<PAGE> 1
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 8-K
CURRENT REPORT
Pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934
Date of Report: February 21, 1996
PACIFIC GAS AND ELECTRIC COMPANY
(Exact name of registrant as specified in its charter)
California 1-2348 94-0742640
- ----------------------------------------------------------------
(State or other juris- (Commission (IRS Employer
diction of incorporation) File Number) Identification Number)
77 Beale Street, P.O.Box 770000, San Francisco, California 94177
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code:(415) 973-7000
<PAGE> 2
Item 7. Financial Statements, Pro Forma Financial Information
And Exhibits
A. 1995 Financial Statements
Copies of the following documents are attached hereto as Appendix I and
incorporated herein: (i) the selected financial data; (ii) management's
discussion and analysis of consolidated results of operations and financial
condition; (iii) audited consolidated balance sheet and statement of
consolidated capitalization of Pacific Gas and Electric Company (PG&E) and
subsidiaries as of December 31, 1995 and 1994, 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, 1995, and related notes to consolidated financial
statements, and supplementary financial information, and (iv) the report dated
February 12, 1996, of Arthur Andersen LLP, independent public accountants,
with respect to the consolidated financial statements and schedule of
consolidated segment information.
B. Ratios of Earnings to Fixed Charges and Ratios of Earnings to Combined
Fixed Charges and Preferred Stock Dividends
PG&E's earnings to fixed charges ratio for the year ended December 31, 1995 was
4.12. PG&E's earnings to combined fixed charges and preferred stock dividends
ratio for the year ended December 31, 1995 was 3.56.
Exhibits:
<TABLE>
<S> <C>
11 Computation of Earnings per Common Share
12.1 Computation of Ratios of Earnings to Fixed Charges
12.2 Computation of Ratios of Earnings to Combined Fixed
Charges and Preferred Stock Dividends
23 Consent of Arthur Andersen LLP
27 Financial Data Schedule
</TABLE>
<PAGE> 3
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
PACIFIC GAS AND ELECTRIC COMPANY
By /s/ GORDON R. SMITH
------------------------------
GORDON R. SMITH
Senior Vice President and
Chief Financial Officer
Dated: February 21, 1996
<PAGE> 4
Appendix I
Pacific Gas and Electric Company
Selected Financial Data
<TABLE>
<CAPTION>
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) 1995 1994 1993 1992 1991
----------- ----------- ----------- ----------- -----------
<S> <C> <C> <C> <C> <C>
FOR THE YEAR
Operating revenues $ 9,621,765 $10,350,230 $10,550,002 $10,315,713 $ 9,823,137
Operating income 2,762,985 2,423,786 2,560,235 2,699,824 2,550,334
Net income 1,338,885 1,007,450 1,065,495 1,170,581 1,026,392
Earnings per common share 2.99 2.21 2.33 2.58 2.24
Dividends declared per common share 1.96 1.96 1.88 1.76 1.64
AT YEAR END
Book value per common share $ 20.77 $ 20.07 $ 19.77 $ 19.41 $ 18.40
Common stock price per share 28.38 24.38 35.13 33.13 32.63
Total assets 26,850,290 27,708,564 27,145,899 24,188,159 22,900,670
Long-term debt and preferred stock
and preferred securities with
mandatory redemption provisions
(excluding current portions) 8,486,046 8,812,591 9,367,100 8,525,948 8,341,310
</TABLE>
Matters relating to certain data above are discussed in Management's Discussion
and Analysis of Consolidated Results of Operations and Financial Condition and
in Notes to Consolidated Financial Statements.
12
<PAGE> 5
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
CONSOLIDATED RESULTS OF OPERATIONS AND FINANCIAL CONDITION
PACIFIC GAS AND ELECTRIC COMPANY
Pacific Gas and Electric Company (PG&E) and its wholly owned and controlled
subsidiaries (collectively, the Company) are engaged principally in the business
of supplying electric and natural gas services. PG&E is a regulated public
utility which provides generation, procurement, transmission and distribution of
electricity and natural gas to customers throughout most of Northern and Central
California. Pacific Gas Transmission Company (PGT), a wholly owned subsidiary,
transports gas from the Canadian border to the California border and the Pacific
Northwest. The Company's operations are regulated by the California Public
Utilities Commission (CPUC), the Federal Energy Regulatory Commission (FERC) and
the Nuclear Regulatory Commission (NRC), among others.
Building on its expertise in the energy industry, the Company is also
expanding its diversified operations, principally through its wholly owned
subsidiary, PG&E Enterprises (Enterprises). Enterprises, through its
subsidiaries and affiliates, develops, owns and operates electric projects
around the world, as discussed further in the Diversified Operations section.
The following discussion includes some forward looking information.
Importantly, the ultimate impact of increased competition and the changing
regulatory environment on future results is uncertain but is expected to cause
fundamental changes in the way PG&E conducts its business and to make earnings
more volatile. This outcome and other matters discussed below may cause future
results to differ materially from historic results or from results or outcomes
currently expected or sought by the Company.
COMPETITION AND CHANGING REGULATORY ENVIRONMENT: Under traditional utility
regulation, utilities have been accorded the right to serve customers within
designated areas in return for their commitment to provide service to all who
request it. Regulation was designed in part to take the place of competition to
ensure that utility services were provided at fair prices. However, recent
changes in both the gas and electric industries have allowed competition to
develop in the gas supply and electric generation segments of PG&E's business,
resulting in fundamental changes in the way PG&E's various services are
regulated and managed.
ELECTRIC INDUSTRY: PG&E currently performs the functions of electric generation,
transmission, distribution and customer service. However, competition from
nonutility and nonregulated electric suppliers and self-generation and
cogeneration have provided some major utility customers with alternative sources
to satisfy their electric supply needs. Currently, PG&E obtains a portion of its
electric supply from generation sources outside its service territory and from
qualifying facilities, or QFs (small power producers or cogenerators that meet
certain federal guidelines qualifying them to supply generating capacity and
electric energy to utilities), owned and operated by independent power producers
(IPPs).
Regulatory changes enacted at the federal level and those contemplated at
the state level have transformed and will continue to transform the electric
transmission function by promoting open access to nonutility suppliers. At the
federal level, the National Energy Policy Act of 1992 reduced various
restrictions on the operation and ownership of IPPs and provided them and other
wholesale suppliers and purchasers with increased access to electric
transmission lines throughout the United States.
The FERC has established a Notice of Proposed Rulemaking (NOPR) on open
access. The NOPR requires that all utilities offer open access wholesale
transmission service that is comparable to the wholesale transmission service
that utilities provide themselves. In addition, the FERC accepted, subject to
refund and the outcome of the NOPR, PG&E's proposed open access wholesale
electric transmission tariffs, effective July 1, 1995. These tariffs generally
conform to the FERC NOPR.
On December 20, 1995, the CPUC issued a decision calling for the
restructuring of California's electric industry. The CPUC's goal is to provide a
structure that will ultimately allow California consumers to choose among
competing suppliers of electricity. In summary, the decision would (1)
simultaneously create a wholesale power pool (the Exchange) and allow direct
access for certain customers to contract directly with electric generation
providers beginning in 1998; (2) establish an Independent System Operator (ISO)
to manage and control the transmission
13
<PAGE> 6
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
CONSOLIDATED RESULTS OF OPERATIONS AND FINANCIAL CONDITION
PACIFIC GAS AND ELECTRIC COMPANY
system; and (3) provide recovery of utilities' stranded costs (costs which are
above-market and could not be recovered under market-based pricing) through a
surcharge, or competition transition charge (CTC), to be imposed on all
customers taking retail electric services as of or after December 20, 1995. The
decision, while effective immediately, provides a 100-day period for legislative
review and sets out an ambitious schedule for various implementation filings and
comments over the period ending in September 1996.
Under the restructuring decision, investor-owned utilities (IOUs) would
continue to provide distribution, generation and procurement functions for those
customers choosing to take bundled service from utilities, all of which would be
regulated under performance-based ratemaking. The decision requires the IOUs to
file proposals to establish performance-based ratemaking for the generation and
distribution functions. The decision provides that by January 1, 1998, a
representative number of customers from all customer groups, individually or in
the aggregate, will be able to participate in the first phase of direct access
which will last one year, with the balance of customers phased in to direct
access within five years. Ultimately, it is contemplated that all customers will
have the choice of buying electricity from their utility, the Exchange or
directly from electric generation providers through direct access bilateral
contracts.
The decision requires the three largest IOUs, in conjunction with other
interested parties, to work together to prepare a joint proposal for the
creation of the Exchange which will be separate from and independent of the ISO.
The Exchange would manage bids for energy, set the market clearing price and
then submit its delivery schedule to the ISO for dispatch. The IOUs would be
required to bid all their generation output into the Exchange and purchase all
their energy from the Exchange during the five-year transition period to full
direct access. Participation in the Exchange would be voluntary for all other
market participants.
The decision also requires the three largest IOUs to develop a detailed
proposal for submission to the FERC for creation of the ISO. The decision
contemplates that the IOUs, after approvals from the FERC and the CPUC, turn
over control, but not ownership, of their transmission systems to the ISO. The
ISO will control the power dispatch and transmission system and provide
transmission service on a nondiscriminatory basis.
The CPUC concluded that market power issues associated with the electric
industry restructuring almost certainly mandate that the IOUs divest themselves
of a substantial portion of their fossil fuel generation assets. Accordingly,
the decision requires that the three IOUs file plans to voluntarily divest
themselves of at least 50 percent of their fossil fuel generation assets. To
encourage divestiture, for each ten percent of fossil fuel generation capacity
divested, the decision proposes an increase of up to ten basis points in the
equity return on the undepreciated net book value of fossil fuel generation
assets. The decision also directs the IOUs to file comments within 90 days on
the feasibility, timing and consequences of a corporate restructuring to
separate their operations and assets between the generation, transmission and
distribution functions, including the option of forming a holding company
structure. In response, PG&E is considering a range of possible alternatives,
including the possible divestiture of a substantial portion of its generation
assets.
The decision provides for the collection of transition costs through the
imposition of a non-bypassable CTC applied to transmission and distribution
rates. Transition cost recovery shall not increase rates beyond the rate levels
in effect as of January 1, 1996. A transition cost account will be established
for each utility. Transition costs associated with regulatory assets will be
included in the account as authorized by the CPUC. The account will be adjusted
annually for the difference between authorized revenues associated with the
generation assets and actual revenues earned in the market as well as after a
generation asset receives its market valuation. Valuation of above-market
generation assets will be completed by 2003. Utility nonnuclear generation
assets will be valued through sale, spin-off
14
<PAGE> 7
or market appraisal. The CTC will include the undepreciated book value of a
utility's fossil fuel generation assets as reflected in rate base at a reduced
return on equity equal to ten percent below the utility's embedded cost of debt.
For hydroelectric and geothermal generation assets, the CTC will be the above-
or below-market portion of the revenue requirement for those facilities derived
through a performance-based ratemaking method.
Transition costs resulting from the operation of nuclear generation
facilities and electricity purchases under existing wholesale and QF contracts
will also be recorded in this account. Transition costs for these resources will
be calculated annually over the terms of the contracts or until the authorized
transition cost recovery has been completed. Except for existing QF generation
contracts with contractual payments beyond 2003, all transition costs will be
collected by 2005.
With respect to recovery of costs associated with Diablo Canyon Nuclear
Power Plant (Diablo Canyon) and the Diablo Canyon rate case settlement (Diablo
Settlement), the decision confirms that the CPUC will continue to honor
regulatory commitments regarding the recovery of nuclear generation costs. The
decision provides that transition costs associated with Diablo Canyon will be
calculated over the term of the Diablo Settlement as the difference between the
revised Diablo Settlement price and the market price as determined by the
Exchange and the ISO will schedule power from Diablo Canyon on a must-take
basis, consistent with the Diablo Settlement. The decision requires PG&E to file
a proposal for pricing Diablo Canyon generation at market prices by 2003 and for
completing recovery of Diablo Canyon CTC by 2005 while assuring no overall rate
increase over January 1, 1996, levels. If PG&E retains ownership of Diablo
Canyon, decommissioning costs will also be included in the transition cost
account. The CPUC requires that at least one of the alternatives presented in
PG&E's proposal shall be structured to accelerate recovery of the undepreciated
portion of Diablo Canyon, at a significantly reduced return tied to the embedded
cost of debt, and to include performance-based ratemaking for recovery of
operating costs and prospective capital additions.
Two commissioners voted for a minority proposal which differed from the
decision in the following significant respects: (1) phase-in of direct access
for all customers would be over a twelve-month period; (2) participation in the
wholesale power pool would be voluntary for all participants; and (3)
withholding of ten percent of total allowable transition costs would be used as
a disincentive for utilities to retain the current level of generation ownership
until such time that 50 percent of current utility-owned generation, excluding
nuclear plants, is divested.
FINANCIAL IMPACT OF THE ELECTRIC INDUSTRY RESTRUCTURING: In December 1994, in
response to one of the proceedings leading to the decision, PG&E estimated the
revenue requirements of its owned generation assets and power purchase
obligations to be above market by $3 billion and $11 billion at assumed market
prices of $.040 and $.032 per kilowatt-hour (kWh), respectively. These market
prices were used to provide a range of possible transition costs and do not
represent a forecast of expected market prices. These above-market estimates
were determined by comparing future revenue requirements of generation assets
and power purchase obligations, over a 20-year and 30-year period, respectively,
with revenues computed at assumed market prices. The revenue requirements for
Diablo Canyon and all PG&E-owned generation assets included a return on
investment. Diablo Canyon was included in the revenue requirements calculation
using the revised pricing included in the modified Diablo Settlement. (See Note
4 of Notes to Consolidated Financial Statements.) The above-market revenue
requirements for Diablo Canyon included above were $4 billion and $6 billion at
assumed market prices of $.040 and $.032 per kWh, respectively. At this time,
PG&E has not completed a more current estimate of its above-market revenue
requirements. However, market prices could be less than $.032 per kWh. The
actual amounts of above-market revenue requirements may differ materially from
those indicated above and will depend on the final regulations and the actual
market prices of electricity or a definitive market valuation.
15
<PAGE> 8
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
CONSOLIDATED RESULTS OF OPERATIONS AND FINANCIAL CONDITION
PACIFIC GAS AND ELECTRIC COMPANY
The CPUC electric industry restructuring decision establishes an account to
track the accumulation of transition costs and their recovery. While the
decision provides an opportunity for recovery of all above-market costs, actual
recovery of the CTC will be limited to an amount that does not increase the
customers' aggregate rates above those in effect on January 1, 1996. Recent CPUC
decisions effective on January 1, 1996, including PG&E's General Rate Case
(GRC), have resulted in an average electric system rate of 9.9 cents per kWh.
PG&E's ability to recover its transition costs will be dependent on achieving
overall reductions in costs such that it can recover its ongoing operating
costs, capital costs and transition costs at the 1996 rate level and on
continuing to collect CTC for the duration of the recovery period.
As a result of applying the provisions of Statement of Financial Accounting
Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of
Regulation" (see Note 1 of Notes to Consolidated Financial Statements), PG&E has
accumulated approximately $2.6 billion of electric regulatory assets, including
balancing accounts, at December 31, 1995. The regulatory assets attributable to
electric generation, excluding balancing accounts of $248 million which are
expected to be recovered in the near term, were approximately $1.5 billion at
December 31, 1995. When generation rates are no longer based on cost of service,
as ultimately contemplated under the decision, PG&E will discontinue application
of SFAS No. 71 for that portion of its business. However, PG&E expects to
recover its regulatory assets as transition costs through the CTC and does not
expect a material loss from the discontinuance of SFAS No. 71. PG&E's
transmission and distribution businesses are expected to remain on
cost-of-service rates.
