<PAGE>
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 8-K
CURRENT REPORT
Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
Date of Report: February 19, 1997
<TABLE>
<CAPTION>
Exact Name of
Commission Registrant State or other IRS Employer
File as specified Jurisdiction of Identification
Number in its charter Incorporation Number
- ---------------------------------------------------------------
<S> <C> <C> <C>
1-12609 PG&E Corporation California 94-3234914
1-2348 Pacific Gas and California 94-0742640
Electric Company
</TABLE>
77 Beale Street, P.O. Box 770000, San Francisco, California 94177
(Address of principal executive offices) (Zip Code)
Registrants' telephone number, including area code:(415) 973-7000
<PAGE>
Item 7. Financial Statements, Pro Forma Financial Information
And Exhibits
1996 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 PG&E Corporation and subsidiaries as of December
31, 1996 and 1995, and the related statements of consolidated income, cash
flows, common stock equity, preferred stock, and preferred securities, and
segment information, for each of the three years in the period ended December
31, 1996, and related notes to consolidated financial statements, and
supplementary financial information, and (iv) the report dated February 10,
1997, of Arthur Andersen LLP, independent public accountants, with respect to
the consolidated financial statements and schedule of consolidated segment
information.
Exhibits:
23 Consent of Arthur Andersen LLP
27 Financial Data Schedule
1
<PAGE>
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrants have duly caused this report to be signed on their behalf by the
undersigned thereunto duly authorized.
PG&E CORPORATION
and
PACIFIC GAS AND ELECTRIC COMPANY
By CHRISTOPHER P. JOHNS
________________________________
CHRISTOPHER P. JOHNS
Controller
Dated: February 19, 1997
2
<PAGE>
Appendix I
PG&E Corporation
Selected Financial Data
<TABLE>
<CAPTION>
(in thousands, except per share amounts) 1996 1995 1994 1993 1992
------------- ------------- ------------- ------------- -------------
<S> <C> <C> <C> <C> <C>
For the Year
Operating revenues $ 9,609,972 $ 9,621,765 $10,350,230 $10,550,002 $10,315,713
Operating income 1,895,585 2,762,985 2,423,786 2,560,235 2,699,824
Net income 755,209 1,338,885 1,007,450 1,065,495 1,170,581
Earnings per common share 1.75 2.99 2.21 2.33 2.58
Dividends declared per common share 1.77 1.96 1.96 1.88 1.76
At Year End
Book value per common share $ 20.73 $ 20.77 $ 20.07 $ 19.77 $ 19.41
Common stock price per share 21.00 28.38 24.38 35.13 33.13
Total assets 26,129,925 26,850,290 27,708,564 27,145,899 24,188,159
Long-term debt and preferred
stock and securities with mandatory
redemption provisions (excluding
current portions) 8,207,567 8,486,046 8,812,591 9,367,100 8,525,948
</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 the Consolidated Financial Statements.
8
<PAGE>
PG&E Corporation
Management's Discussion and Analysis of
Consolidated Results of Operations and Financial Condition
Effective January 1, 1997, Pacific Gas and Electric Company (PG&E) became a
subsidiary of its new parent holding company, PG&E Corporation. PG&E's ownership
interest in Pacific Gas Transmission Company (PGT) and PG&E Enterprises
(Enterprises) was transferred to PG&E Corporation. PG&E's outstanding common
stock was converted on a share-for-share basis into PG&E Corporation common
stock. PG&E's debt securities and preferred stock were unaffected and remain
securities of PG&E.
This holding company structure is intended to improve PG&E Corporation's
ability to respond to new business opportunities and changes in the utility
industry. It will enhance the financial separation of the California utility
business from PG&E Corporation's other businesses and will provide greater
financing flexibility.
The consolidated financial statements in this annual report include the
accounts of PG&E and its wholly-owned and controlled subsidiaries (collectively,
the Company) and, therefore, also represent the accounts of PG&E Corporation and
its subsidiaries. PG&E provides generation, procurement, transmission, and
distribution of electricity and natural gas to customers throughout most of
Northern and Central California. PG&E is regulated by the California Public
Utilities Commission (CPUC), the Federal Energy Regulatory Commission (FERC),
and the Nuclear Regulatory Commission, among others.
PGT and Enterprises, previously wholly-owned by PG&E, are now wholly-owned
subsidiaries of PG&E Corporation. Through these subsidiaries, the Company is
expanding its presence in the "midstream" portion of the gas business, the
independent power generation business, and the energy services business.
The midstream portion of the gas business includes gas gathering, processing,
storage, and transportation. The energy services business includes obtaining gas
and electricity from competitive producers, arranging for distribution and
transmission service, and providing customized energy billing and analysis,
power quality assessments, energy efficiency products and services, and facility
improvements.
PGT transports gas from the Canadian border to the California border and the
Pacific Northwest and is regulated by the FERC. In 1996, PGT acquired PGT
Queensland Gas Pipeline in Australia and Energy Source, the North American gas
operations of Edisto Resources Corporation. In January 1997, PG&E Corporation
acquired Teco Pipeline Company (Teco) in Texas. Teco owns a natural gas pipeline
system in Texas, investments in gas gathering and processing facilities, and a
gas marketing company in Houston. Also in January 1997, PG&E Corporation agreed
to acquire Valero Natural Gas Company (Valero) (see Acquisitions and Sales
below).
Enterprises, through its subsidiaries and affiliates, develops, owns, and
operates unregulated electric and gas projects in the U.S. and around the world.
Vantus Energy Corporation (Vantus), a subsidiary of Enterprises, markets gas and
electricity commodities and provides energy services.
The following discussion of consolidated results of operations and financial
condition includes forward-looking statements that involve risks and
uncertainties. Words such as "estimates," "expects," "anticipates," "plans," and
similar expressions identify forward-looking statements involving risks and
uncertainties.
These risks and uncertainties include but are not limited to the ongoing
restructuring of the electric and gas industries and the outcome of regulatory
proceedings related to that restructuring. The ultimate impacts of both
increased competition and the changing regulatory environment on future results
are uncertain, but both are expected to fundamentally change how the Company
conducts its business. The outcome of these changes 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: The electric and gas industries
are undergoing significant change. Under traditional regulation, utilities were
provided the opportunity to earn a fair return on their invested capital in
exchange for a commitment to serve all customers within a designated service
territory. The objective of this regulatory policy was to provide universal
access to safe and reliable utility services. Regulation was designed in part to
take the place of competition and ensure that these services were provided at
fair prices.
Today, competitive pressures and emerging market forces are exerting an
increasing influence over the structure of the gas and electric industries.
Other companies are challenging the utilities' exclusive relationship with
customers and are seeking to replace certain utility functions with their own.
Customers, too, are asking for choice in their energy provider.
9
<PAGE>
PG&E Corporation
Management's Discussion and Analysis of
Consolidated Results of Operations and Financial Condition
These pressures are causing a move from the existing regulatory framework to a
framework under which competition would be allowed in certain segments of the
gas and electric industries.
For several years, PG&E has been working with its regulators to achieve an
orderly transition to competition and to ensure that PG&E has an opportunity to
recover investments made under the traditional regulatory policies. In addition,
PG&E has proposed alternative forms of regulation for those services for which
prices and terms will not be determined by competition. These alternative forms
include performance-based ratemaking (PBR) and other incentive-based
alternatives. Over the next five years, a significant portion of PG&E's business
will be transformed from the current utility monopoly to a competitive
operation. This change will impact PG&E's financial results and may result in
greater earnings volatility. During the transition period, PG&E expects the
return on Diablo Canyon Nuclear Power Plant (Diablo Canyon) and certain other
generation assets to be significantly lower than historical levels.
Electric Industry Restructuring: In 1995, the CPUC issued a decision that
provides a plan to restructure California's electric utility industry. The
decision acknowledges that much of utilities' current costs and commitments
result from past CPUC decisions and that, in a competitive generation market,
utilities would not recover some of these costs through market-based revenues.
To assure the continued financial integrity of California utilities, the CPUC
authorized recovery of these above-market costs, called "transition costs."
In 1996, California legislation was passed that adopts the basic tenets of
the CPUC's restructuring decision, including recovery of transition costs. In
addition, the legislation provides a 10 percent rate reduction for residential
and small commercial customers by January 1, 1998, freezes electric customer
rates for all other customers, and requires the accelerated recovery of
transition costs associated with owned generation facilities. The legislation
also establishes the operating framework for a competitive generation market.
The rate freeze will continue until the earlier of March 31, 2002, or until
PG&E has recovered its transition costs (the transition period). The freeze will
hold rates at 1996 levels for all customers except those receiving the 10
percent rate reduction. The rate freeze will hold the rates for these customers
at the reduced level.
To achieve the 10 percent rate reduction, the legislation authorizes
utilities to finance a portion of their transition costs with "rate reduction
bonds." The maturity period of the bonds is expected to extend beyond the
transition period. Also, the interest cost of the bonds is expected to be lower
than PG&E's current cost of capital. Once this portion of transition costs is
financed, PG&E would collect a separate tariff to recover principal, interest,
and issuance costs over the life of the bonds from residential and small
commercial customers. The combination of the longer maturity period and the
reduced interest costs will lower the amounts paid by these customers each year
during the transition period thereby achieving the 10 percent reduction in
rates.
During 1997, differences between authorized and actual base revenues and
differences between the actual cost of electric generation and the revenue
designated for recovery of such revenues or costs will be recorded in balancing
accounts. Any residual balance will be available for transition cost recovery.
During 1997, amounts recorded in balancing accounts will be subject to a
reasonableness review by the CPUC.
Absent the rate freeze, PG&E's rates would be expected to decline under
existing cost-based ratemaking methodologies. The most significant reasons for
the decrease in cost-based rates are the declining cost of power committed under
certain purchased power contracts, the reduction in the Diablo Canyon price for
power under the existing CPUC-approved settlement, and the decline in
uncollected electric balancing accounts.
Transition Cost Recovery: The legislation authorizes the CPUC to determine the
costs eligible for recovery as transition costs. The amount of costs will be
based on the aggregate of above-market and below-market values of utility-owned
generation assets and obligations. PG&E has proposed that costs eligible for
transition cost recovery include: (1) above-market sunk costs (costs associated
with utility generating facilities that are fixed and unavoidable and currently
collected through rates) and future costs, such as costs related to plant
removal, (2) above-market costs associated with purchase power obligations with
Qualifying Facilities (QFs) and other Power Purchase Agreements, and (3)
generation-related regulatory assets and obligations. PG&E cannot determine the
exact amount of sunk
10
<PAGE>
costs that will be above market and recoverable as transition costs until a
market valuation process (appraisal or sale) is completed for each generation
facility. This process will be completed during the transition period.
In compliance with the CPUC's restructuring decision and the restructuring
legislation, PG&E has filed numerous regulatory applications and proposals that
detail its transition cost recovery plan. PG&E's recovery plan includes: (1)
separation or unbundling of its previously approved cost-of-service revenue
requirement for its electric operations into distribution, transmission, public
purpose programs (PPPs), and generation, (2) accelerated recovery of transition
costs, and (3) development of a ratemaking mechanism to track and match revenues
and cost recovery during the transition period.
The unbundling of PG&E's revenue requirement enables it to separate revenue
provided by frozen rates into transmission, distribution, PPPs, and generation.
As proposed, revenues collected under frozen rates would be assigned to
transmission, distribution, and PPPs based upon their respective cost of
service. Revenue would also be provided for other costs, including nuclear
decommissioning, rate-reduction-bond debt service, the on-going cost of
generation, and transition cost recovery. The combination of a rate freeze and
decreasing costs, based upon existing ratemaking and cost recovery periods,
provides an adequate amount of revenue available for full transition cost
recovery.
PG&E has proposed to accelerate recovery for certain transition costs related
to generation facilities, including Diablo Canyon. Additionally, PG&E would
receive a reduced return on common equity associated with generation plant
assets for which recovery is accelerated. The lower return reflects the reduced
risk associated with the shorter amortization period and increased certainty of
recovery.
In applying its cost recovery plan to Diablo Canyon, PG&E has proposed to
replace the existing settlement prices with: (1) a sunk cost revenue requirement
to recover fixed costs, including a return on these costs, and (2) a PBR
mechanism to recover the facility's variable costs and capital addition costs.
As proposed, the sunk cost revenue requirement would accelerate recovery of
Diablo Canyon sunk costs from a twenty-year period ending in 2016 to a five-year
period beginning in 1997 and ending in 2001. The related return on common equity
associated with Diablo Canyon sunk costs would be reduced to 90 percent of
PG&E's long-term cost of debt. PG&E's authorized long-term cost of debt was 7.52
percent in 1996. The reduced rate of return combined with a shorter recovery
period would result in an estimated $4 billion decrease in the net present value
of PG&E's future revenues from Diablo Canyon operations. If the proposed cost
recovery plan for Diablo Canyon were adopted during 1996, Diablo Canyon's 1996
reported net income would have been reduced by $350 million ($0.85 per share).
