<PAGE>
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 8-K
CURRENT REPORT
Pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934
Date of Report: March 2, 1994
PACIFIC GAS AND ELECTRIC COMPANY
(Exact name of registrant as specified in its charter)
California 1-2348 94-0742640
(State or other juris- (Commission (IRS Employer
diction of incorporation) File Number) Identification Number)
77 Beale Street, P.O.Box 770000, San Francisco, California 94177
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code:(415) 973-7000
<PAGE>
Item 5. Other Events
California Public Utilities Commission (CPUC) Proceedings
1. PGT/PG&E Pipeline Expansion Project
On February 16, 1994, the CPUC announced a decision on the
Company's request for an increase in the California portion of
the expansion project's cost cap and its interim rate filing.
The CPUC granted the Company's request to increase the cost cap
to $849 million, but set interim rates based on the original cost
cap of $736 million, subject to an adjustment to the newly
approved cost cap after the outcome of a reasonableness review of
capital costs. The CPUC's decision finds that given market
conditions at the time, the Company was reasonable in
constructing the expansion project. In its decision, the CPUC
also approved a 1% increase in the return on equity over the
authorized return on utility operations in order to reflect the
risk associated with the additional leverage of a capital
structure of 70% debt and 30% equity for the California portion
of the expansion project. The decision rejects assignment of
unused capacity costs on other pipelines (or the Company's
intrastate facilities) to the expansion project as previously
proposed by an Administrative Law Judge's proposed decision.
2. 1992 Reasonableness Proceeding - Division of Ratepayer
Advocates Recommendation
On January 28, 1994, the CPUC's Division of Ratepayer
Advocates (DRA) issued its report on the reasonableness of the
Company's gas procurement and operating activities for 1992 and
recommended a disallowance of approximately $92 million in costs
for that period.
The major recommended disallowance relates to the DRA's
contention that the Company failed to pursue least-cost
purchasing alternatives in acquiring Canadian gas supplies during
the 1992 record period. The DRA calculated that the Company
would have saved $60.5 million in gas costs if it had purchased
50% of its Canadian gas supply at spot market prices, and
accordingly recommended that amount be disallowed.
In addition, the DRA recommended a disallowance of approximately
$5.1 million in connection with the Company's Southwest gas
procurement activities during a three-month period in 1992 and a
disallowance of $8.2 million related to the Company's gas
inventory operations.
In its report, the DRA also argued that the Company imprudently
entered into firm transportation agreements with Transwestern
Pipeline Company in 1992 and recommended a disallowance of the
associated demand charges of approximately $18 million paid by
the Company during the record period of which $4.5 million
related to capacity for the electric department. The DRA
asserted that the incremental interstate capacity was unnecessary
to meet the expected needs of the Company's core customers and
2
<PAGE>
that the Company should not have contracted for such capacity on
account of noncore customers.
The DRA is a consumer advocacy branch of the CPUC staff and its
recommendations do not constitute a CPUC decision. The CPUC can
accept all, part or none of the DRA's recommendations.
3. 1988-1990 Reasonableness Proceeding - Non-Canadian Gas
Phase
On January 26, 1994, the assigned Administrative Law Judge issued a
proposed decision on the Company's non-Canadian gas operations
activities during 1988 through 1990. The proposed decision
generally finds the Company's gas operations reasonable during
the record periods, but indicates that the evidence is
inconclusive on whether the Company should have withdrawn more
gas from storage during December 1990 for the electric
department's generation. On that basis, the proposed decision
recommends a disallowance of $7.5 million plus accrued interest.
4. Canadian Affiliates Audit
On January 28, 1994, the DRA filed with the CPUC a report on
alleged conflicts of interest which discusses the stock holdings
of certain officers and directors of Alberta and Southern Gas
Co. Ltd. (A&S), the Company's wholly owned subsidiary, in
companies from which A&S contracted for gas supplies that
eventually flowed to California. The report was filed in the
phase of the pending gas reasonableness proceeding in which the
Company's Canadian non-gas costs for the 1988-1991 period are
being evaluated.
In its report, the DRA indicates that it did not discover
specific transactions resulting from the stock ownership which
caused identifiable harm to California ratepayers. However, the
DRA concluded that the stock ownership created the appearance of
impropriety and that the interests may have created a
disincentive for those officers to aggressively seek
opportunities to drive down the price for gas paid to producers.
The DRA's report also criticizes the Company for not taking
sufficient action to ensure that A&S's conflicts threshold was as
stringent as that which the Company employed in evaluating
possible conflicts of interest of its employees.
However, the DRA's report does not request any specific
disallowance associated with the conflicts of interest discussed
in the report. Rather, the DRA argues that the Company's lack of
oversight in this respect provides further evidence to support
the $50 million penalty recommended in its September 1993 report
on Canadian non-gas costs.
3
<PAGE>
Item 7. Financial Statements, Pro Forma Financial Information
And Exhibits
A. 1993 Financial Statements
Copies of the following documents are attached hereto as Appendix
I and incorporated herein: (i) the selected financial data; (ii)
management's discussion and analysis of consolidated results of
operations and financial condition; (iii) audited consolidated
balance sheet and statement of consolidated capitalization of
Pacific Gas and Electric Company and its subsidiaries as of
December 31, 1993 and 1992, and the related statements of
consolidated income, cash flows, common stock equity and
preferred stock, and the schedule of consolidated segment
information for each of the three years in the period ended
December 31, 1993, and related footnotes, and supplementary
financial information, and (iv) the report dated February 16,
1994, of Arthur Andersen & Co., independent public accountants,
with respect to the consolidated financial statements and
schedule of consolidated segment information.
B. Ratios of Earnings to Fixed Charges and Ratios of Earnings
to Combined Fixed Charges and Preferred Stock Dividends
The Company's earnings to fixed charges ratio for the year ended
December 31, 1993 was 3.69. The Company's earnings to combined
fixed charges and preferred stock dividends ratio for the year
ended December 31, 1993 was 3.19.
Exhibits:
11 Computation of Earnings per Common Share
12.1 Computation of Ratios of Earnings to Fixed Charges
12.2 Computation of Ratios of Earnings to Combined Fixed
Charges and Preferred Stock Dividends
23 Consent of Arthur Andersen & Co.
4
<PAGE>
SIGNATURE
Pursuant to the requirements 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.
PACIFIC GAS AND ELECTRIC COMPANY
GORDON R. SMITH
By ______________________________
GORDON R. SMITH
Vice President and Chief
Financial Officer
Dated: March 2, 1994
5
<PAGE>
APPENDIX I
SELECTED FINANCIAL DATA
PACIFIC GAS AND ELECTRIC COMPANY
<TABLE>
<CAPTION>
1993 1992 1991 1990 1989
- --------------------------------------------------------------------------------------------------------
(in thousands, except per share amounts)
<S> <C> <C> <C> <C> <C>
For the Year
Operating revenues $10,582,408 $10,296,088 $ 9,778,119 $ 9,470,092 $ 8,588,264
Operating income 1,762,930 1,833,441 1,713,079 1,706,136 1,622,558
Net income 1,065,495 1,170,581 1,026,392 987,170 900,628
Earnings per common share 2.33 2.58 2.24 2.10 1.90
Dividends declared per common
share 1.88 1.76 1.64 1.52 1.40
At Year End
Book value per common share $ 19.77 $ 19.41 $ 18.40 $ 17.86 $ 17.38
Common stock price per share 35.13 33.13 32.63 25.00 22.00
Total assets 27,162,526 24,188,159 22,900,670 21,958,397 21,351,970
Long-term debt and preferred stock
with mandatory redemption
provision (excluding current
portions) 9,367,100 8,525,948 8,341,310 7,902,409 7,951,320
</TABLE>
Matters relating to certain data above are discussed in Management's Discussion
and Analysis of Consolidated Results of Operations and Financial Condition and
in Notes to Consolidated Financial Statements.
12
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF CONSOLIDATED RESULTS OF OPERATIONS AND
FINANCIAL CONDITION
PACIFIC GAS AND ELECTRIC COMPANY
Results of Operations
- ---------------------
Pacific Gas and Electric Company (PG&E) and its wholly owned and majority-owned
subsidiaries (the Company) have three types of operations: utility, Diablo
Canyon Nuclear Power Plant (Diablo Canyon) and nonregulated through PG&E
Enterprises (Enterprises). For 1993, 1992 and 1991, selected financial
information for the three types of operations is shown below:
<TABLE>
<CAPTION>
Diablo
Utility Canyon(1) Enterprises Total
- ------------------------------------------------------------------------------
(in millions, except per share amounts)
<S> <C> <C> <C> <C>
1993
Operating revenues
Electric $ 5,933 $1,933 $ - $ 7,866
Gas 2,465 - 251 2,716
- ------------------------------------------------------------------------------
Total operating revenues 8,398 1,933 251 10,582
Operating expenses 7,335 1,225 259 8,819
- ------------------------------------------------------------------------------
Operating income (loss) $ 1,063 $ 708 $ (8) $ 1,763
==============================================================================
Net income $ 552 $ 496 $ 17 $ 1,065
==============================================================================
Earnings per common share $ 1.18 $ 1.11 $ .04 $ 2.33
Total assets at year end $19,870 $6,250 $1,043 $27,163
1992
Operating revenues
Electric $ 5,966 $1,781 $ - $ 7,747
Gas 2,340 - 209 2,549
- ------------------------------------------------------------------------------
Total operating revenues 8,306 1,781 209 10,296
Operating expenses 7,125 1,118 220 8,463
- ------------------------------------------------------------------------------
Operating income (loss) $ 1,181 $ 663 $ (11) $ 1,833
==============================================================================
Net income (loss) $ 738 $ 443 $ (10) $ 1,171
==============================================================================
Earnings (loss) per
common share $ 1.61 $ .99 $ (.02) $ 2.58
Total assets at year end $17,759 $5,494 $ 935 $24,188
1991
Operating revenues
Electric $ 5,868 $1,501 $ - $ 7,369
Gas 2,336 - 73 2,409
- ------------------------------------------------------------------------------
Total operating revenues 8,204 1,501 73 9,778
Operating expenses 6,953 1,004 108 8,065
- ------------------------------------------------------------------------------
Operating income (loss) $ 1,251 $ 497 $ (35) $ 1,713
==============================================================================
Net income (loss) $ 777 $ 274 $ (25) $ 1,026
==============================================================================
Earnings (loss) per
common share $ 1.71 $ .59 $ (.06) $ 2.24
Total assets at year end $16,440 $5,543 $ 918 $22,901
</TABLE>
(1) See Note 3 of Notes to Consolidated Financial Statements for discussion of
allocations.
EARNINGS PER COMMON SHARE: Earnings per common share were $2.33, $2.58 and $2.24
for 1993, 1992 and 1991, respectively. Earnings per common share for 1993 were
lower than for 1992 due to charges against earnings of $410 million which were
partially offset by Diablo Canyon's performance as discussed in the Operating
Revenues section. The above charges are detailed as follows:
<TABLE>
<CAPTION>
Year ended December 31, 1993
- ------------------------------------------------------
(in millions)
<S> <C>
Workforce reduction program costs $190
Gas decontracting costs and reserves for
gas transportation commitments 127
Reserve for gas reasonableness proceedings 61
Diablo Canyon deferred tax liability adjustment 32
- ------------------------------------------------------
Total $410
======================================================
</TABLE>
Earnings per common share for 1992 were higher than for 1991 primarily due to
one scheduled refueling outage at Diablo Canyon in 1992, compared to two
scheduled refueling outages in 1991, and the annual increase in the price per
kilowatthour (kWh) as provided in the Diablo Canyon rate case settlement.
In 1993 and 1992, the Company earned an 11.9% and a 13.7% return on average
common stock equity, respectively.
COMMON STOCK DIVIDEND: In January 1994, the Company raised the quarterly common
stock dividend 4.3%, from an annualized rate of $1.88 per share to $1.96 per
share.
The amount of the Company's common stock dividend is based on a number of
financial considerations, including sustainability, financial flexibility and
competitiveness with investment opportunities of similar risk. Over time, the
Company plans to reduce its dividend payout ratio (dividends declared divided by
earnings available for common stock) to reflect the increased business risk in
the utility industry and the earnings volatility associated with the Diablo
Canyon rate case settlement.
OPERATING REVENUES: Electric revenues increased $119 million and $378 million in
1993 and 1992, respectively, compared to the preceding year. The increase in
1993 electric revenues was due to rate increases associated with general
increases in operating expenses and a higher electric
13
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF CONSOLIDATED RESULTS OF OPERATIONS AND
FINANCIAL CONDITION (continued)
PACIFIC GAS AND ELECTRIC COMPANY
rate base on which PG&E is allowed to earn a return, as provided in the 1993
General Rate Case (GRC). This increase was offset by a decrease in revenues
resulting from a decrease in the cost of electric energy. In addition, Diablo
Canyon revenues, which are included in the electric revenues discussed above,
increased due to the annual increase in the price per kWh as provided in the
Diablo Canyon rate case settlement.
The increase in 1992 electric revenues was primarily due to one scheduled
refueling outage at Diablo Canyon in 1992, compared to two scheduled refueling
outages in 1991, and the annual increase in the price per kWh as provided in the
Diablo Canyon rate case settlement.
Gas revenues increased $167 million and $140 million in 1993 and 1992,
respectively, compared to the preceding year. The 1993 increase was primarily
due to rate increases associated with general increases in operating expenses
and a higher gas rate base on which PG&E is allowed to earn a return, as
provided in the 1993 GRC, as well as increased revenues from Enterprises
reflecting increases in the price and production of gas.
The 1992 increase was primarily due to revenues resulting from the December
1991 acquisition of Tex/Con Oil & Gas Company (Tex/Con) by PG&E Resources
Company (Resources), a wholly owned subsidiary of Enterprises.
OPERATING EXPENSES: In 1993 and 1992, the Company's operating expenses increased
$356 million and $398 million, respectively, over the preceding year. The 1993
increase was due to a charge against earnings of $190 million related to the
Company's workforce reduction program and increases in administrative and
general expense, income tax expense, and depreciation and decommissioning
expense of $114 million, $100 million and $94 million, respectively, offset by a
decrease of $166 million in the cost of electric energy. Most of the increase in
administrative and general expense was due to an increase in litigation costs
and an increase in employee costs upon adoption of Statement of Financial
Accounting Standards (SFAS) No. 106, "Employers' Accounting for Postretirement
Benefits Other Than Pensions." The increase in income tax expense was primarily
due to the increase in the federal income tax rate to 35% from 34%, and a
related adjustment to Diablo Canyon deferred income tax liability, as required
under SFAS No. 109, "Accounting for Income Taxes." The increase in depreciation
and decommissioning expense was a result of an increase in depreciation expense
related to the increase in plant in service. The decrease in the cost of
electric energy was a result of improved hydroelectric conditions and reflects a
decline in the cost per kWh for purchased power and a reduction in the volume of
gas used to provide electric energy.
The 1992 increase in operating expenses was primarily due to increases in the
cost of gas, the cost of electric energy, and depreciation and decommissioning
expense. The cost of gas increased in 1992 by $103 million over the preceding
year, primarily due to an increase in the cost of gas purchased on behalf of,
and transported for, noncore customers. The cost of electric energy increased
$98 million in 1992 compared to 1991, primarily due to increases in the cost of
purchased power and natural gas. The $81 million increase in depreciation and
decommissioning expense reflects an increase in depreciation expense related to
the increase in plant in service.
OTHER INCOME AND (INCOME DEDUCTIONS): Total other income was $74 million, $124
million and $95 million for 1993, 1992 and 1991, respectively.
Allowance for equity funds used during construction was $42 million, $39
million and $25 million for 1993, 1992 and 1991, respectively. The increases in
1993 and 1992 compared to the preceding year were primarily due to the PGT-PG&E
Pipeline Expansion Project which was put in service in November 1993.
Other -- net for 1993 includes amounts recorded for the gas decontracting
costs, losses on long-term commitments for gas transportation capacity and a
possible disallowance in connection with gas reasonableness proceedings as
discussed in the Natural Gas Matters section.
14
<PAGE>
Other -- net for 1992 included a $19 million after-tax gain from the sale by
Pacific Gas Transmission Company (PGT), a wholly owned gas pipeline subsidiary
of the Company, of its 49.98% interest in Alberta Natural Gas Company Ltd (ANG).
Other -- net for 1992 also reflects the establishment of new accounting
guidelines for the recognition of revenues related to customer energy efficiency
programs, which resulted in a $25 million decrease in the amount of income
recognized in 1992 compared to 1991.
Included in 1991 other -- net is the write-off by ANG of its investment in a
magnesium metal production facility project in Alberta, Canada. This write-off
resulted in a $26 million after-tax charge.
DIABLO CANYON: The Diablo Canyon rate case settlement, which became effective
July 1988, bases revenues for the plant primarily on the amount of electricity
generated, rather than on traditional cost-based ratemaking. Under this
"performance-based" approach, the Company assumes a significant portion of the
operating risk of the plant because the extent and timing of the recovery of
actual operating costs, depreciation and a return on the investment in the plant
primarily depend on the amount of power produced and the level of costs
incurred. The Company's earnings are affected directly by plant performance and
costs incurred.
Diablo Canyon revenues are based primarily on a pre-established price per kWh
consisting of a fixed component and an escalating component of electricity
generated by the plant. (Pricing for Diablo Canyon is discussed in Note 3 of
Notes to Consolidated Financial Statements.) From the revenues received for
Diablo Canyon, the Company must recover the costs of owning and operating the
plant, including all future capital additions. If power generation drops below
specified capacity levels, the Company may request floor payments which ensure
that the Company will receive some revenue, even if the plant stops producing
power. However, payments received must be refunded to customers under specified
conditions. Decommissioning and certain specific costs will continue to be
recovered through base rates and are not subject to plant performance.
The plant capacity factors for 1993 and 1992 were 89% and 88%, respectively,
reflecting the scheduled refueling outage for Unit 2 in 1993 and Unit 1 in 1992.
There were no extended unscheduled outages in 1993 and 1992. Through December
31, 1993, the lifetime capacity factor for the plant was 79%. The Company will
report significantly lower revenues for the plant during any extended outages,
including refueling outages. Refueling outages, the lengths of which depend on
the scope of the work, typically occur for each unit every eighteen months.
Refueling outages for Unit 1 and Unit 2 are scheduled to begin in March 1994 and
September 1994, respectively, and each is planned to last about nine weeks.
