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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(MARK ONE)
/X/ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF
THE SECURITIES EXCHANGE ACT OF 1934 [FEE REQUIRED]
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1993
OR
/ / TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF
THE SECURITIES EXCHANGE ACT OF 1934 [NO FEE REQUIRED]
FOR THE TRANSITION PERIOD FROM TO
COMMISSION FILE NUMBER 1-2348
PACIFIC GAS AND ELECTRIC COMPANY
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
California 94 - 0742640
(STATE OR OTHER JURISDICTION OF (IRS EMPLOYER IDENTIFICATION NO.)
INCORPORATION OR ORGANIZATION)
77 Beale Street
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:
TITLE OF EACH CLASS WHICH REGISTERED
Common Stock, par value $5 per share New York Stock Exchange and
Pacific Stock Exchange
First Preferred Stock, cumulative, American Stock Exchange and
par value $25 per share: Pacific Stock Exchange
Redeemable:
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%
First and Refunding Mortgage Bonds: New York Stock Exchange
INTEREST DATE OF INTEREST DATE OF
SERIES RATE % MATURITY SERIES RATE % MATURITY
- ------- -------- -------------- ------- -------- --------------
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
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.
(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
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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.
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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
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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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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)
ELECTRIC GAS TOTAL
------------- ----------- -------------
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)
----- ---- -----
----- ---- -----
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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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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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)
1994 1995 1996 1997 1998 TOTAL
------ ------ ------ ------ ------ -------
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
------ ------ ------ ------ ------ -------
------ ------ ------ ------ ------ -------
- ------------
(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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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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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.
YEARS ENDED DECEMBER 31
----------------------------------------------------------------------
1993 1992 1991 1990 1989
---------- ---------- ---------- ---------- ----------
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 $6,216,050
---------- ---------- ---------- ---------- ----------
---------- ---------- ---------- ---------- ----------
- ----------
(1) Includes energy supplied through the Company's system by the City and County
of San Francisco for San Francisco's own use and for sale by San Francisco
to its customers, by the Department of Energy for government use and sale to
its customers, and by the State of California for California Water Project
pumping, as well as energy supplied by QFs and purchases from other
utilities.
(2) Includes energy output from Modesto and Turlock Irrigation Districts' own
resources.
(3) Represents energy required for pumping operations.
(4) Includes use by business units other than Electric Supply.
15
19
YEARS ENDED DECEMBER 31
-----------------------------------------------------------------
1993 1992 1991 1990 1989
--------- --------- --------- --------- ---------
SELECTED STATISTICS:
Total customers (at year-end)..................... 4,400,000 4,300,000 4,300,000 4,200,000 4,100,000
Average annual residential usage (kWh)............ 6,431 6,381 6,421 6,443 6,468
Average billed revenues per kWh (c):
Residential..................................... 12.25 11.79 11.60 10.41 9.69
Commercial...................................... 11.10 10.92 10.66 9.79 9.26
Industrial...................................... 7.18 7.29 7.20 6.59 6.36
Agricultural.................................... 11.43 10.10 10.08 9.13 8.90
Net plant investment per customer ($)............. 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
- ------------
(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:
NET
OPERATING
NUMBER CAPACITY
GENERATING PLANT COUNTY LOCATION OF UNITS KILOWATTS (KW)
- ------------------------------------- ------------------------------------ ---------------
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
------ ---------------
------ ---------------
- ----------
(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
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.
CONTROL AREA
NET CAPACITY
(AT DATE OF 1993 PEAK)
--------------------
KW %
--------- -----
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
---------
---------
GENERATION
YEAR ENDED
DECEMBER 31, 1993(3)
----------------------
KWH
THOUSANDS %
------------- -----
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
------------- ----
------------- ----
- ----------
(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
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
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:
1993 1992 1991
------ ------ ------
(IN MILLIONS)
kWh received............................................. 21,242 21,173 19,127
Energy payments.......................................... $1,099 $1,084 $970
Capacity payments........................................ $503 $489 $450
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
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
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
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.
YEARS ENDED DECEMBER 31
-----------------------------------------------------------------
1993 1992 1991 1990 1989
--------- --------- --------- --------- ---------
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
- ---------------
(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.
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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.
