1
Exhibit 13
Pacific Gas and Electric Company
SELECTED FINANCIAL DATA
(in thousands, except per share amounts)
1994 1993 1992 1991 1990
FOR THE YEAR
Operating revenues $10,447,351 $10,582,408 $10,296,088 $ 9,778,119 $ 9,470,092
Operating income 1,633,359 1,762,930 1,833,441 1,713,079 1,706,136
Net income 1,007,450 1,065,495 1,170,581 1,026,392 987,170
Earnings per common share 2.21 2.33 2.58 2.24 2.10
Dividends declared per common
share 1.96 1.88 1.76 1.64 1.52
AT YEAR END
Book value per common share $20.07 $19.77 $19.41 $18.40 $17.86
Common stock price per share 24.38 35.13 33.13 32.63 25.00
Total assets 27,809,133 27,162,526 24,188,159 22,900,670 21,958,397
Long-term debt and preferred stock
with mandatory redemption
provision (excluding current
portions) 8,812,591 9,367,100 8,525,948 8,341,310 7,902,409
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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Pacific Gas and Electric Company
MANAGEMENT'S DISCUSSION AND ANALYSIS OF CONSOLIDATED RESULTS OF OPERATIONS AND
FINANCIAL CONDITION
Pacific Gas and Electric Company (PG&E) and its wholly owned and majority-owned
subsidiaries (collectively, the Company) have three types of operations:
utility, Diablo Canyon Nuclear Power Plant (Diablo Canyon) and nonregulated
through PG&E Enterprises (Enterprises). The Company is engaged principally in
the business of supplying electric and natural gas service throughout most of
Northern and Central California. The Company's operations are regulated by the
California Public Utilities Commission (CPUC) and the Federal Energy Regulatory
Commission (FERC), among others.
Competition and Changing Regulatory Environment:
Recent changes in both the gas and electric industries have allowed competition
to develop in the gas supply and electric generation segments of the Company's
business. A number of reforms at both the federal and state level have been
proposed. These reforms are designed to restructure regulation in the energy
supply industry and promote competition by providing electric and gas customers
with purchasing options.
As a result of the restructuring of the natural gas industry, the Company no
longer provides combined purchase and transportation services to many of its
industrial and large commercial gas customers. Instead, most of these customers
now procure their gas supplies from a source other than the Company while
purchasing transportation service from the Company. These customers can also
use alternative transportation services available within the Company's service
territory.
In November 1994, the FERC approved the expansion of a competing company's
natural gas pipeline into the Company's service territory. This pipeline could
compete directly for transportation service to several of the Company's large
customers as soon as January 1, 1996, and may result in the loss of sales on
the Company's gas transportation system.
While the restructuring of the electric industry is still evolving,
proposals being considered are expected to bring increased competition into the
electric generation business. At the federal level, the National Energy Policy
Act of 1992 (Energy 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.
At the state level, in April 1994, the CPUC issued a proposal on electric
industry restructuring which seeks to lower energy prices and provide customers
with a choice of electric generation suppliers (known as direct access). This
proposal involves two key strategies: One, phase in direct access to electric
generation for all customers over a six-year period beginning in 1996; two,
where competition does not exist, replace traditional cost-of-service
regulation with performance-based regulation (PBR). To ensure a transition that
maintains the financial integrity of the utilities, the CPUC proposed that
uneconomic costs of utility generating assets resulting from its proposal be
recovered through a "competition transition charge." However, the CPUC
proposal did not specify which costs might be recovered through such a
transition charge or how such a charge would be allocated to and collected from
customers.
The Company has filed a response to the CPUC proposal embracing the
objective of lower prices and supporting increased competition, but
recommending a longer phase-in period to direct access to permit an orderly
transition. Based on market prices of $.048 and $.032 per kilowatthour (kWh),
the Company estimated that its uneconomic generating assets and obligations are
approximately $3 billion and $11 billion, respectively, resulting from the
restructuring as proposed by the CPUC. The Company identified three categories
of uneconomic assets: utility-owned generation assets and power purchase
commitments, power purchase obligations relating to qualifying facilities (QFs)
and generation-related regulatory assets. The estimates of uneconomic assets
were determined by comparing the future revenue requirements of generation
assets and power purchase obligations over a twenty-year and thirty-year
period, respectively, with revenues computed at the assumed market price.
Diablo Canyon was included in the revenue requirement calculation using the
proposed pricing modifications to the Diablo Canyon settlement. (See Operating
Revenues.) The revenue requirement for Diablo Canyon and all Company-owned
generation assets included a return on investment. The actual amount of
uneconomic assets and obligations will depend upon the final regulation and the
actual market price of electricity. The Company intends to seek recovery of its
uneconomic assets and obligations through the competition transition charge.
(See Note 2 of Notes to Consolidated Financial Statements.)
In addition to working with the CPUC on this proposal, the Company has made
several proposals to modify existing regulatory processes and to provide
additional pricing flexibility to those customers with the most competitive
options. The Company has proposed instituting PBR for determining nonfuel
revenues, under which electric and natural gas
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revenues would be determined annually by formula rather than through general
rate cases (GRCs), attrition rate adjustments and cost of capital proceedings.
The Company has also proposed a gas procurement incentive mechanism that would
replace after-the-fact reasonableness reviews of certain costs. This proposed
mechanism would measure the Company's gas procurement costs against market
benchmarks and would provide for the sharing, between ratepayers and
shareholders, of variances from a preset range around the market benchmark.
The shifting of utility regulation from traditional cost-of-service based
concepts to concepts based upon market competition and benchmarks will place
greater emphasis on the Company's ability to provide valued products and
services at competitive prices. The Company has announced a five-year goal of
reducing its system-wide average electric rates. In addition, the Company has
taken several significant actions to position itself to effectively compete in
the restructured electric and gas industries. Specifically, the Company has:
- Extended through 1995 its electric rate freeze which began in 1993.
- Proposed a modification of the Diablo Canyon settlement to reduce the
price paid for electricity generated at Diablo Canyon over the next five
years.
- Reduced electric rates for certain of its largest industrial customers
through an economic stimulus rate that will extend through the end of
1995.
- Planned reductions in annual spending in 1995 of approximately $600
million from 1993 spending levels.
- Refinanced debt and preferred stock over the last three years resulting
in annual savings of approximately $97 million in financing costs.
The Company cannot predict the ultimate outcome of the ongoing changes that
are taking place in the utility industry. However, management believes the end
result will involve a fundamental change in the way the Company conducts its
business. These changes may impact financial operating trends and add
volatility to the Company's earnings. Management is actively seeking regulatory
and operational changes that will allow the Company to provide energy services
in a safe, reliable and competitive manner while achieving strong financial
performance.
Accounting for the Effects of Regulation:
The transition to a competitive market environment may affect the Company's
future revenues and cash flows. In the event that recovery of the Company's
costs and investments becomes unlikely or uncertain due to competitive
pressures or regulatory changes, it could cause the Company to write off
applicable portions of its regulatory assets. The final CPUC determination of
uneconomic costs and the method of recovery could adversely affect the Company's
returns on its investments in electric generation assets. If future electric
generation revenues are insufficient to recover the Company's investments and
QF obligations, the Company would recognize a loss.
The Company currently accounts for the economic effects of regulation in
accordance with the provisions of Statement of Financial Accounting Standards
(SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation." As
a result of applying the provisions of SFAS No. 71, the Company has accumulated
approximately $3.7 billion of regulatory assets, including balancing accounts,
at December 31, 1994. As discussed further in Note 2 of Notes to Consolidated
Financial Statements, if the CPUC's electric industry restructuring proposal is
adopted as proposed or the Company determines that future electric generation
rates will no longer be based on cost-of-service, the Company will discontinue
application of SFAS No. 71 for the electric generation portion of its
operations. If such discontinuance should occur, the Company would write off
all applicable electric generation-related regulatory assets to the extent that
transition cost recovery is not assured. The regulatory assets attributable to
electric generation, excluding balancing accounts of approximately $700 million
which are expected to be recovered in the near term, are estimated to be $1.6
billion at December 31, 1994.
The final determination of the financial impact will depend on the form of
regulation, including transition mechanisms, if any, adopted by the CPUC and
the groups of customers affected. Currently, the Company is unable to predict
the ultimate outcome of the electric industry restructuring or predict whether
such outcome will have a significant impact on its financial position or
results of operations.
Proposed Accounting Standard:
The Financial Accounting Standards Board (FASB) has proposed a new accounting
standard, "Accounting for the Impairment of Long-Lived Assets," which is
expected to be issued in early 1995. The Company would be required to adopt the
new standard beginning January 1, 1996, but may elect to adopt it earlier.
If issued by the FASB as proposed, the new standard would require, among
other things, that regulatory assets recorded as a result of SFAS No. 71
continue to be probable of recovery in
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rates at all times, rather than only at the time the regulatory asset is
recorded. As such, regulatory assets currently recorded may require adjustment
in the future if recovery is no longer probable. Under the current ratemaking,
the Company does not believe there would be any immediate significant impact of
adopting the standard, as proposed.
Results of Operations
The Company's results of operations for the three years ended December 31,
1994, are reflected in the following table and discussed below.
Diablo
(in millions, except per share amounts) Utility Canyon (1) Enterprises Total
1994
Operating revenues $ 8,329 $1,870 $ 248 $10,447
Operating expenses 7,281 1,252 281 8,814
------- ------ ------ -------
Operating income (loss) $ 1,048 $ 618 $ (33) $ 1,633
======= ====== ====== =======
Net income $ 541 $ 461 $ 5 $ 1,007
======= ====== ====== =======
Earnings per common share $ 1.16 $ 1.04 $ .01 $ 2.21
======= ====== ====== =======
Total assets at year end $20,303 $5,978 $1,528 $27,809
======= ====== ====== =======
1993
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 $ 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
======= ====== ====== =======
(1) See Note 4 of Notes to Consolidated Financial Statements for discussion
of allocations.
Earnings Per Common Share:
Earnings per common share were $2.21, $2.33 and $2.58 for 1994, 1993 and 1992,
respectively. Earnings per common share for 1994 were lower than for 1993
primarily due to the refueling of both units of Diablo Canyon in 1994 compared
to only one unit in 1993. In 1994, the Company recorded special charges for
workforce reductions, gas reasonableness matters, contingencies related to gas
transportation commitments and an increase in litigation reserves which in the
aggregate totaled approximately $434 million. Special charges in 1993 totaled
approximately $410 million and included charges for workforce reductions, gas
decontracting, gas reasonableness matters, contingencies related to gas
transportation commitments and the impact of increasing the federal income
tax rate to 35 percent.
Earnings per common share for 1993 were lower than for 1992 due to charges
against earnings discussed above. These charges were partially offset by higher
Diablo Canyon revenues due to the annual increase in the price per kWh as
provided in the Diablo Canyon settlement.
Since the Diablo Canyon settlement in 1988, Diablo Canyon has made an
increasing contribution to the Company's total earnings per share. For the year
ended December 31, 1994, Diablo Canyon contributed $1.04 (47 percent) to the
total earnings per share of $2.21. The proposed modification of the price for
power produced by Diablo Canyon, discussed below, will likely cause a decrease
in the Diablo Canyon earnings per share contribution.
On a consolidated basis, the Company earned an 11.1 percent, 11.9 percent
and 13.7 percent return on average common stock equity for the years ended
December 31, 1994, 1993 and 1992, respectively. For 1995, the CPUC has
authorized a return on average common stock equity of 12.1 percent for the
Company's utility operations.