Most transition costs must be recovered by March 1, 2002. However, the
legislation authorizes recovery of certain transition costs after that time.
These costs include: (1) certain employee-related transition costs, (2) payments
under existing QF and power purchase contracts, and (3) unrecovered
implementation costs. Excluding these exceptions, any transition costs not
recovered during the transition period will be absorbed by PG&E. Nuclear
decommissioning costs, which are not considered transition costs, will be
recovered through a CPUC authorized charge. During the transition period, this
charge will be incorporated into the frozen rates. After the transition period,
customers will be assessed a surcharge until the nuclear decommissioning costs
are fully recovered.
PG&E's ability to recover its transition costs during the transition period
will be dependent on several factors. These factors include: (1) the extent to
which application of the current regulatory framework established by the
restructuring legislation will continue to be applied, (2) the amount of
transition costs approved by the CPUC, (3) the market value of PG&E's generation
plants, (4) future sales levels, (5) fuel and operating costs, (6) the market
price of electricity, and (7) the ratemaking methodology adopted for Diablo
Canyon. Considering its current evaluation of these factors, PG&E believes it
will recover its transition costs and that its owned generation plants are not
impaired. However, a change in these factors could affect the probability of
recovery of transition costs and result in a material loss.
PG&E has proposed to implement portions of its transition cost recovery plan
in 1997. The CPUC decision on PG&E's 1997 Energy Cost Adjustment Clause (ECAC)
application would decrease PG&E's 1997 revenue requirement by $720 million. This
decrease would be partially offset by a $160 million revenue requirement
increase, provided by the legislation, for purposes of enhancing transmission
and distribution system
11
<PAGE>
PG&E Corporation
Management's Discussion and Analysis of
Consolidated Results of Operations and Financial Condition
safety and reliability. This increase was approved by the CPUC as part of PG&E's
transition cost recovery plan.
Given the electric customer rate freeze, the $560 million net revenue
requirement decrease resulting from the consolidation of the ECAC decision and
the revenue requirement increase contemplated in the cost recovery plan would be
available for transition cost recovery. The proposed accelerated recovery of
Diablo Canyon would absorb an estimated $400 million of this available revenue
requirement. The remaining revenue requirement would be available to recover
other transition costs.
Competitive Market Framework: In addition to transition cost recovery, the
legislation establishes the operating framework for the competitive generation
market in California. This framework will consist of a power exchange (PX) and
an independent system operator (ISO). The PX, open to all electricity providers,
will conduct a competitive auction to establish the price of electricity. The
ISO will ensure system reliability and provide all electricity generators with
open and comparable access to transmission and distribution services.
Although the PX will be available to all customers, the legislation allows
customers to bypass the PX by entering into direct access contracts with other
electricity providers, subject to a nonbypassable transition charge. This direct
access will be available to certain customers by January 1, 1998, and will be
phased in for all remaining customers through December 31, 2001. During the
transition period, PG&E will bill direct access customers based upon fully
bundled frozen rates. Direct access customers' bills from PG&E would then be
reduced by an amount based on the PX price and the customers' electric usage.
These customers can be billed for their usage directly by their chosen supplier,
or the supplier may contract with PG&E to perform this billing. During the
transition period, these customers' overall electric rates will vary only to the
extent that their direct access contract price differs from the PX price.
To prevent undue influence on the PX price by any participant in the
competitive framework, PG&E has indicated it is willing to proceed with
divestiture of at least 50 percent of its fossil-fueled power plants as directed
by the CPUC. PG&E has filed an application seeking approval from the CPUC to
sell four plants before the end of 1997. The book value for these plants is
approximately $400 million, and together they generate approximately 10 percent
of PG&E's total electric sales. PG&E proposes to recover any shortfall in
proceeds from divestiture of these plants as a transition cost. Accordingly, the
Company does not expect any adverse impact on its results of operations from the
sale of these plants.
In addition to the CPUC's electric industry restructuring discussed above,
the FERC has required utilities to provide wholesale open access to electric
transmission systems on terms that are comparable to the way utilities use their
own systems. PG&E's open access tariff, filed in July 1996, provides access to
any eligible party interested in wholesale transmission service over PG&E's
transmission system. The FERC also reaffirmed its intention to permit utilities
to recover any legitimate, verifiable, and prudently incurred costs stranded as
a result of customers taking advantage of wholesale open access orders to meet
their power needs from other sources. Further, the FERC asserted that it has
jurisdiction over the transmission component of retail direct access.
By developing the PX and the ISO and by implementing direct access to
generation and open access to transmission, regulators have established the
operating framework of the competitive generation and wholesale transmission
markets. Although this framework will fundamentally change the way PG&E does
business, the Company does not believe that the changes will have a material
adverse impact on its ability to recover transition costs.
Accounting for the Effects of Regulation: PG&E accounts for the financial
effects of regulation in accordance with Statement of Financial Accounting
Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of
Regulation." This statement allows the Company to record certain regulatory
assets and liabilities that would not be recorded under generally accepted
accounting principles for nonregulated entities. In addition, SFAS No. 121,
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to
Be Disposed Of," requires that regulatory assets be written off when they are no
longer probable of recovery and that impairment losses be recorded for
long-lived assets when related future cash flows are less than the carrying
value of the asset.
As a result of applying the provisions of SFAS No. 71, PG&E has accumulated
approximately $1.6 billion of regulatory assets attributable to electric
generation at December 31, 1996.
12
<PAGE>
The net investments in Diablo Canyon and the other generation assets were
$4.5 billion and $2.7 billion, respectively, at December 31, 1996. The net
present value of above-market QF power purchase obligations is estimated to be
$5.3 billion at January 1, 1998, at an assumed PX price of $0.025 per
kilowatt-hour (kWh) beginning in 1997 and escalating at 3.2 percent per year.
PG&E believes that the restructuring legislation establishes a definitive
transition to market-based pricing for electric generation. Incorporating the
effects of the PX and direct access, this transition includes cost-of-service
based ratemaking. In addition, PG&E's generation-related transition costs will
be collected through a nonbypassable charge. Based on this structure, PG&E
believes it will continue to meet the requirements of SFAS No. 71 throughout the
transition period.
At the conclusion of the transition period, PG&E believes it will be at risk
to recover its generation costs through market-based revenues. At that time,
PG&E expects to discontinue the application of SFAS No. 71 for the electric
generation portion of its business. Since PG&E anticipates it will have
recovered all transition costs required to be recovered during the transition
period, including generation-related regulatory assets and above-market
investments in net plant, PG&E does not expect a material adverse impact on its
financial position or results of operations from discontinuing the application
at that time.
As a result of the CPUC's restructuring decision and California's electric
industry restructuring legislation, the Securities and Exchange Commission (SEC)
has begun inquiries regarding the appropriateness of the continued application
of SFAS No. 71 by California utilities to their electric generation businesses.
As discussed above, PG&E believes it currently meets and will continue to meet
the requirements to apply SFAS No. 71 during the transition period. In the event
that the SEC concludes that the current regulatory and legal framework in
California no longer meets the requirements to apply SFAS No. 71 to the
generation business, the Company would reevaluate the financial impact of
electric industry restructuring and a material write-off could occur.
Given the current regulatory environment, PG&E's electric transmission and
distribution businesses are expected to remain regulated and, as a result, will
continue application of the provisions of SFAS No. 71.
Gas Industry Restructuring: Restructuring of the natural gas industry on both
the national and the state level has given customers greater options in meeting
their gas supply needs. PG&E's customers may buy commodity gas directly from
competing suppliers and purchase transmission- and distribution-only services
from PG&E. Transmission and distribution services have remained "bundled," or
sold together at a combined rate, within the state. PGT, as an interstate
pipeline, has provided nondiscriminatory transmission-only service since 1993
and no longer sells commodity gas.
Most of PG&E's industrial and larger commercial (noncore) customers purchase
their commodity gas from marketers and brokers. Substantially all residential
and smaller commercial (core) customers continue to buy commodity gas as well as
transmission and distribution from PG&E as a bundled service.
In 1995 and 1996, PG&E actively pursued changes in the California gas
industry in an effort to promote competition and increase options for all
customers, as well as to position itself for the competitive marketplace. In
1996, PG&E submitted to the CPUC the Gas Accord Settlement (Accord). The Accord
is the result of an extensive negotiation process, begun in 1995, among a broad
coalition of customer groups and industry participants. The Accord must be
approved by the CPUC before it can be implemented. A CPUC decision is expected
in 1997.
The Accord consists of three broad initiatives:
(1) The Accord would separate, or "unbundle," PG&E's gas transmission and
storage services from its distribution services and would change the terms of
service and rate structure for gas transportation. Unbundling would give
customers the opportunity to select from a menu of services offered by PG&E and
would enable them to pay only for the services they use. PG&E would be at risk
for variations in revenues resulting from differences between actual and
forecasted transmission throughput. PG&E would also continue to provide cost-of-
service based distribution service, much as it does today.
(2) The Accord would increase opportunities for PG&E's core customers to
purchase gas from competing suppliers and, therefore, could reduce PG&E's role
in procuring gas for such customers. However, PG&E would continue to procure gas
as a regulated utility supplier for those customers who request it. The Accord
also would establish principles for continuing negotiations between PG&E and
California gas producers for
13
<PAGE>
PG&E Corporation
Management's Discussion and Analysis of
Consolidated Results of Operations and Financial Condition
the mutual release of supply contracts and the sale of gas gathering facilities.
Also related to PG&E's procurement activities, PG&E has proposed that
traditional reasonableness reviews of its core gas costs be replaced with a core
procurement incentive mechanism (CPIM) for the period June 1, 1994, through
2002. Under the CPIM, PG&E would be able to recover its gas commodity and
interstate transportation costs and would receive benefits or be penalized
depending on whether its actual core procurement costs were within, below, or
above a "tolerance band" constructed around market benchmarks. Actual core
procurement costs measured for the period June 1, 1994, through December 31,
1996, have generally been within the CPIM "tolerance band." The CPIM proposal
also requests authorization to use derivative financial instruments to reduce
the risk of gas price and foreign currency fluctuations. Gains, losses, and
transaction costs associated with the use of derivative financial instruments
would be included in the purchased gas account and the measurement against the
benchmarks.
(3) The Accord would resolve various regulatory issues (see further
discussion in Note 3 to the Consolidated Financial Statements) including:
. the disallowances ordered by the CPUC in connection with PG&E's 1988 through
1995 gas reasonableness proceedings;
. the recovery of certain capital costs associated with the PG&E portion of the
PGT/PG&E Pipeline Expansion;
. the recovery of costs related to PG&E's capacity commitments with
Transwestern Pipeline Company through 2002; and
. the recovery, through PG&E's interstate transition cost surcharge, of fixed
demand charges paid to El Paso Natural Gas Company and PGT for firm capacity
held by PG&E on behalf of its customers.
As of December 31, 1996, PG&E has reserved approximately $527 million,
including $182 million reserved during 1996, relating to its gas regulatory
issues and gas capacity commitments, the majority of which are addressed by the
Accord. PG&E believes the ultimate resolution of these matters, whether through
approval of the Accord or otherwise, will not have a material adverse impact on
its financial position or future results of operations.
Acquisitions and Sales: The Company has developed strategies to focus on the
unregulated independent power generation market, the unregulated energy services
market, and the regulated and unregulated "midstream" portions of the gas
market. As a result of this focus, the Company has been acquiring related
businesses and disposing of unrelated businesses.
Enterprises participates in multiple domestic and international energy
businesses. The majority of Enterprises' domestic investments are in
nonregulated energy projects through U.S. Generating Company (USGen), a joint
venture with Bechtel Enterprises, Inc. (Bechtel). USGen and its affiliates
develop, own, and operate power plants in the United States.
Enterprises' entry into the international market was also made in partnership
with Bechtel. Enterprises and Bechtel formed International Generating Company,
Ltd., (InterGen) which develops, owns, and operates international electric
generation projects. However, in November 1996, Enterprises and Bechtel reached
an agreement for Bechtel to acquire Enterprises' interest in InterGen. The
Company expects to complete the sale in the first quarter of 1997 and realize an
after-tax gain. Enterprises has refined its international strategy to focus on
select countries and to concentrate on end-use energy customers.
In 1995, Enterprises formed Vantus, a retail energy services provider, to
assist customers in locating the most cost-effective electric and gas products
and services. Vantus' energy services include power marketing for industrial and
large commercial businesses nationwide. In 1996, Vantus opened new offices in
the western United States to establish a presence and market its services in
emerging energy markets.
Also in 1995, Enterprises sold DALEN Corporation (DALEN). 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.
14
<PAGE>
The Company is pursuing gas-related opportunities as the gas industry
continues to evolve. In July 1996, the Company, through its subsidiary PGT,
purchased PGT Queensland State Gas Pipeline, a 389-mile natural gas
transportation system in the Australian state of Queensland. The final purchase
price was $136 million.
