1
EXHIBIT 13
SELECTED FINANCIAL DATA
PACIFIC GAS AND ELECTRIC COMPANY
1993 1992 1991 1990 1989
----------- ----------- ----------- ----------- -----------
(in thousands, except per share amounts)
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
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.
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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:
Diablo
Utility Canyon(1) Enterprises Total
------- --------- ----------- -------
(in millions, except per share amounts)
1993
Operating revenues
Electric $ 5,933 $1,933 $ - $ 7,866
Gas 2,465 - 251 2,716
------- ------ ------ -------
Total operating revenues 8,398 1,933 251 10,582
Operating expenses 7,335 1,225 259 8,819
------- ------ ------ -------
Operating income (loss) $ 1,063 $ 708 $ (8) $ 1,763
======= ====== ====== =======
Net income $ 552 $ 496 $ 17 $ 1,065
======= ====== ====== =======
Earnings per common share $ 1.18 $ 1.11 $ .04 $ 2.33
Total assets at year end $19,870 $6,250 $1,043 $27,163
1992
Operating revenues
Electric $ 5,966 $1,781 $ - $ 7,747
Gas 2,340 - 209 2,549
------- ------ ------ -------
Total operating revenues 8,306 1,781 209 10,296
Operating expenses 7,125 1,118 220 8,463
------- ------ ------ -------
Operating income (loss) $ 1,181 $ 663 $ (11) $ 1,833
======= ====== ====== =======
Net income (loss) $ 738 $ 443 $ (10) $ 1,171
======= ====== ====== =======
Earnings (loss) per
common share $ 1.61 $ .99 $ (.02) $ 2.58
Total assets at year end $17,759 $5,494 $ 935 $24,188
1991
Operating revenues
Electric $ 5,868 $1,501 $ - $ 7,369
Gas 2,336 - 73 2,409
------- ------ ------ -------
Total operating revenues 8,204 1,501 73 9,778
Operating expenses 6,953 1,004 108 8,065
------- ------ ------ -------
Operating income (loss) $ 1,251 $ 497 $ (35) $ 1,713
======= ====== ====== =======
Net income (loss) $ 777 $ 274 $ (25) $ 1,026
======= ====== ====== =======
Earnings (loss) per common share $ 1.71 $ .59 $ (.06) $ 2.24
Total assets at year end $16,440 $5,543 $ 918 $22,901
(1) See Note 3 of Notes to Consolidated Financial Statements for discussion of
allocations.
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:
Year ended
December 31, 1993
-----------------------
(in millions)
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
====
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
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF CONSOLIDATED RESULTS OF
OPERATIONS AND FINANCIAL CONDITION (continued)
PACIFIC GAS AND ELECTRIC COMPANY
rate base on which PG&E is allowed to earn a return, as provided in the
1993 General Rate Case (GRC). This increase was offset by a decrease in
revenues resulting from a decrease in the cost of electric energy. In addition,
Diablo Canyon revenues, which are included in the electric revenues discussed
above, increased due to the annual increase in the price per kWh as provided in
the Diablo Canyon rate case settlement.
The increase in 1992 electric revenues was primarily due to one
scheduled refueling outage at Diablo Canyon in 1992, compared to two scheduled
refueling outages in 1991, and the annual increase in the price per kWh as
provided in the Diablo Canyon rate case settlement.
Gas revenues increased $167 million and $140 million in 1993 and 1992,
respectively, compared to the preceding year. The 1993 increase was primarily
due to rate increases associated with general increases in operating expenses
and a higher gas rate base on which PG&E is allowed to earn a return, as
provided in the 1993 GRC, as well as increased revenues from Enterprises
reflecting increases in the price and production of gas.
The 1992 increase was primarily due to revenues resulting from the
December 1991 acquisition of Tex/Con Oil & Gas Company (Tex/Con) by PG&E
Resources Company (Resources), a wholly owned subsidiary of Enterprises.
OPERATING EXPENSES: In 1993 and 1992, the Company's operating expenses
increased $356 million and $398 million, respectively, over the preceding year.
The 1993 increase was due to a charge against earnings of $190 million related
to the Company's workforce reduction program and increases in administrative
and general expense, income tax expense, and depreciation and decommissioning
expense of $114 million, $100 million and $94 million, respectively, offset by
a decrease of $166 million in the cost of electric energy. Most of the increase
in administrative and general expense was due to an increase in litigation
costs and an increase in employee costs upon adoption of Statement of Financial
Accounting Standards (SFAS) No. 106, "Employers' Accounting for Postretirement
Benefits Other Than Pensions." The increase in income tax expense was primarily
due to the increase in the federal income tax rate to 35% from 34%, and a
related adjustment to Diablo Canyon deferred income tax liability, as required
under SFAS No. 109, "Accounting for Income Taxes." The increase in depreciation
and decommissioning expense was a result of an increase in depreciation expense
related to the increase in plant in service. The decrease in the cost of
electric energy was a result of improved hydroelectric conditions and reflects
a decline in the cost per kWh for purchased power and a reduction in the volume
of gas used to provide electric energy.
The 1992 increase in operating expenses was primarily due to increase
in the cost of gas, the cost of electric energy, and depreciation and
decommissioning expense. The cost of gas increased in 1992 by $103 million over
the preceding year, primarily due to an increase in the cost of gas purchased
on behalf of, and transported for, noncore customers. The cost of electric
energy increased $98 million in 1992 compared to 1991, primarily due to
increases in the cost of purchased power and natural gas. The $81 million
increase in depreciation and decommissioning expense reflects an increase in
depreciation expense related to the increase in plant in service.
OTHER INCOME AND (INCOME DEDUCTIONS): Total other income was $74 million, $124
million and $95 million for 1993, 1992 and 1991, respectively.
Allowance for equity funds used during construction was $42 million,
$39 million and $25 million for 1993, 1992 and 1991, respectively. The
increases in 1993 and 1992 compared to the preceding year were primarily due to
the PGT-PG&E Pipeline Expansion Project which was put in service in November
1993.
Other -- net for 1993 includes amounts recorded for the gas
decontracting costs, losses on long-term commitments for gas transportation
capacity and a possible disallowance in connection with gas reasonableness
proceedings as discussed in the Natural Gas Matters section.
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Other -- net for 1992 included a $19 million after-tax gain from the
sale by Pacific Gas Transmission Company (PGT), a wholly owned gas pipeline
subsidiary of the Company, of its 49.98% interest in Alberta Natural Gas
Company Ltd (ANG). Other -- net for 1992 also reflects the establishment of new
accounting guidelines for the recognition of revenues related to customer
energy efficiency programs, which resulted in a $25 million decrease in the
amount of income recognized in 1992 compared to 1991.
Included in 1991 other -- net is the write-off by ANG of its investment
in a magnesium metal production facility project in Alberta, Canada. This
write-off resulted in a $26 million after-tax charge.
DIABLO CANYON: The Diablo Canyon rate case settlement, which became
effective July 1988, bases revenues for the plant primarily on the amount of
electricity generated, rather than on traditional cost-based ratemaking. Under
this "performance-based" approach, the Company assumes a significant portion of
the operating risk of the plant because the extent and timing of the recovery
of actual operating costs, depreciation and a return on the investment in the
plant primarily depend on the amount of power produced and the level of costs
incurred. The Company's earnings are affected directly by plant performance and
costs incurred.
Diablo Canyon revenues are based primarily on a pre-established price per kWh
consisting of a fixed component and an escalating component of electricity
generated by the plant. (Pricing for Diablo Canyon is discussed in Note 3 of
Notes to Consolidated Financial Statements.) From the revenues received for
Diablo Canyon, the Company must recover the costs of owning and operating the
plant, including all future capital additions. If power generation drops below
specified capacity levels, the Company may request floor payments which ensure
that the Company will receive some revenue, even if the plant stops producing
power. However, payments received must be refunded to customers under specified
conditions. Decommissioning and certain specific costs will continue to be
recovered through base rates and are not subject to plant performance.
The plant capacity factors for 1993 and 1992 were 89% and 88%,
respectively, reflecting the scheduled refueling outage for Unit 2 in 1993 and
Unit 1 in 1992. There were no extended unscheduled outages in 1993 and 1992.
Through December 31, 1993, the lifetime capacity factor for the plant was 79%.
The Company will report significantly lower revenues for the plant during any
extended outages, including refueling outages. Refueling outages, the lengths
of which depend on the scope of the work, typically occur for each unit every
eighteen months. Refueling outages for Unit 1 and Unit 2 are scheduled to begin
in March 1994 and September 1994, respectively, and each is planned to last
about nine weeks.
Each Diablo Canyon unit will contribute approximately $3.1 million in
revenues per day at full operating power in 1994. Beginning in 1995 and
thereafter, the escalating component in the price of Diablo Canyon power
provided by the settlement agreement will be based on a formula that will be
adjusted by the change in the consumer price index plus 2.5%, divided by two.
This could slow the rate of future earnings growth from the plant.
WORKFORCE REDUCTION PROGRAM: In the first quarter of 1993, the Company
announced a corporate reorganization and workforce reduction program. As of
December 31, 1993, the Company has recorded workforce reduction program costs
of $264 million, net of a curtailment gain relating to pension benefits. In
April 1993, the Company announced a freeze on electric rates through 1994. As a
result, the Company has expensed $190 million of such costs relating to
electric operations. The remaining $74 million of such costs relating to gas
operations has been deferred for future rate recovery. The amount deferred is
currently being amortized as savings are realized. The Company is seeking rate
recovery of all costs incurred in connection with the workforce reduction
program relating to electric and gas operations.
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF CONSOLIDATED RESULTS OF
OPERATIONS AND FINANCIAL CONDITION (continued)
PACIFIC GAS AND ELECTRIC COMPANY
During 1994 and 1995, the Company expects to benefit from the expense
reduction attributable to the electric operations' workforce reduction. The
Company currently estimates that the workforce reduction program will result in
a net revenue requirement savings of approximately $170 million during the
three-year 1993 GRC cycle, which ends December 31, 1995. Beginning in 1996, the
workforce reduction program is expected to result in annual revenue requirement
savings of at least $200 million. (See Note 8 of Notes to Consolidated
Financial Statements for further discussion of the workforce reduction
program.)
