of strikes, lockouts and other industrial
disturbances shall be entirely within the discretion of the party
involved.
12.6 In the event that the provision of Service is curtailed or interrupted
by reason of force majeure, Company may during the continuance of such
force majeure provide such Service as it deems appropriate.
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13.0 INDEMNIFICATION
13.1 Customer shall be liable for and shall indemnify and save harmless
Company from and against any and all claims, demands, suits, actions,
damages, costs, losses and expenses of whatsoever nature arising out
of or in any way connected, either directly or indirectly, with any
act, omission or default arising out of the negligence of Customer.
13.2 Company shall be liable for and shall indemnify and save harmless
Customer from and against any and all claims, demands, suits, actions,
damages, costs, losses and expenses of whatsoever nature arising out
of or in any way connected, either directly or indirectly, with any
act, omission or default arising out of the negligence of Company.
13.3 Notwithstanding the provisions of paragraphs 13.1 and 13.2:
(a) Company and Customer shall have no liability for, nor
obligation to indemnify and save harmless the other from, any
claim, demand, suit, action, damage, cost, loss or expense
which was not reasonably foreseeable at the time of the act,
omission or default;
(b) Company shall have no liability to Customer, nor obligation to
indemnify and save harmless Customer, in respect of Company's
failure for any reason whatsoever, other than Company's wilful
default, to provide Service pursuant to the provisions of
Customer's Service Agreement; and
(c) The failure by Company for any reason whatsoever to receive
gas from Customer or deliver gas to Customer shall not suspend
or relieve Customer from the obligation to pay any minimum
bill, demand charge, basic charge, Surcharge or any other
amount payable to Company.
Effective Date: November 1, 1993
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14.0 EXCHANGE OF INFORMATION
14.1 Company and Customer shall make available, on request by either made
to the other, certificates, estimates and information as shall be in
their possession, and as shall be reasonably required by the other.
14.2 Notwithstanding paragraph 14.1, Customer shall furnish Company with
such estimated daily, monthly and annual volumes as Company may
require, with respect to any Service provided or to be provided,
together with any data that Company may require in order to design,
operate and construct facilities to meet Customer's requirements.
Effective Date: November 1, 1993
<PAGE> 55
[NOVA LOGO] Page 164
15.0 MISCELLANEOUS PROVISIONS
15.1 EFFECT OF HEADINGS
The headings used throughout the Rate Schedules, the Service
Agreements, and these General Terms and Conditions are inserted for
reference purposes only and are not to be considered or taken into
account in construing any terms or provision nor be deemed in any way
to qualify, modify or explain any term or provision.
15.2 WORDS IN SINGULAR OR PLURAL
In the interpretation of the Rate Schedules, the Service Agreements,
and these General Terms and Conditions words in the singular shall be
read and construed in the plural and words in the plural shall be read
and construed in the singular where the context so requires.
15.3 PRESERVATION OF RIGHTS AND AUTHORITY UNDER THE ACT
Notwithstanding any of the provisions of the Rate Schedules, the
Service Agreements, and these General Terms and Conditions, Company
and Customer reserve all their respective rights and authorities under
the Act.
15.4 INTERPRETATION
The interpretation of the Rate Schedules, the Service Agreements, and
these General Terms and Conditions shall be in accordance with the
laws in force in the Province of Alberta.
Effective Date: November 1, 1993
<PAGE> 56
[NOVA LOGO] Page 165
15.5 ASSIGNMENT
Customer shall not assign any Service Agreement, Schedule of Service
or any Service without the prior written consent of Company.
15.6 NO INTEREST IN FACILITIES
Customer does not acquire any right to, title to or interest in the
Facilities or any part thereof nor does Company dedicate any portion
of the Facilities to Service for any Customer.
15.7 FORBEARANCE
Forbearance to enforce any provision of the Rate Schedules, the
Service Agreements or these General Terms and Conditions shall not be
construed as a continuing forbearance to enforce any such provision.
15.8 INCONSISTENCY
In the event that there is any inconsistency between any provision of
these General Terms and Conditions and any provision of any Rate
Schedule the provision of the Rate Schedule shall prevail.
15.9 AMENDMENT OF SERVICE AGREEMENT
No amendment or variation of any term, condition or provision of any
Service Agreement shall be of any force or effect unless in writing
and signed by Company.
Effective Date: November 1, 1993
<PAGE> 57
[NOVA LOGO] Page 166
15.10 PRIORITY FOR NEW OR ADDITIONAL SERVICE
Company may from time to time establish procedures respecting priority
of entitlement for Customers seeking new or additional Service.
15.11 ESTABLISHMENT OF PROCEDURES AND PILOT PROJECTS
Company may from time to time establish procedures, including
procedures for carrying out and evaluating any pilot projects Company
determines to be necessary or desirable, respecting or relating to or
affecting any Service or any term, condition or provision contained
within any Rate Schedule, Service Agreement or the General Terms and
Conditions.
Effective Date: November 1, 1993
<PAGE> 1
EXHIBIT 10.3
SERVICE AGREEMENT
APPLICABLE TO FIRM TRANSPORTATION SERVICE
UNDER RATE SCHEDULE FS-1
THIS AGREEMENT made effective as of 08:00 MST on November 1, 1993, or such
later date as is determined to be the Decontracting Date under the provisions
of the Decontracting Agreement among Alberta and Southern Gas Co. Ltd., Pacific
Gas Transmission Company, Pacific Gas and Electric Company and the
decontracting producers, dated September 22, 1993;
ALBERTA NATURAL GAS COMPANY LTD, a body corporate, having an office
and carrying on business in the City of Calgary, in the Province of
Alberta (hereinafter referred to as "Company"),
- and -
PACIFIC GAS AND ELECTRIC COMPANY, a body corporate, having an office
and carrying on business in the City of San Francisco in the State of
California (hereinafter referred to as "Shipper")
WHEREAS, Company's Facilities extend from a point of interconnection with the
pipeline facilities of NOVA Corporation of Alberta at the Alberta-British
Columbia border near Coleman, Alberta, through southeast British Columbia to a
point of interconnection with the pipeline facilities of Pacific Gas
Transmission Company at the international border near Kingsgate, British
Columbia; and
WHEREAS, Shipper desires Company, on a firm basis, to transport certain volumes
of natural gas through Company's Facilities from Alberta/British Columbia
border near Coleman, Alberta to British Columbia/U.S. international border near
Kingsgate, B.C.; and
WHEREAS, Company is willing to transport certain volumes of natural gas for
Shipper, on a firm basis;
NOW, THEREFORE, the parties agree as follows:
1. This Agreement is subject to all valid legislation with
respect to the subject matters hereof, either provincial or federal, and to all
valid present and future decisions, orders, rules, and regulations of all duly
constituted governmental authorities having jurisdiction.
2. Shipper acknowledges receipt of a current copy of Company's
Gas Transportation Service Documents and Company agrees to provide Shipper with
any amendments thereto.
-1-
<PAGE> 2
3. The terms used herein shall have the same meanings as are
ascribed to corresponding terms in the General Terms and Conditions contained
in the Gas Transportation Service Documents.
4. Shipper hereby requests, and Company agrees to provide Service
pursuant to Service Schedule FS-1 in accordance with the attached Schedule A
which is incorporated into and forms part of this Agreement, such Service to
commence on the Service Availability Date and to terminate, subject to the
provisions hereof, on the Service Termination Date.
5. Shipper agrees to make gas available for Shipper's share of
Company Use Gas, or pay for such gas, pursuant to Article V of the General
Terms and Conditions.
6. Company undertakes to redeliver to Shipper, and Shipper agrees
to accept, at the Delivery Point, a volume of gas equivalent in heat content to
the volume received by Company from Shipper, at the Receipt Point, after
deducting gas volumes, if any, provided by Shipper for Company Use Gas.
7. In providing service to its existing or new Shippers, Company
will use the priority of service specified in Article XI of Company's General
Terms and Conditions.
8. Prior to the Service Availability Date, Shipper shall provide
Company with all information identified in Company's Request for Transportation
Form.
9. Shipper agrees to pay, during the period commencing from the
Service Availability Date, and in accordance with Schedule FS-1, the General
Terms and Conditions, the Statement of Effective Rates and Charges and Schedule
"A" attached hereto (all as may be amended from time to time), the rates, tolls
and charges fixed by Company from time to time, in respect of each month, and
portion thereof that this Service Agreement and any renewal thereof is in
effect.
In the event that the Service Availability Date occurs on any day
other than the first day of a month, then the demand charge payable for such
month under section 3.1 of Service Schedule FS-1 shall be the product resulting
from multiplying the demand charge otherwise payable for such month by a
fraction, the numerator of which shall be the number of days in such month
subsequent to and including the Service Availability Date and the denominator
of which is the total number of days in such month.
-2-
<PAGE> 3
10. Shipper covenants that it will make timely arrangements for
upstream and downstream transportation, gas supply and markets and all
necessary governmental authorizations and that it will advise the upstream and
downstream transporters of the receipt and delivery points under this
Agreement.
Shipper acknowledges and agrees with Company that Company is
relying upon the covenant contained in this clause and agrees that if any such
arrangements or authorizations are not in place prior to the Service
Availability Date, such will not affect the Shipper's obligation to pay any
demand charge, surcharge, or any other amount payable to the Company.
11. If Shipper elects to exercise its option to terminate this
Service Agreement as provided for in Clause 9. of Service Schedule FS-1, it
shall execute and serve upon Company a termination notice not less than twelve
months prior to the Service Termination Date as such date may be extended from
time to time.
12. Shipper agrees not to make demand or bring action against
Company for Company's refusal to transport gas hereunder in the event that any
upstream or downstream transporter fails to receive or deliver gas as
contemplated by this agreement provided that such failure was not directly
caused by the negligence of Company.
13. Every notice, request, demand, statement or bill provided for
by the Service Schedules, the Service Agreements and the General Terms and
Conditions, or any notice which either Shipper or Company may wish to give to
the other, shall be in writing and shall be directed as follows:
Shipper: PACIFIC GAS AND ELECTRIC COMPANY
Gas Services Department, B1GA
Rm. 1611, 77 Beale Street
P.O. Box 770000
San Francisco, California 94177
Attn: Mr. H. O. LaFlash, Manager, Gas Services
Company: ALBERTA NATURAL GAS COMPANY LTD
2900, 240 - Fourth Avenue S.W.
Calgary, Alberta, Canada
T2P 4L7
Attn: Mr. T. L. (Tim) Stauft, P.Eng.
Manager, Customer Services
-3-
<PAGE> 4
Any notice may be given by personal delivery, by telecopier or by mail and
shall be deemed to be given on the day of delivery, if by personal delivery or
by telecopier, and four (4) business days after mailing if by mail. Any notice
may also be given by telephone followed immediately by telecopier, or other
telecommunication agreed to by both parties, and any notice so given shall be
deemed to be given as of the date of the confirming telecommunication.
14. The terms and conditions of Service Schedule FS-1 and the
General Terms and Conditions are by this reference incorporated into and made
part of this Service Agreement.
15. A waiver by either party of one or more defaults by the other
hereunder shall not operate as a waiver of any future default or defaults,
whether of a like or different character.
16. This agreement may be amended only by an instrument in writing
executed by both parties hereto.
17. Nothing in this agreement shall be deemed to create any rights
or obligations between the parties hereto after the expiration of the term
hereof as same may be extended from time to time except that termination of
this agreement shall not relieve either party of the obligation to correct any
gas volume imbalances or of the obligation to pay any amounts due hereunder.
IN WITNESS WHEREOF the parties hereto have caused this
agreement to be executed as of the day and year first written above.
ALBERTA NATURAL GAS COMPANY LTD
By: V. Mirosh
Name: M. Pfaefflin
Title:____________________________
PACIFIC GAS AND ELECTRIC COMPANY
By: Daniel Thomas
Name: Daniel F. Thomas
Title: Asst. to Sr. Vice Pres. GSBU
-4-
<PAGE> 5
SCHEDULE A
TO THE FIRM SERVICE AGREEMENT
made effective as of 08:00 MST on November 1, 1993, or such later date as is
determined to be the Decontracting Date under the provisions of the
Decontracting Agreement among Alberta and Southern Gas Co. Ltd., Pacific Gas
Transmission Company, Pacific Gas and Electric Company and the decontracting
producers, dated September 22, 1993 Between
ALBERTA NATURAL GAS COMPANY LTD
AND
PACIFIC GAS AND ELECTRIC COMPANY (SHIPPER)
1. Receipt Point: Alberta/British Columbia
Border near Coleman, Alberta
Minimum Pressure Available
4200 kPa
2. Delivery Point: British Columbia/U.S.
international border near
Kingsgate, B.C. Maximum
Pressure Available 5500 kPa
3. Shipper's Haul Distance 170.7 Km
4. Shipper's Compression Utilization 170.7 Km
5. Maximum Day Delivery Quantity (Winter) 16,996.7 10(3)m(3)/d
(Summer) 16,996.7 10(3)m(3)/d
6. Service Availability Date made effective as of 08:00
MST on November 1, 1993, or
such later date as is
determined to be the
Decontracting Date under the
provisions of the
Decontracting Agreement among
Alberta and Southern Gas Co.
Ltd., Pacific Gas
Transmission Company, Pacific
Gas and Electric Company and
the decontracting producers,
dated September 22, 1993
7. Service Termination Date October 31, 2005
8. Surcharge Amount:
For Special Facilities N/A Dollars/Month
For Other N/A Dollars/Month
Total Surcharge N/A Dollars/Month
SHIPPER COMPANY
PACIFIC GAS AND ELECTRIC COMPANY ALBERTA NATURAL GAS COMPANY LTD
Daniel Thomas V. Mirosh
_______________________________ _______________________________
(name) (name)
Asst. to Sr. Vice Pres. GSBU M. Pfaefflin
_______________________________ _______________________________
(name) (name)
<PAGE> 6
Sheet 20
ALBERTA NATURAL GAS COMPANY LTD
STATEMENT OF
EFFECTIVE RATES AND CHARGES
Firm Service
Demand Rate Commodity Rate
--------------- --------------
($/10(3)m(3)/Km/Mo.) ($/10(3)m(3)/Km)
PIPELINE 0.22434757
COMPRESSOR 0.20273731 0.00138734
Interruptible Service
Commodity Rate
--------------
($/10(3)m(3)/Km)
0.01698862
Company Use Gas and Line Pack Requirements
Shipper's Share of Company use Gas shall be determined pursuant to Article V of
the General Terms and Conditions. Shipper's share of the Line Pack
Requirements shall be determined pursuant to paragraph 9.6 of Article IX of
General Terms and Conditions. In the event that Company provides Shipper's
Share of Company Use Gas and/or Line Pack Requirements, Company shall bill
Shipper for such gas at the rate of:
$ [price to be determined.]
Effective: November 1, 1993
<PAGE> 7
Sheet 21
RATE CALCULATION METHODOLOGY
INTRODUCTION AND GENERAL
Gas transportation rates charged by Alberta Natural Gas Company Ltd
(ANG) to its shippers are based on a determination of conventional cost of
service including return on a fully depreciated rate base. The costs included
are limited to those incurred in the operation of ANG's gas pipeline system
located in south east British Columbia plus (after October 31, 1993) the
amounts billed to ANG by Foothills Pipe Lines Limited under tariffs approved by
the National Energy Board.
ANG fixes its rates in consultation with its shippers. Such
consultations determine matters such as ANG's deemed capital structure,
appropriate rates for debt interest expense (if no debt actually is in place),
equity return rate, depreciation policy, etc.
To ensure that rates reflect actual ANG costs, an adjustment to the
rates calculation is carried forward from the preceding period each time rates
are recalculated. The adjustment corrects for the difference between revenue
requirements and actual revenue collections for the preceding period. Firm
service rates are based on net costs after deduction of revenues collected from
interruptible shippers.
Rates established from time to time are set out on the Statement of
Effective Rates and Charges, Sheet 20, contained in ANG's Gas Transportation
Service Documents, filed with the National Energy Board and made available to
all ANG shippers and prospective shippers.
Effective: April 1, 1991
<PAGE> 8
Sheet 22
SHEETS 22 THROUGH 29
ARE RESERVED FOR
FUTURE REVISIONS TO THIS DOCUMENT
Effective: April 1, 1991
<PAGE> 9
Sheet 30
ALBERTA NATURAL GAS COMPANY LTD
SERVICE SCHEDULE FS-1
1. Availability
Service under Service Schedule FS-1 is available to all shippers of gas which
desire transportation service from Company for such gas for delivery for export
from Canada or to markets in Canada, which quality for service hereunder and
which have executed a Service Agreement in the form contained in these Gas
Transportation Service Documents.
The term of the Service Agreement shall be for a minimum of fifteen (15) years
if an expansion of Company's Facilities is required.
2. Applicability and Character of Service
Subject to the terms and conditions applicable to service under this Service
Schedule FS-1, service hereunder shall consist of receipt from Shipper of daily
quantities of gas up to Shipper's Maximum Day Receipt Quantity as specified in
the executed firm transportation Service Agreement between Company and Shipper,
transportation of such quantities through Company's Facilities and delivery of
an amount equivalent to the quantity received less Shipper's share of Company
Use Gas provided by Shipper. Shipper's share of Company Use Gas shall be
provided in accordance with the provisions of Article V of the General Terms
and Conditions.
This transportation service shall be firm and not subject to curtailment or
interruption except as provided in the General Terms and Conditions.
Effective: April 1, 1991
<PAGE> 10
Sheet 31
3. Charge for Service
Company's charge for service under this Service Schedule shall be determined
using the rates for FS-1 Service contained in the Statement of Effective Rates
and Charges on Sheet 20 of these Gas Transportation Service Documents.
Effective rates for service under this Service Schedule FS-1 shall be set by
Company from time to time. The amount of any interruptible toll revenues
collected by Company shall be credited to Company's cost of service.
Company's billing to each Shipper each month shall be the total of the amounts
described under sub-paragraphs 3.1, 3.2, 3.3, 3.4, 3.5, 3.6 and 3.7 for that
Shipper determined as follows:
3.1 Shipper's Monthly Demand Charge
Shipper's monthly demand charge shall be the product of:
(a) Shipper's Maximum Day Delivery Quantity as indicated on
Schedule A to Shipper's Service Agreement;
(b) Shipper's Haul Distance as indicated on Schedule A to
Shipper's Service Agreement; and
(c) the Demand Rate currently in effect for Service Schedule FS-1
from Company's Statement of Effective Rates and Charges, Sheet
20 of these Gas Transportation Service Documents.
3.2 Shipper's Commodity Charge
Shipper's commodity charge for the month shall be the product of:
(a) the quantity of gas delivered by Company to Shipper at the
Delivery Point during such month;
Effective: April 1, 1991
<PAGE> 11
Sheet 32
(b) Shipper's Haul Distance from Schedule A to Shipper's Service
Agreement; and
(c) the Commodity Rate currently in effect for firm service from
Company's Statement of Effective Rates and Charges, Sheet 20
of these Gas Transportation Service Documents.
3.3 Charge for Company Use Gas
If Shipper elects not to provide Shipper's share of Company Use Gas in kind and
such gas is provided by Company, then the charge to Shipper for such gas for
any month shall be the product of:
(a) Shipper's share of Company Use Gas determined pursuant to
paragraph 5.1 of the General Terms and Conditions for such
month; and
(b) the rate charged by Company for such gas set out on Company's
Statement of Effective Rates and Charges, Sheet 20 of these
Gas Transportation Service Documents.
3.4 Surcharge
Shippers surcharge amount, if any, shall be an amount to recognize the recovery
of costs associated with special facilities installed by Company for Shipper
agreed to between Company and Shipper expressed in dollars per month. Such
amount shall be entered on Schedule A to Shipper's Service Agreement.
Effective: April 1, 1991
<PAGE> 12
Sheet 33
3.5 Charge for Over-Run Gas
In the event that Company determines that Shipper has tendered for
transportation, and Company has transported for Shipper under this Service
Schedule on any day during a billing month, a volume of gas at the Delivery
Point in excess of Shipper's Maximum Day Delivery Quantity in effect on such
day, Shipper shall pay to Company an amount equal to the product of such excess
for such day and the Tier 1 commodity rate for service under Service Schedule
IS-1, provided that Shipper shall not be required to pay any charge for make-up
quantities delivered by Company pursuant to paragraph 4 of this Service
Schedule FS-1 or for excess deliveries on any day which are less than two
percent (2%) of Shipper's Maximum Day Delivery Quantity.
3.6 Demand Charge Credit
(a) Subject to paragraph 3.6(b), if in any month Company is unable
to deliver up to ninety eight percent (98%) of the quantity of
gas that Shipper has in good faith nominated up to the Maximum
Day Delivery Quantity times the number of days in such month,
then in respect of such month, a credit shall be applied to
the monthly bill rendered by Company determined according to
the following formula:
Shippers Shipper's
credit = Demand x Haul x Maximum Day - Avg. Day Del.
Rate Distance Delivery Quantity
Where: Avg. Day Del. = Deliveries to Shipper in such month divided by the
number of days in such month.
Effective: April 1, 1991
<PAGE> 13
Sheet 34
(b) No credit to the monthly bill shall be made if Company
delivers less than ninety eight percent (98%) of the volume of
gas nominated as a result of planned maintenance on Company's
Facilities or as a result of Shipper being unable to deliver
gas at the Receipt Point or accept gas at the Delivery Point.
3.7 Charge for Company's Line Pack Requirements
If Shipper elects not to provide Shipper's Share of Company's Line Pack
Requirements in kind and such gas is provided by Company, then the charge to
shipper for such gas shall be the product of:
(a) Shipper's Share of Company's Line Pack Requirements; and
(b) the rate charged by Company for line pack set out on Company's
Statement of Effective Rates and Charges, Sheet 20 of the Gas
Transportation Service Documents.
4. Make-Up Provision
In the event that Company fails on any day to deliver to Shipper at the
Delivery Point the quantity of gas nominated by Shipper and available at the
Receipt Point, up to Shipper's Maximum Day Delivery Quantity, Shipper shall be
entitled, subject to paragraph 11.2 of Article XI of the General Terms and
Conditions and within two years of such failure, to have Company transport
volumes of gas in excess of Shipper's Maximum Day Delivery Quantity at no
additional demand charge sufficient to cancel such deficiency. Demand charges
credited to Shipper under paragraph 3.6 shall be recovered by Company
respecting volumes delivered by Company under this paragraph 4.
Effective: April 1, 1991
<PAGE> 14
Sheet 35
5. Company Use Gas
Shipper's share of Company Use Gas shall be furnished by Shipper to Company
each day, or paid for by Shipper, pursuant to Article V of the General Terms
and Conditions.
6. Backhauls
Company may provide backhaul service under this Service Schedule where such
service is requested and provided that, in Company's judgement, it is practical
to provide such service considering the capacity of Company's Facilities and
throughput volumes. Company's charge for backhaul service shall be as
determined under paragraph 3. above. Company shall not require that Shipper
provide a share of Company Use Gas respecting backhaul service.
7. Assurances and Information
Shipper shall provide such assurances and information as Company may reasonably
require respecting any service to be provided pursuant to this Service Schedule
including, without limiting the generality of the foregoing, an assurance that
all necessary arrangements have been made among Shipper, sellers of gas to
Shipper, purchasers of gas from Shipper, and transporters of Shipper's gas to,
and from, Company's Facilities.
8. Relief
If Shipper requests relief from its obligation to pay all or any portion of its
charges under this Service Schedule which are based on Shipper's Maximum Day
Delivery Quantity, Shipper shall notify Company of its request for relief.
Company may, at its option, elect to attempt to find another Person who
qualifies for service under this Service Schedule and who is willing to assume
the Maximum Day Delivery Quantity, or a portion thereof, which Shipper proposes
to make available, although Company assumes no obligation to find such a
Person. If Company so elects to attempt to find such a Person, it shall first
have regard to the queue for firm service established in accordance with its
Queuing Procedures. If Company finds such a Person, then Company may grant
relief to Shipper, to the extent requested, by reducing Shipper's Maximum Day
Delivery Quantity by the amount specified in a Service Agreement executed by
Company and such Person.
Effective: April 1, 1991
<PAGE> 15
Sheet 36
9. Renewal
This Service Agreement, as amended from time to time, and any renewal thereof,
shall be automatically renewed subject to Article XV of the General Terms and
Conditions for a one year term (or such longer term as is agreed upon by
Company and Shipper) for the Maximum Day Delivery Quantity in effect
immediately prior to renewal ()or such lesser volume as is agreed upon by
Company and Shipper not less than twelve months prior to the date when the
Service Agreement would otherwise terminate), unless:
(a) Shipper notifies Company of its intention to terminate the
Service Agreement not less than twelve months before the
termination date which would otherwise prevail pursuant to the
Service Agreement or any renewal thereof; or
(b) Shipper is in default under the Service Agreement.
Any renewal of this Service Agreement shall be subject to the terms and
conditions of Company's Gas Transportation Service Documents then in effect.
Effective: April 1, 1991
<PAGE> 16
Sheet 37
10. General Terms and Conditions
All of the General Terms and Conditions, including the definitions contained
therein, are applicable to this Service Schedule unless otherwise indicated in
the Service Agreement executed between Company and Shipper.
Effective: April 1, 1991
<PAGE> 17
Sheet 38
SHEETS 38 THROUGH 39
ARE RESERVED FOR
FUTURE REVISIONS TO THIS DOCUMENT
Effective: April 1, 1991
<PAGE> 18
ALBERTA NATURAL GAS COMPANY LTD
Sheet 70
GENERAL TERMS AND CONDITIONS
TABLE OF CONTENTS
<TABLE>
<CAPTION>
Article Sheet No.
- ------- --------
<S> <C> <C>
I DEFINITIONS 71
II QUALITY OF GAS 76
III MEASUREMENT 78
IV MEASURING INSPECTION 81
V COMPANY USE GAS 83
VI BILLING AND PAYMENT 84
VII POSSESSION OF GAS AND RESPONSIBILITY 87
VIII WARRANTY OF ELIGIBILITY FOR TRANSPORTATION 88
IX OPERATING PROVISIONS 89
X RECEIPT AND DELIVERY POINT AND GAS PRESSURES 92
XI SERVICE PRIORITIES, INTERRUPTION AND CURTAILMENT 93
XII DELIVERY OBLIGATION 95
XIII FORCE MAJEURE 96
XIV INDEMNIFICATION 98
XV FINANCIAL INFORMATION AND SECURITY 100
XVI MISCELLANEOUS PROVISIONS 101
</TABLE>
Effective: April 1, 1991
<PAGE> 19
Sheet 71
Article I
GENERAL TERMS AND CONDITIONS
1.0 Definitions
Except where the content expressly states otherwise the following
terms and abbreviations, when used in these General Terms and Conditions, the
Service Schedules and the Service Agreements, shall be construed to have the
following meanings:
The terms "Commodity Rate" shall mean the rate entered on Company's
current Statement of Effective Rates and Charges under the heading Commodity
Rate.
The term "Company" shall mean Alberta Natural Gas Company Ltd.
The term "Company's Facilities" shall mean all pipeline, compressor,
metering and other facilities which of any kind are used by Company to provide
transportation service to shippers. Such facilities may be owned by Company or
may be owned by others and used by Company pursuant to an agreement between
Company and such other owners under which Company receives transportation
service.
The term "Company's Line Pack Requirements" shall mean the quantity of
line pack which Company determines from time to time to be required by the
Company when Company's Facilities are at normal operating pressures.
Effective: April 1, 1991
<PAGE> 20
Sheet 72
The term "Company Use Gas" shall mean all gas used by Company for
compressor station and other fuel, gas blown down from Company's Facilities,
gas lost, gas used for purging and other construction uses, unaccounted for gas
and the variation from time to time in Company's line pack.
The term "Contract year" shall mean a twelve month period, beginning
on any November 1st, which falls within the contract term.
The term "Cubic Metre" shall mean that quantity of gas, which at a
temperature of fifteen (15 degrees) degrees Celsius and at an absolute pressure
of one hundred one and three hundred twenty-five thousandths kilopascals
(101.325 kPa) occupies one cubic metre.
The term "Day" shall mean a period of twenty-four (24) consecutive
hours, beginning and ending at 7:00 o'clock a.m. Pacific Standard time.
The term "Delivery Point" shall mean the point set out in Schedule A
to Shipper's Service Agreement under Delivery Point, at which Company delivers
Shipper's gas to Shipper following transportation through Company's Facilities.
The term "Demand Rate" shall mean the rate entered on Company's
current Statement of Effective Rates and Charges under the heading Demand Rate.
The term "Founding Shippers" shall mean Alberta and Southern Gas Co.
Ltd., Westcoast Energy Inc., and Foothills Pipe Lines (South B.C.) Ltd.
Effective: April 1, 1991
<PAGE> 21
Sheet 73
The term "Gas transportation Service Documents" shall mean this Gas
Transportation Service Document including these General Terms and Conditions,
the Queuing Procedure, the Statement of Effective Rates and Charges and the
Service Schedules.
The term "GJ" shall mean gigajoule.
The term "Gross Heating Value" shall mean the number of MJ obtainable
from the combustion, at constant pressure, of one cubic metre of gas at a
temperature of fifteen degrees (15 degrees) Celsius, free of all water vapor,
and at an absolute pressure of one hundred and one hundred one and three hundred
twenty-five thousandths (101.325) kPa, with the products of combustion cooled
to the initial temperature of the gas and all water formed by the combustion
reaction condensed to the liquid state.
The term "kPa" shall mean kilopascal.
The term "Maximum Day Delivery Quantity" shall mean the maximum volume
of gas which Company is obligated to transport and redeliver to Shipper at the
Delivery Point on any day.
The term "Maximum Day Receipt Quantity" shall mean the volume of gas
which Company must receive from Shipper at the Receipt Point on any day in
order to deliver the Maximum Day Delivery Quantity, after taking account of
Shipper's share of Company Use Gas provided by Shipper.
The term "MJ" shall mean megajoule.
The term "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.
Effective: April 1, 1991
<PAGE> 22
Sheet 74
The term "Nomination" shall mean Shipper's notice to Company
respecting the volumes of gas which Shipper wishes Company to receive and
deliver for shipper.
The term "Nomination Form" shall mean the form provided, or agreed to,
by Company on which Shipper provides its Nominations to Company.
The term "Person" shall mean any party except the parties to any
Service Agreement.
The term "Receipt Point" shall mean the point set out in Schedule A to
Shipper's Service Agreement under Receipt Point at which Company receives gas
from shipper for transportation in Company's Facilities.
The term "Service Agreement" shall mean an agreement between Shipper
and Company in the form contained in these Gas Transportation Service Documents
for the service requested by Shipper.
The term "Service Availability Date" shall mean the later of the
Service Availability Date on Schedule A to Shipper's Service Agreement executed
by Shipper and Company, or, the date on which Company's Facilities are capacity
of providing service under Shipper's Service Agreement.
The term "Service Termination Date" shall mean the Requested Service
Termination Date on Schedule A to Shipper's Service Agreement executed by
Shipper and Company.
Effective: April 1, 1991
<PAGE> 23
Sheet 75
The term "Shipper" shall mean any shipper of gas receiving
transportation service from Company pursuant to a Service Agreement executed
with Company.
The term "Shipper's Haul Distance" shall mean the distance through
which shipper's gas is moved in Company's Facilities as shown on Schedule A to
any Shipper's Service Agreement.
The term "Shipper's Share of Company's Line Pack Requirements" shall
mean that quantity of Company's Line Pack Requirements determined as the
proportion that the product of Shipper's Maximum Day Delivery Quantity and
shipper's Haul Distance bears to the sum of the products of all shippers'
Maximum Day Delivery Quantity and haul distances.
The term "Summer" shall mean the six-month period April 1st to
September 30th in any year.
The term "Winter" shall mean the six-month period from October 1st in
any year to March 31st in the following year.
The term "10(3)m(3)" shall mean one thousand (1,000) cubic metres of
gas as determined on the measurement basis set forth in Article III hereof.
Effective: April 1, 1991
<PAGE> 24
Sheet 76
Article II
QUALITY OF GAS
2.1 The following specifications shall apply to the gas which
Shipper delivers or causes to be delivered to Company for transportation at the
Receipt Point.
(a) The gas shall be commercially free from sand, dust, gums,
crude oil, impurities or other objectionable substances in
quantities which may render it unmerchantable and which may be
injurious to Company's Facilities or may interfere with the
transmission, measurement or commercial utilization of gas.
(b) The gas shall not, unless otherwise agreed upon, have a
hydrocarbon dew point in excess of minus ten (-10) degrees
Celsius at operating pressure.
(c) The gas shall not contain more than twenty three (23)
milligrams of hydrogen sulphide per one Cubic Metre of gas.
(d) The gas shall not contain more than two hundred and thirty
(230) milligrams of total sulphur per one Cubic Metre of gas.
(e) The gas shall not contain more than two percent (2%) by volume
of carbon dioxide, unless otherwise agreed upon.
(f) The gas shall not contain more than sixty five (65) milligrams
of water vapour per one Cubic Metre of gas.
(g) The gas shall not exceed 43.3 degrees C in temperature at the
Receipt Point.
(h) The gas 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.
Effective: April 1, 1991
<PAGE> 25
Sheet 77
2.2 The gas Company delivers to Shipper or for Shipper's account
shall have the constituent parts that result from the commingling of the gas
from various sources on Company's pipeline.
2.3 The gas shall have a Gross Heating Value not less than thirty
six point nine four (36.94) megajoules per Cubic Metre of gas; provided
however, that Company may at its sole discretion permit gas of lower gross
heating value to be tendered to Company at the Receipt Point.
2.4 (a) If the gas tendered for transportation shall fail at any time
to conform to any of the specifications set forth in this
Section 2, then Company shall notify Shipper of such
deficiency and may, at its option, refuse to accept such gas
pending the remedying such failure to conform to quality
specifications. If the deficiency in quality is not promptly
remedied, Company may accept such gas and may make changes
necessary to bring such gas into conformity with such quality
specifications and Company shall include all reasonable
expenses incurred by it in effecting such changes in Shipper's
monthly bill.
(b) Notwithstanding subsection 2.4(a) above, Company shall have
the right to discontinue receipt of gas from Shipper without
notice should the gas fail to meet the specification set forth
in subparagraphs (a), (b), (c), (d), (f), or (g) of subsection
2.1 hereof. Provided, however, that any such suspension shall
not relieve Shipper from any obligation to pay its demand
charge, or any other charge payable to Company.
2.5 Company shall establish reasonable methods and procedures,
including instrumentation, for making tests to determine whether gas tendered
by Shipper to Company for transportation or delivered by Company to Shipper
meet the specifications set forth in this Section 2.
Effective: April 1, 1991
<PAGE> 26
Sheet 78
Article III
MEASUREMENT
3.1 Company shall cause to be furnished, installed, maintained and
operated at each Receipt and Delivery Point all equipment, necessary to
determine gas volume and energy as well as pressure, temperature, gross heating
value, quality, relative density and super-compressibility.
3.2 Company will establish necessary metering, dispatch and
operating procedures to provide information required by Company, Shipper or
other affected parties.
3.3 The gas shall be metered by custody transfer type apparatus
acceptable to the parties and to Consumer and Corporate Affairs Canada. All
measuring equipment, devices and material required shall be compatible with the
quantities to be metered at the particular point, and shall be of a type
approved for their intended use under the provisions of the Electricity and Gas
Inspection Act being Chapter E-4 of the Revised Statues of Canada, 1985 as
amended (hereinafter referred to as GIA), where such approvals are applicable.
3.4 At each Shipper's Receipt Point, and Delivery Point, Shipper,
at its own expense, may cause to be furnished, installed, maintained and
operated check measuring equipment, provided that such equipment does not
interfere with the operations of the measuring equipment installed or caused to
be installed by Company and the transportation of gas hereunder. All
non-company measuring equipment, devices and material installed in Company
Facilities shall be compatible with the quantities to be metered at the
particular point, and shall be of a type approved for their intended use under
the provisions of GIA where such approvals are applicable.
Effective: April 1, 1991
<PAGE> 27
Sheet 79
3.5 The unit of volume for purposes of measurement shall be one
thousand cubic metres (10(3)m(3)).
3.6 All measurements, calculations and procedures used in
determining the volume delivered at any point shall be in accordance with GIA
and all applicable regulations issued pursuant thereto. Provided, however,
that correction for deviations from Boyle's Law shall be determined from data
contained in the "American Gas Association Manual for the Determination of
Super Compressibility Factors for Natural Gas, AGA No. 8" or "Par Research
Project NX-19" as published by the American Gas Association in 1962, or any
subsequent revision thereof acceptable to Company and Shipper.
3.7 For the purposes of measurement the atmospheric pressure at
any Receipt Point or Delivery Point shall be fixed by agreement between Shipper
and Company and by a method that meets the requirements of the GIA.
3.8 The gas characteristics, including gross heating value,
relative density, and nitrogen and carbon dioxide content of the gas tendered
by Shipper to Company for transportation at the Receipt Point or delivered by
Company at the Delivery Point shall be determined, where applicable, by
recording equipment approved for this use under the provisions of the GIA.
The gas characteristics used in computing gas measurement
shall be:
(a) The actual "real time" value determined when continuous
analyzing equipment supplies live data of the gas
characteristics to the real time measurement computer
equipment; or
(b) the arithmetical average recorded each day or part thereof if
continuous recording equipment is otherwise used; or
Effective: April 1, 1991
<PAGE> 28
Sheet 80
(c) where sampling is utilized, determinations available from
analyses of such samples.
3.9 The parties hereto shall preserve all original test data and
records, including where applicable charts, in such party's possession for a
period compatible with record retention rules of any governmental agencies
having jurisdiction thereover, except that the parties hereto agree that such
records shall be retained for a minimum period of six (6) years.
Effective: April 1, 1991
<PAGE> 29
Sheet 81
Article IV
MEASURING INSPECTION
4.1 The accuracy of Company's measuring equipment shall be
verified at monthly intervals or at such larger intervals as the Company and
the Shippers may agree. Advance notice of the time and nature of each test
shall be given to allow shipper a reasonable amount of time to arrange for a
representative to observe the test and any adjustments resulting from such
tests. If, after notice, Shipper fails to have a representative present, the
results of the test shall nevertheless be considered accurate until the next
test.
4.2 If, as a result of any such tests any of the measuring
equipment is found to be out of service or registering inaccurately in
comparison to Company's calibration equipment, it shall be adjusted at once to
read as accurately as possible. If such equipment is out of service or
inaccurate such that it causes a measurement error or an energy basis of less
than one-half of one percent, a correction may be made at Company's option. If
such measurement error is greater than or equal to one-half of one percent as
aforesaid, then the previous readings of such equipment shall be corrected to
zero error for a period agreed upon, or if not as agreed upon, for a period of
one-half (1/2) of the elapsed time since the last test. The volume of gas
delivered during such period shall be determined by Company using one of the
following four (4) methods, which in the opinion of the Company will provide
the most accurate results:
(a) by using the data recorded by any check measuring equipment if
installed and accurately registering; or
Effective: April 1, 1991
<PAGE> 30
Sheet 82
(b) by correcting the error if ascertainable by calibration test
or mathematical calculation; or
(c) by estimating the quantity delivered based upon deliveries
under similar conditions during a period when the equipment
was registering accurately; or
(d) by calculation of the balance between Company's receipts and
deliveries over the period.
4.3 If Shipper requests a special test of accuracy of any
measuring equipment and upon testing the equipment the inaccuracy of the
equipment is found to be less than one (1) percent, Shipper shall bear the
expense of such special test.
4.4 Shipper or Shipper's agent shall have the right to inspect, at
Shipper's expense, Company furnished or installed measuring equipment and other
Company measurement or test data including, where applicable, charts at all
times during normal business hours, but the reading, calibration and adjustment
of such equipment and, where applicable, the changing of charts shall be done
only by Company or Company's agent.
4.5 The parties hereto shall exchange, upon request of either
party, copies of all measuring and testing data and information including,
where applicable, charts as soon as practicable for any such requests.
Effective: April 1, 1991
<PAGE> 31
Sheet 83
Article V
COMPANY USE GAS
5.1 Shipper's share of Company Use Gas shall be provided by
Shipper in kind, or by Company pursuant to paragraph 5.3 of this Article V.
Shipper's share of Company Use Gas on any day shall be the total Company Use
Gas for the month in which such day falls divided by the days in such month,
multiplied by Shipper's volume delivered by Company on such day and by
Shipper's Haul Distance, and divided by the sum of the products of all
shippers' volumes delivered by Company on such day and such shippers' Haul
Distances.
5.2 Shipper shall have the right, exercisable by notice to Company
at least 60 days prior to the Service Availability Date to supply in kind its
share of Company Use Gas. This election shall apply to each subsequent
Contract Year unless the Shipper provides the Company with notice to the
contrary at least 60 days prior to the start of any subsequent Contract Year.
5.3 If Shipper elects not to exercise its right to supply
Shipper's share of Company Use Gas, Company may, at its option, either:
(a) supply Shipper's share of Company Use Gas and bill Shipper for
the quantity supplied at the price set out in paragraph 5.4 of
this Article V, or
(b) take Shipper's share in kind from the volumes transported by
Company for Shipper.
5.4 In the event that Company provides Shipper's share of Company
Use Gas the price to be charged Shipper by Company for such gas volumes shall
be the price set out in Company's currently effective Statement of Effective
Rates and Charges.
Effective: April 1, 1991
<PAGE> 32
Sheet 84
Article VI
BILLING AND PAYMENT
6.1 On or before the twentieth (20th) day of a month, beginning
with the twentieth (20th) day of the month immediately following the month in
which the Service Availability Date occurs, Company shall render a bill to
Shipper for the prior month. When information necessary for billing by Company
is in control of Shipper, Shipper shall furnish such information to Company on
or before the fifth (5th) day of the month in connection with services rendered
during the prior month.
6.2 Shipper shall make payment of such bill to Company on or
before the last day of such month.
6.3 If presentation of a bill by Company is delayed after the
twentieth (20th) day of the month, then the time for payment shall be extended
correspondingly, unless Shipper is responsible for such delay.
6.4 Interest on Unpaid Amounts
Except where presentation of the bill is delayed under
paragraph 6.3 or as provided under paragraph 6.5, Company shall have the right
to charge interest on the unpaid portion of any bill commencing with the date
payment was due and continuing until the date payment is actually made. The
initial rate of interest to be charged by Company shall be the rate of interest
which is (2%) percent over and above the Prime Rate quoted by the Royal Bank of
Canada on the first day of the quarter during which such unpaid portion of the
bill becomes due. The first day of the quarter during each year shall be
deemed to be the first day of January, April, July and October, as the case may
be. The rate of interest in effect during a prior quarter, with respect
Effective: April 1, 1991
<PAGE> 33
Sheet 85
to any amounts owning in such prior quarter which remain outstanding in the
following quarter, shall be adjusted effective the first day of the following
quarter to the interest rate which is two (2%) percent over and above the Prime
Rate in effect on the first day of such following quarter.
6.5 Adjustment Where Bill Estimated
Information used for billing may be actual or estimated. If
actual information necessary for billing is unavailable to Company sufficiently
in advance of the twentieth (20th) day of the month to permit the use of such
information in the preparation of a bill, Company shall use reasonably
estimated information. In the month that actual information becomes available
respecting a previous month where estimated information was used, the bill for
the month in which the information became available shall be adjusted to
reflect the difference between the actual and estimated information. Neither
Company nor Shipper shall be entitled to interest on any adjustment.
6.6 Adjustment of Underpayment, Overpayment or Error in Billing
(a) In the event that an error is discovered in any bill rendered
by Company to Shipper for transportation services on Company's
Facilities, the amount of such error shall be adjusted,
provided that claim therefore 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.
(b) In the event that an overpayment has been made, Company shall
make reimbursement of such overpayment. Shipper shall be
entitled to interest on the amount of such overpayment from
the time such overcharge was paid to the date of
reimbursement. The initial rate of interest shall be
determined as set forth in paragraph 6.4 of this Article VI
and shall be revised with respect to any subsequent quarter
prior to adjustment of error, in the manner set forth for
revision of such initial rate in such paragraph 6.4
Effective: April 1, 1991
<PAGE> 34
Sheet 86
(c) In the event of an undercharge, Shipper shall pay the amount
of any such undercharge to Company but without interest. Such
amount shall be payable on the same terms and conditions as
all amounts payable by Shipper to Company.
6.7 In the event Shipper disputes in good faith any part of a
monthly bill, Shipper shall nevertheless pay to Company the full amount of the
bill within the time such payment is due together with a statement of and
explanation respecting the amount so disputed. Company shall segregate that
portion of the payment in dispute from its general funds by placing such
portion in a separate account to be held in trust by Company pending resolution
of the dispute.
6.8 In the event Shipper fails to pay the full amount of any bill
within (30) days after payment is due, Company, in addition to any other remedy
it may have, may suspend receipt and delivery of gas until full payment is
made. Such suspension shall not relieve Shipper from any obligation to pay any
charge payable hereunder to Company.
If Shipper's failure to pay the full amount outstanding in
respect of any month bill shall continue after such suspension, Company may,
in addition to any other remedy Company may have, terminate Shipper's Service
Agreement effective on the date of the delivery of written notice by the
Company to Shipper of such termination.
Effective: April 1, 1991
<PAGE> 35
Sheet 87
Article VII
POSSESSION OF GAS AND RESPONSIBILITY
7.1 Gas received by Company for Shipper for transporting shall be
deemed to be in the custody and under the control of Company from the time such
gas is accepted for transportation at the Receipt Point until delivered by
Company to Shipper at the Delivery Point.
7.2 As between Shipper and Company, Company shall be responsible
for all gas received from Shipper between the time such gas is received by it
from Shipper at the Receipt Point until the time gas is delivered to Shipper by
Company at the Delivery Point, and at no other time.
Effective: April 1, 1991
<PAGE> 36
Sheet 88
Article VIII
WARRANTY OF ELIGIBILITY FOR TRANSPORTATION
8.1 Shipper shall provide such assurances and information as
Company may reasonably require respecting any service to be provided by Shipper
including, without limiting the generality of the foregoing, an assurance that
all necessary arrangements have been made among Shipper, sellers of gas to
Shipper, purchasers of gas from Shipper and transporters of Shipper's gas to,
and from Company's Facilities.
Effective: April 1, 1991
<PAGE> 37
Sheet 89
Article IX
OPERATING PROVISIONS
9.1 Shipper shall advise Company, at the times noted under (a),
and (b) below of the gas volumes which it contemplates delivering to Company
for transportation. Such advice, hereinafter called Nomination, shall be
transmitted to Company on a completed Nomination form transmitted
electronically, by personal delivery, or by mail.
(a) For the purpose of scheduling commencement of initial
transportation service, Shippers Nomination must be received
by Company five (5) business days prior to the day on which
Shipper desires service to commence, or such lesser period of
time agreed to by Company.
(b) For the purpose of scheduling any change in transportation
volumes during a month, Company must receive Shipper's
Nomination indicating amendments to transportation volumes and
their effective dates no later than 12:00 noon Pacific time on
the day prior to the first date of delivery of volumes
provided for in such nomination.
9.2 All Nominations received by Company shall remain in effect,
whether or not deliveries are made, until an amended Nomination is received by
Company pursuant to paragraph 9.1.
9.3 Not less than three (3) months prior to the commencement of
Shipper's first and each subsequent Contract year, Shipper shall furnish to
Company, on Company's request, estimates of Shipper's monthly requirements for
gas deliveries for such Contract Year and estimates of Shipper's annual
requirements for deliveries for each of the following two (2) Contact years.
Such estimates shall not effect Shipper's right to have its Maximum Day
Delivery Quantity transported hereunder.
Effective: April 1, 1991
<PAGE> 38
Sheet 90
9.4 All Nominations shall be delivered to:
Alberta Natural Gas Company Ltd.
#2900, 240 Fourth Avenue S.W.
Calgary, Alberta, Canada
T2P 4L7
Phone: (403) 691-7818
Fax: (403) 691-7817
9.5 In the event that Company determines that it has delivered
more or less gas to Shipper at the Delivery Point, than it has received from
Shipper at the Receipt Point, Company shall advise Shipper of such discrepancy.
Company shall thereafter have the right to adjust receipts or deliveries or
both until such discrepancy is resolved. Company shall not adjust receipts to
cancel excess deliveries for which Shipper has paid a charge pursuant to
paragraph 3.5 of Service Schedule FS-1.
9.6 (a) Shipper's Share of Company's Line Pack Requirements shall be
provided by Shipper in kind or by Company pursuant to
paragraph 9.6 (c) of this Article IX.
(b) Shipper shall have the right exercisable by notice to Company
at least 60 days prior to the Service Availability Date to
supply in kind Shipper's Share of Company Line Pack
Requirements. This election shall apply to each subsequent
Contract year unless the Shipper provides the Company with
notice to the contrary at lest 60 days prior to the start of
any subsequent Contract Year.
Effective: April 1, 1991
<PAGE> 39
Sheet 91
(c) If Shipper elects not to exercise its right to supply
Shipper's Share of Company's Line Pack Requirements, Company
may purchase such quantity of line pack from Shipper, or if
Company can purchase line pack at a price lower than the price
quoted by Shipper, Company may purchase Shipper's share from
the lower priced source.
(d) Company's investment in line pack shall be added to Company's
rate base but Company shall not depreciate such investment.
(e) Variations from day to day in Company's Line Pack Requirements
shall be taken from, or delivered to, shippers pursuant to
Article V of this General Terms and Conditions.
9.7 Company will, at the request of Shipper and subject to
operational constraints on the Company's Facilities, divert the volume of gas
Shipper is authorized to receive on any day under an FS-1 Service Agreement to
a point which is upstream of the Delivery Point, provided that Shipper will pay
to Company the same monthly demand charge which would have been otherwise
payable had such diversion not occurred.
Effective: April 1, 1991
<PAGE> 40
Sheet 92
Article X
RECEIPT AND DELIVERY POINT GAS PRESSURES
10.1 Shipper shall deliver the gas to Company at the Receipt Point
at 4200 kPa, or, with Company's agreement, at such pressure as will enable the
gas to enter Company's Facilities, but in no event shall Shipper be required to
deliver the gas at a pressure greater than 5826 kPa.
10.2 Shipper recognizes that Company will be transporting the gas
in a commingled stream to the Delivery Point and that the pressure of the gas
delivered at the Delivery Point will be the pressure of such commingled stream;
provided that Company shall deliver the gas to shipper at the Delivery Point at
a pressure not less than 5500 kPa.
Effective: April 1, 1991
<PAGE> 41
Sheet 93
Article XI
SERVICE PRIORITIES, INTERRUPTION AND CURTAILMENT
11.1 All firm service shippers who are receiving transportation
service shall have equal priorities of service. In the event that Company's
pipeline capacity is constrained by the need to effect any repairs,
maintenance, replacement or upgrading or other work related to Company's
Facilities, or for any other reason such that all firm service volumes cannot
be delivered, Company shall first interrupt all deliveries under interruptible
service agreements and shall then act to maximize its total deliveries under
firm service agreements. If curtailments continue to be required, Company
shall curtail all firm service deliveries pro rata with the Maximum Day
Delivery Quantity of each shipper.
11.2 If capacity remains in Company's Facilities after first
meeting all firm service nominations, Company shall transport gas requested
by shippers pursuant to paragraph 4 Make-Up Provision, of Service Schedule
FS-1. If additional capacity remains, Company shall transport gas under
interruptible service agreements. Interruptible volumes shall be transported
on a priority ranking as described in Service Schedule IS-1.
11.3 Company may interrupt, curtail or reduce service for such
periods of times as it may reasonably require for the purpose of effecting any
repairs, maintenance, replacement or other upgrading, or other work related to
Company's Facilities. Company shall give firm shippers at least three (3) days
notice of such interruptions or curtailments or, in the event of unforeseen
circumstances, such shorter notice as it is reasonably possible for Company to
give. Company shall consult annually with shippers respecting the scheduling
of major maintenance programs.
Effective: April 1, 1991
<PAGE> 42
Sheet 94
11.4 Shipper and Company shall give each other as much notice as is
reasonably possible in the circumstances of unexpected temporary changes in the
rates of delivery or receipt of gas, pressures or any other operating
conditions, together with the expected duration and the reason for such
expected temporary changes.
11.5 Shipper acknowledges and agrees with Company that any
interruption or curtailment shall not suspend or relieve Shipper from the
obligation to pay any demand charge, surcharge, or any other amount payable to
Company, except as provided in paragraph 3.6 of Service Schedule FS-1.
Effective: April 1, 1991
<PAGE> 43
Sheet 95
Article XII
DELIVERY OBLIGATION
12.1 Company's delivery obligation for any period where Shipper has
exercised its right as provided in paragraph 5.2 shall be to deliver to Shipper
at Shipper's Delivery Point, the volume of gas which has the aggregate energy
content of gas received from Shipper in such period at Shipper's Receipt Point,
less Shipper's share of Company Use Gas as determined under paragraph 5.1.
Company's delivery obligation for any period where Company has exercised its
option to supply Shipper's share of Company's requirements as provided for in
paragraph 5.3 (a), shall be to deliver to Shipper at Shipper's Delivery Point
the volume of gas which has the aggregate energy content of gas received from
Shipper in such period at Shipper's Receipt Point.
12.2 Gas delivered by Company to Shipper at Shipper's Delivery
Point shall have the heating value and the quality that results from the gas
having been transported and commingled with gas belonging to others in
Company's Facilities.
12.3 All deliveries of gas to Company at a Receipt Point shall be
made in uniform hourly quantities to the extent practicable.
Effective: April 1, 1991
<PAGE> 44
Sheet 96
Article XIII
FORCE MAJEURE
13.1 As utilized herein, force majeure shall mean any act of God,
strikes, lockouts, or other industrial disturbances, acts of the Queen's
enemies, sabotage, wars, blockades, insurrections, riots, epidemics,
landslides, lightning, earthquakes, floods, storms, fires, washouts, arrests
and restraints of rulers and peoples, civil disturbances, explosions,
breakages, or accidents to machinery or pipelines, hydrate obstructions of
pipelines or appurtenances thereto, inability to obtain materials or equipment,
inability to obtain permits, orders, licenses, certificates or other
authorizations; orders of any court, board or governmental authority having
jurisdiction, any claim by any third party that any covenant or obligation of
such third party is suspended by reason of force majeure, including without
limiting the generality of the foregoing any such claim by any transporter of
gas to, from or for Company or Shipper; or any other cause, whether of the kind
therein enumerated or otherwise not within the control of the applicable party
or that shall be occasioned by the necessity of making repairs to or
reconditioning machinery, equipment or pipeline facilities not resulting from
the default or negligence of such party and which by the exercise of due
diligence such party is unable to prevent or overcome.
13.2 If either party fails to perform any obligations imposed by
this Agreement and such failure shall be caused or materially contributed to by
any occurrence of force majeure 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. Provided, however,
that the settlement of strikes or lockouts shall be entirely within the
discretion of each party, and that the above requirement that any force majeure
shall be remedied with the exercise of due diligence shall not require the
settlement of strikes or lockouts by acceding to the demands of the opposing
party when such course is inadvisable in the discretion of the appropriate
party.
Effective: April 1, 1991
<PAGE> 45
Sheet 97
13.3 Notwithstanding any other provision herein, no cause
affecting the performance of obligations by any party:
(a) shall relieve any party from its obligations to make payment,
except as provided in paragraph 3.6 of Service Schedule FS-1,
of amounts pursuant to Shipper's Service Agreement;
(b) shall relieve any party from any other obligation unless such
party shall give notice of such cause in writing to the other
party with reasonable promptness and like notice shall be
given upon termination of such cause, nor shall such cause
continue to relieve such party from such other obligation
after the expiration of a reasonable period of item within
which, by the use of due diligence, such party could have
remedied the situation.
13.4 Notwithstanding any other provision herein, Company and
Shipper agree that a lack of funds or other financial cause shall not under any
circumstances be an event of force majeure.
13.5 In the event that the provision of service is curtailed or
interrupted by reason of force majeure Company shall, during the continuance of
such force majeure, curtail or interrupt service in accordance with Article XI
hereof.
Effective: April 1, 1991
<PAGE> 46
Sheet 98
Article XIV
INDEMNIFICATION
14.1 Shipper shall be liable for and shall indemnify and save
harmless Company from and against any and all claims, demands, suits, actions,
damages, costs, losses and expenses of whatsoever nature arising out of or in
any way connected either directly or indirectly, with: (1) any act, omission or
default arising out of the negligence or wilful default of Shipper; and (2) any
adverse claim by any third party claiming ownership of or an interest in the
gas delivered by Shipper to Company at Shipper's Receipt Point.
14.2 Company shall be liable for and shall indemnify and save
harmless Shipper from and against any and all claims, demands, suits, actions,
damages, costs, losses and expenses of whatsoever nature arising out of or in
any way connected, either directly or indirectly with any act, omission or
default arising out of the negligence of wilful default of Company.
14.3 Notwithstanding the provisions of paragraphs 14.1 and 14.2:
(a) Company and Shipper shall have no liability for, nor any
obligation to indemnify and save harmless the other from any
claim, demand, suit, action, damage, cost loss or expense
which is indirect, special or consequential, including but not
so as to limit the generality of the foregoing; loss of profit
or revenue, cost of capital loss for failure to deliver gas,
cost of purchased or replacement gas, cancellation of permits
or termination of contracts (provided that this shall in no
way affect Shipper's obligation to make the payments to
Company provided for in any Service Agreement);
(b) Company shall have no liability, nor obligation to indemnify
and save harmless Shipper in respect of failure for any reason
whatsoever, other than Company's negligence or wilful default,
to accept receipt of, receive or deliver gas pursuant to the
provision of any Service Agreement between Company and
Shipper; and
Effective: April 1, 1991
<PAGE> 47
Sheet 99
(c) Subject to paragraph 3.6 of Service Schedule FS-1, Shipper
shall, notwithstanding any such failure to accept receipt of
or deliver gas, make payment to Company in the amounts, in the
manner and at the times provided in any Service Agreement.
(d) Neither Company nor Shipper shall be liable to indemnify the
other unless the party requesting indemnification shall have
given reasonably prompt notification to the other in writing
of service of any claim, suit or action for or in respect of
which indemnification is to be claimed.
Effective: April 1, 1991
<PAGE> 48
Sheet 100
Article XV
FINANCIAL INFORMATION AND SECURITY
15.1 Shipper shall provide Company with any financial information
Company reasonably requests prior to Company providing service and prior to any
extension of the term of any Service Agreement in order that Company may
establish Shipper's creditworthiness.
15.2 Company may request Shipper to provide to Company, as a
condition to the provision or extension of service or any assignment of a
Service Agreement, such financial security as Company may reasonably require.
15.3 In addition to the foregoing, at any time during the term of
service that Company determines that it has a reasonable basis for concern
respecting Shipper's creditworthiness, Company may request, and Shipper shall
provide, an irrevocable letter of credit in an amount equal to the monthly
demand charge set forth in Article 3.1 of Service Schedule FS-1 multiplied by
three.
Effective: April 1, 1991
<PAGE> 49
Sheet 101
Article XVI
MISCELLANEOUS PROVISIONS
16.1 No default in the performance of any of the obligations of
Company or Shipper, under any Service Agreement, shall operate to terminate
such Agreement, or except as specifically provided in such Agreement, to
relieve Company or Shipper from due and punctual compliance with its
obligations thereunder.
16.2 The division of these General Terms and Conditions into
articles and clauses, the provision of a table of contents hereto and the
insertion of headings are for convenience of reference only and shall not
affect the construction or interpretation of this Document.
16.3 In the interpretation of these General Terms and Conditions
words in the singular shall be read and construed in the plural and words in
the plural shall be read and construed in the singular where the context so
requires.
16.4 Amendments to any Service Agreement must be in writing and
signed by both parties.
16.5 All Service Agreements and all amendments, modifications,
alternations or supplements thereto shall be governed by the laws in force in
the Province of Alberta as to the nature, validity and interpretation thereof.
16.6(a) Subject to sub-clauses (b) and (c) of this Article 16.6, the
Service Agreement into which these General Terms and
Conditions are incorporated shall not be assigned in whole
or in part by Shipper without the consent of Company, which
consent shall not be unreasonably withheld.
Effective: April 1, 1991
<PAGE> 1
Exhibit 10.4
FIRM TRANSPORTATION SERVICE AGREEMENT
THIS AGREEMENT is made and entered into this 26th day of October, 1993 by and
between
PACIFIC GAS TRANSMISSION COMPANY, a California corporation (hereinafter
referred to as "PGT"),
and
PACIFIC GAS & ELECTRIC COMPANY, a corporation existing under the laws of the
State of California (hereinafter referred to as "Shipper").
WHEREAS, PGT owns and operates a natural gas interstate pipeline transmission
system which extends from a point of interconnection with the pipeline
facilities of Alberta Natural Gas Company Ltd. (ANG) at the International
Boundary near Kingsgate, British Columbia, through the states of Idaho,
Washington and Oregon to a point of interconnection with Pacific Gas and
Electric Company at the Oregon-California border near Malin, Oregon; and
WHEREAS, Shipper desires PGT, on a firm basis, to transport certain
quantities of natural gas from Kingsgate, British Columbia to Malin, Oregon for
ultimate delivery to Shipper, a local distribution company; and
WHEREAS, puruant to FERC Order No. 636, et. seq., PGT will unbundle its firm
transportation and sales services, and PGT and Shipper will execute a new
service agreement for unbundles firm transportation service; and
WHEREAS, this Agreement will supersede any prior agreements between PGT and
Shipper for firm gas sales or firm transportation,and willincorporate the
transportation rights thereunder into this Agreement; and
WHEREAS, PGT is willing to transport certain quantities of natural gas for
Shipper, on a firm basis,
NOW, THEREFORE, the parties agree as follows:
I
GOVERNMENTAL AUTHORITY
1.1 This Firm Transportation Agreement ("Agreement") is made pursuant to the
regulations of the Federal Energy Regulatory Commission (FERC) contained in 18
CFR Part 284, as amended from time to time.
<PAGE> 2
I
GOVERNMENTAL AUTHORITY
(continued)
1.2 This Agreement is subject to all valid legislation with respect to the
subject matters hereof, either state or federal, and to all valid present and
future decisions, orders, rules, regulations and ordinances of all duly
constituted governmental authorities having jurisdiction.
1.3 Shipper shall reimburse PGT for any all filing fees incurred by PGT in
seeking governmental authorization for the initiation, extension, or
termination of service under this Agreement and Rate Schedule FTS-1. Shipper
shall reimburse PGT for such fees at PGT's designated office within ten (10)
days of receipt of notice from PGT that such fees are due and payable.
Additionally, Shipper shall reimburse PGT for any and all penalty fees or fines
assessed PGT caused by the negligence of Shipper in not obtaining all proper
Canadian and domestic import/export licenses, surety bonds or any other
documents and approvals related to the Canadian exportation and subsequent
domestic importation of natural gas transported by PGT hereunder.
II
QUANTITY OF GAS AND PRIORITY OF SERVICE
2.1 Subject to the terms and provisions of this Agreement and PGT's
Transportation General Terms and Conditions contained in PGT's FERC Gas Tariff
First Revised Volume No. 1-A (Transportation General Terms and Conditions)
applicable to Rate Schedule FTS-1, daily receipts of gas by PGT from Shipper at
the point(s) of receipt shall be equal to daily deliveries of gas by PGT to
Shipper at the point(s) of delivery; provided, however, Shipper shall deliver
to PGT an additional quantity of natural gas at the point(s) of receipt as
compressor station fuel, line loss and unaccounted for gas as specified in the
Statement of Effective Rates and Charges of PGT's FERC Gas Tariff First Revised
Volume No. 1-A which by this reference is made a part hereof. Any limitations
of the quantities to be received from each point of delivery shall be as
specified on the Exhibit A attached hereto.
2.2 The maximum quantities of gas to be delivered by PGT for Shipper's
account at the point(s) of delivery are set forth in Exhibit A.
2.3 In providing service to its existing or new customers, PGT will use the
priorities of service specified in Paragraph 18 of PGT's Transportation General
Terms and Conditions on file with the FERC.
2.4 Prior to initiation of service, Shipper shall provide PGT with any
information required by the FERC, as well as the information identified in
Paragraphs 21, 28, and 29 of PGT's Transportation General Terms and Conditions
applicable to Rate Schedule FTS-1.
2
<PAGE> 3
III
TERM OF AGREEMENT
3.1 This Agreement shall become effective November 1, 1993, and shall
continue in full force and effect until October 31, 2005. Thereafter, this
Agreement shall continue in effect from year to year unless Shipper gives PGT
twelve (12) months prior written notice of termination of this Agreement. The
Agreeement shall terminate twelve (12) months after such notice.
IV
POINTS OF RECEIPT AND DELIVERY
4.1 The primary point of receipt of gas deliveries to PGT is as designated
in Exhibit A, attached hereto.
4.2 The primary point of delivery of gas to Shipper is as designated in
Exhibit A, attached hereto.
4.3 Shipper shall deliver or cause to be delivered to PGT the gas to be
transported hereunder at pressures sufficient to deliver such gas into PGT's
system at the point(s) of receipt. PGT shall deliver the gas to be transported
hereunder to or for the account of Shipper at the pressures existing in PGT's
system at the point(s) of delivery.
4.4 Pursuant to Paragraph 28 of PGT's Transportation General Terms and
Conditions, Shipper may designate other receipt and/or delivery points as
secondary receipt or delivery points.
V
OPERATING PROCEDURES
5.1 Shipper shall conform to the operating procedures set forth in PGT's
Transportation General Terms and Conditions.
5.2 Nothing in Section 5.1 shall compel PGT to transport gas pursuant to
Shipper's request on any given day. PGT shall have the right to interrupt or
curtail the transport of gas for the account of Shipper pursuant to PGT's
Transportation General Terms and Conditions applicable to Rate Schedule FTS-1.
3
<PAGE> 4
VI
RATE(S), RATE SCHEDULES, AND
GENERAL TERMS AND CONDITIONS OF SERVICE
6.1 Shipper shall pay PGT each month for services rendered pursuant to this
Agreement in accordance with PGT's Rate Schedule FTS-1, or superseding rate
schedule(s) on file with and subject to the jurisdiction of the FERC.
6.2 Shipper shall compensate PGT each month for compressor station fuel,
line loss and other unaccounted for gas associated with this transportation
service provided herein in accordance with PGT's Rate Schedule FTS-1, or
superseding rate schedule(s), on file with and subject to the jurisdiction of
the FERC.
6.3 This Agreement in all respects shall be and remains subject to the
applicable provisions of Rate Schedule FTS-1, or superseding rate schedule(s)
and of the applicable Transportation General Terms and Conditions of PGT's FERC
Gas Tariff, First Revised Volume No. 1-A on file with the FERC, all of which
are by this reference made a part hereof.
6.4 PGT shall have the unilateral right from time to time to propose and
file with the FERC such changes in the rates and charges applicable to
transportation services pursuant to this Agreement, the rate schedule(s) under
which this service is hereunder provided, or any provisions of PGT's
Transportation General Terms and Conditions applicable to such services.
Shipper shall have the right to protest any such changes proposed by PGT and to
exercise any other rights that Shipper may have with respect thereto.
VII
MISCELLANEOUS
7.1 This Agreement shall be interpreted according to the laws of the State
of California.
7.2 Shipper agrees to indemnify and hold PGT harmless for refusal to
transport gas hereunder in the event any upstream or downstream transporter
fails to receive or deliver gas as contemplated by this Agreement.
4
<PAGE> 5
VII
MISCELLANEOUS
(continued)
7.3 Unless herein provided to the contrary, any notice called for in this
Agreement shall be in writing and shall be considered as having been given if
delivered by registered mail or telex with all postage or charges prepaid, to
either PGT or Shipper at the place designated below. Routine communications,
including monthly statements and payment, shall be considered as duly delivered
when received by ordinary mail. Unless changed, the addresses of the parties
are as follows:
"PGT" PACIFIC GAS TRANSMISSION COMPANY
Room 1900
160 Spear Street
San Francisco, California 94105-1570
Attention: President & CEO
"Shipper" PACIFIC GAS & ELECTRIC COMPANY
77 Beale Street, Room 1611
Mail Code: B16A, PO Box 770000
San Francisco, CA 94177
Attention: Manager, Gas Services Department
7.4 A waiver by either party of any one or more defaults by the other
hereunder shall not operate as a waiver of any future default or defaults,
whether of a like or of a different character.
7.5 This Agreement may only be amended by an instrument in writing executed
by both parties hereto.
7.6 Nothing in this Agreement shall be deemed to create any rights or
obligations between the parties hereto after the expiration of the term set
forth herein, except that termination of this Agreement shall not relieve
either party of the obligation to correct any quantity imbalances or Shipper of
the obligation to pay any amounts due hereunder to PGT.
7.7 Exhibits A and C attached hereto are incorporated herein by refernce and
made a part hereof for all purposes.
5
<PAGE> 6
IN WITNESS WHEREOF the parties hereto have caused this Agreement to be
executed as of the day and year first above written.
PACIFIC GAS TRANSMISSION COMPANY
By: Paula G. Rosput
Name: Paula G. Rosput
Title: Senior Vice President
Date: October 26, 1993
PACIFIC GAS & ELECTRIC COMPANY
By: William R. Mazotti
Name: William R. Mazotti
Title: Vice President-Gas
Services Operations
Date: October 26, 1993
6
<PAGE> 7
EXHIBIT A
to the
FIRM TRANSPORTATION SERVICE AGREEMENT
Dated _________________________________ Between
PACIFIC GAS TRANSMISSION COMPANY
And
PACIFIC GAS & ELECTRIC COMPANY
Receipt Delivery Maximum Daily Quantity (MDQ)
Point(1) Point(1) (Delivered) MMBtu/d
Summer(2) Winter(3)
Kingsgate, Malin, 1,023,120(4) 1,081,990
British Columbia Oregon
(1) Pursuant to Paragraph 29 of PGT's Transportation General Terms and
Conditions, Shipper may designate other receipt and delivery points as
"secondary receipt" and "secondary delivery" points. For example, Shipper
may designate Stanfield, Oregon and/or Spokane, Washington as secondary
receipt points.
(2) Summer -- months of May through October.
(3) Winter -- months of November through April.
(4) In accordance with FERC's October 1, 1993, order at Docket No. RS92-46
Shipper's firm summer MDQ (Delivered) may exceed 1,023,120 MMBtu/d to the
extent firm capacity is available on PGT's original system. However, under
no circumstances may Shipper's firm Summer MDQ (Delivered) exceed 1,081,990
MMBtu/d.
7
<PAGE> 8
EXHIBIT C
to the
FIRM TRANSPORTATION SERVICE AGREEMENT
Dated _________________________________ Between
PACIFIC GAS TRANSMISSION COMPANY
And
PACIFIC GAS & ELECTRIC COMPANY
Type of Replacement Service:
Replacement Shipper:
Receipt Point:
Delivery Point:
Maximum Daily Quantity:
Commencment of Credit:
Termination of Credit:
Level of Credit: _____ percent of the maximum rate defined as
_______________________________________________
_______________________________________________
_______________________________________________
applicable for service under Rate Schedule FTS-1
Other Terms and Conditions:
(1) ________________________________________________________________________
(2) ________________________________________________________________________
(3) ________________________________________________________________________
8
<PAGE> 9
PACIFIC GAS TRANSMISSION COMPANY
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 and redeliver an amount equal to the quantity received less
applicable compressor station fuel, line loss and other unaccounted for gas
associated with the specific transportation service. 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.
3. RATES
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.
<PAGE> 10
RATE SCHEDULE FTS-1
FIRM TRANSPORTATION SERVICE
(Continued)
3. RATES (Continued)
3.2 Reservation Surcharge
Shippers converting to firm transportation under Rate Schedule
FTS-1 from Rate Schedules T-1, 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-1, 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.
3.3 Firm Transportation Charge
The monthly Firm Transportation Charge shall be the product of the
following:
(a) The quantities of gas 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.
<PAGE> 11
RATE SCHEDULE FTS-1
FIRM TRANSPORTATION SERVICE
(Continued)
3. RATES (Continued)
3.4 Delivery Rate Surcharge
Shippers converting from Rate Schedule T-3 of PGT's Second Revised
Volume No. 1 tariff shall receive a credit calculated as the
product of the 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 Surcharge is 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.
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.
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.
<PAGE> 12
RATE SCHEDULE FTS-1
FIRM TRANSPORTATION SERVICE
(Continued)
3. RATES (Continued)
3.8 Direct Bills
PG&E shall pay a Direct Bill for 100% of the costs allocated to the
Direct Bill portion of Approved Gas Supply Restructuring (GSR)
Costs excluding the amount to be collected from the Northwest
Shippers as defined in Paragraph 30 of the Transportation General
Terms and Conditions and credited against the Direct Bill portion
of Approved GSR Costs as defined in Paragraph 30 of the
Transportation General Terms and Conditions. In accordance with
Paragraph 30.5(b) of the Transportation General Terms and
Conditions, PG&E may elect to pay its Direct Bill in a lump sum or
select one of three payment plans as shown on the Statement of
Rates and Charges for Transportation of Natural Gas.
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.
<PAGE> 13
RATE SCHEDULE FTS-1
FIRM TRANSPORTATION SERVICE
(Continued)
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.
4. FUEL AND LINE LOSS
Shipper shall furnish to PGT quantities of gas for compressor station fuel,
line loss and other utility purposes, plus other unaccounted for gas used
in the operation of PGT's combined pipeline system between the
International Boundary near Kingsgate, British Columbia and the
Oregon-California boundary for the transportation quantities of gas
delivered by PGT to Shipper, based upon the effective fuel and line loss
percentages in accordance with Paragraph 37 of the General Terms and
Conditions.
5. TRANSPORTATION GENERAL TERMS AND CONDITIONS
All of the Transportation General Terms and Conditions except Paragraph 19
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.
<PAGE> 14
PACIFIC GAS TRANSMISSION COMPANY
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
(Continued)
</TABLE>
<PAGE> 15
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" shall mean the maximum daily
quantity in MMBtu of gas which PGT agrees to receive inclusive
of an allowance for compressor station fuel, line loss and
other unaccounted for gas and transport for the account of
Shipper on each day during each year during the term of
Shipper's Transportation Service Agreement with PGT.
1.4 The term "marketing affiliate" shall mean Pacific Gas and
Electric Company.
1.5 The word "gas" shall mean natural gas.
1.6 The term "cubic foot of gas" shall mean that quantity of gas
which, at a temperature of sixty degrees (60 degrees)
Fahrenheit and at a pressure of 14.73 pounds per square inch
absolute, occupies one (1) cubic foot.
1.7 The term "Mcf" shall mean one thousand (1,000) cubic feet of
gas and shall be measured as set forth in Paragraph 5 hereof.
The term "MMcf" shall mean one million (1,000,000) cubic feet
of gas.
1.8 The term "Btu" shall mean British Thermal Unit. The term
"MMBtu" shall mean one million (1,000,000) British Thermal
Units.
1.9 The term "gross heating value" shall mean the number of
Btu's in a cubic foot of gas at a temperature of sixty degrees
(60 degrees) Fahrenheit, saturated with water vapor, and at an
absolute pressure equivalent to thirty (30) inches of mercury
at thirty-two degrees (32 degrees) Fahrenheit.
1.10 The term "psig" shall mean pounds per square inch gauge.
(Continued)
<PAGE> 16
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)
<PAGE> 17
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 Deals C and D during which
the Prearranged Shipper may match the highest bid(s) any higher
bids for the Parcel.
(Continued)
<PAGE> 18
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)
<PAGE> 19
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 delivered hereunder shall have a
gross heating value of not less than nine hundred
seventy-five (975) Btus per cubic foot, but with the
consent of Shipper, PGT may deliver gas at a lower gross
heating value.
(b) Freedom from Objectionable Matter: The gas delivered
hereunder:
(1) Shall be commercially free from sand, dust, gums,
crude oil, impurities and other objectionable
substances which may be injurious to pipelines or
which may interfere with its transmission through
pipelines or its commercial utilization.
(2) Shall not have a hydrocarbon dew-point in excess of
fifteen degrees (15 degrees) Fahrenheit at pressures
up to eight hundred (800) psig.
(3) Shall not contain more than one-quarter (1/4) grain
of hydrogen sulfide per one hundred (100) cubic
feet.
(4) Shall not contain more than ten (10) grains of total
sulphur per one hundred (100) 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) cubic feet.
(7) Shall not exceed one hundred ten degrees (110
degrees) Fahrenheit in temperature at the point of
delivery.
(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 (.04%) by volume of oxygen.
(Continued)
<PAGE> 20
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 1826-83 or any
subsequent revisions. Analysis of gas with gas
chromatographs shall comply with the standards set forth
in ASTM D 1945-81 or any subsequent revisions.
Calculation of the gross heating value from compositional
analysis by gas chromatography shall comply with the
standards set forth in ASTM D 3588-81 or any subsequent
revisions.
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)
<PAGE> 21
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)
<PAGE> 22
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)
<PAGE> 23
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. 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. 7 or any subsequent revision. When displacement
meters are used, 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 chromatographs shall comply with the standards set
forth in ASTM D 1945-81 or any subsequent revision.
Calculation of the specific gravity from compositional analysis
by gas chromatography shall comply with the standards set forth
in ASTM D 3588-81 or any subsequent revision. Measurement of
the specific gravity with a gravitometer shall comply with the
standards set forth in ASTM D 1070-73 or any subsequent
revision.
5.3 Flowing Temperature: The arithmetic average of readings each
day shall be deemed the gas temperature and used in computing
the volumes of gas metered for each day unless another method
is mutually agreed upon by both parties.
(Continued)
<PAGE> 24
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 Rate Schedules FTS-1 and ITS-1: On or before the
twentieth (20th) day of each month, PGT shall render a bill to
each Shipper under Rate Schedule FTS-1 and a bill to each
Shipper under Rate Schedule ITS-1, for the service rendered
during the preceding month.
(Continued)
<PAGE> 25
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
8. PAYMENT
8.1 Payment under Rate Schedules FTS-1 and ITS-1: On or before the
last day of each month, each Shipper under Rate Schedule FTS-1
and each Shipper under Rate Schedule ITS-1 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)
<PAGE> 26
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 involving 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)
<PAGE> 27
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 and 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.
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)
<PAGE> 28
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)
<PAGE> 29
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)
<PAGE> 30
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
18. SCHEDULING OF RECEIPTS AND DELIVERIES
18.1 Priority 1 - Firm Service
Firm transportation service under this FERC Gas Tariff First
Revised Volume No. 1-A shall be provided when, and to the
extent that, firm capacity is available in PGT's existing
facilities.
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 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.
When capacity is constrained at the receipt point,
interruptible transport through that point will be curtailed
first (in reverse order of the first-come, first-served (FCFS)
queue), followed by secondary receipt firm transport (pro rata
based on MDQ) and finally by primary receipt firm transport
(pro rata based on MDQ).
When capacity in constrained along PGT's mainline,
interruptible transport will be curtailed first (in reverse
order of the FCFS queue) followed by all firm transport (pro
rata based on MDQ at that point).