Each Diablo Canyon unit will contribute approximately $3.1 million in revenues
per day at full operating power in 1994. Beginning in 1995 and thereafter, the
escalating component in the price of Diablo Canyon power provided by the
settlement agreement will be based on a formula that will be adjusted by the
change in the consumer price index plus 2.5%, divided by two. This could slow
the rate of future earnings growth from the plant.
WORKFORCE REDUCTION PROGRAM: In the first quarter of 1993, the Company announced
a corporate reorganization and workforce reduction program. As of December 31,
1993, the Company has recorded workforce reduction program costs of $264
million, net of a curtailment gain relating to pension benefits. In April 1993,
the Company announced a freeze on electric rates through 1994. As a result, the
Company has expensed $190 million of such costs relating to electric operations.
The remaining $74 million of such costs relating to gas operations has been
deferred for future rate recovery. The amount deferred is currently being
amortized as savings are realized. The Company is seeking rate recovery of all
costs incurred in connection with the workforce reduction program relating to
electric and gas operations.
15
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF CONSOLIDATED RESULTS OF OPERATIONS AND
FINANCIAL CONDITION (continued)
PACIFIC GAS AND ELECTRIC COMPANY
During 1994 and 1995, the Company expects to benefit from the expense
reduction attributable to the electric operations' workforce reduction. The
Company currently estimates that the workforce reduction program will result in
a net revenue requirement savings of approximately $170 million during the
three-year 1993 GRC cycle, which ends December 31, 1995. Beginning in 1996, the
workforce reduction program is expected to result in annual revenue requirement
savings of at least $200 million. (See Note 8 of Notes to Consolidated Financial
Statements for further discussion of the workforce reduction program.)
ELECTRIC RATE INITIATIVE: In April 1993, the Company proposed a comprehensive
electric rate initiative to freeze current retail electric rates through the end
of 1994 and to reduce electric rates by $100 million for major businesses as an
economic stimulus for those customers. In June 1993, the California Public
Utilities Commission (CPUC) approved the economic stimulus rate, effective for
the period July 1993 through December 1994.
In December 1993, the CPUC approved the electric rate freeze and issued its
decision in the Company's Attrition Rate Adjustment (ARA) and the Energy Cost
Adjustment Clause (ECAC) proceedings. As part of the ECAC decision, the CPUC
approved the Company's request to defer beyond 1994 recovery of a portion of the
undercollections in the ECAC balancing account. The total undercollection at
December 31, 1993, was $427 million.
Pursuant to the electric rate initiative, the effects of the CPUC decisions on
the Company's various electric rate proceedings (including the cost of capital
proceeding discussed in the Liquidity and Capital Resources section) were
consolidated resulting in a net change in electric rates of zero, effective
January 1994.
The Company intends to achieve cost reductions to offset revenue reductions
due to the economic stimulus rate. To the extent that these cost reductions
are not achieved, there would be a negative impact on the Company's 1994
results of operations.
COMPETITION: The Company is currently experiencing increasing competition in
both the gas and electric energy markets. In recent years, changes in
governmental regulations, new technology, interest in self-generation and
cogeneration, and competition from nonutility and nonregulated energy suppliers
have provided many major utility customers with alternative sources to satisfy
their gas and electric requirements.
The recent restructuring of the natural gas industry has increased
competition. As a result of regulatory changes, the Company no longer provides
combined purchase and transportation services to many of its industrial and
large commercial customers (noncore customers). Instead, many noncore customers
now purchase gas supplies directly from gas shippers or producers, reserve
interstate transportation capacity directly from interstate pipelines, and then
purchase intrastate transportation service from the Company once their gas
arrives at the California border. Furthermore, an interstate pipeline has
proposed expanding its facilities into the Company's service territory which, if
approved, would allow it to compete directly for intrastate transportation
service to the Company's noncore customers. To the extent that regulators
approve this pipeline, the Company could lose customers and volume on its gas
transportation system.
The restructuring of the natural gas industry has had a significant impact on
the Company's gas operations. In 1993, the Company terminated its long-term
Canadian gas purchase contracts and has entered into new, more flexible
arrangements for the purchase of the Company's current lower gas supply
requirements. In addition, the Company is continuing its efforts to permanently
assign or broker its commitments for firm gas transportation capacity which it
once held for its noncore customers. As a result of these changes, the Company
has recorded reserves in 1993 for its transportation commitments. (See Natural
Gas Matters section and Note 2 of Notes to Consolidated Financial Statements for
further discussion of regulatory restructuring and the impact on the Company's
gas purchase and transportation commitments.)
16
<PAGE>
While the restructuring of the electric industry is still evolving, proposals
being considered at state and federal levels and the recently enacted National
Energy Policy Act of 1992 (Act) are expected to bring more competition into the
electric generation business. The Company currently purchases approximately one-
third of the electrical power supplied to its customers from generation sources
outside the Company's service territory and from qualifying facilities owned and
operated by independent power producers. (Qualifying facilities are small power
producers or cogenerators that meet certain federal guidelines and thereby
qualify to supply generating capacity and electric energy to electric utilities,
which must purchase this power at prices approved by state regulatory bodies.)
Future additions to satisfy electric supply needs in the Company's service
territory will be determined largely through a competitive resource procurement
process, a feature of the new competitive market for electric generation. The
Company has indicated a willingness to forgo building new generation capacity in
its service territory if appropriate regulatory reforms are instituted in the
energy procurement process to provide increased procurement flexibility.
With its enactment, the Act reduces various restrictions on the operation and
ownership of independent power producers and provides them and other wholesale
suppliers and purchasers with increased access to electric transmission lines
throughout the United States. The Federal Energy Regulatory Commission (FERC)
now has increased authority to order a utility to transport and deliver, or
"wheel," energy for wholesale purchasers or sellers of power. While the Act
prohibits FERC-ordered retail wheeling, it does not address the states' ability
to order retail wheeling. If future restructuring were to include retail
wheeling whereby customers purchase energy directly from an independent power
producer and separately pay the Company to wheel the purchased power, the
Company's power generation plants and resources would be subject to competition
from other available supply options.
Under current regulation, customer prices are based on an allocation among
customer classes of the Company's approved cost of service revenue requirements.
Currently, large industrial and commercial customers are the most likely to have
lower cost competitive alternatives. If a substantial number of these customers
were to leave the system, the Company's recovery of its investment in production
sources and distribution facilities would be dependent on prices charged to
remaining customers and the Company's ability to reduce costs. This could lead
to lower shareholder returns.
To succeed in this more competitive environment, the Company has taken steps
in 1993 to improve service to customers, reduce costs and lower the price of gas
and electric service. The Company has:
1) Reduced its workforce by approximately 3,000 positions which will result in
net revenue requirement savings of approximately $170 million during the three-
year 1993 GRC cycle and annual revenue requirement savings of at least $200
million beginning in 1996. (See the Workforce Reduction Program section and Note
8 of Notes to Consolidated Financial Statements for further discussion of the
workforce reduction program.)
2) Reduced its cost of capital by taking advantage of significantly lower
interest rates to reduce financing costs. (See the Sources of Capital section
for further discussion of debt refinancing.)
3) Obtained CPUC approval to freeze current electric rates through the end of
1994 and to reduce electric rates by $100 million for major businesses over an
18-month period beginning in July 1993. (See the Electric Rate Initiative
section for further discussion of the electric rate initiative.)
4) Begun discussions with the CPUC, customers and other interested parties on
the Company's regulatory reform initiative which, in part, would allow the
Company more flexibility to respond to competitive conditions quickly. (See the
Regulatory Reform Initiative section for further discussion of the regulatory
reform initiative.)
17
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF CONSOLIDATED RESULTS OF OPERATIONS AND
FINANCIAL CONDITION (continued)
PACIFIC GAS AND ELECTRIC COMPANY
5) Given discounts on its gas transportation contracts for certain major
industrial customers to obtain long-term commitments. To date, customers
entering into these contracts represent approximately 12 percent of total
noncore transportation volume.
Further, the Company continues to pursue improvements in the efficiency and
productivity of its operations and is committed to sustaining high levels of
customer service.
REGULATORY REFORM INITIATIVE: In February 1993, the CPUC's Division of Strategic
Planning issued its report on electric industry restructuring, which concluded
that the current regulatory approach is incompatible with the emerging industry
structure resulting from technological change, competitive pressure and new
market forces. The CPUC has several proceedings in progress in which it is
investigating reform proposals. The Company has begun discussions with the CPUC,
customers and other interested parties concerning various reforms to the current
regulatory approach to setting rates. Under the traditional regulatory approach,
rates generally are based on a detailed examination of the utility's costs of
providing service plus a reasonable rate of return. The resulting amount is the
utility's revenue requirement, which the Company is permitted to recover in
rates. Under the approach being explored by the Company, the Company's revenue
requirement would be adjusted annually on the basis of a series of market
indices, such as inflation and customer growth, and a productivity factor
designed to reflect cost savings from increased efficiency. The Company and its
customers would share in savings or excess costs.
This approach would act as a surrogate for detailed cost examinations and
would be used to determine the Company's base revenues, intended to recover the
Company's fixed costs and nonfuel variable costs and to provide a return on
invested capital. Fuel procurement incentives also could be implemented for the
Company's gas purchases for core portfolio customers and power plant fuel. This
approach would use market-based benchmarks to determine the amount of revenues
which the Company could recover to offset these costs, replacing the current
after-the-fact reasonableness reviews of those costs by the CPUC.
As part of the Company's proposal for its largest electric customers, the
Company is seeking to have increased flexibility to provide discounts and tailor
its services to these customers while assuming the risk for decreases in
revenues. This change in the cost of service rate approach could result in a
change in accounting principle for this customer class. If the accounting
criteria applicable to cost of service rate regulation are no longer met, then
the Company would write off the allocable share of regulatory assets, including
regulatory balancing accounts receivable and those regulatory assets included in
deferred charges.
The Company intends to solicit comments from the CPUC, customers and other
interested parties and to file a formal application with the CPUC in the first
quarter of 1994, with implementation proposed for 1995. To the extent that
regulators approve the Company's regulatory reform initiative, changes may occur
to the current regulatory framework as discussed below in the Regulatory Matters
section.
ACCOUNTING FOR THE EFFECTS OF REGULATION: Based on the regulatory framework in
which it operates, the Company currently accounts for the economic effects of
regulation in accordance with the provisions of SFAS No. 71, "Accounting for the
Effects of Certain Types of Regulation." The Company is exploring regulatory
reforms and expects to file a formal application with the CPUC in 1994. (See the
Regulatory Reform Initiative section for further discussion.) If the regulatory
reforms contemplated by the Company are adopted, the mechanics of the rate
setting process would change. The Company anticipates that rates derived from
the regulatory reforms would remain based on cost of service. However, the final
determination will be dependent upon the regulatory reform initiative that is
ultimately adopted.
In the event that recovery of costs through rates becomes unlikely or
uncertain, whether resulting from the expanding effects of competition or
specific regulatory actions which force the Company away from cost of service
ratemaking, SFAS No. 71 would no longer apply. If the Company were to
18
<PAGE>
discontinue application of SFAS No. 71 for some or all of its operations, then
it would write off the applicable portion of regulatory assets, including
regulatory balancing accounts receivable and those regulatory assets included in
deferred charges. The financial effects upon discontinuing application of SFAS
No. 71 could be significant.
REGULATORY MATTERS: The Company's electric and gas energy prices are regulated
primarily by the CPUC. Base rates compensate the Company for operating and
maintenance costs, depreciation and taxes, and provide a return on capital. Base
rates are set every three years in GRC proceedings. The base rates for 1993 were
established in the 1993 GRC. Between rate cases, the ARA mechanism provides for
rate adjustments for inflation, changes in rate base and changes in the
authorized cost of capital.
Balancing accounts help stabilize the Company's earnings. The CPUC sets rates
based on estimates of future revenues and costs; differences between revenues or
energy costs authorized by the CPUC and actual revenues or energy costs are
accumulated in the balancing accounts for subsequent rate adjustment. Energy
cost balancing accounts (which include ECAC) reduce the effect on earnings of
fluctuations in most electric energy and gas costs. Sales balancing accounts
(which include Electric Revenue Adjustment Mechanism) reduce the effect on
earnings of fluctuations in most sales to electric and gas customers.
Both the ARA mechanism and the energy cost balancing accounts limit the effect
of inflation on the Company's earnings from utility operations by closely
matching rates with costs.
The regulatory framework for natural gas service (1) segments the Company's
gas customers into core (residential and small commercial customers) and noncore
classes, (2) provides noncore customers with options in procuring their own gas
supplies, (3) allows noncore customers to negotiate interstate gas
transportation directly with the interstate pipelines and separately negotiate
intrastate gas transportation with their utilities, and (4) places the Company's
noncore transportation revenues at increased risk due to competitive
alternatives.
Gas cost allocation proceedings allocate forecasted costs between core and
noncore customers and set associated rates. This ratemaking mechanism covers a
two-year forecast period and includes a balancing account which allows the
Company to accumulate 75% of the difference between authorized and actual
noncore transportation revenues. Prior to the establishment of the 75% balancing
account in May 1992, a 90% balancing account was in effect. As a result, this
placed the Company's noncore gas transportation revenues at increased risk to
the extent authorized revenues differ from actual.
NATURAL GAS MATTERS: Decontracting Plan: As discussed in Note 2 of Notes to
Consolidated Financial Statements, regulatory changes have restructured the
natural gas industry. Certain Canadian gas producers filed lawsuits against the
Company claiming damages of at least $466 million (Canadian) resulting from the
alleged failure of Alberta and Southern Gas Co. Ltd. (A&S), a wholly owned
subsidiary of the Company, to meet its minimum contractual gas purchase
obligations. A&S, PGT, PG&E and approximately 190 Canadian gas producers
subsequently entered into agreements (collectively, the Decontracting Plan) that
restructured the Company's Canadian gas supply arrangements. The Decontracting
Plan, which became effective November 1, 1993, terminated A&S's contracts with
Canadian gas producers and settled all litigation and claims arising from such
contracts. The total amount of settlement payments paid to Canadian gas
producers pursuant to the Decontracting Plan was approximately $210 million.
In July 1993, FERC approved a transition cost recovery mechanism (TCRM) under
which PGT will absorb 25% of approved transition costs, including settlement
payments incurred in connection with the termination of A&S's contracts, with
the remainder of such costs to be recovered from PGT's shippers.
The Company incurred transition costs of $228 million, consisting of
settlement payments made to producers in connection with the implementation of
the Decontracting Plan and amounts incurred by A&S in reducing certain
administrative and general functions resulting from the restructuring.
19
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF CONSOLIDATED RESULTS OF OPERATIONS AND
FINANCIAL CONDITION (continued)
PACIFIC GAS AND ELECTRIC COMPANY
Of these costs, the Company deferred $143 million (included in deferred
charges -- other) for future rate recovery. In addition, the Company recorded a
reserve of $31 million due to the uncertainty of A&S's ability to assign or
broker its remaining Canadian gas transportation capacity, as costs associated
with this capacity are not recoverable as transition costs under the TCRM.
Accordingly, the Company expensed $93 million in 1993 and a total of $23 million
in prior years.
PGT and PG&E are seeking recovery of all transition costs eligible for
recovery under the TCRM other than the 25% of such costs to be absorbed by PGT.
While such transition costs are still subject to challenges at the FERC level
and the recovery of such costs paid by PG&E as a shipper of gas on PGT's
pipelines will depend on the recovery mechanism adopted by the CPUC, the Company
believes that it will ultimately recover the deferred transition costs.
Transportation Commitments: As discussed in Note 2 of Notes to Consolidated
Financial Statements, PG&E has transportation commitments with several
interstate pipeline companies -- El Paso Natural Gas Company (El Paso), PGT, and
Transwestern Pipeline Company (Transwestern). PG&E's compliance with regulatory
changes has resulted in a decrease in the amount of gas required to be purchased
by PG&E and a related decrease in the need for firm interstate transportation
capacity. Accordingly, PG&E has retained portions of this interstate capacity
for its core customers and core subscription customers (noncore customers
choosing bundled service) and is brokering or assigning the remaining capacity.
The CPUC has established a mechanism that will allow PG&E to recover demand
charges paid to El Paso and PGT in excess of the demand charges for the capacity
held for core and core subscription customers, reduced by any revenues received
from brokering such capacity, subject to a reasonableness review. With respect
to the capacity held by PG&E on Transwestern's pipelines, the CPUC has ordered
PG&E to exclude such demand charges from rates pending a reasonableness review.
Gas Reasonableness Proceedings: The CPUC reviews the reasonableness of the
Company's gas operations on an annual basis. As part of this review, a CPUC
Administrative Law Judge (ALJ) recently issued proposed decisions on the
Company's Canadian gas procurement activities and gas inventory operations for
1988 through 1990, recommending disallowances totaling $53 million in gas costs
plus interest estimated at approximately $15 million. The ALJ's proposed
decisions are not binding and are subject to modification by the CPUC in the
final decisions. A final CPUC decision on the Company's Canadian gas procurement
activities during 1988 through 1990 is expected in the first quarter of 1994. In
reaching this outcome, the ALJ found that the disallowances of up to $670
million which had been recommended by the CPUC's Division of Ratepayer Advocates
(DRA) and certain other parties overstated the magnitude of gas cost savings
which the Company could have achieved during 1988 through 1990.
The DRA has also contended that the Company overpaid for Canadian gas by $105
million and $61 million in 1991 and 1992, respectively. It is possible that
similar issues will be raised regarding the Company's Canadian gas procurement
activities during 1993. In addition, the DRA recommended disallowances of $11
million and $31 million for 1991 and 1992, respectively, relating to gas
inventory operations and Southwest gas issues.
The DRA also issued a report on its investigation of the operations of A&S and
the Company's former affiliate, ANG, recommending a penalty and disallowance of
$50 million and $6 million, respectively, for 1988 through 1991. The
investigation was initiated in connection with the reasonableness proceeding for
1991. The recommended penalty and disallowance are primarily related to the
Company's alleged failure to properly oversee its subsidiaries' activities. In
addition, recommendations related to 1992 activities may be made in a subsequent
report.
The Company believes that its gas procurement activities, transportation
arrangements and operations were prudent and will vigorously contest the
disallowances and penalty proposed by the DRA or other parties. However, based
on its
20
<PAGE>
current assessment of the matter, the Company recorded a reserve of $61
million in 1993 for any disallowance that may be ordered by the CPUC in the gas
reasonableness proceedings. The Company currently is unable to estimate the
ultimate outcome of the gas reasonableness proceedings or predict whether such
outcome will have a significant adverse impact on its financial position or
results of operations. (See Note 2 of Notes to Consolidated Financial Statements
for further discussion of gas reasonableness proceedings.)