Common Stock Dividend:
In January 1995, the Board of Directors (Board) declared a quarterly dividend
of $.49 per share which corresponds to an annualized dividend of $1.96 per
share. 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. The Company has
a long-term objective of reducing its dividend payout ratio (dividends declared
divided by earnings available for common stock) to reflect the increased
business risk in the utility industry.
At this time, the Company is unable to determine the impact, if any, the
restructuring of the electric industry will have on the Company's ability to
increase its dividends in the future.
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Operating Revenues:
Electric revenues increased $162 million, $119 million and $378 million in
1994, 1993 and 1992, respectively, compared to the preceding year. Despite the
rate freeze, electric revenues increased due to higher energy costs in 1994
reflected in the electric energy cost balancing account. The higher revenues
from the energy cost balancing account were offset by the decrease in revenues
from Diablo Canyon resulting from the refueling of both units of the nuclear
power plant in 1994 as compared with only one unit in 1993. The Company will
continue through the end of 1995 its freeze on electric rates which began in
1993.
The increase in 1993 electric revenues was due to rate increases associated
with general increases in operating expenses and a higher electric rate base on
which PG&E is allowed to earn a return. 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 settlement.
The 1992 increase in electric revenues was primarily due to one scheduled
refueling outage at Diablo Canyon as compared with two scheduled refueling
outages in 1991, and the annual increase in the price per kWh as provided in
the Diablo Canyon settlement.
The Diablo Canyon 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.
As discussed further in Note 4 of Notes to Consolidated Financial
Statements, in December 1994, the Company, a consumer advocacy branch of the
CPUC staff (the Division of Ratepayer Advocates (DRA)), the California Attorney
General and several other parties representing energy consumers have agreed to
modify the pricing provisions of the Diablo Canyon settlement, subject to CPUC
approval. Under the proposed modification, the price for power produced by
Diablo Canyon would be reduced from what it would have been under the original
terms of the Diablo Canyon settlement.
The Diablo Canyon capacity factors for 1994, 1993 and 1992 were 81 percent,
89 percent and 88 percent, respectively, reflecting the scheduled refueling
outages for Units 1 and 2 in 1994, Unit 2 in 1993 and Unit 1 in 1992. The 1994
capacity factors were also impacted by 24 days of extended unscheduled outages.
There were no extended unscheduled outages in 1993 or 1992. Through December
31, 1994, the lifetime capacity factor for Diablo Canyon was 79 percent. The
Company will report significantly lower revenues for Diablo Canyon during any
extended outages, including refueling outages. Refueling outages, the length of
which depend on the scope of the work, typically occur for each unit every
eighteen months. The next refueling outages for Unit 1 and Unit 2 are scheduled
to begin in September 1995 and March 1996, respectively, and each is planned to
last about six weeks.
Under the proposed modification to the prices prescribed in the Diablo
Canyon settlement, each Diablo Canyon unit will contribute approximately $2.9
million in revenues per day at full operating power in 1995. The daily revenues
could decline each year for the next five years.
Gas revenues decreased $297 million in 1994 compared to the preceding year
primarily due to a decrease in revenues received from our industrial and large
commercial customers, who are now arranging for the purchase of their own gas
supplies, with the Company providing only transportation service partially
offset by revenues generated from the natural gas transmission expansion
project. (See Regulatory Matters.)
Gas revenues increased $168 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 well
as increased revenues from Enterprises reflecting increases in the price and
production of gas.
The 1992 increase in gas revenues was primarily due to revenues resulting
from the December 1991 acquisition of Tex/Con Oil & Gas Company by DALEN
Resources Corp. (DALEN), a wholly owned subsidiary of Enterprises.
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Operating Expenses:
Operating expenses in 1994 remained constant as compared to 1993. The 1994
operating expenses include a charge against earnings of $249 million related to
the workforce reductions that commenced in 1994. In comparison, the Company
expensed $190 million related to the 1993 workforce reductions. As a result of
the 1993 workforce reductions, administrative and general expense was less in
1994 as compared to 1993. The cost of electric energy was $312 million greater
in 1994 as compared to 1993 primarily due to less favorable hydro conditions
and an increase in the cost per kWh of purchased power. These unfavorable
variances were offset by a favorable variance of $365 million in the cost of
gas as a result of the Company no longer procuring gas for certain customers.
Income tax expense has declined due to lower operating income in 1994.
In 1993 and 1992, the Company's operating expenses increased $357 million
and $398 million, respectively, over the preceding year. The 1993 increase was
due to the charge related to the Company's 1993 workforce reductions and
increases in administrative and general expense, income tax expense, and
depreciation and decommissioning expense, partially offset by a decrease in the
cost of electric energy. Most of the $114 million increase in administrative
and general expense was due to an increase in litigation costs and an increase
in employee benefit costs upon adoption of SFAS No. 106, "Employers' Accounting
for Postretirement Benefits Other Than Pensions." The $100 million increase in
income tax expense was primarily due to the increase in the federal income tax
rate to 35 percent. The $166 million decrease in the cost of electric energy
was a result of improved hydro conditions and reflects a decline in the cost
per kWh for purchased power.
The 1992 increase in operating expenses was primarily due to increases in
the cost of gas, the cost of electric energy, and depreciation and
decommissioning expense.
Other Income and (Income Deductions):
Other--net includes charges in 1994 and 1993 related to gas issues. The 1994
charges consist of accruals for gas reasonableness matters, including proposed
settlement agreements and contingencies related to transportation capacity
commitments. (See Note 3 of Notes to Consolidated Financial Statements.) The
1993 charges include accruals for gas reasonableness matters and contingencies
related to transportation capacity commitments as well as charges associated
with restructuring the Company's Canadian gas supply arrangements.
Regulatory Matters:
In addition to the CPUC electric industry restructuring proposal, discussed
further in Note 2 of Notes to Consolidated Financial Statements, during 1994
the Company received CPUC decisions in proceedings on revenues and energy costs
and filed applications which will impact rates in 1995 and beyond. The most
significant of these are discussed below.
The CPUC has approved the Company's request to freeze retail electric rates
through the end of 1995. In order to accomplish the rate freeze, rate increases
attributable to energy costs and the increase in the authorized rate of return
were offset by base revenue reductions. The Company is implementing base cost
reductions which are reflected in the decreased base revenues.
Gas rates for commodity, transportation and base costs have increased as a
result of two decisions during 1994. In July, the CPUC approved a $162 million
increase for recovery of previously deferred gas and transportation costs. In
December, a $100 million increase in revenue was approved reflecting an
increase in the cost of capital, balancing accounts adjustments and
inflationary increases in costs.
In addition, the Company filed an application with the CPUC requesting a gas
rate increase of approximately $173 million annually for the two-year period
beginning in October 1, 1995. The Company's request reflects an increase in gas
and transportation costs and the collection of amounts previously deferred in
balancing accounts. If the Company's request is adopted, rates would be
effective September 15, 1995.
In January 1995, the Company updated its 1996 GRC application to reflect
CPUC decisions that went into effect on January 1, 1995. In the GRC, the
Company is seeking a $162 million decrease for electric revenues and a $92
million decrease for gas revenues, compared to rates in effect in 1994.
(Compared to rates in effect in 1995, there would be no change for electric
revenues and a $162 million decrease for gas revenues.) Revenues to be
collected from customers in 1996 may also be affected by future requests
related to energy costs and cost of capital.
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
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additional firm capacity to the Pacific Northwest and to Northern and
Southern California. The total cost of construction is approximately $1.7
billion. The Company has filed applications with the FERC (for the interstate
portion) and the CPUC (for the portion within California) requesting that
capital and operating costs be found reasonable. Revenues are currently being
collected under rates approved by the FERC and the CPUC, subject to refund. The
Company believes the final decisions on these applications will not have a
significant impact on its financial position or results of operations.
In accordance with mechanisms established by the CPUC, the Company
accumulates the difference between actual costs of generating electricity and
the revenues designed to recover such costs. To the extent costs exceed
revenues, the undercollection accumulates in the electric energy cost balancing
account. Over the past few years, the Company has experienced a significant
increase in the level of balancing account undercollection related to its
electric energy costs. The increase primarily results from Diablo Canyon's
generation exceeding that forecasted in the annual electric energy cost
proceeding, increased fuel costs, the use of higher-cost energy sources to
compensate for less than normal hydro conditions and the deferred recovery of
undercollected balances. At December 31, 1994, the electric energy cost
balancing account undercollection was approximately $716 million.
In order to accomplish its freeze on retail electric rates, the Company will
be deferring the recovery of $444 million of the electric energy cost
undercollection beyond 1995 and will also forgo collection of interest on these
deferred costs. Recovery of these deferred costs will depend on a number of
factors. However, the Company currently believes that the amount deferred will
be collected through rates over the near term. The modification of the price
for Diablo Canyon power will assist in reducing the undercollected energy cost
balance.
Nonregulated Operations:
The Company, through its wholly owned subsidiary, Enterprises, has taken steps
to position itself to compete in the nonregulated energy business. Enterprises
contributed $.01, $.04 and $(.02) per share to the Company's total earnings per
share for the years ended December 31, 1994, 1993 and 1992, respectively.
Enterprises makes the majority of its investments in nonregulated energy
projects through a joint venture, U.S. Generating. Enterprises in partnership
with Bechtel Enterprises, Inc. is in the process of forming a company to
develop, build, own and operate international nonutility generation projects.
In August 1994, Enterprises and Bechtel Enterprises, Inc. completed their
acquisition of J. Makowski Co., Inc. (JMC), a Boston-based company engaged in
the development of natural gas-fueled power generation projects and natural gas
distribution, supply and underground storage projects. The final purchase price
was approximately $250 million. Enterprises' effective ownership share of JMC
is approximately 80 percent.
In July 1994, the Company's Board approved a plan for the disposition of
DALEN, formerly PG&E Resources Company, through an initial public offering of
DALEN's common stock, as DALEN no longer fits Enterprises' business strategy.
The disposition, if completed, is not anticipated to have a significant impact
on the Company's financial position or results of operations.
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. Proceeds from the issuance of securities are used for capital
expenditures, refundings and other general corporate purposes.
Debt: In 1994, the Company issued $30 million of medium-term notes and
redeemed or repurchased $135 million of mortgage bonds, medium-term notes and
Eurobonds. In 1993, the Company issued $4.0 billion of mortgage bonds,
pollution control revenue bonds and medium-term notes. Substantially all these
proceeds were used to redeem or repurchase higher-cost mortgage bonds to
accomplish a reduction in financing costs.
In January 1995, the Board authorized the Company to redeem or repurchase up
to $153 million of mortgage bonds. In addition, $85 million remains from a
previous authorization to repurchase medium-term notes.
The Company issues short-term debt (principally commercial paper) to fund
fuel oil, nuclear fuel and gas inventories, unrecovered balances in balancing
accounts and cyclical fluctuations in daily cash flows. At December 31, 1994
and 1993, the Company had $525 million and $764
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million, respectively, of commercial paper outstanding. In addition, the
Company has a $1 billion short-term credit facility to support the sale of
commercial paper and other corporate purposes. There were no borrowings under
this facility in 1994, 1993 or 1992.
Equity: In 1994 and 1993, the Company received $274 million and $264 million,
respectively, 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 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. This program is 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, 1994, the
Company had repurchased approximately $435 million of its common stock under
this program.
In 1994, the Company issued $63 million of preferred stock with a mandatory
redemption provision and redeemed $75 million of the Company's higher-cost
preferred stock.
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.
