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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, 1994
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
(STATE OR OTHER JURISDICTION OF
INCORPORATION OR ORGANIZATION)
77 Beale Street
P.O. Box 770000
San Francisco, California
(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES)
94-0742640
(IRS EMPLOYER IDENTIFICATION NO.)
94177
(ZIP CODE)
(415) 973-7000
(REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE)
SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:
NAME OF EACH EXCHANGE ON
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
SERIES RATE % MATURITY
- ------- -------- --------------
II 4-1/4 Jun. 1, 1995
JJ 4-1/2 Jun. 1, 1996
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 6, 1995 was 430,151,818. On that date the aggregate market value of the
voting stock held by nonaffiliates of the Company was approximately $11,511
million. The market values of the various classes of voting stock held by
nonaffiliates were as follows: Common Stock, $10,787 million; and First
Preferred Stock, $724 million. The market values of certain series of First
Preferred Stock, for which market prices were not available, were derived by
dividing the annual dividend rate of each such series of stock by the average
yield of all of the Company's Preferred Stock outstanding for which market
prices were available.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the documents listed below have been incorporated by reference
into the indicated parts of this report, as specified in the responses to the
item numbers involved.
(1) Designated portions of the Annual Report to Shareholders for the
year ended December 31, 1994...................................... Part II (Items 5, 6, 7 and 8)
Part IV (Item 14)
(2) Designated portions of the Proxy Statement relating to
the 1995 annual meeting of shareholders........................... Part III (Items 10, 11, 12 and 13)
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TABLE OF CONTENTS
PAGE
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Glossary of Terms
PART I
Item 1. Business..................................................................... 1
General
Corporate Structure and Business............................................. 1
Competition and Industry Restructuring....................................... 2
Gas Industry................................................................. 2
Electric Industry............................................................ 3
The Company's Response to the New Competitive Environment.................... 3
California Ratemaking Mechanisms............................................. 5
Base Revenue Mechanisms...................................................... 5
Electric Fuel Revenue Mechanisms............................................. 5
Gas Fuel Revenue Mechanisms.................................................. 6
Other Rate Adjustment Mechanisms............................................. 7
Proposed Regulatory Reforms.................................................. 7
Electric Industry Restructuring Proposal..................................... 7
Financial Impact of the Electric Industry Restructuring Proposal............. 9
Company's Proposals.......................................................... 10
Current Rate Proceedings..................................................... 12
1995 Revenue Changes......................................................... 12
Biennial Cost Allocation Proceeding.......................................... 13
1996 General Rate Case....................................................... 14
Workforce Reduction Rate Mechanism........................................... 14
Customer Energy Efficiency/Demand Side Management Programs................... 14
Capital Requirements and Financing Programs.................................. 15
Electric Utility Operations
Electric Operating Statistics................................................ 17
Electric Generating and Transmission Capacity................................ 18
Electric Load Forecast and Resource Planning and Procurement................. 19
Electric Resources........................................................... 20
QF Generation................................................................ 20
Geothermal Generation........................................................ 21
Western Systems Power Pool................................................... 21
Electric Transmission Policies............................................... 21
Transmission Access and Pricing.............................................. 21
Regional Transmission Groups................................................. 22
Stranded Costs Rulemaking.................................................... 22
CPUC Transmission Policies................................................... 22
Electric Reasonableness Proceeding........................................... 23
Helms Pumped Storage Plant................................................... 23
Gas Utility Operations
Gas Operations............................................................... 24
Gas Operating Statistics..................................................... 25
Natural Gas Supplies......................................................... 26
Gas Regulatory Framework..................................................... 26
Restructuring of Canadian Gas Supply Arrangements............................ 27
Decontracting Plan........................................................... 27
Financial Impact of Decontracting Plan and Litigation........................ 28
Restructuring of Interstate Gas Supply Arrangements.......................... 28
Current Gas Transportation and Procurement Arrangements...................... 28
Recovery of Interstate Transportation Demand Charges......................... 28
Gas Reasonableness Proceedings............................................... 29
1988-1990 Canadian Gas Procurement Activities................................ 30
Proposed Gas Settlements..................................................... 30
Financial Impact of Gas Reasonableness Proceedings........................... 30
PGT/PG&E Pipeline Expansion Project.......................................... 31
Other Competitive Pipeline Projects.......................................... 32
Storage Service.............................................................. 32
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PAGE
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Diablo Canyon
Diablo Canyon Operations..................................................... 33
Diablo Settlement............................................................ 33
Nuclear Fuel Supply and Disposal............................................. 35
Insurance.................................................................... 36
Decommissioning.............................................................. 36
PG&E Enterprises
Non-Utility Electric Generation.............................................. 36
Gas and Oil Exploration and Production....................................... 37
Real Estate Development...................................................... 37
Environmental Matters and Other Regulation
Environmental Matters........................................................ 37
Environmental Protection Measures............................................ 38
Hazardous Materials and Hazardous Waste Compliance and Remediation........... 39
Electric and Magnetic Fields................................................. 42
Low Emission Vehicle Programs................................................ 42
Other Regulation............................................................. 43
California Public Utilities Commission....................................... 43
California Energy Commission................................................. 43
Federal Energy Regulatory Commission......................................... 43
FERC-Hydroelectric Licensing................................................. 43
Nuclear Regulatory Commission................................................ 44
Item 2. Properties................................................................... 44
Item 3. Legal Proceedings............................................................ 44
Antitrust Litigation......................................................... 44
Hinkley Compressor Station Litigation........................................ 45
Counties Franchise Fees Litigation........................................... 46
Cities Franchise Fees Litigation............................................. 46
Time-of-Use Meter Litigation................................................. 47
Norcen Litigation............................................................ 47
Potter Valley Hydroelectric Project.......................................... 48
PGT Unit 4C Compressor Unit Permit........................................... 48
Item 4. Submission of Matters to a Vote of Security Holders.......................... 49
Executive Officers of the Registrant......................................... 49
PART II
Item 5. Market for the Registrant's Common Equity and Related Stockholder Matters.... 50
Item 6. Selected Financial Data...................................................... 50
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations...................................................... 50
Item 8. Financial Statements and Supplementary Data.................................. 50
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure....................................................... 50
PART III
Item 10. Directors and Executive Officers of the Registrant........................... 50
Item 11. Executive Compensation....................................................... 50
Item 12. Security Ownership of Certain Beneficial Owners and Management............... 50
Item 13. Certain Relationships and Related Transactions............................... 51
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K............. 51
Indemnification Undertaking.................................................. 55
Signatures............................................................................... 56
Report of Independent Public Accountants................................................. 57
Financial Statement Schedule............................................................. 58
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GLOSSARY OF TERMS
AEAP.................. Annual Earnings Assessment Proceeding
AER................... Annual Energy Rate
AFUDC................. allowance for funds used during construction
ANG................... Alberta Natural Gas Company Ltd
ARA................... Attrition Rate Adjustment
A&S................... Alberta and Southern Gas Co. Ltd.
BCAP.................. Biennial Cost Allocation Proceeding
BRPU.................. Biennial Resource Plan Update Proceeding
BTA................... best technology available
Btu................... British thermal unit
California
Superfund........... California Hazardous Substance Account Act
CARE.................. California Alternate Rates for Energy program (formerly, LIRA)
CCAA.................. California Clean Air Act
CEC................... California Energy Commission
CEE................... Customer Energy Efficiency
CEMA.................. Catastrophic Events Memorandum Account
CERCLA................ Comprehensive Environmental Response, Compensation, and Liability
Act
CIG................... customer identified gas program
Company............... Pacific Gas and Electric Company
core customers........ All residential gas customers and smaller commercial gas customers
that do not exceed certain volume limitations
core subscription
customers........... Noncore customers who elect to receive combined gas procurement and
transportation service from the Company
CPIM.................. Core Procurement Incentive Mechanism
CPUC.................. California Public Utilities Commission
CTC................... Competition Transition Charge
DALEN................. DALEN Resources Corp.
Diablo Canyon......... Diablo Canyon Nuclear Power Plant
Diablo Settlement..... Diablo Canyon rate case settlement
DOE................... U.S. Department of Energy
DPS................... Destec Power Services
DRA................... Division of Ratepayer Advocates
DSM................... Demand Side Management
DTSC.................. California Department of Toxic Substances Control
ECAC.................. Energy Cost Adjustment Clause
El Paso............... El Paso Natural Gas Company
EMF................... electric and magnetic fields
Energy Act............ National Energy Policy Act of 1992
Enterprises........... PG&E Enterprises
EPA................... Environmental Protection Agency
ERAM.................. Electric Revenue Adjustment Mechanism
ER94.................. 1994 Electricity Report
EV.................... electric vehicle
FERC.................. Federal Energy Regulatory Commission
Geysers............... The Geysers Power Plant
GFCA.................. Gas Fixed Cost Account
GRC................... General Rate Case
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GWh................... gigawatt-hours
Helms................. Helms Pumped Storage Project
Helms Settlement...... proposed settlement resolving the treatment of unrecovered Helms
costs
Humboldt.............. Humboldt Bay Power Plant
IPP................... independent power producer
ITCS.................. Interstate Transition Cost Surcharge
kV.................... kilovolts
kVa................... kilovolt-amperes
kW.................... kilowatts
kWh................... kilowatt-hour
LEV................... low emission vehicle
LIRA.................. Low Income Rate Assistance program (now referred to as CARE)
Makowski.............. J. Makowski Co., Inc.
Mcf................... thousand cubic feet
MMBtu/d............... million British thermal units per day
MMcf.................. million cubic feet
MMcf/d................ million cubic feet per day
Mojave................ Mojave Pipeline Company
MW.................... megawatts
NEIL.................. Nuclear Electric Insurance Limited
NGV................... natural gas vehicle
NML................... Nuclear Mutual Limited
noncore customers..... industrial and commercial gas customers that exceed certain volume
limitations
NOx................... oxides of nitrogen
NOVA.................. NOVA Corporation of Alberta
Nuclear Act........... Nuclear Waste Policy Act of 1982
OIR/OII............... Order Instituting Rulemaking and Investigation
OPA................... Oil Pollution Act of 1990
OSPRA................. Oil Spill Prevention and Response Act of 1990
PBR................... performance-based ratemaking
PCBs.................. polychlorinated biphenyls
PGA................... Purchased Gas Account
PG&E.................. Pacific Gas and Electric Company
PGT................... Pacific Gas Transmission Company
Pipeline Expansion.... The expansion of the Company's and PGT's natural gas transmission
systems which was placed in service in November 1993
Properties............ PG&E Properties, Inc.
PRP................... potentially responsible party
PURPA................. Public Utility Regulatory Policies Act of 1978
PXC................... Power Exchange Corp.
QF.................... qualifying facility
RD&D.................. research development & demonstration
RDW................... Rate Design Window
Regional Board........ Central Coast Regional Water Quality Control Board
RRI................... Regulatory Reform Initiative
RTG................... Regional Transmission Group
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SFAS.................. Statement of Financial Accounting Standards
SoCal Gas............. Southern California Gas Company
SPCC.................. Spill Prevention Control and Countermeasure
TID................... Turlock Irrigation District
TCRM.................. Transition Cost Recovery Mechanism
Transwestern.......... Transwestern Pipeline Company
USGen................. U.S. Generating Company
USOSC................. U.S. Operating Services Company
WRTA.................. Western Regional Transmission Association
WSPP.................. Western Systems Power Pool
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PART I
ITEM 1. BUSINESS.
GENERAL
CORPORATE STRUCTURE AND BUSINESS
Pacific Gas and Electric Company, incorporated in California in 1905, is an
operating public utility engaged principally in the business of supplying
electric and natural gas service throughout most of Northern and Central
California. (Unless the context otherwise requires, the Company or PG&E shall
refer to Pacific Gas and Electric Company and its wholly owned and
majority-owned subsidiaries.)
The Company's principal executive office is located at 77 Beale Street,
P.O. Box 770000, San Francisco, California 94177, and its telephone number is
(415) 973-7000.
As of December 31, 1994, the Company had approximately $27.8 billion in
assets. The Company generated approximately $10.4 billion in operating revenues
for 1994. As of December 31, 1994, the Company had approximately 22,000
employees.
The Company's gas and electric utility operations, which include Diablo
Canyon Nuclear Power Plant (Diablo Canyon) operations, represent the principal
component of its business, contributing $10.2 billion in revenues in 1994 (98%
of the Company's total revenues). The Company's utility operations contributed
$2.20 of the Company's total 1994 earnings per share of $2.21. The Company's
utility assets were $26.3 billion at December 31, 1994, representing 95% of the
Company's total assets.
Diablo Canyon operations consist of two nuclear power reactor units, each
capable of generating up to approximately 26 million kilowatt-hours (kWh) of
electricity per day. In 1994, Diablo Canyon contributed $1.9 billion of revenues
(18% of the Company's total revenues) and $1.04 in earnings per share (47% of
the Company's total 1994 earnings per share). Diablo Canyon had assets of $6.0
billion at December 31, 1994 (22% of the Company's total assets).
The Company's utility service territory covers 94,000 square miles with an
estimated population of approximately 13 million, and includes all or portions
of 48 of California's 58 counties. The area's diverse economy includes
aerospace, electronics, financial services, food processing, petroleum refining,
agriculture and tourism. At December 31, 1994, the Company served approximately
4.4 million electric customers and 3.5 million gas customers.
The Company serves its electric customers with power generated by seven
primarily natural gas-fueled steam power plants with 21 units, ten combustion
turbines, the Diablo Canyon nuclear power plant with two units, 70 hydroelectric
powerhouses with 111 units, the Helms hydroelectric pumped storage plant (Helms)
with three units, and a geothermal energy complex of 14 units. The Company also
purchases power produced by other generating entities that use a wide array of
resources and technologies, including hydroelectric, wind, solar, biomass,
geothermal and cogeneration. In addition, the Company is interconnected with
electric power systems in 14 western states and British Columbia, Canada, for
the purposes of buying, selling and transmitting power.
To ensure a diverse and competitive mix of natural gas supplies, the
Company purchases gas from both Canadian and United States suppliers. In 1994,
about 53% of the Company's gas supply came from fields in Canada, about 42% came
from fields in other states (substantially all from the U.S. Southwest) and
about 5% came from fields in California.
The Company's utility operations also include Pacific Gas Transmission
Company (PGT), a wholly owned gas pipeline subsidiary of the Company. PGT owns
and operates gas transmission pipelines and associated facilities capable of
transporting approximately 2.4 billion cubic feet per day of natural gas over
612 miles from the Canadian-U.S. border to the Oregon-California border. PGT had
assets of approximately $1.2 billion at December 31, 1994. PGT's revenues in
1994 were approximately $175 million, excluding revenues related to services
provided to the Company.
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Currently, the Company's utility operations, other than Diablo Canyon, are
regulated primarily under the traditional cost-based approach to ratemaking.
However, as discussed below (see "Competition and Industry Restructuring" and
"Proposed Regulatory Reforms"), a number of proposals are being considered which
would shift utility regulation from traditional cost-of-service based concepts
to concepts based upon market competition and benchmarks.
Diablo Canyon operations are conducted under an alternative
performance-based approach to ratemaking, as a result of the Diablo Canyon rate
case settlement (Diablo Settlement), effective in 1988. Under this approach,
revenues for the plant are based primarily on the amount of electricity
generated, rather than on the costs associated with the plant's operations.
PG&E Enterprises (Enterprises), a wholly owned subsidiary of the Company,
is the parent company for the nonregulated portion of the Company's business.
Enterprises, through its subsidiaries and affiliates, engages in nonutility
electric generation, power plant operations and services, gas and oil
exploration and production and real estate development. Enterprises generated
approximately $250 million in revenues in 1994 and contributed $.01 of the
Company's total 1994 earnings per share of $2.21. Enterprises had assets of $1.5
billion at December 31, 1994.
COMPETITION AND INDUSTRY RESTRUCTURING
Under traditional utility regulatory schemes, utilities have been accorded
the exclusive right to serve customers within designated areas in return for the
commitment to provide service to all who request it. Regulation was designed in
part to take the place of competition to ensure that utility services were
provided at fair prices.
Recent changes in both the gas and electric industries have allowed
competition to develop in the gas supply and electric production segments of the
Company's business. A number of reforms at both the federal and state level have
been proposed. These reforms are designed to restructure regulation in the
energy supply industry and promote competition by providing electric and gas
customers with purchasing options.
GAS INDUSTRY
The current regulatory framework for natural gas service was established in
California in 1988. This framework segmented customers into core (all
residential customers and smaller commercial customers that do not exceed
certain volume limitations) and noncore (industrial and commercial customers
that exceed certain volume limitations) classes, and unbundled utilities' gas
transportation and procurement services which allowed noncore customers to
purchase gas directly from producers, aggregators and marketers and separately
negotiate transportation services. Similarly, in 1992 the Federal Energy
Regulatory Commission (FERC) instituted regulatory changes which required
interstate pipelines, including PGT, to unbundle sales services from
transportation services and established programs providing for the reallocation
of pipeline capacity.
As a result of these regulatory changes, the Company no longer provides
combined procurement and transportation services to most of its noncore
customers. Instead, many of these customers now procure their own gas supplies
and then purchase transportation service from the Company. As a result, the
Company has restructured its own gas operations to accommodate its decreased gas
supply and transportation requirements. The Company has terminated its long-term
Canadian gas purchase contracts and entered into new, more flexible arrangements
for the purchase of the Company's reduced gas supply requirement and is
continuing its efforts to permanently assign or broker its commitments for firm
gas transportation capacity on interstate pipelines which it once held to serve
its noncore customers.
The changes in the supply and transportation segments of the gas industry
will likely result in increased competition. The FERC has conditionally approved
the expansion of an interstate pipeline's existing system into the Company's
service territory. See "Gas Utility Operations -- Other Competitive Pipeline
Projects" below. If built, this pipeline will compete directly for
transportation service to the Company's noncore customers and may result in the
loss of sales on the Company's gas transportation system. If the Company's
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gas customers leave the Company's system by moving to an alternative intrastate
delivery system, the Company will need to recover the fixed costs of its gas
supply and delivery system over fewer units of sales. Unless costs are reduced
or imposed as transition charges on exiting customers, the price per unit for
remaining customers would go up, further exacerbating the competitive pressures.
ELECTRIC INDUSTRY
While the restructuring of the electric industry is still evolving,
recently effected and currently proposed changes at both the federal and state
levels are expected to bring increased competition into the electric generation
business. The Company performs the functions of electricity production,
transmission, distribution and customer service. However, the Company already
obtains one-third of its electrical power supply from generation sources outside
its service territory and from qualifying facilities (QFs), small power
producers or cogenerators who meet certain federal guidelines which qualify them
to supply generating capacity and electric energy to utilities, owned and
operated by independent power producers (IPPs). It is expected that new power
plant projects will be increasingly undertaken by IPPs rather than utilities. In
addition, the recently enacted National Energy Policy Act of 1992 (Energy Act)
reduces various restrictions on the operation and ownership of IPPs and provides
them and other wholesale suppliers and purchasers with increased access to
electric transmission lines throughout the United States.
At the state level, in April 1994 the California Public Utilities
Commission (CPUC) issued a proposal on electric industry restructuring which
seeks to lower energy prices and provide customers with a choice of electric
generation suppliers (known as direct access). In addition, where competition
does not exist, the CPUC proposes to move electric utilities from traditional
regulation, under which the utilities' revenues are set by regulators so as to
cover the utilities' costs and provide a fair rate of return, to
performance-based ratemaking (PBR). The shift to PBR is intended to provide
stronger incentives for efficient utility operations, management and investment.
Under its April 1994 proposal, the CPUC would unbundle electric services
and, on a phased-in basis over time, provide to electric utility retail
customers the option to choose from a range of electric generation providers,
including utilities, beginning in 1996. This plan is termed "direct access."
Utilities serving a given territory would still be obligated to provide
transmission and distribution services on a nondiscriminatory basis to customers
choosing direct access service from another generation provider, thereby
engaging in the practice known as retail wheeling. Coinciding with these
changes, the CPUC foresees development of a competitive spot market for electric
generation and an increasing need for inter-regional coordination of the
electric grid, and elimination of existing resource planning and procurement
approaches.
If as a result of restructuring a substantial number of the Company's
customers were to elect electric generation alternatives under a retail wheeling
system, the Company's recovery of its purchased power obligations to QFs and its
investment in its electric generation assets would be dependent on prices
charged to remaining customers, transition charges that may be imposed on
existing customers, and the Company's ability to reduce its costs. While the
CPUC proposal contemplates that some stranded costs of utility generating
facilities be recovered through a "competition transition charge," the CPUC has
not specified whether other costs, such as regulatory assets and QF obligations,
might be recovered through such a charge or how such charge would be allocated
to and collected from customers. See "Proposed Regulatory Reforms -- Electric
Industry Restructuring Proposal" below.
THE COMPANY'S RESPONSE TO THE NEW COMPETITIVE ENVIRONMENT
The restructuring of the electric and gas industries has led to a greater
emphasis on the Company's ability to offer its services at competitive prices.
Currently, the Company's average gas prices for residential, commercial and
industrial customers are among the lowest utility gas prices in California. The
Company's residential electric bills are at the middle of the scale nationally.
However, the Company's prices per kWh are high when compared with national
averages. The Company's prices for industrial customers average approximately
7.0 cents per kWh, which is comparable to prices charged by the other major
California
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utilities, but above the industrial electric prices in many other states. The
Company's electric prices include the costs for generation, transmission,
distribution and customer service.
The Company has taken several significant steps to address the issues
raised by the new competitive environment in the energy industry. These steps
include proposals to modify the existing regulatory process and to provide the
Company additional pricing flexibility for those customers with the most
competitive options. These proposals, together with various cost containment
measures implemented by the Company, are intended to help position the Company
to effectively compete in the restructured electric and gas industries. With
this goal in mind:
-- The Company has proposed to extend through 1996 its electric rate
freeze, which began in 1993.
-- The Company has announced a five-year goal of reducing its system
average electric rate to 10 cents per kWh or less, which would
constitute about a 25% reduction in the Company's system average
electric rate after adjusting for inflation.
-- In December 1994, the Company, the CPUC's Division of Ratepayer
Advocates (DRA), the California Attorney General and other parties
proposed to modify the Diablo Settlement to reduce the price paid for
electricity generated at Diablo Canyon over the next five years. See
"Diablo Canyon -- Diablo Settlement" below.
-- The Company has requested CPUC approval to implement a statewide
three-year experimental program under which California utilities would
offer certain industrial customers and other large energy users the
option to receive electricity from competitive suppliers, starting as
early as January 1, 1996.
-- The Company has proposed instituting PBR for determining base revenues,
under which electric and natural gas base revenues would be determined
annually by formula rather than through general rate cases (GRCs),
attrition rate adjustments (ARAs) and Cost of Capital proceedings. The
Company has also proposed a core gas procurement incentive mechanism
(CPIM) that would substitute for reasonableness reviews of certain
costs. The CPIM would measure the Company's gas procurement costs
against market benchmarks and would provide for the sharing between
ratepayers and shareholders of variances from a preset range around the
market benchmark.
-- The Company has reduced electric rates for certain of its largest
industrial customers through an economic stimulus rate that the Company
proposes to extend through the end of 1996.
-- The Company has planned reductions in annual spending in 1995 of
approximately $600 million from 1993 spending levels.
-- The Company has refinanced debt and preferred stock over the last three
years resulting in annual savings of approximately $97 million in
financing costs.
-- Through its wholly owned subsidiary, Enterprises, the Company has taken
steps to position itself to compete in the nonregulated energy business.
In 1994, Enterprises and Bechtel Enterprises, Inc. acquired J. Makowski
Co., Inc. (Makowski), a company engaged in the development of natural
gas-fueled power generation projects and natural gas distribution,
supply and underground storage projects. In addition, Enterprises, in
partnership with Bechtel Enterprises, Inc., is in the process of forming
a company to develop, build, own and operate international nonutility
generation projects.
While it is difficult to predict the ultimate outcome of the ongoing
changes that are taking place in the utility industry, the Company believes that
the end result will involve a fundamental change in the way it conducts its
business. The changes may impact financial operating trends and add volatility
to the Company's earnings. The Company is actively seeking regulatory and
operational changes that will allow the Company to provide energy services in a
safe, reliable and competitive manner while achieving strong financial
performance.
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CALIFORNIA RATEMAKING MECHANISMS
The ratemaking mechanisms currently applied by the CPUC in setting the
Company's rates are discussed below. As more fully discussed below (see
"Proposed Regulatory Reforms -- Company's Proposals"), the Company has filed
proposals with the CPUC requesting alternatives to certain aspects of the
current regulatory approach to setting rates. If adopted, those proposals would
significantly alter the existing ratemaking mechanisms. In addition, the Company
proposes to continue through 1996 its freeze on retail electric rates, first
implemented in 1993, which impacts the application of certain of these
ratemaking mechanisms in current rate proceedings (see "Current Rate
Proceedings" below).
BASE REVENUE MECHANISMS
Under the CPUC's Rate Case Plan, the CPUC sets the Company's base revenue
requirements for both electric and gas operations in the GRC proceeding. Base
revenue is revenue intended to recover the Company's fixed costs and non-fuel
variable costs and to provide a return on invested capital. (Fuel revenue
requirements, intended to recover the Company's fuel and fuel-related costs, are
set as part of the Energy Cost Adjustment Clause (ECAC) proceeding for electric
operations and the Biennial Cost Allocation Proceeding (BCAP) for gas
operations, as discussed below.) In the GRC, revenues and expenses are
determined on a forecast or future test-year basis, rather than on a
historic-year basis. The Company files a GRC application once every three years,
with a decision issued approximately 13 months after the application is filed.
The Company's current rates are based on its 1993 GRC. The Company filed its
1996 GRC application in December 1994, for rates effective January 1, 1996.
The ARA adjusts base rates in the years between GRC decisions to partially
offset attrition in earnings due to changes in non-fuel operating expenses and
capital costs. Labor expenses and nonlabor maintenance and operation expenses
are indexed, and a prescribed amount is allowed for recovery of expenses related
to changes in depreciation, income taxes, financing costs, rate base growth and
other items. The ARA improves the Company's ability to earn its authorized rate
of return for utility operations in the years between GRCs. The cost of capital
incorporated in an ARA, including authorized return on equity, is determined
separately by the CPUC in the annual Cost of Capital consolidated proceeding
which reviews financing costs and adopts capital structures for all California
energy utilities.