ELECTRIC RATE INITIATIVE: In April 1993, the Company proposed a
comprehensive electric rate initiative to freeze current retail electric rates
through the end of 1994 and to reduce electric rates by $100 million for major
businesses as an economic stimulus for those customers. In June 1993, the
California Public Utilities Commission (CPUC) approved the economic stimulus
rate, effective for the period July 1993 through December 1994.
In December 1993, the CPUC approved the electric rate freeze and issued
its decision in the Company's Attrition Rate Adjustment (ARA) and the Energy
Cost Adjustment Clause (ECAC) proceedings. As part of the ECAC decision, the
CPUC approved the Company's request to defer beyond 1994 recovery of a portion
of the undercollections in the ECAC balancing account. The total
undercollection at December 31, 1993, was $427 million.
Pursuant to the electric rate initiative, the effects of the CPUC
decisions on the Company's various electric rate proceedings (including the
cost of capital proceeding discussed in the Liquidity and Capital Resources
section) were consolidated resulting in a net change in electric rates of zero,
effective January 1994.
The Company intends to achieve cost reductions to offset revenue
reductions due to the economic stimulus rate. To the extent that these cost
reductions are not achieved, there would be a negative impact on the Company's
1994 results of operations.
COMPETITION: The Company is currently experiencing increasing
competition in both the gas and electric energy markets. In recent years,
changes in governmental regulations, new technology, interest in
self-generation and cogeneration, and competition from nonutility and
nonregulated energy suppliers have provided many major utility customers with
alternative sources to satisfy their gas and electric requirements.
The recent restructuring of the natural gas industry has increased
competition. As a result of regulatory changes, the Company no longer provides
combined purchase and transportation services to many of its industrial and
large commercial customers (noncore customers). Instead, many noncore customers
now purchase gas supplies directly from gas shippers or producers, reserve
interstate transportation capacity directly from interstate pipelines, and then
purchase intrastate transportation service from the Company once their gas
arrives at the California border. Furthermore, an interstate pipeline has
proposed expanding its facilities into the Company's service territory which,
if approved, would allow it to compete directly for intrastate transportation
service to the Company's noncore customers. To the extent that regulators
approve this pipeline, the Company could lose customers and volume on its gas
transportation system.
The restructuring of the natural gas industry has had a significant
impact on the Company's gas operations. In 1993, the Company terminated its
long-term Canadian gas purchase contracts and has entered into new, more
flexible arrangements for the purchase of the Company's current lower gas
supply requirements. In addition, the Company is continuing its efforts to
permanently assign or broker its commitments for firm gas transportation
capacity which it once held for its noncore customers. As a result of these
changes, the Company has recorded reserves in 1993 for its transportation
commitments. (See Natural Gas Matters section and Note 2 of Notes to
Consolidated Financial Statements for further discussion of regulatory
restructuring and the impact on the Company's gas purchase and transportation
commitments.)
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While the restructuring of the electric industry is still evolving,
proposals being considered at state and federal levels and the recently enacted
National Energy Policy Act of 1992 (Act) are expected to bring more competition
into the electric generation business. The Company currently purchases
approximately one-third of the electrical power supplied to its customers from
generation sources outside the Company's service territory and from qualifying
facilities owned and operated by independent power producers. (Qualifying
facilities are small power producers or cogenerators that meet certain federal
guidelines and thereby qualify to supply generating capacity and electric
energy to electric utilities, which must purchase this power at prices approved
by state regulatory bodies.) Future additions to satisfy electric supply needs
in the Company's service territory will be determined largely through a
competitive resource procurement process, a feature of the new competitive
market for electric generation. The Company has indicated a willingness to
forgo building new generation capacity in its service territory if appropriate
regulatory reforms are instituted in the energy procurement process to provide
increased procurement flexibility.
With its enactment, the Act reduces various restrictions on the
operation and ownership of independent power producers and provides them and
other wholesale suppliers and purchasers with increased access to electric
transmission lines throughout the United States. The Federal Energy Regulatory
Commission (FERC) now has increased authority to order a utility to transport
and deliver, or "wheel," energy for wholesale purchasers or sellers of power.
While the Act prohibits FERC-ordered retail wheeling, it does not address the
states' ability to order retail wheeling. If future restructuring were to
include retail wheeling whereby customers purchase energy directly from an
independent power producer and separately pay the Company to wheel the
purchased power, the Company's power generation plants and resources would be
subject to competition from other available supply options.
Under current regulation, customer prices are based on an allocation
among customer classes of the Company's approved cost of service revenue
requirements. Currently, large industrial and commercial customers are the most
likely to have lower cost competitive alternatives. If a substantial number of
these customers were to leave the system, the Company's recovery of its
investment in production sources and distribution facilities would be dependent
on prices charged to remaining customers and the Company's ability to reduce
costs. This could lead to lower shareholder returns.
To succeed in this more competitive environment, the Company has taken
steps in 1993 to improve service to customers, reduce costs and lower the price
of gas and electric service. The Company has:
1) Reduced its workforce by approximately 3,000 positions which
will result in net revenue requirement savings of approximately $170
million during the three-year 1993 GRC cycle and annual revenue
requirement savings of at least $200 million beginning in 1996. (See
the Workforce Reduction Program section and Note 8 of Notes to
Consolidated Financial Statements for further discussion of the
workforce reduction program.)
2) Reduced its cost of capital by taking advantage of
significantly lower interest rates to reduce financing costs. (See the
Sources of Capital section for further discussion of debt refinancing.)
3) Obtained CPUC approval to freeze current electric rates
through the end of 1994 and to reduce electric rates by $100 million
for major businesses over an 18-month period beginning in July 1993.
(See the Electric Rate Initiative section for further discussion of the
electric rate initiative.)
4) Begun discussions with the CPUC, customers and other
interested parties on the Company's regulatory reform initiative which,
in part, would allow the Company more flexibility to respond to
competitive conditions quickly. (See the Regulatory Reform Initiative
section for further discussion of the regulatory reform initiative.)
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF CONSOLIDATED RESULTS OF
OPERATIONS AND FINANCIAL CONDITION (continued)
PACIFIC GAS AND ELECTRIC COMPANY
5) Given discounts on its gas transportation contracts for certain
major industrial customers to obtain long-term commitments. To date, customers
entering into these contracts represent approximately 12 percent of total
noncore transportation volume.
Further, the Company continues to pursue improvements in the efficiency
and productivity of its operations and is committed to sustaining high levels
of customer service.
REGULATORY REFORM INITIATIVE: In February 1993, the CPUC's Division of
Strategic Planning issued its report on electric industry restructuring, which
concluded that the current regulatory approach is incompatible with the
emerging industry structure resulting from technological change, competitive
pressure and new market forces. The CPUC has several proceedings in progress
in which it is investigating reform proposals. The Company has begun
discussions with the CPUC, customers and other interested parties concerning
various reforms to the current regulatory approach to setting rates. Under the
traditional regulatory approach, rates generally are based on a detailed
examination of the utility's costs of providing service plus a reasonable rate
of return. The resulting amount is the utility's revenue requirement, which the
Company is permitted to recover in rates. Under the approach being explored by
the Company, the Company's revenue requirement would be adjusted annually on
the basis of a series of market indices, such as inflation and customer growth,
and a productivity factor designed to reflect cost savings from increased
efficiency. The Company and its customers would share in savings or excess
costs.
This approach would act as a surrogate for detailed cost examinations
and would be used to determine the Company's base revenues, intended to recover
the Company's fixed costs and nonfuel variable costs and to provide a return on
invested capital. Fuel procurement incentives also could be implemented for the
Company's gas purchases for core portfolio customers and power plant fuel. This
approach would use market-based benchmarks to determine the amount of revenues
which the Company could recover to offset these costs, replacing the current
after-the-fact reasonableness reviews of those costs by the CPUC.
As part of the Company's proposal for its largest electric customers,
the Company is seeking to have increased flexibility to provide discounts and
tailor its services to these customers while assuming the risk for decreases in
revenues. This change in the cost of service rate approach could result in a
change in accounting principle for this customer class. If the accounting
criteria applicable to cost of service rate regulation are no longer met, then
the Company would write off the allocable share of regulatory assets, including
regulatory balancing accounts receivable and those regulatory assets included
in deferred charges.
The Company intends to solicit comments from the CPUC, customers and
other interested parties and to file a formal application with the CPUC in the
first quarter of 1994, with implementation proposed for 1995. To the extent
that regulators approve the Company's regulatory reform initiative, changes may
occur to the current regulatory framework as discussed below in the Regulatory
Matters section.
ACCOUNTING FOR THE EFFECTS OF REGULATION: Based on the regulatory framework in
which it operates, the Company currently accounts for the economic effects of
regulation in accordance with the provisions of SFAS No. 71, "Accounting for
the Effects of Certain Types of Regulation." The Company is exploring
regulatory reforms and expects to file a formal application with the CPUC in
1994. (See the Regulatory Reform Initiative section for further discussion.)
If the regulatory reforms contemplated by the Company are adopted, the
mechanics of the rate setting process would change. The Company anticipates
that rates derived from the regulatory reforms would remain based on cost of
service. However, the final determination will be dependent upon the regulatory
reform initiative that is ultimately adopted.
In the event that recovery of costs through rates becomes unlikely or
uncertain, whether resulting from the expanding effects of competition or
specific regulatory actions which force the Company away from cost of service
ratemaking, SFAS No. 71 would no longer apply. If the Company were to
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discontinue application of SFAS No. 71 for some or all of its operations, then
it would write off the applicable portion of regulatory assets, including
regulatory balancing accounts receivable and those regulatory assets included
in deferred charges. The financial effects upon discontinuing application of
SFAS No. 71 could be significant.
REGULATORY MATTERS: The Company's electric and gas energy prices are regulated
primarily by the CPUC. Base rates compensate the Company for operating and
maintenance costs, depreciation and taxes, and provide a return on capital.
Base rates are set every three years in GRC proceedings. The base rates for
1993 were established in the 1993 GRC. Between rate cases, the ARA mechanism
provides for rate adjustments for inflation, changes in rate base and changes
in the authorized cost of capital.
Balancing accounts help stabilize the Company's earnings. The CPUC sets
rates based on estimates of future revenues and costs; differences between
revenues or energy costs authorized by the CPUC and actual revenues or energy
costs are accumulated in the balancing accounts for subsequent rate adjustment.