Capital Requirements:
The Company's estimated capital requirements for the next three years are shown
below:
Year ended December 31,
-------------------------
(in millions) 1995 1996 1997
Utility $1,212 $1,276 $1,237
Diablo Canyon 47 50 52
Enterprises 285 142 284
------ ------ ------
Total capital expenditures 1,544 1,468 1,573
Maturing debt and sinking funds 477 373 369
------ ------ ------
Total capital requirements $2,021 $1,841 $1,942
====== ====== ======
Utility and Diablo Canyon expenditures will be primarily for improvements to
the Company's facilities to maintain their efficiency and reliability, to
extend their useful lives and to comply with environmental laws and
regulations.
Enterprises' estimated expenditures include oil and gas exploration and
development activities by DALEN of approximately $120 million for 1995, project
development expenditures for power and real-estate projects and equity
commitments associated with generating facility projects.
In addition to these capital requirements, the Company has other commitments
as discussed in Notes 3 and 12 of Notes to Consolidated Financial Statements.
Risk Management:
The Company uses a number of techniques to mitigate its financial risk
including the purchase of commercial insurance, the maintenance of systems of
internal control and the selected use of financial instruments. The extent to
which these techniques are used depends on the risk of loss and the cost to
employ such techniques. These techniques do not eliminate financial risk to the
Company.
The majority of the Company's financing is done on a fixed-term basis
thereby eliminating the financial risk associated with fluctuating interest
rates. The Company has used financial instruments to eliminate the effects of
fluctuations in interest rates and foreign currency exchange rates on certain
of its debt. At December 31, 1994, the Company, through a series of interest
rate swap transactions, had converted $639 million of a subsidiary's debt from
a floating rate to a fixed rate through July 31, 1999. The Company, through
foreign exchange contracts, has agreed to pay fixed interest and principal
payments in U.S. dollars on $67 million of Swiss Franc debentures.
In addition, DALEN periodically enters into crude oil and natural gas
hedging transactions to minimize the risk of price fluctuations. The net gains
and losses associated with these transactions have not been material.
Environmental Matters:
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 $39 million, $93 million and $85
million for 1995, 1996 and 1997, respectively, and are included in the
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Company's three-year table in the Capital Requirements section above.
Expenditures during these years will be primarily for nitrogen oxide (NOx)
emission reduction projects for the Company's fossil fuel fired generating
plants and natural gas compressor stations. Pursuant to federal and state
legislation, local air districts have adopted rules that require reductions in
NOx emissions from company facilities. Final rules have yet to be adopted in
all local air districts in which the Company operates and these rules continue
to be modified. The Company currently estimates that compliance with NOx rules
likely to be in place could require capital expenditures of up to $355 million
over the next ten years.
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 is difficult to estimate, the Company has
an accrued liability at December 31, 1994, of $95 million for hazardous waste
remediation costs. The costs could be as much as $235 million, 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. (See Note 13 of Notes to Consolidated
Financial Statements.)
Legal Matters:
In the normal course of business, the Company is named as a party in a number
of claims and lawsuits. Substantially all of these are litigated or settled
with no significant impact on either the Company's results of operations or
financial position.
There are several significant litigation cases which are discussed in Note
13 of Notes to Consolidated Financial Statements. These cases include claims
for personal injury and property damage, as well as punitive damages, allegedly
suffered as a result of exposure to chromium near the Company's Hinkley
Compressor Station, antitrust claims for damages as a result of Canadian
natural gas purchases by one of the Company's wholly owned subsidiaries and two
claims that the Company underpaid franchise fees.
Accounting for Decommissioning Expense:
The staff of the Securities and Exchange Commission has questioned certain
current accounting practices of the electric utility industry, regarding the
recognition, measurement and classification of decommissioning costs for
nuclear generating stations. In response to these questions, the FASB has
agreed to review the accounting for removal costs, including decommissioning.
If current electric utility industry accounting practices for such
decommissioning are changed: (1) Annual expense for decommissioning could
increase and (2) The estimated total cost for decommissioning could be recorded
as a liability rather than accrued over time as accumulated depreciation. The
Company does not believe that such changes, if required, would have an adverse
effect on its results of operations due to its current ability to recover
decommissioning costs through rates.
20
10
Pacific Gas and Electric Company
STATEMENT OF CONSOLIDATED INCOME
Year Ended December 31,
- ----------------------------------------
(in thousands, except per share amounts) 1994 1993 1992
OPERATING REVENUES
Electric $ 8,027,976 $ 7,866,043 $ 7,747,492
Gas 2,419,375 2,716,365 2,548,596
----------- ----------- -----------
Total operating revenues 10,447,351 10,582,408 10,296,088
----------- ----------- -----------
OPERATING EXPENSES
Cost of electric energy 2,561,778 2,250,209 2,416,554
Cost of gas 574,894 939,572 907,945
Distribution 229,640 226,975 219,082
Transmission 293,995 319,022 339,099
Customer accounts and services 433,603 403,560 421,990
Maintenance 456,889 442,939 484,751
Depreciation and decommissioning 1,397,470 1,315,524 1,221,490
Administrative and general 973,302 1,041,453 927,316
Workforce reduction costs 249,097 190,200 -
Income taxes 924,620 1,006,774 906,845
Property and other taxes 296,911 297,495 295,164
Other 421,793 385,755 322,411
----------- ----------- -----------
Total operating expenses 8,813,992 8,819,478 8,462,647
----------- ----------- -----------
OPERATING INCOME 1,633,359 1,762,930 1,833,441
----------- ----------- -----------
OTHER INCOME AND (INCOME DEDUCTIONS)
Interest income 108,092 85,642 87,244
Allowance for equity funds used during
construction 19,046 41,531 39,368
Other--net (8,344) (53,524) (3,006)
----------- ----------- -----------
Total other income and (income deductions) 118,794 73,649 123,606
----------- ----------- -----------
INCOME BEFORE INTEREST EXPENSE 1,752,153 1,836,579 1,957,047
----------- ----------- -----------
INTEREST EXPENSE
Interest on long-term debt 651,912 731,610 739,279
Other interest charges 105,744 118,100 91,404
Allowance for borrowed funds used during
construction (12,953) (78,626) (44,217)
----------- ----------- -----------
Total interest expense 744,703 771,084 786,466
----------- ----------- -----------
NET INCOME 1,007,450 1,065,495 1,170,581
Preferred dividend requirement 57,603 63,812 78,887
----------- ----------- -----------
EARNINGS AVAILABLE FOR COMMON STOCK $ 949,847 $ 1,001,683 $ 1,091,694
=========== =========== ===========
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING 429,846 430,625 422,714
EARNINGS PER COMMON SHARE $2.21 $2.33 $2.58
DIVIDENDS DECLARED PER COMMON SHARE $1.96 $1.88 $1.76
The accompanying Notes to Consolidated Financial Statements are an integral
part of this statement.
21
11
Pacific Gas and Electric Company
CONSOLIDATED BALANCE SHEET
December 31,
----------------------------
(in thousands) 1994 1993
ASSETS
PLANT IN SERVICE
Electric
Nonnuclear $ 17,045,247 $ 16,633,772
Diablo Canyon 6,647,162 6,518,413
Gas 7,447,879 7,146,741
------------ ------------
Total plant in service (at original cost) 31,140,288 30,298,926
Accumulated depreciation and decommissioning (12,269,377) (11,235,519)
------------ ------------
Net plant in service 18,870,911 19,063,407
------------ ------------
CONSTRUCTION WORK IN PROGRESS 527,867 620,187
OTHER NONCURRENT ASSETS
Oil and gas properties 437,352 573,523
Nuclear decommissioning funds 616,637 536,544
Investment in nonregulated projects 761,355 304,223
Other assets 137,325 193,466
------------ ------------
Total other noncurrent assets 1,952,669 1,607,756
------------ ------------
CURRENT ASSETS
Cash and cash equivalents 136,900 61,066
Accounts receivable
Customers 1,413,185 1,264,907
Other 98,035 123,255
Allowance for uncollectible accounts (29,769) (23,647)
Regulatory balancing accounts receivable 1,345,669 992,477
Inventories
Materials and supplies 197,394 239,856
Gas stored underground 136,326 170,345
Fuel oil 67,707 109,615
Nuclear fuel 140,357 134,411
Prepayments 33,251 56,062
------------ ------------
Total current assets 3,539,055 3,128,347
------------ ------------
DEFERRED CHARGES
Income tax-related deferred charges 1,155,421 1,276,532
Diablo Canyon costs 401,110 419,775
Unamortized loss net of gain on reacquired debt 382,862 395,659
Workers' compensation and disability claims recoverable 247,209 192,203
Other 732,029 458,660
------------ ------------
Total deferred charges 2,918,631 2,742,829
------------ ------------
TOTAL ASSETS $ 27,809,133 $ 27,162,526
============ ============
The accompanying Notes to Consolidated Financial Statements are an integral
part of this statement.
22
12
Pacific Gas and Electric Company
CONSOLIDATED BALANCE SHEET
December 31,
----------------------------
(in thousands) 1994 1993
CAPITALIZATION AND LIABILITIES
CAPITALIZATION
Common stock $ 2,151,213 $ 2,136,095
Additional paid-in capital 3,806,508 3,666,455
Reinvested earnings 2,677,304 2,643,487
----------- -----------
Total common stock equity 8,635,025 8,446,037
Preferred stock without mandatory redemption provisions 732,995 807,995
Preferred stock with mandatory redemption provisions 137,500 75,000
Long-term debt 8,675,091 9,292,100
----------- -----------
Total capitalization 18,180,611 18,621,132
----------- -----------
OTHER NONCURRENT LIABILITIES
Customer advances for construction 152,384 152,872
Workers' compensation and disability claims 221,200 157,000
Other 644,233 246,950
----------- -----------
Total other noncurrent liabilities 1,017,817 556,822
----------- -----------
CURRENT LIABILITIES
Short-term borrowings 524,685 764,163
Long-term debt 477,047 221,416
Accounts payable
Trade creditors 414,291 472,985
Other 337,726 389,065
Accrued taxes 436,467 303,575
Deferred income taxes 432,026 315,584
Interest payable 84,805 82,105
Dividends payable 210,903 203,923
Other 643,779 487,809
----------- -----------
Total current liabilities 3,561,729 3,240,625
----------- -----------
DEFERRED CREDITS
Deferred income taxes 3,902,645 3,978,950
Deferred investment tax credits 391,455 410,969
Noncurrent balancing account liabilities 226,844 112,533
Other 528,032 241,495
----------- -----------
Total deferred credits 5,048,976 4,743,947
----------- -----------
COMMITMENTS AND CONTINGENCIES
(Notes 2, 3, 12 and 13)
----------- -----------
TOTAL CAPITALIZATION AND LIABILITIES $27,809,133 $27,162,526
=========== ===========
23
13
Pacific Gas and Electric Company
STATEMENT OF CONSOLIDATED CASH FLOWS
Year ended December 31,
----------------------------------------
(in thousands) 1994 1993 1992
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 1,007,450 $ 1,065,495 $ 1,170,581
Adjustments to reconcile net income to net cash
provided by operating activities
Depreciation and decommissioning 1,397,470 1,315,524 1,221,490
Amortization 49,671 135,808 121,795
Gain on sale of investment in Alberta Natural
Gas Company Ltd - - (48,722)
Deferred income taxes and investment tax
credits--net 15,312 319,198 164,457
Allowance for equity funds used during
construction (19,046) (41,531) (39,368)
Other deferred charges 32,740 (158,725) 8,147
Other noncurrent liabilities 301,842 50,279 31,374
Other deferred credits 105,262 110,145 73,259
Net effect of changes in operating assets
and liabilities
Accounts receivable (116,936) 64,790 39,922
Regulatory balancing accounts receivable (353,192) (218,553) (215,195)
Inventories 112,443 23,097 (7,161)
Accounts payable (110,033) (39,422) (102,559)
Accrued taxes 132,892 44,638 128,243
Other working capital 181,481 108,873 (36,117)
Other--net 210,331 13,184 49,891
----------- ----------- -----------
Net cash provided by operating activities 2,947,687 2,792,800 2,560,037
----------- ----------- -----------
CASH FLOWS FROM INVESTING ACTIVITIES
Construction expenditures (1,094,495) (1,763,024) (2,307,318)
Allowance for borrowed funds used during
construction (12,953) (78,626) (44,217)
Nonregulated expenditures (328,266) (234,221) (148,226)
Proceeds from sale of investment in Alberta
Natural Gas Company Ltd - - 97,251
Other--net (29,914) 9,992 82,352
---------- ----------- -----------
Net cash used by investing activities (1,465,628) (2,065,879) (2,320,158)
---------- ----------- -----------
CASH FLOWS FROM FINANCING ACTIVITIES
Common stock issued 274,269 264,489 296,653
Common stock repurchased (181,558) (257,780) (5,410)
Preferred stock issued 62,312 200,001 195,451
Preferred stock redeemed (83,275) (302,640) (276,806)
Long-term debt issued 60,907 4,584,548 1,676,513
Long-term debt matured or reacquired (436,673) (4,002,704) (1,409,337)
Short-term debt issued (redeemed)--net (239,478) (366,961) 121,213
Dividends paid (891,850) (857,515) (809,108)
Other--net 29,121 (24,885) (28,736)
---------- ----------- -----------
Net cash used by financing activities (1,406,225) (763,447) (239,567)
---------- ----------- -----------
NET CHANGE IN CASH AND CASH EQUIVALENTS 75,834 (36,526) 312
CASH AND CASH EQUIVALENTS AT JANUARY 1 61,066 97,592 97,280
---------- ----------- -----------
CASH AND CASH EQUIVALENTS AT DECEMBER 31 $ 136,900 $ 61,066 $ 97,592
========== =========== ===========
Supplemental disclosures of cash flow information
Cash paid for
Interest (net of amounts capitalized) $ 674,758 $ 642,712 $ 694,512
Income taxes 712,777 542,827 682,809
The accompanying Notes to Consolidated Financial Statements are an integral
part of this statement.