When capacity is constrained at the delivery point,
interruptible transport through that point will be curtailed
first (in reverse order of the FCFS queue), followed by
secondary delivery firm transport (pro rata based on MDQ) and
finally by primary delivery firm transport (pro rata based on
MDQ).
(Continued)
<PAGE> 31
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
18. SCHEDULING OF RECEIPTS AND DELIVERIES (Continued)
18.1 Priority 1 - Firm Service (Continued)
These provisions also apply for capacity released under PGT's
capacity release program, and are subject to the terms and
conditions as specified in 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.
Priority 2 - Interruptible Service
Interruptible transportation service under this FERC Gas Tariff
First Revised Volume No. 1-A shall be provided when, and to the
extent that, capacity is available in PGT's existing
facilities, which capacity is not subject to a prior claim
under a pre-existing contract, service agreement, certificate
or under Priority 1 - Firm Service. PGT will provide
interruptible transportation service among all Shippers
requesting interruptible transportation service, as set forth
in Paragraph 21 of these Transportation General Terms and
Conditions, on a first-come, first-served basis as approved by
the Commission in Docket No. CP87-159-000.
18.2 Reserved.
18.3 If, on any day, PGT determines that 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 18.1, except that mid-gas day
nomination increases by interruptible Shippers shall not bump
those interruptible Shipper's volumes already confirmed for
that gas day.
18.4 Upon termination of the executed Transportation Service
Agreement Shipper's priority of service will terminate.
(Continued)
<PAGE> 32
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
18. SCHEDULING OF RECEIPTS AND DELIVERIES (Continued)
18.5 PGT shall contract with Shippers requesting interruptible
transportation service under this FERC Gas Tariff First Revised
Volume No. 1-A on a first-come, first-served basis.
18.6 A Shipper receiving service under ITS-1 or FTS-1 shall not lose
its priority for purposes of this Paragraph 18 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.
19. OPERATING PROVISIONS FOR INTERRUPTIBLE TRANSPORTATION SERVICE
The provisions of this Paragraph 19 shall be applicable to interruptible
transportation service under Rate Schedule ITS-1 contained in this FERC Gas
Tariff First Revised Volume No. 1-A.
Interruptible transportation service under this FERC Gas Tariff First
Revised Volume No. 1-A shall be provided when, and to the extent that,
capacity is available in PGT's existing facilities, which capacity is not
subject to a prior claim under a pre-existing contract, service agreement,
certificate or under another class of service. Available interruptible
capacity shall be allocated by PGT on a first-come, first-served basis as
provided in Paragraph 18 and as determined by the date and time PGT
receives a completed request for service under this FERC Gas Tariff which
conforms to Paragraph 21 of these Transportation General Terms and
Conditions. 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)
<PAGE> 33
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
19. OPERATING PROVISIONS FOR INTERRUPTIBLE TRANSPORTATION SERVICE (Continued)
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, nor
shall the Shipper's request for service 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.
20. OPERATING PROVISIONS FOR FIRM TRANSPORTATION SERVICE
The provisions of this Paragraph 20 shall be applicable to firm
transportation service under Rate Schedule FTS-1 contained in this FERC Gas
Tariff First Revised Volume No. 1-A. Firm transportation service under
this FERC Gas Tariff 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.
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:
20.1 In order to be eligible for firm capacity, a party requesting
service (requestor) must be deemed credit-worthy per Paragraph
21.7 and submit a valid request in accordance with the
provisions herein.
20.2 PGT will post on its 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 20.3.
(Continued)
<PAGE> 34
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
20. OPERATING PROVISIONS FOR FIRM TRANSPORTATION SERVICE (Continued)
20.3 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 20.5. 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 service requests
are equal, then service shall be offered to such requestors on
a pro-rata basis.
20.4 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.
20.5 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.
(Continued)
<PAGE> 35
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
21. OPERATING PROVISIONS FOR INTERRUPTIBLE AND FIRM TRANSPORTATION SERVICE
21.1 Requests for interruptible and firm transportation service
hereunder shall be made by providing the following information
in writing utilizing PGT's Transportation Request Form to PGT:
PACIFIC GAS TRANSMISSION COMPANY
TRANSPORTATION REQUEST FORM
Gentlemen:
________________________________ (Shipper) hereby requests gas transportation
service from Pacific Gas Transmission Company (PGT) in accordance with
Paragraph 21.1 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)
<PAGE> 36
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
21. OPERATING PROVISIONS FOR INTERRUPTIBLE AND FIRM TRANSPORTATION SERVICE
(Continued)
21.1 (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)
<PAGE> 37
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
21. OPERATING PROVISIONS FOR INTERRUPTIBLE AND FIRM TRANSPORTATION SERVICE
(Continued)
21.1 (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)
<PAGE> 38
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
21. OPERATING PROVISIONS FOR INTERRUPTIBLE AND FIRM TRANSPORTATION SERVICE
(Continued)
21.1 (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)
<PAGE> 39
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
21. OPERATING PROVISIONS FOR INTERRUPTIBLE AND FIRM TRANSPORTATION SERVICE
(Continued)
21.2 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.
21.3 Reserved for future use
21.4 PGT shall not be required to perform or continue service on
behalf of any Shipper that fails to comply with the terms
contained in this Paragraph 21 and any and all terms of the
applicable rate schedule and the terms of Shipper's executed
Transportation Service Agreement with PGT.
21.5 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.
21.6 Nominations: Request for nomination of gas delivery 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
deliveries during the following day. The request by the
downstream Shipper or customer, via the nomination process, for
gas from a designated upstream Shipper and the corresponding
supplier nomination designating the same downstream nomination as
an acceptable customer is PGT's notice that a valid contractual
arrangement between the two parties is in existence. PGT requires
that a valid Shipper designate, in writing, those individuals who
will be authorized to place nominations for gas on the system.
(Continued)
<PAGE> 40
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
21. OPERATING PROVISIONS FOR INTERRUPTIBLE AND FIRM TRANSPORTATION SERVICE
(Continued)
21.6 (Continued)
Requests for nomination may be amended during the gas day provided
the appropriate gas supply adjustment is made at the Shipper's
receipt point. Such amended requests will become effective when
system operating conditions, as determined by PGT, permit the
changes to occur. Requests for nomination are for a daily rate,
and will be delivered at a uniform hourly rate of requested
quantity divided by 24. Requests for nomination, as amended by
Shipper and received by PGT, shall remain in effect, whether or
not deliveries are made, until a new or amended request is
provided by Shipper and received by PGT. PGT reserves the right
to reject any request for nomination that is less than 24 Mcf/day.
PGT's primary method of nomination transmission shall be the
Electronic Bulletin Board (EBB). If and only if, the EBB system
fails between PGT and Shippers shall PGT accept nominations via
alternative means such as fax.
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
(Continued)
<PAGE> 41
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
21. OPERATING PROVISIONS FOR INTERRUPTIBLE AND FIRM TRANSPORTATION SERVICE
(Continued)
21.7 Credit-worthiness
21.7 (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:
(1) The rating will be determined by Standard and Poors or
another recognized U.S. or Canadian debt rating service;
(2) 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)
<PAGE> 42
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
21. OPERATING PROVISIONS FOR INTERRUPTIBLE AND FIRM TRANSPORTATION SERVICE
(Continued)
21.7 (A) Credit-worthiness for Firm Transportation Service (Continued)
(3) 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.
(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:
(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.
(Continued)
<PAGE> 43
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
21. OPERATING PROVISIONS FOR INTERRUPTIBLE AND FIRM TRANSPORTATION SERVICE
(Continued)
21.7 (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)
<PAGE> 44
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
21. OPERATING PROVISIONS FOR INTERRUPTIBLE AND FIRM TRANSPORTATION SERVICE
(Continued)
21.7 (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)
<PAGE> 45
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
21. OPERATING PROVISIONS FOR INTERRUPTIBLE AND FIRM TRANSPORTATION SERVICE
(Continued)
21.7 (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.
21.7 (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)
<PAGE> 46
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
21. OPERATING PROVISIONS FOR INTERRUPTIBLE AND FIRM TRANSPORTATION SERVICE
(Continued)
21.7 (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.
21.8 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.
(Continued)
<PAGE> 47
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
21. OPERATING PROVISIONS FOR INTERRUPTIBLE AND FIRM TRANSPORTATION SERVICE
(Continued)
21.9 A penalty shall be charged by PGT and paid in dollars by any
Shipper who, upon notification by PGT of the existence of an
overage in deliveries and/or takes, fails to correct such daily
overage within a minimum of forty-eight (48) hours, except in
those instances where it is necessary for PGT to protect the
integrity of its system. The applicable penalty shall be
applied if:
(a) The daily quantities exceed 10 percent or 50 MMBtu,
whichever is greater, of Shipper's Maximum Daily
Quantity, as specified in the executed Transportation
Service Agreement.
Penalty: The penalty shall be $5 for each MMBtu of
gas exceeding the 10 percent or 50 MMBtu limits
specified therein. In the event Shipper does not
balance within 45 days, commencing with the third day
after Shipper's receipt of notification from PGT,
PGT shall also charge $5/MMBtu for any remaining net
balance of overdeliveries which exists at the
conclusion of such 45-day period.
(b) The Shipper delivers or causes to be delivered to an
individual delivery point a quantity which, after
appropriate reductions, exceeds by 10 percent or 50
MMBtu, whichever is greater, the quantities received
from PGT for delivery to the delivery point.
Penalty: The penalty shall be $5 for each MMBtu of
gas exceeding the 10 percent or 50 MMBtu limits
specified therein. In the event Shipper does not
balance within 45 days, commencing with the third
day after Shipper's receipt of notification from PGT,
PGT shall also charge $5/MMBtu for any remaining net
balance of overdeliveries which exists at the
conclusion of such 45-day period.
(Continued)
<PAGE> 48
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
21. OPERATING PROVISIONS FOR INTERRUPTIBLE AND FIRM TRANSPORTATION SERVICE
(Continued)
21.9 (Continued)
(c) The Shipper takes quantities from PGT which exceed by
more than 10 percent or 50 MMBtu, whichever is
greater, the quantities received by PGT after
appropriate reductions and the Shipper does not
correct the excess takes in two (2) days or less.
Penalty: The penalty shall be $5/MMBtu which shall
apply to the total remaining net balance at the end
of the 45-day period (inclusive of takes in excess of
the limits occurring prior to commencement of the 45
day period), less any previously assessed penalty
amounts; provided, however, such penalty charge shall
not be less than zero.
(d) The quantity of gas which PGT, at Shipper's request,
has scheduled for delivery to PGT on any day exceeds
the quantity actually delivered to PGT on such day by
10 percent of the scheduled quantity or 50 MMBtu,
whichever is greater.
Penalty: The penalty shall be equivalent to the
otherwise applicable transportation rate multiplied
by the amount by which the quantity scheduled for
delivery to PGT, minus the greater of 10 percent or
50 MMBtu exceeds the actual quantity delivered to
PGT multiplied by the pipeline distance.
21.10 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.
21.11 The payment of a penalty in dollars pursuant to Paragraph 21.9
shall under no circumstances be considered as giving any
shipper the right to deliver or take overrun quantities.
(Continued)
<PAGE> 49
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
21. OPERATING PROVISIONS FOR INTERRUPTIBLE AND FIRM TRANSPORTATION SERVICE
(Continued)
21.12 Balancing of thermally equivalent quantities of gas received and
delivered shall be achieved as nearly as feasible on a daily
basis, with any cumulative imbalance accounted for on a monthly
basis. Imbalances shall be carried forward to the following
month and corrected to the extent possible. PGT and Shipper
shall use their best efforts to eliminate any cumulative
imbalance between receipts and deliveries of gas as soon as
possible but no later than sixty (60) days after the termination
of the Service Agreement. Transportation of gas during this sixty
day period shall be for balancing purposes only.
21.13 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.
21.14 If Shipper fails, within 30 days of the date of PGT's tendering
the Transportation Service Agreement to Shipper, to execute and
deliver to PGT said Agreement, Shipper's transportation request
for service, and its assigned priority date referenced in Section
2.3 of the Agreement, shall be deemed null and void. The date on
which PGT receives the executed Transportation Service Agreement
shall serve to establish Shipper's new assigned priority date.
(Continued)
<PAGE> 50
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
22. ANNUAL CHARGE ADJUSTMENT (ACA) PROVISION
22.1 Purpose: PGT shall recover from Shippers the annual charge
assessedto PGT by the Federal Energy Regulatory Commission for
budgetary expenses pursuant to Section 154.38(d)(6) of the
Commission's regulations and Order No. 472 issued May 29, 1987.
PGT shall recover this charge by means of an Annual Charge
Adjustment (ACA); a per unit rate equivalent to the unit rate
assessed against PGT by the Commission shall be included in PGT's
transportation rates. (During the period that this ACA provision
is in effect, PGT shall not recover in a Natural Gas Act Section 4
rate case annual charges recorded in FERC Account No. 928 assessed
to PGT by the Commission pursuant to Order No. 472.)
22.2 Filing Procedure: The notice period and proposed effective date
of filings pursuant to this paragraph shall be as permitted under
Section 4 of the Natural Gas Act; provided, however, that any such
filing shall not become effective unless they become effective
without suspension or refund obligation.
22.3 ACA Unit Rate Adjustment: PGT's ACA unit rate shall be the unit
rate used by the Commission to determine the annual charge
assessment to PGT, and shall be reflected in the Statement of
Effective Rates and Charges of this FERC Gas Tariff First Revised
Volume No. 1-A.
22.4 Affected Rate Schedules: The ACA provision shall apply to all
rate schedules contained in PGT's FERC Gas Tariff First Revised
Volume No. 1-A.
23. SHARED OPERATING PERSONNEL AND FACILITIES
PGT and its marketing affiliate do not share any operating personnel. PGT
does not share any facilities with its marketing affiliate. To the extent
PG&E elects service under Rate Schedule USS-1, PGT employees involved with
the implementation of USS-1 service will operate independently from PGT's
pipeline operating employees.
(Continued)
<PAGE> 51
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)
<PAGE> 52
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)
<PAGE> 53
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
21 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 sign an agreement with 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.
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)
<PAGE> 54
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)
<PAGE> 55
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 recall provisions or special terms or conditions.
Short term - three months or less, is not prearranged and requires
bidding.
Medium Term - over three months up to two years, is not
prearranged, and requires bidding .
Long term - equal to or greater than two years, 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 - equal to or greater than 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 - one month up to two years 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)
<PAGE> 56
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
28. CAPACITY RELEASE (Continued)
28.2 Types of Releases (Continued)
Prearranged Deal-D - two years or longer at a rate less than the
maximum rate bid pursuant to the methodology selected by the
Releasing Shipper. This is type of release is prearranged, allows
for bidding, and allows the right of first refusal .
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)
<PAGE> 57
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.
(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)
<PAGE> 58
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)
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
<PAGE> 59
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)
<PAGE> 60
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)
<PAGE> 61
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)
<PAGE> 62
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)
<PAGE> 63
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)
<PAGE> 64
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)
<PAGE> 65
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)
<PAGE> 66
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)
<PAGE> 67
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
28. CAPACITY RELEASE (Continued)
28.7 Allocation of Parcels
(a) Primary Allocation
Winning bids for Parcels shall be awarded based on one of
the following three options to be selected by the
Releasing Shipper when posting a Parcel:
Option 1 - Price
Bids will be given priority based on the maximum rate bid as
represented by a Replacement Shipper's bid of the
percentage of: the maximum authorized reservation charge
or a volumetric equivalent of the maximum reservation
charge applicable to the Parcel on a 100% load factor
basis. Releasing Shippers using a volumetric rate and
wishing to accept reservation charge bids will be
considered an Option 3 criteria. In this instance
Releasing Shipper must define the method for evaluating
such bids. A bid queue will be maintained for each
individual Parcel.
Option 2 - Net Present Value
Bids will be given priority based on the net present value
per MMBtu for the term of the bid according to the following
formula:
n
(1 + i) -1
Present Value per unit = P * R * _________
n
i (1 + i)
where: P = percent of the rate or charge that the
Replacement Shipper is willing to pay.
(Continued)
<PAGE> 68
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)
<PAGE> 69
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 for releases up to two years and 5
business days for releases beyond two years 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)
<PAGE> 70
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)
<PAGE> 71
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 3rd business
day before the commencement of the Release Term.
Bid Period - a 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 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) Short-Term - three months or less, not prearranged.
Posting Period - up to 12:00 p.m. Pacific Time 8 business days
prior to the commencement of the Release Term.
Bid Period - a period of 3 business days subsequent to the close
of the Posting Period. The Bid Period closes at 2:00 p.m.
Pacific Time 5 business days prior to the commencement of the
Release Term.
Bid Reconciliation Period - a period of 3 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)
<PAGE> 72
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
28. CAPACITY RELEASE (Continued)
28.8 Scheduling of Parcels, Bids and Notifications (Continued)
(c) Medium-Term - over three months up to two years, not prearranged.
Posting Period - up to 12:00 p.m. Pacific Time on the 17th
business day before the commencement of the Release Term.
Bid Period - a period of 10 business days subsequent to the close
of the Posting Period. The Bid Period closes at 2:00 p.m.
Pacific Time on the 7th business day before the commencement of
the Release Term.
Bid Reconciliation Period - a period of 5 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.
(d) Long Term - two years or longer, not prearranged.
Posting Period - up to 12:00 p.m. Pacific Time on the 30th
business day before the commencement of the Release Term.
Bid Period - a period of 20 business days subsequent to the close
of the Posting Period. The Bid Period closes at 2:00 p.m.
Pacific Time on the 10th business day before the commencement of
the Release Term.
Bid Reconciliation Period - a period of 8 business days subsequent
to the close of the Bid Period. Notification of the results of
the bidding for Parcels will be posted not later than 2:00 p.m.
Pacific Time 2 business days prior to the commencement of the
Release Term.
(Continued)
<PAGE> 73
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
28. CAPACITY RELEASE (Continued)
28.8 Scheduling of Parcels, Bids and Notifications (Continued)
(e) 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.
(f) 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.
(g) Prearranged Deal-C - one month up to two years.
Posting Period - up to 12:00 p.m. Pacific Time on the 10th
business day before the commencement of the Release Term.
Bid Period - a period of 5 business days 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)
<PAGE> 74
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
28. CAPACITY RELEASE (Continued)
28.8 Scheduling of Parcels, Bids and Notifications (Continued)
(g) Prearranged Deal-C - one month up to two years (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.
(h) Prearranged Deal-D - two years or longer.
Posting Period - up to 12:00 p.m. Pacific Time on the 30th
business day before the commencement of the Release Term.
Bid Period - a period of 20 business days subsequent to the close
of the Posting Period. The Bid Period closes at 2:00 p.m.
Pacific Time on the 10th business day before the commencement of
the Release Term.
Bid Reconciliation Period - a period of 3 business days subsequent
to the close of the Bid Period. The Bid Reconciliation Period
closes at 2:00 p.m. Pacific Time on the 7th business day before
the commencement of the Release Term.
Match Period - a period of 5 business days 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 the 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)
<PAGE> 75
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)
<PAGE> 76
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)
<PAGE> 77
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
28. CAPACITY RELEASE (Continued)
(RAPID CAPACITY RELEASE TIMELINE GRAPH)
(SHORT TERM CAPACITY RELEASE TIMELINE GRAPH)
(MEDIUM TERM CAPACITY RELEASE TIMELINE GRAPH)
(LONG TERM CAPACITY RELEASE TIMELINE GRAPH)
(PRE-ARRANGED DEAL-A CAPACITY RELEASE TIMELINE GRAPH)
(PRE-ARRANGED DEAL-B CAPACITY RELEASE TIMELINE GRAPH)
(PRE-ARRANGED DEAL-C CAPACITY RELEASE TIMELINE GRAPH)
(PRE-ARRANGED DEAL-D CAPACITY RELEASE TIMELINE GRAPH)
<PAGE> 78
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.
A firm Shipper may add secondary receipt points, provided the
secondary receipt points are downstream of the primary receipt
point, at any time during the life of the contract. In this
instance, 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.
Service at the secondary receipt point will be allocated pro rata
to all firm Shippers using the point as a secondary receipt point
after service is allocated to firm Shippers using the receipt
point as a primary receipt point.
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
21.13.
(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 21.13
(Continued)
<PAGE> 79
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. Service at the secondary delivery
point will be allocated pro rata to all firm Shippers using the
point as a secondary delivery point after service is allocated to
firm Shippers using the delivery point as a primary delivery
point.
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 and subject to any
operating constraints capacity is required to effect the delivery
point(s) change, PGT will construct the additional capacity
consistent with Paragraph 21.13.
(Continued)
<PAGE> 80
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 a 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 21.13
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 and assigned an interruptible priority at the end of PGT's
interruptible queue.
(Continued)
<PAGE> 81
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 assigned
an interruptible priority at the end of PGT's interruptible queue
on a first-come first-served basis.
(Continued)
<PAGE> 82
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)
<PAGE> 83
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)
<PAGE> 84
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)
<PAGE> 85
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)
<PAGE> 86
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)
<PAGE> 87
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)
<PAGE> 88
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)
<PAGE> 89
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)
<PAGE> 90
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)
<PAGE> 91
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
34. ELECTRONIC BULLETIN BOARD
34.1 General
PGT shall use US GasNet as an interim step to full implementation of
Order No. 636 on its Electronic Bulletin Board (EBB), "Pacific Trail".
PGT shall post capacity for release beginning October 14, 1993. On
November 1, 1993, PGT will utilize "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 charge to use the EBB.
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)
<PAGE> 92
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)
<PAGE> 93
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 Volum 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)
<PAGE> 94
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)
<PAGE> 95
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)
<PAGE> 96
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, T-1, T-2 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. Costs allocated to
interruptible service include costs allocated to existing facilities
per Docket No. RP90-109-000 and to expansion facilities per Docket No.
CP89-460-000. 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)
<PAGE> 97
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)
<PAGE> 98
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.
<PAGE> 99
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)
<PAGE> 100
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 effective 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 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.
<PAGE> 101
Graphic Appendix List to Exhibit 10.4 of the Form 10-K
Description
The substantive information conveyed by the Rapid Capacity Release (equal to or
less than one month) Time-line graph (appearing in Paragraph 28) is described
in the body of the electronic document in Paragraphs 28.2 and 28.8 as permitted
by Item 304 of Regulation S-T.
The substantive information conveyed by the Short Term Capacity Release (three
months or less) Time-line graph (appearing in Paragraph 28) is described in the
body of the electronic document in Paragraphs 28.2 and 28.8 as permitted by
Item 304 of Regulation S-T.
The substantive information conveyed by the Medium Term Capacity Release (over
three months up to two years) Time-line graph (appearing in Paragraph 28) is
described in the body of the electronic document in Paragraphs 28.2 and 28.8 as
permitted by Item 304 of Regulation S-T.
The substantive information conveyed by the Long Term Capacity Release (two
years or longer) Time-line graph (appearing in Paragraph 28) is described in
the body of the electronic document in Paragraphs 28.2 and 28.8 as permitted by
Item 304 of Regulation S-T.
The substantive information conveyed by the Capacity Release for Pre-Arranged
Deal-A (less than one calendar month) Time-line graph (appearing in Paragraph
28) is described in the body of the electronic document in Paragraphs 28.2 and
28.8 as permitted by Item 304 of Regulation S-T.
The substantive information conveyed by the Capacity Release for Pre-Arranged
Deal-B (equal to or greater than one month at highest value bid) Time-line
graph (appearing in Paragraph 28) is described in the body of the electronic
document in Paragraphs 28.2 and 28.8 as permitted by Item 304 of Regulation
S-T.
The substantive information conveyed by the Capacity Release for Pre-Arranged
Deal-C (one month up to two years) Time-line graph (appearing in Paragraph 28)
is described in the body of the electronic document in Paragraphs 28.2 and 28.8
as permitted by Item 304 of Regulation S-T.
The substantive information conveyed by the Capacity Release for Pre-Arranged
Deal-D (two years or longer) Time-line graph (appearing in Paragraph 28) is
described in the body of the electronic document in Paragraphs 28.2 and 28.8 as
permitted by Item 304 of Regulation S-T.
<PAGE> 1
Exhibit 10.5
TRANSPORTATION SERVICE AGREEMENT AS AMENDED AND RESTATED
(Conversion from Firm Sales Service)
THIS AGREEMENT was made and entered into as of the 10th day of
October, 1990, and is amended and restated as of this 1st day of November,
1993, by and between EL PASO NATURAL GAS COMPANY, a Delaware corporation,
hereinafter referred to as "El Paso," and PACIFIC GAS AND ELECTRIC COMPANY, a
California corporation, hereinafter referred to as "Shipper."
WHEREAS, El Paso owns and operates a natural gas transmission system;
and
WHEREAS, Shipper owns and operates a natural gas distribution system
situated within the State of California; and
WHEREAS, El Paso has a blanket certificate authorizing transportation
pursuant to Subpart G of Part 284 of the Regulations promulgated by the Federal
Energy Regulatory Commission ("Commission"); and
WHEREAS, El Paso and Shipper now desire to amend and restate this
Agreement so as to remove those provisions which provide for intermediate
third-party transportation; and
WHEREAS, this Agreement, as amended and restated, provides for the
transportation on a firm basis by El Paso of certain quantities of natural gas
for Shipper from points of receipt located in various states to an existing
delivery point located at the borderline between the States of Arizona and
California near Topock, Arizona, pursuant to Subpart G of Part 284 of the
Commission's Regulations;
NOW THEREFORE, in consideration of the representations, covenants and
conditions herein contained, El Paso and Shipper agree as of the date first
above written as follows:
ARTICLE I
GAS TO BE TRANSPORTED
1.1 Subject to the terms and provisions of this Agreement and of
El Paso's Rate Schedule T-3, El Paso agrees to receive on each day at each
Receipt Point, such quantity of natural gas, if any, up to the Maximum Daily
Quantity specified for each Receipt Point on Exhibit A, not to exceed the
physical capacity of such point, as may be tendered to El Paso by Shipper (or
for Shipper's account), and to transport such quantity on a firm basis for
Shipper. The sum of the Maximum Daily Quantities reflected on Exhibit A shall
constitute Shipper's Transportation Contract Demand reflected on Exhibit B.
1.2 In addition to the quantity which Shipper may tender or cause
to be tendered to El Paso at each Receipt Point each day for firm
transportation in accordance with paragraph 1.1, Shipper shall tender or cause
to be tendered to El Paso at that point that quantity of natural
<PAGE> 2
gas as may be required from time to time to compensate El Paso for fuel
consumption, shrinkage, and lost and unaccounted for volumes associated with
such transportation. Such additional quantity is additive to (and shall not be
considered as constituting a part of) Shipper's Maximum Daily Quantity at such
Receipt Point.
1.3 In accordance with Section 4.1 of the General Terms and
Conditions incorporated by reference in Rate Schedule T-3, El Paso shall
deliver and Shipper shall accept or cause to be accepted at the Delivery
Point(s) referenced in paragraph 2.2 of Article II, a quantity of natural gas
equivalent, on a dth basis, to the sum of the quantities of natural gas
received by El Paso at the Receipt Points for transportation hereunder in
accordance with paragraph 1.1; provided, however, that in no event shall El
Paso be obligated to deliver on any day a quantity in excess of Shipper's
Transportation Contract Demand set forth on Exhibit B.
1.4 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. If El Paso elects to transport said
excess gas, Shipper shall pay El Paso pursuant to the terms and conditions set
forth in El Paso's Rate Schedule T-3.
1.5 In addition to transportation through El Paso's mainline
system, the service contemplated herein includes:
(a) Field Transportation
(b) Dehydration
(c) Purification
(d) Products Extraction
1.6 If on any day El Paso should determine that the transportation
capacity of its facilities is insufficient to transport all volumes of natural
gas up to the Transportation Contract Demand tendered for transportation under
this Agreement and by other shippers under similar, firm transportation
agreements, El Paso shall allocate the available transportation capacity on the
basis set forth in the General Terms and Conditions incorporated by reference
in El Paso's Rate Schedule T-3.
ARTICLE II
RECEIPT POINT(S), DELIVERY POINT(S)
AND DELIVERY PRESSURES
2.1 The Receipt Point(s) at which Shipper shall cause natural gas
to be tendered to El Paso for transportation hereunder are described in Exhibit
A to this Agreement. The delivery pressure and other pertinent factors are
also set forth in Exhibit A.
2.2 The Delivery Point(s) at which El Paso shall deliver
hereunder, are described in Exhibit B to this Agreement. The delivery pressure
and other pertinent factors applicable to the Delivery Point(s) are also set
forth in Exhibit B.
<PAGE> 3
ARTICLE III
RATE, RATE SCHEDULE(S) AND GENERAL TERMS AND CONDITIONS
3.1 Shipper shall pay El Paso for services rendered hereunder in
accordance with El Paso's Rate Schedule T-3, or superseding rate schedule(s),
on file with and subject to the jurisdiction of the Commission and lawfully in
effect from time to time.
3.2 The parties hereto agree that El Paso shall have the right
from time to time to propose and file with the Commission, in accordance with
Section 4 of the Natural Gas Act, changes, amendments, revisions and
modifications in:
(a) the rate(s) and Rate Schedule incorporated by reference
as a part of this Agreement pursuant to this Article III; and
(b) the General Terms and Conditions incorporated by
reference in said Rate Schedule, which are applicable hereto;
provided, however, that Shipper shall have the right to protest any such
changes before the Commission (or successor governmental agency) or other
authorities and to exercise any other rights that Shipper may have with respect
thereto.
3.3 This Agreement in all respects is subject to the provisions of
El Paso's Rate Schedule T-3, or superseding rate schedule(s), and applicable
provisions of the General Terms and Conditions included by reference in said
transportation rate schedule filed by El Paso with the Commission, all of which
are by reference made a part hereof.
3.4 Certain of the General Terms and Conditions may be adjusted for
the purpose of this Agreement and any such adjustments shall be set forth in
Exhibit C to this Agreement.
ARTICLE IV
REGULATORY REQUIREMENTS AND CONDITIONS PRECEDENT
4.1 The transportation arrangements provided for in this Agreement
are subject to the provisions of Subpart G of Part 284 of the Commission's
Regulations, as amended from time to time, except as expressly waived in
paragraph 5.3 hereof.
4.2 Transportation of natural gas provided for under the terms and
provisions of this Agreement shall not commence until the following conditions
have been met:
(NOT APPLICABLE)
<PAGE> 4
ARTICLE V
TERM
5.1 This Agreement shall become effective, as amended and
restated, on November 1, 1993.
5.2 After this Agreement becomes effective, it shall continue in
full force and effect for a primary term ending December 31, 1997, and
thereafter from year to year until terminated by written notice so stating
given no less than twelve (12) months in advance by either party to the other.
5.3 El Paso agrees to waive its rights to effect pre-granted
abandonment of transportation service upon the expiration of transportation
service agreements. As of the date of this Agreement, such right is codified
in Section 284.221(d) of the Commission's Regulations.
5.4 Without limitation of paragraph 5.3, prior to terminating
service under this Agreement, El Paso agrees to file for such authorization, if
any, as may be required for the abandonment of the transportation service
contemplated hereunder pursuant to Section 7(b) of the Natural Gas Act or any
successor statute, and not to terminate such service unless and until it shall
have received such abandonment authorization. Shipper shall have the right to
oppose such abandonment. El Paso will not apply for or otherwise seek
Commission approval for abandonment of Shipper's Transportation Contract Demand
as set forth in Exhibit B, or any portion thereof, prior to the date El Paso
notifies Shipper of its intent to terminate this Agreement as provided herein.
5.5 Termination of this Agreement shall not relieve El Paso or
Shipper of the obligation to correct any volume imbalances hereunder, or
Shipper of the obligation, if any, to pay monies due hereunder to El Paso.
ARTICLE VI
CANCELLATION OF PRIOR CONTRACTS
6.1 When this Agreement becomes effective, it supersedes and
cancels as of the effective date hereof the following contracts between the
parties hereto:
(NOT APPLICABLE)
ARTICLE VII
NOTICES
7.1 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 in hand to the following address
of the other party:
<PAGE> 5
El Paso: El Paso Natural Gas Company
Post Office Box 1492
El Paso, Texas 79978
Attention: Director, Marketing Services Department
Shipper: Pacific Gas and Electric Company
444 Market Street, Suite 6203
Post Office Box 770000
San Francisco, California 94177
Attention: Vice President, Gas Services and Operations
or to such other address as a party shall designate by formal written notice.
Routine communications may be mailed by ordinary mail. Operating
communications by telephone, facsimile or other mutually agreeable means shall
be considered as duly delivered without subsequent written confirmation.
Payments to El Paso for services rendered hereunder shall be made in accordance
with Section 6 of the General Terms and Conditions incorporated by reference in
Rate Schedule T-3.
ARTICLE VIII
OTHER OPERATING PROVISIONS
8.1 The natural gas liquids expressly reserved by Shipper are all,
and only, those liquid hydrocarbons recovered and allocated by El Paso to
Shipper as the result of Products Extraction, whether in El Paso's plants or in
another plant performing Products Extraction on behalf of El Paso.
8.2 In the event both parties agree in writing that additional
facilities are necessary primarily for Shipper in order to implement the
transportation service provided hereunder, Shipper hereby 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,
unless otherwise agreed to in writing.
8.3 Except as provided in paragraphs 5.3 and 5.4 hereof, the
parties hereto acknowledge that this Agreement or any operation conducted
pursuant thereto does not constitute an implied waiver or intentional
forfeiture of any rights of either party otherwise available under the
Commission's Order Nos. 436, et seq.; 451, et seq.; 500, et seq.; or 636, et
seq.
8.4 El Paso shall only be obligated to deliver the quantities of
natural gas hereunder at pressures that exist in El Paso's systems from time to
time, using all appropriate facilities available, unless a minimum pressure is
stated on Exhibit B to this Agreement. El Paso reserves the right to deliver
the quantities at higher pressures, up to any maximum pressure indicated on
Exhibit B to this Agreement.
8.5 The gas delivered by El Paso to Shipper at the Topock Delivery
Point shall have a heating value of not less than 995 Btu per cubic foot.
<PAGE> 6
ARTICLE IX
MISCELLANEOUS
9.1 El Paso and Shipper expressly agree that the laws of the State
of Texas shall govern the validity, construction, interpretation and effect of
this Agreement and of the General Terms and Conditions incorporated by
reference in El Paso's Rate Schedule T-3.
9.2 All substances, whether or not of commercial value, including
all liquid hydrocarbons of whatever nature, except substances expressly
reserved for Shipper, that El Paso recovers in the course of transporting the
quantities of natural gas tendered hereunder to Shipper shall be El Paso's sole
property and El Paso shall not be obligated to account to Shipper for any
value, whether or not realized by El Paso, that may attach or be said to attach
to such substances.
9.3 Exhibits A, B and C, attached to this Agreement, are hereby
incorporated by reference as part of this Agreement. The parties may amend
Exhibits A, B or C by mutual agreement, which amendments shall be reflected in
a revised Exhibit A, B or C and shall be incorporated by reference as part of
this Agreement.
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 A. W. Clark
Assistant Secretary Vice President
ATTEST: PACIFIC GAS AND ELECTRIC COMPANY
By B. L. McGrath By William R. Mazotti
Assistant Secretary Vice President
Gas Services and Operations
<PAGE> 7
EXHIBIT A
To The Transportation Service Agreement
Dated October 10, 1990
As Amended and Restated
Between El Paso Natural Gas Company
and Pacific Gas and Electric Company
<TABLE>
<CAPTION>
Maximum Type of Field
Delivery Daily Field Shrinkage
Pressure(s) Quantity Service(s) Factor(s)
Receipt Point(s) (psig) (Mcf) (3) (3)
---------------- ----------- --------- ---------- ---------
<S> <C> <C> <C> <C>
El Paso System
(EPNG Code STANDARD)
Any point of inter-
connection existing
from time to time
on El Paso's
facilities, except
those requiring
transportation by
others to provide
service under As As
this Agreement (1) (2) Required Published
</TABLE>
(1) Necessary pressure to enter the El Paso System and, except as
otherwise noted, not in excess of the MAOP of that facility.
(2) El Paso shall be obligated to receive hereunder, in accordance with
paragraph 1.1 of the Agreement and Section 4.2 of the General Terms and
Conditions contained in El Paso's Volume No. 1-A Tariff, or superseding
tariff, up to 1,140,000 Mcf per day of natural gas in the aggregate
from all Receipt Points plus applicable fuel, shrinkage and lost and
unaccounted for volumes as provided in paragraph 1.2 of the Agreement.
(3) Purification, Products Extraction and Dehydration may include
performance of these services by others on behalf of El Paso.
(4) Field Shrinkage Factor(s) includes all field fuel and other field
shrinkage.
<PAGE> 8
EXHIBIT A
(Continued)
A. Effective Date of this Exhibit A: November 1, 1993.
B. Supersedes Exhibit A Effective: September 1, 1991.
PACIFIC GAS AND ELECTRIC COMPANY EL PASO NATURAL GAS COMPANY
By William R. Mazotti By A. W. Clark
Vice President Vice President
Date December 17, 1993 Date October 25, 1993
<PAGE> 9
EXHIBIT B
To The
Transportation Service Agreement
Dated October 10, 1990
As Amended and Restated
Between El Paso Natural Gas Company
and Pacific Gas and Electric Company
<TABLE>
<CAPTION>
Maximum
Daily
Quantity
Delivery Point(s) (Mcf)
- ----------------- --------
<S> <C> <C>
Topock
(EPNG Code 32001 82)
Interconnection between
the facilities of El Paso
and Pacific Gas and
Electric Company located
at the borderline between
the States of Arizona and Delivery Pressure
California near Topock, not less than
Arizona 600 psig *
Topock
(EPNG Code 32003 22)
Interconnection between
the facilities of El Paso
and Southern California Gas
Company located at the
borderline between
the States of Arizona and
California near Topock,
Arizona *
Mojave Pipeline Company
(EPNG Code IMOJAVE)
Interconnection between
the facilities of El Paso
and Mojave Pipeline Company
located at the borderline
between the States of Arizona
and California near Topock,
Arizona *
Shipper's Transportation
Contract Demand 1,140,000 Mcf
</TABLE>
<PAGE> 10
EXHIBIT B
(Continued)
Unless otherwise specified on this exhibit, the Delivery Pressure(s) for the
point(s) listed above shall be the pressure existing from time to time at the
metering facility; however, El Paso reserves the right to deliver quantities at
pressures up to the MAOP of that facility.
* El Paso shall be obligated to deliver hereunder, in accordance with
paragraph 1.3 of the Agreement and Section 4.2 of the General Terms
and Conditions contained in El Paso's Volume No. 1-A Tariff, or
superseding tariff, up to the mainline MDQ of 1,140,000 Mcf per day of
natural gas in the aggregate at all Delivery Points, provided however,
that El Paso shall be obligated to deliver hereunder only Shipper's
quantities of natural gas received pursuant to this Agreement in the
aggregate at all Delivery Point(s).
A. Effective Date of this Exhibit B: November 1, 1993.
B. Supersedes Exhibit B Effective: September 1, 1991.
PACIFIC GAS AND ELECTRIC COMPANY EL PASO NATURAL GAS COMPANY
By William R. Mazotti By A. W. Clark
Vice President Vice President
Date October 17, 1993 Date October 25, 1993
<PAGE> 11
EXHIBIT C
To The
Transportation Service Agreement
Dated October 10, 1990
As Amended and Restated
Between El Paso Natural Gas Company
and Pacific Gas and Electric Company
The following shall apply in substitution for the identified
provisions of the General Terms and Conditions of El Paso's Tariff:
<TABLE>
<CAPTION>
Section of
General Terms
and Conditions Substitute Provision
- -------------- --------------------
<S> <C>
Substitution Any company which shall succeed by purchase, merger or
for Section 15 consolidation to the properties, substantially as an entirety,
of El Paso or of Shipper, as the case may be, shall be
entitled to the rights and shall be subject to the obligations
of its predecessor in title thereunder. Either Shipper or El
Paso may, without relieving itself of its obligations
hereunder, assign any of its rights thereunder to a company
with which it is affiliated, but otherwise no assignment of
the executed Transportation Service Agreement or any of the
rights or obligations thereunder shall be made unless there
first shall have been obtained the consent thereto of El Paso,
in the event of any asssignment by Shipper, or consent thereto
of Shipper, in the event of an assignment by El Paso. Such
consent shall not be unreasonably withheld.
Either party may assign its right, title and interest
in and to and under the executed Transportation Service
Agreement to a trustee or trustees, individual or corporate,
as security for bonds or other obligations or securities
without the necessity of obtaining such consent and without
such trustee or trustees assuming or becoming in any respect
obligated to perform the obligations of the assignor and, if
any such trustee be a corporation, without its being required
to qualify to do business in any state in which any
performance of the executed Transportation Service Agreement
may occur.
</TABLE>
<PAGE> 12
EXHIBIT C
(Continued)
A. Effective Date of this Exhibit C: November 1, 1993.
B. Supersedes Exhibit C Effective: September 1, 1991.
PACIFIC GAS AND ELECTRIC COMPANY EL PASO NATURAL GAS COMPANY
By William R. Mazotti By A. W. Clark
Vice President Vice President
Date October 17, 1993 Date October 25, 1993
<PAGE> 13
EXHIBIT 10.5
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff First Revised Sheet No. 110
First Revised Volume No. 1-A Superseding
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 (herein-after referred to as "El Paso")
under the following conditions:
(a) El Paso determines it has available capacity to render the firm
transportation service; and
(b) Shipper and El Paso have executed a Transportation Service
Agreement, in the form contained in this Volume No. 1-A Tariff, for
such firm transportation service.
2. APPLICABILITY AND CHARACTER OF SERVICE
This Rate Schedule shall apply to all natural gas transported by El
Paso for Shipper pursuant to the executed Transportation Service
Agreement.
Transportation service hereunder shall be firm, subject to the
provisions of the executed Transportation Service Agreement and to the
Transportation General Terms and Conditions incorporated herein by
reference.
Transportation service hereunder shall consist of the acceptance by El
Paso of natural gas on behalf of Shipper for transportation at the
Receipt Point(s) specified in the executed Transportation Service
Agreement, the transportation of that natural gas through El Paso's
pipeline system, and the delivery of that gas, after appropriate
reductions as provided for in this Rate Schedule, to Shipper or for
Shipper's account at the Delivery Point(s) specified in the executed
Transportation Service Agreement.
3. DEFINITIONS
3.1 Transportation Contract Demand: A Shipper's Transportation
Contract Demand shall be the maximum quantity of gas El Paso is
obligated to deliver to Shipper (or for Shipper's account) at the
Delivery Point(s) under this Rate Schedule. The Transportation
Contract Demand shall be specified on Exhibit B of the executed
Transportation Service Agreement, except that the Transportation
Contract Demand shall not apply to full requirements agreements.
Issued by: A. W. Clark, Vice President
Issued on: August 29, 1991 Effective: September 1, 1991
<PAGE> 14
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Fourth Revised Sheet No. 111
First Revised Volume No. 1-A Superseding
Substitute Third Revised Sheet No. 111
RATE SCHEDULE T-3
Firm Transportation Service
3. DEFINITIONS (Continued)
3.2 Maximum Daily Quantity: The maximum quantity that El Paso is
obligated to receive at each Receipt Point or deliver at each Delivery
Point as specified in the executed Transportation Service Agreement;
provided, however, that the Maximum Daily Quantity for a full
requirements customer on any day shall be its full requirements on
that day.
4. RATE
Shipper shall pay to El Paso each month the charges set forth below as
such charges are designated to be applicable to the transportation
service rendered by El Paso for Shipper under the executed
Transportation Service Agreement. The quantity of natural gas to
which the charges shall apply is set forth below.
4.1 Transportation Charges: As compensation for the use of El Paso's
facilities in the transportation of natural gas under the executed
Transportation Service Agreement, Shipper shall pay the following
rate(s):
(a) Mainline Transportation Reservation Charges: The maximum unit
amount in dollars per dth, unless otherwise provided, applicable to
the production area or state(s) in which deliveries are made as set
forth from time to time on the currently effective Sheet No. 21 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, applicable from the production
basin(s) in which natural gas is received to the production area(s)
within such basin or
Issued by: A. W. Clark, Vice President
Issued on: September 13, 1993 Effective: October 1, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-60-011, et al., dated August 31, 1993
<PAGE> 15
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Fourth Revised Sheet No. 112
First Revised Volume No. 1-A Superseding
Third Revised Sheet No. 112
RATE SCHEDULE T-3
Firm Transportation Service
(Continued)
4. RATE (Continued)
4.1 Transportation Charges (continued)
state(s) in which deliveries are made set forth from time to time on
currently effective Sheet No. 21 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. 21 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. 21 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: September 13, 1993 Effective: October 1, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-60-011, et al., dated August 31, 1993
<PAGE> 16
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff First Revised Sheet No. 112A
First Revised Volume No. 1-A Superseding
Original Sheet No. 112A
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. 21 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 (This space intentionally left blank)
Issued by: A. W. Clark, Vice President
Issued on: April 30, 1993 Effective: April 1, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-60-002 and 003 dated December 17, 1992
<PAGE> 17
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Substitute Second Revised Sheet No. 113
First Revised Volume No. 1-A Superseding
1st Sub First Revised Sheet No. 113
RATE SCHEDULE T-3
Firm Transportation Service (Continued)
4. RATE (Continued)
4.2 Field Transportation Usage Charges (Continued)
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. 22 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 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
Issued by: A. W. Clark, Vice President
Issued on: April 30, 1993 Effective: April 1, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-60-002 and 003 dated December 17, 1992
<PAGE> 18
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Third Revised Sheet No. 114
First Revised Volume No. 1-A Superseding
Substitute Second Revised Sheet No. 114
RATE SCHEDULE T-3
Firm Transportation Service
(Continued)
4. RATE (Continued)
4.3 Production Area Charges (Continued)
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.
Issued by: A. W. Clark, Vice President
Issued on: September 13, 1993 Effective: October 1, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-60-011, et al., dated August 31, 1993
<PAGE> 19
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff First Revised Sheet No. 114A
First Revised Volume No. 1-A Superseding
Sheet No. 114A
Reserved Sheet
Second Revised Sheet No. 114A has been reserved.
Issued by: A. W. Clark, Vice President
Issued on: September 13, 1993 Effective: October 1, 1993
<PAGE> 20
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Third Revised Sheet No. 115
First Revised Volume No. 1-A Superseding
Substitute Second Revised Sheet No. 115
RATE SCHEDULE T-3
Firm Transportation Service
(Continued)
4. RATE (Continued)
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. 21 and 22 of this
Volume No. 1-A Tariff, or superseding tariff. If El Paso so adjusts
any rates to any Shipper, El Paso shall file with the Federal Energy
Regulatory Commission any and all required reports respecting such
adjusted rates.
5. 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 Charge" 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: September 13, 1993 Effective: October 1, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-60-011, et al., dated August 31, 1993
<PAGE> 21
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A Substitute Original Sheet No. 116
RATE SCHEDULE T-3
Firm Transportation Service
(Continued)
7. FUEL AND/OR SHRINKAGE (Continued)
other services provided pursuant to Shipper's 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 0% 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, et al., shall be entitled to receive firm
transportation of the quantities specified by its Transportation
Service Agreement with El Paso
Issued by: A. W. Clark, Vice President
Issued on: November 13, 1991 Effective: September 1, 1991
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RP88-44-019, dated October 30, 1991
<PAGE> 22
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Fifth Revised Sheet No. 117
First Revised Volume No. 1-A Superseding
Substitute Fourth Revised Sheet No. 117
RATE SCHEDULE T-3
Firm Transportation Service
(Continued)
9. PROVISIONS APPLICABLE TO SHIPPERS THAT CONVERTED TO FIRM
TRANSPORTATION (Continued)
(a) (continued) for a period, unless 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
Production Area
<S> <C>
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: September 13, 1993 Effective: October 1, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-60-011, et al., dated August 31, 1993
<PAGE> 23
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Fourth Revised Sheet No. 118
First Revised Volume No. 1-A Superseding
Substitute Third Revised Sheet No. 118
RATE SCHEDULE T-3
Firm Transportation Service
(Continued)
9. PROVISIONS APPLICABLE TO SHIPPERS THAT CONVERTED TO FIRM TRANSPORTATION
(Continued)
<TABLE>
<CAPTION>
Shipper Billing Determinants
<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
Petroleos Mexicanos 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: September 13, 1993 Effective: October 1, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-60-011, et al., dated August 31, 1993
<PAGE> 24
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A Original Sheet No. 119
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
Issued by: A. W. Clark, Vice President
Issued on: September 13, 1993 Effective: October 1, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-60-011, et al., dated August 31, 1993
<PAGE> 25
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A Original Sheet No. 120
RATE SCHEDULE T-3
Firm Transportation Service
(Continued)
10. MAINLINE TRANSPORTATION RESERVATION CHARGE CREDIT (Continued)
Reservation 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: September 13, 1993 Effective: October 1, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-60-011, et al., dated August 31, 1993
<PAGE> 26
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A Sheet Nos. 121 through 124
Reserved Sheets
Original Sheet Nos. 121 through 124 have been reserved
Issued by: A. W. Clark, Vice President
Issued on: September 13, 1993 Effective: October 1, 1993
<PAGE> 27
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Fifth Revised Sheet No. 200
First Revised Volume No. 1-A Superseding
1st Sub Fourth Revised Sheet No. 200
TRANSPORTATION GENERAL TERMS AND CONDITIONS
<TABLE>
<CAPTION>
Table of Contents
<S> <C> <C>
1 Definitions 201
2 Method of Measurement 203
3 Measurement Equipment 205
4 Scheduling and Capacity Allocation 208
5 Quality 211
6 Billing and Payment 213
7 Force Majeure 216
8 Control and Possession of Natural Gas 217
9 Adverse Claims to Natural Gas 218
10 Indemnification 219
11 Odorization 220
12 Non-Waiver of Future Default 221
13 Service Conditions 222
14 Statutory Regulation 223
15 Assignments 224
16 Descriptive Headings 225
17 Taxes 226
18 Gas Research Institute General 227
Research Development and Demonstration
Funding Unit Adjustment Provision
19 Operating Provision for Interruptible 229
Transportation Service
20 Operating Provisions for Firm 235
Transportation Service
21 Annual Charge Adjustment Provision 241
22 Take-or-Pay Buyout and Buydown Cost 242
Recovery
23 Compliance Plan for Transportation 243
Services and Affiliate Transactions
24 Order No. 636 Electronic Bulletin Board 258
25 Reserved 260
26 Reserved 270
27 Unauthorized Gas 277
28 Capacity Release Program 281
29 Compliance Plan for Unbundled Sales 298
Division
30 Assignment of Firm Capacity on 299
Upstream Pipelines
31 Washington Ranch Facility Stranded 299C
Investment Cost Recovery
</TABLE>
Issued by: A. W. Clark, Vice President
Issued on: September 13, 1993 Effective: October 1, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-60-011, et al., dated August 31, 1993
<PAGE> 28
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A Original Sheet No. 201
TRANSPORTATION GENERAL TERMS AND CONDITIONS
1. DEFINITIONS
1.1 Day - A period of twenty-four (24) consecutive hours commencing
at seven (7:00) a.m., Mountain Standard Time, or such other period as
the parties may agree upon.
1.2 Month - A period commencing on the first day of the
corresponding calendar month and ending on the first day of the next
following calendar month.
1.3 Year - A period of three hundred sixty-five (365) consecutive
days commencing on the date to be specified in the executed
Transportation Service Agreement; provided, however, that any such
year which contains the date of February 29 shall consist of three
hundred sixty-six (366) consecutive days.
1.4 British Thermal Unit ("Btu") - One (1) Btu shall mean one
British thermal unit and is defined as the amount of heat required to
raise the temperature of one (1) pound of water from fifty-nine
degrees Fahrenheit (59 degrees F) to sixty degrees Fahrenheit
(60 degrees F) at a constant pressure of fourteen and seventy-three
hundredths pounds per square inch absolute (14.73 psia). Total
Btu's shall be determined by multiplying the total volume of
natural gas delivered times the gas heating value expressed in Btu's
per cubic foot of gas adjusted on a dry basis.
1.5 Dekatherm ("dth") - One (1) dth shall mean a quantity of gas
containing one million (1,000,000) Btu's.
1.6 Heating Value - The quantity of heat, measured in Btu, produced
by combustion in air of one (1) cubic foot of anhydrous gas at a
temperature of sixty degrees Fahrenheit (60 degrees F) and a constant
pressure of fourteen and seventy-three hundredths pounds per square
inch absolute (14.73 psia), the air being at the same temperature and
pressure as the gas, after the products of combustion are cooled to
the initial temperature of the gas and air, and after condensation of
the water formed by combustion.
1.7 Operator - The person or entity that controls the flow of gas
into El Paso's system.
1.8 Natural Gas - Any mixture of hydrocarbons or of hydrocarbons and
noncombustible gases, in a gaseous state, consisting essentially of
methane.
Issued by: A. W. Clark, Vice President
Issued on: April 26, 1990 Effective: May 1, 1990
<PAGE> 29
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A Original Sheet No. 202
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
1. DEFINITIONS (Continued)
1.9 One Thousand Cubic Feet ("Mcf") The quantity of natural gas
occupying a volume of one thousand (1,000) cubic feet at a temperature
of sixty degrees Fahrenheit (60 degrees F) and at a pressure of
fourteen and seventy-three hundredths pounds per square inch absolute
(14.73 psia).
1.10 El Paso System - The El Paso System is displayed on the map set
forth on Sheet No. 11 of this FERC Gas Tariff.
Issued by: A. W. Clark, Vice President
Issued on: April 26, 1990 Effective: May 1, 1990
<PAGE> 30
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A Original Sheet No. 203
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: April 26, 1990 Effective: May 1, 1990
<PAGE> 31
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A Original Sheet No. 204
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: April 26, 1990 Effective: May 1, 1990
<PAGE> 32
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A Original Sheet No. 205
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: April 26, 1990 Effective: May 1, 1990
<PAGE> 33
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff First Revised Sheet No. 206
First Revised Volume No. 1-A Superseding
Original Sheet No. 206
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: August 29, 1991 Effective: September 1, 1991
<PAGE> 34
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff First Revised Sheet No. 207
First Revised Volume No. 1-A Superseding
Original Sheet No. 207
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: August 29, 1991 Effective: September 1, 1991
<PAGE> 35
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A Original Sheet No. 207A
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
3. MEASUREMENT EQUIPMENT (Continued)
3.8 Right-of-Way and Rural Consumers - (Continued)
For measurement of gas delivered by El Paso to Shipper for resale to
such rural consumers, El Paso may, at its option, require Shipper to
install, maintain and operate at Shipper's own expense, adjacent to El
Paso's high-pressure regulators, the meters, low-pressure regulators
and other equipment required. Notwithstanding the other provisions of
these General Terms and Conditions and unless other operating
arrangements mutually agreeable to Shipper and El Paso are employed,
the following arrangements shall apply to deliveries of gas by El Paso
to Shipper for resale to right-of-way consumers as well as to
deliveries of gas by El Paso to Shipper for resale to rural consumers
where, pursuant to the immediately preceding paragraph, Shipper
installs meters, low-pressure regulators and other equipment. Shipper
will service all equipment installed by it and the consumers served by
use thereof, including handling of all complaints and/or service
calls. The reading of said meters shall be performed by the party
most conveniently able to do so as mutually agreed upon by El Paso and
Shipper. If the meters are read by Shipper, then Shipper shall
furnish a copy of the meter readings to the El Paso, all without
expense to El Paso; provided, however, that El Paso shall have the
right to read said meters at any reasonable time upon giving notice to
Shipper. All pipe, meters and other equipment shall remain the
property of the person or corporation paying for same. Shipper at
its own expense will from time to time check the accuracy of the
meters measuring said gas and shall give El Paso reasonable notice in
writing of its intention to do so. The provisions of Sections 3.6 and
3.7 hereof shall apply to the accuracy of Shipper's measuring
equipment. El Paso may at its option have a representative present at
such test. The frequency of meter reading and the billing for gas
delivered by El Paso to Shipper for resale to such right-of-way and
rural consumers shall be in accordance with such operating
arrangements as may be mutually satisfactory to El Paso and Shipper.
Issued by: A. W. Clark, Vice President
Issued on: August 29, 1991 Effective: September 1, 1991
<PAGE> 36
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A Original Sheet No. 207B
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: August 29, 1991 Effective: September 1, 1991
<PAGE> 37
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Fourth Revised Sheet No. 208
First Revised Volume No. 1-A Superseding
Substitute Third Revised Sheet No. 208
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: September 13, 1993 Effective: October 1, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-60-011, et al., dated August 31, 1993
<PAGE> 38
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff 1st Sub Second Revised Sheet No. 209
First Revised Volume No. 1-A Superseding
First Revised Sheet No. 209
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.
(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.
Issued by: A. W. Clark, Vice President
Issued on: September 13, 1993 Effective: April 1, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-60-011, et al., dated August 31, 1993
<PAGE> 39
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff First Revised Sheet No. 209A
First Revised Volume No. 1-A Superseding
1st Substitute Original Sheet No. 209A
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
4. SCHEDULING AND CAPACITY ALLOCATION (Continued)
4.1 Scheduling of Receipts and Deliveries (Continued)
(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: September 13, 1993 Effective: October 1, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-60-011, et al., dated August 31, 1993
<PAGE> 40
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
Original Volume No. 1-A Original Sheet No. 209B
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
4. SCHEDULING AND CAPACITY ALLOCATION (Continued)
4.1 Scheduling of Receipts and Deliveries (Continued)
(i) The Shipper who desires to divert gas to an alternate delivery
point must: (1) Contact the Operator of the delivery point to which
the gas was originally scheduled and arrange for that Operator to
decrease the quantity to be received from El Paso, and (2) Arrange
with the Operator of the alternate delivery point to receive the gas.
(ii) The Operator of the delivery point from which the gas is to be
diverted must notify El Paso, via El Paso's electronic scheduling
system, which Shipper's gas is to be diverted and to whom and where it
is to be diverted.
(iii) The Operator of the alternate delivery point must notify El
Paso, via El Paso's electronic scheduling system, that said Operator
has agreed to receive the diverted gas and must specify the quantities
to be diverted to each delivery point.
(iv) El Paso shall compare the notifications to verify that the
transactions correspond and shall determine if all or part of the
requested transaction can be accommodated given the current and
anticipated pipeline loading and operating conditions. A flow day
diversion shall not have the effect of bumping a Shipper moving gas
under Rate Schedule 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: September 13, 1993 Effective: October 1, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-60-011, et al., dated August 31, 1993
<PAGE> 41
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A Original Sheet No. 209C
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
(This space intentionally left blank)
Issued by: A. W. Clark, Vice President
Issued on: September 13, 1993 Effective: October 1, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-60-011, et al., dated August 31, 1993
<PAGE> 42
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff 1st Sub Second Revised Sheet No. 210
First Revised Volume No. 1-A Superseding
First Revised Sheet No. 210
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
4. SCHEDULING AND CAPACITY ALLOCATION (Continued)
4.2 Capacity Allocation Procedure (Continued) 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 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: September 13, 1993 Effective: April 1, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-60-011, et al., dated August 31, 1993
<PAGE> 43
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A Substitute Original Sheet No. 210A
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: April 29, 1993 Effective: May 1, 1993
<PAGE> 44
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A Substitute Original Sheet No. 210B
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 is 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 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
Issued by: A. W. Clark, Vice President
Issued on: April 29, 1993 Effective: May 1, 1993
<PAGE> 45
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A Substitute Original Sheet No. 210C
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)
(1) Calculation of Performance Factors - (Continued)
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 Operator's 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 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.
Issued by: A. W. Clark, Vice President
Issued on: April 29, 1993 Effective: May 1, 1993
<PAGE> 46
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A Substitute Original Sheet No. 210D
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)
(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: April 29, 1993 Effective: May 1, 1993
<PAGE> 47
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff First Revised Sheet No. 211
First Revised Volume No. 1-A Superseding Original Sheet No. 211
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: August 29, 1991 Effective: September 1, 1991
<PAGE> 48
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff First Revised Sheet No. 212
First Revised Volume No. 1-A Superseding
Original Sheet No. 212
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
5. QUALITY (Continued)
(e) Carbon Dioxide - The gas shall not have a carbon content in
excess of two percent (2%) by volume, except for gas applicable to
Sections 5.2 and 5.3.
(f) Diluents - The gas shall not at any time contain in excess of
three percent (3%) total diluents (the total combined carbon dioxide,
nitrogen, helium, oxygen, and any other diluent compound) by volume,
except for gas applicable to Sections 5.2 and 5.3.
(g) Dust, Gums and Solid Matter - The gas shall be commercially free
of dust, gums and other solid matter.
(h) Heating Value - The gas shall have a heating value of not less
than 967 Btu per cubic foot.
(i) Temperature - The gas received by El Paso shall be at
temperatures not in excess of one hundred twenty degrees Fahrenheit
(120 degrees F) nor less than fifty degrees Fahrenheit (50 degrees F).
Any party tendering gas at a temperature standard less than fifty
degrees Fahrenheit (50 degrees F) shall receive a waiver of such
standard only if a test has been conducted in accordance with
procedures set forth in Section 5.12(b) hereof and the results from
such test demonstrate that the particular segment of the pipeline
tested can be safely operated below the fifty degrees Fahrenheit
(50 degrees F) temperature standard.
(j) Deleterious Substances - The gas shall not contain deleterious
substances in concentrations that are hazardous to health, injurious
to pipeline facilities or adversely affect merchantability.
5.2 El Paso agrees that plant Receipt Points on El Paso's system,
where gas does not conform to the carbon dioxide and/or the total
diluent specification set forth in Sections 5.1(e) and (f) above,
shall be grandfathered based on the highest non-conforming monthly
average percentages of carbon dioxide and total diluents for a month
during the twelve (12) month base period ended July 31, 1990. El
Paso shall accept gas with carbon dioxide and/or total diluents at
percentages up to the non-conforming specifications at volumes up to
the residue volume at the plant design capacity as it exists on July
31, 1990; provided, however, to
Issued by: A. W. Clark, Vice President
Issued on: August 29, 1991 Effective: September 1, 1991
<PAGE> 49
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A Original Sheet No. 212A
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
5. QUALITY (Continued)
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
Specifications
-------------------------- Historical
Meter Total Diluents Volume
Location Code CO2MOL % MOL% (MCF/D)
-------- ------ -------- -------------- ----------
<S> <C> <C> <C> <C>
Amoco Slaughter Plant
(IAMSLAUG) 77-039 - 11.89 6,915
Barnhart Plant (J.L.Davis)
(IBARNHRT) 77-002 - 3.55 6,149
Big Lake Texon Plant
(Damson Oil Corp.)
(ITEXON) 77-055 - 9.67 2,362
Chevron Puckett Plant
(TPUCKETT) 14-261 3.55 4.09 37,390
Conoco Ramsey Plant
(IRAMSEY) 77-095 - 6.38 4,579
Exxon Snyder Plant
(Oryx Energy)
(IEXSNYDR) 77-009 - 7.42 696
</TABLE>
Issued by: A. W. Clark, Vice President
Issued on: August 29, 1991 Effective: September 1, 1991
<PAGE> 50
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A Original Sheet No. 212B
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
5. QUALITY (Continued)
Non-Conforming Plants
---------------------
(Continued)
<TABLE>
<CAPTION>
Grandfathered
Specifications
--------------------------
Historical
Meter Total Diluents Volume
Location Code CO2MOL % MOL% (MCF/D)
-------- -------- -------- -------------- ----------
<S> <C> <C> <C> <C>
Jameson Plant (Oryx Energy)
(ISUNJAME) 77-078 - 7.02 2,823
Meridian Benedum Plant
(MOHI)(IHYBENDM) 02-304 - 3.18 75,585
Midkiff Plant
(TMIDKIFF) 01-079 - 4.95 39,371
Midway Lane Plant
(Apache Gas Corporation)
(IMIDWAY) 03-933 - 4.45 4,617
Permian Corp. CPD #2
(IPERTOD2) 14-082 - 6.03 6,620
Phillips Goldsmith Plant
(IPHGOLDS) 03-105)
03-927) - 5.23 62,267
02-381)
Phillips Lee Plant
(IPHLEE) 77-025 - 7.34 27,484
Phillips Eunice Plant
(IPHEUNIC) 77-287 - 5.15 57,672
Phillips Fullerton Plant
(IPHFULTN) 77-289 - 6.18 28,200
Phillips Spraberry Plant
(IPHSPBRY) 77-248 - 4.64 11,277
Phillips Crane Plant
(IPHCRANE) 77-285 - 3.86 8,706
San Juan River Plant
(TBKRDOMN) 01-125 - 4.35 32,827
Shell TXL Plant (ISHTXL) 77-029 - 6.17 12,054
Shell Wasson Plant
(ISHWASON) 01-106 - 5.98 8,682
Terrell Plant
(TTERRELL) 01-596 2.89 4.53 102,708
Texaco Fuller
(ITEXFULR) 77-036 - 7.66 661
</TABLE>
Issued by: A. W. Clark, Vice President
Issued on: August 29, 1991 Effective: September 1, 1991
<PAGE> 51
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A Original Sheet No. 212C
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
5. QUALITY (Continued)
Non-Conforming Plants
---------------------
(Continued)
<TABLE>
<CAPTION>
Grandfathered
Specifications
-------------------------- Historical
Meter Total Diluents Volume
Location Code CO2MOL % MOL% (MCF/D)
------------ ------- --------- -------------- ----------
<S> <C> <C> <C> <C>
Texaco Vealmoor Plant
(IVEALMOR) 77-028 - 6.32 10,204
Tipperary Denton Plant
(J.L. Davis)(IDENTON) 77-001 - 5.02 2,554
Union of California
Dollarhide Plant
(IUTDOLHD) 77-027 - 6.42 2,056
Union Texas Perkins Plant
(IUTPERKN) 77-068 - 10.19 9,178
Val Verde
(IMOIIRKA) 14-136 2.13 - 195,985
Warren Monument
(IWARMONU) 77-045 - 4.04 31,576
Warren Saunders Plant
(IWARSAUD) 77-046 - 5.75 12,421
</TABLE>
5.3 El Paso agrees that interconnect Receipt Points on El Paso's
system, where gas does not conform to the carbon dioxide and/or the
total diluent specification set forth in Sections 5.1(e) and (f)
above, shall be grandfathered based on the twelve (12) month average
non-conforming percentages of carbon dioxide and total diluents for
the twelve (12) month base period ended July 31, 1990. El Paso shall
accept gas with carbon dioxide and/or total diluents at percentages up
to the grandfathered non-conforming specifications at volumes up to
the historical volume. The historical volume is deemed to be the
daily average volume received by El Paso at each of the non-conforming
interconnect Receipt Points for the twelve (12) month base period
ended July 31, 1990. The identification of the non-conforming
interconnects, the grandfathered specifications and the historical
volumes are set forth on the following table:
Issued by: A. W. Clark, Vice President
Issued on: August 29, 1991 Effective: September 1, 1991
<PAGE> 52
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A Original Sheet No. 212D
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
5. QUALITY (Continued)
<TABLE>
<CAPTION>
Non-Conforming Interconnects
----------------------------
Historical
Meter Total Diluents Volume
Location Code CO2MOL % MOL% (MCF/D)
------------- ------ -------- -------------- ----------
<S> <C> <C> <C> <C>
Big Blue Receipt Point
(Colorado Interstate)
(IBIGBLUE) 14-091 - 9.50 11,900
Howe Ranch Discharge
(Meridian) 02-721 4.12 5.20 3,480
Northern Natural Plains
(INNPLAIN) 01-094 - 4.22 111,072
Plains Compressor
(Westar-Felmac)
(IW40-043) 40-043 - 4.50 8,464
</TABLE>
5.4 In addition, El Paso agrees to grandfather the sulfur
specifications set forth in Section 5.1(c) above for natural gas
received at the tailgate of the Terrell and Puckett Plants, based on
the actual monthly highest non-conforming concentrations during the
twelve (12) month base period ending July 31, 1990. The sulfur
specifications El Paso shall accept for natural gas at volumes up to
the residue volume at plant design capacity received at the tailgate
of the Terrell and Puckett Plants are identified below. To the
extent a Shipper can demonstrate to El Paso that any other plant
located on El Paso's system has not historically met the sulfur
specifications set forth in Section 5.1(c) above, El Paso shall
grandfather such plant on the same basis as the Terrell and Puckett
Plants; provided, however, a plant shall not qualify if such plant has
changed the method of processing the gas in the last five (5) years.
<TABLE>
<CAPTION>
Grandfathered Non-conforming Sulfur
(grains per 100 standard cubic feet)
Total Hydrogen Mercaptan Organic
Location 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: August 29, 1991 Effective: September 1, 1991
<PAGE> 53
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A Original Sheet No. 212E
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
5. QUALITY (Continued)
5.5 El Paso agrees to accept natural gas (including volumes in
excess of the volumes identified in Sections 5.2 and 5.3) which does
not conform to the quality specifications set forth in Sections 5.1(e)
and (f) at the Receipt Point(s), but only until such time as El Paso,
in its reasonable discretion and judgement, determines that such
natural gas must conform to the quality specifications set forth above
to maintain prudent operation of part or all of El Paso's system. In
exercising its discretion to discontinue accepting nonconforming
natural gas under this Section, El Paso will consider only the volume,
compositions and location of the gas, and the impact of its continued
introduction into El Paso's system on El Paso's operations and an
ability to meet its obligations to third parties, and will
appropriately document the basis for its decision. Upon determining
that it will no longer accept non-conforming volumes, El Paso will
notify Shippers and/or plant operators that all prospective deliveries
must comply with the quality specifications set forth above and that
the provisions of Section 5.8 below shall be applicable to all natural
gas tendered for transportation which does not so comply. In the
event the aforementioned occurrences cause El Paso to curtail volumes
at plant and/or interconnect Receipt Points such curtailment shall
exclude those plant and/or interconnect volumes identified in Sections
5.2 and 5.3, provided, however, if El Paso determines that it must
further curtail volumes of non-conforming gas to meet El Paso's
delivery specifications for carbon dioxide and/or total diluents, El
Paso shall curtail volumes down to 125% of the historical volumes for
those plants identified in Section 5.2 on the following basis:
(a) First, volumes of natural gas that did not meet the 967 Btu
standard would be curtailed in order of lowest Btu to highest down to
the level of 125% of historical volumes;
(b) Second, plants with pipeline interconnects in addition to El
Paso would be curtailed down to the level of 125% of historical
volumes on a pro rata basis; and
(c) Third, all other volumes would be curtailed on a pro rata basis,
based on a percentage of such volumes that are out of compliance as to
the particular substance that is causing the problem, down to 125% of
historical volumes.