Energy cost balancing accounts (which include ECAC) reduce the effect on
earnings of fluctuations in most electric energy and gas costs. Sales balancing
accounts (which include Electric Revenue Adjustment Mechanism) reduce the
effect on earnings of fluctuations in most sales to electric and gas customers.
Both the ARA mechanism and the energy cost balancing accounts limit the
effect of inflation on the Company's earnings from utility operations by
closely matching rates with costs.
The regulatory framework for natural gas service (1) segments the
Company's gas customers into core (residential and small commercial customers)
and noncore classes, (2) provides noncore customers with options in procuring
their own gas supplies, (3) allows noncore customers to negotiate interstate
gas transportation directly with the interstate pipelines and separately
negotiate intrastate gas transportation with their utilities, and (4) places
the Company's noncore transportation revenues at increased risk due to
competitive alternatives.
Gas cost allocation proceedings allocate forecasted costs between core
and noncore customers and set associated rates. This ratemaking mechanism
covers a two-year forecast period and includes a balancing account which allows
the Company to accumulate 75% of the difference between authorized and actual
noncore transportation revenues. Prior to the establishment of the 75%
balancing account in May 1992, a 90% balancing account was in effect. As a
result, this placed the Company's noncore gas transportation revenues at
increased risk to the extent authorized revenues differ from actual.
NATURAL GAS MATTERS: Decontracting Plan: As discussed in Note 2 of Notes to
Consolidated Financial Statements, regulatory changes have restructured the
natural gas industry. Certain Canadian gas producers filed lawsuits against
the Company claiming damages of at least $466 million (Canadian) resulting
from the alleged failure of Alberta and Southern Gas Co. Ltd. (A&S), a wholly
owned subsidiary of the Company, to meet its minimum contractual gas purchase
obligations. A&S, PGT, PG&E and approximately 190 Canadian gas producers
subsequently entered into agreements (collectively, the Decontracting Plan)
that restructured the Company's Canadian gas supply arrangements. The
Decontracting Plan, which became effective November 1, 1993, terminated A&S's
contracts with Canadian gas producers and settled all litigation and claims
arising from such contracts. The total amount of settlement payments paid to
Canadian gas producers pursuant to the Decontracting Plan was approximately
$210 million.
In July 1993, FERC approved a transition cost recovery mechanism (TCRM)
under which PGT will absorb 25% of approved transition costs, including
settlement payments incurred in connection with the termination of A&S's
contracts, with the remainder of such costs to be recovered from PGT's
shippers.
The Company incurred transition costs of $228 million, consisting of
settlement payments made to producers in connection with the implementation of
the Decontracting Plan and amounts incurred by A&S in reducing certain
administrative and general functions resulting from the restructuring.
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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
10
current assessment of the matter, the Company recorded a reserve of $61
million in 1993 for any disallowance that may be ordered by the CPUC in the gas
reasonableness proceedings. The Company currently is unable to estimate the
ultimate outcome of the gas reasonableness proceedings or predict whether such
outcome will have a significant adverse impact on its financial position or
results of operations. (See Note 2 of Notes to Consolidated Financial
Statements for further discussion of gas reasonableness proceedings.)
PGT-PG&E Pipeline Expansion Project: In November 1993, the Company placed in
service an expansion of its natural gas transmission system from the Canadian
border into California. At December 31, 1993 and 1992, the Company's total
investment in the expansion project was approximately $1,587 million (included
in plant in service) and $979 million (included in construction work in
progress), respectively. The $1,587 million at December 31, 1993, consisted of
$767 million for the facilities within California (i.e., intrastate portion)
and $820 million for the facilities outside California (i.e., interstate
portion).
In February 1994, the CPUC announced a decision on the Company's
request for an increase in the California portion of the expansion project's
cost cap and its interim rate filing. The CPUC granted the Company's request to
increase the cost cap to $849 million but set interim rates based on $736
million, subject to an adjustment based on the outcome of a reasonableness
review of capital costs. The CPUC's decision finds that, given market
conditions at the time, the Company was reasonable in constructing the
expansion project. The CPUC rejected the assignment of costs related to unused
capacity on other pipelines (or the Company's intrastate facilities) to the
expansion project as previously recommended by an ALJ's proposed decision.
Due to the ratemaking treatment adopted by the CPUC for the California
portion of the expansion project, the Company's ability to recover its cost of
service rates is contingent upon demand and competitive market pricing for gas
transportation services. In light of anticipated demand and pricing in the
foreseeable future, the Company has determined that it may not bill its
customers to recover its full cost of service (including a return on
investment). Consequently, application of SFAS No. 71 was discontinued for the
California portion of the expansion project during 1993. This accounting change
did not have a significant impact on the Company's financial position or
results of operations in 1993.
Based upon the current status of the rate case and market demand, the
Company believes it will recover its investment in the expansion project.
However, due to the ratemaking adopted by the CPUC and the discontinued
application of SFAS No. 71, earnings attributable to the California portion of
the expansion project will vary with demand and market pricing. (See the
PGT-PG&E Pipeline Expansion Project section of Note 2 of Notes to Consolidated
Financial Statements for further discussion.)
LEGAL MATTERS: Antitrust Litigation: In December 1993, the County of
Stanislaus, California, and a residential customer of PG&E, filed a complaint
against PG&E and PGT on behalf of themselves and purportedly as a class action
on behalf of all natural gas customers of PG&E, for the period of February 1988
through October 1993. The complaint alleges that the purchase of natural gas in
Canada by A&S was accomplished in violation of various antitrust laws which
resulted in increased prices of natural gas for PG&E's customers.
The complaint alleges that the Company could have purchased as much as
50% of its Canadian gas on the spot market instead of relying on long-term
contracts and that the damage to the class members is at least as much as the
price differential multiplied by the replacement volume of gas, an amount
estimated in the complaint as potentially exceeding $800 million. The complaint
indicates that the damages to the class could include over $150 million paid by
the Company to terminate the contracts with the Canadian gas producers in
November 1993. The complaint also seeks recovery
21
11
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
12
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:
Utility
Capital Weighted
Structure Cost Cost
--------- ----- --------
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%
====
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
13
MANAGEMENT'S DISCUSSION AND ANALYSIS OF CONSOLIDATED RESULTS OF OPERATIONS AND
FINANCIAL CONDITION (continued)
PACIFIC GAS AND ELECTRIC COMPANY
CAPITAL REQUIREMENTS: The Company's three-year projection of capital
requirements is shown below:
Year ended December 31,
------------------------------
1994 1995 1996
------ ------ ------
(in millions)
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
====== ====== ======
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
14
STATEMENT OF CONSOLIDATED INCOME
PACIFIC GAS AND ELECTRIC COMPANY
Year ended December 31,
------------------------------------------
1993 1992 1991
----------- ----------- ----------
(in thousands, except per share amounts)
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
The accompanying Notes to Consolidated Financial Statements are an
integral part of this statement.
25
15
CONSOLIDATED BALANCE SHEET
PACIFIC GAS AND ELECTRIC COMPANY
December 31,
-----------------------------
1993 1992
------------ -----------
(in thousands)
A S S E T S
Plant In Service
Electric
Nonnuclear $ 16,633,772 $ 16,295,567
Diablo Canyon 6,518,413 5,983,976
Gas 7,146,741 5,454,084
------------ ------------
Total plant in service (at original cost) 30,298,926 27,733,627
Accumulated depreciation and decommissioning (11,235,519) (10,507,560)
------------ ------------
Net plant in service 19,063,407 17,226,067
------------ ------------
Construction Work in Progress 620,187 1,534,578
Other Noncurrent Assets
Oil and gas properties 573,523 591,544
Decommissioning and other funds held
by trustees 536,544 456,061
Other assets 497,689 402,041
------------ ------------
Total other noncurrent assets 1,607,756 1,449,646
------------ ------------
Current Assets
Cash and cash equivalents 61,066 97,592
Accounts receivable
Customers 1,264,907 1,319,285
Other 123,255 133,826
Allowance for uncollectible accounts (23,647) (23,806)
Regulatory balancing accounts receivable 992,477 743,253
Inventories
Materials and supplies 239,856 234,630
Gas stored underground 170,345 151,707
Fuel oil 109,615 155,816
Nuclear fuel 134,411 135,171
Prepayments 56,062 47,809
------------ ------------
Total current assets 3,128,347 2,995,283
------------ ------------
Deferred Charges
Income tax-related deferred charges 1,246,890 -
Diablo Canyon costs 419,775 260,042
Unamortized loss net of gain on reacquired debt 395,659 289,338
Workers' compensation and disability
claims recoverable 192,203 174,168
Other 488,302 259,037
------------ ------------
Total deferred charges 2,742,829 982,585
------------ ------------
Total Assets $ 27,162,526 $ 24,188,159
============ ============
The accompanying Notes to Consolidated Financial Statements are an integral part
of this statement.