In December 1996, PGT entered the unregulated gas marketing arena with the
purchase of Energy Source (ESI), the North American gas marketing operations of
Edisto Resources Corporation for approximately $23 million. The purchase
included most of ESI's existing contracts for the purchase, sale, and
transportation of natural gas and natural gas futures. In 1996, ESI generated
over $1.1 billion in gas marketing revenues, of which $283 million was earned in
December 1996.
In January 1997, PG&E Corporation acquired Teco and its subsidiaries for
approximately $380 million. Teco is an owner of a 500-mile natural gas pipeline
system in Texas. Teco also has investments in gas gathering and processing
facilities and owns a gas marketing company in Houston.
Also in January 1997, PG&E Corporation agreed to acquire Valero. Valero's
operations include the gathering, transportation, marketing, and storage of
natural gas, the processing, transportation, and marketing of natural gas
liquids, and the marketing of electric power. Valero operates approximately
7,500 miles of natural gas pipeline and also owns and operates 536 miles of
natural gas liquid pipeline and eight natural gas processing plants in Texas.
PG&E Corporation will acquire Valero for approximately $1.5 billion, comprised
of approximately $720 million in PG&E Corporation common stock and the
assumption of debt and liabilities. The acquisition is expected to be completed
by mid-1997 and is subject to applicable regulatory and shareholder approvals.
All of the above acquisitions have been or will be accounted for using the
purchase method of accounting.
Results of Operations: The Company's results of operations were derived from
three business lines: utility (excluding Diablo Canyon and including PGT's gas
pipeline operations), Diablo Canyon, and diversified operations (principally,
Enterprises and ESI). The results of operations and total assets for 1996, 1995,
and 1994 are reflected in the following table and discussed below:
<TABLE>
<CAPTION>
Diablo Diversified
Utility Canyon/(1)/ Operations Total
---------- ------------ ----------- ----------
(in millions, except per share
amounts)
<S> <C> <C> <C> <C>
1996
Operating revenues $ 7,411 $1,789 $ 410 $ 9,610
Operating expenses 6,465 791 458 7,714
------- ------ ------ -------
Operating income (loss)
before income taxes $ 946 $ 998 $ (48) $ 1,896
======= ====== ====== =======
Net income (loss) $ 292 $ 497 $(34)/(2)/ $ 755
======= ====== ====== =======
Earnings per
common share $ .65 $ 1.18 $(.08) $ 1.75
======= ====== ====== =======
Total assets at year end $19,283 $5,413 $1,434 $26,130
======= ====== ====== =======
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
======= ====== ====== =======
</TABLE>
/(1)/ See Note 4 to the Consolidated Financial Statements for discussion
of allocations.
/(2)/ Includes non-operating income resulting from property sales, partnership
earnings, and investment income.
Earnings Per Common Share: Earnings per common share were $1.75, $2.99, and
$2.21 for 1996, 1995, and 1994, respectively. Utility earnings in 1996 were
lower than 1995, reflecting revenue reductions ordered in the 1996 General Rate
Case (GRC) and other related rate proceedings and reflecting several one-time
charges. The revenue reductions resulted from a lower cost of capital, lower
capital expenditures, and reductions in authorized expense levels. Actual
maintenance and other operating expenses for distribution
15
<PAGE>
PG&E Corporation
Management's Discussion and Analysis of
Consolidated Results of Operations and Financial Condition
and customer-related services increased in 1996 and exceeded levels authorized
in the 1996 GRC. These increases were primarily attributable to several projects
related to transmission and distribution system reliability, and improved
customer-related services. Additionally, PG&E recorded a charge of $.26 per
common share for contingencies related to gas transportation commitments and
recorded a charge of $.19 per common share for settlement of litigation. (See
Operating Expenses below and Notes 3 and 13 to the Consolidated Financial
Statements.) Finally, the Company recorded a charge of $.09 per common share for
write-downs of nonregulated investments.
Earnings per common share for 1995 were higher than 1994 due to fewer
one-time charges against earnings than in 1994 (see Operating Expenses below).
In addition, there were fewer scheduled refueling outages at Diablo Canyon in
1995, compared with 1994.
On a consolidated basis, the Company earned 8.5, 14.6, and 11.1 percent
returns on average common stock equity for the years ended December 31, 1996,
1995, and 1994, respectively. PG&E has received a CPUC decision which
authorizes, for 1997, a return on common equity of 11.6 percent and an overall
rate of return of 9.45 percent. However, PG&E has filed a proposal with the CPUC
to accelerate recovery of certain transition costs related to generation
facilities, including Diablo Canyon. Additionally, PG&E would receive a reduced
return on common equity associated with generation plant assets for which
recovery is accelerated. This return would equal 90 percent of PG&E's long-term
cost of debt. PG&E's authorized long-term cost of debt was 7.52 percent in 1996.
(See Electric Industry Restructuring above.)
Common Stock Dividend: The Company's common stock dividend is based on a number
of financial considerations, including sustainability, financial flexibility,
and competitiveness with investment opportunities of similar risk. The Company's
current quarterly common stock dividend is $.30 per common share which
corresponds to an annualized dividend of $1.20 per common share. This represents
a decrease from the previous annualized dividend of $1.96 per common share. The
Company has identified a dividend payout ratio objective (dividends declared
divided by earnings available for common stock) of between 50 and 65 percent
(based on earnings exclusive of nonrecurring adjustments).
Operating Revenues: Operating revenues in 1996 decreased slightly from 1995. The
decreases in utility revenues as ordered in the 1996 GRC, discussed above, and
in Diablo Canyon revenues were offset by increased revenues from diversified
operations. Revenues from Diablo Canyon decreased due to a decline in the
generation price, as provided in the Diablo Canyon rate case settlement as
modified in 1995 (Diablo Settlement) (see Note 4 to the Consolidated Financial
Statements). This decline was partially offset by higher net generation, which
was a result of fewer scheduled refuelings in 1996 compared to 1995. Revenues
from diversified operations increased primarily due to the purchase of ESI in
December 1996. This purchase created $283 million of revenue but was partially
offset by a decline in revenue due to the sale of DALEN in 1995. (See
Acquisitions and Sales above.)
Operating revenues for 1995 decreased $728 million from 1994. The decrease in
utility revenues was primarily due to a decrease in electric energy costs caused
by favorable hydroelectric conditions and lower natural gas prices. Diablo
Canyon operating revenues decreased due to a decrease in the generation price as
provided in the modified Diablo Settlement (see Note 4 to the Consolidated
Financial Statements for further discussion). This decrease was partially offset
by favorable operating revenues from Diablo Canyon resulting from fewer
refueling days in 1995. Revenues from diversified operations decreased $72
million in 1995 compared to 1994 primarily due to the sale of DALEN in June
1995.
Operating Expenses: Operating expenses increased $855 million in 1996 compared
to 1995, primarily due to: (1) a charge of $182 million for contingencies
related to gas transportation commitments, (2) increases in the cost of gas due
to price increases, (3) increases in purchased power prices and volumes, (4)
increases in maintenance and other operating expenses for transmission and
distribution system reliability and for improved customer-related services, (5)
increases in litigation costs, and (6) an increase in the cost of gas for resale
due to the purchase of ESI in December 1996. The cost of gas increase from the
purchase of ESI was offset by revenues as discussed above.
Operating expenses decreased $1,067 million in 1995 compared to 1994
primarily due to decreased electric costs caused by favorable hydroelectric
conditions, decreased natural gas
16
<PAGE>
prices, and no workforce reduction charges in 1995. (See Note 10 to the
Consolidated Financial Statements.)
Other Income and (Expense): Other income and expense changed in 1996 compared to
1995 primarily due to write-downs of certain nonregulated investments.
Liquidity and Capital Resources:
The Company's capital requirements are funded from cash provided from 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. Based
on cash provided from operations and its capital requirements, the Company may
repurchase equity and long-term debt in order to manage the overall balance of
its capital structure.
Debt: In 1996, 1995, and 1994, the Company redeemed or repurchased $1,113, $758,
and $202 million, respectively, of long-term debt to manage the overall balance
of the Company's capital structure. Long-term debt maturing during 1996, 1995,
and 1994 was not refinanced.
Included in the 1996 repurchases is $988 million of variable and fixed
interest rate pollution control mortgage bonds and loan agreements which were
replaced with variable interest rate pollution control loan agreements. Also in
1996, the Company entered into additional loan agreements of $92 million to
finance the PGT acquisition of PGT Queensland State Gas Pipeline. In addition,
the Company used its cash balances to reduce short-term borrowings by $115
million in 1996.
In 1995, PGT issued $400 million of bonds and $70 million of medium-term
notes. In addition, PGT issued commercial paper which is classified as long-term
debt. This classification is based upon the availability of committed credit
facilities expiring in 2000 and management's intent to maintain such amounts in
excess of one year. The commercial paper outstanding was $108 and $109 million
at December 31, 1996, and 1995, respectively. Substantially all of the proceeds
of PGT's debt issued in 1995 were used to refinance outstanding debt.
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, 1996, and 1995,
PG&E had $681 and $796 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 can also be used for general corporate purposes. There were no
borrowings under this facility in 1996, 1995, or 1994.
In January 1997, PG&E Corporation established a $500 million revolving credit
facility in order to provide for corporate short-term liquidity needs and other
purposes.
As discussed in electric industry restructuring above, to achieve the 10
percent rate reduction for residential and small commercial customers, the
electric industry restructuring legislation authorizes utilities to finance a
portion of the transition costs with "rate reduction bonds." PG&E expects to
work with state authorities to coordinate the issuance of up to $2.5 billion of
these bonds by a special purpose entity. Once issued, PG&E would collect, on
behalf of the special purpose entity, a separate tariff to recover principal,
interest, and issuance costs over the life of the bonds from residential and
small commercial customers. PG&E does not expect to secure the bonds with the
Company's assets or unrelated future revenues.
Equity: In 1996, 1995, and 1994, PG&E received $220, $140, 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.
Since 1993, the Board has authorized the Company to repurchase up to $2
billion of its common stock on the open market or in negotiated transactions.
These repurchases are funded by internally generated funds and are used to
manage the overall balance of common stock in the Company's capital structure.
Through December 31, 1996, the Company had repurchased approximately $1.5
billion of its common stock under this program. Repurchases for 1996, 1995, and
1994 were $455, $601, and $182 million, respectively.
In 1996, PG&E did not redeem or repurchase any preferred stock. In 1995 and
1994, PG&E redeemed or repurchased $331 and $75 million, respectively, of its
higher-cost preferred stock. In 1994, PG&E issued $62 million of preferred
stock.
PG&E is limited as to the amount of dividends that it may pay to PG&E
Corporation based on PG&E's regulatory capital
17
<PAGE>
PG&E Corporation
Management's Discussion and Analysis of
Consolidated Results of Operations and Financial Condition
structure authorized by the CPUC. PG&E's equity shall be retained such that, on
average, the capital structure authorized by the CPUC is maintained. This
restriction is not expected to affect PG&E Corporation's ability to meet its
cash obligations.
Other Capital: In 1995, PG&E through its wholly-owned subsidiary, PG&E Capital
I, issued $300 million of cumulative quarterly income preferred securities. Net
proceeds were used to redeem and repurchase higher-cost preferred stock.
Investing Activities: The Company's estimated capital requirements for the next
three years are shown below:
<TABLE>
<CAPTION>
Year ended December 31, 1997 1998 1999
--------- --------- ---------
(in millions)
<S> <C> <C> <C>
Utility (including PGT) $1,773 $1,825 $1,705
Diablo Canyon 38 39 41
Diversified operations 211 80 172
--------- --------- ---------
Total capital expenditures 2,022 1,944 1,918
Maturing debt and sinking funds 210 660 270
--------- --------- ---------
Total capital requirements $2,232 $2,604 $2,188
========= ========= =========
</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.
Expenditures for diversified operations (consisting primarily of Enterprises)
include capital contributions for Enterprises' equity share of generating
facility projects. Ongoing capital expenditures for Teco are included in
diversified operations in the above estimated capital requirements.
In addition to the above, the Company, in January 1997, has acquired Teco for
approximately $380 million, consisting of a note payable of $61 million and $319
million of PG&E Corporation's common stock. Further, the Company, in January
1997, agreed to acquire Valero for approximately $1.5 billion, consisting of
approximately $720 million of PG&E Corporation's common stock and the assumption
of debt and liabilities. The Company has other commitments as discussed in Notes
3 and 12 to the Consolidated Financial Statements.
In December 1995, the Company had a balance of $734 million of cash and cash
equivalents due to the sale of DALEN and the retention of cash for potential
investments.