Issued by: A. W. Clark, Vice President
Issued on: August 29, 1991 Effective: September 1, 1991
<PAGE> 54
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A Original Sheet No. 212F
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
5. QUALITY (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: August 29, 1991 Effective: September 1, 1991
<PAGE> 55
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A Original Sheet No. 212G
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
5. QUALITY (Continued)
<TABLE>
<CAPTION>
Hydro- Total Sulfur/
Water Carbons H2S Mercaptan Sulfur/
Vapor Dew GR/100 Organic Sulfur 3/
Location #/MMCF Point Scf GR/100 Scf
------------ ------ ----- ------ --------------
<S> <C> <C> <C> <C>
San Juan Basin
Sweet Gas 25 1/ 0.25 5/.75/1.25
(GSANJUAN)
La Jara
(ILAJARA) 25 1/ 0.25 5/.75/1.25
Tapacito Field
(ITAPACIT) 25 1/ 0.25 5/.75/1.25
Kutz (Exchange
Point No. 13)
(IEXCPT13) 25 1/ 0.25 5/.75/1.25
Kutz (Exchange Point
No. 18)
(IEXCPT18) 25 1/ 0.25 5/.75/1.25
Gas Company of New
Mexico (Exchange
Point No. 47)
(IEXCPT47) 25 1/ 0.25 5/.75/1.25
San Juan Ignacio
Dry (GIGNACIO) 25 20 degrees F 0.25 5/.75/1.25
Bondad (WestGas)
(IBONDAD) 25 20 degrees F 0.25 5/.75/1.25
WestGas
(IWESTGAS) 25 20 degrees F 0.25 5/.75/1.25
San Juan Barker
Dome (GBKRDOMN) 25 20 degrees F 2/ 4/
</TABLE>
<TABLE>
<CAPTION>
Dust, Minimum
Total Gums and Heating
CO2 Diluents Oxygen Solid Value
Location MOL % MOL % % Matter Btu Temperature
-------- ----- --------- ------ -------- ------- -----------
<S> <C> <C> <C> <C> <C> <C>
San Juan Basin Max 120 degrees F
Sweet Gas 2 3 .2 Free of 967 Min 50 degrees F
(GSANJUAN)
La Jara Max 120 degrees F
(ILAJARA) 2 3 .2 Free of 967 Min 50 degrees F
Tapacito Field Max 120 degrees F
(ITAPACIT) 2 3 .2 Free of 967 Min 50 degrees F
Kutz (Exchange
Point No. 13) Max 120 degrees F
(IEXCPT13) 2 3 .2 Free of 967 Min 50 degrees F
Kutz (Exchange Point
No. 18) Max 120 degrees F
(IEXCPT18) 2 3 .2 Free of 967 Min 50 degrees F
Gas Company of New
Mexico (Exchange
Point No. 47) Max 120 degrees F
(IEXCPT47) 2 3 .2 Free of 967 Min 50 degrees F
San Juan Ignacio Max 120 degrees F
Dry (GIGNACIO) 2 3 .2 Free of 967 Min 50 degrees F
Bondad (WestGas) Max 120 degrees F
(IBONDAD) 2 3 .2 Free of 967 Min 50 degrees F
WestGas Max 120 degrees F
(IWESTGAS) 2 3 .2 Free of 967 Min 50 degrees F
San Juan Barker Max 120 degrees F
Dome (GBKRDOMN) 5/ 4.35 6/ .2 Free of 967 7/ Min 50 degrees F
</TABLE>
Issued by: A.W. Clark, Vice President Effective: September 1, 1991
Issued on: August 29, 1991
<PAGE> 56
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A Original Sheet No. 212H
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
5. QUALITY (Continued)
<TABLE>
<CAPTION>
Hydro- Total Sulfur/
Water Carbons H2S Mercaptan Sulfur/
Vapor Dew GR/100 Organic Sulfur 3/
Location #/MMCF Point Scf GR/100 Scf
------------- ------ ----- ------ ----------------
<S> <C> <C> <C> <C>
Western Gas
Processors CPD#1
(IWGPCPD1) 15 20 degrees F 0.25 5/.75/1.25
Lockridge
(GLOCKRID) 20 20 degrees F 2/ 4/
Worsham
(GWORSHAM) 20 20 degrees F 2/ 4/
Waha
(GWAHA) 20 20 degrees F 2/ 4
West Waha
(GWSTWAHA) 20 20 degrees F 2/ 4/
Gomez
(GGOMEZ) 20 20 degrees F 2/ 4/
Toro
(GTORO) 20 20 degrees F 2/ 4/
Rojo Caballos
(GROJOCAB) 20 20 degrees F 2/ 4/
Carlsbad
(GCARLSBAD) 7 20 degrees F 0.25 5/.75/1.25
Terrell
(GTERRELL) 15 20 degrees F 2/ 5/.75/1.25
</TABLE>
<TABLE>
<CAPTION>
Dust, Minimum
Total Gums and Heating
CO2 Diluents Oxygen Solid Value
Location MOL % MOL % % Matter Btu Temperature
-------- ----- --------- ------ -------- ------- -----------
<S> <C> <C> <C> <C> <C> <C>
Western Gas
Processors CPD#1 Max 120 degrees F
(IWGPCPD1) 2 3 .2 Free of 967 Min 50 degrees F
Lockridge Max 120 degrees F
(GLOCKRID) 5/ 3 6/ .2 Free of 967 Min 50 degrees F
Worsham Max 120 degrees F
(GWORSHAM) 5/ 3 6/ .2 Free of 967 Min 50 degrees
Waha Max 120 degrees F
(GWAHA) 5/ 3 6/ .2 Free of 967 Min 50 degrees F
West Waha Max 120 degrees F
(GWSTWAHA) 5/ 3 6/ .2 Free of 967 Min 50 degrees F
Gomez Max 120 degrees F
(GGOMEZ) 5/ 3 6/ .2 Free of 967 Min 50 degrees F
Toro Max 120 degrees F
(GTORO) 5/ 3 6/ .2 Free of 967 Min 50 degrees F
Rojo Caballos Max 120 degrees F
(GROJOCAB) 5/ 3 6/ .2 Free of 967 Min 50 degrees F
Carlsbad Max 120 degrees F
(GCARLSBAD) 2 3 .2 Free of 967 Min 50 degrees F
Terrell Max 120 degrees F
(GTERRELL) 5/ 4.53 6/ .2 Free of 967 7/ Min 50 degrees F
</TABLE>
Issued by: A.W. Clark, Vice President Effective: September 1, 1991
Issued on: August 29, 1991
<PAGE> 57
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A Original Sheet No. 212I
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
5. QUALITY (Continued)
<TABLE>
<CAPTION>
Hydro- Total Sulfur/
Water Carbons H2S Mercaptan Sulfur/
Vapor Dew GR/100 Organic Sulfur 3/
Location #/MMCF Point Scf GR/100 Scf
-------------- ------ ----- ------ ----------------
<S> <C> <C> <C> <C>
Dewey County Gathering
System OK (GDEWEY) 6 20 degrees F 0.25 5/.75/1.25
Beckham County
(GBECKHAM) 7 20 degrees F 0.25 5/.75/1.25
San Juan Mainline
(GSJMNLIN) 7 20 degrees F 0.25 5/.75/1.25
26" Eunice to Pecos
(GEU-PECS) 7 20 degrees F 0.25 5/.75/1.25
Plains to San Juan
(GSJXOVER) 7 20 degrees F 0.25 5/.75/1.25
Terrell to Puckett
(GTER-PUK) 7 20 degrees F 0.25 5/.75/1.25
Culberson County
(GCULBERS) 7 20 degrees F 0.25 5/.75/1.25
20" Goldsmith to Plains
(G20G0-PL) 7 20 degrees F 0.25 5/.75/1.25
Texas to 16" C
(GTX-16C) 7 20 degrees F 0.25 5/.75/1.25
16" C Line
(G16C-LIN) 7 20 degrees F 0.25 5/.75/1.25
</TABLE>
<TABLE>
<CAPTION>
Dust, Minimum
Total Gums and Heating
CO2 Diluents Oxygen Solid Value
Location MOL % MOL % % Matter Btu Temperature
-------- ----- --------- ------ -------- ------- -----------
<S> <C> <C> <C> <C> <C> <C>
Dewey County Gathering Max 120 degrees F
System OK (GDEWEY) 2 3 .2 Free of 967 Min 50 degrees F
Beckham County Max 120 degrees F
(GBECKHAM) 2 3 .2 Free of 967 Min 50 degrees F
San Juan Mainline Max 120 degrees F
(GSJMNLIN) 2 3 .2 Free of 967 Min 50 degrees F
26" Eunice to Pecos Max 120 degrees F
(GEU-PECS) 2 3 .2 Free of 967 Min 50 degrees F
Plains to San Juan Max 120 degrees F
(GSJXOVER) 2 3 .2 Free of 967 Min 50#
Terrell to Puckett Max 120 degrees F
(GTER-PUK) 2 3 .2 Free of 967 Min 50 degrees F
Culberson County Max 120 degrees F
(GCULBERS) 2 3 .2 Free of 967 Min 50 degrees F
20" Goldsmith to Plains Max 120 degrees F
(G20G0-PL) 2 3 .2 Free of 967 Min 50 degrees F
Texas to 16" C Max 120 degrees F
(GTX-16C) 2 3 .2 Free of 967 Min 50 degrees F
16" C Line Max 120 degrees F
(G16C-LIN) 2 3 .2 Free of 967 Min 50 degrees F
</TABLE>
Issued by: A.W. Clark, Vice President Effective: September 1, 1991
Issued on: August 29, 1991
<PAGE> 58
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A Original Sheet No. 212J
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
5. QUALITY (Continued)
<TABLE>
<CAPTION>
Hydro- Total Sulfur/
Water Carbons H2S Mercaptan Sulfur/
Vapor Dew GR/100 Organic Sulfur 3/
Location #/MMCF Point Scf GR/100 Scf
--------------- ------ ------- ------ ----------------
<S> <C> <C> <C> <C>
Yucca Butte
(GYUCBUTE) 7 20 degrees F 0.25 5/.75/1.25
McKay Creek
(GMCKAYCR) 7 20 degrees F 0.25 5/.75/1.25
20" Sonora to Benedum
(GSON-BEN) 7 20 degrees F 0.25 5/.75/1.25
Hobart (Phillips)
(GHOBART) 7 20 degrees F 0.25 5/.75/1.25
Hobart - Zybach
(GHOB-ZYB) 7 20 degrees F 0.25 5/.75/1.25
ANR No. 1
(IANR#1AN) 7 20 degrees F 0.25 5/.75/1.25
ANR No. 2
(IANR#2AN) 7 20 degrees F 0.25 5/.75/1.25
BP Gas Transmission
(Roger Mills County)
(ICHEY-CP) 7 20 degrees F 0.25 5/.75/1.25
NGPL Beckham #3
(INGLPB#3) 7 20 degrees F 0.25 5/.75/1.25
Lea County (100#)
(GLEA100#) 8/ 1/ 2/ 4/
</TABLE>
<TABLE>
<CAPTION>
Dust, Minimum
Total Gums and Heating
CO2 Diluents Oxygen Solid Value
Location MOL % MOL % % Matter Btu Temperature
-------- ----- --------- ------ -------- ------- -----------
<S> <C> <C> <C> <C> <C> <C>
Yucca Butte Max 120 degrees F
(GYUCBUTE) 2 3 .2 Free of 967 Min 50 degrees F
McKay Creek Max 120 degrees F
(GMCKAYCR) 2 3 .2 Free of 967 Min 50 degrees F
20" Sonora to Benedum Max 120 degrees F
(GSON-BEN) 2 3 .2 Free of 967 Min 50 degrees F
Hobart (Phillips) Max 120 degrees F
(GHOBART) 2 3 .2 Free of 967 Min 50 degrees F
Hobart - Zybach Max 120 degrees F
(GHOB-ZYB) 2 3 .2 Free of 967 Min 50 degrees F
ANR No. 1 Max 120 degrees F
(IANR#1AN) 2 3 .2 Free of 967 Min 50 degrees F
ANR No. 2 Max 120 degrees F
(IANR#2AN) 2 3 .2 Free of 967 Min 50 degrees F
BP Gas Transmission
(Roger Mills County) Max 120 degrees F
(ICHEY-CP) 2 3 .2 Free of 967 Min 50 degrees F
NGPL Beckham #3 Max 120 degrees F
(INGLPB#3) 2 3 .2 Free of 967 Min 50 degrees F
Lea County (100#) Max 120 degrees F
(GLEA100#) 5/ 3 6/ .2 Free of 967 Min 50 degrees F
</TABLE>
Issued by: A.W. Clark, Vice President Effective: September 1, 1991
Issued on: August 29, 1991
<PAGE> 59
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A Original Sheet No. 212K
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
5. QUALITY (Continued)
<TABLE>
<CAPTION>
Total
Hydro- Sulfur/
Water Carbons H2S Mercaptan Sulfur/
Vapor Dew GR/100 Organic Sulfur 3/
Location #/MMCF Point Scf GR/100 Scf
------------- ------ ----- ------ ---------------
<S> <C> <C> <C> <C>
Lea County (Low
Pressure) 8/ 1/ 2/ 4/
(GLEA/LP)
Texas to Lea (Low
Pressure)
(GTX-LEAL) 8/ 1/ 2/ 4/
Texas to Lea 100#
(GTX-LEAH) 8/ 1/ 2/ 4/
16" A Line
(G16A-LIN) 8/ 1/ 2/ 4/
Wilshire
(GWILSHIR) 8/ 1/ 2/ 4/
Jack Herbert
(GJACKHER) 8/ 1/ 2/ 4/
Lusk
(GLUSK) 8/ 1/ 0.25 5/.75/1.25
Midkiff
(GMIDKIFF) 8/ 1/ 9/ 5/.75/1.25
Sealy Smith
(GSLYSMITH) 8/ 1/ 2/ 4/
Peyton
(GPEYTON) 8/ 1/ 2/ 4/
</TABLE>
<TABLE>
<CAPTION>
Dust, Minimum
Total Gums and Heating
CO2 Diluents Oxygen Solid Value
Location MOL % MOL % % Matter Btu Temperature
-------- ----- --------- ------ -------- ------- -----------
<S> <C> <C> <C> <C> <C> <C>
Lea County (Low Max 120 degrees F
Pressure) (GLEA/LP) 5/ 3 6/ .2 Free of 967 Min 50 degrees F
Texas to Lea (Low Max 120 degrees F
Pressure) (GTX-LEAL) 5/ 3 6/ .2 Free of 967 Min 50 degrees F
Texas to Lea 100# Max 120 degrees F
(GTX-LEAH) 5/ 3 6/ .2 Free of 967 Min 50 degrees F
16" A Line Max 120 degrees F
(G16A-LIN) 5/ 3 6/ .2 Free of 967 Min 50 degrees F
Wilshire Max 120 degrees F
(GWILSHIR) 5/ 3 6/ .2 Free of 967 Min 50 degrees F
Jack Herbert Max 120 degrees F
(GJACKHER) 5/ 3 6/ .2 Free of 967 Min 50 degrees F
Lusk Max 120 degrees F
(GLUSK) 2 3 .2 Free of 967 Min 50 degrees F
Midkiff Max 120 degrees F
(GMIDKIFF) 2 4.95 .2 Free of 967 Min 50 degrees F
Sealy Smith Max 120 degrees F
(GSLYSMITH) 2 3 6/ .2 Free of 967 Min 50 degrees F
Peyton Max 120 degrees F
(GPEYTON) 2 3 6/ .2 Free of 967 Min 50 degree F
</TABLE>
Issued by: A.W. Clark, Vice President Effective: September 1, 1991
Issued on: August 29, 1991
<PAGE> 60
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A Original Sheet No. 212L
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
5. QUALITY (Continued)
<TABLE>
<CAPTION>
Hydro- Total Sulfur/
Water Carbons H2S Mercaptan Sulfur/
Vapor Dew GR/100 Organic Sulfur 3/
Location #/MMCF Point Scf GR/100 Scf
---------------- ------ ----- ------ ------------------
<S> <C> <C> <C> <C>
Pecos Valley
(GPECVALY) 8/ 1/ 2/ 4/
Fort Stockton
(GFTSTOCK) 8/ 1/ 2/ 4/
South Andrews 8/ 1/ 2/ 4/
(GSOANDRW)
Sweetie Peck 8/ 1/ 2/ 4/
(GSWETPCK)
Beaver 8/ 1/ 0.25 5/.75/1.25
(GBEAVER)
</TABLE>
<TABLE>
<CAPTION>
Dust, Minimum
Total Gums and Heating
CO2 Diluents Oxygen Solid Value
Location MOL % MOL % % Matter Btu Temperature
-------- ----- --------- ------ -------- ------- -----------
<S> <C> <C> <C> <C> <C> <C>
Pecos Valley Max 120 degrees F
(GPECVALY) 2 3 6/ .2 Free of 967 Min 50 degrees F
Fort Stockton Max 120 degrees F
(GFTSTOCK) 5/ 3 6/ .2 Free of 967 Min 50 degrees F
South Andrews Max 120 degrees F
(GSOANDRW) 2 3 6/ .2 Free of 967 Min 50 degrees F
Sweetie Peck Max 120 degrees F
(GSWETPCK) 2 3 6/ .2 Free of 967 Min 50 degrees F
Beaver Max 120 degrees F
(GBEAVER) 2 3 .2 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
Effective: September 1, 1991
Issued on: August 29, 1991
<PAGE> 61
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A Original Sheet No. 212M
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.
7/ El Paso will accept natural gas in these gathering systems that is
less than the minimum heating value of 967 Btu only if the gas at the
tailgate of the treating plant where the gas is processed exceeds the
minimum heating value of 967 Btu.
8/ Free of water in liquid form.
9/ El Paso shall accept natural gas with hydrogen sulfide at levels above
0.25 grains per 100 Scf only to the extent that the processing plant
or gathering system operations and the natural gas liquids product
quality are not adversely impacted by the hydrogen sulfide and the
residue gas from these processing plants meets the hydrogen sulfide
specification listed under Section 5.1(c)(i) above.
Issued by: A.W. Clark, Vice President Effective: September 1, 1991
Issued on: August 29, 1991
<PAGE> 62
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A Original Sheet No. 212N
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
5. QUALITY (Continued)
5.8 If, at any time, gas tendered by Shipper for transportation
shall fail to substantially conform to any of the applicable quality
specifications set forth in Section 5.1 above and El Paso notifies
Shipper of such deficiency and Shipper fails to remedy any such
deficiency within a reasonable period of time (immediately in those
situations which threaten the integrity of El Paso's system), El Paso
may, at its option, refuse to accept delivery pending correction of
the deficiency by Shipper or continue to accept delivery and make such
changes necessary to cause the gas to conform to such specifications,
in which event Shipper shall reimburse El Paso for all reasonable
expenses incurred by El Paso in effecting such changes, including
operational and gas costs associated with purging and/or venting the
pipeline. Failure by Shipper to tender quantities that conform to any
of the applicable quality specifications shall not be construed to
eliminate, or limit in any manner, the obligations of Shipper existing
under any other provisions of the executed Transportation Service
Agreement. In the event natural gas is delivered into El Paso's
system that would cause the natural gas in a portion of El Paso's
pipeline to become unmerchantable, then El Paso is permitted to act
expediently to make the gas merchantable again by any and all
reasonable methods, including, without limitation, to venting the
pipeline of whatever quantity of natural gas necessary to achieve a
merchantable stream of gas. Shipper shall reimburse El Paso for all
reasonable expenses incurred by El Paso to obtain merchantable natural
gas again, including operational and gas costs associated with venting
the pipeline. In such cases, El Paso shall promptly notify Shipper of
the non-conforming supply and any steps taken to protect the
merchantability of the gas.
5.9 After giving sufficient notice to a Shipper, El Paso shall have
the right to collect from all Shippers delivering gas to El Paso at a
common Receipt Point their volumetric pro rata share of the cost of
any additional hydrogen sulfide analysis and/or water vapor analysis
equipment which El Paso, at its reasonable discretion, determines is
required to be installed at such Receipt Point to monitor the quality
of gas delivered.
5.10 Except as otherwise provided below, all natural gas delivered
by El Paso shall conform to the following specifications:
Issued by: A. W. Clark, Vice President
Issued on: August 29, 1991 Effective: September 1, 1991
<PAGE> 63
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A Original Sheet No. 212O
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
5. QUALITY (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: August 29, 1991 Effective: September 1, 1991
<PAGE> 64
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A Original Sheet No. 212P
TRANSPORTATION GENERAL TERMS AND CONDITIONS (Continued)
5. QUALITY (Continued)
Shipper or its designee in effecting such changes.
(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 merchant-ability. 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
Issued by: A. W. Clark, Vice President
Issued on: August 29, 1991 Effective: September 1, 1991
<PAGE> 65
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A Original Sheet No. 212Q
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 as 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 chromatographs. (b) To determine whether specific
points on El Paso's system can operate below the fifty degree
Fahrenheit (50 degree 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: August 29, 1991 Effective: September 1, 1991
<PAGE> 66
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A Original Sheet No. 213
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: April 26, 1990 Effective: May 1, 1990
<PAGE> 67
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Substitute First Revised Sheet No. 214 First
First Revised Volume No. 1-A Superceding
Original Sheet No. 214
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: July 16, 1992 Effective: July 3, 1992
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RP92-185-000, dated July 2, 1992
<PAGE> 68
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Substitute First Revised Sheet No. 215 First
First Revised Volume No. 1-A Superseding
Original Sheet No. 215
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: July 16, 1992 Effective: July 3, 1992
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RP92-185-000, dated July 2, 1992
<PAGE> 69
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A Substitute Original Sheet No. 215A
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
6. BILLING AND PAYMENT (Continued)
6.4 Failure to Pay Bills (Continued) any amounts of less than
$10,000. If resolution of the dispute is in favor of Shipper and the
Shipper furnished a surety bond instead of paying the disputed amount,
then El Paso shall refund to Shipper the costs incurred in securing
that surety bond for this dispute. This section does not apply to
ordinary adjustments of overcharges and undercharges in accordance
with Section 6.5.
6.5 Adjustment of Overcharge and Undercharge - If it shall be
found that at any time or times, within the time limits of Section 6.7
below, Shipper has been overcharged or undercharged in any form
whatsoever under the provisions hereof as a result of an error in
billing for which El Paso is solely responsible and Shipper shall have
actually paid the bill containing such overcharge or undercharge,
then, unless mutually agreed otherwise, within thirty (30) days after
the final determination thereof, and except where otherwise required
by statute, rule, regulation or order, El Paso shall refund the amount
of any such overcharge, with interest thereon at the then effective
rate computed in the same manner as set forth in Section 6.4 above,
and Shipper shall pay the amount of any such undercharge, with
interest thereon at the then effective rate computed in the same
manner as set forth in Section 6.4 above. Interest on overcharges or
undercharges shall be calculated from the time such overcharge or
undercharge was paid to the date of refund or payment, respectively;
provided, however, neither El Paso nor Shipper shall calculate or pay
interest on any amounts of less than $10,000. This section does not
apply to payments subject to a billing dispute in accordance with
Section 6.4.
6.6 Delayed Bill or Notice - If El Paso fails to render or
otherwise fails to mail any bill by the fifteenth (15th) day of the
month then the time of payment shall be extended by one (1) day for
each day that the rendering of said bill is delayed unless Shipper is
responsible for such delay. If El Paso fails to render or otherwise
fails to mail any notice within the time specified in this Billing and
Payment Section, then the time for Shipper's response to such notice
shall be extended by one (1) day for each day that the rendering of
said notice is delayed unless Shipper is responsible for such delay.
Issued by: A. W. Clark, Vice President
Issued on: July 16, 1992 Effective: July 3, 1992
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RP92-185-000, dated July 2, 1992
<PAGE> 70
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A Original Sheet No. 215B
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: July 16, 1992 Effective: July 3, 1992
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RP92-185-000, dated July 2, 1992
<PAGE> 71
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A Original Sheet No. 216
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
7. FORCE MAJEURE
7.1 Effect of Force Majeure - In the event of either El Paso or Shipper
being rendered unable by force majeure to wholly or in part carry out
its obligations under the provisions of the executed Transportation
Service Agreement, it is agreed that the obligations of the party
affected by such force majeure, other than to make payments due, shall
be suspended without liability for breach of contract during the
continuance of any inability so caused but for no longer period, and
such cause shall, so far as possible, be remedied with all reasonable
dispatch. A force majeure event affecting the performance by either
party shall not relieve it of liability in the event of its concurring
negligence, where such negligence was a cause of the force majeure
event, or in the event of its failure to use reasonable diligence to
remedy the situation and remove the cause in an adequate manner and
with all reasonable dispatch, nor shall such causes or contingencies
relieve either party of liability unless such party shall give notice
and full particulars of the same in writing to the other party as soon
as possible after the occurrence relied on.
7.2 Definition of Force Majeure - The term "force majeure" as
employed herein shall mean acts of God, strikes, lockouts or other
industrial disturbances, failure of any third parties necessary to the
performance by either El Paso or Shipper under the executed
Transportation Service Agreement, inability to obtain pipe or other
material or equipment or labor, wars, riots, insurrections, epidemics,
landslides, lightning, earthquakes, fires, storms, floods, washouts,
arrests and restraint of rulers and people, interruptions by
government or court orders, present or future orders of any regulatory
body having proper jurisdiction, civil disturbances, explosions,
breakage or accident to machinery or lines of pipe, freezing of wells
or pipelines, and any other cause whether of the kind herein
enumerated or otherwise, not within the control of the party claiming
suspension and which, by the exercise of due diligence, such party is
unable to overcome. Nothing contained herein, however, shall be
construed to require either party to settle a strike against its will.
Issued by: A. W. Clark, Vice President
Issued on: April 26, 1990 Effective: May 1, 1990
<PAGE> 72
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A Original Sheet No. 217
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
8. CONTROL AND POSSESSION OF NATURAL GAS
8.1 As between El Paso and Shipper, El Paso shall be deemed to be
in control and possession of the natural gas from the time it is
delivered to El Paso at the Receipt Point(s) until it is redelivered
to Shipper at the Delivery Point(s), and Shipper shall be deemed to be
in control and possession of the natural gas at all other times.
Issued by: A. W. Clark, Vice President
Issued on: April 26, 1990 Effective: May 1, 1990
<PAGE> 73
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A Original Sheet No. 218
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: April 26, 1990 Effective: May 1, 1990
<PAGE> 74
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A Original Sheet No. 219
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: April 26, 1990 Effective: May 1, 1990
<PAGE> 75
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A Original Sheet No. 220
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: April 26, 1990 Effective: May 1, 1990
<PAGE> 76
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A Original Sheet No. 221
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.
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 sales and
firm transportation customers.
Issued by: A. W. Clark, Vice President
Issued on: April 26, 1990 Effective: May 1, 1990
<PAGE> 77
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A Original Sheet No. 222
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
13. SERVICE CONDITIONS (Continued)
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: April 26, 1990 Effective: May 1, 1990
<PAGE> 78
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A Substitute Original Sheet No. 222A
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: January 22, 1992 Effective: January 17, 1992
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RP92-58-000, dated January 8, 1992
<PAGE> 79
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A Original Sheet No. 223
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: April 26, 1990 Effective: May 1, 1990
<PAGE> 80
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A Original Sheet No. 224
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: April 26, 1990 Effective: May 1, 1990
<PAGE> 81
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A Original Sheet No. 225
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: April 26, 1990 Effective: May 1, 1990
<PAGE> 82
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A Original Sheet No. 226
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: April 26, 1990 Effective: May 1, 1990
<PAGE> 83
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Second Revised Sheet No. 227
First Revised Volume No. 1-A Superseding
First Revised Sheet No. 227
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. For the period commencing January 1, 1994 through
December 31, 1994 the Commission approved a GRI funding mechanism
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 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 using the new Shipper's estimated annual volumes to be
Issued by: A. W. Clark, Vice President
Issued on: November 29, 1993 Effective: January 1, 1994
<PAGE> 84
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Second Revised Sheet No. 228
First Revised Volume No. 1-A Superseding
First Revised Sheet No. 228
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
18. GAS RESEARCH INSTITUTE GENERAL RESEARCH, DEVELOPMENT AND
DEMONSTRATION FUNDING UNIT ADJUSTMENT PROVISION (Continued)
18.2 Applicability (Continued)
transported, divided by the Shipper's contract demand or billing
determinant. 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 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.
Issued by: A. W. Clark, Vice President
Issued on: November 29, 1993 Effective: January 1, 1994
Tariff Sheet Subject
to Further Modifications
<PAGE> 85
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A Original Sheet No. 228A
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
High Load Factor (in excess of 50%) Shippers
<TABLE>
<CAPTION>
Agreement
Description Code
----------- ---------
<S> <C>
Amoco Energy Trading Corporation 97JB
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
Mobil Natural Gas Inc. 97YK
PEMEX Gas y Petroquimica Basica 97ZZ
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
Low Load Factor (50% or less) Shippers
--------------------------------------
Arizona Electric Power Cooperative, Inc. 9838
Arizona Public Service Company 97ZC
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
Mission Energy Fuel Company 97YX
Natural Gas Processors Company 97YR
Navajo Tribal Utility Authority 97ZY
Salt River Project Agricultural 9826
Improvement and Power District
Southdown, Inc. (SW Portland) 982Q
Southwest Gas Corporation 97ZL
Southwest Gas Corporation 97ZK
</TABLE>
Issued by: A. W. Clark, Vice President
Issued on: November 29, 1993 Effective: January 1, 1994
<PAGE> 86
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A Original Sheet No. 229
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 23.6 shall govern.
19.3 On any day that sufficient capacity is not available in El
Paso's system to provide transportation for all gas tendered under
executed Transportation Service Agreements with Shippers referred to
in Section 19.2 above, El Paso shall allocate its available capacity
among such Shippers on a first come/first served basis. For purposes
of allocating such capacity, any Shipper holding an effective
Transportation Service Agreement or any Shipper who has furnished El
Paso with a valid request complying with the requirements contained in
Section 19.4 and in Section 23, when accepted by El Paso in an
executed Transportation Service Agreement, will be entitled to
priority over any Shipper furnishing El Paso with a valid request on a
later date and shall be unaffected by and shall have priority over
subsequent requests for service under Rate Schedule T-1.
Issued by: A. W. Clark, Vice President
Issued on: April 26, 1990 Effective: May 1, 1990
<PAGE> 87
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Second Revised Sheet No. 230
First Revised Volume No. 1-A Superseding
First Revised Sheet No. 230
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
23.6 of this FERC Gas Tariff is provided to El Paso.
19.5 Upon receipt of all of the information required in Section 23
for a valid request for transportation service, El Paso shall prepare
and tender to Shipper for execution a Transportation Service Agreement
in the form contained in this Volume No. 1-A Tariff. If Shipper fails
to execute the Transportation Service Agreement or any amendment
thereto within thirty (30) days of the date tendered, Shipper's
request shall be deemed null and void.
19.6 If a Shipper that has executed a Transportation Service
Agreement fails, on the later of the date service is to commence or
fifteen (15) days after the Shipper executes the Transportation
Service Agreement, or the completion of construction of any necessary
facilities or the issuance of any necessary certificate authorization,
to nominate pursuant to Section 4.1 of these General Terms and
Conditions any quantity of gas for transportation or fails, having
nominated a quantity of gas and El Paso having scheduled the quantity
for transportation, to tender any gas for transportation, the
Shipper's Transportation Service Agreement shall be terminated and the
Shipper's request for service shall be deemed null and void; provided,
however, that the Shipper's Transportation Service Agreement shall not
be terminated nor shall the Shipper's request for service be deemed
null and void if the Shipper's failure to nominate or tender is caused
by an event of force majeure as defined in Section 7 of these General
Terms and Conditions.
19.7 El Paso shall not be required to perform or continue service
on behalf of any Shipper that fails to comply with the terms contained
in Sections 19 and 23 and any and all terms of the applicable rate
schedule and the terms of Shipper's Transportation Service Agreement
with El Paso. El Paso shall have the right to waive any one or more
specific defaults by any Shipper under Sections 19.8 through 19.13,
inclusive, or any
Issued by: A. W. Clark, Vice President
Issued on: March 20, 1992 Effective: May 15, 1992
<PAGE> 88
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff 1st Revised First Revised Sheet No. 231
First Revised Volume No. 1-A Superseding
Original Sheet No. 231
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
19 OPERATING PROVISIONS FOR INTERRUPTIBLE TRANSPORTATION SERVICE
(Continued)
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.
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
Issued by: A. W. Clark, Vice President
Issued on: December 29, 1992 Effective: February 1, 1993
<PAGE> 89
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A
Original Sheet No. 231A
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
19. OPERATING PROVISIONS FOR INTERRUPTIBLE TRANSPORTATION SERVICE
(Continued)
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.
(This space intentionally left blank)
Issued by: A. W. Clark, Vice President
Issued on: December 29, 1992 Effective: February 1, 1993
<PAGE> 90
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff 1st Rev Sub Second Revised Sheet No. 232
First Revised Volume No. 1-A Superseding
First Revised Sheet No. 232
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
19. OPERATING PROVISIONS FOR INTERRUPTIBLE TRANSPORTATION SERVICE
(Continued)
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) 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
Issued by: A. W. Clark, Vice President
Issued on: September 13, 1993 Effective: October 1, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-60-011, et al., dated August 31, 1993
<PAGE> 91
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff 1st Rev Sub Second Revised Sheet No. 233
First Revised Volume No. 1-A Superseding
First Revised Sheet No. 233
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
19. OPERATING PROVISIONS FOR INTERRUPTIBLE TRANSPORTATION SERVICE
(Continued)
19.12 Resolution of Imbalances (Continued)
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 inbona 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
Issued by: A. W. Clark, Vice President
Issued on: September 13, 1993 Effective: October 1, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-60-011, et al., dated August 31, 1993
<PAGE> 92
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff 1st Rev Sub Second Revised Sheet No. 234
First Revised Volume No. 1-A Superseding
Substitute First Revised Sheet No. 234
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
19. OPERATING PROVISIONS FOR INTERRUPTIBLE TRANSPORTATION SERVICE
(Continued)
19.12 Resolution of Imbalances (Continued)
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 it is determined that El Paso has caused in any month an
imbalance equal to or greater than +/- 10% of the denominator
determined above, El Paso will cash-out that portion of the imbalance
at 100% of the Index Price. 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)
Issued by: A. W. Clark, Vice President
Issued on: September 13, 1993 Effective: October 1, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-60-011, et al., dated August 31, 1993
<PAGE> 93
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff 1st Rev Sub First Revised Sheet No. 234A
First Revised Volume No. 1-A Superseding
Substitute Original Sheet No. 234A
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
19. OPERATING PROVISIONS FOR INTERRUPTIBLE TRANSPORTATION SERVICE
(Continued)
19.12 Resolution of Imbalances (Continued)
below. Written agreements may consist of, but are not limited to the
following provisions (i) offsetting of imbalances; (ii) extension of a
payback period within a set time period; and (iii) negotiated price
other than the cash-out prices reflected herein.
(c) Triggering of Cash-Out - Except for those contracts without
activity for a period of six (6) months, as discussed in Section
19.12(d), any cumulative imbalance at the end of any month that is
within a tolerance level less than +/-5% shall not be subject to this
Section 19.12 during such month. Such imbalance shall be forwarded to
the next month's imbalance calculation. If the cumulative imbalance
for any month is equal to or greater than +/-5%, El Paso shall notify
Shipper, as indicated in Section 19.12(b), that it is approaching a
cash-out situation for an imbalance equal to or in excess of +/-10%.
For any month that a cumulative imbalance is equal to or in excess of
+/-10%, cash-out of the imbalance will take place provided Shipper has
received a minimum of two (2) consecutive monthly notices (minimum of
45 days from date of first notice) alerting Shipper to an imbalance
equal to or in excess of +/-5%. El Paso shall extend the 45-day grace
period by one (1) day for each day that El Paso is unable to receive
or deliver scheduled 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.
(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
Issued by: A. W. Clark, Vice President
Issued on: September 13, 1993 Effective: October 1, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-60-011, et al., dated August 31, 1993
<PAGE> 94
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff 1st Rev Sub First Revised Sheet No. 234B
First Revised Volume No. 1-A Superseding
Substitute Original Sheet No. 234B
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
19. OPERATING PROVISIONS FOR INTERRUPTIBLE TRANSPORTATION SERVICE
(Continued)
19.12 Resolution of Imbalances (Continued)
+/-10%, for which no cash-out was applicable and before the next
invoice and balance statement date, such imbalance shall be reduced to
zero (0) by cash-out utilizing the Index Price for the month after the
end of six (6) month period reflected in Section 19.12(e).
(e) Index Prices and Cash Out
(i) Cash-out shall be based on one of four calculated price indices,
depending on whether Shipper has one or more of the three supply
basins (i.e., San Juan, Permian or Anadarko Basins) included in its
agreement. A single price index calculated only for a specific supply
basin will be used if Shipper has only that one supply basin in its
agreement. A System Weighted Index Price calculated for all supply
basins will be used if Shipper has more than one supply basin in its
agreement. The calculation of each price index is set forth below:
(1) The Anadarko Basin Index Price shall be computed using a simple
average of reported prices as delivered to El Paso's Mainline System
at Washita, Anadarko, Oklahoma, or the Texas Panhandle from the
publications identified in Section 19.12(e)(ii);
(2) The Permian Basin Index Price shall be computed using a simple
average of reported prices as delivered to El Paso's Mainline System
at West Texas, Permian or Waha from the publications identified in
Section 19.12(e)(ii); and
(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).
Issued by: A. W. Clark, Vice President
Issued on: September 13, 1993 Effective: October 1, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-60-011, et al., dated August 31, 1993
<PAGE> 95
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A
1st Rev Sub Original Sheet No. 234C
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
19. OPERATING PROVISIONS FOR INTERRUPTIBLE TRANSPORTATION SERVICE
(Continued)
19.12 Resolution of Imbalances (Continued)
(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. (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.
Issued by: A. W. Clark, Vice President
Issued on: September 13, 1993 Effective: October 1, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-60-011, et al., dated August 31, 1993
<PAGE> 96
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A
1st Rev Sub Original Sheet No. 234D
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 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.
(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;
Issued by: A. W. Clark, Vice President
Issued on: September 13, 1993 Effective: October 1, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-60-011, et al., dated August 31, 1993
<PAGE> 97
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A
1st Rev Sub Original Sheet No. 234E
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
19. OPERATING PROVISIONS FOR INTERRUPTIBLE TRANSPORTATION SERVICE
(Continued)
19.12 Resolution of Imbalances (Continued)
(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 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.
Issued by: A. W. Clark, Vice President
Issued on: September 13, 1993 Effective: October 1, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-60-011, et al., dated August 31, 1993
<PAGE> 98
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A
1st Rev Original Sheet No. 234F
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
19. OPERATING PROVISIONS FOR INTERRUPTIBLE TRANSPORTATION SERVICE
(Continued)
19.12 Resolution of Imbalances (Continued)
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 - For any net dollar amount received net
of gas and administrative costs from cash-out assessed on El Paso or
an affiliate of El Paso, El Paso shall credit such net amount within
90 days of the payment date to other 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 is willing to negotiate, on a
non-discriminatory basis, netting of gas imbalances, adjusted to
reflect a common point at which the imbalance is held, between
contracts with such Shipper pursuant to the following conditions:
(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.
(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.
Issued by: A. W. Clark, Vice President
Issued on: September 13, 1993 Effective: October 1, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-60-011, et al., dated August 31, 1993
<PAGE> 99
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A
1st Rev Original Sheet No. 234G
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
19. OPERATING PROVISIONS FOR INTERRUPTIBLE TRANSPORTATION SERVICE
(Continued)
19.12 Resolution of Imbalances (Continued)
(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 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.
Issued by: A. W. Clark, Vice President
Issued on: September 13, 1993 Effective: October 1, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-60-011, et al., dated August 31, 1993
<PAGE> 100
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A
1st Rev Sub Original Sheet No. 234H
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
19. OPERATING PROVISIONS FOR INTERRUPTIBLE TRANSPORTATION SERVICE
(Continued)
19.13 Unauthorized Overpull Penalty (Continued)
(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: September 13, 1993 Effective: October 1, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-60-011, et al., dated August 31, 1993
<PAGE> 101
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A
Original Sheet No. 235
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 23.6 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: April 26, 1990 Effective: May 1, 1990
<PAGE> 102
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A
Original Sheet No. 236
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
20. OPERATING PROVISIONS FOR FIRM TRANSPORTATION SERVICE (Continued)
(b) In the event that two or more Shippers seek to obtain the firm
capacity that one or more Shippers offer to relinquish on the Outer
Continental Shelf, such capacity shall be allocated as follows:
(i) during the open season conducted in accordance with Order No.
509, et seq., firm capacity will be reallocated in accordance with
Section 284.304(a) of the Commission's Regulations; and
(ii) after the open season within ten (10) days of receiving a
complete and valid request for firm transportation, El Paso will
provide the requesting Shipper a list of all firm Shippers under
contract with El Paso. If the requesting Shipper finds an existing
Shipper willing to relinquish voluntarily all or a portion of its firm
capacity, El Paso will reallocate that capacity on a first come/first
served basis. The relinquishing Shipper and the new Shipper shall
advise El Paso in writing of their mutual agreement. In the event
there is more than one valid request for service on a given day, and
such requests exceed the available firm capacity, such capacity shall
be allocated among the requesting Shippers on a pro rata basis. Any
capacity which is relinquished by an existing Shipper and subsequently
assumed by the requesting Shipper must have compatible receipt and
delivery point obligations, unless El Paso has capacity available at
other requested receipt and delivery points. In the event El Paso has
uncommitted firm capacity available, it may assign part or all of that
capacity before it reallocates the capacity of existing Shippers.
Upon execution of the new Transportation Service Agreement with the
new Shipper, El Paso shall be absolved of all service obligations to
the relinquishing Shipper and shall be deemed to have received
pregranted abandonment authorization for such relinquishing Shipper.
Issued by: A. W. Clark, Vice President
Issued on: April 26, 1990 Effective: May 1, 1990
<PAGE> 103
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff 1st Revised First Revised Sheet No. 237
First Revised Volume No. 1-A Superseding
Original Sheet No. 237
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 Annotated, Business and
Commerce Code,
Issued by: A. W. Clark, Vice President
Issued on: December 29, 1992 Effective: February 1, 1993
<PAGE> 104
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Third Revised Sheet No. 238
First Revised Volume No. 1-A Superseding
Substitute Second Revised Sheet No. 238
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
20. OPERATING PROVISIONS FOR FIRM TRANSPORTATION SERVICE (Continued)
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: December 29, 1992 Effective: February 1, 1993
<PAGE> 105
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff 1st Rev Sub Second Revised Sheet No. 239
First Revised Volume No. 1-A Superseding
First Revised Sheet No. 239
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
20. OPERATING PROVISIONS FOR FIRM TRANSPORTATION SERVICE (Continued)
20.11 Resolution of Imbalances
For purposes of this Section 20.11 "Shipper" shall include any party
utilizing El Paso's system and services including, without limitation,
any party tendering or receiving gas under Shipper's contract but
excluding any operator of interconnecting facilities and any volume
subject to a written assistance agreement with El Paso. El Paso and
the operator of any interconnecting facilities may cash-out
imbalances, pursuant to a written agreement between them.
(a) Imbalances Prior to Effective Date of this Provision -
Imbalances existing prior to the effective date of this provision will
be corrected in kind, as described below, unless El Paso and Shipper
agree to correct such imbalances in cash. El Paso and Shipper shall
attempt, in good faith, to agree upon the historical imbalance and the
time period to correct such historical imbalance. If, despite such
good faith efforts, El Paso and Shipper fail to reach written
agreement upon the appropriate corrective action within six (6) months
from the effectiveness of this section, then Shipper shall be required
to correct any remaining imbalance within sixty (60) days, subject to
operational constraints on El Paso's system. El Paso shall extend the
sixty (60) day balancing period by one (1) day for each day that El
Paso is unable to receive or deliver scheduled imbalance gas due to
operational constraints on El Paso's system. If after the sixty (60)
day balancing period or extension due to operational constraints
Shipper has not corrected the imbalance, then El Paso shall (i) for
any remaining imbalances where deliveries exceed receipts ("negative
imbalance") charge Shipper per dth based upon the arithmetic average
of the System Weighted Index Price for each quarter of the twelve (12)
months ending December 31, 1992 (the System Weighted Index Price for
each quarter shall be based on the method set forth in Section
20.11(e)(i) below); or (ii) for any remaining imbalances where
receipts exceed deliveries ("positive imbalance") retain the imbalance
at no cost and free and clear of any adverse claims by any party or
any obligation to account for such gas; provided however, that in the
event of a bona fide dispute by Shipper of
Issued by: A. W. Clark, Vice President
Issued on: September 13, 1993 Effective: October 1, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-60-011, et al., dated August 31, 1993
<PAGE> 106
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff 1st Rev Sub Second Revised Sheet No. 240
First Revised Volume No. 1-A Superseding
Substitute First Revised Sheet No. 240
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 inbona 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 in accordance with this
Section
20.11. Each month, El Paso will calculate a percentage
Issued by: A. W. Clark, Vice President
Issued on: September 13, 1993 Effective: October 1, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-60-011, et al., dated August 31, 1993
<PAGE> 107
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff 1st Rev Sub First Revised Sheet No. 240A
First Revised Volume No. 1-A Superseding
Substitute Original Sheet No. 240A
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
20. OPERATING PROVISIONS FOR FIRM TRANSPORTATION SERVICE (Continued)
20.11 Resolution of Imbalances (Continued)
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 it is determined that
El Paso has caused in any month an imbalance equal to or greater than
+/- 10% of the denominator determined above, El Paso will cash-out
that portion of the imbalance at 100% of the Index Price. In
addition, cash-out of imbalances will not be mandatory if the parties
have reached written agreement on the resolution of the imbalance
provided such agreement is final prior to the triggering of cash-out
as specified in Section 20.11(c) below. Written agreements may
consist of, but are not limited to the following provisions (i)
offsetting of imbalances; (ii) extension of a payback period within a
set time period; and (iii) negotiated price other than the cash-out
prices reflected herein.
(c) Triggering of Cash-Out - Except for those contracts without
activity for a period of six (6) months, as discussed in Section
20.11(d), any cumulative imbalance at the end of any month that is
within a tolerance level less than +/-5% shall not be subject to this
Section 20.11 during such month. Such imbalance shall be
Issued by: A. W. Clark, Vice President
Issued on: September 13, 1993 Effective: October 1, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-60-011, et al., dated August 31, 1993
<PAGE> 108
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff 1st Rev Sub First Revised Sheet No. 240B
First Revised Volume No. 1-A Superseding
Original Sheet No. 240B
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
20. OPERATING PROVISIONS FOR FIRM TRANSPORTATION SERVICE (Continued)
20.11 Resolution of Imbalances (Continued)
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 scheduled imbalance gas for a
given contract due to operational constraints on El Paso's system. If
the parties have not reached written agreement otherwise, the
imbalance will be reduced to +/-5% by "cash-out" the month following
the last notice, at the dollar value calculated with the cumulative
imbalance and an established monthly price, referred to herein as the
Index Price, as determined in Section 20.11(e) below. The Index Price
shall be calculated as of the month the imbalance first equals or
exceeds the +/-10% level.
(d) Six-Month Resolution of Inactive Contracts - El Paso will notify
Shipper after three (3) consecutive months of inactivity that at the
end of any six (6) month period that a contract between Shipper and El
Paso has been inactive and has maintained an imbalance of less than
+/-10%, for which no cash-out was applicable and before the next
invoice and balance statement date, such imbalance shall be reduced to
zero (0) by cash-out utilizing the Index Price for the month after the
end of six (6) month period reflected in Section 20.11(e).
(e) Index Prices and Cash Out
(i) Cash-out shall be based on one of four calculated price indices,
depending on whether Shipper has one or more of the three supply
basins (i.e., San Juan,
Issued by: A. W. Clark, Vice President
Issued on: September 13, 1993 Effective: October 1, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-60-011, et al., dated August 31, 1993
<PAGE> 109
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff 1st Rev Sub First Revised Sheet No. 240C
First Revised Volume No. 1-A Superseding
1st Substitute Original Sheet No. 240C
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
20. OPERATING PROVISIONS FOR FIRM TRANSPORTATION SERVICE (Continued)
20.11 Resolution of Imbalances (Continued)
Permian or Anadarko Basins) included in its agreement. A single price
index calculated only for a specific supply basin will be used if
Shipper has only that one supply basin in its agreement. A System
Weighted Index Price calculated for all supply basins will be used if
Shipper has more than one supply basin in its agreement. The
calculation of each price index is set forth below:
(1) The Anadarko Basin Index Price shall be computed using a simple
average of reported prices as delivered to El Paso's Mainline System
at Washita, Anadarko, Oklahoma, or the Texas Panhandle from the
publications identified in Section 20.11(e)(ii);
(2) The Permian Basin Index Price shall be computed using a simple
average of reported prices as delivered to El Paso's Mainline System
at West Texas, Permian or Waha from the publications identified in
Section 20.11(e)(ii); and
(3) The San Juan Basin Index Price shall be computed using a simple
average of reported prices as delivered to El Paso's Mainline System
at Ignacio, San Juan or New Mexico from the publications identified in
Section 20.11(e)(ii).
(4) The System Weighted Index Price shall be computed monthly by
using the weighted average of the Anadarko Basin Index Price, the
Permian Basin Index Price, and the San Juan Basin Index Price. The
weighting is based on the volumes entering El Paso's system in each
basin during the previous quarter and will be updated quarterly.
Issued by: A. W. Clark, Vice President
Issued on: September 13, 1993 Effective: October 1, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-60-011, et al., dated August 31, 1993
<PAGE> 110
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff 1st Rev Sub First Revised Sheet No. 240D
First Revised Volume No. 1-A Superseding
1st Substitute Original Sheet No. 240D
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
20. OPERATING PROVISIONS FOR FIRM TRANSPORTATION SERVICE (Continued)
20.11 Resolution of Imbalances (Continued)
(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.
(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: September 13, 1993 Effective: October 1, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-60-011, et al., dated August 31, 1993
<PAGE> 111
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A 1st Rev Sub Original Sheet No. 240E
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
20. OPERATING PROVISIONS FOR FIRM TRANSPORTATION SERVICE (Continued)
20.11 Resolution of Imbalances (Continued)
(3) For any contract with an imbalance greater than +10% but less
than or equal to +15%, the volume in excess of +10% will be invoiced
at 120% of the Index Price;
(4) For any contract with an imbalance greater than +15% but less
than or equal to +20%, the volume in excess of +15% will be invoiced
at 130% of the Index Price; and
(5) For any contract with an imbalance greater than +20%, the volume
in excess of +20% will be invoiced at 140% of the Index Price.
(v) For any contract where total receipts by El Paso from a Shipper,
after appropriate reductions, exceed total deliveries for that
Shipper, such imbalance shall be "cashed out" based on the percentages
provided below. Further, the Index Price shall be adjusted to reflect
the point at which the imbalance is held.
(1) For any contract subject to Section 20.11(d) or subject to any
other mutually agreeable terms, with an imbalance up to and including
-5%, the quantity will be purchased by El Paso at 100% of the Index
Price;
(2) For any contract subject to Section 20.11(d) or any contract
with an imbalance greater than -5% but less than or equal to -10%, the
quantity in excess of -5% will be purchased by El Paso at 90% of the
Index Price;
(3) For any contract with an imbalance greater than -10% but less
than or equal to -15%, the volume in excess of -10% will be purchased
by El Paso at 80% of the Index Price;
Issued by: A. W. Clark, Vice President
Issued on: September 13, 1993 Effective: October 1, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-60-011, et al., dated August 31, 1993
<PAGE> 112
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A
1st Rev Sub Original Sheet No. 240F
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
20. OPERATING PROVISIONS FOR FIRM TRANSPORTATION SERVICE (Continued)
20.11 Resolution of Imbalances (Continued)
(4) For any contract with an imbalance greater than -15% but less
than or equal to -20%, the volume in excess of -15% will be purchased
by El Paso at 70% of the Index Price; and
(5) For any contract with an imbalance greater than -20%, the volume
in excess of -20% will be purchased by El Paso at 60% of the Index
Price.
(vi) At the time a Shipper is in a cash-out position requiring
payment to El Paso at the appropriate rate set forth in Section
20.11(e)(iv) above and such Shipper also has an Unauthorized Gas
balance, as such term is defined in Section 27.1 of these General
Terms and Conditions, such Unauthorized Gas balance may be offset
against the quantities due El Paso within the same production basin
and adjusted to reflect the point at which the imbalance is held. At
the time of invoicing for the net imbalance, El Paso shall
appropriately invoice or account for any production area charges and
liquid credits applicable to the unauthorized gas used as an offset.
This provision is not applicable to the Unauthorized Gas retained as a
penalty pursuant to Section 27 of these General Terms and Conditions.
Prior to any offsets, El Paso at its option may first offset any under
or over-deliveries between contracts with such Shipper. Shipper or its
suppliers shall be responsible for reporting and payment of any
royalty, tax, or other burdens on natural gas volumes received by El
Paso and El Paso shall not be obligated to account for or pay such
burdens.
(f) Crediting of Revenues - For any net dollar amount received net
of gas and administrative costs from cash-out assessed on El Paso or
an affiliate of El Paso, El Paso shall credit such net amount within
90 days of the payment date to other Shippers on a pro rata basis in
accordance with the volumes transported for each Shipper.
Issued by: A. W. Clark, Vice President
Issued on: September 13, 1993 Effective: October 1, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-60-011, et al., dated August 31, 1993
<PAGE> 113
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A
1st Rev Sub Original Sheet No. 240G
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
20. OPERATING PROVISIONS FOR FIRM TRANSPORTATION SERVICE (Continued)
20.11 Resolution of Imbalances (Continued)
(g) Netting of Contracts - For purposes of resolving an imbalance
with a Shipper, El Paso is willing to negotiate, on a
non-discriminatory basis, netting of gas imbalances, adjusted to
reflect a common point at which the imbalance is held, between
contracts with such Shipper pursuant to the following conditions:
(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.
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 is 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.
Issued by: A. W. Clark, Vice President
Issued on: September 13, 1993 Effective: October 1, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-60-011, et al., dated August 31, 1993
<PAGE> 114
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A
1st Rev Sub Original Sheet No. 240H
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
20. OPERATING PROVISIONS FOR FIRM TRANSPORTATION SERVICE (Continued)
20.12 Unauthorized Overpull Penalty (Continued)
(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. El Paso shall
notify Shippers each day during an Unauthorized Overpull Penalty
situation, via El Paso's Electronic Bulletin Board, that the situation
continues
Issued by: A. W. Clark, Vice President
Issued on: September 13, 1993 Effective: October 1, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-60-011, et al., dated August 31, 1993
<PAGE> 115
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A
1st Rev Sub Original Sheet No. 240I
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
20. OPERATING PROVISIONS FOR FIRM TRANSPORTATION SERVICE (Continued)
20.12 Unauthorized Overpull Penalty (Continued)
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 apro 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: September 13, 1993 Effective: October 1, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-60-011, et al., dated August 31, 1993
<PAGE> 116
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A
Substitute Original Sheet No. 240J
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
Issued by: A. W. Clark, Vice President
Issued on: April 7, 1993 Effective: April 1, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-60-002, et al., dated March 31, 1993
<PAGE> 117
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff First Revised Sheet No. 240K
First Revised Volume No. 1-A Superseding
Substitute Original Sheet No. 240K
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
20. OPERATING PROVISIONS FOR FIRM TRANSPORTATION SERVICE (Continued)
20.13 Flexible Receipt and Delivery Point(s) (Continued)
be Shipper's 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 Shipper's
primary delivery point(s) is located. In addition, Shipper shall pay
the maximum usage charge(s), unless otherwise provided, applicable to
the production basin(s) and delivery point(s) actually used for the
transportation service. Notwithstanding the applicability of any
contractually agreed-upon lower rate for services using primary
receipt and delivery points, all transportation services using either
an alternate receipt point or alternate delivery point, or both, shall
be subject to the maximum transportation rate for such service, as set
forth in this FERC Gas Tariff, unless El Paso otherwise agrees in
writing at the time the service using such alternate point(s) is
requested.
20.15 Abandonment of Transportation Service - Unless otherwise
provided in the applicable Transportation Service Agreement and
subject to Section 20.16 below, El Paso shall be entitled to avail
itself of the pregranted abandonment authority under Section 7(b) of
the Natural Gas Act of long-term (twelve (12) months or more) firm
transportation services, as authorized by Section 284.221(d) of the
Commission's Regulations, upon the expiration of the contractual term
or upon termination of each individual transportation arrangement and
shall seek offers from competing Shippers interested in receiving such
firm transportation service, as provided below.
Issued by: A. W. Clark, Vice President
Issued on: September 13, 1993 Effective: October 1, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-60-011, et al., dated August 31, 1993
<PAGE> 118
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A
Original Sheet No. 240L
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
20. OPERATING PROVISIONS FOR FIRM TRANSPORTATION SERVICE
20.16 Right-of-First-Refusal
(a) Upon expiration of the term of the Transportation Service
Agreement of a long term Shipper, such Shipper shall have a
"right-of-first-refusal" as prescribed in this Section 20.16. In
order to avail itself of its right-of-first-refusal, the Shipper must
give El Paso its written notice of intent to exercise such right of
first refusal not later than (i) the date of the notice period
provided for in Shipper's contract; or (ii) twelve (12) months prior
to the expiration of the term of the contract, whichever shall first
occur.
(b) El Paso shall post on its electronic bulletin board the terms and
conditions of the available capacity under the expiring contract as
follows:
(i) firm daily quantities stated in Mcf/d;
(ii) the delivery point(s) at which capacity is available and the
firm quantities at such point(s);
(iii) effective date;
(iv) term;
(v) the rate (i.e., Reservation Charge(s) and Usage Charge(s)
applicable to each delivery point);
(vi) minimum conditions; and
(vii) the criteria by which bids are to be evaluated.
(c) Capacity will be made available on a nondiscriminatory basis and
will be assigned on the basis of an open season for a period of not
less than ninety (90) days duration.
(i) Shipper(s) desiring to acquire such available capacity shall
notify El Paso, via its electronic bulletin board, during the open
season. Such notice shall be binding once received by El Paso and
shall not be revocable by such Shipper.
Issued by: A. W. Clark, Vice President
Issued on: September 13, 1993 Effective: October 1, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-60-011, et al., dated August 31, 1993
<PAGE> 119
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A
Original Sheet No. 240M
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
20. OPERATING PROVISIONS FOR FIRM TRANSPORTATION SERVICE (Continued)
20.16 Right-of-First-Refusal (Continued)
(ii) Shipper's bid must include:
(a) Shipper's legal name and, if applicable, the contract number
under which it desires to acquire capacity;
(b) the quantity of capacity to be acquired at each delivery point(s);
(c) the term of the acquisition (the maximum term used for bid
evaluation will be twenty (20) years); and
(d) the maximum rate Shipper is willing to pay for the capacity.
(iii) The potential Shipper must satisfy the other provisions of this
Tariff applicable to requests for firm transportation.
(d) El Paso shall not be obligated to accept any offer for such
capacity at less than the maximum applicable tariff rate. In the event
El Paso accepts an offer, however, El Paso shall inform the existing
Shipper of the terms of such offer. The existing Shipper shall have
seven (7) days in which to inform El Paso that it agrees to match such
offer. Such agreement shall be irrevocable. The existing Shipper or
the offering Shipper, as appropriate, shall execute a Transportation
Service Agreement containing the terms offered or matched.
(e) In the event there are no competing offers, then the existing
Shipper shall not be entitled to continue to receive transportation
service upon the expiration of its contract except by agreeing to pay
the maximum tariff rate unless El Paso and such Shipper shall enter
into a new firm transportation service agreement providing otherwise.
Issued by: A. W. Clark, Vice President
Issued on: September 13, 1993 Effective: October 1, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-60-011, et al., dated August 31, 1993
<PAGE> 120
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Substitute Second Revised Sheet No. 241
First Revised Volume No. 1-A Superseding
First Revised Sheet No. 241
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 and 21, 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: April 30, 1993 Effective: April 1, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-60-002 and 003 dated December 17, 1992
<PAGE> 121
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A
Original Sheet No. 242
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
22. TAKE-OR-PAY BUYOUT AND BUYDOWN COST RECOVERY
The provisions for this Section 22 are contained in Section 21 of the
General Terms and Conditions of El Paso's Volume No. 1 Tariff and are
incorporated herein by reference with respect to those provisions
applicable to the Throughput Surcharge. Such Throughput Surcharge is
applicable to all Shippers subject to El Paso's mainline
transportation rates and/or Rate Schedules contained in this Volume
No. 1-A Tariff.
Issued by: A. W. Clark, Vice President
Issued on: April 26, 1990 Effective: May 1, 1990
<PAGE> 122
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Second Revised Sheet No. 243
First Revised Volume No. 1-A Superseding
First Revised Sheet No. 243
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
23. COMPLIANCE PLAN FOR TRANSPORTATION SERVICES AND AFFILIATE TRANSACTIONS
23.1 The operating personnel and facilities shared by El Paso and
its marketing affiliate(s):
<TABLE>
<CAPTION>
Marketing
El Paso Affiliate(s)
------- ------------
<S> <C> <C>
William A. Wise President and Chief President
Executive Officer
H. Brent Austin Senior Vice President Vice President
and Chief Financial and Treasurer
Officer
Thomas S. Jensen Vice President Vice President
(in charge of gas
merchant operations)
</TABLE>
Other than those persons listed above, there are no other operating
personnel shared between (i) the transportation function of El Paso
and the merchant function of El Paso or (ii) El Paso and its marketing
affiliate(s). Only support systems, including utility,
telecommunication, and computer facilities 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, including
transactions in which an affiliated marketer is involved, are
contained in Section 23.6 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: November 18, 1992 Effective: December 20, 1992
<PAGE> 123
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff First Revised Sheet No. 244
First Revised Volume No. 1-A Superseding
Original Sheet No. 244
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
23. COMPLIANCE PLAN FOR TRANSPORTATION SERVICES AND AFFILIATE TRANSACTIONS
(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 and
Customer Services Department
(Street Address: 304 Texas, 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 The procedures used by El Paso to inform affiliated and
nonaffiliated Shippers and potential Shippers on the availability and
pricing of transportation service are as follows:
(a) Inquiries as to the availability of service on El Paso's system
are to be directed to El Paso's Mainline Transportation and Customer
Services Department and are generally responded to by telephone at
which time the Shipper or potential Shipper is informed verbally of
the availability and pricing of transportation service(s).
(b) Upon request, the initial advisement is supported by sending
copies of El Paso's Volume No. 1-A Tariff and any published Notices to
Shippers announcing discounts them available to all similarly-situated
shippers, to potential Shippers (existing Shippers on the system are
already in receipt of such written documents).
Issued by: A. W. Clark, Vice President
Issued on: November 18, 1992 Effective: December 20, 1992
<PAGE> 124
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A Original Sheet No. 245
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
23. COMPLIANCE PLAN FOR TRANSPORTATION SERVICES AND AFFILIATE TRANSACTIONS
(Continued)
(c) Once a Shipper has executed a Transportation Service Agreement
with El Paso, Shipper will be sent all Notices to to Shippers
announcing subsequent rate discounts available to all
similarly-situated shippers as such Notices are published, and under
the requirements of Rule 2010 of the FERC's Rules of Practice and
Procedure are served with copies of any El Paso filings proposing
changes in rates for and types of transportation service available.
Shippers are subsequently sent copies of revised sheets to El Paso's
Volume No. 1-A Tariff as such sheets are approved and made effective
by the FERC.
(d) El Paso has established a 24-hour "electronic bulletin board,"
to which any Shipper or potential Shipper may subscribe, on which
information concerning the availability and pricing of transportation
service, including all currently effective rates and discount notices,
is posted. For subscription information telephone (915) 541-2000.
The procedures used by El Paso to schedule service and allocate system capacity
are set forth in Section 4 of this Tariff, a copy of which is sent to all
potential Shippers upon request. Consistent with such procedures, after
receiving all requests for transportation service on any day, system
constraints resulting from over-requests for service at various points are
identified, the available capacity allocated, and Shippers advised by
Operations Control Department of the allocated capacity available to that
Shipper.
When El Paso schedules system maintenance activities which may affect available
capacity at various points on the system, Shippers are notified by Operations
Control in advance of such activities and their expected duration. This
information shall also be posted on El Paso's 24-hour "electronic bulletin
board."
Issued by: A. W. Clark, Vice President
Issued on: April 26, 1990 Effective: May 1, 1990
<PAGE> 125
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A Original Sheet No. 246
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
23. COMPLIANCE PLAN FOR TRANSPORTATION SERVICES AND AFFILIATE
TRANSACTIONS (Continued)
23.5. El Paso will maintain a log containing the following
information on all requests for transportation service made by
affiliated or nonaffiliated Shippers or in which an affiliated
or nonaffiliated Shipper is involved, from the time the
information is received until December 31, 1990, or any
extension thereof authorized by the Commission.
(a) The date of receipt of the request;
(b) The date that the request was accepted as valid;
(c) 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;
(d) The extent of the supplier's affiliation with El Paso;
(e) 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;
(f) The maximum daily contract volume of gas requested to be
transported and the total contract volume of gas requested to
be transported over the life of the contract;
(g) The producing area of the source of the gas requested to be
transported;
(h) The date service is requested to commence and terminate;
(i) A list of all receipt and delivery points between which the
gas is requested to be transported and the distance in
pipeline miles between the receipt point and the delivery
point that are the furthest apart;
Issued by: A. W. Clark, Vice President
Issued on: April 26, 1990 Effective: May 1, 1990
<PAGE> 126
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A Original Sheet No. 247
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
23. COMPLIANCE PLAN FOR TRANSPORTATION SERVICES AND AFFILIATE
TRANSACTIONS (Continued)
(j) Whether the service requested is firm or interruptible;
(k) The state of the ultimate end user of the gas;
(l) The identity of the transportation rate schedules and the
transportation rates applicable for such service;
(m) Whether any of the gas being transported is subject to
take-or-pay relief and, if so, how much;
(n) Whether and by how much the cost of the gas to the affiliated
marketer exceeds the price received for the sale of the gas by
the affiliated marketer, after deducting associated costs,
including those incurred for transportation; i.e., whether the
gas is being sold at a loss;
(o) Current status of the request, including whether the request
is: (i) Incomplete, (ii) Complete and awaiting service, (iii)
Complete, a contract signed, and awaiting commencement of
service, (iv) Complete, service has begun and the Commission
docket number assigned to the transaction, (v) Withdrawn, or
(vi) Denied and the reason why;
(p) The position of the request i the transportation
request queue;
Issued by: A. W. Clark, Vice President
Issued on: April 26, 1990 Effective: May 1, 1990
<PAGE> 127
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A Original Sheet No. 248
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
23. COMPLIANCE PLAN FOR TRANSPORTATION SERVICES AND AFFILIATE
TRANSACTIONS (Continued)
(q) The disposition of the request, including the date the
requester was notified of availability of capacity, the date
the contract was executed, the date service actually
commenced, and any explanation concerning the disposition of
the request;
(r) Any complaints by the Shipper or end user concerning the
requested or furnished service and the disposition of such
complaints;
(s) Whether the transportation is being requested, offered or
provided at discounted rates, duration of the discount
requested, offered or provided, the maximum rate or fee, the
rate or fee actually charged during the billing period, the
Shipper, corporate affiliation between the Shipper and the
transporting pipeline, and the quantity of gas scheduled at
the discounted rate during the billing period for each
delivery point; and
(t) Any waiver that El Paso grants with respect to tariff
provisions that provide for a discretionary waiver.
Issued by: A. W. Clark, Vice President
Issued on: April 26, 1990 Effective: May 1, 1990
<PAGE> 128
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Sheet No. 249 Superseding
First Revised Volume No. 1-A Original Sheet No. 249
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
23. COMPLIANCE PLAN FOR TRANSPORTATION SERVICES AND AFFILIATE TRANSACTIONS
(Continued)
23.6 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:
Manager of Mainline
Transportation and 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. 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: March 20, 1992 Effective: May 15, 1992
<PAGE> 129
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A Original Sheet No. 250
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
23. COMPLIANCE PLAN FOR TRANSPORTATION SERVICES AND AFFILIATE
TRANSACTIONS (Continued)
5. Shipper is (check one of the following):
a. ___Interstate Pipeline End-User e. ___End-User
b. ___Intrastate Pipeline* f. ___Producer
c. ___Local Distribution Company* g. ___Marketer
d. ___Hinshaw Pipeline* h. ___Other
(Specify)__________
*State(s) in which Shipper's natural gas system facilities are located:
6. This request is for (check one): _____ New Service
_____ Amended Service Under
Contract # _________
If the request is for new service, please skip the Amended Service
Request section. If the request is for amended service, please
complete the Affiliate Information and Amended Service Request
sections only.
SERVICE/CONTRACT INFORMATION
1. Type of Transportation Service Requested (check one):
___Firm
___Interruptible
___Other ____________________
2. Date service is requested to commence: _____________________
Date service is requested to terminate:_____________________
Evergreen term requested: _____ Yes _____ No
3. Maximum daily contract quantity requested (please specify both):
__________ Mcf/d __________ MMBtu/d
Total contract quantity requested over primary term of agreement (please
specify both): __________ Mcf __________ MMBtu
Issued by: A. W. Clark, Vice President
Issued on: April 26, 1990 Effective: May 1, 1990
<PAGE> 130
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A
Original Sheet No. 251
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. State(s) where gas transported will be consumed ultimately:
___________________________________________________________________
At the time it executes a Transportation Service Agreement, Shipper
shall be required to:
- identify the name of the corporate entity or entities
ultimately receiving the gas if other than a pipeline or local
distribution company purchasing for system supply, which
end-user(s) shall be identified in the Transportation Service
Agreement; and
- provide El Paso with verification that the end-user(s) have
signed sales contracts to use the transportation services
provided for in the Transportation Service Agreement.
7. 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: April 26, 1990 Effective: May 1, 1990
<PAGE> 131
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A
Original Sheet No. 252
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
23. COMPLIANCE PLAN FOR TRANSPORTATION SERVICES AND AFFILIATE TRANSACTIONS
(Continued)
8. Name of Shipper's dispatcher for 24-hour contact:
____________________________
Phone: __________________ Telecopy: _____________________
9. Is the gas to be transported subject to take-or-pay relief to El Paso?
___ Yes ___ No ___ Unknown
If YES, what percentage of total contract quantity? _____%
RATE INFORMATION ________________
1. Does Shipper request a discounted rate? ___Yes ___No
2. If YES, please specify the selectively discounted rate(s) requested
and the related service(s): ________________________________________
____________________________________________________________________
____________________________________________________________________
3. If El Paso is unable or unwilling to provide service at the requested
discounted rate, is Shipper willing to pay the maximum rate(s) for the
requested service(s) (to include any published discounts available to
all similarly situated Shippers)?
___Yes ___No
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: April 26, 1990 Effective: May 1, 1990
<PAGE> 132
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A
Original Sheet No. 253
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
23. COMPLIANCE PLAN FOR TRANSPORTATION SERVICES AND AFFILIATE TRANSACTIONS
(Continued)
Based on its review of Shipper's financial statements, El Paso may agree to
waive any further credit requirements as a condition of service.
Alternatively, El Paso may request Shipper to provide additional evidence of
its creditworthiness, in which event Shipper may elect to provide one of the
following:
- a clean irrevocable letter of credit in form and substance
satisfactory to El Paso in a face amount equal to (i) the sum
of the gas cost component of El Paso's sale-for-resale rates
and the applicable unit transportation rate(s) specified in El
Paso's Tariff for the service(s) which El Paso provides
Shipper, (ii) multiplied by the maximum daily quantity
specified in El Paso's Transportation Service Agreement with
Shipper, (iii) multiplied by 90; or
- a guarantee, in form and substance satisfactory to El Paso,
executed by a person whom El Paso deems creditworthy, of
Shipper's performance of its obligations to El Paso under the
Transportation Service Agreement; or
- such other form of security as Shipper may agree to provide
and as may be acceptable to El Paso.
The FERC Gas Tariff of El Paso does not require the pipeline to provide
transportation service on behalf of any Shipper who fails to demonstrate
creditworthiness. El Paso will treat the financial statements provided by
Shipper as confidential.
AFFILIATE INFORMATION _____________________
1. Is Shipper affiliated with El Paso: ___Yes ___No
If YES, please state specific affiliation:
_________________________________________________________________
Issued by: A. W. Clark, Vice President
Issued on: April 26, 1990 Effective: May 1, 1990
<PAGE> 133
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A
Original Sheet No. 254
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
If YES, please state specific affiliation:
________________________________________________
3. Is Shipper's or the Requesting Party's supplier affiliated with
El Paso: ___Yes ___No
If YES, please state specific affiliation:
_________________________________________________
4. If gas transported is being purchased from an El Paso affiliate, or if
the Requesting Party or Shipper is an El Paso affiliate, does the cost
of gas to that affiliate exceed its sales price, less associated costs
including transportation expenses, i.e., is the gas being sold at a
loss?
___Yes ___No ___Unknown
If YES, specify amount of loss: ____________________________
AMENDED SERVICE REQUEST _______________________
1. Addition of Receipt Point(s) -- Add the Receipt Point(s) identified
on Exhibit A to Contract # ____________
Is the gas to be transported from the additional Receipt Point(s)
subject to take-or-pay relief to El Paso?
___Yes ___No ___Unknown
If YES, what percentage of total contract quantity? _____%
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 serve queue.)
State(s) in which the gas transported to the additional Delivery
Point(s) will ultimately be consumed:
___________________________________________________________________
Issued by: A. W. Clark, Vice President
Issued on: April 26, 1990 Effective: May 1, 1990
<PAGE> 134
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A
Original Sheet No. 255
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 serve 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 or will have title to 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: April 26, 1990 Effective: May 1, 1990
<PAGE> 135
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A
Original Sheet No. 256
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 of
Requested Maximum Total Volume Source
Receipt Point(s)* Daily Volume (Over Term) of Gas*
<S> <C> <C> <C>
_______________ _____Mcf/d _____Mcf ________
_____MMBtu/d _____MMBtu
_______________ _____Mcf/d _____Mcf ________
_____MMBtu/d _____MMBtu
_______________ _____Mcf/d _____Mcf ________
_____MMBtu/d _____MMBtu
_______________ _____Mcf/d _____Mcf ________
_____MMBtu/d _____MMBtu
_______________ _____Mcf/d _____Mcf ________
_____MMBtu/d _____MMBtu
_______________ _____Mcf/d _____Mcf ________
_____MMBtu/d _____MMBtu
_______________ _____Mcf/d _____Mcf ________
_____MMBtu/d _____MMBtu
</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: April 26, 1990 Effective: May 1, 1990
<PAGE> 136
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A
Original Sheet No. 257
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
_____MMBtu/d _____MMBtu
_______________ _____Mcf/d _____Mcf
_____MMBtu/d _____MMBtu
_______________ _____Mcf/d _____Mcf
_____MMBtu/d _____MMBtu
_______________ _____Mcf/d _____Mcf
_____MMBtu/d _____MMBtu
_______________ _____Mcf/d _____Mcf
_____MMBtu/d _____MMBtu
_______________ _____Mcf/d _____Mcf
_____MMBtu/d _____MMBtu
_______________ _____Mcf/d _____Mcf
_____MMBtu/d _____MMBtu
</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: April 26, 1990 Effective: May 1, 1990
<PAGE> 137
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff First Revised Sheet No. 258
First Revised Volume No. 1-A Superseding
Substitute Original Sheet No. 258
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
24. ORDER No. 636 ELECTRONIC BULLETIN BOARD
24.1 El Paso's Electronic Bulletin Board ("EBB") is accessed
through its electronic communications service known as
"Passport". Passport provides a portfolio of electronic
business services to El Paso's customers. El Paso's EBB is
available on a non-discriminatory basis to any party that has
compatible equipment for electronic transmission of data,
provided that such party has entered into a Passport
Electronic Network Agreement and has been assigned a user
identification, password and security code. Access to the
EBB may be obtained by contacting Passport Services at (915)
541-2000. There is no charge to use the EBB.
24.2 El Paso's EBB shall provide such data as described in and
shall be in compliance with FERC Order No. 636, et seq., by
providing:
(a) a means for all firm shippers to post their "grandfathered"
buy/sell transactions, for informational purposes only, for a period
of thirty (30) days identifying price, terms and conditions and name
of the parties; and (b) a means for a releasing or acquiring Shipper
electing to release all or a portion of its firm transportation rights
in accordance with Section 28.4 and Section 28.5 contained in this
Volume No. 1-A Tariff to advertise such release.
24.3 Parties wishing to bid on released capacity or to compete with
pre-arranged offers shall post their bids through the EBB. Only those
parties who are prequalified with respect to creditworthiness in
accordance with Section 28.20 contained in El Paso's Volume No. 1-A
Tariff may submit a bid during the open season in accordance with
Section 28.9 contained in said Tariff.
24.4 The EBB shall contain information concerning the availability
of capacity: (a) at receipt points; (b) on the mainline; (c) at
delivery points; and
Issued by: A. W. Clark, Vice President
Issued on: September 13, 1993 Effective: October 1, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-60-011, et al., dated August 31, 1993
<PAGE> 138
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff Second Revised Sheet No. 259
First Revised Volume No. 1-A Superseding
First Revised Sheet No. 259
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
24. ORDER No. 636 ELECTRONIC BULLETIN BOARD (Continued)
24.4 The EBB shall contain information concerning the availability
of capacity: (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: September 13, 1993 Effective: October 1, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-60-011, et al., dated August 31, 1993
<PAGE> 139
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A
Sheet Nos. 260 through 262
Reserved Sheets
Original Sheet Nos. 260 through 262 have been reserved.
Issued by: A. W. Clark, Vice President
Issued on: April 7, 1993 Effective: April 1, 1993
<PAGE> 140
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff First Revised Sheet No. 263
First Revised Volume No. 1-A Superseding
Sheet Nos. 263 through 269
The following sheets have been superseded:
Substitute Original Sheet No. 263
Original Sheet No. 264
Substitute Original Sheet Nos. 265 through 269
Issued by: A. W. Clark, Vice President
Issued on: April 15, 1993 Effective: January 1, 1993
<PAGE> 141
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff First Revised Sheet No. 270
First Revised Volume No. 1-A Superseding
Sheet Nos. 270 through 276
Reserved Sheets
Second Revised Sheet No. 270 and First Revised
Sheet Nos. 271 through 276 have
been reserved.
Issued by: A. W. Clark, Vice President
Issued on: September 13, 1993 Effective: October 1, 1993
<PAGE> 142
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A
1st Rev Sub Original Sheet No. 277
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: September 13, 1993 Effective: October 1, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-60-011, et al., dated August 31, 1993
<PAGE> 143
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A
1st Rev Sub Original Sheet No. 278
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
27. UNAUTHORIZED GAS (Continued)
27.2 (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 Period") to resolve the
Unauthorized Gas volumes; provided however, that any such resolution
must be approved by El Paso. El Paso and the party agree to
negotiate in good faith for resolution of the Unauthorized Gas and to
commit in writing during the Return Period any mutually agreed upon
resolution. If El Paso incorrectly classifies gas as Unauthorized
Gas, El Paso will transfer such gas to the appropriate agreement and
will not assess any penalties under this Section 27 on such volumes.
27.5 Unauthorized Gas Prior to the Effectiveness of this Section -
For any Unauthorized Gas volumes delivered to El Paso prior to the
effectiveness of this section, said party shall have six (6) months
after El Paso's notification ("Extended Return Period") to resolve the
Unauthorized Gas volumes; provided however, that any such resolution
must be approved by El Paso. El Paso and the party agree to
negotiate in good faith for resolution of the Unauthorized Gas and to
commit to writing during this Extended Return Period any mutually
agreed upon resolution.
Issued by: A. W. Clark, Vice President
Issued on: September 13, 1993 Effective: October 1, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-60-011, et al., dated August 31, 1993
<PAGE> 144
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A
1st Rev Sub Original Sheet No. 279
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: September 13, 1993 Effective: October 1, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-60-011, et al., dated August 31, 1993
<PAGE> 145
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A
1st Rev 1st Sub Original Sheet No. 280
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
27. UNAUTHORIZED GAS (Continued)
27.9 Challenging El Paso's Classification of Unauthorized Gas - Any
party claiming an interest in volumes of natural gas which El Paso has
determined to be Unauthorized Gas may challenge that determination by
the first day of the month following receipt from El Paso of the
notice of Unauthorized Gas. Such challenge shall be in writing and
include all documentation upon which such party relies to substantiate
its challenge. El Paso shall hold such gas until a final
determination has been reached as to the classification of the gas in
question. If no such challenge is received by El Paso within the
period specified, then El Paso's determination that the quantities in
question were Unauthorized Gas shall be final. Upon a determination
that El Paso incorrectly classified natural gas as unauthorized, El
Paso shall correct all records and make gas available, subject to
operational conditions, within sixty (60) days of such determination.
27.10 Accounting for Retained Unauthorized Gas and Penalties - El
Paso shall record the value of the Unauthorized Gas retained (pursuant
to Sections 27.2 and 27.6(b) of this tariff) and the penalty payments
received by El Paso (pursuant to Section 27.6(a) of this tariff) in
the appropriate revenue account. The Unauthorized Gas volumes
retained shall be valued at the lesser of the value determined for the
month the Unauthorized Gas is retained or for the month the proceeds
from the retained Unauthorized Gas are to be credited to eligible
Shippers. The value of such retained Unauthorized Gas shall be based
on the appropriate index price for each production basin (Anadarko,
Permian or San Juan). Such calculation shall be in accordance with
Sections 20.11(e)(i)(1), (2) or (3), respectively, of this tariff.
Any Shipper who has a valid Transportation Service Agreement providing
for mainline transportation services shall be eligible to receive a
share of the value of the Unauthorized Gas volumes retained (less
production area charges and other burdens, if any) 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 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: September 13, 1993 Effective: October 1, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-60-011, et al., dated August 31, 1993
<PAGE> 146
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A
3rd Substitute Original Sheet No. 281
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 (1) week prior to the
beginning of the month(s) for which such conversion is to be
effective. For purposes of determining capacity rights of such
Shipper, El Paso will utilize either the Shipper's billing
determinants
Issued by: A. W. Clark, Vice President
Issued on: September 13, 1993 Effective: April 1, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-60-011, et al., dated August 31, 1993
<PAGE> 147
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A
2nd Substitute Original Sheet No. 282
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
28. CAPACITY RELEASE PROGRAM (Continued)
28.2 Applicability (Continued) 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 pre-arranged
release for which notice is given pursuant to Section 28.5.
(d) Acquiring Shipper - any Shipper who acquires released capacity
rights from a Releasing Shipper.
(e) Firm Recallable Capacity - firm capacity released subject to
the Releasing Shipper's right to recall such capacity during the term
of the release.
(f) Acquired Capacity Agreement - an agreement between El Paso and
the Acquiring Shipper setting forth rate(s) and the terms and
conditions of service for using capacity rights acquired pursuant to
this Section 28, in the form contained in Section 28.25 of this Volume
No. 1-A Tariff.
28.4 Notice by Shipper Electing to Release Capacity - A Releasing
Shipper shall deliver a notice via El Paso's electronic bulletin board
that it elects to release firm capacity. The notice shall set forth:
Issued by: A. W. Clark, Vice President
Issued on: April 7, 1993 Effective: April 1, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-60-002, et al., dated March 31, 1993
<PAGE> 148
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A
2nd Substitute Original Sheet No. 283
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
28. CAPACITY RELEASE PROGRAM (Continued)
28.4 Notice by Shipper Electing to Release Capacity (Continued)
(a) Releasing Shipper's legal name, contract number, and the name
and title of the individual responsible for authorizing the release of
capacity;
(b) the maximum and minimum (if desired) quantity of firm daily
capacity which the Releasing Shipper desires to release, stated in
Mcf/d;
(c) the delivery point(s) at which the Releasing Shipper will release
capacity and the firm capacity to be released at each such point;
(d) whether capacity will be released on a firm or firm recallable
basis and, if on a firm recallable basis, the terms on which the
capacity can be recalled, which terms must be objectively stated,
non-discriminatory and applicable to all bidders;
(e) the requested effective date and the term of the release;
(f) whether the Releasing Shipper is willing to consider release
for a shorter time period than that specified in (e) above, and,
if so, the minimum (if desired) acceptable period of release;
(g) whether the Releasing Shipper desires bids in dollars or as a
percentage of El Paso's maximum reservation charge(s) and reservation
surcharge(s) applicable to the capacity to be released under this
Volume No. 1-A Tariff as in effect from time to time;
(h) the maximum reservation charge(s) and reservation surcharge(s)
applicable to the capacity being released as shown on El Paso's
Statement of Rates applicable to the Releasing Shipper's
Transportation Service Agreement or Acquired Capacity Agreement and
whether the Releasing Shipper is willing to consider releasing
capacity at a lower rate;
Issued by: A. W. Clark, Vice President
Issued on: April 7, 1993 Effective: April 1, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-60-002, et al., dated March 31, 1993
<PAGE> 149
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A
3rd Substitute Original Sheet No. 284
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
28. CAPACITY RELEASE PROGRAM (Continued)
28.4 Notice by Shipper Electing to Release Capacity (Continued)
(i) whether the Releasing Shipper desires to release capacity on the
basis of a volumetric reservation charge and, if so, whether bids
shall be stated in dollars or as a percentage of El Paso's maximum
reservation charge(s) and reservation surcharge(s) in accordance with
Section 28.16 below;
(j) whether Option 1, Option 2, Option 3 or Option 4 of Section 28.10
shall be used to determine the highest bidder and, if Option 3 is
selected, the criteria by which bids are to be evaluated; whatever
evaluation option the Releasing Shipper chooses, it may establish and
post objective, non-discriminatory minimum conditions for an
acceptable bid, subject to the provisions of Section 28.4(q) set forth
below;
(k) the weight for each factor if bids will be evaluated using the
Option 1 weighted composite bid method;
(l) the method by which ties will be broken;
(m) whether the Releasing Shipper wants El Paso to market its released
capacity in accordance with Section 28.17;
(n) the duration of the open season and of the matching period if
longer than the minimums specified in Section 28.8 below;
(o) the date and time the notice is posted on the electronic bulletin
board;
(p) whether the Releasing Shipper is willing to accept contingent bids
that extend beyond the open season and, if so, any non-discriminatory
terms and conditions applicable to such contingencies including the
date by which such contingency must be satisfied (which date shall be
no later than two (2) business days prior to the first day the
Acquired Capacity Agreement is to be effective) and whether, or for
what time period, the next highest bidder will be obligated to acquire
the capacity should the winning contingent bidder be unable to satisfy
the contingency specified in its bid; and
Issued by: A. W. Clark, Vice President
Issued on: September 13, 1993 Effective: April 1, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-60-011, et al., dated August 31, 1993
<PAGE> 150
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A
2nd Substitute Original Sheet No. 285
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
28. CAPACITY RELEASE PROGRAM (Continued)
28.4 Notice by Shipper Electing to Release Capacity (Continued)
(q) whether the Releasing Shipper's notice will state minimum
conditions or that such Shipper has revealed such minimums to El Paso
which conditions shall not be revealed during the open season; and
(r) any other applicable conditions.