24
14
Pacific Gas and Electric Company
STATEMENT OF CONSOLIDATED COMMON STOCK EQUITY AND PREFERRED STOCK
Preferred Preferred
Stock Stock
Total Without With
Additional Common Mandatory Mandatory
(dollars in thousands) Common Paid-in Reinvested Stock Redemption Redemption
Stock Capital Earnings Equity Provisions Provisions(1)
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
---------- ---------- ---------- ---------- --------- --------
Net income--1994 1,007,450 1,007,450
Common stock issued
(10,508,483 shares) 52,543 221,726 274,269
Common stock repurchased
(7,485,001 shares) (37,425) (66,334) (77,799) (181,558)
Preferred stock issued
(2,500,000 shares) (188) (188) 62,500
Preferred stock redeemed
(3,000,000 shares) (5,331) (2,544) (7,875) (75,000)
Cash dividends declared
Preferred stock (58,203) (58,203)
Common stock (840,627) (840,627)
Other (9,820) 5,540 (4,280)
---------- ---------- ---------- ---------- --------- --------
Net change 15,118 140,053 33,817 188,988 (75,000) 62,500
---------- ---------- ---------- ---------- --------- --------
BALANCE DECEMBER 31, 1994 $2,151,213 $3,806,508 $2,677,304 $8,635,025 $ 732,995 $137,500
========== ========== ========== ========== ========= ========
(1) Includes current portion.
The accompanying Notes to Consolidated Financial Statements are an integral
part of this statement.
25
15
Pacific Gas and Electric Company
STATEMENT OF CONSOLIDATED CAPITALIZATION
December 31,
----------------------------
(dollars in thousands, except per share amounts) 1994 1993
COMMON STOCK EQUITY
Common stock, par value $5 per share
(authorized 800,000,000 shares, issued and
outstanding 430,242,687 and 427,219,205 $ 2,151,213 $ 2,136,095
Additional paid-in capital 3,806,508 3,666,455
Reinvested earnings 2,677,304 2,643,487
----------- -----------
Common stock equity 8,635,025 8,446,037
----------- -----------
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%--23,534,958 and 26,534,958 shares outstanding 588,374 663,374
----------- -----------
Total preferred stock without mandatory redemption
provision 732,995 807,995
----------- -----------
Preferred stock with mandatory redemption provision
Par value $25 per share (1)
6.30%--2,500,000 and none outstanding 62,500 -
6.57%--3,000,000 shares outstanding 75,000 75,000
Par value $100 per share (authorized 10,000,000 shares) - -
----------- -----------
Total preferred stock with mandatory redemption
provision 137,500 75,000
----------- -----------
Preferred stock 870,495 882,995
----------- -----------
LONG-TERM DEBT
PG&E long-term debt
First and refunding mortgage bonds
Maturity Interest rates
1994-1999 4.25% to 6.875% 714,074 724,610
2000-2005 5.875% to 8.75% 1,658,749 1,739,649
2006-2012 6.25% to 8.875% 477,870 477,870
2013-2019 7.5% to 12.75% 136,030 140,900
2020-2026 5.85% to 9.30% 2,902,945 2,947,428
----------- -----------
Principal amounts outstanding 5,889,668 6,030,457
Unamortized discount net of premium (66,198) (71,817)
----------- -----------
Total mortgage bonds 5,823,470 5,958,640
Unsecured debentures, 10.81% to 12%, due 1994-2000 124,939 221,523
Pollution control loan agreements, variable rates,
due 2008-2016 925,000 925,000
Unsecured medium-term notes, 4.13% to 10.10% due 1994-2014 1,443,800 1,542,625
Unamortized discount related to unsecured medium-term notes (2,428) (3,459)
Other long-term debt 22,209 24,127
----------- -----------
Total PG&E long-term debt 8,336,990 8,668,456
Long-term debt of subsidiaries 815,148 845,060
----------- -----------
Total long-term debt of PG&E and subsidiaries 9,152,138 9,513,516
Less long-term debt--current portion 477,047 221,416
----------- -----------
Long-term debt 8,675,091 9,292,100
----------- -----------
TOTAL CAPITALIZATION $18,180,611 $18,621,132
=========== ===========
(1) Authorized 75,000,000 shares in total (both with and without mandatory
redemption provisions).
The accompanying Notes to Consolidated Financial Statements are an integral
part of this statement.
26
16
Pacific Gas and Electric Company
SCHEDULE OF CONSOLIDATED SEGMENT INFORMATION
Diversified
Operations Intersegment
(in thousands) Electric Gas (4) Eliminations Total
1994
Operating revenues $ 8,006,157 $2,194,870 $ 246,324 $ - $10,447,351
Intersegment revenues (1) 12,852 85,341 1,695 (99,888) -
----------- ---------- ---------- --------- -----------
Total operating revenues $ 8,019,009 $2,280,211 $ 248,019 $ (99,888) $10,447,351
=========== ========== ========== ========= ===========
Depreciation and
decommissioning $ 982,859 $ 295,979 $ 118,632 $ - $ 1,397,470
Operating income before
income taxes (2) 2,213,518 381,078 (33,390) (3,227) 2,557,979
Construction
expenditures (3) 834,494 292,000 - - 1,126,494
Identifiable assets (3) $19,471,121 $6,433,984 $1,436,128 $ - $27,341,233
Corporate assets 467,900
-----------
Total assets at end of year $27,809,133
===========
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 end of year $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 end of year $24,188,159
===========
(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 the 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 statement.
27
17
Pacific Gas and Electric Company
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 (collectively, 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 the California border; Alberta and Southern Gas Co. Ltd. (A&S)--
prior to November 1, 1993, bought gas in Canada and arranged its transport to
the U.S. border (see Note 3 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 DALEN Resources
Corp. (DALEN), formerly PG&E Resources Company, which engages in exploration,
development and production of oil and natural gas, and PG&E Generating Company
which through a joint venture (U.S. Generating) develops, builds, owns and
operates independent power projects.
Alberta Natural Gas Company Ltd (ANG), a 49.98% owned affiliate of PGT which
transports natural gas, was sold in June 1992. 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 delivery 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 primarily
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 the actual cost of gas and
electric energy and the revenues 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 3 for further
discussion of gas costs.)
Plant in Service:
The cost of plant additions and replacements is capitalized. Cost includes
labor, materials, construction overhead 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, the California portion of the PGT-PG&E Pipeline
Expansion Project (Pipeline Expansion), and other nonregulated projects are
calculated under Statement of Financial Accounting Standards (SFAS) No. 34,
"Capitalization of Interest Cost." The original cost of retired plant plus
removal costs less salvage value are charged to accumulated depreciation.
Maintenance, repairs and minor replacements and additions are charged to
maintenance expense.
Depreciation and Nuclear Decommissioning Costs:
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 years ended
December 31, 1994, 1993 and 1992, the amount recovered in rates for
decommissioning costs was $54 million each year. The estimated total obligation
for nuclear decommissioning costs is approximately $1.1 billion in 1994 dollars
(or $4.5 billion in future dollars); this obligation is being recognized
ratably over the facilities' lives. This estimate considers the total cost
(including labor, materials and other 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.
The decommissioning method selected for Diablo Canyon anticipates that the
equipment, structures, and portions of the facility and site containing
radioactive contaminants will be removed or decontaminated to a level that
permits the property to be released for unrestricted use. Humboldt Bay Power
Plant is being decommissioned under a method that consists of placing and
maintaining the facility in protective storage until some future time when
dismantling can be initiated. The average annualized escalation rate and the
assumed return on qualified trust assets used to calculate the decommissioning
obligation and annual expense are approximately 5.5 percent and 5.25 percent
(6.25 percent on
28
18
nonqualified trust assets), respectively. (See Note 8 for
further discussion of nuclear decommissioning funds.)
As required by federal law, the U.S. Department of Energy (DOE) is
responsible for the future storage and disposal of spent nuclear fuel. No
permanent storage site has been identified and the DOE has indicated that the
storage site will not be available until after 2010. The Company pays a
one-tenth of one cent fee on each nuclear kilowatthour (kWh) sold to fund DOE
storage and disposal activities.
Income Taxes:
The Company files a consolidated federal income tax return that includes
domestic subsidiaries in which its ownership is 80 percent or more. Income tax
expense includes current and deferred income taxes 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 current income tax rates.
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 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 $300 million 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. Due to regulatory treatment, the
adoption of SFAS No. 109 did not have a significant impact on the Company's
results of operations.
Debt Premium, Discount and Related Expenses:
Long-term debt premium, discount and related expenses 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 Pipeline Expansion are recognized in income,
and if material as an extraordinary item, at the time such debt is reacquired.
Occasionally, the Company uses interest rate swap agreements and foreign
currency contracts to hedge fluctuations in interest rates and foreign currency
exchange rates. The Company defers any gains or losses on these transactions
and records interest expense adjusted for the effects of the agreements.
Oil and Gas Properties:
DALEN 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 (valued at cost which approximates market) include
special deposits, working funds and short-term investments with original
maturities of three months or less.
Reclassifications:
Certain amounts in the prior years' consolidated financial statements have been
reclassified to conform to the 1994 presentation.