Risk Management: Due to the changing business environment, the Company's
exposure to risks associated with changes in energy commodity prices, interest
rates, and foreign currencies is increasing. To manage these risks, the Company
has adopted a price risk management policy and established an officer-level
price risk management committee. The Company's price risk management committee
oversees implementation of the policy, approves each price risk management
program, and monitors compliance with the policy.
The Company's price risk management policy and procedures adopted by the
committee establish guidelines for implementation of price risk management
programs. Such programs may include the use of energy and financial derivatives.
(A derivative is a contract whose value is dependent on or derived from the
value of some underlying asset.) Additionally, the Company's policy allows
derivatives to be used for hedging and non-hedging purposes. (Hedging is the
process of protecting one transaction by means of another to reduce price risk.)
Both hedging and non-hedging activities are limited to those specifically
approved by the committee only after appropriate controls and procedures are put
in place to measure, monitor, and control the risk of such activities. The
Company's policy prohibits the use of derivatives whose payment formula includes
a multiple of some underlying asset.
In 1996, the Company approved and implemented interest rate and foreign
exchange risk management programs, applied for regulatory approval to use energy
derivatives to manage commodity price risk in its utility business, and acquired
certain natural gas marketing operations which engage in both hedging and
non-hedging derivative transactions. Gains and losses associated with price risk
management activities during 1996 were immaterial.
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 $36, $50,
and $72 million for 1997, 1998, and 1999, respectively. Expenditures during
these years will be primarily for nitrogen oxide (NOx) emission reduction
projects at the Company's fossil fuel generating plants and natural gas
compressor stations. Pursuant to federal and state legislation,
18
<PAGE>
local air districts have adopted rules that require reductions in NOx emissions.
These rules are subject to continued review and modification by the local air
districts in which PG&E operates. The Company currently estimates that
compliance with NOx rules could require capital expenditures of up to $360
million over the next ten years.
On an ongoing basis, the Company assesses compliance with laws and
regulations related to hazardous substance remediation. The Company has an
accrued liability at December 31, 1996, of $170 million for remediation costs at
sites where such costs are probable and quantifiable. The costs at identified
sites may be as much as $400 million if, among other things, other potentially
responsible parties are not financially able to contribute to these costs, or
identifiable possible outcomes change. The Company will seek recovery of
prudently incurred compliance costs through ratemaking procedures approved by
the CPUC. The Company has recorded a regulatory asset at December 31, 1996, of
$146 million for recovery of these costs in future rates. Additionally, the
Company will seek recovery of costs from insurance carriers and from other third
parties. (See Note 13 to the Consolidated Financial Statements.)
Effective January 1, 1997, the Company will adopt the provisions of the
American Institute of Certified Public Accountants' Statement of Position (SOP)
96-1, Environmental Remediation Liabilities. This SOP provides authoritative
guidance for recognition, measurement, display, and disclosure of environmental
remediation liabilities in financial statements. The adoption of SOP 96-1 is not
expected to have a material adverse impact on the Company's financial position
or results of operations.
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 adverse impact on either the Company's
results of operations or financial position. In addition, the Company believes
that the litigation or settlement of pending claims and lawsuits will not have a
material adverse impact on its results of operations or financial position. See
Note 13 to the Consolidated Financial Statements for further discussion of
significant pending legal matters.
Accounting for Decommissioning Expense:
In 1996, the Financial Accounting Standards Board issued an exposure draft on a
proposed SFAS entitled "Accounting for Certain Liabilities Related to Closure or
Removal of Long-Lived Assets." If this exposure draft is adopted: (1) annual
expense for power plant decommissioning could increase, and (2) the estimated
total cost for power plant decommissioning could be recorded as a liability,
with recognition of an increase in the cost of the related power plant, rather
than accrued over time as accumulated depreciation. The Company does not believe
that this change, if implemented as proposed, would have a material adverse
impact on its results of operations due to its current and future ability to
recover decommissioning costs through rates. (See Note 2 to the Consolidated
Financial Statements for discussion of electric industry restructuring.)
Inflation: The Company's rates are designed to recover operating and historical
plant investment costs. Financial statements, which are prepared in accordance
with generally accepted accounting principles, report operating results in terms
of historic costs and do not evaluate the impact of inflation.
Inflation affects the Company's construction costs, operating expenses, and
interest charges. Due to the Company's five-year electric rate freeze, electric
revenues will not reflect the impact of inflation. However, inflation at the
levels currently being experienced is not expected to have a material adverse
impact on the Company's future results of operations.
19
<PAGE>
PG&E Corporation
Statement of Consolidated Income
<TABLE>
<CAPTION>
Year ended December 31, 1996 1995 1994
--------------- --------------- ---------------
(in thousands, except per share amounts)
<S> <C> <C> <C>
Operating Revenues
Electric utility $7,160,215 $7,386,307 $ 8,021,547
Gas utility 2,039,802 2,059,117 2,081,062
Diversified operations 409,955 176,341 247,621
--------------- --------------- ---------------
Total operating revenues 9,609,972 9,621,765 10,350,230
--------------- --------------- ---------------
Operating Expenses
Cost of electric energy 2,303,488 2,116,840 2,570,723
Cost of gas 761,837 333,280 583,356
Maintenance and other operating 2,118,174 1,799,781 1,855,585
Depreciation and decommissioning 1,221,952 1,360,118 1,397,470
Administrative and general 1,016,439 971,576 973,302
Workforce reduction costs -- (18,195) 249,097
Property and other taxes 292,497 295,380 296,911
--------------- --------------- ---------------
Total operating expenses 7,714,387 6,858,780 7,926,444
--------------- --------------- ---------------
Operating Income 1,895,585 2,762,985 2,423,786
--------------- --------------- ---------------
Interest income 72,900 72,524 79,643
Interest expense (639,823) (688,408) (729,207)
Other income and (expense) (18,459) 87,073 69,995
--------------- --------------- ---------------
Pretax Income 1,310,203 2,234,174 1,844,217
--------------- --------------- ---------------
Income Taxes 554,994 895,289 836,767
--------------- --------------- ---------------
Net Income 755,209 1,338,885 1,007,450
Preferred dividend requirement and redemption premium 33,113 70,288 57,603
--------------- --------------- ---------------
Earnings Available for Common Stock $ 722,096 $1,268,597 $ 949,847
=============== =============== ===============
Weighted Average Common Shares Outstanding 412,542 423,692 429,846
Earnings Per Common Share $ 1.75 $ 2.99 $ 2.21
Dividends Declared Per Common Share $ 1.77 $ 1.96 $ 1.96
</TABLE>
The accompanying Notes to the Consolidated Financial Statements are an integral
part of this statement.
20
<PAGE>
PG&E Corporation
Statement of Consolidated Cash Flows
<TABLE>
<CAPTION>
Year ended December 31, 1996 1995 1994
------------ ------------ ------------
(in thousands)
<S> <C> <C> <C>
Cash Flows From Operating Activities
Net income $ 755,209 $ 1,338,885 $ 1,007,450
Adjustments to reconcile net income to net cash provided by
operating activities
Depreciation and decommissioning 1,221,952 1,360,118 1,397,470
Amortization 93,948 89,353 95,331
Deferred income taxes and tax credits--net (149,990) (116,069) 15,312
Other deferred charges 94,475 61,700 32,740
Other noncurrent liabilities 113,244 (17,218) 181,902
Noncurrent balancing account liabilities and other deferred credits (185,390) (69,787) 316,920
Net effect of changes in operating assets and liabilities
Accounts receivable (46,368) 212,515 (116,936)
Regulatory balancing accounts receivable 302,188 498,756 (269,250)
Inventories 32,043 32,409 66,783
Accounts payable 193,012 49,702 (110,033)
Accrued taxes 36,014 (162,374) 132,892
Other working capital (6,234) 8,304 5,821
Other--net 156,773 50,423 191,285
------------ ------------ ------------
Net cash provided by operating activities 2,610,876 3,336,717 2,947,687
------------ ------------ ------------
Cash Flows From Investing Activities
Capital expenditures (1,230,331) (944,618) (1,126,904)
Diversified operations (99,532) (178,874) (308,810)
Acquisition of PGT Queensland Gas Pipeline (136,227) -- --
Acquisition of Energy Source (23,270) -- --
Proceeds from sale of DALEN -- 340,000 --
Other--net (119,923) (122,913) (29,914)
------------ ------------ ------------
Net cash used by investing activities (1,609,283) (906,405) (1,465,628)
------------ ------------ ------------
Cash Flows From Financing Activities
Common stock issued 219,726 139,595 274,269
Common stock repurchased (455,278) (601,360) (181,558)
Preferred stock issued -- -- 62,312
Preferred stock redeemed or repurchased -- (358,212) (82,875)
Company obligated mandatorily redeemable preferred securities issued -- 300,000 --
Long-term debt issued 1,087,732 591,160 60,907
Long-term debt matured, redeemed, or repurchased (1,471,390) (1,296,549) (436,673)
Short-term debt issued (redeemed)--net (115,243) 305,262 (239,478)
Dividends paid (843,997) (891,270) (891,850)
Other--net (14,036) (21,543) 28,721
------------ ------------ ------------
Net cash used by financing activities (1,592,486) (1,832,917) (1,406,225)
------------ ------------ ------------
Net Change in Cash and Cash Equivalents (590,893) 597,395 75,834
Cash and Cash Equivalents at January 1 734,295 136,900 61,066
------------ ------------ ------------
Cash and Cash Equivalents at December 31 $ 143,402 $ 734,295 $ 136,900
============ ============ ============
Supplemental disclosures of cash flow information
Cash paid for
Interest (net of amounts capitalized) $ 598,394 $ 644,978 $ 674,758
Income taxes 639,813 1,125,635 712,777
</TABLE>
The accompanying Notes to the Consolidated Financial Statements are an integral
part of this statement.
21
<PAGE>
PG&E Corporation
Consolidated Balance Sheet
<TABLE>
<CAPTION>
December 31, 1996 1995
------------- -------------
(in thousands)
<S> <C> <C>
Assets
Plant in Service
Electric
Nonnuclear $18,099,342 $17,530,446
Diablo Canyon 6,658,137 6,646,853
Gas 8,138,106 7,732,681
------------- -------------
Total plant in service (at original cost) 32,895,585 31,909,980
Accumulated depreciation and decommissioning (14,301,934) (13,311,500)
------------- -------------
Net plant in service 18,593,651 18,598,480
------------- -------------
Construction Work in Progress 414,229 333,263
Other Noncurrent Assets
Nuclear decommissioning funds 882,929 769,829
Investment in nonregulated projects 817,259 855,962
Other assets 134,271 130,128
------------- -------------
Total other noncurrent assets 1,834,459 1,755,919
------------- -------------
Current Assets
Cash and cash equivalents 143,402 734,295
Accounts receivable, net 1,499,674 1,268,936
Regulatory balancing accounts receivable 444,156 746,344
Inventories
Materials and supplies 185,771 181,763
Gas stored underground 130,229 146,499
Fuel oil 23,433 40,756
Nuclear fuel 190,652 175,957
Prepayments 54,116 47,025
------------- -------------
Total current assets 2,671,433 3,341,575
------------- -------------
Deferred Charges
Income tax-related deferred charges 1,133,043 1,079,673
Other deferred charges 1,483,110 1,741,380
------------- -------------
Total deferred charges 2,616,153 2,821,053
------------- -------------
Total Assets $26,129,925 $26,850,290
============= =============
</TABLE>
The accompanying Notes to the Consolidated Financial Statements are an integral
part of this statement.