A Releasing Shipper including any Shipper with a pre-arranged release
that is subject to an open season, may withdraw such notice regardless
of whether a valid bid has been received, at any time prior to the
close of the open season set forth in Section 28.8 if such withdrawal
is due to an unanticipated need for the capacity; provided, however,
that once the notice is withdrawn, both the offer to release and any
bids received during the open season shall remain posted on the
electronic bulletin board for a period of thirty (30) days for
monitoring and control purposes.
28.5 Notice of Pre-Arranged Release - The Releasing Shipper shall
deliver a notice via El Paso's electronic bulletin board of a
pre-arranged release. The notice shall set forth all of the
information on the terms of the release called for in Section 28.4
above and all of the information called for in Section 28.9 below
required to define the pre-arranged bid. In addition, it shall
specify if the pre-arranged bid is for the maximum applicable
reservation rate, whether the Releasing Shipper is seeking bids to
compete with the non-rate provisions of the pre-arranged bid. The
Releasing Shipper shall also designate if it is seeking bids when the
release of capacity is for less than one (1) month.
28.6 Term of Released Capacity - The term of any release of firm
capacity shall not exceed the term of the Transportation Service
Agreement or Acquired Capacity Agreement under which releasing occurs,
nor shall it be less than one (1) full gas flow day.
28.7 Availability of Released Capacity - Released capacity shall be
made available on a nondiscriminatory basis and shall be assigned on
the basis of an open season or pre-arrangement in accordance with the
procedures described in Sections 28.8 and 28.10 below.
Issued by: A. W. Clark, Vice President
Issued on: April 7, 1993 Effective: April 1, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-60-002, et al., dated March 31, 1993
<PAGE> 151
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A
2nd Substitute Original Sheet No. 286
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
28. CAPACITY RELEASE PROGRAM (Continued)
28.8 Open Season and Matching Period - The minimum term of any open
season to be held as a consequence of the posting by a Releasing
Shipper of its election to release capacity in accordance with
Sections 28.4 or 28.5 hereof shall be as specified below, except that:
(1) no open season shall be required for a pre-arranged release that
is for the maximum reservation charge(s) and reservation surcharge(s)
applicable to the rate schedule pursuant to which capacity is released
under this Volume No. 1-A Tariff as in effect from time to time; and
(2) no open season shall be required for a pre-arranged release with a
duration of less than one month regardless of the rate bid.
(a) Capacity released under a pre-arrangement, 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 pre-arranged release and initiating the
appropriate open season. A Releasing Shipper may not re-release
capacity subject to this paragraph (a) to the same Acquiring Shipper
until 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 pre-arranged bid, the open season must commence at least
three (3) business days prior to the effective date of the release to
allow for a minimum of one (1) business day for the Pre-Arranged
Shipper to match any bids received during the open
Issued by: A. W. Clark, Vice President
Issued on: April 7, 1993 Effective: April 1, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-60-002, et al., dated March 31, 1993
<PAGE> 152
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A
2nd Substitute Original Sheet No. 287
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
28. CAPACITY RELEASE PROGRAM (Continued)
28.8 Open Season and Matching Period (Continued) season. If the
bids are to be 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: April 7, 1993 Effective: April 1, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-60-002, et al., dated March 31, 1993
<PAGE> 153
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A
2nd Substitute Original Sheet No. 288
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
28. CAPACITY RELEASE PROGRAM (Continued)
28.8 Open Season and Matching Period (Continued)
(f) With respect to any pre-arranged release which is not subject to
an open season, the Releasing Shipper shall post notice not later than
forty-eight (48) hours after the transaction commences.
(g) If any Releasing Shipper agrees to accept a contingent bid
pursuant to Section 28.4(p) the beginning of the open season as set
forth in Sections 28.8(a), (b), (c), (d) and (e) above shall start
earlier by the number of business days so stated by the Releasing
Shipper.
28.9 Bids for Released Capacity - A bid may be submitted to El
Paso by a Bidding Shipper at any time during the open season via El
Paso's electronic bulletin board.
(a) Each bid for released capacity must include the following:
(i) Bidding Shipper's legal name, address, and the name and title of
the individual responsible for authorizing the bid; (ii) the term of
the proposed acquisition;
(iii) 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 volume;
(v) whether or not the Bidding Shipper is an affiliate of the
Releasing Shipper;
(vi) whether the bid is a contingent bid and the contingency which
must be satisfied before the date specified by the Releasing Shipper
pursuant to Section 28.4(p) above; and
(vii) all other information requested by the Releasing Shipper.
(b) Any bid received by El Paso during the open season shall be posted
on El Paso's electronic bulletin board
Issued by: A. W. Clark, Vice President
Issued on: April 7, 1993 Effective: April 1, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-60-002, et al., dated March 31, 1993
<PAGE> 154
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A
2nd Substitute Original Sheet No. 289
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
28 CAPACITY RELEASE PROGRAM (Continued)
28.9 Bids for Released Capacity (Continued)
(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: April 7, 1993 Effective: April 1, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-60-002, et al., dated March 31, 1993
<PAGE> 155
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A
2nd Substitute Original Sheet No. 290
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
28. CAPACITY RELEASE PROGRAM (Continued)
28.10 Awarding of Released Capacity (Continued)
(b) If a bid is received that exceeds the minimum but does not conform
completely to the reservation charge(s) and reservation surcharge(s)
and all the terms and conditions specified in the Releasing Shipper's
notice, then the Acquiring Shipper(s) shall be the Bidding Shipper(s)
who offer(s) the highest bid determined under Option 1, Option 2,
Option 3 or Option 4 below, as applicable. Provided, however, if such
bid was submitted as a bid in an open season relating to a
pre-arranged release and the Pre-Arranged Shipper matches such offer,
then the capacity shall be awarded pursuant to Section 28.10(g)
hereof. If bids from two or more Bidding Shippers result in bids of
equal rank then the capacity shall be awarded in accordance with
Section 28.10(f) hereof. El Paso shall evaluate and rank all bids
submitted during the open season. If Bidding Shipper has not removed
its contingency by the date specified by the Releasing Shipper
pursuant to Section 28.4(p) hereof, such bid shall be deemed to have
been withdrawn.
(i) Default Bid Evaluation Criteria - If Releasing Shipper does not
specify otherwise, all bids will be evaluated pursuant to Option 1
with equal weighting factors on all three criteria.
Issued by: A. W. Clark, Vice President
Issued on: April 7, 1993 Effective: April 1, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-60-002, et al., dated March 31, 1993
<PAGE> 156
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A
2nd Substitute Original Sheet No. 291
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 ______%
</TABLE>
c
---
* d = b x a
(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 = volume stated in Mcf or
Issued by: A. W. Clark, Vice President
Issued on: April 7, 1993 Effective: April 1, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-60-002, et al., dated March 31, 1993
<PAGE> 157
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A
2nd Substitute Original Sheet No. 292
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
component's actual weight. Once all bid components are calculated,
an actual composite weighting will be determined for each bid by
summing the bid weightings for each component. The bids will then be
ranked in order from the highest to the lowest actual weighted
composite score.
Issued by: A. W. Clark, Vice President
Issued on: April 7, 1993 Effective: April 1, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-60-002, et al., dated March 31, 1993
<PAGE> 158
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A
2nd Substitute Original Sheet No. 293
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
28. CAPACITY RELEASE PROGRAM (Continued)
28.10 Awarding of Released Capacity (Continued)
(d) If Option 2 is selected by the Releasing Shipper, then, at the end
of the open season, El Paso shall calculate a Net Present Value for
each bid received, with the bids being ranked in order from the
highest to the lowest Net Present Value.
(e) If no bids are received which meet or exceed all of the minimum
conditions specified by the Releasing Shipper, no capacity shall be
awarded. If any bids are received which meet or exceed the Releasing
Shipper's minimum criteria, El Paso shall rank all such bids in
accordance with the criteria specified in the notice of release and
shall award the capacity to the successful Bidding Shipper(s). Any
Bidding Shipper who would receive less than the minimum acceptable bid
volume shall not be obligated to accept released capacity.
(f) If bids from two or more Bidding Shippers result in bids of equal
score, the Acquiring Shipper(s) shall be determined based upon the tie
breaking method designated by the Releasing Shipper, and if none is
specified, by a lottery. The lottery shall be conducted by El Paso
on a non-discriminatory basis. Capacity shall be awarded in
accordance with the order of draw, with capacity awarded to the
first-drawn Bidding Shipper up to the volume bid by such Shipper, and,
if any released capacity remains after such award, it shall be offered
to other Bidding Shippers in the lottery in accordance with the order
of draw. Any Bidding Shipper who, by virtue of its place in the
order of draw, receives less than the minimum acceptable bid volume
shall not be obligated to accept released capacity. The results of
the lottery shall be posted on El Paso's electronic bulletin board.
(g) If a pre-arranged release is for the maximum reservation charge(s)
and reservation surcharge(s) under this Volume No. 1-A Tariff, as in
effect from time to time, and meets all other terms and conditions
imposed by the Releasing Shipper, then the Pre-Arranged Shipper shall
become the Acquiring Shipper. Service to such Acquiring Shipper may
begin on the next scheduling day after award of the
Issued by: A. W. Clark, Vice President
Issued on: April 7, 1993 Effective: April 1, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-60-002, et al., dated March 31, 1993
<PAGE> 159
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A
2nd Substitute Original Sheet No. 294
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
28. CAPACITY RELEASE PROGRAM (Continued)
28.10 Awarding of Released Capacity (Continued) capacity and
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: April 7, 1993 Effective: April 1, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-60-002, et al., dated March 31, 1993
<PAGE> 160
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A
2nd Substitute Original Sheet No. 295
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: April 7, 1993 Effective: April 1, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-60-002, et al., dated March 31, 1993
<PAGE> 161
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A
2nd Substitute Original Sheet No. 296
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
28 CAPACITY RELEASE PROGRAM (Continued)
28.12 Notice of Completed Transactions (Continued)
(d) volume in Mcf;
(e) whether the capacity is firm or firm recallable;
(f) all conditions, including any minimums, concerning the release;
(g) the names of the Releasing Shipper and the Acquiring Shipper; and
(h) whether or not the Acquiring Shipper is an affiliate of the
Releasing Shipper or El Paso.
28.13 Effective Date of Release and Acquisition - The effective date
of the release by a Releasing Shipper and acquisition by an Acquiring
Shipper shall be on the date so designated in the Acquired Capacity
Agreement or Transportation Service Agreement referenced in Section
28.11 above.
28.14 Notice by El Paso of Uncommitted Firm Capacity - In the
event E 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 or of a pre-arrangement
concerning such capacity, setting forth the same information as
prescribed in Section 28.4 or Section 28.5, as applicable, and the
capacity shall be awarded using the procedures specified by Sections
28.8 and 28.10; provided, however, that 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 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
Issued by: A. W. Clark, Vice President
Issued on: April 7, 1993 Effective: April 1, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-60-002, et al., dated March 31, 1993
<PAGE> 162
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A
2nd Substitute Original Sheet No. 297
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
28. CAPACITY RELEASE PROGRAM (Continued)
28.15 Notice of Offer to Purchase Capacity (Continued)
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
Service Agreement and any other applicable charges and such Acquiring
Shipper shall pay the billed
Issued by: A. W. Clark, Vice President
Issued on: April 7, 1993 Effective: April 1, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-60-002, et al., dated March 31, 1993
<PAGE> 163
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A
Substitute Original Sheet No. 297A
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
28. CAPACITY RELEASE PROGRAM (Continued)
28.18 Billing (Continued)
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 later
Issued by: A. W. Clark, Vice President
Issued on: April 7, 1993 Effective: April 1, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-60-002, et al., dated March 31, 1993
<PAGE> 164
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A
Substitute Original Sheet No. 297B
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
28. CAPACITY RELEASE PROGRAM (Continued)
28.19 Nominations and Scheduling (Continued)
than the close of Day 1 scheduling for the day on which the recall is
to take effect. Releasing Shipper, when returning recalled capacity
to the Acquiring Shipper(s), shall give El Paso and such Acquiring
Shipper(s) notice prior to the close of Day 1 scheduling for the day
on which the capacity is to revert to the Acquiring Shipper(s).
28.20 Qualification for Participation in the Capacity Release
Program - Any Shipper wishing to become a Bidding Shipper, or a
potential Pre-Arranged Shipper, must satisfy the creditworthiness
requirements of El Paso's transportation tariff by pre-qualifying
prior to submitting a bid for capacity or prior to becoming a party
to a pre-arranged release. Once a Shipper becomes an Acquiring
Shipper, such Shipper can be subject to an annual credit review with
respect to its eligibility to make additional bids on other offers of
released capacity. A Shipper cannot bid for services which exceed its
qualified level of creditworthiness. Notwithstanding such
qualification to participate in the open season, El Paso does not
guarantee the payment of any outstanding amounts by an Acquiring
Shipper.
28.21 Compliance by Acquiring Shipper - By acquiring released
capacity, an Acquiring Shipper agrees that it will comply with the
terms and conditions of El Paso's certificate of public convenience
and necessity authorizing this Capacity Release Program and all
applicable Commission orders and regulations, including Part 284
thereof. Such Acquiring Shipper also agrees to be responsible to El
Paso for compliance with all terms and conditions of El Paso's Volume
No. 1-A Tariff, as well as the terms and conditions of the Acquired
Capacity Agreement. End user lists shall not be required.
28.22 Obligations of Releasing Shipper - The Releasing Shipper
shall continue to be liable and responsible for all reservation
charge(s) and reservation surcharge(s) associated with the released
capacity up to the maximum reservation charge(s) and reservation
surcharge(s) specified in such Releasing Shipper's Transportation
Service Agreement or Acquired Capacity Agreement. Re-releases by an
Acquiring Shipper shall not relieve the original or any subsequent
Releasing Shipper of its obligations under this section.
Issued by: A. W. Clark, Vice President
Issued on: April 7, 1993 Effective: April 1, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-60-002, et al., dated March 31, 1993
<PAGE> 165
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A
Substitute Original Sheet No. 297C
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
28. CAPACITY RELEASE PROGRAM (Continued)
28.23 Flexible Receipt and Delivery Point(s) - Shipper(s) using
Acquired Capacity Agreements may utilize alternate receipt and
delivery point(s) pursuant to the conditions contained in Section
20.13 of this Volume No. 1-A Tariff which is incorporated herein.
28.24 Refunds - In the event that the Commission orders refunds of any
rates charged by El Paso, El Paso shall flow-through refunds to any
Acquiring Shipper to the extent that such Shipper has paid a rate in
excess of El Paso's just and reasonable, applicable maximum rates.
28.25 Acquired Capacity Agreement -
Acquired Capacity Agreement
Between
El Paso Natural Gas Company
and
---------------------------
THIS AGREEMENT is made and entered into as of this day _______ of
________, by and between EL PASO NATURAL GAS COMPANY, a Delaware ________
corporation, hereinafter referred to as "El Paso," and ________, a ____________
corporation, hereinafter referred to as "Acquiring Shipper."
WHEREAS, El Paso and _________________, hereinafter referred
_________________ to as "Releasing Shipper," are parties to a ________________
Agreement under Rate Schedule ___ contained in El Paso's FERC Gas ___
Tariff________, First Revised Volume No. 1-A, dated __________ (contract
_____________ code
WHEREAS, Acquiring Shipper desires to acquire all or a portion of the
firm capacity rights to be released from said ____________________________
Agreement.
NOW THEREFORE, in consideration of the promises and premises
hereinafter set forth, El Paso and Acquiring Shipper agree as follows:
Issued by: A. W. Clark, Vice President
Issued on: April 7, 1993 Effective: April 1, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-60-002, et al., dated March 31, 1993
<PAGE> 166
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A
1st Substitute Original Sheet No. 297D
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
28. CAPACITY RELEASE PROGRAM (Continued)
28.25 Acquired Capacity Agreement (Continued)
1. Acquiring Shipper agrees to comply with the terms and conditions
of El Paso's certificate of public convenience and necessity issued by
the Commission authorizing El Paso's Capacity Release Program and with
Section 28 of the General Terms and Conditions contained in El Paso's
Volume No. 1-A Tariff. In addition, Acquiring Shipper agrees to
comply with all other terms and conditions of said Volume No. 1-A
Tariff as well as the terms and conditions set forth herein.
2. The following capacity rights, which are released through the
Capacity Release Program, are acquired at the Receipt Point(s) and
Delivery Point(s) designated below:
Receipt Point(s): Those Receipt Point(s) set forth in the
_____________________________ Agreement.
Delivery Point(s)
The Delivery Point(s) as specified in the Notice posted pursuant to
Sections 28.4 or 28.5 of El Paso's Volume No. 1-A Tariff. If the
Releasing Shipper does not limit the Acquiring Shipper's rights to the
primary Delivery Point(s) specified in the Notice, then the Acquiring
Shipper may designate any primary Delivery Point(s) within the same
zone as the Releasing Shipper's primary Delivery Point(s), 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
Issued by: A. W. Clark, Vice President
Issued on: September 13, 1993 Effective: April 1, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-60-011, et al., dated August 31, 1993
<PAGE> 167
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A
1st Substitute Original Sheet No. 297E
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
28. CAPACITY RELEASE PROGRAM (Continued)
28.25 Acquired Capacity Agreement (Continued)
responsible for exercising such recall, in accordance with the
provisions of Section 28.19 of El Paso's Volume No. 1-A Tariff. (The
foregoing paragraph shall be applicable to Acquiring Shipper(s) who
acquire firm recallable capacity.)
4. For capacity acquired hereunder, Acquiring Shipper shall pay El
Paso each month the charges set forth below:
5. This Agreement shall become effective on and continue in full
force and effect through unless terminated pursuant to Section 28.18
of El Paso's Volume No. 1-A Tariff.
6. Other terms: As specified in the Notice posted pursuant to
Sections 28.4 or 28.5 of El Paso's Volume No. 1-A Tariff.
7. Any formal notice, request or demand that either party gives to
the other respecting this Agreement, shall be in writing and shall be
mailed by registered or certified mail or delivered by hand to the
following address of the other party:
El Paso: El Paso Natural Gas Company
Post Office Box 1492
El Paso, Texas 79978
Attention: Director, Mainline Transportation and
Customer Services Department
Acquiring Shipper:
Notices regarding recall rights shall also be delivered by telephone,
facsimile, or El Paso's electronic system.
8. Acquiring Shipper hereby certifies that it has or will have title
to 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: September 13, 1993 Effective: April 1, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-60-011, et al., dated August 31, 1993
<PAGE> 168
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A
Original Sheet No. 297F
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: April 7, 1993 Effective: April 1, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-60-002, et al., dated March 31, 1993
<PAGE> 169
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A
Substitute Original Sheet No. 298
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: November 4, 1993 Effective: October 1, 1993
Issue to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-60-016, et al., dated October 29, 1993
Tariff Sheet Subject to Further Modification
<PAGE> 170
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A
Substitute Original Sheet No. 299
TRANSPORTATION GENERAL TERMS AND CONDITIONS
(Continued)
30. ASSIGNMENT OF FIRM CAPACITY ON UPSTREAM PIPELINES
30.1 Purpose - This Section 30 sets forth the terms and conditions
under which El Paso shall assign, in whole or in part, the rights and
obligations under contracts held by El Paso for firm capacity on
upstream jurisdictional pipelines.
30.2 Applicability - This Section 30 shall apply to any firm Shipper
who accepts assignment of any or all of El Paso's firm transportation
capacity rights described in Section 30.1 above.
30.3 Availability of Capacity - El Paso's firm upstream capacity shall
be made available on a nondiscriminatory basis and shall be assigned
on the basis of an open season in accordance with the procedures
described in Section 30.6 below.
30.4 Permanent Assignment - All assignments pursuant to this Section
30 shall be for the entire remaining term of El Paso's contract with
such upstream pipeline.
30.5 Rate - The rate for such assigned capacity shall be as
established by the tariff of such upstream pipeline or as otherwise
negotiated between the Shipper and upstream pipeline. El Paso shall
not charge any fee in connection with the assignment of its capacity
on the upstream pipeline.
30.6 Open Season - Upon the effectiveness of this Section 30, El Paso
shall conduct an open season for a period of fifteen (15) days by
posting a notice of such availability on its electronic bulletin
board. In order for a Shipper to participate in this open season,
Shipper shall submit to El Paso a completed bid in the form set forth
in Section 30.9 below. If Shippers' requests for capacity exceed the
available firm capacity during the open season, such capacity shall be
allocated among the requesting Shippers based on a lottery. After the
open season, El Paso will allocate all requests for available capacity
on a first-come/first-served basis.
30.7 Qualifications for Assignment - Shipper must satisfy any
applicable requirements of the upstream pipeline's tariff, including
creditworthiness.
Issued by: A. W. Clark, Vice President
Issued on: April 30, 1993 Effective: April 1, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-60-002 and 003 dated December 17, 1992
<PAGE> 171
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A
Substitute Original Sheet No. 299A
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. Upsream Contract _______________________________
6. Contract Quantity ______________________________
7. Receipt Point(s) ______________________________
______________________________
______________________________
Delivery Point(s) ____________________________
____________________________
____________________________
8. Requested Begin
Date ____________________________
Issued by: A. W. Clark, Vice President
Issued on: April 30, 1993 Effective: April 1, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-60-002 and 003 dated December 17, 1992
<PAGE> 172
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A
Substitute Original Sheet No. 299B
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: April 30, 1993 Effective: April 1, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-60-002 and 003 dated December 17, 1992
<PAGE> 173
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A
Original Sheet No. 299C
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, et al., "Prospective Period."
The Monthly
Issued by: A. W. Clark, Vice President
Issued on: September 13, 1993 Effective: October 1, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-60-011, et al., dated August 31, 1993
<PAGE> 174
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff First Revised Sheet No. 299D
First Revised Volume No. 1-A Superseding
Original Sheet No. 299D
GENERAL TERMS AND CONDITIONS
(Continued)
31. WASHINGTON RANCH FACILITY STRANDED INVESTMENT COST RECOVERY (Continued)
31.3 Definitions (Continued)
Amortized Amounts 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. 25 and 26 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. 24 and 25 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: November 29, 1993 Effective: January 1, 1994
<PAGE> 175
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A
Original Sheet No. 299E
GENERAL TERMS AND CONDITIONS
(Continued)
31. WASHINGTON RANCH FACILITY STRANDED INVESTMENT COST RECOVERY (Continued)
31.4 Determination of the Reservation Surcharge and Monthly Amortized
Amount (Continued)
(b) El Paso shall adjust the Monthly Amortized Amount for interest
calculated on the unrecovered balance of El Paso's stranded investment
costs as set forth below. Interest shall commence to accrue with
respect to El Paso's stranded investment costs effective February 1,
1993.
(i) Effective with the Settlement at Docket No. RP92-214-000, et al.,
El Paso shall include the actual accrued interest from February 1,
1993 through the effective date and estimated interest through
December 31, 1993 utilizing the actual Interest Rate (if the actual
Interest Rate is unknown the interest rate shall be estimated),
divided by the number of months remaining in 1993 to derive the
interest adjustment to the Monthly Amortized Amount.
(ii) Effective for the six (6) months commencing January 1, 1994, El
Paso shall reflect any differences resulting from the use of estimated
versus actual accrued interest for the period February 1, 1993 through
December 31, 1993. Any resulting difference shall be added to or
deducted from the estimated interest for the six (6) month period
commencing January 1, 1994. The total interest shall be divided by
six (6) to determine the monthly interest for such Recovery Period.
(iii) At the end of each six (6) month period following June 30, 1994
through the termination of the Amortization Period, El Paso shall
calculate an estimate for the projected interest expense for the next
six (6) month Recovery Period. At the same time, El Paso shall
calculate the actual interest expense that would have accrued during
the previous Recovery Period. This actual interest amount will be
compared to the previously estimated interest amount for such period
and any resulting difference shall be added to or deducted from the
next six (6)
Issued by: A. W. Clark, Vice President
Issued on: September 13, 1993 Effective: October 1, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-60-011, et al., dated August 31, 1993
<PAGE> 176
EL PASO NATURAL GAS COMPANY
FERC Gas Tariff
First Revised Volume No. 1-A
Original Sheet No. 299F
GENERAL TERMS AND CONDITIONS
(Continued)
31. WASHINGTON RANCH FACILITY STRANDED INVESTMENT COST RECOVERY (Continued)
31.4 Determination of the Reservation Surcharge and Monthly Amortized
Amount (Continued)
month interest projection, divided by six (6) months to derive the
interest for the applicable Recovery Period.
(iv) Effective the third month following the end of the Amortization
Period, El Paso shall calculate the actual interest for any past
period of estimated interest utilizing the appropriate Interest Rate,
and shall make a one time adjustment to reflect the appropriate amount
to each Shipper's invoice.
(c) In the event the Transportation Service Agreement of any existing
Shipper terminates during any Recovery Period, the unamortized portion
of the costs inclusive of interest allocated to such Shipper under
this Section 31.4 will be due within thirty (30) days or such other
period as mutually agreed to by El Paso and Shipper, not to extend
beyond the termination of the Amortization Period.
(d) Each Shipper subject to this Section 31 shall have the option of
paying the amount allocated to it in a lump sum or over a shorter
Amortization Period if desired, with an appropriate interest
adjustment.
31.5 True-up of Actual Versus Estimated Loss or Gain Realized from the
Sale of Washington Ranch Gas Inventory - El Paso shall adjust the
remaining unamortized balance to reflect the difference between the
actual gain or loss and the previously estimated gain or loss from the
sale of gas inventory from the Washington Ranch Facility. Such
adjustment shall be reflected in El Paso's earliest semi-annual filing
following one year's effectiveness of this Section 31. Such
adjustment shall be reflected in the balance as of February 1, 1993
for interest accrual purposes.
Issued by: A. W. Clark, Vice President
Issued on: September 13, 1993 Effective: October 1, 1993
Issued to comply with order of the Federal Energy Regulatory
Commission, Docket No. RS92-60-011, et al., dated August 31, 1993
<PAGE> 1
Exhibit 10.9
THE PACIFIC GAS AND ELECTRIC COMPANY
SAVINGS FUND PLAN
FOR MANAGEMENT EMPLOYEES
This is the controlling and definitive statement of the Pacific Gas and
Electric Company Savings Fund Plan for MANAGEMENT EMPLOYEES 1/ in effect on and
after January 1, 1994. 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.
ELIGIBILITY AND PARTICIPATION
1. Eligibility
A MANAGEMENT EMPLOYEE becomes an ELIGIBLE EMPLOYEE upon completion
of one year of SERVICE. Once eligibility occurs it continues as long as
the employee remains a MANAGEMENT EMPLOYEE and SERVICE continues.
2. Participation
To become a participant, an ELIGIBLE EMPLOYEE must submit a completed
APPLICATION to the PLAN ADMINISTRATOR. Through the APPLICATION, the
ELIGIBLE EMPLOYEE:
(a) authorizes 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;
(b) elects to make NON-Section 401(k) CONTRIBUTIONS, if any, to the
PLAN; and
(c) instructs 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 28.
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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. A participant in the COMPANY'S Flex Plan may elect to
have any unused FLEXDOLLARS contributed to this PLAN. A participant
shall make the election on such forms and subject to such rules as
may be established from time to time by the Flex Plan Administrator.
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 submitting a completed APPLICATION 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 an
appropriate, correctly completed APPLICATION.
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.
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(1) Certain Section 401(k) and non-Section 401(k) CONTRIBUTIONS
are 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
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 average rate of Section 401(k) CONTRIBUTIONS as a
percentage of compensation for all other participating
ELIGIBLE EMPLOYEES multiplied by 2 but only if the average
rate of Section 401(k) CONTRIBUTIONS for the participating
ELIGIBLE HIGHLY COMPENSATED EMPLOYEES does not exceed by more
than 2 percentage points the average rate of Section 401(k)
CONTRIBUTIONS for all other participating ELIGIBLE EMPLOYEES,
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
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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(a)(8).
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 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, but
only if the average rate of NON-Section 401(k) CONTRIBUTIONS
and EMPLOYER CONTRIBUTIONS for the participating HIGHLY
COMPENSATED ELIGIBLE EMPLOYEES does not exceed by more than 2
percentage points the average rate of NON-Section 401(k)
CONTRIBUTIONS and EMPLOYER CONTRIBUTIONS for all other
participating ELIGIBLE EMPLOYEES, 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 EMPLOYEE in the group, of the amount
of NON-Section 401(k) CONTRIBUTIONS and EMPLOYER CONTRIBUTIONS made
by and on behalf of
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<PAGE> 5
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(a)(8).
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 be reduced in one percent increments until the maximum
permissible average rate of contributions is met.
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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 April 15 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 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)
CONTRI-
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BUTIONS, (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) CONTRIBUTIONS
until the Section 415 limitations are met.
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<PAGE> 8
(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.
If a participant is also a participant in the COMPANY'S RETIREMENT
PLAN, the Internal Revenue Code provides that the sum of the defined
benefit plan fraction and the defined contribution plan fraction for
any PLAN YEAR shall not exceed 1.0. The defined benefit plan
fraction for any PLAN YEAR is a fraction, the numerator of which is
the participant's projected annual benefit under the COMPANY'S
RETIREMENT PLAN (determined at the close of the PLAN YEAR) and the
denominator of which is the greater of the product of 1.25
multiplied by the projected current accrued benefit; or the lesser
of: (i) the product of 1.25 multiplied by the maximum dollar
limitation provided under CODE Section 415(b)(1)(A) for a PLAN YEAR,
or (ii) the product of 1.4 multiplied by the amount which may be
taken into account under CODE Section 415(b)(1)(B) for such PLAN
YEAR.
(1) For purposes of applying the limitations of CODE Section 415,
the projected annual benefit for any participant is the
benefit, payable annually, under the terms of the RETIREMENT
PLAN determined pursuant to Regulation Section 1.415-7(b)(3).
(2) For purposes of applying the limitations of CODE Section 415,
projected current accrued benefit for a participant in the
RETIREMENT PLAN shall be the accrued benefit, payable
annually, provided for under question T-3 of the Internal
Revenue Service Notice 83-10.
The defined contribution plan fraction for any PLAN YEAR is a
fraction, the numerator of which is the sum of the annual additions
to the participants' accounts in this PLAN and in any other defined
contribution plan maintained by the EMPLOYER in such PLAN YEAR and
the denominator of which is the sum of the lesser of the following
amounts determined for such PLAN YEAR and each prior year of SERVICE
with an EMPLOYER: (i) the product of 1.25 multiplied by the dollar
limitation in effect under CODE Section 415(c)(1)(A) for such PLAN
YEAR (determined without regard to CODE Section 415(c)(6), or (ii)
the product of 1.4 multiplied by the amount which may be taken into
account under CODE Section 415(c)(1)(B) for such year. For years
beginning before January 1, 1987, the annual additions shall not be
recomputed to treat all NON-Section 401(k) CONTRIBUTIONS as an
annual addition. Notwithstanding the foregoing, the numerator of
the defined contribution plan fraction shall be adjusted pursuant to
Regulation Section 1.415-7(d)(1) and questions T-6 and T-7 of
Internal Revenue Service Notice 83-10. 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
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416(g) of the CODE, the provision contained in Special Provision A
shall supersede any conflicting provision of the PLAN.
SELECTION OF INVESTMENT FUNDS
6. (a) Section 401(k) CONTRIBUTIONS. A participant shall direct the PLAN
ADMINISTRATOR to invest his Section 401(k) CONTRIBUTIONS in one or
more INVESTMENT FUNDS. The minimum amount which can be invested in
any single INVESTMENT FUND shall be twenty percent of a
participant's current Section 401(k) 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 five percent of the participant's current Section
401(k) CONTRIBUTIONS.
(b) NON-Section 401(k) CONTRIBUTIONS. A participant who is making
NON-Section 401(k) CONTRIBUTIONS to the PLAN shall direct the PLAN
ADMINISTRATOR to invest his NON-Section 401(k) CONTRIBUTIONS in one
or more INVESTMENT FUNDS. A participant's directions as to the
investment of participant NON-Section 401(k) CONTRIBUTIONS shall be
separate and distinct from investment directions given for Section
401(k) CONTRIBUTIONS. The minimum amount of NON-Section 401(k)
CONTRIBUTIONS which may be invested in any single FUND shall be
twenty percent of a participant's current NON-Section 401(k)
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 five percent of the
participant's current NON-Section 401(k) CONTRIBUTIONS.
(c) EMPLOYER CONTRIBUTIONS. A participant shall direct the PLAN
ADMINISTRATOR to invest the matching EMPLOYER CONTRIBUTIONS
allocated to his account into one or more INVESTMENT FUNDS. The
minimum amount which can be invested in any single INVESTMENT FUND
shall be twenty percent of the matching EMPLOYER CONTRIBUTIONS
currently allocated to the participant's account. A participant's
directions as to the investment of matching EMPLOYER CONTRIBUTIONS
shall be separate and distinct from investment directions given for
Section 401(k) CONTRIBUTIONS and NON-Section 401(k) CONTRIBUTIONS.
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 five percent of the current matching EMPLOYER
CONTRIBUTIONS allocated the participant's account. If the PLAN
ADMINISTRATOR has not received directions from a participant as to
the investment of matching EMPLOYER CONTRIBUTIONS allocated to the
participant's account, the PLAN ADMINISTRATOR shall invest EMPLOYER
CONTRIBUTIONS in COMPANY STOCK.
(d) CHANGE OF INVESTMENT FUND ALLOCATIONS. By submitting the
appropriate Form 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. A participant shall be permitted to make one such change
in any CALENDAR QUARTER.
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THE INVESTMENT FUNDS
7. Company Stock Fund
This FUND is invested entirely in Common Stock of the COMPANY. The FUND
also holds all 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. All cash
dividends received by the TRUSTEE on COMPANY STOCK are reinvested in
COMPANY STOCK and credited to the participant account in which the
COMPANY STOCK is held. COMPANY STOCK received by the TRUSTEE as a stock
dividend or stock right or from a stock split or bought with cash
obtained from the sale of a stock right, warrant or option is similarly
credited to the account in which the underlying COMPANY STOCK is held.
(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) directly from the
COMPANY at an averaged cost, (ii) at a public sale on a recognized
stock exchange, or (iii) from a private source at a price no higher
than the price that would have been payable under (ii).
(b) Dividends. Cash dividends or other cash received by the TRUSTEE on
COMPANY STOCK shall be reinvested in additional COMPANY STOCK at the
averaged cost.
(c) Computation of Cost of Stock. The cost to the TRUSTEE of all
COMPANY STOCK purchased directly from the COMPANY shall be the
averaged cost. The averaged cost is the average of the mid-points
of the daily high and low composite prices as shown in the Pacific
Coast Edition of the WALL STREET JOURNAL (subject to verification)
for the period for which the money was contributed. The averaged
cost for COMPANY STOCK purchased with dividends will be averaged
over the five trading days immediately preceding receipt of the
dividends by the TRUSTEE. The cost to the TRUSTEE of all COMPANY
STOCK purchased at a public sale on a recognized stock exchange
shall be the average of the purchase prices paid for all stock
required for a given periodic contribution. Thus, if the TRUSTEE is
required to purchase stock for a contribution to the PLAN over
several days, the purchase price for all of the shares shall be the
average of the prices paid during the days required to make the
total purchase.
(d) 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 in a participant's account.
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
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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 will no longer accept 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. 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 from time-to-time by the DEF INVESTMENT
MANAGER (but no less frequently than once a week), 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. The FUND seeks to
provide investment results that correspond to the price and yield
performance of common stocks of selected utilities engaged in the
generation, transmission, or distribution of electric energy, as
represented by an index comprising the common stocks of companies that
are members of the Edison Electric Institute. Stocks in the FUND's
portfolio are generally held in the same proportions that each stock has
within the index. Seeking to duplicate the index as closely as possible,
the portfolio is monitored and adjusted by computer; no attempt is made
to manage the portfolio in the traditional sense using economic,
financial, and market analyses.
Contributions to the USF are paid to the TRUSTEE and invested in
accordance with the instructions from the USF INVESTMENT MANAGER. A
participant's account is credited with the number of USF UNITS purchased
with contributions allocated to his account.
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<PAGE> 12
(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 from time to time by the TRUSTEE (but no less
frequently than once a week), 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 maintained to invest in contracts which offer a rate of
interest guaranteed by the issuer for a specified period of time.
For employee contributions made to the GIF before April 1, 1990, the
conditions applicable to this FUND varied in accordance with the terms of
the contract in effect at the time a participant invested his
contributions in the GIF. For example, withdrawal provisions, the
applicable rate of interest, the period in which contributions may be
made, and the length of the contract are all terms which were subject to
negotiation and market conditions.
Contributions made to the GIF on or after April 1, 1990, are invested in
a portfolio of contracts in which each contract offers a guaranteed rate
of interest for a specified period of time. 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 weekly to the
participant's account.
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. The BIF INVESTMENT MANAGER
directs the day-to-day investment of the BIF.
Contributions to the BIF are paid over to the TRUSTEE and invested in
accordance with instructions received from the BIF INVESTMENT MANAGER. A
participant's account is credited with the number of BIF UNITS purchased
with contributions allocated to his account.
(a) Cost of BIF UNITS. The cost of a BIF UNIT shall be the current
value of a UNIT as determined by the TRUSTEE as of the valuation
date immediately preceding the date that the TRUSTEE invests
contributions in the FUND.
(b) Value of BIF UNITS. The value of a BIF UNIT is the value of the BIF
assets, as determined from time to time by the TRUSTEE (but no less
frequently than once a week), 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
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<PAGE> 13
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. 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 from time-to-time by the TRUSTEE (but no less
frequently than once a week), 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 participant may elect to transfer INVESTMENT FUND UNITS held in his
account, plus the earnings thereon, to another INVESTMENT FUND or FUNDS.
A participant shall be permitted to make one such change in any CALENDAR
QUARTER effective July 1, 1992. INVESTMENT FUND UNITS attributable to
EMPLOYER CONTRIBUTIONS, plus earnings thereon, may also be transferred.
(a) Eligible Transfer Between FUNDS. By submitting the appropriate
transfer Form to the PLAN ADMINISTRATOR, a participant may transfer
all or a portion of the UNITS held in any INVESTMENT FUND to another
FUND or FUNDS except as follows:
(1) UNITS held in the U.S. Bond FUND are not eligible for transfer
to any other FUND. Effective July 1, 1991 transfers cannot be
made from another FUND to the U.S. Bond FUND.
(2) GIF UNITS attributable to employee contributions or transfers
into the GIF before April 1, 1990 are not eligible for
transfer to other FUNDS until the expiration of the applicable
contract.
(3) GIF UNITS attributable to employee contributions or transfers
into the GIF on or after April 1, 1990 are transferable to any
other fund except the MONEY MARKET INVESTMENT FUND.
A transfer from one FUND to another FUND shall be in a minimum
amount of twenty percent of the number of UNITS held
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<PAGE> 14
in the FUND from which the transfer is made. A participant may
elect to transfer more than twenty percent of the UNITS held in
any FUND to another FUND, provided, however, that any such greater
amount must be in increments of five percent of the number of UNITS
held in the FUND from which the transfer is made. Transfers shall
be made as soon as practicable, but in no event later than 30 days,
after receipt by the TRUSTEE of a completed transfer Form.
Upon receipt of the transfer Form, 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.
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<PAGE> 15
16. Account Statements
As soon as practicable after the end of each CALENDAR QUARTER, all
participants will receive from the ADMINISTRATOR a statement of their
interest in the PLAN.
PLAN WITHDRAWALS
17. Withdrawal During Service
Except as provided in this Section, withdrawals of any part of a
participant's interest in the PLAN are not permitted as long as SERVICE
continues. A participant may never replace in the TRUST FUND any UNITS
or cash which have been withdrawn. By submitting a withdrawal Form, a
participant may make withdrawals as provided below.
(a) 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.
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<PAGE> 16
A request for a withdrawal under this subsection 17(a)(2) will
not be deemed to be for immediate and heavy financial needs
unless the participant represents that the need cannot be met
from the following resources:
(a) through reimbursement or compensation by insurance or
otherwise,
(b) by reasonable liquidation of the participant's resources,
(c) by cessation of contributions to the PLAN, or
(d) by other distributions, withdrawals or nontaxable loans
from any plans maintained by an EMPLOYER, or by
borrowing from commercial sources on reasonable
commercial terms.
For purposes of this Subsection 17(a)(2), a participant's
resources shall be deemed to include any assets of his spouse
and minor children that are reasonably available to the
participant. In addition, withdrawals under Subsection
17(a)(2) may not exceed the amount actually required to meet
the participant's immediate financial needs.
(3) A participant who withdraws UNITS under Subsection 17(a) will
automatically be suspended from the PLAN and will not be
permitted to resume making contributions to the PLAN for six
months following the date upon which the withdrawal Form is
processed by the PLAN ADMINISTRATOR. After suspension ends,
contributions may be resumed by submitting a new APPLICATION.
(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
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<PAGE> 17
(c) the participant has requested and is entitled to receive
a hardship distribution which meets the requirements of
Subsection 17(a)(2).
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 and
the manner in which the withdrawal is to be allocated among the
INVESTMENT FUNDS. 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. Upon submission of the appropriate Form(s) to
the PLAN ADMINISTRATOR, 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.
19. Distribution of Plan Benefits
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
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<PAGE> 18
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 sell the
COMPANY STOCK on the open market and distribute the cash proceeds less
brokerage commissions, together with the then current value of the
INVESTMENT FUND UNITS and uninvested cash. Until the TRUSTEE sells
COMPANY STOCK or converts INVESTMENT FUND UNITS to cash, UNITS shall
continue to share in investment gains and losses. Distributions from the
BOND FUND can only be made in United States BONDS.
ADMINISTRATIVE PROVISIONS
20. 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 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.
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<PAGE> 19
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.
22. 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.
23. 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,
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(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.
24. 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.
25. 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.
26. 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.
27. 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
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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.
28. Definitions
<TABLE>
<S> <C>
Administrator: Employee Benefit Administrative
------------- Committee, 201 Mission Street,
19th Floor, Mail Code P19A,
P.O. Box 770000, San Francisco,
California 94177
Application: A form prepared by the Administrator
----------- which must be completed by any Eligible
Employee to become a participant, or by
a participant to suspend participation
or change future contributions.
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 his Division or General
Office Personnel Department.
Board of Directors: The Board of Directors of Pacific Gas
------------------ and Electric Company.
</TABLE>
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<PAGE> 22
<TABLE>
<S> <C>
Bond Fund: A fund invested in United States Savings Bonds. (See Section 8)
---------
Bond Index Fund: A fund invested in marketable fixed-income securities. (See Section 12)
---------------
Bonds: Series "EE" Savings Bonds issued by the United States Treasury. If the issuance of Series
----- "EE" Bonds is discontinued, Bonds will refer to any other Bond issued by the United States
Treasury which the Employee Benefit Finance Committee selects for purchase under the Plan.
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, or earnings from an Employer in excess of $150,000 for 1994, or such other amount
permitted by the Secretary of the Treasury under Section 401(a)(17) of the Code.
</TABLE>
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<PAGE> 23
<TABLE>
<S> <C>
DEF: The Diversified Equity Fund.
---
Diversified Equity Fund: A fund invested in a diversified portfolio of securities. (See Section 9)
-----------------------
Eligible Employee: One entitled to become a contributing participant, provided, however, a "leased
----------------- employee," as defined in Section 414(n)(2) of the Code shall not be entitled to become an
Eligible Employee.
Employee Benefit The Employee Benefit Administrative Committee referred to in Section 22.
----------------
Administrative Committee:
------------------------
Employee Benefit Finance The Employee Benefit Finance Committee referred to in Section 21.
------------------------
Committee:
---------
Employer: Pacific Gas and Electric Company, Pacific Gas Transmission Company, Alaska
-------- California LNG Company, Pacific Gas Marine Company, Pacific Gas LNG Terminal Company, the
Pacific Service Employees Association, and any other company or association designated by
the Board of Directors as eligible to participate in the Plan.
Employer Contributions: Any contributions to the Plan by Company.
----------------------
FlexDollars: Amounts which a participant elects pursuant to the Company's Flex Plan to contribute
----------- as 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 Investment Fund.
---
Guaranteed Investment 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 under the
------------------ rules of Code Section 414(q) and the regulations issued thereunder.
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
</TABLE>
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<PAGE> 24
<TABLE>
<S> <C>
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 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.
Management Employee: A monthly salaried employee who is not
------------------- represented by a union.
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.
Plan: This Company's Savings Fund Plan for
----- Management Employees, as amended,
revised and set forth herein.
</TABLE>
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<PAGE> 25
<TABLE>
<S> <C>
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, 19th Floor
------------------------ Mail Code P19A
P.O. Box 770000
San Francisco, CA 94177
Section 401(k) Contributions: 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 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 or
Date: dies; or
----
</TABLE>
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<PAGE> 26
<TABLE>
<S> <C>
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 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
</TABLE>
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<PAGE> 27
<TABLE>
<S> <C>
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 Company Stock Fund and
the Bond Fund, a unit shall be a share
of common stock and a United States
Bond, respectively.
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>
-27-
<PAGE> 28
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 compensation set by subsection (c).
(3) 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 COVERED COMPENSATION (as defined in Section 4
for purposes of applying the dollar limitations on contribution 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). 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 as does not exceed $200,000 (adjusted
in the same manner as the amount set forth in subsection (d) below).
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.
-28-
<PAGE> 29
(c) Limitation on Contributions
Annual compensation taken into account under this Section for purposes of
computing benefits under this PLAN shall not exceed the first $200,000,
provided that such limit shall be adjusted automatically for each PLAN YEAR to
the amount prescribed by the Secretary of the Treasury or his delegate pursuant
to regulations for the calendar year in which such PLAN YEAR commences. A
participant's compensation shall be his compensation as defined in Section 4
for purposes of applying the dollar 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.
(d) 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 apply for such PLAN YEAR
as if amended so that the "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".
(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 (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).
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<PAGE> 30
(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 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.
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<PAGE> 31
(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 distributions to
employees which represented the entire amount credited to
their accounts under the applicable plan.
(C) Further, in making such determination, in any case where an
individual is a "non-key employee" as defined in subsection
(h) below, with respect to an applicable plan, but was a key
employee with respect to such plan for any prior PLAN YEAR,
any accrued benefit and any account of such employee shall be
altogether disregarded. For this purpose, to the extent that a
key employee is deemed to be a key employee if he or she met
the definition of key employee within any of the four
preceding PLAN YEARS, this provision shall apply following the
end of such period of time.
(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 having an annual compensation greater
than 150 percent of the amount in effect under Section 415(c)(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, the highest-paid officers shall be selected.
Business organizations other than corporations shall be deemed to
have no officers.
-31-
<PAGE> 32
(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
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 EMPLOYER or stock possessing
more than one percent of the combined total voting power of all
stock of the EMPLOYER. For purposes of this subsection,
compensation means all items includable as compensation for purposes
of applying the limitations on contributions and other annual
additions to a participant's account in a defined contribution plan
and the maximum benefit payable under a defined benefit plan under
the CODE.
For purposes of parts (1), (2), (3) and (4) of this definition, a
BENEFICIARY of a key employee shall be treated as a key employee.
For purposes of parts (3) and (4), each EMPLOYER is treated
separately (without regard to the definition in subsection (i)) in
determining ownership percentages; but, in determining the amount of
compensation, the definition of EMPLOYER in subsection (i) is taken
into account.
(h) Non-key Employee
The term "non-key employee" means any employee (and any beneficiary or an
employee) who is not a key employee.
(i) Employer
The term "employer" as defined in Section 28 of this PLAN.
(j) Distributions to Key Employees
Any other provision of this PLAN to the contrary notwithstanding,
distribution of the entire interest in this PLAN of each participant who is or
at 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.
-32-
<PAGE> 1
Exhibit 10.10
PERFORMANCE INCENTIVE PLAN
OF
THE PACIFIC GAS AND ELECTRIC COMPANY
This is the controlling and definitive statement of the Performance
Incentive Plan ("PLAN"1/ or "PIP") of the Pacific Gas and Electric Company and
participating subsidiaries, affiliates, and associations. The purpose of the
PLAN is to benefit ratepayers and shareholders by rewarding employees for
overall COMPANY performance, as well as for FUNDING UNITS and individual
achievements. The PLAN was first adopted in 1983 and has since been amended
from time to time. The COMPANY reserves the right to amend, suspend, or
terminate the PLAN in its sole discretion at any time.
ARTICLE I
DEFINITIONS
1.01 Committee shall mean the Compensation and Management Development
Committee of the Board of Directors of the COMPANY.
1.02 Company shall mean the Pacific Gas and Electric Company, a
California corporation.
1.03 PIP or Plan shall mean the Performance Incentive Plan, formerly
called the "Management Incentive Plan," as set forth herein and as may be
amended from time to time.
1.04 Plan Administrator shall mean the Committee or such individual or
individuals as the Committee may appoint to handle the day-to-day affairs of
the PLAN and to issue the annual PIP Administrative Guidelines.
1.05 Plan Participant shall mean each individual who, under the PIP
Administrative Guidelines adopted by the PLAN ADMINISTRATOR, is eligible to
receive a PLAN award for the YEAR.
1.06 Unit shall mean each of the separate organizational units of the
COMPANY which, by function, make up each line of business. UNITS are defined
by the Chief Executive Officer before the beginning of the PLAN YEAR.
__________________________________
1/ Words in all capitals are defined in Article I.
<PAGE> 2
1.07 Year shall mean a calendar year.
ARTICLE II
ELIGIBILITY
2.01 Prior to each YEAR, the PLAN ADMINISTRATOR will issue PIP
Administrative Guidelines which will set forth the criteria for receiving
awards under the PLAN. The PIP Administrative Guidelines will contain rules
for determining PLAN eligibility including, but not limited to, eligibility for
individuals who are newly hired, on leaves of absence, deceased, or retired.
The PIP Administrative Guidelines shall also specify the conditions under which
awards will be prorated and which elements of pay will be included in the
calculation of a PIP Award. The PIP Administrative Guidelines shall be
attached hereto and made a part hereof and shall be available for review at the
request of PLAN PARTICIPANTS.
ARTICLE III
ANNUAL PERFORMANCE MEASURES
3.01 Each YEAR the COMMITTEE shall determine the criteria used to
measure the COMPANY's annual performance. The COMMITTEE shall determine the
performance measures for the Chief Executive Officer for each YEAR. The Chief
Executive Officer, in conjunction with the senior officer of each UNIT, shall
set the performance measures for each UNIT for the YEAR. The Chief Executive
Officer shall determine the performance measures for those executive officers
who are not included in a UNIT. Performance measures for each YEAR shall be
attached to the PLAN and are made a part of hereof.
3.02 Each YEAR the Board of Directors shall approve the individual
target participation rate for the Chief Executive Officer. The COMMITTEE shall
determine the annual individual target participation rates applicable to all
other PLAN PARTICIPANTS. A schedule of the individual target participation
rates for each YEAR shall be attached to the PLAN and are made a part hereof.
3.03 As soon as practicable after the beginning of each YEAR, the senior
officer of each UNIT shall determine and communicate work group and/or
individual performance measures for PLAN PARTICIPANTS in the UNIT.
2
<PAGE> 3
3.04 The COMMITTEE retains the right to adjust or modify any of the
performance measures to reflect extraordinary events which may affect the
COMPANY, or if in its sole opinion, application of any of the performance
measures substantially overstates or understates actual COMPANY performance.
ARTICLE IV
PLAN AWARDS
4.01 As soon as practicable after the end of the YEAR, the actual
performance of the COMPANY, each of the UNITS, and PLAN PARTICIPANTS (to the
extent that PLAN PARTICIPANTS have individual performance measures) will be
measured against the performance measures adopted for the YEAR.
4.02 PLAN awards will be based upon the target participation rate
applicable to each PLAN PARTICIPANT, as modified by actual performance for the
YEAR. Individual awards under the PLAN will be made prior to the end of the
first quarter of the year.
4.03 The COMMITTEE retains the right to terminate the PLAN at any time
prior to the payment of any award which may be earned under the PLAN.
ARTICLE V
ADMINISTRATIVE PROVISIONS
5.01 Administration. The PLAN shall be administered by the PLAN
ADMINISTRATOR who shall have the authority to interpret the PLAN and make such
rules as it deems appropriate. The PLAN ADMINISTRATOR shall have the duty and
responsibility of maintaining records, making the requisite calculations, and
disbursing payments hereunder. The PLAN ADMINISTRATOR's interpretations,
determinations, rules, and calculations shall be final and binding on all
persons and parties concerned.
3
<PAGE> 1
Exhibit 10.11
THE PACIFIC GAS AND ELECTRIC COMPANY
RETIREMENT PLAN
<PAGE> 2
PART I
APPLICABLE TO MANAGEMENT EMPLOYEES ONLY
TABLE OF CONTENTS
RETIREMENT PLAN
<TABLE>
<CAPTION>
Page
----
<S> <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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
8. Pensions Where Employment Ends Before Age 55 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
9. Deferred Retirement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
10. Forms of Pension . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
11. Spouse's Pension . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
12. Withdrawal of Participant Contributions on Termination of Employment . . . . . . . . . . . . . . . . . . . . . . . 9
13. Death Benefits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
14. Facility of Payment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
15. Benefits Are Not Assignable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
16. Employer Contributions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
17. Company's Powers and Duties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
18. Funding and Investment Provisions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
19. Administration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12
20. Claims Procedure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12
21. Amendment, Termination, and Merger . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13
22. Definitions and Cross-References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13
SPECIAL PROVISIONS A, B, C, D, E, F, G, H, I, J, K and M . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .19-72
</TABLE>
<PAGE> 3
RETIREMENT PLAN
1. Introduction
This is the controlling and definitive statement of the Pacific Gas
and Electric Company Retirement Plan which, with certain exceptions, is
effective on and after January 1, 1994, for EMPLOYEES 1/ 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 1988.
Except for pension adjustments provided for in Special Provision G,
PARTICIPANTS who retire or terminate employment before the effective date
of any amendment are not affected or benefited by such amendments.
Since final regulations governing many statutory requirements of the
Employee Retirement Income Security Act of 1974 (ERISA) have not yet been
issued, the COMPANY reserves the right to retroactively modify the final
language of the revised PLAN to conform to these requirements.
It is proposed to use the ERISA "elapsed" time rules for determining
SERVICE under the PLAN for covered employment after 1975.
The PLAN is intended to be a single employer plan for all purposes
under the Employee Retirement Security Act of 1974 (ERISA), as amended,
and the Internal Revenue Code of 1954, as amended.
This PLAN consists of Part I and Part II. Part I applies solely to
MANAGEMENT EMPLOYEES, and Part II applies solely to NON-MANAGEMENT
EMPLOYEES (all other employees).
__________________________________
1/ Words in all capitals are defined in Section 22.
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<PAGE> 4
PART I
APPLICABLE TO MANAGEMENT EMPLOYEES ONLY
2. Eligibility and Participation
An EMPLOYEE automatically becomes a PARTICIPANT in the PLAN on the
first day of work for an EMPLOYER, and participation continues until the
PARTICIPANT's SERVICE is terminated.
3. Service
(a) The SERVICE of a PARTICIPANT on any date shall consist of the
sum of the following:
(1) Any CREDITED SERVICE as of December 31, 1975, as defined
under the PLAN prior to the January 1, 1976, amendment and reproduced in
Special Provision F, and
(2) The elapsed time from the first day of employment with
an EMPLOYER (but not earlier than January 1, 1976) to the PARTICIPANT's
SEVERANCE FROM SERVICE DATE, excluding any periods of BREAK IN SERVICE
and any SERVICE cancelled by the operation of Sections 4 and 13.
(b) For EMPLOYEES who attain part-time or intermittent 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 or intermittent
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 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
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<PAGE> 5
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 was
less than the prior SERVICE. If the PARTICIPANT's contributions to the
PLAN have been withdrawn, restoration of the PARTICIPANT's prior SERVICE
will be in accordance with the provisions of Section 12.
(d) EMPLOYEES who were PARTICIPANTS in the PLAN prior to January
1, 1976, and whose prior SERVICE would not be restored under the
provisions of (a) of this Section, but would have been restored under the
provisions of the PLAN prior to the January 1, 1976, amendment, shall
continue to be eligible to have their prior SERVICE restored under the
rules of the PLAN prior to the January 1, 1976, amendment. Such rules
are set forth in Special Provision E.
5. Normal Retirement Date
NORMAL RETIREMENT DATE is the first day of the month following a
PARTICIPANT's 65th birthday.
6. Basic Pension Benefit Formula
A PARTICIPANT whose SERVICE continues to NORMAL RETIREMENT DATE or
beyond 2/ is entitled to a BASIC PENSION payable on ACTUAL RETIREMENT
DATE and on the first day of each month thereafter as long as the
PARTICIPANT lives. 3/
(a) The monthly amount of the BASIC PENSION for a PARTICIPANT who
is a MANAGEMENT EMPLOYEE on January 1, 1988, or who is thereafter hired
as a MANAGEMENT EMPLOYEE, and whose entire SERVICE thereafter is accrued
as a MANAGEMENT EMPLOYEE under Part I of this PLAN, shall be the largest
of the amounts under (1), (2), or (3) below, and 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.
(1) A monthly amount equal to 1.6 percent of the
PARTICIPANT's average BASIC MONTHLY SALARY for the final
36 consecutive months of SERVICE, 4/ multiplied by the
number of whole and fractional years of SERVICE. For
participants whose ACTUAL RETIREMENT DATE is prior to
January 1, 1991, the average BASIC MONTHLY SALARY shall
be the average BASIC MONTHLY SALARY for the period
beginning with January 1, 1988, and ending on the last
day of the month preceding ACTUAL RETIREMENT DATE.
(2) (Applicable only to PARTICIPANTS whose SERVICE began
before 1977.)
__________________________________
2/ See Section 9 for the conditions under which this may occur.
3/ See Section 10 for the conditions under which other forms of pension
may be substituted for the BASIC PENSION.
4/ 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.
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<PAGE> 6
A monthly amount equal to 40 percent of the
PARTICIPANT'S HIGHEST MONTHLY AVERAGE COVERED
COMPENSATION during any period of 60 consecutive months
(but not counting increases in COVERED COMPENSATION
which may occur after December 31, 1985), provided the
PARTICIPANT has 30 years of SERVICE. The 40 percent
shall be increased by 1/24th of one percent for each
month of SERVICE in excess of 30 years and shall be
reduced by 1/12th of one percent for each month of
SERVICE less than 30 years.
(3) (Applicable only to PARTICIPANTS whose SERVICE began
before 1977.)
A monthly amount equal to 50 percent of the
PARTICIPANT'S HIGHEST MONTHLY AVERAGE COVERED
COMPENSATION during any period of 60 consecutive months
(but not counting increases in COVERED COMPENSATION
which may occur after December 31, 1985), minus an
amount equal to one-half of the PRIMARY SOCIAL SECURITY
BENEFIT, provided the PARTICIPANT has 30 years of
SERVICE. (Such computation does not in any way affect
the amount of Social Security Benefits to be paid.) The
50 percent shall be increased by 1/24th of one percent
for each month of SERVICE in excess of 30 years and
shall be reduced by 1/12th of one percent for each month
of SERVICE less than 30 years.
(b) The monthly amount of the BASIC PENSION for a PARTICIPANT
whose classification is changed from a MANAGEMENT EMPLOYEE to a
NON-MANAGEMENT EMPLOYEE, or from a NON-MANAGEMENT EMPLOYEE to MANAGEMENT
EMPLOYEE, shall be the larger of (1) or (2) below:
(1) The amount produced by computing all years of SERVICE
pursuant to the applicable formula for the new
classification.
(2) The amount equal to the sum of (i) a pension benefit for
SERVICE prior to the change in classification, computed
pursuant to the applicable formula for the PARTICIPANT's
old classification in effect at the time of the change
in classification; and (ii) a pension benefit for
SERVICE after the change in classification, computed
pursuant to the formula applicable for 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
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<PAGE> 7
(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 5/ 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
PENSION 6/ will be as follows:
(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 years of SERVICE and is less
than 62 years of age on the EARLY RETIREMENT DATE, the
__________________________________
5/ For PARTICIPANTS whose ACTUAL RETIREMENT DATE is prior to January 1,
1991, the average BASIC MONTHLY SALARY shall be the average BASIC
MONTHLY SALARY for the period beginning with January 1, 1988, and
ending on the last day of the month preceding ACTUAL RETIREMENT DATE.
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.
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<PAGE> 8
amount of the BASIC PENSION shall be reduced by one-fourth of
one percent for each month (three percent per year) by which
PARTICIPANT's EARLY RETIREMENT DATE precedes PARTICIPANT's
62nd birthday, and further reduced by 1/12th of one percent
for each month (one percent per year) by which PARTICIPANT's
EARLY RETIREMENT DATE precedes PARTICIPANT's 60th birthday; or
(4) If PARTICIPANT has at least 25 but less than 30 years of
SERVICE and is less than 62 years of age on the EARLY
RETIREMENT DATE, the amount of the BASIC PENSION shall be
reduced by one-fourth of one percent for each month (three
percent per year) by which PARTICIPANT's EARLY RETIREMENT DATE
precedes PARTICIPANT's 62nd birthday; or
(5) If a PARTICIPANT has at least 30 years of SERVICE and is less
than 60 years of age on the EARLY RETIREMENT DATE, the amount
of the BASIC PENSION shall be reduced by one- half of one
percent for each month (up to a maximum of 12 months or six
percent) by which PARTICIPANT'S EARLY RETIREMENT DATE precedes
PARTICIPANT's 60th birthday, and further reduced by one-fourth
of one percent for each month (three percent per year) by
which PARTICIPANT'S EARLY RETIREMENT DATE precedes
PARTICIPANT's 59th birthday; or
(6) If PARTICIPANT has at least 30 years of SERVICE and is 60
years of age or older on the EARLY RETIREMENT DATE, the amount
shall be the PARTICIPANT's BASIC PENSION computed to the
PARTICIPANT's EARLY RETIREMENT DATE.
See Special Provision B for a table of EARLY RETIREMENT reductions.
8. Pensions Where Employment Ends Before Age 55
Until January 1, 1989, a PARTICIPANT with at least 10 years of
SERVICE will be designated as a former EMPLOYEE rather than a retired
EMPLOYEE if such PARTICIPANT's SERVICE ends before the first day of the
month which follows the PARTICIPANT's 55th birthday. Effective January
1, 1989, any PARTICIPANT with at least five years of SERVICE will be
designated as a former EMPLOYEE if such PARTICIPANT's SERVICE ends before
the first day of the month which follows the PARTICIPANT's 55th birthday.
Such former EMPLOYEE has a vested right to receive a PENSION with the
same rights of election and in the same amounts as provided in Section 7,
provided that the earliest election date for commencement of PENSION
payments is the first day of the month after the PARTICIPANT's 55th
birthday and the latest shall be April 1 of the year following the year
in which the PARTICIPANT attains age 70-1/2. Such a PARTICIPANT is also
entitled to the elections provided in Sections 10 (Forms of Pension), 12
(Withdrawal of Participant Contributions on Termination of Employment),
13 (Death Benefits in Certain Cases), and 15 (Facility of Payment).
9. Deferred Retirement
An EMPLOYEE may continue in employment beyond the NORMAL RETIREMENT
DATE only at the request of an EMPLOYER or as may be required by law. A
PARTICIPANT whose employment continues beyond NORMAL RETIREMENT DATE
shall not be entitled to a pension until PARTICIPANT's ACTUAL RETIREMENT
DATE. Any provision of the PLAN notwithstanding, if an EMPLOYEE
continues employment beyond the end of the year in which the EMPLOYEE
attains age 70-1/2, PENSION payments shall begin no later than April 1 of
the year following the year in which the EMPLOYEE attains age 70-1/2.
The amount of the PENSION payable shall be the PENSION benefit
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<PAGE> 9
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.
10. Forms of Pension
(a) Joint Pension With Non-Spouse
For a PARTICIPANT who is unmarried on the ACTUAL RETIREMENT DATE,
the normal form of a PENSION shall be a BASIC PENSION or an EARLY
RETIREMENT PENSION which terminates on the PARTICIPANT'S death. A
MARITAL PENSION, as described in 10(b) below, is the normal form of
PENSION for PARTICIPANTS who are married on the ACTUAL RETIREMENT
DATE. However, any PARTICIPANT, whether married or unmarried, who
wishes to have the PENSION continued in whole or in part after the
PARTICIPANT'S death for the life of a non-spouse JOINT PENSIONER,
may elect to have the applicable normal form of PENSION paid as a
JOINT PENSION by giving the EMPLOYER at least 30 days' advance
written notice prior to the PARTICIPANT'S ACTUAL RETIREMENT DATE.
If such an election is made, the PARTICIPANT will receive a reduced
BASIC or EARLY RETIREMENT PENSION for life and, upon the
PARTICIPANT'S death, the non-spouse JOINT PENSIONER designated by
the PARTICIPANT will receive that proportion of such reduced
PENSION, up to 100 percent, which the PARTICIPANT has elected, for
the remainder of the JOINT PENSIONER'S life.
Non-spouse JOINT PENSIONS shall be determined in accordance with an
actuarial formula which is set forth in Special Provision C.
(b) Joint Pension With Spouse
For a PARTICIPANT who is married on the ACTUAL RETIREMENT DATE, the
normal form of PENSION shall be a MARITAL PENSION, reducing the
amount of the PARTICIPANT'S BASIC PENSION and providing that on the
PARTICIPANT'S death one-half of such MARITAL PENSION will be
continued to the SPOUSE for the remainder of the SPOUSE'S life.
In lieu of the MARITAL PENSION, a married PARTICIPANT, by giving the
EMPLOYER at least 30 days' advance written notice prior to ACTUAL
RETIREMENT DATE, may elect one of the following options:
(1) a JOINT PENSION with SPOUSE which provides that an amount
equal to either 25, 75 or 100 percent of a reduced BASIC or
EARLY RETIREMENT PENSION will, upon the PARTICIPANT'S death,
be continued for the remainder of the SPOUSE'S life, or
(2) a SPECIAL JOINT PENSION with SPOUSE which provides an amount
of one-half or 100 percent of a reduced BASIC or EARLY
RETIREMENT PENSION that, upon the PARTICIPANT'S death, will be
continued for the remainder of the SPOUSE'S life. However, if
the SPOUSE predeceases the PARTICIPANT, future PENSION
payments will be restored to the amount of the full BASIC or
EARLY RETIREMENT PENSION that the PARTICIPANT would be
entitled to receive if no SPECIAL JOINT PENSION with SPOUSE
had been elected.
MARITAL PENSIONS and JOINT PENSIONS with SPOUSE shall be determined
in accordance with an actuarial formula which is set forth in
Special Provision D. Special Provision D also includes tables of
factors which apply to typical options which may be elected.
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SPECIAL JOINT PENSIONS with SPOUSE shall also be determined in
accordance with the actuarial formula which is set forth in Special
Provision D, but actuarially adjusted further to reflect the value
of the restoration feature. Provision D also includes tables of the
factors which apply to SPECIAL JOINT PENSION options that may be
elected.
(c) Basic or Early Retirement Pension Terminating Upon The Death Of The
Participant
Under this option, no additional PENSION payments are made to anyone
after the PARTICIPANT'S death.
(d) Conditions Applicable To All Forms Of Pensions
The written consent of the SPOUSE is required whenever an option is
elected which would provide benefits to a surviving SPOUSE less than
those provided by a MARITAL PENSION.
Once elected, no option under this Section can be changed after the
30th day preceding the PARTICIPANT'S ACTUAL RETIREMENT DATE except,
however, in the event that the PARTICIPANT or SPOUSE or JOINT
PENSIONER should die before the PARTICIPANT'S ACTUAL RETIREMENT
DATE, any election will automatically become inoperative.
The SPOUSE of a PARTICIPANT may not receive a benefit under any
provisions of this Section if a larger SPOUSE'S PENSION is payable
under Section 11.
11. Spouse's Pension
(a) If a married PARTICIPANT dies while employed by an EMPLOYER and
prior to the ACTUAL RETIREMENT DATE, or within 30 days thereafter, the
PARTICIPANT's surviving SPOUSE will be eligible to receive a SPOUSE's
PENSION if, at the time of the PARTICIPANT'S death, (i) the PARTICIPANT
was at least 55 years of age, or (ii) the sum of the PARTICIPANT's age
and years of SERVICE equaled 70 or more. (69.5 or more is rounded to
70.)
The amount of the SPOUSE's PENSION is one-half of the PENSION that the
PARTICIPANT would have been entitled to receive, and will be calculated
as if:
(1) the PARTICIPANT had elected a BASIC PENSION under Section 10(b)(3),
(2) the first day of the month following the PARTICIPANT's death had
been the PARTICIPANT's ACTUAL RETIREMENT DATE, and
(3) The PARTICIPANT had in fact retired on that date without reduction
for early retirement. However, if the SPOUSE is more than 10 years
younger than the PARTICIPANT, the amount of the SPOUSE's PENSION
shall be reduced 1/20th of one percent for each full month in excess
of 120 months' difference in their ages, except that such reduction
shall not result in a SPOUSE's PENSION lower than would have been
payable if the PARTICIPANT had retired as of the date of death and
elected an optional form providing for continuation of 50 percent to
a named JOINT PENSIONER with SPOUSE the same sex and age of the
SPOUSE, under the provisions of Section 10(b)(1). The SPOUSE's
PENSION is payable to the PARTICIPANT's surviving SPOUSE on the
first day of the month following the PARTICIPANT's death and the
first day of each month thereafter so long as the SPOUSE lives.
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<PAGE> 11
(b) The surviving SPOUSE of a PARTICIPANT or of a former EMPLOYEE who
dies prior to actual retirement date shall be entitled to receive a
SPOUSE's PENSION under this Section 11(b) if, at the time of the
death of the PARTICIPANT or former EMPLOYEE, (i) the PARTICIPANT or
former EMPLOYEE had at least five years of SERVICE, and (ii) the
surviving SPOUSE does not qualify for a SPOUSE's PENSION under
Section 11(a), above.
A SPOUSE's PENSION under this Section 11(b) shall be payable on the
first day of the month following the later of (i) the date of death
or (ii) the month in which the deceased PARTICIPANT or former
EMPLOYEE would have attained his 55th birthday. By submitting an
election form to the PLAN ADMINISTRATOR, a SPOUSE may elect to begin
receiving a SPOUSE's PENSION at a specified later date.
(1) For a PARTICIPANT who is less than 55 years of age at the time
of his death, the SPOUSE's PENSION will be an amount equal to
the MARITAL PENSION that would have been payable to the
PARTICIPANT's SPOUSE if the PARTICIPANT had terminated
employment at the date of death, had lived until age 55, had
begun to receive PENSION payments, and had subsequently died.
(2) For a former EMPLOYEE, age 55 or older at the time of his
death, who is not yet receiving PENSION payments, the SPOUSE's
PENSION will be equal to the MARITAL PENSION that would have
been payable to the SPOUSE if the former EMPLOYEE had begun
receiving a PENSION immediately prior to his death.
(3) For a former EMPLOYEE, younger than age 55 at the time of his
death, the SPOUSE's PENSION will be equal to the MARITAL
PENSION that would have been payable to the SPOUSE if the
former EMPLOYEE had survived until age 55, had begun receiving
a PENSION, and had subsequently died.
A PARTICIPANT's SPOUSE may not receive both a SPOUSE's PENSION under this
Section and a MARITAL or JOINT PENSION under Section 10. If the
PARTICIPANT dies within 30 days after the PARTICIPANT's ACTUAL RETIREMENT
DATE, the SPOUSE will receive the larger of the monthly Pensions under
this Section and Section 3.10, but not both.
12. Withdrawal of Participant Contributions on Termination of Employment
A PARTICIPANT's contributions to the PLAN may not be withdrawn prior
to ACTUAL RETIREMENT DATE or other termination of SERVICE. After a
PARTICIPANT's SERVICE is terminated, the PARTICIPANT, by written notice
to the PARTICIPANT's EMPLOYER at least 30 days before the date the
PENSION begins, may elect to have such CONTRIBUTIONS PLUS INTEREST
returned. If SERVICE terminates before the PARTICIPANT has ten years of
SERVICE, such withdrawal terminates all of the PARTICIPANT's rights under
the PLAN. If such PARTICIPANT is reemployed and such cancelled SERVICE
would otherwise be restored pursuant to Section 4, the PARTICIPANT shall
be given an option to repay the amount of any contributions withdrawn
under this Section, together with additional interest at the rate of five
percent per annum from the date of distribution to the date of repayment.
Such repayment must be made within 24 months of the reemployment date of
such PARTICIPANT. If such withdrawn contributions are not thus repaid,
the PARTICIPANT's prior SERVICE which was accrued during the period of
time that contributions to the PLAN were required shall not be restored.
If such failure to repay causes a forfeiture of
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<PAGE> 12
all prior SERVICE, such PARTICIPANT shall be treated as a new EMPLOYEE
for all purposes.
If SERVICE terminates with at least ten years of SERVICE, 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
are contained in the table set forth in Special Provision I.
These factors may be changed by the EMPLOYEE BENEFIT ADMINISTRATIVE
COMMITTEE from time to time to reflect the ERISA formula, but in no event
will the PENSION be reduced more than one-third.
13. Death Benefits
If a PARTICIPANT with contributions on deposit in the PLAN dies
before receiving payments from the PLAN equal to the amount of the
PARTICIPANT's CONTRIBUTIONS PLUS INTEREST, the difference between the
payments made and the CONTRIBUTIONS PLUS INTEREST will be paid to the
named BENEFICIARY, unless a PENSION is payable to the PARTICIPANT's
surviving SPOUSE or JOINT PENSIONER. If a PENSION is payable after such
PARTICIPANT's death, and if upon the death of the SPOUSE or JOINT
PENSIONER the total combined amount paid to the PARTICIPANT and the
SPOUSE or JOINT PENSIONER does not equal the amount of the PARTICIPANT's
CONTRIBUTIONS PLUS INTEREST, the difference between the total amount paid
and the PARTICIPANT's CONTRIBUTIONS PLUS INTEREST will be paid to the
BENEFICIARY of the SPOUSE or JOINT PENSIONER.
14. Facility of Payment
(a) If the present value of the PENSION 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. In determining the present
value, the PLAN ADMINISTRATOR shall use the interest rate set, as of the
first day of the PLAN year in which the lump sum payment is made, by the
Pension Benefit Guaranty Corporation for the purpose of determining the
present value of a lump sum distribution on PLAN termination.
(b) If the ADMINISTRATOR determines that any individual entitled to
any payment under the PLAN is physically or mentally incompetent to
handle the payment and no guardian or conservator has been appointed to
receive such payment, the ADMINISTRATOR may cause all payments thereafter
becoming due to such individual to be applied for and on behalf of and
for the benefit of such individual. Payments made pursuant to this
provision shall completely discharge the EMPLOYER, the ADMINISTRATOR, the
Trustee, and all fiduciaries of all further responsibility with respect
to such individual.
15. Benefits Are Not Assignable
Except as may be required by law, a PARTICIPANT's interest in the
PLAN, either before or after retirement, and that of a PARTICIPANT's
SPOUSE, JOINT PENSIONER, or BENEFICIARY shall not be subject to
assignment, anticipation, sale, transfer, pledge, encumbrance, or charge,
whether voluntary or involuntary, and any attempt to so assign,
anticipate, sell, transfer, pledge, encumber, or charge shall be void.
-10-
<PAGE> 13
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 charge
to each EMPLOYER its share of the EMPLOYER contributions made by the
COMPANY.
17. Company's Powers and Duties
The COMPANY, acting through its Board of Directors or Executive
Committee, reserves to itself the exclusive power to amend, suspend, or
terminate the PLAN as provided below and to appoint and remove from time
to time:
(a) The individuals comprising the EMPLOYEE BENEFIT FINANCE
COMMITTEE;
(b) The individuals comprising the EMPLOYEE BENEFIT ADMINISTRATIVE
COMMITTEE;
(c) The EMPLOYERS whose EMPLOYEES may participate in the PLAN.
All powers and duties not reserved to the COMPANY are delegated to
the EMPLOYEE BENEFIT FINANCE COMMITTEE and to the EMPLOYEE BENEFIT
ADMINISTRATIVE COMMITTEE. Action of either committee shall be by vote of
a majority of the members of the committee at a meeting, or in writing
without a meeting, and evidenced by the signature of any member who is so
authorized by the committee. The COMPANY indemnifies each member of each
committee against any personal liability or expense arising out of any
action or inaction of the committee or of any member of the committee or
of such individual, except that due to his own willful misconduct.
18. Funding and Investment Provisions
The EMPLOYEE BENEFIT FINANCE COMMITTEE appointed by the COMPANY's
Board of Directors to serve at its pleasure has the express powers and
duties described in this Section.
(a) Appointments. The EMPLOYEE BENEFIT FINANCE COMMITTEE has the
sole power and duty from time to time to appoint and remove the Funding
Agents, the Investment Manager, actuaries, accountants, and such other
advisors and consultants as may be needed for the proper financial
administration and investment of the assets of the PLAN. Supplementing
such appointments, the EMPLOYEE BENEFIT FINANCE COMMITTEE may enter into
appropriate agreements with each Trustee, Investment Manager or other
advisors appointed under this paragraph and delegate to them appropriate
powers and duties. The EMPLOYEE BENEFIT FINANCE COMMITTEE may appoint
and delegate to one or more individuals the power and duty to handle the
day-to-day financial administration of the PLAN. Such individuals need
not be members of the committee and shall serve at the pleasure of the
committee.
(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
-11-
<PAGE> 14
insurance companies or corporate trustees, or to any combination thereof,
as the EMPLOYEE BENEFIT FINANCE COMMITTEE may determine from time to
time. These contributions, and all previous contributions of
PARTICIPANTS and EMPLOYERS, together with the proceeds of their
investment, shall be held and administered by these Funding Agents
pursuant to the agreements between the COMPANY and the Funding Agents.
19. Administration
The EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE, appointed by the
COMPANY's Board of Directors to serve at its pleasure, is the
ADMINISTRATOR of the PLAN and is responsible for the overall
administration of the PLAN. The ADMINISTRATOR has the sole power and
duty to establish, and from time to time revise, such rules and
regulations as may be necessary to administer the PLAN in a
nondiscriminatory manner for the exclusive benefit of PARTICIPANTS and
all other persons entitled to benefits under the PLAN.
The ADMINISTRATOR shall also maintain such records and make such
computations, interpretations, and decisions as may be necessary or
desirable for the proper administration of the PLAN. The ADMINISTRATOR
may demand such proof of age of any PARTICIPANT, JOINT PENSIONER, or
SPOUSE as it considers necessary, and it may adjust any PENSION or other
payment or payments thereafter due under the PLAN as it deems appropriate
and equitable to correct any factual error or misrepresentation. The
ADMINISTRATOR shall maintain for PARTICIPANTS' inspection copies of the
PLAN, trust agreement, investment policy, each agreement with an
Investment Manager, the latest annual report, PLAN description, and
summary description, and any amendments or changes in any of these
documents. On written request, PARTICIPANTS may obtain from the
ADMINISTRATOR a copy of any of these documents at a cost established by
the ADMINISTRATOR from time to time.