Note 2: COMPETITION AND REGULATION
In April 1994, the CPUC issued an order instituting a rulemaking and an
investigation (OIR/OII) on electric industry restructuring. The proposal, which
is subject to comment and modification, involves two major changes in electric
industry regulation in California.
The first would move electric utilities from traditional ratemaking to
performance-based ratemaking. The second would unbundle electric services and
provide electric utility retail customers with the option to choose from a
range of electric generation providers, including utilities (direct access).
Direct access would be phased in over a six-year period beginning in 1996.
Utilities would still be obligated to provide transmission and distribution
services to all customers.
To ensure an orderly transition that maintains the financial integrity of
the utilities, the CPUC proposed that uneconomic costs of utility generating
assets be recovered through a "competition transition charge" (CTC). However,
the OIR/OII did not specify which costs might be recovered through such a
transition charge or how such a charge would be allocated to and collected from
customers.
In June 1994, the Company filed its initial comments on the CPUC's proposal.
The Company's response proposed an implementation schedule for direct access
beginning in
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1996, with direct access service available to all customers by
2008. For direct access customers, the Company proposed that it be given the
pricing flexibility to compete and sell unbundled electric power while assuming
the market risk of competitive pricing.
In November 1994, the Company filed testimony with the CPUC on its plan for
recovering uneconomic assets and obligations which would result from the
restructuring of the electric industry as proposed by the CPUC. The Company's
testimony, among other things, identifies and defines the costs proposed to be
included in the CTC, provides preliminary estimates of the transition costs and
discusses options for allocating and recovering those costs. Based on market
prices of $.048 and $.032 per kWh, the Company estimated that its uneconomic
generating assets and obligations are approximately $3 billion and $11 billion,
respectively, resulting from the restructuring as proposed by the CPUC. The
Company identified three categories of uneconomic assets: utility-owned
generation assets and power purchase commitments, power purchase obligations
relating to Qualifying Facilities (QFs), and generation-related regulatory
assets. The estimates of uneconomic assets were determined by comparing future
revenue requirements of generation assets and power purchase obligations, over
a twenty-year and thirty-year period, respectively, with revenues computed at
assumed market prices. Diablo Canyon was included in the revenue requirement
calculation using the proposed pricing modification to the Diablo Canyon
settlement. (See Note 4.) The revenue requirement for Diablo Canyon and all
Company-owned generation assets included a return on investment. The actual
amount of uneconomic assets and obligations will depend on the final regulation
and the actual market price of electricity.
Under the Company's proposal for a longer phase-in period to direct access,
the Company would not seek recovery of the transition costs associated with its
own generation assets and power purchase commitments, except for commitments to
purchase power from QFs. Based on this assumption and the market price
assumptions referred to above, the uneconomic assets and obligations are
approximately $3 billion and $5 billion, respectively. If the CPUC adopts a
shorter phase-in period, the Company indicated that it would seek recovery of
all uneconomic assets and obligations resulting from the restructuring through
the CTC.
In December 1994, the CPUC issued an interim decision in the OIR/OII. The
decision sets a schedule under which the CPUC will propose a policy decision in
March 1995, with a final policy decision to be effective no earlier than
September 1995. The CPUC's proposed policy statement will be subject to
hearings and state legislative review before it can be implemented. The CPUC
also established a public working group to comment on unbundling and transition
cost recovery, social programs and resource procurement, under several
different models for restructuring which include direct access and a supply
pool for use by wholesale and/or retail purchasers of electricity.
Financial Impact of the Electric Industry Restructuring Proposal:
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." As a result of applying the provisions of SFAS No. 71, the Company
has accumulated approximately $3.7 billion of regulatory assets, including
balancing accounts, at December 31, 1994.
In the event that recovery of specific costs through rates becomes unlikely
or uncertain for all or a portion of the Company's utility operations, whether
resulting from the expanding effects of competition or specific regulatory
actions, it could cause the Company to write off applicable portions of its
regulatory assets.
If the OIR/OII is adopted as proposed, or the Company determines that future
electric generation rates will no longer be based on cost-of-service, the
Company will discontinue application of SFAS No. 71 for the electric generation
portion of its operations. The Company continues to evaluate the current
regulatory and competitive environment to determine whether and when such a
discontinuance would be appropriate. If such discontinuance should occur, the
Company would write off all applicable generation-related regulatory assets to
the extent that transition cost recovery is not assured. The regulatory assets
attributable to electric generation, excluding balancing accounts of
approximately $700 million which are expected to be recovered in the near term,
were approximately $1.6 billion at December 31, 1994. This amount could vary
depending on the allocation methods used.
The final CPUC determination of uneconomic costs and the method of recovery
could adversely affect the Company's returns on its investments in electric
generation assets. If future electric generation revenues are insufficient to
recover the Company's investments and QF obligations, the Company would
recognize a loss.
The final determination of the financial impact will depend on the form of
regulation, including transition mechanisms, if any, adopted by the CPUC and
the groups of customers affected. Currently, the Company is unable to predict
the ultimate outcome of the electric industry restructuring or predict whether
such outcome will have a significant impact on its financial position or
results of operations.
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Note 3: Natural Gas Matters
Regulatory Restructuring:
Beginning August 1, 1993, PG&E implemented the CPUC's capacity brokering
program which requires PG&E to make available for brokering all interstate gas
pipeline capacity which is not held for its residential and smaller commercial
(core) customers, and industrial and large commercial customers who choose
bundled gas services (core subscription customers). PG&E's industrial and large
commercial (noncore) customers, producers, aggregators, marketers and the
Company's electric department can bid for such capacity.
In addition, beginning November 1, 1993, PGT implemented the FERC's Order No.
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 allowed more of the
Company's noncore customers to arrange for the purchase and transportation of
their own gas supplies. As a result, the Company's gas purchase requirements
and related need for firm transportation capacity for its gas purchases
decreased, contributing to the Company's need to restructure its 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 natural gas from
approximately 190 Canadian gas producers under various long-term contracts,
most of which extended through 2005. 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 effective
November 1, 1993.
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 prior claims related to these contracts. The total
amount of settlement payments paid to producers was approximately $210 million.
As part of the overall decontracting process, A&S's operations have been
significantly reduced. A&S permanently assigned significant portions of its
commitments for transportation capacity with NOVA Corporation of Alberta (NOVA)
through October 2001 and ANG through October 2005 to third parties. In
addition, A&S 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. With the permanent assignments of its
capacity made through the end of 1994, A&S holds remaining capacity of
approximately 300 MMcf/d on each of the pipelines with total annual demand
charges of approximately $15 million for which it is continuing its efforts to
assign or broker. A&S believes it will be able to permanently assign
substantially all of its remaining capacity by the end of 1995. To the extent
others do not take this capacity, A&S will remain obligated to pay for the
related demand charges.
The FERC approved a transition cost recovery mechanism for PGT under which
most costs incurred to restructure, reform or terminate the sales arrangements
between A&S and PGT and the 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 arising out of the former contracts, are treated as transition
costs. Twenty-five percent of the transition costs was absorbed by PGT.
Twenty-five percent of the transition costs was recovered by PGT through direct
bills (substantially all to PG&E as PGT's principal customer). The final fifty
percent of the transition costs is being 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.
Financial Impact of Decontracting Plan:
The Company incurred transition costs of $228 million in 1993, consisting of
settlement payments made to producers in connection with the implementation of
the Decontracting Plan and amounts incurred by A&S in reducing certain
administrative and general functions resulting from the restructuring. Of these
costs, the Company deferred $143 million for future rate recovery. In addition,
the Company recorded a charge of $31 million in 1993 related to A&S's remaining
commitments for Canadian transportation capacity. Accordingly, the Company
expensed $93 million in 1993 and a total of $23 million in prior years.
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 offset to the extent the Company can broker or permanently
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 agreements with PGT) were approximately $225 million in 1994, $280
million in 1993 and $300 million in 1992.
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The following table summarizes the approximate capacity held by the Company
on various pipelines and the related annual demand charges as of December 31,
1994:
Total
Firm Capacity Annual Demand
Pipeline Held Charges Contract
Company (MMcf/d) (in millions) Expiration
- ------------------------- ------------- ------------- ----------
El Paso 1,140 $130 December 1997
Transwestern 200 $ 30 March 2007
NOVA 870 $ 25 October 2001
ANG 890 $ 15 October 2005
Regulatory changes have resulted in a decrease in the Company's need for
firm transportation capacity for its own gas purchases. PG&E holds
approximately 600 MMcf/d of firm capacity on each of the pipelines owned by El
Paso Natural Gas Company (El Paso), NOVA and ANG, and 150 MMcf/d on the
pipeline owned by Transwestern Pipeline Company (Transwestern) to service its
core and core subscription customers. In addition, PG&E holds for its electric
department approximately 50 MMcf/d on Transwestern. The Company is continuing
its efforts to broker or assign any remaining unused capacity including certain
amounts of that held for its core and core subscription customers when such
capacity is not being used.
Based on the current demand for Canadian pipeline capacity, the Company
believes it will be able to broker or assign substantially all of its unused
capacity on NOVA and ANG; however, due to lower demand for Southwest pipeline
capacity, the Company cannot predict the volume or price of the capacity on El
Paso and Transwestern that will be brokered or assigned. Substantially all
demand charges incurred by the Company for pipeline capacity, including charges
for capacity that is not brokered or brokered at a discount, are eligible for
rate recovery subject to a reasonableness review.
The Division of Ratepayer Advocates (DRA), a consumer advocacy branch of the
CPUC staff, and others have challenged recovery of all demand charges for the
Company's Transwestern capacity and of certain other demand charges for
capacity not brokered or brokered at a discount. In November 1994, the CPUC
approved an interim increase in gas rates, subject to refund, designed to
collect approximately one-half of the demand charges for unbrokered or
discounted El Paso and PGT capacity. The decision set hearings on the issue,
and acknowledged that significant reasonable costs continue to accrue. The
Company believes that the ultimate resolution of these matters will not have a
significant adverse impact on its financial position or results of operations.
Gas Reasonableness Proceedings:
Recovery of energy 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.
In March 1994, the CPUC issued decisions covering the years 1988 through
1990, ordering disallowances of $90 million of gas costs, plus accrued interest
of approximately $25 million through 1993 for the Company's Canadian gas
procurement activities, and $8 million for gas inventory operations. The
Company has filed a lawsuit in a federal district court challenging the CPUC
decision on Canadian gas costs.
The CPUC decision on the Company's Canadian gas procurement activities found
that the Company could have saved its customers money if it had bargained more
aggressively with its then-existing Canadian suppliers or bought lower-priced
gas from other Canadian sources. The CPUC concluded that it was appropriate for
the Company to take a substantial portion of its Canadian gas (up to 700
MMcf/d) at the actual price charged under its then-existing Canadian gas supply
contracts, but that the Company could have met the remainder of its Canadian
gas requirement with lower-priced gas, either under those same contracts or
with purchases from other Canadian natural gas sources.
A number of other reasonableness issues related to the Company's gas
procurement practices, transportation capacity commitments and supply
operations for periods dating from 1988 to 1994 are still under review by the
CPUC. The DRA recommended disallowances of $142 million and a penalty of $50
million and indicated that it was considering additional recommendations for
pending issues. The Company and the DRA have signed settlement agreements to
resolve most of these issues for a $68 million disallowance.