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)
--------- -------- --------- -------- --------- -------- --------- -------- ---------
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
--------- -------- --------- -------- --------- -------- --------- -------- --------- --------
--------- -------- --------- -------- --------- -------- --------- -------- --------- --------
- ----------
(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
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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
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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
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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.
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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
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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
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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33
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.
1994 1995 1996 1997 1998
---------- ---------- ---------- ---------- ----------
Unit 1
Refueling........... March September March September
Startup............. May November May November
Unit 2
Refueling........... September March September
Startup............. November May November
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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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.
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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:
AGE AT
DECEMBER 31,
NAME 1993 POSITION EFFECTIVE DATE
----------------------------------------------------------------------------------------------
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
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:
NAME POSITION PERIOD HELD OFFICE
------------------------- ---------------------------------------------- ----------------------------------
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
47
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
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
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
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
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
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
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
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.
SIGNATURE TITLE DATE
- --------------------------------------------- --------------------- --------------
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
* By BRUCE R. WORTHINGTON
(Bruce R. Worthington,
Attorney-in-Fact)
55
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
60
SCHEDULE V
PACIFIC GAS AND ELECTRIC COMPANY
SCHEDULE V -- CONSOLIDATED PROPERTY, PLANT AND EQUIPMENT
FOR THE YEAR ENDED DECEMBER 31, 1993
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E COLUMN F
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
---------- --------- -------- --------- ----------
---------- --------- -------- --------- ----------
- ------------
(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)
57
61
SCHEDULE V
PACIFIC GAS AND ELECTRIC COMPANY
SCHEDULE V -- CONSOLIDATED PROPERTY, PLANT AND EQUIPMENT
FOR THE YEAR ENDED DECEMBER 31, 1992
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E COLUMN F
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
---------- --------- -------- --------- ----------
---------- --------- -------- --------- ----------
- ------------
(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)
58
62
SCHEDULE V
PACIFIC GAS AND ELECTRIC COMPANY
SCHEDULE V -- CONSOLIDATED PROPERTY, PLANT AND EQUIPMENT
FOR THE YEAR ENDED DECEMBER 31, 1991
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E COLUMN F
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
---------- --------- -------- -------- ----------
---------- --------- -------- -------- ----------
- ---------------
(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.
(3) Additions include acquisition of Tex/Con Oil & Gas Company..................... $388,662
(4) Other changes consist of:
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)
59
63
SCHEDULE VI
PACIFIC GAS AND ELECTRIC COMPANY
SCHEDULE VI -- ACCUMULATED DEPRECIATION OF CONSOLIDATED PLANT IN SERVICE
FOR THE YEAR ENDED DECEMBER 31, 1993
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
------------------------ (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
----------- ----------- -------- ---------- -----------
----------- ----------- -------- ---------- -----------
- ------------
(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
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
64
SCHEDULE VI
PACIFIC GAS AND ELECTRIC COMPANY
SCHEDULE VI -- ACCUMULATED DEPRECIATION OF CONSOLIDATED PLANT IN SERVICE
FOR THE YEAR ENDED DECEMBER 31, 1992
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
----------------------- (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
---------- ----------- -------- ---------- -----------
---------- ----------- -------- ---------- -----------
- ------------
(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
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
65
SCHEDULE VI
PACIFIC GAS AND ELECTRIC COMPANY
SCHEDULE VI -- ACCUMULATED DEPRECIATION OF CONSOLIDATED PLANT IN SERVICE
FOR THE YEAR ENDED DECEMBER 31, 1991
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
------------------------ (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
---------- ---------- -------- -------- ----------
---------- ---------- -------- -------- ----------
- ------------
(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.
(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
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
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
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
----------------- (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
-------- -------- -------- -------- --------
-------- -------- -------- -------- --------
- ---------------
(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
67
SCHEDULE IX
PACIFIC GAS AND ELECTRIC COMPANY
SCHEDULE IX -- CONSOLIDATED SHORT-TERM BORROWINGS
FOR THE YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991
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)
----------------(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
- ------------
(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
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
COLUMN A COLUMN B
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
------------
------------
- ------------
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
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
------------------
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
70
INDEX TO EXHIBITS
EXHIBIT
NUMBER DESCRIPTION OF EXHIBITS
-------
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.
- ---------------
* 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.
71
INDEX TO EXHIBITS--(CONTINUED)
EXHIBIT
NUMBER DESCRIPTION OF EXHIBITS
-------
*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.