In addition, the adoption of SFAS No. 121, "Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to Be Disposed Of," in 1996 will
require that regulatory assets continue to be probable of recovery in rates. In
the event that this criterion can no longer be met, whether due to changing
regulation or PG&E's inability to collect these costs, applicable portions of
any regulatory assets would be written off. The transition cost account will be
a regulatory asset also subject to the criteria of SFAS No. 121.
The CPUC decision provides a structure for full recovery of PG&E's
generation investments and costs through market prices and the CTC. However,
market pricing of Diablo Canyon by 2003, possible divestiture of generation
assets and lower returns on a portion of its investments in fossil fuel
generation assets will adversely impact PG&E's future returns on its generation
investments. The Diablo Canyon investment and the related Diablo Settlement will
represent a major portion of PG&E's transition costs. Current recovery of this
investment is occurring through 2015, the period of the Diablo Settlement.
Adjusting Diablo Canyon generation to market prices by 2003 would require an
acceleration in recovery of undepreciated plant costs. The net book value of
PG&E's investment in Diablo Canyon was approximately $4.8 billion at December
31, 1995. The net book value of the remaining PG&E-owned generation assets,
including an allocation of common plant, was approximately $3.1 billion at
December 31, 1995.
Because of the expected transition cost recovery as provided in the
decision, PG&E does not anticipate a material impairment loss on its investment
in generation assets due to electric industry restructuring. However, should
final regulations differ significantly from the CPUC decision or should full
recovery of generation assets and obligations not be achieved due to changing
costs or limitations imposed by the market, a material loss could occur.
The Company cannot predict the ultimate outcome of the ongoing changes that
are taking place in the electric utility industry or predict whether such
outcome will have a material impact on its financial position or results of
operations. However, the Company believes the end result will involve a
fundamental change in the way it conducts business. These changes will impact
financial operating trends, resulting in greater earnings volatility.
16
<PAGE> 9
GAS INDUSTRY: Restructuring of the natural gas industry has given customers
greater options in meeting their gas supply needs. Industrial and large
commercial (noncore) customers have the option of buying gas directly from the
supplier of their choice and purchasing from PG&E transmission and distribution
services only. In the latter half of 1993, even greater numbers of noncore
customers began purchasing their own gas with the implementation of FERC Order
636 and the CPUC's capacity brokering program. FERC Order 636 required
interstate pipeline companies, including PGT, to unbundle their services into
separate sales, transportation and storage services. The CPUC's capacity
brokering program required California utilities to release firm capacity on
interstate pipelines that they no longer needed. These changes have made it
easier for customers to purchase gas directly from suppliers.
Certain customers can also use alternative transportation services provided
by competing companies. The FERC has approved the expansion of a competing
company's natural gas pipeline into PG&E's service territory. If this expansion
takes place, this pipeline could compete directly for transportation service to
several of PG&E's large customers and result in the loss of sales on PG&E's gas
transportation system.
While noncore customers have had options in the gas marketplace, residential
and smaller commercial (core) customers have had more limited opportunities in
choosing their gas suppliers. Currently, substantially all core customers
receive bundled services from PG&E. PG&E purchases and delivers gas to these
customers and prices such service as a package.
In an effort to promote competition and increase options for all customers,
as well as to position itself for success in the competitive marketplace, PG&E
is actively pursuing changes in the California gas industry. In October 1995,
PG&E presented a proposal, called the "Gas Accord," to numerous parties active
in the California gas marketplace, including consumer groups, industrial
customers, shippers and marketers. PG&E has invited these parties to join it in
a collaborative effort to develop a restructuring of the California gas
marketplace.
The Gas Accord proposes three broad initiatives:
(1) Increased Customer Choice -- Under the Gas Accord, PG&E proposes to give
all customers greater ability to choose their gas suppliers in the future. PG&E
has formed an advisory group to help it design a program that will facilitate
opening the core market for full competition.
(2) Separation of Transmission and Distribution Service and Rates -- PG&E
proposes to charge separately for, or unbundle, its gas transmission and
distribution services. This would give noncore customers and gas suppliers more
flexibility with respect to the purchase of gas transportation services. The
proposed unbundled gas transmission and distribution rates would continue to
recover PG&E's cost of service. Accordingly, PG&E believes it would be able to
continue the application of SFAS No. 71 for a majority of its gas business.
(3) Resolution of Existing Regulatory Issues -- PG&E also proposes to settle
several outstanding gas regulatory issues that are currently pending at the CPUC
in separate proceedings. These issues include recovery of costs related to
PG&E's capacity commitments with Transwestern Pipeline Company, PG&E's capacity
commitments with El Paso Natural Gas Company and PGT related to its noncore
customers, and the PG&E portion of the PGT/PG&E Pipeline Expansion Project
(Pipeline Expansion). (See Note 3 of Notes to Consolidated Financial
Statements.)
Negotiations on the Gas Accord began in October 1995. Any agreement reached
by PG&E and other parties must be approved by the CPUC before it may be
implemented. The Company believes the ultimate outcome of the Gas Accord
negotiations, including resolution of gas regulatory issues, will not have a
material impact on its financial position or results of operations.
17
<PAGE> 10
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
CONSOLIDATED RESULTS OF OPERATIONS AND FINANCIAL CONDITION
PACIFIC GAS AND ELECTRIC COMPANY
HOLDING COMPANY STRUCTURE: In October 1995, the Board of Directors (Board) of
PG&E authorized management to seek appropriate shareholder and regulatory
approvals for the formation of a holding company structure. Under such
structure, the holders of common stock of PG&E would become the holders of
common stock of a new holding company which, in turn, would own all the common
stock of PG&E. PG&E would become a subsidiary of the new holding company. The
debt and preferred stock of PG&E would remain outstanding at the PG&E level and
would not become obligations or securities of the holding company.
This transaction would not result in any change in PG&E's ownership of
California utility operations, which currently are conducted by PG&E and
represent substantially all of the assets, revenues and earnings of the
consolidated group. It is intended that PG&E's ownership interest in PGT and
Enterprises would be transferred to the holding company. These two wholly owned
subsidiaries represented approximately eight percent of the Company's
consolidated assets and four percent of the Company's consolidated net income at
December 31, 1995.
The Company believes that the formation of a holding company will help the
Company to respond more effectively and efficiently to competitive changes
taking place in the utility industry and to new business opportunities that may
arise from those changes. This structure should enhance the financial separation
of the Company's California utility business from its other businesses and also
provide greater financing flexibility.
The Company will be seeking approval of the transaction from the CPUC, the
FERC and the NRC. Shareholders will be asked to approve the transaction at the
annual meeting in April 1996. The Company intends to form the holding company
structure by the end of 1996. However, approval from the regulatory agencies
could have an effect on the timing.
UTILITY REVENUE MATTERS: In addition to the CPUC decision on electric industry
restructuring (discussed above and in Note 2 of Notes to Consolidated Financial
Statements) and various gas proceedings (see Note 3 of Notes to Consolidated
Financial Statements), there are other regulatory matters with respect to
revenues and costs which will affect PG&E's rates in 1996 and beyond. In
December 1995, the CPUC issued its decision in PG&E's 1996 GRC. (See below for
further discussion.) Based on the GRC decision and the consolidation of the
electric rate cases that became effective January 1, 1996, including the energy
cost, cost of capital and various other proceedings, PG&E's electric revenue
will decrease by $443 million from rates in effect in 1995. The GRC decision and
various gas proceedings will also result in an overall gas revenue decrease of
$211 million. The more significant of these gas and electric proceedings are
discussed below.
The 1996 GRC decision for base rates effective January 1, 1996, authorized
electric and gas base revenue decreases of approximately $300 million and $270
million, respectively, compared to rates in effect in 1995. The $570 million
revenue decrease is attributable to declining capital expenditures, lower cost
of capital and reductions in expense levels, principally relating to workforce
reductions.
The GRC proceeding has been held open to consider, among other things,
PG&E's response to outages caused by recent storms and a study to determine the
cost effectiveness of the Helms pumped storage facility (Helms). The study will
consider changes in rate recovery for the plant which will include, among other
things, the option of retirement with recovery of the investment without a
return. Helms had a net book value of $631 million at December 31, 1995.
In December 1995, PG&E's service territory experienced severe storms and
winds which caused approximately 1.7 million electric service interruptions. The
assigned commissioner in the 1996 GRC subsequently issued a ruling which ordered
hearings on various issues arising out of PG&E's response to those wind storms.
The hearings will
18
<PAGE> 11
also address potential remedies, including reparations to customers for reduced
reliability, penalties, disallowances and damages to customers for property
loss.
In December 1995, the CPUC issued its decision in PG&E's 1996 electric
energy cost proceeding authorizing a revenue decrease of $112 million due
primarily to lower gas costs, lower Diablo Canyon generation costs, lower QF
expenses and lower estimated undercollections in the energy cost and electric
revenue balancing accounts.
In December 1995, the CPUC approved an increase in gas revenues for PG&E of
approximately $60 million in addition to the changes resulting from the GRC and
other gas proceedings discussed above. The revenue increase reflects an increase
in transportation costs and the collection of amounts previously deferred in
balancing accounts. This decision also ordered a one-time refund, to be made
during the first half of 1996, of approximately $162 million, which represents
an overcollection in certain gas procurement balancing accounts.
In its November 1995 decision, the CPUC adopted the following 1996 cost of
capital for PG&E:
<TABLE>
<CAPTION>
Capital Weighted
Ratio Cost/Return Cost/Return
- ------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Common equity 48.00% 11.60% 5.57%
Long-term debt 46.50% 7.52% 3.49%
Preferred stock and preferred securities 5.50% 7.79% 0.43%
----
Total return on average utility rate base 9.49%
----
</TABLE>
The revenue decrease as a result of this decision has been reflected in the GRC
revenue decreases discussed above.
DIVERSIFIED OPERATIONS: The Company, through its wholly owned subsidiary,
Enterprises, has taken steps to position itself to compete in the nonregulated
energy business. Enterprises contributed $.03, $.01 and $.04 per common share to
the Company's total earnings per common share for the years ended December 31,
1995, 1994 and 1993, respectively.
Enterprises in partnership with Bechtel Enterprises, Inc. (Bechtel) has made
the majority of its investments in nonregulated energy projects through a joint
venture, U.S. Generating Company (USGen). USGen and its affiliates develop, own
and operate power plants in the United States. As the utility business continues
to change, Enterprises is pursuing emerging opportunities, including electric
and gas transmission and distribution opportunities throughout the world. In
1995, Enterprises in partnership with Bechtel formed another joint venture,
International Generating Company, Ltd. (InterGen). InterGen and its affiliates
develop, own and operate international electric generation projects. Also,
Enterprises formed Vantus Energy Corporation to assist customers outside of
PG&E's service territory to locate the most cost-effective electric and gas
products and services.
In June 1995, Enterprises completed its sale of DALEN Corporation (DALEN),
formerly DALEN Resources. The sales price was $455 million, including $340
million cash and the assumption of $115 million of existing debt. The sale
resulted in an after-tax gain of approximately $13 million.
In August 1994, Enterprises and Bechtel acquired J. Makowski Company, Inc.
(JMC), a Boston-based company engaged primarily in the development of natural
gas-fueled electric generation projects. The purchase price was approximately
$250 million. Enterprises' effective ownership share of JMC is approximately 90
percent.
RESULTS OF OPERATIONS
The Company's revenues are derived from three types of operations: utility
(excluding Diablo Canyon and including PGT), Diablo Canyon and diversified
operations (principally
19
<PAGE> 12
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
CONSOLIDATED RESULTS OF OPERATIONS AND FINANCIAL CONDITION
PACIFIC GAS AND ELECTRIC COMPANY
Enterprises). The results of operations for these areas for 1995, 1994 and 1993
are reflected in the following table and discussed below.
<TABLE>
<CAPTION>
DIABLO DIVERSIFIED
UTILITY CANYON(1) OPERATIONS TOTAL
------- --------- ----------- -------
<S> <C> <C> <C> <C>
(in millions, except per share amounts)
1995
Operating revenues $ 7,601 $ 1,845 $ 176 $ 9,622
Operating expenses 5,820 816 223 6,859
------- ------- ------- -------
Operating income (loss) before income taxes $ 1,781 $ 1,029 $ (47) $ 2,763
------- ------- ------- -------
Net income $ 820 $ 507 $ 12(2) $ 1,339
------- ------- ------- -------
Earnings per common share $ 1.80 $ 1.16 $ .03 $ 2.99
------- ------- ------- -------
Total assets at year end $20,090 $ 5,717 $ 1,043 $26,850
------- ------- ------- -------
1994
Operating revenues $ 8,232 $ 1,870 $ 248 $10,350
Operating expenses 6,732 914 280 7,926
------- ------- ------- -------
Operating income (loss) before income taxes $ 1,500 $ 956 $ (32) $ 2,424
------- ------- ------- -------
Net income $ 539 $ 461 $ 7(2) $ 1,007
------- ------- ------- -------
Earnings per common share $ 1.15 $ 1.04 $ .02 $ 2.21
------- ------- ------- -------
Total assets at year end $20,295 $ 5,978 $ 1,436 $27,709
------- ------- ------- -------
1993
Operating revenues $ 8,366 $ 1,933 $ 251 $10,550
Operating expenses 6,921 810 259 7,990
------- ------- ------- -------
Operating income (loss) before income taxes $ 1,445 $ 1,123 $ (8) $ 2,560
------- ------- ------- -------
Net income $ 524 $ 496 $ 45(2) $ 1,065
------- ------- ------- -------
Earnings per common share $ 1.12 $ 1.11 $ .10 $ 2.33
------- ------- ------- -------
Total assets at year end $19,843 $ 6,250 $ 1,053 $27,146
------- ------- ------- -------
</TABLE>
(1) See Note 4 of Notes to Consolidated Financial Statements for discussion of
allocations.
(2) Includes nonoperating income resulting from property sales, partnership
earnings and investment income.
EARNINGS PER COMMON SHARE: Earnings per common share were $2.99, $2.21 and $2.33
for 1995, 1994 and 1993, respectively. Earnings per common share for 1995 were
higher than 1994 due to fewer one-time charges against earnings than in 1994. In
addition, there was only one scheduled refueling outage at Diablo Canyon in
1995, compared with two in 1994.
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 charges for workforce reductions, gas
reasonableness matters, contingencies related to gas transportation commitments
and increased litigation reserves which in the aggregate equaled approximately
$.60 per common share. Similar charges and the impact of increasing the federal
income tax rate to 35 percent in 1993 equaled, in the aggregate, approximately
$.61 per common share. Partially offsetting the 1993 charges was a gain of $.05
per common share from diversified operations resulting from the sale of an
investment held by Mission Trail Insurance Ltd.
On a consolidated basis, the Company earned 14.6 percent, 11.1 percent and
11.9 percent returns on average common stock equity for the years ended December
31, 1995, 1994 and 1993, respectively.
COMMON STOCK DIVIDEND: In January 1996, the Board declared a quarterly dividend
of $.49 per common share which corresponds to an annualized dividend of $1.96
per common share. PG&E's common stock dividend is based on a number of financial
considerations, including sustainability, financial flexibility and
competitiveness with investment opportunities of similar risk. PG&E 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, changes
in regulation will have on its dividend level in the future.
20
<PAGE> 13
OPERATING REVENUES: Electric utility revenues decreased $635 million in 1995
compared to the preceding year primarily due to the decrease in electric energy
costs caused by favorable hydro conditions and lower natural gas prices. In
addition, Diablo Canyon operating revenues decreased due to a decrease in the
price per kWh as provided in the modified pricing provisions of the Diablo
Settlement. This decrease was partially offset by favorable operating revenues
from Diablo Canyon resulting from fewer refueling days in 1995.