26
16
CONSOLIDATED BALANCE SHEET
PACIFIC GAS AND ELECTRIC COMPANY
CAPITALIZATION AND LIABILITIES
December 31,
---------------------------
1993 1992
----------- -----------
(in thousands)
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
=========== ===========
27
17
STATEMENT OF CONSOLIDATED CASH FLOWS
PACIFIC GAS AND ELECTRIC COMPANY
Year ended December 31,
--------------------------------------------------------
1993 1992 1991
----------- ----------- -----------
(in thousands)
Cash Flows From Operating Activities $ 1,065,495 $ 1,170,581 $ 1,026,392
Net income
Adjustments to reconcile net income to net cash
provided by operating activities
Depreciation and decommissioning 1,315,524 1,221,490 1,140,877
Amortization 135,808 121,795 103,923
Gain on sale of investment in Alberta Natural
Gas Company Ltd - (48,722) -
Deferred income taxes and investment tax
credits -- net 319,198 164,457 60,376
Allowance for equity funds used during
construction (41,531) (39,368) (24,543)
Net effect of changes in operating assets
and liabilities
Accounts receivable 64,790 39,922 (69,076)
Regulatory balancing accounts receivable (218,553) (215,195) 202,401
Inventories 23,097 (7,161) (7,440)
Accounts payable (39,422) (102,559) 172,245
Accrued taxes 44,638 128,243 35,977
Other working capital 108,873 (36,117) 36,784
Other deferred charges (158,725) 8,147 (68,905)
Other noncurrent liabilities 50,279 31,374 75,889
Other deferred credits 110,145 73,259 9,795
Other -- net 13,184 49,891 30,382
----------- ----------- -----------
Net cash provided by operating activities 2,792,800 2,560,037 2,725,077
----------- ----------- -----------
Cash Flows From Investing Activities
Construction expenditures (1,763,024) (2,307,318) (1,753,609)
Allowance for borrowed funds used during
construction (78,626) (44,217) (17,574)
Purchase of subsidiary - - (388,662)
Nonregulated expenditures (234,221) (148,226) (117,847)
Proceeds from sale of investment in Alberta
Natural Gas Company Ltd - 97,251 -
Other -- net 9,992 82,352 33,156
----------- ----------- -----------
Net cash used by investing activities (2,065,879) (2,320,158) (2,244,536)
----------- ----------- -----------
Cash Flows From Financing Activities
Common stock issued 264,489 296,653 271,482
Common stock repurchased (257,780) (5,410) (337,969)
Preferred stock issued 200,001 195,451 -
Preferred stock redeemed (302,640) (276,806) (123,667)
Long-term debt issued 4,584,548 1,676,513 738,649
Long-term debt matured or reacquired (4,002,704) (1,409,337) (263,220)
Short-term debt issued (redeemed) -- net (366,961) 121,213 (14,278)
Dividends paid (857,515) (809,108) (765,543)
Other -- net (24,885) (28,736) 10,075
----------- ----------- -----------
Net cash used by financing activities (763,447) (239,567) (484,468)
----------- ----------- -----------
Net Change in Cash and Cash Equivalents (36,526) 312 (3,927)
Cash and Cash Equivalents at January 1 97,592 97,280 101,207
----------- ----------- -----------
Cash and Cash Equivalents at December 31 $ 61,066 $ 97,592 $ 97,280
=========== =========== ===========
Supplemental disclosures of cash flow information
Cash paid for
Interest (net of amounts capitalized) $ 642,712 $ 694,512 $ 723,968
Income taxes 542,827 682,809 768,097
The accompanying Notes to Consolidated Financial Statements are
an integral part of this statement.
28
18
STATEMENT OF CONSOLIDATED COMMON STOCK EQUITY AND PREFERRED STOCK
PACIFIC GAS AND ELECTRIC COMPANY
Preferred
Stock
Total Without
Additional Common Mandatory
Common Paid-in Reinvested Stock Redemption
Stock Capital Earnings Equity Provision Provision(1)
---------- ---------- ---------- ----------- ---------- ------------
(in thousands, except shares)
Balance December 31, 1990 $2,101,095 $3,170,890 $2,234,227 $7,506,212 $ 983,961 $129,510
---------- ---------- ---------- ---------- --------- --------
Net income - 1991 1,026,392 1,026,392
Common stock issued (10,263,302 shares) 51,317 220,165 271,482
Common stock repurchased (12,910,487 shares) (64,553) (98,455) (174,961) (337,969)
Preferred stock redeemed (3,811,325 shares) (5,287) (4,438) (9,725) (89,064) (24,878)
Cash dividends declared
Preferred stock (91,501) (91,501)
Common stock (685,341) (685,341)
Other 1,774 1,774
---------- ---------- ---------- ---------- --------- --------
Net change (13,236) 116,423 71,925 175,112 (89,064) (24,878)
---------- ---------- ---------- ---------- --------- --------
Balance December 31, 1991 2,087,859 3,287,313 2,306,152 7,681,324 894,897 104,632
---------- ---------- ---------- ---------- --------- --------
Net income - 1992 1,170,581 1,170,581
Common stock issued (9,453,353 shares) 47,267 249,386 296,653
Common stock repurchased (179,610 shares) (898) (2,450) (2,062) (5,410)
Preferred stock issued (8,000,000 shares) (4,549) (4,549) 125,000 75,000
Preferred stock redeemed (9,365,449 shares) (12,638) (14,940) (27,578) (229,106) (20,122)
Cash dividends declared
Preferred stock (81,393) (81,393)
Common stock (744,277) (744,277)
Other (2,214) (2,214)
---------- ---------- ---------- ---------- --------- --------
Net change 46,369 229,749 325,695 601,813 (104,106) 54,878
---------- ---------- ---------- ---------- --------- --------
Balance December 31, 1992 2,134,228 3,517,062 2,631,847 8,283,137 790,791 159,510
---------- ---------- ---------- ---------- --------- --------
Net income - 1993 1,065,495 1,065,495
Common stock issued (7,708,512 shares) 38,541 225,948 264,489
Common stock repurchased (7,334,876 shares) (36,674) (63,180) (157,926) (257,780)
Preferred stock issued (8,000,000 shares) 200,001
Preferred stock redeemed (8,156,968 shares) (13,375) (21,958) (35,333) (182,797) (84,510)
Cash dividends declared
Preferred stock (62,521) (62,521)
Common stock (811,196) (811,196)
Other (254) (254)
---------- ---------- ---------- ---------- --------- --------
Net change 1,867 149,393 11,640 162,900 17,204 (84,510)
---------- ---------- ---------- ---------- --------- --------
Balance December 31, 1993 $2,136,095 $3,666,455 $2,643,487 $8,446,037 $ 807,995 $ 75,000
========== ========== ========== ========== ========= ========
(1) Includes current portion.
The accompanying Notes to Consolidated Financial Statements are an integral part of this statement.
29
19
STATEMENT OF CONSOLIDATED CAPITALIZATION
PACIFIC GAS AND ELECTRIC COMPANY
December 31,
-------------------------------
1993 1992
------------- ------------
(dollars in thousands,
except per share amounts)
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
=========== ===========
(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
20
SCHEDULE OF CONSOLIDATED SEGMENT INFORMATION
PACIFIC GAS AND ELECTRIC COMPANY
Diversified Intersegment
Electric Gas Operations(4) Eliminations Total
----------- ---------- ------------- ------------ ------------
(in thousands)
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
=========== ========== ========== ========= ===========
(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
21
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
PACIFIC GAS AND ELECTRIC COMPANY
Note 1 -- Summary of Significant Accounting Policies
- ----------------------------------------------------
REGULATION: Pacific Gas and Electric Company (PG&E) is regulated by the
California Public Utilities Commission (CPUC) and the Federal Energy
Regulatory Commission (FERC). PG&E's consolidated financial statements reflect
the ratemaking policies of these commissions in conformity with generally
accepted accounting principles for rate-regulated enterprises. In the Notes to
Consolidated Financial Statements, regulated operations other than the Diablo
Canyon Nuclear Power Plant (Diablo Canyon) are referred to as the utility.
PRINCIPLES OF CONSOLIDATION: The consolidated financial statements include
PG&E and its wholly owned and majority-owned subsidiaries (the Company). All
significant intercompany transactions have been eliminated.
Major subsidiaries, all of which are wholly owned, are: Pacific Gas
Transmission Company (PGT) -- transports natural gas from the U.S./Canadian
border to PG&E at the California border; Alberta and Southern Gas Co. Ltd.
(A&S) -- prior to November 1, 1993, bought gas in Canada and arranged transport
to the U.S. border (see Note 2 for discussion of the restructuring of A&S's
operations); Pacific Energy Fuels Company -- finances the purchase of nuclear
fuel through issuance of its commercial paper; PG&E Enterprises (Enterprises)
- -- the parent company for nonregulated subsidiaries, including PG&E Resources
Company (Resources), which engages in exploration, development and production
of oil and natural gas, and PG&E Generating Company which develops independent
power projects.
Alberta Natural Gas Company Ltd (ANG), a 49.98%-owned affiliate of PGT,
was sold in June 1992. ANG, a Canadian pipeline company, transported natural
gas for A&S to the U.S. border. Prior to the sale of ANG, the Company's
investment in ANG was accounted for by the equity method of accounting.
REVENUES: Revenues are recorded primarily for deliveries of gas and electric
energy to customers. These revenues give rise to receivables from a diversified
base of customers including residential, commercial and industrial customers in
Northern and Central California.
The CPUC has established mechanisms known as balancing accounts which help
stabilize the Company's earnings. Specifically, sales balancing accounts
accumulate differences between authorized and actual base revenues. Energy cost
balancing accounts accumulate differences between actual costs of gas and
electric energy and the revenue designated for recovery of such costs. Recovery
of gas and electric energy costs through these balancing accounts is subject
to a reasonableness review by the CPUC. (See Note 2 for further discussion of
gas costs.) These balancing accounts are recorded to the extent that future
rate recovery from customers, or refunds to customers, are probable.
PLANT IN SERVICE: The costs of plant additions, including replacements of
retired plant, are capitalized. Costs include labor, materials, construction
overheads and an allowance for funds used during construction (AFUDC). AFUDC is
the cost of debt and equity funds used to finance the construction of new
facilities. Financing costs of capital additions for Diablo Canyon and the
California portion of the PGT-PG&E Pipeline Expansion Project are calculated
under Statement of Financial Accounting Standards (SFAS) No. 34,
"Capitalization of Interest Cost," since Diablo Canyon and the California
portion of the PGT-PG&E Pipeline Expansion Project are not on traditional
cost-based ratemaking. (See Notes 2 and 3 for further discussion of these
matters.) These costs are included in allowance for borrowed funds used during
construction. The original cost of retired plant plus removal costs less
salvage are charged to accumulated depreciation. Maintenance, repairs and minor
replacements and additions are charged to maintenance expense.
DEPRECIATION AND DECOMMISSIONING: Depreciation of plant in service is computed
using a straight-line remaining-life method.
The estimated cost of decommissioning the Company's nuclear power
facilities is recovered in base rates through an annual allowance. For the year
ended December 31, 1993, 1992 and 1991, the amounts recovered in rates for
decommissioning costs were $54 million, $54 million, and $65 million,
respectively. The estimated total obligation for decommissioning costs is
approximately $1 billion in 1993 dollars; this obligation is being recognized
ratably over the facilities' lives. This estimate considers the total costs of
decommissioning and dismantling plant systems and structures and includes a
contingency factor for possible changes in regulatory requirements and waste
disposal cost increases.