PGT-PG&E Pipeline Expansion Project: In November 1993, the Company placed in
service an expansion of its natural gas transmission system from the Canadian
border into California. At December 31, 1993 and 1992, the Company's total
investment in the expansion project was approximately $1,587 million (included
in plant in service) and $979 million (included in construction work in
progress), respectively. The $1,587 million at December 31, 1993, consisted of
$767 million for the facilities within California (i.e., intrastate portion) and
$820 million for the facilities outside California (i.e., interstate portion).
In February 1994, the CPUC announced a decision on the Company's request for
an increase in the California portion of the expansion project's cost cap and
its interim rate filing. The CPUC granted the Company's request to increase the
cost cap to $849 million but set interim rates based on $736 million, subject to
an adjustment based on the outcome of a reasonableness review of capital costs.
The CPUC's decision finds that, given market conditions at the time, the Company
was reasonable in constructing the expansion project. The CPUC rejected the
assignment of costs related to unused capacity on other pipelines (or the
Company's intrastate facilities) to the expansion project as previously
recommended by an ALJ's proposed decision.
Due to the ratemaking treatment adopted by the CPUC for the California portion
of the expansion project, the Company's ability to recover its cost of service
rates is contingent upon demand and competitive market pricing for gas
transportation services. In light of anticipated demand and pricing in the
foreseeable future, the Company has determined that it may not bill its
customers to recover its full cost of service (including a return on
investment). Consequently, application of SFAS No. 71 was discontinued for the
California portion of the expansion project during 1993. This accounting change
did not have a significant impact on the Company's financial position or results
of operations in 1993.
Based upon the current status of the rate case and market demand, the Company
believes it will recover its investment in the expansion project. However, due
to the ratemaking adopted by the CPUC and the discontinued application of SFAS
No. 71, earnings attributable to the California portion of the expansion project
will vary with demand and market pricing. (See the PGT-PG&E Pipeline Expansion
Project section of Note 2 of Notes to Consolidated Financial Statements for
further discussion.)
LEGAL MATTERS: Antitrust Litigation: In December 1993, the County of Stanislaus,
California, and a residential customer of PG&E, filed a complaint against PG&E
and PGT on behalf of themselves and purportedly as a class action on behalf of
all natural gas customers of PG&E, for the period of February 1988 through
October 1993. The complaint alleges that the purchase of natural gas in Canada
by A&S was accomplished in violation of various antitrust laws which resulted in
increased prices of natural gas for PG&E's customers.
The complaint alleges that the Company could have purchased as much as 50% of
its Canadian gas on the spot market instead of relying on long-term contracts
and that the damage to the class members is at least as much as the price
differential multiplied by the replacement volume of gas, an amount estimated in
the complaint as potentially exceeding $800 million. The complaint indicates
that the damages to the class could include over $150 million paid by the
Company to terminate the contracts with the Canadian gas producers in November
1993. The complaint also seeks recovery
21
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF CONSOLIDATED RESULTS OF OPERATIONS
AND FINANCIAL CONDITION (continued)
PACIFIC GAS AND ELECTRIC COMPANY
of three times the amount of the actual damages pursuant to antitrust laws.
The Company believes the case is without merit and has filed a motion to
dismiss the complaint. The Company believes that the ultimate outcome of the
antitrust litigation will not have a significant adverse impact on its
financial position.
Hinkley Litigation: In 1993, a complaint was filed on behalf of a number of
individuals seeking recovery of an unspecified amount of damages for personal
injuries and property damage allegedly suffered as a result of exposure to
chromium near the Company's Hinkley Compressor Station, as well as punitive
damages.
In 1987, the Company undertook an extensive project to remediate potential
groundwater chromium contamination. The Company has incurred substantially all
of the costs it currently deems necessary to clean up the affected groundwater
contamination. In accordance with the remediation plan approved by the regional
water quality control board, the Company will continue to monitor the affected
area and perform environmental assessments.
In November 1993, the parties engaged in private mediation sessions. In
December 1993, the plaintiffs filed an offer to compromise and settle their
claims against the Company for $250 million.
The Company is unable to estimate the ultimate outcome of this matter, but
such outcome could have a significant adverse impact on the Company's results of
operations. The Company believes that the ultimate outcome of this matter will
not have a significant adverse impact on its financial position. (See Note 11 of
Notes to Consolidated Financial Statements for further discussion.)
ACCOUNTING PRINCIPLES: Postretirement Benefits Other Than Pensions: SFAS No. 106
established new financial accounting standards which the Company adopted
effective January 1, 1993. Due to current regulatory treatment, adoption of SFAS
No. 106 did not have a significant impact on the Company's financial position or
results of operations.
In 1993, the Company implemented a plan change that will limit the amount it
will contribute toward postretirement medical benefits. This limitation, which
will take effect for all retirees beginning in 2001, reduces the estimated
future annual SFAS No. 106 medical cost by approximately $70 million and the
accumulated postretirement obligation for these benefits at July 1, 1993, by
approximately $450 million. Due to current regulatory treatment, the limitation
did not have a significant impact on the Company's financial position or results
of operations. (See Note 7 of Notes to Consolidated Financial Statements for
further discussion of postretirement benefits other than pensions.)
Income Taxes: SFAS No. 109 established new financial accounting standards which
the Company adopted January 1, 1993. Due to current regulatory treatment,
adoption of SFAS No. 109 did not have a significant impact on the Company's
results of operations. Adoption of SFAS No. 109 resulted in an increase of $1.8
billion in consolidated liabilities as of January 1, 1993, as a result of
recording additional deferred taxes; consolidated assets also increased $1.8
billion, consisting of a $1.5 billion increase in deferred charges (income tax-
related deferred charges and Diablo Canyon costs) and a $.3 billion increase in
net plant in service. (See Note 9 of Notes to Consolidated Financial Statements
for further discussion of income taxes.)
Postemployment Benefits: SFAS No. 112, "Employers' Accounting for Postemployment
Benefits," requires employers to adopt accrual accounting for benefits provided
to former or inactive employees and their beneficiaries and covered dependents,
after employment but before retirement. Due to current regulatory treatment,
adoption of SFAS No. 112 in 1994 is not expected to have a significant impact on
the Company's financial position or results of operations. (See Note 7 of Notes
to Consolidated Financial Statements for further discussion of postemployment
benefits.)
22
<PAGE>
Liquidity and Capital Resources
- -------------------------------
SOURCES OF CAPITAL: The Company's capital requirements are funded from cash
provided by operations, and to the extent necessary, external financing. The
Company's capital structure provides financial flexibility and access to capital
markets at reasonable rates, ensuring the Company's ability to meet all of its
capital requirements. As part of its focus on cost reduction, the Company will
further reduce financing costs in 1994 by refinancing existing debt and
preferred stock with lower-cost issuances.
CPUC Authorized Cost of Capital:In December 1993, the CPUC issued its decision
in the Company's 1994 cost of capital proceeding authorizing a utility capital
structure and cost as follows:
<TABLE>
<CAPTION>
Utility
Capital Weighted
Structure Cost Cost
- ------------------------------------------------------------------
<S> <C> <C> <C>
Common equity 47.50% 11.00% 5.22%
Preferred stock 5.50 8.15 .45
Long-term debt 47.00 7.53 3.54
- ------------------------------------------------------------------
Total authorized return on
average utility rate base 9.21%
==================================================================
</TABLE>
The authorized return on common equity is a decrease from the 11.90%
authorized for 1993. Average utility rate base is projected to be $12.5 billion
for 1994.
Debt: In 1993, the Company issued $2,950 million of First and Refunding Mortgage
Bonds (series 93A through 93H), $260 million of pollution control revenue bonds
and $750 million of medium-term notes. Substantially all the proceeds were used
to redeem or repurchase $3,536 million of higher-cost mortgage bonds to
accomplish a reduction in financing costs. In December 1993, the Board of
Directors (Board) authorized the Company to redeem or repurchase up to $1.2
billion of mortgage bonds, and $125 million of medium-term notes to further
reduce financing costs.
The Company issues short-term debt (principally commercial paper) to fund fuel
oil, nuclear fuel and gas inventories, and unrecovered balances in balancing
accounts. The Company uses external financing when balancing account revenues
are undercollected, as in 1993 and 1992, until the revenues, plus interest, are
recovered in rates. Short-term debt also has helped fund construction and
fluctuations in general working capital. At December 31, 1993, the Company had a
$1 billion short-term credit facility, with no borrowings outstanding.
In 1993, PGT finalized a new loan agreement for $710 million. Proceeds were
used to finance PGT's portion of the PGT-PG&E Pipeline Expansion Project and to
refinance PGT's existing borrowings. As of December 31, 1993, there was $648
million outstanding under this agreement. (See Notes 5 and 6 of Notes to
Consolidated Financial Statements for further discussion of long- and short-term
debt.)
Equity: In 1993, the Company received $264 million in proceeds from the sale of
common stock under the employee Savings Fund Plan, the Dividend Reinvestment
Plan and the employee Long-term Incentive Program. Proceeds were used for
capital expenditures and other general corporate purposes.
In 1993, the Company issued $200 million of redeemable preferred stock.
Proceeds were used to finance a portion of the redemption of $267 million of the
Company's higher-cost preferred stock in an effort to reduce financing costs. In
December 1993, the Board authorized the Company to redeem or repurchase an
additional $175 million of preferred stock. (See Note 4 of Notes to Consolidated
Financial Statements for further discussion of preferred stock.)
In July 1993, the Board authorized the Company to reinstate its common stock
repurchase program and repurchase up to $1 billion of common stock on the open
market or in negotiated transactions over the next three years. This program
will be funded by internally-generated funds. Shares will be repurchased to
manage the overall balance of common stock in the Company's capital structure.
Through December 31, 1993, the Company had repurchased $258 million of its
common stock under this program.
23
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF CONSOLIDATED RESULTS OF OPERATIONS AND
FINANCIAL CONDITION (continued)
PACIFIC GAS AND ELECTRIC COMPANY
CAPITAL REQUIREMENTS: The Company's three-year projection of capital
requirements is shown below:
<TABLE>
<CAPTION>
Year ended December 31, 1994 1995 1996
- ---------------------------------------------------------
(in millions)
<S> <C> <C> <C>
Utility $1,397 $1,319 $1,369
Diablo Canyon 105 87 82
Enterprises 227 149 137
- ---------------------------------------------------------
Total capital expenditures 1,729 1,555 1,588
Maturing debt and sinking funds 221 514 460
- ---------------------------------------------------------
Total capital requirements $1,950 $2,069 $2,048
=========================================================
</TABLE>
The above projection of capital requirements has been reduced from last year's
projection to reflect the anticipated reduction in new customer connections and
the Company's ongoing cost control efforts. Utility and Diablo Canyon
expenditures will be primarily for replacing and enhancing the Company's
facilities to improve their efficiency and reliability, to extend their useful
lives and to comply with environmental laws and regulations.
Enterprises' actual capital expenditures may vary significantly depending on
the availability of attractive investment opportunities. Projected expenditures
include oil and gas exploration and development costs for 1994 and Enterprises'
equity share of generating facility projects for 1994 through 1996.
In addition to these capital requirements, the Company has other commitments
as discussed in Notes 2 and 10 of Notes to Consolidated Financial Statements.
ENVIRONMENTAL MATTERS: The Company is subject to a number of laws and
regulations designed to protect human health and the environment by imposing
stringent controls with regard to planning and construction activities, land
use, air and water pollution and hazardous materials and waste management
activities. These laws and regulations affect future planning and existing
operations, including environmental protection and remediation activities.
Environmental Protection Measures: The Company's projected expenditures for
environmental protection are subject to periodic review and revision to reflect
changing technology and evolving regulatory requirements. Capital expenditures
for environmental protection are currently estimated to be approximately $50
million, $50 million and $75 million for 1994, 1995 and 1996, respectively, and
are included in the Company's three-year projection table in the above Capital
Requirements section. Expenditures during these years will be primarily for
nitrogen oxide (NOx) emission reduction projects. The Company currently
estimates that compliance with NOx rules could require capital expenditures
ranging from $300 million to $500 million to achieve NOx emission reductions
over a period of approximately ten years. The Company's environmental protection
capital expenditures are generally recovered through rates.
Environmental Remediation: The Company assesses, on an ongoing basis, measures
that may need to be taken to comply with laws and regulations related to
hazardous materials and hazardous waste compliance and remediation activities.
Although the ultimate amount of costs that will be incurred by the Company in
connection with its compliance and remediation activities are difficult to
estimate due to uncertainty concerning the Company's responsibility and the
extent of contamination, the complexity of environmental laws and regulations
and the selection of compliance alternatives, the Company has an accrued
liability as of December 31, 1993, of $60 million for hazardous waste
remediation costs. (See further discussion of the accrued liability for
hazardous waste remediation costs and the related deferred charge in Note 11 of
Notes to Consolidated Financial Statements.)
SALES AND ACQUISITION: In January 1994, the Company approved a final plan for
the disposition of Resources in 1994 if market conditions remain favorable. As
of December 31, 1993, Resources had assets of approximately $680 million.
In June 1992, PGT sold its 49.98% interest in ANG for $97 million. The sale
resulted in an after-tax gain of $19 million.
In December 1991, Resources purchased Tex/Con, an oil and gas exploration and
production company, for $389 million.
24
<PAGE>
STATEMENT OF CONSOLIDATED INCOME
PACIFIC GAS AND ELECTRIC COMPANY
<TABLE>
<CAPTION>
Year ended December 31, 1993 1992 1991
- ----------------------------------------------------------------------------------------
(in thousands, except per share amounts)
<S> <C> <C> <C>
Operating Revenues
Electric $ 7,866,043 $ 7,747,492 $7,368,640
Gas 2,716,365 2,548,596 2,409,479
- ----------------------------------------------------------------------------------------
Total operating revenues 10,582,408 10,296,088 9,778,119
- ----------------------------------------------------------------------------------------
Operating Expenses
Cost of electric energy 2,250,209 2,416,554 2,318,179
Cost of gas 1,092,055 1,062,879 960,208
Distribution 226,975 219,082 208,881
Transmission 166,539 184,165 195,642
Customer accounts and services 403,560 421,990 372,088
Maintenance 442,939 484,751 525,220
Depreciation and decommissioning 1,315,524 1,221,490 1,140,877
Administrative and general 1,041,453 927,316 875,878
Workforce reduction costs 190,200 - -
Income taxes 1,006,774 906,845 863,089
Property and other taxes 297,495 295,164 288,610
Other 385,755 322,411 316,368
- ----------------------------------------------------------------------------------------
Total operating expenses 8,819,478 8,462,647 8,065,040
- ----------------------------------------------------------------------------------------
Operating Income 1,762,930 1,833,441 1,713,079
- ----------------------------------------------------------------------------------------
Other Income and (Income Deductions)
Interest income 85,642 87,244 94,161
Allowance for equity funds used during
construction 41,531 39,368 24,543
Other -- net (53,524) (3,006) (23,909)
- ----------------------------------------------------------------------------------------
Total other income and (income deductions) 73,649 123,606 94,795
- ----------------------------------------------------------------------------------------
Income Before Interest Expense 1,836,579 1,957,047 1,807,874
- ----------------------------------------------------------------------------------------
Interest Expense
Interest on long-term debt 731,610 739,279 697,185
Other interest charges 118,100 91,404 101,871
Allowance for borrowed funds used during
construction (78,626) (44,217) (17,574)
- ----------------------------------------------------------------------------------------
Net interest expense 771,084 786,466 781,482
- ----------------------------------------------------------------------------------------
Net Income 1,065,495 1,170,581 1,026,392
Preferred dividend requirement 63,812 78,887 89,595
- ----------------------------------------------------------------------------------------
Earnings Available for Common Stock $ 1,001,683 $ 1,091,694 $ 936,797
========================================================================================
Weighted Average Common Shares Outstanding 430,625 422,714 417,965
Earnings Per Common Share $2.33 $2.58 $2.24
Dividends Declared Per Common Share $1.88 $1.76 $1.64
</TABLE>
The accompanying Notes to Consolidated Financial Statements are an integral
part of this statement.
25
<PAGE>
CONSOLIDATED BALANCE SHEET
PACIFIC GAS AND ELECTRIC COMPANY
<TABLE>
<CAPTION>
December 31, 1993 1992
- ------------------------------------------------------------------------------
(in thousands)
<S> <C> <C>
ASSETS
Plant In Service
Electric
Nonnuclear $ 16,633,772 $ 16,295,567
Diablo Canyon 6,518,413 5,983,976
Gas 7,146,741 5,454,084
- ---------------------------------------------------------------------------
Total plant in service (at original cost) 30,298,926 27,733,627
Accumulated depreciation and decommissioning (11,235,519) (10,507,560)
- ---------------------------------------------------------------------------
Net plant in service 19,063,407 17,226,067
- ---------------------------------------------------------------------------
Construction Work in Progress 620,187 1,534,578
Other Noncurrent Assets
Oil and gas properties 573,523 591,544
Decommissioning and other funds held by trustees 536,544 456,061
Other assets 497,689 402,041
- ---------------------------------------------------------------------------
Total other noncurrent assets 1,607,756 1,449,646
- ---------------------------------------------------------------------------
Current Assets
Cash and cash equivalents 61,066 97,592
Accounts receivable
Customers 1,264,907 1,319,285
Other 123,255 133,826
Allowance for uncollectible accounts (23,647) (23,806)
Regulatory balancing accounts receivable 992,477 743,253
Inventories
Materials and supplies 239,856 234,630
Gas stored underground 170,345 151,707
Fuel oil 109,615 155,816
Nuclear fuel 134,411 135,171
Prepayments 56,062 47,809
- ---------------------------------------------------------------------------
Total current assets 3,128,347 2,995,283
- ---------------------------------------------------------------------------
Deferred Charges
Income tax-related deferred charges 1,246,890 -
Diablo Canyon costs 419,775 260,042
Unamortized loss net of gain on reacquired debt 395,659 289,338
Workers' compensation and disability claims
recoverable 192,203 174,168
Other 488,302 259,037
- ---------------------------------------------------------------------------
Total deferred charges 2,742,829 982,585
- ---------------------------------------------------------------------------
Total Assets $ 27,162,526 $ 24,188,159
===========================================================================
</TABLE>
The accompanying Notes to Consolidated Financial Statements are an integral part
of this statement.