Electric utility revenues increased $145 million in 1994 as compared to the
preceding year. Despite the rate freeze, electric utility revenues increased due
to higher energy costs in 1994 reflected in increased electric energy cost
balancing account revenues. The higher revenues from the energy cost balancing
account were offset by a 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 Diablo Settlement, which became effective July 1988, bases revenues for
Diablo Canyon 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 Diablo Canyon
because the extent and timing of the recovery of actual operating costs,
depreciation and a return on the investment in Diablo Canyon 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, the CPUC approved a modification to the Diablo Settlement under
which the price for power produced by Diablo Canyon was reduced from the level
originally set in 1988. PG&E has the right to reduce the price below the amount
specified. All other terms and conditions of the Diablo Settlement remain
unchanged.
Under the modified pricing, each Diablo Canyon operating unit will
contribute approximately $2.7 million in revenues per day at full operating
power in 1996.
The Diablo Canyon capacity factors for 1995, 1994 and 1993 were 86 percent,
81 percent and 89 percent, respectively, reflecting the refueling outages for
Unit 1 in 1995, Units 1 and 2 in 1994 and Unit 2 in 1993. Through December 31,
1995, the lifetime capacity factor for Diablo Canyon was 80 percent. Because of
the nature of the Diablo Settlement, the Company will report significantly lower
revenues for Diablo Canyon during any extended outages, including refueling
outages. In the past, refueling outages, the length of which depend on the scope
of the work, typically occurred for each unit every 18 months. Beginning in
1996, refueling outages will be planned every 21 months as allowed under Diablo
Canyon's current NRC operating license. PG&E intends to seek licensing authority
from the NRC to extend the time between refueling outages to 24 months beginning
in 2001. The next refueling outages for Unit 1 and Unit 2 are scheduled to begin
in May 1997 and April 1996, respectively, and each is planned to last
approximately six weeks.
Gas utility revenues decreased $341 million in 1994 as compared to the
preceding year primarily due to a decrease in revenues received from noncore
customers, who are now arranging for the purchase of their own gas supplies,
with PG&E providing transportation service only. This decrease was partially
offset by higher revenues generated from the Pipeline Expansion. (See Note 3 of
Notes to Consolidated Financial Statements for further discussion.)
Revenues from diversified operations decreased $71 million in 1995 compared
to the preceding year primarily due to the sale of DALEN in June 1995. (See the
Diversified Operations section above for further discussion.)
OPERATING EXPENSES: Operating expenses decreased $1,068 million in 1995 as
compared to the preceding year primarily due to decreased electric costs caused
by favorable hydro conditions, decreased natural gas prices and no workforce
reduction charges in 1995. (See Note 10 of Notes to Consolidated Financial
Statements.)
21
<PAGE> 14
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
CONSOLIDATED RESULTS OF OPERATIONS AND FINANCIAL CONDITION
PACIFIC GAS AND ELECTRIC COMPANY
Operating expenses in 1994 remained constant as compared to 1993. The 1994
and 1993 operating expenses included workforce reduction charges against
earnings of $249 million and $190 million, respectively. The cost of electric
energy was $321 million greater in 1994, primarily due to less favorable hydro
conditions and an increase in the cost of purchased power. These unfavorable
1994 variances were offset by a favorable variance of $369 million in the cost
of gas as a result of PG&E no longer procuring gas for certain customers.
Budgeted 1996 operating expenses are approximately $250 million greater than
the amount adopted by the CPUC for setting rates in the 1996 GRC. The greater
expense level is primarily attributable to several projects related to
distribution system reliability, improved customer service and public
information systems. To the extent that additional cost reductions do not offset
the greater expense level, PG&E's authorized return on equity will be adversely
impacted.
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 policy is to finance its assets with a capital structure that
minimizes financing costs, maintains financial flexibility and complies with
regulatory guidelines. Proceeds from the issuance of securities are used for
capital expenditures, refundings and other general corporate purposes.
DEBT: In 1995, PG&E issued no debt, while PGT issued $400 million of bonds and
$70 million of medium-term notes. All other debt issued during the year by PGT
was commercial paper, which is classified as long-term debt and which had a
balance outstanding at December 31, 1995, of $109 million. Substantially all of
the proceeds of PGT's debt issued were used to refinance outstanding PGT debt.
Also in 1995, PG&E redeemed or repurchased $114 million of mortgage bonds in an
effort to reduce the levels of higher-cost debt.
In 1994, PG&E issued $30 million of medium-term notes and redeemed or
repurchased $135 million of mortgage bonds, medium-term notes and Eurobonds. In
1993, PG&E issued $4 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.
PG&E 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, 1995 and 1994, PG&E
had $796 million and $525 million, respectively, of commercial paper
outstanding. PG&E maintains a $1 billion revolving credit facility which
primarily provides support for PG&E's commercial paper issuance. At maturity,
commercial paper can be either reissued or replaced with borrowings from this
credit facility. The facility also can be used for general corporate purposes.
There were no borrowings under this facility in 1995, 1994 or 1993.
EQUITY: In 1995 and 1994, PG&E received $140 million and $274 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 1993, the Board authorized PG&E to reinstate its common stock repurchase
program. Since that time, the Board has authorized PG&E to repurchase up to $2
billion of its common stock on the open market or in negotiated transactions.
This program is funded by internally generated funds. Shares are being
repurchased to manage the overall balance of common stock in PG&E's capital
structure. Through December 31, 1995, PG&E had repurchased approximately $1
billion of its common stock under this program.
In 1994 and 1993, PG&E issued $62 million and $200 million, respectively, of
preferred stock. In 1995, 1994 and 1993, PG&E redeemed or repurchased $331
million, $75 million and $267 million, respectively, of its higher-cost
preferred stock.
22
<PAGE> 15
OTHER CAPITAL: In 1995, PG&E through its wholly owned subsidiary, PG&E Capital
I, issued $300 million of cumulative quarterly income preferred securities.
CAPITAL REQUIREMENTS: The Company's estimated capital requirements for the next
three years are shown below:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, 1996 1997 1998
------ ------ ------
<S> <C> <C> <C>
(IN MILLIONS)
Utility $1,291 $1,220 $1,283
Diablo Canyon 36 37 39
Diversified operations 162 153 332
------ ------ ------
Total capital expenditures 1,489 1,410 1,654
Maturing debt and sinking
funds 304 322 668
------ ------ ------
Total capital requirements $1,793 $1,732 $2,322
------ ------ ------
</TABLE>
Utility and Diablo Canyon expenditures will be primarily for improvements to
the Company's facilities to enhance their efficiency and reliability, to extend
their useful lives and to comply with environmental laws and regulations.
Diversified operations consist substantially of Enterprises whose estimated
expenditures include 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.
NEW ACCOUNTING STANDARD: The Company will adopt SFAS No. 121 effective January
1, 1996. The general provisions of SFAS No. 121 require, among other things,
that the existence of an impairment be evaluated whenever events or changes in
circumstances indicate that the carrying amount of an asset may not be fully
recoverable and prescribe standards for the recognition and measurement of
impairment losses. In addition, SFAS No. 121 requires that regulatory assets
continue to be probable of recovery in rates, rather than only at the time the
regulatory asset is recorded. Regulatory assets currently recorded would be
written off if recovery is no longer probable.
Based on the expected CTC recovery set forth in the CPUC decision on
electric industry restructuring discussed in Note 2 of Notes to Consolidated
Financial Statements, the Company currently does not anticipate a material
impairment of its assets. However, the CPUC decision is subject to legislative
review. Should final regulations differ significantly from the CPUC decision or
should full recovery of generation assets and obligations not be achieved due to
changing costs or limitations imposed by the market, a material loss could
occur.
RISK MANAGEMENT: Due to the changing regulatory environment, the Company's
exposure to price risk is expected to increase. To manage this risk, in December
1995, the Company adopted a risk management policy and created a committee of
officers to oversee the implementation of the policy, approve each price risk
management program and monitor compliance with the policy.
This action established policies and guidelines for cost effective risk
management programs designed to mitigate financial exposure to changes in the
price of energy commodities, interest rates and currencies. These programs may
include the use of financial derivatives that are designed to offset changes in
the value of an underlying asset, obligation, instrument, contract or index on a
one-for-one basis. This policy prohibits the use of financial derivatives whose
payment formula includes a multiple of some underlying asset. It also prohibits
engaging in speculative financial derivatives trading or adopting compensation
policies that encourage such speculative trading. The Company had no open
positions in derivative financial instruments at December 31, 1995.
The Company also uses other techniques to manage its financial risk
including the purchase of commercial insurance and the maintenance of systems of
internal control. The extent to which these techniques are used depends on the
risk of loss and the cost to employ such techniques.
23
<PAGE> 16
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
CONSOLIDATED RESULTS OF OPERATIONS AND FINANCIAL CONDITION
PACIFIC GAS AND ELECTRIC COMPANY
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 $65
million, $68 million and $121 million for 1996, 1997 and 1998, respectively.
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 PG&E 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 $415 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. The Company has an
accrued liability at December 31, 1995, of $122 million for hazardous waste
remediation costs at those sites where such costs are probable and quantifiable.
The costs may be as much as $287 million if, among other things, 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. This upper limit of the range of costs was estimated using
assumptions least favorable to the Company, among a range of reasonably possible
outcomes. Costs may be higher if the Company is found to be responsible for
cleanup costs at additional sites or identifiable possible outcomes change. (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 have been
litigated or settled with no material impact on either the Company's results of
operations or financial position.
Significant litigation cases are discussed in Note 13 of Notes to
Consolidated Financial Statements. These cases involve claims for personal
injury, and property and punitive damages allegedly suffered as a result of
exposure to chromium near PG&E's Hinkley Compressor Station, anti-trust claims
for damages as a result of Canadian natural gas purchases by one of the
Company's wholly owned subsidiaries and a claim that PG&E 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 the financial
statements of electric utilities. In response to these questions, the Financial
Accounting Standards Board has agreed to review the accounting for closure and
removal costs, including decommissioning of nuclear power plants. 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, with recognition of an
increase in the cost of the related nuclear power plant. The Company does not
believe that such changes, if required, would have an adverse effect on its
results of operations due to its current and future ability to recover
decommissioning costs through rates. (See Note 2 of Notes to Consolidated
Financial Statements for discussion of electric industry restructuring.)
24
<PAGE> 17
PACIFIC GAS AND ELECTRIC COMPANY
STATEMENT OF CONSOLIDATED INCOME
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, 1995 1994 1993
- ----------------------------------------------------------------------------------------------------------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<S> <C> <C> <C>
OPERATING REVENUES
Electric utility $ 7,386,307 $ 8,021,547 $ 7,876,925
Gas utility 2,059,117 2,081,062 2,421,733
Diversified operations 176,341 247,621 251,344
------------ ------------ ------------
Total operating revenues 9,621,765 10,350,230 10,550,002
------------ ------------ ------------
OPERATING EXPENSES
Cost of electric energy 2,116,840 2,570,723 2,250,209
Cost of gas 333,280 583,356 952,510
Maintenance and other operating 1,799,781 1,855,585 1,942,376
Depreciation and decommissioning 1,360,118 1,397,470 1,315,524
Administrative and general 971,576 973,302 1,041,453
Workforce reduction costs (18,195) 249,097 190,200
Property and other taxes 295,380 296,911 297,495
------------ ------------ ------------
Total operating expenses 6,858,780 7,926,444 7,989,767
------------ ------------ ------------
OPERATING INCOME 2,762,985 2,423,786 2,560,235
------------ ------------ ------------
OTHER INCOME AND (INCOME DEDUCTIONS)
Interest income 72,524 79,643 55,361
Allowance for equity funds used during construction 20,039 19,046 41,531
Other--net 58,564 37,996 51,061
------------ ------------ ------------
Total other income and (income deductions) 151,127 136,685 147,953
------------ ------------ ------------
INCOME BEFORE INTEREST EXPENSE 2,914,112 2,560,471 2,708,188
------------ ------------ ------------
INTEREST EXPENSE
Interest on long-term debt 629,548 651,912 731,610
Other interest charges 61,033 77,295 87,819
Allowance for borrowed funds used during construction (10,643) (12,953) (78,626)
------------ ------------ ------------
Total interest expense 679,938 716,254 740,803
------------ ------------ ------------
PRETAX INCOME 2,234,174 1,844,217 1,967,385
------------ ------------ ------------
INCOME TAXES 895,289 836,767 901,890
------------ ------------ ------------
NET INCOME 1,338,885 1,007,450 1,065,495
Preferred dividend requirement and redemption premium 70,288 57,603 63,812
------------ ------------ ------------
EARNINGS AVAILABLE FOR COMMON STOCK $ 1,268,597 $ 949,847 $ 1,001,683
------------ ------------ ------------
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING 423,692 429,846 430,625
EARNINGS PER COMMON SHARE $ 2.99 $ 2.21 $ 2.33
DIVIDENDS DECLARED PER COMMON SHARE $ 1.96 $ 1.96 $ 1.88
</TABLE>
THE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS ARE AN INTEGRAL
PART OF THIS STATEMENT.
25
<PAGE> 18
PACIFIC GAS AND ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEET
<TABLE>
<CAPTION>
DECEMBER 31, 1995 1994
------------ ------------
(IN THOUSANDS)
<S> <C> <C>
ASSETS
PLANT IN SERVICE
Electric
Nonnuclear $ 17,513,830 $ 17,045,247
Diablo Canyon 6,646,853 6,647,162
Gas 7,732,681 7,447,879
------------ ------------
Total plant in service (at original cost) 31,893,364 31,140,288
Accumulated depreciation and decommissioning (13,308,596) (12,269,377)
------------ ------------
Net plant in service 18,584,768 18,870,911
------------ ------------
CONSTRUCTION WORK IN PROGRESS 333,263 527,867
OTHER NONCURRENT ASSETS
Oil and gas properties -- 437,352
Nuclear decommissioning funds 769,829 616,637
Investment in nonregulated projects 869,674 761,355
Other assets 130,128 137,325
------------ ------------
Total other noncurrent assets 1,769,631 1,952,669
------------ ------------
CURRENT ASSETS
Cash and cash equivalents 734,295 136,900
Accounts receivable
Customers 1,238,549 1,413,185
Other 65,907 98,035
Allowance for uncollectible accounts (35,520) (29,769)
Regulatory balancing accounts receivable 746,344 1,245,100
Inventories
Materials and supplies 181,763 197,394
Gas stored underground 146,499 136,326
Fuel oil 40,756 67,707
Nuclear fuel 175,957 140,357
Prepayments 47,025 33,251
------------ ------------
Total current assets 3,341,575 3,438,486
------------ ------------
DEFERRED CHARGES
Income tax-related deferred charges 1,079,673 1,155,421
Diablo Canyon costs 382,445 401,110
Unamortized loss net of gain on reacquired debt 392,116 382,862
Workers' compensation and disability claims recoverable 297,266 247,209
Other 669,553 732,029
------------ ------------
Total deferred charges 2,821,053 2,918,631
------------ ------------
TOTAL ASSETS $ 26,850,290 $ 27,708,564
------------ ------------
</TABLE>
THE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS ARE AN INTEGRAL
PART OF THIS STATEMENT.