22
<PAGE>
PG&E Corporation
Consolidated Balance Sheet
<TABLE>
<CAPTION>
December 31, 1996 1995
------------ ------------
(in thousands)
<S> <C> <C>
Capitalization and Liabilities
Capitalization
Common stock equity $ 8,363,301 $ 8,599,133
Preferred stock without mandatory redemption provisions 402,056 402,056
Preferred stock with mandatory redemption provisions 137,500 137,500
Company obligated mandatorily redeemable preferred securities of trust
holding solely PG&E subordinated debentures 300,000 300,000
Long-term debt 7,770,067 8,048,546
------------ ------------
Total capitalization 16,972,924 17,487,235
------------ ------------
Current Liabilities
Short-term borrowings 680,900 829,947
Current portion of long-term debt 209,867 304,204
Accounts payable
Trade creditors 834,143 413,972
Other 365,499 387,747
Accrued taxes 310,271 274,093
Amounts due customers 186,899 49,175
Deferred income taxes 157,064 227,782
Interest payable 63,193 70,179
Dividends payable 123,310 205,467
Other 309,104 455,798
------------ ------------
Total current liabilities 3,240,250 3,218,364
------------ ------------
Deferred Credits and Other Noncurrent Liabilities
Deferred income taxes 3,941,435 3,933,765
Deferred tax credits 379,563 393,255
Noncurrent balancing account liabilities 120,858 185,647
Other 1,474,895 1,632,024
------------ ------------
Total deferred credits and other noncurrent liabilities 5,916,751 6,144,691
------------ ------------
Commitments and Contingencies (Notes 1, 2, 3, 12, and 13) -- --
------------ ------------
Total Capitalization and Liabilities $26,129,925 $26,850,290
============ ============
</TABLE>
23
<PAGE>
PG&E Corporation
<TABLE>
<CAPTION>
Statement of Consolidated Common Stock Equity, Preferred Stock, and Preferred Securities
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 Provisions Provisions
---------- ---------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C> <C>
Balance December 31, 1993 $2,136,095 $3,666,455 $2,643,487 $8,446,037 $ 807,995 $ 75,000
---------- ---------- ---------- ---------- ---------- ----------
Net income 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)
---------- ---------- ---------- ---------- ---------- ----------
Balance December 31, 1994 2,151,213 3,806,508 2,677,304 8,635,025 732,995 137,500
---------- ---------- ---------- ---------- ---------- ----------
Net income 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 securities issued/(1)/
(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
---------- ---------- ---------- ---------- ---------- ----------
Balance December 31, 1995 2,070,128 3,716,322 2,812,683 8,599,133 402,056 437,500
---------- ---------- ---------- ---------- ---------- ----------
Net income 755,209 755,209
Common stock issued
(9,290,102 shares) 46,448 173,278 219,726
Common stock repurchased
(19,811,396 shares) (99,055) (182,088) (174,135) (455,278)
Cash dividends declared
Preferred stock (33,113) (33,113)
Common stock (728,727) (728,727)
Other 2,381 3,970 6,351
---------- ---------- ---------- ---------- ---------- ----------
Balance December 31, 1996 $2,017,521 $3,709,893 $2,635,887 $8,363,301 $ 402,056 $437,500
========== ========== ========== ========== ========== ==========
</TABLE>
/(1)/ Relates to company obligated mandatorily redeemable preferred securities
of trust holding solely PG&E subordinated debentures.
The accompanying Notes to the Consolidated Financial Statements are an integral
part of this statement.
24
<PAGE>
PG&E Corporation
Statement of Consolidated Capitalization
<TABLE>
<CAPTION>
December 31, 1996 1995
------------ -----------
(dollars in thousands, except per share amounts)
<S> <C> <C>
Common Stock Equity
Common stock, par value $5 per share (authorized 800,000,000 shares, issued and
outstanding 403,504,292 and 414,025,856) $ 2,017,521 $ 2,070,128
Additional paid-in capital 3,709,893 3,716,322
Reinvested earnings 2,635,887 2,812,683
------------ -----------
Common stock equity 8,363,301 8,599,133
Preferred Stock and Preferred Securities
Preferred stock without mandatory redemption provisions
Par value $25 per share/(1)/
Nonredeemable
5% to 6%--5,784,825 shares outstanding 144,621 144,621
Redeemable
4.36% to 7.44%--10,297,404 shares outstanding 257,435 257,435
------------ -----------
Total preferred stock without mandatory redemption provisions 402,056 402,056
------------ -----------
Preferred stock with mandatory redemption provisions
Par value $25 per share/(1)/
6.30% and 6.57%--5,500,000 shares outstanding, due 2002-2009 137,500 137,500
------------ -----------
Preferred stock 539,556 539,556
------------ -----------
Company obligated mandatorily redeemable preferred securities of trust holding
solely PG&E subordinated debentures
7.90%--12,000,000 shares outstanding, due 2025 300,000 300,000
------------ -----------
Long-Term Debt
PG&E long-term debt
First and refunding mortgage bonds
Maturity Interest rates
1996-2001 4.50% to 8.75% 880,450 915,249
2002-2006 5.875% to 7.875% 1,392,135 1,450,000
2007-2012 6.25% to 8.875% 475,000 477,870
2013-2019 7.5% to 8.2% 45,000 105,000
2020-2026 5.85% to 8.875% 2,627,736 2,749,651
------------ -----------
Principal amounts outstanding 5,420,321 5,697,770
Unamortized discount net of premium (49,923) (55,802)
------------ -----------
Total mortgage bonds 5,370,398 5,641,968
Debentures, 12%, due 2000 57,539 57,539
Pollution control loan agreements, variable rates, due 2016-2026 987,870 925,000
Unsecured medium-term notes, 4.93% to 9.9%, due 1997-2014 828,900 1,096,400
Unamortized discount related to unsecured medium-term notes (1,187) (1,652)
Other long-term debt 32,800 20,298
------------ -----------
Total PG&E long-term debt 7,276,320 7,739,553
Long-term debt of PGT and Enterprises 703,614 613,197
------------ -----------
Total long-term debt 7,979,934 8,352,750
Less current portion 209,867 304,204
------------ -----------
Long-term debt, excluding current portion 7,770,067 8,048,546
------------ -----------
Total Capitalization $16,972,924 $17,487,235
============ ===========
</TABLE>
/(1)/ Authorized 75,000,000 shares in total (both with and without mandatory
redemption provisions).
The accompanying Notes to the Consolidated Financial Statements are an integral
part of this statement.
25
<PAGE>
PG&E Corporation
Statement of Consolidated Segment Information
<TABLE>
<CAPTION>
Electric Gas Diversified Intersegment
(in thousands) Utility Utility Operations/(4)/ Eliminations Total
------------ ----------- -------------- -------------- ------------
<S> <C> <C> <C> <C> <C>
1996
Operating revenues $ 7,160,215 $2,039,802 $ 409,955 $ -- $ 9,609,972
Intersegment revenues/(1)/ 12,156 69,645 -- (81,801) --
------------ ----------- -------------- -------------- ------------
Total operating revenues $ 7,172,371 $2,109,447 $ 409,955 $(81,801) $ 9,609,972
============ =========== ============== ============== ============
Depreciation and decommissioning $ 919,958 $ 288,994 $ 13,000 $ -- $ 1,221,952
Operating income before
income taxes/(2)/ 1,757,611 184,506 (47,921) 1,389 1,895,585
Capital expenditures/(3)/ 921,425 459,074 23,270 -- 1,403,769
Identifiable assets/(3)/ $18,005,105 $6,215,028 $1,434,216 $ -- $25,654,349
Corporate assets 475,576
------------
Total assets at year end $26,129,925
============
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 2,067 -- 964,657
Identifiable assets/(3)/ $18,610,610 $6,064,596 $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 19,456 -- 1,145,950
Identifiable assets/(3)/ $19,637,222 $6,167,314 $1,436,128 $ -- $27,240,664
Corporate assets 467,900
-----------
Total assets at year end $27,708,564
============
</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 Energy Source (gas marketing).
The accompanying Notes to the Consolidated Financial Statements are an integral
part of this schedule.
26
<PAGE>
PG&E Corporation
Notes to Consolidated Financial Statements
Note 1: Significant Accounting Policies
Corporate Restructuring: Effective January 1, 1997, Pacific Gas and Electric
Company (PG&E) became a subsidiary of its new parent holding company, PG&E
Corporation. PG&E's ownership interest in Pacific Gas Transmission Company (PGT)
and PG&E Enterprises (Enterprises) was transferred to PG&E Corporation. PG&E's
outstanding common stock was converted on a share-for-share basis into PG&E
Corporation's outstanding common stock. PG&E's debt securities and preferred
stock were unaffected and remain securities of PG&E. The members of PG&E's
current Board of Directors became directors of PG&E Corporation.
Basis of Presentation: The consolidated financial statements include the
accounts of PG&E and its wholly-owned and controlled subsidiaries (collectively,
the Company) and, therefore, also represent the accounts of PG&E Corporation and
its subsidiaries. All significant intercompany transactions have been
eliminated. Certain amounts in the prior years' consolidated financial
statements have been reclassified to conform to the 1996 presentation.
The preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions.
These estimates and assumptions affect the reported amounts of revenues,
expenses, assets, and liabilities and disclosure of contingencies. Actual
results could differ from these estimates.
Operations: The Company and its subsidiaries provide electric and natural gas
services and retail energy 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. PGT
transports gas from the Canadian border to the California border and the Pacific
Northwest. PGT also has operations in Australia and Texas. Enterprises, through
its subsidiaries and affiliates, develops, owns, and operates electric and gas
projects and provides energy services.
Regulation: PG&E is regulated by the California Public Utilities Commission
(CPUC), the Federal Energy Regulatory Commission (FERC), and the Nuclear
Regulatory Commission, among others. PG&E currently accounts for the economic
effects of regulation in accordance with Statement of Financial Accounting
Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of
Regulation." This statement allows the Company to record certain regulatory
assets and liabilities which would be included in future rates and would not be
recorded under generally accepted accounting principles for nonregulated
entities.
Effective January 1, 1996, the Company adopted SFAS No. 121, "Accounting for
the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed
Of." SFAS No. 121 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. Adoption of this
standard had no material impact on the Company's financial position or results
of operations.
On an ongoing basis, PG&E reviews its regulatory assets and liabilities for
the continued applicability of SFAS No. 71 and the effect of SFAS No. 121. (See
Note 2 for further discussion.)
Net regulatory assets and liabilities include the following:
<TABLE>
<CAPTION>
December 31, 1996 1995
------ ------
(in millions)
<S> <C> <C>
Deferred income tax $1,133 $1,080
Unamortized loss net of gain on reacquired debt 377 392
Diablo Canyon pre-settlement costs 364 382
Workers' compensation and disability claims costs 288 297
Regulatory balancing accounts (net) 323 561
Other deferred (net) 267 474
------ ------
$2,752 $3,186
====== ======
</TABLE>
Revenues and Regulatory Balancing Accounts: Revenues are recorded primarily for
delivery of gas and electric energy to customers. Electric and gas utility
revenues include amounts for services rendered but unbilled at the end of the
year. Revenues also are recorded for changes in regulatory balancing accounts
established by the CPUC. 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 energy cost balancing accounts is subject to
27
<PAGE>
PG&E Corporation
Notes to Consolidated Financial Statements
reasonableness reviews by the CPUC. The regulatory balancing accounts accumulate
balances until they are refunded to or received from utility customers through
authorized rate adjustments.
Dividend Restriction: PG&E is limited as to the amount of dividends that it may
pay to PG&E Corporation based on PG&E's regulatory capital structure authorized
by the CPUC. PG&E's equity shall be retained such that, on average, the capital
structure authorized by the CPUC is maintained. This restriction is not expected
to affect PG&E Corporation's ability to meet its cash obligations.
Financial Derivative Instruments (Derivatives): The Company engages in price
risk management activities to manage risks associated with changes in energy
commodity prices, interest rates, and foreign currencies. These price risk
management activities include the use of derivatives.
Gains and losses on derivatives used for hedging purposes are intended to
offset losses and gains on the underlying hedged item. Under hedge accounting,
changes in the market value of these transactions are deferred and recognized as
an addition to the income or expense of the underlying instrument upon
completion of the underlying transaction. All 1996 transactions were accounted
for using hedge accounting. Gains and losses associated with derivative
transactions during 1996 were immaterial.
Plant in Service: The cost of plant additions and replacements includes labor,
materials, construction overhead, and an allowance for funds used during
construction (AFUDC) or capitalized interest. AFUDC is the estimated cost of
debt and equity funds used to finance regulated plant additions. Capitalized
interest is the interest incurred on borrowed funds used to finance nonregulated
plant additions. The original cost of retired plant and removal costs less
salvage value is charged to accumulated depreciation upon retirement of plant in
service.
Plant in service is depreciated using a straight-line remaining-life method.
The Company's composite depreciation rates were 3.65, 4.09, and 4.31 percent for
the years ended December 31, 1996, 1995, and 1994.
Nuclear Decommissioning Costs: The estimated total obligation for
decommissioning PG&E's nuclear power facilities is comprised of the total cost
(including labor, materials, and other costs) of decommissioning and dismantling
plant systems and structures. In addition, a contingency amount for possible
changes in regulatory requirements and increases in waste disposal costs is
included in the estimated total obligation.
The estimated total obligation for nuclear decommissioning costs, based on a
1994 site study, is approximately $1.2 billion in 1996 dollars (or $5.9 billion
in future dollars). Actual decommissioning costs are expected to vary from this
estimate because of changes in assumed dates of decommissioning, regulatory
requirements, technology, and costs of labor, materials, and equipment. The
estimated total obligation is being recognized proportionately over the license
of each facility.
For the years ended December 31, 1996, 1995, and 1994, nuclear
decommissioning costs recovered in rates through an annual allowance were $33,
$54, and $54 million, respectively. Based on the 1994 site study, the amount
assumed to be recovered in rates in 1997 and annually up to the commencement of
decommissioning is $33 million. This amount will be reviewed in future rate
proceedings.
At December 31, 1996, the total nuclear decommissioning obligation accrued
was $889 million and was included in the balance sheet classification of
Accumulated Depreciation and Decommissioning.
Decommissioning costs recovered in rates are placed in external trust funds.