26
<PAGE>
CONSOLIDATED BALANCE SHEET
PACIFIC GAS AND ELECTRIC COMPANY
<TABLE>
<CAPTION>
December 31, 1993 1992
- ---------------------------------------------------------------------------
(in thousands)
<S> <C> <C>
CAPITALIZATION AND LIABILITIES
Capitalization
Common stock $ 2,136,095 $ 2,134,228
Additional paid-in capital 3,666,455 3,517,062
Reinvested earnings 2,643,487 2,631,847
- ---------------------------------------------------------------------------
Total common stock equity 8,446,037 8,283,137
Preferred stock without mandatory redemption
provision 807,995 790,791
Preferred stock with mandatory redemption
provision 75,000 146,888
Long-term debt 9,292,100 8,379,060
- ---------------------------------------------------------------------------
Total capitalization 18,621,132 17,599,876
- ---------------------------------------------------------------------------
Other Noncurrent Liabilities
Customer advances for construction 152,872 175,451
Workers' compensation and
disability claims 157,000 139,000
Other 246,950 172,607
- ---------------------------------------------------------------------------
Total other noncurrent liabilities 556,822 487,058
- ---------------------------------------------------------------------------
Current Liabilities
Short-term borrowings 764,163 1,131,124
Long-term debt 221,416 353,692
Accounts payable
Trade creditors 472,985 529,315
Other 389,065 372,157
Accrued taxes 303,575 237,305
Deferred income taxes 315,584 326,219
Interest payable 82,105 87,975
Dividends payable 203,923 187,721
Other 487,809 377,186
- ---------------------------------------------------------------------------
Total current liabilities 3,240,625 3,602,694
- ---------------------------------------------------------------------------
Deferred Credits
Deferred income taxes 3,978,950 1,780,769
Deferred investment tax credits 410,969 473,879
Other 354,028 243,883
- ---------------------------------------------------------------------------
Total deferred credits 4,743,947 2,498,531
- ---------------------------------------------------------------------------
Commitments and Contingencies (Notes 2,
10 and 11)
- ---------------------------------------------------------------------------
Total Capitalization and Liabilities $27,162,526 $24,188,159
===========================================================================
</TABLE>
27
<PAGE>
STATEMENT OF CONSOLIDATED CASH FLOWS
PACIFIC GAS AND ELECTRIC COMPANY
<TABLE>
<CAPTION>
Year ended December 31, 1993 1992 1991
- -------------------------------------------------------------------------------------------
<S> <C> <C> <C>
(in thousands)
Cash Flows From Operating Activities
Net income $ 1,065,495 $ 1,170,581 $ 1,026,392
Adjustments to reconcile net income to net cash
provided by operating activities
Depreciation and decommissioning 1,315,524 1,221,490 1,140,877
Amortization 135,808 121,795 103,923
Gain on sale of investment in Alberta Natural
Gas Company Ltd - (48,722) -
Deferred income taxes and investment tax
credits -- net 319,198 164,457 60,376
Allowance for equity funds used during
construction (41,531) (39,368) (24,543)
Net effect of changes in operating assets
and liabilities
Accounts receivable 64,790 39,922 (69,076)
Regulatory balancing accounts receivable (218,553) (215,195) 202,401
Inventories 23,097 (7,161) (7,440)
Accounts payable (39,422) (102,559) 172,245
Accrued taxes 44,638 128,243 35,977
Other working capital 108,873 (36,117) 36,784
Other deferred charges (158,725) 8,147 (68,905)
Other noncurrent liabilities 50,279 31,374 75,889
Other deferred credits 110,145 73,259 9,795
Other -- net 13,184 49,891 30,382
- -----------------------------------------------------------------------------------------
Net cash provided by operating activities 2,792,800 2,560,037 2,725,077
- -----------------------------------------------------------------------------------------
Cash Flows From Investing Activities
Construction expenditures (1,763,024) (2,307,318) (1,753,609)
Allowance for borrowed funds used during
construction (78,626) (44,217) (17,574)
Purchase of subsidiary - - (388,662)
Nonregulated expenditures (234,221) (148,226) (117,847)
Proceeds from sale of investment in Alberta
Natural Gas Company Ltd - 97,251 -
Other -- net 9,992 82,352 33,156
- -----------------------------------------------------------------------------------------
Net cash used by investing activities (2,065,879) (2,320,158) (2,244,536)
- -----------------------------------------------------------------------------------------
Cash Flows From Financing Activities
Common stock issued 264,489 296,653 271,482
Common stock repurchased (257,780) (5,410) (337,969)
Preferred stock issued 200,001 195,451 -
Preferred stock redeemed (302,640) (276,806) (123,667)
Long-term debt issued 4,584,548 1,676,513 738,649
Long-term debt matured or reacquired (4,002,704) (1,409,337) (263,220)
Short-term debt issued (redeemed) -- net (366,961) 121,213 (14,278)
Dividends paid (857,515) (809,108) (765,543)
Other -- net (24,885) (28,736) 10,078
- -----------------------------------------------------------------------------------------
Net cash used by financing activities (763,447) (239,567) (484,468)
- -----------------------------------------------------------------------------------------
Net Change in Cash and Cash Equivalents (36,526) 312 (3,927)
Cash and Cash Equivalents at January 1 97,592 97,280 101,207
- -----------------------------------------------------------------------------------------
Cash and Cash Equivalents at December 31 $ 61,066 $ 97,592 $ 97,280
=========================================================================================
Supplemental disclosures of cash flow information
Cash paid for
Interest (net of amounts capitalized) $ 642,712 $ 694,512 $ 723,968
Income taxes 542,827 682,809 768,097
</TABLE>
The accompanying Notes to Consolidated Financial Statements are an integral
part of this statement.
28
<PAGE>
STATEMENT OF CONSOLIDATED COMMON STOCK EQUITY AND PREFERRED STOCK
PACIFIC GAS AND ELECTRIC COMPANY
<TABLE>
<CAPTION>
Preferred Preferred
Stock Stock
Total Without With
Additional Common Mandatory Mandatory
Common Paid-in Reinvested Stock Redemption Redemption
Stock Capital Earnings Equity Provision Provision(1)
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
(in thousands, except shares)
- ------------------------------------------------------------------------------------------------------------------------------------
Balance December 31, 1990 $2,101,095 $3,170,890 $2,234,227 $7,506,212 $ 983,961 $129,510
- ----------------------------------------------------------------------------------------------------------------------------------
Net income - 1991 1,026,392 1,026,392
Common stock issued (10,263,302 shares) 51,317 220,165 271,482
Common stock repurchased (12,910,487 shares) (64,553) (98,455) (174,961) (337,969)
Preferred stock redeemed (3,811,325 shares) (5,287) (4,438) (9,725) (89,064) (24,878)
Cash dividends declared
Preferred stock (91,501) (91,501)
Common stock (685,341) (685,341)
Other 1,774 1,774
- -----------------------------------------------------------------------------------------------------------------------------------
Net change (13,236) 116,423 71,925 175,112 (89,064) (24,878)
- ----------------------------------------------------------------------------------------------------------------------------------
Balance December 31, 1991 2,087,859 3,287,313 2,306,152 7,681,324 894,897 104,632
- ----------------------------------------------------------------------------------------------------------------------------------
Net income - 1992 1,170,581 1,170,581
Common stock issued (9,453,353 shares) 47,267 249,386 296,653
Common stock repurchased (179,610 shares) (898) (2,450) (2,062) (5,410)
Preferred stock issued (8,000,000 shares) (4,549) (4,549) 125,000 75,000
Preferred stock redeemed (9,365,449 shares) (12,638) (14,940) (27,578) (229,106) (20,122)
Cash dividends declared
Preferred stock (81,393) (81,393)
Common stock (744,277) (744,277)
Other (2,214) (2,214)
- ----------------------------------------------------------------------------------------------------------------------------------
Net change 46,369 229,749 325,695 601,813 (104,106) 54,878
- ----------------------------------------------------------------------------------------------------------------------------------
Balance December 31, 1992 2,134,228 3,517,062 2,631,847 8,283,137 790,791 159,510
- ----------------------------------------------------------------------------------------------------------------------------------
Net income - 1993 1,065,495 1,065,495
Common stock issued (7,708,512 shares) 38,541 225,948 264,489
Common stock repurchased (7,334,876 shares) (36,674) (63,180) (157,926) (257,780)
Preferred stock issued (8,000,000 shares) 200,001
Preferred stock redeemed (8,156,968 shares) (13,375) (21,958) (35,333) (182,797) (84,510)
Cash dividends declared
Preferred stock (62,521) (62,521)
Common stock (811,196) (811,196)
Other (254) (254)
- ----------------------------------------------------------------------------------------------------------------------------------
Net change 1,867 149,393 11,640 162,900 17,204 (84,510)
- ----------------------------------------------------------------------------------------------------------------------------------
Balance December 31, 1993 $2,136,095 $3,666,455 $2,643,487 $8,446,037 $ 807,995 $ 75,000
==================================================================================================================================
</TABLE>
(1) Includes current portion.
The accompanying Notes to Consolidated Financial Statements are an integral part
of this statement.
29
<PAGE>
STATEMENT OF CONSOLIDATED CAPITALIZATION
PACIFIC GAS AND ELECTRIC COMPANY
<TABLE>
<CAPTION>
December 31, 1993 1992
- -----------------------------------------------------------------------------------------------
(dollars in thousands, except
per share amounts)
<S> <C> <C>
Common Stock Equity
Common stock, par value $5 per share
(authorized 800,000,000 shares, issued
and outstanding 427,219,205 and 426,845,569) $ 2,136,095 $ 2,134,228
Additional paid-in capital 3,666,455 3,517,062
Reinvested earnings 2,643,487 2,631,847
- -----------------------------------------------------------------------------------------------
Total common stock equity 8,446,037 8,283,137
- -----------------------------------------------------------------------------------------------
Preferred Stock
Preferred stock without mandatory redemption provision
Par value $25 per share(1)
Nonredeemable
5% to 6% -- 5,784,825 shares outstanding 144,621 144,621
Redeemable
4.36% to 8.2% -- 26,534,958 and 18,534,959 shares
outstanding 663,374 463,373
9% to 10.28% -- 0 and 7,311,868 shares outstanding - 182,797
- -----------------------------------------------------------------------------------------------
Total preferred stock without mandatory
redemption provision 807,995 790,791
- -----------------------------------------------------------------------------------------------
Preferred stock with mandatory
redemption provision
Par value $25 per share(1)
6.57% -- 3,000,000 shares outstanding 75,000 75,000
Par value $100 per share
(authorized 10,000,000 shares)
9% and 10.17% -- 0 and 845,100 shares outstanding - 84,510
- -----------------------------------------------------------------------------------------------
Total preferred stock with mandatory
redemption provision 75,000 159,510
Less preferred stock with mandatory redemption
provision--current portion - 12,622
- -----------------------------------------------------------------------------------------------
Preferred stock with mandatory redemption
provision in total capitalization 75,000 146,888
- -----------------------------------------------------------------------------------------------
Preferred stock in total capitalization 882,995 937,679
- -----------------------------------------------------------------------------------------------
Long-Term Debt
Pacific Gas and Electric Company (PG&E)
First and refunding mortgage bonds
Maturity Interest rates
1993-1998 4.25% to 13% 577,931 1,034,214
1999-2005 5.5% to 9.375% 1,886,328 1,840,611
2006-2012 6.25% to 10.07% 477,870 852,870
2013-2019 7.5% to 12.75% 140,900 852,196
2020-2026 5.85% to 9.95% 2,947,428 2,044,950
- -----------------------------------------------------------------------------------------------
Principal amounts outstanding 6,030,457 6,624,841
Unamortized discount net of premium (71,817) (103,707)
- -----------------------------------------------------------------------------------------------
Total mortgage bonds 5,958,640 6,521,134
Unsecured debentures, 10.81% to 12%, due 1994-2000 221,523 221,523
Pollution control loan agreements, variable rates,
due 2008-2016 925,000 925,000
Unsecured medium-term notes, 4.13% to 10.1%,
due 1993-2013 1,542,625 847,361
Unamortized discount related to unsecured
medium-term notes (3,459) (3,289)
Other long-term debt 24,127 26,056
- -----------------------------------------------------------------------------------------------
Total PG&E long-term debt 8,668,456 8,537,785
Long-term debt of subsidiaries 845,060 194,967
- -----------------------------------------------------------------------------------------------
Total long-term debt of PG&E
and subsidiaries 9,513,516 8,732,752
Less long-term debt -- current portion 221,416 353,692
- -----------------------------------------------------------------------------------------------
Long-term debt in total capitalization 9,292,100 8,379,060
- -----------------------------------------------------------------------------------------------
Total Capitalization $18,621,132 $17,599,876
===============================================================================================
</TABLE>
(1) Authorized 75,000,000 shares in total (both with and without mandatory
redemption provision).
The accompanying Notes to Consolidated Financial Statements are an integral
part of this statement.
30
<PAGE>
SCHEDULE OF CONSOLIDATED SEGMENT INFORMATION
PACIFIC GAS AND ELECTRIC COMPANY
<TABLE>
<CAPTION>
Diversified Intersegment
Electric Gas Operations(4) Eliminations Total
- -----------------------------------------------------------------------------------------------------------------------------------
(in thousands)
<S> <C> <C> <C> <C> <C>
1993
Operating revenues $ 7,866,043 $2,466,788 $ 249,577 $ - $10,582,408
Intersegment revenues(1) 15,369 223,443 5,079 (243,891) -
- -----------------------------------------------------------------------------------------------------------------------------------
Total operating revenues $ 7,881,412 $2,690,231 $ 254,656 $(243,891) $10,582,408
===================================================================================================================================
Depreciation and
decommissioning $ 925,673 $ 251,490 $ 138,361 $ - $ 1,315,524
Operating income before income taxes(2) 2,344,796 440,323 (7,375) (8,040) 2,769,704
Construction expenditures(3) 929,065 954,116 - - 1,883,181
Identifiable assets(3) $19,125,555 $6,467,424 $1,053,027 $ - $26,646,006
Corporate assets 516,520
- -----------------------------------------------------------------------------------------------------------------------------------
Total assets at year end $27,162,526
===================================================================================================================================
1992
Operating revenues $ 7,747,492 $2,342,202 $ 206,394 $ - $10,296,088
Intersegment revenues(1) 15,150 410,014 28,191 (453,355) -
- -----------------------------------------------------------------------------------------------------------------------------------
Total operating revenues $ 7,762,642 $2,752,216 $ 234,585 $(453,355) $10,296,088
===================================================================================================================================
Depreciation and decommissioning $ 856,124 $ 231,443 $ 133,923 $ - $ 1,221,490
Operating income before income taxes(2) 2,308,828 441,612 (9,808) (346) 2,740,286
Construction expenditures(3) 1,124,368 1,266,535 - - 2,390,903
Identifiable assets(3) $17,658,656 $5,068,213 $ 996,860 $ - $23,723,729
Corporate assets 464,430
- -----------------------------------------------------------------------------------------------------------------------------------
Total assets at year end $24,188,159
===================================================================================================================================
1991
Operating revenues $ 7,368,640 $2,341,054 $ 68,425 $ - $ 9,778,119
Intersegment revenues(1) 15,043 541,963 39,958 (596,964) -
- -----------------------------------------------------------------------------------------------------------------------------------
Total operating revenues $ 7,383,683 $2,883,017 $ 108,383 $(596,964) $ 9,778,119
===================================================================================================================================
Depreciation and decommissioning $ 843,768 $ 214,488 $ 82,621 $ - $ 1,140,877
Operating income before income taxes(2) 2,271,571 336,754 (31,227) (930) 2,576,168
Construction expenditures(3) 1,192,570 603,156 - - 1,795,726
Identifiable assets(3) $17,253,156 $4,212,764 $ 469,222 $ - $21,935,142
Corporate assets 965,528
- -----------------------------------------------------------------------------------------------------------------------------------
Total assets at year end $22,900,670
===================================================================================================================================
</TABLE>
(1) Intersegment electric and gas revenues are accounted for at tariff rates
prescribed by the CPUC.
(2) Income taxes and general corporate expenses are allocated in accordance
with FERC Uniform System of Accounts and requirements of the CPUC.
Operating income in the Statement of Consolidated Income is net of utility
income taxes.
(3) Includes an allocation of common plant in service and allowance for funds
used during construction.
(4) Includes the nonregulated operations of wholly owned subsidiaries including
PG&E Enterprises, Mission Trail Insurance Ltd. (liability insurance),
Pacific Gas Properties Company (real estate development), and Pacific
Conservation Services Company (conservation loans).
The accompanying Notes to Consolidated Financial Statements are an integral
part of this schedule.
31
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PACIFIC GAS AND ELECTRIC COMPANY
Note 1 -- Summary of Significant Accounting Policies
- ----------------------------------------------------
REGULATION: Pacific Gas and Electric Company (PG&E) is regulated by the
California Public Utilities Commission (CPUC) and the Federal Energy Regulatory
Commission (FERC). PG&E's consolidated financial statements reflect the
ratemaking policies of these commissions in conformity with generally accepted
accounting principles for rate-regulated enterprises. In the Notes to
Consolidated Financial Statements, regulated operations other than the Diablo
Canyon Nuclear Power Plant (Diablo Canyon) are referred to as the utility.
PRINCIPLES OF CONSOLIDATION: The consolidated financial statements include PG&E
and its wholly owned and majority-owned subsidiaries (the Company). All
significant intercompany transactions have been eliminated.
Major subsidiaries, all of which are wholly owned, are: Pacific Gas
Transmission Company (PGT) -- transports natural gas from the U.S./Canadian
border to PG&E at the California border; Alberta and Southern Gas Co. Ltd. (A&S)
- -- prior to November 1, 1993, bought gas in Canada and arranged transport to the
U.S. border (see Note 2 for discussion of the restructuring of A&S's
operations); Pacific Energy Fuels Company -- finances the purchase of nuclear
fuel through issuance of its commercial paper; PG&E Enterprises (Enterprises) --
the parent company for nonregulated subsidiaries, including PG&E Resources
Company (Resources), which engages in exploration, development and production of
oil and natural gas, and PG&E Generating Company which develops independent
power projects.
Alberta Natural Gas Company Ltd (ANG), a 49.98%-owned affiliate of PGT, was
sold in June 1992. ANG, a Canadian pipeline company, transported natural gas for
A&S to the U.S. border. Prior to the sale of ANG, the Company's investment in
ANG was accounted for by the equity method of accounting.