26
<PAGE> 19
PACIFIC GAS AND ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEET
<TABLE>
<CAPTION>
DECEMBER 31, 1995 1994
----------- -----------
(IN THOUSANDS)
<S> <C> <C>
CAPITALIZATION AND LIABILITIES
CAPITALIZATION
Common stock $ 2,070,128 $ 2,151,213
Additional paid-in capital 3,716,322 3,806,508
Reinvested earnings 2,812,683 2,677,304
----------- -----------
Total common stock equity 8,599,133 8,635,025
Preferred stock without mandatory redemption provision 402,056 732,995
Preferred stock with mandatory redemption provision 137,500 137,500
Company obligated mandatorily redeemable preferred securities of trust holding
solely PG&E subordinated debentures 300,000 --
Long-term debt 8,048,546 8,675,091
----------- -----------
Total capitalization 17,487,235 18,180,611
----------- -----------
OTHER NONCURRENT LIABILITIES
Customer advances for construction 146,191 152,384
Workers' compensation and disability claims 271,000 221,200
Other 815,960 819,893
----------- -----------
Total other noncurrent liabilities 1,233,151 1,193,477
----------- -----------
CURRENT LIABILITIES
Short-term borrowings 829,947 524,685
Long-term debt 304,204 477,047
Accounts payable
Trade creditors 413,972 414,291
Other 387,747 337,726
Accrued taxes 274,093 436,467
Deferred income taxes 227,782 432,026
Interest payable 70,179 84,805
Dividends payable 205,467 210,903
Other 504,973 468,119
----------- -----------
Total current liabilities 3,218,364 3,386,069
----------- -----------
DEFERRED CREDITS
Deferred income taxes 3,933,765 3,902,645
Deferred tax credits 393,255 391,455
Noncurrent balancing account liabilities 185,647 226,844
Other 398,873 427,463
----------- -----------
Total deferred credits 4,911,540 4,948,407
----------- -----------
COMMITMENTS AND CONTINGENCIES (Notes 1, 2, 3, 12 and 13)
----------- -----------
TOTAL CAPITALIZATION AND LIABILITIES $26,850,290 $27,708,564
----------- -----------
</TABLE>
27
<PAGE> 20
PACIFIC GAS AND ELECTRIC COMPANY
STATEMENT OF CONSOLIDATED CASH FLOWS
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, 1995 1994 1993
- --------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
(IN THOUSANDS)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 1,338,885 $ 1,007,450 $ 1,065,495
Adjustments to reconcile net income to net cash provided by
operating activities
Depreciation and decommissioning 1,360,118 1,397,470 1,315,524
Amortization 89,353 95,331 135,808
Gain on sale of DALEN (13,107) -- --
Deferred income taxes and tax credits--net (116,069) 15,312 319,198
Allowance for equity funds used during construction (20,039) (19,046) (41,531)
Other deferred charges 61,700 32,740 (158,725)
Other noncurrent liabilities (17,218) 181,902 50,279
Noncurrent balancing account liabilities and other deferred credits (69,787) 316,920 124,189
Net effect of changes in operating assets and liabilities
Accounts receivable 212,515 (116,936) 64,790
Regulatory balancing accounts receivable 498,756 (269,250) (232,597)
Inventories 32,409 66,783 23,097
Accounts payable 49,702 (110,033) (39,422)
Accrued taxes (162,374) 132,892 44,638
Other working capital 8,304 5,821 108,873
Other--net 83,569 210,331 13,184
----------- ----------- -----------
Net cash provided by operating activities 3,336,717 2,947,687 2,792,800
----------- ----------- -----------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (931,908) (1,094,495) (1,763,024)
Allowance for borrowed funds used during construction (10,643) (12,953) (78,626)
Diversified operations (180,941) (328,266) (234,221)
Proceeds from sale of DALEN 340,000 -- --
Other--net (122,913) (29,914) 9,992
----------- ----------- -----------
Net cash used by investing activities (906,405) (1,465,628) (2,065,879)
----------- ----------- -----------
CASH FLOWS FROM FINANCING ACTIVITIES
Common stock issued 139,595 274,269 264,489
Common stock repurchased (601,360) (181,558) (257,780)
Preferred stock issued -- 62,312 200,001
Preferred stock redeemed or repurchased (358,212) (82,875) (302,640)
Company obligated mandatorily redeemable preferred securities issued 300,000 -- --
Long-term debt issued 591,160 60,907 4,584,548
Long-term debt matured, redeemed or repurchased (1,296,549) (436,673) (4,002,704)
Short-term debt issued (redeemed)--net 305,262 (239,478) (366,961)
Dividends paid (891,270) (891,850) (857,515)
Other--net (21,543) 28,721 (24,885)
----------- ----------- -----------
Net cash used by financing activities (1,832,917) (1,406,225) (763,447)
----------- ----------- -----------
NET CHANGE IN CASH AND CASH EQUIVALENTS 597,395 75,834 (36,526)
CASH AND CASH EQUIVALENTS AT JANUARY 1 136,900 61,066 97,592
----------- ----------- -----------
CASH AND CASH EQUIVALENTS AT DECEMBER 31 $ 734,295 $ 136,900 $ 61,066
----------- ----------- -----------
Supplemental disclosures of cash flow information
Cash paid for
Interest (net of amounts capitalized) $ 647,151 $ 674,758 $ 642,712
Income taxes 1,125,635 712,777 542,827
</TABLE>
THE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS ARE AN INTEGRAL PART
OF THIS STATEMENT.
28
<PAGE> 21
PACIFIC GAS AND ELECTRIC COMPANY
STATEMENT OF CONSOLIDATED COMMON STOCK EQUITY, PREFERRED STOCK AND PREFERRED
SECURITIES
<TABLE>
<CAPTION>
PREFERRED PREFERRED
STOCK STOCK
TOTAL WITHOUT WITH
ADDITIONAL COMMON MANDATORY MANDATORY
COMMON PAID-IN REINVESTED STOCK REDEMPTION REDEMPTION
(DOLLARS IN THOUSANDS) STOCK CAPITAL EARNINGS EQUITY PROVISION PROVISION(1)
---------- ---------- ---------- ---------- ---------- ------------
<S> <C> <C> <C> <C> <C> <C>
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
---------- ---------- ---------- ---------- -------- --------
Net income--1995 1,338,885 1,338,885
Common stock issued
(5,316,876 shares) 26,584 113,011 139,595
Common stock repurchased
(21,533,977 shares) (107,669) (195,383) (298,308) (601,360)
Preferred securites issued(2)
(12,000,000 shares) 300,000
Preferred stock redeemed or
repurchased (13,237,554 shares) (7,814) (19,459) (27,273) (330,939)
Cash dividends declared
Preferred stock (56,006) (56,006)
Common stock (829,828) (829,828)
Other 95 95
---------- ---------- ---------- ---------- -------- --------
Net change (81,085) (90,186) 135,379 (35,892) (330,939) 300,000
---------- ---------- ---------- ---------- -------- --------
BALANCE DECEMBER 31, 1995 $2,070,128 $3,716,322 $2,812,683 $8,599,133 $402,056 $437,500
---------- ---------- ---------- ---------- -------- --------
</TABLE>
(1) Includes current portion.
(2) Relates to company obligated mandatorily redeemable preferred securities of
trust holding solely PG&E subordinated debentures.
THE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS ARE AN INTEGRAL PART
OF THIS STATEMENT.
29
<PAGE> 22
PACIFIC GAS AND ELECTRIC COMPANY
STATEMENT OF CONSOLIDATED CAPITALIZATION
<TABLE>
<CAPTION>
DECEMBER 31, 1995 1994
- ---------------------------------------------------------------------------------------------------------------
<S> <C> <C>
(DOLLARS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
COMMON STOCK EQUITY
Common stock, par value $5 per share (authorized 800,000,000 shares, issued and
outstanding 414,025,586 and 430,242,687) $ 2,070,128 $ 2,151,213
Additional paid-in capital 3,716,322 3,806,508
Reinvested earnings 2,812,683 2,677,304
----------- -----------
Common stock equity 8,599,133 8,635,025
PREFERRED STOCK AND PREFERRED SECURITIES
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 8.20%--10,297,404 and 23,534,958 shares outstanding 257,435 588,374
----------- -----------
Total preferred stock without mandatory redemption provision 402,056 732,995
----------- -----------
Preferred stock with mandatory redemption provision
Par value $25 per share(1)
6.30% to 6.57%--5,500,000 shares outstanding 137,500 137,500
Par value $100 per share (authorized 10,000,000 shares) -- --
----------- -----------
Total preferred stock with mandatory redemption provision 137,500 137,500
----------- -----------
Preferred stock 539,556 870,495
Company obligated mandatorily redeemable preferred securities of trust holding
solely PG&E subordinated debentures
7.90%--12,000,000 shares outstanding 300,000 --
----------- -----------
LONG-TERM DEBT
PG&E long-term debt
First and refunding mortgage bonds
Maturity Interest rates
1995-2000 4.25% to 6.875% 816,249 823,823
2001-2005 5.875% to 8.75% 1,549,000 1,549,000
2006-2012 6.25% to 8.875% 477,870 477,870
2013-2019 7.5% to 12.75% 105,000 136,030
2020-2026 5.85% to 9.30% 2,749,651 2,902,945
----------- -----------
Principal amounts outstanding 5,697,770 5,889,668
Unamortized discount net of premium (55,802) (66,198)
----------- -----------
Total mortgage bonds 5,641,968 5,823,470
Debentures, 10.81% to 12%, due 1995-2000 57,539 124,939
Pollution control loan agreements, variable rates, due 2008-2016 925,000 925,000
Unsecured medium-term notes, 4.13% to 9.9%, due 1995-2014 1,096,400 1,443,800
Unamortized discount related to unsecured medium-term notes (1,652) (2,428)
Other long-term debt 20,298 22,209
----------- -----------
Total PG&E long-term debt 7,739,553 8,336,990
Long-term debt of subsidiaries 613,197 815,148
----------- -----------
Total long-term debt of PG&E and subsidiaries 8,352,750 9,152,138
Less long-term debt--current portion 304,204 477,047
----------- -----------
Long-term debt 8,048,546 8,675,091
----------- -----------
TOTAL CAPITALIZATION $17,487,235 $18,180,611
=========== ===========
</TABLE>
(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.
30
<PAGE> 23
PACIFIC GAS AND ELECTRIC COMPANY
SCHEDULE OF CONSOLIDATED SEGMENT INFORMATION
<TABLE>
<CAPTION>
ELECTRIC GAS DIVERSIFIED INTERSEGMENT
(IN THOUSANDS) UTILITY UTILITY OPERATIONS(4) ELIMINATIONS TOTAL
- -------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
1995
Operating revenues $ 7,386,307 $2,059,117 $ 176,341 $ -- $ 9,621,765
Intersegment revenues(1) 12,678 85,356 -- (98,034) --
----------- ---------- ---------- --------- -----------
Total operating revenues $ 7,398,985 $2,144,473 $ 176,341 $ (98,034) $ 9,621,765
----------- ---------- ---------- --------- -----------
Depreciation and decommissioning $ 1,007,467 $ 306,717 $ 45,934 $ -- $ 1,360,118
Operating income before
income taxes(2) 2,267,193 540,378 (46,618) 2,032 2,762,985
Capital expenditures(3) 679,866 282,724 -- -- 962,590
Identifiable assets(3) $18,402,373 $6,272,833 $1,042,764 $ -- $25,717,970
Corporate assets 1,132,320
-----------
Total assets at year end $26,850,290
-----------
1994
Operating revenues $ 8,021,547 $2,081,062 $ 247,621 $ -- $10,350,230
Intersegment revenues(1) 12,852 85,341 -- (98,193) --
----------- ---------- ---------- --------- -----------
Total operating revenues $ 8,034,399 $2,166,403 $ 247,621 $ (98,193) $10,350,230
----------- ---------- ---------- --------- -----------
Depreciation and decommissioning $ 982,859 $ 295,979 $ 118,632 $ -- $ 1,397,470
Operating income before
income taxes(2) 2,187,569 271,537 (32,093) (3,227) 2,423,786
Capital expenditures(3) 834,494 292,000 -- -- 1,126,494
Identifiable assets(3) $19,464,080 $6,340,456 $1,436,128 $ -- $27,240,664
Corporate assets 467,900
-----------
Total assets at year end $27,708,564
-----------
1993
Operating revenues $ 7,876,925 $2,421,733 $ 251,344 $ -- $10,550,002
Intersegment revenues(1) 15,369 223,443 -- (238,812) --
----------- ---------- ---------- --------- -----------
Total operating revenues $ 7,892,294 $2,645,176 $ 251,344 $(238,812) $10,550,002
----------- ---------- ---------- --------- -----------
Depreciation and decommissioning $ 925,673 $ 251,490 $ 138,361 $ -- $ 1,315,524
Operating income before
income taxes(2) 2,328,241 247,846 (7,812) (8,040) 2,560,235
Capital expenditures(3) 929,065 954,116 -- -- 1,883,181
Identifiable assets(3) $19,124,964 $6,451,388 $1,053,027 $ -- $26,629,379
Corporate assets 516,520
-----------
Total assets at year end $27,145,899
-----------
</TABLE>
(1) Intersegment electric and gas revenues are accounted for at tariff rates
prescribed by the CPUC.
(2) General corporate expenses are allocated in accordance with FERC Uniform
System of Accounts and requirements of the CPUC.
(3) Includes an allocation of common plant in service and allowance for funds
used during construction.
(4) Represents the nonregulated operations of wholly owned subsidiaries
including Enterprises, Mission Trail Insurance Ltd. (liability insurance)
and Pacific Gas Properites Company (real estate development).
THE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS ARE AN INTEGRAL PART
OF THIS SCHEDULE.
31
<PAGE> 24
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PACIFIC GAS AND ELECTRIC COMPANY
NOTE 1: SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Pacific Gas and Electric Company (PG&E) and its wholly owned and controlled
subsidiaries (collectively, the Company) are engaged principally in the business
of supplying electric and natural gas services. PG&E is a regulated public
utility which provides generation, procurement, transmission and distribution of
electricity and natural gas throughout most of Northern and Central California.
A significant component of PG&E's electric generation is its operation of the
Diablo Canyon Nuclear Power Plant (Diablo Canyon), as discussed in Note 4.
PG&E's diversified operations, conducted primarily through its wholly owned
subsidiary, PG&E Enterprises (Enterprises), include nonutility electric
generation and power plant operations and services.
Major subsidiaries, all of which are wholly owned, are Pacific Gas
Transmission Company (PGT) -- an interstate pipeline company that transports
natural gas from the U.S./Canadian border to the California border and
Enterprises -- the parent company for substantially all of PG&E's diversified
operations, including PG&E Generating Company which through a joint venture
(U.S. Generating Company) develops, owns and operates power plants. DALEN
Corporation, a wholly owned subsidiary of Enterprises engaged in exploration,
development and production of oil and natural gas, was sold in June 1995.
The consolidated financial statements include PG&E and its wholly owned and
controlled subsidiaries. All significant intercompany transactions have been
eliminated. Certain amounts in the prior years' consolidated financial
statements have been reclassified to conform to the 1995 presentation.
REGULATION: The operations of the utility and Diablo Canyon are regulated by the
California Public Utilities Commission (CPUC), the Federal Energy Regulatory
Commission (FERC) and the Nuclear Regulatory Commission, among others. The
consolidated financial statements reflect the ratemaking policies of the CPUC
and the FERC in accordance with Statement of Financial Accounting Standards
(SFAS)No. 71, "Accounting for the Effects of Certain Types of Regulation." SFAS
No. 71 requires a cost-of-service based, rate-regulated enterprise to reflect
the impact of regulatory decisions in its financial statements. As a result,
certain costs are deferred as regulatory assets when recovery through rates is
not currently provided but is expected in the future. As a result of applying
the provisions of SFAS No. 71, PG&E has accumulated approximately $3.2 billion
of net regulatory assets, including balancing accounts, at December 31, 1995.