In May 1993, the DRA and various special interest groups filed a joint
petition with the CPUC requesting suspension, for an indefinite period, of the
ARA mechanism. The petition requests that any future attrition rate increases be
considered only upon application for such relief and only if the then current
rate of inflation exceeds 6% on an annual basis. The petition recommends that
any attrition rate adjustment authorized in such cases be limited to inflation
above the 6% threshold level. The CPUC has not acted on the DRA's petition, but
its staff has recommended that the petitioners raise the matter in the Company's
1996 GRC.
The Electric Revenue Adjustment Mechanism (ERAM) allows rate adjustments to
offset the effect on base revenues of differences between actual electric sales
volumes and the forecasted volumes used to set rates in the last GRC or ARA
proceeding. The ERAM eliminates the impact on earnings of sales fluctuations,
including those resulting from conservation and weather conditions. Base revenue
differences resulting from the disparity between actual and forecasted electric
sales accumulate in a balancing account, with interest, and are recovered from
or returned to customers through higher or lower future rates. ERAM rate
adjustments are made as part of the ECAC proceeding described below.
ELECTRIC FUEL REVENUE MECHANISMS
The ECAC provides for recovery of 91% of recorded (or actual) electric fuel
and fuel-related energy costs, and for collection of revenues attributable to
Diablo Canyon generation. Differences between the sum of actual costs and Diablo
Canyon revenues recoverable through ECAC, and the revenues intended to cover
such amounts, accumulate in a balancing account, usually with interest, and are
recovered from or returned to ratepayers through ECAC adjustments to future
rates. ECAC rate adjustments are set once a year, based on a January 1 effective
date, to recover the adjustment amount over a forward-looking calendar test
year. Revenue adjustments resulting from the California Alternate Rates for
Energy (CARE) program (formerly known as
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the Low Income Rate Assistance, or LIRA, program) and the ERAM are consolidated
with the ECAC adjustment in the annual ECAC proceeding. The CARE program
provides for discount residential rates for customers who qualify under
low-income criteria, with the direct costs of CARE electric rate discounts
funded through revenue adjustments made in the ECAC proceeding. Rates are
subject to a further ECAC adjustment effective May 1 if the required adjustment
would be more than 5% of total annual electric revenues.
Fuel and fuel-related costs included in an ECAC adjustment are subject to a
subsequent reasonableness review, in which the CPUC determines whether those
costs were reasonably incurred. Costs found to be unreasonable may be
disallowed, or deducted, from the amount to be recovered in rates. The amount of
Diablo Canyon revenues recovered through the ECAC is determined under the Diablo
Settlement and is not subject to reasonableness review. See "Diablo
Canyon -- Diablo Settlement" below.
The Annual Energy Rate (AER) mechanism provides for recovery of 9% of
forecasted electric fuel and fuel-related costs, without balancing account
protection for actual costs that are higher or lower than forecasted. Thus, the
AER mechanism places the Company at partial risk for variations between actual
and forecasted electric energy costs. To minimize the revenue risk resulting
from the potential for substantial swings in energy-related expenses, the
increase or reduction in earnings due to operation of the AER is limited to a
change in return on equity of 1.4 percent.
GAS FUEL REVENUE MECHANISMS
The BCAP is the major rate proceeding for the Company's natural gas
service. As part of this proceeding, the gas fuel revenue requirement and gas
transportation revenue requirement are adopted, based on forecasts and
assumptions for the upcoming two-year period. The gas fuel revenue requirement
provides for the recovery of the cost of the gas procured for core customers;
the gas transportation revenue requirement provides for the recovery of the cost
of providing gas transportation service for all gas customers and other costs
incurred in providing gas service, and also includes the gas base revenue
requirement set in the GRC and adjusted by the ARA mechanism.
Both the gas fuel revenue requirement and the gas transportation revenue
requirement set in the BCAP include amounts accumulated in several associated
balancing accounts. The main balancing account associated with the gas fuel
revenue requirement is the Purchased Gas Account (PGA), which accumulates
differences between the actual cost of gas procured for core customers and the
revenues intended to recover those costs. The main balancing accounts associated
with the gas transportation revenue requirement are the core and noncore Gas
Fixed Cost Accounts (GFCAs), which generally accumulate differences between the
actual transportation revenues and the authorized transportation revenue amounts
for the core and noncore customer classes, respectively. In the case of the
noncore GFCA, only 75% of any overcollection or undercollection of revenues is
included in rates.
BCAP rate adjustments may also include amounts accumulated in the
Interstate Transition Cost Surcharge (ITCS) balancing account. Demand charges
for interstate gas transportation capacity held by a utility which are not fully
recovered under the operation of the CPUC's capacity brokering rules accumulate
in the ITCS account and are recovered as authorized by the CPUC. Unrecovered
demand charges will be allocated to customers on an equal cents-per-therm-usage
basis, subject to a limit on the amount that can be allocated to core customers.
In addition to adopting the gas revenue requirements in the BCAP, the CPUC
also allocates both the gas fuel and transportation revenue requirements among
core and noncore classes and among the customer groups within those classes.
Revenue allocation (also referred to as cost allocation) is based primarily on
forecasts of demand and use by each customer class. The BCAP also includes the
rate design process, in which it is determined how specific costs are recovered
from customers, with rates set accordingly.
Generally, a BCAP filing is made on August 15 of every other year for rates
to be effective on April 1 of the following year. An interim filing, referred to
as a trigger filing, is permitted to set new rates for the second year of the
BCAP period if amortization of accumulated overcollections or undercollections
in balancing accounts would change either bundled core rates or noncore
transportation rates by more than 5%.
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In December 1992, the CPUC announced proposed rules which would (i) extend
the gas ratemaking cycle from two to three years and (ii) reduce the amount of
balancing account protection provided for noncore transportation revenues. Other
than accepting comments from interested parties, the CPUC has taken no further
action on the proposed rules.
OTHER RATE ADJUSTMENT MECHANISMS
Under the Customer Energy Efficiency (CEE) ratemaking mechanism adopted in
1990, the Company is authorized to recover in rates some of the energy savings
resulting from and costs of certain of its CEE, or Demand Side Management (DSM),
programs. CEE rate adjustments resulting from shareholder incentives earned on
CEE programs are determined as part of the Annual Earnings Assessment Proceeding
(AEAP), a consolidated proceeding established by the CPUC to authorize
shareholder earnings for the Company and the other California energy utilities
arising out of the previous year's DSM program accomplishments. AEAP rate
adjustments will be consolidated with any other rate changes effective on
January 1 of each year. See "Customer Energy Efficiency/Demand Side Management
Programs" below.
The Catastrophic Events Memorandum Account (CEMA) permits utilities to
record for eventual recovery through rates the reasonable costs they incur in
restoring service, repairing or replacing facilities and complying with
government orders following a catastrophic event which is declared a disaster by
the appropriate federal or state authorities. The utility must seek recovery of
costs accumulated in the CEMA through a GRC or other formal rate-setting
application, with recovery subject to a reasonableness review by the CPUC.
PROPOSED REGULATORY REFORMS
A number of proposals have been made by both the CPUC and the Company to
effect reforms to the current regulatory approach to setting rates for
California utilities. The most significant of these proposed reforms are
detailed below.
ELECTRIC INDUSTRY RESTRUCTURING PROPOSAL
In April 1994, the CPUC issued an order instituting a rulemaking and
investigation (OIR/OII) on electric industry restructuring. The proposal, which
is subject to comment and modification, involves two major changes in electric
industry regulation.
The first would move electric utilities from traditional ratemaking to PBR.
The second would unbundle electric services and provide electric utility retail
customers the option to choose from a range of electric generation providers,
including utilities. The CPUC characterized this approach as customer direct
access. Under the CPUC's proposal, customer direct access to power supplies
would be phased in over a six-year period from 1996 to 2002. Utilities would
still be obligated to provide transmission and distribution services to all
customers.
To ensure an orderly transition that maintains the financial integrity of
the utilities, the CPUC proposed that uneconomic costs of utility generating
assets (i.e., costs which are above market and could not be recovered under
market-based pricing) be recovered through a competition transition charge
(CTC). However, the OIR/OII did not specify which costs might be recovered
through such a transition charge or how such a charge would be allocated to and
collected from customers.
In June 1994, the Company filed its initial comments on the CPUC's
proposal. The Company's response generally supported the CPUC's direct access
approach to restructuring the energy services industry, but proposed an
implementation schedule for direct access beginning in 1996, with direct access
service available to all customers by 2008. The Company indicated that if its
proposed implementation schedule is adopted, it will request recovery of certain
incurred and committed costs through the CTC, but will not request recovery of
transition costs associated with its electric generation facilities. The Company
also indicated that it did not intend to shift costs between customer classes.
For direct access customers, the Company proposed that it be given the pricing
flexibility to compete and sell unbundled electric power while assuming the
market risk of competitive pricing. The Company indicated that its proposed
schedule, coupled with pricing flexibility, will
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permit the Company sufficient time to reduce its generation costs and recover
its investment in facilities built to meet its long-standing utility service
obligations.
Under the Company's proposed implementation schedule for direct access,
industrial and large commercial customers (which represented approximately 30%
of the Company's electric generation revenues in 1994) would be eligible for
direct access in the period 1996 through 2002. The remaining non-residential
customers (which represent approximately 31% of 1994 electric generation
revenues) would be eligible in the period 2003 through 2006. Residential
customers (which represent approximately 39% of 1994 electric generation
revenues) would be eligible in 2007 and 2008.
In its response, the Company proposed that unless and until a policy
decision is made to discontinue existing environmental or social benefit
programs, the costs of those programs should be allocated to all electric
customers, including those who elect direct access, and included as a separately
identified component on customers' bills. The Company also proposed to retain an
ongoing obligation to provide electric power for residential customers, but
suggested that the utility should be obligated to provide electric supply only
on a best efforts basis to non-residential direct access customers that decide
to return to the Company for their power supply and on terms of service to be
negotiated.
In November 1994, the Company filed testimony with the CPUC on uneconomic
assets and obligations which would result from the CPUC's proposed electric
industry restructuring. The Company indicated that the CTC should be permitted
to provide for three types of costs: (1) utility-owned generation assets and
obligations resulting from power purchase agreements other than contracts with
QFs, (2) QF power purchase obligations, and (3) generation-related regulatory
assets. The Company also indicated that it would not seek CTC recovery for the
first of these categories -- costs associated with utility-owned generation
assets and non-QF obligations -- if direct access is phased in over a 12-year
period consistent with the proposal made by the Company in June 1994 and if
pricing flexibility was provided to allow the Company to successfully compete to
provide energy services to direct access eligible customers.
The Company has since filed revised testimony which reflects the proposed
agreement to modify the pricing provisions of the Diablo Settlement. See "Diablo
Canyon -- Diablo Settlement" below. If the agreement is approved, it would
reduce the amount of potential transition costs associated with the Company's
generation assets.
The table below sets forth the Company's revised estimates of the CTC which
reflects the proposed settlement amounts for Diablo Canyon.
ILLUSTRATION OF PG&E'S POTENTIAL CTC*
USING PG&E'S COMPETITIVE PROXY PRICE AND REVISED DIABLO PRICING
1996 PRESENT VALUE @ 9.2%
($ BILLIONS)
-------------------------------------------------------------------------------------------------------
COMPETITIVE PROXY PRICE (C/KWH)
-------------------------------------------------
DESCRIPTIONS 3.2C IN 1994 4.0C IN 1994 4.8C IN 1994
-------------------------------------------------- ------------- ------------- -------------
PG&E Generation w/Revised Diablo Pricing.......... $5.9 $0.9 $0.0
QF Contracts...................................... $4.0 $2.9 $2.0
Generation-Related Regulatory Assets.............. $0.9-$1.3 $0.9-$1.3 $0.9-$1.3
Total CTC............................... $10.8-$11.2 $4.7-$5.1 $2.9-$3.3
- ---------------
* The calculations reflected in the table are based on numerous assumptions,
variables and estimates of future prices, energy supplies and economic trends.
The CTC shown should be viewed only as preliminary estimates. The adopted CTC
could be higher or lower depending on the method and assumptions selected by
the CPUC for deriving the CTC.
These CTC estimates were determined by comparing the future revenue
requirements of generation assets (including Diablo Canyon at the proposed
modified prices) and power purchase obligations over a twenty-year and
thirty-year period, respectively, with the revenues computed at the assumed
market price.
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The revenue requirement for Diablo Canyon and all Company-owned generation
assets included a return on investment. The actual amount of uneconomic assets
and obligations will depend upon the final form of regulatory changes adopted by
the CPUC and the actual market price of electricity. CTC recovery less than the
amount estimated by the Company will not equate to the loss, if any, the Company
may record as a result of the electric industry restructuring. See "Financial
Impact of the Electric Industry Restructuring Proposal" below.
In December 1994, the CPUC issued an interim decision in the OIR/OII. The
decision set a schedule under which the CPUC would propose a policy decision in
March 1995, with a final policy decision effective no earlier than September
1995. However, on March 21, 1995, the CPUC announced that it was postponing
issuance of its proposed policy statement to allow additional time for analysis
of the extensive record developed in the OIR/OII. It is expected that, when it
is issued, the CPUC's proposed policy statement will be subject to hearings and
state legislative review before it can be implemented.
The CPUC's December 1994 interim decision also established a public working
group to comment on unbundling and cost recovery, social programs and resource
procurement under several different models for restructuring which involve
direct access or a supply pool for use by wholesale and/or retail purchasers of
electricity. The working group, which consisted of the energy utilities and any
other parties who joined voluntarily, submitted its report to the CPUC in
February 1995.
In an effort to allow large energy users to begin exercising choice among
electricity suppliers while public policy issues are resolved in the OIR/OII,
the Company has requested CPUC approval to implement an experimental program
under which California utilities would offer certain customers the option to
receive electricity from competitive suppliers beginning as early as January
1996. See "Company's Proposals -- Experimental Procurement Service for
Customer-Identified Electric Supply" below.
FINANCIAL IMPACT OF THE ELECTRIC INDUSTRY RESTRUCTURING PROPOSAL
The transition to a competitive market environment may affect the Company's
future revenues and cash flows. In the event that recovery of the Company's
costs and investments becomes unlikely or uncertain due to competitive pressures
or regulatory changes, it could cause the Company to write off applicable
portions of its regulatory assets. The final CPUC determination of uneconomic
costs and the method and amount of recovery could adversely affect the Company's
returns on its investments in electric generation assets. If future electric
generation revenues are insufficient to recover the Company's investments and QF
obligations, the Company would recognize a loss upon the determination of the
competitive price for electricity resulting from the electric industry
restructuring. The book value of the Company's generation assets, excluding
Diablo Canyon, is approximately $2.7 billion at December 31, 1994. The net book
value of the Company's investment in Diablo Canyon is approximately $5.2 billion
at December 31, 1994.
The Company currently accounts for the economic effects of regulation in
accordance with the provisions of Statement of Financial Accounting Standards
(SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation." As a
result of applying the provisions of SFAS No. 71, the Company has accumulated
approximately $3.7 billion of regulatory assets, including balancing accounts,
as of December 31, 1994. If the OIR/OII is adopted as proposed by the CPUC or
the Company determines that future electric generation rates will no longer be
based on cost-of-service, the Company will discontinue application of SFAS No.
71 for the electric generation portion of its operations. If such discontinuance
should occur, the Company would write off all applicable generation-related
regulatory assets to the extent that transition cost recovery is not assured.
The regulatory assets attributable to electric generation, excluding balancing
accounts of approximately $700 million which are expected to be recovered in the
near term, are estimated to be $1.6 billion at December 31, 1994. This amount
could vary depending on the allocation methods used.
The final determination of the financial impact will depend on the form of
regulation, including transition mechanisms, if any, adopted by the CPUC and the
groups of customers affected. Currently, the Company is unable to predict the
ultimate outcome of the electric industry restructuring or predict whether such
outcome will have a significant impact on its financial position or results of
operations.
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COMPANY'S PROPOSALS
Experimental Procurement Service for Customer-Identified Electric Supply
In February 1995, the Company requested CPUC approval to implement a
statewide three-year experimental program under which California utilities would
offer industrial customers and other large energy users the option to receive
electricity from competitive suppliers, starting as early as January 1, 1996.
The Company's proposed program would include the following key features:
-- A group of large electricity users would be permitted to enter into
individually negotiated "buy/sell" agreements with alternative suppliers
of electricity. This "buy/sell" proposal would be modeled to a large
extent after the "customer identified gas" (CIG) program implemented by
the CPUC in 1991 as part of its restructuring of the natural gas
industry. The utility would purchase electricity on behalf of each
participating customer. The electricity would be purchased from any
supplier chosen by the customer, at a price previously negotiated by the
customer. The utility then would resell the electricity to the customer
at the customer's negotiated price, as part of a bundled retail sale to
that customer. For customers who elect to purchase energy from
alternative sources located outside the Company's service territory, the
Company will agree to use a portion of its transmission capacity (up to
50 megawatts (MW) at the Oregon-California border to accommodate
purchases on behalf of customers whose suppliers deliver at that point.
The Company will accept and buy power delivered to its other points of
interconnection, and amounts in excess of 50 MW at the Oregon-California
border interconnection, only if transmission capacity is available.
-- The number of the Company's customers eligible to participate in the
experiment would increase each year. The experimental program initially
would apply in 1996 to customers with annual average demand above 7,500
kilowatts (kW) (approximately 30 customers). In 1997 customers with
annual average demand above 4,000 kW (approximately 50 additional
customers) would be eligible for the program, joined in 1998 by
customers with annual average demand above 2,000 kW (approximately 110
additional customers).
-- Utilities would be permitted to negotiate agreements with customers to
compete with alternative suppliers of electricity. Lower revenues to the
utility resulting from such individually negotiated contracts would not
be offset through rate increases to other customers, putting
shareholders at risk for any loss of revenue resulting from the
experimental program. The Company estimates that if, upon full
implementation of the experiment, all eligible customers who might find
it economic participated in the buy/sell program and were able to use
alternative suppliers to meet their entire load requirements, the
maximum annual revenues that could be lost to the Company, net of
generation costs saved as a result of customers' participation in the
buy/sell program, is approximately $21 million.
-- Customers participating in the "buy/sell" experiment would receive a
predetermined credit on their utility bills which is based on prices
paid to QFs for energy and capacity. This credit is used as a proxy for
the market price of electricity. Added to participating customers' bills
would be the cost of power they negotiated with an alternative supplier.
-- The participating customers' prices would remain fully "bundled," a full
package of services at one price. This would mean that issues such as
unbundling, recover of transition costs, funding of social and
environmental programs and resolution of state and federal
jurisdictional matters would not have to be resolved prior to
commencement of the experimental program.
-- At the conclusion of the three-year experimental program, the
information gained could be used by public policy makers to evaluate the
benefits of customer choice.
PBR
In March 1994, the Company filed an application with the CPUC requesting
that it adopt the Company's proposed Regulatory Reform Initiative (RRI). The
Company's RRI included, among other things, a PBR proposal. While the guiding
principles behind the Company's RRI proposal are not affected by the OIR/OII,
many of the specifics would change. Once the details of the CPUC's electric
industry restructuring plan are
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sufficiently definitive, the Company proposes to revise its RRI filing to
reflect the CPUC's plan. The Company expects to seek a revised RRI that includes
PBR for determining base revenues annually by formula rather than through GRCs,
ARAs and Cost of Capital proceedings.
CPIM
Specific proposals regarding a gas procurement mechanism were not included
in the Company's March 1994 RRI filing. However, in December 1994, the Company
filed an application for approval of the CPIM, a three-year experimental gas
procurement incentive mechanism for core procurement purchases. The CPIM
reflects an agreement with the DRA and would, among other things, replace
traditional reasonableness review of gas costs with a comparison to a
market-based benchmark.
The CPIM covers all of the Company's purchases of commodity gas and
pipeline capacity for its core and core subscription customers. (Core
subscription customers are noncore customers who elect to receive combined
procurement and transportation service from the Company.) The CPIM does not
cover any gas base costs, including amounts associated with storage operations,
gas and pipeline capacity purchased for the Company's power plants or
out-of-state pipeline capacity beyond that reserved for the core and core
subscription customers.
Under the CPIM, the reasonableness of the Company's core gas purchases is
determined by a comparison of actual costs against a market benchmark. The
Company is either rewarded or penalized depending on whether its actual incurred
costs fall below or above the benchmark and a tolerance band, or reasonableness
zone. The Company would recover all costs that fall within the reasonableness
zone; ratepayers and shareholders would share the costs or savings if actual
costs fall above or below the reasonableness zone.
The Company proposed an expedited schedule under which the CPUC would
approve the CPIM by May 1995. However, protests have been filed requesting
hearings or workshops on the Company's CPIM application, and it is not clear
when a CPUC decision will be issued.
Pricing Flexibility Proposals
The Company has filed testimony in its 1995 electric rate design window
(RDW) proceeding proposing beneficial rate options for certain industrial,
commercial and agricultural customers who might otherwise not take service from
the Company. The CPUC's GRC plan establishes the RDW as a forum for considering
certain rate design changes in years between GRCs. The Company's proposals are
narrowly focused to provide beneficial options to some customers. Specifically,
the Company proposes several standard contracts for commercial and industrial
customers which offer prices based upon the cost of the customer's alternatives
or, in some cases, specified discounts from the Company's rates. (These
contracts are similar to those contemplated in the Large Electric Manufacturing
Class proposal that was included in the Company's March 1994 RRI filing.) In
addition, the Company proposes rate options which would establish discounts from
the current rates charged to certain agricultural customers. Although the
Company's RDW filing seeks to have any revenue shortfall associated with these
rate options allocated to all customers in future revenue allocation
proceedings, in other instances in which the CPUC has approved similar rate
options, revenue shortfalls have been allocated, in whole or in part, to
shareholders.
With respect to gas service, the Company filed a petition with the CPUC in
June 1994 requesting authorization to implement an optional long-term
competitive noncore gas transportation tariff which would be offered to the
Company's largest gas transport customers under a ten-year firm service
agreement. The Company's petition indicated that its shareholders would bear the
risk of any revenue shortfalls attributable to differences between the long-term
rate option and the customer's otherwise applicable standard rate. In September
1994, the CPUC issued a decision approving the Company's proposed long-term
noncore gas transportation tariff, but subject to certain conditions that were
not contemplated by the Company's original proposal. The Company has filed a
petition for rehearing of that decision, and indicated that if the CPUC
continues to insist upon its proposed conditions as the basis for its approval
of the proposed tariff, the Company intends to decline to implement the proposed
tariff and would not voluntarily accept the tariff as modified by the CPUC.
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As an alternative service option, in October 1994 the Company began
offering a standard 59-month interruptible transportation service, at a rate
comparable to that requested under the noncore gas transportation tariff
proposal, to noncore customers with potential transportation alternatives. A
potential competitor of the Company has filed a complaint at the CPUC
challenging the Company's use of this service option on several grounds. The
CPUC has not yet acted on the complaint.
CURRENT RATE PROCEEDINGS
In August 1994, the Company announced that it would extend through 1995 its
freeze on retail electric rates which began in 1993. The Company also announced
that it would continue its annual $70 million economic stimulus rate reduction
through 1995 for its largest business customers. (The Company has since proposed
to extend its electric rate freeze and the economic stimulus rate reduction
through 1996.)
In December 1994, the CPUC approved the continuation of the electric rate
freeze through 1995 and issued its decisions in the Company's ARA and ECAC
proceedings. In order to accomplish the electric rate freeze, the effects of the
CPUC decisions on the Company's various electric rate proceedings were
consolidated, resulting in a net change in electric rates of zero, effective
January 1, 1995 (see "1995 Revenue Changes" below).
1995 REVENUE CHANGES
The following table summarizes the various rate case decisions that became
effective on January 1, 1995.
SUMMARY OF RATE CASE DECISIONS
EFFECTIVE JANUARY 1, 1995
(IN MILLIONS)
ELECTRIC GAS TOTAL
----- ---- -----
1995 Attrition (excluding Cost of Capital)...................... $ 0 $ 69 $ 69
1995 Cost of Capital............................................ 105 33 138
Helms Proceeding................................................ 12 -- 12
Petition to Modify 1993 GRC (reduced CEE and RD&D funding)...... (117) (33) (150)
ARA Proceeding.................................................. (158) -- (158)
ITCS............................................................ -- 31 31
ECAC/AER/ERAM/LIRA/CEE.......................................... 158 -- 158
----- ---- -----
Total Change in Revenue Requirement................... $ 0 $100 $ 100
===== ==== =====
ARA Proceeding. In December 1994, the CPUC issued a resolution authorizing
the Company to implement an ARA to keep the Company's retail electric rates
unchanged through 1995, consistent with the Company's 1995 electric rate freeze.
The CPUC authorized the Company to forgo the electric rate increase of
approximately $170 million that otherwise would have occurred on January 1, 1995
as authorized in the Company's 1993 GRC. In addition, the CPUC adopted the
Company's proposal to decrease electric base revenues in an amount equal to the
increase in revenues approved by the CPUC in the Company's 1995 Cost of Capital
proceeding and ECAC proceeding (as described below), and the increase in
revenues contemplated by the proposed settlement in the Helms proceeding (see
"Electric Utility Operations -- Helms Pumped Storage Plant" below), such that
electric rates will not increase through the end of 1995. The Company is
implementing base cost reductions which are reflected in the decreased base
revenues.
The CPUC also authorized the implementation of an ARA which results in an
increase of $69 million for gas base rates. Combined with the previously
authorized increases of $33 million relating to the 1995 Cost of Capital
proceeding and $31 million for partial recovery of amounts accrued in the ITCS
balancing account (see "Gas Utility Operations -- Restructuring of Interstate
Gas Supply Arrangements -- Recovery of Interstate Transportation Demand Charges"
below), and approval of the Company's request to reduce authorized funding for
gas CEE programs in 1995 by $33 million, gas revenues increased, effective
January 1, 1995, by approximately $100 million, or 4.7% over rates previously in
effect.
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Also in December 1994, the CPUC granted the Company's request for
reductions of approximately $100 million in authorized funding levels for 1995
electric CEE programs and $17 million for electric research development and
demonstration (RD&D) programs. The request for such reductions was made as part
of the Company's efforts to control costs under its electric rate freeze plan.