Significant issues covered by the settlement agreements include (1) the
Company's purchases of Canadian, Southwest and California gas for its electric
department in 1991 and 1992 and its core customers from 1991 through May 1994;
(2) the investigation by the DRA of A&S and proposed investigation of ANG for
the period 1988 through May 1994; (3) the effects of Canadian gas prices on
amounts paid by the Company for Northwest power purchases for 1988 through 1992
and power from QFs and geothermal producers for 1991 and 1992; (4) the
Company's gas storage operations for 1991 and 1992; (5) the Company's
Southwest gas procurement activities for 1988 through 1990; and (6) Canadian
gas restructuring transition costs billed to PG&E by PGT.
Agreements with the DRA do not constitute a CPUC decision and are subject to
modification by the CPUC in its final decisions.
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Financial Impact of Reasonableness Proceedings:
The Company accrued approximately $135 million and $61 million in 1994 and
1993, respectively, for gas reasonableness matters including the CPUC decisions
for the years 1988 through 1990 and issues covered by the settlement
agreements. The Company believes the ultimate outcome of these matters will not
have a significant impact on its financial position or results of operations.
Note 4: Diablo Canyon
Rate Case Settlement:
The 1988 Diablo Canyon rate case settlement (Diablo Canyon settlement) 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 affirmed that Diablo Canyon costs and operations should no
longer be subject to CPUC reasonableness reviews.
The Diablo Canyon settlement provides that only certain Diablo Canyon costs
be recovered through base rates over the term of the Diablo Canyon settlement,
including a full return on such costs. 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:
In December 1994, the Company, the DRA, the California Attorney
General and several other parties representing energy consumers agreed to
modify the pricing provisions of the Diablo Canyon settlement. The
modification, which is subject to CPUC approval, calls for a reduction in the
price paid for electricity generated by Diablo Canyon over the next five years.
Under the Diablo Canyon settlement, the price per kWh of electricity
generated by Diablo Canyon consists of a fixed and an escalating component. The
total prices for 1994, 1993 and 1992 were 11.89 cents, 11.16 cents and 10.34
cents per kWh, respectively. Under the proposed modification, the price for
power produced by Diablo Canyon would be reduced from the current level as
shown in the following table. Under the proposed pricing, at full operating
power each Diablo Canyon unit would contribute approximately $2.9 million in
revenues per day in 1995.
Diablo Canyon Price (cents) per kWh
-----------------------------------
1995 1996 1997 1998 1999
Original Settlement Price* 12.15 12.42 12.70 12.98 13.28
Proposed Price 11.00 10.50 10.00 9.50 9.00
- ----------------
* assumes 3.5% inflation
After December 31, 1999, the escalating portion of the Diablo Canyon price
would increase using the same formula specified in the original Diablo Canyon
settlement. The proposed modification provides the Company with the right to
reduce the price below the amount specified.
The parties to the proposed modification have agreed that the difference
between the Company's revenue requirement under the original Diablo Canyon
settlement prices and the proposed prices would be applied to the energy cost
balancing account until the undercollection in that account is fully amortized.
Financial Information:
Selected financial information for Diablo Canyon is shown below:
Year ended December 31,
---------------------------
(in millions) 1994 1993 1992
Operating revenues $1,870 $1,933 $1,781
Operating income 618 708 663
Net income 461 496 443
In determining operating results of Diablo Canyon, operating revenues were
specifically identified pursuant to the Diablo Canyon 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 to Diablo Canyon
based on an allocation of corporate debt.
Note 5: 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 mandatory redemption provisions (4.36
percent to 8.2 percent, $25 par value) is subject to redemption at the
Company's option, 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 6.30% (due 2004 to 2009) and the 6.57% (due 2002 to 2007) series of
preferred stock are subject to mandatory redemption provisions and are entitled
to sinking funds providing for the retirement of stock outstanding, beginning
on January 31, 2004, and July 31, 2002, respectively, at par value plus
accumulated and unpaid dividends through the redemption date. In addition, the
6.30% and 6.57% series may be redeemed at the Company's option at par value
plus
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accumulated and unpaid dividends on or after January 31, 2004, and July
31, 2002, respectively. The estimated fair value of the Company's preferred
stock with mandatory redemption provisions at December 31, 1994 and 1993, was
approximately $117 million and $81 million, respectively, based primarily on
matrix pricing models.
During 1994, the Company issued $63 million of 6.30% redeemable preferred
stock and redeemed the 8.16% redeemable preferred stock with a par value of $75
million.
During 1993, the Company issued $125 million of 6 7/8% redeemable preferred
stock and $75 million of 7.04% redeemable preferred stock. Proceeds were used
to finance a portion of the 1993 redemption of the Company's 9.00%, 9.30%,
9.48% and 10.17% redeemable preferred stock with an aggregate par value of $267
million.
Dividends on preferred stock are cumulative. All shares of preferred stock
have voting rights and 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 6: Long-term Debt
Mortgage Bonds:
The Company's First and Refunding Mortgage Bonds are issued in series, and at
December 31, 1994, bear annual interest rates ranging from 4.25 percent to
12.75 percent and mature from 1995 to 2026. The Company had $5.9 billion and
$6.0 billion of mortgage bonds outstanding at December 31, 1994 and 1993,
respectively. Additional bonds may be issued, subject to CPUC approval, up to a
maximum total amount outstanding of $10 billion, assuming compliance with
indenture covenants for earnings coverage and property available as security.
The Board of Directors (Board) 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. These payments equal .5 percent 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
higher-cost debt, the Company redeemed or repurchased $80 million and $3,536
million of higher-cost mortgage bonds in 1994 and 1993, respectively. Interest
rates on the bonds redeemed or repurchased ranged from 7.50 percent to 12.75
percent. In January 1995, the Board authorized the Company to redeem or
repurchase up to $153 million of mortgage bonds.
Included in the total of outstanding mortgage bonds are First and Refunding
Mortgage Bonds issued by the Company to finance air and water pollution control
and sewage and solid waste disposal facilities. These mortgage bonds are held
in trust for the California Pollution Control Financing Authority (CPCFA), who
arranged these financings, and are in addition to the Pollution Control Loan
Agreements discussed below. At December 31, 1994 and 1993, the Company had
outstanding $768 million of mortgage bonds held in trust for the CPCFA with
interest rates ranging from 5.85 percent to 8.875 percent 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, 1994 and 1993, from the CPCFA to finance air and water pollution
control and sewage and solid waste disposal facilities. Interest rates on the
loans vary depending upon 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 1994
ranged from 2.79 percent to 2.98 percent. These loans are subject to redemption
on demand by the holder under certain circumstances and are secured by
irrevocable letters of credit which mature as early as 1997.
Medium-term Notes:
The Company had $1,444 million of unsecured medium-term notes outstanding at
December 31, 1994 with interest rates ranging from 4.13 percent to 9.90 percent
and maturities from 1995 to 2014. At December 31, 1994, the Company has
remaining $85 million on a previous authorization to repurchase medium-term
notes. Holders of Series B medium-term notes maturing in 2004 have an option to
redeem their notes in 1995.
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Long-term Debt of Subsidiaries:
PGT obtained long-term debt financing from a consortium of banks pursuant to a
loan agreement dated April 30, 1993. Under the loan agreement, PGT borrowed
$673 million to finance the pipeline expansion and its existing pipeline
system. The debt is initially guaranteed by PG&E. The weighted average rate of
interest on this loan during 1994 was 6.4 percent.
The interest rate on the PGT debt (which ranged from 4.0 percent to 8.1
percent in 1994) is a floating rate subject to periodic determination in
accordance with the terms of the loan agreement and may vary depending on the
nature and the length of the borrowings, but is generally tied to the banks'
base rate, domestic certificate of deposit rates, or the applicable London
Interbank Offered Rates (LIBOR) for maturities ranging from one to twelve
months. In 1994, PGT executed a series of interest rate swap transactions
which converted $639 million of the floating rate debt to a fixed rate through
July 31, 1999. The interest rate on the remaining debt outstanding, which is
due in 1995, was fixed by utilizing options available to PGT under the loan
agreement.
At December 31, 1994, PGT had outstanding ten interest rate swap agreements
with commercial banks with a total notional principal amount of $639 million.
These swap agreements effectively change PGT's interest rate on its floating
rate debt to a fixed rate of 8.4 percent. The interest rate swap agreements
mature in July 1999. At December 31, 1994, the fair market value of these swap
agreements represented an unrealized gain of $25.7 million.
DALEN has a two-year revolving loan agreement expiring February 1997 which
provides for maximum borrowings of $200 million at a variable interest rate.
The revolving loan may be extended annually by consent of the banks and may be
converted to a five-year term loan at DALEN's option. At December 31, 1994,
approximately $115 million was outstanding at an effective interest rate of
approximately 7 percent. The loan is secured by DALEN's oil and gas
investments.
Repayment Schedule:
At December 31, 1994, the Company's combined aggregate amount of maturing
long-term debt and sinking fund requirements, for the years 1995 through 1999,
are $477 million, $373 million, $369 million, $715 million and $317 million,
respectively.
Fair Value:
The estimated fair value of the Company's total long-term debt of $9.2 billion
and $9.5 billion at December 31, 1994 and 1993, respectively, was approximately
$8.6 billion (including the $25.7 million unrealized gain attributable to the
PGT interest rate swap agreements) and $9.9 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).
Note 7: Short-term Borrowings
Short-term borrowings consist of commercial paper with a weighted average
interest rate of 6.18 percent at December 31, 1994. The usual maturity for
commercial paper is one to ninety days. Commercial paper outstanding at
December 31, 1994 and 1993, was $525 million and $764 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. There
were no borrowings under this facility in 1994, 1993 or 1992. This credit
facility expires in November 1999; however, it may be extended annually for
additional one-year periods upon mutual agreement between the Company and the
banks.
Note 8: Investments in Debt and Equity Securities
Effective January 1, 1994, the Company adopted SFAS No. 115, "Accounting for
Certain Investments in Debt and Equity Securities," which established new
financial accounting and reporting standards for investments in debt and equity
securities. All of the Company's investments in debt and equity securities are
included in Nuclear Decommissioning Funds and are classified as
available-for-sale. These securities are held in external trust funds to be
used for the decommissioning of the Company's nuclear facilities and are
reported at fair value. Unrealized gains and losses are recorded to Accumulated
Depreciation and Decommissioning, net of tax. Funds may not be released from
the external trust funds until authorized by the CPUC.
The proceeds received during 1994 from the sale of securities held as
available-for-sale were approximately $1 billion. During 1994, the gross
realized gains and losses on sales of securities held as available-for-sale
were $9.9 million and $11.9 million, respectively. The cost of equity
securities sold is determined by specific identification. The cost of debt
securities sold is based on a first-in-first-out method.
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The following table provides a summary of amortized cost and fair value by
major security type:
- ------------------------------------------------------------------------------------------------
(in thousands) December 31, 1994
- ------------------------------------------------------------------------------------------------
Gross Gross
unrealized unrealized
Amortized holding holding Fair
cost gains losses value
--------- ---------- ---------- ---------
Debt of U.S. Treasury and
other federal entities $290,511 $ 20 $ (7,972) $282,559
State and local obligations 94,899 1,268 (2,485) 93,682
Equity Securities 184,954 18,556 (9,261) 194,249
Other 46,398 24 (275) 46,147
-------- ------- -------- --------
Total investments in securities $616,762 $19,868 $(19,993) $616,637
======== ======= ======== ========
Investments in debt securities maturing within ten years totaled $293
million, and investments in debt securities with maturities in excess of ten
years totaled $114 million.
At December 31, 1993, the cost and estimated fair value of the
decommissioning funds was $537 million and $576 million, respectively.
Note 9: 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.