20. Claims Procedure
If a claim is denied in whole or in part, the ADMINISTRATOR shall
furnish to the claimant a written notice setting forth:
(a) Specific reason(s) for the denial,
(b) The PLAN provision(s) on which the denial is based,
(c) A description of any material or information, if any,
necessary for the claimant to perfect the claim, and an explanation of
why such material or information is necessary, and
(d) Information concerning the steps to be taken if claimant
wishes to submit a claim for review.
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.
-12-
<PAGE> 15
21. Amendment, Termination, and Merger
The COMPANY hopes and expects to continue this PLAN indefinitely
but, because future conditions cannot be foreseen, its Board of Directors
necessarily reserves the right to change, suspend, or terminate the PLAN
at any time. However, no change can be made which would adversely affect
the rights which any PARTICIPANT, retired EMPLOYEE, former EMPLOYEE,
SPOUSE, JOINT PENSIONER, or BENEFICIARY may then have with respect to
funds then being held under the PLAN by any Funding Agent or permit any
such funds to revert to an EMPLOYER or be used for any purpose except for
the exclusive benefit of PARTICIPANTS, Pensioners, and their SPOUSES,
JOINT PENSIONERS, and BENEFICIARIES.
In the event the PLAN is partially terminated, terminated or
suspended, all EMPLOYER contributions with respect to the affected
PARTICIPANTS shall cease and the accrued benefits of the affected
PARTICIPANTS shall become nonforfeitable. Subject to applicable
requirements of notice to the Pension Benefit Guaranty Corporation
governing termination of PENSION benefit plans, the funds held under the
PLAN by the Funding Agents shall be applied to provide the PENSIONS,
benefits and refunds accrued to the date of termination or suspension and
to the extent funded. Such provision shall be made in such manner as the
ADMINISTRATOR shall direct, including the purchase of paid-up annuities,
distribution in installments, or lump-sum distributions and shall be in
conformance with the requirements and priorities established by various
governmental agencies to oversee PLAN suspensions and terminations.
Notwithstanding any contrary provisions of the PLAN, after its
termination and after all liabilities for the payment of PENSIONS,
benefits and refunds to the date of termination have been satisfied or
provided for in accordance with the foregoing, any funds remaining with
the Funding Agents shall be returned to the COMPANY.
This PLAN shall not be merged into or consolidated with any other
PLAN, nor shall any of its assets or liabilities be transferred to any
other PLAN, unless each PARTICIPANT in this PLAN would (if such other
PLAN then terminated) receive a benefit immediately after the merger,
consolidation, or transfer which is equal to or greater than the benefit
such PARTICIPANT would have been entitled to receive immediately before
the merger, consolidation, or transfer (if this PLAN had then
terminated).
22. 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.
Administrator: The EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE referred to in Section 20,
------------- 201 Mission Street, 19th Floor, Mail Code
</TABLE>
-13-
<PAGE> 16
<TABLE>
<S> <C>
Basic Monthly Salary: The rate of pay used to calculate the monthly earnings from an EMPLOYER, adjusted
-------------------- to reflect nuclear premium payments, if any, but excluding payments from the LONG TERM
DISABILITY PLAN and all other bonuses, premiums, special allowances, overtime pay, or any
other payments, and excluding earnings from an EMPLOYER in excess of $200,000 for 1989,
multiplied by the adjustment factor prescribed by the Secretary of the Treasury under
Section 415(d) of the Internal Revenue Code for years beginning after December 31, 1989.
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
14. Such designation must be made on forms provided by the EMPLOYER and filed with the
ADMINISTRATOR. A PARTICIPANT, or the PARTICIPANT's SPOUSE (if receiving a SPOUSE's
PENSION), or the PARTICIPANT's JOINT PENSIONER (if receiving a Joint PENSION), may change
the designated Beneficiary from time to time by filing an appropriate written notice with
the ADMINISTRATOR. In the absence of a designation, the Beneficiary shall be the estate of
the person entitled to make the designation. There were no employee contributions after
December 31, 1972. Therefore, Employees who first became Participants in the PLAN after
said date were not required or permitted to name a Beneficiary.
Break in Service: A BREAK IN SERVICE occurs 12 months after the SEVERANCE FROM SERVICE DATE if during
---------------- such 12-month period an EMPLOYEE does not work for an EMPLOYER. Once a Break in Service
occurs, it continues until an EMPLOYEE is reemployed by an EMPLOYER.
Company: Pacific Gas and Electric Company.
-------
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.
</TABLE>
-14-
<PAGE> 17
<TABLE>
<S> <C>
Covered Compensation: A Participant's Covered Compensation shall be the amount of Participant's 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 and pay for other time off with permission carrying
full pay. A Participant's Covered Compensation shall not include pay or shift and nuclear
premiums for more than 40 hours per week, overtime bonuses, other special fees or
allowances, per diem allowances and payments under Part B of the Group Life Insurance and
Long Term Disability Plan, any Workers' Compensation Law, supplemental benefits for
industrial injury, voluntary wage benefit or state disability plans, or any other benefit
plan.
For purposes of calculating a PARTICIPANT's accrued benefit under this PLAN, the
compensation limitations of Internal Revenue 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 Internal Revenue 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
</TABLE>
-15-
<PAGE> 18
<TABLE>
<S> <C>
PLAN YEAR beginning before January 1, 1994, frozen in
accordance with Internal Revenue 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.
An Internal Revenue 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.
Credited Service: See Special Provision F.
----------------
Early Retirement Date: See Section 7.
---------------------
Early Retirement Pension: See Section 7.
------------------------
Employee: An EMPLOYEE of an EMPLOYER. A "leased employee," as defined in Section 414(n) of the
-------- Internal Revenue Code, shall not be considered an EMPLOYEE eligible to become a
PARTICIPANT in the PLAN.
Employee Benefit
Administrative Committee: The EMPLOYEE BENEFIT ADMINISTRATIVE COMMITTEE referred to in Section 20.
------------------------
The Employee Benefit
Finance Committee: The EMPLOYEE BENEFIT FINANCE COMMITTEE referred to in Section 19.
--------------------
Employer: Pacific Gas and Electric Company, Standard Pacific Gas Line Incorporated,
-------- Pacific Gas Transmission Company, Pacific Service Employees Association,
Alaska California LNG Company, Pacific Gas Marine Company, Pacific Gas LNG
Terminal Company, Calaska Energy Company, Eureka Energy Company, Gas Lines,
Inc., Pacific Transmission Supply Company, 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.
-------------
</TABLE>
-16-
<PAGE> 19
<TABLE>
<S> <C>
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.
Management Employee: A monthly salaried EMPLOYEE who is not represented by a union.
-------------------
Marital Pension: See Section 10(b).
---------------
Maximum Pension: See Special Provision H.
---------------
Non-Management Employee: An EMPLOYEE who is not a MANAGEMENT EMPLOYEE.
-----------------------
Normal Retirement Date: The first of the month following the PARTICIPANT's 65th birthday.
----------------------
Participant: See Section 2.
-----------
Pension: Retirement income payable under the PLAN.
-------
Plan: The Company's Retirement Plan as amended, revised and set forth herein.
----
Service: For full-time EMPLOYEES, the period of time commencing with the first day
------- of work for an EMPLOYER and ending on PARTICIPANT's SEVERANCE FROM SERVICE
Date. For periods of part-time and intermittent employment, SERVICE for
purposes of benefit accrual is prorated based on the ratio of actual hours
worked in the calendar year to the full-time equivalent (2,080 per calendar
year) rounded to the nearest month. Such proration is applicable for any
employment period beginning with initiation of part-time or intermittent
status on or after January 1, 1991, and ending on the earlier of
Participant's return to full time status or the PARTICIPANT'S SEVERANCE
FROM SERVICE DATE. The method of computing SERVICE is described in Section 3.
Severance from Service Date: (i) The date prior to NORMAL RETIREMENT DATE on which an Employee quits,
--------------------------- retires, is discharged or dies, or the ACTUAL RETIREMENT DATE; or
(ii) The first anniversary of the first date of a period in which a
PARTICIPANT remains absent from work for an EMPLOYER for any
reason other than a quit, retirement, discharge, or death.
</TABLE>
-17-
<PAGE> 20
<TABLE>
<S> <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:
(a) Absence on a leave of absence authorized by an EMPLOYER.
(b) Absence because of illness or injury as long as the PARTICIPANT
is entitled to receive sick leave pay or is entitled to receive benefits
under the provisions of the Voluntary Wage Benefit Plan, a
state disability plan, Part B of the Group Life Insurance and Long Term
Disability Plan, or a Workers' Compensation Law.
(c) Absence for military service or service in the Merchant Marines so long
as reemployment rights are protected by law.
(d) Absence caused by layoff for lack of work of less than 12 continuous months
for a PARTICIPANT who has less than five years of SERVICE, or 24 continuous
months for a PARTICIPANT who has five years or more of SERVICE.
Special Joint Pension: See Section 10.
---------------------
Spouse: (a) If a PARTICIPANT dies in SERVICE, SPOUSE shall mean the PARTICIPANT's wife
------ or husband at the time of the PARTICIPANT'S death.
(b) If a PARTICIPANT dies after ACTUAL RETIREMENT DATE, SPOUSE shall mean the
PARTICIPANT's wife or husband at the time of the PARTICIPANT's Actual Retirement.
Spouse's Pension: See Section 11.
----------------
</TABLE>
-18-
<PAGE> 21
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
<TABLE>
<CAPTION>
Years Of Service At Early Retirement Date
---------------------------------------------------------------
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>
-19-
<PAGE> 22
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>
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.
-20-
<PAGE> 23
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 RETIREMENT
---------- --- --- --- --- --- --- --- --- ------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
25 .844 .836 .827 .817 .807 .797 .786 .775 25
26 .847 .838 .829 .819 .809 .799 .788 .777 26
27 .849 .840 .831 .821 .811 .801 .790 .779 27
28 .851 .842 .833 .824 .814 .803 .793 .781 28
29 .853 .844 .835 .826 .816 .806 .795 .784 29
30 .855 .847 .838 .828 .818 .808 .797 .786 30
31 .858 .849 .840 .831 .821 .811 .800 .789 31
32 .860 .852 .843 .833 .824 .813 .803 .792 32
33 .863 .854 .846 .836 .826 .816 .806 .794 33
34 .866 .857 .848 .839 .829 .819 .809 .797 34
35 .868 .860 .851 .842 .832 .822 .812 .801 35
36 .871 .863 .854 .845 .835 .825 .815 .804 36
37 .874 .866 .857 .848 .839 .829 .818 .807 37
38 .877 .869 .860 .851 .842 .832 .821 .811 38
39 .880 .872 .864 .855 .845 .835 .825 .814 39
40 .884 .875 .867 .858 .849 .839 .829 .818 40
41 .887 .879 .870 .862 .852 .843 .832 .822 41
42 .890 .882 .874 .865 .856 .846 .836 .826 42
43 .893 .886 .877 .869 .860 .850 .840 .830 43
44 .897 .889 .881 .873 .864 .854 .844 .834 44
45 .900 .893 .885 .876 .868 .858 .848 .838 45
46 .904 .896 .889 .880 .872 .862 .853 .842 46
47 .907 .900 .892 .884 .876 .867 .857 .847 47
48 .911 .904 .896 .888 .880 .871 .861 .851 48
49 .914 .907 .900 .892 .884 .875 .866 .856 49
</TABLE>
<TABLE>
<CAPTION>
BENEFICIARY'S BENEFICIARY'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 63 64 65 66 67 68 69 70 RETIREMENT
---------- --- --- --- --- --- --- --- --- ------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
25 .763 .751 .738 .725 .711 .697 .682 .667 25
26 .765 .753 .740 .727 .713 .699 .684 .669 26
27 .767 .755 .742 .729 .715 .701 .686 .671 27
28 .769 .757 .745 .731 .718 .703 .689 .674 28
29 .772 .760 .747 .734 .720 .706 .691 .676 29
30 .774 .762 .750 .736 .723 .708 .694 .679 30
31 .777 .765 .752 .739 .725 .711 .696 .681 31
32 .780 .768 .755 .742 .728 .714 .699 .684 32
33 .783 .771 .758 .745 .731 .717 .702 .687 33
34 .786 .774 .761 .748 .734 .720 .705 .690 34
35 .789 .777 .764 .751 .737 .723 .708 .693 35
36 .792 .780 .768 .754 .741 .727 .712 .697 36
37 .796 .784 .771 .758 .744 .730 .715 .700 37
38 .799 .787 .775 .761 .748 .734 .719 .704 38
39 .803 .791 .778 .765 .752 .737 .723 .708 39
40 .806 .795 .782 .769 .756 .741 .727 .712 40
41 .810 .798 .786 .773 .760 .746 .731 .716 41
42 .814 .803 .790 .777 .764 .750 .735 .720 42
43 .818 .807 .794 .782 .768 .754 .740 .725 43
44 .823 .811 .799 .786 .773 .759 .744 .729 44
45 .827 .816 .803 .791 .777 .764 .749 .734 45
46 .832 .820 .808 .795 .782 .768 .754 .739 46
47 .836 .825 .813 .800 .787 .774 .759 .744 47
48 .841 .830 .818 .805 .792 .779 .764 .750 48
49 .846 .835 .823 .811 .798 .784 .770 .755 49
</TABLE>
-21-
<PAGE> 24
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 RETIREMENT
---------- --- --- --- --- --- --- --- --- ------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
50 .918 .911 .904 .896 .888 .880 .870 .861 50
51 .921 .915 .908 .900 .892 .884 .875 .866 51
52 .925 .918 .912 .904 .897 .888 .880 .870 52
53 .928 .922 .916 .908 .901 .893 .884 .875 53
54 .932 .926 .919 .913 .905 .897 .889 .880 54
55 .935 .929 .923 .917 .909 .902 .894 .885 55
56 .938 .933 .927 .921 .914 .906 .898 .890 56
57 .942 .936 .931 .925 .918 .911 .903 .895 57
58 .945 .940 .934 .928 .922 .915 .908 .900 58
59 .948 .943 .938 .932 .926 .920 .912 .905 59
60 .951 .947 .942 .936 .930 .924 .917 .910 60
61 .954 .950 .945 .940 .934 .928 .922 .914 61
62 .957 .953 .948 .944 .938 .932 .926 .919 62
63 .960 .956 .952 .947 .942 .937 .931 .924 63
64 .963 .959 .955 .951 .946 .941 .935 .929 64
65 .965 .962 .958 .954 .949 .944 .939 .933 65
66 .968 .965 .961 .957 .953 .948 .943 .938 66
67 .970 .967 .964 .960 .956 .952 .947 .942 67
68 .972 .970 .967 .963 .960 .955 .951 .946 68
69 .975 .972 .969 .966 .963 .959 .955 .950 69
70 .977 .974 .972 .969 .966 .962 .958 .954 70
71 .979 .976 .974 .971 .968 .965 .961 .957 71
72 .980 .978 .976 .974 .971 .968 .965 .961 72
73 .982 .980 .978 .976 .973 .971 .968 .964 73
74 .984 .982 .980 .978 .976 .973 .970 .967 74
</TABLE>
<TABLE>
<CAPTION>
BENEFICIARY'S BENEFICIARY'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 63 64 65 66 67 68 69 70 RETIREMENT
---------- --- --- --- --- --- --- --- --- ------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
50 .850 .840 .828 .816 .803 .790 .775 .761 50
51 .855 .845 .833 .821 .808 .795 .781 .767 51
52 .860 .850 .839 .827 .814 .801 .787 .773 52
53 .865 .855 .844 .832 .820 .807 .793 .779 53
54 .870 .860 .849 .838 .826 .813 .799 .785 54
55 .876 .866 .855 .844 .832 .819 .806 .792 55
56 .881 .871 .861 .849 .838 .825 .812 .798 56
57 .886 .876 .866 .855 .844 .831 .819 .805 57
58 .891 .882 .872 .861 .850 .838 .825 .812 58
59 .896 .887 .878 .867 .856 .844 .832 .819 59
60 .902 .893 .883 .873 .863 .851 .839 .826 60
61 .907 .898 .889 .879 .869 .858 .846 .833 61
62 .912 .904 .895 .885 .875 .864 .853 .840 62
63 .917 .909 .901 .891 .882 .871 .860 .848 63
64 .922 .914 .906 .897 .888 .878 .867 .855 64
65 .927 .920 .912 .903 .894 .884 .874 .862 65
66 .931 .925 .917 .909 .900 .891 .881 .870 66
67 .936 .930 .923 .915 .907 .897 .888 .877 67
68 .940 .934 .928 .920 .913 .904 .894 .884 68
69 .945 .939 .933 .926 .918 .910 .901 .891 69
70 .949 .944 .938 .931 .924 .916 .908 .898 70
71 .953 .948 .942 .936 .930 .922 .914 .905 71
72 .957 .952 .947 .941 .935 .928 .920 .912 72
73 .960 .956 .951 .946 .940 .933 .926 .918 73
74 .964 .960 .955 .950 .945 .939 .932 .925 74
</TABLE>
-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 RETIREMENT
---------- --- --- --- --- --- --- --- --- -------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
75 .985 .984 .982 .980 .978 .976 .973 .970 75
76 .987 .985 .984 .982 .980 .978 .976 .973 76
77 .988 .987 .985 .984 .982 .980 .978 .975 77
78 .989 .988 .987 .985 .984 .982 .980 .978 78
79 .990 .989 .988 .987 .985 .984 .982 .980 79
80 .991 .990 .989 .988 .987 .985 .984 .982 80
81 .992 .991 .990 .989 .988 .987 .986 .984 81
82 .993 .992 .991 .991 .990 .988 .987 .986 82
83 .994 .993 .992 .992 .991 .990 .989 .987 83
84 .995 .994 .993 .993 .992 .991 .990 .989 84
</TABLE>
<TABLE>
<CAPTION>
BENEFICIARY'S BENEFICIARY'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 63 64 65 66 67 68 69 70 RETIREMENT
---------- --- --- --- --- --- --- --- --- -------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
75 .967 .963 .959 .954 .949 .944 .937 .931 75
76 .970 .966 .963 .958 .954 .948 .943 .936 76
77 .973 .970 .966 .962 .958 .953 .948 .942 77
78 .975 .972 .969 .966 .962 .957 .952 .947 78
79 .978 .975 .972 .969 .965 .961 .957 .952 79
80 .980 .978 .975 .972 .969 .965 .961 .956 80
81 .982 .980 .978 .975 .972 .969 .965 .961 81
82 .984 .982 .980 .978 .975 .972 .968 .964 82
83 .986 .984 .982 .980 .978 .975 .972 .968 83
84 .987 .986 .984 .982 .980 .978 .975 .972 84
</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 70 71 72 73 74 75 76 77 RETIREMENT
---------- --- --- --- --- --- --- --- --- ----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
25 .667 .652 .636 .620 .603 .586 .569 .551 25
26 .669 .654 .638 .622 .605 .588 .571 .553 26
27 .671 .656 .640 .624 .607 .590 .573 .555 27
28 .674 .658 .642 .626 .609 .592 .575 .557 28
29 .676 .661 .645 .628 .612 .595 .577 .560 29
30 .679 .663 .647 .631 .614 .597 .580 .562 30
31 .681 .666 .650 .633 .617 .600 .582 .564 31
32 .684 .669 .653 .636 .619 .602 .585 .567 32
33 .687 .671 .655 .639 .622 .605 .588 .570 33
34 .690 .675 .659 .642 .625 .608 .591 .573 34
35 .693 .678 .662 .645 .628 .611 .594 .576 35
36 .697 .681 .665 .649 .632 .614 .597 .579 36
37 .700 .685 .669 .652 .635 .618 .600 .582 37
38 .704 .688 .672 .656 .639 .621 .604 .586 38
39 .708 .692 .676 .659 .643 .625 .607 .589 39
40 .712 .696 .680 .663 .647 .629 .611 .593 40
41 .716 .700 .684 .668 .651 .633 .616 .597 41
42 .720 .705 .689 .672 .655 .638 .620 .602 42
43 .725 .709 .693 .677 .660 .642 .624 .606 43
44 .729 .714 .698 .681 .664 .647 .629 .611 44
45 .734 .719 .703 .686 .669 .652 .634 .616 45
46 .739 .724 .708 .691 .674 .657 .639 .621 46
47 .744 .729 .713 .697 .680 .662 .644 .626 47
48 .750 .734 .718 .702 .685 .668 .650 .631 48
49 .755 .740 .724 .708 .691 .673 .655 .637 49
</TABLE>
<TABLE>
<CAPTION>
BENEFICIARY'S BENEFICIARY'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 78 79 80 81 82 83 84 85 RETIREMENT
---------- --- --- --- --- --- --- --- --- ----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
25 .533 .515 .497 .479 .461 .442 .424 .406 25
26 .535 .517 .499 .481 .462 .444 .426 .407 26
27 .537 .519 .501 .483 .464 .446 .427 .409 27
28 .539 .521 .503 .485 .466 .448 .429 .411 28
29 .542 .524 .505 .487 .468 .450 .431 .413 29
30 .544 .526 .507 .489 .470 .452 .433 .414 30
31 .546 .528 .510 .491 .473 .454 .435 .417 31
32 .549 .531 .512 .494 .475 .456 .437 .419 32
33 .552 .533 .515 .496 .477 .459 .440 .421 33
34 .555 .536 .518 .499 .480 .461 .442 .423 34
35 .558 .539 .520 .502 .483 .464 .445 .426 35
36 .561 .542 .524 .505 .486 .467 .448 .429 36
37 .564 .545 .527 .508 .489 .470 .451 .431 37
38 .567 .549 .530 .511 .492 .473 .454 .434 38
39 .571 .552 .534 .515 .495 .476 .457 .438 39
40 .575 .556 .537 .518 .499 .480 .460 .441 40
41 .579 .560 .541 .522 .503 .483 .464 .444 41
42 .583 .564 .545 .526 .507 .487 .468 .448 42
43 .588 .569 .550 .530 .511 .491 .472 .452 43
44 .592 .573 .554 .535 .515 .495 .476 .456 44
45 .597 .578 .559 .539 .520 .500 .480 .460 45
46 .602 .583 .564 .544 .524 .505 .485 .465 46
47 .607 .588 .569 .549 .529 .509 .489 .469 47
48 .613 .594 .574 .554 .535 .515 .494 .474 48
49 .618 .599 .580 .560 .540 .520 .500 .479 49
</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 70 71 72 73 74 75 76 77 RETIREMENT
---------- --- --- --- --- --- --- --- --- ----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
50 .761 .746 .730 .713 .697 .679 .661 .643 50
51 .767 .752 .736 .720 .703 .685 .667 .649 51
52 .773 .758 .742 .726 .709 .692 .674 .655 52
53 .779 .764 .748 .732 .715 .698 .680 .662 53
54 .785 .770 .755 .739 .722 .705 .687 .669 54
55 .792 .777 .762 .746 .729 .712 .694 .676 55
56 .798 .784 .768 .753 .736 .719 .701 .683 56
57 .805 .790 .775 .760 .743 .726 .709 .691 57
58 .812 .798 .783 .767 .751 .734 .717 .699 58
59 .819 .805 .790 .775 .759 .742 .725 .707 59
60 .826 .812 .798 .783 .767 .750 .733 .715 60
61 .833 .820 .805 .790 .775 .758 .741 .724 61
62 .840 .827 .813 .799 .783 .767 .750 .733 62
63 .848 .835 .821 .807 .792 .776 .759 .742 63
64 .855 .843 .829 .815 .800 .785 .768 .751 64
65 .862 .850 .837 .824 .809 .794 .778 .761 65
66 .870 .858 .845 .832 .818 .803 .787 .770 66
67 .877 .866 .854 .841 .827 .812 .797 .780 67
68 .884 .873 .862 .849 .836 .821 .806 .790 68
69 .891 .881 .870 .858 .845 .831 .816 .801 69
70 .898 .888 .878 .866 .853 .840 .826 .811 70
71 .905 .896 .885 .874 .862 .849 .836 .821 71
72 .912 .903 .893 .882 .871 .859 .845 .831 72
73 .918 .910 .900 .890 .879 .868 .855 .841 73
74 .925 .917 .908 .898 .888 .876 .864 .851 74
</TABLE>
<TABLE>
<CAPTION>
BENEFICIARY'S BENEFICIARY'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 78 79 80 81 82 83 84 85 RETIREMENT
---------- --- --- --- --- --- --- --- --- ----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
50 .624 .605 .585 .566 .546 .525 .505 .485 50
51 .630 .611 .591 .572 .551 .531 .511 .490 51
52 .637 .617 .598 .578 .558 .537 .517 .496 52
53 .643 .624 .604 .584 .564 .543 .523 .502 53
54 .650 .631 .611 .591 .571 .550 .529 .508 54
55 .657 .638 .618 .598 .578 .557 .536 .515 55
56 .664 .645 .625 .605 .585 .564 .543 .522 56
57 .672 .653 .633 .613 .592 .571 .550 .529 57
58 .680 .661 .641 .621 .600 .579 .558 .537 58
59 .688 .669 .649 .629 .608 .587 .566 .545 59
60 .696 .677 .658 .638 .617 .596 .575 .553 60
61 .705 .686 .667 .646 .626 .605 .584 .562 61
62 .714 .695 .676 .656 .635 .614 .593 .571 62
63 .724 .705 .685 .665 .645 .624 .602 .581 63
64 .733 .715 .695 .675 .655 .634 .612 .591 64
65 .743 .725 .705 .686 .665 .644 .623 .601 65
66 .753 .735 .716 .696 .676 .655 .634 .612 66
67 .763 .745 .727 .707 .687 .666 .645 .623 67
68 .774 .756 .738 .718 .698 .678 .657 .635 68
69 .784 .767 .749 .730 .710 .690 .668 .647 69
70 .795 .778 .760 .741 .722 .702 .681 .659 70
71 .805 .789 .771 .753 .734 .714 .693 .672 71
72 .816 .800 .783 .765 .746 .727 .706 .685 72
73 .826 .811 .794 .777 .759 .739 .719 .698 73
74 .837 .822 .806 .789 .771 .752 .732 .712 74
-25-
</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 RETIREMENT
- ------------ --- --- --- --- --- --- --- --- ------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
75 .931 .923 .915 .906 .896 .885 .873 .861 75
76 .936 .929 .921 .913 .904 .893 .882 .870 76
77 .942 .935 .928 .920 .911 .902 .891 .880 77
77 .947 .941 .934 .927 .918 .909 .900 .889 78
78 .952 .946 .940 .933 .925 .917 .908 .898 79
80 .956 .951 .945 .939 .932 .924 .916 .906 80
81 .961 .956 .951 .945 .938 .931 .923 .914 81
82 .964 .960 .955 .950 .944 .937 .930 .922 82
83 .968 .964 .960 .955 .950 .943 .937 .929 83
84 .972 .968 .964 .960 .955 .949 .943 .936 84
</TABLE>
<TABLE>
<CAPTION>
BENEFICIARY'S BENEFICIARY'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 78 79 80 81 82 83 84 85 RETIREMENT
- ------------ --- --- --- --- --- --- --- --- ------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
75 .847 .833 .817 .801 .784 .765 .746 .726 75
76 .858 .844 .829 .813 .796 .778 .759 .740 76
77 .868 .854 .840 .825 .808 .791 .773 .754 77
78 .877 .865 .851 .836 .821 .804 .786 .768 78
79 .887 .875 .862 .848 .833 .817 .800 .782 79
80 .896 .885 .872 .859 .845 .829 .813 .795 80
81 .905 .894 .883 .870 .856 .842 .826 .809 81
82 .913 .903 .892 .881 .868 .854 .839 .823 82
83 .921 .912 .902 .891 .879 .866 .851 .836 83
84 .928 .920 .911 .900 .889 .877 .863 .849 84
</TABLE>
-26-
<PAGE> 29
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 RETIREMENT
- ------------- ---- ---- ---- ---- ---- ---- ---- ---- -------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
25 .731 .718 .704 .691 .676 .662 .647 .632 25
26 .734 .721 .707 .694 .679 .665 .650 .635 26
27 .737 .724 .710 .697 .683 .668 .653 .638 27
28 .740 .727 .714 .700 .686 .671 .656 .641 28
29 .744 .731 .717 .703 .689 .675 .660 .644 29
30 .747 .734 .721 .707 .693 .678 .663 .648 30
31 .751 .738 .725 .711 .696 .682 .667 .651 31
32 .755 .742 .728 .715 .700 .686 .671 .655 32
33 .759 .746 .732 .719 .704 .690 .675 .659 33
34 .763 .750 .737 .723 .708 .694 .679 .663 34
35 .768 .754 .741 .727 .713 .698 .683 .667 35
36 .772 .759 .746 .732 .717 .703 .687 .672 36
37 .777 .764 .750 .736 .722 .707 .692 .677 37
38 .781 .768 .755 .741 .727 .712 .697 .681 38
39 .786 .773 .760 .746 .732 .717 .702 .687 39
40 .791 .779 .765 .751 .737 .723 .707 .692 40
41 .797 .784 .771 .757 .743 .728 .713 .697 41
42 .802 .789 .776 .762 .748 .734 .719 .703 42
43 .807 .795 .782 .768 .754 .740 .724 .709 43
44 .813 .800 .788 .774 .760 .746 .731 .715 44
45 .819 .806 .793 .780 .766 .752 .737 .721 45
46 .824 .812 .799 .786 .773 .758 .743 .728 46
47 .830 .818 .806 .793 .779 .765 .750 .734 47
48 .836 .824 .812 .799 .785 .771 .757 .741 48
49 .842 .830 .818 .805 .792 .778 .764 .748 49
</TABLE>
<TABLE>
<CAPTION>
BENEFICIARY'S BENEFICIARY'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 63 64 65 66 67 68 69 70 RETIREMENT
- ------------- ---- ---- ---- ---- ---- ---- ---- ---- -------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
25 .617 .601 .585 .568 .551 .535 .518 .500 25
26 .619 .603 .587 .571 .554 .537 .520 .503 26
27 .622 .606 .590 .574 .557 .540 .523 .505 27
28 .625 .609 .593 .576 .560 .543 .525 .508 28
29 .629 .613 .596 .580 .563 .545 .528 .511 29
30 .632 .616 .599 .583 .566 .549 .531 .514 30
31 .636 .619 .603 .586 .569 .552 .534 .517 31
32 .639 .623 .607 .590 .573 .555 .538 .520 32
33 .643 .627 .610 .593 .576 .559 .541 .523 33
34 .647 .631 .614 .597 .580 .562 .545 .527 34
35 .651 .635 .618 .601 .584 .566 .549 .531 35
36 .656 .639 .623 .606 .588 .570 .553 .535 36
37 .661 .644 .627 .610 .593 .575 .557 .539 37
38 .665 .649 .632 .615 .597 .579 .561 .543 38
39 .670 .654 .637 .620 .602 .584 .566 .548 39
40 .676 .659 .642 .625 .607 .589 .571 .552 40
41 .681 .665 .648 .630 .612 .594 .576 .557 41
42 .687 .670 .653 .636 .618 .600 .581 .563 42
43 .693 .676 .659 .642 .624 .605 .587 .568 43
44 .699 .682 .665 .648 .630 .611 .593 .574 44
45 .705 .689 .671 .654 .636 .618 .599 .580 45
46 .712 .695 .678 .660 .642 .624 .605 .586 46
47 .718 .702 .685 .667 .649 .631 .612 .593 47
48 .725 .709 .692 .674 .656 .638 .619 .600 48
49 .732 .716 .699 .681 .663 .645 .626 .607 49
</TABLE>
-27-
<PAGE> 30
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 RETIREMENT
---------- --- --- --- --- --- --- --- --- ----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
50 .848 .837 .825 .812 .799 .785 .771 .756 50
51 .854 .843 .831 .819 .806 .792 .778 .763 51
52 .860 .849 .838 .826 .813 .799 .785 .770 52
53 .866 .855 .844 .832 .820 .807 .793 .778 53
54 .872 .862 .851 .839 .827 .814 .800 .786 54
55 .878 .868 .857 .846 .834 .821 .808 .794 55
56 .884 .874 .864 .853 .841 .829 .816 .802 56
57 .890 .880 .870 .860 .848 .836 .823 .810 57
58 .895 .886 .877 .866 .855 .844 .831 .818 58
59 .901 .893 .883 .873 .863 .851 .839 .826 59
60 .907 .898 .890 .880 .870 .859 .847 .834 60
61 .912 .904 .896 .887 .877 .866 .855 .842 61
62 .918 .910 .902 .893 .884 .873 .862 .851 62
63 .923 .916 .908 .900 .890 .881 .870 .859 63
64 .928 .921 .914 .906 .897 .888 .878 .867 64
65 .933 .926 .919 .912 .904 .895 .885 .875 65
66 .937 .931 .925 .918 .910 .902 .892 .882 66
67 .942 .936 .930 .924 .916 .908 .900 .890 67
68 .946 .941 .935 .929 .922 .915 .906 .897 68
69 .950 .946 .940 .934 .928 .921 .913 .905 69
70 .954 .950 .945 .939 .933 .927 .920 .912 70
71 .958 .954 .949 .944 .939 .932 .926 .918 71
72 .962 .958 .953 .949 .944 .938 .932 .925 72
73 .965 .961 .957 .953 .948 .943 .937 .931 73
74 .968 .965 .961 .957 .953 .948 .942 .936 74
</TABLE>
<TABLE>
<CAPTION>
BENEFICIARY'S BENEFICIARY'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 63 64 65 66 67 68 69 70 RETIREMENT
---------- --- --- --- --- --- --- --- --- ----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
50 .740 .723 .706 .689 .671 .652 .633 .614 50
51 .747 .731 .714 .697 .679 .660 .641 .622 51
52 .755 .739 .722 .705 .687 .668 .649 .630 52
53 .763 .747 .730 .713 .695 .676 .657 .638 53
54 .771 .755 .738 .721 .703 .685 .666 .646 54
55 .779 .763 .747 .730 .712 .693 .674 .655 55
56 .787 .771 .755 .738 .721 .702 .683 .664 56
57 .795 .780 .764 .747 .730 .712 .693 .673 57
58 .804 .789 .773 .756 .739 .721 .702 .683 58
59 .812 .798 .782 .766 .749 .731 .712 .693 59
60 .821 .806 .791 .775 .758 .741 .722 .703 60
61 .829 .815 .800 .785 .768 .751 .733 .714 61
62 .838 .824 .810 .794 .778 .761 .743 .725 62
63 .846 .833 .819 .804 .788 .772 .754 .736 63
64 .855 .842 .829 .814 .799 .782 .765 .747 64
65 .863 .851 .838 .824 .809 .793 .776 .758 65
66 .872 .860 .847 .833 .819 .803 .787 .770 66
67 .880 .868 .856 .843 .829 .814 .798 .781 67
68 .888 .877 .865 .853 .839 .825 .809 .793 68
69 .895 .885 .874 .862 .849 .835 .820 .804 69
70 .903 .893 .883 .871 .859 .845 .831 .816 70
71 .910 .901 .891 .880 .868 .855 .842 .827 71
72 .917 .908 .899 .889 .878 .865 .852 .838 72
73 .923 .916 .907 .897 .887 .875 .863 .849 73
74 .930 .922 .914 .905 .895 .884 .873 .860 74
</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 RETIREMENT
---------- --- --- --- --- --- --- --- --- ----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
75 .971 .968 .965 .961 .957 .952 .948 .942 75
76 .974 .971 .968 .965 .961 .957 .952 .947 76
77 .976 .974 .971 .968 .965 .961 .957 .952 77
78 .979 .976 .974 .971 .968 .965 .961 .957 78
79 .981 .979 .976 .974 .971 .968 .965 .961 79
80 .983 .981 .979 .977 .974 .971 .968 .965 80
81 .985 .983 .981 .979 .977 .974 .971 .968 81
82 .986 .985 .983 .981 .979 .977 .975 .972 82
83 .988 .986 .985 .983 .982 .980 .977 .975 83
84 .989 .988 .987 .985 .984 .982 .980 .978 84
</TABLE>
<TABLE>
<CAPTION>
BENEFICIARY'S BENEFICIARY'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 63 64 65 66 67 68 69 70 RETIREMENT
---------- --- --- --- --- --- --- --- --- ----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
75 .936 .929 .921 .913 .904 .893 .882 .870 75
76 .941 .935 .928 .920 .912 .902 .892 .880 76
77 .947 .941 .934 .927 .919 .910 .900 .890 77
78 .952 .946 .940 .934 .926 .918 .909 .899 78
79 .956 .952 .946 .940 .933 .926 .917 .908 79
80 .961 .956 .951 .946 .939 .932 .925 .916 80
81 .965 .961 .956 .951 .945 .939 .932 .924 81
82 .968 .965 .961 .956 .951 .945 .939 .931 82
83 .972 .969 .965 .961 .956 .951 .945 .938 83
84 .975 .972 .969 .965 .961 .958 .951 .945 84
</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 70 71 72 73 74 75 76 77 RETIREMENT
- ----------- --- --- --- --- --- --- --- --- -------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
25 .500 .483 .466 .449 .432 .414 .397 .380 25
26 .503 .486 .468 .451 .434 .416 .399 .382 26
27 .505 .488 .471 .453 .436 .419 .401 .384 27
28 .508 .491 .473 .456 .438 .421 .403 .386 28
29 .511 .493 .476 .458 .441 .423 .406 .388 29
30 .514 .496 .478 .461 .443 .426 .408 .391 30
31 .517 .499 .481 .464 .446 .428 .411 .393 31
32 .520 .502 .484 .466 .449 .431 .413 .396 32
33 .523 .505 .488 .470 .452 .434 .416 .398 33
34 .527 .509 .491 .473 .455 .437 .419 .401 34
35 .531 .513 .494 .476 .458 .440 .422 .404 35
36 .535 .516 .498 .480 .462 .443 .425 .407 36
37 .539 .520 .502 .484 .465 .447 .429 .411 37
38 .543 .525 .506 .488 .469 .451 .432 .414 38
39 .548 .529 .511 .492 .473 .455 .436 .418 39
40 .552 .534 .515 .496 .478 .459 .440 .422 40
41 .557 .539 .520 .501 .482 .463 .445 .426 41
42 .563 .544 .525 .506 .487 .468 .449 .430 42
43 .568 .549 .530 .511 .492 .473 .454 .435 43
44 .574 .555 .536 .517 .497 .478 .459 .440 44
45 .580 .561 .542 .522 .503 .483 .464 .445 45
46 .586 .567 .548 .528 .509 .489 .469 .450 46
47 .593 .573 .554 .534 .515 .495 .475 .455 47
48 .600 .580 .561 .541 .521 .501 .481 .461 48
49 .607 .587 .567 .548 .528 .507 .487 .467 49
</TABLE>
<TABLE>
<CAPTION>
BENEFICIARY'S BENEFICIARY'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 78 79 80 81 82 83 84 85 RETIREMENT
- ----------- --- --- --- --- --- --- --- --- ------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
25 .364 .347 .331 .315 .299 .284 .269 .254 25
26 .365 .349 .333 .316 .301 .285 .270 .256 26
27 .367 .351 .334 .318 .302 .287 .272 .257 27
28 .369 .353 .336 .320 .304 .288 .273 .258 28
29 .371 .355 .338 .322 .306 .290 .275 .260 29
30 .374 .357 .340 .324 .307 .292 .276 .261 30
31 .376 .359 .342 .326 .309 .294 .278 .263 31
32 .378 .361 .344 .328 .311 .295 .280 .265 32
33 .381 .364 .347 .330 .314 .298 .282 .267 33
34 .384 .366 .349 .332 .316 .300 .284 .269 34
35 .387 .369 .352 .335 .318 .302 .286 .271 35
36 .390 .372 .355 .337 .321 .304 .288 .273 36
37 .393 .375 .357 .340 .323 .307 .291 .275 37
38 .396 .378 .361 .343 .326 .310 .293 .277 38
39 .400 .382 .364 .346 .329 .312 .296 .280 39
40 .403 .385 .367 .350 .332 .315 .299 .283 40
41 .407 .389 .371 .353 .336 .319 .302 .286 41
42 .412 .393 .375 .357 .339 .322 .305 .289 42
43 .416 .397 .379 .361 .343 .326 .309 .292 43
44 .421 .402 .383 .365 .347 .329 .312 .295 44
45 .425 .406 .388 .369 .351 .333 .316 .299 45
46 .431 .411 .392 .374 .355 .337 .320 .303 46
47 .436 .417 .397 .379 .360 .342 .324 .307 47
48 .442 .422 .403 .384 .365 .346 .328 .311 48
49 .447 .428 .408 .389 .370 .351 .333 .315 49
</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 70 71 72 73 74 75 76 77 RETIREMENT
- ------------ --- --- --- --- --- --- --- --- -------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
50 .614 .594 .575 .555 .534 .514 .494 .474 50
51 .622 .602 .582 .562 .542 .521 .501 .480 51
52 .630 .610 .590 .570 .549 .529 .508 .487 52
53 .638 .618 .598 .577 .557 .536 .515 .495 53
54 .646 .626 .606 .586 .565 .544 .523 .502 54
55 .655 .635 .615 .594 .574 .553 .532 .510 55
56 .664 .644 .624 .603 .582 .561 .540 .519 56
57 .673 .654 .633 .613 .592 .570 .549 .528 57
58 .683 .663 .643 .622 .601 .580 .558 .537 58
59 .693 .673 .653 .632 .611 .590 .568 .546 59
60 .703 .684 .663 .643 .622 .600 .578 .556 60
61 .714 .694 .674 .654 .632 .611 .589 .567 61
62 .725 .705 .685 .665 .644 .622 .600 .578 62
63 .736 .716 .697 .676 .655 .634 .612 .589 63
64 .747 .728 .708 .688 .667 .646 .624 .601 64
65 .758 .740 .720 .700 .679 .658 .636 .614 65
66 .770 .751 .732 .712 .692 .671 .649 .627 66
67 .781 .763 .745 .725 .705 .684 .662 .640 67
68 .793 .775 .757 .738 .718 .697 .676 .653 68
69 .804 .787 .769 .751 .731 .711 .689 .667 69
70 .816 .799 .782 .764 .744 .724 .703 .682 70
71 .827 .811 .794 .777 .758 .738 .718 .696 71
72 .838 .823 .807 .790 .771 .752 .732 .711 72
73 .849 .835 .819 .802 .785 .766 .746 .726 73
74 .860 .846 .831 .815 .798 .780 .761 .741 74
</TABLE>
<TABLE>
<CAPTION>
BENEFICIARY'S BENEFICIARY'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 78 79 80 81 82 83 84 85 RETIREMENT
- ------------ --- --- --- --- --- --- --- --- -------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
50 .454 .434 .414 .394 .375 .356 .338 .320 50
51 .460 .440 .420 .400 .381 .362 .343 .325 51
52 .467 .446 .426 .406 .387 .367 .348 .330 52
53 .474 .453 .433 .413 .393 .373 .354 .335 53
54 .481 .461 .440 .419 .399 .379 .360 .341 54
55 .489 .468 .447 .426 .406 .386 .366 .347 55
56 .497 .476 .455 .434 .413 .393 .373 .353 56
57 .506 .484 .463 .442 .421 .400 .380 .360 57
58 .515 .493 .472 .450 .429 .408 .387 .367 58
59 .524 .502 .481 .459 .437 .416 .395 .374 59
60 .534 .512 .490 .468 .446 .424 .403 .382 60
61 .545 .522 .500 .478 .455 .434 .412 .391 61
62 .556 .533 .510 .488 .465 .443 .421 .400 62
63 .567 .644 .521 .499 .476 .453 .431 .409 63
64 .579 .556 .533 .510 .487 .464 .441 .419 64
65 .591 .568 .545 .522 .498 .475 .452 .430 65
66 .604 .581 .557 .534 .511 .487 .464 .441 66
67 .617 .594 .571 .547 .523 .500 .476 .453 67
68 .631 .608 .584 .560 .537 .513 .489 .465 68
69 .645 .622 .598 .574 .550 .526 .502 .478 69
70 .659 .636 .613 .589 .565 .540 .516 .492 70
71 .674 .651 .628 .604 .580 .555 .531 .506 71
72 .689 .666 .643 .619 .595 .571 .546 .521 72
73 .704 .682 .659 .635 .611 .586 .562 .536 73
74 .720 .698 .675 .651 .627 .603 .578 .553 74
</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 RETIREMENT
---------- --- --- --- --- --- --- --- --- -------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
75 .870 .857 .843 .828 .811 .794 .775 .756 75
76 .880 .868 .854 .840 .824 .807 .790 .771 76
77 .890 .878 .865 .852 .837 .821 .804 .785 77
78 .899 .888 .876 .863 .849 .834 .818 .800 78
79 .908 .898 .886 .874 .861 .847 .831 .814 79
80 .916 .907 .896 .885 .873 .859 .844 .828 80
81 .924 .915 .906 .895 .884 .871 .857 .842 81
82 .931 .923 .915 .905 .894 .882 .869 .855 82
83 .938 .931 .923 .914 .904 .893 .881 .868 83
84 .945 .938 .931 .922 .913 .903 .892 .880 84
</TABLE>
<TABLE>
<CAPTION>
BENEFICIARY'S BENEFICIARY'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 78 79 80 81 82 83 84 85 RETIREMENT
---------- --- --- --- --- --- --- --- --- -----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
75 .735 .714 .691 .668 .644 .620 .595 .569 75
76 .751 .730 .708 .685 .661 .637 .612 .587 76
77 .766 .746 .724 .702 .679 .654 .630 .605 77
78 .781 .762 .741 .719 .696 .672 .648 .623 78
79 .797 .778 .757 .736 .714 .690 .666 .641 79
80 .811 .793 .774 .753 .731 .709 .685 .660 80
81 .826 .808 .790 .770 .749 .727 .704 .680 81
82 .840 .823 .806 .787 .766 .745 .723 .699 82
83 .853 .838 .821 .803 .784 .763 .741 .718 83
84 .866 .852 .836 .819 .800 .781 .760 .738 84
</TABLE>
-32-
<PAGE> 35
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 higher.
(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>
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>
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.
-33-
<PAGE> 36
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 RETIREMENT
- ----------- --- --- --- --- --- --- --- --- ----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
40 .969 .967 .964 .962 .959 .956 .953 .950 40
41 .970 .968 .965 .963 .960 .957 .954 .951 41
42 .971 .969 .966 .964 .961 .958 .955 .952 42
43 .972 .970 .967 .965 .962 .960 .957 .953 43
44 .973 .971 .968 .966 .963 .961 .958 .955 44
45 .974 .972 .969 .967 .965 .962 .959 .956 45
46 .975 .973 .970 .968 .966 .963 .960 .957 46
47 .976 .974 .972 .969 .967 .964 .962 .959 47
48 .977 .975 .973 .970 .968 .966 .963 .960 48
49 .978 .976 .974 .972 .969 .967 .964 .961 49
50 .979 .977 .975 .973 .970 .968 .965 .963 50
51 .980 .978 .976 .974 .972 .969 .967 .964 51
52 .980 .979 .977 .975 .973 .970 .968 .965 52
53 .981 .980 .978 .976 .974 .972 .969 .967 53
54 .982 .981 .979 .977 .975 .973 .971 .968 54
55 .983 .982 .980 .978 .976 .974 .972 .969 55
56 .984 .983 .981 .979 .977 .975 .973 .971 56
57 .985 .984 .982 .980 .979 .977 .975 .972 57
58 .986 .984 .983 .981 .980 .978 .976 .974 58
59 .987 .985 .984 .982 .981 .979 .977 .975 59
</TABLE>
<TABLE>
<CAPTION>
SPOUSE'S SPOUSE'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 63 64 65 66 67 68 69 70 RETIREMENT
- ----------- --- --- --- --- --- --- --- --- ----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
40 .946 .943 .939 .935 .930 .926 .921 .916 40
41 .948 .944 .940 .936 .932 .927 .922 .917 41
42 .949 .945 .941 .937 .933 .929 .924 .919 42
43 .950 .947 .943 .939 .934 .930 .925 .920 43
44 .951 .948 .944 .940 .936 .931 .927 .922 44
45 .953 .949 .946 .942 .937 .933 .928 .923 45
46 .954 .951 .947 .943 .939 .935 .930 .925 46
47 .955 .952 .948 .945 .940 .936 .932 .927 47
48 .957 .953 .950 .946 .942 .938 .933 .928 48
49 .958 .955 .951 .948 .944 .939 .935 .930 49
50 .960 .956 .953 .949 .945 .941 .937 .932 50
51 .961 .958 .955 .951 .947 .943 .939 .934 51
52 .962 .959 .956 .953 .949 .945 .940 .936 52
53 .964 .961 .958 .954 .951 .947 .942 .938 53
54 .965 .962 .959 .956 .952 .948 .944 .940 54
55 .967 .964 .961 .958 .954 .950 .946 .942 55
56 .968 .966 .963 .959 .956 .952. .948 .944 56
57 .970 .967 .964 .961 .958 .954 .950 .946 57
58 .971 .969 .966 .963 .959 .956 .952 .948 58
59 .973 .970 .967 .964 .961 .958 .954 .950 59
</TABLE>
NOTE: Factors for additional age combinations are available from the
Administrator.
-34-
<PAGE> 37
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 RETIREMENT
- ----------- --- --- --- --- --- --- --- --- ----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
60 .987 .986 .985 .984 .982 .980 .978 .976 60
61 .988 .987 .986 .985 .983 .981 .980 .978 61
62 .989 .988 .987 .985 .984 .983 .981 .979 62
63 .990 .989 .988 .986 .985 .984 .982 .980 63
64 .990 .990 .988 .987 .986 .985 .983 .981 64
65 .991 .990 .989 .988 .987 .986 .984 .983 65
66 .992 .991 .990 .989 .988 .987 .985 .984 66
67 .992 .992 .991 .990 .989 .988 .986 .985 67
68 .993 .992 .992 .991 .990 .989 .987 .986 68
69 .994 .993 .992 .991 .990 .989 .988 .987 69
70 .994 .993 .993 .992 .991 .990 .989 .988 70
71 .995 .994 .993 .993 .992 .991 .990 .989 71
72 .995 .995 .994 .993 .993 .992 .991 .990 72
73 .995 .995 .995 .994 .993 .993 .992 .991 73
74 .996 .995 .995 .994 .994 .993 .992 .992 74
</TABLE>
<TABLE>
<CAPTION>
SPOUSE'S SPOUSE'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 63 64 65 66 67 68 69 70 RETIREMENT
- ----------- --- --- --- --- --- --- --- --- ----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
60 .974 .972 .969 .966 .963 .960 .956 .952 60
61 .976 .973 .971 .968 .965 .962 .958 .954 61
62 .977 .975 .972 .970 .967 .964 .960 .957 62
63 .978 .976 .974 .971 .969 .966 .962 .959 63
64 .980 .978 .975 .973 .970 .967 .964 .961 64
65 .981 .979 .977 .975 .972 .969 .966 .963 65
66 .982 .980 .978 .976 .974 .971 .968 .965 66
67 .983 .982 .980 .978 .975 .973 .970 .967 67
68 .985 .983 .981 .979 .977 .975 .972 .969 68
69 .986 .984 .983 .981 .979 .976 .974 .971 69
70 .987 .985 .984 .982 .980 .978 .976 .973 70
71 .988 .987 .985 .984 .982 .980 .978 .975 71
72 .989 .988 .986 .985 .983 .981 .979 .977 72
73 .990 .989 .987 .986 .985 .983 .981 .979 73
74 .991 .990 .989 .987 .986 .984 .982 .980 74
</TABLE>
NOTE: Factors for additional age combinations are available from the
Administrator.
-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
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 RETIREMENT
- ----------- --- --- --- --- --- --- --- --- ----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
40 .942 .938 .934 .929 .924 .919 .914 .909 40
41 .943 .939 .935 .931 .926 .921 .916 .911 41
42 .945 .941 .937 .933 .928 .923 .918 .913 42
43 .947 .943 .939 .934 .930 .925 .920 .915 43
44 .948 .945 .941 .936 .932 .927 .922 .917 44
45 .950 .946 .942 .938 .934 .929 .924 .919 45
46 .952 .948 .944 .940 .936 .931 .926 .921 46
47 .954 .950 .946 .942 .938 .933 .929 .923 47
48 .955 .952 .948 .944 .940 .935 .931 .926 48
49 .957 .954 .950 .946 .942 .938 .933 .928 49
50 .959 .956 .952 .948 .944 .940 .935 .930 50
51 .961 .957 .954 .950 .946 .942 .938 .933 51
52 .962 .959 .956 .952 .948 .944 .940 .935 52
53 .964 .961 .958 .954 .950 .946 .942 .938 53
54 .966 .963 .960 .956 .953 .949 .945 .940 54
55 .968 .965 .962 .958 .955 .951 .947 .942 55
56 .969 .966 .963 .960 .957 .953 .949 .945 56
57 .971 .968 .965 .962 .959 .955 .952 .947 57
58 .972 .970 .967 .964 .961 .958 .954 .950 58
59 .974 .972 .969 .966 .963 .960 .956 .952 59
</TABLE>
<TABLE>
<CAPTION>
SPOUSE'S SPOUSE'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 63 64 65 66 67 68 69 70 RETIREMENT
- ----------- --- --- --- --- --- --- --- --- ----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
40 .903 .897 .891 .885 .878 .871 .863 .856 40
41 .905 .899 .893 .887 .880 .873 .865 .858 41
42 .907 .901 .895 .889 .882 .875 .868 .860 42
43 .909 .903 .897 .891 .884 .877 .870 .862 43
44 .911 .906 .899 .893 .886 .879 .872 .865 44
45 .914 .908 .902 .895 .889 .882 .875 .867 45
46 .916 .910 .904 .898 .891 .884 .877 .870 46
47 .918 .912 .906 .900 .894 .887 .880 .872 47
48 .920 .915 .909 .903 .896 .889 .882 .875 48
49 .923 .917 .911 .905 .899 .892 .885 .878 49
50 .925 .920 .914 .908 .901 .895 .888 .880 50
51 .928 .922 .917 .911 .904 .898 .891 .883 51
52 .930 .925 .919 .913 .907 .900 .894 .886 52
53 .933 .927 .922 .916 .910 .903 .897 .889 53
54 .935 .930 .925 .919 .913 .906 .900 .893 54
55 .938 .933 .927 .922 .916 .909 .903 .896 55
56 .940 .936 .930 .925 .919 .913 .906 .899 56
57 .943 .938 .933 .928 .922 .916 .909 .902 57
58 .946 .941 .936 .931 .925 .919 .913 .906 58
59 .948 .944 .939 .934 .928 .922 .916 .909 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
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 RETIREMENT
- ----------- --- --- --- --- --- --- --- --- ----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
60 .976 .973 .971 .968 .965 .962 .959 .955 60
61 .977 .975 .973 .970 .967 .964 .961 .957 61
62 .979 .976 .974 .972 .969 .966 .963 .960 62
63 .980 .978 .976 .974 .971 .968 .965 .962 63
64 .981 .979 .977 .975 .973 .970 .967 .964 64
65 .983 .981 .979 .977 .975 .972 .970 .967 65
66 .984 .982 .980 .979 .976 .974 .972 .969 66
67 .985 .984 .982 .980 .978 .976 .974 .971 67
68 .986 .985 .983 .982 .980 .978 .975 .973 68
69 .987 .986 .985 .983 .981 .979 .977 .975 69
70 .988 .987 .986 .984 .983 .981 .979 .977 70
71 .989 .988 .987 .986 .984 .983 .981 .979 71
72 .990 .989 .988 .987 .985 .984 .982 .980 72
73 .991 .990 .989 .988 .987 .985 .984 .982 73
74 .992 .991 .990 .989 .988 .987 .985 .984 74
</TABLE>
<TABLE>
<CAPTION>
SPOUSE'S SPOUSE'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 63 64 65 66 67 68 69 70 RETIREMENT
- ----------- --- --- --- --- --- --- --- --- -----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
60 .951 .946 .942 .937 .931 .926 .919 .913 60
61 .953 .949 .945 .940 .934 .929 .923 .916 61
62 .956 .952 .947 .943 .938 .932 .926 .920 62
63 .958 .955 .950 .946 .941 .936 .930 .924 63
64 .961 .957 .953 .949 .944 .939 .933 .928 64
65 .963 .960 .956 .952 .947 .942 .937 .931 65
66 .966 .962 .959 .955 .950 .945 .940 .935 66
67 .968 .965 .961 .957 .953 .949 .944 .939 67
68 .970 .967 .964 .960 .956 .952 .947 .942 68
69 .972 .970 .966 .963 .959 .955 .951 .946 69
70 .974 .972 .969 .966 .962 .958 .954 .949 70
71 .976 .974 .971 .968 .965 .961 .957 .953 71
72 .978 .976 .973 .971 .967 .964 .960 .956 72
73 .980 .978 .976 .973 .970 .967 .963 .959 73
74 .982 .980 .978 .975 .972 .969 .966 .962 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
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 RETIREMENT
- ----------- --- --- --- --- --- --- --- --- ----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
40 .890 .883 .875 .868 .859 .851 .842 .833 40
41 .893 .886 .878 .871 .863 .854 .845 .836 41
42 .896 .889 .881 .874 .866 .857 .849 .840 42
43 .899 .892 .885 .877 .869 .861 .852 .843 43
44 .902 .895 .888 .880 .872 .864 .856 .847 44
45 .905 .898 .891 .884 .876 .868 .859 .850 45
46 .908 .901 .894 .887 .879 .871 .863 .854 46
47 .911 .905 .898 .891 .883 .875 .867 .858 47
48 .915 .908 .901 .894 .887 .879 .870 .862 48
49 .918 .911 .905 .898 .890 .883 .874 .866 49
50 .921 .915 .908 .901 .894 .886 .878 .870 50
51 .924 .918 .912 .905 .898 .890 .882 .874 51
52 .927 .922 .915 .909 .902 .894 .887 .878 52
53 .931 .925 .919 .912 .906 .898 .891 .883 53
54 .934 .928 .922 .916 .910 .902 .895 .887 54
55 .937 .932 .926 .920 .913 .906 .899 .891 55
56 .940 .935 .930 .924 .917 .911 .903 .896 56
57 .943 .938 .933 .927 .921 .915 .908 .900 57
58 .946 .942 .936 .931 .925 .919 .912 .905 58
59 .949 .945 .940 .935 .929 .923 .916 .909 59
</TABLE>
<TABLE>
<CAPTION>
SPOUSE'S SPOUSE'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 63 64 65 66 67 68 69 70 RETIREMENT
- ----------- --- --- --- --- --- --- --- --- ----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
40 .824 .814 .803 .793 .782 .771 .760 .748 40
41 .827 .817 .807 .796 .785 .774 .763 .751 41
42 .830 .820 .810 .800 .789 .778 .766 .754 42
43 .834 .824 .814 .803 .792 .781 .770 .758 43
44 .837 .827 .817 .807 .796 .785 .773 .762 44
45 .841 .831 .821 .811 .800 .789 .777 .765 45
46 .845 .835 .825 .814 .804 .792 .781 .769 46
47 .849 .839 .829 .819 .808 .797 .785 .773 47
48 .853 .843 .833 .823 .812 .801 .789 .778 48
49 .857 .847 .837 .827 .816 .805 .794 .782 49
50 .861 .851 .842 .831 .821 .810 .798 .786 50
51 .865 .856 .846 .836 .825 .814 .803 .791 51
52 .869 .860 .851 .840 .830 .819 .808 .796 52
53 .874 .865 .855 .845 .835 .824 .813 .801 53
54 .878 .869 .860 .850 .840 .829 .818 .806 54
55 .883 .874 .865 .855 .845 .834 .823 .811 55
56 .887 .879 .870 .860 .850 .839 .828 .817 56
57 .892 .884 .875 .865 .855 .845 .834 .822 57
58 .897 .888 .880 .870 .860 .850 .839 .828 58
59 .901 .893 .885 .876 .866 .856 .845 .834 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
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 RETIREMENT
- ----------- --- --- --- --- --- --- --- --- ----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
60 .952 .948 .943 .938 .933 .927 .920 .914 60
61 .955 .951 .946 .942 .936 .931 .925 .918 61
62 .958 .954 .950 .945 .940 .935 .929 .922 62
63 .961 .957 .953 .948 .944 .939 .933 .927 63
64 .963 .960 .956 .952 .947 .942 .937 .931 64
65 .966 .962 .959 .955 .951 .946 .941 .935 65
66 .968 .965 .962 .958 .954 .950 .945 .939 66
67 .971 .968 .964 .961 .957 .953 .948 .943 67
68 .973 .970 .967 .964 .960 .956 .952 .947 68
69 .975 .972 .970 .967 .963 .960 .956 .951 69
70 .977 .975 .972 .969 .966 .963 .959 .955 70
71 .979 .977 .974 .972 .969 .966 .962 .958 71
72 .981 .979 .976 .974 .971 .968 .965 .962 72
73 .982 .980 .978 .976 .974 .971 .968 .965 73
74 .984 .982 .980 .978 .976 .974 .971 .968 74
</TABLE>
<TABLE>
<CAPTION>
SPOUSE'S SPOUSE'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 63 64 65 66 67 68 69 70 RETIREMENT
- ----------- --- --- --- --- --- --- --- --- ----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
60 .906 .898 .890 .881 .871 .861 .851 .840 60
61 .911 .903 .895 .886 .877 .867 .857 .846 61
62 .915 .908 .900 .892 .883 .873 .863 .852 62
63 .920 .913 .905 .897 .888 .879 .869 .858 63
64 .925 .918 .910 .902 .894 .885 .875 .865 64
65 .929 .923 .916 .908 .900 .891 .881 .871 65
66 .934 .927 .921 .913 .905 .897 .887 .878 66
67 .938 .932 .925 .918 .911 .902 .894 .884 67
68 .942 .936 .930 .924 .916 .908 .900 .891 68
69 .946 .941 .935 .929 .922 .914 .906 .897 69
70 .950 .945 .940 .933 .927 .920 .912 .903 70
71 .954 .949 .944 .938 .932 .925 .918 .910 71
72 .958 .953 .948 .943 .937 .930 .923 .916 72
73 .961 .957 .952 .947 .942 .936 .929 .922 73
74 .964 .960 .956 .951 .946 .940 .934 .927 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
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 RETIREMENT
- ----------- --- --- --- --- --- --- --- --- ----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
40 .844 .834 .824 .814 .803 .792 .781 .769 40
41 .847 .838 .828 .818 .807 .796 .785 .773 41
42 .851 .842 .832 .822 .811 .800 .789 .777 42
43 .855 .846 .836 .826 .816 .805 .793 .782 43
44 .860 .850 .841 .831 .820 .809 .798 .786 44
45 .864 .855 .845 .835 .825 .814 .803 .791 45
46 .868 .859 .850 .840 .829 .819 .807 .796 46
47 .873 .864 .854 .844 .834 .824 .812 .801 47
48 .877 .868 .859 .849 .839 .829 .817 .806 48
49 .881 .873 .864 .854 .844 .834 .823 .811 49
50 .886 .877 .868 .859 .849 .839 .828 .817 50
51 .890 .882 .873 .864 .854 .844 .833 .822 51
52 .895 .887 .878 .869 .860 .850 .839 .828 52
53 .899 .892 .883 .874 .865 .855 .845 .834 53
54 .904 .896 .888 .879 .870 .860 .850 .839 54
55 .908 .901 .893 .884 .876 .866 .856 .845 55
56 .913 .906 .898 .890 .881 .872 .862 .851 56
57 .917 .910 .903 .895 .886 .877 .868 .857 57
58 .922 .915 .908 .900 .892 .883 .873 .863 58
59 .926 .919 .912 .905 .897 .888 .879 .870 59
</TABLE>
<TABLE>
<CAPTION>
SPOUSE'S SPOUSE'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 63 64 65 66 67 68 69 70 RETIREMENT
- ----------- --- --- --- --- --- --- --- --- ----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
40 .757 .744 .732 .719 .705 .692 .678 .664 40
41 .761 .748 .736 .723 .709 .696 .682 .668 41
42 .765 .753 .740 .727 .713 .700 .686 .672 42
43 .770 .757 .744 .731 .718 .704 .690 .676 43
44 .774 .762 .749 .736 .722 .709 .695 .680 44
45 .779 .766 .754 .740 .727 .713 .699 .685 45
46 .784 .771 .759 .745 .732 .718 .704 .690 46
47 .789 .776 .764 .750 .737 .723 .709 .695 47
48 .794 .782 .769 .756 .742 .728 .714 .700 48
49 .799 .787 .774 .761 .748 .734 .719 .705 49
50 .805 .793 .780 .767 .753 .739 .725 .711 50
51 .810 .798 .786 .772 .759 .745 .731 .716 51
52 .816 .804 .791 .778 .765 .751 .737 .722 52
53 .822 .810 .797 .784 .771 .757 .743 .728 53
54 .828 .816 .804 .791 .777 .763 .749 .735 54
55 .834 .822 .810 .797 .784 .770 .756 .741 55
56 .840 .829 .816 .804 .791 .777 .763 .748 56
57 .846 .835 .823 .810 .797 .784 .770 .755 57
58 .853 .842 .830 .817 .804 .791 .777 .762 58
59 .859 .848 .837 .824 .811 .798 .784 .770 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
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 RETIREMENT
- ----------- --- --- --- --- --- --- --- --- -----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
60 .930 .924 .917 .910 .902 .894 .885 .876 60
61 .934 .928 .922 .915 .908 .900 .891 .882 61
62 .938 .933 .926 .920 .913 .905 .897 .888 62
63 .942 .937 .931 .925 .918 .911 .903 .894 63
64 .946 .941 .935 .929 .923 .916 .908 .900 64
65 .950 .945 .940 .934 .928 .921 .914 .906 65
66 .953 .949 .944 .938 .933 .926 .919 .912 66
67 .957 .952 .948 .943 .937 .931 .925 .918 67
68 .960 .956 .951 .947 .942 .936 .930 .923 68
69 .963 .959 .955 .951 .946 .941 .935 .928 69
70 .966 .962 .959 .955 .950 .945 .940 .934 70
71 .969 .965 .962 .958 .954 .949 .944 .939 71
72 .971 .968 .965 .962 .958 .953 .949 .943 72
73 .974 .971 .968 .965 .961 .957 .953 .948 73
74 .976 .974 .971 .968 .965 .961 .957 .952 74
</TABLE>
<TABLE>
<CAPTION>
SPOUSE'S SPOUSE'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 63 64 65 66 67 68 69 70 RETIREMENT
- ----------- --- --- --- --- --- --- --- --- -----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
60 .866 .855 .843 .831 .819 .805 .792 .777 60
61 .872 .861 .850 .839 .826 .813 .799 .785 61
62 .878 .868 .857 .846 .834 .821 .807 .793 62
63 .885 .875 .864 .853 .841 .829 .815 .802 63
64 .891 .882 .871 .860 .849 .837 .824 .810 64
65 .897 .888 .878 .868 .857 .845 .832 .819 65
66 .904 .895 .885 .875 .864 .853 .840 .827 66
67 .910 .901 .892 .882 .872 .860 .848 .836 67
68 .916 .908 .899 .890 .879 .868 .857 .844 68
69 .921 .914 .906 .897 .887 .876 .865 .853 69
70 .927 .920 .912 .903 .894 .884 .873 .862 70
71 .932 .926 .918 .910 .901 .892 .881 .870 71
72 .938 .931 .924 .917 .908 .899 .889 .879 72
73 .943 .937 .930 .923 .915 .906 .897 .887 73
74 .947 .952 .936 .929 .921 .913 .904 .895 74
</TABLE>
NOTE: Factors for additional age combinations are available from the
Administrator.
-41-
<PAGE> 44
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 RETIREMENT
- ----------- --- --- --- --- --- --- --- --- ----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
20 .966 .964 .961 .959 .956 .953 .950 .947 20
21 .967 .964 .962 .959 .957 .954 .951 .948 21
22 .967 .965 .963 .960 .957 .955 .952 .949 22
23 .968 .966 .963 .961 .958 .955 .952 .949 23
24 .969 .966 .964 .961 .959 .956 .953 .950 24
25 .969 .967 .965 .962 .960 .957 .954 .951 25
26 .970 .968 .965 .963 .960 .958 .955 .952 26
27 .971 .969 .966 .964 .961 .959 .956 .953 27
28 .971 .969 .967 .965 .962 .959 .957 .954 28
29 .972 .970 .968 .965 .963 .960 .957 .954 29
30 .973 .971 .969 .966 .964 .961 .958 .955 30
31 .974 .972 .969 .967 .965 .962 .959 .956 31
32 .974 .972 .970 .968 .965 .963 .960 .957 32
33 .975 .973 .971 .969 .966 .964 .961 .958 33
34 .976 .974 .972 .970 .967 .965 .962 .959 34
35 .977 .975 .973 .970 .968 .966 .963 .960 35
36 .977 .975 .973 .971 .969 .967 .964 .961 36
37 .978 .976 .974 .972 .970 .968 .965 .962 37
38 .979 .977 .975 .973 .971 .969 .966 .963 38
39 .980 .978 .976 .974 .972 .970 .967 .964 39
</TABLE>
<TABLE>
<CAPTION>
SPOUSE'S SPOUSE'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 48 49 50 51 52 53 54 55 RETIREMENT
- ----------- --- --- --- --- --- --- --- --- ----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
20 .944 .940 .937 .933 .929 .926 .921 .917 20
21 .945 .941 .938 .934 .930 .926 .922 .918 21
22 .945 .942 .938 .935 .931 .927 .923 .919 22
23 .946 .943 .939 .936 .932 .928 .924 .920 23
24 .947 .944 .940 .937 .933 .929 .925 .921 24
25 .948 .944 .941 .937 .934 .930 .926 .921 25
26 .949 .945 .942 .938 .935 .931 .927 .922 26
27 .950 .946 .943 .939 .936 .932 .928 .923 27
28 .950 .947 .944 .940 .936 .933 .929 .924 28
29 .951 .948 .945 .941 .937 .934 .930 .925 29
30 .952 .949 .946 .942 .939 .935 .931 .927 30
31 .953 .950 .947 .943 .940 .936 .932 .928 31
32 .954 .951 .948 .944 .941 .937 .933 .929 32
33 .955 .952 .949 .945 .942 .938 .934 .930 33
34 .956 .953 .950 .947 .943 .939 .935 .931 34
35 .957 .954 .951 .948 .944 .940 .937 .933 35
36 .958 .955 .952 .949 .945 .942 .938 .934 36
37 .960 .957 .953 .950 .947 .943 .939 .935 37
38 .961 .958 .955 .951 .948 .944 .940 .937 38
39 .962 .959 .956 .952 .949 .946 .942 .938 39
</TABLE>
NOTE: Factors for additional age combinations are available from the
Administrator.