As of December 31, 1993 and 1992, the Company had accumulated in
external trust funds $537 million and $456 million, respectively, to be used
for the decommissioning of the Company's nuclear facilities; corresponding
amounts are thus included in accumulated depreciation and decommissioning.
These trust funds maintain substantially all of their investments in debt
securities. All fund earnings are reinvested. At December 31, 1993 and 1992,
the estimated fair
32
22
values of the external trust funds were approximately $576 million and
$475 million, respectively, based on quoted market prices. Funds may not be
released from the external trust funds until authorized by the CPUC.
As required by federal law, the U.S. Department of Energy (DOE)
is responsible for the future storage and disposal of spent nuclear fuel. The
cost of these activities is funded through a one-tenth of one cent fee on each
kilowatthour (kWh) sold by all nuclear power plants. This fee is paid quarterly
to the DOE.
INCOME TAXES: The Company files a consolidated federal income tax return that
includes domestic subsidiaries in which its ownership is 80% or more. Income
tax expense includes the current and deferred income tax expense resulting from
operations during the year. Investment tax credits are deferred and amortized
to income over the life of the related property.
Effective January 1, 1993, the Company adopted SFAS No. 109,
"Accounting for Income Taxes," which established new financial accounting
standards for income taxes. SFAS No. 109 prohibits net-of-tax accounting,
requires that deferred tax liabilities and assets be adjusted for enacted
changes in the income tax rates and requires the use of the liability method of
accounting for income taxes. Under the liability method, the deferred tax
liability represents the tax effect of temporary differences between the
financial statement and income tax bases of assets and liabilities at the
currently enacted income tax rates. Temporary differences are measured at the
balance sheet date, resulting in adjustments to the deferred tax liability and
related deferred charge, consistent with the ratemaking process.
The effect of the adoption of SFAS No. 109, as of January 1, 1993, was
an increase of $1.8 billion in consolidated liabilities as the result of
recording additional deferred taxes; consolidated assets also increased $1.8
billion, consisting of a $1.5 billion increase in deferred charges (income
tax-related deferred charges and Diablo Canyon costs) and a $.3 billion
increase in net plant in service. These adjustments relate to temporary
differences, which prior to adoption of SFAS No. 109 were not recorded as
deferred taxes, consistent with the ratemaking process. These differences
included removal costs and federal tax depreciation on property acquired prior
to 1981, depreciation differences for state purposes, percentage repair
allowances expensed for tax purposes and certain capitalized overheads expensed
for tax purposes. Due to current regulatory treatment, the adoption of SFAS No.
109 did not have a significant impact on the Company's results of operations.
During 1993, the Omnibus Budget Reconciliation Act of 1993 (Act) was
enacted, which included an increase in the corporate federal income tax rate to
35% from 34%. Due to current regulatory treatment, the Company recorded a
deferred charge for the adjustment of deferred income taxes related to utility
operations as a result of this increase. Since Diablo Canyon is not on
traditional cost-based ratemaking, a one-time adjustment to income tax expense
of $32 million resulted. The Act did not have a significant impact on the
Company's results of operations during 1993.
DEBT PREMIUM, DISCOUNT AND RELATED EXPENSE: Long-term debt premium,
discount and related expense are amortized over the life of each issue. Gains
and losses on reacquired debt allocated to the utility are amortized over the
remaining original lives of the debt reacquired, consistent with ratemaking;
gains and losses on debt allocated to Diablo Canyon and the California portion
of the PGT- PG&E Pipeline Expansion Project are recognized in income at the
time such debt is reacquired.
OIL AND GAS PROPERTIES: Resources uses the successful-efforts method of
accounting for oil and gas properties.
INVENTORIES: Nuclear fuel inventory is stated at the lower of average
cost or market. Amortization of fuel in the reactor is based on the amount of
energy output.
Other inventories are valued at average cost except for fuel oil, which is
valued by the last-in-first-out method.
STATEMENT OF CONSOLIDATED CASH FLOWS: Cash and cash equivalents (at
cost which approximates market) include special deposits, working funds and
short-term investments with original maturities of three months or less.
RECLASSIFICATIONS: Prior years' amounts in the consolidated financial
statements have been reclassified where necessary to conform to the 1993
presentation.
NOTE 2 -- Natural Gas Matters
- -----------------------------
REGULATORY RESTRUCTURING: The CPUC has established a regulatory
framework for natural gas service in California which segments customers into
core (residential and smaller commercial customers) and noncore (industrial and
commercial customers that exceed certain size limitations) classes. This
framework allows noncore customers to
33
23
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
PACIFIC GAS AND ELECTRIC COMPANY
purchase gas directly from producers, aggregators or marketers and
separately negotiate gas transportation with their utilities. The CPUC has also
adopted a capacity brokering program which allows noncore customers and other
shippers to obtain rights to firm interstate pipeline transportation capacity
held by the local gas distribution utilities. Under the capacity brokering
program implemented August 1, 1993, the Company is required to make available
for brokering all interstate pipeline capacity which is not retained for its
core customers and core subscription customers (noncore customers choosing
bundled service). Noncore customers, producers, aggregators, marketers and the
Company's electric department can bid for such capacity.
In addition, in April 1992, FERC issued Order 636 which requires
interstate pipelines to restructure their services. This order unbundled sales,
transportation and storage services, instituted capacity release programs and
provided for recovery of transition costs related to the restructuring of
services.
The Company's compliance with these regulatory changes has allowed many of the
Company's noncore customers to arrange for the purchase and transportation of
their own gas supplies. These changes have resulted in a decrease in the amount
of gas required to be purchased by the Company and a related decrease in the
need for firm transportation capacity and have contributed to the need to
restructure the Company's gas supply arrangements.
Decontracting Plan: Until November 1993, PG&E purchased Canadian
natural gas from PGT which in turn purchased such gas from A&S. A&S had
commitments to purchase minimum quantities of natural gas from approximately
190 Canadian gas producers under various long-term contracts, most of which
extended through 2005. Certain of these Canadian gas producers filed lawsuits
against the Company claiming damages of at least $466 million (Canadian)
resulting from the alleged failure of A&S to meet its minimum contractual gas
purchase obligations. As a result of the regulatory restructuring discussed
above, A&S, PGT, PG&E and approximately 190 Canadian gas producers entered into
agreements (collectively, the Decontracting Plan) which terminated A&S's
contracts with these Canadian gas producers and settled all litigation and
claims arising from such contracts. Under the Decontracting Plan which became
effective November 1, 1993, producers' contracts with A&S, the sales agreement
between A&S and PGT, and PG&E's service agreement with PGT were terminated,
allowing producers to decontract their reserves from the A&S supply pool. As a
result, PG&E may contract on an individual basis for its gas supply
requirements directly with any producer, aggregator or marketer, whether or not
they were formerly in the A&S supply pool.
Under the Decontracting Plan, producers released A&S, PGT and PG&E from
any claims they may have had that resulted from the termination of the former
arrangements as well as any claims for losses arising from alleged historical
shortfalls in gas taken by A&S. The total amount of settlement payments paid to
producers was approximately $210 million.
As part of the overall A&S decontracting process, A&S's operations have
been significantly reduced, with a major aggregator of Canadian natural gas
acquiring A&S's restructured gas purchase contracts and remaining sales
contracts. A&S continues to hold gas transportation capacity on Canadian
pipelines and is in the process of permanently assigning or brokering such
capacity.
As part of the Decontracting Plan, A&S permanently assigned portions of
its commitments for transportation capacity with NOVA Corporation of Alberta
(NOVA) through October 2001 and ANG through October 2005 to third parties. A&S
also assigned approximately 600 million cubic feet per day (MMcf/d) of capacity
on each of these pipelines to PG&E for use in the servicing of PG&E's core and
core subscription customers. A&S currently holds the remaining capacity of
approximately 450 MMcf/d with annual demand charges of approximately $25
million for which it is continuing its efforts to assign or broker. There is
uncertainty about the ability of A&S to assign or broker this remaining
capacity. To the extent others do not take this capacity, A&S will remain
obligated to pay for the related demand charges.
In July 1993, FERC approved a transition cost recovery mechanism (TCEM)
for PGT under which most costs which were incurred to restructure, reform or
terminate the sales arrangements between A&S and PGT and underlying A&S gas
supply contracts, or to resolve claims by gas suppliers related to past or
future liabilities or obligations of PGT or A&S, are eligible for recovery in
PGT's rates. The TCRM precludes most objections to the eligibility and
prudence of such costs; prudence challenges may be made only on the grounds
that the payment is unreasonably high in light of the damages claimed.
Disposition of approved transition costs will be as follows: (1) 25% of such
costs will be absorbed by PGT; (2) 25% will be recovered by PGT through direct
bills (substantially all to PG&E as PGT's principal customer); and (3) 50% will
be recovered by PGT through volumetric surcharges over a three-year period.
Costs associated with A&S's commitments for Canadian pipeline capacity do not
qualify as transition costs recoverable under this mechanism.
34
24
Financial Impact of Decontracting Plan and Litigation: The Company incurred
transition costs of $228 million, consisting of settlement payments made to
producers in connection with the implementation of the Decontracting Plan and
amounts incurred by A&S in reducing certain administrative and general
functions resulting from the restructuring. Of these costs, the Company
deferred $143 million (included in deferred charges -- other) for future rate
recovery. In addition, the Company recorded a reserve of $31 million due to the
uncertainty of A&S's ability to assign or broker its remaining commitments for
Canadian transportation capacity. Accordingly, the Company expensed $93 million
in 1993 and a total of $23 million in prior years.
PGT and PG&E are seeking recovery of all transition costs eligible for recovery
under the TCRM other than the 25% of such costs to be absorbed by PGT. While
such transition costs are still subject to challenges at the FERC level and the
recovery of such costs paid by PG&E as a shipper of gas on PGT's pipelines will
depend on the recovery mechanism adopted by the CPUC, the Company believes that
it will ultimately recover the deferred transition costs.