1995 Cost of Capital Proceeding. As part of its ruling in the annual
generic Cost of Capital proceeding for California's major energy utilities, the
CPUC authorized the Company to set rates in 1995 to provide a utility return on
common equity of 12.10%. This represents an increase from the 11.00% return on
common equity allowed in 1994. The higher return on common equity is intended to
recognize increased interest rates as well as increased risks associated with
the CPUC's OIR/OII on electric industry restructuring in California. The
decision authorizes a utility capital structure of 48.00% common equity, 5.50%
preferred stock and 46.50% long-term debt, which represents an increase from
47.50% in the current equity component of the Company's capital structure. The
combined authorized costs of debt, preferred stock and the 12.10% return on
common equity results in an overall return on rate base of 9.79% for 1995,
compared with the 9.21% authorized for 1994. The decision increased revenue
requirements by approximately $105 million for electric rates and $33 million
for gas rates, effective January 1, 1995. However, consistent with the Company's
current electric rate freeze, the electric revenue increase authorized in this
proceeding was offset by a decrease in base revenues, such that electric rates
will not increase through the end of 1995.
ECAC. In December 1994, the CPUC issued a decision in the Company's 1995
ECAC proceeding which adopted all of the Company's proposals to continue the
electric rate freeze currently in effect, including a $158 million ECAC
increase, a base rate decrease approved in the ARA proceeding described above,
an early refund of $84 million in CEE program dollars collected from ratepayers
but not spent in 1993 and 1994, and deferral of collection of approximately $444
million of ECAC costs forecasted to be undercollected as of December 31, 1995.
In granting the deferral, the decision continued imposition of the three
conditions placed on the first deferral in the 1994 ECAC proceeding: (i)
reinstatement of the AER mechanism, which places shareholders at risk for 9% of
any deviations from forecasted operations, (ii) no interest on the estimated
revenue requirement deferral, and (iii) written notification to all parties if
the Company forecasts that rates would need to rise an additional 5% or more to
amortize the undercollection.
In its decision the CPUC agreed with the Company that the forgoing of
interest on the deferral was limited to the adopted deferral amount and not to
undercollections resulting from forecast error. The decision also makes it clear
that the deferral would not be considered a transition cost in any restructuring
of the electric industry, but should be separately collected from the customers
receiving electric service during the period in which the deferred amounts were
incurred.
The ECAC decision also approved continuation of the Company's economic
stimulus rate reduction, an annual $70 million rate reduction offered to the
Company's largest business customers. The rate reduction, originally offered in
July 1993, was developed to help attract and retain major employers in Northern
and Central California.
Although the ability of the Company to recover the ECAC balancing account
undercollection has been impacted by the Company's freeze on retail electric
rates, the proposed modification of the price for Diablo Canyon power will
assist in reducing the ECAC balance. The Company currently believes that the
ECAC balance will be collected in rates over the near term.
BIENNIAL COST ALLOCATION PROCEEDING
In July 1994, the CPUC approved the Company's request for an increase of
$162 million (9.3%) in core gas rates effective July 15, 1994. The Company had
requested the increase in an interim, or trigger, filing as permitted under the
BCAP mechanism to set new rates for the second year of the BCAP period. During
the first half of the applicable BCAP period (November 1992 -- October 1993),
actual gas costs were higher than the forecasted costs used to adopt rates and
actual gas sales were less than expected, leading to unrecovered gas and related
fixed costs.
In November 1994, the Company filed an application with the CPUC in its
1995 BCAP requesting a gas rate increase of approximately $173 million annually
for the two-year test period beginning October 1, 1995, and ending September 30,
1997. The Company's request reflects a $53 million annual increase in
procurement
13
20
revenues and a $120 million annual increase in transportation revenues. If the
Company's request is adopted, rates would be effective September 15, 1995. A
final CPUC decision is expected in the third quarter of 1995.
1996 GENERAL RATE CASE
The Company filed its 1996 GRC application in December 1994 for base rates
effective January 1, 1996. The application, as updated by the Company since the
original filing, requests no change in electric revenues and a $163 million
decrease in gas revenues, compared to rates in effect in 1995. The electric and
gas requests will be consolidated with other proceedings, including the BCAP,
the ECAC and the Cost of Capital proceedings, to determine the revenues to be
collected from customers in 1996. (The request included in the original
application to increase revenues by $13 million for the California, or in-state,
portion of the Pipeline Expansion (see "Gas Utility Operations -- PGT/PG&E
Pipeline Expansion Project" below) will be considered in a separate proceeding.)
Since the Company anticipates that the CPUC will have implemented the Company's
proposed PBR mechanism for determining base revenues before January 1, 1997, the
Company's GRC application does not request the adoption of an ARA for the years
1997 and 1998.
In March 1995, the DRA submitted its report on the Company's GRC
application. The DRA recommendation, which is subject to further revision,
proposes an overall revenue requirement which is significantly lower than that
requested by the Company. The DRA recommends that the Company reduce its
electric revenue requirement by $434 million (compared with the Company's
request for no change), and its gas revenue requirement by $292 million
(compared with the Company's request for a $163 million reduction). A
significant portion of the difference between the revenue requirement requested
by the Company and that recommended by the DRA relates to administrative and
general expenses and the level of wages and benefits paid to Company employees.
Hearings on the 1996 GRC are expected to begin in April 1995, with a final
decision on the application expected in December 1995.
WORKFORCE REDUCTION RATE MECHANISM
In March 1993, the CPUC authorized the establishment of a memorandum
account to record all costs and savings incurred in connection with the
Company's 1993 workforce reduction program, subject to a reasonableness review.
In October 1993, the Company filed a report with the CPUC to update the
forecasted costs and savings associated with the workforce reduction program. As
proposed in its filing with the CPUC, the Company's net revenue requirement
savings expected to be achieved during the 1993 GRC cycle through the workforce
reduction program are being passed on to ratepayers over a two-year period
beginning January 1, 1994. These estimated savings total approximately $156
million.
The total cost of the 1993 workforce reduction program was $264 million,
net of a curtailment gain relating to pension benefits. As a result of the
Company's freeze on electric rates in 1994, the Company expensed $190 million of
such costs relating to electric operations. The amount relating to gas
operations was deferred for future rate recovery and is being amortized as
savings are realized. At December 31, 1994, $31 million remained to be
amortized.
CUSTOMER ENERGY EFFICIENCY/DEMAND SIDE MANAGEMENT PROGRAMS
The Company has long been active in the implementation of CEE and other DSM
programs which encourage customers to implement energy-efficient measures. These
measures allow the Company to defer capital expenditures in connection with
generation, transmission and distribution facilities, reduce operating costs,
reduce the environmental impact of operations and provide service options to
customers. In addition, these measures help to minimize the use of existing
fossil fueled generation. Since the mid-1970s, the Company has expended over
$1.5 billion on DSM programs, allowing the Company to avoid the need for
approximately 1,600 MW of new generating capacity.
Since 1990, the CPUC has permitted the Company to earn shareholder
incentives on its CEE programs. For resource programs which are designed to
produce positive net benefits (i.e., the net present value of the avoided
energy, capacity, transmission and distribution costs of the programs exceeds
the cost of the CEE
14
21
program), the shareholder incentive is a percentage of the positive net
benefits. For certain service programs, including the Company's direct
weatherization and energy efficiency education programs, the shareholder
incentive is 5% of the cost of the programs.
In a 1993 decision, the CPUC determined that shareholder incentives on
resource programs will be based on actual measured energy savings rather than
forecasted savings, beginning with the 1994 DSM programs. The decision also
concluded that, starting with the 1994 programs, shareholder incentives will be
recovered in rates in four equal installments over a ten-year period, and the
amount recoverable will be subject to the outcome of periodic measurement and
evaluation studies. Beginning in 1994, the amount of shareholder incentives
authorized for the Company and other California utilities will be determined
annually in the AEAP. In early 1994, the Company filed the first annual AEAP
application, requesting shareholder incentives for its 1993 CEE programs. The
CPUC granted the Company's request of $14.9 million in shareholder incentives to
be recovered over a three-year period. The Company estimates that it will earn
approximately $15 million (after-tax) in shareholder incentives from the 1994
CEE programs. In accordance with the 1993 decision, the 1994 shareholder
incentive will be collected in four installments over a ten-year period, and
will be adjusted based on the results of measurement and evaluation studies.
In October 1994, the CPUC issued a decision establishing the incentive
mechanism and incentive level for DSM programs in 1995 and beyond. The
shareholder incentive level is established at 30% of the net benefits of the
resource programs. However, the utilities must guarantee the overall cost
effectiveness of their residential and non-residential portfolio of programs. If
a portfolio is not cost-effective, the utility must refund to ratepayers the
amount by which the costs of the programs exceed the resource benefits of the
portfolio. If the actual accomplishments of a portfolio fall below a minimum
performance standard established for the portfolio, the entire portfolio will be
ineligible for shareholder incentives.
The Company plans to spend approximately $150 million on CEE programs in
1995, compared to the $235 million spent on 1994 programs. The new shareholder
incentive mechanism and the requirement of ex post measurement of energy savings
over the 10 years makes an estimate of earnings over that period difficult at
this time. The Company currently estimates it will earn approximately $57
million in shareholder incentives over the 10-year period as a result of the
1995 programs. The Company is permitted to recover, through a balancing account,
up to a maximum of 130% of the program expenses authorized for resource
programs.
CAPITAL REQUIREMENTS AND FINANCING PROGRAMS
The Company continues to require capital for improving its existing
generation, transmission and distribution facilities to maintain their
efficiency and reliability, to extend their useful lives and to comply with
environmental laws and regulations. Expenditures for these purposes, including
the allowance for funds used during construction (AFUDC) were approximately $1.1
billion for 1994. New investments in nonregulated businesses totaled $328
million in 1994.
The following table sets forth the estimated total capital requirements,
consisting of capital expenditures for the utility functions, Diablo Canyon and
the nonregulated investments of Enterprises and amounts for maturing debt and
sinking funds for the years 1995 through 1999.
CAPITAL REQUIREMENTS
(IN MILLIONS)
1995 1996 1997 1998 1999 TOTAL
------ ------ ------ ------ ------ -------
Utility(1)(2)........................... $1,212 $1,276 $1,237 $1,255 $1,304 $ 6,284
Diablo Canyon(2)........................ 47 50 52 54 56 259
Enterprises(3)
DALEN Resources Company(4)............ 120 -- -- -- -- 120
U.S. Generating Company(5)............ 142 125 84 173 166 690
Other(6).............................. 23 17 200 203 198 641
------ ------ ------ ------ ------ -------
Total Capital Expenditures......... 1,544 1,468 1,573 1,685 1,724 7,994
Maturing Debt and Sinking Funds......... 477 373 369 715 317 2,251
------ ------ ------ ------ ------ -------
Total Capital Requirements......... $2,021 $1,841 $1,942 $2,400 $2,041 $10,245
====== ====== ====== ====== ====== =======
(See footnotes on following page)
15
22
- ---------------
(1) Utility expenditures are shown net of reimbursed capital and include
California electric and gas operations and existing operations of the gas
pipeline from Canada to California. Utility expenditures also include
amounts relating to the expansion of PGT's pipeline system in 1995 through
1996 to provide additional deliveries in the Pacific Northwest. Capital
expenditures relating to such further expansion total approximately $34
million. PGT is also considering a further expansion of its system which, if
warranted by market demand at the time, could require capital expenditures
of approximately $180 million during 1996 and 1997, which amount is not
included in the table above.
(2) Utility expenditures include AFUDC. Expenditures for Diablo Canyon and the
in-state portion of the PGT/PG&E Pipeline Expansion (see "Gas Utility
Operations -- PGT/PG&E Pipeline Expansion Project" below) include
capitalized interest.
(3) Enterprises' actual capital expenditures may vary significantly depending on
the availability of attractive investment opportunities.
(4) In July 1994, the Company approved a plan for the disposition of DALEN
Resources Corp. (DALEN), formerly PG&E Resources Company.
(5) U.S. Generating Company's expenditures include commitments by the Company
and/or Enterprises to make capital contributions for Enterprises' equity
share of currently identified generating facility projects. These
contributions, payable upon commercial operation of the projects, are
estimated to be $100 million and $114 million in 1995 and 1996,
respectively. There are no current commitments to make contributions in 1997
or thereafter.
(6) "Other" includes development and investment activity for international power
generation, real estate and corporate development activities.
Most of the utility capital expenditures for 1995 through 1999 are
associated with short lead time, modest capital expenditure projects aimed at
providing the facilities required by new customers and at the replacement and
enhancement of existing generation, transmission, distribution and common
utility facilities to maintain their efficiency and reliability and to comply
with environmental laws and regulations. One exception is the seismic retrofit
of part of the Company's general office complex in downtown San Francisco.
The Company estimates that, in addition to the capital expenditure
objectives referred to above, its total capital requirements for the years 1995
through 1999 will include approximately $2,251 million for payment at maturity
of outstanding long-term debt and for meeting sinking fund requirements for
debt. In January 1995, the Board of Directors authorized the Company to redeem
or repurchase up to $153 million of mortgage bonds. In addition, $85 million
remains from a previous authorization to repurchase medium-term notes. In 1994,
the Company redeemed or repurchased $135 million of mortgage bonds, medium-term
notes and Eurobonds. Redemptions and repurchases were financed in part by the
issuance in 1994 of $30 million of medium-term notes and $63 million of
redeemable preferred stock.
The funds necessary for the Company's 1995-1999 capital requirements will
be obtained from (i) internal sources, principally net income before noncash
charges for depreciation and deferred income taxes, and (ii) external sources,
including short-term financing, such as bank loans and the sale of short-term
notes, and long-term financing, such as sales of equity and long-term debt
securities, when and as required.
The Company conducts a continuing review of its capital expenditures and
financing programs. The programs and estimates above are subject to revision
based upon changes in assumptions as to system load growth, rates of inflation,
receipt of adequate and timely rate relief, availability and timing of
regulatory approvals, total cost of major projects, availability and cost of
suitable nonregulated investments, and availability and cost of external sources
of capital.
16
23
ELECTRIC UTILITY OPERATIONS
ELECTRIC OPERATING STATISTICS
The following table shows the Company's operating statistics (excluding
subsidiaries except where indicated) for electric energy, including the
classification of sales and revenues by type of service.
YEARS ENDED DECEMBER 31
----------------------------------------------------------------------
1994 1993 1992 1991 1990
---------- ---------- ---------- ---------- ----------
CUSTOMERS (AVERAGE FOR THE YEAR):
Residential....................................... 3,788,044 3,748,831 3,708,374 3,665,055 3,604,327
Commercial........................................ 452,049 449,619 455,480 450,789 440,670
Industrial........................................ 1,260 1,243 1,207 1,186 1,102
Agricultural...................................... 90,520 91,376 94,562 96,270 98,131
Public street and highway lighting................ 16,709 16,096 15,681 15,314 14,979
Other electric utilities.......................... 29 28 24 21 20
---------- ---------- ---------- ---------- ----------
Total....................................... 4,348,611 4,307,193 4,275,328 4,228,635 4,159,229
========= ========= ========= ========= =========
GENERATED, RECEIVED AND SOLD -- KWH (IN MILLIONS):
Generated:
Hydroelectric plants............................ 7,791 14,403 7,537 7,996 8,008
Thermal-electric plants:
Fossil fueled................................. 29,543 19,070 26,623 21,984 24,496
Geothermal.................................... 6,024 6,491 7,007 6,947 7,324
Nuclear....................................... 15,265 16,816 16,698 15,073 16,274
---------- ---------- ---------- ---------- ----------
Total thermal-electric plants............... 50,832 42,377 50,328 44,004 48,094
Wind and solar plants........................... 1 -- -- -- --
Received from other sources(1).................... 47,199 48,859 46,243 48,966 46,682
---------- ---------- ---------- ---------- ----------
Total gross system output(2)................ 105,823 105,639 104,108 100,966 102,784
Delivered for interchange or exchange............. 3,275 8,848 3,912 5,391 5,281
Delivered for the account of others(1)............ 18,622 13,726 17,235 13,602 16,093
Helms pumpback energy (3)......................... 467 452 398 593 396
Company use, losses, etc.(4)...................... 7,838 6,960 7,278 7,184 6,957
---------- ---------- ---------- ---------- ----------
Total energy sold........................... 75,621 75,653 75,285 74,196 74,057
========= ========= ========= ========= =========
POWER PLANT FUEL SUPPLY (IN THOUSANDS):
Natural gas (equivalent barrels).................. 44,119 28,791 43,446 36,262 37,777
Fuel oil.......................................... 2,395 2,080 171 631 2,066
Nuclear (equivalent barrels)...................... 26,135 28,724 28,540 25,808 27,847
---------- ---------- ---------- ---------- ----------
Total....................................... 72,649 59,595 72,157 62,701 67,690
========= ========= ========= ========= =========
POWER PLANT FUEL COSTS (AVERAGE COST PER
MILLION BTU'S):
Natural gas....................................... $2.19 $2.86 $2.61 $2.75 $3.09
Fuel oil.......................................... $2.83 $3.49 $3.13 $3.00 $4.11
Weighted average.................................. $2.23 $2.90 $2.62 $2.75 $3.14
SALES -- KWH (IN MILLIONS):
Residential....................................... 24,326 24,111 23,664 23,535 23,222
Commercial........................................ 26,195 26,258 26,246 25,758 25,867
Industrial........................................ 16,010 16,492 16,600 16,472 16,271
Agricultural...................................... 4,426 3,672 4,741 4,734 4,702
Public street and highway lighting................ 418 419 400 389 376
Other electric utilities.......................... 4,246 4,701 3,634 3,308 3,619
---------- ---------- ---------- ---------- ----------
Total energy sold........................... 75,621 75,653 75,285 74,196 74,057
========= ========= ========= ========= =========
REVENUES (IN THOUSANDS):
Residential....................................... $2,980,966 $2,952,893 $2,790,605 $2,729,763 $2,418,250
Commercial........................................ 2,892,302 2,914,855 2,864,817 2,745,040 2,532,655
Industrial........................................ 1,128,561 1,183,728 1,210,754 1,186,452 1,071,714
Agricultural...................................... 477,330 419,628 478,941 477,397 429,445
Public street and highway lighting................ 55,545 55,976 53,133 50,631 47,121
Other electric utilities.......................... 201,133 242,433 185,555 204,089 217,276
---------- ---------- ---------- ---------- ----------
Revenues from energy sales.................. 7,735,837 7,769,513 7,583,805 7,393,372 6,716,461
Miscellaneous..................................... 142,771 87,991 51,716 103,180 217,038
Regulatory balancing accounts..................... 127,549 8,539 111,971 (127,912) 102,572
---------- ---------- ---------- ---------- ----------
Operating revenues.......................... $8,006,157 $7,866,043 $7,747,492 $7,368,640 $7,036,071
========= ========= ========= ========= =========
- ----------
(1) Includes energy supplied through the Company's system by the City and County
of San Francisco for San Francisco's own use and for sale by San Francisco
to its customers, by the Department of Energy for government use and sale to
its customers, and by the State of California for California Water Project
pumping, as well as energy supplied by QFs and purchases from other
utilities.
(2) Includes energy output from Modesto and Turlock Irrigation Districts' own
resources.
(3) Represents energy required for pumping operations.
(4) Includes use by business units other than the Electric Supply business unit.
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24
YEARS ENDED DECEMBER 31
-----------------------------------------------------------------
1994 1993 1992 1991 1990
--------- --------- --------- --------- ---------
SELECTED STATISTICS:
Total customers (at year-end)..................... 4,400,000 4,400,000 4,300,000 4,300,000 4,200,000
Average annual residential usage (kWh)............ 6,422 6,431 6,381 6,421 6,443
Average billed revenues per kWh (c):
Residential..................................... 12.25 12.25 11.79 11.60 10.41
Commercial...................................... 11.04 11.10 10.92 10.66 9.79
Industrial...................................... 7.05 7.18 7.29 7.20 6.59
Agricultural.................................... 10.78 11.43 10.10 10.08 9.13
Net plant investment per customer ($)............. 3,362 3,436 3,428 3,445 3,443
Electric control area capability(1)(MW)........... 21,851 23,009 22,475 21,670 22,931
Electric net control area peak demand(2)(MW)...... 19,118 19,607 18,594 18,620 19,400
- ------------
(1) Area net capability at time of annual peak, based on actual water
conditions.
(2) Net control area peak demand includes demand served by Modesto and Turlock
Irrigation Districts' own resources.
ELECTRIC GENERATING AND TRANSMISSION CAPACITY
As of December 31, 1994, the Company owned and operated the following
generating plants, all located in California, listed by energy source:
NET
OPERATING
NUMBER CAPACITY
GENERATION TYPE COUNTY LOCATION OF UNITS 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
------ ---------
Steam Plants:
Contra Costa(1)......................... Contra Costa 2 680,000
Humboldt Bay............................ Humboldt 2 105,000
Hunters Point........................... San Francisco 3 377,000
Morro Bay............................... San Luis Obispo 4 1,002,000
Moss Landing(1)......................... Monterey 2 1,478,000
Pittsburg............................... Contra Costa 7 2,022,000
Potrero................................. San Francisco 1 207,000
------ ---------
Steam Subtotal.......................... 21 5,871,000
------ ---------
Combustion Turbines:
Hunters Point........................... San Francisco 1 52,000
Oakland................................. Alameda 3 165,000
Potrero................................. San Francisco 3 156,000
Mobile Turbines(2)...................... Contra Costa and Humboldt 3 45,000
------ ---------
Combustion Turbines Subtotal............ 10 418,000
------ ---------
Geothermal:
The Geysers(3).......................... Sonoma and Lake 14 1,224,000
Nuclear:
Diablo Canyon........................... San Luis Obispo 2 2,160,000
------ ---------
Thermal Subtotal................... 47 9,673,000
------ ---------
Total........................................................... 161 13,588,100
======= =========
- ----------
(1) Several fossil fuel steam units (527 MW) were on long-term standby reserve
during 1994. The units require a 12-18 month reactivation time, and are
included as unavailable capacity in the Control Area Net Capacity table
below. Effective December 31, 1994, 12 units, totaling 1342 MW (including
the 527 MW on long-term standby reserve), were retired in place.
(2) Listed to show capability; subject to relocation within the system as
required.
(3) The Geysers net operating capacity is based on adequate geothermal steam
supply conditions. Any decrease in capacity, at peak, is included as
unavailable capacity in the Control Area Net Capacity table below. See
"Geothermal Generation" below.
18
25
To transport energy to load centers, the Company as of December 31, 1994,
owned and operated approximately 18,450 circuit miles of interconnected
transmission lines of 60 kilovolts (kV) to 500 kV and transmission substations
having a capacity of approximately 34,209,000 kilovolt-amperes (kVa). Energy is
distributed to customers through approximately 105,527 circuit miles of
distribution system and distribution substations having a capacity of
approximately 22,091,000 kVa.
The following table sets forth the available capacity for the control area
(the area served by the Company and various publicly owned systems in Northern
California) at the date of peak (including reduction for scheduled and forced
outages and based on actual water conditions) by various sources of generation
available to the control area and the total amount of generation provided by
these sources during the year ended December 31, 1994.
CONTROL AREA
NET CAPACITY
(AT DATE OF 1994 PEAK)
--------------------
KW %
---------
Sources of Electric Generation:
Company-Owned Plants:
Fossil Fueled.................. 7,631,000 52
Geothermal..................... 1,224,000 8
Nuclear........................ 2,160,000 15
--------- -----
Total Thermal................ 11,015,000 75
Hydroelectric (available)...... 3,556,400 25
Solar.......................... 0 0
--------- -----
Total Company-Owned Capacity..... 14,571,400 100
====
Less Unavailable Capacity...... (913,000)
---------
Total Company Available
Capacity....................... 13,658,400 62
Capacity Received from Others:
QF Producers (available)....... 2,981,000 14
Area Producers &
Imports...................... 5,211,600 24
--------- -----
Capacity from Others........... 8,192,600 38
--------- -----
Total Available Capacity......... 21,851,000 100
========= ====
Total Area Demand(1)(2)............ 19,118,000
=========
GENERATION
YEAR ENDED
DECEMBER 31, 1994(3)
----------------------
KWH
THOUSANDS %
-------------
Electric Generation:
Company-Owned Plants:
Fossil Fueled.................. 29,542,611 28
Geothermal..................... 6,024,133 6
Nuclear........................ 15,264,977 15
------------- ----
Total Thermal................ 50,831,721 49
Hydroelectric.................. 7,791,473 8
Solar.......................... 973 --
------------- ----
Total Company Generation......... 58,624,167 57
Helms Pumpback Energy............ (466,524) --
------------- ----
Net Company Generation......... 58,157,643 57
Generation Received from Others:
QF Producers................... 21,692,229 21
Area Producers &
Imports...................... 22,913,620 22
------------- ----
Generation from Others......... 44,605,849 43
Total Area Generation............ 102,763,492 100
=========== ====
- ----------
(1) The maximum control area peak demand to date was 19,607,000 kW which
occurred in August 1993.
(2) The reserve capacity margin at the time of the 1994 control area peak,
taking into account short-term firm capacity purchases from utilities
located outside the Company's service area: spinning reserve (capability
already connected to the system and ready to meet instantaneous changes in
demand) to the control area peak was 6.7% of the peak demand and total
reserve (spinning reserve and capability available within a short period of
time) was 14.3%.
(3) Represents actual year net generation from sources shown.
ELECTRIC LOAD FORECAST AND RESOURCE PLANNING AND PROCUREMENT
At present, California's long-range electric resource planning is
coordinated between the California Energy Commission (CEC) and the CPUC. Every
two years, the CEC prepares an Electricity Report that includes load forecasts
and resource assumptions for a 20-year period. The CPUC conducts a Biennial
Resource Plan Update (BRPU) proceeding which is linked to a specific CEC
Electricity Report. The purpose of the BRPU is to determine whether any
cost-effective electric resources (either new generating resources or power
purchases) should be added to the regulated utilities' electric systems based on
a 12-year planning horizon (as described below). In making this determination,
the CPUC gives great weight to the load forecasts and resource assumptions
included in the CEC's Electricity Report.
The CEC has not yet adopted the complete 1994 Electricity Report (ER94).
However, the CEC has adopted ER94 forecasts for energy loads and peak demands.
The forecast for area electric peak demand (on a CEC area basis) indicates an
increase from approximately 16,300 MW in 1994 to approximately 21,400 MW in
2013, reflecting a compound annual growth rate of 1.4%. The forecast for area
electric energy load indicates an increase from approximately 88,600
gigawatt-hours (GWh) in 1994 to 116,100 GWh in 2013, reflecting a compound
annual growth rate of 1.4%. The Company's current energy and peak demand
forecasts after 2000 are higher than the CEC's ER94 forecast, primarily due to
the Company's more optimistic economic and demographic assumptions.