-42-
<PAGE> 45
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 RETIREMENT
- ----------- --- --- --- --- --- --- --- --- -----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
40 .980 .979 .977 .975 .973 .970 .968 .966 40
41 .981 .979 .978 .976 .974 .971 .969 .967 41
42 .982 .980 .978 .977 .975 .972 .970 .968 42
43 .983 .981 .979 .977 .975 .973 .971 .969 43
44 .983 .982 .980 .978 .976 .974 .972 .970 44
45 .984 .982 .981 .979 .977 .975 .973 .971 45
46 .985 .983 .982 .980 .978 .976 .974 .972 46
47 .985 .984 .982 .981 .979 .977 .975 .973 47
48 .986 .984 .983 .981 .980 .978 .976 .974 48
49 .986 .985 .984 .982 .981 .979 .977 .975 49
50 .987 .986 .984 .983 .981 .980 .978 .976 50
51 .988 .986 .985 .984 .982 .981 .979 .977 51
52 .988 .987 .986 .984 .983 .981 .980 .978 52
53 .989 .988 .986 .985 .984 .982 .980 .979 53
54 .989 .988 .987 .986 .984 .983 .981 .980 54
55 .990 .989 .988 .986 .985 .984 .982 .980 55
56 .990 .989 .988 .987 .986 .984 .983 .981 56
57 .991 .990 .989 .988 .987 .985 .984 .982 57
58 .991 .990 .989 .988 .987 .986 .985 .983 58
59 .992 .991 .990 .989 .988 .987 .985 .984 59
</TABLE>
<TABLE>
<CAPTION>
SPOUSE'S SPOUSE'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 48 49 50 51 52 53 54 55 RETIREMENT
- ----------- --- --- --- --- --- --- --- --- -----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
40 .963 .960 .957 .954 .950 .947 .943 .939 40
41 .964 .961 .958 .955 .952 .948 .945 .941 41
42 .965 .962 .959 .956 .953 .950 .946 .942 42
43 .966 .963 .961 .958 .954 .951 .947 .944 43
44 .967 .965 .962 .959 .956 .952 .949 .945 44
45 .968 .966 .963 .960 .957 .954 .950 .947 45
46 .969 .967 .964 .961 .958 .955 .952 .948 46
47 .971 .968 .965 .963 .960 .957 .953 .950 47
48 .972 .969 .967 .964 .961 .958 .955 .951 48
49 .973 .970 .968 .965 .962 .959 .956 .953 49
50 .974 .971 .969 .966 .964 .961 .958 .954 50
51 .975 .973 .970 .968 .965 .962 .959 .956 51
52 .976 .974 .971 .969 .966 .963 .961 .957 52
53 .977 .975 .972 .970 .968 .965 .962 .959 53
54 .978 .976 .974 .971 .969 .966 .963 .960 54
55 .979 .977 .975 .972 .970 .968 .965 .962 55
56 .980 .978 .976 .974 .971 .969 .966 .963 56
57 .981 .979 .977 .975 .973 .970 .968 .965 57
58 .981 .980 .978 .976 .974 .971 .969 .966 58
59 .982 .981 .979 .977 .975 .973 .970 .968 59
</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
-------------------
(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 RETIREMENT
- ----------- --- --- --- --- --- --- --- --- ----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
60 .992 .991 .990 .989 .988 .987 .986 .985 60
61 .993 .992 .991 .990 .989 .988 .987 .985 61
62 .993 .992 .991 .991 .990 .988 .987 .986 62
63 .993 .993 .992 .991 .990 .989 .988 .987 63
64 .994 .993 .992 .991 .991 .990 .989 .987 64
65 .994 .993 .993 .992 .991 .990 .989 .988 65
66 .994 .994 .993 .992 .992 .991 .990 .989 66
67 .995 .994 .994 .993 .992 .991 .990 .989 67
68 .995 .994 .994 .993 .993 .992 .991 .990 68
69 .995 .995 .994 .994 .993 .992 .991 .990 69
70 .996 .995 .995 .994 .993 .993 .992 .991 70
71 .996 .995 .995 .994 .994 .993 .992 .991 71
72 .996 .996 .995 .995 .994 .993 .993 .992 72
73 .996 .996 .996 .995 .994 .994 .993 .992 73
74 .997 .996 .996 .995 .995 .994 .994 .993 74
75 .997 .996 .996 .996 .995 .995 .994 .993 75
76 .997 .997 .996 .996 .995 .995 .994 .994 76
77 .997 .997 .997 .996 .996 .995 .995 .994 77
78 .997 .997 .997 .996 .996 .996 .995 .994 78
79 .998 .997 .997 .997 .996 .996 .995 .995 79
</TABLE>
<TABLE>
<CAPTION>
SPOUSE'S SPOUSE'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 48 49 50 51 52 53 54 55 RETIREMENT
- ----------- --- --- --- --- --- --- --- --- ----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
60 .983 .981 .980 .978 .976 .974 .972 .969 60
61 .984 .982 .981 .979 .977 .975 .973 .971 61
62 .985 .983 .982 .980 .978 .976 .974 .972 62
63 .985 .984 .983 .981 .979 .977 .975 .973 63
64 .986 .985 .983 .982 .980 .978 .976 .974 64
65 .987 .986 .984 .983 .981 .979 .978 .976 65
66 .988 .986 .985 .984 .982 .980 .979 .977 66
67 .988 .987 .986 .984 .983 .981 .980 .978 67
68 .989 .988 .987 .985 .984 .982 .981 .979 68
69 .989 .988 .987 .986 .985 .983 .982 .980 69
70 .990 .989 .988 .987 .986 .984 .983 .981 70
71 .991 .990 .989 .987 .986 .985 .984 .982 71
72 .991 .990 .989 .988 .987 .986 .985 .983 72
73 .992 .991 .990 .989 .988 .987 .985 .984 73
74 .992 .991 .990 .989 .988 .987 .986 .985 74
75 .993 .992 .991 .990 .989 .988 .987 .986 75
76 .993 .992 .992 .991 .990 .989 .988 .987 76
77 .993 .993 .992 .991 .990 .989 .988 .987 77
78 .994 .993 .992 .992 .991 .990 .989 .988 78
79 .994 .994 .993 .992 .991 .991 .990 .989 79
</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 RETIREMENT
- ----------- --- --- --- --- --- --- --- --- ----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
80 .998 .997 .997 .997 .997 .996 .996 .995 80
81 .998 .998 .997 .997 .997 .996 .996 .995 81
82 .998 .998 .998 .997 .997 .997 .996 .996 82
83 .998 .998 .998 .997 .997 .997 .996 .996 83
84 .998 .998 .998 .998 .997 .997 .997 .996 84
85 .998 .998 .998 .998 .998 .997 .997 .997 85
86 .999 .998 .998 .998 .998 .997 .997 .997 86
87 .999 .998 .998 .998 .998 .998 .997 .997 87
88 .999 .999 .998 .998 .998 .998 .998 .997 88
89 .999 .999 .999 .998 .998 .998 .998 .997 89
</TABLE>
<TABLE>
<CAPTION>
SPOUSE'S SPOUSE'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 48 49 50 51 52 53 54 55 RETIREMENT
- ----------- --- --- --- --- --- --- --- --- ----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
80 .995 .994 .993 .993 .992 .991 .990 .990 80
81 .995 .994 .994 .993 .993 .992 .991 .990 81
82 .995 .995 .994 .994 .993 .992 .992 .991 82
83 .996 .995 .995 .994 .993 .993 .992 .991 83
84 .996 .995 .995 .994 .994 .993 .993 .992 84
85 .996 .996 .995 .995 .994 .994 .993 .992 85
86 .996 .996 .996 .995 .995 .994 .994 .993 86
87 .997 .996 .996 .995 .995 .995 .994 .993 87
88 .997 .997 .996 .996 .995 .995 .994 .994 88
89 .997 .997 .996 .996 .996 .995 .995 .994 89
</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
-------------------
<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 RETIREMENT
- ----------- --- --- --- --- --- --- --- --- -----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
20 .917 .913 .908 .903 .898 .893 .888 .882 20
21 .918 .913 .909 .904 .899 .894 .888 .883 21
22 .919 .914 .910 .905 .900 .895 .889 .884 22
23 .920 .915 .911 .906 .901 .896 .890 .885 23
24 .921 .916 .912 .907 .902 .897 .891 .886 24
25 .921 .917 .912 .908 .903 .898 .892 .887 25
26 .922 .918 .913 .909 .904 .899 .893 .888 26
27 .923 .919 .914 .910 .905 .900 .894 .889 27
28 .924 .920 .916 .911 .906 .901 .895 .890 28
29 .925 .921 .917 .912 .907 .902 .896 .891 29
30 .927 .922 .918 .913 .908 .903 .898 .892 30
31 .928 .923 .919 .914 .909 .904 .899 .893 31
32 .929 .925 .920 .915 .911 .905 .900 .895 32
33 .930 .926 .921 .917 .912 .907 .901 .896 33
34 .931 .927 .923 .918 .913 .908 .903 .897 34
35 .933 .928 .924 .919 .915 .909 .904 .899 35
36 .934 .930 .925 .921 .916 .911 .906 .900 36
37 .935 .931 .927 .922 .917 .912 .907 .902 37
38 .937 .932 .928 .924 .919 .914 .909 .903 38
39 .938 .934 .930 .925 .920 .915 .910 .905 39
</TABLE>
<TABLE>
<CAPTION>
SPOUSE'S SPOUSE'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 63 64 65 66 67 68 69 70 RETIREMENT
- ----------- --- --- --- --- --- --- --- --- -----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
20 .876 .870 .864 .857 .850 .843 .836 .828 20
21 .877 .871 .865 .858 .851 .844 .837 .829 21
22 .878 .872 .865 .859 .852 .845 .838 .830 22
23 .879 .873 .866 .860 .853 .846 .838 .831 23
24 .880 .874 .867 .861 .854 .847 .839 .832 24
25 .881 .875 .868 .862 .855 .848 .840 .833 25
26 .882 .876 .869 .863 .856 .849 .841 .834 26
27 .883 .887 .870 .864 .857 .850 .842 .835 27
28 .884 .878 .871 .865 .858 .851 .844 .836 28
29 .885 .879 .873 .866 .859 .852 .845 .837 29
30 .886 .880 .874 .867 .860 .853 .846 .838 30
31 .887 .881 .875 .868 .862 .855 .847 .840 31
32 .889 .883 .876 .870 .863 .856 .849 .841 32
33 .890 .884 .878 .871 .864 .857 .850 .842 33
34 .891 .885 .879 .873 .866 .859 .851 .844 34
35 .893 .887 .881 .874 .867 .860 .853 .845 35
36 .894 .888 .882 .876 .869 .862 .854 .847 36
37 .896 .890 .884 .877 .870 .863 .856 .849 37
38 .897 .892 .885 .879 .872 .865 .858 .850 38
39 .899 .893 .887 .880 .874 .867 .859 .852 39
</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 55 56 57 58 59 60 61 62 RETIREMENT
- ----------- --- --- --- --- --- --- --- --- -----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
40 .939 .935 .931 .927 .922 .917 .912 .906 40
41 .941 .937 .933 .928 .924 .919 .914 .908 41
42 .942 .938 .934 .930 .925 .920 .915 .910 42
43 .944 .940 .936 .931 .927 .922 .917 .912 43
44 .945 .941 .937 .933 .929 .924 .919 .914 44
45 .947 .943 .939 .935 .930 .926 .921 .915 45
46 .948 .944 .941 .936 .932 .927 .922 .917 46
47 .950 .946 .942 .938 .934 .929 .924 .919 47
48 .951 .948 .944 .940 .936 .931 .926 .921 48
49 .953 .949 .946 .942 .937 .933 .928 .923 49
50 .954 .951 .947 .943 .939 .935 .930 .925 50
51 .956 .953 .949 .945 .941 .937 .932 .927 51
52 .957 .954 .951 .947 .943 .939 .934 .929 52
53 .959 .956 .952 .949 .945 .941 .936 .932 53
54 .960 .957 .954 .950 .947 .943 .938 .934 54
55 .962 .959 .956 .952 .948 .945 .940 .936 55
56 .963 .960 .957 .954 .950 .946 .942 .938 56
57 .965 .962 .959 .956 .952 .948 .944 .940 57
58 .966 .964 .961 .957 .954 .950 .946 .942 58
59 .968 .965 .962 .959 .956 .952 .948 .944 59
</TABLE>
<TABLE>
<CAPTION>
SPOUSE'S SPOUSE'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 63 64 65 66 67 68 69 70 RETIREMENT
- ----------- --- --- --- --- --- --- --- --- -----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
40 .901 .895 .889 .882 .875 .868 .861 .854 40
41 .903 .897 .890 .884 .877 .870 .863 .856 41
42 .904 .898 .892 .886 .879 .872 .865 .858 42
43 .906 .900 .894 .888 .881 .874 .867 .860 43
44 .908 .902 .896 .890 .883 .876 .869 .862 44
45 .910 .904 .898 .892 .885 .878 .871 .864 45
46 .912 .906 .900 .894 .887 .880 .873 .866 46
47 .914 .908 .902 .896 .889 .883 .876 .868 47
48 .916 .910 .904 .898 .892 .885 .878 .871 48
49 .918 .912 .907 .900 .894 .887 .880 .873 49
50 .920 .915 .909 .903 .896 .890 .883 .875 50
51 .922 .917 .911 .905 .899 .892 .885 .878 51
52 .924 .919 .913 .907 .901 .895 .888 .880 52
53 .927 .921 .916 .910 .904 .897 .890 .883 53
54 .929 .924 .918 .912 .906 .900 .893 .886 54
55 .931 .926 .920 .915 .909 .902 .896 .889 55
56 .933 .928 .923 .917 .911 .905 .898 .891 56
57 .935 .931 .925 .920 .914 .908 .901 .894 57
58 .938 .933 .928 .922 .917 .910 .904 .897 58
59 .940 .935 .930 .925 .919 .913 .907 .900 59
</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
-------------------
(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 RETIREMENT
- ------------ -- --- --- --- --- --- --- --- ------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
60 .969 .967 .964 .961 .958 .954 .950 .946 60
61 .971 .968 .965 .962 .959 .956 .952 .949 61
62 .972 .969 .967 .964 .961 .958 .954 .951 62
63 .973 .971 .968 .966 .963 .960 .956 .953 63
64 .974 .972 .970 .967 .965 .962 .958 .955 64
65 .976 .974 .971 .969 .966 .963 .960 .957 65
66 .977 .975 .973 .970 .968 .965 .962 .959 66
67 .978 .976 .974 .972 .969 .967 .964 .961 67
68 .979 .977 .975 .973 .971 .968 .966 .963 68
69 .980 .978 .977 .975 .972 .970 .967 .964 69
70 .981 .980 .978 .976 .974 .971 .969 .966 70
71 .982 .981 .979 .977 .975 .973 .971 .968 71
72 .983 .982 .980 .978 .976 .974 .972 .970 72
73 .984 .983 .981 .979 .978 .976 .974 .971 73
74 .985 .984 .982 .981 .979 .977 .975 .973 74
75 .986 .985 .983 .982 .980 .978 .976 .974 75
76 .987 .985 .984 .983 .981 .980 .978 .976 76
77 .987 .986 .985 .984 .982 .981 .979 .977 77
78 .988 .987 .986 .985 .983 .982 .980 .978 78
79 .989 .988 .987 .986 .984 .983 .981 .980 79
</TABLE>
<TABLE>
<CAPTION>
SPOUSE'S SPOUSE'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 63 64 65 66 67 68 69 70 RETIREMENT
- ------------ --- --- --- --- --- --- --- --- ------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
60 .942 .938 .933 .927 .922 .916 .910 .903 60
61 .944 .940 .935 .930 .925 .919 .913 .906 61
62 .947 .942 .938 .933 .927 .922 .916 .909 62
63 .949 .945 .940 .935 .930 .924 .919 .912 63
64 .951 .947 .942 .938 .933 .927 .922 .916 64
65 .953 .949 .945 .940 .935 .930 .925 .919 65
66 .955 .951 .947 .943 .938 .933 .928 .922 66
67 .957 .954 .950 .945 .941 .936 .930 .925 67
68 .959 .956 .952 .948 .943 .939 .933 .928 68
69 .961 .958 .954 .950 .946 .941 .936 .931 69
70 .963 .960 .956 .953 .948 .944 .939 .934 70
71 .965 .962 .959 .955 .951 .947 .942 .937 71
72 .967 .964 .961 .957 .953 .949 .945 .940 72
73 .969 .966 .963 .959 .956 .952 .947 .943 73
74 .970 .968 .965 .961 .958 .954 .950 .946 74
75 .972 .969 .967 .963 .960 .956 .953 .948 75
76 .973 .971 .968 .965 .962 .959 .955 .951 76
77 .975 .973 .970 .967 .964 .961 .957 .954 77
78 .976 .974 .972 .969 .966 .963 .960 .956 78
79 .978 .976 .974 .971 .968 .965 .962 .959 79
</TABLE>
NOTE: Factors for additional age combinations are available 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 RETIREMENT
- ----------- --- --- --- --- --- --- --- --- -----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
80 .990 .989 .988 .986 .985 .984 .983 .981 80
81 .990 .989 .988 .987 .986 .985 .984 .982 81
82 .991 .990 .989 .988 .987 .986 .985 .983 82
83 .991 .991 .990 .989 .988 .987 .986 .984 83
84 .992 .991 .990 .990 .989 .988 .987 .985 84
85 .992 .992 .991 .990 .989 .988 .987 .986 85
86 .993 .992 .992 .991 .990 .989 .988 .987 86
87 .993 .993 .992 .992 .991 .990 .989 .988 87
88 .994 .993 .993 .992 .991 .991 .990 .989 88
89 .994 .994 .993 .993 .992 .991 .991 .990 89
</TABLE>
<TABLE>
<CAPTION>
SPOUSE'S SPOUSE'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 63 64 65 66 67 68 69 70 RETIREMENT
- ----------- --- --- --- --- --- --- --- --- -----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
80 .979 .977 .975 .973 .970 .967 .964 .961 80
81 .980 .979 .977 .974 .972 .969 .966 .963 81
82 .982 .980 .978 .976 .974 .971 .968 .965 82
83 .983 .981 .979 .978 .975 .973 .970 .968 83
84 .984 .982 .981 .979 .977 .975 .972 .970 84
85 .985 .984 .982 .980 .978 .976 .974 .972 85
86 .986 .985 .983 .982 .980 .978 .976 .973 86
87 .987 .986 .984 .983 .981 .979 .977 .975 87
88 .988 .987 .985 .984 .983 .981 .979 .977 88
89 .989 .988 .987 .985 .984 .982 .980 .978 89
</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
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 RETIREMENT
- ----------- --- --- --- --- --- --- --- --- -----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
20 .904 .898 .892 .885 .879 .872 .864 .856 20
21 .906 .900 .894 .887 .880 .873 .866 .858 21
22 .908 .902 .896 .889 .882 .875 .868 .860 22
23 .909 .904 .897 .891 .884 .877 .870 .862 23
24 .911 .905 .899 .893 .886 .879 .872 .864 24
25 .913 .907 .901 .895 .888 .881 .874 .866 25
26 .915 .909 .903 .897 .890 .883 .876 .868 26
27 .917 .911 .905 .899 .892 .885 .878 .870 27
28 .919 .913 .907 .901 .894 .887 .880 .872 28
29 .921 .915 .909 .903 .896 .889 .882 .875 29
30 .923 .917 .911 .905 .899 .892 .885 .877 30
31 .925 .919 .913 .907 .901 .894 .887 .880 31
32 .927 .921 .916 .909 .903 .896 .889 .882 32
33 .929 .923 .918 .912 .905 .899 .892 .884 33
34 .931 .926 .920 .914 .908 .901 .894 .887 34
35 .933 .928 .922 .916 .910 .904 .897 .890 35
36 .935 .930 .924 .919 .913 .906 .899 .892 36
37 .937 .932 .927 .921 .915 .909 .902 .895 37
38 .939 .934 .929 .923 .917 .911 .905 .898 38
39 .941 .936 .931 .926 .920 .914 .907 .900 39
</TABLE>
<TABLE>
<CAPTION>
SPOUSE'S SPOUSE'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 48 49 50 51 52 53 54 55 RETIREMENT
- ----------- --- --- --- --- --- --- --- --- -----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
20 .849 .840 .832 .823 .815 .805 .796 .787 20
21 .850 .842 .834 .825 .816 .807 .798 .788 21
22 .852 .844 .836 .827 .818 .809 .800 .790 22
23 .854 .846 .838 .829 .820 .811 .802 .792 23
24 .856 .848 .840 .831 .822 .813 .804 .794 24
25 .858 .850 .842 .833 .824 .815 .806 .796 25
26 .860 .852 .844 .835 .826 .817 .808 .798 26
27 .862 .854 .846 .837 .829 .820 .810 .801 27
28 .865 .857 .848 .840 .831 .822 .813 .803 28
29 .867 .859 .851 .842 .833 .824 .815 .805 29
30 .869 .861 .853 .845 .836 .827 .817 .808 30
31 .872 .864 .856 .847 .838 .829 .820 .811 31
32 .874 .866 .858 .850 .841 .832 .823 .813 32
33 .877 .869 .861 .852 .844 .835 .825 .816 33
34 .879 .872 .864 .855 .846 .838 .828 .819 34
35 .882 .874 .866 .858 .849 .840 .831 .822 35
36 .885 .877 .869 .861 .852 .843 .834 .825 36
37 .888 .880 .872 .864 .855 .846 .837 .828 37
38 .890 .883 .875 .867 .858 .850 .840 .831 38
39 .893 .886 .878 .870 .861 .853 .844 .834 39
</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
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 RETIREMENT
- ----------- --- --- --- --- --- --- --- --- -----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
40 .943 .939 .934 .928 .922 .916 .910 .903 40
41 .945 .941 .936 .930 .925 .919 .913 .906 41
42 .947 .943 .938 .933 .927 .921 .915 .909 42
43 .949 .945 .940 .935 .930 .924 .918 .912 43
44 .951 .947 .942 .937 .932 .927 .921 .914 44
45 .953 .949 .945 .940 .935 .929 .923 .917 45
46 .955 .951 .947 .942 .937 .932 .926 .920 46
47 .957 .953 .949 .944 .939 .934 .929 .923 47
48 .959 .955 .951 .946 .942 .937 .931 .925 48
49 .960 .957 .953 .949 .944 .939 .934 .928 49
50 .962 .959 .955 .951 .946 .941 .936 .931 50
51 .964 .960 .957 .953 .948 .944 .939 .934 51
52 .965 .962 .959 .955 .951 .946 .941 .936 52
53 .967 .964 .960 .957 .953 .948 .944 .939 53
54 .969 .966 .962 .959 .955 .951 .946 .941 54
55 .970 .967 .964 .960 .957 .953 .948 .944 55
56 .971 .969 .966 .962 .959 .955 .951 .946 56
57 .973 .970 .967 .964 .961 .957 .953 .948 57
58 .974 .972 .969 .966 .962 .959 .955 .951 58
59 .975 .973 .970 .967 .964 .961 .957 .953 59
</TABLE>
<TABLE>
<CAPTION>
SPOUSE'S SPOUSE'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 48 49 50 51 52 53 54 55 RETIREMENT
- ----------- --- --- --- --- --- --- --- --- ----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
40 .896 .889 .881 .873 .865 .856 .847 .838 40
41 .899 .892 .884 .876 .868 .859 .850 .841 41
42 .902 .895 .887 .879 .871 .863 .854 .845 42
43 .905 .898 .890 .883 .874 .866 .857 .848 43
44 .908 .901 .893 .886 .878 .869 .861 .852 44
45 .911 .904 .897 .889 .881 .873 .864 .856 45
46 .914 .907 .900 .892 .885 .876 .868 .859 46
47 .916 .910 .903 .896 .888 .880 .872 .863 47
48 .919 .913 .906 .899 .891 .884 .875 .867 48
49 .922 .916 .909 .902 .895 .887 .879 .871 49
50 .925 .919 .912 .906 .898 .891 .883 .875 50
51 .928 .922 .916 .909 .902 .894 .887 .878 51
52 .931 .925 .919 .912 .905 .898 .890 .882 52
53 .933 .928 .922 .915 .909 .902 .894 .886 53
54 .936 .931 .925 .918 .912 .905 .898 .890 54
55 .939 .933 .928 .922 .915 .909 .901 .894 55
56 .941 .936 .931 .925 .919 .912 .905 .898 56
57 .944 .939 .933 .928 .922 .915 .909 .902 57
58 .946 .941 .936 .931 .925 .919 .912 .905 58
59 .949 .944 .939 .934 .928 .922 .916 .909 59
</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
--------------------
(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 RETIREMENT
- ----------- --- --- --- --- --- --- --- --- -----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
60 .977 .974 .972 .969 .966 .963 .959 .955 60
61 .978 .976 .973 .971 .968 .964 .961 .957 61
62 .979 .977 .975 .972 .969 .966 .963 .959 62
63 .980 .978 .976 .974 .971 .968 .965 .961 63
64 .981 .979 .977 .975 .972 .970 .967 .963 64
65 .982 .981 .978 .976 .974 .971 .968 .965 65
66 .983 .982 .980 .978 .975 .973 .970 .967 66
67 .984 .983 .981 .979 .977 .974 .971 .969 67
68 .985 .984 .982 .980 .978 .976 .973 .970 68
69 .986 .985 .983 .981 .979 .977 .974 .972 69
70 .987 .985 .984 .982 .980 .978 .976 .973 70
71 .988 .986 .985 .983 .981 .979 .977 .975 71
72 .988 .987 .986 .984 .983 .981 .979 .976 72
73 .989 .988 .987 .985 .984 .982 .980 .978 73
74 .990 .989 .987 .986 .985 .983 .981 .979 74
75 .990 .989 .988 .987 .986 .984 .982 .980 75
76 .991 .990 .989 .988 .986 .985 .983 .981 76
77 .992 .991 .990 .989 .987 .986 .984 .983 77
78 .992 .991 .990 .989 .988 .987 .985 .984 78
79 .993 .992 .991 .990 .989 .988 .986 .985 79
</TABLE>
<TABLE>
<CAPTION>
SPOUSE'S SPOUSE'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 48 49 50 51 52 53 54 55 RETIREMENT
- ----------- --- --- --- --- --- --- --- --- -----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
60 .951 .946 .942 .937 .931 .925 .919 .913 60
61 .953 .949 .944 .939 .934 .929 .923 .917 61
62 .955 .951 .947 .942 .937 .932 .926 .920 62
63 .958 .954 .949 .945 .940 .935 .929 .924 63
64 .960 .956 .952 .947 .943 .938 .933 .927 64
65 .962 .958 .954 .950 .945 .941 .936 .930 65
66 .964 .960 .956 .952 .948 .944 .939 .934 66
67 .965 .962 .959 .955 .951 .946 .942 .937 67
68 .967 .964 .961 .957 .953 .949 .945 .940 68
69 .969 .966 .963 .959 .955 .952 .947 .943 69
70 .971 .968 .965 .961 .958 .954 .950 .946 70
71 .972 .970 .967 .963 .960 .956 .953 .948 71
72 .974 .971 .968 .965 .962 .959 .955 .951 72
73 .975 .973 .970 .967 .964 .961 .957 .954 73
74 .977 .974 .972 .969 .966 .963 .960 .956 74
75 .978 .976 .973 .971 .968 .965 .962 .959 75
76 .979 .977 .975 .972 .970 .967 .964 .961 76
77 .981 .979 .976 .974 .972 .969 .966 .963 77
78 .982 .980 .978 .976 .973 .971 .968 .965 78
79 .983 .981 .979 .977 .975 .972 .970 .967 79
</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 RETIREMENT
- ----------- --- --- --- --- --- --- --- --- -----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
80 .993 .992 .992 .991 .990 .988 .987 .986 80
81 .994 .993 .992 .991 .990 .989 .988 .987 81
82 .994 .993 .993 .992 .991 .990 .989 .987 82
83 .995 .994 .993 .992 .992 .991 .990 .988 83
84 .995 .994 .994 .993 .992 .991 .990 .989 84
85 .995 .995 .994 .994 .993 .992 .991 .990 85
86 .996 .995 .995 .994 .993 .992 .992 .991 86
87 .996 .995 .995 .994 .994 .993 .992 .991 87
88 .996 .996 .995 .995 .994 .994 .993 .992 88
89 .996 .996 .996 .995 .995 .994 .993 .993 89
</TABLE>
<TABLE>
<CAPTION>
SPOUSE'S SPOUSE'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 48 49 50 51 52 53 54 55 RETIREMENT
- ----------- --- --- --- --- --- --- --- --- -----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
80 .984 .982 .980 .978 .976 .974 .972 .969 80
81 .985 .983 .982 .980 .978 .976 .973 .971 81
82 .986 .985 .983 .981 .979 .977 .975 .973 82
83 .987 .986 .984 .982 .981 .979 .977 .975 83
84 .988 .986 .985 .983 .982 .980 .978 .976 84
85 .989 .987 .986 .985 .983 .981 .980 .978 85
86 .989 .988 .987 .986 .984 .983 .981 .979 86
87 .990 .989 .988 .987 .985 .984 .982 .981 87
88 .991 .990 .989 .988 .986 .985 .983 .982 88
89 .992 .991 .990 .988 .987 .986 .985 .983 89
</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
--------------------
<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 RETIREMENT
- ----------- --- --- --- --- --- --- --- --- -----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
20 .787 .777 .767 .757 .746 .736 .725 .714 20
21 .788 .779 .769 .759 .748 .737 .726 .715 21
22 .790 .781 .771 .760 .750 .739 .728 .717 22
23 .792 .782 .772 .762 .752 .741 .730 .719 23
24 .794 .784 .774 .764 .754 .743 .732 .721 24
25 .796 .787 .776 .766 .756 .745 .734 .723 25
26 .798 .789 .779 .768 .758 .747 .736 .725 26
27 .801 .791 .781 .771 .760 .749 .738 .727 27
28 .803 .793 .783 .773 .762 .751 .740 .729 28
29 .805 .796 .786 .775 .765 .754 .743 .731 29
30 .808 .798 .788 .778 .767 .756 .745 .734 30
31 .811 .801 .791 .780 .770 .759 .748 .736 31
32 .813 .803 .793 .783 .772 .761 .750 .739 32
33 .816 .806 .796 .786 .775 .764 .753 .741 33
34 .819 .809 .799 .789 .778 .767 .756 .744 34
35 .822 .812 .802 .792 .781 .770 .759 .747 35
36 .825 .815 .805 .795 .784 .773 .762 .750 36
37 .828 .818 .808 .798 .787 .776 .765 .753 37
38 .831 .821 .811 .801 .791 .780 .768 .757 38
39 .834 .825 .815 .805 .794 .783 .772 .760 39
</TABLE>
<TABLE>
<CAPTION>
SPOUSE'S SPOUSE'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 63 64 65 66 67 68 69 70 RETIREMENT
- ----------- --- --- --- --- --- --- --- --- -----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
20 .702 .691 .679 .667 .654 .642 .629 .617 20
21 .704 .692 .680 .668 .656 .643 .631 .618 21
22 .705 .694 .682 .670 .657 .645 .632 .620 22
23 .707 .695 .683 .671 .659 .646 .634 .621 23
24 .709 .697 .685 .673 .661 .648 .635 .623 24
25 .711 .699 .687 .675 .662 .650 .637 .624 25
26 .713 .701 .689 .677 .664 .652 .639 .626 26
27 .715 .703 .691 .679 .666 .653 .641 .628 27
28 .717 .705 .693 .681 .668 .655 .643 .630 28
29 .719 .708 .695 .683 .670 .658 .645 .632 29
30 .722 .710 .698 .685 .673 .660 .647 .634 30
31 .724 .712 .700 .688 .675 .662 .649 .636 31
32 .727 .715 .703 .690 .677 .664 .651 .638 32
33 .730 .718 .705 .693 .680 .667 .654 .641 33
34 .732 .720 .708 .695 .682 .669 .656 .643 34
35 .735 .723 .711 .698 .685 .672 .659 .646 35
36 .738 .726 .714 .701 .688 .675 .662 .648 36
37 .742 .729 .717 .704 .691 .678 .665 .651 37
38 .745 .733 .720 .707 .694 .681 .668 .654 38
39 .748 .736 .723 .711 .698 .684 .671 .657 39
</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 55 56 57 58 59 60 61 62 RETIREMENT
- ----------- --- --- --- --- --- --- --- --- ----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
40 .838 .828 .818 .808 .797 .787 .775 .764 40
41 .841 .832 .822 .812 .801 .790 .779 .767 41
42 .845 .835 .825 .815 .805 .794 .783 .771 42
43 .848 .839 .829 .819 .808 .798 .786 .775 43
44 .852 .843 .833 .823 .812 .802 .790 .779 44
45 .856 .846 .837 .827 .816 .806 .794 .783 45
46 .859 .850 .841 .831 .820 .810 .799 .787 46
47 .863 .854 .845 .835 .825 .814 .803 .791 47
48 .867 .858 .849 .839 .829 .818 .807 .796 48
49 .871 .862 .853 .843 .833 .823 .812 .800 49
50 .875 .866 .857 .847 .837 .827 .816 .805 50
51 .878 .870 .861 .852 .842 .832 .821 .810 51
52 .882 .874 .865 .856 .846 .836 .825 .814 52
53 .886 .878 .869 .860 .851 .841 .830 .819 53
54 .890 .882 .874 .865 .855 .845 .835 .824 54
55 .894 .886 .878 .869 .860 .850 .840 .829 55
56 .898 .890 .882 .873 .864 .855 .845 .834 56
57 .902 .894 .886 .878 .869 .860 .850 .839 57
58 .905 .898 .890 .882 .874 .864 .855 .845 58
59 .909 .902 .895 .887 .878 .869 .860 .850 59
</TABLE>
<TABLE>
<CAPTION>
SPOUSE'S SPOUSE'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 63 64 65 66 67 68 69 70 RETIREMENT
- ----------- --- --- --- --- --- --- --- --- ----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
40 .752 .739 .727 .714 .701 .688 .674 .661 40
41 .755 .743 .730 .718 .704 .691 .678 .664 41
42 .759 .747 .734 .721 .708 .695 .681 .667 42
43 .763 .751 .738 .725 .712 .698 .685 .671 43
44 .767 .755 .742 .729 .716 .702 .689 .675 44
45 .771 .759 .746 .733 .720 .706 .693 .679 45
46 .775 .763 .750 .737 .724 .711 .697 .683 46
47 .780 .767 .755 .742 .728 .715 .701 .687 47
48 .784 .772 .759 .746 .733 .719 .705 .691 48
49 .789 .776 .764 .751 .738 .724 .710 .696 49
50 .793 .781 .769 .756 .742 .729 .715 .701 50
51 .798 .786 .773 .761 .747 .734 .720 .706 51
52 .803 .791 .778 .766 .752 .739 .725 .711 52
53 .808 .796 .784 .771 .757 .744 .730 .716 53
54 .813 .801 .789 .776 .763 .749 .735 .721 54
55 .818 .806 .794 .781 .768 .755 .741 .727 55
56 .823 .812 .799 .787 .774 .760 .747 .732 56
57 .828 .817 .805 .793 .780 .766 .752 .738 57
58 .834 .822 .811 .798 .785 .772 .758 .744 58
59 .839 .828 .816 .804 .791 .778 .764 .750 59
</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
--------------------
(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 RETIREMENT
- ----------- --- --- --- --- --- --- --- --- -----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
60 .913 .906 .899 .891 .883 .874 .865 .855 60
61 .917 .910 .903 .895 .887 .879 .870 .860 61
62 .920 .914 .907 .900 .892 .884 .875 .865 62
63 .924 .917 .911 .904 .896 .888 .880 .870 63
64 .927 .921 .915 .908 .901 .893 .884 .876 64
65 .930 .925 .918 .912 .905 .897 .889 .881 65
66 .934 .928 .922 .916 .909 .902 .894 .886 66
67 .937 .931 .926 .920 .913 .906 .899 .891 67
68 .940 .935 .929 .924 .917 .911 .903 .895 68
69 .943 .938 .933 .927 .921 .915 .908 .900 69
70 .946 .941 .936 .931 .925 .919 .912 .905 70
71 .948 .944 .939 .934 .929 .923 .916 .909 71
72 .951 .947 .942 .938 .932 .927 .921 .914 72
73 .954 .950 .945 .941 .936 .931 .925 .918 73
74 .956 .952 .948 .944 .939 .934 .929 .922 74
75 .959 .955 .951 .947 .943 .938 .932 .927 75
76 .961 .958 .954 .950 .946 .941 .936 .931 76
77 .963 .960 .957 .953 .949 .944 .940 .934 77
78 .965 .962 .959 .955 .952 .948 .943 .938 78
79 .967 .964 .961 .958 .954 .951 .946 .942 79
</TABLE>
<TABLE>
<CAPTION>
SPOUSE'S SPOUSE'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 63 64 65 66 67 68 69 70 RETIREMENT
- ----------- --- --- --- --- --- --- --- --- -----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
60 .844 .834 .822 .810 .797 .784 .771 .757 60
61 .850 .839 .828 .816 .803 .790 .777 .763 61
62 .855 .845 .834 .822 .810 .797 .784 .770 62
63 .861 .850 .839 .828 .816 .803 .790 .776 63
64 .866 .856 .845 .834 .822 .810 .797 .783 64
65 .871 .862 .851 .840 .828 .816 .803 .790 65
66 .877 .867 .857 .846 .835 .823 .810 .797 66
67 .882 .873 .863 .852 .841 .829 .817 .804 67
68 .887 .878 .868 .858 .847 .836 .824 .811 68
69 .892 .883 .874 .864 .854 .842 .830 .818 69
70 .897 .889 .880 .870 .860 .849 .837 .825 70
71 .902 .894 .885 .876 .866 .855 .844 .832 71
72 .907 .899 .890 .881 .872 .861 .851 .839 72
73 .911 .904 .896 .887 .878 .868 .857 .846 73
74 .916 .909 .901 .893 .884 .874 .864 .853 74
75 .920 .913 .906 .898 .889 .880 .870 .859 75
76 .924 .918 .911 .903 .895 .886 .876 .866 76
77 .929 .922 .916 .908 .900 .892 .882 .873 77
78 .933 .927 .920 .913 .906 .897 .888 .879 78
79 .936 .931 .925 .918 .911 .903 .894 .885 79
</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 RETIREMENT
- ----------- --- --- --- --- --- --- --- --- -----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
80 .969 .967 .964 .961 .957 .953 .949 .945 80
81 .971 .969 .966 .963 .960 .956 .952 .948 81
82 .973 .970 .968 .965 .962 .959 .955 .951 82
83 .975 .972 .970 .967 .965 .961 .958 .954 83
84 .976 .974 .972 .969 .967 .964 .961 .957 84
85 .978 .976 .974 .971 .969 .966 .963 .960 85
86 .979 .977 .975 .973 .971 .968 .966 .963 86
87 .981 .979 .977 .975 .973 .971 .968 .965 87
88 .982 .980 .979 .977 .975 .973 .970 .967 88
89 .983 .982 .980 .978 .976 .974 .972 .970 89
</TABLE>
<TABLE>
<CAPTION>
SPOUSE'S SPOUSE'S
AGE AT PENSIONER WHOSE RETIREMENT AGE IS: AGE AT
PENSIONER'S PENSIONER'S
RETIREMENT 63 64 65 66 67 68 69 70 RETIREMENT
- ----------- --- --- --- --- --- --- --- --- -----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
80 .940 .935 .929 .923 .916 .908 .900 .891 80
81 .944 .939 .933 .927 .920 .913 .906 .897 81
82 .947 .942 .937 .931 .925 .918 .911 .903 82
83 .950 .946 .941 .936 .930 .923 .916 .909 83
84 .953 .949 .945 .939 .934 .928 .921 .914 84
85 .956 .952 .948 .943 .938 .932 .926 .919 85
86 .959 .956 .951 .947 .942 .937 .931 .924 86
87 .962 .958 .955 .950 .946 .941 .935 .929 87
88 .965 .961 .958 .954 .949 .945 .939 .934 88
89 .967 .964 .961 .957 .953 .948 .943 .938 89
</TABLE>
NOTE: Factors for additional age combinations are available from the
Administrator.
-57-
<PAGE> 60
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:
-58-
<PAGE> 61
(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.
-59-
<PAGE> 62
SPECIAL PROVISION H
MAXIMUM PENSION
Anything herein contained to the contrary notwithstanding, in no event
shall any PENSION payable under this PLAN exceed the lesser of (i) $90,000 per
year or (ii) 100 percent of the PARTICIPANT's average compensation (as defined
in Section 415 of the Internal Revenue Code) for PARTICIPANT's three highest
consecutive years. Items (i) and (ii) above are subject to adjustment for
increases in the cost of living in accordance with regulations issued by the
Secretary of the Treasury under Section 415 of the Internal Revenue Code. If a
PARTICIPANT in this PLAN also participates in the COMPANY's Savings Fund Plan,
Section 415 of the Code imposes a combined benefit limitation. If the combined
maximum benefit permitted would be exceeded, the PENSION will be reduced, so
that the limitation will be met.
In addition to other limitations set forth in the PLAN and
notwithstanding any other provisions of the PLAN, the accrued benefit,
including the right to any optional benefit provided in the PLAN (and all other
defined benefit plans required to be aggregated with this PLAN under the
provisions of section 415 of the Internal Revenue Code of 1954) shall not
increase to an amount in excess of the amount permitted under Section 415 of
the Internal Revenue Code of 1954 as amended by the Tax Equity and Fiscal
Responsibility Act of 1982.
In the event that this PLAN should become "top heavy" as that term is
defined in Section 416 of the Code, the provisions of Special Provision J shall
supersede any conflicting provisions of the PLAN.
SPECIAL PROVISION I
If SERVICE terminates with at least ten years of SERVICE, 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:
<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>
-60-
<PAGE> 63
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.
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)
divided by 12 Months
($9,000 x .0871 divided by 12 Months = $65.33)
-61-
<PAGE> 64
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).
(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.
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
-62-
<PAGE> 65
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 Compensation
Annual compensation taken into account under this Section and Section 22
for purposes of computing benefits under this PLAN shall not exceed the first
$200,000, provided that such limit shall be adjusted automatically for each
PLAN YEAR to the amount prescribed by the Secretary of the Treasury or his
delegate pursuant to regulations for the calendar year in which such PLAN YEAR
commences.
(e) 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
-63-
<PAGE> 66
there are no EMPLOYER contributions, forfeitures or voluntary
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".
(f) 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.
(g) 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
-64-
<PAGE> 67
group. Such plan or plans may be added to the permissive
aggregation 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.
(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 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.
(h) 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:
-65-
<PAGE> 68
(1) An officer of the EMPLOYER (as defined in subsection (j)). 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 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 Internal Revenue Code of
1954, as amended) 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.
(i) Non-Key Employee
The term "non-key employee" means any employee (and any beneficiary of an
employee) who is not a key employee.
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(j) Employer
The term "employer" means EMPLOYER as defined in Section 22 of this PLAN.
(k) 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.
(l) 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 calcu-
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lating 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.
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).
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V. VRI Retirement Dates
At such time as an employee elects to participate in the VRI, he
shall select a VRI Retirement Date. For purposes of this Special
Provision K, a VRI Retirement Date shall mean one of the following:
A. For Eligible Employees other than Eligible Employees employed by
Pacific Gas Transmission Company:
1. February 1, 1987, provided, however, that eligible
participants have completed all necessary VRI enrollment
procedures prior to January 15, 1987;
2. March 1, 1987;
3. April 1, 1987; or
4. The first of any month during the period commencing with March
1, 1987, and ending with and including October 1, 1987. This
Subsection V.A.4. shall only apply in the event that the
COMPANY or the Participating Employer, as the case may be, has
a demonstrated business need which requires the retention of
the Eligible Employee. Should the business needs of the
COMPANY or of a Participating Employer require the retention
of an Eligible Employee beyond October 1, 1987, the VRI
Retirement Date shall be the first of any month during the
period subsequent to October 1, 1987, and ending with and
including July 1, 1988. The selection of any such VRI
Retirement Date subsequent to October 1, 1987, shall be made
by the COMPANY, or Participating Employer, through an
appropriate member of the COMPANY's Management Committee.
B. For Eligible Employees employed by Pacific Gas Transmission Company:
1. October 1, 1987, provided, however, that eligible participants
have completed all necessary VRI enrollment procedures prior
to September 15, 1987;
2. November 1, 1987; or
3. The first of any month during the period commencing with
December 1, 1987, and ending with and including June 1, 1988.
This Subsection V.B.3. shall only apply in the event that
Pacific Gas Transmission Company has a demonstrated need which
requires the retention of the Eligible Employee.
The VRI Retirement Date selected shall also be the date as of
which an Eligible Employee ceases to be an employee of the COMPANY
or a Participating Employer, as the case may be.
VI. Revocation of Election
An Eligible Employee who has elected to participate in the VRI may
revoke his election, provided, however, that any such revocation shall
only be effective if received by the COMPANY on or before January 30,
1987, for those Eligible Employees who elected a VRI Retirement Date of
February 1, 1987; February 15, 1987, for those Eligible Employees who
elected a VRI Retirement Date of March 1, 1987, or later; September 30,
1987, for those Eligible Employees of Pacific Gas Transmission Company
who elected a VRI Retirement Date of October 1, 1987; or October 15,
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<PAGE> 72
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.
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
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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
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 subse-
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quent to June 1, 1993, can be made only with the written approval of
both of the Company's Executive Vice Presidents.
The VRI Retirement Date selected shall also be the date as of which
an Eligible Employee ceases to be an employee of the COMPANY.
VI. Revocation of Election
An Eligible Employee who has elected to participate in the VRI may
revoke his election, provided, however, that any such revocation shall
only be effective if received by the COMPANY on or before April 23, 1993,
for those Eligible Employees who elected a VRI Retirement Date of May 1,
1993; or April 30, 1993, for those Eligible Employees who elected a VRI
Retirement Date of June 1, 1993, or later.
VII. Definitions
A. Basic VRI Benefit: The benefit calculated under Section IV of this
Special Provision M.
B. Eligible Employee: An employee of the COMPANY who has met the
eligibility criteria as set forth in Section II. For purposes of
this Special Provision M only, Eligible Employee shall not include
any COMPANY Officer.
C. Targeted Organization: Distribution Business Unit; Engineering and
Construction Business Unit; Gas Supply Business Unit except the Gas
Dispatch Department and except employees with job levels of 32 and
above; Nuclear Operations Support Department; Nuclear Safety and
Regulatory Affairs Department; Nuclear Engineering and Construction
Services Department; Nuclear Business and Financial Management
Department; Nuclear Documentation and Support Department; Quality
Assurance Department; human resources departments, including
business unit human resources organizations being consolidated with
corporate human resources; computer and telecommunication services
departments, including business unit and corporate services
organizations being consolidated with corporate computer and
telecommunication services departments; Corporate Communications
departments, including business unit media and employee
communications units being consolidated with Corporate
Communications departments; community and governmental relations
departments including regional public affairs units being
consolidated with corporate governmental relations departments; and
the Economics and Forecasting Department.
D. VRI: The COMPANY's Voluntary Retirement Incentive program as set
forth in this Special Provision M.
E. VRI Retirement Date: The date selected by an Eligible Employee
under Section V of this Special Provision M.
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Exhibit 10.13
PACIFIC GAS AND ELECTRIC COMPANY
STOCK OPTION PLAN
(As adopted effective as of January 1, 1992
pursuant to the 1992 Long-Term Incentive Program
and amended on September 16, 1992)
1. Purpose of the Plan
This is the controlling and definitive statement of the Pacific Gas
and Electric Company Stock Option Plan (hereinafter called the PLAN1/). The
purpose of the PLAN is to advance the interests of the COMPANY by providing
ELIGIBLE PARTICIPANTS with financial incentives to promote the success of its
long-term (five to ten years) business objectives, and to increase their
proprietary interest in the success of the COMPANY. It is the intent of the
COMPANY to reward those ELIGIBLE PARTICIPANTS who have a significant impact on
improved long-term corporate achievements. Inasmuch as the PLAN is designed to
encourage financial performance and to improve the value of shareholders'
investment in PG&E, the costs of the PLAN will be funded from corporate
earnings.
2. Plan Administration
The PLAN shall be administered by the COMMITTEE, which shall be
constituted in such a manner as to comply with the rules governing a plan
intended to qualify as a discretionary plan under RULE 16b-3.
Subject to the provisions of the PLAN, the COMMITTEE shall have full
and final authority, in its sole discretion:
(a) to determine the ELIGIBLE PARTICIPANTS to whom OPTIONS shall
be granted and the number of shares of COMMON STOCK to be awarded under each
OPTION, based on the recommendation of the CHIEF EXECUTIVE OFFICER (except that
awards to the CHIEF EXECUTIVE OFFICER shall be shall be based on the
recommendation of the BOARD OF DIRECTORS);
(b) to determine the time or times at which OPTIONS shall be
granted;
__________________________________
1/ Capitalized words are defined in Section 19 hereof.
<PAGE> 2
(c) to designate the OPTIONS being granted as ISOS or
NON-QUALIFIED STOCK OPTIONS;
(d) to vary the OPTION vesting schedule described in Section 10
hereof;
(e) to determine the terms and conditions, not inconsistent with
the terms of the PLAN, of any OPTION granted hereunder (including, but not
limited to, the consideration and method of payment for shares purchased upon
the exercise of an OPTION, and any vesting acceleration or exercisability
provisions in the event of a CHANGE IN CONTROL or TERMINATION), based in each
case on such factors as the COMMITTEE shall deem appropriate;
(f) to approve forms of agreement for use under the PLAN;
(g) to construe and interpret the PLAN and any related OPTION
agreement and to define the terms employed herein and therein;
(h) except as provided in Section 17 hereof, to modify or amend
any OPTION or to waive any restrictions or conditions applicable to any OPTION
or the exercise thereof;
(i) except as provided in Section 17 hereof, to prescribe, amend
and rescind rules, regulations and policies relating to the administration of
the PLAN;
(j) except as provided in Section 17 hereof, to suspend,
terminate, modify or amend the PLAN;
(k) to delegate to one or more agents such administrative duties
as the COMMITTEE may deem advisable, to the extent permitted by applicable law;
and
(l) to make all other determinations and take such other action
with respect to the PLAN and any OPTION granted hereunder as the COMMITTEE may
deem advisable, to the extent permitted by applicable law.
Notwithstanding the provisions contained in the foregoing paragraph,
the CHIEF EXECUTIVE OFFICER shall have the authority, in his sole discretion:
(a) to grant OPTIONS to any ELIGIBLE PARTICIPANT who, at the time of the
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<PAGE> 3
OPTION grant, (i) is not an officer of the COMPANY or a DIRECTOR, and (ii) if
such ELIGIBLE PARTICIPANT is an EMPLOYEE, is receiving an annual salary which
is below the level which requires approval by the COMMITTEE; (b) to determine
the time or times at which OPTIONS shall be granted to such ELIGIBLE
PARTICIPANTS; (c) to designate the OPTIONS being granted to such ELIGIBLE
PARTICIPANTS as ISOS or NON-QUALIFIED STOCK OPTIONS; and (d) to vary the
OPTION vesting schedule described in Section 10 hereof for the OPTIONS granted
to such ELIGIBLE PARTICIPANTS; provided, however, that all grants of OPTIONS
by the CHIEF EXECUTIVE OFFICER shall conform to the guidelines previously
approved by the COMMITTEE.
3. Shares of Stock Subject to the Plan
There shall be reserved for use under the Plan and for the grant of
any other incentive awards pursuant to the PROGRAM (subject to the provisions
of Section 13 hereof) a total of 13,000,000 shares of COMMON STOCK, which
shares may be authorized but unissued shares of COMMON STOCK or issued shares
of COMMON STOCK which shall have been reacquired by PG&E.
If any OPTION expires or terminates for any reason without having
been exercised in full, then any unexercised, shares which were subject to such
OPTION (except shares as to which a related TANDEM SAR has been exercised)
shall again be available for the future grant of OPTIONS under the PLAN (unless
the PLAN has terminated). In addition, shares may be reused or added back to
the PLAN to the extent permitted by applicable law.
4. Eligibility
OPTIONS will be granted only to ELIGIBLE PARTICIPANTS. ISOS will be
granted only to EMPLOYEES. The COMMITTEE, in its sole discretion, may grant
OPTIONS to an ELIGIBLE PARTICIPANT who is a resident or citizen of a foreign
country, with such modifications as the COMMITTEE may deem advisable to reflect
the laws, tax policy or customs of such foreign country.
The PLAN shall not confer upon any OPTIONEE any right to
continuation of employment, service as a DIRECTOR or consulting relationship
with the COMPANY; nor shall it interfere in any way with the right of the
OPTIONEE or the COMPANY to terminate such employment, service as a DIRECTOR or
consulting relationship at any time, with or without cause.
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<PAGE> 4
5. Designation of Options
At the time of the grant of each OPTION under this PLAN, the
COMMITTEE (or the CHIEF EXECUTIVE OFFICER, in the case of OPTIONS granted by
the CHIEF EXECUTIVE OFFICER to certain ELIGIBLE PARTICIPANTS pursuant to
Section 2 hereof) shall determine whether such OPTION is to be designated as an
ISO or a NON-QUALIFIED STOCK OPTION; provided, however, that ISOS may be
granted only to EMPLOYEES.
Notwithstanding such designation, to the extent that the aggregate
FAIR MARKET VALUE (determined for each share as of the date of grant of the
OPTION covering each share) of the shares with respect to which OPTIONS
designated as ISOS become exercisable for the first time by any OPTIONEE during
any calendar year exceeds $100,000, such OPTIONS shall be treated as
NON-QUALIFIED STOCK OPTIONS.
OPTIONS shall be awarded at no cost to the OPTIONEE.
6. Option Price
The OPTION PRICE of the COMMON STOCK under each OPTION issued shall
be the FAIR MARKET VALUE of the COMMON STOCK on the date of grant.
7. Stock Appreciation Rights
At the discretion of the COMMITTEE, an OPTION may be granted with or
without a TANDEM SAR which permits the OPTIONEE to surrender unexercised an
OPTION or portion thereof and to receive in exchange a payment having a value
equal to the difference between (x) the FAIR MARKET VALUE of the COMMON STOCK
covered by the surrendered portion of the OPTION on the date the SAR is
exercised and (y) the OPTION PRICE for such COMMON STOCK. The SAR is subject
to the same terms and conditions as the related OPTION, except that (i) the SAR
may be exercised only when there is a positive spread (i.e., when the FAIR
MARKET VALUE of the COMMON STOCK subject to the OPTION exceeds the OPTION
PRICE), (ii) in accordance with Section 8 hereof, payment of the DEA (if any)
to the OPTIONEE may be restricted, and (iii) if the OPTIONEE is a SECTION 16
OFFICER, DIRECTOR or other person whose transactions in the COMMON STOCK are
subject to Section 16(b) of the EXCHANGE ACT, the SAR may be exercised only
during the period beginning on
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the third (3rd) business day following the date of release of the COMPANY'S
quarterly or annual statement of earnings and ending on the twelfth (12th)
business day following such date. Upon the exercise of a SAR, the number of
shares subject to exercise under the related OPTION shall be automatically
reduced by the number of shares represented by the OPTION or portion thereof
surrendered. No payment will be required from the OPTIONEE upon the exercise
of a SAR, except that any amount necessary to satisfy applicable federal, state
or local tax requirements shall be withheld.
8. Dividend Equivalent Account
At the discretion of the COMMITTEE, an OPTION may be granted with or
without TANDEM DIVIDEND EQUIVALENTS. When an OPTION is granted with TANDEM
DIVIDEND EQUIVALENTS, a Dividend Equivalent Account ("DEA") shall be
established for the OPTIONEE. This DEA shall be credited quarterly on each
dividend record date with dividends which would have been paid on the COMMON
STOCK subject to the unexercised portion of the OPTION (including any portion
which has not yet vested on the record date), if such portion had been
exercised. Except as provided in Section 11(d) hereof, at the time the OPTION
or any related SAR is exercised, the OPTIONEE shall receive all funds which
have accumulated in the DEA with respect to the shares of COMMON STOCK for
which the OPTION or SAR is being exercised; provided, however, that if the
OPTIONEE exercises a SAR, such DEA funds shall only be paid to the OPTIONEE if
(i) the percentage increase in the FAIR MARKET VALUE of the COMMON STOCK over
the OPTION PRICE averages at least five percent (5%) per year for the first
five (5) years after the grant, or (ii) in the case of OPTIONS held for longer
than five (5) years from the date of grant, such FAIR MARKET VALUE has
increased by at least twenty-five percent (25%) over the OPTION PRICE.
9. Terms of Options
The term of each ISO shall be for ten (10) years from the date of
grant, subject to earlier termination as provided in Section 11 hereof. The
term of each NON-QUALIFIED STOCK OPTION shall be ten (10) years and one (1) day
from the date of grant, subject to earlier termination as provided in Section
11 hereof. Any provision of the PROGRAM to the contrary notwithstanding, no
OPTION shall be exercised after the time limitations stated in this Section 9.
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<PAGE> 6
10. Limitations on Exercise
(a) Each OPTION granted under the PROGRAM shall become exercisable
and vested only to the following extent: (i) up to one-third (1/3) of the
OPTIONS granted may be exercised on or after the second (2nd) anniversary of
the date of grant; (ii) up to two-thirds (2/3) of the OPTIONS granted may be
exercised on or after the third (3rd) anniversary of the date of grant; and
(iii) up to one hundred percent (100%) of the OPTIONS granted may be exercised
on or after the fourth (4th) anniversary of the date of grant.
(b) No OPTION under the PROGRAM designated by the COMMITTEE as an
ISO and granted before January 1, 1987 may be exercised while there is
outstanding in the hands of the OPTIONEE any ISO which was granted before the
granting of the ISO hereunder sought to be exercised. For this purpose an ISO
shall be treated as outstanding until such OPTION is (i) exercised in full,
(ii) surrendered in full by exercising SARS pursuant to Section 7 hereof, or
(iii) rendered void by reason of lapse of time.
11. Termination of Employment or Relationship with the Company
(a) In the event of a TERMINATION by reason of a discharge or
TERMINATION FOR CAUSE, any unexercised OPTIONS theretofore granted to an
OPTIONEE under the PROGRAM shall forthwith terminate.
(b) In the event of a TERMINATION by reason of RETIREMENT:
(i) all OPTIONS held by the OPTIONEE and granted prior to
September 16, 1992, to the extent that such OPTIONS have not previously expired
or been exercised, shall become fully exercisable and vested, notwithstanding
the provisions of Section 10(a) hereof, and the OPTIONEE shall have the right
to exercise such OPTIONS in full at any time within their respective terms or
within three (3) years after such RETIREMENT, whichever is shorter; and
(ii) all OPTIONS held by the OPTIONEE and granted on or after
September 16, 1992, to the extent that such OPTIONS have not previously expired
or been exercised, shall become fully exercisable and vested, notwithstanding
the provisions of Section 10(a) hereof, and the OPTIONEE shall have the right
to exercise such OPTIONS in full at any time within their respective terms or
within five (5) years after such RETIREMENT, whichever is shorter.
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<PAGE> 7
This three-year or five-year period (as the case may be) shall be
extended if an OPTIONEE remains on the BOARD OF DIRECTORS after RETIREMENT. In
such case, the OPTIONS may be exercised as long as the OPTIONEE remains a
DIRECTOR and for a period of six (6) months thereafter, or within three (3)
years or five (5) years (as the case may be) after RETIREMENT, whichever is
longer; provided, however, that no OPTION may be exercised after the expiration
of its term. Notwithstanding the foregoing, any ISOS held by the OPTIONEE may
be exercised only within their respective terms or within three (3) months
after RETIREMENT, whichever is shorter.
(c) In the event of a TERMINATION by reason of disability or
death, all OPTIONS held by the OPTIONEE, to the extent that such OPTIONS have
not previously expired or been exercised, shall become fully exercisable and
vested, notwithstanding the provisions of Section 10(a) hereof, and the
OPTIONEE (or the OPTIONEE'S estate or a person who acquired the right to
exercise such OPTIONS by bequest or inheritance) shall have the right to
exercise such OPTIONS at any time within their respective terms or within one
(1) year after the date of such TERMINATION, whichever is shorter. The term
"disability" shall, for the purposes of these Rules, be defined in Section
22(e)(3) of the CODE.
(d) In the event of a TERMINATION by reason of a divestiture or
change in control of a subsidiary of PG&E, which divestiture or change in
control results in such subsidiary no longer qualifying as a subsidiary
corporation under Section 424(f) of the CODE, all OPTIONS held by the OPTIONEE,
to the extent that such OPTIONS have not previously expired or been exercised,
shall become fully exercisable and vested, notwithstanding the provisions of
Section 10(a) hereof, and the OPTIONEE shall have the right to exercise such
OPTIONS in full at any time within their respective terms or within three (3)
years after such TERMINATION, whichever is shorter. This three-year period
shall be extended if an OPTIONEE remains on the BOARD OF DIRECTORS after such
TERMINATION. In such case, the OPTIONS may be exercised as long as the
OPTIONEE remains a DIRECTOR and for a period of six (6) months thereafter, or
within three (3) years after such TERMINATION, whichever is longer; provided,
however, that no OPTION may be exercised after the expiration of its term.
Notwithstanding the foregoing, any ISOS held by the OPTIONEE may be exercised
only within their respective terms or within three (3) months after such
TERMINATION, whichever is shorter.
(e) In the event of a TERMINATION for any reason other than those
specified in subparagraphs (a) through (d) above, (i) any unexercised OPTION
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<PAGE> 8
or OPTIONS granted under the PROGRAM shall be deemed cancelled and terminated
forthwith, except that the OPTIONEE may exercise any unexercised OPTIONS
theretofore granted which are otherwise exercisable and vested within the
provisions of Section 10(a) hereof, during the balance of their respective
terms or within thirty (30) days of such TERMINATION, whichever is shorter, and
(ii) the DEA (if any) shall not be credited with any dividends paid after the
date of such TERMINATION.
(f) Notwithstanding the provisions of subparagraphs (a) through
(e) above, the COMMITTEE may, in its sole discretion, establish different terms
and conditions pertaining to the effect of TERMINATION, to the extent permitted
by applicable federal and state law.
12. Payment for Shares Upon Exercise of Options
The exercise of any OPTION shall be contingent upon receipt by the
COMPANY of (i) cash (including any DEA funds payable to the OPTIONEE in
connection with the exercise of such OPTION), (ii) check, (iii) shares of
COMMON STOCK, (iv) an executed exercise notice together with irrevocable
instructions to a broker to either sell the shares subject to the OPTION or
hold such shares as collateral for a margin loan and to promptly deliver to the
COMPANY the amount of sale or loan proceeds required to pay the OPTION PRICE,
(v) any combination of the foregoing in an amount equal to the full OPTION
PRICE of the shares being purchased, or (vi) such other consideration and
method of payment, other than a note from the OPTIONEE, as the COMMITTEE, in
its sole discretion, may allow (which, in the case of an ISO shall be
determined at the time of grant), to the extent permitted by applicable law.
For purposes of this paragraph, shares of COMMON STOCK that are delivered in
payment of the OPTION PRICE must have been previously owned by the OPTIONEE for
a minimum of one year, and shall be valued at their FAIR MARKET VALUE as of the
date of the exercise of the OPTION. The COMPANY shall not make loans to any
OPTIONEE for the purpose of exercising OPTIONS.
13. Adjustments Upon Changes in Number or Value of Shares of Common Stock
If there are any changes in the number or value of shares of COMMON
STOCK by reason of stock dividends, stock splits, reverse stock splits,
recapitalizations, mergers, consolidations or other events that materially
increase or decrease the number or value of issued and outstanding shares of
COMMON
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<PAGE> 9
STOCK, the COMMITTEE may make such adjustments as it shall deem appropriate, to
prevent dilution or enlargement of rights, in (i) the number of shares of
COMMON STOCK available for future grants of OPTIONS under the PLAN, (ii) the
number of shares of COMMON STOCK covered by OPTIONS then outstanding, and (iii)
the price per share of COMMON STOCK covered by each such outstanding OPTION.
14. Non-Transferability of Options
An OPTION shall not be transferable by the OPTIONEE otherwise than
by will or the laws of descent and distribution, or pursuant to a qualified
domestic relations order as defined by the CODE, Title I of ERISA or the rules
thereunder. During the lifetime of the OPTIONEE, an OPTION may be exercised
only by the OPTIONEE or by an alternate payee under a qualified domestic
relations order.
15. Change in Control
Upon the occurrence of a CHANGE IN CONTROL (as defined below):
(a) Any time periods relating to the exercise of any OPTION
granted hereunder shall be accelerated so that such OPTION may be immediately
exercised in full; and
(b) The COMMITTEE may offer any OPTIONEE the option of having the
COMPANY purchase his or her OPTION for an amount of cash which could have been
attained upon the exercise of such OPTION had it been fully exercisable;
unless the COMMITTEE in its sole discretion determines that such CHANGE IN
CONTROL will not adversely impact the OPTIONEES of OPTIONS hereunder and is in
the best interests of the shareholders of PG&E. The COMMITTEE may make such
further provisions with respect to a CHANGE IN CONTROL as it shall deem
equitable and in the best interests of the shareholders of PG&E. Such
provision may be made in any agreement relating to any OPTION granted
hereunder, by amendment to any such agreement or by resolution of the
COMMITTEE.
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<PAGE> 10
The phrase "CHANGE IN CONTROL" shall have such meaning as ascribed
thereto from time to time by the COMMITTEE and set forth in any agreement
relating to any OPTION granted hereunder or by resolution of the COMMITTEE;
provided, however, that, notwithstanding the foregoing, a "CHANGE IN CONTROL"
shall be deemed to have occurred if:
(a) any "person" (as such term is used in Sections 13(d) and
14(d)(2) of the EXCHANGE ACT, but excluding any benefit plan for EMPLOYEES or
any trustee, agent or other fiduciary for any such plan acting in such person's
capacity as such fiduciary), directly or indirectly, becomes the beneficial
owner of securities of PG&E representing twenty percent (20%) or more of the
combined voting power of PG&E's then outstanding securities;
(b) during any two consecutive years, individuals who at the
beginning of such a period constitute the BOARD OF DIRECTORS cease for any
reason to constitute at least a majority of the BOARD OF DIRECTORS, unless the
election, or the nomination for election by the shareholders of PG&E, of each
new DIRECTOR was approved by a vote of at least two-thirds (2/3) of the
DIRECTORS then still in office who were DIRECTORS at the beginning of the
period; or
(c) the shareholders of PG&E shall have approved (i) any
consolidation or merger of PG&E in which PG&E is not the continuing or
surviving corporation or pursuant to which shares of COMMON STOCK are converted
into cash, securities or other property, other than a merger of PG&E in which
the holders of the COMMON STOCK immediately prior to the merger have the same
proportionate ownership of common stock of the surviving corporation
immediately after the merger, (ii) any sale, lease, exchange or other transfer
(in one transaction or a series of related transactions) of all or
substantially all of the assets of the COMPANY, or (iii) any plan or proposal
for the liquidation or dissolution of PG&E.
16. Listing and Registration of Shares
Each OPTION shall be subject to the requirement that if at any time
the COMMITTEE shall determine, in its discretion, that the listing,
registration or qualification of the shares covered thereby under any
securities exchange or under any state or federal law or the consent or
approval of any governmental regulatory body, including the California Public
Utilities Commission, is necessary or desirable as a condition of, or in
connection with, the granting of such OPTION or the issue
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<PAGE> 11
or purchase of shares thereunder, such OPTION may not be exercised in whole or
in part unless and until such listing, registration, qualification, consent or
approval shall have been effected or obtained free of any conditions not
acceptable to the COMMITTEE.
17. Amendment and Termination of the Plan and Options
The BOARD OF DIRECTORS or the COMMITTEE may at any time suspend,
terminate, modify or amend the PLAN in any respect; provided, however, that, to
the extent necessary and desirable to comply with RULE 16b-3 or with Section
422 of the CODE (or any other applicable law or regulation, including the
requirements of any stock exchange on which the COMMON STOCK is listed or
quoted), shareholder approval of any PLAN amendment shall be obtained in such a
manner and to such a degree as is required by the applicable law or regulation.
No suspension, termination, modification or amendment of the PLAN
may, without the consent of the OPTIONEE, adversely affect his or her rights
under OPTIONS theretofore granted to such OPTIONEE. In the event of amendments
to the CODE or applicable rules or regulations relating to ISOS subsequent to
the date hereof, the COMPANY may amend the PLAN, and the COMPANY and OPTIONEES
holding OPTION agreements may agree to amend outstanding OPTION agreements, to
conform to such amendments.
The COMMITTEE may make such amendments or modifications in the terms
and conditions of any OPTION as it may deem advisable, or cancel or annul any
grant of an OPTION; provided, however, that no such amendment, modification,
cancellation or annulment may, without the consent of the OPTIONEE, adversely
affect his or her rights under such OPTION; and provided further the COMMITTEE
may not reduce the OPTION PRICE or purchase price of any OPTION or OPTION below
the original OPTION PRICE or purchase price.
Notwithstanding the foregoing, the COMMITTEE reserves the right, in
its sole discretion, to (i) convert any outstanding ISOS to NON- QUALIFIED
STOCK OPTIONS, (ii) to require a OPTIONEE to forfeit any unexercised or
unpurchased OPTIONS, any shares received or purchased pursuant to an OPTION, or
any gains realized by virtue of the receipt of an OPTION in the event that such
OPTIONEE competes against the COMPANY, and (iii) to cancel or annul any grant
of an OPTION in the event of a OPTIONEE'S TERMINATION FOR CAUSE. For purposes
of the PROGRAM, "TERMINATION FOR CAUSE" shall
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<PAGE> 12
include, but not be limited to, termination because of dishonesty, criminal
offense or violation of a work rule, and shall be determined by, and in the
sole discretion of, the COMMITTEE.
18. Effective Date of Program and Duration
This PLAN shall become effective as of January 1, 1992, provided the
PROGRAM is approved by the vote of the holders of a majority of the outstanding
shares of the COMMON STOCK at the April 15, 1992 Annual Meeting of Shareholders
of PG&E. Unless terminated sooner pursuant to Section 17 hereof, the PLAN
shall terminate on December 31, 2001.
19. Definitions
a. BOARD OF DIRECTORS means the Board of Directors of PG&E.
b. CHANGE IN CONTROL has the meaning set forth in Section 15 hereof.
c. CHIEF EXECUTIVE OFFICER means the Chief Executive Officer of PG&E.
d. CODE means the Internal Revenue Code of 1986, as amended from time
to time.
e. COMMITTEE means the Compensation and Management Development
Committee of the BOARD OF DIRECTORS or any successor to such
committee.
f. COMMON STOCK means common shares of PG&E with a par value of $5.00
per share.
g. COMPANY means PG&E, and any parent corporation (as defined in
Section 424(e) of the CODE) or subsidiary corporation (as defined in
Section 424(f) of the CODE).
h. CONSULTANT means any person, including an advisor, who is engaged by
the COMPANY to render services.
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<PAGE> 13
i. DEA means a Dividend Equivalent Account described in Section 8
hereof.
j. DIRECTOR means any person who is a member of the BOARD OF DIRECTORS,
including an advisory, emeritus or honorary director.
k. DIVIDEND EQUIVALENT means a right that entitles the OPTIONEE to
receive cash or COMMON STOCK based on the dividends declared on the
COMMON STOCK covered by such right.
l. ELIGIBLE PARTICIPANT means any KEY EMPLOYEE. It also means, if so
identified by the COMMITTEE (or by the CHIEF EXECUTIVE OFFICER, in
the case of OPTIONS granted by the CHIEF EXECUTIVE OFFICER to
certain ELIGIBLE PARTICIPANTS pursuant to Section 2 hereof), other
EMPLOYEES, DIRECTORS, CONSULTANTS, employees or consultants of any
affiliates of PG&E, and other persons whose participation in the
PROGRAM is deemed by the COMMITTEE (or by the CHIEF EXECUTIVE
OFFICER, in the case of OPTIONS granted by the CHIEF EXECUTIVE
OFFICER to certain ELIGIBLE PARTICIPANTS pursuant to Section 2
hereof) to be in the best interests of the COMPANY; provided,
however, that DIRECTORS who are not EMPLOYEES shall not be ELIGIBLE
PARTICIPANTS.
m. EMPLOYEE means any person who is employed by the COMPANY. The
payment of a director's fee or consulting fee by the COMPANY shall
not be sufficient to constitute "employment" by the COMPANY.
n. ERISA means the Employee Retirement Income Security Act of 1974, as
amended.
o. EXCHANGE ACT means the Securities Exchange Act of 1934, as amended.
p. FAIR MARKET VALUE means the closing price of the COMMON STOCK
reported on the New York Stock Exchange Composite Transactions for
the date specified for determining such value.
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<PAGE> 14
q. ISO means an OPTION intended to qualify as an incentive stock option
under Section 422 of the CODE.
r. KEY EMPLOYEE means the Corporate Secretary, Treasurer, Vice
Presidents and other executive officers of PG&E above the rank of
Vice President. It also means, if so identified by the COMMITTEE
(or by the CHIEF EXECUTIVE OFFICER, in the case of OPTIONS granted
by the CHIEF EXECUTIVE OFFICER to certain ELIGIBLE PARTICIPANTS
pursuant to Section 2 hereof), executive officers of wholly-owned
subsidiaries of PG&E (including subsidiaries which become such after
adoption of the PROGRAM) and any other key management employee of
PG&E or any wholly-owned subsidiary of PG&E.
s. NON-EMPLOYEE DIRECTOR means a DIRECTOR who is not an EMPLOYEE.
t. NON-QUALIFIED STOCK OPTION means any OPTION which is not an ISO.
u. OPTION means an option to purchase shares of COMMON STOCK granted
under the PLAN.
v. OPTIONEE means the ELIGIBLE PARTICIPANT receiving the OPTION, or his
or her legal representative, legatees, distributees or alternate
payees, as the case may be.
w. OPTION PRICE means the purchase price for the COMMON STOCK upon
exercise of an OPTION.
x. PG&E means Pacific Gas and Electric Company, a California
corporation.
y. PLAN means this Stock Option Plan or any successor plan which the
COMMITTEE may adopt from time to time with respect to the grant of
OPTIONS under the PROGRAM.
z. PROGRAM means the Pacific Gas and Electric Company 1992 Long-Term
Incentive Program, pursuant to which this PLAN is adopted.
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<PAGE> 15
aa. RETIREMENT means the Actual Retirement Date under the PG&E
Retirement Plan.
ab. RULE 16b-3 means Rule 16b-3 under the EXCHANGE ACT or any successor
to Rule 16b-3, as in effect when discretion is being exercised with
respect to the Plan.
ac. SAR means a stock appreciation right whose value is based on the
increase in the FAIR MARKET VALUE of the COMMON STOCK covered by
such right.
ad. SECTION 16 OFFICER means any person who is designated by the BOARD
OF DIRECTORS as an executive officer of PG&E and any other person
who is designated as an officer of PG&E for purposes of Section 16
of the EXCHANGE ACT.
ae. TANDEM refers to a DIVIDEND EQUIVALENT or SAR (as the case may be)
granted in conjunction with an OPTION.
af. TERMINATION occurs when an EMPLOYEE ceases to be employed by the
COMPANY as a common law employee, when a DIRECTOR ceases to be a
member of the BOARD OF DIRECTORS or when the relationship between
the COMPANY and a CONSULTANT or other ELIGIBLE PARTICIPANT
terminates, as the case may be.
ag. TERMINATION FOR CAUSE has the meaning set forth in Section 11 hereof.
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<PAGE> 1
Exhibit 10.16
Perquisites
Executive Flexible Perquisites Program
The Flexible Perquisites Program provides you
with a wide range of services and gives you
the flexibility to create a personalized
spending or savings program.
How The
Program Works
As an officer, you are automatically enrolled
in the plan. In January of each year you may
receive an annual flexible allowance to apply
to the cost of certain services. A menu of
services is provided from which you may build
the program most valuable to you. Current
allowances are as follows:
o Chairman and Chief Executive Officer,
President, Executive Vice Presidents,
and Senior Vice Presidents $15,500
o All other officers $14,000
Perquisite allowances are subject to income
tax withholding at the time of grant.
Officers appointed on or after July 1 of any
year are eligible for a 50 percent allowance
for the year of appointment.
Flexible Perquisite Menu
The following is a list of approved
perquisites. You may choose the provider for
any given service and authorize payments or
reimbursements from your account
accordingly.* There are no cost limits for
these perquisites as long as you do not
exceed the current year's allowance plus any
unused allowance carried over from prior
years.
* The company will not recognize statements
for services rendered from PG&E employees
or from relatives of a participating
officer.
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<PAGE> 2
Executive Flexible Perquisites Program
Financial Planning includes retirement
counseling, insurance analysis, cash-flow
planning, investment planning, debt
management, estate planning, portfolio
management, and stock option and Savings Fund
Plan counseling.
Tax Preparation includes annual fees for
preparing federal and state income tax
returns, as well as tax consultation and
assistance with revenue examining agencies on
tax returns filed.
Legal Counsel includes advice pertaining to
financial, estate, or legal matters. Your
allowance cannot be used for fees incurred in
any action in which your interest is inimical
to the company.
Health, Business, or Professional Club
Membership includes annual membership dues
and related annual fees (such as locker,
storage, or rental fees). Clubs with
discriminatory practices are ineligible for
payment. You may also use your allowance to
purchase home exercise equipment.
The company wants you to maintain good
health, and therefore will continue to pay
for annual physical examinations under the
Executive Health Program. This cost will not
be charged against your flexible perquisite
allowance. (Refer to the Executive Health
Program section of this binder for more
information.)
Insurance includes the purchase of
supplemental life, disability, and accidental
death and dismemberment insurance, as well as
personal liability and automobile insurance
coverage to meet your personal needs.
Home Security System includes any home
security device for use in your primary
residence (such as electrical or mechanical
alarms, lighting, electrical fences or
cameras).
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<PAGE> 3
For your convenience, a list of various
providers of perquisite services is provided
in the Contacts section of the binder. Of
course, this list is not meant as a
recommendation. The choice of providers is
entirely yours.
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<PAGE> 4
Executive Flexible Perquisites Program
Unused Allowance
Your perquisite dollars accrue in a non
interest-bearing account until you wish to
use those amounts. You may accrue unused
allowances from year to year, up to a maximum
of four times the annual allowance. Once this
maximum is reached, no further allowances
will be granted until the accrued allowances
are used. Further allowances will be granted
only in amounts that will not exceed the
maximum. The four-year maximum accrued amount
cannot be exceeded at any time.
Reimbursement Procedures
Reimbursement payments may be made in one of
three ways:
1. You may pay the invoice and submit it
with a completed payment authorization
form to Executive Payroll. (Refer to the
Forms section of this binder for a sample
of this form.) This form must be
submitted to Executive Payroll during the
year the benefit is received (or, if the
benefit was provided in November or
December, no later than March 31 of the
following year). The reimbursement check
will be sent directly to you.
2. You may have a provider of the service
forward the unpaid invoice directly to
Executive Payroll. A payment
authorization form, completed by you,
must accompany the provider's invoice.
The form and unpaid invoice must be
submitted to the company during the year
the benefit is received (or, if the
benefit was provided in November or
December, no later than March 31 of the
following year). The check will be sent
directly to the provider of the service.
3. The company may pay for eligible expenses
and charge your allowance account
accordingly. Executive Payroll will issue
all checks within 10 working days after
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<PAGE> 5
receiving proper documentation.
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<PAGE> 6
Executive Flexible Perquisites Program
More You
Should Know
o In connection with the perquisites
program, you will be sent:
- Quarterly statements itemizing
activity and unused allowances.
- An annual statement summarizing the
current year's activities and
itemizing eligible perquisites and
available dollars (including
accumulated amounts, if any) for the
following year.
o If you are promoted to a senior officer
position, changes in your allowance will
become effective on the date of your
promotion.
o If your employment is terminated due to
death, unused balances in your perquisite
account will be paid or reimbursed to
your beneficiary or estate.
o If you retire or become disabled, or if
your employment is terminated for any
other reason, unused balances in your
perquisite account will be paid to you as
soon as practicable.
o You may defer all or a portion of your
annual Flexible Perquisites allowance
through the Deferred Compensation Plan.
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<PAGE> 1
EXHIBIT 13
SELECTED FINANCIAL DATA
PACIFIC GAS AND ELECTRIC COMPANY
<TABLE>
<CAPTION>
1993 1992 1991 1990 1989
----------- ----------- ----------- ----------- -----------
(in thousands, except per share amounts)
<S> <C> <C> <C> <C> <C>
For the Year
Operating revenues $10,582,408 $10,296,088 $ 9,778,119 $ 9,470,092 $ 8,588,264
Operating income 1,762,930 1,833,441 1,713,079 1,706,136 1,622,558
Net income 1,065,495 1,170,581 1,026,392 987,170 900,628
Earnings per common share 2.33 2.58 2.24 2.10 1.90
Dividends declared per common share 1.88 1.76 1.64 1.52 1.40
At Year End
Book value per common share $ 19.77 $ 19.41 $ 18.40 $ 17.86 $ 17.38
Common stock price per share 35.13 33.13 32.63 25.00 22.00
Total assets 27,162,526 24,188,159 22,900,670 21,958,397 21,351,970
Long-term debt and preferred stock
with mandatory redemption
provision (excluding current
portions) 9,367,100 8,525,948 8,341,310 7,902,409 7,951,320
</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
MANAGEMENT'S DISCUSSION AND ANALYSIS OF CONSOLIDATED
RESULTS OF OPERATIONS AND FINANCIAL CONDITION
PACIFIC GAS AND ELECTRIC COMPANY
Results of Operations
- ---------------------
Pacific Gas and Electric Company (PG&E) and its wholly owned and
majority-owned subsidiaries (the Company) have three types of operations:
utility, Diablo Canyon Nuclear Power Plant (Diablo Canyon) and nonregulated
through PG&E Enterprises (Enterprises). For 1993, 1992 and 1991, selected
financial information for the three types of operations is shown below:
<TABLE>
<CAPTION>
Diablo
Utility Canyon(1) Enterprises Total
------- --------- ----------- -------
(in millions, except per share amounts)
<S> <C> <C> <C> <C>
1993
Operating revenues
Electric $ 5,933 $1,933 $ - $ 7,866
Gas 2,465 - 251 2,716
------- ------ ------ -------
Total 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
Electric $ 5,966 $1,781 $ - $ 7,747
Gas 2,340 - 209 2,549
------- ------ ------ -------
Total 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
1991
Operating revenues
Electric $ 5,868 $1,501 $ - $ 7,369
Gas 2,336 - 73 2,409
------- ------ ------ -------
Total operating revenues 8,204 1,501 73 9,778
Operating expenses 6,953 1,004 108 8,065
------- ------ ------ -------
Operating income (loss) $ 1,251 $ 497 $ (35) $ 1,713
======= ====== ====== =======
Net income (loss) $ 777 $ 274 $ (25) $ 1,026
======= ====== ====== =======
Earnings (loss) per common share $ 1.71 $ .59 $ (.06) $ 2.24
Total assets at year end $16,440 $5,543 $ 918 $22,901
(1) See Note 3 of Notes to Consolidated Financial Statements for discussion of
allocations.
</TABLE>
EARNINGS PER COMMON SHARE: Earnings per common share were $2.33, $2.58 and
$2.24 for 1993, 1992 and 1991, respectively. Earnings per common share for
1993 were lower than for 1992 due to charges against earnings of $410 million
which were partially offset by Diablo Canyon's performance as discussed in the
Operating Revenues section. The above charges are detailed as follows:
<TABLE>
<CAPTION> Year ended
December 31, 1993
-----------------------
(in millions)
<S> <C>
Workforce reduction program costs $190
Gas decontracting costs and reserves for
gas transportation commitments 127
Reserve for gas reasonableness proceedings 61
Diablo Canyon deferred tax liability
adjustment 32
----
Total $410
====
</TABLE>
Earnings per common share for 1992 were higher than for 1991 primarily
due to one scheduled refueling outage at Diablo Canyon in 1992, compared to two
scheduled refueling outages in 1991, and the annual increase in the price per
kilowatthour (kWh) as provided in the Diablo Canyon rate case settlement.
In 1993 and 1992, the Company earned an 11.9% and a 13.7% return on
average common stock equity, respectively.
COMMON STOCK DIVIDEND: In January 1994, the Company raised the quarterly
common stock dividend 4.3%, from an annualized rate of $1.88 per share to
$1.96 per share.
The amount of 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. Over time,
the Company plans to reduce its dividend payout ratio (dividends declared
divided by earnings available for common stock) to reflect the increased
business risk in the utility industry and the earnings volatility associated
with the Diablo Canyon rate case settlement.
OPERATING REVENUES: Electric revenues increased $119 million and $378 million
in 1993 and 1992, respectively, compared to the preceding year. The increase
in 1993 electric revenues was due to rate increases associated with general
increases in operating expenses and a higher electric
13
<PAGE> 3
MANAGEMENT'S DISCUSSION AND ANALYSIS OF CONSOLIDATED RESULTS OF
OPERATIONS AND FINANCIAL CONDITION (continued)
PACIFIC GAS AND ELECTRIC COMPANY
rate base on which PG&E is allowed to earn a return, as provided in the
1993 General Rate Case (GRC). 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 rate case settlement.
The increase in 1992 electric revenues was primarily due to one
scheduled refueling outage at Diablo Canyon in 1992, compared to two scheduled
refueling outages in 1991, and the annual increase in the price per kWh as
provided in the Diablo Canyon rate case settlement.
Gas revenues increased $167 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
provided in the 1993 GRC, as well as increased revenues from Enterprises
reflecting increases in the price and production of gas.
The 1992 increase was primarily due to revenues resulting from the
December 1991 acquisition of Tex/Con Oil & Gas Company (Tex/Con) by PG&E
Resources Company (Resources), a wholly owned subsidiary of Enterprises.
OPERATING EXPENSES: In 1993 and 1992, the Company's operating expenses
increased $356 million and $398 million, respectively, over the preceding year.
The 1993 increase was due to a charge against earnings of $190 million related
to the Company's workforce reduction program and increases in administrative
and general expense, income tax expense, and depreciation and decommissioning
expense of $114 million, $100 million and $94 million, respectively, offset by
a decrease of $166 million in the cost of electric energy. Most of the increase
in administrative and general expense was due to an increase in litigation
costs and an increase in employee costs upon adoption of Statement of Financial
Accounting Standards (SFAS) No. 106, "Employers' Accounting for Postretirement
Benefits Other Than Pensions." The increase in income tax expense was primarily
due to the increase in the federal income tax rate to 35% from 34%, and a
related adjustment to Diablo Canyon deferred income tax liability, as required
under SFAS No. 109, "Accounting for Income Taxes." The increase in depreciation
and decommissioning expense was a result of an increase in depreciation expense
related to the increase in plant in service. The decrease in the cost of
electric energy was a result of improved hydroelectric conditions and reflects
a decline in the cost per kWh for purchased power and a reduction in the volume
of gas used to provide electric energy.