These funds along with accumulated earnings will be used exclusively for
decommissioning. (See Note 8 for further discussion of nuclear decommissioning
funds.)
Decommissioning is scheduled to begin for Diablo Canyon Nuclear Power Plant's
(Diablo Canyon) Unit 1 and Unit 2 in 2015 and 2016, respectively, with scheduled
completion for both units in 2034. The decommissioning method selected for
Diablo Canyon anticipates that the facilities will be decontaminated to a level
that permits the property to be released for unrestricted use.
Decommissioning for Humboldt Bay Power Plant is scheduled to begin in 2015.
The decommissioning method selected consists of placing and maintaining the
facility in protective storage until some future time when dismantling can be
initiated.
PG&E, as required by federal law, has signed a contract with the U.S.
Department of Energy (DOE) to provide for the
28
<PAGE>
disposal of spent nuclear fuel and high-level radioactive waste from PG&E's
nuclear power facilities beginning not later than January 1998. However, due to
delays in identifying a storage site, the DOE has officially acknowledged that
it will not be able to meet its contract commitment. The DOE's current estimate
for an available site to begin accepting physical possession of the spent
nuclear fuel is 2010.
At the projected level of operation for Diablo Canyon, PG&E's facilities are
sufficient to store on-site all spent fuel produced through approximately 2006.
It is likely that an interim or permanent DOE storage facility will not be
available for Diablo Canyon's spent fuel by 2006. PG&E is examining options for
providing additional temporary spent fuel storage at Diablo Canyon or other
facilities, pending disposal or storage at a DOE facility.
Gains and Losses on Reacquired Debt: Gains and losses on reacquired debt charged
to operations subject to the provisions of SFAS No. 71 are deferred and
amortized over the remaining original lives of the debt reacquired, consistent
with ratemaking principles. Gains and losses on reacquired debt associated with
other operations are recognized in earnings at the time such debt is reacquired.
Inventories: Stored nuclear fuel inventory is stated at lower of average cost or
market. Nuclear fuel in the reactor is amortized 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.
Cash Equivalents: Cash equivalents (stated at cost, which approximates market)
include working funds and short-term investments with original maturities of
three months or less.
Note 2: Electric Industry Restructuring
In 1995, the CPUC issued a decision that provides a plan to restructure
California's electric utility industry. The decision acknowledges that much of
utilities' current costs and commitments result from past CPUC decisions and
that, in a competitive generation market, utilities would not recover some of
these costs through market-based revenues. To assure the continued financial
integrity of California utilities, the CPUC authorized recovery of these
above-market costs, called "transition costs."
In 1996, California legislation was passed that adopts the basic tenets of
the CPUC's restructuring decision, including recovery of transition costs. In
addition, the legislation provides a 10 percent rate reduction for residential
and small commercial customers by January 1, 1998, freezes electric customer
rates for all other customers, and requires the accelerated recovery of
transition costs associated with owned generation facilities. The legislation
also establishes the operating framework for a competitive generation market.
The rate freeze will continue until the earlier of March 31, 2002, or until
PG&E has recovered its transition costs (the transition period). The freeze will
hold rates at 1996 levels for all customers except those receiving the 10
percent rate reduction. The rate freeze will hold the rates for these customers
at the reduced level.
To achieve the 10 percent rate reduction, the legislation authorizes
utilities to finance a portion of their transition costs with "rate reduction
bonds." The maturity period of the bonds is expected to extend beyond the
transition period. Also, the interest cost of the bonds is expected to be lower
than PG&E's current cost of capital. Once this portion of transition costs is
financed, PG&E would collect a bond service payment to recover principal,
interest, and issuance costs over the life of the bonds from residential and
small commercial customers. The combination of the longer maturity period and
the reduced interest costs will lower the amounts paid by these customers each
year during the transition period thereby achieving the 10 percent reduction in
rates.
Tax-exempt trusts have been established to oversee the development of the
operating framework for the competitive generation market. The CPUC has
authorized California utilities to guarantee bank loans of up to $250 million to
be used by the trusts for this purpose. Under this authorization, PG&E will
guarantee a maximum of $112.5 million of these loans.
Transition Cost Recovery: The legislation authorizes the CPUC to determine the
costs eligible for recovery as transition costs. The amount of costs will be
based on the aggregate of above-market and below-market values of utility-owned
generation assets and obligations. PG&E has proposed that costs eligible for
transition cost recovery include: (1) above-market sunk costs (costs associated
with utility generating facilities that are fixed and unavoidable and currently
collected through rates) and future costs, such as costs related to plant
removal,
29
<PAGE>
PG&E Corporation
Notes to Consolidated Financial Statements
(2) above-market costs associated with purchase power obligations with
Qualifying Facilities (QFs) and other Power Purchase Agreements, and (3)
generation-related regulatory assets and obligations. PG&E cannot determine the
exact amount of sunk costs that will be above market and recoverable as
transition costs until a market valuation process (appraisal or sale) is
completed for each generation facility. This process will be completed during
the transition period.
Most transition costs must be recovered by March 1, 2002. However, the
legislation authorizes recovery of certain transition costs after that time.
These costs include: (1) certain employee-related transition costs, (2) payments
under existing QF and power purchase contracts, and (3) unrecovered
implementation costs. Excluding these exceptions, any transition costs not
recovered during the transition period will be absorbed by PG&E. Nuclear
decommissioning costs, which are not considered transition costs, will be
recovered through a CPUC authorized charge. During the transition period, this
charge will be incorporated into the frozen rates. After the transition period,
customers will be assessed a surcharge until the nuclear decommissioning costs
are fully recovered.
PG&E's ability to recover its transition costs during the transition period
will be dependent on several factors. These factors include: (1) the extent to
which application of the current regulatory framework established by the
restructuring legislation will continue to be applied, (2) the amount of
transition costs approved by the CPUC, (3) the market value of its generation
plants, (4) future sales levels, (5) fuel and operating costs, (6) the market
price of electricity, and (7) the ratemaking methodology adopted for Diablo
Canyon. Considering its current evaluation of these factors, PG&E believes it
will recover its transition costs and that its owned generation plants are not
impaired. However, a change in these factors could affect the probability of
recovery of transition costs and result in a material loss.
PG&E has proposed to implement portions of its transition cost recovery plan
in 1997. The CPUC decision on PG&E's 1997 Energy Cost Adjustment Clause (ECAC)
application would decrease PG&E's 1997 revenue requirement by $720 million. This
decrease would be partially offset by a $160 million revenue requirement
increase, provided by the legislation, for purposes of enhancing transmission
and distribution system safety and reliability. This increase was approved by
the CPUC as part of PG&E's transition cost recovery plan.
Given the electric customer rate freeze, the $560 million net revenue
requirement decrease resulting from the consolidation of the ECAC decision and
the revenue requirement increase contemplated in the cost recovery plan would be
available for transition cost recovery. The proposed accelerated recovery of
Diablo Canyon would absorb an estimated $400 million of this available revenue
requirement. The remaining revenue requirement would be available to recover
other transition costs.
Accounting for the Effects of Regulation: As a result of applying the provisions
of SFAS No. 71 (discussed in Note 1 above), PG&E has accumulated approximately
$1.6 billion of regulatory assets attributable to electric generation at
December 31, 1996. The net investments in Diablo Canyon and the other generation
assets were $4.5 and $2.7 billion, respectively, at December 31, 1996. The net
present value of above-market QF power purchase obligations is estimated to be
$5.3 billion at January 1, 1998, at an assumed market price of $0.025 per
kilowatt-hour (kWh) beginning in 1997 and escalating at 3.2 percent per year.
PG&E believes that the restructuring legislation establishes a definitive
transition to market-based pricing for electric generation. Incorporating the
effects of the competitive auction pricing of electricity and customer direct
access, this transition includes cost-of-service based ratemaking. In addition,
PG&E's generation-related transition costs will be collected through a
nonbypassable charge. Based on this structure, PG&E believes it will continue to
meet the requirements of SFAS No. 71 throughout the transition period.
At the conclusion of the transition period, PG&E believes it will be at risk
to recover its generation costs through market-based revenues. At that time,
PG&E expects to discontinue the application of SFAS No. 71 for the electric
generation portion of its business. Since PG&E anticipates it will have
recovered all transition costs required to be recovered during the transition
period, including generation-related regulatory assets and above-market
investments in net plant, PG&E does not expect a material adverse impact on its
financial position or results of operations from discontinuing the application
at that time.
As a result of the CPUC's restructuring decision and California's electric
industry restructuring legislation, the Securities and Exchange Commission (SEC)
has begun inquiries regarding the appropriateness of the continued application
of
30
<PAGE>
SFAS No. 71 by California utilities to their electric generation businesses. As
discussed above, PG&E believes it currently meets and will continue to meet the
requirements to apply SFAS No. 71 during the transition period. In the event
that the SEC concludes that the current regulatory and legal framework in
California no longer meets the requirements to apply SFAS No. 71 to the
generation business, the Company would reevaluate the financial impact of
electric industry restructuring and a material write-off could occur.
Given the current regulatory environment, PG&E's electric transmission and
distribution businesses are expected to remain regulated and, as a result, will
continue application of the provisions of SFAS No. 71.
Note 3: Natural Gas Matters
The Gas Accord Settlement (Accord): In an effort to promote competition and to
give all residential and smaller commercial (core) customers the same options
that exist for industrial and larger commercial (noncore) customers, PG&E
submitted the Accord to the CPUC in 1996. In addition to offering increased
customer choice, the Accord would establish gas transmission rates for the
period July 1997 through December 2002 and resolve various pending regulatory
issues. The Accord must be approved by the CPUC before it can be implemented. A
CPUC decision is expected in 1997.
The major outstanding gas regulatory issues that the Accord would resolve
include the 1988 through 1995 gas reasonableness proceedings, the initial
capital costs for the PG&E Pipeline Expansion, the interstate transition cost
surcharge (ITCS) recovery, and the PG&E pipeline transportation commitments, all
of which are discussed in further detail below.
As of December 31, 1996, PG&E has reserved approximately $527 million,
including $182 million reserved during 1996, relating to its gas regulatory
issues and gas capacity commitments, the majority of which are addressed by the
Accord. The Company believes the ultimate resolution of these matters, whether
through approval of the Accord or otherwise, will not have a material adverse
impact on its financial position or future results of operations.
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 a decision which ordered a disallowance of
approximately $90 million of gas costs plus accrued interest of approximately
$25 million through 1993 for PG&E's Canadian gas procurement activities from
1988 through 1990. PG&E has filed a lawsuit in a federal district court
challenging the CPUC's decision on Canadian gas costs. PG&E expects this issue
to be resolved as part of the Accord discussed above. Under the Accord, PG&E
would agree to forgo recovery of the $90 million disallowance ordered in the
1988 through 1990 gas reasonableness proceeding, irrespective of the outcome of
the lawsuit.
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 were resolved when the CPUC accepted a
settlement in December 1996 between PG&E and the Office of Ratepayer Advocates
(ORA) of the CPUC. Under the terms of that settlement, PG&E will return $67
million plus interest to ratepayers in 1997. PG&E has previously recorded
reserves for this settlement.
PGT/PG&E Pipeline Expansion: In November 1993, the Company expanded its natural
gas transmission system providing additional firm transportation capacity from
the Canadian border to Northern and Southern California and the Pacific
Northwest.
PG&E has filed an application with the CPUC requesting that capital costs of
$810 million and ongoing operating costs for the PG&E, or California, portion of
the Pipeline Expansion be found reasonable. Revenues are currently being
collected under interim rates approved by the CPUC, subject to adjustment.
In 1996, a CPUC Administrative Law Judge (ALJ) ordered consolidation of the
market impact phase of the PG&E Pipeline Expansion reasonableness proceeding and
the ITCS proceeding discussed below. An ALJ also ordered reopening of the 1993
PG&E Pipeline Expansion Rate Case to allow reconsideration of issues regarding
the decision to construct the PG&E Pipeline Expansion. Were the CPUC to reverse
its previous decision, which found that PG&E was reasonable in constructing the
PG&E Pipeline Expansion, the ultimate outcome could have an adverse impact on
PG&E's ability to recover its cost for unused
31
<PAGE>
PG&E Corporation
Notes to Consolidated Financial Statements
capacity on other pipelines as well as on its own intrastate facilities. PG&E
expects these issues to be resolved as part of the Accord discussed above. Under
the Accord, PG&E would agree to set rates for the PG&E Pipeline Expansion based
on total capital costs of $736 million.
Transportation Commitments: PG&E has gas transportation service agreements with
various Canadian and interstate pipeline companies. These agreements include
provisions for payment of 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. The total demand and transportation charges paid
by PG&E under these agreements (excluding agreements with PGT) were
approximately $212, $175, and $225 million in 1996, 1995, and 1994,
respectively.