19
26
For the remainder of this decade, the Company anticipates adding between
600 and 750 MW of electric resources. These resources will be comprised of (i)
up to 265 MW of new purchases or company-owned resources resulting from the 1993
BRPU solicitation, assuming a recent FERC order finding the 1993 BRPU
solicitation unlawful is not upheld, (ii) approximately 308 MW of new QF
purchases to come on line by the end of 1996, (iii) between 49 and 200 MW of
generation and DSM resources resulting from the integrated bid solicitation,
(iv) improvements in its existing generating system, including 20 MW of upgrades
of the hydroelectric system, and (v) further developments in regional operations
efficiency from the Company's existing transmission lines from the Pacific
Northwest. The Company currently plans no new major construction projects for
electric supply before the year 2000, other than projects already under
development.
The future of electric resource acquisition is being addressed in the
electric industry restructuring OIR/OII. However, future additions to satisfy
electric supply needs in the Company's service territory likely will be
determined largely through a competitive resource procurement process open to
all potential suppliers. The Company has indicated its willingness to forgo
competing in this process to build new generation resources if the CPUC grants
the Company significant flexibility in conducting the planning and procurement
process.
The CEC committee conducting proceedings relating to the CEC's ER94
expanded the proceeding to include an extensive analysis of how changes in the
structure of the electric industry may affect the achievement of California's
energy policies. It is presently unclear to what extent considerations relating
to electric industry restructuring will impact the content and timing of the
final ER94.
In 1993, the CPUC issued a decision in a DSM proceeding (see
"General -- Customer Energy Efficiency/Demand Side Management Programs" above)
which selected the Company to conduct an integrated bidding pilot program in
which both resource generation and DSM bidders compete in the procurement
process. The CPUC ordered the Company to conduct a pilot bid program for between
49 and 200 MW. The Company issued a request for bids in December 1994 and
expects to file contracts in early 1996 for approval by the CPUC.
ELECTRIC RESOURCES
QF GENERATION
Under the Public Utility Regulatory Policies Act of 1978 (PURPA), the
Company is required to purchase electric energy and capacity produced by QFs.
The CPUC established a series of power purchase agreements which set the
applicable terms, conditions and price options. A QF must meet certain
performance obligations, depending on the contract, prior to receiving capacity
payments. The total cost of both energy and capacity payments to QFs is
recoverable in rates. The Company's contracts with QFs expire on various dates
from 1995 to 2026. Under these contracts the Company is required to make
payments only when energy is supplied or when capacity commitments are met.
In 1994, the Company negotiated the early termination or temporary
suspension of seven QF contracts at
a cost of $155 million, to be paid over a six-year period beginning in 1994. The
amount has been deferred with the expectation that it will be recovered in
future rates.
Payments to QFs are expected to vary in future years. QF deliveries in the
aggregate accounted for approximately 21% of the Company's 1994 total electric
energy requirements and no single contract accounted for more than 5% of the
Company's electric energy needs.
The amount of energy received from QFs and the total energy and capacity
payments made under these agreements were:
1994 1993 1992
------ ------ ------
(IN MILLIONS)
kWh received............................................. 21,699 21,242 21,173
Energy payments.......................................... $1,196 $1,099 $1,084
Capacity payments........................................ $518 $503 $489
20
27
As of December 31, 1994, the Company had approximately 5,900 MW of QF
capacity under CPUC-mandated power purchase agreements. Of the 5,900 MW,
approximately 4,600 MW were operational. Development of the balance is uncertain
but it is estimated that only 300 MW of the remaining contracts will become
operational. The 5,900 MW of QF capacity consists of 3,300 MW from cogeneration
projects, 1,500 MW from wind projects and 1,100 MW from other projects,
including biomass, geothermal, solar and hydroelectric.
GEOTHERMAL GENERATION
Because of declining geothermal steam supplies, the Company's geothermal
units at The Geysers Power Plant (Geysers) are forecast to operate at reduced
capacities. The consolidated Geysers capacity factor is forecast to be
approximately 33% in 1995, which includes forced outages, scheduled overhauls
and projected steam shortage curtailments, as compared to the actual Geysers
capacity factor of 56% in 1994. The Company expects steam supplies at the
Geysers to continue to decline.
The Company has entered into new steam sale agreements with several of its
steam suppliers which allow the Company to alter the operation of its units to
more economically utilize the existing installed capacity and partially offset
the impact of the declining steam supplies at the Geysers. The new agreements
permit the steam suppliers to furnish lower pressure steam and require that they
make payments to the Company to compensate for the declining steam supply to the
Company's units.
WESTERN SYSTEMS POWER POOL
In 1991, the FERC approved an agreement among 40 utilities (including the
Company) operating in 22 states and British Columbia for a permanent Western
Systems Power Pool (WSPP). The entities participating in the WSPP may, on a
voluntary basis, buy and sell surplus power and transmission capacity by posting
quotes daily on a computer "bulletin board." The prices are negotiable but
cannot exceed ceilings approved by the FERC. The permanent WSPP agreement
approved by the FERC, among other things, imposes cost-based ceilings calculated
from pool-wide average costs and allows QFs to participate in the pool if they
waive their rights under PURPA to be paid avoided cost prices for transactions
performed within the pool. The FERC order approving the permanent WSPP agreement
was challenged in the U.S. Court of Appeals for the District of Columbia Circuit
on the basis that the cost-based ceilings were improperly calculated and that
the FERC exceeded its authority in conditioning QF participation in the pool.
The Court of Appeals affirmed the FERC's authority to set cost-based ceilings
and, at the request of the FERC, remanded the QF participation issues to the
FERC for further consideration. In February 1994, the FERC ordered WSPP to
permit QFs to participate on the same basis as other members without being
required to waive their rights under PURPA.
ELECTRIC TRANSMISSION POLICIES
Beginning in 1993, the FERC implemented the Energy Act by establishing a
number of policies with respect to transmission service, transmission pricing
and Regional Transmission Groups (RTGs).
TRANSMISSION ACCESS AND PRICING
In 1993, the FERC held that eligible entities were entitled to receive
network transmission service unless the transmitting utility was unable to
provide it. Eligible entities under the Energy Act include electric utilities,
federal power marketing agencies or any entity generating power for resale.
Network transmission service generally involves delivery from multiple
generators to multiple loads for a single charge. The FERC later held that
network service could be priced based on the ratio of the load served by the
network service to the entire load served by the transmitting utility's
transmission system.
In 1994, the FERC held that any utility providing service under an
open-access transmission tariff (i.e., a filed tariff offering transmission
service at specified rates and terms to all eligible entities) must provide
transmission service to transmission customers on the same basis on which the
utility provides transmission service to its own customers. This means the
service must be comparable in terms of price, in terms of quality,
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and with respect to all the uses the transmitting utility makes of its own
transmission system. The Company currently intends to file an open-access tariff
by May 1, 1995.
In October 1994, the FERC issued a policy statement on transmission
pricing. The new policy permits increased flexibility in transmission pricing
methodology and rate design in instances where the transmitting utility is
basing rates on a traditional embedded cost revenue requirement. In return
utilities must meet the comparability of service standard described above. The
FERC will also consider deviations from embedded cost revenues, but only from
entities which have already filed open-access comparable service transmission
tariffs. The FERC regards market-based pricing for transmission as disfavored,
believing transmission to be a monopoly.
Consistent with the intent of the Energy Act to promote competition in the
wholesale power markets through increasing transmission access, in December
1994, the Company filed with the FERC for its approval an agreement to provide
network transmission service to a power marketer, Destec Power Services (DPS).
Under this agreement, the Company will provide flexible wholesale network
transmission from generators who market their power through DPS. Many of these
generators will be QFs which already have power purchase agreements to sell to
the Company, but which have surplus power not covered by such agreements which
can be marketed by DPS. The FERC is expected to act on the DPS agreement
shortly. In March 1995, the Company entered into a similar agreement with
another marketer, Power Exchange Corp. (PXC), which agreement has been filed
with the FERC for approval. The services and rates under the PXC agreement are
identical to those in the DPS agreement. However, the Company will provide
transmission service under the PXC Agreement only for power bought or sold by
PXC under contracts entered into before such time as the Company's open-access
tariff has been filed and effective for two years. For all power contracts PXC
enters into after that date, it must rely on transmission service under the
Company's open-access tariff.
REGIONAL TRANSMISSION GROUPS
In 1993, the FERC issued a policy statement on RTGs, voluntary associations
of transmission owners and wholesale transmission users, that would facilitate
transmission access, coordinate transmission planning, and resolve disputes. In
May 1994, the Western Regional Transmission Association (WRTA) became the first
RTG to file its governing agreement at the FERC. The Company was one of the
founding members of WRTA and supported FERC's approval of the bylaws. The FERC
conditionally accepted the WRTA bylaws, but added two requirements. First, the
FERC required either WRTA itself or all WRTA members to file comparable service
open access tariffs providing transmission service to all other members. Second,
the FERC required WRTA to file a single coordinated regional transmission plan
and to update that plan as necessary. WRTA has filed a revised set of bylaws
essentially accepting those conditions, which FERC will rule on within the next
few months.
STRANDED COSTS RULEMAKING
In June 1994, the FERC issued a Notice of Proposed Rulemaking relating to
stranded costs. These are fixed costs (typically for generation) which a utility
may be unable to recover because of customers leaving the system. The proposed
rules cover stranded costs for wholesale transactions and propose in the
alternative either no role for FERC regarding retail stranded costs or only a
limited role. A decision is expected sometime in 1995.
CPUC TRANSMISSION POLICIES
In September 1990, the CPUC issued an order instituting investigation into
the development of transmission policies for (i) transmission access and
allocation of transmission costs for a utility buying non-utility power; and
(ii) transmission access, cost allocation and pricing issues for non-utility
power producers who require transmission-only service from a utility. In
September 1992, the CPUC issued a decision in the first phase of the
investigation. The decision adopted certain policies and procedures on an
interim basis which permit the Company to consider the expected transmission
impacts of non-utility power purchases as it selects new QF resources through a
competitive bidding process. Among other things, the decision provided that
ratepayers, as opposed to utility shareholders, will bear prudently incurred
costs of the most cost-effective transmission upgrades necessary to accommodate
purchases from winning bidders. The recent BRPU
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solicitation proceeded under these rules and enabled bidders in one utility's
service territory to bid into another utility's auction.
A second phase of the investigation to consider certain broader long-term
transmission access and cost issues is currently on hold pending the outcome of
the CPUC's electric industry restructuring OIR/OII.
ELECTRIC REASONABLENESS PROCEEDING
Recovery of costs through the ECAC are subject to a CPUC determination that
such costs were incurred reasonably. Under the current regulatory framework,
annual reasonableness proceedings are conducted on a historic calendar year
basis.
In August 1993, the DRA filed a report on the Company's ECAC expenses for
the 1991 record period, which questioned the Company's execution of amendments
to three power purchase agreements with Texaco, Inc. for three QFs. In its
report and in testimony filed in February 1994, the DRA asserted that the
Company improperly agreed to extend the construction time under these agreements
and recommended that the CPUC find these extensions unreasonable. Although no
payments are at issue in the 1991 record period, the DRA argues that certain
capacity payments under the contracts should be disallowed in subsequent year
proceedings over the 15-year term of the contracts. In its August 1993 report,
the DRA indicated that this disallowance over the 15-year term of the contracts
would approximate $80 million. In its report on ECAC expenses for the 1992 and
1993 record periods, the DRA recommended disallowances of approximately $3.5
million and $3.0 million, respectively, for two of these agreements.
HELMS PUMPED STORAGE PLANT
Helms, a three-unit hydroelectric combined generating and pumped storage
facility, completion of which was delayed due to a water conduit rupture in
September 1982 and various start-up problems related to the plant's generators,
became commercially operable in June 1984. As a result of the damage caused by
the rupture and the delay in the operational date, the Company incurred
additional costs which are not yet included in rate base and lost revenues
during the period the plant was under repair. Excluding the costs of the conduit
rupture already reserved by the Company and the amount received in settlement of
litigation with the supplier of the plant's generators, the remaining
unrecovered costs of Helms (after adjustment for depreciation) and revenues
discussed above totaled approximately $104 million at December 31, 1994.
In October 1994, the Company and the DRA filed a joint motion seeking CPUC
approval of a proposed all-parties settlement (Helms Settlement) resolving the
treatment of remaining unrecovered Helms costs. The Helms Settlement would
permit recovery of $48.9 million of Helms plant costs and $14.6 million of prior
revenue requirements to be included in the Company's rate base on January 1,
1995. However, in connection with the Company's rate freeze for 1995, the
revenue requirement for 1995 would not increase, as a result of other unrelated
base revenue reductions. An additional amount of $35.3 million, representing
revenues lost during the time the generators were being repaired, would be
transferred to the ERAM account and amortized over the life of Helms, to 2034.
Under the Helms Settlement, the Company would also agree not to seek recovery of
the costs associated with the 1982 water conduit rupture, estimated to be $72.4
million. The Company took a charge against earnings for such costs in 1990.
As noted above (see "General -- 1995 Revenue Changes"), in December 1994,
the CPUC issued a resolution authorizing the Company to implement an ARA to keep
the Company's retail electric rates unchanged through 1995. In its resolution,
the CPUC adopted the revenue requirement increase of approximately $12 million
that is contemplated by the Helms Settlement, and authorized a decrease in base
revenues. The CPUC also authorized the collection in 1995 of $2 million as part
of the amortization through ERAM of revenues lost during the time the generators
were being repaired. The CPUC noted that because the Helms Settlement is still
pending before the CPUC, the amount adopted in the resolution may be subject to
further adjustment depending upon the final decision in the Helms proceeding.
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GAS UTILITY OPERATIONS
GAS OPERATIONS
The Company owns and operates an integrated gas transmission, storage and
distribution system in California. At December 31, 1994, the Company's "vintage"
system consisted of approximately 5,300 miles of transmission pipelines, three
gas storage facilities and approximately 35,400 miles of gas distribution lines.
In addition, in November 1993, the Company placed in service a third
transmission pipeline of approximately 400 miles (Line 401) as the in-state
portion of the PGT/PG&E Pipeline Expansion. See "PGT/PG&E Pipeline Expansion
Project" below.
The Company's peak day send-out of gas on its integrated system in
California during the year ended December 31, 1994 was 3,801 million cubic feet
(MMcf). The total volume of gas throughput during 1994 was approximately 948,000
MMcf, of which 307,000 MMcf was sold to direct end-use or resale customers,
298,000 MMcf was transported by PG&E for its fossil-fueled electric generating
plants, and 343,000 MMcf was transported customer-owned gas.
The California Gas Report, which presents the outlook for natural gas
requirements and supplies for the State of California through the year 2010, is
prepared annually by the California electric and gas utilities as a result of a
CPUC order. The 1994 report forecasts the Company's gas demand from 1994 through
2010. (Beginning in 1996, the report will be issued biennially.)
The 1994 report forecasts growth in gas throughput served by the Company of
1.4% per year from 1994 through 2010. While this is a lower growth rate than the
1.8% shown for the same period in last year's forecast, most of the difference
is due to higher power plant gas demand in 1994 than previously forecasted, as a
result of lower than expected rainfall. Much of the forecasted growth in gas
demand, outside of utility electric generation, is related to a more optimistic
forecast of industrial output in the service territory and expected growth in
the use of natural gas vehicles as a result of the Company's natural gas vehicle
programs and state and federal clean air regulations.
The gas requirements forecast is subject to many uncertainties and there
are many factors that can influence the demand for natural gas, including
weather conditions, level of utility electric generation, fuel switching and new
technology. In addition, some large customers, mostly in the industrial and
enhanced oil recovery sectors, have the ability to purchase gas directly from
gas producers, using unregulated private pipelines or interstate pipelines,
bypassing the Company's system entirely. The report forecasts a total bypass
volume of 126 billion cubic feet for 1994. The forecast assumes that bypass
which began in 1991 will change little from the 1994 level and does not include
any potential bypass from the proposed Mojave Pipeline Company expansion
project. See "Other Competitive Pipeline Projects" below.
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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
-------------------------------------------------------------
1994 1993 1992 1991 1990
--------- --------- --------- --------- ---------
CUSTOMERS (AVERAGE FOR THE YEAR):
Residential........................................... 3,372,768 3,339,859 3,311,881 3,275,247 3,214,424
Commercial............................................ 196,509 195,815 195,689 197,029 194,596
Industrial............................................ 1,400 1,265 1,185 1,150 1,150
Other gas utilities................................... 2 4 4 4 4
--------- --------- --------- --------- ---------
Total........................................... 3,570,679 3,536,943 3,508,759 3,473,430 3,410,174
========= ========= ========= ========= =========
GAS SUPPLY -- THOUSAND CUBIC FEET (MCF) (IN THOUSANDS):
Purchased:
From Canada......................................... 319,453 329,693 321,770 345,020 372,421
From California..................................... 31,757 32,096 50,953 73,257 77,935
From other states................................... 249,733 243,058 327,272 240,141 273,981
--------- --------- --------- --------- ---------
Total purchased................................. 600,943 604,847 699,995 658,418 724,337
Net from storage (to storage)......................... 3,591 (12,234) 10,135 (6,849) 6,152
--------- --------- --------- --------- ---------
Total........................................... 604,534 592,613 710,130 651,569 730,489
Company use, losses, etc.(1).......................... 297,604 161,895 281,021 223,176 257,943
--------- --------- --------- --------- ---------
Net gas for sales............................... 306,930 430,718 429,109 428,393 472,546
========= ========= ========= ========= =========
BUNDLED GAS SALES AND TRANSPORTATION SERVICE -- MCF
(IN THOUSANDS):
Residential........................................... 214,358 206,053 190,176 210,657 204,433
Commercial............................................ 72,183 82,048 79,983 85,203 102,579
Industrial............................................ 19,495 133,178 145,356 119,916 133,930
Other gas utilities................................... 894 9,439 13,594 12,617 31,604
--------- --------- --------- --------- ---------
Total(2)........................................ 306,930 430,718 429,109 428,393 472,546
========= ========= ========= ========= =========
TRANSPORTATION SERVICE ONLY -- MCF (IN THOUSANDS):
Vintage system (Substantially all Industrial)(3)...... 142,393 101,888 103,186 207,544 168,969
In-state portion of Pipeline Expansion (Line 401)..... 200,755 20,513 -- -- --
--------- --------- --------- --------- ---------
Total........................................... 343,148 122,401 103,186 207,544 168,969
========= ========= ========= ========= =========
REVENUES (IN THOUSANDS):
Bundled gas sales and transportation service:
Residential......................................... $1,268,966 $1,152,494 $1,092,324 $1,226,094 $1,139,998
Commercial.......................................... 444,805 467,962 479,599 551,669 565,608
Industrial.......................................... 57,297 367,221 425,467 366,346 453,871
Other gas utilities................................. 2,371 25,654 38,504 43,224 84,771
--------- --------- --------- --------- ---------
Bundled gas revenues............................ 1,773,439 2,013,331 2,035,894 2,187,333 2,244,248
Transportation only revenue:
Vintage system (Substantially all Industrial)....... 132,509 56,733 75,606 133,348 106,759
In-state portion of Pipeline Expansion (Line 401)... 58,442 8,097 -- -- --
--------- --------- --------- --------- ---------
Transportation service only revenue............. 190,951 64,830 75,606 133,348 106,759
Miscellaneous......................................... 41,840 (14,925) 21,022 (59,056) 52,308
Regulatory balancing accounts......................... 11,068 138,627 36,093 (44,213) (124,606)
Subsidiaries(4)....................................... 402,077 514,502 379,981 192,067 155,312
--------- --------- --------- --------- ---------
Operating revenues.............................. $2,419,375 $2,716,365 $2,548,596 $2,409,479 $2,434,021
========= ========= ========= ========= =========
- ---------------
(1) Includes use by business units other than the Gas Supply business unit,
principally as fuel for fossil-fueled generating plants.
(2) In August 1991, the Company implemented its CIG program. Sales included
approximately 105,000 MMcf, 130,000 MMcf and 50,000 MMcf in 1993, 1992 and
1991, respectively, of gas procured by the Company for CIG customers at
prices negotiated directly between those customers and suppliers. The CIG
Program was terminated on October 31, 1993 upon full implementation of the
CPUC's capacity brokering program.
(3) Does not include on-system transportation volumes transported on the
in-state portion of the Pipeline Expansion of 79,749 MMcf and 7,205 MMcf
for 1994 and 1993, respectively.
(4) Includes gas transportation revenues from PGT and oil and gas revenues from
Enterprises.
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YEARS ENDED DECEMBER 31
-------------------------------------------------------------
1994 1993 1992 1991 1990
--------- --------- --------- --------- ---------
SELECTED STATISTICS:
Total customers (at year-end)......................... 3,500,000 3,600,000 3,500,000 3,500,000 3,500,000
Average annual residential usage (Mcf)................ 64 62 57 64 64
Heating temperature -- % of normal(1)................. 104.4 89.9 76.0 101.5 94.9
Average billed bundled gas sales revenues Mcf:
Residential......................................... $5.92 $5.59 $5.74 $5.82 $5.58
Commercial.......................................... 6.16 5.70 6.00 6.47 5.51
Industrial.......................................... 2.94 2.76 2.93 3.06 3.39
Average billed transportation only revenue per Mcf:
Vintage system...................................... 0.60 0.52 0.73 0.64 0.63
In-state portion of Pipeline Expansion (Line 401)... 0.29 0.39 -- -- --
Net plant investment per customer..................... $1,340 $1,339 $1,170 $893 $748
- ------------
(1) Over 100% indicates colder than normal.
NATURAL GAS SUPPLIES
The objective of the Company's gas supply planning is to maintain a
balanced supply portfolio which provides supply reliability and contract
flexibility, minimizes costs and fosters competition among suppliers.
Under current CPUC regulations, the Company purchases natural gas from its
various suppliers based on economic considerations, consistent with regulatory,
contractual and operational constraints. During the year ended December 31,
1994, approximately 53% of the Company's total purchases of natural gas
consisted of Canadian gas purchased from various Canadian producers and
transported by PGT, a wholly owned subsidiary of the Company, approximately 5%
was purchased from various California producers, and approximately 42% was
purchased from other states (substantially all U.S. Southwest sources and
transported by El Paso Natural Gas Company (El Paso) or Transwestern Pipeline
Company (Transwestern)). The following table shows the volume and average price
of gas in dollars per thousand cubic feet (Mcf) purchased by the Company from
these sources during each of the last five years.
YEARS ENDED DECEMBER 31
----------------------------------------------------------------------------------------------------------------
1994 1993 1992 1991 1990
-------------------- -------------------- -------------------- -------------------- --------------------
THOUSANDS AVG. THOUSANDS AVG. THOUSANDS AVG. THOUSANDS AVG. THOUSANDS AVG.
OF MCF PRICE(1) OF MCF PRICE(1) OF MCF PRICE(1) OF MCF PRICE(1) OF MCF PRICE(1)
--------- -------- --------- -------- --------- -------- --------- -------- --------- --------
Canada.......... 319,453 $ 1.94 329,693 $ 2.26 321,770 $ 2.14 345,020 $ 2.34 372,421 $ 2.41
California...... 31,757 1.55 32,096 1.65 50,953 1.73 73,257 2.00 77,935 2.04
Other states
(substantially
all U.S.
Southwest).... 249,733 2.41 243,058 2.84 327,272 2.51 240,141 2.61 273,981 2.81
--------- --------- --------- --------- ---------
Total/Weighted
Average....... 600,943 $ 2.12 604,847 $ 2.46 699,995 $ 2.28 658,418 $ 2.40 724,337 $ 2.52
======== ======= ======== ======= ======== ======= ======== ======= ======== =======
- ----------
(1) The average prices for Canadian and U.S. Southwest gas include the commodity
gas prices, interstate pipeline demand or reservation charges,
transportation charges and other pipeline assessments, including direct
bills allocated over the quantities received at the California border. The
average prices for California gas include only commodity gas prices
delivered to the Company's gas system.
GAS REGULATORY FRAMEWORK
The current regulatory framework for natural gas service in California (i)
segments customers into core and noncore classes; (ii) unbundles utilities' gas
transportation and procurement services; (iii) allows noncore customers and some
core customers to purchase gas directly from producers, aggregators or
marketers, and separately negotiate gas transportation with their utilities; and
(iv) places the utilities at risk for collecting a portion of the transportation
revenues associated with their noncore markets. Under the CPUC's capacity
brokering program implemented in 1993, the Company is required to make available
for brokering all interstate pipeline capacity not reserved for its core
customers and core subscription customers. Noncore customers, marketers and
shippers, and the Company's electric department can bid for such capacity.
In addition, in April 1992, the FERC issued its Order 636, which required
interstate pipelines to unbundle sales services from transportation services,
established various programs providing for reallocation of
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pipeline capacity and adopted various mechanisms by which pipelines may recover
transition costs arising from the restructuring of their services. Under the
Order 636 capacity allocation rules, firm capacity holders were permitted to
exercise a one-time opportunity to "relinquish," i.e., permanently abandon, some
or all of their transportation capacity, either by paying a negotiated exit fee
or through a third party assuming the obligations of the existing transportation
agreement. Thereafter, firm capacity holders may also "release" some or all of
their capacity, i.e., give up capacity rights to third parties for a limited
period of time. Releasing capacity holders remain liable on their existing
contracts, but will receive a credit for the acquiring third parties' demand
charge payments, the amounts of which will depend on the percentage of full rate
paid by the acquiring third party.
The Company's compliance with these regulatory changes allowed many of the
Company's noncore customers to arrange for the purchase and transportation of
their own gas supplies. These changes resulted in a decrease in the amount of
gas required to be purchased by the Company and a related decrease in the
Company's need for firm transportation capacity, and contributed to the need to
restructure the Company's gas supply arrangements.
RESTRUCTURING OF CANADIAN GAS SUPPLY ARRANGEMENTS
DECONTRACTING PLAN
Until November 1993, PG&E purchased Canadian natural gas from PGT, which in
turn purchased such gas from Alberta and Southern Gas Co. Ltd. (A&S), a wholly
owned subsidiary of PG&E. A&S had commitments to purchase minimum quantities of
gas from Canadian producers under various contracts, most of which extended
through 2005. As a result of the regulatory restructuring discussed above,
negotiations were conducted to terminate A&S's contracts with Canadian gas
producers, restructure A&S's contracts with Canadian pipelines and gas
processors and settle all litigation and claims arising from such contracts.