At December 31, 1994, plan assets exceeded the projected benefit obligation
by $517 million. The plan's funded status was:
December 31,
-------------------------
(in thousands) 1994 1993
Actuarial present value of benefit obligations
Vested benefits $(3,079,045) $(3,203,408)
Nonvested benefits ( 131,489) (154,349)
----------- -----------
Accumulated benefit obligation (3,210,534) (3,357,757)
Effect of projected future compensation increases ( 441,951) (577,926)
----------- -----------
Projected benefit obligation (3,652,485) (3,935,683)
Plan assets at market value 4,169,516 4,376,110
----------- -----------
Plan assets in excess of projected benefit obligation 517,031 440,427
Unrecognized prior service cost 93,425 117,312
Unrecognized net gain (908,485) (759,690)
Unrecognized net transition obligation 108,800 120,253
----------- -----------
Accrued pension liability $ (189,229) $ (81,698)
=========== ===========
Plan assets consist substantially of common stocks and fixed-income
securities. The unrecognized prior service cost is amortized over approximately
16 years. The unrecognized net transition obligation is amortized over
approximately 18 years, beginning in 1987.
The vested benefit obligation is the actuarial present value of vested
benefits to which employees are currently entitled based on their expected
termination dates.
Assumptions used to calculate the projected benefit obligation to determine
the plan's funded status were:
December 31,
----------------------
1994 1993
Weighted average discount rate 8% 7%
Average rate of projected future compensation increases 5% 5%
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,
----------------------------------
(in thousands) 1994 1993 1992
Service cost for benefits earned $ 109,132 $ 129,166 $ 127,388
Interest cost 272,932 268,698 248,674
Actual loss (return) on plan assets 20,358 (511,526) (204,576)
Net amortization and deferral (412,547) 177,597 (78,560)
--------- --------- ---------
Net pension (income) cost $ (10,125) $ 63,935 $ 92,926
========= ========= =========
The decrease in net pension cost in 1994 compared to 1993 was primarily due
to changes in the assumed rates of projected compensation increases and
turnover to better reflect actual and expected rates. 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 expected long-term rate of return on plan assets used to calculate
pension cost was nine percent for 1994 and 1993 and eight percent for 1992.
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 1994, the plan experienced a negative rather
36
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than an expected positive investment return on plan assets, due to weak
performance in domestic equities and bonds. In 1993, actual return on plan
assets exceeded expected return whereas, in 1992, actual return on plan
assets was less than expected.
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.
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 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 $35 million, $36
million and $35 million for 1994, 1993 and 1992, 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, 1994, stock options on 2,496,356 shares, granted at option
prices ranging from $16.75 to $34.25, were outstanding. During 1994, 597,000
options were granted at an option price of $34.25, which was 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 or death, and upon certain changes in control of the
Company.
In 1994, 1993 and 1992, stock options on 52,143, 174,387 and 157,446 shares,
respectively, were exercised at option prices ranging from $24.75 to $32.13,
$16.75 to $33.13 and $16.75 to $26.63, respectively. At December 31, 1994,
stock options on 940,076 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.
In 1993, the Company implemented a plan change that will limit the amount it
will contribute toward postretirement medical benefits. This limitation will
take effect for all retirees beginning in 2001.
The Company's funding policy for the medical and life insurance benefits is
to contribute each year the 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.
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 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.
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27
At December 31, 1994, the accumulated postretirement benefit obligation
exceeded plan assets by $427 million, principally due to recent adoption of
SFAS No. 106. The medical and life insurance plans' funded status was:
(in thousands) December 31,
-------------------------------
1994 1993
Accumulated postretirement benefit obligation
Retirees $(497,889) $(384,706)
Other fully eligible participants (104,865) (148,018)
Other active plan participants (219,639) (365,786)
--------- ---------
Total accumulated postretirement benefit obligation (822,393) (898,510)
Plan assets at market value 394,939 345,938
--------- ---------
Accumulated postretirement benefit obligation
in excess of plan assets (427,454) (552,572)
Unrecognized prior service cost 25,377 -
Unrecognized net (gain) loss (115,249) 21,481
Unrecognized transition obligation 462,082 543,939
--------- ---------
(Accrued) prepaid postretirement benefit liability $ (55,244) $ 12,848
========= =========
The unrecognized prior service cost in 1994 reflects a plan amendment which
provides an increase in benefits to certain retirees. It is amortized over
approximately 18 years.
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 over 20 years beginning in
1993. The plan change implemented in 1993 that will limit the Company's
contributions toward postretirement medical benefits reduced the accumulated
postretirement benefit obligation at July 1, 1993 by approximately $450
million.
The assumptions used to calculate the benefit obligations included a
weighted average discount rate of eight percent for 1994 and seven percent for
1993, and an average rate of projected future compensation increases of five
percent for 1994 and 1993. The assumed health care cost trend rate for 1995 is
approximately 11 percent, grading down to an ultimate rate in 2005 of
approximately six percent. 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, 1994, by
approximately $110 million and the 1994 aggregate service and interest costs by
approximately $13 million.
Net postretirement medical and life insurance cost, using the projected unit
credit actuarial cost method, was:
Year ended December 31,
---------------------------
(in thousands) 1994 1993
Service cost for benefits earned $ 23,617 $ 38,496
Interest cost 64,872 73,502
Actual return on plan assets (1,232) (23,999)
Amortization of unrecognized prior service cost 1,711 -
Amortization of transition obligation 28,913 39,620
Net amortization and deferral (29,804) (3,390)
-------- --------
Net postretirement benefit cost $ 88,077 $124,229
======== ========
The decrease in net postretirement benefit cost in 1994 compared to 1993 was
primarily due to the plan change implemented July 1, 1993 that will limit the
Company's contributions toward postretirement medical benefits.
The expected long-term rate of return on plan assets used to calculate
postretirement medical and life insurance benefit costs was nine percent for
1994 and 1993.
Net postretirement benefit 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 postretirement benefit cost. In 1994 and 1993, actual
return on plan assets was less than expected return.
For 1992, the cost of postretirement medical and life insurance benefits was
based on benefits paid and funded and totaled $98 million.
Workforce Reductions:
The effects of workforce reductions announced by the Company in 1994 and 1993
are reflected in the pension and postretirement benefits funded status tables
above and the costs are discussed in Note 10.
Postemployment Benefits:
Effective January 1, 1994, the Company adopted 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. For the Company, such benefits consist primarily of long-term
disability, workers' compensation, and continuation of medical and life
insurance coverage. Due to current regulatory treatment, adoption of SFAS No.
112 did not have a significant impact on the Company's financial position or
results of operations. Adoption of SFAS No. 112 resulted in an increase of
approximately $90 million in noncurrent liabilities and deferred charges as of
January 1, 1994.
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28
Note 10: Workforce Reductions
In 1994, the Company announced workforce reductions which when combined with
the 3,000 positions eliminated in 1993 will result in the elimination of
approximately 6,000 positions by the end of 1995. The majority of the
reductions have occurred through voluntary retirement incentives (VRI) for
employees 50 years of age with at least 15 years of service. Remaining
reductions will be accomplished by severances and attrition in 1995.
In December 1994, the Company expensed the total cost of the 1994 workforce
reductions of $249 million and recorded a corresponding liability for benefits
to be funded or paid. This amount consists of $136 million for additional
pension benefits and $52 million for other postretirement benefits extended in
connection with the VRI, and $61 million of estimated severance costs for
approximately 1,500 severances. Most of these severances will be in the
Customer Energy Services and Electric Supply business units, in functions that
the Company has determined to be not absolutely necessary for safe, reliable
and responsive service, including construction and certain staff and support
services. The Company does not plan to seek rate recovery for the cost of the
1994 workforce reductions as it did with the 1993 workforce reductions.
The total cost of the 1993 workforce reductions was $264 million, net of a
curtailment gain relating to pension benefits. Included in this amount was $151
million for additional pension benefits and $22 million for other
postretirement benefits extended in connection with the VRI. As a result of a
freeze on electric rates, the Company expensed $190 million of workforce
reduction costs relating to electric operations. The amount relating to gas
operations was deferred for future rate recovery and is being amortized as
savings are realized. At December 31, 1994, $31 million remained to be
amortized.
The Company recorded the costs and savings incurred in connection with the
1993 workforce reductions in a memorandum account authorized by the CPUC, with
the recovery of such costs subject to a CPUC reasonableness review.
Note 11: Income Taxes
The current and deferred components of income tax expense were:
Year ended December 31,
-----------------------------------
(in thousands) 1994 1993 1992
Current
Federal $ 606,885 $ 417,558 $536,774
State 214,570 165,134 193,895
--------- ---------- --------
Total current 821,455 582,692 730,669
--------- ---------- --------
Deferred (substantially all federal)
Depreciation 174,600 207,690 165,944
Regulatory balancing accounts 96,881 77,515 85,210
Workforce reduction (102,975) 24,765 -
Gas reasonableness (47,952) (25,037) -
(Gain) loss on reacquired debt (6,374) 42,405 15,959
Other--net (79,523) 12,270 (78,783)
--------- ---------- --------
Total deferred 34,657 339,608 188,330
--------- ---------- --------
Investment tax credits--net (19,345) (20,410) (23,873)
--------- ---------- --------
Total income tax expense $ 836,767 $ 901,890 $895,126
========= ========== ========
Classification of income tax expense:
Included in operating expenses $ 924,620 $1,006,774 $906,845
Included in other--net (87,853) (104,884) (11,719)
--------- ---------- --------
Total income tax expense $ 836,767 $ 901,890 $895,126
========= ========== ========
The significant components of net deferred income tax liabilities are as
follows:
December 31,
------------------------------------
(in thousands) 1994 1993
- -----------------------------------------------------------------------------------------
Deferred income taxes assets:
Deferred income taxes--current $ 173,357 $ 160,177
Deferred income taxes--noncurrent 959,459 647,018
---------- ----------
Total deferred income tax assets 1,132,816 807,195
========== ==========
Deferred income tax liabilities:
Deferred income taxes--current
Regulatory balancing accounts 559,750 449,216
Other 45,633 26,545
---------- ----------
Total deferred income taxes--current 605,383 475,761
---------- ----------
Deferred income taxes-noncurrent
Plant in service 3,627,294 3,386,122
Income tax-related deferred charges (1) 474,242 523,953
Other 760,568 715,893
---------- ----------
Total deferred income taxes--noncurrent 4,862,104 4,625,968
---------- ----------
Total deferred income tax liabilities 5,467,487 5,101,729
========== ==========
Total net deferred income taxes $4,334,671 $4,294,534
========== ==========
Classification of net deferred income taxes:
Included in current liabilities $ 432,026 $ 315,584
Included in deferred credits 3,902,645 3,978,950
---------- ----------
Total net deferred income taxes $4,334,671 $4,294,534
========== ==========
(1) Represents the portion of the deferred income tax liability related to the
revenues required to recover future income taxes.
39
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The differences between income taxes and amounts determined by applying the
federal statutory rate to income before income tax expense were:
Year ended December 31,
-------------------------------
1994 1993 1992
Federal statutory income tax rate 35.0% 35.0% 34.0%
Increase (decrease) in income tax rate
resulting from
State income tax (net of federal benefit) 8.3 6.5 6.7
Effect of regulatory treatment of
depreciation differences 3.7 4.5 5.0
Investment tax credits (1.1) (1.0) (1.2)
Other--net (.5) .8 (1.2)
---- ---- ----
Effective tax rate 45.4% 45.8% 43.3%
==== ==== ====
Note 12: Commitments
Capital Projects:
Capital expenditures for 1995 are estimated to be approximately $1,544 million,
consisting of $1,212 million for utility expenditures, $47 million for Diablo
Canyon expenditures and $285 million for nonregulated expenditures. At December
31, 1994, Enterprises had firm commitments totaling $214 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 $100 million in 1995 and $114 million in 1996.