The following table summarizes the approximate capacity held by PG&E on
various pipelines (excluding PGT) and the related annual demand charges at
December 31, 1996:
<TABLE>
<CAPTION>
Total
Annual
Firm Gross
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 $ 29 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
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
almost all of its core customers and those noncore customers who choose bundled
service (core subscription customers). To serve 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), Alberta
Natural Gas Company Ltd (ANG), and PGT.
PG&E is continuing its efforts to broker or assign any remaining unused
capacity, including unused capacity held for its core and core subscription
customers. 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 are
eligible for rate recovery, subject to a reasonableness review. These demand
charges include capacity that was formerly used to serve noncore customers but
which at present cannot be brokered or which is brokered at a discount. However,
certain groups, including the ORA and intervenors, have challenged the recovery
of these unrecovered 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 commit to
transportation capacity with Transwestern. The decision 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.
The recovery of demand charges associated with capacity which was formerly
used to serve PG&E's noncore customers will be decided by the CPUC in the ITCS
proceeding, unless otherwise resolved as part of the Accord. Pending a final
decision in the ITCS proceeding, the CPUC has approved collection (subject to
refund) in rates of approximately 50 percent of the demand charges for
unbrokered or discounted El Paso and PGT capacity which was formerly used to
serve PG&E's noncore customers.
Under the Accord, PG&E would not recover costs through 1997 associated with
Transwestern capacity originally subscribed to in order to serve core customers
and would have limited recovery during the period 1998 through 2002. Also as
part of the Accord, PG&E would forgo recovery of 100 percent and 50 percent of
the ITCS amounts allocated to its core and noncore customers, respectively.
The Company believes ultimate resolution of its capacity commitments and the
ITCS proceeding, either through approval of the Accord or otherwise, will not
have a material adverse impact on its financial position or future results of
operations.
Note 4: Diablo Canyon
The Diablo Canyon rate case settlement as adopted in 1988 and modified in 1995
(Diablo Settlement) bases revenues primarily on the amount of electricity
generated by Diablo Canyon. The Diablo Settlement provides that Diablo Canyon
costs and operations are not subject to CPUC reasonableness reviews. Only
certain Diablo Canyon costs may be recovered
32
<PAGE>
through base revenues over the term of the Diablo Settlement, including a full
return on such costs. The revenues to recover all Diablo Canyon costs are
included in Diablo Canyon operating revenues reported below. Other than for
these and decommissioning costs, Diablo Canyon discontinued the application of
SFAS No. 71 in July 1988.
Under the pricing provisions of the existing Diablo Settlement, the price for
power produced by Diablo Canyon for 1997 is 10.0 cents per kWh effective January
1. PG&E has the right to reduce the price below the amount specified. Under the
existing settlement, at full operating power, each Diablo Canyon unit would
contribute approximately $2.6 million in revenues per day in 1997. The prices
per kWh of electricity generated by Diablo Canyon for 1996, 1995, and 1994 were
10.50, 11.00, and 11.89 cents per kWh, respectively.
Selected financial information for Diablo Canyon is shown below:
<TABLE>
<CAPTION>
Year ended December 31, 1996 1995 1994
-------- --------- ---------
(in millions)
<S> <C> <C> <C>
Operating revenues $1,789 $1,845 $1,870
Operating income before
income taxes 998 1,029 956
Net income 497 507 461
</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 PG&E debt.
In conjunction with electric industry restructuring, PG&E filed in March 1996
a proposal for pricing Diablo Canyon generation at market prices and completing
recovery of the investment in Diablo Canyon by the end of 2001. If this proposal
is adopted, there would be a significant change to the manner in which Diablo
Canyon earns revenues.
Under its proposal, PG&E would replace the existing settlement prices with:
(1) a sunk cost revenue requirement to recover fixed costs, including a return
on these costs, and (2) a performance-based ratemaking (PBR) mechanism to
recover the facility's variable costs and capital addition costs. As proposed,
the sunk cost revenue requirement would accelerate recovery of Diablo Canyon
sunk costs from a twenty-year period ending in 2016 to a five-year period
beginning in 1997 and ending in 2001. The related return on common equity
associated with Diablo Canyon sunk costs would be reduced to 90 percent of
pg&e's long-term cost of debt. PG&E's authorized long-term cost of debt was 7.52
percent in 1996. The reduced rate of return combined with a shorter recovery
period would result in an estimated $4 billion decrease in the net present value
of PG&E's future revenues from Diablo Canyon operations. If the proposed cost
recovery plan for Diablo Canyon were adopted during 1996, Diablo Canyon's 1996
reported net income would have been reduced by $350 million ($0.85 per share).
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, 1996, 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, 1996, 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, 1996. These series of
preferred stock are subject to mandatory redemption provisions entitling them to
sinking funds providing for the retirement of stock outstanding. They 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, 1996, and 1995, was approximately $135 and $139
million, respectively, based on quoted market prices.
In 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
67/8%, 7.04%, and 7.44% redeemable
33
<PAGE>
PG&E Corporation
Notes to Consolidated Financial Statements
preferred stock through a tender offer. The aggregate par value of these
redemptions and repurchases was $331 million.
Dividends on all 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: During 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 Trust in turn used
the net proceeds from the QUIPS offering and issuance of the common securities
to purchase 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. These subordinated debentures are the only assets of the Trust.
Proceeds to PG&E from the sale of the subordinated debentures were used to
redeem and repurchase higher-cost preferred stock.
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. The subordinated debentures may be redeemed at PG&E's option beginning in
2000 at par plus accrued interest through the redemption date. The proceeds of
any redemption will be used by the Trust to redeem QUIPS in accordance with
their terms.
Upon liquidation or dissolution of PG&E, holders of these QUIPS would be
entitled to the liquidation preference of $25 per share plus all accrued and
unpaid dividends thereon to the date of payment. The estimated fair value of
PG&E's QUIPS at December 31, 1996, and 1995, was approximately $291 and $311
million, respectively, based on quoted market prices.
Note 6: Long-term Debt
(See the Statement of Consolidated Capitalization for additional information.)
Mortgage Bonds: PG&E had $5.4 and $5.7 billion of mortgage bonds outstanding at
December 31, 1996, and 1995, respectively. Additional mortgage bonds may be
issued, subject to CPUC approval, up to a maximum total amount outstanding of
$10 billion. All real properties and substantially all personal properties of
PG&E are subject to the lien of the mortgage, and PG&E is required to make semi-
annual sinking fund payments for the retirement of the bonds.
PG&E redeemed or repurchased $182 and $114 million of mortgage bonds in 1996
and 1995, respectively, with interest rates ranging from 5.375 to 12.75 percent.
Included in the total of outstanding mortgage bonds at December 31, 1996, and
1995, are $705 and $768 million, respectively, of mortgage bonds held in trust
for the California Pollution Control Financing Authority (CPCFA) with interest
rates ranging from 5.85 to 8.875 percent and maturity dates from 2007 to 2023.
In addition to these mortgage bonds, PG&E holds long-term loan agreements with
the CPCFA as described below.
Pollution Control Loan Agreements: In 1996, PG&E refinanced $925 million of
variable interest rate pollution control loan agreements with variable interest
rate pollution control loan agreements to extend certain maturities and achieve
cost savings. These loan agreements from the CPCFA totaled $988 and $925
million, respectively, at December 31, 1996, and 1995. Interest rates on the
loans vary with average annual interest rates for 1996 ranging from 3.24 to 3.54
percent. These loans are subject to redemption by the holder under certain
circumstances. These loans are secured by irrevocable letters of credit which
mature as early as 1999.
Long-term Debt of PGT: In 1996, PGT borrowed $92 million of long-term debt to
finance the acquisition of PGT Queensland Gas Pipeline.
In 1995, PGT issued $470 million of long-term debt, the proceeds of which were
used to refinance $600 million of outstanding PGT debt.
34
<PAGE>
Additionally, in 1995, PGT issued commercial paper classified as long-term
debt based upon the availability of committed credit facilities expiring in 2000
and management's intent to maintain such amounts in excess of one year. The
commercial paper outstanding was $108 and $109 million at December 31, 1996, and
1995, respectively.
Repayment Schedule: At December 31, 1996, the Company's combined aggregate
amounts of maturing long-term debt and sinking fund requirements, for the years
1997 through 2001, are $210, $660, $270, $413, and $376 million, respectively.
Fair Value: The estimated fair value of the Company's total long-term debt of
$8.0 and $8.4 billion at December 31, 1996, and 1995, respectively, was
approximately $8.0 and $8.7 billion, respectively. The estimated fair value of
long-term debt was determined based on quoted market prices, where available.
Where quoted market prices were not available, the estimated fair value was
determined using other valuation techniques (e.g., the present value of future
cash flows).
Note 7: Short-term Borrowings
Substantially all short-term borrowings consist of commercial paper, having a
maturity of one to ninety days. Commercial paper outstanding and the associated
weighted average interest rate at December 31, 1996, and 1995, were $681 million
and 5.86 percent and were $796 million and 5.92 percent, respectively. The
carrying amount of short-term borrowings approximates fair value.
PG&E maintains a $1 billion revolving credit facility which expires in 2001;
however, it may be extended annually for additional one-year periods upon mutual
agreement between PG&E and the banks. This credit facility 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. There
were no borrowings under this facility in 1996 or 1995.
In January 1997, PG&E Corporation established a $500 million revolving credit
facility in order to provide for corporate short-term liquidity needs and other
purposes.
Note 8: Investments in Debt and
Equity Securities
All of PG&E's investments in debt and equity securities are held in external
trust funds and are reported at fair value. These investments, which are
included in Nuclear Decommissioning Funds, cannot be released from the trust
funds until authorized by the CPUC.
The proceeds received during 1996 and 1995 from sales were approximately $1.5
billion in each year. During 1996 and 1995, the gross realized gains on sales of
securities held as available-for-sale were $14 and $9 million, respectively, and
the gross realized losses on sales of securities held as available-for-sale
were $20 and $22 million, respectively. The cost of debt and equity securities
sold is determined by specific identification.
The following table provides a summary of amortized cost and fair value of
these investments:
<TABLE>
<CAPTION>
Year ended December 31, 1996 1995
------------ ------------
(in thousands)
<S> <C> <C>
Amortized Cost:
U.S. government and agency issues $374,931 $322,838
Equity securities 281,532 269,117
Municipal bonds and other 32,952 63,061
Gross unrealized holding gains 198,875 117,673
Gross unrealized holding losses (5,361) (2,860)
------------ ------------
Fair value $882,929 $769,829
============ ============
</TABLE>
Note 9: Employee Benefit Plans
Retirement Plan: The Company provides noncontributory defined benefit pension
plans covering substantially all employees. Pension benefits are based on an
employee's years of service and base salary. The Company'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.
35
<PAGE>
PG&E Corporation
Notes to Consolidated Financial Statements
The following schedule reconciles the plans' funded status to the pension
liability recorded on the Consolidated Balance Sheet:
<TABLE>
<CAPTION>
December 31, 1996 1995
------------ ------------
(in thousands)
<S> <C> <C>
Actuarial present value of benefit
obligations
Vested benefits $(3,486,136) $(3,464,782)
Nonvested benefits (177,782) (182,503)
------------ ------------
Accumulated benefit obligation (3,663,918) (3,647,285)
Effect of projected future
compensation increases (529,045) (548,743)
------------ ------------
Projected benefit obligation (4,192,963) (4,196,028)
Plan assets at market value 5,526,247 4,935,267
------------ ------------
Plan assets in excess of projected
benefit obligation 1,333,284 739,239
Unrecognized prior service cost 82,756 90,496
Unrecognized net gain (1,559,281) (1,074,347)
Unrecognized net transition
obligation 85,895 97,348
------------ ------------
Accrued pension liability $ (57,346) $ (147,264)
============ ============
</TABLE>
Plan assets consist primarily of 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 being amortized over 17.5 years from 1987.
Using the projected unit credit actuarial cost method, net pension income
consisted of the following components:
<TABLE>
<CAPTION>
Year ended December 31, 1996 1995 1994
----------- ----------- -----------
(in thousands)
<S> <C> <C> <C>
Service cost for benefits
earned $ (99,946) $ (82,814) $(109,132)
Interest cost (301,631) (290,563) (272,932)
Actual return (loss) on
plan assets 811,130 968,126 (20,358)
Net amortization and
deferral (353,195) (586,350) 412,547
----------- ----------- -----------
Net pension income $ 56,358 $ 8,399 $ 10,125
=========== =========== ===========
</TABLE>
The following actuarial assumptions were used in determining the plans'
funded status and net pension income. Year-end assumptions are used to compute
funded status, while prior year-end assumptions are used to compute net pension
income.