Those negotiations resulted in the implementation of a Decontracting Plan,
effective November 1, 1993. Approximately 190 Canadian gas producers
representing nearly 100% of the total volume of the gas supply of A&S
participated in the Decontracting Plan.
Under the Decontracting Plan, the Canadian producers' contracts with A&S,
the sales agreement between A&S and PGT, and PG&E's service agreement with PGT
each were terminated, effective on November 1, 1993. Participating producers
released A&S, PGT and PG&E from any claims they may have had that resulted from
the termination of the former arrangements as well as any prior claims related
to these contracts. The total amount of settlement payments paid to the
producers was approximately $210 million.
As part of the overall A&S decontracting process, A&S' operations have been
significantly reduced. A&S permanently assigned substantial portions of its
commitments for transportation capacity with NOVA Corporation of Alberta (NOVA)
through October 2001 and Alberta Natural Gas Company Ltd (ANG) through October
2005 to third parties and approximately 600 MMcf per day (MMcf/d) of capacity on
each of these pipelines to PG&E for use in the servicing of PG&E's core and core
subscription customers. A&S currently holds remaining capacity of approximately
300 MMcf/d on each of these pipelines with total annual demand charges of
approximately $15 million for which it is continuing its efforts to assign or
broker. It is currently anticipated that A&S will complete the permanent
assignment to others of substantially all of its NOVA and ANG capacity by
November 1995.
The FERC has approved a transition cost recovery mechanism (TCRM) for PGT
under which most costs which were incurred to restructure, reform or terminate
the sales arrangements between A&S and PGT and underlying A&S gas supply
contracts, or to resolve claims by gas suppliers related to past or future
liabilities or obligations of PGT or A&S, are eligible for recovery in PGT's
rates. Under the TCRM (1) 25% of such costs are absorbed by PGT; (2) 25% are
recovered by PGT through direct bills (substantially all to PG&E as PGT's
principal customer); and (3) 50% are recovered by PGT through volumetric
surcharges over a three-year period. Costs associated with A&S's commitments for
Canadian pipeline capacity do not qualify as transition costs recoverable under
this mechanism.
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In May 1994, the FERC approved PGT's application seeking recovery of $154
million under the TCRM, which is 75% of the $206 million in estimated settlement
payments expected to be paid to Canadian gas producers as of the time PGT filed
its application. PGT has also sought recovery of an additional $14 million under
the TCRM. This amount represents 75% of additional settlement payments to
producers and certain costs related to A&S' wind-down of its gas aggregation and
supply business as a result of the decontracting process. In February 1995, the
FERC held that this amount was eligible for recovery under the TCRM. The CPUC
and other parties have until April 3, 1995 to challenge the prudency of this
amount. If no such challenge is made, the amount will be recovered under the
TCRM.
In November 1993, PG&E paid PGT approximately $51 million in payment of a
direct bill charged by PGT for transition costs under the TCRM. PG&E sought
recovery in its most recent BCAP application of this amount and the volumetric
surcharges to be billed to PG&E. As part of proposed gas settlement agreements
discussed below (see "Gas Reasonableness Proceedings -- Proposed Gas
Settlements"), the DRA has agreed that it will not seek any disallowance
relating to costs incurred by PG&E in connection with its Canadian
restructuring/decontracting activities once those costs are approved by the
FERC.
FINANCIAL IMPACT OF DECONTRACTING PLAN AND LITIGATION
The Company incurred transition costs of $228 million in 1993, consisting
of settlement payments made to producers in connection with the implementation
of the Decontracting Plan and amounts incurred by A&S in reducing certain
administrative and general functions resulting from the restructuring. Of these
costs, the Company deferred $143 million for future rate recovery. In addition,
the Company recorded a reserve of $31 million in 1993 related to A&S's remaining
commitments for Canadian transportation capacity. Accordingly, the Company
expensed $93 million in 1993 and a total of $23 million in prior years.
RESTRUCTURING OF INTERSTATE GAS SUPPLY ARRANGEMENTS
CURRENT GAS TRANSPORTATION AND PROCUREMENT ARRANGEMENTS
The Company's firm transportation agreement with PGT for up to 1,066 MMcf/d
runs through October 31, 2005. The Company's firm transportation agreement with
El Paso for up to 1,140 MMcf/d runs through December 31, 1997. The agreements
include provisions for fixed demand charges for reserving firm capacity on the
pipelines. The firm transportation reservation charges associated with the
Company's firm capacity on PGT and El Paso are approximately $50 million and
$130 million per year, respectively.
In April 1992, the Company executed firm transportation agreements with
Transwestern to transport 200 MMcf/d of San Juan basin gas supplies into the
Company's southern gas system, of which approximately 150 MMcf/d is to be used
to meet the Company's gas sales demands and approximately 50 MMcf/d is for use
by the Company's electric department. The demand charges associated with the
entire Transwestern capacity are currently approximately $30 million per year.
RECOVERY OF INTERSTATE TRANSPORTATION DEMAND CHARGES
Pursuant to FERC rules on capacity relinquishment and release and the
CPUC's capacity brokering program, the Company retained approximately 600 MMcf/d
on each of the PGT and El Paso systems to support its core and core subscription
customers and made amounts not needed to support such customers available for
capacity release and brokering to other potential shippers beginning in 1993.
Under the CPUC's capacity brokering program, noncore customers, or their gas
suppliers, are able to make firm interstate transportation arrangements to
deliver gas at the Company's interconnections with the interstate pipelines.
The Company has permanently assigned portions of the capacity it no longer
uses and is continuing its efforts to assign or broker the remaining unused
capacity. During 1994, the Company has been able to broker a portion of its
unused capacity, including limited amounts of that held for its core and core
subscription customers when such capacity was not being used. Amounts brokered
have generally been on a short-term basis, most of which were at a discounted
price. Based on the current demand for Canadian gas, the Company believes it
will be able to broker or assign substantially all of its unused capacity on PGT
by the end of 1995; however, due to lower demand for Southwest pipeline
capacity, the Company cannot predict the volume or price of the capacity on El
Paso and Transwestern that will be brokered or assigned.
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Interstate transportation capacity which cannot be marketed at the full
rate results in unrecovered demand charges. Under the CPUC brokering rules, the
CPUC has authorized the use of the ITCS to account for unrecovered demand
charges associated with interstate pipeline obligations in existence at the time
the decision creating the ITCS was issued in November 1991. To the extent the
Company is unable to broker its firm interstate capacity above core and core
subscription reservations at the full as-billed rate, or to broker such capacity
at all, the Company has been authorized to accumulate unrecovered demand charges
for El Paso and PGT in the ITCS account for later review and allocation among
customer classes.
Ultimate recovery of unrecovered interstate pipeline demand charges
accumulated in the ITCS will be subject to CPUC reasonableness review. There may
be instances where the CPUC may not allow full recovery with respect to
discounted rates, such as rates given to a customer in a negotiated discount gas
transportation contract entered into pursuant to the Company's EAD procedure.
The CPUC has indicated that if an EAD rate discount results in a shortfall in
recovery of ITCS costs contained in the otherwise applicable tariff rate, the
Company will not recover those ITCS costs from other customers.
In November 1994, the CPUC issued a decision on the Company's application
seeking recovery of amounts accumulated in the ITCS. The Company's application
sought to have $60.7 million, which represents the revenue requirement for the
estimated amount accrued in the ITCS account for the period August 1, 1993
through August 31, 1994, recovered in noncore rates over a 12-month period
beginning September 1, 1994. In its decision, the CPUC indicated that it did not
have a sufficient record to resolve contested issues regarding the total amount
of the Company's unrecovered costs of interstate pipeline capacity to allocate
to noncore customers. However, citing the fact that legitimate unrecovered costs
continue to accrue at a substantial rate, the decision authorized the Company to
increase rates to all noncore customers on December 1, 1994 through a rate
designed to collect approximately one-half of the accumulated demand charges for
unbrokered or discounted capacity on an interim basis, subject to refund should
ITCS costs prove to have been caused by improper acts of the Company. (This
amount was included in the rate adjustments effected January 1, 1995. See
"General -- Current Rate Proceedings -- 1995 Revenue Changes" above.) The CPUC
also set the matter for hearing at the earliest practicable date to consider
protests filed by El Paso. El Paso contends that the Company is inducing
customers to move from the El Paso pipeline system to the Company's Pipeline
Expansion by discounting rates on the Pipeline Expansion and recouping those
discounts through the ITCS. The Company expects to seek recovery of the balance
of the ITCS amounts originally sought in the hearing on this matter, which is
scheduled for September 1995.
Currently, the Company is not permitted to include any Transwestern firm
capacity demand charges in rates or in the ITCS account. The Company is
authorized to record costs associated with its Transwestern capacity in a
balancing account, with recovery of such costs subject to reasonableness review
proceedings, which are currently under way.
In January 1994, the DRA issued its report on the reasonableness of the
Company's gas procurement and operating activities for the 1992 record period.
In its report, the DRA argued that the Company imprudently entered into firm
transportation agreements with Transwestern in 1992 and recommended a
disallowance of the associated demand charges of approximately $18 million paid
by the Company during the record period, of which $4.5 million related to
capacity for the Company's electric department. The DRA asserted that the
Transwestern capacity was unnecessary to meet the expected needs of the
Company's core customers and that the Company should not have contracted for
such capacity. Hearings on this issue were concluded in January 1995, with a
decision expected in late 1995.
GAS REASONABLENESS PROCEEDINGS
Recovery of gas costs through the Company's regulatory balancing account
mechanisms is subject to a CPUC determination that such costs were incurred
reasonably. Under the current regulatory framework, annual reasonableness
proceedings are conducted by the CPUC on a historic calendar year basis.
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1988-1990 CANADIAN GAS PROCUREMENT ACTIVITIES
In March 1994, the CPUC issued a final decision on the Company's Canadian
gas procurement activities during 1988 through 1990. The CPUC found that the
Company could have saved its customers money if it had bargained more
aggressively with its existing Canadian suppliers or bought cheaper gas from
other Canadian sources. The CPUC concluded that it was appropriate for the
Company to take a substantial portion (up to 700 MMcf/d) of its Canadian gas at
its then-existing price, but that the Company could have met the remainder of
its demand for Canadian gas at lower prices, either from the same suppliers or
with purchases from other available Canadian natural gas sources. The decision
orders a disallowance of $90 million of gas costs, plus accrued interest
estimated at approximately $25 million through December 31, 1993. The CPUC also
issued a final decision on the Company's non-Canadian gas operations during 1988
through 1990, ordering a disallowance of $8 million.
The Company filed a request for rehearing of the CPUC's decision ordering a
disallowance in connection with the Company's Canadian gas procurement
activities in 1988-1990, which was denied in November 1994. In December 1994,
the Company filed a complaint against the CPUC in the U.S. District Court for
the Northern District of California challenging this decision by the CPUC. The
complaint alleges that the CPUC disallowance order purports to regulate the
foreign and interstate purchase and transportation of natural gas, matters
within the exclusive jurisdiction of United States and Canadian regulatory
authorities. Accordingly, the complaint alleges, such order is preempted by
federal law and violates the Company's rights under the United States
Constitution. The complaint seeks injunctive and declaratory relief.
PROPOSED GAS SETTLEMENTS
A number of other reasonableness issues related to the Company's gas
procurement practices and supply operations for periods dating from 1988 through
1994 are still under review by the CPUC. The DRA recommended disallowances of
$142 million and a penalty of $50 million and indicated that it was considering
additional recommendations for pending issues. The Company and the DRA have
signed settlement agreements to resolve most of these issues for a $68 million
disallowance.
Significant issues covered by the gas settlement agreements include (i) the
Company's purchases of Canadian, Southwest and California gas for its electric
department in 1991 and 1992 and its core customers from 1991 through May 1994;
(ii) issues not related to gas procurement which arise from the DRA's
investigation of A&S, and the proposed investigation of ANG, a former affiliate
of the Company, for the period 1988 through May 1994; (iii) the effects the
Company's Canadian gas procurement costs may have had on amounts paid by the
Company for Northwest power purchases for 1988 through 1992 and for power
purchased from geothermal and QF producers during 1991 and 1992; (iv) the
Company's gas storage operations for 1991 and 1992; (v) the Company's Southwest
gas procurement activities for 1988 through 1990; and (vi) Canadian gas
restructuring transition costs billed to PG&E by PGT through FERC-approved
rates.
Agreements with the DRA do not constitute a CPUC decision and are subject
to modification by the CPUC in its final decisions. The gas settlement
agreements are expressly conditioned upon CPUC approval. Upon such approval, the
Company would return approximately $68 million to its ratepayers.
The proposed gas settlement agreements do not resolve issues related to the
effect the Company's Canadian gas procurement costs during the 1988 through 1990
period may have had on the price the Company paid to geothermal and QF producers
during those years. Hearings on those issues have not yet been scheduled by the
CPUC. The proposed gas settlement agreements also do not resolve the
reasonableness of the Company's subscription to Transwestern pipeline capacity
or the costs accrued in the Company's ITCS account.
FINANCIAL IMPACT OF GAS REASONABLENESS PROCEEDINGS
The Company accrued approximately $135 million and $61 million in 1994 and
1993, respectively, for gas reasonableness matters including the CPUC decisions
for the years 1988 through 1990 and issues covered by
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the gas settlement agreements. The Company believes that the ultimate outcome of
these matters will not have a significant impact on its financial position or
results of operations.
PGT/PG&E PIPELINE EXPANSION PROJECT
In November 1993, PGT and the Company placed in service an expansion of
their natural gas transmission systems from the Canadian border into California
(Pipeline Expansion). The 840-mile combined pipeline provides an additional 148
MMcf/d of firm capacity to the Pacific Northwest and an additional 851 MMcf/d of
capacity to Northern and Southern California. At December 31, 1994, the
Company's total investment in the Pipeline Expansion project was approximately
$1,627 million. The $1,627 million consisted of $786 million for the facilities
within California (i.e., in-state portion) and $841 million for the facilities
outside California (i.e., interstate, or PGT, portion).
The conditions of the CPUC's approval of the construction of the in-state
portion of the Pipeline Expansion place the Company at risk for its decision to
construct based on its assessment of market demand and for undersubscription and
underutilization of the facility. The CPUC required the application of a "cross-
over" ban under which volumes delivered from the incremental PGT portion of the
Pipeline Expansion must be transported at an incremental in-state expansion
rate. Incremental rate design is based on the concept that expansion shippers,
not existing ratepayers, bear the incremental costs of the expansion facilities.
Capacity on the PGT portion of the Pipeline Expansion is fully subscribed under
long-term firm transportation contracts. However, to date, shippers have only
executed long-term firm transportation contracts for approximately 40% of the
in-state capacity, and the Company continues negotiations for the remainder of
that capacity. The CPUC has authorized the Company to provide as-available
service on the in-state portion of the Pipeline Expansion, which provides
additional revenues to recover the incremental costs of the expansion.
In February 1994, the CPUC issued a decision on the Company's request for
an increase in the cost cap for the in-state portion of the Pipeline Expansion
and its interim rate filing. The cost cap represented the maximum amount
determined by the CPUC to be reasonable and prudent based on an estimate of the
anticipated construction costs at that time. The CPUC granted the Company's
request to increase the cost cap to $849 million, but set interim rates based on
the original cost cap of $736 million, subject to adjustment within the newly
approved cost cap after the outcome of a reasonableness review of capital costs.
The CPUC's decision finds that given market conditions at the time, the Company
was reasonable in constructing the Pipeline Expansion. The CPUC has denied
rehearing of this decision.
In September 1994, the Company filed an application with the CPUC
requesting that the CPUC find reasonable the full capital costs of the in-state
portion of the Pipeline Expansion (estimated to be $813 million) and its initial
operating expenses. The Company's request for a $13 million increase in revenues
from the in-state portion of the Pipeline Expansion, compared to rates in effect
in 1994, will also be considered in this proceeding. A decision in this
proceeding is not expected until 1996.
In its 1991 order approving the PGT portion of the Pipeline Expansion, the
FERC concluded that PGT had not sufficiently demonstrated that shippers would
not be subject to discriminatory restraints on access into California or on the
PGT portion of the Pipeline Expansion as a result of the "cross-over" ban
imposed by the CPUC. As a result, the FERC reduced PGT's approved rate of return
on equity until such time as PGT demonstrates that neither its rates or
transportation policies nor those of the Company result in unduly discriminatory
restraints. In March 1994, the FERC allowed PGT to implement, subject to refund,
an increase in the nominal return on equity to 12.75%, but reaffirmed the lower
10.13% return on equity it implemented as an incentive for PGT to seek removal
of unduly discriminating restraints.
In February 1994, PGT filed a general rate case with the FERC which
proposed, among other things, that the lower return on equity imposed by the
FERC be removed and PGT be allowed to determine rates for all of its facilities
on an equity rate of return of 13%. In March 1994, the FERC approved PGT's
proposal to determine rates based on the higher rate of return, subject to
refund, pending the outcome of hearings in PGT's rate case, and authorized the
rate change to begin in September 1994. Hearings in PGT's rate case are
scheduled to begin in April 1995.
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The Company believes that resolution of the rate proceedings pending at the
CPUC and FERC will not have a significant impact on its financial position or
results of operations.
OTHER COMPETITIVE PIPELINE PROJECTS
In March 1993, Mojave Pipeline Company (Mojave), which is a subsidiary of
El Paso, filed a request seeking FERC authorization for construction of a 475
MMcf/d transportation-only pipeline expansion of its interstate natural gas
pipeline. Mojave indicated that it intends to place the proposed expansion into
service by January 1, 1996. The expansion would extend Mojave's system from its
current terminus in Bakersfield, California, through California's Central Valley
to Sacramento and the San Francisco Bay Area. Mojave's filing indicated that 433
MMcf/d of the firm service capacity provided by the proposed expansion would be
provided to customers located in the Company's service territory, with
approximately 257 MMcf/d of that amount to be used to provide gas service that
currently is not provided by the Company. The remaining 176 MMcf/d represents
service to customers currently served by the Company.
In November 1994, the FERC issued an order, approving, with conditions,
Mojave's expansion application and granting Mojave a permit to construct,
subject to further environmental review. In response to Mojave's original
application, the Company had requested that the FERC establish a mechanism to
reimburse the Company for costs arising from bypass associated with Mojave's
proposed expansion. In its order approving Mojave's expansion, the FERC rejected
the Company's claim that the Mojave expansion will result in lost revenues of
between $204 million and $223 million. Instead, the FERC estimated the amount
would not likely exceed $5 million per year for 15 years. The FERC also rejected
the Company's request to be relieved of up to $86 million in charges for El Paso
capacity to account for reduced load resulting from Mojave's proposed expansion,
concluding instead that such amount could not exceed $19.5 million. The FERC
concluded that these costs did not justify rejection of Mojave's application,
but it was unable to determine whether and what amount of compensation is owed
to the Company by Mojave. The FERC also directed the Company, Mojave and El Paso
to provide information explaining whether a connection exists between the
Company's obligation to purchase service from El Paso and Mojave's service to
the customers Mojave intends to serve within the Company's service territory,
and specifying what type and volume of load the Company will lose as a direct
result of the bypass by Mojave.
In December 1994, the Company filed its response to the FERC's order. In
its response, the Company affirmed that a direct connection exists between the
Company's obligation to purchase service from El Paso and Mojave's service to
bypassing end users. The Company included a list of current and future natural
gas customers that the Company believes might be targeted by Mojave for bypass
transportation service. The Company also updated its request for compensation as
a result of the Mojave bypass, asking the FERC to relieve the Company of up to
$66 million in El Paso capacity charges and require Mojave to pay the Company
$135 million in lost revenues associated with the proposed bypass.
In March 1994, the FERC denied several requests for rehearing of its order
approving Mojave's expansion. The FERC deferred to a subsequent order
consideration of the Company's request for relief from El Paso capacity charges
and compensation from Mojave.
The Company also faces competition from various other pipeline projects
completed in recent years to serve the enhanced oil recovery market in Southern
California and other customers. In 1992, projects sponsored by Mojave and the
Kern River Gas Transmission Company commenced commercial operations, and both
Transwestern and El Paso put into service expanded pipeline facilities from the
San Juan Basin in New Mexico to the California border. These projects provide
additional capacity to some of the same markets served by the Pipeline
Expansion. Some of the gas available from the U.S. Southwest over these projects
is priced equal to or lower than the price of Canadian gas available over the
Pipeline Expansion, due in part to federal tax credits available for certain San
Juan gas production.
STORAGE SERVICE
The Company has generally provided natural gas storage service only in
conjunction with its procurement and transportation services. In February 1993,
the CPUC adopted policies and rules for permanent unbundled
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gas storage programs for noncore customers, and an unbundled storage program for
the Company was approved by the CPUC in May 1994. Storage service for core
customers remains bundled with procurement and transportation services.
In September 1994, the Company began offering unbundled storage to noncore
customers for varying terms of one year or less. Customers bid to purchase this
storage capacity, with available capacity awarded to the highest bids first. To
the extent the Company does not recover the full costs allocated to this noncore
storage program, the CPUC authorized a Noncore Storage Balancing Account in
which these unrecovered costs are accumulated for later review and allocation
among customer classes. The CPUC also approved negotiated discounted rates for
storage services for noncore customers under certain circumstances, but provided
that a portion of any revenue shortfalls attributable to such discounted rates
may not be recovered from other customers. To date, the Company has not offered
storage service at discounted rates.
DIABLO CANYON
DIABLO CANYON OPERATIONS
Diablo Canyon Units 1 and 2 began commercial operation in May 1985 and
March 1986, respectively. As of December 31, 1994, Diablo Canyon Units 1 and 2
had achieved lifetime capacity factors of 78% and 80%, respectively.
The table below outlines Diablo Canyon's refueling schedule for the next
five years. This schedule assumes that a refueling outage for a unit will last
approximately six weeks, depending on the scope of the work required for a
particular outage. The schedule is subject to change in the event of unscheduled
plant outages or changes in the length of the fuel cycle.
1995 1996 1997 1998 1999
---------- ---------- ---------- ---------- ----------
Unit 1
Refueling........... September March September
Startup............. November April November
Unit 2
Refueling........... March September March
Startup............. May November May
In November 1994, the Nuclear Regulatory Commission's (NRC) Atomic Safety
and Licensing Board issued its decision approving the Company's request to
change the operating license expiration dates for both units at Diablo Canyon.
Diablo Canyon Units 1 and 2 were originally licensed to operate for 40 years
commencing on the date the construction permit for the respective unit was
issued, which occurred in April 1968 and December 1970, respectively. In 1982,
the NRC determined that the 40-year term of operation for nuclear power plants
may instead begin upon issuance of the first operating license. License
amendments were issued in March 1994 to extend the operating license expiration
date for Units 1 and 2 to September 2021 and April 2025, respectively.
DIABLO SETTLEMENT
In December 1994, the Company, the DRA, the California Attorney General and
several other parties representing energy consumers agreed to a memorandum of
understanding and draft settlement agreement to modify the pricing provisions of
the Diablo Settlement. All other terms and conditions of the Settlement
Agreement would remain unchanged. The parties have filed the proposed
modification with the CPUC and will seek expedited CPUC approval of the proposed
change.
Under the proposed modification, the price for power produced by Diablo
Canyon would be reduced from the current level and would be as shown in the
following table. Based on Diablo Canyon's current operating
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performance, the proposed modification would result in approximately $2.1
billion less revenue over the next five years, compared to the original pricing
provisions of the Diablo Settlement.
DIABLO CANYON PRICE (CENTS) PER KWH
1995 1996 1997 1998 1999
------ ------ ------ ------ ------
Original Settlement Agreement Price*............... 12.15 12.42 12.70 12.98 13.28
Proposed Price..................................... 11.00 10.50 10.00 9.50 9.00
- ---------------
* Assumes 3.5% inflation
After December 31, 1999, the escalating portion of the Diablo Canyon price
will increase using the same formula specified in the Diablo Settlement. The
proposed modification provides the Company with the right to reduce the price
below the amount specified if it so chooses.
The parties to the proposed modification agree that the difference between
the Company's revenue requirement under the original terms of the Diablo
Settlement and the proposed new prices will be applied to the ECAC balancing
account until the ECAC undercollection as of December 31, 1995 (see "General --
Current Rate Proceedings -- 1995 Revenue Changes -- ECAC" above) is fully
amortized. As a result, the Diablo Canyon price reductions would help achieve
amortization of the ECAC undercollection. In addition, the parties agree that
the prices for the period through December 31, 1999 are reasonable and shall be
the basis for the recovery of the Company's ECAC revenue requirement pursuant to
the pricing of Diablo Canyon power.
The Diablo Settlement adopted alternative ratemaking for Diablo Canyon by
basing revenues primarily on the amount of electricity generated by the plant,
rather than on traditional cost-based ratemaking. Under this "performance based"
approach, the Company assumes a significant portion of the operating risk of the
plant because the extent and timing of the recovery of actual operating costs,
depreciation and a return on the investment in the plant primarily depend on the
amount of power produced and the level of costs incurred. The Company's earnings
are affected directly by plant performance and costs incurred. Earnings relating
to Diablo Canyon will fluctuate significantly as a result of refueling or other
extended plant outages, plant expenses and the effects of a peak-period pricing
mechanism. See "Diablo Canyon Operations" above for the plant refueling
schedule.
The settlement decision explicitly affirmed that Diablo Canyon costs and
operations no longer should be subject to CPUC reasonableness reviews. The
decision states that, to the extent permitted by law, the CPUC intends that this
decision be binding upon future Commissions, based upon a determination that
taken as a whole the settlement produces a just and reasonable result, and that
the settlement has been approved based on the reasonable reliance of the parties
and the CPUC that all of the terms and conditions will remain in effect for the
full term of the settlement, ending 2016. However, the decision states that the
CPUC cannot bind future Commissions in fixing just and reasonable rates for
Diablo Canyon.
Under the Diablo Settlement, revenues are based on a pre-established price
per kWh consisting of a fixed component (3.15 cents per kWh) and an escalating
component for each kWh of electricity generated by the plant. As noted above,
the Company has proposed modifying the price for the years 1995 through 1999.
After 1999, the escalating component will be adjusted by the change in the
consumer price index plus 2.5%, divided by two. During the first 700 hours of
full-power operation for each unit during the peak period (10 a.m. to 10 p.m. on
weekdays in June through September), the price is 130% of the stated amount to
encourage the Company to utilize the plant during the peak period. During the
first 700 hours of full-power operation for each unit during the non-peak period
of the year, the price is 70% of the stated amount. At all other times, the
price is 100% of the stated amount.