Transportation Commitments: The Company has gas transportation service
agreements with various Canadian and interstate pipeline companies. These
agreements include provisions for fixed demand charges for reserving firm
capacity on the pipelines. The total demand charges that the Company will pay
each year may change due to changes in tariff rates and may be reduced to the
extent the Company can broker or assign any unused capacity. In addition to
demand charges, the Company is required to pay transportation charges for
actual quantities shipped. The Company's total demand and transportation
charges paid under these agreements (excluding PGT) were approximately $280
million in 1993, $300 million in 1992 and $260 million in 1991.
As discussed above, regulatory changes have resulted in a decrease in
the amount of gas required to be purchased by the Company and a related
decrease in the need for firm transportation capacity. The Company has retained
portions of this capacity to be used for its core and core subscription
customers and has permanently assigned significant portions of the remaining
capacity. The following table summarizes the approximate amounts of capacity
held by the Company on various pipelines for its core and core subscription
customers and capacity remaining to be assigned or brokered as of December 31,
1993:
Remaining Total
Amount Held Amount Available Annual Demand
Pipeline for Core for Brokering Charges Contract
Company (MMcf/d) (MMcf/d) (in millions) Expiration
- ------- ----------- ---------------- ------------- ----------
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
* 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
25
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
PACIFIC GAS AND ELECTRIC COMPANY
GAS REASONABLENESS PROCEEDINGS: Recovery of gas costs through the
Company's regulatory balancing account mechanisms is subject to a CPUC
determination that such costs were incurred reasonably. Under the current
regulatory framework, annual reasonableness proceedings are conducted by the
CPUC on a historic calendar year basis.
1988-1990: The CPUC consolidated its review of the reasonableness of gas
system costs for 1988 through 1990. A CPUC Administrative Law Judge (ALJ)
recently issued proposed decisions on the Company's Canadian gas procurement
activities and gas inventory operations during 1988 through 1990.
The proposed decision on the Company's Canadian gas procurement
activities finds that the Company's procurement practices were reasonable in
light of the events and circumstances then applicable, but that the Company was
imprudent to the extent that it failed to take reasonable steps to bargain more
aggressively with Canadian gas suppliers. The proposed decision recommends a
disallowance of approximately $46 million of gas costs plus accrued interest
estimated at approximately $15 million. The proposed decision also finds that
the disallowances recommended by the CPUC's Division of Ratepayer Advocates
(DRA) and an intervenor overstate the magnitude of savings which the Company
could have achieved during 1988 through 1990. The DRA had recommended that the
Company refund $392 million based on its contention that the Company should
have purchased 50% of its Canadian supplies on the spot market instead of
almost totally relying on long-term contracts. Using a different theory than
the DRA, an intervenor had asserted that the Company overpaid for Canadian gas
in the range of $540 million to $670 million.
In the proposed decision on gas inventory operations, the ALJ found the
Company's gas inventory operations in 1989 and 1990 to be reasonable except for
operations during December 1990 for which the ALJ proposed a disallowance of
$7 million. Earlier, the DRA recommended a disallowance of $37 million
contending that the Company should have withdrawn additional gas from storage
in the winter of 1989-1990 and December 1990 rather than burning fuel oil,
which was more expensive.
A final CPUC decision on the Company's Canadian gas procurement
activities is expected in the first quarter of 1994. CPUC consideration of
other issues which relate to purchased electric energy and certain contracts
with Southwestern gas producers has been deferred. Relating to purchased
electric energy costs, the DRA recommended a disallowance of $18 million
contending that had the Company purchased lower cost Canadian gas, the Company
would have realized a reduction in its electric energy costs. However, the DRA
has not yet addressed issues related to certain contracts with Southwestern gas
producers.
1991: The DRA has issued a report on the reasonableness of the Company's gas
procurement and operating activities for 1991. The DRA recommended that the
Company refund approximately $116 million, consisting of $105 million related
to Canadian gas purchases and $11 million related to gas inventory operations
and Southwest gas procurement issues. The DRA's recommendations are based on
the same theories outlined in the DRA's reports for 1988 through 1990, as
discussed above.
1992: The DRA issued a report on the reasonableness of the Company's
gas procurement and operating activities for 1992, recommending that the
Company refund approximately $92 million. The recommended disallowance includes
$61 million related to Canadian gas purchases and $8 million related to gas
inventory operations, based on the same theories outlined in prior DRA reports.
Also included are disallowances totaling $23 million related to Southwest gas
transportation and procurement issues. It is possible that similar issues will
be raised regarding the Company's Canadian gas procurement activities during
1993. However, the Company estimates the disallowance that the DRA may
recommend for 1993 should be significantly lower than those for prior years.
Affiliate Audit: The DRA issued a report on its investigation of the
operations of A&S and the Company's former affiliate, ANG, for 1988 through
1991. The investigation was initiated in connection with the reasonableness
proceeding for 1991. The DRA reviewed certain nongas costs, primarily Canadian
pipeline charges and A&S overhead costs, and recommended a penalty and
disallowance of $50 million and $6 million, respectively. The recommended
penalty and disallowance are primarily related to the Company's alleged failure
to properly oversee its subsidiaries' activities. In addition, recommendations
related to 1992 activities may be made in a subsequent report. The Company
filed a motion with the CPUC asking it to disregard the recommended penalty and
disallowance because prior federal rulings approved such costs and thus preempt
the issue. In December 1993, an ALJ denied this motion.
36
26
Financial Impact of Gas Reasonableness Proceedings: The DRA is a consumer
advocacy branch of the CPUC staff. Neither the DRA's recommendations nor the
ALJ's proposed decisions constitute a CPUC decision. The CPUC can accept all,
part or none of the DRA's recommendations or the ALJ's proposed decisions. The
Company believes that its gas procurement activities, transportation
arrangements and operations were prudent and will vigorously contest the
disallowances and penalty proposed by the DRA or other parties. However, based
on its current assessment of the matter, the Company recorded a reserve of $61
million in 1993 for any disallowance that may be ordered by the CPUC in the
gas reasonableness proceedings. The Company currently is unable to estimate
the ultimate outcome of the gas reasonableness proceedings or predict whether
such outcome will have a significant adverse impact on its financial position
or results of operations.
PGT-PG&E PIPELINE EXPANSION PROJECT: In November 1993, the Company placed in
service an expansion of its natural gas transmission system from the Canadian
border into California. The pipeline provides an additional 148 MMcf/d of firm
capacity to the Pacific Northwest and an additional 755 MMcf/d of firm capacity
to Northern and Southern California. At December 31, 1993 and 1992, the
Company's total investment in the expansion project was approximately $1,587
million (included in plant in service) and $979 million (included in
construction work in progress), respectively. The $1,587 million at December
31, 1993, consisted of $767 million for the facilities within California (i.e.,
intrastate portion) and $820 million for the facilities outside California
(i.e., interstate portion).
The construction of facilities within the state of California has been
certificated by the CPUC. The conditions of the certificate place the Company
at risk for its decision to construct based on its assessment of market demand
and subsequent underutilization of the facility. The certificate requires the
application of a "cross-over" ban under which volumes delivered from the
incremental interstate (PGT) expansion must be transported at an incremental
expansion rate within California. Incremental rate design is based on the
concept that expansion shippers, not existing ratepayers, bear the incremental
costs of the expansion project. Capacity on the interstate portion is fully
subscribed under long-term firm transportation contracts. However, to date,
shippers have only executed long-term firm transportation contracts for
approximately 40% of the intrastate capacity. The CPUC has authorized the
Company to provide as-available service on the expansion project, which would
provide additional revenues to recover the incremental costs of the expansion
project. The Company continues negotiations for the remaining capacity.
The CPUC certificate issued in December 1990 established a cost cap of
$736 million for the California portion, which represented the maximum amount
determined by the CPUC to be reasonable and prudent based on an estimate of the
anticipated construction costs at that time. In October 1993, the CPUC issued a
decision granting the Company's motion to put in place temporary interim rates
based on the existing cost cap of $736 million. The decision authorized the
temporary interim rates to become effective on the date of commercial
operation, November 1, 1993, and remain in effect for five months or until
interim rates are established by the CPUC.
In February 1994, the CPUC announced a decision on the Company's
request for an increase in the California portion of the expansion project's
cost cap and its interim rate filing. The CPUC granted the Company's request to
increase the cost cap to $849 million but set interim rates based on $736
million, subject to an adjustment based on the outcome of a reasonableness
review of capital costs. The CPUC's decision finds that, given market
conditions at the time, the Company was reasonable in constructing the
expansion project. The CPUC rejected the assignment of costs related to unused
capacity on other pipelines (or the Company's intrastate facilities) to the
expansion project as previously recommended by an ALJ's proposed decision.
Due to the ratemaking treatment adopted by the CPUC for the California
portion of the expansion project, the Company's ability to recover its cost of
service rates is contingent upon demand and competitive market pricing for gas
transportation services. In light of anticipated demand and pricing in the
foreseeable future, the Company has determined that it may not bill its
customers to recover its full cost of service. Consequently, application of
SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation" was
discontinued for the California portion of the expansion project during 1993.
This accounting change was implemented using the guidelines contained in SFAS
No. 101, "Regulated Enterprises -- Accounting for the Discontinuation of
Application of FASB Statement No. 71" and did not have a significant impact on
the Company's financial position or results of operations in 1993.
Financial Impact of PGT-PG&E Pipeline Expansion Project: Based upon the current
status of the rate case and market demand, the Company believes it will recover
its investment in the expansion project.
37
27
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
PACIFIC GAS AND ELECTRIC COMPANY
NOTE 3 -- DIABLO CANYON
- -----------------------
RATE CASE SETTLEMENT: The Diablo Canyon rate case settlement, effective
July 1988, bases revenues primarily on the amount of electricity generated by
the plant, rather than on traditional cost-based ratemaking. In approving the
settlement, the CPUC explicitly stated that it affirmed that Diablo Canyon
costs and operations should no longer be subject to CPUC reasonableness
reviews. The CPUC cannot bind future commissions in fixing just and reasonable
rates for Diablo Canyon, but to the extent permitted by law intends that this
decision remain in effect for the full term of the settlement, ending 2016.
The settlement provides that certain Diablo Canyon costs be recovered
over the term of the settlement, including a full return on such costs, through
base rates. The related revenues to recover these costs are included in Diablo
Canyon operating revenues for reporting purposes. Other than these and
decommissioning costs, Diablo Canyon no longer meets the criteria for
application of SFAS No. 71. Consequently, application of this statement was
discontinued for Diablo Canyon effective July 1988.