The 1992 increase in operating expenses was primarily due to increase
in the cost of gas, the cost of electric energy, and depreciation and
decommissioning expense. The cost of gas increased in 1992 by $103 million over
the preceding year, primarily due to an increase in the cost of gas purchased
on behalf of, and transported for, noncore customers. The cost of electric
energy increased $98 million in 1992 compared to 1991, primarily due to
increases in the cost of purchased power and natural gas. The $81 million
increase in depreciation and decommissioning expense reflects an increase in
depreciation expense related to the increase in plant in service.
OTHER INCOME AND (INCOME DEDUCTIONS): Total other income was $74 million, $124
million and $95 million for 1993, 1992 and 1991, respectively.
Allowance for equity funds used during construction was $42 million,
$39 million and $25 million for 1993, 1992 and 1991, respectively. The
increases in 1993 and 1992 compared to the preceding year were primarily due to
the PGT-PG&E Pipeline Expansion Project which was put in service in November
1993.
Other -- net for 1993 includes amounts recorded for the gas
decontracting costs, losses on long-term commitments for gas transportation
capacity and a possible disallowance in connection with gas reasonableness
proceedings as discussed in the Natural Gas Matters section.
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<PAGE> 4
Other -- net for 1992 included a $19 million after-tax gain from the
sale by Pacific Gas Transmission Company (PGT), a wholly owned gas pipeline
subsidiary of the Company, of its 49.98% interest in Alberta Natural Gas
Company Ltd (ANG). Other -- net for 1992 also reflects the establishment of new
accounting guidelines for the recognition of revenues related to customer
energy efficiency programs, which resulted in a $25 million decrease in the
amount of income recognized in 1992 compared to 1991.
Included in 1991 other -- net is the write-off by ANG of its investment
in a magnesium metal production facility project in Alberta, Canada. This
write-off resulted in a $26 million after-tax charge.
DIABLO CANYON: The Diablo Canyon rate case 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. The Company's earnings are affected directly by plant performance and
costs incurred.
Diablo Canyon revenues are based primarily on a pre-established price per kWh
consisting of a fixed component and an escalating component of electricity
generated by the plant. (Pricing for Diablo Canyon is discussed in Note 3 of
Notes to Consolidated Financial Statements.) From the revenues received for
Diablo Canyon, the Company must recover the costs of owning and operating the
plant, including all future capital additions. If power generation drops below
specified capacity levels, the Company may request floor payments which ensure
that the Company will receive some revenue, even if the plant stops producing
power. However, payments received must be refunded to customers under specified
conditions. Decommissioning and certain specific costs will continue to be
recovered through base rates and are not subject to plant performance.
The plant capacity factors for 1993 and 1992 were 89% and 88%,
respectively, reflecting the scheduled refueling outage for Unit 2 in 1993 and
Unit 1 in 1992. There were no extended unscheduled outages in 1993 and 1992.
Through December 31, 1993, the lifetime capacity factor for the plant was 79%.
The Company will report significantly lower revenues for the plant during any
extended outages, including refueling outages. Refueling outages, the lengths
of which depend on the scope of the work, typically occur for each unit every
eighteen months. Refueling outages for Unit 1 and Unit 2 are scheduled to begin
in March 1994 and September 1994, respectively, and each is planned to last
about nine weeks.
Each Diablo Canyon unit will contribute approximately $3.1 million in
revenues per day at full operating power in 1994. Beginning in 1995 and
thereafter, the escalating component in the price of Diablo Canyon power
provided by the settlement agreement will be based on a formula that will be
adjusted by the change in the consumer price index plus 2.5%, divided by two.
This could slow the rate of future earnings growth from the plant.
WORKFORCE REDUCTION PROGRAM: In the first quarter of 1993, the Company
announced a corporate reorganization and workforce reduction program. As of
December 31, 1993, the Company has recorded workforce reduction program costs
of $264 million, net of a curtailment gain relating to pension benefits. In
April 1993, the Company announced a freeze on electric rates through 1994. As a
result, the Company has expensed $190 million of such costs relating to
electric operations. The remaining $74 million of such costs relating to gas
operations has been deferred for future rate recovery. The amount deferred is
currently being amortized as savings are realized. The Company is seeking rate
recovery of all costs incurred in connection with the workforce reduction
program relating to electric and gas operations.
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<PAGE> 5
MANAGEMENT'S DISCUSSION AND ANALYSIS OF CONSOLIDATED RESULTS OF
OPERATIONS AND FINANCIAL CONDITION (continued)
PACIFIC GAS AND ELECTRIC COMPANY
During 1994 and 1995, the Company expects to benefit from the expense
reduction attributable to the electric operations' workforce reduction. The
Company currently estimates that the workforce reduction program will result in
a net revenue requirement savings of approximately $170 million during the
three-year 1993 GRC cycle, which ends December 31, 1995. Beginning in 1996, the
workforce reduction program is expected to result in annual revenue requirement
savings of at least $200 million. (See Note 8 of Notes to Consolidated
Financial Statements for further discussion of the workforce reduction
program.)
ELECTRIC RATE INITIATIVE: In April 1993, the Company proposed a
comprehensive electric rate initiative to freeze current retail electric rates
through the end of 1994 and to reduce electric rates by $100 million for major
businesses as an economic stimulus for those customers. In June 1993, the
California Public Utilities Commission (CPUC) approved the economic stimulus
rate, effective for the period July 1993 through December 1994.
In December 1993, the CPUC approved the electric rate freeze and issued
its decision in the Company's Attrition Rate Adjustment (ARA) and the Energy
Cost Adjustment Clause (ECAC) proceedings. As part of the ECAC decision, the
CPUC approved the Company's request to defer beyond 1994 recovery of a portion
of the undercollections in the ECAC balancing account. The total
undercollection at December 31, 1993, was $427 million.
Pursuant to the electric rate initiative, the effects of the CPUC
decisions on the Company's various electric rate proceedings (including the
cost of capital proceeding discussed in the Liquidity and Capital Resources
section) were consolidated resulting in a net change in electric rates of zero,
effective January 1994.
The Company intends to achieve cost reductions to offset revenue
reductions due to the economic stimulus rate. To the extent that these cost
reductions are not achieved, there would be a negative impact on the Company's
1994 results of operations.
COMPETITION: The Company is currently experiencing increasing
competition in both the gas and electric energy markets. In recent years,
changes in governmental regulations, new technology, interest in
self-generation and cogeneration, and competition from nonutility and
nonregulated energy suppliers have provided many major utility customers with
alternative sources to satisfy their gas and electric requirements.
The recent restructuring of the natural gas industry has increased
competition. As a result of regulatory changes, the Company no longer provides
combined purchase and transportation services to many of its industrial and
large commercial customers (noncore customers). Instead, many noncore customers
now purchase gas supplies directly from gas shippers or producers, reserve
interstate transportation capacity directly from interstate pipelines, and then
purchase intrastate transportation service from the Company once their gas
arrives at the California border. Furthermore, an interstate pipeline has
proposed expanding its facilities into the Company's service territory which,
if approved, would allow it to compete directly for intrastate transportation
service to the Company's noncore customers. To the extent that regulators
approve this pipeline, the Company could lose customers and volume on its gas
transportation system.
The restructuring of the natural gas industry has had a significant
impact on the Company's gas operations. In 1993, the Company terminated its
long-term Canadian gas purchase contracts and has entered into new, more
flexible arrangements for the purchase of the Company's current lower gas
supply requirements. In addition, the Company is continuing its efforts to
permanently assign or broker its commitments for firm gas transportation
capacity which it once held for its noncore customers. As a result of these
changes, the Company has recorded reserves in 1993 for its transportation
commitments. (See Natural Gas Matters section and Note 2 of Notes to
Consolidated Financial Statements for further discussion of regulatory
restructuring and the impact on the Company's gas purchase and transportation
commitments.)
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<PAGE> 6
While the restructuring of the electric industry is still evolving,
proposals being considered at state and federal levels and the recently enacted
National Energy Policy Act of 1992 (Act) are expected to bring more competition
into the electric generation business. The Company currently purchases
approximately one-third of the electrical power supplied to its customers from
generation sources outside the Company's service territory and from qualifying
facilities owned and operated by independent power producers. (Qualifying
facilities are small power producers or cogenerators that meet certain federal
guidelines and thereby qualify to supply generating capacity and electric
energy to electric utilities, which must purchase this power at prices approved
by state regulatory bodies.) Future additions to satisfy electric supply needs
in the Company's service territory will be determined largely through a
competitive resource procurement process, a feature of the new competitive
market for electric generation. The Company has indicated a willingness to
forgo building new generation capacity in its service territory if appropriate
regulatory reforms are instituted in the energy procurement process to provide
increased procurement flexibility.
With its enactment, the 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. The Federal Energy Regulatory
Commission (FERC) now has increased authority to order a utility to transport
and deliver, or "wheel," energy for wholesale purchasers or sellers of power.
While the Act prohibits FERC-ordered retail wheeling, it does not address the
states' ability to order retail wheeling. If future restructuring were to
include retail wheeling whereby customers purchase energy directly from an
independent power producer and separately pay the Company to wheel the
purchased power, the Company's power generation plants and resources would be
subject to competition from other available supply options.
Under current regulation, customer prices are based on an allocation
among customer classes of the Company's approved cost of service revenue
requirements. Currently, large industrial and commercial customers are the most
likely to have lower cost competitive alternatives. If a substantial number of
these customers were to leave the system, the Company's recovery of its
investment in production sources and distribution facilities would be dependent
on prices charged to remaining customers and the Company's ability to reduce
costs. This could lead to lower shareholder returns.
To succeed in this more competitive environment, the Company has taken
steps in 1993 to improve service to customers, reduce costs and lower the price
of gas and electric service. The Company has:
1) Reduced its workforce by approximately 3,000 positions which
will result in net revenue requirement savings of approximately $170
million during the three-year 1993 GRC cycle and annual revenue
requirement savings of at least $200 million beginning in 1996. (See
the Workforce Reduction Program section and Note 8 of Notes to
Consolidated Financial Statements for further discussion of the
workforce reduction program.)
2) Reduced its cost of capital by taking advantage of
significantly lower interest rates to reduce financing costs. (See the
Sources of Capital section for further discussion of debt refinancing.)
3) Obtained CPUC approval to freeze current electric rates
through the end of 1994 and to reduce electric rates by $100 million
for major businesses over an 18-month period beginning in July 1993.
(See the Electric Rate Initiative section for further discussion of the
electric rate initiative.)
4) Begun discussions with the CPUC, customers and other
interested parties on the Company's regulatory reform initiative which,
in part, would allow the Company more flexibility to respond to
competitive conditions quickly. (See the Regulatory Reform Initiative
section for further discussion of the regulatory reform initiative.)
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF CONSOLIDATED RESULTS OF
OPERATIONS AND FINANCIAL CONDITION (continued)
PACIFIC GAS AND ELECTRIC COMPANY
5) Given discounts on its gas transportation contracts for certain
major industrial customers to obtain long-term commitments. To date, customers
entering into these contracts represent approximately 12 percent of total
noncore transportation volume.
Further, the Company continues to pursue improvements in the efficiency
and productivity of its operations and is committed to sustaining high levels
of customer service.
REGULATORY REFORM INITIATIVE: In February 1993, the CPUC's Division of
Strategic Planning issued its report on electric industry restructuring, which
concluded that the current regulatory approach is incompatible with the
emerging industry structure resulting from technological change, competitive
pressure and new market forces. The CPUC has several proceedings in progress
in which it is investigating reform proposals. The Company has begun
discussions with the CPUC, customers and other interested parties concerning
various reforms to the current regulatory approach to setting rates. Under the
traditional regulatory approach, rates generally are based on a detailed
examination of the utility's costs of providing service plus a reasonable rate
of return. The resulting amount is the utility's revenue requirement, which the
Company is permitted to recover in rates. Under the approach being explored by
the Company, the Company's revenue requirement would be adjusted annually on
the basis of a series of market indices, such as inflation and customer growth,
and a productivity factor designed to reflect cost savings from increased
efficiency. The Company and its customers would share in savings or excess
costs.
This approach would act as a surrogate for detailed cost examinations
and would be used to determine the Company's base revenues, intended to recover
the Company's fixed costs and nonfuel variable costs and to provide a return on
invested capital. Fuel procurement incentives also could be implemented for the
Company's gas purchases for core portfolio customers and power plant fuel. This
approach would use market-based benchmarks to determine the amount of revenues
which the Company could recover to offset these costs, replacing the current
after-the-fact reasonableness reviews of those costs by the CPUC.
As part of the Company's proposal for its largest electric customers,
the Company is seeking to have increased flexibility to provide discounts and
tailor its services to these customers while assuming the risk for decreases in
revenues. This change in the cost of service rate approach could result in a
change in accounting principle for this customer class. If the accounting
criteria applicable to cost of service rate regulation are no longer met, then
the Company would write off the allocable share of regulatory assets, including
regulatory balancing accounts receivable and those regulatory assets included
in deferred charges.
The Company intends to solicit comments from the CPUC, customers and
other interested parties and to file a formal application with the CPUC in the
first quarter of 1994, with implementation proposed for 1995. To the extent
that regulators approve the Company's regulatory reform initiative, changes may
occur to the current regulatory framework as discussed below in the Regulatory
Matters section.
ACCOUNTING FOR THE EFFECTS OF REGULATION: 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." The Company is exploring
regulatory reforms and expects to file a formal application with the CPUC in
1994. (See the Regulatory Reform Initiative section for further discussion.)
If the regulatory reforms contemplated by the Company are adopted, the
mechanics of the rate setting process would change. The Company anticipates
that rates derived from the regulatory reforms would remain based on cost of
service. However, the final determination will be dependent upon the regulatory
reform initiative that is ultimately adopted.
In the event that recovery of costs through rates becomes unlikely or
uncertain, whether resulting from the expanding effects of competition or
specific regulatory actions which force the Company away from cost of service
ratemaking, SFAS No. 71 would no longer apply. If the Company were to
18
<PAGE> 8
discontinue application of SFAS No. 71 for some or all of its operations, then
it would write off the applicable portion of regulatory assets, including
regulatory balancing accounts receivable and those regulatory assets included
in deferred charges. The financial effects upon discontinuing application of
SFAS No. 71 could be significant.
REGULATORY MATTERS: The Company's electric and gas energy prices are regulated
primarily by the CPUC. Base rates compensate the Company for operating and
maintenance costs, depreciation and taxes, and provide a return on capital.
Base rates are set every three years in GRC proceedings. The base rates for
1993 were established in the 1993 GRC. Between rate cases, the ARA mechanism
provides for rate adjustments for inflation, changes in rate base and changes
in the authorized cost of capital.
Balancing accounts help stabilize the Company's earnings. The CPUC sets
rates based on estimates of future revenues and costs; differences between
revenues or energy costs authorized by the CPUC and actual revenues or energy
costs are accumulated in the balancing accounts for subsequent rate adjustment.
Energy cost balancing accounts (which include ECAC) reduce the effect on
earnings of fluctuations in most electric energy and gas costs. Sales balancing
accounts (which include Electric Revenue Adjustment Mechanism) reduce the
effect on earnings of fluctuations in most sales to electric and gas customers.
Both the ARA mechanism and the energy cost balancing accounts limit the
effect of inflation on the Company's earnings from utility operations by
closely matching rates with costs.
The regulatory framework for natural gas service (1) segments the
Company's gas customers into core (residential and small commercial customers)
and noncore classes, (2) provides noncore customers with options in procuring
their own gas supplies, (3) allows noncore customers to negotiate interstate
gas transportation directly with the interstate pipelines and separately
negotiate intrastate gas transportation with their utilities, and (4) places
the Company's noncore transportation revenues at increased risk due to
competitive alternatives.
Gas cost allocation proceedings allocate forecasted costs between core
and noncore customers and set associated rates. This ratemaking mechanism
covers a two-year forecast period and includes a balancing account which allows
the Company to accumulate 75% of the difference between authorized and actual
noncore transportation revenues. Prior to the establishment of the 75%
balancing account in May 1992, a 90% balancing account was in effect. As a
result, this placed the Company's noncore gas transportation revenues at
increased risk to the extent authorized revenues differ from actual.
NATURAL GAS MATTERS: Decontracting Plan: As discussed in Note 2 of Notes to
Consolidated Financial Statements, regulatory changes have restructured the
natural gas industry. Certain Canadian gas producers filed lawsuits against
the Company claiming damages of at least $466 million (Canadian) resulting
from the alleged failure of Alberta and Southern Gas Co. Ltd. (A&S), a wholly
owned subsidiary of the Company, to meet its minimum contractual gas purchase
obligations. A&S, PGT, PG&E and approximately 190 Canadian gas producers
subsequently entered into agreements (collectively, the Decontracting Plan)
that restructured the Company's Canadian gas supply arrangements. The
Decontracting Plan, which became effective November 1, 1993, terminated A&S's
contracts with Canadian gas producers and settled all litigation and claims
arising from such contracts. The total amount of settlement payments paid to
Canadian gas producers pursuant to the Decontracting Plan was approximately
$210 million.
In July 1993, FERC approved a transition cost recovery mechanism (TCRM)
under which PGT will absorb 25% of approved transition costs, including
settlement payments incurred in connection with the termination of A&S's
contracts, with the remainder of such costs to be recovered from PGT's
shippers.
The Company incurred transition costs of $228 million, 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.
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<PAGE> 9
MANAGEMENT'S DISCUSSION AND ANALYSIS OF CONSOLIDATED
RESULTS OF OPERATIONS AND FINANCIAL CONDITION (continued)
PACIFIC GAS AND ELECTRIC COMPANY
Of these costs, the Company deferred $143 million (included in deferred
charges -- other) for future rate recovery. In addition, the Company recorded a
reserve of $31 million due to the uncertainty of A&S's ability to assign or
broker its remaining Canadian gas transportation capacity, as costs associated
with this capacity are not recoverable as transition costs under the TCRM.
Accordingly, the Company expensed $93 million in 1993 and a total of $23
million in prior years.
PGT and PG&E are seeking recovery of all transition costs eligible for
recovery under the TCRM other than the 25% of such costs to be absorbed by PGT.
While such transition costs are still subject to challenges at the FERC level
and the recovery of such costs paid by PG&E as a shipper of gas on PGT's
pipelines will depend on the recovery mechanism adopted by the CPUC, the
Company believes that it will ultimately recover the deferred transition
costs.
Transportation Commitments: As discussed in Note 2 of Notes to
Consolidated Financial Statements, PG&E has transportation commitments with
several interstate pipeline companies -- El Paso Natural Gas Company (El
Paso), PGT, and Transwestern Pipeline Company (Transwestern). PG&E's
compliance with regulatory changes has resulted in a decrease in the amount
of gas required to be purchased by PG&E and a related decrease in the need for
firm interstate transportation capacity. Accordingly, PG&E has retained
portions of this interstate capacity for its core customers and core
subscription customers (noncore customers choosing bundled service) and is
brokering or assigning the remaining capacity.
The CPUC has established a mechanism that will allow PG&E to recover
demand charges paid to El Paso and PGT in excess of the demand charges for the
capacity held for core and core subscription customers, reduced by any revenues
received from brokering such capacity, subject to a reasonableness review. With
respect to the capacity held by PG&E on Transwestern's pipelines, the CPUC has
ordered PG&E to exclude such demand charges from rates pending a reasonableness
review.
Gas Reasonableness Proceedings: The CPUC reviews the reasonableness of
the Company's gas operations on an annual basis. As part of this review, a CPUC
Administrative Law Judge (ALJ) recently issued proposed decisions on the
Company's Canadian gas procurement activities and gas inventory operations for
1988 through 1990, recommending disallowances totaling $53 million in gas costs
plus interest estimated at approximately $15 million. The ALJ's proposed
decisions are not binding and are subject to modification by the CPUC in the
final decisions. A final CPUC decision on the Company's Canadian gas
procurement activities during 1988 through 1990 is expected in the first
quarter of 1994. In reaching this outcome, the ALJ found that the disallowances
of up to $670 million which had been recommended by the CPUC's Division of
Ratepayer Advocates (DRA) and certain other parties overstated the magnitude of
gas cost savings which the Company could have achieved during 1988 through
1990.
The DRA has also contended that the Company overpaid for Canadian gas
by $105 million and $61 million in 1991 and 1992, respectively. It is possible
that similar issues will be raised regarding the Company's Canadian gas
procurement activities during 1993. In addition, the DRA recommended
disallowances of $11 million and $31 million for 1991 and 1992, respectively,
relating to gas inventory operations and Southwest gas issues.
The DRA also issued a report on its investigation of the operations of
A&S and the Company's former affiliate, ANG, recommending a penalty and
disallowance of $50 million and $6 million, respectively, for 1988 through
1991. The investigation was initiated in connection with the reasonableness
proceeding for 1991. The recommended penalty and disallowance are primarily
related to the Company's alleged failure to properly oversee its subsidiaries'
activities. In addition, recommendations related to 1992 activities may be made
in a subsequent report.
The Company believes that its gas procurement activities,
transportation arrangements and operations were prudent and will vigorously
contest the disallowances and penalty proposed by the DRA or other parties.
However, based on its
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<PAGE> 10
current assessment of the matter, the Company recorded a reserve of $61
million in 1993 for any disallowance that may be ordered by the CPUC in the gas
reasonableness proceedings. The Company currently is unable to estimate the
ultimate outcome of the gas reasonableness proceedings or predict whether such
outcome will have a significant adverse impact on its financial position or
results of operations. (See Note 2 of Notes to Consolidated Financial
Statements for further discussion of gas reasonableness proceedings.)
PGT-PG&E Pipeline Expansion Project: In November 1993, the Company placed in
service an expansion of its natural gas transmission system from the Canadian
border into California. At December 31, 1993 and 1992, the Company's total
investment in the expansion project was approximately $1,587 million (included
in plant in service) and $979 million (included in construction work in
progress), respectively. The $1,587 million at December 31, 1993, consisted of
$767 million for the facilities within California (i.e., intrastate portion)
and $820 million for the facilities outside California (i.e., interstate
portion).
In February 1994, the CPUC announced a decision on the Company's
request for an increase in the California portion of the expansion project's
cost cap and its interim rate filing. The CPUC granted the Company's request to
increase the cost cap to $849 million but set interim rates based on $736
million, subject to an adjustment based on 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
expansion project. The CPUC rejected the assignment of costs related to unused
capacity on other pipelines (or the Company's intrastate facilities) to the
expansion project as previously recommended by an ALJ's proposed decision.
Due to the ratemaking treatment adopted by the CPUC for the California
portion of the expansion project, the Company's ability to recover its cost of
service rates is contingent upon demand and competitive market pricing for gas
transportation services. In light of anticipated demand and pricing in the
foreseeable future, the Company has determined that it may not bill its
customers to recover its full cost of service (including a return on
investment). Consequently, application of SFAS No. 71 was discontinued for the
California portion of the expansion project during 1993. This accounting change
did not have a significant impact on the Company's financial position or
results of operations in 1993.
Based upon the current status of the rate case and market demand, the
Company believes it will recover its investment in the expansion project.
However, due to the ratemaking adopted by the CPUC and the discontinued
application of SFAS No. 71, earnings attributable to the California portion of
the expansion project will vary with demand and market pricing. (See the
PGT-PG&E Pipeline Expansion Project section of Note 2 of Notes to Consolidated
Financial Statements for further discussion.)
LEGAL MATTERS: Antitrust Litigation: In December 1993, the County of
Stanislaus, California, and a residential customer of PG&E, filed a complaint
against PG&E and PGT on behalf of themselves and purportedly as a class action
on behalf of all natural gas customers of PG&E, for the period of February 1988
through October 1993. The complaint alleges that the purchase of natural gas in
Canada by A&S was accomplished in violation of various antitrust laws which
resulted in increased prices of natural gas for PG&E's customers.
The complaint alleges that the Company could have purchased as much as
50% of its 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. 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 also seeks recovery
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF CONSOLIDATED RESULTS OF
OPERATIONS AND FINANCIAL CONDITION (continued)
PACIFIC GAS AND ELECTRIC COMPANY
of three times the amount of the actual damages pursuant to
antitrust laws.
The Company believes the case is without merit and has filed a motion
to dismiss the complaint. The Company believes that the ultimate outcome of the
antitrust litigation will not have a significant adverse impact on its
financial position.
Hinkley Litigation: In 1993, a complaint was filed 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, as well as
punitive damages.
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 control board, the Company will continue
to monitor the affected area and perform environmental assessments.
In November 1993, the parties engaged in private mediation sessions. In
December 1993, the plaintiffs filed an offer to compromise and settle their
claims against the Company for $250 million.
The Company is unable to estimate the ultimate outcome of this matter,
but such outcome could have a significant adverse impact on the Company's
results of operations. The Company believes that the ultimate outcome of this
matter will not have a significant adverse impact on its financial position.
(See Note 11 of Notes to Consolidated Financial Statements for further
discussion.)
ACCOUNTING PRINCIPLES: Postretirement Benefits Other Than Pensions:
SFAS No. 106 established new financial accounting standards which the Company
adopted effective January 1, 1993. Due to current regulatory treatment,
adoption of SFAS No. 106 did not have a significant impact on the Company's
financial position or results of operations.
In 1993, the Company implemented a plan change that will limit the
amount it will contribute toward postretirement medical benefits. This
limitation, which will take effect for all retirees beginning in 2001, reduces
the estimated future annual SFAS No. 106 medical cost by approximately $70
million and the accumulated postretirement obligation for these benefits at
July 1, 1993, by approximately $450 million. Due to current regulatory
treatment, the limitation did not have a significant impact on the Company's
financial position or results of operations. (See Note 7 of Notes to
Consolidated Financial Statements for further discussion of postretirement
benefits other than pensions.)
Income Taxes: SFAS No. 109 established new financial accounting
standards which the Company adopted January 1, 1993. Due to current regulatory
treatment, adoption of SFAS No. 109 did not have a significant impact on the
Company's results of operations. Adoption of SFAS No. 109 resulted in an
increase of $1.8 billion in consolidated liabilities as of January 1, 1993, 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
$.3 billion increase in net plant in service. (See Note 9 of Notes to
Consolidated Financial Statements for further discussion of income taxes.)
Postemployment Benefits: SFAS No. 112, "Employers' Accounting for
Postemployment Benefits," 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. Due to current
regulatory treatment, adoption of SFAS No. 112 in 1994 is not expected to have
a significant impact on the Company's financial position or results of
operations. (See Note 7 of Notes to Consolidated Financial Statements for
further discussion of postemployment benefits.)
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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. As part of its focus on cost reduction, the Company
will further reduce financing costs in 1994 by refinancing existing debt and
preferred stock with lower-cost issuances.
CPUC Authorized Cost of Capital: In December 1993, the CPUC issued its
decision in the Company's 1994 cost of capital proceeding authorizing a utility
capital structure and cost as follows:
<TABLE>
<CAPTION>
Utility
Capital Weighted
Structure Cost Cost
--------- ----- --------
<S> <C> <C> <C>
Common equity 47.50% 11.00% 5.22%
Preferred stock 5.50 8.15 .45
Long-term debt 47.00 7.53 3.54
----- ----- ----
Total authorized return on
average utility rate base 9.21%
====
</TABLE>
The authorized return on common equity is a decrease from the 11.90%
authorized for 1993. Average utility rate base is projected to be $12.5 billion
for 1994.
Debt: In 1993, the Company issued $2,950 million of First and Refunding
Mortgage Bonds (series 93A through 93H), $260 million of pollution control
revenue bonds and $750 million of medium-term notes. Substantially all the
proceeds were used to redeem or repurchase $3,536 million of higher-cost
mortgage bonds to accomplish a reduction in financing costs. In December 1993,
the Board of Directors (Board) authorized the Company to redeem or repurchase
up to $1.2 billion of mortgage bonds, and $125 million of medium-term notes
to further reduce financing costs.
The Company issues short-term debt (principally commercial paper) to
fund fuel oil, nuclear fuel and gas inventories, and unrecovered balances in
balancing accounts. The Company uses external financing when balancing account
revenues are undercollected, as in 1993 and 1992, until the revenues, plus
interest, are recovered in rates. Short-term debt also has helped fund
construction and fluctuations in general working capital. At December 31, 1993,
the Company had a $1 billion short-term credit facility, with no borrowings
outstanding.
In 1993, PGT finalized a new loan agreement for $710 million. Proceeds
were used to finance PGT's portion of the PGT-PG&E Pipeline Expansion Project
and to refinance PGT's existing borrowings. As of December 31, 1993, there was
$648 million outstanding under this agreement. (See Notes 5 and 6 of Notes to
Consolidated Financial Statements for further discussion of long- and short-term
debt.)
Equity: In 1993, the Company received $264 million in proceeds from the
sale of common stock under the employee Savings Fund Plan, the Dividend
Reinvestment Plan and the employee Long-term Incentive Program. Proceeds were
used for capital expenditures and other general corporate purposes.
In 1993, the 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 in an effort to reduce financing
costs. In December 1993, the Board authorized the Company to redeem or
repurchase an additional $175 million of preferred stock. (See Note 4 of Notes
to Consolidated Financial Statements for further discussion of preferred stock.)
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 over the next three years. This
program will be 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, 1993, the Company had repurchased $258 million
of its common stock under this program.
23
<PAGE> 13
MANAGEMENT'S DISCUSSION AND ANALYSIS OF CONSOLIDATED RESULTS OF OPERATIONS AND
FINANCIAL CONDITION (continued)
PACIFIC GAS AND ELECTRIC COMPANY
CAPITAL REQUIREMENTS: The Company's three-year projection of capital
requirements is shown below:
<TABLE>
<CAPTION>
Year ended December 31,
------------------------------
1994 1995 1996
------ ------ ------
(in millions)
<S> <C> <C> <C>
Utility $1,397 $1,319 $1,369
Diablo Canyon 105 87 82
Enterprises 227 149 137
------ ------ ------
Total capital expenditures 1,729 1,555 1,588
Maturing debt and sinking funds 221 514 460
------ ------ ------
Total capital requirements $1,950 $2,069 $2,048
====== ====== ======
</TABLE>
The above projection of capital requirements has been reduced from last
year's projection to reflect the anticipated reduction in new customer
connections and the Company's ongoing cost control efforts. Utility and Diablo
Canyon expenditures will be primarily for replacing and enhancing the Company's
facilities to improve their efficiency and reliability, to extend their useful
lives and to comply with environmental laws and regulations.
Enterprises' actual capital expenditures may vary significantly
depending on the availability of attractive investment opportunities. Projected
expenditures include oil and gas exploration and development costs for 1994 and
Enterprises' equity share of generating facility projects for 1994 through
1996.
In addition to these capital requirements, the Company has other
commitments as discussed in Notes 2 and 10 of Notes to Consolidated Financial
Statements.
ENVIRONMENTAL MATTERS: The Company is subject to a number of laws and
regulations designed to protect human health and the environment by imposing
stringent controls with regard to planning and construction activities, land
use, air and water pollution and hazardous materials and waste management
activities. These laws and regulations affect future planning and existing
operations, including environmental protection and remediation activities.
ENVIRONMENTAL PROTECTION MEASURES: 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 $50 million, $50 million and $75 million for 1994, 1995 and 1996,
respectively, and are included in the Company's three-year projection table in
the above Capital Requirements section. Expenditures during these years will
be primarily for nitrogen oxide (NOx) emission reduction projects. The Company
currently estimates that compliance with NOx rules could require capital
expenditures ranging from $300 million to $500 million to achieve NOx
emission reductions over a period of approximately ten years. The Company's
environmental protection capital expenditures are generally recovered
through rates.
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. Although the ultimate amount of costs that will be incurred by the
Company in connection with its compliance and remediation activities are
difficult to estimate 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, the Company
has an accrued liability as of December 31, 1993, of $60 million for hazardous
waste remediation costs. (See further discussion of the accrued liability for
hazardous waste remediation costs and the related deferred charge in Note 11 of
Notes to Consolidated Financial Statements.)
SALES AND ACQUISITION: In January 1994, the Company approved a final
plan for the disposition of Resources in 1994 if market conditions remain
favorable. As of December 31, 1993, Resources had assets of approximately $680
million.
In June 1992, PGT sold its 49.98% interest in ANG for $97 million. The
sale resulted in an after-tax gain of $19 million.
In December 1991, Resources purchased Tex/Con, an oil and gas
exploration and production company, for $389 million.
24
<PAGE> 14
STATEMENT OF CONSOLIDATED INCOME
PACIFIC GAS AND ELECTRIC COMPANY
<TABLE>
<CAPTION>
Year ended December 31,
------------------------------------------
1993 1992 1991
----------- ----------- ----------
(in thousands, except per share amounts)
<S> <C> <C> <C>
Operating Revenues
Electric $ 7,866,043 $ 7,747,492 $7,368,640
Gas 2,716,365 2,548,596 2,409,479
----------- ---------- ----------
Total operating revenues 10,582,408 10,296,088 9,778,119
----------- ---------- ----------
Operating Expenses
Cost of electric energy 2,250,209 2,416,554 2,318,179
Cost of gas 1,092,055 1,062,879 960,208
Distribution 226,975 219,082 208,881
Transmission 166,539 184,165 195,642
Customer accounts and services 403,560 421,990 372,088
Maintenance 442,939 484,751 525,220
Depreciation and decommissioning 1,315,524 1,221,490 1,140,877
Administrative and general 1,041,453 927,316 875,878
Workforce reduction costs 190,200 - -
Income taxes 1,006,774 906,845 863,089
Property and other taxes 297,495 295,164 288,610
Other 385,755 322,411 316,368
----------- ---------- ----------
Total operating expenses 8,819,478 8,462,647 8,065,040
----------- ---------- ----------
Operating Income 1,762,930 1,833,441 1,713,079
----------- ---------- ----------
Other Income and (Income Deductions)
Interest income 85,642 87,244 94,161
Allowance for equity funds used
during construction 41,531 39,368 24,543
Other -- net (53,524) (3,006) (23,909)
----------- ---------- ----------
Total other income and
(income deductions) 73,649 123,606 94,795
----------- ---------- ----------
Income Before Interest Expense 1,836,579 1,957,047 1,807,874
----------- ---------- ----------
Interest Expense
Interest on long-term debt 731,610 739,279 697,185
Other interest charges 118,100 91,404 101,871
Allowance for borrowed funds
used during construction (78,626) (44,217) (17,574)
----------- ---------- ----------
Net interest expense 771,084 786,466 781,482
----------- ---------- ----------
Net Income 1,065,495 1,170,581 1,026,392
Preferred dividend requirement 63,812 78,887 89,595
----------- ---------- ----------
Earnings Available for
Common Stock $ 1,001,683 $1,091,694 $ 936,797
=========== ========== ==========
Weighted Average Common
Shares Outstanding 430,625 422,714 417,965
Earnings Per Common Share $2.33 $2.58 $2.24
Dividends Declared Per Common Share $1.88 $1.76 $1.64
</TABLE>
The accompanying Notes to Consolidated Financial Statements are an
integral part of this statement.
25
<PAGE> 15
CONSOLIDATED BALANCE SHEET
PACIFIC GAS AND ELECTRIC COMPANY
<TABLE>
<CAPTION>
December 31,
-----------------------------
1993 1992
------------ -----------
(in thousands)
<S> <C> <C>
A S S E T S
Plant In Service
Electric
Nonnuclear $ 16,633,772 $ 16,295,567
Diablo Canyon 6,518,413 5,983,976
Gas 7,146,741 5,454,084
------------ ------------
Total plant in service (at original cost) 30,298,926 27,733,627
Accumulated depreciation and decommissioning (11,235,519) (10,507,560)
------------ ------------
Net plant in service 19,063,407 17,226,067
------------ ------------
Construction Work in Progress 620,187 1,534,578
Other Noncurrent Assets
Oil and gas properties 573,523 591,544
Decommissioning and other funds held
by trustees 536,544 456,061
Other assets 497,689 402,041
------------ ------------
Total other noncurrent assets 1,607,756 1,449,646
------------ ------------
Current Assets
Cash and cash equivalents 61,066 97,592
Accounts receivable
Customers 1,264,907 1,319,285
Other 123,255 133,826
Allowance for uncollectible accounts (23,647) (23,806)
Regulatory balancing accounts receivable 992,477 743,253
Inventories
Materials and supplies 239,856 234,630
Gas stored underground 170,345 151,707
Fuel oil 109,615 155,816
Nuclear fuel 134,411 135,171
Prepayments 56,062 47,809
------------ ------------
Total current assets 3,128,347 2,995,283
------------ ------------
Deferred Charges
Income tax-related deferred charges 1,246,890 -
Diablo Canyon costs 419,775 260,042
Unamortized loss net of gain on reacquired debt 395,659 289,338
Workers' compensation and disability
claims recoverable 192,203 174,168
Other 488,302 259,037
------------ ------------
Total deferred charges 2,742,829 982,585
------------ ------------
Total Assets $ 27,162,526 $ 24,188,159
============ ============
</TABLE>
The accompanying Notes to Consolidated Financial Statements are an integral part
of this statement.
26
<PAGE> 16
CONSOLIDATED BALANCE SHEET
PACIFIC GAS AND ELECTRIC COMPANY
CAPITALIZATION AND LIABILITIES
<TABLE>
<CAPTION>
December 31,
---------------------------
1993 1992
----------- -----------
(in thousands)
<S> <C> <C>
Capitalization
Common stock $ 2,136,095 $ 2,134,228
Additional paid-in capital 3,666,455 3,517,062
Reinvested earnings 2,643,487 2,631,847
----------- -----------
Total common stock equity 8,446,037 8,283,137
Preferred stock without mandatory
redemption provision 807,995 790,791
Preferred stock with mandatory
redemption provision 75,000 146,888
Long-term debt 9,292,100 8,379,060
----------- -----------
Total capitalization 18,621,132 17,599,876
----------- -----------
Other Noncurrent Liabilities
Customer advances for construction 152,872 175,451
Workers' compensation and disability claims 157,000 139,000
Other 246,950 172,607
----------- -----------
Total other noncurrent liabilities 556,822 487,058
----------- -----------
Current Liabilities
Short-term borrowings 764,163 1,131,124
Long-term debt 221,416 353,692
Accounts payable
Trade creditors 472,985 529,315
Other 389,065 372,157
Accrued taxes 303,575 237,305
Deferred income taxes 315,584 326,219
Interest payable 82,105 87,975
Dividends payable 203,923 187,721
Other 487,809 377,186
----------- -----------
Total current liabilities 3,240,625 3,602,694
----------- -----------
Deferred Credits
Deferred income taxes 3,978,950 1,780,769
Deferred investment tax credits 410,969 473,879
Other 354,028 243,883
----------- -----------
Total deferred credits 4,743,947 2,498,531
----------- -----------
Commitments and Contingencies
(Notes 2, 10 and 11)
Total Capitalization and Liabilities $27,162,526 $24,188,159
=========== ===========
</TABLE>
27
<PAGE> 17
STATEMENT OF CONSOLIDATED CASH FLOWS
PACIFIC GAS AND ELECTRIC COMPANY
<TABLE>
<CAPTION>
Year ended December 31,
--------------------------------------------------------
1993 1992 1991
----------- ----------- -----------
(in thousands)
<S> <C> <C> <C>
Cash Flows From Operating Activities $ 1,065,495 $ 1,170,581 $ 1,026,392
Net income
Adjustments to reconcile net income to net cash
provided by operating activities
Depreciation and decommissioning 1,315,524 1,221,490 1,140,877
Amortization 135,808 121,795 103,923
Gain on sale of investment in Alberta Natural
Gas Company Ltd - (48,722) -
Deferred income taxes and investment tax
credits -- net 319,198 164,457 60,376
Allowance for equity funds used during
construction (41,531) (39,368) (24,543)
Net effect of changes in operating assets
and liabilities
Accounts receivable 64,790 39,922 (69,076)
Regulatory balancing accounts receivable (218,553) (215,195) 202,401
Inventories 23,097 (7,161) (7,440)
Accounts payable (39,422) (102,559) 172,245
Accrued taxes 44,638 128,243 35,977
Other working capital 108,873 (36,117) 36,784
Other deferred charges (158,725) 8,147 (68,905)
Other noncurrent liabilities 50,279 31,374 75,889
Other deferred credits 110,145 73,259 9,795
Other -- net 13,184 49,891 30,382
----------- ----------- -----------
Net cash provided by operating activities 2,792,800 2,560,037 2,725,077
----------- ----------- -----------
Cash Flows From Investing Activities
Construction expenditures (1,763,024) (2,307,318) (1,753,609)
Allowance for borrowed funds used during
construction (78,626) (44,217) (17,574)
Purchase of subsidiary - - (388,662)
Nonregulated expenditures (234,221) (148,226) (117,847)
Proceeds from sale of investment in Alberta
Natural Gas Company Ltd - 97,251 -
Other -- net 9,992 82,352 33,156
----------- ----------- -----------
Net cash used by investing activities (2,065,879) (2,320,158) (2,244,536)
----------- ----------- -----------
Cash Flows From Financing Activities
Common stock issued 264,489 296,653 271,482
Common stock repurchased (257,780) (5,410) (337,969)
Preferred stock issued 200,001 195,451 -
Preferred stock redeemed (302,640) (276,806) (123,667)
Long-term debt issued 4,584,548 1,676,513 738,649
Long-term debt matured or reacquired (4,002,704) (1,409,337) (263,220)
Short-term debt issued (redeemed) -- net (366,961) 121,213 (14,278)
Dividends paid (857,515) (809,108) (765,543)
Other -- net (24,885) (28,736) 10,075
----------- ----------- -----------
Net cash used by financing activities (763,447) (239,567) (484,468)
----------- ----------- -----------
Net Change in Cash and Cash Equivalents (36,526) 312 (3,927)
Cash and Cash Equivalents at January 1 97,592 97,280 101,207
----------- ----------- -----------
Cash and Cash Equivalents at December 31 $ 61,066 $ 97,592 $ 97,280
=========== =========== ===========
Supplemental disclosures of cash flow information
Cash paid for
Interest (net of amounts capitalized) $ 642,712 $ 694,512 $ 723,968
Income taxes 542,827 682,809 768,097
</TABLE>
The accompanying Notes to Consolidated Financial Statements are
an integral part of this statement.
28
<PAGE> 18
<TABLE>
<CAPTION>
STATEMENT OF CONSOLIDATED COMMON STOCK EQUITY AND PREFERRED STOCK
PACIFIC GAS AND ELECTRIC COMPANY
Preferred
Stock
Total Without
Additional Common Mandatory
Common Paid-in Reinvested Stock Redemption
Stock Capital Earnings Equity Provision Provision(1)
---------- ---------- ---------- ----------- ---------- ------------
(in thousands, except shares)
<S> <C> <C> <C> <C> <C> <C>
Balance December 31, 1990 $2,101,095 $3,170,890 $2,234,227 $7,506,212 $ 983,961 $129,510
---------- ---------- ---------- ---------- --------- --------
Net income - 1991 1,026,392 1,026,392
Common stock issued (10,263,302 shares) 51,317 220,165 271,482
Common stock repurchased (12,910,487 shares) (64,553) (98,455) (174,961) (337,969)
Preferred stock redeemed (3,811,325 shares) (5,287) (4,438) (9,725) (89,064) (24,878)
Cash dividends declared
Preferred stock (91,501) (91,501)
Common stock (685,341) (685,341)
Other 1,774 1,774
---------- ---------- ---------- ---------- --------- --------
Net change (13,236) 116,423 71,925 175,112 (89,064) (24,878)
---------- ---------- ---------- ---------- --------- --------
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
========== ========== ========== ========== ========= ========
(1) Includes current portion.
The accompanying Notes to Consolidated Financial Statements are an integral part of this statement.
</TABLE>
29
<PAGE> 19
STATEMENT OF CONSOLIDATED CAPITALIZATION
PACIFIC GAS AND ELECTRIC COMPANY
<TABLE>
<CAPTION>
December 31,
-------------------------------
1993 1992
------------- ------------
(dollars in thousands,
except per share amounts)
<S> <C> <C>
Common Stock Equity
Common stock, par value $5 per share
(authorized 800,000,000 shares, issued
and outstanding 427,219,205 and 426,845,569) $ 2,136,095 $ 2,134,228
Additional paid-in capital 3,666,455 3,517,062
Reinvested earnings 2,643,487 2,631,847
----------- -----------
Total common stock equity 8,446,037 8,283,137
----------- -----------
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% -- 26,534,958 and 18,534,959 shares outstanding 663,374 463,373
9% to 10.28% -- 0 and 7,311,868 shares outstanding -- 182,797
----------- -----------
Total preferred stock without mandatory
redemption provision 807,995 790,791
----------- -----------
Preferred stock with mandatory redemption provision
Par value $25 per share(1)
6.57% -- 3,000,000 shares outstanding 75,000 75,000
Par value $100 per share
(authorized 10,000,000 shares)
9% and 10.17% -- 0 and 845,100 shares outstanding -- 84,510
----------- -----------
Total preferred stock with mandatory
redemption provision 75,000 159,510
Less preferred stock with mandatory redemption
provision--current portion -- 12,622
----------- -----------
Preferred stock with mandatory redemption
provision in total capitalization 75,000 146,888
----------- -----------
Preferred stock in total capitalization 882,995 937,679
----------- -----------
Long-Term Debt
Pacific Gas and Electric Company (PG&E)
First and refunding mortgage bonds
Maturity Interest rates
1993-1998 4.25% to 13% 577,931 1,034,214
1999-2005 5.5% to 9.375% 1,886,328 1,840,611
2006-2012 6.25% to 10.07% 477,870 852,870
2013-2019 7.5% to 12.75% 140,900 852,196
2020-2026 5.85% to 9.95% 2,947,428 2,044,950
----------- -----------
Principal amounts outstanding 6,030,457 6,624,841
Unamortized discount net of premium (71,817) (103,707)
----------- -----------
Total mortgage bonds 5,958,640 6,521,134
Unsecured debentures, 10.81% to 12%, due 1994-2000 221,523 221,523
Pollution control loan agreements, variable rates,
due 2008-2016 925,000 925,000
Unsecured medium-term notes, 4.13% to 10.1%,
due 1993-2013 1,542,625 847,361
Unamortized discount related to unsecured
medium-term notes (3,459) (3,289)
Other long-term debt 24,127 26,056
----------- -----------
Total PG&E long-term debt 8,668,456 8,537,785
Long-term debt of subsidiaries 845,060 194,967
----------- -----------
Total long-term debt of PG&E and subsidiaries 9,513,516 8,732,752
Less long-term debt -- current portion 221,416 353,692
----------- -----------
Long-term debt in total capitalization 9,292,100 8,379,060
----------- -----------
Total Capitalization $18,621,132 $17,599,876
=========== ===========
</TABLE>
(1) Authorized 75,000,000 shares in total (both with and without mandatory
redemption provision).
The accompanying Notes to Consolidated Financial Statements are an integral
part of this statement.
30
<PAGE> 20
SCHEDULE OF CONSOLIDATED SEGMENT INFORMATION
PACIFIC GAS AND ELECTRIC COMPANY
<TABLE>
<CAPTION>
Diversified Intersegment
Electric Gas Operations(4) Eliminations Total
----------- ---------- ------------- ------------ ------------
(in thousands)
<S> <C> <C> <C> <C> <C>
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 year end $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 year end $24,188,159
=========== ========== ========== ========= ===========
1991
Operating revenues $ 7,368,640 $2,341,054 $ 68,425 $ - $ 9,778,119
Intersegment revenues(1) 15,043 541,963 39,958 (596,964) -
----------- ---------- ---------- --------- -----------
Total operating revenues $ 7,383,683 $2,883,017 $ 108,383 $(596,964) $ 9,778,119
=========== ========== ========== ========= ===========
Depreciation and decommissioning $ 843,768 $ 214,488 $ 82,621 $ - $ 1,140,877
Operating income before income taxes(2) 2,271,571 336,754 (31,227) (930) 2,576,168
Construction expenditures(3) 1,192,570 603,156 - - 1,795,726
Identifiable assets(3) $17,253,156 $4,212,764 $ 469,222 $ - $21,935,142
Corporate assets 965,528
----------- ---------- ---------- --------- -----------
Total assets at year end $22,900,670
=========== ========== ========== ========= ===========
</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 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 schedule.
31
<PAGE> 21
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
PACIFIC GAS AND ELECTRIC COMPANY
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 (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 PG&E at the California border; Alberta and Southern Gas Co. Ltd.
(A&S) -- prior to November 1, 1993, bought gas in Canada and arranged transport
to the U.S. border (see Note 2 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 PG&E Resources
Company (Resources), which engages in exploration, development and production
of oil and natural gas, and PG&E Generating Company which develops independent
power projects.
Alberta Natural Gas Company Ltd (ANG), a 49.98%-owned affiliate of PGT,
was sold in June 1992. ANG, a Canadian pipeline company, transported natural
gas for A&S to the U.S. border. 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 deliveries 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 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 actual costs of gas and
electric energy and the revenue 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 2 for further discussion of
gas costs.) These balancing accounts are recorded to the extent that future
rate recovery from customers, or refunds to customers, are probable.
PLANT IN SERVICE: The costs of plant additions, including replacements of
retired plant, are capitalized. Costs include labor, materials, construction
overheads 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 and the
California portion of the PGT-PG&E Pipeline Expansion Project are calculated
under Statement of Financial Accounting Standards (SFAS) No. 34,
"Capitalization of Interest Cost," since Diablo Canyon and the California
portion of the PGT-PG&E Pipeline Expansion Project are not on traditional
cost-based ratemaking. (See Notes 2 and 3 for further discussion of these
matters.) These costs are included in allowance for borrowed funds used during
construction. The original cost of retired plant plus removal costs less
salvage are charged to accumulated depreciation. Maintenance, repairs and minor
replacements and additions are charged to maintenance expense.
DEPRECIATION AND DECOMMISSIONING: 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 year
ended December 31, 1993, 1992 and 1991, the amounts recovered in rates for
decommissioning costs were $54 million, $54 million, and $65 million,
respectively. The estimated total obligation for decommissioning costs is
approximately $1 billion in 1993 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, 1993 and 1992, the Company had accumulated in
external trust funds $537 million and $456 million, respectively, to be used
for the decommissioning of the Company's nuclear facilities; corresponding
amounts are thus included in accumulated depreciation and decommissioning.
These trust funds maintain substantially all of their investments in debt
securities. All fund earnings are reinvested. At December 31, 1993 and 1992,
the estimated fair
32
<PAGE> 22
values of the external trust funds were approximately $576 million and
$475 million, respectively, based on quoted market prices. Funds may not be
released from the external trust funds until authorized by the CPUC.
As required by federal law, the U.S. Department of Energy (DOE)
is responsible for the future storage and disposal of spent nuclear fuel. The
cost of these activities is funded through a one-tenth of one cent fee on each
kilowatthour (kWh) sold by all nuclear power plants. This fee is paid quarterly
to the DOE.
INCOME TAXES: The Company files a consolidated federal income tax return that
includes domestic subsidiaries in which its ownership is 80% or more. Income
tax expense includes the current and deferred income tax expense 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 the
currently enacted income tax rates. Temporary differences are measured at the
balance sheet date, resulting in adjustments to the deferred tax liability and
related deferred charge, consistent with the ratemaking process.
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 the 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 $.3 billion
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. These differences
included removal costs and federal tax depreciation on property acquired prior
to 1981, depreciation differences for state purposes, percentage repair
allowances expensed for tax purposes and certain capitalized overheads expensed
for tax purposes. Due to current regulatory treatment, the adoption of SFAS No.
109 did not have a significant impact on the Company's results of operations.
During 1993, the Omnibus Budget Reconciliation Act of 1993 (Act) was
enacted, which included an increase in the corporate federal income tax rate to
35% from 34%. Due to current regulatory treatment, the Company recorded a
deferred charge for the adjustment of deferred income taxes related to utility
operations as a result of this increase. Since Diablo Canyon is not on
traditional cost-based ratemaking, a one-time adjustment to income tax expense
of $32 million resulted. The Act did not have a significant impact on the
Company's results of operations during 1993.
DEBT PREMIUM, DISCOUNT AND RELATED EXPENSE: Long-term debt premium,
discount and related expense 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 PGT- PG&E Pipeline Expansion Project are recognized in income at the
time such debt is reacquired.
OIL AND GAS PROPERTIES: Resources 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 (at
cost which approximates market) include special deposits, working funds and
short-term investments with original maturities of three months or less.
RECLASSIFICATIONS: Prior years' amounts in the consolidated financial
statements have been reclassified where necessary to conform to the 1993
presentation.
NOTE 2 -- Natural Gas Matters
- -----------------------------
REGULATORY RESTRUCTURING: The CPUC has established a regulatory
framework for natural gas service in California which segments customers into
core (residential and smaller commercial customers) and noncore (industrial and
commercial customers that exceed certain size limitations) classes. This
framework allows noncore customers to
33
<PAGE> 23
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
PACIFIC GAS AND ELECTRIC COMPANY
purchase gas directly from producers, aggregators or marketers and
separately negotiate gas transportation with their utilities. The CPUC has also
adopted a capacity brokering program which allows noncore customers and other
shippers to obtain rights to firm interstate pipeline transportation capacity
held by the local gas distribution utilities. Under the capacity brokering
program implemented August 1, 1993, the Company is required to make available
for brokering all interstate pipeline capacity which is not retained for its
core customers and core subscription customers (noncore customers choosing
bundled service). Noncore customers, producers, aggregators, marketers and the
Company's electric department can bid for such capacity.
In addition, in April 1992, FERC issued Order 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 has allowed many of the
Company's noncore customers to arrange for the purchase and transportation of
their own gas supplies. These changes have resulted in a decrease in the amount
of gas required to be purchased by the Company and a related decrease in the
need for firm transportation capacity and have contributed to the need to
restructure the Company's 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 minimum quantities of natural gas from approximately
190 Canadian gas producers under various long-term contracts, most of which
extended through 2005. Certain of these Canadian gas producers filed lawsuits
against the Company claiming damages of at least $466 million (Canadian)
resulting from the alleged failure of A&S to meet its minimum contractual gas
purchase obligations. 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 and settled all litigation and
claims arising from such contracts. Under the Decontracting Plan which became
effective November 1, 1993, producers' contracts with A&S, the sales agreement
between A&S and PGT, and PG&E's service agreement with PGT were terminated,
allowing producers to decontract their reserves from the A&S supply pool. As a
result, PG&E may contract on an individual basis for its gas supply
requirements directly with any producer, aggregator or marketer, whether or not
they were formerly in the A&S supply pool.
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 claims for losses arising from alleged historical
shortfalls in gas taken by A&S. The total amount of settlement payments paid to
producers was approximately $210 million.
As part of the overall A&S decontracting process, A&S's operations have
been significantly reduced, with a major aggregator of Canadian natural gas
acquiring A&S's restructured gas purchase contracts and remaining sales
contracts. A&S continues to hold gas transportation capacity on Canadian
pipelines and is in the process of permanently assigning or brokering such
capacity.
As part of the Decontracting Plan, A&S permanently assigned portions of
its commitments for transportation capacity with NOVA Corporation of Alberta
(NOVA) through October 2001 and ANG through October 2005 to third parties. A&S
also 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. A&S currently holds the remaining capacity of
approximately 450 MMcf/d with annual demand charges of approximately $25
million for which it is continuing its efforts to assign or broker. There is
uncertainty about the ability of A&S to assign or broker this remaining
capacity. To the extent others do not take this capacity, A&S will remain
obligated to pay for the related demand charges.
In July 1993, FERC approved a transition cost recovery mechanism (TCEM)
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. The TCRM precludes most objections to the eligibility and
prudence of such costs; prudence challenges may be made only on the grounds
that the payment is unreasonably high in light of the damages claimed.
Disposition of approved transition costs will be as follows: (1) 25% of such
costs will be absorbed by PGT; (2) 25% will be recovered by PGT through direct
bills (substantially all to PG&E as PGT's principal customer); and (3) 50% will
be 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.
34
<PAGE> 24
Financial Impact of Decontracting Plan and Litigation: The Company incurred
transition costs of $228 million, 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 (included in deferred charges -- other) for future rate
recovery. In addition, the Company recorded a reserve of $31 million due to the
uncertainty of A&S's ability to assign or broker its remaining commitments for
Canadian transportation capacity. Accordingly, the Company expensed $93 million
in 1993 and a total of $23 million in prior years.
PGT and PG&E are seeking recovery of all transition costs eligible for recovery
under the TCRM other than the 25% of such costs to be absorbed by PGT. While
such transition costs are still subject to challenges at the FERC level and the
recovery of such costs paid by PG&E as a shipper of gas on PGT's pipelines will
depend on the recovery mechanism adopted by the CPUC, the Company believes that
it will ultimately recover the deferred transition costs.
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 reduced to the
extent the Company can broker or 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 PGT) were approximately $280
million in 1993, $300 million in 1992 and $260 million in 1991.
As discussed above, regulatory changes have resulted in a decrease in
the amount of gas required to be purchased by the Company and a related
decrease in the need for firm transportation capacity. The Company has retained
portions of this capacity to be used for its core and core subscription
customers and has permanently assigned significant portions of the remaining
capacity. The following table summarizes the approximate amounts of capacity
held by the Company on various pipelines for its core and core subscription
customers and capacity remaining to be assigned or brokered as of December 31,
1993:
<TABLE>
<CAPTION>
Remaining Total
Amount Held Amount Available Annual Demand
Pipeline for Core for Brokering Charges Contract
Company (MMcf/d) (MMcf/d) (in millions) Expiration
- ------- ----------- ---------------- ------------- ----------
<S> <C> <C> <C> <C>
El Paso 610 530 $130 Dec. 1997
PGT 610 430 $ 50 Oct. 2005
Transwestern 50* 150 $ 30 Mar. 2007
NOVA 610 460 $ 35 Oct. 2001
ANG 600 440 $ 20 Oct. 2005
</TABLE>
* This amount is held by the Company's electric department for
electric power generation.
The Company expects to recover the demand charges associated with
capacity held for its core and core subscription customers through its gas
balancing account mechanisms. The CPUC has established a separate mechanism that
will allow PG&E to recover the demand charges paid to PGT and El Paso Natural
Gas Company (El Paso) in excess of the demand charges for the capacity held for
core and core subscription customers, reduced by revenues received from
brokering such capacity, subject to a reasonableness review. With respect to
Transwestern Pipeline Company (Transwestern) capacity, which the Company
contracted in order to provide supply diversity and reliability and to stimulate
price competition, the CPUC has ordered the Company to exclude such demand
charges from rates pending a reasonableness review.
The Company is continuing its efforts to broker or assign the remaining
transportation capacity that is not used. During the latter half of 1993, as
implementation of capacity brokering began on interstate pipelines -- El Paso,
PGT and Transwestern -- PG&E has been able to broker a significant portion of
the 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 been on a short-term basis, most of which were at a discounted
price. The average monthly demand charges associated with the Company's unused
interstate capacity have been approximately $10 million, of which the Company
has been able to recover approximately 50% through capacity brokering during the
past few months. Because the success of the Company's brokering efforts will
depend on market demand, the Company cannot predict the volume or the price of
the capacity that will be brokered in the future.
35
<PAGE> 25
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
PACIFIC GAS AND ELECTRIC COMPANY
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.
1988-1990: The CPUC consolidated its review of the reasonableness of gas
system costs for 1988 through 1990. A CPUC Administrative Law Judge (ALJ)
recently issued proposed decisions on the Company's Canadian gas procurement
activities and gas inventory operations during 1988 through 1990.
The proposed decision on the Company's Canadian gas procurement
activities finds that the Company's procurement practices were reasonable in
light of the events and circumstances then applicable, but that the Company was
imprudent to the extent that it failed to take reasonable steps to bargain more
aggressively with Canadian gas suppliers. The proposed decision recommends a
disallowance of approximately $46 million of gas costs plus accrued interest
estimated at approximately $15 million. The proposed decision also finds that
the disallowances recommended by the CPUC's Division of Ratepayer Advocates
(DRA) and an intervenor overstate the magnitude of savings which the Company
could have achieved during 1988 through 1990. The DRA had recommended that the
Company refund $392 million based on its contention that the Company should
have purchased 50% of its Canadian supplies on the spot market instead of
almost totally relying on long-term contracts. Using a different theory than
the DRA, an intervenor had asserted that the Company overpaid for Canadian gas
in the range of $540 million to $670 million.
In the proposed decision on gas inventory operations, the ALJ found the
Company's gas inventory operations in 1989 and 1990 to be reasonable except for
operations during December 1990 for which the ALJ proposed a disallowance of
$7 million. Earlier, the DRA recommended a disallowance of $37 million
contending that the Company should have withdrawn additional gas from storage
in the winter of 1989-1990 and December 1990 rather than burning fuel oil,
which was more expensive.
A final CPUC decision on the Company's Canadian gas procurement
activities is expected in the first quarter of 1994. CPUC consideration of
other issues which relate to purchased electric energy and certain contracts
with Southwestern gas producers has been deferred. Relating to purchased
electric energy costs, the DRA recommended a disallowance of $18 million
contending that had the Company purchased lower cost Canadian gas, the Company
would have realized a reduction in its electric energy costs. However, the DRA
has not yet addressed issues related to certain contracts with Southwestern gas
producers.
1991: The DRA has issued a report on the reasonableness of the Company's gas
procurement and operating activities for 1991. The DRA recommended that the
Company refund approximately $116 million, consisting of $105 million related
to Canadian gas purchases and $11 million related to gas inventory operations
and Southwest gas procurement issues. The DRA's recommendations are based on
the same theories outlined in the DRA's reports for 1988 through 1990, as
discussed above.
1992: The DRA issued a report on the reasonableness of the Company's
gas procurement and operating activities for 1992, recommending that the
Company refund approximately $92 million. The recommended disallowance includes
$61 million related to Canadian gas purchases and $8 million related to gas
inventory operations, based on the same theories outlined in prior DRA reports.
Also included are disallowances totaling $23 million related to Southwest gas
transportation and procurement issues. It is possible that similar issues will
be raised regarding the Company's Canadian gas procurement activities during
1993. However, the Company estimates the disallowance that the DRA may
recommend for 1993 should be significantly lower than those for prior years.
Affiliate Audit: The DRA issued a report on its investigation of the
operations of A&S and the Company's former affiliate, ANG, for 1988 through
1991. The investigation was initiated in connection with the reasonableness
proceeding for 1991. The DRA reviewed certain nongas costs, primarily Canadian
pipeline charges and A&S overhead costs, and recommended a penalty and
disallowance of $50 million and $6 million, respectively. The recommended
penalty and disallowance are primarily related to the Company's alleged failure
to properly oversee its subsidiaries' activities. In addition, recommendations
related to 1992 activities may be made in a subsequent report. The Company
filed a motion with the CPUC asking it to disregard the recommended penalty and
disallowance because prior federal rulings approved such costs and thus preempt
the issue. In December 1993, an ALJ denied this motion.
36
<PAGE> 26
Financial Impact of Gas Reasonableness Proceedings: The DRA is a consumer
advocacy branch of the CPUC staff. Neither the DRA's recommendations nor the
ALJ's proposed decisions constitute a CPUC decision. The CPUC can accept all,
part or none of the DRA's recommendations or the ALJ's proposed decisions. The
Company believes that its gas procurement activities, transportation
arrangements and operations were prudent and will vigorously contest the
disallowances and penalty proposed by the DRA or other parties. However, based
on its current assessment of the matter, the Company recorded a reserve of $61
million in 1993 for any disallowance that may be ordered by the CPUC in the
gas reasonableness proceedings. The Company currently is unable to estimate
the ultimate outcome of the gas reasonableness proceedings or predict whether
such outcome will have a significant adverse impact on its financial position
or results of operations.
PGT-PG&E PIPELINE EXPANSION PROJECT: 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 an additional 148 MMcf/d of firm
capacity to the Pacific Northwest and an additional 755 MMcf/d of firm capacity
to Northern and Southern California. At December 31, 1993 and 1992, the
Company's total investment in the expansion project was approximately $1,587
million (included in plant in service) and $979 million (included in
construction work in progress), respectively. The $1,587 million at December
31, 1993, consisted of $767 million for the facilities within California (i.e.,
intrastate portion) and $820 million for the facilities outside California
(i.e., interstate portion).
The construction of facilities within the state of California has been
certificated by the CPUC. The conditions of the certificate place the Company
at risk for its decision to construct based on its assessment of market demand
and subsequent underutilization of the facility. The certificate requires the
application of a "cross-over" ban under which volumes delivered from the
incremental interstate (PGT) expansion must be transported at an incremental
expansion rate within California. Incremental rate design is based on the
concept that expansion shippers, not existing ratepayers, bear the incremental
costs of the expansion project. Capacity on the interstate portion 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 intrastate capacity. The CPUC has authorized the
Company to provide as-available service on the expansion project, which would
provide additional revenues to recover the incremental costs of the expansion
project. The Company continues negotiations for the remaining capacity.
The CPUC certificate issued in December 1990 established a cost cap of
$736 million for the California portion, which 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. In October 1993, the CPUC issued a
decision granting the Company's motion to put in place temporary interim rates
based on the existing cost cap of $736 million. The decision authorized the
temporary interim rates to become effective on the date of commercial
operation, November 1, 1993, and remain in effect for five months or until
interim rates are established by the CPUC.
In February 1994, the CPUC announced a decision on the Company's
request for an increase in the California portion of the expansion project's
cost cap and its interim rate filing. The CPUC granted the Company's request to
increase the cost cap to $849 million but set interim rates based on $736
million, subject to an adjustment based on 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
expansion project. The CPUC rejected the assignment of costs related to unused
capacity on other pipelines (or the Company's intrastate facilities) to the
expansion project as previously recommended by an ALJ's proposed decision.
Due to the ratemaking treatment adopted by the CPUC for the California
portion of the expansion project, the Company's ability to recover its cost of
service rates is contingent upon demand and competitive market pricing for gas
transportation services. In light of anticipated demand and pricing in the
foreseeable future, the Company has determined that it may not bill its
customers to recover its full cost of service. Consequently, application of
SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation" was
discontinued for the California portion of the expansion project during 1993.
This accounting change was implemented using the guidelines contained in SFAS
No. 101, "Regulated Enterprises -- Accounting for the Discontinuation of
Application of FASB Statement No. 71" and did not have a significant impact on
the Company's financial position or results of operations in 1993.
Financial Impact of PGT-PG&E Pipeline Expansion Project: Based upon the current
status of the rate case and market demand, the Company believes it will recover
its investment in the expansion project.
37
<PAGE> 27
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
PACIFIC GAS AND ELECTRIC COMPANY
NOTE 3 -- DIABLO CANYON
- -----------------------
RATE CASE SETTLEMENT: The Diablo Canyon rate case settlement, effective
July 1988, 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 stated that it affirmed that Diablo Canyon
costs and operations should no longer be subject to CPUC reasonableness
reviews. The CPUC cannot bind future commissions in fixing just and reasonable
rates for Diablo Canyon, but to the extent permitted by law intends that this
decision remain in effect for the full term of the settlement, ending 2016.
The settlement provides that certain Diablo Canyon costs be recovered
over the term of the settlement, including a full return on such costs, through
base rates. 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: Under the Diablo Canyon rate case settlement, the price per
kWh of electricity generated by Diablo Canyon consists of a fixed and an
escalating component. The total prices for 1991 through 1993 were 9.60 cents,
10.34 cents and 11.16 cents per kWh, respectively, effective January 1. The
total price for 1994, effective January 1, is 11.89 cents per kWh. For 1995
through 2016, 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. Beginning
in January of each year, during the first 700 hours of full-power operation for
each unit outside the peak period, the price is 70% of the stated amount. At
all other times, the price is 100% of the stated amount.
FINANCIAL INFORMATION: Selected financial information for Diablo Canyon
is shown below:
<TABLE>
<CAPTION>
Year ended December 31,
------------------------------
1993 1992 1991
------ ------ ------
(in millions)
<S> <C> <C> <C>
Operating revenues $1,933 $1,781 $1,501
Operating income 708 663 497
Net income 496 443 274
</TABLE>
In determining operating results of Diablo Canyon, operating revenues
were specifically identified pursuant to the Diablo Canyon rate case
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 based on an allocation of corporate debt to Diablo Canyon.
NOTE 4 -- 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 a mandatory redemption provision
(4.36% to 8.2%, $25 par value) is subject to redemption, 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 6.57% series ($25 par value) preferred stock is subject to a mandatory
redemption provision and is entitled to a sinking fund providing for the
retirement of stock outstanding, beginning in 2002, at par value per share
plus accumulated and unpaid dividends through the redemption date. In addition
to mandatory redemptions, this stock may be redeemed at the Company's option
at par value per share plus accumulated and unpaid dividends through the
redemption date and a redemption premium under specified circumstances after
July 2002. The estimated fair value for the Company's preferred stock with a
mandatory redemption provision at December 31, 1993 and 1992, was approximately
$81 million and $168 million, respectively, based primarily on quoted market
prices.
During 1993, the Company issued $125 million of 6.875% redeemable
preferred stock and $75 million of 7.04% redeemable preferred stock. Proceeds
were used to finance a portion of the 1993 redemption of all the Company's
9.00%, 9.30%, 9.48% and 10.17% redeemable preferred stock with an aggregate par
value of $267 million.
During 1992, the Company issued $125 million of 7.44% redeemable
preferred stock and $75 million of 6.57% preferred stock with a mandatory
redemption provision, and redeemed the 9.28%, 10.18% and 10.28% series of
redeemable preferred stock with an aggregate par value of $229 million.
38
<PAGE> 28
Dividends on preferred stock are cumulative. Preferred dividends are
accrued based on declaration date, whereas preferred dividend requirement,
which is used to calculate earnings per common share, is based on the
accumulated dividends on preferred stock outstanding at year end. All shares of
preferred stock have 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 5 -- Long-term Debt
- ------------------------
MORTGAGE BONDS: The First and Refunding Mortgage Bonds of the Company are
issued in series, bear annual interest rates ranging from 4.25% to 12.75% and
mature from 1994 to 2026. The Company had $6.0 billion and $6.6 billion of
mortgage bonds outstanding at December 31, 1993 and 1992, respectively.
Additional bonds may be issued, subject to CPUC approval, up to a maximum total
outstanding of $10 billion, assuming compliance with indenture covenants for
earnings coverage and property available as security. The Company's Board of
Directors 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. The payments equal .5% 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
high-cost debt, the Company redeemed or repurchased $3,536 million and $1,182
million of higher-cost mortgage bonds in 1993 and 1992, respectively. Interest
rates on the bonds redeemed or repurchased ranged from 7.50% to 12.75%.
During 1993, the Company issued $2,950 million of First and Refunding
Mortgage Bonds, series 93A through 93H, with interest rates ranging from 5.375%
to 7.250% and maturity dates ranging from 1998 to 2026. Substantially all the
proceeds from these bonds were used to redeem or repurchase higher-cost
mortgage bonds.
Included in the total of outstanding mortgage bonds are First and
Refunding Mortgage Bonds issued by the Company to secure its obligation
to repay various loans from the California Pollution Control Financing
Authority (CPCFA) to finance air and water pollution control, and sewage and
solid waste disposal facilities. The amounts loaned to the Company by the CPCFA
consist of proceeds from the CPCFA's sale of tax-exempt pollution control
revenue bonds having the same principal amounts and terms as the Company's
mortgage bonds securing the loans. At December 31, 1993 and 1992, the Company
had outstanding $768 million and $508 million, respectively, of mortgage bonds
securing loans from the CPCFA. These mortgage bonds have interest rates ranging
from 5.85% to 8.875% 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, 1993 and 1992, from the CPCFA to
finance air and water pollution control, and sewage and solid waste disposal
facilities. Interest rates on the loans vary depending on 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 1993 ranged from 2.31% to 2.54%. These loans are
subject to redemption on demand by the holder under certain circumstances. The
Company's obligations for such demands are secured by irrevocable letters of
credit which mature as early as 1996.
MEDIUM-TERM NOTES: The Company had $1,543 million and $847 million of unsecured
medium-term notes outstanding at December 31, 1993 and 1992, respectively, with
interest rates ranging from 4.13% to 10.10% and maturities from 1994 to 2013.
During 1993 and 1992, the Company issued $750 million and $263 million of
medium-term notes, respectively. Proceeds from these notes were applied to
construction expenditures and to the redemption, repurchase or retirement of
debt or preferred stock.
39
<PAGE> 29
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
PACIFIC GAS AND ELECTRIC COMPANY
LONG-TERM DEBT OF SUBSIDIARIES: In 1993, PGT finalized a new loan agreement for
$710 million to finance PGT's portion of the PGT-PG&E Pipeline Expansion
Project and to refinance PGT's existing borrowings. As of December 31, 1993,
there was $648 million outstanding under this agreement. The loan is secured
by PGT's operating revenues and gas transportation contracts. The loan will
mature no later than 2004, however, if certain terms and conditions are not
met by November 1996, the loan could mature as early as 1997. If early maturity
does not occur, a reserve sufficient to cover a minimum of six months of debt
service must be established. At December 31, 1993, the Company was in
compliance with all terms and conditions. The interest rate varies depending
on the rate selected by the Company, which can be the prime rate, London
Interbank Offered Rate or certificate of deposit rate, plus applicable margin.
During 1993, the weighted average rate of interest was 3.83%.
REPAYMENT SCHEDULE: At December 31, 1993, the Company's combined aggregate
amount of maturing long-term debt and sinking fund requirements, for the
years 1994 through 1998, are $221 million, $514 million, $460 million, $369
million and $714 million, respectively.
FAIR VALUE: The estimated fair value for the Company's total long-term debt of
$9.5 billion and $8.7 billion at December 31, 1993 and 1992, respectively, was
approximately $9.9 billion and $9.2 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). Debt allocated to Diablo
Canyon at December 31, 1993 and 1992, had a book value of $2.2 billion, and a
fair value of approximately $2.3 billion.
Note 6 -- Short-term Borrowings
Short-term borrowings consist of commercial paper with a weighted average
interest rate of 3.43% at December 31, 1993. The usual maturity for commercial
paper is 10 to 90 days. Commercial paper outstanding at December 31, 1993 and
1992, was $764 million and $916 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.
At December 31, 1993 and 1992, there were no borrowings outstanding under this
facility. This credit facility expires in November 1997; however, it may be
extended annually for additional one-year periods upon mutual agreement between
the Company and the banks. The Company is in compliance with all covenants
associated with the facility.
Note 7 -- 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. 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,
-----------------------------------
1993 1992 1991
--------- --------- ---------
(in thousands)
<S> <C> <C> <C>
Service cost for benefits earned $ 129,166 $ 127,388 $ 112,940
Interest cost 268,698 248,674 238,153
Actual return on plan assets (511,526) (204,576) (774,445)
Net amortization and deferral 177,597 (78,560) 552,775
--------- --------- ---------
Net pension cost $ 63,935 $ 92,926 $ 129,423
========= ========= =========
</TABLE>
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 decrease
in net pension cost in 1992 compared to 1991 was mostly due to favorable
investment returns in 1991.
The expected long-term rate of return on plan assets used to calculate
pension cost was 9% for 1993, and 8% for 1992 and 1991.
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 1993 and 1991, actual return on plan assets exceeded expected
return whereas, in 1992, actual return on plan assets was less than expected
return.
40
<PAGE> 30
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.
The plan's funded status was:
<TABLE>
<CAPTION>
December 31,
-------------------------
1993 1992
----------- -----------
(in thousands)
<S> <C> <C>
Actuarial present value of
benefit obligations
Vested benefits $(3,203,408) $(2,680,364)
Nonvested benefits (154,349) (183,971)
----------- -----------
Accumulated benefit obligation (3,357,757) (2,864,335)
Effect of projected future
compensation increases (577,926) (859,764)
----------- -----------
Projected benefit obligation (3,935,683) (3,724,099)
Plan assets at market value 4,376,110 3,872,374
----------- -----------
Plan assets in excess of
projected benefit obligation 440,427 148,275
Unrecognized prior service cost 117,312 71,324
Unrecognized net gain (759,690) (383,498)
Unrecognized net obligation 120,253 137,763
----------- -----------
Accrued pension liability $ (81,698) $ (26,136)
=========== ===========
</TABLE>
The increase in unrecognized prior service cost in 1993 compared to
1992 reflects a plan amendment which provides an increase in benefits to
certain retirees.
Plan assets consist substantially of common stocks, fixed-income
securities and real estate investments. The unrecognized prior service cost is
amortized over approximately 16 years. The unrecognized net obligation is being
amortized over approximately 18 years, beginning in 1987.
The vested benefit obligation is the actuarial present based on their
expected 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,
------------
1993 1992
---- ----
<S> <C> <C>
Weighted average discount rate 7% 7%
Average rate of projected future
compensation increases 5% 6%
</TABLE>
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 14 percent and, effective January 1994, 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 $36 million, $35 million and $33
million for 1993, 1992 and 1991, 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, 1993, stock options on 1,973,161 shares, granted at
option prices ranging from $16.75 to $33.38, were outstanding. During 1993,
691,200 options were granted at an option price of $33.13. Option prices are
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, death or a change in control of a subsidiary, and
upon certain changes in control of the Company.
In 1993, stock options on 174,387 shares were exercised at option
prices ranging from $16.75 to $33.13. At December 31, 1993, stock options on
493,989 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.
The Company's funding policy for the medical and life insurance
benefits is to contribute each year the tax-deductible 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.
41
<PAGE> 31
Substantially all employees retiring at or after age 55 are
eligible for these
benefits. The medical benefits are provided through plans
administered by an
insurance carrier or a health maintenance organization. Certain
retirees are
responsible for a portion of the cost based on past claims
experience of the
Company's retirees.
The Company's funding policy for the medical and life insurance
benefits is to
contribute each year the tax-deductible 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.
41
<PAGE> 32
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
PACIFIC GAS AND ELECTRIC COMPANY
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 in the final phase of the
investigation 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.
Net postretirement medical and life insurance cost, using the projected
unit credit actuarial cost method, was:
<TABLE>
<CAPTION>
Year ended
December 31,
1993
--------------
(in thousands)
<S> <C>
Service cost for benefits earned $ 38,496
Interest cost 73,502
Actual return on plan assets (23,999)
Amortization of transition obligation 39,620
Net amortization and deferral (3,390)
--------
Net postretirement benefit cost $124,229
========
</TABLE>
The medical and life insurance plans' funded status was:
<TABLE>
<CAPTION>
Year ended
December 31,
1993
--------------
(in thousands)
<S> <C>
Accumulated postretirement benefit obligation
Retirees $(384,706)
Other fully eligible participants (148,018)
Other active plan participants (365,786)
---------
Total accumulated postretirement
benefit obligation (898,510)
Plan assets at market value 345,938
---------
Accumulated postretirement benefit obligation
in excess of plan assets (552,572)
Unrecognized net loss 21,481
Unrecognized transition obligation 543,939
---------
Prepaid postretirement benefit $ 12,848
=========
</TABLE>
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 at January 1, 1993, of $1,018
million over 20 years beginning in 1993. In 1993, the Company implemented a
plan change that will limit the amount it will contribute toward postretirement
medical benefits. This limitation, which will take effect for all retirees
beginning in 2001, reduced the accumulated postretirement obligation for these
benefits at July 1, 1993, by approximately $450 million. Due to current
regulatory treatment, the limitation did not have a significant impact on the
Company's financial position or results of operations.