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 1995 to
2026. 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.
In 1994, the Company negotiated early termination or suspension of certain
QF contracts at a cost of $155 million to be paid over a six-year period
beginning in 1994. This amount was deferred and is expected to be recovered in
future rates.
QF deliveries in the aggregate account for approximately 21 percent of the
Company's 1994 electric energy requirements and no single contract accounted
for more than five percent of the Company's energy needs. QF deliveries in 1994
represented approximately 86 percent 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,
-----------------------------
(in millions) 1994 1993 1992
Kilowatthours received 21,699 21,242 21,173
Energy payments $ 1,196 $ 1,099 $ 1,084
Capacity payments $ 518 $ 503 $ 489
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 the FERC's 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, 1994, the future minimum payments under
these contracts are $34 million for each of the years 1995 through 1999 and a
total of $451 million for periods thereafter. Total payments under these
contracts were $49 million, $45 million and $54 million in 1994, 1993 and 1992,
respectively.
Note 13: 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.
In October 1994, the Company signed a settlement with the DRA regarding the
recovery of Helms costs not currently in rate base and prior-year revenue
requirements related to these costs. The settlement provides for recovery of
substantially all of the remaining net unrecovered costs (after adjustment for
depreciation) and revenues. The settlement has been submitted to the CPUC for
approval.
40
30
The Company cannot predict whether the settlement will be approved by the
CPUC. However, the Company does not believe the ultimate outcome of the matter
will have a significant impact on its financial position or results of
operations.
Nuclear Insurance:
The Company is a member of Nuclear Mutual Limited (NML) and Nuclear Electric
Insurance Limited (NEIL). Under these policies, if the nuclear plant of a
member utility is damaged or the member incurs costs beyond those covered by
insurance for business interruption due to a prolonged accidental outage, the
Company may be subject to maximum assessments of $28 million (property damage)
and $7 million (business interruption), in each case per policy period, in the
event losses exceed the resources of NML or NEIL.
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 $8.9 billion per
incident. Coverage of the first $200 million is provided by a pool of
commercial insurers. If a nuclear incident results in public liability claims
in excess of $200 million, the Company may be assessed up to $159 million per
incident, with payments in each year limited to a maximum of $20 million per
incident.
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 pay for remedial action at sites where the Company has been or may
be a potentially responsible party under the Comprehensive Environmental
Response, Compensation, and Liability Act (CERCLA; federal Superfund law) or
the California Hazardous Substance Account Act (California Superfund law).
These sites include former manufactured gas plant sites and sites used by the
Company for the storage or disposal of materials which may be determined to
present a significant threat to human health or the environment because of an
actual or potential release of hazardous substances. Under CERCLA, the
Company's financial responsibilities may include remediation of hazardous
wastes, even if the Company did not deposit those wastes on the site.
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. The Company has an accrued liability at December 31,
1994, of $95 million for hazardous waste remediation costs. The costs may be as
much as $235 million 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 or necessary remediation is greater
than anticipated at sites for which the Company is responsible.
The Company will seek recovery of prudently incurred hazardous waste
compliance and remediation costs through ratemaking procedures approved by the
CPUC. The Company believes the ultimate outcome of these matters will not have
a significant adverse impact on its financial position or results of
operations.
Legal Matters:
Stanislaus Litigation: In 1993, a lawsuit was filed on behalf of the County of
Stanislaus, California and a residential customer of the Company and
purportedly as a class action on behalf of all natural gas customers of the
Company during the period of February 1988 through October 1993. The lawsuit
alleged that the purchase of natural gas in Canada by A&S was accomplished in
violation of various antitrust laws resulting in increased prices of natural
gas for PG&E's customers. Damages to the class members were estimated as
potentially exceeding $800 million. The complaint indicated 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.
In August 1994, a federal district court granted the Company's motion to
dismiss the federal and state antitrust claims and the state unfair practices
claims against the Company and PGT. The court also granted the plaintiffs'
motion seeking class certification.
In September 1994, the plaintiffs filed an amended complaint in which A&S
has been added as a defendant. The amended complaint restates the claims in the
original complaint and alleges that the defendants, through anticompetitive
practices, precluded certain customers of the Company access to alternative
sources of gas in Canada over the PGT pipeline. A new motion to dismiss was
filed by the Company in early November 1994. The Company believes that the
ultimate outcome of this matter will not have a significant adverse impact on
its financial position.
41
31
Hinkley Litigation: In 1993, a complaint was filed in a state superior court on
behalf 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 original complaint has been amended, and additional
complaints have been filed, to include additional plaintiffs.
The plaintiffs contend that the Company discharged chromium-contaminated
wastewater into unlined ponds, which led to chromium percolating into the
groundwater of surrounding property. The plaintiffs further allege that the
Company discharged the chromium into those ponds to avoid costly alternatives.
The Company has reached an agreement with plaintiffs pursuant to which those
plaintiffs' actions will be submitted to binding arbitration for resolution of
issues concerning the cause and extent of any damages suffered by plaintiffs as
a result of the alleged chromium contamination. Under the terms of the
agreement, the Company will pay an aggregate amount of no more than $400
million in settlement of such plaintiffs' claims, including $50 million paid to
escrow to date. In turn, those plaintiffs, and their attorneys, agree to
indemnify the Company against any additional losses the Company may incur with
respect to related claims pursued by the identified plaintiffs who do not agree
to this settlement or by other third parties who may be sued by the plaintiffs
in connection with the alleged chromium contamination.
At December 31, 1994, the Company has a remaining reserve of $50 million
against any future potential liability in this case. The Company believes the
ultimate outcome of this matter will not have a significant adverse impact on
its financial position or results of operations.
County Franchise Fees Litigation: In March 1994, Santa Clara and Alameda
counties filed a class action suit in a state superior court against the
Company on behalf of themselves and 45 other counties in the Company's service
area. This lawsuit alleges that the Company underpaid franchise fees to the
counties for the right to use or occupy public streets or roads as a result of
incorrectly computing these payments. Should the counties prevail, the amount
of damages for alleged underpayments for the years 1987 through 1994 could be
as high as $145 million, including interest, at Decmeber 31, 1994. The Company
believes that the ultimate outcome of this matter will not have a significant
adverse impact on its financial position or results of operations.
City Franchise Fees Litigation: In May 1994, the City of Santa Cruz filed a
class action suit in a state superior court against the Company on behalf of
itself and 106 other cities in the Company's service area. The complaint
alleges that the Company has underpaid electric franchise fees to the cities by
calculating fees at different rates from other cities. Should the cities
prevail, the amount of damages for alleged underpayments for the years 1987
through 1994 could be as high as $137 million, including interest, at December
31, 1994. The Company believes that the ultimate outcome of this matter will
not have a significant adverse impact on its financial position or results of
operations.
42
32
Pacific Gas and Electric Company
Quarterly Consolidated Financial Data (Unaudited)
Quarterly Financial Data:
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 first quarter of 1994, the Company took a charge against earnings of
approximately $90 million as a result of the CPUC disallowances in the gas
reasonableness proceedings for 1988 through 1990 and the Company's assessment
of open reasonableness issues. In the second quarter of 1994, the Company
increased its litigation reserves by $50 million. In the fourth quarter of
1994, the Company took a charge against earnings of $249 million related to
1994 workforce reductions.
In the second quarter of 1993, the Company took a charge against earnings of
$141 million related to the workforce reductions for management employees. In
the third quarter of 1993, the Company's earnings reflected charges of $144
million resulting from the Company's workforce reductions, termination of
Canadian gas contracts and an increase in the federal income tax rate. 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.
The Company's common stock is traded on the New York, Pacific, London,
Amsterdam, Basel and Zurich stock exchanges. There were approximately 230,000
common shareholders of record at December 31, 1994. 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
----------------------------------------------------
(in thousands, except per share amounts) December 31 September 30 June 30 March 31
1994
Operating revenues $2,638,179 $2,855,221 $2,439,680 $2,514,271
Operating income 238,286 584,694 395,705 414,674
Net income 103,500 425,633 241,365 236,952
Earnings per common share (1) .21 .96 .53 .52
Dividends declared per common share .49 .49 .49 .49
Common stock price per share
High 25.25 25.13 29.75 35.00
Low 21.38 22.00 22.50 28.50
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
(1) Includes Diablo Canyon scheduled refueling outages which impacted earnings
per common share for all quarters in 1994 and for the first and second
quarters of 1993. In addition, Diablo Canyon experienced unscheduled
outages in the second quarter of 1994.
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Pacific Gas and Electric Company
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
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, 1994 and 1993, 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, 1994. These financial
statements and schedule of consolidated segment information 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, 1994 and 1993, and the results of their
operations and cash flows for each of the three years in the period ended
December 31, 1994 in conformity with generally accepted accounting principles.
As discussed in Note 2 of Notes to Consolidated Financial Statements, in
1994, the California Public Utilities Commission (CPUC) issued a proposal to
restructure the electric industry in California which could significantly alter
the ratemaking applied to the Company. If this proposal is adopted or if
electric generation rates are no longer based on cost of service, the Company
would discontinue the application of Statement of Financial Accounting
Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of
Regulation" for a portion of its operations. The CPUC's proposal could also
impact the recovery of certain costs, including power purchase obligations and
investments in related electric generation assets. Currently, the Company is
unable to predict the ultimate outcome of the electric industry restructuring
or predict whether such outcome will have a significant impact on its financial
position or results of operations.
As explained in Notes 1 and 9 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 LLP
ARTHUR ANDERSEN LLP
San Francisco, California
February 6, 1995
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34
Pacific Gas and Electric Company
RESPONSIBILITY FOR FINANCIAL STATEMENTS
The responsibility for the integrity of the financial information included in
this report rests with management. Such information has been prepared in
accordance with generally accepted accounting principles appropriate in the
circumstances, and is based on the Company's best estimates and judgments after
giving consideration to materiality.
The Company maintains systems of internal controls supported by formal
policies and procedures which are communicated throughout the Company. These
controls are adequate to provide reasonable assurance that assets are
safeguarded from material loss or unauthorized use and to produce the records
necessary for the preparation of financial information. There are limits
inherent in all systems of internal controls, based on the recognition that the
costs of such systems should not exceed the benefits to be derived. The
Company believes its systems provide this appropriate balance. In addition,
the Company's internal auditors perform audits and evaluate the adequacy of and
the adherence to these controls, policies and procedures.
Arthur Andersen LLP, the Company's independent public accountants,
considered the Company's systems of internal accounting controls and have
conducted other tests as they deemed necessary to support their opinion on the
consolidated financial statements. Their auditors' report contains an
independent informed judgment as to the fairness, in all material respects, of
the Company's reported results of operations and financial position.
The financial data contained in this report have been reviewed by the Audit
Committee of the Board of Directors. The Audit Committee is composed of six
outside directors who meet regularly with management, the corporate internal
auditors and Arthur Andersen LLP, jointly and separately, to review internal
accounting controls and auditing and financial reporting matters.
The Company maintains high standards in selecting, training and developing
personnel to ensure that management's objectives of maintaining strong,
effective internal controls and unbiased, uniform reporting standards are
attained. The Company believes its policies and procedures provide reasonable
assurance that operations are conducted in conformity with applicable laws and
with its commitment to a high standard of business conduct.
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