REVENUES: Revenues are recorded primarily for deliveries of gas and electric
energy to customers. These revenues give rise to receivables from a diversified
base of customers including residential, commercial and industrial customers in
Northern and Central California.
The CPUC has established mechanisms known as balancing accounts which help
stabilize the Company's earnings. Specifically, sales balancing accounts
accumulate differences between authorized and actual base revenues. Energy cost
balancing accounts accumulate differences between actual costs of gas and
electric energy and the revenue designated for recovery of such costs. Recovery
of gas and electric energy costs through these balancing accounts is subject to
a reasonableness review by the CPUC. (See Note 2 for further discussion of gas
costs.) These balancing accounts are recorded to the extent that future rate
recovery from customers, or refunds to customers, are probable.
PLANT IN SERVICE: The costs of plant additions, including replacements of
retired plant, are capitalized. Costs include labor, materials, construction
overheads and an allowance for funds used during construction (AFUDC). AFUDC is
the cost of debt and equity funds used to finance the construction of new
facilities. Financing costs of capital additions for Diablo Canyon and the
California portion of the PGT-PG&E Pipeline Expansion Project are calculated
under Statement of Financial Accounting Standards (SFAS) No. 34, "Capitalization
of Interest Cost," since Diablo Canyon and the California portion of the PGT-
PG&E Pipeline Expansion Project are not on traditional cost-based ratemaking.
(See Notes 2 and 3 for further discussion of these matters.) These costs are
included in allowance for borrowed funds used during construction. The original
cost of retired plant plus removal costs less salvage are charged to accumulated
depreciation. Maintenance, repairs and minor replacements and additions are
charged to maintenance expense.
DEPRECIATION AND DECOMMISSIONING: Depreciation of plant in service is computed
using a straight-line remaining-life method.
The estimated cost of decommissioning the Company's nuclear power facilities
is recovered in base rates through an annual allowance. For the year ended
December 31, 1993, 1992 and 1991, the amounts recovered in rates for
decommissioning costs were $54 million, $54 million, and $65 million,
respectively. The estimated total obligation for decommissioning costs is
approximately $1 billion in 1993 dollars; this obligation is being recognized
ratably over the facilities' lives. This estimate considers the total costs of
decommissioning and dismantling plant systems and structures and includes a
contingency factor for possible changes in regulatory requirements and waste
disposal cost increases.
As of December 31, 1993 and 1992, the Company had accumulated in external
trust funds $537 million and $456 million, respectively, to be used for the
decommissioning of the Company's nuclear facilities; corresponding amounts are
thus included in accumulated depreciation and decommissioning. These trust funds
maintain substantially all of their investments in debt securities. All fund
earnings are reinvested. At December 31, 1993 and 1992, the estimated fair
32
<PAGE>
values of the external trust funds were approximately $576 million and $475
million, respectively, based on quoted market prices. Funds may not be released
from the external trust funds until authorized by the CPUC.
As required by federal law, the U.S. Department of Energy (DOE) is responsible
for the future storage and disposal of spent nuclear fuel. The cost of these
activities is funded through a one-tenth of one cent fee on each kilowatthour
(kWh) sold by all nuclear power plants. This fee is paid quarterly to the DOE.
INCOME TAXES: The Company files a consolidated federal income tax return that
includes domestic subsidiaries in which its ownership is 80% or more. Income tax
expense includes the current and deferred income tax expense resulting from
operations during the year. Investment tax credits are deferred and amortized to
income over the life of the related property.
Effective January 1, 1993, the Company adopted SFAS No. 109, "Accounting for
Income Taxes," which established new financial accounting standards for income
taxes. SFAS No. 109 prohibits net-of-tax accounting, requires that deferred tax
liabilities and assets be adjusted for enacted changes in the income tax rates
and requires the use of the liability method of accounting for income taxes.
Under the liability method, the deferred tax liability represents the tax effect
of temporary differences between the financial statement and income tax bases of
assets and liabilities at the currently enacted income tax rates. Temporary
differences are measured at the balance sheet date, resulting in adjustments to
the deferred tax liability and related deferred charge, consistent with the
ratemaking process.
The effect of the adoption of SFAS No. 109, as of January 1, 1993, was an
increase of $1.8 billion in consolidated liabilities as the result of recording
additional deferred taxes; consolidated assets also increased $1.8 billion,
consisting of a $1.5 billion increase in deferred charges (income tax-related
deferred charges and Diablo Canyon costs) and a $.3 billion increase in net
plant in service. These adjustments relate to temporary differences, which prior
to adoption of SFAS No. 109 were not recorded as deferred taxes, consistent with
the ratemaking process. These differences included removal costs and federal tax
depreciation on property acquired prior to 1981, depreciation differences for
state purposes, percentage repair allowances expensed for tax purposes and
certain capitalized overheads expensed for tax purposes. Due to current
regulatory treatment, the adoption of SFAS No. 109 did not have a significant
impact on the Company's results of operations.
During 1993, the Omnibus Budget Reconciliation Act of 1993 (Act) was enacted,
which included an increase in the corporate federal income tax rate to 35% from
34%. Due to current regulatory treatment, the Company recorded a deferred charge
for the adjustment of deferred income taxes related to utility operations as a
result of this increase. Since Diablo Canyon is not on traditional cost-based
ratemaking, a one-time adjustment to income tax expense of $32 million resulted.
The Act did not have a significant impact on the Company's results of operations
during 1993.
DEBT PREMIUM, DISCOUNT AND RELATED EXPENSE: Long-term debt premium, discount and
related expense are amortized over the life of each issue. Gains and losses on
reacquired debt allocated to the utility are amortized over the remaining
original lives of the debt reacquired, consistent with ratemaking; gains and
losses on debt allocated to Diablo Canyon and the California portion of the PGT-
PG&E Pipeline Expansion Project are recognized in income at the time such debt
is reacquired.
OIL AND GAS PROPERTIES: Resources uses the successful-efforts method of
accounting for oil and gas properties.
INVENTORIES: Nuclear fuel inventory is stated at the lower of average cost or
market. Amortization of fuel in the reactor is based on the amount of energy
output.
Other inventories are valued at average cost except for fuel oil, which is
valued by the last-in-first-out method.
STATEMENT OF CONSOLIDATED CASH FLOWS: Cash and cash equivalents (at cost which
approximates market) include special deposits, working funds and short-term
investments with original maturities of three months or less.
RECLASSIFICATIONS: Prior years' amounts in the consolidated financial statements
have been reclassified where necessary to conform to the 1993 presentation.
NOTE 2 -- Natural Gas Matters
- -----------------------------
REGULATORY RESTRUCTURING: The CPUC has established a regulatory framework for
natural gas service in California which segments customers into core
(residential and smaller commercial customers) and noncore (industrial and
commercial customers that exceed certain size limitations) classes. This
framework allows noncore customers to
33
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
PACIFIC GAS AND ELECTRIC COMPANY
purchase gas directly from producers, aggregators or marketers and separately
negotiate gas transportation with their utilities. The CPUC has also adopted a
capacity brokering program which allows noncore customers and other shippers to
obtain rights to firm interstate pipeline transportation capacity held by the
local gas distribution utilities. Under the capacity brokering program
implemented August 1, 1993, the Company is required to make available for
brokering all interstate pipeline capacity which is not retained for its core
customers and core subscription customers (noncore customers choosing bundled
service). Noncore customers, producers, aggregators, marketers and the Company's
electric department can bid for such capacity.
In addition, in April 1992, FERC issued Order 636 which requires interstate
pipelines to restructure their services. This order unbundled sales,
transportation and storage services, instituted capacity release programs and
provided for recovery of transition costs related to the restructuring of
services.
The Company's compliance with these regulatory changes has allowed many of the
Company's noncore customers to arrange for the purchase and transportation of
their own gas supplies. These changes have resulted in a decrease in the amount
of gas required to be purchased by the Company and a related decrease in the
need for firm transportation capacity and have contributed to the need to
restructure the Company's gas supply arrangements.
Decontracting Plan: Until November 1993, PG&E purchased Canadian natural gas
from PGT which in turn purchased such gas from A&S. A&S had commitments to
purchase minimum quantities of natural gas from approximately 190 Canadian gas
producers under various long-term contracts, most of which extended through
2005. Certain of these Canadian gas producers filed lawsuits against the Company
claiming damages of at least $466 million (Canadian) resulting from the alleged
failure of A&S to meet its minimum contractual gas purchase obligations. As a
result of the regulatory restructuring discussed above, A&S, PGT, PG&E and
approximately 190 Canadian gas producers entered into agreements (collectively,
the Decontracting Plan) which terminated A&S's contracts with these Canadian gas
producers and settled all litigation and claims arising from such contracts.
Under the Decontracting Plan which became effective November 1, 1993, producers'
contracts with A&S, the sales agreement between A&S and PGT, and PG&E's service
agreement with PGT were terminated, allowing producers to decontract their
reserves from the A&S supply pool. As a result, PG&E may contract on an
individual basis for its gas supply requirements directly with any producer,
aggregator or marketer, whether or not they were formerly in the A&S supply
pool.
Under the Decontracting Plan, producers released A&S, PGT and PG&E from any
claims they may have had that resulted from the termination of the former
arrangements as well as any claims for losses arising from alleged historical
shortfalls in gas taken by A&S. The total amount of settlement payments paid to
producers was approximately $210 million.
As part of the overall A&S decontracting process, A&S's operations have been
significantly reduced, with a major aggregator of Canadian natural gas acquiring
A&S's restructured gas purchase contracts and remaining sales contracts. A&S
continues to hold gas transportation capacity on Canadian pipelines and is in
the process of permanently assigning or brokering such capacity.
As part of the Decontracting Plan, A&S permanently assigned portions of its
commitments for transportation capacity with NOVA Corporation of Alberta (NOVA)
through October 2001 and ANG through October 2005 to third parties. A&S also
assigned approximately 600 million cubic feet per day (MMcf/d) of capacity on
each of these pipelines to PG&E for use in the servicing of PG&E's core and core
subscription customers. A&S currently holds the remaining capacity of
approximately 450 MMcf/d with annual demand charges of approximately $25 million
for which it is continuing its efforts to assign or broker. There is uncertainty
about the ability of A&S to assign or broker this remaining capacity. To the
extent others do not take this capacity, A&S will remain obligated to pay for
the related demand charges.
In July 1993, FERC approved a transition cost recovery mechanism (TCRM) for
PGT under which most costs which were incurred to restructure, reform or
terminate the sales arrangements between A&S and PGT and underlying A&S gas
supply contracts, or to resolve claims by gas suppliers related to past or
future liabilities or obligations of PGT or A&S, are eligible for recovery in
PGT's rates. The TCRM precludes most objections to the eligibility and prudence
of such costs; prudence challenges may be made only on the grounds that the
payment is unreasonably high in light of the damages claimed. Disposition of
approved transition costs will be as follows: (1) 25% of such costs will be
absorbed by PGT; (2) 25% will be recovered by PGT through direct bills
(substantially all to PG&E as PGT's principal customer); and (3) 50% will be
recovered by PGT through volumetric surcharges over a three-year period. Costs
associated with A&S's commitments for Canadian pipeline capacity do not qualify
as transition costs recoverable under this mechanism.
34
<PAGE>
Financial Impact of Decontracting Plan and Litigation: The Company incurred
transition costs of $228 million, consisting of settlement payments made to
producers in connection with the implementation of the Decontracting Plan and
amounts incurred by A&S in reducing certain administrative and general functions
resulting from the restructuring. Of these costs, the Company deferred $143
million (included in deferred charges -- other) for future rate recovery. In
addition, the Company recorded a reserve of $31 million due to the uncertainty
of A&S's ability to assign or broker its remaining commitments for Canadian
transportation capacity. Accordingly, the Company expensed $93 million in 1993
and a total of $23 million in prior years.
PGT and PG&E are seeking recovery of all transition costs eligible for
recovery under the TCRM other than the 25% of such costs to be absorbed by PGT.
While such transition costs are still subject to challenges at the FERC level
and the recovery of such costs paid by PG&E as a shipper of gas on PGT's
pipelines will depend on the recovery mechanism adopted by the CPUC, the Company
believes that it will ultimately recover the deferred transition costs.
Transportation Commitments: The Company has gas transportation service
agreements with various Canadian and interstate pipeline companies. These
agreements include provisions for fixed demand charges for reserving firm
capacity on the pipelines. The total demand charges that the Company will pay
each year may change due to changes in tariff rates and may be reduced to the
extent the Company can broker or assign any unused capacity. In addition to
demand charges, the Company is required to pay transportation charges for actual
quantities shipped. The Company's total demand and transportation charges paid
under these agreements (excluding PGT) were approximately $280 million in 1993,
$300 million in 1992 and $260 million in 1991.
As discussed above, regulatory changes have resulted in a decrease in the
amount of gas required to be purchased by the Company and a related decrease in
the need for firm transportation capacity. The Company has retained portions of
this capacity to be used for its core and core subscription customers and has
permanently assigned significant portions of the remaining capacity. The
following table summarizes the approximate amounts of capacity held by the
Company on various pipelines for its core and core subscription customers and
capacity remaining to be assigned or brokered as of December 31, 1993:
<TABLE>
<CAPTION>
Remaining Total
Amount Held Amount Available Annual Demand
Pipeline for Core for Brokering Charges Contract
Company (MMcf/d) (MMcf/d) (in millions) Expiration
- -----------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
El Paso 610 530 $130 Dec. 1997
PGT 610 430 $ 50 Oct. 2005
Transwestern 50* 150 $ 30 Mar. 2007
NOVA 610 460 $ 35 Oct. 2001
ANG 600 440 $ 20 Oct. 2005
</TABLE>
* This amount is held by the Company's electric department for electric power
generation.
The Company expects to recover the demand charges associated with capacity
held for its core and core subscription customers through its gas balancing
account mechanisms. The CPUC has established a separate mechanism that will
allow PG&E to recover the demand charges paid to PGT and El Paso Natural Gas
Company (El Paso) in excess of the demand charges for the capacity held for core
and core subscription customers, reduced by revenues received from brokering
such capacity, subject to a reasonableness review. With respect to Transwestern
Pipeline Company (Transwestern) capacity, which the Company contracted in order
to provide supply diversity and reliability and to stimulate price competition,
the CPUC has ordered the Company to exclude such demand charges from rates
pending a reasonableness review.
The Company is continuing its efforts to broker or assign the remaining
transportation capacity that is not used. During the latter half of 1993, as
implementation of capacity brokering began on interstate pipelines -- El Paso,
PGT and Transwestern -- PG&E has been able to broker a significant portion of
the unused capacity, including limited amounts of that held for its core and
core subscription customers when such capacity was not being used. Amounts
brokered have been on a short-term basis, most of which were at a discounted
price. The average monthly demand charges associated with the Company's unused
interstate capacity have been approximately $10 million, of which the Company
has been able to recover approximately 50% through capacity brokering during the
past few months. Because the success of the Company's brokering efforts will
depend on market demand, the Company cannot predict the volume or the price of
the capacity that will be brokered in the future.
35
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
PACIFIC GAS AND ELECTRIC COMPANY
GAS REASONABLENESS PROCEEDINGS: Recovery of gas costs through the Company's
regulatory balancing account mechanisms is subject to a CPUC determination that
such costs were incurred reasonably. Under the current regulatory framework,
annual reasonableness proceedings are conducted by the CPUC on a historic
calendar year basis.
1988-1990: The CPUC consolidated its review of the reasonableness of gas system
costs for 1988 through 1990. A CPUC Administrative Law Judge (ALJ) recently
issued proposed decisions on the Company's Canadian gas procurement activities
and gas inventory operations during 1988 through 1990.
The proposed decision on the Company's Canadian gas procurement activities
finds that the Company's procurement practices were reasonable in light of the
events and circumstances then applicable, but that the Company was imprudent to
the extent that it failed to take reasonable steps to bargain more aggressively
with Canadian gas suppliers. The proposed decision recommends a disallowance of
approximately $46 million of gas costs plus accrued interest estimated at
approximately $15 million. The proposed decision also finds that the
disallowances recommended by the CPUC's Division of Ratepayer Advocates (DRA)
and an intervenor overstate the magnitude of savings which the Company could
have achieved during 1988 through 1990. The DRA had recommended that the Company
refund $392 million based on its contention that the Company should have
purchased 50% of its Canadian supplies on the spot market instead of almost
totally relying on long-term contracts. Using a different theory than the DRA,
an intervenor had asserted that the Company overpaid for Canadian gas in the
range of $540 million to $670 million.
In the proposed decision on gas inventory operations, the ALJ found the
Company's gas inventory operations in 1989 and 1990 to be reasonable except for
operations during December 1990 for which the ALJ proposed a disallowance of $7
million. Earlier, the DRA recommended a disallowance of $37 million contending
that the Company should have withdrawn additional gas from storage in the winter
of 1989-1990 and December 1990 rather than burning fuel oil, which was more
expensive.
A final CPUC decision on the Company's Canadian gas procurement activities is
expected in the first quarter of 1994. CPUC consideration of other issues which
relate to purchased electric energy and certain contracts with Southwestern gas
producers has been deferred. Relating to purchased electric energy costs, the
DRA recommended a disallowance of $18 million contending that had the Company
purchased lower cost Canadian gas, the Company would have realized a reduction
in its electric energy costs. However, the DRA has not yet addressed issues
related to certain contracts with Southwestern gas producers.
1991: The DRA has issued a report on the reasonableness of the Company's gas
procurement and operating activities for 1991. The DRA recommended that the
Company refund approximately $116 million, consisting of $105 million related to
Canadian gas purchases and $11 million related to gas inventory operations and
Southwest gas procurement issues. The DRA's recommendations are based on the
same theories outlined in the DRA's reports for 1988 through 1990, as discussed
above.
1992: The DRA issued a report on the reasonableness of the Company's gas
procurement and operating activities for 1992, recommending that the Company
refund approximately $92 million. The recommended disallowance includes $61
million related to Canadian gas purchases and $8 million related to gas
inventory operations, based on the same theories outlined in prior DRA reports.
Also included are disallowances totaling $23 million related to Southwest gas
transportation and procurement issues. It is possible that similar issues will
be raised regarding the Company's Canadian gas procurement activities during
1993. However, the Company estimates the disallowance that the DRA may recommend
for 1993 should be significantly lower than those for prior years.