The expected long-term rate of return on plan assets used to calculate
postretirement medical and life insurance benefit costs for 1993 was 9%. The
assumptions used to calculate the benefit obligations included a weighted
average discount rate of 7% and a rate of projected future compensation
increases of 5%. The assumed health care cost trend rate in 1994 is
approximately 11.5%, grading down to an ultimate rate in 2005 of approximately
6%. 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, 1993, by approximately $107
million and the 1993 aggregate service and interest costs by approximately $17
million.
For 1992 and 1991, the cost of postretirement medical and life
insurance benefits was based on benefits paid and funded and totaled $98
million and $92 million, respectively.
VOLUNTARY RETIREMENT INCENTIVE PLAN: In 1993, the Company announced a workforce
reduction program which included a voluntary retirement incentive plan for
certain employees 50 years of age with at least 15 years of service. The
additional pension and other postretirement benefits extended in connection
with the voluntary retirement incentive plan are reflected in the funded status
tables above and are discussed further in Note 8.
POSTEMPLOYMENT BENEFITS: In November 1992, the Financial Accounting Standards
Board issued 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. The Company will adopt the new standard
in 1994.
Based on a preliminary valuation by the Company's actuary, it is
estimated that the recorded liability for such benefits will increase by
approximately $100 million upon adoption. However, due to current regulatory
treatment, adoption of SFAS No. 112 is not expected to have a significant
impact on the Company's financial position or results of operations.
42
<PAGE> 33
POSTEMPLOYMENT BENEFITS: In November 1992, the Financial
Accounting Standards
Board issued 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. The Company will adopt
the new standard
in 1994.
Based on a preliminary valuation by the Company's actuary, it
is estimated
that the recorded liability for such benefits will increase by
approximately
$100 million upon adoption. However, due to current regulatory
treatment,
adoption of SFAS No. 112 is not expected to have a significant
impact on the
Company's financial position or results of operations.
42
<PAGE> 34
Note 8 -- Workforce Reduction Program
- -------------------------------------
In the first quarter of 1993, the Company announced a corporate
reorganization and workforce reduction program which reduced employment
positions through a combination of a targeted voluntary retirement incentive
plan, targeted voluntary severance, involuntary severance, transitional leaves
of absence and attrition.
In March 1993, the CPUC authorized the establishment of a memorandum
account to record costs and savings incurred in connection with the workforce
reduction program, with the recovery of such costs subject to a reasonableness
review by the CPUC. The Company is seeking rate recovery of all costs incurred
in connection with the workforce reduction program relating to electric and gas
operations.
As of December 31, 1993, the Company has recorded workforce reduction
program costs of $264 million, net of a curtailment gain relating to pension
benefits. (Included in this amount is $151 million for additional pension
benefits and $22 million for other postretirement benefits extended in
connection with the voluntary retirement incentive plan.) In April 1993, the
Company announced a freeze on electric rates through 1994. As a result, the
Company has expensed $190 million of such costs relating to electric
operations. The remaining $74 million of such costs relating to gas operations
has been deferred for future rate recovery. The amount deferred is currently
being amortized as savings are realized.
Note 9 -- Income Taxes
- ----------------------
The current and deferred components of income tax expense were:
<TABLE>
<CAPTION>
Year ended December 31,
----------------------------------------
1993 1992 1991
---------- ---------- ----------
(in thousands)
<S> <C> <C> <C>
Current
Federal $ 417,558 $ 536,774 $ 589,713
State 165,134 193,895 201,445
---------- ---------- ----------
Total current 582,692 730,669 791,158
---------- ---------- ----------
Deferred (substantially all federal)
Regulatory balancing accounts 77,515 85,210 (86,682)
Depreciation 207,690 165,944 161,937
(Gain) loss on reacquired debt 42,405 15,959 (1,377)
Other -- net 11,998 (78,783) 4,922
---------- ---------- ----------
Total deferred 339,608 188,330 78,800
---------- ---------- ----------
Investment tax credits -- net (20,410) (23,873) (18,424)
---------- ---------- ----------
Total income tax expense $ 901,890 $ 895,126 $ 851,534
========== ========== ==========
Classification of income taxes
Included in operating expenses $1,006,774 $ 906,845 $ 863,089
---------- ---------- ----------
Included in other -- net (104,884) (11,719) (11,555)
---------- ---------- ----------
Total income tax expense $ 901,890 $ 895,126 $ 851,534
========== ========== ==========
</TABLE>
The significant components of net deferred income tax liabilities
are as follows:
<TABLE>
<CAPTION>
December 31, 1993
--------------------------------------------
Deferred Deferred Net deferred
income tax income tax income tax
assets liabilities liability
---------- ----------- ------------
(in thousands)
<S> <C> <C> <C>
Deferred income taxes -- current
Regulatory balancing accounts $ -- $ 449,216
Other 160,177 26,545
---------- ---------- ----------
Total deferred income
taxes -- current 160,177 475,761 $ 315,584
---------- ---------- ----------
Deferred income taxes -- noncurrent
Plant in service -- 3,386,122
Income tax-related
deferred charges(1) -- 511,786
Other 647,018 728,060
---------- ---------- ----------
Total deferred income
taxes -- noncurrent 647,018 4,625,968 3,978,950
---------- ---------- ----------
Total deferred income taxes $ 807,195 $5,101,729 $4,294,534
========== ========== ==========
</TABLE>
<PAGE> 35
(1) Represents the portion of deferred income tax liability related to the
revenues required to recover future income taxes.
The differences between income tax expense and amounts determined by
applying the federal statutory rate to income before income tax expense were:
<TABLE>
<CAPTION>
Year ended December 31,
-----------------------
1993 1992 1991
---- ---- ----
<S> <C> <C> <C>
Federal statutory income tax rate 35.0% 34.0% 34.0%
Increase (decrease) in income tax rate
resulting from
Investment tax credits (1.0) (1.2) (1.0)
State income tax
(net of federal benefit) 6.1 6.1 7.1
Effect of regulatory accounting
for depreciation differences 4.5 5.0 5.4
Other -- net 1.2 (0.6) (0.2)
---- ---- ----
Effective tax rate 45.8% 43.3% 45.3%
==== ==== ====
</TABLE>
Note 10 -- Commitments
CAPITAL PROJECTS: Capital expenditures for 1994 are estimated to be
approximately $1,729 million, consisting of $1,397 million for utility
expenditures, $105 million for Diablo Canyon and $227 million for nonregulated
expenditures. At December 31, 1993, Enterprises had firm commitments totaling
$241 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 $95 million in 1994, $119 million in 1995,
43
<PAGE> 36
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
PACIFIC GAS AND ELECTRIC COMPANY
$27 million in 1996, and none in 1997, 1998, and thereafter. The
partnerships which own the generating facility projects typically finance
them with nonrecourse debt.
QUALIFYING FACILITIES (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 1994 to 2022. 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.
There are no requirements to make debt service payments. QF deliveries in the
aggregate account for approximately 24% of the Company's 1993 total electric
energy requirements and no single contract accounted for more than 5% of the
Company's energy needs. QF deliveries in 1993 represented approximately 84% 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,
---------------------------
1993 1992 1991
------- ------- ------
(in millions)
<S> <C> <C> <C>
Kilowatthours received 21,242 21,173 19,127
Energy payments $ 1,099 $ 1,084 $ 970
Capacity payments $ 503 $ 489 $ 450
</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 FERC
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, 1993,
the future minimum payments under these contracts were $34 million for each of
the years 1994 through 1998 and a total of $484 million for periods thereafter.
Total payments under these contracts were $45 million, $54 million and $47
million in 1993, 1992 and 1991, respectively.
WESTERN AREA POWER ADMINISTRATION (WAPA) ENERGY AGREEMENT: The Company
has an agreement with WAPA to purchase energy from them and resell it to them
upon their request. The energy under contract has been purchased by the Company
from WAPA at favorable prices based on WAPA's cost of generation. That energy
must be sold back to WAPA at a price equal to the Company's current thermal
production cost at the time of delivery to WAPA less the Company's savings that
resulted from the purchases at the lower WAPA prices.
The contract will expire in 2005. At December 31, 1993, the cost to the
Company to return the amount of energy currently available to WAPA was
approximately $177 million, assuming WAPA requests the return of all the energy
prior to the contract's expiration date. However, such cost represents a return
of the benefits the Company received through its purchases from WAPA, which
were passed on to ratepayers at that time. The Company believes it is entitled
to recover in rates costs of energy resold to WAPA.
Note 11 -- 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.
The Company has filed an application for rate recovery of the remaining
unrecovered Helms costs, the associated revenue requirement on such costs since
1984 and lost revenues during the time the generators were being repaired. The
remaining net unrecovered costs of Helms (after adjustment for depreciation)
and revenues discussed above totaled $106 million at December 31, 1993.
In June 1993, the DRA issued its report on the Company's 1991 Helms
application and recommended a disallowance of all requested costs and revenues.
The DRA recommends ratepayers should not be held responsible for plant costs or
losses incurred by a utility due to contractor error, whether or not the
utility was prudent, and cites past CPUC action for this policy. The DRA also
contends the Company acted imprudently in the management of the project and
failed to adequately oversee the engineering and design of the generators.
44
<PAGE> 37
With respect to the lost revenues and related recorded interest during
the time that Helms was out of service for the modification and repair of the
generators, the DRA asserts the Company has failed to establish that the outage
was not caused by a problem first identified during the precommercial testing
program.
The Company filed its rebuttal testimony in January 1994 asserting that
it was prudent in managing and overseeing the project and various issues raised
by DRA were not based on facts or were irrelevant to the application. The
Company is uncertain whether, and to what extent, any of the remaining costs
and revenues will be recovered through the ratemaking process.
NUCLEAR INSURANCE: The Company is a member of Nuclear Mutual Limited (NML) and
Nuclear Electric Insurance Limited (NEIL I and II). 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 assessments of $21 million (property damage) or $7 million (business
interruption), in each case per policy period, if losses exceed premiums,
reserves and other resources of NML, NEIL I or NEIL II.
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 $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 take remedial action at certain disposal and
retired manufactured gas plant sites if they are determined to present a
significant threat to human health or the environment because of an actual or
potential release of hazardous substances. The Company has been designated as
a potentially responsible party under the Comprehensive Environmental Response,
Compensation, and Liability Act (federal Superfund law) and the California
Hazardous Substance Account Act (California Superfund law) with respect to
several sites. 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. However, based on the information
currently available, the Company has an accrued liability as of December 31,
1993, of $60 million for hazardous waste remediation costs. The ultimate amount
of such costs may be significantly higher 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 and
affected natural resources is greater than anticipated at sites for which the
Company is responsible.
To the extent that hazardous waste compliance and remediation costs are
not recovered through insurance or by other means, the Company will apply for
recovery through ratemaking procedures established by the CPUC and expects that
most prudently incurred hazardous waste compliance and remediation costs will
be recovered through rates. As of December 31, 1993, the Company has a deferred
charge of $61 million for most hazardous waste remediation costs, which
represents the minimum amount of such costs expected to be recovered. Due to
expected regulatory treatment, 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.
LEGAL MATTERS: Antitrust Litigation: In December 1993, the County of
Stanislaus, California, and a residential customer of PG&E, filed a complaint
against PG&E and PGT on behalf of themselves and purportedly as a class action
on behalf of all natural gas customers of PG&E, for the period of February 1988
through October 1993. The complaint alleges that the purchase of natural gas in
Canada by A&S was accomplished in violation of various antitrust laws which
resulted in increased prices of natural gas for PG&E's customers.
The complaint alleges that the Company could have purchased as much as
50% of its 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. The complaint
indicates that the damages to the class could
45
<PAGE> 38
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
PACIFIC GAS AND ELECTRIC COMPANY
include over $150 million paid by the Company to terminate the contracts with
the Canadian gas producers in November 1993. The complaint also seeks recovery
of three times the amount of the actual damages pursuant to antitrust laws.
The Company believes the case is without merit and has filed a motion
to dismiss the complaint. The Company believes that the ultimate outcome of the
antitrust litigation will not have a significant adverse impact on its financial
position.
Hinkley Litigation: In 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, as well as punitive damages.
The plaintiffs contend that the Company discharged chromium-
contaminated waste water 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 control board, the Company will
continue to monitor the affected area and periodically perform environmental
assessments.
In November 1993, the parties engaged in private mediation sessions. In
December 1993, the plaintiffs filed an offer to compromise and settle their
claims against the Company for $250 million.
The Company is unable to estimate the ultimate outcome of this matter,
but such outcome could have a significant adverse impact on the Company's
results of operations. The Company believes that the ultimate outcome of this
matter will not have a significant adverse impact on its financial position.
QF Transmission Litigation: The Company is a defendant in a lawsuit, currently
in trial, resulting from the termination of a power purchase agreement. The
plaintiff contends the Company misrepresented to the CPUC and to QFs its
transmission capacity and that the existence of transmission constraints
extended the deadline for delivery of energy. The plaintiff also alleges
the Company had an obligation to build transmission upgrades at the Company's
expense, which it did not fulfill. The complaint seeks compensatory and
punitive damages of an unspecified amount. However, the plaintiff's damage
expert has given a preliminary estimate of damages sought of $67 million. There
are other similarly situated QFs which might choose to file similar complaints
depending on the outcome of this litigation. The Company believes that the
matter has no merit and that the ultimate outcome will not have a significant
adverse impact on its financial position or results of operations.
46
<PAGE> 39
QUARTERLY CONSOLIDATED FINANCIAL DATA (UNAUDITED)
PACIFIC GAS AND ELECTRIC COMPANY
QUARTERLY FINANCIAL DATA
The four quarters of 1993 and 1992 are shown below. 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 second quarter of 1993, the Company charged to earnings $141
million related to the workforce reduction program for management employees. In
the third quarter of 1993, the Company's earnings reflected charges of $144
million resulting from the Company's workforce reduction program, termination
of Canadian gas contracts and an increase in the federal income tax rate that
was signed into law this year. 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.
Earnings for the second quarter of 1992 included a $19 million after-tax gain
from the sale by PGT of its 49.98% interest in ANG.
The Company's common stock is traded on the New York, Pacific, London,
Amsterdam, Basel and Zurich stock exchanges. There were approximately 245,000
common shareholders of record at December 31, 1993. 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
---------------------------------------------------
December 31 September 30 June 30 March 31
----------- ------------ ---------- ----------
(in thousands, except per share amounts)
<S> <C> <C> <C> <C>
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
1992
Operating revenues $2,557,787 $2,798,763 $2,519,679 $2,419,859
Operating income 386,196 507,137 491,131 448,977
Net income 205,804 351,939 336,409 276,429
Earnings per common
share(1) .44 .78 .75 .61
Dividends declared per
common share .44 .44 .44 .44
Common stock price per
share
High 34.00 34.63 33.63 32.38
Low 30.00 31.13 29.00 29.13
</TABLE>
(1) Includes Diablo Canyon scheduled refueling outages for the first and second
quarters of 1993 and for the third and fourth quarters of 1992.
47
<PAGE> 40
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
PACIFIC GAS AND ELECTRIC COMPANY
To the Shareholders and the Board of Directors of Pacific Gas and
Electric Company:
We have audited the accompanying consolidated balance sheet and the
statement of consolidated capitalization of Pacific Gas and Electric Company (a
California corporation) and subsidiaries as of December 31, 1993 and 1992, 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, 1993. These financial
statements 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, 1993 and 1992, and the results of their
operations and cash flows for each of the three years in the period ended
December 31, 1993 in conformity with generally accepted accounting principles.
As discussed in Note 2 of Notes to Consolidated Financial Statements,
the reasonableness of Canadian gas costs for 1988 through 1993 is subject to
California Public Utilities Commission review. The Company currently is unable
to estimate the ultimate outcome of the gas reasonableness proceedings or
predict whether such outcome will have a significant adverse impact on its
financial position or results of operations.
As discussed in Note 11 of Notes to Consolidated Financial Statements,
the Company has filed an application for rate recovery of the remaining
unrecovered Helms costs and certain lost revenues which totaled $106 million at
December 31, 1993. The Company is uncertain whether, and to what extent, any of
the remaining costs and revenues will be recovered through the ratemaking
process.
As discussed in Note 11 of Notes to Consolidated Financial Statements,
in 1993, a complaint was filed on behalf of a number of individuals seeking
recovery for personal injuries and property damage related to alleged
groundwater contamination caused by Company activity. The Company is unable to
estimate the ultimate outcome of this matter, but such outcome could have a
significant adverse impact on the Company's results of operations. The Company
believes that the ultimate outcome of this matter will not have a significant
adverse impact on the Company's financial position.
As explained in Notes 1 and 7 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 & CO.
ARTHUR ANDERSEN & CO.
San Francisco, California
February 16, 1994
48
<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 16, 1994, 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. 33-27010 (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).
We also consent to the incorporation of our report dated March 14, 1994,
included in Exhibit 99 to this Form 10-K into the Company's previously filed
Registration Statement File No. 33-50601 (relating to the Company's Savings
Fund Plan for Employees).
ARTHUR ANDERSEN & CO.
San Francisco, California,
March 28, 1994
<PAGE> 1
Exhibit 24.1
I, KATHLEEN RUEGER, do hereby certify that I am an
Assistant Corporate Secretary of PACIFIC GAS AND ELECTRIC
COMPANY, a corporation organized and existing under the laws of
the State of California; that the above and foregoing is a full,
true and correct copy of a resolution which was duly adopted by
the Board of Directors of said corporation at a meeting of said
Board which was duly and regularly called and held at the office
of said corporation on March 16, 1994, 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 25th day of March, 1994.
KATHLEEN RUEGER
Kathleen Rueger
Assistant Corporate Secretary
PACIFIC GAS AND ELECTRIC COMPANY
C O R P O R A T E
S E A L
<PAGE> 2
RESOLUTIONS OF
THE BOARD OF DIRECTORS OF
PACIFIC GAS AND ELECTRIC COMPANY
MARCH 16, 1994
BE IT RESOLVED that each of LESLIE H. EVERETT, BRIAN L. McGRATH, KATHLEEN
RUEGER, BRUCE R. WORTHINGTON, and JULIE C. GAVIN is hereby authorized to sign
on behalf of this corporation and as attorneys in fact for the Chairman of the
Board and Chief Executive Officer, Vice President and Chief Financial Officer,
and Controller of this corporation the Form 10-K Annual Report for the year
ended December 31, 1993, 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 pursuant thereto with regard to said Form 10-K Annual Report.
<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, BRIAN L. McGRATH, KATHLEEN RUEGER,
BRUCE R. WORTHINGTON 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, 1993 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 16th day of March,
1994.
<TABLE>
<S> <C>
R. A. CLARKE JOHN C. SAWHILL
- --------------------------- --------------------------
STANLEY T. SKINNER WILLIAM S. DAVILA
- --------------------------- --------------------------
LESLIE L. LUTTGENS ALAN SEELENFREUND
- --------------------------- --------------------------
H. M. CONGER SAMUEL T. REEVES
- --------------------------- --------------------------
WILLIAM F. MILLER BARRY LAWSON WILLIAMS
- --------------------------- --------------------------
MARY S. METZ CARL E. REICHARDT
- --------------------------- --------------------------
MELVIN B. LANE JOHN B. M. PLACE
- --------------------------- --------------------------
RICHARD B. MADDEN GEORGE A. MANEATIS
- --------------------------- --------------------------
</TABLE>
<PAGE> 2
POWER OF ATTORNEY
RICHARD A. CLARKE, the undersigned, Chairman of the Board, Chief
Executive Officer and Director of Pacific Gas and Electric Company, hereby
constitutes and appoints LESLIE H. EVERETT, BRIAN L. McGRATH, KATHLEEN RUEGER,
BRUCE R. WORTHINGTON or JULIE C. GAVIN his attorneys in fact with full power of
substitution to sign and file with the Securities and Exchange Commission in
his capacity as Chairman of the Board, Chief Executive Officer, and Director of
said corporation the Form 10-K Annual Report for the year ended December 31,
1993 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 16th day of
March, 1994.
RICHARD A. CLARKE
-----------------------------------
RICHARD A. CLARKE
<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, BRIAN L. McGRATH, KATHLEEN RUEGER, BRUCE R. WORTHINGTON 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, 1993 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 16th day of
March, 1994.
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, BRIAN L.
McGRATH, KATHLEEN RUEGER, BRUCE R. WORTHINGTON 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, 1993 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 16th day of
March, 1994.
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, 1993
A. Full title of the plan and the address of the plan, if different from
that of the issuer named below:
SAVINGS FUND PLAN FOR EMPLOYEES OF
PACIFIC GAS AND ELECTRIC COMPANY
B. Name of issuer of the securities held pursuant to the plan and the
address of its principal executive office:
PACIFIC GAS AND ELECTRIC COMPANY
77 Beale Street
P.O. Box 770000
San Francisco, California 94177
<PAGE> 2
The combined statements of financial condition and statements of financial
condition of the Plan as of December 31, 1993 and 1992, the related combined
statements of changes in participants' interest and the statements of changes
in participants' interest for each of the three years in the period ended
December 31, 1993, and the schedule of investments as of December 31, 1993 and
1992, together with the report of Arthur Andersen & Co., independent
accountants, are presented herewith.
<PAGE> 3
[ARTHUR ANDERSEN & CO. 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 combined statements of financial condition of
the Savings Fund Plan for Employees of Pacific Gas and Electric Company (the
Plan) as of December 31, 1993 and 1992, and the related combined statements of
changes in participants' interest for each of the three years in the period
ended December 31, 1993. We have also audited the combined statements of
financial condition (by fund) as of December 31, 1993 and 1992, and the combined
statements of changes in participants' interest (by fund) for each of the three
years in the period ended December 31, 1993. These financial statements and the
schedule referred to below are the responsibility of the Plan's management. Our
responsibility is to express an opinion on these financial statements and this
schedule based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the combined financial condition and the combined
financial condition (by fund) of the Plan as of December 31, 1993 and 1992, and
the changes in combined participants' interest and the changes in combined
participants' interest (by fund) for each of the three years in the period ended
December 31, 1993, in conformity with generally accepted accounting principles.
Our audit was made for the purpose of forming an opinion on the basic financial
statements taken as a whole. Schedule I is presented for purposes of complying
with the Securities and Exchange Commission's rules and is not part of the basic
financial statements. This schedule has been subjected to the auditing
procedures applied in the audit of the basic financial statements and, in our
opinion, fairly states in all material respects the financial data required to
be set forth therein in relation to the basic financial statements taken as a
whole.
ARTHUR ANDERSEN & CO.
San Francisco, California
March 14, 1994
<PAGE> 4
SAVINGS FUND PLAN
FOR EMPLOYEES OF PACIFIC GAS AND ELECTRIC COMPANY
FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 1993 AND 1992
WITH
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
<PAGE> 5
SAVINGS FUND PLAN
FOR EMPLOYEES OF PACIFIC GAS AND ELECTRIC COMPANY
COMBINED STATEMENT OF FINANCIAL CONDITION
<TABLE>
<CAPTION>
DECEMBER 31,
-----------------------
1993 1992
--------- ---------
(IN THOUSANDS)
<S> <C> <C>
ASSETS
Investments, at market (Schedule I)
Pacific Gas and Electric Company common stock (cost $966,716 and
$1,171,745 at December 31, 1993 and December 31, 1992,
respectively).................................................. $1,579,574 $1,963,276
United States Savings Bonds (cost $3,009 and $3,501 at December
31, 1993 and December 31, 1992, respectively).................. 4,562 4,971
Other common stocks (cost $264,199 and $164,278 at December 31,
1993 and December 31, 1992, respectively)...................... 301,338 190,107
Guaranteed income investments..................................... 229,520 114,088
Fixed income investments (cost $28,625 and $18,124 at December 31,
1993 and December 31, 1992, respectively)...................... 28,740 18,080
Other common stocks, bonds, fixed income securities, and
money-market investments (cost $92,144 and $42,944 at December
31, 1993 and December 31, 1992, respectively).................. 104,083 45,788
Utility Stocks (cost $76,395 and $26,682 at December 31, 1993 and
December 31, 1992, respectively)............................... 75,336 26,945
--------- ---------
Total Investments.............................................. 2,323,153 2,363,255
--------- ---------
Cash and short-term investments (at cost, which approximates
market)........................................................... 6,775 34,033
--------- ---------
Receivables
Dividends and interest............................................ 24,856 28,659
Other receivables................................................. 1,821 8,794
--------- ---------
Total Receivables.............................................. 26,677 37,453
--------- ---------
Total Assets.............................................. 2,356,605 2,434,741
--------- ---------
LIABILITIES
Pending distributions............................................... 12,655 1,433
Other liabilities................................................... 1,311 182
--------- ---------
Total Liabilities......................................... 13,966 1,615
--------- ---------
PARTICIPANTS' INTEREST.............................................. $2,342,639 $2,433,126
--------- ---------
--------- ---------
</TABLE>
The accompanying Notes to Financial Statements are an integral part of this
statement.
1
<PAGE> 6
SAVINGS FUND PLAN
FOR EMPLOYEES OF PACIFIC GAS AND ELECTRIC COMPANY
COMBINED STATEMENT OF FINANCIAL CONDITION
DECEMBER 31, 1993
<TABLE>
<CAPTION>
UNITED
COMPANY STATES DIVERSIFIED GUARANTEED BOND STOCK AND UTILITY
STOCK BOND EQUITY INCOME INDEX BOND STOCK PAYSOP
FUND FUND FUND FUND FUND FUND FUND FUND TOTAL
--------- ------- ------------ ----------- ------- ---------- ------- ------- ---------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
ASSETS
Investments, at market
(Schedule I)
Pacific Gas and
Electric Company
common stock (cost
Company Stock Fund,
$960,608; and PAYSOP
Fund, $6,108)....... $1,569,458 $ -- $ -- $ -- $ -- $ -- $ -- $10,116 $1,579,574
United States Savings
Bonds
(cost $3,009)....... -- 4,562 -- -- -- -- -- -- 4,562
Other common stocks
(cost $264,199)..... -- -- 301,338 -- -- -- -- -- 301,338
Guaranteed Income
Investments......... -- -- -- 229,520 -- -- -- -- 229,520
Fixed Income
Investments
(cost $28,625)...... -- -- -- -- 28,740 -- -- -- 28,740
Other common stocks,
bonds, fixed income
securities, and
money-market
investments (cost
$92,144)............ -- -- -- -- -- 104,083 -- -- 104,083
Utility Stocks (cost
$76,395)............ -- -- -- -- -- -- 75,336 -- 75,336
--------- ------- ------------ ----------- ------- ---------- ------- ------- ---------
Total Investments... 1,569,458 4,562 301,338 229,520 28,740 104,083 75,336 10,116 2,323,153
--------- ------- ------------ ----------- ------- ---------- ------- ------- ---------
Cash and short-term
Investments (at cost,
which approximates
market)............... 110 24 5,313 1,328 -- -- -- -- 6,775
--------- ------- ------------ ----------- ------- ---------- ------- ------- ---------
Receivables
Dividends and
interest............ 21,132 -- 767 2,821 -- -- -- 136 24,856
Other receivables..... 306 -- 1,315 75 21 53 51 -- 1,821
--------- ------- ------------ ----------- ------- ---------- ------- ------- ---------
Total Receivables... 21,438 -- 2,082 2,896 21 53 51 136 26,677
--------- ------- ------------ ----------- ------- ---------- ------- ------- ---------
Total Assets.... 1,591,006 4,586 308,733 233,744 28,761 104,136 75,387 10,252 2,356,605
--------- ------- ------------ ----------- ------- ---------- ------- ------- ---------
LIABILITIES
Pending
distributions....... 6,881 5 1,111 3,784 166 391 285 32 12,655
Other liabilities..... 114 -- 1,197 -- -- -- -- -- 1,311
--------- ------- ------------ ----------- ------- ---------- ------- ------- ---------
Total
Liabilities... 6,995 5 2,308 3,784 166 391 285 32 13,966
--------- ------- ------------ ----------- ------- ---------- ------- ------- ---------
PARTICIPANTS'
INTEREST..............$1,584,011 $4,581 $306,425 $ 229,960 $28,595 $103,745 $75,102 $10,220 $2,342,639
--------- ------- ------------ ----------- ------- ---------- ------- ------- ---------
--------- ------- ------------ ----------- ------- ---------- ------- ------- ---------
</TABLE>
The accompanying Notes to Financial Statements are an integral part of this
statement.
2
<PAGE> 7
SAVINGS FUND PLAN
FOR EMPLOYEES OF PACIFIC GAS AND ELECTRIC COMPANY
COMBINED STATEMENT OF FINANCIAL CONDITION
DECEMBER 31, 1992
<TABLE>
<CAPTION>
UNITED
COMPANY STATES DIVERSIFIED GUARANTEED BOND STOCK AND UTILITY
STOCK BOND EQUITY INCOME INDEX BOND STOCK PAYSOP
FUND FUND FUND FUND FUND FUND FUND FUND TOTAL
--------- ------- ------------ ----------- ------- ---------- ------- ------- ---------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
ASSETS
Investments, at market
(Schedule I)
Pacific Gas and
Electric Company
common stock (cost
Company Stock Fund,
$1,161,099; and
PAYSOP Fund,
$10,646)............ $1,946,050 $ -- $ -- $ -- $ -- $ -- $ -- $17,226 $1,963,276
United States Savings
Bonds............... -- 4,971 -- -- -- -- -- -- 4,971
Other common stocks
(cost $164,278)..... -- -- 190,107 -- -- -- -- -- 190,107
Guaranteed Income
Investments......... -- -- -- 114,088 -- -- -- -- 114,088
Fixed Income
Investments
(cost $18,124)...... -- -- -- -- 18,080 -- -- -- 18,080
Other common stocks,
bonds, fixed income
securities, and
money-market
investments (cost
$42,944)............ -- -- -- -- -- 45,788 -- -- 45,788
Utility Stocks (cost
$26,682)............ -- -- -- -- -- -- 26,945 -- 26,945
--------- ------ ---------- --------- ------- --------- ------- ------- ----------
Total
Investments... 1,946,050 4,971 190,107 114,088 18,080 45,788 26,945 17,226 2,363,255
--------- ------ ---------- --------- ------- --------- ------- ------- ----------
Cash and short-term
Investments (at cost,
which approximates
market)............... 203 25 15,164 18,641 -- -- -- -- 34,033
--------- ------ ---------- --------- ------- --------- ------- ------- ----------
Receivables
Dividends and
interest............ 26,043 -- 522 1,865 -- -- -- 229 28,659
Other receivables..... 8,500 -- 144 74 16 36 24 -- 8,794
--------- ------- ----------- --------- ------- --------- ------- ------- ----------
Total
Receivables... 34,543 -- 666 1,939 16 36 24 229 37,453
---------- ------- ----------- --------- ------- --------- ------- ------- ----------
Total Assets... 1,980,796 4,996 205,937 134,668 18,096 45,824 26,969 17,455 2,434,741
---------- ------- ----------- --------- ------- ---------- ------- ------- ----------
LIABILITIES
Pending
distributions....... 1,237 -- 83 111 -- -- -- 2 1,433
Other liabilities..... 122 -- 60 -- -- -- -- -- 182
--------- ------- ----------- ---------- ------- ---------- ------- ------- ----------
Total
Liabilities... 1,359 -- 143 111 -- -- -- 2 1,615
--------- ------- ----------- ---------- ------- ---------- ------- -------- ----------
PARTICIPANTS'
INTEREST.............. $1,979,437 $4,996 $205,794 $ 134,557 $18,096 $ 45,824 $26,969 $17,453 $2,433,126
--------- ------- ----------- --------- ------- ---------- ------- ------- ----------
--------- ------- ----------- --------- ------- ---------- ------- ------- ----------
</TABLE>
The accompanying Notes to Financial Statements are an integral part of this
statement.
3
<PAGE> 8
SAVINGS FUND PLAN
FOR EMPLOYEES OF PACIFIC GAS AND ELECTRIC COMPANY
COMBINED STATEMENT OF CHANGES IN PARTICIPANTS' INTEREST
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
-------------------------------------
1993 1992 1991
---------- ---------- ----------
(IN THOUSANDS)
<S> <C> <C> <C>
BALANCE, JANUARY 1................................................... $2,433,126 $2,272,426 $1,656,538
---------- ---------- ----------
ADDITIONS
Contributions
Participant........................................................ 94,039 90,057 80,530
Employer........................................................... 34,542 34,309 31,861
---------- ---------- ----------
Total contributions........................................ 128,581 124,366 112,391
---------- ---------- ----------
Earnings from investments
Interest........................................................... 11,859 5,900 5,253
Dividends.......................................................... 108,899 114,676 104,247
Other income....................................................... 85 199 36
---------- ---------- ----------
Total earnings from investments............................ 120,843 120,775 109,536
---------- ---------- ----------
Gain on securities
Realized on sale or distribution................................... 295,659 147,247 38,824
Unrealized appreciation (depreciation) in market value of
securities held................................................. (159,429) (101,997) 451,719
Gains on futures contracts......................................... 61 181 --
---------- ---------- ----------
Total gain on securities................................... 136,291 45,431 490,543
---------- ---------- ----------
Total additions............................................ 385,715 290,572 712,470
---------- ---------- ----------
DEDUCTIONS
Distributions to participants or their beneficiaries, at market...... 464,536 128,242 94,138
Pending distributions to participants or their beneficiaries, at
market............................................................. 11,222 1,433 2,417
Other expenses....................................................... 444 197 27
---------- ---------- ----------
Total deductions........................................... 476,202 129,872 96,582
---------- ---------- ----------
CHANGE IN PARTICIPANTS' INTEREST..................................... (90,487) 160,700 615,888
---------- ---------- ----------
BALANCE, DECEMBER 31................................................. $2,342,639 $2,433,126 $2,272,426
---------- ---------- ----------
---------- ---------- ----------
</TABLE>
The accompanying Notes to Financial Statements are an integral part of this
statement.
4
<PAGE> 9
SAVINGS FUND PLAN
FOR EMPLOYEES OF PACIFIC GAS AND ELECTRIC COMPANY
COMBINED STATEMENT OF CHANGES IN PARTICIPANTS' INTEREST
FOR THE YEAR ENDED DECEMBER 31, 1993
<TABLE>
<CAPTION>
UNITED
COMPANY STATES DIVERSIFIED GUARANTEED BOND STOCK AND UTILITY
STOCK BOND EQUITY INCOME INDEX BOND STOCK PAYSOP
FUND FUND FUND FUND FUND FUND FUND FUND TOTAL
--------- ------- ------------ ----------- ------- ---------- ------- ------- ---------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
BALANCE, JANUARY 1,
1993.................. $1,979,437 $4,996 $205,794 $ 134,557 $18,096 $ 45,824 $26,969 $17,453 $2,433,126
---------- ------ -------- --------- ------- -------- ------- ------- ----------
INTERFUND TRANSFERS,
Net................... (432,276) -- 88,138 228,209 13,964 56,332 50,287 (4,654) --
ADDITIONS
Contributions
Participant......... 58,104 -- 20,364 5,904 1,240 4,566 3,861 -- 94,039
Employer.............. 28,649 -- 2,535 800 310 1,092 1,156 -- 34,542
---------- ------ -------- --------- ------- -------- ------- ------- ----------
Total
contributions..... 86,753 -- 22,899 6,704 1,550 5,658 5,017 -- 128,581
---------- ------ -------- --------- ------- -------- ------- ------- ----------
Earnings from investment
Interest.............. 194 351 334 10,980 -- -- -- -- 11,859
Dividends............. 94,633 -- 7,282 -- 2,062 -- 4,050 872 108,899
Other income.......... 42 -- 41 1 -- 1 -- -- 85
---------- ------ -------- --------- ------- -------- ------- ------- ----------
Total earnings from
investments....... 94,869 351 7,657 10,981 2,062 1 4,050 872 120,843
---------- ------ -------- --------- ------- -------- ------- ------- ----------
Gain on securities
Realized on sale or
distribution........ 283,526 -- 10,422 -- 170 746 256 539 295,659
Unrealized
appreciation
(depreciation) in
market value of
securities held..... (176,100) -- 11,312 -- 158 9,094 (1,322) (2,571) (159,429)
Gains on futures
contracts........... 61 61
---------- ------ -------- --------- ------- -------- ------- ------- ----------
Total gain on
securities........ 107,426 -- 21,795 -- 328 9,840 (1,066) (2,032) 136,291
---------- ------ -------- --------- ------- -------- ------- ------- ----------
Total additions
(reductions).... 289,048 351 52,351 17,685 3,940 15,499 8,001 (1,160) 385,715
---------- ------ -------- --------- ------- -------- ------- ------- ----------
DEDUCTIONS
Distributions to
participants or their
beneficiaries, at
market................ 246,554 761 38,829 146,818 7,239 13,076 9,870 1,389 464,536
Pending distributions to
participants or their
beneficiaries, at
market................ 5,644 5 1,028 3,673 166 391 285 30 11,222
Other expenses.......... -- -- 1 -- -- 443 -- -- 444
---------- ------ -------- --------- ------- -------- ------- ------- ----------
Total
deductions.... 252,198 766 39,858 150,491 7,405 13,910 10,155 1,419 476,202
---------- ------ -------- --------- ------- ------- ------- ------- ----------
CHANGE IN PARTICIPANTS'
INTEREST.............. (395,426) (415) 100,631 95,403 10,499 57,921 48,133 (7,233) (90,487)
---------- ------ -------- --------- ------- ------- ------- ------- ----------
BALANCE, DECEMBER 31,
1993.................. $1,584,011 $4,581 $306,425 $ 229,960 $28,595 $103,745 $75,102 $10,220 $2,342,639
---------- ------ -------- --------- ------- -------- ------- ------- ----------
---------- ------ -------- --------- ------- -------- ------- ------- ----------
</TABLE>
The accompanying Notes to Financial Statements are an integral part of this
statement.
5
<PAGE> 10
SAVINGS FUND PLAN
FOR EMPLOYEES OF PACIFIC GAS AND ELECTRIC COMPANY
COMBINED STATEMENT OF CHANGES IN PARTICIPANTS' INTEREST
FOR THE YEAR ENDED DECEMBER 31, 1992
<TABLE>
<CAPTION>
UNITED
COMPANY STATES DIVERSIFIED GUARANTEED BOND STOCK AND UTILITY
STOCK BOND EQUITY INCOME INDEX BOND STOCK PAYSOP
FUND FUND FUND FUND FUND FUND FUND FUND TOTAL
---------- ------ ----------- ---------- ------- ---------- ------- ------- ----------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
BALANCE, JANUARY 1,
1992.................. $2,038,990 $4,850 $ 131,693 $ 62,211 $ 2,467 $ 5,063 $ -- $27,152 $2,272,426
---------- ------ --------- -------- ------- -------- ------- ------- ----------
INTERFUND TRANSFERS,
Net................... (179,904) -- 43,414 67,228 14,494 36,130 25,380 (6,742) --
ADDITIONS
Contributions
Participant........... 63,174 -- 17,322 5,825 658 2,410 665 -- 990,057
Employer.............. 33,165 -- 456 191 63 205 229 -- 34,309
---------- ------ --------- -------- ------- -------- ------- ------- ----------
Total
Contributions..... 96,339 -- 17,776 6,016 721 2,615 697 -- 124,366
---------- ------ --------- -------- ------- -------- ------- ------- ----------
Earnings from investment
Interest.............. 77 413 433 4,977 -- -- -- -- 5,900
Dividends............. 107,706 -- 4,553 -- 619 -- 466 1,332 114,676
Other income.......... 184 -- 10 2 1 -- -- 2 199
---------- ------ --------- -------- ------- -------- ------- ------- ----------
Total earnings from
investments....... 107,967 413 4,996 4,979 620 -- 466 1,334 120,775
---------- ------ --------- -------- ------- -------- ------- ------- ----------
Gain on securities
Realized on sale or
distribution........ 127,513 -- 19,478 -- 13 48 (5) 200 147,247
Unrealized
appreciation
(depreciation) in
market value of
securities held..... (93,466) -- (7,075) -- (152) 2,382 263 (3,947) (101,997)
Gains on future
contracts........... 181 181
---------- ------ --------- -------- ------- -------- ------- ------- ----------
Total gain on
securities........ 34,045 -- 12,584 -- (139) 2,430 258 (3,747) 45,431
---------- ------ --------- -------- ------- ------- ------- ------- ----------
Total additions
(reductions).... 238,351 413 35,358 10,995 1,202 5,405 1,621 (2,413) 290,572
---------- ------ --------- -------- ------- -------- ------- ------- ----------
DEDUCTIONS
Distributions to
participants or their
beneficiaries, at
market................ 116,672 267 4,588 5,766 67 309 32 541 128,242
Pending distributions to
participants or their
beneficiaries, at
market................ 1,237 -- 83 111 -- -- -- 2 1,433
Other expenses.......... 91 -- -- -- -- 105 -- 1 197
---------- ------ --------- -------- ------- -------- ------- ------- -----------
Total
deductions...... 118,000 287 4,671 5,677 67 414 32 544 129,872
---------- ------ --------- -------- ------- -------- ------- ------- -----------
CHANGE IN PARTICIPANTS'
INTEREST.............. (59,553) 145 74,101 72,346 15,629 40,761 26,969 (9,699 ) 160,700
---------- ------ --------- -------- ------- -------- ------- ------- -----------
BALANCE, DECEMBER 31,
1992.................. $1,979,437 $4,996 $ 205,794 $134,557 $18,096 $ 45,824 $26,969 $17,453 $2,433,126
---------- ------ --------- -------- ------- -------- ------- ------- ----------
---------- ------ --------- -------- ------- -------- ------- ------- ----------
</TABLE>
The accompanying Notes to Financial Statements are an integral part of this
statement.
6
<PAGE> 11
SAVINGS FUND PLAN
FOR EMPLOYEES OF PACIFIC GAS AND ELECTRIC COMPANY
COMBINED STATEMENT OF CHANGES IN PARTICIPANTS' INTEREST
FOR THE YEAR ENDED DECEMBER 31, 1991
<TABLE>
<CAPTION>
UNITED MONEY-
COMPANY STATES DIVERSIFIED MARKET GUARANTEED BOND STOCK AND
STOCK BOND EQUITY INVESTMENT INCOME INDEX BOND TRASOP PAYSOP
FUND FUND FUND FUND FUND FUND FUND FUND FUND TOTAL
--------- ------- ------------ ---------- ----------- ------ ---------- ------- ------- ---------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
BALANCE, JANUARY 1,
1991................$1,473,377 $4,463 $ 96,552 $ 14,140 $37,938 $ -- $ -- $ 652 $29,416 $1,656,538
---------- ------ -------- ---------- ----------- ------ ---------- ------- ------- ----------
INTERFUND TRANSFERS,
Net................. (3,101) 88 2,149 (14,822) 17,423 2,140 4,181 (470) (7,588) --
ADDITIONS
Contributions
Participant......... 58,688 303 15,011 874 5,052 167 435 -- -- 80,530
Employer............ 31,861 -- -- -- -- -- -- -- -- 31,861
---------- ------ -------- ---------- ----------- ------ ---------- ------- ------- ---------
Total
contributions.... 90,549 303 15,011 874 5,052 167 435 -- -- 112,391
---------- ------ -------- ---------- ----------- ------ ---------- ------- ------- ---------
Earnings from
investment
Interest............ 12 239 496 450 3,995 60 -- -- 1 5,253
Dividends........... 98,637 -- 3,786 -- -- -- -- 33 1,791 104,247
Other income........ 4 -- 13 -- -- -- -- 19 -- 36
---------- ------ -------- ---------- ----------- ------ ---------- ------- ------- ---------
Total earnings from
investments...... 98,653 239 4,295 450 3,995 60 -- 52 1,792 109,536
---------- ------- -------- ---------- ----------- ------ ---------- ------- ------- ---------
Gain on securities
Realized on sale or
distribution...... 35,898 -- 2,760 -- -- -- 1 4 161 38,824
Unrealized
appreciation
(depreciation) in
market value of
securities held... 432,827 -- 14,547 -- -- 109 463 (224) 3,997 451,719
---------- ------- -------- ---------- ----------- ------ ---------- ------- ------- ---------
Total gain on
securities....... 468,725 -- 17,307 -- -- 109 464 (220) 4,158 490,543
---------- ------- -------- ---------- ----------- ------ ---------- ------- ------- ---------
Total additions
(reductions)..... 657,927 542 36,613 1,324 9,047 336 899 (168) 5,950 712,470
---------- ------- -------- ---------- ----------- ------ ---------- ------- ------- ---------
DEDUCTIONS
Distributions to
participants or
their beneficiaries,
at market........... 86,925 230 3,528 642 2,166 9 10 14 614 94,138
Pending distributions
to participants or
their beneficiaries,
at market........... 2,268 13 93 -- 31 -- -- -- 12 2,417
Other expenses........ 20 -- -- -- -- -- 7 -- -- 27
---------- ------- -------- ---------- ----------- ------ ---------- ------- ------- ---------
Total deductions... 89,213 243 3,621 642 2,197 9 17 14 626 96,582
---------- ------- -------- ---------- ----------- ------ ---------- ------- ------- ---------
CHANGE IN
PARTICIPANTS'
INTEREST............ 565,613 387 35,141 (14,140) 24,273 2,467 5,063 (652) (2,264) 615,888
---------- ------- -------- ---------- ----------- ------ ---------- ------- ------- ---------
BALANCE, DECEMBER 31,
1991................$2,038,990 $4,850 $131,693 $ -- $62,211 $2,467 $5,063 $ -- $27,152 $2,272,426
---------- ------- -------- ---------- ----------- ------ ---------- ------- ------- ---------
---------- ------- -------- ---------- ----------- ------ ---------- ------- ------- ---------
</TABLE>
The accompanying Notes to Financial Statements are an integral part of this
statement.
7
<PAGE> 12
SAVINGS FUND PLAN
FOR EMPLOYEES OF PACIFIC GAS AND ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 1993
NOTE 1: PLAN DESCRIPTION
The Savings Fund Plan for Employees of Pacific Gas and Electric Company
(the Plan) is a defined contribution plan which has been in existence since 1959
and is subject to the provisions of the Employee Retirement Income Security Act
of 1974 (ERISA). The Plan covers all eligible employees of Pacific Gas and
Electric Company (the Company), Pacific Gas Transmission Company, Pacific
Service Employees Association and any other entity designated by the Company's
Board of Directors. The Plan is comprised of three parts: the management plan,
the non-management plan, and the Payroll-Based Employee Stock Ownership Plan
(PAYSOP) Fund plan. 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.
The Plan 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
and Bond Index Fund and are paid by the Company in connection with the
Diversified Equity Fund and the Guaranteed Income Fund. In addition, all Plan
securities and cash are held in trust by the Plan Trustee as provided in the
Trust Agreement.
All participants' contributions and their share of all employer
contributions, and the earnings and losses resulting from such contributions are
immediately vested and nonforfeitable.
MANAGEMENT AND NON-MANAGEMENT PLANS
Employees are eligible to participate in the Plan upon completion of one
year of service. Employee contributions, up to a maximum of six percent of
covered compensation, depending on length of service, are matched by employer
contributions at a 75% rate for management employees and at a 50% rate for non-
management employees. Prior to July 1, 1992, matching employer contributions
were invested solely in the common stock of the Company and could not be
transferred. Effective July 1, 1992, the company match (past and future) can be
invested in any Savings Fund Plan fund.
Eligible employees may elect to contribute to the Plan up to 14% 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. Effective January 1, 1991, the Company began matching
all contributions up to a specified amount depending upon length of service.
Prior to January 1, 1991, the Company only matched 401(k) contributions.
Beginning January 1, 1994, employees may elect to contribute to the Plan up to
15% of their covered compensation on a pre-tax or after-tax basis.
8
<PAGE> 13
SAVINGS FUND PLAN
FOR EMPLOYEES OF PACIFIC GAS AND ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS (CONTINUED)
DECEMBER 31, 1993
NOTE 1: PLAN DESCRIPTION (CONTINUED)
All contributions made to the Plan prior to October 1, 1984, are considered
to be non-401(k) contributions. In accordance with Internal Revenue Service
regulations, employee 401(k) contributions may not exceed $9,240 for 1994,
$8,994 for 1993, $8,728 for 1992, and $8,475 for 1991, and total contributions
to a participant's account may not exceed the lesser of 25% of compensation or
$30,000 a year. This annual limitation is adjusted each year to reflect changes
in the cost of living.
Management and non-management non-bargaining unit employees may elect to
contribute to the Plan any excess funds from the FLEX Benefits Program (Flex),
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.
Participants designate the way in which their contributions are invested
and may change their investment designation and may transfer among investment
funds 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 a diversified portfolio
consisting of marketable fixed-income securities;
- Stock and Bond Fund (SBF), invested in a diversified portfolio of
marketable equity securities and marketable fixed-income securities;
- Utility Stock Fund (USF), which was added to the Plan effective July
1, 1992, invested in marketable equity securities of electric
utility companies that are members of the Edison Electric Institute,
including PG&E.
9
<PAGE> 14
SAVINGS FUND PLAN
FOR EMPLOYEES OF PACIFIC GAS AND ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS (CONTINUED)
DECEMBER 31, 1993
NOTE 1: PLAN DESCRIPTION (CONTINUED)
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. For additional information of the DEF, GIF, BIF, SBF and USF, see
Note 6.
PAYSOP FUND
Effective January 1, 1983, the Economic Recovery Tax Act of 1981 (ERTA)
permitted the Company to establish the PAYSOP Fund for all eligible employees.
ERTA allowed 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 coincides with the calendar year.
Contributions to the PAYSOP Funds 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 Savings Fund Plan
Company Stock Fund. The last allocation to the PAYSOP Fund was made in 1987
based upon compensation earned by participants in tax year 1986. Therefore, the
PAYSOP Fund will fulfill the 84-month requirement in 1994.
NOTE 2: SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The financial statements and related schedules of the Plan are prepared in
conformity with regulations under Article 6A of the Securities and Exchange
Commission's Regulation S-X. The accounts of the Plan are maintained on an
accrual basis.
Investments in the GIF are valued at cost which approximates market. All
other investments held by the Plan are stated at market value based on published
market quotations at the end of the year.
The DEF routinely enters into futures contracts in the Standard and Poor's
(S&P) index as a hedge against price increases in the S&P stocks that are to be
purchased at a future date. The contracts are marked to market at each balance
sheet date, and a resulting gain or loss is recorded.
10
<PAGE> 15
SAVINGS FUND PLAN
FOR EMPLOYEES OF PACIFIC GAS AND ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS (CONTINUED)
DECEMBER 31, 1993
NOTE 3: INVESTMENT FUNDS
Pacific Gas and Electric Company common stock purchased for the Plan was
$175,522,000 (5,236,797 shares) in 1993, $216,248,000 (6,996,307 shares) in
1992; and $191,459,000 (7,218,364 shares) in 1991.
Participants' contributions are invested by the Plan Trustee in the
investment fund(s) elected by each participant. The investment funds available
under the Plan and the number of participants in each fund at December 31, 1993,
1992 and 1991 were as follows:
<TABLE>
<CAPTION>
NUMBER OF PARTICIPANTS
BY FUND
----------------------------
INVESTMENT 1993 1992 1991
------------------------------------------------- ------ ------ ------
<S> <C> <C> <C>
Company Stock Fund -- Pacific Gas and Electric
Company common stock........................... 25,885 27,181 26,921
------ ------ ------
United States Bond Fund -- United States Savings
Bonds.......................................... 1,154 1,247 1,298
------ ------ ------
DEF -- other common stocks....................... 12,421 11,181 9,854
------ ------ ------
GIF -- contracts with a fixed rate of interest... 6,354 5,753 5,078
------ ------ ------
BIF -- marketable fixed-income securities........ 1,816 1,226 408
------ ------ ------
SBF -- marketable equity securities and
marketable fixed-income securities............. 4,517 2,807 899
------ ------ ------
USF -- marketable equity securities of electric
utility companies.............................. 4,317 1,874 --
------ ------ ------
PAYSOP Fund -- Pacific Gas and Electric Company
common stock................................... 19,485 21,306 21,843
------ ------ ------
</TABLE>
11
<PAGE> 16
SAVINGS FUND PLAN
FOR EMPLOYEES OF PACIFIC GAS AND ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS (CONTINUED)
DECEMBER 31, 1993
NOTE 4: FEDERAL INCOME TAXES
The Internal Revenue Service 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 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.
NOTE 5: CONTRIBUTIONS
Employee and employer contributions to the Plan for both management and
non-management employees as classified by employer were as follows:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, 1993
---------------------------------------------
401(K) NON-401(K)
CONTRIBUTIONS CONTRIBUTIONS
----------------------------- -------------
EMPLOYEE EMPLOYER EMPLOYEE
CONTRIBUTIONS CONTRIBUTIONS CONTRIBUTIONS
------------- ------------- -------------
(IN THOUSANDS)
<S> <C> <C> <C>
Pacific Gas and Electric Company......................... $86,609 $33,954 $ 5,877
Pacific Gas Transmission Company......................... 1,238 500 110
Pacific Service Employees Association.................... 197 86 8
------------- ------------- -------------
Total.................................................. $88,044 $34,542 $ 5,995
------------- ------------- -------------
------------- ------------- -------------
</TABLE>
12
<PAGE> 17
SAVINGS FUND PLAN
FOR EMPLOYEES OF PACIFIC GAS AND ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS (CONTINUED)
DECEMBER 31, 1993
NOTE 5: CONTRIBUTIONS (CONTINUED)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, 1992
----------------------------------------------
401(K) NON-401(K)
CONTRIBUTIONS CONTRIBUTIONS
----------------------------- -------------
EMPLOYEE EMPLOYER EMPLOYEE
CONTRIBUTIONS CONTRIBUTIONS CONTRIBUTIONS
------------- ------------- -------------
(IN THOUSANDS)
<S> <C> <C> <C>
Pacific Gas and Electric Company......................... $82,869 $33,760 $ 5,817
Pacific Gas Transmission Company......................... 1,120 446 91
Pacific Service Employees Association.................. 152 103 8
------------- ------------- -------------
Total.......................................... $84,141 $34,309 $ 5,916
------------- ------------- -------------
------------- ------------- -------------
</TABLE>
13
<PAGE> 18
SAVINGS FUND PLAN
FOR EMPLOYEES OF PACIFIC GAS AND ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS (CONTINUED)
DECEMBER 31, 1993
NOTE 5: CONTRIBUTIONS (CONTINUED)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, 1991
----------------------------------------------
401(K) NON-401(K)
CONTRIBUTIONS CONTRIBUTIONS
----------------------------- -------------
EMPLOYEE EMPLOYER EMPLOYEE
CONTRIBUTIONS CONTRIBUTIONS CONTRIBUTIONS
------------- ------------- -------------
(IN THOUSANDS)
<S> <C> <C> <C>
Pacific Gas and Electric Company......................... $74,695 $31,372 $ 4,664
Pacific Gas Transmission Company......................... 958 417 64
Pacific Service Employees Association.................. 145 72 4
------------- ------------- -------------
Total.......................................... $75,798 $31,861 $ 4,732
------------- ------------- -------------
------------- ------------- -------------
</TABLE>
14
<PAGE> 19
SAVINGS FUND PLAN
FOR EMPLOYEES OF PACIFIC GAS AND ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS (CONTINUED)
DECEMBER 31, 1993
NOTE 6: NET ASSET VALUE PER UNIT:
The net asset value per unit of the DEF, BIF, SBF and USF is determined by
dividing the market 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 and the value per unit of the DEF, GIF, BIF, SBF and USF as of December
31, 1993 and 1992 are as follows:
<TABLE>
<CAPTION>
DECEMBER DECEMBER
31, 31,
1993 1992
----------- -----------
<S> <C> <C>
DEF
Number of Units................................................ 4,423,282 3,291.012
Value per unit................................................. $69.23 $62.48
GIF
Number of Units................................................ 229,960,000 134,557,000
Value per unit................................................. $1.00 $1.00
BIF
Number of Units................................................ 2,383,266 1,642,284
Value per unit................................................. $12.00 $11.01
SBF
Number of Units................................................ 16,702,833 8,253,122
Value per unit................................................. $6.21 $5.55
USF
Number of Units................................................ 5,159,002 2,060,533
Value per unit................................................. $14.56 $13.09
</TABLE>
15
<PAGE> 20
SAVINGS FUND PLAN
FOR EMPLOYEES OF PACIFIC GAS AND ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS (CONTINUED)
DECEMBER 31, 1993
NOTE 7: REALIZED GAIN ON INVESTMENTS
The following summarizes the proceeds, cost and gain/(loss) on investment
transactions for the years ended December 31, 1993, 1992 and 1991. Actual unit
cost by participant is used to determine the cost of shares sold for the Company
Stock and PAYSOP Funds. Average unit cost by participant is used to determine
the cost of shares sold for the DEF, BIF, SBF and USF.
<TABLE>
<CAPTION>
DECEMBER DECEMBER DECEMBER
31, 31, 31,
1993 1992 1991
----------- ----------- -----------
(IN THOUSANDS)
<S> <C> <C> <C>
Company Stock Fund,
PAYSOP Funds
Proceeds.................................. $ 664,616 $ 325,288 $ 105,540
Cost...................................... 380,551 197,575 69,477
----------- ----------- -----------
Gain...................................... $ 284,065 $ 127,713 $ 36,063
----------- ----------- -----------
----------- ----------- -----------
DEF
Proceeds.................................. $ 99,509 $ 101,846 $ 7,077
Cost...................................... 89,087 82,368 4,317
----------- ----------- -----------
Gain...................................... $ 10,422 $ 19,478 $ 2,760
----------- ----------- -----------
----------- ----------- -----------
BIF
Proceeds.................................. $ 8,184 $ 1,057 $ 11
Cost...................................... 8,014 1,044 11
----------- ----------- -----------
Gain...................................... $ 170 $ 13 $ --
----------- ----------- -----------
----------- ----------- -----------
SBF
Proceeds.................................. $ 8,623 $ 1,130 $ 18
Cost...................................... 7,877 1,082 17
----------- ----------- -----------
Gain...................................... $ 746 $ 48 $ 1
----------- ----------- -----------
----------- ----------- -----------
USF
Proceeds.................................. $ 8,682 $ 657 $ --
Cost...................................... 8,426 662 --
----------- ----------- -----------
Gain/(Loss)............................... $ 256 $ (5) $ --
----------- ----------- -----------
----------- ----------- -----------
</TABLE>
16
<PAGE> 21
SAVINGS FUND PLAN
FOR EMPLOYEES OF PACIFIC GAS AND ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS (CONTINUED)
DECEMBER 31, 1993
NOTE 8: UNREALIZED APPRECIATION (DEPRECIATION) OF SECURITIES
Investments in securities have been reported in the financial statements at
market value. Unrealized appreciation (depreciation) of securities resulting
from changes between the cost and related market values of investments held at
the end of the year as compared to the beginning of the year is as follows:
<TABLE>
<CAPTION>
UNREALIZED APPRECIATION
(DEPRECIATION)
-----------------------------------
12/31/93 12/31/92 CHANGE
-------- -------- ---------
(IN THOUSANDS)
<S> <C> <C> <C>
Company Stock Fund -- Pacific Gas and
Electric Company common stock........... $608,850 $784,950 $(176,100)
DEF -- other common stocks................ 37,139 25,827 11,312
BIF -- government, corporate, and mortgage
backed securities....................... 115 (43) 158
SBF -- other common stocks, investment
grade bonds, other fixed income
securities, and money market
securities.............................. 11,939 2,845 9,094
USF -- marketable equity securities of
electric utility companies.............. (1,059) 263 (1,322)
PAYSOP Fund -- Pacific Gas and Electric
Company common stock.................... 4,008 6,579 (2,571)
-------- -------- ---------
Total........................... $660,992 $820,421 $(159,429)
-------- -------- ---------
-------- -------- ---------
</TABLE>
<TABLE>
<CAPTION>
12/31/92 12/31/91 CHANGE
-------- -------- ---------
<S> <C> <C> <C>
Company Stock Fund -- Pacific Gas and
Electric Company common stock........... $784,950 $878,418 $ (93,468)
DEF -- other common stocks................ 25,827 32,902 (7,075)
BIF -- government, corporate, and mortgage
backed securities....................... (43) 109 (152)
SBF -- other common stocks, investment
grade bonds, other fixed income
securities, and money market
securities.............................. 2,845 463 2,382
USF -- marketable equity securities of
electric utility companies.............. 263 -- 263
PAYSOP Fund -- Pacific Gas and Electric
Company common stock.................... 6,579 10,526 (3,947)
-------- -------- ---------
Total........................... $820,421 $922,418 $(101,997)
-------- -------- ---------
-------- -------- ---------
</TABLE>
17
<PAGE> 22
SAVINGS FUND PLAN
FOR EMPLOYEES OF PACIFIC GAS AND ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS (CONTINUED)
DECEMBER 31, 1993
NOTE 8: UNREALIZED APPRECIATION (DEPRECIATION) (CONTINUED)
<TABLE>
<CAPTION>
UNREALIZED APPRECIATION
(DEPRECIATION)
----------------------------------
12/31/91 12/31/90 CHANGE
-------- -------- --------
(IN THOUSANDS)
<S> <C> <C> <C>
Company Stock Fund -- Pacific Gas and
Electric Company common stock............ $878,418 $445,591 $432,827
DEF -- other common stocks................. 32,902 18,355 14,547
BIF -- government, corporate, and mortgage
backed securities........................ 109 -- 109
SBF -- other common stocks, investment
grade bonds, other fixed income
securities, and money market
securities............................... 463 -- 463
TRASOP Fund -- Pacific Gas and Electric
Company common stock..................... -- 224 (224)
PAYSOP Fund -- Pacific Gas and Electric
Company common stock..................... 10,526 6,529 3,997
-------- -------- --------
Total............................ $922,418 $470,699 $451,719
-------- -------- --------
-------- -------- --------
</TABLE>
The unrealized depreciation on Pacific Gas and Electric Company's common
stock in the Company Stock Fund and the PAYSOP Fund for the years ended December
31, 1993 and 1992 is due to a decrease in the number of shares held in those
Funds as opposed to a decrease in the stock price.
Since December 31, 1993, the market value of Pacific Gas and Electric
Company's common stock has decreased in value from $35.13 to $30.38 at March 14,
1994.
NOTE 9: GAIN ON FUTURES CONTRACTS
For the years ended December 31, 1993 and 1992, a gain on futures contracts
was recorded. The collateral (included in cash and short-term investments) held
by the Bank of New York with respect to these contracts consisted of an $50,000
United States Treasury Bill maturing on April 14, 1994 and a $100,000 United
States Treasury Bill maturing on May 19, 1994.
18
<PAGE> 23
SAVINGS FUND PLAN
FOR EMPLOYEES OF PACIFIC GAS AND ELECTRIC COMPANY
SCHEDULE I -- INVESTMENTS
DECEMBER 31, 1993
<TABLE>
<CAPTION>
NUMBER OF
SHARES OF
U.S. SAVINGS
BONDS HELD AT MARKET
NAME OF ISSUER CLOSE OF PERIOD COST VALUE
- ------------------------------------------------------ --------------- -------- ----------
(IN THOUSANDS)
<S> <C> <C> <C>
Funds with Pacific Gas and Electric Company common
stock(2)
Company Stock Fund.................................. 44,682,070 $960,608 $1,569,458
--------------- -------- ----------
PAYSOP Fund......................................... 288,059 6,108 10,116
--------------- -------- ----------
Total Pacific Gas and Electric Company
common stock.............................. 44,970,129 $966,716 $1,579,574
--------------- -------- ----------
--------------- -------- ----------
United States Bond Fund
United States Savings Bonds, Series E............... 7,605 143 504
(units of $18.75 bonds)
United States Savings Bonds, Series EE.............. 93,848 2,346 3,466
(units of $25.00 bonds)
United States Savings Bonds, Series EE.............. 10,397 520 592
(units of $50.00 bonds)
--------------- -------- ----------
Total United States Bond Fund............... 111,850 $ 3,009 $ 4,562
--------------- -------- ----------
--------------- -------- ----------
DEF -- other common stocks
Basic industries.................................... 466,500 17,728 19,849
Capital goods....................................... 406,400 17,074 20,938
Consumer basics..................................... 1,301,500 55,472 58,440
Consumer durable goods.............................. 209,700 9,178 12,513
Consumer non-durables............................... 704,100 23,674 22,910
Consumer services................................... 147,200 5,813 6,590
Energy.............................................. 551,500 27,659 32,181
Finance............................................. 824,300 29,255 34,403
General Business.................................... 208,900 10,655 11,897
Miscellaneous....................................... 29,996 1,779 2,600
Shelter............................................. 110,700 3,645 4,790
Technology.......................................... 528,500 20,720 25,262
Transportation...................................... 80,600 3,500 5,093
Utilities........................................... 1,098,500 38,047 43,872
--------------- -------- ----------
Total DEF................................... 6,668,396 $264,199 $ 301,338
--------------- -------- ----------
--------------- -------- ----------
</TABLE>
19
<PAGE> 24
SAVINGS FUND PLAN
FOR EMPLOYEES OF PACIFIC GAS AND ELECTRIC COMPANY
SCHEDULE I -- INVESTMENTS (CONTINUED)
DECEMBER 31, 1993
<TABLE>
<CAPTION>
NUMBER OF SHARES OR
U.S. SAVINGS BONDS
HELD AT CLOSE OF MARKET
NAME OF ISSUER PERIOD COST VALUE
- --------------------------------------------------- ------------------- -------- ----------
(IN THOUSANDS)
<S> <C> <C> <C>
GIF(1)
Blended Contracts
Bankers Tr Basic -- 3/95...................... N/A $ 3,030 $ 3,030
Bankers Tr Basic -- 7/96...................... N/A 3,006 3,006
Bankers Tr Basic -- 7/97...................... N/A 9,685 9,685
Bankers Tr Gic -- 9/94........................ N/A 2,535 2,535
Canada Life Assurance -- 12/95................ N/A 4,012 4,012
Canada Life Assurance -- 3/96................. N/A 5,010 5,010
Confederated Life Assur -- 3/94............... N/A 1,000 1,000
Confederated Life Assur -- 3/96............... N/A 1,000 1,000
Continental Assurance Co. -- 6/96............. N/A 4,203 4,203
Continental Assurance Co. -- 8/94............. N/A 3,409 3,409
Crown Life -- 9/98............................ N/A 1,209 1,209
Hancock John Mutual Life -- 9/96............. N/A 4,243 4,243
Hancock John Mutual Life -- 10/97............ N/A 6,343 6,343
Hartford -- 12/94............................. N/A 1,460 1,460
Hartford -- 12/95............................. N/A 2,992 2,992
IBM CR Corp PGE 005 -- 11/94.................. N/A 2,500 2,500
IBM CR Corp PGE 004 -- 4/94................... N/A 2,500 2,500
IBM CR Corp GIC 001 -- 10/94.................. N/A 1,000 1,000
IBM CR Corp GIC 002 -- 2/95................... N/A 1,000 1,000
Life Ins. Co. of Virginia -- 8/94............. N/A 1,389 1,389
Mass Mutual Life Ins. -- 11/03................ N/A 17,003 17,003
Met Life Ins. -- 8/99......................... N/A 4,671 4,671
New York Life Ins. Co. -- 5/94................ N/A 1,500 1,500
New York Life Ins. Co. -- 5/96................ N/A 1,500 1,500
New York Life Ins. Co. -- 12/98............... N/A 9,876 9,876
New York Life Ins. Co. -- 12/99............... N/A 9,898 9,898
Peoples Security Life -- 7/96................. N/A 7,916 7,916
Peoples Security Life -- 9/96................. N/A 6,847 6,847
Peoples Security Life -- 7/98................. N/A 5,961 5,961
Peoples Security Life -- 6/97................. N/A 9,999 9,999
Peoples Security Life -- 1/98................. N/A 2,835 2,835
Peoples Security Life -- 9/98................. N/A 3,214 3,214
Peoples Security Life -- 3/99................. N/A 4,994 4,994
Peoples Security Life -- 9/97................. N/A 5,216 5,216
Peoples Security Life -- 6/96................. N/A 2,505 2,505
Peoples Security Life -- 7/94................. N/A 1,229 1,229
</TABLE>
20
<PAGE> 25
SAVINGS FUND PLAN
FOR EMPLOYEES OF PACIFIC GAS AND ELECTRIC COMPANY
SCHEDULE I -- INVESTMENTS (CONTINUED)
DECEMBER 31, 1993
<TABLE>
<CAPTION>
NUMBER OF
SHARES OR
U.S. SAVINGS
BONDS HELD AT MARKET
NAME OF ISSUER CLOSE OF PERIOD COST VALUE
- ----------------------------------------------------- --------------- ---------- ----------
(IN THOUSANDS)
<S> <C> <C> <C>
Prudential Ins. Co. -- 6769 11/95.................... N/A 4,357 4,357
Prudential Ins. Co. -- 6769 4/96..................... N/A 3,000 3,000
Prudential Ins. Co. -- 6769 3/95..................... N/A 3,000 3,000
Prudential Ins. Co. -- 7486 9/98..................... N/A 4,735 4,735
Provident Mutual Life Ins. Co. -- 5/95............... N/A 4,381 4,381
Provident Mutual Life Ins. Co. -- 11/94.............. N/A 2,702 2,702
Provident Mutual Life Ins. Co. -- 10/94.............. N/A 3,180 3,180
State Mutual Life GA 91905A -- 2/94.................. N/A 3,000 3,000
Union Bank of Switzerland -- 3/00.................... N/A 6,575 6,575
Union Bank of Switzerland -- 10/98................... N/A 10,268 10,268
Union Bank of Switzerland -- 3/00.................... N/A 10,310 10,310
Union Bank of Switzerland -- 8/97.................... N/A 7,099 7,099
United of Omaha Life -- 1/94......................... N/A 1,000 1,000
United of Omaha Life -- 9/96......................... N/A 1,572 1,572
United of Omaha Life -- 7/95......................... N/A 2,067 2,067
United of Omaha Life -- 8/95......................... N/A 3,567 3,567
United of Omaha Life -- 9/95......................... N/A 2,017 2,017
--------------- ---------- ----------
Total GIF.................................. N/A $ 229,520 $ 229,520
--------------- ---------- ----------
--------------- ---------- ----------
BIF
Vanguard Bond Market Fund............................ 2,856,822 $ 28,625 $ 28,740
--------------- ---------- ----------
--------------- ---------- ----------
SBF
Columbia Balanced Fund............................... 161,452 $ 92,144 $ 104,083
--------------- ---------- ----------
--------------- ---------- ----------
USF
Dreyfus Utility Stock Fund........................... 5,467,083 $ 76,395 $ 75,336
--------------- ---------- ----------
--------------- ---------- ----------
Total Investments.......................... $1,660,608 $2,323,153
---------- ----------
---------- ----------
</TABLE>
- ---------------
(1) The GIF is not measured in number of shares and is not applicable (N/A).
(2) Party-in-interest transactions.
21
<PAGE> 26
SAVINGS FUND PLAN
FOR EMPLOYEES OF PACIFIC GAS AND ELECTRIC COMPANY
SCHEDULE I -- INVESTMENTS
DECEMBER 31, 1992
<TABLE>
<CAPTION>
NUMBER OF
SHARES OR
U.S. SAVINGS
BONDS HELD AT MARKET
NAME OF ISSUER CLOSE OF PERIOD COST VALUE
- ----------------------------------------------------- --------------- ---------- ----------
(IN THOUSANDS)
<S> <C> <C> <C>
Funds with Pacific Gas and Electric Company common
stock(2)
Company Stock Fund................................. 54,748,699 $1,161,099 $1,946,050
--------------- ---------- ----------
PAYSOP Fund........................................ 520,019 10,646 17,226
--------------- ---------- ----------
Total Pacific Gas and Electric Company
common stock............................. 55,268,718 $1,171,745 $1,963,276
--------------- ---------- ----------
--------------- ---------- ----------
United States Bond Fund
United States Savings Bonds, Series E.............. 9,011 169 566
(units of $18.75 bonds)
United States Savings Bonds, Series EE............. 109,941 2,749 3,771
(units of $25.00 bonds)
United States Savings Bonds, Series EE............. 11,659 583 634
(units of $50.00 bonds)
--------------- ---------- ----------
Total United States Bond Fund.............. 130,611 $ 3,501 $ 4,971
--------------- ---------- ----------
--------------- ---------- ----------
DEF -- other common stocks
Basic industries................................... 262,800 10,600 13,550
Consumer basics.................................... 868,900 36,350 42,232
Consumer durable goods............................. 153,225 5,086 5,191
Capital goods...................................... 276,500 8,452 10,784
Consumer non-durables.............................. 383,800 16,130 17,992
Consumer services.................................. 41,600 1,844 2,027
Energy............................................. 366,200 15,846 16,771
Finance............................................ 493,900 17,505 20,847
General Business................................... 166,600 6,557 7,018
Miscellaneous...................................... 24,694 1,230 1,526
Shelter............................................ 80,100 2,346 2,811
Technology......................................... 308,950 14,375 15,307
Transportation..................................... 56,600 1,928 3,056
Utilities.......................................... 682,300 23,665 27,088
Basic industries -- CANADA......................... 11,900 287 278
Capital goods -- CANADA............................ 21,200 157 194
FINANCE -- CANADA.................................. 8,900 122 171
Energy -- NETHERLANDS.............................. 40,300 1,798 3,264
--------------- ---------- ----------
Total DEF.................................. 4,248,469 $ 164,278 $ 190,107
--------------- ---------- ----------
--------------- ---------- ----------
</TABLE>
22
<PAGE> 27
SAVINGS FUND PLAN
FOR EMPLOYEES OF PACIFIC GAS AND ELECTRIC COMPANY (CONTINUED)
SCHEDULE I -- INVESTMENTS
DECEMBER 31, 1992
<TABLE>
<CAPTION>
NUMBER OF
SHARES OR
U.S. SAVINGS
BONDS HELD AT MARKET
NAME OF ISSUER CLOSE OF PERIOD COST VALUE
- --------------------------------------------------------- --------------- ---------- ----------
(IN THOUSANDS)
<S> <C> <C> <C>
GIF(1)
Blended Contracts
Bankers Tr Basic 3/95............................... N/A 3,069 3,069
Bankers Tr Basic 7/96............................... N/A 3,014 3,014
Bankers Tr Basic 3/94............................... N/A 2,005 2,005
Bankers Tr Gic 9/94................................. N/A 4,756 4,756
Confederated Life Assur - 3/94...................... N/A 1,000 1,000
Confederated Life Assur - 3/96...................... N/A 1,000 1,000
Continental Assurance Co. - 6/96.................... N/A 5,000 5,000
Continental Assurance Co. - 8/94.................... N/A 3,201 3,201
Crown Life - 9/93................................... N/A 1,220 1,220
Hancock John Mutual Life - 9/96..................... N/A 5,000 5,000
Hartford - 9/93..................................... N/A 2,000 2,000
Hartford - 12/94.................................... N/A 1,500 1,500
Hartford - 12/95.................................... N/A 3,000 3,000
IBM CR Corp PGE 005 - 11/94......................... N/A 2,500 2,500
IBM CR Corp PGE 004 - 4/94.......................... N/A 2,500 2,500
IBM CR Corp GIC 001 - 10/94......................... N/A 1,000 1,000
IBM CR Corp GIC 002 - 2/95.......................... N/A 1,000 1,000
IBM CR Corp GIC 003 - 11/93......................... N/A 2,000 2,000
Life Ins. Co. of Virginia........................... N/A 2,285 2,285
Met Life Ins. - 12700............................... N/A 4,380 4,380
New York Life Ins. Co. - 06205...................... N/A 1,500 1,500
New York Life Ins. Co. - 06330...................... N/A 3,000 3,000
New York Life Ins. Co. - 06206...................... N/A 1,500 1,500
New York Life Ins. Co. - 20018 18C.................. N/A 10,000 10,000
Peoples Security Life - 7/93........................ N/A 1,170 1,170
Peoples Security Life - 5/93........................ N/A 1,000 1,000
Prudential Ins. Co. - 6769 11/95.................... N/A 4,106 4,106
Prudential Ins. Co. - 6769 4/96..................... N/A 3,000 3,000
Prudential Ins. Co. - 6848 3/98..................... N/A 3,005 3,005
Prudential Ins. Co. - 6769 3/95..................... N/A 5,000 5,000
Prudential Ins. Co. - 7486 9/98..................... N/A 5,000 5,000
Provident Mutual Life Ins. Co. 8/93................. N/A 1,000 1,000
Provident Mutual Life Ins. Co. 5/95................. N/A 4,120 4,120
Provident Mutual Life Ins. Co. 11/94................ N/A 2,559 2,559
Provident Mutual Life Ins. Co. 10/94................ N/A 3,039 3,039
State Mutual Life GA 91905A - 2/94.................. N/A 3,000 3,000
</TABLE>
23
<PAGE> 28
SAVINGS FUND PLAN
FOR EMPLOYEES OF PACIFIC GAS AND ELECTRIC COMPANY (CONTINUED)
SCHEDULE I -- INVESTMENTS
DECEMBER 31, 1992
<TABLE>
<CAPTION>
NUMBER OF
SHARES OR
U.S. SAVINGS
BONDS HELD AT MARKET
NAME OF ISSUER CLOSE OF PERIOD COST VALUE
- --------------------------------------------------------- --------------- ---------- ----------
(IN THOUSANDS)
<S> <C> <C> <C>
United of Omaha Life - 4/93............................ N/A 1,000 1,000
United of Omaha Life - 1/94............................ N/A 1,000 1,000
United of Omaha Life - 7/95............................ N/A 2,067 2,067
United of Omaha Life - 12/93........................... N/A 1,025 1,025
United of Omaha Life - 8/95............................ N/A 3,567 3,567
United of Omaha Life - 9/95............................ N/A 2,000 2,000
--------------- ---------- ----------
Total GIF...................................... N/A $ 114,088 $ 114,088
--------------- ---------- ----------
--------------- ---------- ----------
BIF
Vanguard Bond Market Fund................................ 1,829,970 $ 18,124 $ 18,080
--------------- ---------- ----------
--------------- ---------- ----------
SBF
Columbia Balanced Fund................................... 8,058,044 $ 42,944 $ 45,788
--------------- ---------- ----------
--------------- ---------- ----------
USF
Dreyfus Utility Stock Fund............................... 2,032,040 $ 26,682 $ 26,945
--------------- ---------- ----------
--------------- ---------- ----------
Total Investments.............................. $1,541,362 $2,363,255
---------- ----------
---------- ----------
</TABLE>
- ---------------
(1) The GIF is not measured in number of shares and is not applicable (N/A).
(2) Party-in-interest transactions.
24