The CPUC has established mechanisms known as balancing accounts which help
stabilize PG&E'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 estimated cost of debt and equity
funds used to finance the construction of new facilities. Financing costs of
capital additions for Diablo Canyon, the PG&E portion of the PGT/PG&E Pipeline
32
<PAGE> 25
Expansion Project (Pipeline Expansion) and other nonregulated projects are
calculated in accordance with 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 PG&E's nuclear power facilities is
recovered in base rates through an annual allowance. For the years ended
December 31, 1995, 1994 and 1993, the amount recovered in rates for
decommissioning costs was $54 million each year. Based on a 1994 site study of
decommissioning costs, the amount to be recovered in rates in 1996 will be $36
million. It is assumed that this amount will be recovered annually in rates up
to the commencement of decommissioning. However, this amount will again be
reviewed in PG&E's future rate proceedings. Also, based on this study, the
estimated total obligation for nuclear decommissioning costs is approximately
$1.2 billion in 1995 dollars (or $5.9 billion in future dollars, an increase of
$1.4 billion from the 1991 site study resulting primarily from lengthening the
decommissioning period); this obligation is being recognized ratably over the
facilities' lives. The decommissioning period for Diablo Canyon Unit 1 is 2015
through 2034 and 2016 through 2034 for Diablo Canyon Unit 2. 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 average annualized escalation rate and the assumed
after-tax annualized rate of return on qualified trust assets used to calculate
the decommissioning obligation and annual expense are 6.00 percent and 6.20
percent (5.75 percent on nonqualified trust assets), respectively. (See Note 8
for further discussion of nuclear decommissioning funds.) The actual
decommissioning costs are expected to vary from the above estimates because of
changes in assumed dates of decommissioning, regulatory requirements, technology
and costs of labor, materials and equipment.
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.
As required by federal law, the U.S. Department of Energy (DOE) is
responsible for the selection and development of repositories for, and the
disposal of, spent nuclear fuel and high-level radioactive waste. PG&E, as
required by federal law, has signed a contract with the DOE to provide for the
disposal of spent nuclear fuel and high-level radioactive waste from its nuclear
generation stations beginning not later than January 1998; however, this
delivery schedule is expected to be delayed. It is not certain when the DOE will
accept high-level radioactive waste from PG&E and other owners of nuclear power
plants. Extended delays or a default by the DOE would lead to consideration of
costly alternatives involving serious siting and environmental issues. PG&E pays
a one-tenth of one cent fee on each nuclear kilowatt-hour (kWh) sold to fund DOE
storage and disposal activities. PG&E has primary responsibility for the interim
storage of its spent nuclear fuel.
33
<PAGE> 26
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PACIFIC GAS AND ELECTRIC COMPANY
GAINS AND LOSSES ON REACQUIRED DEBT: Gains and losses on reacquired debt charged
to the utility are amortized over the remaining original lives of the debt
reacquired, consistent with ratemaking treatment. Gains and losses on reacquired
debt charged to Diablo Canyon and the PG&E portion of the Pipeline Expansion are
recognized in income at the time such debt is reacquired.
INVENTORIES: Nuclear fuel inventory is stated at the lower of average cost or
market. Amortization of nuclear 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.
USE OF ESTIMATES: The preparation of financial statements in conformity with
generally accepted accounting principles requires management to make estimates
and assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates.
NEW ACCOUNTING STANDARD: SFAS No. 121, "Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to Be Disposed Of," effective
January 1, 1996, prescribes general standards for the recognition and
measurement of impairment losses. In addition, it requires that regulatory
assets continue to be probable of recovery in rates, rather than only at the
time the regulatory asset is recorded. Regulatory assets currently recorded
would be written off if recovery is no longer probable.
Based on the expected competition transition charge (CTC) recovery set forth
in the CPUC decision on electric industry restructuring discussed in Note 2, the
Company currently does not anticipate a material impairment of its assets and,
specifically, its generation-related regulatory assets and investments in
electric generation assets. However, the CPUC decision is subject to
legislative review. Should final regulations differ significantly from the CPUC
decision or should full recovery of generation assets and obligations not be
achieved due to changing costs or limitations imposed by the market, a material
loss could occur.
NOTE 2: ELECTRIC INDUSTRY RESTRUCTURING
On December 20, 1995, the CPUC issued a decision calling for the restructuring
of California's electric industry. The CPUC's goal is to provide a structure
that will ultimately allow California consumers to choose among competing
suppliers of electricity. In summary, the decision would (1) simultaneously
create a wholesale power pool (the Exchange) and allow direct access for certain
customers to contract directly with electric generation providers beginning in
1998 with all customers phased in within five years; (2) establish an
Independent System Operator (ISO) to manage and control the transmission system;
and (3) provide recovery of utilities' stranded costs (costs which are
above-market and could not be recovered under market-based pricing) through a
surcharge, or CTC, to be imposed on all customers. The decision, while effective
immediately, provides a 100-day period for legislative review.
Under the restructuring decision, PG&E would continue to provide
distribution, generation and procurement functions for those customers choosing
to take bundled service, all of which would be regulated under performance-based
ratemaking. The decision requires PG&E to file proposals to
34
<PAGE> 27
establish performance-based ratemaking for its generation and distribution
functions.
The CPUC concluded that market power issues associated with the electric
industry restructuring almost certainly mandate that the investor-owned
utilities (IOUs) divest themselves of a substantial portion of their fossil fuel
generation assets. Accordingly, the decision requires PG&E to file a plan to
voluntarily divest itself of at least 50 percent of its fossil fuel generation
assets.
The decision provides for the collection of transition costs through the
imposition of a non-bypassable CTC. Transition cost recovery shall not increase
rates beyond the rate levels in effect as of January 1, 1996. A transition cost
account will be established for each utility. Transition costs associated with
regulatory assets will be included in the account as authorized by the CPUC. The
account will be adjusted annually for the difference between authorized revenues
associated with the generation assets and actual revenues earned in the market
as well as after a generation asset receives its market valuation. Valuation of
above-market generation assets will be completed by 2003. Utility nonnuclear
generation assets will be valued through sale, spin-off or market appraisal.
Transition costs resulting from the operation of nuclear generation
facilities and electricity purchases under existing wholesale and qualifying
facility (QF) contracts will also be recorded in this account. Transition costs
for these resources will be calculated annually over the terms of the contracts
or until the authorized transition cost recovery has been completed. Except for
existing QF generation contracts with contractual payments beyond 2003, all
transition costs will be collected by 2005.
With respect to recovery of costs associated with Diablo Canyon and the
Diablo Canyon rate case settlement (Diablo Settlement), the decision confirms
that the CPUC will continue to honor regulatory commitments regarding the
recovery of nuclear generation costs. Diablo Canyon transition costs will be
calculated over the term of the Diablo Settlement. The decision requires PG&E to
file a proposal for pricing Diablo Canyon generation at market prices by 2003
and for completing recovery of Diablo Canyon CTC by 2005 while assuring no
overall rate increase over January 1, 1996, levels. If PG&E retains ownership of
Diablo Canyon, decommissioning costs will also be included in the transition
cost account.
FINANCIAL IMPACT OF THE ELECTRIC INDUSTRY RESTRUCTURING: In December 1994, in
response to one of the proceedings leading to the decision, PG&E estimated the
revenue requirements of its owned generation assets and power purchase
obligations to be above market by $3 billion and $11 billion at assumed market
prices of $.040 and $.032 per kWh, respectively. These market prices were used
to provide a range of possible transition costs and do not represent a forecast
of expected market prices. These above-market estimates were determined by
comparing future revenue requirements of generation assets and power purchase
obligations, over a 20-year and 30-year period, respectively, with revenues
computed at assumed market prices. The revenue requirements for Diablo Canyon
and all PG&E-owned generation assets included a return on investment. Diablo
Canyon was included in the revenue requirements calculation using the revised
pricing included in the modified Diablo Settlement. (See Note 4.) The
above-market revenue requirements for Diablo Canyon included above were $4
billion and $6 billion at assumed market prices of $.040 and $.032 per kWh,
respectively. At this time, PG&E has not completed a more current estimate of
its above-market revenue requirements. However, market prices could be less than
$.032 per kWh. The actual amounts of above-market revenue requirements may
differ materially from those indicated above and will depend on the final
regulations and the actual market prices of electricity or a definitive market
valuation.
35
<PAGE> 28
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PACIFIC GAS AND ELECTRIC COMPANY
The CPUC electric industry restructuring decision establishes an account to
track the accumulation of transition costs and their recovery. While the
decision provides an opportunity for recovery of all above-market costs, actual
recovery will occur through a CTC applied to transmission and distribution
rates. The level of CTC will be limited to an amount that does not increase the
customers' aggregate rates above those in effect January 1, 1996. Recent CPUC
decisions effective on January 1, 1996, including PG&E's General Rate Case
(GRC), have resulted in an average electric system rate of 9.9 cents per kWh.
PG&E's ability to recover its transition costs will be dependent on achieving
overall reductions in costs such that it can recover its ongoing operating
costs, capital costs and transition costs at the 1996 rate level and on
continuing to collect CTC for the duration of the recovery period.
As a result of applying the provisions of SFAS No. 71 (see Note 1), PG&E has
accumulated approximately $2.6 billion of electric regulatory assets, including
balancing accounts, at December 31, 1995. The regulatory assets attributable to
electric generation, excluding balancing accounts of $248 million which are
expected to be recovered in the near term, were approximately $1.5 billion at
December 31, 1995. When generation rates are no longer based on cost of service,
as ultimately contemplated under the decision, PG&E will discontinue application
of SFAS No. 71 for that portion of its business. However, PG&E expects to
recover its regulatory assets as transition costs through the CTC and does not
expect a material loss from the discontinuance of SFAS No. 71. PG&E's
transmission and distribution businesses are expected to remain on
cost-of-service rates.
In addition, the adoption of SFAS No. 121 in 1996 will require that all
regulatory assets continue to be probable of recovery in rates. In the event
that this criterion can no longer be met, whether due to changing regulation or
PG&E's inability to collect these costs, applicable portions of any regulatory
assets would be written off. The transition cost account will be a regulatory
asset also subject to the criteria of SFAS No. 121.
The net book value of PG&E's investment in Diablo Canyon was approximately
$4.8 billion at December 31, 1995. The net book value of the remaining
PG&E-owned generation assets, including an allocation of common plant, was
approximately $3.1 billion at December 31, 1995.
Because of the expected transition cost recovery as provided in the
decision, PG&E does not anticipate a material impairment loss on its investment
in generation assets due to electric industry restructuring. However, should
final regulations differ significantly from the CPUC decision or should full
recovery of generation assets and obligations not be achieved due to changing
costs or limitations imposed by the market, a material loss could occur.
The Company cannot predict the ultimate outcome of the ongoing changes that
are taking place in the electric utility industry or predict whether such
outcome will have a material impact on its financial position or results of
operations.
NOTE 3: NATURAL GAS MATTERS
GAS REASONABLENESS PROCEEDINGS: Recovery of gas costs through PG&E's regulatory
balancing account mechanisms is subject to a CPUC determination that such costs
were reasonable. Under the current regulatory framework, annual reasonableness
proceedings are conducted by the CPUC on a historic calendar year basis.
In 1994, the CPUC issued decisions covering the years 1988 through 1990,
ordering disallowances of approximately $90 million of gas costs, plus accrued
interest of
36
<PAGE> 29
approximately $25 million through 1993 for PG&E's Canadian gas procurement
activities, and $8 million for gas inventory operations. PG&E has filed a
lawsuit in a federal district court challenging the CPUC decision on Canadian
gas costs. In September 1995, the federal court denied a motion filed by the
CPUC to dismiss the lawsuit.
During 1995, the CPUC approved settlement agreements between the CPUC's
Division of Ratepayer Advocates (DRA) and PG&E which resolve $25 million of
disallowances recommended by the DRA relating to certain non-Canadian gas issues
arising from the 1991 and 1992 record periods. Pursuant to these agreements,
PG&E will refund $1.1 million to ratepayers.
A number of other reasonableness issues related to PG&E'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 had
recommended disallowances of approximately $79 million and a penalty of $50
million and indicated that it was considering additional recommendations for
pending issues. PG&E and the DRA have signed a settlement agreement to resolve
these issues for a $67 million disallowance.
As of December 31, 1995, PG&E has accrued approximately $208 million for the
CPUC decisions for the years 1988 through 1992 and issues covered by the
settlement agreements described above. The Company believes the ultimate outcome
of these matters will not have a material impact on its financial position or
results of operations.
Settlement of certain other unresolved gas issues is being negotiated as
part of the Gas Accord negotiations discussed below.
PIPELINE EXPANSION: In November 1993, the Company placed in service an expansion
of its natural gas transmission system from the Canadian border into California.
The Pipeline Expansion provides additional firm transportation capacity to
Northern and Southern California and the Pacific Northwest. The total cost of
construction was approximately $1.7 billion; $813 million for the PG&E or
California portion and $852 million for the PGT or interstate portion.
PG&E has filed an application with the CPUC requesting that capital and
operating costs for the PG&E portion of the Pipeline Expansion be found
reasonable. In that CPUC proceeding, the DRA recommended that $100 million in
capital costs be disallowed for recovery in rates while two intervenors jointly
recommended a $223 million disallowance. An order issued by a CPUC
Administrative Law Judge (ALJ) has also reopened the 1993 PG&E Pipeline
Expansion Rate Case to allow reconsideration of issues regarding the decision to
construct the PG&E Pipeline Expansion.
In January 1996, a CPUC ALJ ordered consolidation of the market impact phase
of the PG&E Pipeline Expansion reasonableness proceeding and the Interstate
Transition Cost Surcharge (ITCS) proceeding discussed below.
If the CPUC were to reverse its previous decision finding PG&E was
reasonable in constructing the PG&E Pipeline Expansion, the ultimate outcome
could have an impact on PG&E's ability to recover its cost for unused capacity
on other pipelines as well as on its own intrastate facilities.
For the interstate portion of the Pipeline Expansion, PGT included the total
capital cost in its 1994 GRC filing with the FERC; no parties contested these
costs. Decisions in these three proceedings are expected in 1996. Revenues are
currently being collected under interim rates approved by the FERC and the CPUC,
subject to adjustment.
37
<PAGE> 30
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PACIFIC GAS AND ELECTRIC COMPANY
TRANSPORTATION COMMITMENTS: PG&E 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 PG&E will pay each year may change due
to changes in tariff rates and may be offset to the extent PG&E can broker or
permanently assign any unused capacity. In addition to demand charges, PG&E is
required to pay transportation charges for actual quantities shipped. The total
demand and transportation charges paid by PG&E under these agreements (excluding
agreements with PGT) were approximately $175 million in 1995, $225 million in
1994 and $280 million in 1993.
The following table summarizes the approximate capacity held by PG&E on
various pipelines and the related annual demand charges as of December 31, 1995:
<TABLE>
<CAPTION>
TOTAL
FIRM ANNUAL
CAPACITY DEMAND
PIPELINE HELD CHARGES CONTRACT
COMPANY (MMCF/D) (IN MILLIONS) EXPIRATION
--------- ------------- ----------
<S> <C> <C> <C>
El Paso 1,140 $163 Dec. 1997
Transwestern 200 $28 Mar. 2007
NOVA 600 $20 Oct. 2001
ANG 600 $13 Oct. 2005
</TABLE>
As a result of regulatory changes, PG&E no longer procures gas for its
industrial and large commercial (noncore) customers resulting in a decrease in
PG&E's need for firm transportation capacity for its gas purchases. PG&E
continues to procure gas for its residential and smaller commercial (core)
customers and noncore customers who choose bundled service (core subscription
customers). In order to service these customers, PG&E holds approximately 600
million cubic feet per day (MMcf/d) of firm capacity for its core and core
subscription customers on each of the pipelines owned by El Paso Natural Gas
Company (El Paso), NOVA Corporation of Alberta (NOVA) and Alberta Natural Gas
Company Ltd (ANG).