Affiliate Audit: The DRA issued a report on its investigation of the operations
of A&S and the Company's former affiliate, ANG, for 1988 through 1991. The
investigation was initiated in connection with the reasonableness proceeding
for 1991. The DRA reviewed certain nongas costs, primarily Canadian pipeline
charges and A&S overhead costs, and recommended a penalty and disallowance of
$50 million and $6 million, respectively. The recommended penalty and
disallowance are primarily related to the Company's alleged failure to
properly oversee its subsidiaries' activities. In addition, recommendations
related to 1992 activities may be made in a subsequent report. The Company
filed a motion with the CPUC asking it to disregard the recommended penalty
and disallowance because prior federal rulings approved such costs and thus
preempt the issue. In December 1993, an ALJ denied this motion.
36
<PAGE>
Financial Impact of Gas Reasonableness Proceedings: The DRA is a consumer
advocacy branch of the CPUC staff. Neither the DRA's recommendations nor the
ALJ's proposed decisions constitute a CPUC decision. The CPUC can accept all,
part or none of the DRA's recommendations or the ALJ's proposed decisions. The
Company believes that its gas procurement activities, transportation
arrangements and operations were prudent and will vigorously contest the
disallowances and penalty proposed by the DRA or other parties. However, based
on its current assessment of the matter, the Company recorded a reserve of $61
million in 1993 for any disallowance that may be ordered by the CPUC in the gas
reasonableness proceedings. The Company currently is unable to estimate the
ultimate outcome of the gas reasonableness proceedings or predict whether such
outcome will have a significant adverse impact on its financial position or
results of operations.
PGT-PG&E PIPELINE EXPANSION PROJECT: In November 1993, the Company placed in
service an expansion of its natural gas transmission system from the Canadian
border into California. The pipeline provides an additional 148 MMcf/d of firm
capacity to the Pacific Northwest and an additional 755 MMcf/d of firm capacity
to Northern and Southern California. At December 31, 1993 and 1992, the
Company's total investment in the expansion project was approximately $1,587
million (included in plant in service) and $979 million (included in
construction work in progress), respectively. The $1,587 million at December 31,
1993, consisted of $767 million for the facilities within California (i.e.,
intrastate portion) and $820 million for the facilities outside California
(i.e., interstate portion).
The construction of facilities within the state of California has been
certificated by the CPUC. The conditions of the certificate place the Company at
risk for its decision to construct based on its assessment of market demand and
subsequent underutilization of the facility. The certificate requires the
application of a "cross-over" ban under which volumes delivered from the
incremental interstate (PGT) expansion must be transported at an incremental
expansion rate within California. Incremental rate design is based on the
concept that expansion shippers, not existing ratepayers, bear the incremental
costs of the expansion project. Capacity on the interstate portion is fully
subscribed under long-term firm transportation contracts. However, to date,
shippers have only executed long-term firm transportation contracts for
approximately 40% of the intrastate capacity. The CPUC has authorized the
Company to provide as-available service on the expansion project, which would
provide additional revenues to recover the incremental costs of the expansion
project. The Company continues negotiations for the remaining capacity.
The CPUC certificate issued in December 1990 established a cost cap of $736
million for the California portion, which represented the maximum amount
determined by the CPUC to be reasonable and prudent based on an estimate of the
anticipated construction costs at that time. In October 1993, the CPUC issued a
decision granting the Company's motion to put in place temporary interim rates
based on the existing cost cap of $736 million. The decision authorized the
temporary interim rates to become effective on the date of commercial operation,
November 1, 1993, and remain in effect for five months or until interim rates
are established by the CPUC.
In February 1994, the CPUC announced a decision on the Company's request for
an increase in the California portion of the expansion project's cost cap and
its interim rate filing. The CPUC granted the Company's request to increase the
cost cap to $849 million but set interim rates based on $736 million, subject to
an adjustment based on the outcome of a reasonableness review of capital costs.
The CPUC's decision finds that, given market conditions at the time, the Company
was reasonable in constructing the expansion project. The CPUC rejected the
assignment of costs related to unused capacity on other pipelines (or the
Company's intrastate facilities) to the expansion project as previously
recommended by an ALJ's proposed decision.
Due to the ratemaking treatment adopted by the CPUC for the California portion
of the expansion project, the Company's ability to recover its cost of service
rates is contingent upon demand and competitive market pricing for gas
transportation services. In light of anticipated demand and pricing in the
foreseeable future, the Company has determined that it may not bill its
customers to recover its full cost of service. Consequently, application of SFAS
No. 71, "Accounting for the Effects of Certain Types of Regulation" was
discontinued for the California portion of the expansion project during 1993.
This accounting change was implemented using the guidelines contained in SFAS
No. 101, "Regulated Enterprises -- Accounting for the Discontinuation of
Application of FASB Statement No. 71" and did not have a significant impact on
the Company's financial position or results of operations in 1993.
Financial Impact of PGT-PG&E Pipeline Expansion Project: Based upon the current
status of the rate case and market demand, the Company believes it will recover
its investment in the expansion project.
37
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
PACIFIC GAS AND ELECTRIC COMPANY
Note 3 -- Diablo Canyon
- -----------------------
RATE CASE SETTLEMENT: The Diablo Canyon rate case settlement, effective July
1988, bases revenues primarily on the amount of electricity generated by the
plant, rather than on traditional cost-based ratemaking. In approving the
settlement, the CPUC explicitly stated that it affirmed that Diablo Canyon costs
and operations should no longer be subject to CPUC reasonableness reviews. The
CPUC cannot bind future commissions in fixing just and reasonable rates for
Diablo Canyon, but to the extent permitted by law intends that this decision
remain in effect for the full term of the settlement, ending 2016.
The settlement provides that certain Diablo Canyon costs be recovered over the
term of the settlement, including a full return on such costs, through base
rates. The related revenues to recover these costs are included in Diablo Canyon
operating revenues for reporting purposes. Other than these and decommissioning
costs, Diablo Canyon no longer meets the criteria for application of SFAS No.
71. Consequently, application of this statement was discontinued for Diablo
Canyon effective July 1988.
PRICING: Under the Diablo Canyon rate case settlement, the price per kWh of
electricity generated by Diablo Canyon consists of a fixed and an escalating
component. The total prices for 1991 through 1993 were 9.60 cents, 10.34 cents
and 11.16 cents per kWh, respectively, effective January 1. The total price for
1994, effective January 1, is 11.89 cents per kWh. For 1995 through 2016, the
escalating component will be adjusted by the change in the consumer price index
plus 2.5%, divided by two. During the first 700 hours of full-power operation
for each unit during the peak period (10 a.m. to 10 p.m. on weekdays in June
through September), the price is 130% of the stated amount to encourage the
Company to utilize the plant during the peak period. Beginning in January of
each year, during the first 700 hours of full-power operation for each unit
outside the peak period, the price is 70% of the stated amount. At all other
times, the price is 100% of the stated amount.
FINANCIAL INFORMATION: Selected financial information for Diablo Canyon is shown
below:
<TABLE>
<CAPTION>
Year ended December 31, 1993 1992 1991
- ------------------------------------------------
(in millions)
<S> <C> <C> <C>
Operating revenues $1,933 $1,781 $1,501
Operating income 708 663 497
Net income 496 443 274
</TABLE>
In determining operating results of Diablo Canyon, operating revenues were
specifically identified pursuant to the Diablo Canyon rate case settlement. The
majority of operating expenses were also specifically identified, including
income tax expense. Administrative and general expense, principally labor costs,
is allocated based on a study of labor costs. Interest is charged based on an
allocation of corporate debt to Diablo Canyon.
Note 4 -- Preferred Stock
- -------------------------
Nonredeemable preferred stock ($25 par value) consists of 5%, 5.5% and 6%
series, which have rights to annual dividends per share of $1.25, $1.375 and
$1.50, respectively.
Redeemable preferred stock without a mandatory redemption provision (4.36% to
8.2%, $25 par value) is subject to redemption, in whole or in part, if the
Company pays the specified redemption price plus accumulated and unpaid
dividends through the redemption date. Annual dividends and redemption prices
per share range from $1.09 to $2.05, and from $25.75 to $28.125, respectively.
The 6.57% series ($25 par value) preferred stock is subject to a mandatory
redemption provision and is entitled to a sinking fund providing for the
retirement of stock outstanding, beginning in 2002, at par value per share plus
accumulated and unpaid dividends through the redemption date. In addition to
mandatory redemptions, this stock may be redeemed at the Company's option at par
value per share plus accumulated and unpaid dividends through the redemption
date and a redemption premium under specified circumstances after July 2002. The
estimated fair value for the Company's preferred stock with a mandatory
redemption provision at December 31, 1993 and 1992, was approximately $81
million and $168 million, respectively, based primarily on quoted market prices.
During 1993, the Company issued $125 million of 6.875% redeemable preferred
stock and $75 million of 7.04% redeemable preferred stock. Proceeds were used to
finance a portion of the 1993 redemption of all the Company's 9.00%, 9.30%,
9.48% and 10.17% redeemable preferred stock with an aggregate par value of $267
million.
During 1992, the Company issued $125 million of 7.44% redeemable preferred
stock and $75 million of 6.57% preferred stock with a mandatory redemption
provision, and redeemed the 9.28%, 10.18% and 10.28% series of redeemable
preferred stock with an aggregate par value of $229 million.
38
<PAGE>
Dividends on preferred stock are cumulative. Preferred dividends are accrued
based on declaration date, whereas preferred dividend requirement, which is
used to calculate earnings per common share, is based on the accumulated
dividends on preferred stock outstanding at year end. All shares of preferred
stock have equal preference in dividend and liquidation rights. Upon liquidation
or dissolution of the Company, holders of the preferred stock would be entitled
to the par value of such shares plus all accumulated and unpaid dividends, as
specified for the class and series.
Note 5 -- Long-term Debt
- ------------------------
MORTGAGE BONDS: The First and Refunding Mortgage Bonds of the Company are issued
in series, bear annual interest rates ranging from 4.25% to 12.75% and mature
from 1994 to 2026. The Company had $6.0 billion and $6.6 billion of mortgage
bonds outstanding at December 31, 1993 and 1992, respectively. Additional bonds
may be issued, subject to CPUC approval, up to a maximum total outstanding of
$10 billion, assuming compliance with indenture covenants for earnings coverage
and property available as security. The Company's Board of Directors may
increase the amount authorized, subject to CPUC approval. The indenture requires
that net earnings excluding depreciation and interest be equal to or greater
than 1.75 times the annual interest charges on the Company's mortgage bonds
outstanding. All real properties and substantially all personal properties of
PG&E are subject to the lien of the indenture.
The Company is required by the indenture to make semi-annual sinking fund
payments on February 1 and August 1 of each year for the retirement of the
bonds. The payments equal .5% of the aggregate bonded indebtedness outstanding
on the preceding November 30 and May 31, respectively. Bonds of any series, with
certain exceptions, may be used to satisfy this requirement. In addition,
holders of series 84D bonds maturing in 2017 have an option to redeem their
bonds in 1995.
In conjunction with the Company's focus on reducing the levels of high-cost
debt, the Company redeemed or repurchased $3,536 million and $1,182 million of
higher-cost mortgage bonds in 1993 and 1992, respectively. Interest rates on the
bonds redeemed or repurchased ranged from 7.50% to 12.75%.
During 1993, the Company issued $2,950 million of First and Refunding Mortgage
Bonds, series 93A through 93H, with interest rates ranging from 5.375% to 7.250%
and maturity dates ranging from 1998 to 2026. Substantially all the proceeds
from these bonds were used to redeem or repurchase higher-cost mortgage bonds.
Included in the total of outstanding mortgage bonds are First and Refunding
Mortgage Bonds issued by the Company to secure its obligation to repay various
loans from the California Pollution Control Financing Authority (CPCFA) to
finance air and water pollution control, and sewage and solid waste disposal
facilities. The amounts loaned to the Company by the CPCFA consist of proceeds
from the CPCFA's sale of tax-exempt pollution control revenue bonds having the
same principal amounts and terms as the Company's mortgage bonds securing the
loans. At December 31, 1993 and 1992, the Company had outstanding $768 million
and $508 million, respectively, of mortgage bonds securing loans from the CPCFA.
These mortgage bonds have interest rates ranging from 5.85% to 8.875% and
maturity dates from 2007 to 2023.
POLLUTION CONTROL LOAN AGREEMENTS: In addition to the pollution control loans
secured by the Company's mortgage bonds (described above), the Company had loans
totaling $925 million at December 31, 1993 and 1992, from the CPCFA to finance
air and water pollution control, and sewage and solid waste disposal facilities.
Interest rates on the loans vary depending on whether the loans are in a daily,
weekly, commercial paper or fixed rate mode. Conversions from one mode to
another take place at the Company's option. Average annual interest rates on
these loans for 1993 ranged from 2.31% to 2.54%. These loans are subject to
redemption on demand by the holder under certain circumstances. The Company's
obligations for such demands are secured by irrevocable letters of credit which
mature as early as 1996.
MEDIUM-TERM NOTES: The Company had $1,543 million and $847 million of unsecured
medium-term notes outstanding at December 31, 1993 and 1992, respectively, with
interest rates ranging from 4.13% to 10.10% and maturities from 1994 to 2013.
During 1993 and 1992, the Company issued $750 million and $263 million of
medium-term notes, respectively. Proceeds from these notes were applied to
construction expenditures and to the redemption, repurchase or retirement of
debt or preferred stock.
39
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
PACIFIC GAS AND ELECTRIC COMPANY
LONG-TERM DEBT OF SUBSIDIARIES: In 1993, PGT finalized a new loan agreement for
$710 million to finance PGT's portion of the PGT-PG&E Pipeline Expansion Project
and to refinance PGT's existing borrowings. As of December 31, 1993, there was
$648 million outstanding under this agreement. The loan is secured by PGT's
operating revenues and gas transportation contracts. The loan will mature no
later than 2004, however, if certain terms and conditions are not met by
November 1996, the loan could mature as early as 1997. If early maturity does
not occur, a reserve sufficient to cover a minimum of six months of debt service
must be established. At December 31, 1993, the Company was in compliance with
all terms and conditions. The interest rate varies depending on the rate
selected by the Company, which can be the prime rate, London Interbank Offered
Rate or certificate of deposit rate, plus applicable margin. During 1993, the
weighted average rate of interest was 3.83%.
REPAYMENT SCHEDULE: At December 31, 1993, the Company's combined aggregate
amount of maturing long-term debt and sinking fund requirements, for the years
1994 through 1998, are $221 million, $514 million, $460 million, $369 million
and $714 million, respectively.
FAIR VALUE: The estimated fair value for the Company's total long-term debt of
$9.5 billion and $8.7 billion at December 31, 1993 and 1992, respectively, was
approximately $9.9 billion and $9.2 billion, respectively. The estimated fair
value of long-term debt was determined based on quoted market prices, where
available. Where quoted market prices were not available, the estimated fair
value was determined using other valuation techniques (e.g., matrix pricing
models or the present value of future cash flows). Debt allocated to Diablo
Canyon at December 31, 1993 and 1992, had a book value of $2.2 billion, and a
fair value of approximately $2.3 billion.
Note 6 -- Short-term Borrowings
- -------------------------------
Short-term borrowings consist of commercial paper with a weighted average
interest rate of 3.43% at December 31, 1993. The usual maturity for commercial
paper is 10 to 90 days. Commercial paper outstanding at December 31, 1993 and
1992, was $764 million and $916 million, respectively. The carrying amount of
short-term borrowings approximates fair value.
The Company has a $1 billion revolving credit facility with various banks to
support the sale of commercial paper and for other corporate purposes. At
December 31, 1993 and 1992, there were no borrowings outstanding under this
facility. This credit facility expires in November 1997; however, it may be
extended annually for additional one-year periods upon mutual agreement between
the Company and the banks. The Company is in compliance with all covenants
associated with the facility.
Note 7 -- Employee Benefit Plans
- --------------------------------
RETIREMENT PLAN: The Company provides a noncontributory defined benefit pension
plan covering substantially all employees. The retirement benefits are based on
years of service and the employee's base salary. The Company's funding policy is
to contribute each year not more than the maximum amount deductible for federal
income tax purposes and not less than the minimum contribution required under
the Employee Retirement Income Security Act of 1974. The cost of this plan is
charged to expense and to plant in service through construction work in
progress.
Net pension cost, using the projected unit credit actuarial cost method, was:
<TABLE>
<CAPTION>
Year ended December 31, 1993 1992 1991
- -----------------------------------------------------------------------
(in thousands)
<S> <C> <C> <C>
Service cost for benefits earned $ 129,166 $ 127,388 $ 112,940
Interest cost 268,698 248,674 238,153
Actual return on plan assets (511,526) (204,576) (774,445)
Net amortization and deferral 177,597 (78,560) 552,775
- -----------------------------------------------------------------------
Net pension cost $ 63,935 $ 92,926 $ 129,423
=======================================================================
</TABLE>
The decrease in net pension cost in 1993 compared to 1992 was primarily due to
a change in the expected long-term rate of return on plan assets to better
reflect actual and expected earnings on the funds invested. The decrease in net
pension cost in 1992 compared to 1991 was mostly due to favorable investment
returns in 1991.
The expected long-term rate of return on plan assets used to calculate pension
cost was 9% for 1993, and 8% for 1992 and 1991.
Net pension cost is calculated using expected return on plan assets. The
difference between actual and expected return on plan assets is included in net
amortization and deferral and is considered in the determination of future
pension cost. In 1993 and 1991, actual return on plan assets exceeded expected
return whereas, in 1992, actual return on plan assets was less than expected
return.
40
<PAGE>
In conformity with accounting for rate-regulated enterprises, regulatory
adjustments have been recorded in the income statement and balance sheet for the
difference between utility pension cost determined for accounting purposes and
that for ratemaking, which is based on a contribution approach.
<TABLE>
<CAPTION>
The plan's funded status was:
December 31, 1993 1992
- -------------------------------------------------------------
<S> <C> <C>
(in thousands)
Actuarial present value of
benefit obligations
Vested benefits $(3,203,408) $(2,680,364)
Nonvested benefits (154,349) (183,971)
- -------------------------------------------------------------
Accumulated benefit obligation (3,357,757) (2,864,335)
Effect of projected future
compensation increases (577,926) (859,764)
- -------------------------------------------------------------
Projected benefit obligation (3,935,683) (3,724,099)
Plan assets at market value 4,376,110 3,872,374
- -------------------------------------------------------------
Plan assets in excess of
projected benefit obligation 440,427 148,275
Unrecognized prior service cost 117,312 71,324
Unrecognized net gain (759,690) (383,498)
Unrecognized net obligation 120,253 137,763
- -------------------------------------------------------------
Accrued pension liability $ (81,698) $ (26,136)
=============================================================
</TABLE>
The increase in unrecognized prior service cost in 1993 compared to 1992
reflects a plan amendment which provides an increase in benefits to certain
retirees.