PRICING: Under the Diablo Canyon rate case settlement, the price per
kWh of electricity generated by Diablo Canyon consists of a fixed and an
escalating component. The total prices for 1991 through 1993 were 9.60 cents,
10.34 cents and 11.16 cents per kWh, respectively, effective January 1. The
total price for 1994, effective January 1, is 11.89 cents per kWh. For 1995
through 2016, the escalating component will be adjusted by the change in the
consumer price index plus 2.5%, divided by two. During the first 700 hours of
full-power operation for each unit during the peak period (10 a.m. to 10 p.m.
on weekdays in June through September), the price is 130% of the stated amount
to encourage the Company to utilize the plant during the peak period. Beginning
in January of each year, during the first 700 hours of full-power operation for
each unit outside the peak period, the price is 70% of the stated amount. At
all other times, the price is 100% of the stated amount.
FINANCIAL INFORMATION: Selected financial information for Diablo Canyon
is shown below:
Year ended December 31,
------------------------------
1993 1992 1991
------ ------ ------
(in millions)
Operating revenues $1,933 $1,781 $1,501
Operating income 708 663 497
Net income 496 443 274
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
28
Dividends on preferred stock are cumulative. Preferred dividends are
accrued based on declaration date, whereas preferred dividend requirement,
which is used to calculate earnings per common share, is based on the
accumulated dividends on preferred stock outstanding at year end. All shares of
preferred stock have equal preference in dividend and liquidation rights. Upon
liquidation or dissolution of the Company, holders of the preferred stock would
be entitled to the par value of such shares plus all accumulated and unpaid
dividends, as specified for the class and series.
Note 5 -- Long-term Debt
- ------------------------
MORTGAGE BONDS: The First and Refunding Mortgage Bonds of the Company are
issued in series, bear annual interest rates ranging from 4.25% to 12.75% and
mature from 1994 to 2026. The Company had $6.0 billion and $6.6 billion of
mortgage bonds outstanding at December 31, 1993 and 1992, respectively.
Additional bonds may be issued, subject to CPUC approval, up to a maximum total
outstanding of $10 billion, assuming compliance with indenture covenants for
earnings coverage and property available as security. The Company's Board of
Directors may increase the amount authorized, subject to CPUC approval. The
indenture requires that net earnings excluding depreciation and interest be
equal to or greater than 1.75 times the annual interest charges on the
Company's mortgage bonds outstanding. All real properties and substantially all
personal properties of PG&E are subject to the lien of the indenture.
The Company is required by the indenture to make semi-annual sinking
fund payments on February 1 and August 1 of each year for the retirement of the
bonds. The payments equal .5% of the aggregate bonded indebtedness outstanding
on the preceding November 30 and May 31, respectively. Bonds of any series,
with certain exceptions, may be used to satisfy this requirement. In addition,
holders of series 84D bonds maturing in 2017 have an option to redeem their
bonds in 1995.
In conjunction with the Company's focus on reducing the levels of
high-cost debt, the Company redeemed or repurchased $3,536 million and $1,182
million of higher-cost mortgage bonds in 1993 and 1992, respectively. Interest
rates on the bonds redeemed or repurchased ranged from 7.50% to 12.75%.
During 1993, the Company issued $2,950 million of First and Refunding
Mortgage Bonds, series 93A through 93H, with interest rates ranging from 5.375%
to 7.250% and maturity dates ranging from 1998 to 2026. Substantially all the
proceeds from these bonds were used to redeem or repurchase higher-cost
mortgage bonds.
Included in the total of outstanding mortgage bonds are First and
Refunding Mortgage Bonds issued by the Company to secure its obligation
to repay various loans from the California Pollution Control Financing
Authority (CPCFA) to finance air and water pollution control, and sewage and
solid waste disposal facilities. The amounts loaned to the Company by the CPCFA
consist of proceeds from the CPCFA's sale of tax-exempt pollution control
revenue bonds having the same principal amounts and terms as the Company's
mortgage bonds securing the loans. At December 31, 1993 and 1992, the Company
had outstanding $768 million and $508 million, respectively, of mortgage bonds
securing loans from the CPCFA. These mortgage bonds have interest rates ranging
from 5.85% to 8.875% and maturity dates from 2007 to 2023.
POLLUTION CONTROL LOAN AGREEMENTS: In addition to the pollution control loans
secured by the Company's mortgage bonds (described above), the Company had
loans totaling $925 million at December 31, 1993 and 1992, from the CPCFA to
finance air and water pollution control, and sewage and solid waste disposal
facilities. Interest rates on the loans vary depending on whether the loans are
in a daily, weekly, commercial paper or fixed rate mode. Conversions from one
mode to another take place at the Company's option. Average annual interest
rates on these loans for 1993 ranged from 2.31% to 2.54%. These loans are
subject to redemption on demand by the holder under certain circumstances. The
Company's obligations for such demands are secured by irrevocable letters of
credit which mature as early as 1996.
MEDIUM-TERM NOTES: The Company had $1,543 million and $847 million of unsecured
medium-term notes outstanding at December 31, 1993 and 1992, respectively, with
interest rates ranging from 4.13% to 10.10% and maturities from 1994 to 2013.
During 1993 and 1992, the Company issued $750 million and $263 million of
medium-term notes, respectively. Proceeds from these notes were applied to
construction expenditures and to the redemption, repurchase or retirement of
debt or preferred stock.
39
29
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
PACIFIC GAS AND ELECTRIC COMPANY
LONG-TERM DEBT OF SUBSIDIARIES: In 1993, PGT finalized a new loan agreement for
$710 million to finance PGT's portion of the PGT-PG&E Pipeline Expansion
Project and to refinance PGT's existing borrowings. As of December 31, 1993,
there was $648 million outstanding under this agreement. The loan is secured
by PGT's operating revenues and gas transportation contracts. The loan will
mature no later than 2004, however, if certain terms and conditions are not
met by November 1996, the loan could mature as early as 1997. If early maturity
does not occur, a reserve sufficient to cover a minimum of six months of debt
service must be established. At December 31, 1993, the Company was in
compliance with all terms and conditions. The interest rate varies depending
on the rate selected by the Company, which can be the prime rate, London
Interbank Offered Rate or certificate of deposit rate, plus applicable margin.
During 1993, the weighted average rate of interest was 3.83%.
REPAYMENT SCHEDULE: At December 31, 1993, the Company's combined aggregate
amount of maturing long-term debt and sinking fund requirements, for the
years 1994 through 1998, are $221 million, $514 million, $460 million, $369
million and $714 million, respectively.
FAIR VALUE: The estimated fair value for the Company's total long-term debt of
$9.5 billion and $8.7 billion at December 31, 1993 and 1992, respectively, was
approximately $9.9 billion and $9.2 billion, respectively. The estimated fair
value of long-term debt was determined based on quoted market prices, where
available. Where quoted market prices were not available, the estimated fair
value was determined using other valuation techniques (e.g., matrix pricing
models or the present value of future cash flows). Debt allocated to Diablo
Canyon at December 31, 1993 and 1992, had a book value of $2.2 billion, and a
fair value of approximately $2.3 billion.
Note 6 -- Short-term Borrowings
Short-term borrowings consist of commercial paper with a weighted average
interest rate of 3.43% at December 31, 1993. The usual maturity for commercial
paper is 10 to 90 days. Commercial paper outstanding at December 31, 1993 and
1992, was $764 million and $916 million, respectively. The carrying amount of
short-term borrowings approximates fair value.
The Company has a $1 billion revolving credit facility with various
banks to support the sale of commercial paper and for other corporate purposes.
At December 31, 1993 and 1992, there were no borrowings outstanding under this
facility. This credit facility expires in November 1997; however, it may be
extended annually for additional one-year periods upon mutual agreement between
the Company and the banks. The Company is in compliance with all covenants
associated with the facility.
Note 7 -- Employee Benefit Plans
RETIREMENT PLAN: The Company provides a noncontributory defined benefit pension
plan covering substantially all employees. The retirement benefits are based
on years of service and the employee's base salary. The Company's funding
policy is to contribute each year not more than the maximum amount deductible
for federal income tax purposes and not less than the minimum contribution
required under the Employee Retirement Income Security Act of 1974. The cost of
this plan is charged to expense and to plant in service through construction
work in progress.
Net pension cost, using the projected unit credit actuarial cost method,
was:
Year ended December 31,
-----------------------------------
1993 1992 1991
--------- --------- ---------
(in thousands)
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
========= ========= =========
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
30
In conformity with accounting for rate-regulated enterprises,
regulatory adjustments have been recorded in the income statement and balance
sheet for the difference between utility pension cost determined for accounting
purposes and that for ratemaking, which is based on a contribution approach.
The plan's funded status was:
December 31,
-------------------------
1993 1992
----------- -----------
(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)
=========== ===========
The increase in unrecognized prior service cost in 1993 compared to
1992 reflects a plan amendment which provides an increase in benefits to
certain retirees.
Plan assets consist substantially of common stocks, fixed-income
securities and real estate investments. The unrecognized prior service cost is
amortized over approximately 16 years. The unrecognized net obligation is being
amortized over approximately 18 years, beginning in 1987.
The vested benefit obligation is the actuarial present based on their
expected benefits to which employees are currently entitled based on their
expected termination dates.
Assumptions used to calculate the projected benefit obligation to
determine the plan's funded status were:
December 31,
------------
1993 1992
---- ----
Weighted average discount rate 7% 7%
Average rate of projected future
compensation increases 5% 6%
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
31
Substantially all employees retiring at or after age 55 are
eligible for these
benefits. The medical benefits are provided through plans
administered by an
insurance carrier or a health maintenance organization. Certain
retirees are
responsible for a portion of the cost based on past claims
experience of the
Company's retirees.
The Company's funding policy for the medical and life insurance
benefits is to
contribute each year the tax-deductible amount provided for in
rates. Life
insurance benefits which are not funded are provided through an
insurance
company at a cost based on total current claims paid plus
administrative fees.
The cost of these plans is charged to expense and to plant in
service through
construction work in progress.