If power generation drops below specified capacity levels, the Company may
trigger an annual revenue floor provision, or under certain conditions, seek
abandonment of the plant (discussed below). Floor payments ensure that the
Company will receive some revenue, even if the plant stops producing power.
Floor payments
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are based on the prices set in the agreement at a 36% capacity factor from 1988
through 1997 (reduced by 3% each time the floor provision is exercised and not
repaid) with the capacity factor decreasing in the future. Floor payments must
be refunded to customers under specified circumstances.
If actual operation falls below the floor capacity factor in three
consecutive years, whether or not the floor payment provision has been
triggered, the Company must file for abandonment or explain why continued
application of the settlement is appropriate. In the event there is a prolonged
plant outage and the Company files for abandonment, the Company may ask for
recovery of the lesser of (a) floor payments allowed for ten years, less any
years of floor payments already received and not repaid, or (b) $3 billion,
reduced by $100 million per year of operation on January 1 of each year starting
in 1989.
The Diablo Settlement provides that certain Diablo Canyon costs, including
decommissioning costs, be recovered over the term of the Diablo Settlement,
including a full return on such costs through base rates.
NUCLEAR FUEL SUPPLY AND DISPOSAL
The Company has purchase contracts for, and an inventory of, uranium
concentrates and contracts for conversion of uranium to uranium hexafluoride,
uranium enrichment and fuel fabrication. Based on current operations forecasts,
Diablo Canyon's requirements for uranium supply, enrichment services and
conversion services will be satisfied through existing long-term contracts
through 1998, 1999 and 2001, respectively. The Company is also negotiating
contracts for alternative uranium supply and enrichment services through 2002.
Fuel fabrication contracts for the two units will supply their requirements for
the next five operating cycles for each unit. These contracts are intended to
ensure long-term fuel supply, but permit the Company the flexibility to take
advantage of short-term supply opportunities. In most cases, the Company's
nuclear fuel contracts are requirements-based, with the Company's obligations
linked to the continued operation of Diablo Canyon.
Under the Nuclear Waste Policy Act of 1982 (Nuclear Act), the U.S.
Department of Energy (DOE) is responsible for the transportation and ultimate
long-term disposal of spent nuclear fuel and high-level waste. The Nuclear Act
sets a national policy for the disposal of nuclear waste from commercial
reactors, and establishes a timetable for the DOE to choose one or more sites
for the deep underground burial of wastes from nuclear power plants. Under the
Nuclear Act, utilities are required to provide interim storage facilities until
permanent storage facilities are provided by the federal government. The Nuclear
Act mandates that one or more such permanent disposal sites be in operation by
1998, although DOE has indicated that such sites may not be in operation until
2010. DOE is also considering providing interim storage in a monitored
retrievable storage facility earlier than 2010. However, under DOE's current
estimated acceptance schedule for spent fuel, Diablo Canyon's spent fuel is not
likely to be accepted by DOE for interim or permanent storage before 2011, at
the earliest. At the projected level of operation for Diablo Canyon, the
Company's facilities are sufficient to store on-site all spent fuel produced
through approximately 2006 while maintaining the capability for a full-core
off-load. In the event an interim or permanent DOE storage facility is not
available for Diablo Canyon's spent fuel by 2006, the Company will examine
options for providing additional temporary spent fuel storage at Diablo Canyon
or other facilities, pending disposal or storage at a DOE facility. Such
additional temporary spent fuel storage may be necessary in order for the
Company to continue operating Diablo Canyon beyond approximately 2006, and may
require approval by the NRC and other regulatory agencies.
In June 1994, a number of utilities (including the Company), state utility
commissions and state attorneys general filed lawsuits seeking declaratory and
injunctive relief against the DOE's alleged failure to meet its obligations
under the Nuclear Act. Action on the lawsuits has been deferred pending issuance
of a DOE policy statement on the same subject.
In July 1988, the NRC gave final approval to the Company's plan to store
radioactive waste from the Humboldt Bay Power Plant (Humboldt) at Humboldt for
20 to 30 years and, ultimately, to decommission the unit. The license amendment
issued by the NRC allows storage of spent fuel rods at Humboldt until a federal
repository is established. The Company has agreed to remove all nuclear waste as
soon as possible after the federal disposal site is available.
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INSURANCE
The Company is a member of Nuclear Mutual Limited (NML) and Nuclear
Electric Insurance Limited (NEIL). These companies, which are owned by utilities
with nuclear generating facilities, provide insurance coverage against property
damage, decontamination, decommissioning and business interruption and/or extra
expenses during prolonged accidental outages for reactor units in commercial
operation. If the nuclear plant of a member utility is damaged or increased
costs for business interruption are incurred due to a prolonged accidental
outage, the Company may be subject to maximum retrospective premium assessments
of $28 million (property damage) and $7 million (business interruption), in each
case per policy period, if losses exceed premiums, reserves and other resources
of NML or NEIL.
The federal government has enacted laws that require all utilities with
nuclear generating facilities with a capacity of 100 MW or more to share in
payment of claims resulting from a nuclear incident. The Price-Anderson Act
limits industry liability for third-party claims resulting from any nuclear
incident to $8.9 billion per incident. Coverage of the first $200 million is
provided by a pool of commercial insurers. If a nuclear incident results in
public liability claims in excess of $200 million, the Company may be assessed
up to $159 million per incident with payments in each year limited to a maximum
of $20 million per incident; payments in excess are deferred to the next
calendar year.
DECOMMISSIONING
The estimated cost of decommissioning the Company's nuclear power
facilities is recovered in base rates through an annual allowance. For the year
ended December 31, 1994, the amount recovered in rates for decommissioning costs
was $54 million. The estimated total obligation for decommissioning costs is
approximately $1.1 billion in 1994 dollars (or $4.5 billion in future dollars);
this obligation is being recognized ratably over the facilities' lives. This
estimate considers the total costs of decommissioning and dismantling plant
systems and structures and includes a contingency factor for possible changes in
regulatory requirements and waste disposal cost increases.
As of December 31, 1994, the Company had accumulated external trust funds
with an estimated fair value of $617 million, based on quoted market prices, to
be used for the decommissioning of the Company's nuclear facilities.
Corresponding amounts are included in accumulated depreciation and
decommissioning. The trust funds maintain substantially all of their investments
in debt and equity securities. All fund earnings are reinvested. Funds may not
be released from the external trust funds until authorized by the CPUC.
The CPUC reviews the funding levels for the Company's decommissioning trust
in each GRC. Based upon the trust's then-current asset level, and revised
earnings and decommissioning cost assumptions, the CPUC may revise the amount of
decommissioning costs it has authorized in rates for contribution to the trust.
To date the CPUC has not revised the funding levels initially established in
1987. However, to comply with tax law requirements, the Company anticipates that
the CPUC will revise the funding levels no later than the 1997 tax year to
reflect then-current earnings assumptions and decommissioning cost estimates.
PG&E ENTERPRISES
Enterprises is the parent company established to oversee the Company's
unregulated non-utility business activities. Enterprises was established in 1988
and is a wholly owned subsidiary of the Company. Enterprises' activities are
conducted through the entities described below.
NON-UTILITY ELECTRIC GENERATION
A wholly owned Enterprises subsidiary is a general partner in U.S.
Generating Company (USGen), a California general partnership. A subsidiary of
Bechtel Enterprises, Inc., Bechtel Generating Company, Inc., is the other
general partner of USGen. USGen develops and manages non-utility electric
generation facilities that compete in the U.S. power generation market and sell
power to utilities other than the Company. Enterprises' ownership interest in
projects developed by USGen varies by project. Profits and losses realized by
USGen are distributed in proportion to the partners' relative interests in the
project from which those
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profits or losses are derived. USGen is currently involved in eight operational
plants and five projects under construction. The total generating capacity of
these 13 plants is 2,238 MW. Enterprises' share of capacity from those projects
is approximately 971 MW. The projects are typically financed with a combination
of equity commitments from the project sponsors and non-recourse debt.
In August 1994, USGen negotiated and completed the acquisition of Makowski
on behalf of Enterprises and Bechtel Enterprises, Inc. Makowski is a
Boston-based company engaged in the development of natural gas-fueled power
generation projects and natural gas distribution, supply and underground storage
projects. Makowski is currently involved in five operational plants. (USGen is
also involved in one of these plants.) With the acquisition of Makowski,
Enterprises' affiliates are involved in a total of 12 plants in operation and 5
plants under construction, with total generating capacity of 3,298 MW.
Enterprises' share of capacity from all 17 plants is approximately 1,389 MW.
In addition, Enterprises is in the process of forming, in conjunction with
Bechtel Enterprises, Inc., a company to develop, build, own and operate
international nonutility generation projects.
U.S. Operating Services Company (USOSC), a California general partnership,
provides operations and maintenance services for power facilities managed by
USGen and to third parties in the independent power production business. An
Enterprises subsidiary and a subsidiary of Bechtel Group, Inc. are the general
partners of USOSC. Enterprises' economic interest in USOSC projects varies by
project.
GAS AND OIL EXPLORATION AND PRODUCTION
DALEN, a wholly owned indirect subsidiary of Enterprises, is engaged in
natural gas and oil exploration and production primarily in the Gulf Coast, east
Texas, Anadarko and Rocky Mountain regions of the U.S.
In July 1994, the Company approved a plan for the disposition of DALEN
through an initial public offering of DALEN's common stock, subject to favorable
market conditions. In February 1995, the Company confirmed its intent to sell
DALEN in 1995, either through an initial public offering or a private sale. The
Company's decision is based upon the Company's determination that oil and gas
exploration and production activities do not fit within its revised long-term
corporate strategy. In anticipation of the disposition, DALEN entered into
multiple contracts in June 1994 to sell $130 million of its oil and gas
properties, resulting in a net pretax gain of $2 million. As of December 31,
1994, DALEN had assets of approximately $490 million.
REAL ESTATE DEVELOPMENT
PG&E Properties, Inc. (Properties), a wholly owned subsidiary of
Enterprises, develops real estate in the Company's service territory, focusing
on residential lot creation. It also develops offices, industrial buildings,
retail outlets and apartments.
ENVIRONMENTAL MATTERS AND OTHER REGULATION
ENVIRONMENTAL MATTERS
The Company is subject to a number of federal, state and local laws and
regulations designed to protect human health and the environment by imposing
stringent controls with regard to planning and construction activities, land
use, and air and water pollution, and, in recent years, by governing the use,
treatment, storage and disposal of hazardous or toxic materials. These laws and
regulations affect future planning and existing operations, including
environmental protection and remediation activities. The Company has undertaken
major compliance efforts with specific emphasis on its purchase, use and
disposal of hazardous materials, the cleanup or mitigation of historic waste
spill and disposal activities, and the upgrading or replacement of the Company's
bulk waste handling and storage facilities.
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ENVIRONMENTAL PROTECTION MEASURES
The Company's estimated expenditures for environmental protection are
subject to periodic review and revision to reflect changing technology and
evolving regulatory requirements. Capital expenditures for environmental
protection are currently estimated to be approximately $39 million, $93 million,
$85 million, $69 million and $66 million for 1995, 1996, 1997, 1998 and 1999,
respectively, and are included in the Company's five-year estimate of capital
requirements shown above in "General -- Capital Requirements and Financing
Programs." Expenditures during these years will be primarily for oxides of
nitrogen (NOx) emission reduction projects. In addition, PGT estimates its
capital expenditures for environmental protection will be approximately $10
million in 1995, primarily for NOx emission reduction and dry low emission
equipment, and approximately $1.8 million in 1996.
Air Quality
The Company's existing thermal electric generating plants are subject to
numerous air pollution control laws, including the California Clean Air Act
(CCAA) with respect to emissions. Pursuant to the CCAA and the Federal Clean Air
Act, the three local air districts in which the Company operates fossil fuel
fired generating plants adopted final rules that require a reduction in NOx
emissions from the power plants of approximately 90% by 2004 (with numerous
interim compliance deadlines). The first major retrofits are scheduled to begin
in 1996. Certain retrofits will not be required if the smaller generating units
are operated for emergency purposes only after 2000. One rule may also require
additional expenditures of up to $1.5 million in the San Luis Obispo County Air
Pollution Control District, depending on air quality progress in that district.
The Company currently estimates that compliance with these NOx rules could
require capital expenditures of approximately $300 million over 10 years. This
estimate assumes that most of the 170 MW and smaller boilers will be retired
before the retrofits are required. Ongoing business and engineering studies
could change this estimate.
Other air districts have adopted NOx rules for the Company's natural gas
compressor stations in California, and these rules continue to be modified.
Eventually the rules are likely to require NOx reductions of up to 80% for many
of the Company's natural gas compressor stations. The Company currently
estimates that the total cost of complying with these rules will be
approximately $25 to $55 million over five years.
In the Company's 1993 GRC, the CPUC established an Air Quality Adjustment
mechanism under which the Company may seek cost recovery in rates for NOx
reduction projects during 1994 and 1995. However, by the time the retrofits are
operational, the Company may either be subject to PBR or one of several
restructuring proposals currently under consideration by the CPUC. Therefore,
the mechanism for ratemaking treatment of these costs is uncertain at this time.
In 1990 Congress passed extensive amendments to the Federal Clean Air Act.
The Environmental Protection Agency (EPA) has issued numerous regulations for
the implementation of these amendments. The Company is currently assessing the
impact of the regulations. Generally, existing or proposed state and local air
quality requirements are more stringent than the new federal requirements, which
should therefore have little impact on the Company. However, stringent federal
air monitoring requirements mandated the installation of monitoring equipment to
measure emissions from the fossil fuel fired generating plants. The cost of
complying with the monitoring requirements totalled approximately $22 million in
1994.
Water Quality
The Company's existing power plants, including Diablo Canyon, are subject
to federal and state water quality standards with respect to discharge
constituents and thermal effluents. The Company's fossil fueled power plants
comply in all material respects with the discharge constituents standards and
either comply in all material respects with or are exempt from the thermal
standards. A thermal effects study at Diablo Canyon was completed in May 1988,
and has been reviewed by the Central Coast Regional Water Quality Control Board
(Regional Board). The Regional Board has not yet made a final decision on the
report and has requested that the Company continue the marine monitoring
program. In the event that Diablo Canyon does
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not comply with the thermal limitations and in the unlikely event that major
modifications are required (e.g., cooling towers), significant additional
construction expenditures could be required.
A thermal effects study of the Company's Pittsburg and Contra Costa Power
Plants was submitted to the San Francisco and Central Valley Regional Water
Quality Control Boards in December 1992. In general, the study found no
significant adverse effects associated with the thermal discharge at either
plant. Additionally, several fish species listed or proposed for listing as
endangered species may be found in the waters near these plants. There are
severe restrictions on the "taking" (e.g. harassing, wounding or killing) of
such species. Therefore, significant modifications could be required to plant
operations (e.g., cooling towers) if a plant intake structure or thermal
discharge is found to "take" an endangered species.
Pursuant to the federal Clean Water Act, the Company is required to
demonstrate that the location, design, construction and capacity of power plant
cooling water intake structures reflect the best technology available (BTA) for
minimizing adverse environmental impacts at all existing water-cooled thermal
plants. The Company has submitted detailed studies of each power plant's intake
structure to various governmental agencies. Each plant's existing water intake
structure was found to meet the BTA requirements. However, if in the future
there are changes in available technology, these findings are subject to further
review by various agencies. Thus, construction expenditures or operational
changes may be necessary to meet a more stringent future standard.
Oil Spill Prevention
The Company operates three marine terminals, approximately 92 large
aboveground fuel tanks with a capacity of approximately 18 million barrels and
approximately 50 miles of fuel pipelines. These facilities are used for the
transport, handling and storage of residual fuel oil and diesel fuels, both of
which are used at the Company's power plants. The Company continues to assess
its need to operate oil handling and storage facilities as part of its efforts
to reduce exposure to oil handling risks and operational expenses without
sacrificing electric system reliability.
Under the federal Clean Water Act Spill Prevention Control and
Countermeasure (SPCC) regulations, many of the Company's power plants,
substations and service centers must install and maintain facilities to prevent
the release of oil and other hazardous materials to surface waters. Capitalized
SPCC project costs for 1995 and 1996 are estimated to be approximately $2
million.
In addition, activities associated with the transport, storage and handling
of petroleum products are regulated by the federal Oil Pollution Act of 1990
(OPA) and the California Oil Spill Prevention and Response Act of 1990 (OSPRA).
Under these laws, the Company is required to demonstrate $500 million of
financial responsibility, which it demonstrates through a combination of
insurance and self insurance.
Regulations under OPA and OSPRA require development of Oil Spill Emergency
Response Plans utilizing worst case planning scenarios. Plans must include
contracting for response resources to respond to the worst case scenarios. The
Company is a member of the Clean Bay, Clean Seas and Humboldt Bay oil spill
response organizations and the Marine Preservation Association through which it
can obtain the services of the Marine Spill Response Corporation, a national oil
spill response organization.
Company expenditures to comply with OPA and OSPRA requirements in 1995 and
1996 are estimated to total less than $2 million.
HAZARDOUS MATERIALS AND HAZARDOUS WASTE COMPLIANCE AND REMEDIATION
The Company assesses, on an ongoing basis, measures that may need to be
taken to comply with laws and regulations related to hazardous materials and
hazardous waste compliance and remediation activities. Generally, these
compliance costs are recovered through the GRC process. However, as discussed
below, the CPUC has established a separate mechanism for recovery of certain
hazardous waste remediation costs.
The EPA, the California Department of Toxic Substances Control (DTSC), and
associated regional and local agencies have comprehensive rules which regulate
the manufacture, distribution, use and disposal of
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polychlorinated biphenyls (PCBs). The Company has established programs and has
committed resources to achieve compliance with these rules. In 1982, the EPA
adopted new regulations greatly restricting the use of PCBs in electrical
equipment. The regulations have resulted in the early retirement and replacement
of certain equipment. Since Company operations generate PCB-contaminated waste
which requires special handling, the Company has contracted with EPA-approved
firms for the disposal or recycling of PCB waste. The Company estimates that PCB
disposal will cost approximately $8 million in 1995 and 1996.
The Company has a comprehensive program to comply with the many hazardous
waste storage, handling and disposal requirements promulgated by the EPA under
the Resource Conservation and Recovery Act and the Comprehensive Environmental
Response, Compensation, and Liability Act (CERCLA), along with California's
hazardous waste laws and other environmental requirements. As part of this
general compliance effort, the Company has initiated programs to address three
specific environmental issues: (i) wastewater holding ponds, (ii) underground
storage tanks, and (iii) historic hazardous waste sites, including former
manufactured gas plant sites.
Wastewater evaporation ponds contain materials such as compressor cooling
water blowdown from gas compressor stations. The Company has replaced the old
ponds with new evaporation ponds that meet new standards for leak monitoring,
detection and containment. Capital expenditures for this work in 1995 are
estimated to be approximately $0.9 million. Closure and post-closure
expenditures for these ponds, including groundwater remediation, health risk
assessments and management plans, may approximate $30 million for a 30-year
period.
Underground storage tanks are the subject of federal and California
regulatory programs directed at identifying and eliminating the possibility of
leaks. The Company has approximately 270 underground tanks, some of which must
be upgraded to meet new standards. The tanks contain hazardous materials such as
gasoline, waste automotive crankcase oil, transformer fluid or oily wastewater.
The Company has an ongoing program to improve leak monitoring, test each tank
for leakage and, if necessary, sample soil and water from the surrounding area
and remediate any contamination detected. Costs for testing, remediation and
tank replacement in 1995 and 1996 are estimated to be approximately $4.6
million.
A third program is aimed at assessing whether and to what extent remedial
action may be necessary to mitigate potential hazards posed by certain disposal
sites and retired manufactured gas plant sites. During their operation,
manufactured gas plant facilities produced lampblack and tar residues,
byproducts of a process that the Company and other utilities used as early as
the 1850s to manufacture gas from coal and oil. As natural gas became widely
available (beginning about 1930), the Company's manufactured gas plants were
removed from service. The residues which may remain at some sites contain
chemical compounds which now are classified as hazardous. The Company has
identified and reported to federal and California environmental agencies 96
manufactured gas plant sites which the Company operated in its service
territory. The Company owns all or a portion of 29 of these manufactured gas
plant sites. The Company has begun a program, in cooperation with environmental
agencies, to evaluate and take appropriate action to mitigate any potential
health or environmental hazards at sites which the Company owns. The Company
currently estimates that this program may result in expenditures of
approximately $30 million over the period 1995 through 1996. The full long-term
costs of the program cannot be determined accurately until a closer study of
each site has been completed. It is expected that expenses will increase as
remedial actions related to these sites are approved by regulatory agencies or
if the Company is found to be responsible for clean up at sites it does not
currently own.
Manufactured gas plant sites at which the Company has been designated as a
potentially responsible party (PRP) under the California Hazardous Substance
Account Act (California Superfund) include the Martin Service Center site and
Midway/Bayshore sites in Daly City, California, the San Rafael site, and the
Sacramento site. The Company will perform a groundwater remedial action at its
former Sacramento manufactured gas plant site during 1995 at a cost of up to $3
million. The DTSC must approve the groundwater remedial action design plan
proposed for this site before it is implemented. The Company has accrued a $7.3
million liability at December 31, 1994 for the Sacramento gas plant site.
In addition to the manufactured gas plant sites, the Company may be
required to take remedial action at certain other disposal sites if they are
determined to present a significant threat to human health and the
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environment because of an actual or potential release of hazardous substances.
The Company has been designated as a PRP under CERCLA (the federal Superfund
law) with respect to the Purity Oil Sales site in Malaga, California, the
Jibboom Junkyard site in Sacramento, California, the Industrial Waste Processing
site near Fresno, California, and the Lorentz Barrel and Drum site in San Jose,
California. The Purity Oil Sales site is a former used oil recycling facility at
which the Company is one of nine PRPs named in an EPA order requiring
groundwater remediation at the site. The Company has also entered into an
Administrative Order with the EPA to address soil contamination at the site. The
Company has accrued a $6.4 million liability at December 31, 1994 for the Purity
Oil Sales site. Although the Company has not been named as a PRP with respect to
the Casmalia site near Santa Maria, California, the EPA has notified the Company
and approximately 65 other generators who allegedly sent the largest volumes of
waste to the site that action is needed to clean up and close the site. The
Company is working with other alleged generators to evaluate measures which may
need to be taken at the site. The Company has accrued a $1.9 million liability
for the Casmalia site. Although the Company has not been formally designated a
PRP with respect to the Geothermal Industries, Incorporated site in Lake County,
California, the Central Valley Regional Water Quality Control Board and the
California Attorney General's office have directed the Company and other parties
to initiate measures with respect to the study and remediation of that site. The
Company has accrued a liability of $9.8 million for the Geothermal Industries,
Incorporated site.
In addition to the sites discussed above, the Company has also been
identified as a PRP at certain disposal sites under the California Superfund.
These sites include the Emeryville Service Center site in Emeryville, California
and the GBF Landfill at Pittsburg, California. The Company has also received a
demand from the California Attorney General seeking reimbursement of cleanup
costs incurred by the State of California at the Company's former Jibboom Street
power plant in Sacramento, California. In addition, the Company has been named
as a defendant in several civil lawsuits in which plaintiffs allege that the
Company is responsible for performing or paying for remedial action at sites the
Company no longer owns or never owned.
The overall costs of the hazardous materials and hazardous waste compliance
and remediation activities described above are difficult to estimate due to
uncertainty concerning the extent of environmental risks and the Company's
responsibility, the complexity of environmental laws and regulations and the
selection of compliance alternatives. However, based on the information
currently available, the Company has an accrued liability as of December 31,
1994 of $95 million for hazardous waste remediation costs. The ultimate amount
of such costs may be as much as $235 million if, among other things, the Company
is held responsible for cleanup at additional sites, other PRPs are not
financially able to contribute to these costs, or further investigation
indicates that the extent of contamination and affected natural resources is
greater than anticipated at sites for which the Company is responsible.
Potential Recovery of Hazardous Waste Compliance and Remediation Costs
In May 1994, the CPUC issued a decision in the Southern California Gas
Company's (SoCal Gas) environmental reasonableness proceeding. The final
decision adopts the settlement and proposed ratemaking mechanism for hazardous
waste remediation costs which was previously submitted by the Company and other
interested parties. That mechanism assigns 90% of the includable hazardous
substance cleanup costs to utility ratepayers and 10% to utility shareholders,
without a reasonableness review of such costs or of underlying activities.
However, under the proposed mechanism, utilities will have the opportunity to
recover the shareholder portion of the cleanup costs from insurance carriers.
The mechanism provides that 70% of the ratepayer portion of the Company's
cleanup costs is attributed to its gas department and 30% is attributed to its
electric department. The Company can seek to recover hazardous substance cleanup
costs under the new mechanism in any rate proceeding it deems most appropriate.
The final decision in the SoCal Gas proceeding permits the Company to seek
recovery under the new mechanism of environmental cleanup costs previously
recorded in balancing accounts under the old recovery mechanism. Accordingly, in
its 1995 BCAP, the Company is seeking recovery of $10.5 million in environmental
cleanup costs under the new mechanism, which amount represents the gas
department's allocation of such previously recorded cleanup costs.
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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. As of
December 31, 1994, the Company has a deferred charge of $83 million for
hazardous waste remediation costs, which represents the minimum amount of such
costs expected to be recovered under the current ratemaking mechanisms. The
Company believes that the ultimate outcome of these matters will not have a
significant adverse impact on its financial position or results of operations.
In December 1992, the Company filed a complaint in San Francisco County
Superior Court against more than 100 of its domestic and foreign insurers,
seeking damages and declaratory relief for remediation and other costs
associated with hazardous waste mitigation. The Company had previously notified
its insurance carriers that it seeks coverage under its Comprehensive General
Liability Policies to recover costs incurred at certain specified sites. In the
main, the Company's carriers neither admitted nor denied coverage, but requested
additional information from the Company. The amount of recovery from insurance
coverage, if any, cannot be quantified at this time.
ELECTRIC AND MAGNETIC FIELDS
In January 1991, the CPUC opened an investigation into potential interim
policy actions to address increasing public concern, especially with respect to
schools, regarding potential health risks which may be associated with electric
and magnetic fields (EMF) from utility facilities. In its order instituting the
investigation, the Commission acknowledged that the scientific community has not
reached consensus on the nature of any health impacts from contact with EMF, but
went on to state that a body of evidence has been compiled which raises the
question of whether adverse health impacts might exist.