Plan assets consist substantially of common stocks, fixed-income securities
and real estate investments. The unrecognized prior service cost is amortized
over approximately 16 years. The unrecognized net obligation is being amortized
over approximately 18 years, beginning in 1987.
The vested benefit obligation is the actuarial present value of vested
benefits to which employees are currently entitled based on their expected
termination dates.
Assumptions used to calculate the projected benefit obligation to determine
the plan's funded status were:
<TABLE>
<CAPTION>
December 31, 1993 1992
- -----------------------------------------------
<S> <C> <C>
Weighted average discount rate 7% 7%
Average rate of projected future
compensation increases 5% 6%
</TABLE>
SAVINGS FUND PLAN: The Company sponsors a defined contribution pension plan to
which employees with at least one year of service may make contributions.
Employees may contribute up to 14 percent and, effective January 1994, up to 15
percent of their covered compensation on a pretax or after-tax basis. These
contributions, up to a maximum of six percent of covered compensation, are
eligible for matching Company contributions at specified rates. The cost of
Company contributions was charged to expense and to plant in service through
construction work in progress and totaled $36 million, $35 million and $33
million for 1993, 1992 and 1991, respectively.
LONG-TERM INCENTIVE PROGRAM: The Company implemented a Long-term Incentive
Program (Program) in 1992. The Program allows eligible participants to be
granted stock options with or without associated stock appreciation rights,
dividend equivalents and/or performance-based units. The Program incorporates
those shares previously authorized under the Company's 1986 Stock Option Plan.
A total of 14.5 million shares of common stock have been authorized for award
under the Program and the 1986 Stock Option Plan. Costs associated with the
Program, which have not been significant, are not recoverable in rates.
At December 31, 1993, stock options on 1,973,161 shares, granted at option
prices ranging from $16.75 to $33.38, were outstanding. During 1993, 691,200
options were granted at an option price of $33.13. Option prices are the market
price per share on the date of grant.
Outstanding stock options expire ten years and one day after the date of grant
and become exercisable on a cumulative basis at one-third each year commencing
two years from the date of grant. Stock options also become exercisable within
certain time limitations upon the optionee's termination due to retirement,
disability, death or a change in control of a subsidiary, and upon certain
changes in control of the Company.
In 1993, stock options on 174,387 shares were exercised at option prices
ranging from $16.75 to $33.13. At December 31, 1993, stock options on 493,989
shares were exercisable.
POSTRETIREMENT BENEFITS OTHER THAN PENSIONS: The Company provides a contributory
defined benefit medical plan for retired employees and their eligible dependents
and a noncontributory defined benefit life insurance plan for retired employees.
Substantially all employees retiring at or after age 55 are eligible for these
benefits. The medical benefits are provided through plans administered by an
insurance carrier or a health maintenance organization. Certain retirees are
responsible for a portion of the cost based on past claims experience of the
Company's retirees.
The Company's funding policy for the medical and life insurance benefits is to
contribute each year the tax-deductible amount provided for in rates. Life
insurance benefits which are not funded are provided through an insurance
company at a cost based on total current claims paid plus administrative fees.
The cost of these plans is charged to expense and to plant in service through
construction work in progress.
41
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
PACIFIC GAS AND ELECTRIC COMPANY
Effective January 1, 1993, the Company adopted SFAS No. 106, "Employers'
Accounting for Postretirement Benefits Other Than Pensions," which requires
accrual of the expected cost of these benefits during the employees' years of
service. The assumptions and calculations involved in determining the accrual
closely parallel pension accounting requirements. The Company previously
recognized these costs as benefits were paid and funded, which was consistent
with ratemaking.
In December 1992, the CPUC issued a decision in the final phase of the
investigation on the ratemaking treatment for these benefits in 1993 and beyond.
The decision authorized recovery of these benefits, within certain guidelines,
at a level equal to the lesser of the annual SFAS No. 106 cost, based on
amortization of the transition obligation over 20 years, or the amount which can
be contributed annually on a tax-deductible basis to appropriate trusts. Due to
this regulatory treatment, adoption of SFAS No. 106 did not have a significant
impact on the Company's financial position or results of operations.
Net postretirement medical and life insurance cost, using the projected unit
credit actuarial cost method, was:
<TABLE>
<CAPTION>
Year ended December 31, 1993
- ----------------------------------------------------------------------
(in thousands)
<S> <C>
Service cost for benefits earned $ 38,496
Interest cost 73,502
Actual return on plan assets (23,999)
Amortization of transition obligation 39,620
Net amortization and deferral (3,390)
- ----------------------------------------------------------------------
Net postretirement benefit cost $ 124,229
======================================================================
</TABLE>
The medical and life insurance plans' funded status was:
<TABLE>
<CAPTION>
December 31, 1993
- ----------------------------------------------------------------------
<S> <C>
(in thousands)
Accumulated postretirement benefit obligation
Retirees $(384,706)
Other fully eligible participants (148,018)
Other active plan participants (365,786)
- ----------------------------------------------------------------------
Total accumulated postretirement
benefit obligation (898,510)
Plan assets at market value 345,938
- ----------------------------------------------------------------------
Accumulated postretirement benefit obligation
in excess of plan assets (552,572)
Unrecognized net loss 21,481
Unrecognized transition obligation 543,939
- ----------------------------------------------------------------------
Prepaid postretirement benefit $ 12,848
======================================================================
</TABLE>
Plan assets consist substantially of common stocks and fixed-income
securities. In accordance with SFAS No. 106, the Company elected to amortize the
actuarially-determined transition obligation at January 1, 1993, of $1,018
million over 20 years beginning in 1993. In 1993, the Company implemented a plan
change that will limit the amount it will contribute toward postretirement
medical benefits. This limitation, which will take effect for all retirees
beginning in 2001, reduced the accumulated postretirement obligation for these
benefits at July 1, 1993, by approximately $450 million. Due to current
regulatory treatment, the limitation did not have a significant impact on the
Company's financial position or results of operations.
The expected long-term rate of return on plan assets used to calculate
postretirement medical and life insurance benefit costs for 1993 was 9%. The
assumptions used to calculate the benefit obligations included a weighted
average discount rate of 7% and a rate of projected future compensation
increases of 5%. The assumed health care cost trend rate in 1994 is
approximately 11.5%, grading down to an ultimate rate in 2005 of approximately
6%. The effect of a one-percentage-point increase in the assumed health care
cost trend rate for each future year would increase the accumulated
postretirement benefit obligation at December 31, 1993, by approximately $107
million and the 1993 aggregate service and interest costs by approximately $17
million.
For 1992 and 1991, the cost of postretirement medical and life insurance
benefits was based on benefits paid and funded and totaled $98 million and $92
million, respectively.
VOLUNTARY RETIREMENT INCENTIVE PLAN: In 1993, the Company announced a workforce
reduction program which included a voluntary retirement incentive plan for
certain employees 50 years of age with at least 15 years of service. The
additional pension and other postretirement benefits extended in connection with
the voluntary retirement incentive plan are reflected in the funded status
tables above and are discussed further in Note 8.
POSTEMPLOYMENT BENEFITS: In November 1992, the Financial Accounting Standards
Board issued SFAS No. 112, "Employers' Accounting for Postemployment Benefits,"
which requires employers to adopt accrual accounting for benefits provided to
former or inactive employees and their beneficiaries and covered dependents,
after employment but before retirement. The Company will adopt the new standard
in 1994.
Based on a preliminary valuation by the Company's actuary, it is estimated
that the recorded liability for such benefits will increase by approximately
$100 million upon adoption. However, due to current regulatory treatment,
adoption of SFAS No. 112 is not expected to have a significant impact on the
Company's financial position or results of operations.
42
<PAGE>
Note 8 -- Workforce Reduction Program
- -------------------------------------
In the first quarter of 1993, the Company announced a corporate reorganization
and workforce reduction program which reduced employment positions through a
combination of a targeted voluntary retirement incentive plan, targeted
voluntary severance, involuntary severance, transitional leaves of absence and
attrition.
In March 1993, the CPUC authorized the establishment of a memorandum account
to record costs and savings incurred in connection with the workforce reduction
program, with the recovery of such costs subject to a reasonableness review by
the CPUC. The Company is seeking rate recovery of all costs incurred in
connection with the workforce reduction program relating to electric and gas
operations.
As of December 31, 1993, the Company has recorded workforce reduction program
costs of $264 million, net of a curtailment gain relating to pension benefits.
(Included in this amount is $151 million for additional pension benefits and $22
million for other postretirement benefits extended in connection with the
voluntary retirement incentive plan.) In April 1993, the Company announced a
freeze on electric rates through 1994. As a result, the Company has expensed
$190 million of such costs relating to electric operations. The remaining $74
million of such costs relating to gas operations has been deferred for future
rate recovery. The amount deferred is currently being amortized as savings are
realized.
Note 9 -- Income Taxes
- ----------------------
The current and deferred components of income tax expense were:
<TABLE>
<CAPTION>
Year ended December 31, 1993 1992 1991
- --------------------------------------------------------------------------------
(in thousands)
<S> <C> <C> <C>
Current
Federal $ 417,558 $ 536,774 $ 589,713
State 165,134 193,895 201,445
- --------------------------------------------------------------------------------
Total current 582,692 730,669 791,158
- --------------------------------------------------------------------------------
Deferred (substantially all federal)
Regulatory balancing accounts 77,515 85,210 (86,682)
Depreciation 207,690 165,944 161,937
(Gain) loss on reacquired debt 42,405 15,959 (1,377)
Other -- net 11,998 (78,783) 4,922
- --------------------------------------------------------------------------------
Total deferred 339,608 188,330 78,800
- --------------------------------------------------------------------------------
Investment tax credits -- net (20,410) (23,873) (18,424)
- --------------------------------------------------------------------------------
Total income tax expense $ 901,890 $ 895,126 $ 851,534
================================================================================
Classification of income taxes
Included in operating expenses $1,006,774 $ 906,845 $ 863,089
- --------------------------------------------------------------------------------
Included in other -- net (104,884) (11,719) (11,555)
- --------------------------------------------------------------------------------
Total income tax expense $ 901,890 $ 895,126 $ 851,534
================================================================================
</TABLE>
The significant components of net deferred income tax liabilities are as
follows:
<TABLE>
<CAPTION>
Deferred Deferred Net deferred
income tax income tax income tax
December 31, 1993 assets liabilities liability
- --------------------------------------------------------------------------------
(in thousands)
<S> <C> <C>
Deferred income taxes -- current
Regulatory balancing accounts $ -- $ 449,216
Other 160,177 26,545
- --------------------------------------------------------------------------------
Total deferred income
taxes -- current 160,177 475,761 $ 315,584
- --------------------------------------------------------------------------------
Deferred income taxes --
noncurrent
Plant in service -- 3,386,122
Income tax-related
deferred charges(1) -- 511,786
Other 647,018 728,060
- --------------------------------------------------------------------------------
Total deferred income
taxes -- noncurrent 647,018 4,625,968 3,978,950
- --------------------------------------------------------------------------------
Total deferred income taxes $ 807,195 $5,101,729 $4,294,534
================================================================================
</TABLE>
(1) Represents the portion of deferred income tax liability related to the
revenues required to recover future income taxes.
The differences between income tax expense and amounts determined by applying
the federal statutory rate to income before income tax expense were:
<TABLE>
<CAPTION>
Year ended December 31, 1993 1992 1991
- --------------------------------------------------------------------------------
<S> <C> <C> <C>
Federal statutory income tax rate 35.0% 34.0% 34.0%
Increase (decrease) in income tax rate
resulting from
Investment tax credits (1.0) (1.2) (1.0)
State income tax
(net of federal benefit) 6.1 6.1 7.1
Effect of regulatory accounting
for depreciation differences 4.5 5.0 5.4
Other -- net 1.2 (0.6) (0.2)
- --------------------------------------------------------------------------------
Effective tax rate 45.8% 43.3% 45.3%
================================================================================
</TABLE>
Note 10 -- Commitments
- ----------------------
CAPITAL PROJECTS: Capital expenditures for 1994 are estimated to be
approximately $1,729 million, consisting of $1,397 million for utility
expenditures, $105 million for Diablo Canyon and $227 million for nonregulated
expenditures. At December 31, 1993, Enterprises had firm commitments totaling
$241 million to make capital contributions for its equity share of generating
facility projects. The contributions, payable upon commercial operation of the
projects, are estimated to be $95 million in 1994, $119 million in 1995,
43
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
PACIFIC GAS AND ELECTRIC COMPANY
$27 million in 1996, and none in 1997, 1998, and thereafter. The partnerships
which own the generating facility projects typically finance them with
nonrecourse debt.
QUALIFYING FACILITIES (QFs): Under the Public Utility Regulatory Policies Act of
1978, the Company is required to purchase electric energy and capacity produced
by QFs. The CPUC established a series of power purchase agreements which set the
applicable terms, conditions and price options. QFs must meet certain
performance obligations, depending on the contract, prior to receiving capacity
payments. The total cost of both energy and capacity payments to QFs is
recoverable in rates. The Company's contracts with QFs expire on various dates
from 1994 to 2022. Under these contracts, the Company is required to make
payments only when energy is supplied or when capacity commitments are met.
Payments to QFs are expected to vary in future years. There are no requirements
to make debt service payments. QF deliveries in the aggregate account for
approximately 24% of the Company's 1993 total electric energy requirements and
no single contract accounted for more than 5% of the Company's energy needs. QF
deliveries in 1993 represented approximately 84% of the QFs' plant output, in
the aggregate. The amount of energy received from QFs and the total energy and
capacity payments made under these agreements were:
<TABLE>
<CAPTION>
Year ended December 31, 1993 1992 1991
- -------------------------------------------------------
<S> <C> <C> <C>
(in millions)
Kilowatthours received 21,242 21,173 19,127
Energy payments $ 1,099 $ 1,084 $ 970
Capacity payments $ 503 $ 489 $ 450
</TABLE>
IRRIGATION DISTRICTS AND WATER AGENCIES: The Company has contracts with various
irrigation districts and water agencies to purchase hydroelectric power. The
contracts expire on various dates from 2004 to 2031. Under these contracts, the
Company must make specified semi-annual minimum payments whether or not any
energy is supplied, subject to the provider's retention of FERC authorization.
Additional variable payments for operation and maintenance costs incurred by the
providers are also required to be made under the contracts. The total cost of
these payments is recoverable in rates. At December 31, 1993, the future minimum
payments under these contracts were $34 million for each of the years 1994
through 1998 and a total of $484 million for periods thereafter. Total payments
under these contracts were $45 million, $54 million and $47 million in 1993,
1992 and 1991, respectively.
WESTERN AREA POWER ADMINISTRATION (WAPA) ENERGY AGREEMENT: The Company has an
agreement with WAPA to purchase energy from them and resell it to them upon
their request. The energy under contract has been purchased by the Company from
WAPA at favorable prices based on WAPA's cost of generation. That energy must be
sold back to WAPA at a price equal to the Company's current thermal production
cost at the time of delivery to WAPA less the Company's savings that resulted
from the purchases at the lower WAPA prices.
The contract will expire in 2005. At December 31, 1993, the cost to the
Company to return the amount of energy currently available to WAPA was
approximately $177 million, assuming WAPA requests the return of all the energy
prior to the contract's expiration date. However, such cost represents a return
of the benefits the Company received through its purchases from WAPA, which were
passed on to ratepayers at that time. The Company believes it is entitled to
recover in rates costs of energy resold to WAPA.
Note 11 -- Contingencies
- ------------------------
HELMS PUMPED STORAGE PLANT (HELMS): Helms, a three-unit hydroelectric combined
generating and pumped storage facility, completion of which was delayed due to a
water conduit rupture in 1982 and various start-up problems related to the
plant's generators, became commercially operable in 1984. As a result of the
damage caused by the rupture and the delay in the operational date, the Company
incurred additional costs which are currently excluded from rate base and lost
revenues during the period while the plant was under repair.
The Company has filed an application for rate recovery of the remaining
unrecovered Helms costs, the associated revenue requirement on such costs since
1984 and lost revenues during the time the generators were being repaired. The
remaining net unrecovered costs of Helms (after adjustment for depreciation) and
revenues discussed above totaled $106 million at December 31, 1993.
In June 1993, the DRA issued its report on the Company's 1991 Helms
application and recommended a disallowance of all requested costs and revenues.
The DRA recommends ratepayers should not be held responsible for plant costs or
losses incurred by a utility due to contractor error, whether or not the utility
was prudent, and cites past CPUC action for this policy. The DRA also contends
the Company acted imprudently in the management of the project and failed to
adequately oversee the engineering and design of the generators.
44
<PAGE>
With respect to the lost revenues and related recorded interest during the
time that Helms was out of service for the modification and repair of the
generators, the DRA asserts the Company has failed to establish that the
outage was not caused by a problem first identified during the precommercial
testing program.
The Company filed its rebuttal testimony in January 1994 asserting that it was
prudent in managing and overseeing the project and various issues raised by DRA
were not based on facts or were irrelevant to the application. The Company is
uncertain whether, and to what extent, any of the remaining costs and revenues
will be recovered through the ratemaking process.
NUCLEAR INSURANCE: The Company is a member of Nuclear Mutual Limited (NML) and
Nuclear Electric Insurance Limited (NEIL I and II). If the nuclear plant of a
member utility is damaged or increased costs for business interruption are
incurred due to a prolonged accidental outage, the Company may be subject to
maximum assessments of $21 million (property damage) or $7 million (business
interruption), in each case per policy period, if losses exceed premiums,
reserves and other resources of NML, NEIL I or NEIL II.
The federal government has enacted laws that require all utilities with
nuclear generating facilities to share in payment for claims resulting from a
nuclear incident. The Price-Anderson Act limits industry liability for third-
party claims resulting from any nuclear incident to $9 billion per incident.
Coverage of the first $200 million is provided by a pool of commercial insurers.
If a nuclear incident results in public liability claims in excess of $200
million, the Company may be assessed up to $159 million per incident, with
payments in each year limited to a maximum of $20 million per incident.
ENVIRONMENTAL REMEDIATION: The Company assesses, on an ongoing basis, measures
that may need to be taken to comply with laws and regulations related to
hazardous materials and hazardous waste compliance and remediation activities.