PG&E is continuing its efforts to broker or assign any remaining unused
capacity including that held for its core and core subscription customers when
such capacity is not being used. Due to relatively low demand for Southwest
pipeline capacity, PG&E cannot predict the volume or price of the capacity on El
Paso and Transwestern Pipeline Company (Transwestern) that will be brokered or
assigned.
Substantially all demand charges incurred by PG&E for pipeline capacity,
including charges for capacity formerly used to service noncore customers which
cannot be brokered or brokered at a discount, are eligible for rate recovery,
subject to a reasonableness review. However, certain groups, including the DRA
and intervenors, have challenged the recovery of certain demand charges.
In December 1995, the CPUC issued a decision on the reasonableness of PG&E's
1992 operations concluding that it was unreasonable for PG&E to subscribe for
transportation capacity with Transwestern. The decision concluded that PG&E was
unable to prove the benefits of such capacity during 1992 and denied recovery
of the $18 million of Transwestern charges for that year. The decision further
orders that costs for the capacity in subsequent years of the contract, which
expires in 2007, be disallowed unless PG&E can demonstrate that the benefits of
the commitment outweigh the costs. PG&E is seeking rehearing of this decision.
The recovery of demand charges associated with capacity which was formerly
used to service PG&E's noncore customers will be decided by the CPUC in the
ITCS proceeding. Pending a final decision in the ITCS proceeding, the CPUC has
approved collection in rates of approximately one-half of the demand charges for
unbrokered or discounted El Paso and PGT capacity which was formerly used to
service PG&E's noncore customers, subject to refund.
38
<PAGE> 31
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PACIFIC GAS AND ELECTRIC COMPANY
In October 1995, PG&E presented a proposal, called the Gas Accord, to
numerous parties active in the California gas marketplace, in an effort to
restructure the California gas market. As part of the Gas Accord negotiations,
PG&E is pursuing the resolution of existing regulatory issues pending in
separate CPUC proceedings. Regulatory issues being negotiated as part of the Gas
Accord include PG&E's capacity commitments with Transwestern, recovery of the
costs for unbrokered capacity commitments under the ITCS mechanism and the
reasonableness proceedings for the PG&E portion of the Pipeline Expansion. The
Company believes the ultimate resolution of past and future Transwestern costs,
the ITCS proceeding and the PG&E portion of the Pipeline Expansion proceedings,
either through settlement negotiations or ongoing proceedings, will not have a
material adverse impact on its financial position or results of operations.
NOTE 4: DIABLO CANYON
RATE CASE SETTLEMENT: The Diablo Settlement bases revenues primarily on the
amount of electricity generated by the plant, rather than on traditional
cost-based ratemaking. The Diablo Settlement provides that Diablo Canyon costs
and operations should no longer be subject to CPUC reasonableness reviews and
that only certain Diablo Canyon costs be recovered through base rates over the
term of the Diablo Settlement, including a full return on such costs. The
related revenues to recover these costs are included in Diablo Canyon operating
revenues reported below. Other than for these and decommissioning costs, Diablo
Canyon no longer meets the criteria for application of SFAS No. 71, which was
discontinued for Diablo Canyon effective July 1988.
PRICING: In May 1995, the CPUC approved a modification to the pricing provisions
of the Diablo Settlement. Under the modification, the prices for power produced
by Diablo Canyon for 1996 through 1999 are 10.5 cents, 10.0 cents, 9.5 cents and
9.0 cents per kWh, respectively, effective January 1. PG&E has the right to
reduce the price below the amount specified. All other terms and conditions of
the Diablo Settlement remain unchanged.
The modification provides that the difference between PG&E's revenue
requirement under the original Diablo Settlement prices and the modified prices
be applied to PG&E's energy cost balancing account until the undercollection in
that account as of December 31, 1995, is fully amortized.
Under the modified pricing, at full operating power each Diablo Canyon unit
would contribute approximately $2.7 million in revenues per day in 1996.
The prices per kWh of electricity generated by Diablo Canyon for 1995, 1994
and 1993 were 11.00 cents, 11.89 cents and 11.16 cents per kWh, respectively.
FINANCIAL INFORMATION: Selected financial information for Diablo Canyon is shown
below:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, 1995 1994 1993
---- ---- ----
(IN MILLIONS)
<S> <C> <C> <C>
Operating revenues $1,845 $1,870 $1,933
Operating income before
income taxes 1,029 956 1,123
Net income 507 461 496
</TABLE>
In determining operating results of Diablo Canyon, operating revenues and
the majority of operating expenses were specifically identified pursuant to the
Diablo Settlement. Administrative and general expenses, principally labor costs,
are allocated based on a study of labor costs. Interest is charged to Diablo
Canyon based on an allocation of corporate debt.
39
<PAGE> 32
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PACIFIC GAS AND ELECTRIC COMPANY
NOTE 5: PREFERRED STOCK AND COMPANY OBLIGATED MANDATORILY REDEEMABLE PREFERRED
SECURITIES OF TRUST HOLDING SOLELY PG&E SUBORDINATED DEBENTURES
(See the Statement of Consolidated Capitalization for additional information.)
PREFERRED STOCK: PG&E's nonredeemable preferred stock at December 31, 1995, has
rights to annual dividends per share ranging from $1.25 to $1.50.
PG&E's redeemable preferred stock without mandatory redemption provisions is
subject to redemption at PG&E's option, in whole or in part, if PG&E pays the
specified redemption price plus accumulated and unpaid dividends through the
redemption date. Annual dividends and redemption prices per share at December
31, 1995, range from $1.09 to $1.86 and from $25.75 to $27.25, respectively.
PG&E's redeemable preferred stock with mandatory redemption provisions
consists of the 6.30% and 6.57% series at December 31, 1995. These series of
preferred stock are subject to mandatory redemption provisions entitling them to
sinking funds providing for the retirement of stock outstanding or may be
redeemed at PG&E's option, beginning in 2004 and 2002, respectively, at par
value plus accumulated and unpaid dividends through the redemption date. The
estimated fair value of PG&E's preferred stock with mandatory redemption
provisions at December 31, 1995 and 1994, was approximately $139 million and
$117 million, respectively, based primarily on matrix pricing models.
During 1995, PG&E redeemed all of its series 7.84%, 8% and 8.20% redeemable
preferred stock. In addition, PG&E repurchased partial amounts of its series
6 7/8%, 7.04% and 7.44% redeemable preferred stock through a tender offer. The
aggregate par value of these redemptions and repurchases was $331 million.
During 1994, PG&E issued $63 million of series 6.30% redeemable preferred
stock and redeemed its series 8.16% redeemable preferred stock with a par value
of $75 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 PG&E, holders of 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.
COMPANY OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES OF TRUST HOLDING
SOLELY PG&E SUBORDINATED DEBENTURES: In November 1995, PG&E through its wholly
owned subsidiary, PG&E Capital I (Trust), completed a public offering of 12
million shares of 7.90% cumulative quarterly income preferred securities
(QUIPS), with an aggregate liquidation value of $300 million. Concurrent with
the issuance of the QUIPS, the Trust issued to PG&E 371,135 shares of common
securities with an aggregate liquidation value of approximately $9 million. The
only assets of the Trust are the deferrable interest subordinated debentures
issued by PG&E with a face value of approximately $309 million, an interest rate
of 7.90 percent and a maturity date of 2025. PG&E's guarantee of the QUIPS,
considered together with the other obligations of PG&E with respect to the
QUIPS, constitutes a full and unconditional guarantee by PG&E of the Trust's
obligations under the QUIPS issued by the Trust. Net proceeds from the QUIPS
offering and the issuance of the common securities were used by the Trust to
purchase the subordinated debentures. Proceeds to PG&E from the sale of the
subordinated debentures are being used to refinance higher-cost preferred stock.
40
<PAGE> 33
NOTE 6: LONG-TERM DEBT
(See the Statement of Consolidated Capitalization for additional information.)
MORTGAGE BONDS: PG&E had $5.7 billion and $5.9 billion of mortgage bonds
outstanding at December 31, 1995 and 1994, 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. All real properties and substantially all
personal properties of PG&E are subject to the lien of the indenture.
PG&E 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. Mortgage bonds, with certain
exceptions, may be used to satisfy the sinking fund requirement.
In conjunction with PG&E's focus on reducing the levels of higher-cost debt,
PG&E redeemed or repurchased $114 million and $80 million of higher-cost
mortgage bonds in 1995 and 1994, respectively. Interest rates on the bonds
redeemed or repurchased ranged from 8.875 percent to 12.75 percent.
Included in the total of outstanding mortgage bonds are First and Refunding
Mortgage Bonds issued by PG&E 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), which
arranged these financings, and are in addition to the Pollution Control Loan
Agreements discussed below. At December 31, 1995 and 1994, PG&E 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 PG&E's mortgage bonds (described above), PG&E had loans totaling $925
million at December 31, 1995 and 1994, from the CPCFA, issued for similar
purposes. 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 PG&E's option. Average annual interest rates on
these loans for 1995 ranged from 3.77 percent to 3.90 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.
LONG-TERM DEBT OF SUBSIDIARIES: In 1995, PGT, a wholly owned subsidiary of PG&E,
completed the sale of $470 million of debt securities through a $700 million
shelf registration. Additionally, PGT issued commercial paper, $109 million of
which was outstanding at December 31, 1995. This commercial paper is classified
as long-term based upon the availability of committed credit facilities expiring
in 2000 and management's intent to maintain such amounts in excess of one year.
Substantially all of the proceeds from the debt offering and sale of commercial
paper were used to refinance $600 million of outstanding PGT debt.
REPAYMENT SCHEDULE: At December 31, 1995, the Company's combined aggregate
amount of maturing long-term debt and sinking fund requirements, for the years
1996 through 2000, are $304 million, $322 million, $668 million, $271 million
and $447 million, respectively.
FAIR VALUE: The estimated fair value of the Company's total long-term debt of
$8.4 billion and $9.2 billion at December 31, 1995 and 1994, respectively, was
approximately $8.7 billion and $8.6 billion, respectively. The estimated
41
<PAGE> 34
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PACIFIC GAS AND ELECTRIC COMPANY
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
Substantially all short-term borrowings consist of commercial paper. The usual
maturity for commercial paper is one to ninety days. Commercial paper
outstanding at December 31, 1995 and 1994, was $796 million with a weighted
average interest rate of 5.92 percent and $525 million with a weighted average
interest rate of 6.18 percent, respectively. The carrying amount of short-term
borrowings approximates fair value.
PG&E maintains a $1 billion revolving credit facility which primarily
provides support for PG&E's commercial paper issuance. At maturity, commercial
paper can be either reissued or replaced with borrowings from this credit
facility. The facility also can be used for general corporate purposes. There
were no borrowings under this facility in 1995 or 1994. This credit facility
expires in November 2000; however, it may be extended annually for additional
one-year periods upon mutual agreement among PG&E 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 PG&E'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 PG&E'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 1995 and 1994 from the sale of securities held
as available-for-sale were approximately $1.5 billion and $1 billion,
respectively. During 1995 and 1994, the gross realized gains on sales of
securities held as available-for-sale were $9 million and $10 million,
respectively, and the gross realized losses on sales of securities held as
available-for-sale were $22 million and $12 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.
The following tables provide a summary of amortized cost and fair value by
major security type:
<TABLE>
<CAPTION>
GROSS GROSS
UNREALIZED UNREALIZED
DECEMBER 31, AMORTIZED HOLDING HOLDING FAIR
1995 COST GAINS LOSSES VALUE
--------- ---------- ---------- ---------
(IN THOUSANDS)
<S> <C> <C> <C> <C>
Debt of U.S.
Treasury and
other federal
entities $ 332,847 $ 21,157 $ -- $ 354,004
State and local
obligations 45,086 2,716 (97) 47,705
Equity
securities 277,460 93,767 (2,759) 368,468
Other
securities and
adjustments (377) 33 (4) (348)
--------- --------- --------- ---------
Total nuclear
decommis-
sioning funds $ 655,016 $ 117,673 $ (2,860) $ 769,829
--------- --------- --------- ---------
</TABLE>
42
<PAGE> 35
<TABLE>
<CAPTION>
GROSS GROSS
UNREALIZED UNREALIZED
DECEMBER 31, AMORTIZED HOLDING HOLDING FAIR
1994 COST GAINS LOSSES VALUE
--------- ---------- ---------- --------
<S> <C> <C> <C> <C>
(IN THOUSANDS)
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
securities and
adjustments 46,398 24 (275) 46,147
-------- -------- -------- --------
Total nuclear
decommis-
sioning funds $616,762 $ 19,868 $(19,993) $616,637
-------- -------- -------- --------
</TABLE>
At December 31, 1995 and 1994, investments in debt securities maturing
within ten years totaled $275 million and $293 million, respectively, and
investments in debt securities with maturities in excess of ten years totaled
$146 million and $114 million, respectively.
NOTE 9: EMPLOYEE BENEFIT PLANS
RETIREMENT PLAN: PG&E provides a noncontributory defined benefit pension plan
covering substantially all employees. Retirement benefits are based on years of
service and the employee's base salary. PG&E's policy is to fund each year not
more than the maximum amount deductible for federal income tax purposes and not
less than the minimum legal funding requirement. Other than for voluntary
retirement incentive (VRI) benefits, PG&E last funded the retirement plan in
1992, consistent with amounts recovered in rates.
At December 31, 1995, plan assets exceeded the projected benefit obligation
by $739 million. The plan's funded status was:
<TABLE>
<CAPTION>
DECEMBER 31, 1995 1994
----------- -----------
(IN THOUSANDS)
<S> <C> <C>
Actuarial present value of
benefit obligations
Vested benefits $(3,464,782) $(3,079,045)
Nonvested benefits (182,503) (131,489)
----------- -----------
Accumulated benefit
obligation (3,647,285) (3,210,534)
Effect of projected future
compensation increases (548,743) (441,951)
----------- -----------
Projected benefit obligation (4,196,028) (3,652,485)
Plan assets at market value 4,935,267 4,169,516
----------- -----------
Plan assets in excess of
projected benefit obligation 739,239 517,031
Unrecognized prior service
cost 90,496 93,425
Unrecognized net gain (1,074,347) (908,485)
Unrecognized net transition
obligation 97,348 108,800
----------- -----------
Accrued pension liability $ (147,264) $ (189,229)
----------- -----------
</TABLE>
Plan assets are primarily common stocks and fixed-income securities.
Unrecognized prior service costs and net gains are amortized on a straight-line
basis over the average remaining service period of active plan participants. The
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.
43
<PAGE> 36
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PACIFIC GAS AND ELECTRIC COMPANY
The cost of this plan is recorded to expense and, on a funding basis, to
plant in service. Net pension cost or income, using the projected unit credit
actuarial cost method, was:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, 1995 1994 1993
--------- --------- ---------
(IN THOUSANDS)
<S> <C> <C> <C>
Service cost for
benefits earned $ 82,814 $ 109,132 $ 129,166
Interest cost 290,563 272,932 268,698
Actual (return) loss
on plan assets (968,126) 20,358 (511,526)
Net amortization
and deferral 586,350 (412,547) 177,597
--------- --------- ---------
Net pension
(income) cost $ (8,399) $ (10,125) $ 63,935
--------- --------- ---------
</TABLE>
Actuarial assumptions used in accounting for the pension plan were:
<TABLE>
<CAPTION>
December 31, 1995 1994 1993
---- ---- ----
<S> <C> <C> <C>
Discount rate 7.25% 8% 7%
Rate of future compensation
increases 5% 5% 5%
Expected long-term rate of
return on plan assets 9% 9% 9%
</TABLE>
Net pension cost or income is determined using assumptions at the beginning
of the year. Funded status is determined using assumptions at the end of the
year.