The CPUC proceeding was subsequently bifurcated into two phases -- one
focusing on EMF related to electric power and the other on EMF generated by
cellular telephone transmitters. In the electric power phase, in November 1993,
the CPUC adopted an interim EMF policy for California energy utilities which,
among other things, requires California energy utilities to take no-cost and
low-cost steps to reduce EMF from new and upgraded utility facilities.
California energy utilities will be required to fund a $1.5 million EMF
education program and a $5.6 million EMF research program managed by the
California Department of Health Services over the next four years.
As part of its effort to educate the public about EMF, the Company provides
interested customers with information regarding the EMF exposure issue. The
Company also provides a free field measurement service to its customers which
informs customers about EMF levels at different locations in and around their
residences or commercial buildings.
The Company and other utilities are involved in litigation concerning EMFs.
The Company is named as a defendant in three pending civil lawsuits. Plaintiffs
allege personal injury resulting from exposure to EMFs and diminution in
property value due to the presence of EMFs from nearby high voltage lines.
In the event that the scientific community reaches a consensus that EMF
presents a health hazard and further determines that the impact of
utility-related EMF exposures can be isolated from other exposures, the Company
may be required to take mitigation measures at its facilities. The costs of such
mitigation measures cannot be estimated with any certainty at this time.
However, such costs could be significant depending on the particular mitigation
measures undertaken, especially if relocation of existing power lines is
ultimately required.
LOW EMISSION VEHICLE PROGRAMS
In October 1991, the CPUC issued an Order Instituting Investigation/Order
Instituting Rulemaking on Low Emission Vehicles (LEVs) to investigate policy
issues surrounding electric and natural gas utility involvement in the market
associated with LEVs, specifically natural gas vehicles (NGVs) and electric
vehicles (EVs). Hearings in Phase I of the LEV proceeding were conducted in
August 1992, and examined long-term utility involvement in LEV programs in
relation to California's environmental, energy and
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transportation goals. The Company generally proposed that its long-term role in
the LEV market be that of a fuel supplier, transporter and distributor.
In July 1993, the CPUC issued a decision in Phase I of the LEV proceeding.
The decision recognized a significant role for the Company in the LEV market and
directed the Company to file a request for funding for a six-year program
(1995-2000). In August 1994, the Company requested approximately $41 million in
funding for the Company's fleet and market development activities for NGVs and
EVs over the six-year period. Joint hearings on all utilities' LEV funding
requests were held in the fall of 1994, with a Phase II decision expected by
mid-1995.
As noted above (see "Proposed Regulatory Reforms -- Company's
Proposals -- PBR"), the Company proposes to revise its RRI filing to reflect the
CPUC's electric industry restructuring plan once the details of the CPUC's plan
are sufficiently definitive. The Company anticipates that in its revised filing
it will recommend that LEV program costs be funded as part of environmental and
social benefit programs generally, with LEV funding included in the rate
component related to such programs.
The decision in the Company's 1993 GRC extended NGV funding of $8.5 million
per year pending a final decision in the LEV proceeding described above, and
authorized $1.8 million for EV programs. The Company is using the NGV funds to
install additional natural gas refueling facilities, to purchase or convert
additional NGVs for the Company's fleet, and to provide incentives and
assistance in converting additional customer vehicles to NGVs. The Company and
its customers currently operate nearly 2,700 NGVs.
OTHER REGULATION
CALIFORNIA PUBLIC UTILITIES COMMISSION
In addition to its jurisdiction over rate matters, the CPUC has the
authority, among other things, to establish rules and conditions of service, to
authorize disposition of utility property, to establish rules and policies
governing utility facilities, to regulate securities issues, to prescribe rates
of depreciation and uniform systems of accounts and to regulate transactions
between the Company and its subsidiaries and affiliates.
CALIFORNIA ENERGY COMMISSION
The Company also is subject to the jurisdiction of the CEC. The CEC has
developed programs for forecasting peak demands and energy requirements, is
encouraging and requiring certain types of energy conservation, has developed
energy shortage and contingency plans, and is developing and coordinating a
program of energy research and development. In addition, the CEC has statutory
authority to certify future thermal-electric power plant sites and related
facilities 50 MW and above within California. The Governor of California is
currently in the process of submitting to the California State Legislature a
plan to reorganize the CEC. Under that plan, the CEC would be consolidated into
the existing Department of Conservation to create a new Department of Energy and
Conservation, the head of which would be appointed by the Governor.
FEDERAL ENERGY REGULATORY COMMISSION
The Company is subject to regulation by the FERC under the Federal Power
Act as a "public utility" as defined in the Act. The FERC has authority, among
other things, to regulate the Company's rates and terms and conditions for sales
of electricity for resale and transmission of electricity in interstate
commerce, and to prescribe rates of depreciation and uniform systems of
accounts. The FERC also regulates the terms and conditions of interstate
pipeline transportation service utilized by the Company to transport gas it
purchases outside California. In addition, the FERC regulates PGT's rates and
charges for the transportation of natural gas in interstate commerce, the
extension, enlargement or abandonment of PGT's facilities and PGT's accounting,
among other things.
FERC-HYDROELECTRIC LICENSING
Most of the Company's hydroelectric facilities are subject to licenses
issued under Part I of the Federal Power Act, with various expiration dates to
the year 2033 and involving a total normal operating capability of 2,703 MW.
Helms adds an additional capacity of 1,212 MW. As the initial licenses for these
projects expire,
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they become susceptible to competition for a new license. In the years prior to
1986, several governmentally run utilities, claiming a statutory "preference" in
their favor superior to the Company, had filed competing applications for four
of the Company's projects. Federal legislation enacted in 1986 eliminated any
preference for governmentally run utilities in hydroelectric relicensing
proceedings commenced after 1986.
The 1986 law provided options for resolving relicensing competitions. The
Company elected to pay the competing applicants for the four projects a
"reasonable" settlement consisting of their costs incurred to pursue the
licenses and a potential additional amount ranging from 0% to 100% of the
Company's remaining net investment in the relevant project. In return, the
competing applicants are required to withdraw their competing license
applications. The FERC approved the settlement agreement for two projects. In
October 1992, the FERC issued an order requiring the Company to pay compensation
of $1.9 million to the competing applicants for the remaining two projects,
representing the costs incurred preparing their applications. The FERC declined
to award the competing applicants any additional compensation. In December 1993,
the Company paid the amount called for in the FERC order, and in October 1994,
the U.S. Court of Appeals affirmed that order. The Company expects to recover
the costs of all FERC-awarded compensation through rates.
NUCLEAR REGULATORY COMMISSION
The Company also is subject to the jurisdiction of the NRC as to operation
of its nuclear generating plants.
ITEM 2. PROPERTIES.
Information concerning the Company's electric generation units, gas
transmission facilities, and electric and gas distribution facilities is
included in response to Item 1. All real properties and substantially all
personal properties of the Company are subject to the lien of an indenture which
provides security to the holders of the Company's First and Refunding Mortgage
Bonds.
ITEM 3. LEGAL PROCEEDINGS.
See Item 1--Business, for other proceedings pending before governmental and
administrative bodies. In addition to the following legal proceedings, the
Company is subject to routine litigation incidental to its business.
ANTITRUST LITIGATION
On December 3, 1993, the County of Stanislaus and Mary Grogan, a
residential customer of the Company, filed a complaint in the U.S. District
Court, Eastern District of California, against the Company and PGT, on behalf of
themselves and purportedly as a class action on behalf of all natural gas
customers of the Company during the period of February 1988 through October
1993. The complaint alleges that the purchase of natural gas in Canada was
accomplished in violation of various antitrust laws which resulted in increased
prices of natural gas for the Company's customers.
The complaint alleges that the Company could have purchased as much as 50%
of the Canadian gas on the spot market instead of relying on long-term contracts
and that the damage to the class members is at least as much as the price
differential multiplied by the replacement volume of gas, an amount estimated in
the complaint as potentially exceeding $800 million. In addition, the complaint
indicates that the damages to the class could include over $150 million paid by
the Company to terminate the contracts with the Canadian gas producers in
November 1993. The complaint seeks recovery of three times the amount of the
actual damages pursuant to the antitrust laws.
In August 1994, the federal district court issued a decision granting the
Company's motion to dismiss the federal and state antitrust claims and the state
unfair practices claims against the Company and PGT. The only remaining claims
did not seek monetary damages. In addition, the Court granted plaintiffs' motion
seeking class certification.
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In dismissing the antitrust claims, the Court determined that the prices
the Company paid for Canadian gas had been filed with, reviewed and approved as
reasonable by various federal and state regulatory authorities, and as a result,
the plaintiffs were barred from claiming that those rates were too high. The
Court also held that the CPUC's oversight of the Company's gas acquisition costs
constitutes state action which immunizes the Company from a private antitrust
lawsuit such as this one.
In September 1994, plaintiffs filed an amended complaint with the Court.
A&S, the Company's wholly owned Canadian gas purchasing subsidiary, is added as
a defendant in the amended complaint. In essence, the amended complaint restates
the claims in the original complaint, and in addition alleges that the
defendants, through anticompetitive practices, foreclosed access over the PGT
pipeline to alternative sources of gas in Canada by certain customers of the
Company. A new motion to dismiss was filed by the Company in November 1994.
The Company believes that the ultimate outcome of the antitrust litigation
will not have a significant adverse impact on its financial position.
HINKLEY COMPRESSOR STATION LITIGATION
In May 1993, a complaint was filed in San Bernardino County Superior Court
on behalf of a number of individuals seeking recovery of an unspecified amount
of damages for personal injuries and property damage allegedly suffered as a
result of exposure to chromium near the Company's Hinkley Compressor Station,
located along the Company's gas transmission system in San Bernardino County, as
well as punitive damages. The original complaint has been amended, and
additional complaints have been filed, to include additional plaintiffs. The
complaints plead several causes of action, including negligence, negligent and
intentional misrepresentation, fraudulent concealment, strict liability and
violation of California's Safe Drinking Water and Toxic Enforcement Act of 1986
(Proposition 65).
The plaintiffs contend that between 1951 and 1966 the Company discharged
Chromium VI-contaminated wastewater into unlined ponds, which led to chromium
percolating into the groundwater of surrounding property. The plaintiffs further
allege that the Company disposed of the chromium in those ponds to avoid costly
alternatives. In 1987, the Company undertook an extensive project to remediate
potential groundwater chromium contamination. The Company has incurred
substantially all of the costs it currently deems necessary to clean up the
affected groundwater contamination. In accordance with the remediation plan
approved by the regional water quality board, the Company will continue to
monitor the affected area and periodically perform environmental assessments.
The Company has reached an agreement with plaintiffs pursuant to which
plaintiffs' actions will be submitted to binding arbitration for resolution of
issues concerning the cause and extent of any damages suffered by plaintiffs.
Under the terms of the agreement, the Company will pay an aggregate amount of no
more than $400 million in settlement of such plaintiffs' claims, including $50
million paid to escrow to date. In turn, those plaintiffs, and their attorneys,
agree to indemnify the Company against any additional losses the Company may
incur with respect to related claims pursued by the identified plaintiffs who do
not agree to this settlement or by other third parties who may be sued by the
identified plaintiffs in connection with the alleged chromium contamination.
In January 1995, ten representative cases began arbitration before two
judges. At the conclusion of the arbitration, the parties began a process of
mediation in an attempt to settle the remaining 625 cases, based on the results
of the arbitration. If the mediation is not successful, the parties will proceed
to arbitrate another 25 to 30 more cases. Following that, the parties will
attempt to mediate the remaining cases. This process will continue until all
cases are arbitrated or settled.
As of December 31, 1994, the Company had a remaining reserve of $50 million
against any future potential liability in this case. The Company believes the
ultimate outcome of this matter will not have a significant adverse impact on
its financial position or results of operations.
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COUNTIES FRANCHISE FEES LITIGATION
On March 31, 1994, the Counties of Alameda and Santa Clara filed a
complaint in Santa Clara County Superior Court against the Company on behalf of
themselves and purportedly as a class action on behalf of 47 counties with which
the Company has gas or electric franchise contracts. Franchise contracts require
the Company to pay fees on an annual basis to cities and counties for the right
to use or occupy public streets and roads. The complaint alleges that, since at
least 1987, the Company has intentionally underpaid its franchise fees to the
counties in an unspecified amount.
The complaint cites two reasons for the alleged underpayment of fees. Based
on their interpretation of certain legislation, the plaintiffs allege that the
Company has been using the wrong methodology to compute the franchise fees
payable to the plaintiff counties. The plaintiffs also allege that fees have
been underpaid due to incorrect calculations under the methodology used by the
Company.
The parties agreed to stipulate to this case proceeding as a class action
lawsuit regarding the issue of the correct payment methodology to be applied in
calculating the franchise fees due to the plaintiffs. On March 14, 1995, the
Superior Court granted the Company's motion for summary judgment in the class
action lawsuit. The plaintiffs may appeal that ruling. Consistent with the
agreement between the parties noted above, the plaintiffs refiled a separate
action covering just the issue of whether the Company properly computed its
franchise payments, assuming that the Company has been using the correct
methodology. Plaintiffs have not indicated damages to be sought in that separate
action, but they are not anticipated to be material.
Should the counties win the issue of franchise fee calculation methodology,
the Company's annual system-wide county franchise fees could increase by
approximately $15 million. Damages for alleged underpayments in prior years
could be as much as $117 million (exclusive of interest, estimated to be $28
million as of December 31, 1994).
The Company believes that the ultimate outcome of this matter will not have
a significant adverse impact on its financial position or results of operations.
CITIES FRANCHISE FEES LITIGATION
On May 13, 1994, the City of Santa Cruz filed a complaint in Santa Cruz
County Superior Court against the Company on behalf of itself and purportedly as
a class action on behalf of 107 cities with which the Company has certain
electric franchise contracts. The complaint alleges that, since at least 1988,
the Company has intentionally underpaid its franchise fees to the cities in an
unspecified amount.
The complaint alleges that the Company has asked for and accepted electric
franchises from the cities included in the purported class, which provide for
lower franchise payments than required by franchises granted by other cities in
the Company's service territory. Plaintiff asserts that this was done in an
unlawfully discriminatory manner based solely on location. The plaintiff also
alleges that the transfer of these franchises to the Company by its predecessor
companies was not approved by the CPUC as required, and, therefore, all such
franchise contracts are void.
The Court has certified the class of 107 cities in this action, and
approved the City of Santa Cruz as the class representative. The case is in
discovery and no trial date has been set.
Should the cities prevail on the issue of franchise fee calculation
methodology, the Company's annual system-wide city electric franchise fees could
increase by approximately $17 million. Damages for alleged underpayments in
prior years could be as much as $114 million (exclusive of interest, estimated
to be $23 million as of December 31, 1994).
The Company believes that the ultimate outcome of this matter will not have
a significant adverse impact on its financial position or results of operations.
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53
TIME-OF-USE METER LITIGATION
On July 21, 1994, Milton L. Grinstead, Michael Davis, Joan A. Williamson,
Frank H. Lacy, and Matthew Doerksen filed a complaint in the Stanislaus County
Superior Court against the Company on behalf of themselves and purportedly as a
class action on behalf of all of the Company's customers, for "refund of
unlawfully charged fees." The complaint has been amended to broaden the alleged
class to include customers of the Turlock Irrigation District (TID), which
purchases power from the Company, on the theory that TID customers' rates have
been affected by the Company's alleged failure to notify its customers of the
best available rate.
The complaint alleges that the Company improperly failed to notify its
customers of the most favorable rates available to each particular customer. The
complaint focuses on the "time-of-use" billing option, which allows customers to
save money by shifting their electricity use to off-peak hours when electricity
is cheaper. Plaintiffs contend that all customers could have saved an average of
$50-$75 per month per customer had they been placed on time-of-use rates. The
complaint seeks damages estimated to be in excess of $16 billion. The amended
complaint also includes a claim for $100 billion in "exemplary" damages,
alleging that the Company's failure to properly advise customers of the
"time-of-use" billing option and other rates was "wilful."
The Company believes that the ultimate outcome of this matter will not have
a significant adverse impact on its financial position or results of operations.
NORCEN LITIGATION
On March 17, 1994, Norcen Energy Resources Limited (Norcen Energy) and
Norcen Marketing Incorporated (Norcen Marketing) filed a complaint in the U.S.
District Court, Northern District of California, against the Company and PGT.
Norcen Marketing signed a 30-year Firm Service Agreement with PGT for
transportation of 47,022 million Btus per day (MMBtu/d) on the PGT portion of
the Pipeline Expansion. The annual demand charges under the contract currently
are approximately $8.1 million. Norcen Energy is a guarantor of the 30-year
transportation contract between PGT and Norcen Marketing.
The complaint alleges that PGT and the Company wrongfully induced Norcen
Energy and Norcen Marketing to enter into the 30-year contract by concealing
legal action taken by the Company before the CPUC (requesting clarification that
gas shipped on the PGT portion of the Pipeline Expansion should pay PG&E's
incremental Expansion rates for in-state service) two days before Norcen
Marketing's contract became binding. The complaint further alleges breach of
representations to plaintiffs that the Company would not "unreasonably" build
its Pipeline Expansion with less than "sufficient" firm subscription. The
complaint also alleges breach of an agreement between PGT and a Norcen
predecessor named Bonus Gas Processors Corp. (Bonus) relating to the
installation of additional capacity. The complaint generally charges the Company
with monopolizing the capacity on the original PGT facilities from Kingsgate to
Malin and wrongfully preventing Norcen Energy and Norcen Marketing (apparently
based on rights allegedly acquired from Bonus) from utilizing the existing PG&E
transmission system to provide gas to customers in Northern California.
The complaint alleges various antitrust, contractual, and other claims
against the defendants and seeks rescission, restitution and recovery of
unspecified damages. In a pleading filed in June 1994, the plaintiffs indicate a
claim for $140 million (before trebling) based on defendants' allegedly
exclusionary business behavior, as well as an unspecified amount of contract
damages. Based on available information, plaintiffs' out-of-pocket contract
damages appear to be less than $10 million.
On September 19, 1994, the U.S. District Court, Northern District of
California, granted PGT's and the Company's motion to dismiss all federal
antitrust claims in the complaint in this case, and dismissed the remaining
state antitrust and contract claims for lack of jurisdiction. On October 18,
1994, Norcen filed an amended complaint. The amended complaint reasserted part
of the original complaint's antitrust claims, asserted new antitrust claims
based on the same facts and specifically alleged diversity jurisdiction for the
state
47
54
law contract claims. On November 18, 1994, PGT and the Company filed motions to
dismiss the amended complaint.
The Company believes that the ultimate outcome of this matter will not have
a significant adverse impact on its financial position or results of operations.
POTTER VALLEY HYDROELECTRIC PROJECT
On January 19, 1995, the FERC issued a decision finding that the Company
had not violated the FERC's April 1994 order relating to a fish screen and
bypass facility for the Company's Potter Valley Hydroelectric Project, reversing
the compliance order issued by the FERC in September 1994 indicating such a
violation had occurred. Accordingly, no fines will be imposed in connection with
the matters cited in the September compliance order.
PGT UNIT 4C COMPRESSOR UNIT PERMIT
PGT owns and operates the 4C Solar Mars compressor unit near Sandpoint,
Idaho (Unit 4C). In connection with an upgrade of Unit 4C in 1986, PGT applied
for and received a construction permit from the State of Idaho Department of
Environmental Quality. At the time PGT received the construction permit, it was
determined that no permit for the modification was needed under the federal
Prevention of Significant Deterioration (PSD) program, then being administered
in Idaho by the State.
In the process of applying for a permit under the 1990 Clean Air Act, PGT
conducted a review of its environmental permits and discovered information which
now causes it to question whether a construction permit incorporating PSD
requirements may have been required prior to the 1986 upgrade. PGT is in the
process of discussing this information with the State of Idaho. If it is finally
determined that such a permit was required, PGT may be required to apply for and
obtain a PSD permit for Unit 4C and/or to retrofit Unit 4C. PGT may also be
subject to fines and penalties which could exceed $100,000, but it cannot be
determined with any certainty at present whether a fine will ultimately be
imposed or what the amount of any such fine would be.
The Company believes that the ultimate outcome of this matter will not have
a significant adverse impact on its financial position or results of operations.
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55
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
Not applicable.
EXECUTIVE OFFICERS OF THE REGISTRANT
"Executive officers," as defined by Rule 3b-7 of the General Rules and
Regulations under the Securities and Exchange Act of 1934, of the Company are as
follows:
AGE AT
DECEMBER 31,
NAME 1994 POSITION EFFECTIVE DATE
-------------------- -------------- ---------------------- ------------------
R. A. Clarke................. 64 Chairman of the Board July 1, 1994
S. T. Skinner................ 57 President and Chief Executive Officer July 1, 1994
R. D. Glynn, Jr.............. 52 Executive Vice President July 1, 1994
J. D. Shiffer................ 56 Executive Vice President November 1, 1991
R. J. Haywood................ 50 Senior Vice President and General Manager, December 21, 1994
Customer Energy Services
J. F. Jenkins-Stark.......... 43 Senior Vice President and General Manager, Gas August 1, 1993
Supply Business Unit
V. G. Rose................... 48 Senior Vice President and General Manager, January 1, 1994
Electric Supply Business Unit
G. M. Rueger................. 44 Senior Vice President and General Manager, November 1, 1991
Nuclear Power Generation Business Unit
T. W. High................... 47 Vice President and Assistant to the Chief July 1, 1994
Executive Officer
G. N. Horne.................. 63 Vice President--Corporate Communications July 1, 1983
J. Pfannenstiel.............. 47 Vice President--Corporate Planning February 1, 1987
G. R. Smith.................. 46 Vice President and Chief Financial Officer November 1, 1991
B. Coull Williams............ 42 Vice President--Human Resources February 1, 1993
B. R. Worthington............ 45 Vice President and General Counsel December 21, 1994
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
----------------------- -------------------------------------------- ----------------------------------
R. A. Clarke........... Chairman of the Board and Chief Executive May 1, 1986 to June 30, 1994
Officer
S. T. Skinner.......... President and Chief Operating Officer November 1, 1991 to June 30, 1994
Vice Chairman of the Board May 1, 1986 to October 31, 1991
J. D. Shiffer.......... Senior Vice President and General Manager, February 1, 1990 to October 31, 1991
Nuclear Power Generation Business Unit
Vice President--Nuclear Power Generation October 1, 1984 to January 31, 1990
R. D. Glynn, Jr........ Senior Vice President and General Manager, January 1, 1994 to June 30, 1994
Customer Energy Services Business Unit
Senior Vice President and General Manager, November 1, 1991 to December 31, 1993
Electric Supply Business Unit
Vice President--Power Generation January 1, 1988 to October 31, 1991
R. J. Haywood.......... Vice President of Power System February 22, 1993 to December 20, 1994
Vice President--Power Planning and Contracts April 20, 1988 to February 21, 1993
J. F. Jenkins-Stark.... Vice President and Treasurer January 15, 1992 to July 31, 1993
Treasurer November 1, 1987 to January 14, 1992
V. G. Rose............. Senior Vice President and General Manager, February 22, 1993 to December 31, 1993
Customer Energy Services Business Unit
Senior Vice President and General Manager, September 1, 1988 to February 21, 1993
Distribution Business Unit
G. M. Rueger........... Senior Vice President and General Manager January 1, 1988 to October 31, 1991
Electric Supply Business Unit
T. W. High............. Vice President and Assistant to November 1, 1991-June 30, 1994
the Chairman of the Board
Vice President and Corporate Secretary May 1, 1986 to October 31, 1991
G. R. Smith............ Vice President--Finance and Rates November 1, 1987 to October 31, 1991
B. Coull Williams...... Division Manager, San Francisco Division April 13, 1992 to January 31, 1993
Division Manager, North Bay Division July 1, 1989 to April 12, 1992
B. R. Worthington...... Chief Counsel--Corporate January 10, 1991-December 20, 1994
Attorney June 10, 1974-January 9, 1991
49
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PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS.
Information responding to Item 5 is set forth on page 43 under the heading
"Quarterly Consolidated Financial Data" in the Company's 1994 Annual Report to
Shareholders, which information is hereby incorporated by reference and filed as
part of Exhibit 13 to this report.
ITEM 6. SELECTED FINANCIAL DATA.
A summary of selected financial information for the Company for each of the
last five fiscal years is set forth on page 12 under the heading "Selected
Financial Data" in the Company's 1994 Annual Report to Shareholders, which
information is hereby incorporated by reference and filed as part of Exhibit 13
to this report.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS.
A discussion of the Company's results of operations and liquidity and
capital resources is set forth on pages 13 through 20 under the heading
"Management's Discussion and Analysis of Consolidated Results of Operations and
Financial Condition" in the Company's 1994 Annual Report to Shareholders, which
discussion is hereby incorporated by reference and filed as part of Exhibit 13
to this report.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
Information responding to Item 8 is contained in the Company's 1994 Annual
Report to Shareholders on page 44 and pages 21 through 43 under the headings
"Report of Independent Public Accountants," "Statement of Consolidated Income,"
"Consolidated Balance Sheet," "Statement of Consolidated Cash Flows," "Statement
of Consolidated Common Stock Equity and Preferred Stock," "Statement of
Consolidated Capitalization," "Schedule of Consolidated Segment Information,"
"Notes to Consolidated Financial Statements," and "Quarterly Consolidated
Financial Data," which information is hereby incorporated by reference and filed
as part of Exhibit 13 to this report.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE.
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
Information regarding executive officers of the Company is included in a
separate item captioned "Executive Officers of the Registrant" contained on page
47 in Part I of this report. Other information responding to Item 10 is included
on pages 3 through 5 under the heading "Nominees for Director" in the 1995 Proxy
Statement relating to the 1995 Annual Meeting of Shareholders, which information
is hereby incorporated by reference.
ITEM 11. EXECUTIVE COMPENSATION.
Information responding to Item 11 is included on page 7 under the heading
"Compensation of Directors" and on pages 11 through 18 under the heading
"Executive Compensation" in the 1995 Proxy Statement relating to the 1995 Annual
Meeting of Shareholders, which information is hereby incorporated by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
Information responding to Item 12 is included on pages 8 and 19 under the
headings "Security Ownership of Management" and "Principal Shareholders" in the
1995 Proxy Statement relating to the 1995 Annual Meeting of Shareholders, which
information is hereby incorporated by reference.
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57
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
Information responding to Item 13 is included on page 7 under the heading
"Certain Relationships and Related Transactions" in the 1995 Proxy Statement
relating to the 1995 Annual Meeting of Shareholders, which information is hereby
incorporated by reference.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K.