The Company may be required to take remedial action at certain disposal and
retired manufactured gas plant sites if they are determined to present a
significant threat to human health or the environment because of an actual or
potential release of hazardous substances. The Company has been designated as a
potentially responsible party under the Comprehensive Environmental Response,
Compensation, and Liability Act (federal Superfund law) and the California
Hazardous Substance Account Act (California Superfund law) with respect to
several sites. The overall costs of the hazardous materials and hazardous waste
compliance and remediation activities ultimately undertaken by the Company are
difficult to estimate due to uncertainty concerning the Company's
responsibility, the complexity of environmental laws and regulations, and the
selection of compliance alternatives. However, based on the information
currently available, the Company has an accrued liability as of December 31,
1993, of $60 million for hazardous waste remediation costs. The ultimate amount
of such costs may be significantly higher if, among other things, the Company is
held responsible for cleanup at additional sites, other potentially responsible
parties are not financially able to contribute to these costs, or further
investigation indicates that the extent of contamination and affected natural
resources is greater than anticipated at sites for which the Company is
responsible.
To the extent that hazardous waste compliance and remediation costs are not
recovered through insurance or by other means, the Company will apply for
recovery through ratemaking procedures established by the CPUC and expects that
most prudently incurred hazardous waste compliance and remediation costs will be
recovered through rates. As of December 31, 1993, the Company has a deferred
charge of $61 million for most hazardous waste remediation costs, which
represents the minimum amount of such costs expected to be recovered. Due to
expected regulatory treatment, the Company believes that the ultimate outcome of
these matters will not have a significant adverse impact on its financial
position or results of operations.
LEGAL MATTERS: Antitrust Litigation: In December 1993, the County of Stanislaus,
California, and a residential customer of PG&E, filed a complaint against PG&E
and PGT on behalf of themselves and purportedly as a class action on behalf of
all natural gas customers of PG&E, for the period of February 1988 through
October 1993. The complaint alleges that the purchase of natural gas in Canada
by A&S was accomplished in violation of various antitrust laws which resulted in
increased prices of natural gas for PG&E's customers.
The complaint alleges that the Company could have purchased as much as 50% of
its Canadian gas on the spot market instead of relying on long-term contracts
and that the damage to the class members is at least as much as the price
differential multiplied by the replacement volume of gas, an amount estimated in
the complaint as potentially exceeding $800 million. The complaint indicates
that the damages to the class could
45
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
PACIFIC GAS AND ELECTRIC COMPANY
include over $150 million paid by the Company to terminate the contracts with
the Canadian gas producers in November 1993. The complaint also seeks recovery
of three times the amount of the actual damages pursuant to antitrust laws.
The Company believes the case is without merit and has filed a motion to
dismiss the complaint. The Company believes that the ultimate outcome of the
antitrust litigation will not have a significant adverse impact on its financial
position.
Hinkley Litigation: In 1993, a complaint was filed in San Bernadino County
Superior Court on behalf of a number of individuals seeking recovery of an
unspecified amount of damages for personal injuries and property damage
allegedly suffered as a result of exposure to chromium near the Company's
Hinkley Compressor Station, as well as punitive damages.
The plaintiffs contend that the Company discharged chromium-contaminated waste
water into unlined ponds, which led to chromium percolating into the groundwater
of surrounding property. The plaintiffs further allege that the Company disposed
of the chromium in those ponds to avoid costly alternatives.
In 1987, the Company undertook an extensive project to remediate potential
groundwater chromium contamination. The Company has incurred substantially all
of the costs it currently deems necessary to clean up the affected groundwater
contamination. In accordance with the remediation plan approved by the regional
water quality control board, the Company will continue to monitor the affected
area and periodically perform environmental assessments.
In November 1993, the parties engaged in private mediation sessions. In
December 1993, the plaintiffs filed an offer to compromise and settle their
claims against the Company for $250 million.
The Company is unable to estimate the ultimate outcome of this matter, but
such outcome could have a significant adverse impact on the Company's results of
operations. The Company believes that the ultimate outcome of this matter will
not have a significant adverse impact on its financial position.
QF Transmission Litigation: The Company is a defendant in a lawsuit, currently
in trial, resulting from the termination of a power purchase agreement. The
plaintiff contends the Company misrepresented to the CPUC and to QFs its
transmission capacity and that the existence of transmission constraints
extended the deadline for delivery of energy. The plaintiff also alleges the
Company had an obligation to build transmission upgrades at the Company's
expense, which it did not fulfill. The complaint seeks compensatory and punitive
damages of an unspecified amount. However, the plaintiff's damage expert has
given a preliminary estimate of damages sought of $67 million. There are other
similarly situated QFs which might choose to file similar complaints depending
on the outcome of this litigation. The Company believes that the matter has no
merit and that the ultimate outcome will not have a significant adverse impact
on its financial position or results of operations.
46
<PAGE>
QUARTERLY CONSOLIDATED FINANCIAL DATA (UNAUDITED)
PACIFIC GAS AND ELECTRIC COMPANY
Quarterly Financial Data
- ------------------------
The four quarters of 1993 and 1992 are shown below. Due to the seasonal nature
of the utility business and the scheduled refueling outages for Diablo Canyon,
operating revenues, operating income and net income are not generated evenly by
quarter during the year.
In the second quarter of 1993, the Company charged to earnings $141 million
related to the workforce reduction program for management employees. In the
third quarter of 1993, the Company's earnings reflected charges of $144 million
resulting from the Company's workforce reduction program, termination of
Canadian gas contracts and an increase in the federal income tax rate that was
signed into law this year. The fourth quarter of 1993 reflected charges against
earnings of $126 million for Canadian gas costs incurred by the Company for 1988
through 1990 and for commitments for gas transportation capacity. Earnings for
the second quarter of 1992 included a $19 million after-tax gain from the sale
by PGT of its 49.98% interest in ANG.
The Company's common stock is traded on the New York, Pacific, London,
Amsterdam, Basel and Zurich stock exchanges. There were approximately 245,000
common shareholders of record at December 31, 1993. Dividends are paid on a
quarterly basis, and there are no significant restrictions on the present
ability of the Company to pay dividends.
<TABLE>
<CAPTION>
Quarter ended December 31 September 30 June 30 March 31
- --------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
(in thousands, except per
share amounts)
1993
Operating revenues $2,707,171 $2,947,294 $2,464,125 $2,463,818
Operating income 428,914 525,981 387,707 420,328
Net income 208,382 356,099 245,350 255,664
Earnings per common
share(1) .45 .79 .53 .56
Dividends declared per
common share .47 .47 .47 .47
Common stock price per
share
High 36.75 36.63 35.38 35.75
Low 33.50 33.13 31.75 31.75
1992
Operating revenues $2,557,787 $2,798,763 $2,519,679 $2,419,859
Operating income 386,196 507,137 491,131 448,977
Net income 205,804 351,939 336,409 276,429
Earnings per common
share(1) .44 .78 .75 .61
Dividends declared per
common share .44 .44 .44 .44
Common stock price per
share
High 34.00 34.63 33.63 32.38
Low 30.00 31.13 29.00 29.13
</TABLE>
(1) Includes Diablo Canyon scheduled refueling outages for the first and second
quarters of 1993 and for the third and fourth quarters of 1992.
47
<PAGE>
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
PACIFIC GAS AND ELECTRIC COMPANY
To the Shareholders and the Board of Directors of Pacific Gas and Electric
Company:
We have audited the accompanying consolidated balance sheet and the statement of
consolidated capitalization of Pacific Gas and Electric Company (a California
corporation) and subsidiaries as of December 31, 1993 and 1992, and the related
statements of consolidated income, cash flows, common stock equity and preferred
stock, and the schedule of consolidated segment information for each of the
three years in the period ended December 31, 1993. These financial statements
are the responsibility of the Company's management. Our responsibility is to
express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements and schedule of
consolidated segment information referred to above present fairly, in all
material respects, the financial position of Pacific Gas and Electric Company
and subsidiaries as of December 31, 1993 and 1992, and the results of their
operations and cash flows for each of the three years in the period ended
December 31, 1993 in conformity with generally accepted accounting principles.
As discussed in Note 2 of Notes to Consolidated Financial Statements, the
reasonableness of Canadian gas costs for 1988 through 1993 is subject to
California Public Utilities Commission review. The Company currently is unable
to estimate the ultimate outcome of the gas reasonableness proceedings or
predict whether such outcome will have a significant adverse impact on its
financial position or results of operations.
As discussed in Note 11 of Notes to Consolidated Financial Statements, the
Company has filed an application for rate recovery of the remaining unrecovered
Helms costs and certain lost revenues which totaled $106 million at December 31,
1993. The Company is uncertain whether, and to what extent, any of the remaining
costs and revenues will be recovered through the ratemaking process.
As discussed in Note 11 of Notes to Consolidated Financial Statements, in
1993, a complaint was filed on behalf of a number of individuals seeking
recovery for personal injuries and property damage related to alleged
groundwater contamination caused by Company activity. The Company is unable to
estimate the ultimate outcome of this matter, but such outcome could have a
significant adverse impact on the Company's results of operations. The Company
believes that the ultimate outcome of this matter will not have a significant
adverse impact on the Company's financial position.
As explained in Notes 1 and 7 of Notes to Consolidated Financial Statements,
effective January 1, 1993, the Company changed its method of accounting for
postretirement benefits other than pensions and for income taxes.
ARTHUR ANDERSEN & CO.
San Francisco, California
February 16, 1994
48
<PAGE>
EXHIBIT INDEX
Exhibit
Number Exhibit
- --------- -------------------------
11 Computation of Earnings
per Common Share
12.1 Computation of Ratios
of Earnings to Fixed
Charges
12.2 Computation of Ratios of
Earnings to Combined Fixed
Charges and Preferred Stock
Dividends
23 Consent of Arthur
Andersen & Co.
<PAGE>
EXHIBIT 11
PACIFIC GAS AND ELECTRIC COMPANY
COMPUTATION OF EARNINGS PER COMMON SHARE
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------------------
Year ended December 31,
----------------------------------
(in thousands, except per share amounts) 1993 1992 1991
- --------------------------------------------------------------------------------------------
<S> <C> <C> <C>
EARNINGS PER COMMON SHARE (EPS) AS SHOWN
IN THE STATEMENT OF CONSOLIDATED INCOME
Net income $1,065,495 $1,170,581 $1,026,392
Less preferred dividends 63,812 78,887 89,595
---------- ---------- ----------
Net income for calculating EPS for
Statement of Consolidated Income $1,001,683 $1,091,694 $ 936,797
========== ========== ==========
Average common shares outstanding 430,625 422,714 417,965
========== ========== ==========
EPS as shown in the Statement of
Consolidated Income $ 2.33 $ 2.58 $ 2.24
========== ========== ==========
PRIMARY EPS (1)
Net income $1,065,495 $1,170,581 $1,026,392
Less preferred dividends 63,812 78,887 89,595
---------- ---------- ----------
Net income for calculating primary EPS $1,001,683 $1,091,694 $ 936,797
========== ========== ==========
Average common shares outstanding 430,625 422,714 417,965
Add exercise of options, reduced by the
number of shares that could have been
purchased with the proceeds from
such exercise (at average market price) 1,619 707 571
---------- ---------- ----------
Average common shares outstanding as
adjusted 432,244 423,421 418,536
========== ========== ==========
Primary EPS $ 2.32 $ 2.58 $ 2.24
========== ========== ==========
FULLY DILUTED EPS (1)
Net income $1,065,495 $1,170,581 $1,026,392
Less preferred dividends 63,812 78,887 89,595
---------- ---------- ----------
Net income for calculating fully diluted EPS $1,001,683 $1,091,694 $ 936,797
========== ========== ==========
Average common shares outstanding 430,625 422,714 417,965
Add exercise of options, reduced by the
number of shares that could have been
purchased with the proceeds from such
exercise (at the greater of average or
ending market price) 1,895 1,134 730
---------- ---------- ----------
Average common shares outstanding as
adjusted 432,520 423,848 418,695
========== ========== ==========
Fully diluted EPS $ 2.32 $ 2.58 $ 2.24
========== ========== ==========
- --------------------------------------------------------------------------------------------
</TABLE>
(1) This presentation is submitted in accordance with Item 601(b)(11) of
Regulation S-K. This presentation is not required by APB Opinion No. 15,
because it results in dilution of less than 3%.
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT 12.1
PACIFIC GAS AND ELECTRIC COMPANY AND SUBSIDIARIES
COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES
- ---------------------------------------------------------------------------------------
Year ended December 31,
----------------------------------------------------------
(dollars in thousands) 1993 1992 1991 1990 1989
- ---------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Earnings:
Net income $1,065,495 $1,170,581 $1,026,392 $ 987,170 $ 900,628
Company's equity in
undistributed loss
(earnings) of
unconsolidated
affiliates - (3,349) 26,671 (2,799) (4,352)
Income tax expense 901,890 895,126 851,534 881,647 669,885
Net fixed charges 730,708 758,333 760,957 788,889 821,982
---------- ---------- ---------- ---------- ----------
Total Earnings $2,698,093 $2,820,691 $2,665,554 $2,654,907 $2,388,143
========== ========== ========== ========== ==========
Fixed Charges:
Interest on long-
term debt $ 642,408 $ 696,765 $ 682,811 $ 677,476 $ 712,607
Interest on short-
term debt 87,819 61,182 77,760 110,982 108,869
Interest on capital
leases 1,737 1,737 1,737 1,737 1,737
---------- ---------- ---------- ---------- ----------
Total Fixed
Charges $ 731,964 $ 759,684 $ 762,308 $ 790,195 $ 823,213
========== ========== ========== ========== ==========
Ratios of Earnings to
Fixed Charges 3.69 3.71 3.50 3.36 2.90
- ---------------------------------------------------------------------------------------
Note: For the purpose of computing the Company's ratios of earnings to fixed charges,
"earnings" represent net income adjusted for the Company's equity in undistributed
earnings or loss of unconsolidated affiliates, income taxes and fixed charges
(excluding capitalized interest). "Fixed charges" consist of interest on short-term
and long-term debt (including amortization of bond premium, discount and expense; and
excluding interest on decommissioning trust funds [for which an equal amount of
interest income is recorded] and amortization of the gain or loss on reacquired debt
securities) and interest on capital leases (including capitalized interest).
</TABLE>
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<TABLE>
<CAPTION>
EXHIBIT 12.2
PACIFIC GAS AND ELECTRIC COMPANY AND SUBSIDIARIES
COMPUTATION OF RATIOS OF EARNINGS TO COMBINED FIXED CHARGES AND PREFERRED STOCK DIVIDENDS
- ---------------------------------------------------------------------------------------
Year ended December 31,
----------------------------------------------------------
(dollars in thousands) 1993 1992 1991 1990 1989
- ---------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Earnings:
Net income $1,065,495 $1,170,581 $1,026,392 $ 987,170 $ 900,628
Company's equity in
undistributed loss
(earnings) of
unconsolidated
affiliates - (3,349) 26,671 (2,799) (4,352)
Income tax expense 901,890 895,126 851,534 881,647 669,885
Net fixed charges 730,708 758,333 760,957 788,889 821,982
---------- ---------- ---------- ---------- ----------
Total Earnings $2,698,093 $2,820,691 $2,665,554 $2,654,907 $2,388,143
========== ========== ========== ========== ==========
Fixed Charges:
Interest on long-
term debt $ 642,408 $ 696,765 $ 682,811 $ 677,476 $ 712,607
Interest on short-
term debt 87,819 61,182 77,760 110,982 108,869
Interest on capital
leases 1,737 1,737 1,737 1,737 1,737
---------- ---------- ---------- ---------- ----------
Total Fixed Charges 731,964 759,684 762,308 790,195 823,213
---------- ---------- ---------- ---------- ----------
Preferred Stock Dividends:
Tax deductible dividends 4,814 5,136 5,136 5,136 5,136
Pretax earnings required
to cover non-tax
deductible preferred
stock dividend
requirements 108,937 130,147 154,404 175,881 167,440
---------- ---------- ---------- ---------- ----------
Total Preferred
Stock Dividends 113,751 135,283 159,540 181,017 172,576
---------- ---------- ---------- ---------- ----------
Total Combined Fixed
Charges and
Preferred Stock
Dividends $ 845,715 $ 894,967 $ 921,848 $ 971,212 $ 995,789
========== ========== ========== ========== ==========
Ratios of Earnings to
Combined Fixed
Charges and Preferred
Stock Dividends 3.19 3.15 2.89 2.73 2.40
- ---------------------------------------------------------------------------------------
Note: For the purpose of computing the Company's ratios of earnings to combined fixed
charges and preferred stock dividends, "earnings" represent net income adjusted for
the Company's equity in undistributed earnings or loss of unconsolidated affiliates,
income taxes and fixed charges (excluding capitalized interest). "Fixed charges"
consist of interest on short-term and long-term debt (including amortization of bond
premium, discount and expense; and excluding interest on decommissioning trust funds
[for which an equal amount of interest income is recorded] and amortization of the
gain or loss on reacquired debt securities) and interest on capital leases (including
capitalized interest). "Preferred stock dividends" represent the sum of requirements
for preferred stock dividends that are deductible for federal income tax purposes and
requirements for preferred stock dividends that are not deductible for federal income
tax purposes increased to an amount representing pretax earnings which would be
required to cover such dividend requirements.
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EXHIBIT 23
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation of our
report dated February 16, 1994, included as Appendix I to the Report on Form 8-K
dated February 25, 1994, into the Company's previously filed registration
statements as follows: (1) Form S-3 Registration Statement File No. 33-7542
(relating to the Company's Common Stock Shelf Program); (2) Form S-3
Registration Statement File No. 33-27010 (relating to the Company's Dividend
Reinvestment Plan); (3) Form S-3 Registration Statement File No. 33-64136
(relating to $2,000,000,000 aggregate principal amount of the Company's First
and Refunding Mortgage Bonds and Medium-Term Notes); (4) Form S-3 Registration
Statement File No. 33-50707 (relating to $1,500,000,000 aggregate principal
amount of the Company's First and Refunding Mortgage Bonds); (5) Form S-3
Registration Statement File No. 33-38334 (relating to 2,414,892 shares of the
Company's Common Stock); (6) Form S-8 Registration Statements File Nos.
33-36988 and 33-50601 (relating to the Company's Savings Fund Plan for
Employees); (7) Form S-8 Registration Statement File No. 33-23692 (relating to
the Company's 1986 Stock Option Plan); and (8) Form S-3 Registration Statement
File No. 33-62488 (relating to 10,000,000 shares of the Company's Redeemable
First Preferred Stock).
San Francisco, California
February 25, 1994