The decrease in net pension cost in 1994 compared to 1993 was primarily due
to changes in the assumed rates of future compensation increases and turnover to
better reflect actual and expected rates.
Net pension cost or income 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 or income. In 1995 and 1993, actual return on plan assets
exceeded expected return. In 1994, the plan experienced a negative investment
return due to weak performance in domestic equities and bonds.
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 funding approach.
SAVINGS FUND PLAN: PG&E sponsors a defined contribution pension plan. Employees
with at least one year of service 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 PG&E
contributions at specified rates. The cost of PG&E contributions was charged to
expense and to plant in service and totaled $33 million, $35 million and $36
million for 1995, 1994 and 1993, respectively.
POSTRETIREMENT BENEFITS OTHER THAN PENSIONS: PG&E provides a contributory
defined benefit medical plan for retired employees and their eligible dependents
and a non-contributory 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 PG&E's retirees. The cost of these plans is charged to
expense and to plant in service.
The CPUC has authorized recovery of these benefits for 1993 and beyond,
within certain guidelines, at a level equal to the annual accounting cost, based
on amortization of the transition obligation over 20 years, limited by the
44
<PAGE> 37
amount which can be contributed annually on a tax-deductible basis to
appropriate trusts. PG&E's policy for postretirement medical and life insurance
benefits is to fund each year an amount consistent with the basis for rate
recovery.
In 1993, PG&E implemented a plan change that will limit the amount it will
contribute toward postretirement medical benefits beginning in 2001. This change
reduced the accumulated postretirement benefit obligation at July 1, 1993, by
approximately $450 million.
At December 31, 1995, the accumulated postretirement benefit obligation
exceeded plan assets by $422 million. The medical and life insurance plans'
funded status was:
<TABLE>
<CAPTION>
DECEMBER 31, 1995 1994
--------- ---------
(IN THOUSANDS)
<S> <C> <C>
Accumulated postretirement
benefit obligation
Retirees $(528,367) $(497,889)
Other fully eligible participants (123,615) (104,865)
Other active plan participants (309,405) (219,639)
--------- ---------
Total accumulated postretirement
benefit obligation (961,387) (822,393)
Plan assets at market value 538,905 394,939
--------- ---------
Accumulated postretirement
benefit obligation in excess of
plan assets (422,482) (427,454)
Unrecognized prior service cost 23,761 25,377
Unrecognized net gain (104,167) (115,249)
Unrecognized transition obligation 449,647 462,082
--------- ---------
Accrued postretirement
benefit liability $ (53,241) $ (55,244)
--------- ---------
</TABLE>
Plan assets are primarily common stocks and fixed-income securities.
Unrecognized prior service costs are amortized on a straight-line basis over the
average remaining years of service to full eligibility of active plan
participants. Unrecognized net gains are amortized on a straight-line basis over
the average remaining years of service of active plan participants. The
transition obligation is amortized over 20 years, beginning in 1993.
Net postretirement medical and life insurance cost, using the projected unit
credit actuarial cost method, was:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, 1995 1994 1993
--------- --------- ---------
(IN THOUSANDS)
<S> <C> <C> <C>
Service cost for
benefits earned $ 17,004 $ 23,617 $ 38,496
Interest cost 64,776 64,872 73,502
Actual return on
plan assets (108,932) (1,232) (23,999)
Amortization of
unrecognized prior
service cost 1,616 1,711 --
Amortization of
transition obligation 26,533 28,913 39,620
Net amortization
and deferral 70,070 (29,804) (3,390)
--------- --------- ---------
Net postretirement
benefit cost $ 71,067 $ 88,077 $ 124,229
--------- --------- ---------
</TABLE>
The discount rate, rate of future compensation increases and expected
long-term rate of return on plan assets used in accounting for the
postretirement benefit plans for 1995, 1994 and 1993 were the same as those used
for the pension plan. The assumed health care cost trend rate for 1996 is
approximately 10.5 percent, grading down to an ultimate rate in 2005 of
approximately 6 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, 1995, by
approximately $117 million and the 1995 aggregate service and interest costs by
approximately $12 million.
The decrease in net postretirement benefit cost in 1995 compared to 1994 was
primarily due to a reduction in workforce and an increase in discount rate. The
decrease in cost in 1994 compared to 1993 was primarily due to the plan change
implemented July 1, 1993, that will limit PG&E's contributions toward
postretirement medical benefits.
45
<PAGE> 38
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PACIFIC GAS AND ELECTRIC COMPANY
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 1995, actual return on plan assets
exceeded expected return. In 1994 and 1993, actual return on plan assets was
less than expected.
WORKFORCE REDUCTIONS: The effects of workforce reductions announced by PG&E in
1994 and 1993 are reflected in the pension and postretirement benefits funded
status tables above, and the costs are discussed in Note 10.
LONG-TERM INCENTIVE PROGRAM: PG&E 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 PG&E's 1986 Stock Option Plan. As of December
31, 1995, a total of 14.5 million shares of common stock have been authorized
for award under the Program and the 1986 Stock Option Plan. During 1995, an
additional 10 million common shares were authorized for award under the Program,
subject to shareholder approval. At December 31, 1995, stock options on
2,761,290 shares, granted at option prices ranging from $16.75 to $34.25, were
outstanding. During 1995, 570,500 options were granted at an option price of
$24.38, 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. In 1995, 1994 and 1993, stock
options on 235,568, 52,143 and 174,387 shares, respectively, were exercised at
option prices ranging from $16.75 to $33.13, $24.75 to $32.13 and $16.75 to
$33.13, respectively. At December 31, 1995, stock options on 1,337,196 shares
were exercisable.
NOTE 10: WORKFORCE REDUCTIONS
In 1994, PG&E expensed the total cost of its planned 1994-1995 workforce
reductions of $249 million and recorded a corresponding liability for benefits
to be funded or paid. This amount consisted of $136 million for additional
pension benefits and $52 million for other postretirement benefits both extended
in connection with the VRI as well as $61 million of estimated severance costs.
The majority of the severances were in generation and transmission funtions.
PG&E will not seek rate recovery for the cost of the 1994-1995 workforce
reductions.
In 1995, PG&E canceled approximately 800 of the 3,000 planned 1994-1995
reductions in order to accelerate maintenance on its system in light of the
severity of the damage caused by storms in the winter of 1995 and the
identification of certain facilities that would benefit from a more extensive
and accelerated maintenance program. As a result, the estimated severance costs
accrued and expensed in 1994 were reduced by $18.2 million in 1995.
The total cost of the 1993 workforce reductions was $264 million. 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, PG&E expensed $190 million of costs
relating to electric operations. The amount relating to gas operations was
deferred and amortized over the period 1993-1995.
NOTE 11: 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. Tax credits are deferred and amortized to income over the life
of the related property.
46
<PAGE> 39
The significant components of income tax expense were:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, 1995 1994 1993
----------- ----------- -----------
(IN THOUSANDS)
<S> <C> <C> <C>
Current $ 1,011,358 $ 821,455 $ 582,692
Deferred (97,864) 34,657 339,608
Tax credits--net (18,205) (19,345) (20,410)
----------- ----------- -----------
Total income tax
expense $ 895,289 $ 836,767 $ 901,890
----------- ----------- -----------
</TABLE>
The significant components of net deferred income tax liabilities were:
<TABLE>
<CAPTION>
DECEMBER 31, 1995 1994
---------- ----------
(IN THOUSANDS)
<S> <C> <C>
Deferred income tax assets:
Deferred income taxes--
current $ 195,510 $ 173,357
Deferred income taxes--
noncurrent 1,008,471 959,459
---------- ----------
Total deferred income tax assets 1,203,981 1,132,816
---------- ----------
Deferred income tax liabilities:
Deferred income taxes--current
Regulatory balancing
accounts 385,604 559,750
Other 37,688 45,633
---------- ----------
Total deferred income
taxes--current 423,292 605,383
---------- ----------
Deferred income taxes--noncurrent
Plant in service 3,552,974 3,627,294
Income tax-related deferred
charges(1) 443,152 474,242
Other 946,110 760,568
---------- ----------
Total deferred income
taxes--noncurrent 4,942,236 4,862,104
---------- ----------
Total deferred income tax
liabilities 5,365,528 5,467,487
---------- ----------
Total net deferred income taxes $4,161,547 $4,334,671
---------- ----------
Classification of net deferred income taxes:
Included in current liabilities $ 227,782 $ 432,026
Included in deferred credits 3,933,765 3,902,645
---------- ----------
Total net deferred income taxes $4,161,547 $4,334,671
---------- ----------
</TABLE>
(1) Represents the portion of the deferred income tax liability related to the
revenues required to recover future income taxes.
The differences between income taxes and amounts determined by applying the
federal statutory rate to income before income tax expense were:
<TABLE>
<CAPTION>
Year ended December 31, 1995 1994 1993
---- ---- ----
<S> <C> <C> <C>
Federal statutory income
tax rate 35.0% 35.0% 35.0%
Increase (decrease) in income
tax rate resulting from:
State income tax (net of
federal benefit) 4.8 8.3 6.5
Effect of regulatory
treatment of
depreciation
differences 3.2 3.7 4.5
Tax credits--net (.8) (1.1) (1.0)
Other--net (2.1) (.5) .8
---- ---- ----
Effective tax rate 40.1% 45.4% 45.8%
---- ---- ----
</TABLE>
NOTE 12: COMMITMENTS
CAPITAL PROJECTS: Capital expenditures for 1996 are estimated to be
approximately $1,489 million, consisting of $1,291 million for utility
expenditures, $36 million for Diablo Canyon expenditures and $162 million for
expenditures from diversified operations.
At December 31, 1995, Enterprises had firm commitments totaling $143 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 $114 million in 1996 and $29 million in 1997.
QUALIFYING FACILITIES: Under the Public Utility Regulatory Policies Act of 1978,
PG&E is required to purchase electric energy and capacity provided by QFs. The
CPUC established a series of power purchase agreements which set the applicable
terms, conditions and price options. The total cost of
47
<PAGE> 40
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PACIFIC GAS AND ELECTRIC COMPANY
prudently incurred energy and capacity payments to QFs is recoverable in rates.
PG&E's contracts with QFs expire on various dates from 1996 to 2026. Under these
contracts, PG&E 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, with a decline in payments expected in the years 1998 through 2000
under the terms of the QF contracts.
In 1995 and 1994, PG&E negotiated early termination or suspension of certain
QF contracts at a cost of $142 million and $155 million, respectively, to be
paid through 1999. These amounts are expected to be recovered in rates. At
December 31, 1995, $159 million remained to be paid to QFs for early termination
or suspension.
QF deliveries in the aggregate account for approximately 20 percent of
PG&E's 1995 electric energy requirements, and no single contract accounted for
more than 5 percent of PG&E's energy needs. QF deliveries in 1995 represented
approximately 83 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:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, 1995 1994 1993
------- ------- -------
(IN MILLIONS)
<S> <C> <C> <C>
Kilowatt-hours received 20,496 21,699 21,242
Energy payments $ 1,140 $ 1,196 $ 1,099
Capacity payments $ 484 $ 518 $ 503
</TABLE>
OTHER POWER PURCHASES: PG&E 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, PG&E 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, 1995, the undiscounted future minimum
payments under these contracts are $34 million for each of the years 1996
through 2000 and a total of $417 million for periods thereafter. Total payments
under these contracts were $50 million, $49 million and $45 million in 1995,
1994 and 1993, respectively.
NOTE 13: CONTINGENCIES
NUCLEAR INSURANCE: PG&E is a member of Nuclear Mutual Limited (NML) and Nuclear
Electric Insurance Limited (NEIL). Under these policies, if the nuclear
generating facility of a member utility suffers a property damage loss or a
business interruption loss due to a prolonged accidental outage, PG&E may be
subject to maximum assessments of $26 million (property damage) and $8 million
(business interruption), in each case per policy period, in the event losses
exceed the resources of NML or NEIL.
Federal law requires all utilities with nuclear generating facilities to
share in payment for claims resulting from a nuclear incident and limits
industry liability for third-party claims 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 claims in excess of $200 million, PG&E 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 records its environmental liabilities
when site assessments and/or remedial actions are probable and a range of
reasonably likely cleanup costs can be estimated. The Company reviews its sites
and measures the liability quarterly, by assessing a range of reasonably likely
costs for each identified site using currently available information, including
existing technology, presently enacted laws and regulations,
48
<PAGE> 41
experience gained at similar sites and the probable level of involvement and
financial condition of other potentially responsible parties. These estimates
include costs for site investigations, remediation, operations and maintenance,
monitoring and site closure. Unless there is a probable amount, the Company
records the lower end of this reasonably likely range of costs (classified as
other noncurrent liabilities). 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 PG&E 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, and it is reasonably possible that a change in the estimate will occur
in the near term 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, 1995, of $122
million for hazardous waste remediation costs at those sites where such costs
are probable and quantifiable. The costs may be as much as $287 million if,
among other things, 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. This upper limit of the range of
costs was estimated using assumptions least favorable to the Company, among a
range of reasonably possible outcomes. Costs may be higher if the Company is
found to be responsible for cleanup costs at additional sites or identifiable
possible outcomes change.
The Company will seek recovery of prudently incurred hazardous waste
compliance and remediation costs through ratemaking procedures approved by the
CPUC, through insurance and through other recoveries from third-parties. While
the Company has numerous insurance policies that it believes may provide
coverage for some of these liabilities, it does not recognize insurance or
third-party recoveries in its financial statements until they are realized. The
Company believes the ultimate outcome of these matters will not have a material
adverse impact on its financial position or results of operations.
HELMS PUMPED STORAGE PLANT (HELMS): Helms is a three-unit hydroelectric combined
generating and pumped storage plant with a net book value of $631 million at
December 31, 1995. As part of the 1996 GRC decision in December 1995, the CPUC
directed PG&E to perform a cost-effectiveness study of Helms, to be submitted in
July 1996. The study will consider changes in rate recovery for the plant which
will include, among other things, the option of retirement with recovery of the
investment without a return.
PG&E is currently unable to predict whether there will be a change in rate
recovery resulting from the study. The Company believes that the ultimate
outcome of this matter will not have a material adverse impact on its financial
position or results of operations.
49
<PAGE> 42
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PACIFIC GAS AND ELECTRIC COMPANY
LEGAL MATTERS:
STANISLAUS LITIGATION: A lawsuit was filed by the County of Stanislaus,
California, and a residential customer of PG&E, purportedly as a class action on
behalf of all natural gas customers of PG&E during the period of February 1988
through October 1993. The lawsuit alleged that the purchase of natural gas in
Canada by Alberta and Southern Gas Co. Ltd., a subsidiary of PG&E, was
accomplished in violation of various antitrust laws and sought damages of as
much as $950 million, before trebling.
In December 1995, a federal district court dismissed the lawsuit. The
plaintiffs have the right to appeal the dismissal to the Court of Appeals. The
Company believes that the ultimate outcome of this matter will not have a
material adverse impact on its financial position.
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 PG&E'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 PG&E discharged chromium-contaminated wastewater
into unlined ponds to avoid costly alternatives, which led to chromium
percolating into the groundwater of surrounding property.