(A) THE FOLLOWING DOCUMENTS ARE FILED AS A PART OF THIS REPORT:
1. The following consolidated financial statements, schedules of
consolidated segment information, supplemental information and report
of independent public accountants contained in the 1994 Annual Report
to Shareholders, are incorporated by reference in this report:
Statement of Consolidated Income for the Years Ended December 31,
1994, 1993 and 1992.
Consolidated Balance Sheet at December 31, 1994 and 1993.
Statement of Consolidated Cash Flows for the Years Ended December 31,
1994, 1993 and 1992.
Statement of Consolidated Common Stock Equity and Preferred Stock for
the Years Ended December 31, 1994, 1993 and 1992.
Statement of Consolidated Capitalization at December 31, 1994 and
1993.
Schedule of Consolidated Segment Information for the Years Ended
December 31, 1994, 1993 and 1992.
Notes to Consolidated Financial Statements.
Quarterly Consolidated Financial Data.
Report of Independent Public Accountants.
2. Report of Independent Public Accountants.
3. Consolidated financial statement schedules:
II -- Consolidated Valuation and Qualifying Accounts for the Years
Ended December 31, 1994, 1993 and 1992.
Schedules not included are omitted because of the absence of conditions
under which they are required or because the required information is provided in
the consolidated financial statements including the notes thereto.
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58
4. Exhibits required to be filed by Item 601 of Regulation S-K:
3.1 Restated Articles of Incorporation effective as of July 26,
1994 (Form 10-Q for quarter ended June 30, 1994 (File No.
1-2348), Exhibit 3.1).
3.2 By-Laws dated January 1, 1995.
4. First and Refunding Mortgage dated December 1, 1920, and
supplements thereto dated April 23, 1925, October 1, 1931,
March 1, 1941, September 1, 1947, May 15, 1950, May 1, 1954,
May 21, 1958, November 1, 1964, July 1, 1965, July 1, 1969,
January 1, 1975, June 1, 1979, August 1, 1983, and December 1,
1988 (Registration No. 2-1324, Exhibits B-1, B-2, B-3;
Registration No. 2-4676, Exhibit B-22; Registration No. 2-7203,
Exhibit B-23; Registration No. 2-8475, Exhibit B-24;
Registration No. 2-10874, Exhibit 4B; Registration No. 2-14144,
Exhibit 4B; Registration No. 2-22910, Exhibit 2B; Registration
No. 2-23759, Exhibit 2B; Registration No. 2-35106, Exhibit 2B;
Registration No. 2-54302, Exhibit 2C; Registration No. 2-64313,
Exhibit 2C; Registration No. 2-86849, Exhibit 4.3; Form 8-K
dated January 18, 1989 (File No. 1-2348), Exhibit 4.2).
10.1 Firm Transportation Service Agreement between the Company and
Pacific Gas Transmission Company dated October 26, 1993 (Form
10-K for fiscal year 1993 (File No. 1-2348), Exhibit 10.4),
rate schedule FTS-1, and general terms and conditions.
10.2 Transportation Service Agreement as Amended and Restated
Between the Company and El Paso Natural Gas Company dated
November 1, 1993 (Form 10-K for fiscal year 1993 (File No.
1-2348), Exhibit 10.5), rate schedule T-3, and general terms
and conditions.
10.3 Diablo Canyon Settlement Agreement dated June 24, 1988 (Form
8-K dated June 27, 1988) (File No. 1-2348), Exhibit 10.1),
Implementing Agreement dated July 15, 1988 (Form 10-Q for the
quarter ended June 30, 1988 (File No. 1-2348), Exhibit 10.1)
and portions of the California Public Utilities Commission
Decision No. 88-12-083, dated December 19, 1988, interpreting
the Settlement Agreement (Form 10-K for fiscal year 1988 (File
No. 1-2348), Exhibit 10.4).
*10.4 Pacific Gas and Electric Company Deferred Compensation Plan for
Directors (Form 10-K for fiscal year 1992 (File No. 1-2348),
Exhibit 10.5).
*10.5 Pacific Gas and Electric Company Deferred Compensation Plan for
Officers (Form 10-K for fiscal year 1991 (File No. 1-2348),
Exhibit 10.6).
*10.6 Savings Fund Plan for Employees of Pacific Gas and Electric
Company applicable to non-union employees, as amended September
21, 1994, effective April 1, 1995.
*10.7 Performance Incentive Plan of Pacific Gas and Electric Company
(Form 10-K for fiscal year 1993 (File No. 1-2348), Exhibit
10.10).
*10.8 The Pacific Gas and Electric Company Retirement Plan applicable
to non-union employees, as amended September 21, 1994, effective
January 1, 1995.
*10.9 Pacific Gas and Electric Company Supplemental Executive
Retirement Plan, as amended through October 16, 1991 (Form 10-K
for fiscal year 1991 (File No. 1-2348), Exhibit 10.11).
*10.10 Pacific Gas and Electric Company Stock Option Plan, as amended
effective as of September 16, 1992 (Form 10-K for fiscal year
1993 (File No. 1-2348), Exhibit 10.13).
*10.11 Pacific Gas and Electric Company Performance Unit Plan (Form
10-K for fiscal year 1991 (File No. 1-2348), Exhibit 10.13).
*10.12 Pacific Gas and Electric Company Relocation Assistance Program
for Officers (Form 10-K for fiscal year 1989 (File No. 1-2348),
Exhibit 10.16).
*10.13 Pacific Gas and Electric Company Executive Flexible Perquisites
Program (Form 10-K for fiscal year 1993 (File No. 1-2348),
Exhibit 10.16).
*10.14 PG&E Postretirement Life Insurance Plan (Form 10-K for fiscal
year 1991 (File No. 1-2348), Exhibit 10.16).
- ---------------
* Management contract or compensatory plan or arrangement required to be filed
as an exhibit to this report pursuant to Item 14(c) of Form 10-K.
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59
*10.15 Pacific Gas and Electric Company Retirement Plan for
Non-Employee Directors (Form 10-K for fiscal year 1991 (File
No. 1-2348), Exhibit 10.18).
*10.16 Executive Compensation Insurance Indemnity in respect of
Deferred Compensation Plan for Directors, Deferred Compensation
Plan for Officers, Supplemental Executive Retirement Plan and
Retirement Plan for Non-Employee Directors (Form 10-K for
fiscal year 1991 (File No. 1-2348), Exhibit 10.19).
*10.17 Pacific Gas and Electric Company Long-Term Incentive Program
(Form 10-K for fiscal year 1991 (File No. 1-2348), Exhibit
10.21).
11. Computation of Earnings Per Common Share (Form 8-K dated March
2, 1995 (File No. 1-2348), Exhibit 11).
12.1 Restated Computation of Ratios of Earnings to Fixed Charges.
12.2 Restated Computation of Ratios of Earnings to Combined Fixed
Charges and Preferred Stock Dividends.
13. 1994 Annual Report to Shareholders (portions of the 1994 Annual
Report to Shareholders under the headings "Selected Financial
Data," "Management's Discussion and Analysis of Consolidated
Results of Operations and Financial Condition," "Report of
Independent Public Accountants," "Statement of Consolidated
Income," "Consolidated Balance Sheet," "Statement of
Consolidated Cash Flows," "Statement of Consolidated Common
Stock Equity and Preferred Stock," "Statement of Consolidated
Capitalization," "Schedule of Consolidated Segment
Information," "Notes to Consolidated Financial Statements," and
"Quarterly Consolidated Financial Data," included only) (except
for those portions which are expressly incorporated herein by
reference, such 1994 Annual Report to Shareholders is furnished
for the information of the Commission and is not deemed to be
"filed" herein).
21. Subsidiaries of the Company (not included because the Company's
subsidiaries, considered in the aggregate as a single
subsidiary, would not constitute a "significant subsidiary"
under Rule 1-02(v) of Regulation S-X as of the end of the year
covered by this report).
23. Consent of Arthur Andersen LLP.
24.1 Resolution of the Board of Directors authorizing the execution
of the Form 10-K.
24.2 Powers of Attorney.
27. Financial Data Schedule (Form 8-K dated March 2, 1995 (File No.
102348), Exhibit 27).
99. Information required by Form 11-K with respect to the Savings
Fund Plan for Employees of Pacific Gas and Electric Company, as
permitted by Rule 15d-21.
- ---------------
* Management contract or compensatory plan or arrangement required to be filed
as an exhibit to this report pursuant to Item 14(c) of Form 10-K.
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60
The exhibits filed herewith are attached hereto (except as noted) and those
indicated above which are not filed herewith were previously filed with the
Commission as indicated and are hereby incorporated by reference. Exhibits will
be furnished to security holders of the Company upon written request and payment
of a fee of $.30 per page, which fee covers only the Company's reasonable
expenses in furnishing such exhibits.
(B) REPORTS ON FORM 8-K
Reports on Form 8-K during the quarter ended December 31, 1994 and through
the date hereof:
1. October 13, 1994
Item 5. Other Events
-- Helms Pumped Storage Plant -- Proposed Settlement
2. October 21, 1994
Item 5. Other Events
-- Diablo Canyon Nuclear Power Plant -- Diablo Canyon Rate Case
Settlement
-- Performance Incentive Plan -- Year-to-Date Financial Results
3. October 28, 1994
Item 5. Other Events
-- California Public Utilities Commission Proceedings
-- 1995 Cost of Capital Proceeding
-- Long-Term Noncore Gas Transportation Tariff/Gas Transmission
Jurisdiction
4. November 17, 1994
Item 5. Other Events
-- Diablo Canyon Nuclear Power Plant -- Diablo Canyon Rate Case
Settlement
5. November 23, 1994
Item 5. Other Events
-- California Public Utilities Commission Proceedings
-- Electric Industry Restructuring
-- Restructuring of Gas Supply Arrangements -- Recovery of
Interstate Transportation Demand Charges
-- Energy Cost Adjustment Clause
-- 1995 Cost of Capital Proceeding
-- PGT/PG&E Pipeline Expansion Project -- Other Competitive
Interstate Pipeline Projects
-- Diablo Canyon Nuclear Power Plant
-- Diablo Canyon Rate Case Settlement
-- Diablo Canyon License Amendment
6. December 5, 1994
Item 5. Other Events
-- Proposed Modification of Diablo Canyon Pricing Mechanism
7. December 19, 1994
-- California Public Utilities Proceedings
-- Electric Industry Restructuring
-- 1996 General Rate Case
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61
8. January 4, 1995
Item 5. Other Events
-- Performance Incentive Plan -- 1995 Target
-- California Public Utilities Commission Proceedings
-- 1995 Electric Rate Stabilization/Attrition Rate Adjustment
-- ECAC
-- 1988 - 1990 Gas Reasonableness Proceedings
9. January 19, 1995
Item 5. Other Events
-- Performance Incentive Plan -- 1994 Financial Results
-- 1994 Consolidated Earnings (unaudited)
-- Common Stock Dividend
-- California Public Utilities Commission Proceedings -- Core
Procurement Incentive Mechanism
10. February 21, 1995
Item 5. Other Events
-- California Public Utilities Commission Proceedings--Experimental
Procurement Service for Customer-Identified Electric Supply
11. March 2, 1995
Item 7. Financial Statements, Pro Forma Information and Exhibits
-- 1994 Financial Statements
-- Ratios of Earnings to Fixed Charges and Ratios of Earnings to
Combined Fixed Charges and Preferred Dividends
-- Exhibits
INDEMNIFICATION UNDERTAKING
For purposes of complying with the amendments to the rules governing Form
S-8 (effective July 13, 1990) under the Securities Act of 1933, the undersigned
registrant hereby undertakes as follows, which undertaking shall be incorporated
by reference into the registrant's Registration Statement on Form S-8 No.
33-23692 (filed August 12, 1988):
Insofar as indemnification for liabilities arising under the
Securities Act of 1933 may be permitted to directors, officers and
controlling persons of the registrant pursuant to the foregoing provisions,
or otherwise, the registrant has been advised that in the opinion of the
Securities and Exchange Commission such indemnification is against public
policy as expressed in the Securities Act of 1933 and is, therefore,
unenforceable. In the event that a claim for indemnification against such
liabilities (other than the payment by the registrant of expenses incurred
or paid by a director, officer or controlling person of the registrant in a
successful defense of any action, suit or proceeding) is asserted by such
director, officer or controlling person in connection with the securities
being registered, the registrant will, unless in the opinion of its counsel
the matter has been settled by controlling precedent, submit to a court of
appropriate jurisdiction the question whether such indemnification by it is
against public policy as expressed in the Act and will be governed by the
final adjudication of such issue.
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SIGNATURES
PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(D) OF THE SECURITIES
EXCHANGE ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED ON
ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED, IN THE CITY AND COUNTY
OF SAN FRANCISCO, ON THE 27TH DAY OF MARCH, 1995.
PACIFIC GAS AND ELECTRIC COMPANY
(Registrant)
By GARY P. ENCINAS
-----------------------------------
(Gary P. Encinas, Attorney-in-Fact)
PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS
REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE
REGISTRANT AND IN THE CAPACITIES AND ON THE DATES INDICATED.
SIGNATURE TITLE DATE
- ------------------------------------------- --------------------------- ---------------
A. PRINCIPAL EXECUTIVE OFFICER OR OFFICERS
*STANLEY T. SKINNER President and Chief Executive March 27, 1995
Officer and Director
B. PRINCIPAL FINANCIAL OFFICER
*GORDON R. SMITH Vice President and March 27, 1995
Chief Financial Officer
C. CONTROLLER OR PRINCIPAL ACCOUNTING
OFFICER
*THOMAS C. LONG Controller March 27, 1995
D. DIRECTORS
* RICHARD A. CLARKE
* H. M. CONGER
* WILLIAM S. DAVILA
* MELVIN B. LANE
* DAVID M. LAWRENCE
* LESLIE L. LUTTGENS
* RICHARD B. MADDEN
* GEORGE A. MANEATIS Directors March 27, 1995
* MARY S. METZ
* WILLIAM F. MILLER
* JOHN B. M. PLACE
* SAMUEL T. REEVES
* CARL E. REICHARDT
* JOHN C. SAWHILL
* ALAN SEELENFREUND
* BARRY LAWSON WILLIAMS
* By GARY P. ENCINAS
---------------------------------
(Gary P. Encinas,
Attorney-in-Fact)
56
63
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Shareholders and the Board of Directors
of Pacific Gas and Electric Company:
We have audited in accordance with generally accepted auditing standards,
the consolidated financial statements and the schedule of consolidated segment
information included in the Pacific Gas and Electric Company Annual Report to
Shareholders incorporated by reference in this Annual Report on Form 10-K and
have issued our report thereon dated February 6, 1995. Our report on the 1994
consolidated financial statements includes an explanatory paragraph that
describes the uncertainties regarding the ultimate outcome of the electric
industry restructuring, as discussed in note 2 to the consolidated financial
statements. In addition, our report includes an explanatory paragraph indicating
that, effective January 1, 1993, the Company changed its method of accounting
for postretirement benefits other than pensions and for income taxes as
discussed in notes 1 and 9 to the consolidated financial statements.
Our audits of the consolidated financial statements and the schedule of
consolidated segment information were made for the purpose of forming an opinion
on those statements taken as a whole. The supplemental schedule listed in Part
IV, Item 14. (a)(3) of this Annual Report on Form 10-K is the responsibility of
the Company's management and is presented for the purpose of complying with the
Securities and Exchange Commission's rules and is not part of the consolidated
financial statements. The supplemental schedule has been subjected to the
auditing procedures applied in the audits of the basic consolidated financial
statements and the schedule of consolidated segment information and, in our
opinion, fairly states in all material respects the financial data required to
be set forth therein in relation to the basic consolidated financial statements
and schedule of consolidated segment information taken as a whole.
ARTHUR ANDERSEN LLP
ARTHUR ANDERSEN LLP
San Francisco, California
February 6, 1995
57
64
SCHEDULE II
PACIFIC GAS AND ELECTRIC COMPANY
SCHEDULE II -- CONSOLIDATED VALUATION AND
QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 1994, 1993 AND 1992
COLUMN C
COLUMN B ADDITIONS
BALANCE ------------------- COLUMN E
AT CHARGED BALANCE
BEGINNING TO COSTS CHARGED COLUMN D AT
COLUMN A OF AND TO OTHER DEDUC- END OF
DESCRIPTION PERIOD EXPENSES ACCOUNTS TIONS PERIOD
------------------ (IN THOUSANDS)-------------------
VALUATION AND QUALIFYING ACCOUNTS
DEDUCTED FROM ASSETS:
1994:
Reserve for impairment of oil and gas
properties........................... $ 7,924 $ 4,565 $ -- $ 8,148 (3) $ 4,341
========= ======== ======== ========= =========
Reserve for deferred project costs...... $18,689 $ 7,111 $ -- $ -- $25,800
========= ======== ======== ========= =========
Allowance for uncollectible accounts.... $23,647 $14,010 $ -- $ 7,888 (5) $29,769
========= ======== ======== ========= =========
Reserve for land costs.................. $ 6,154 $ -- $ -- $ 194 $ 5,960
========= ======== ======== ========= =========
1993:
Reserve for investment in Alaska Natural
Gas Transportation System............ $152,517 $ -- $ -- $152,517(1) $ 0
========= ======== ======== ========= =========
Reserve for impairment of oil and gas
properties........................... $10,417 $ 7,165 $ -- $ 9,658 (3) $ 7,924
========= ======== ======== ========= =========
Reserve for deferred project costs...... $ 9,207 $11,086 $ -- $ 1,604 (4) $18,689
========= ======== ======== ========= =========
Allowance for uncollectible accounts.... $23,806 $ 1,907 $ -- $ 2,066 (5) $23,647
========= ======== ======== ========= =========
Reserve for land costs.................. $ 1,724 $ 4,749 $ -- $ 319 $ 6,154
========= ======== ======== ========= =========
1992:
Reserve for investment in Alaska Natural
Gas Transportation System............ $132,893 $19,624 $ -- $ -- $152,517(2)
========= ======== ======== ========= =========
Reserve for impairment of oil and gas
properties........................... $10,835 $ 4,857 $ -- $ 5,275 (3) $10,417
========= ======== ======== ========= =========
Reserve for deferred project costs...... $ 4,627 $ 4,580 $ -- $ -- $ 9,207
========= ======== ======== ========= =========
Allowance for uncollectible accounts.... $16,677 $13,664 $ -- $ 6,535 (5) $23,806
========= ======== ======== ========= =========
Reserve for land costs.................. $ 1,724 $ -- $ -- $ -- $ 1,724
========= ======== ======== ========= =========
- ---------------
(1) Company disposed of its investment in Alaska Natural Gas Transportation
System in January 1993.
(2) Construction on the gas transportation system was discontinued in 1983. The
Company accrued and reserved AFUDC through January 1993, at which time the
Company's subsidiary that was a partner in the partnership organized to
build and operate the gas transportation system withdrew from that
partnership.
(3) Deductions consist principally of write-offs of expired leaseholds on
reserved property.
(4) Primarily due to development cost for power projects.
(5) Deductions consist principally of write-offs, net of collections of
receivables considered uncollectible.
58
65
================================================================================
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
EXHIBITS
TO
FORM 10-K
FOR THE YEAR ENDED DECEMBER 31, 1994
------------------
PACIFIC GAS AND ELECTRIC COMPANY
------------------
================================================================================
66
INDEX TO EXHIBITS
EXHIBIT
NUMBER DESCRIPTION OF EXHIBITS
- ------- ------------------------------------------------------------------------------------
3.1 Restated Articles of Incorporation effective as of July 26, 1994 (Form 10-Q for
quarter ended June 30, 1994 (File No. 1-2348), Exhibit 3.1).
3.2 By-Laws dated January 1, 1995.
4. First and Refunding Mortgage dated December 1, 1920, and supplements thereto dated
April 23, 1925, October 1, 1931, March 1, 1941, September 1, 1947, May 15, 1950, May
1, 1954, May 21, 1958, November 1, 1964, July 1, 1965, July 1, 1969, January 1,
1975, June 1, 1979, August 1, 1983, and December 1, 1988 (Registration No. 2-1324,
Exhibits B-1, B-2, B-3; Registration No. 2-4676, Exhibit B-22; Registration No.
2-7203, Exhibit B-23; Registration No. 2-8475, Exhibit B-24; Registration No.
2-10874, Exhibit 4B; Registration No. 2-14144, Exhibit 4B; Registration No. 2-22910,
Exhibit 2B; Registration No. 2-23759, Exhibit 2B; Registration No. 2-35106, Exhibit
2B; Registration No. 2-54302, Exhibit 2C; Registration No. 2-64313, Exhibit 2C;
Registration No. 2-86849, Exhibit 4.3; Form 8-K dated January 18, 1989 (File No.
1-2348), Exhibit 4.2).
10.1 Firm Transportation Service Agreement between the Company and Pacific Gas
Transmission Company dated October 26, 1993 (Form 10-K for fiscal year 1993 (File
No. 1-2348), Exhibit 10.4), rate schedule FTS-1, and general terms and conditions.
10.2 Transportation Service Agreement as Amended and Restated Between the Company and El
Paso Natural Gas Company dated November 1, 1993 (Form 10-K for fiscal year 1993
(File No. 1-2348), Exhibit 10.5), rate schedule T-3, and general terms and
conditions.
10.3 Diablo Canyon Settlement Agreement dated June 24, 1988 (Form 8-K dated June 27,
1988) (File No. 1-2348), Exhibit 10.1), Implementing Agreement dated July 15, 1988
(Form 10-Q for the quarter ended June 30, 1988 (File No. 1-2348), Exhibit 10.1) and
portions of the California Public Utilities Commission Decision No. 88-12-083, dated
December 19, 1988, interpreting the Settlement Agreement (Form 10-K for fiscal year
1988 (File No. 1-2348), Exhibit 10.4).
*10.4 Pacific Gas and Electric Company Deferred Compensation Plan for Directors (Form 10-K
for fiscal year 1992 (File No. 1-2348), Exhibit 10.5).
*10.5 Pacific Gas and Electric Company Deferred Compensation Plan for Officers (Form 10-K
for fiscal year 1991 (File No. 1-2348), Exhibit 10.6).
*10.6 Savings Fund Plan for Employees of Pacific Gas and Electric Company applicable to
non-union employees, as amended September 21, 1994, effective April 1, 1995.
*10.7 Performance Incentive Plan of Pacific Gas and Electric Company (Form 10-K for fiscal
year 1993 (File No. 1-2348), Exhibit 10.10).
*10.8 The Pacific Gas and Electric Company Retirement Plan applicable to non-union
employees, as amended September 21, 1994, effective January 1, 1995.
*10.9 Pacific Gas and Electric Company Supplemental Executive Retirement Plan, as amended
through October 16, 1991 (Form 10-K for fiscal year 1991 (File No. 1-2348), Exhibit
10.11).
*10.10 Pacific Gas and Electric Company Stock Option Plan, as amended effective as of
September 16, 1992 (Form 10-K for fiscal year 1993 (File No. 1-2348), Exhibit
10.13).
*10.11 Pacific Gas and Electric Company Performance Unit Plan (Form 10-K for fiscal year
1991 (File No. 1-2348), Exhibit 10.13).
*10.12 Pacific Gas and Electric Company Relocation Assistance Program for Officers (Form
10-K for fiscal year 1989 (File No. 1-2348), Exhibit 10.16).
*10.13 Pacific Gas and Electric Company Executive Flexible Perquisites Program (Form 10-K
for fiscal year 1993 (File No. 1-2348), Exhibit 10.16).
*10.14 PG&E Postretirement Life Insurance Plan (Form 10-K for fiscal year 1991 (File No.
1-2348), Exhibit 10.16).
*10.15 Pacific Gas and Electric Company Retirement Plan for Non-Employee Directors (Form
10-K for fiscal year 1991 (File No. 1-2348), Exhibit 10.18).
*10.16 Executive Compensation Insurance Indemnity in respect of Deferred Compensation Plan
for Directors, Deferred Compensation Plan for Officers, Supplemental Executive
Retirement Plan and Retirement Plan for Non-Employee Directors (Form 10-K for fiscal
year 1991 (File No. 1-2348), Exhibit 10.19).
*10.17 Pacific Gas and Electric Company Long-Term Incentive Program (Form 10-K for fiscal
year 1991 (File No. 1-2348), Exhibit 10.21).
67
INDEX TO EXHIBITS--(CONTINUED)
EXHIBIT
NUMBER DESCRIPTION OF EXHIBITS
- ------- ------------------------------------------------------------------------------------
11. Computation of Earnings Per Common Share (Form 8-K dated March 2, 1995 (File No.
1-2348), Exhibit 11).
12.1 Restated Computation of Ratios of Earnings to Fixed Charges.
12.2 Restated Computation of Ratios of Earnings to Combined Fixed Charges and Preferred
Stock Dividends.
13. 1994 Annual Report to Shareholders (portions of the 1994 Annual Report to
Shareholders under the headings "Selected Financial Data," "Management's Discussion
and Analysis of Consolidated Results of Operations and Financial Condition," "Report
of Independent Public Accountants," "Statement of Consolidated Income,"
"Consolidated Balance Sheet," "Statement of Consolidated Cash Flows," "Statement of
Consolidated Common Stock Equity and Preferred Stock," "Statement of Consolidated
Capitalization," "Schedule of Consolidated Segment Information," "Notes to
Consolidated Financial Statements," and "Quarterly Consolidated Financial Data,"
included only) (except for those portions which are expressly incorporated herein by
reference, such 1994 Annual Report to Shareholders is furnished for the information
of the Commission and is not deemed to be "filed" herein).
21. Subsidiaries of the Company (not included because the Company's subsidiaries,
considered in the aggregate as a single subsidiary, would not constitute a
"significant subsidiary" under Rule 1-02(v) of Regulation S-X as of the end of the
year covered by this report).
23. Consent of Arthur Andersen LLP.
24.1 Resolution of the Board of Directors authorizing the execution of the Form 10-K.
24.2 Powers of Attorney.
27. Financial Data Schedule (Form 8-K dated March 2, 1995 (File No. 102348), Exhibit
27).
99. Information required by Form 11-K with respect to the Savings Fund Plan for
Employees of Pacific Gas and Electric Company, as permitted by Rule 15d-21.
- ---------------
* Management contract or compensatory plan or arrangement required to be filed
as an exhibit to this report pursuant to Item 14(c) of Form 10-K.