41
32
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
PACIFIC GAS AND ELECTRIC COMPANY
Effective January 1, 1993, the Company adopted SFAS No. 106,
"Employers' Accounting for Postretirement Benefits Other Than Pensions," which
requires accrual of the expected cost of these benefits during the employees'
years of service. The assumptions and calculations involved in determining the
accrual closely parallel pension accounting requirements. The Company
previously recognized these costs as benefits were paid and funded, which was
consistent with ratemaking.
In December 1992, the CPUC issued a decision in the final phase of the
investigation on the ratemaking treatment for these benefits in 1993 and
beyond. The decision authorized recovery of these benefits, within certain
guidelines, at a level equal to the lesser of the annual SFAS No. 106 cost,
based on amortization of the transition obligation over 20 years, or the amount
which can be contributed annually on a tax-deductible basis to appropriate
trusts. Due to this regulatory treatment, adoption of SFAS No. 106 did not have
a significant impact on the Company's financial position or results of
operations.
Net postretirement medical and life insurance cost, using the projected
unit credit actuarial cost method, was:
Year ended
December 31,
1993
--------------
(in thousands)
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
========
The medical and life insurance plans' funded status was:
Year ended
December 31,
1993
--------------
(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
=========
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
33
POSTEMPLOYMENT BENEFITS: In November 1992, the Financial
Accounting Standards
Board issued SFAS No. 112, "Employers' Accounting for
Postemployment Benefits,"
which requires employers to adopt accrual accounting for benefits
provided to
former or inactive employees and their beneficiaries and covered
dependents,
after employment but before retirement. The Company will adopt
the new standard
in 1994.
Based on a preliminary valuation by the Company's actuary, it
is estimated
that the recorded liability for such benefits will increase by
approximately
$100 million upon adoption. However, due to current regulatory
treatment,
adoption of SFAS No. 112 is not expected to have a significant
impact on the
Company's financial position or results of operations.
42
34
Note 8 -- Workforce Reduction Program
- -------------------------------------
In the first quarter of 1993, the Company announced a corporate
reorganization and workforce reduction program which reduced employment
positions through a combination of a targeted voluntary retirement incentive
plan, targeted voluntary severance, involuntary severance, transitional leaves
of absence and attrition.
In March 1993, the CPUC authorized the establishment of a memorandum
account to record costs and savings incurred in connection with the workforce
reduction program, with the recovery of such costs subject to a reasonableness
review by the CPUC. The Company is seeking rate recovery of all costs incurred
in connection with the workforce reduction program relating to electric and gas
operations.
As of December 31, 1993, the Company has recorded workforce reduction
program costs of $264 million, net of a curtailment gain relating to pension
benefits. (Included in this amount is $151 million for additional pension
benefits and $22 million for other postretirement benefits extended in
connection with the voluntary retirement incentive plan.) In April 1993, the
Company announced a freeze on electric rates through 1994. As a result, the
Company has expensed $190 million of such costs relating to electric
operations. The remaining $74 million of such costs relating to gas operations
has been deferred for future rate recovery. The amount deferred is currently
being amortized as savings are realized.
Note 9 -- Income Taxes
- ----------------------
The current and deferred components of income tax expense were:
Year ended December 31,
----------------------------------------
1993 1992 1991
---------- ---------- ----------
(in thousands)
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
========== ========== ==========
The significant components of net deferred income tax liabilities
are as follows:
December 31, 1993
--------------------------------------------
Deferred Deferred Net deferred
income tax income tax income tax
assets liabilities liability
---------- ----------- ------------
(in thousands)
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
========== ========== ==========
35
(1) Represents the portion of deferred income tax liability related to the
revenues required to recover future income taxes.
The differences between income tax expense and amounts determined by
applying the federal statutory rate to income before income tax expense were:
Year ended December 31,
-----------------------
1993 1992 1991
---- ---- ----
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%
==== ==== ====
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,
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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:
Year ended December 31,
---------------------------
1993 1992 1991
------- ------- ------
(in millions)
Kilowatthours received 21,242 21,173 19,127
Energy payments $ 1,099 $ 1,084 $ 970
Capacity payments $ 503 $ 489 $ 450
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.
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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
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38
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
PACIFIC GAS AND ELECTRIC COMPANY
include over $150 million paid by the Company to terminate the contracts with
the Canadian gas producers in November 1993. The complaint also seeks recovery
of three times the amount of the actual damages pursuant to antitrust laws.
The Company believes the case is without merit and has filed a motion
to dismiss the complaint. The Company believes that the ultimate outcome of the
antitrust litigation will not have a significant adverse impact on its financial
position.
Hinkley Litigation: In 1993, a complaint was filed in San Bernardino County
Superior Court on behalf of a number of individuals seeking recovery of
an unspecified amount of damages for personal injuries and property damage
allegedly suffered as a result of exposure to chromium near the Company's
Hinkley Compressor Station, as well as punitive damages.
The plaintiffs contend that the Company discharged chromium-
contaminated waste water into unlined ponds, which led to chromium
percolating into the groundwater of surrounding property. The plaintiffs
further allege that the Company disposed of the chromium in those ponds to
avoid costly alternatives.
In 1987, the Company undertook an extensive project to remediate
potential groundwater chromium contamination. The Company has incurred
substantially all of the costs it currently deems necessary to clean up the
affected groundwater contamination. In accordance with the remediation plan
approved by the regional water quality control board, the Company will
continue to monitor the affected area and periodically perform environmental
assessments.
In November 1993, the parties engaged in private mediation sessions. In
December 1993, the plaintiffs filed an offer to compromise and settle their
claims against the Company for $250 million.
The Company is unable to estimate the ultimate outcome of this matter,
but such outcome could have a significant adverse impact on the Company's
results of operations. The Company believes that the ultimate outcome of this
matter will not have a significant adverse impact on its financial position.
QF Transmission Litigation: The Company is a defendant in a lawsuit, currently
in trial, resulting from the termination of a power purchase agreement. The
plaintiff contends the Company misrepresented to the CPUC and to QFs its
transmission capacity and that the existence of transmission constraints
extended the deadline for delivery of energy. The plaintiff also alleges
the Company had an obligation to build transmission upgrades at the Company's
expense, which it did not fulfill. The complaint seeks compensatory and
punitive damages of an unspecified amount. However, the plaintiff's damage
expert has given a preliminary estimate of damages sought of $67 million. There
are other similarly situated QFs which might choose to file similar complaints
depending on the outcome of this litigation. The Company believes that the
matter has no merit and that the ultimate outcome will not have a significant
adverse impact on its financial position or results of operations.
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39
QUARTERLY CONSOLIDATED FINANCIAL DATA (UNAUDITED)
PACIFIC GAS AND ELECTRIC COMPANY
QUARTERLY FINANCIAL DATA
The four quarters of 1993 and 1992 are shown below. Due to the seasonal
nature of the utility business and the scheduled refueling outages for Diablo
Canyon, operating revenues, operating income and net income are not generated
evenly by quarter during the year.
In the second quarter of 1993, the Company charged to earnings $141
million related to the workforce reduction program for management employees. In
the third quarter of 1993, the Company's earnings reflected charges of $144
million resulting from the Company's workforce reduction program, termination
of Canadian gas contracts and an increase in the federal income tax rate that
was signed into law this year. The fourth quarter of 1993 reflected charges
against earnings of $126 million for Canadian gas costs incurred by the Company
for 1988 through 1990 and for commitments for gas transportation capacity.
Earnings for the second quarter of 1992 included a $19 million after-tax gain
from the sale by PGT of its 49.98% interest in ANG.
The Company's common stock is traded on the New York, Pacific, London,
Amsterdam, Basel and Zurich stock exchanges. There were approximately 245,000
common shareholders of record at December 31, 1993. Dividends are paid on a
quarterly basis, and there are no significant restrictions on the present
ability of the Company to pay dividends.
Quarter ended
---------------------------------------------------
December 31 September 30 June 30 March 31
----------- ------------ ---------- ----------
(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
(1) Includes Diablo Canyon scheduled refueling outages for the first and second
quarters of 1993 and for the third and fourth quarters of 1992.
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REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
PACIFIC GAS AND ELECTRIC COMPANY
To the Shareholders and the Board of Directors of Pacific Gas and
Electric Company:
We have audited the accompanying consolidated balance sheet and the
statement of consolidated capitalization of Pacific Gas and Electric Company (a
California corporation) and subsidiaries as of December 31, 1993 and 1992, and
the related statements of consolidated income, cash flows, common stock equity
and preferred stock, and the schedule of consolidated segment information for
each of the three years in the period ended December 31, 1993. These financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the consolidated financial statements and schedule of
consolidated segment information referred to above present fairly, in all
material respects, the financial position of Pacific Gas and Electric Company
and subsidiaries as of December 31, 1993 and 1992, and the results of their
operations and cash flows for each of the three years in the period ended
December 31, 1993 in conformity with generally accepted accounting principles.
As discussed in Note 2 of Notes to Consolidated Financial Statements,
the reasonableness of Canadian gas costs for 1988 through 1993 is subject to
California Public Utilities Commission review. The Company currently is unable
to estimate the ultimate outcome of the gas reasonableness proceedings or
predict whether such outcome will have a significant adverse impact on its
financial position or results of operations.
As discussed in Note 11 of Notes to Consolidated Financial Statements,
the Company has filed an application for rate recovery of the remaining
unrecovered Helms costs and certain lost revenues which totaled $106 million at
December 31, 1993. The Company is uncertain whether, and to what extent, any of
the remaining costs and revenues will be recovered through the ratemaking
process.
As discussed in Note 11 of Notes to Consolidated Financial Statements,
in 1993, a complaint was filed on behalf of a number of individuals seeking
recovery for personal injuries and property damage related to alleged
groundwater contamination caused by Company activity. The Company is unable to
estimate the ultimate outcome of this matter, but such outcome could have a
significant adverse impact on the Company's results of operations. The Company
believes that the ultimate outcome of this matter will not have a significant
adverse impact on the Company's financial position.
As explained in Notes 1 and 7 of Notes to Consolidated Financial
Statements, effective January 1, 1993, the Company changed its method of
accounting for postretirement benefits other than pensions and for income
taxes.
ARTHUR ANDERSEN & CO.
ARTHUR ANDERSEN & CO.
San Francisco, California
February 16, 1994
48