PG&E 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, PG&E will pay an aggregate amount of no more than $400 million in
settlement of such plaintiffs' claims. In turn, those plaintiffs, and their
attorneys, agree to indemnify PG&E against any additional losses PG&E 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.
As of December 31, 1995, PG&E has paid $50 million to escrow and recorded an
additional $150 million reserve against any future potential liability in this
case. The Company believes the ultimate outcome of this matter will not have a
material adverse impact on its financial position or results of operations.
CITIES FRANCHISE FEES LITIGATION: In 1994, the City of Santa Cruz filed a class
action suit in a state superior court (Court) against PG&E on behalf of itself
and 106 other cities in PG&E's service area. The complaint alleges that PG&E has
underpaid electric franchise fees to the cities by calculating fees at different
rates from other cities.
In September 1995, the Court certified the class of 107 cities in this
action and approved the City of Santa Cruz as the class representative. In
January 1996, the Court granted PG&E's motion for summary judgment against
certain plaintiffs and various motions effectively eliminating a major portion
of the class action. The Court's rulings do not resolve the case completely.
Should the cities prevail on the issue of franchise fee calculation
methodology, PG&E's annual systemwide city electric franchise fees could
increase by approximately $17 million and damages for alleged underpayments for
the years 1987 to 1995 could be as much as $131 million (exclusive of interest,
estimated to be $31 million as of December 31, 1995). If the Court's January
1996 rulings become final, PG&E's annual systemwide city electric franchise fees
for the remaining class member cities could increase by approximately $5.3
million and damages for alleged underpayments for the years 1987 to 1995 could
be as much as $39.1 million (exclusive of interest).
The Company believes that the ultimate outcome of this matter will not have
a material adverse impact on its financial position or results of operations.
50
<PAGE> 43
QUARTERLY CONSOLIDATED FINANCIAL DATA (UNAUDITED)
PACIFIC GAS AND ELECTRIC COMPANY
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 every quarter during the year.
PG&E recorded an increase of $50 million in litigation reserves in the first
and third quarters of 1995.
In the first quarter of 1994, PG&E 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 PG&E's assessment of open
reasonableness issues. In the second quarter of 1994, PG&E increased its
litigation reserves by $50 million. In the fourth quarter of 1994, PG&E took a
charge against earnings of $249 million related to 1994 workforce reductions.
PG&E's common stock is traded on the New York, Pacific, London, Amsterdam,
Basel and Zurich stock exchanges. There were approximately 220,000 common
shareholders of record at December 31, 1995. Dividends are paid on a quarterly
basis, and there are no significant restrictions on the present ability of PG&E
to pay dividends.
<TABLE>
<CAPTION>
QUARTER ENDED DECEMBER 31 SEPTEMBER 30 JUNE 30 MARCH 31
------------- ------------- ------------- -------------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<S> <C> <C> <C> <C>
1995
Operating revenues(1) $ 2,227,224 $ 2,637,653 $ 2,448,641 $ 2,308,247
Operating income(1) 451,674 781,912 820,370 709,029
Net income 227,085 377,593 405,520 328,687
Earnings per common share(2) .48 .85 .92 .73
Dividends declared per common share .49 .49 .49 .49
Common stock price per share
High 30.63 30.00 29.75 25.75
Low 27.13 28.38 24.75 24.25
1994
Operating revenues(1) $ 2,619,484 $ 2,840,962 $ 2,444,457 $ 2,445,327
Operating income(1) 306,270 889,658 611,901 615,957
Net income 103,500 425,633 241,365 236,952
Earnings per common share(2) .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
</TABLE>
(1) Operating revenues and operating income have been reclassified to conform
with the 1995 presentation of the Statement of Consolidated Income.
(2) Includes Diablo Canyon scheduled refueling outages which impacted earnings
per common share for the fourth quarter in 1995 and all quarters in 1994. In
addition, Diablo Canyon experienced unscheduled outages in the third and
fourth quarters of 1995 and in the second quarter of 1994.
51
<PAGE> 44
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
PACIFIC GAS AND ELECTRIC COMPANY
TO THE SHAREHOLDERS AND THE BOARD OF DIRECTORS OF PACIFIC GAS AND ELECTRIC
COMPANY:
We have audited the accompanying consolidated balance sheet and the statement of
consolidated capitalization of Pacific Gas and Electric Company (a California
corporation) and subsidiaries as of December 31, 1995 and 1994, and the related
statements of consolidated income, cash flows, common stock equity, preferred
stock and preferred securities, and the schedule of consolidated segment
information for each of the three years in the period ended December 31, 1995.
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 and schedule 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, 1995 and 1994, and the results of their
operations and cash flows for each of the three years in the period ended
December 31, 1995, in conformity with generally accepted accounting principles.
ARTHUR ANDERSEN LLP
San Francisco, California
February 12, 1996
52
<PAGE> 45
RESPONSIBILITY FOR CONSOLIDATED FINANCIAL STATEMENTS
PACIFIC GAS AND ELECTRIC COMPANY
The responsibility for the integrity of the consolidated financial statements
and related financial information included in this report rests with management.
The consolidated financial statements have been prepared in accordance with
generally accepted accounting principles appropriate in the circumstances and
are 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 consolidated financial statements. 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.
53
<PAGE> 46
EXHIBIT INDEX
<TABLE>
<CAPTION>
Exhibit
Number Exhibit
<S> <C>
11 Computation of Earnings
per Common Share
12.1 Computation of Ratios
of Earnings to Fixed
Charges
12.2 Computation of Ratios of
Earnings to Combined Fixed
Charges and Preferred Stock
Dividends
23 Consent of Arthur
Andersen LLP
27 Financial Data Schedule
</TABLE>
<PAGE> 1
EXHIBIT 11
PACIFIC GAS AND ELECTRIC COMPANY
COMPUTATION OF EARNINGS PER COMMON SHARE
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------------------
Year ended December 31,
----------------------------------
(in thousands, except per share amounts) 1995 1994 1993
- --------------------------------------------------------------------------------------------
<S> <C> <C> <C>
EARNINGS PER COMMON SHARE (EPS) AS SHOWN
IN THE STATEMENT OF CONSOLIDATED INCOME
Net income $1,338,885 $1,007,450 $1,065,495
Less: preferred dividend requirement and
redemption premium 70,288 57,603 63,812
---------- ---------- ----------
Net income for calculating EPS for
Statement of Consolidated Income $1,268,597 $ 949,847 $1,001,683
========== ========== ==========
Average common shares outstanding 423,692 429,846 430,625
========== ========== ==========
EPS as shown in the Statement of
Consolidated Income $ 2.99 $ 2.21 $ 2.33
========== ========== ==========
PRIMARY EPS (1)
Net income $1,338,885 $1,007,450 $1,065,495
Less: preferred dividend requirement and
redemption premium 70,288 57,603 63,812
---------- ---------- ----------
Net income for calculating primary EPS $1,268,597 $ 949,847 $1,001,683
========== ========== ==========
Average common shares outstanding 423,692 429,846 430,625
Add exercise of options, reduced by the
number of shares that could have been
purchased with the proceeds from
such exercise (at average market price) 126 57 1,619
---------- ---------- ----------
Average common shares outstanding as
adjusted 423,818 429,903 432,244
========== ========== ==========
Primary EPS $ 2.99 $ 2.21 $ 2.32
========== ========== ==========
FULLY DILUTED EPS (1)
Net income $1,338,885 $1,007,450 $1,065,495
Less: preferred dividend requirement and
redemption premium 70,288 57,603 63,812
---------- ---------- ----------
Net income for calculating fully diluted EPS $1,268,597 $ 949,847 $1,001,683
========== ========== ==========
Average common shares outstanding 423,692 429,846 430,625
Add exercise of options, reduced by the
number of shares that could have been
purchased with the proceeds from such
exercise (at the greater of average or
ending market price) 149 57 1,895
---------- ---------- ----------
Average common shares outstanding as
adjusted 423,841 429,903 432,520
========== ========== ==========
Fully diluted EPS $ 2.99 $ 2.21 $ 2.32
========== ========== ==========
- --------------------------------------------------------------------------------------------
</TABLE>
(1) This presentation is submitted in accordance with Item 601(b)(11) of
Regulation S-K. This presentation is not required by APB Opinion No. 15,
because it results in dilution of less than 3%.
<PAGE> 1
EXHIBIT 12.1
PACIFIC GAS AND ELECTRIC COMPANY AND SUBSIDIARIES
COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES
<TABLE>
<CAPTION>
- ---------------------------------------------------------------------------------------
Year ended December 31,
----------------------------------------------------------
(dollars in thousands) 1995 1994 1993 1992 1991
- ---------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Earnings:
Net income $1,338,885 $1,007,450 $1,065,495 $1,170,581 $1,026,392
Adjustments for minority
interests in losses of
less than 100% owned
affiliates and the
undistributed losses
(income) of less than
50% owned affiliates 3,820 (2,764) 6,895 (3,349) 26,671
Income tax expense 895,289 836,767 901,890 895,126 851,534
Net fixed charges 715,975 730,965 821,166 802,198 776,682
---------- ---------- ---------- ---------- ----------
Total Earnings $2,953,969 $2,572,418 $2,795,446 $2,864,556 $2,681,279
========== ========== ========== ========== ==========
Fixed Charges:
Interest on long-
term debt $ 627,375 $ 651,912 $ 731,610 $ 739,279 $ 697,185
Interest on short-
term debt 83,024 77,295 87,819 61,182 77,760
Interest on capital
leases 2,735 1,758 1,737 1,737 1,737
Capitalized Interest 957 2,660 46,055 6,511 6,107
Earnings required to
cover the preferred
stock dividend and
preferred security
distribution requirements
of majority owned
subsidiaries 3,306 - - - -
---------- ---------- ---------- ---------- ----------
Total Fixed
Charges $ 717,397 $ 733,625 $ 867,221 $ 808,709 $ 782,789
========== ========== ========== ========== ==========
Ratios of Earnings to
Fixed Charges 4.12 3.51 3.22 3.54 3.43
- ---------------------------------------------------------------------------------------
</TABLE>
Note: For the purpose of computing the Company's ratios of earnings to fixed
charges, "earnings" represent net income adjusted for the minority
interest in losses of less than 100% owned affiliates, the Company's
equity in undistributed income or loss of less than 50% owned affiliates,
income taxes and fixed charges (excluding capitalized interest). "Fixed
charges" include interest on long-term and short-term borrowings
(including a representative portion of rental expense), amortization of
bond premium, discount and expense, interest on capital leases, pretax
earnings required to cover the preferred stock dividend requirements of
majority owned subsidiaries, and after-tax earnings required to cover the
preferred security distribution requirements of majority owned
subsidiaries.
<PAGE> 1
EXHIBIT 12.2
PACIFIC GAS AND ELECTRIC COMPANY AND SUBSIDIARIES
COMPUTATION OF RATIOS OF EARNINGS TO COMBINED FIXED CHARGES AND PREFERRED STOCK
DIVIDENDS
<TABLE>
<CAPTION>
- ---------------------------------------------------------------------------------------
Year ended December 31,
----------------------------------------------------------
(dollars in thousands) 1995 1994 1993 1992 1991
- ---------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Earnings:
Net income $1,338,885 $1,007,450 $1,065,495 $1,170,581 $1,026,392
Adjustments for minority
interests in losses of
less than 100% owned
affiliates and the
Company's equity in
undistributed losses
(income) of less than
50% owned affiliates 3,820 (2,764) 6,895 (3,349) 26,671
Income tax expense 895,289 836,767 901,890 895,126 851,534
Net fixed charges 715,975 730,965 821,166 802,198 776,682
---------- ---------- ---------- ---------- ----------
Total Earnings $2,953,969 $2,572,418 $2,795,446 $2,864,556 $2,681,279
========== ========== ========== ========== ==========
Fixed Charges:
Interest on long-
term debt $ 627,375 $ 651,912 $ 731,610 $ 739,279 $ 697,185
Interest on short-
term debt 83,024 77,295 87,819 61,182 77,760
Interest on capital
leases 2,735 1,758 1,737 1,737 1,737
Capitalized Interest 957 2,660 46,055 6,511 6,107
Earnings required to
cover the preferred stock
dividend and preferred
security distribution
requirements of majority
owned subsidiaries 3,306 - - - -
---------- ---------- ---------- ---------- ----------
Total Fixed Charges 717,397 733,625 867,221 808,709 782,789
---------- ---------- ---------- ---------- ----------
Preferred Stock Dividends:
Tax deductible dividends 11,343 4,672 4,814 5,136 5,136
Pretax earnings required
to cover non-tax
deductible preferred
stock dividend
requirements 99,984 96,039 108,937 130,147 154,404
---------- ---------- ---------- ---------- ----------
Total Preferred
Stock Dividends 111,327 100,711 113,751 135,283 159,540
---------- ---------- ---------- ---------- ----------
Total Combined Fixed
Charges and Preferred
Stock Dividends $ 828,724 $ 834,336 $ 980,972 $ 943,992 $ 942,329
========== ========== ========== ========== ==========
Ratios of Earnings to
Combined Fixed Charges and
Preferred Stock Dividends 3.56 3.08 2.85 3.03 2.85
- ---------------------------------------------------------------------------------------
</TABLE>
Note: For the purpose of computing the Company's ratios of earnings to combined
fixed charges and preferred stock dividends, "earnings" represent net
income adjusted for the minority interest in losses of less than 100%
owned affiliates, the Company's equity in undistributed income or loss of
less than 50% owned affiliates, income taxes and fixed charges (excluding
capitalized interest). "Fixed charges" include interest on long-term debt
and short-term borrowings (including a representative portion of rental
expense), amortization of bond premium, discount and expense, interest on
capital leases, pretax earnings required to cover the preferred stock
dividend requirements of majority owned subsidiaries, and the after-tax
earnings required to cover the preferred security distribution
requirements of majority owned subsidiaries. "Preferred stock dividends"
represent the sum of requirements for preferred stock dividends that are
deductible for federal income tax purposes increased to an amount
representing pretax earnings which would be required to cover such
dividend requirements.
<PAGE> 1
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation of
our report dated February 12, 1996, included in Appendix I to the Report on
Form 8-K dated February 21, 1996, into the Company's previously filed
registration statements as follows: (1) Form S-3 Registration Statement File
No. 33-7542 (relating to the Company's Common Stock Shelf Program); (2) Form
S-3 Registration Statement File No. 33-54469 (relating to the Company's
Dividend Reinvestment Plan); (3) Form S-3 Registration Statement File No.
33-64136 (relating to $2,000,000,000 aggregate principal amount of the
Company's First and Refunding Mortgage Bonds and Medium-Term Notes); (4) Form
S-3 Registration Statement File No. 33-50707 (relating to $1,500,000,000
aggregate principal amount of the Company's First and Refunding Mortgage
Bonds); (5) Form S-3 Registration Statement File No. 33-38334 (relating to
2,414,892 shares of the Company's Common Stock); (6) Form S-8 Registration
Statement File No. 33-50601 (relating to the Company's Savings Fund Plan for
Employees); (7) Form S-8 Registration Statement File No. 33-23692 (relating to
the Company's 1986 Stock Option Plan); (8) Form S-3 Registration Statement File
No. 33-62488 (relating to 10,000,000 shares of the Company's Redeemable First
Preferred Stock) and (9) Form S-3 Registration Statement File No. 33-61959
(relating to $335,000,000 aggregate liquidation value of Cumulative Quarterly
Income Preferred Securities).
/S/ ARTHUR ANDERSEN LLP
ARTHUR ANDERSEN LLP
San Francisco, California,
February 21, 1996
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