<TABLE>
<CAPTION>
December 31, 1996 1995 1994
-------- -------- --------
<S> <C> <C> <C>
Discount rate 7.5% 7.25% 8%
Rate of future
compensation increases 5% 5% 5%
Expected long-term rate
of return on plan assets 9% 9% 9%
</TABLE>
Net pension income or 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 net pension income or cost. In 1996 and 1995, 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 SFAS No. 71, regulatory adjustments have been recorded in
the income statement and balance sheet for the difference between utility
pension income or cost determined for accounting purposes and that for
ratemaking, which is based on a funding approach.
Postretirement Benefits Other Than Pensions:
The Company provides contributory defined benefit medical plans for retired
employees and their eligible dependents and noncontributory defined benefit life
insurance plans for retired employees. Substantially all employees retiring at
or after age 55 are eligible for these benefits. The medical benefits are
provided through plans administered by an insurance carrier or a health
maintenance organization. Certain retirees are responsible for a portion of the
cost based on past claims experience of the Company's retirees.
The CPUC has authorized PG&E to recover these benefits for 1993 and beyond.
Recovery is based on the lesser of the annual accounting costs or annual
contributions on a tax-deductible basis to appropriate trusts. The Company's
policy is to fund each year an amount consistent with the basis for rate
recovery.
36
<PAGE>
The following schedule reconciles the medical and life insurance plans'
funded status to the postretirement benefit liability recorded on the
Consolidated Balance Sheet:
<TABLE>
<CAPTION>
December 31, 1996 1995
------------- ------------
(in thousands)
<S> <C> <C>
Accumulated postretirement benefit
obligation
Retirees $(444,782) $(528,367)
Other fully eligible participants (132,797) (123,615)
Other active plan participants (343,864) (309,405)
------------- ------------
Total accumulated postretirement
benefit obligation (921,443) (961,387)
Plan assets at market value 666,287 538,905
------------- ------------
Accumulated postretirement benefit
obligation in excess of plan assets (255,156) (422,482)
Unrecognized prior service cost 21,946 23,761
Unrecognized net gain (226,753) (104,167)
Unrecognized transition obligation 419,617 449,647
------------- ------------
Accrued postretirement benefit liability $ (40,346) $ (53,241)
</TABLE>
Plan assets consist primarily of 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 being amortized over 20 years from 1993.
Using the projected unit credit actuarial cost method, net postretirement
medical and life insurance cost consisted of the following components:
<TABLE>
<CAPTION>
Year ended December 31, 1996 1995 1994
---------- ----------- -----------
(in thousands)
<S> <C> <C> <C>
Service cost for
benefits earned $ 21,954 $ 17,004 $ 23,617
Interest cost 65,629 64,776 64,872
Actual return on
plan assets (91,050) (108,932) (1,232)
Amortization of
unrecognized prior
service cost 1,602 1,616 1,711
Amortization of
transition obligation 26,314 26,533 28,913
Net amortization
and deferral 38,329 70,070 (29,804)
---------- ---------- ----------
Net postretirement
benefit cost $ 62,778 $ 71,067 $ 88,077
========== ========== ==========
</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 1996, 1995, and 1994 were the same as those used for the
pension plan.
The assumed health care cost trend rate for 1997 is approximately 10.0
percent, grading down to an ultimate rate in 2005 of approximately 6.0 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, 1996, by approximately $75 million and the
1996 aggregate service and interest costs by approximately $8 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.
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 1996 and 1995, actual return on plan
assets exceeded expected return. In 1994, actual return on plan assets was less
than expected.
Workforce Reductions: The effects of workforce reductions announced by PG&E in
1994 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 Corporation maintains a Long-term Incentive
Program (Program) which provides for grants of stock options to eligible
participants with or without associated stock appreciation rights and dividend
equivalents. The Program also grants performance-based units to eligible
participants. As of December 31, 1996, 24.5 million shares of common stock have
been authorized for award under the program. At December 31, 1996, stock options
on 3,461,733 shares, granted at option prices ranging from $16.75 to $34.25,
were outstanding, of which 1,655,450 were exercisable. In 1996, 877,900 options
were granted at an option price of $28.25, which was the market price per share
on the date of grant.
Outstanding stock options expire ten years and one day after the date of
grant and become exercisable on a cumulative
37
<PAGE>
PG&E Corporation
Notes to Consolidated Financial Statements
basis at one-third each year commencing two years from the date of grant. In
1996, 1995, and 1994, stock options on 72,960, 235,568, and 52,143 shares,
respectively, were exercised at option prices ranging from $16.75 to $33.13,
$16.75 to $33.13, and $24.75 to $32.13, respectively.
Effective January 1, 1996, the Company adopted SFAS No. 123, "Accounting for
Stock-Based Compensation." SFAS No. 123 requires the Company to disclose stock
option costs based on the fair value of options granted. For the years ended
December 31, 1996, and 1995, the fair value of options granted was not material
to the Company's results of operations or earnings per share.
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, $52 million for other postretirement benefits, and $61 million
for estimated severance costs. PG&E did 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 response to the severity of the damage caused by the winter storms
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 million in
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 amortized over the life of the related
property.
The significant components of income tax expense were:
<TABLE>
<CAPTION>
Year ended December 31, 1996 1995 1994
------------ ------------ ----------
(in thousands)
<S> <C> <C> <C>
Current $ 704,984 $1,011,358 $821,455
Deferred (132,250) (97,864) 34,657
Tax credits--net (17,740) (18,205) (19,345)
------------ ------------- ----------
Total income
tax expense $ 554,994 $ 895,289 $836,767
============ ============= ==========
</TABLE>
The significant components of net deferred income tax liabilities were:
<TABLE>
<CAPTION>
December 31, 1996 1995
------------ ------------
(in thousands)
<S> <C> <C>
Deferred income tax assets $1,308,395 $1,203,981
------------ ------------
Deferred income tax liabilities:
Regulatory balancing accounts $ 294,494 $ 385,604
Plant in service 3,623,544 3,552,974
Income tax-related deferred
charges /(1)/ 454,359 443,152
Other 1,034,497 983,798
------------ ------------
Total deferred income tax liabilities $5,406,894 $5,365,528
------------ ------------
Total net deferred income taxes $4,098,499 $4,161,547
============ ============
Classification of net deferred
income taxes:
Included in current liabilities $ 157,064 $ 227,782
Included in deferred credits 3,941,435 3,933,765
------------ ------------
Total net deferred income taxes $4,098,499 $4,161,547
============ ============
</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, 1996 1995 1994
-------- --------- --------
(in thousands)
<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) 3.7 4.8 8.3
Effect of regulatory treatment
of depreciation differences 5.9 3.2 3.7
Tax credits--net (1.4) (.8) (1.1)
Other--net (.8) (2.1) (.5)
-------- --------- --------
Effective tax rate 42.4% 40.1% 45.4%
======== ========= ========
</TABLE>
Note 12: Commitments
Capital Projects: Capital expenditures for 1997 are estimated to be $1,773
million for utility, $38 million for Diablo Canyon, and $211 million for
diversified operations.
At December 31, 1996, Enterprises had $67 million in firm commitments 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
38
<PAGE>
$52 million in 1997 (included in the expenditures above) and $15 million in
1998.
Letters of Credit: PG&E utilizes approximately $247 million in standby letters
of credit to secure future workers' compensation liabilities.
Qualifying Facilities and Other Power-Purchase Contracts: Under the Public
Utility Regulatory Policies Act of 1978, PG&E is required to purchase electric
energy and capacity provided by QFs which are cogenerators and small power
producers. The CPUC established a series of power-purchase contracts with
certain QFs and set the applicable terms, conditions, and price options. Under
these contracts, PG&E is required to purchase electric energy and capacity;
however, payments are only required when energy is supplied or when capacity
commitments are met. The total cost of these payments is recoverable in rates.
PG&E's contracts with QFs expire on various dates from 1997 to 2028. Energy
payments to QFs are expected to decline in the years 1997 through 2000. Capacity
payments are expected to remain at current levels.
In 1996, 1995, and 1994, PG&E negotiated early termination or suspension of
certain QF contracts to be paid through 1999 at discounted costs of $25, $142,
and $155 million for 1996, 1995, and 1994, respectively. These amounts are
expected to be recovered in rates and as such are reflected as deferred charges
on the accompanying balance sheet. At December 31, 1996, the total discounted
future payments remaining under QF early termination or suspension contracts is
$68 million.
QF deliveries in the aggregate account for approximately 19 percent of PG&E's
1996 electric energy requirements, and no single contract accounted for more
than 5 percent of PG&E's energy needs.
PG&E also has contracts with various irrigation districts and water agencies
to purchase hydroelectric power. 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) and variable payments for
operation and maintenance costs incurred by the providers. These contracts
expire on various dates from 2004 to 2031. The total cost of these payments is
recoverable in rates. At December 31, 1996, the undiscounted future minimum
payments under these contracts are $34 million for each of the years 1997
through 2001 and a total of $383 million for periods thereafter. Irrigation
district and water agency deliveries in the aggregate account for approximately
six percent of PG&E's 1996 electric energy requirements, and no single contract
accounted for more than five percent of PG&E's energy needs.
The amount of energy received and the total payments made under QF and other
power-purchase contracts were:
<TABLE>
<CAPTION>
Year ended December 31, 1996 1995 1994
---------- ---------- ----------
(in millions)
<S> <C> <C> <C>
Kilowatt-hours received 26,056 26,468 23,903
QF energy payments $1,136 $1,140 $1,196
QF capacity payments $ 521 $ 484 $ 518
Other power purchase
payments $ 52 $ 50 $ 49
</TABLE>
Note 13: Contingencies
Nuclear Insurance: PG&E has insurance coverage for property damage and business
interruption losses as a member of Nuclear Mutual Limited (NML) and Nuclear
Electric Insurance Limited (NEIL). Under these policies, if a nuclear generating
facility of a member utility suffers a loss due to a prolonged accidental
outage, PG&E may be subject to maximum assessments of $29 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.
PG&E has purchased primary insurance of $200 million for public liability
claims resulting from a nuclear incident. An additional $8.7 billion of coverage
is provided by secondary financial protection which provides for loss sharing
among utilities owning nuclear generating facilities if a costly incident
occurs. 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 may be required to pay for environmental
remediation at sites where the Company has been or may be a potentially
responsible party under the Comprehensive Environmental Response, Compensation
and Liability Act (CERCLA) or the California Hazardous Substance Account Act.
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
39
<PAGE>
PG&E Corporation
Notes to Consolidated Financial Statements
substances. Under CERCLA, the Company's financial responsibilities may include
remediation of hazardous substances, even if the Company did not deposit those
substances on the site.
The Company records a liability when site assessments indicate remediation is
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, 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 better estimate
within this range of possible costs, the Company records the lower end of this
range (classified as other noncurrent liabilities).
The cost of the hazardous substance remediation ultimately undertaken by the
Company is difficult to estimate. 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, 1996, of $170 million for hazardous waste remediation costs at
those sites where such costs are probable and quantifiable. Environmental
remediation at identified sites may be as much as $400 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, based upon 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 substance
remediation costs through ratemaking procedures approved by the CPUC. The
Company has recorded a regulatory asset at December 31, 1996, of $146 million
for recovery of these costs in future rates. Additionally, the Company will seek
recovery of costs from insurance carriers and from other third parties. 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 investment of $710 million at
December 31, 1996. The net investment is comprised of the pumped storage
facility (including regulatory assets of $51 million), common plant, and
dedicated transmission plant. As part of the 1996 General Rate Case decision in
December 1995, the CPUC directed PG&E to perform a cost-effectiveness study of
Helms. In July 1996, PG&E submitted its study, which concluded that the
continued operation of Helms is cost effective. As a result of the study, PG&E
recommended that the CPUC take no action and address Helms along with other
generating plants in the context of electric industry restructuring.
PG&E is currently unable to predict whether there will be a change in rate
recovery resulting from the study. As with its other hydroelectric generating
plants, the Company expects to seek recovery of its net investment in Helms
through PBR and transition cost recovery. 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.
Helms became commercially operable in 1984, following delays due to a water
conduit rupture in 1982 and various start-up problems related to the plant's
generators. As a result of the rupture damage and the operational delay, PG&E
incurred additional costs which were excluded from rate base and lost revenues
during the period the plant was under repair. In 1994, PG&E submitted for CPUC
approval a settlement with the ORA regarding recovery of such additional costs
and lost revenues, amounting to approximately $98 million. In September 1996,
the CPUC issued a final decision adopting the settlement which permits PG&E to
recover that amount. Because PG&E's current rate recovery already reflects the
anticipated settlement, adoption of the settlement will have no impact on rates.
40
<PAGE>
Legal Matters:
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 those fees at
different rates from other cities not included in the complaint.
In September 1995, the Court certified the class of 107 cities in this suit
and approved the City of Santa Cruz as the class representative. In January and
March 1996, the Court made two rulings against certain cities effectively
eliminating a major portion of the suit. The Court's rulings do not resolve the
suit completely. The cities appealed both rulings. The trial has been postponed
pending the cities' appeal.
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 $14 million and damages for alleged underpayments for
the years 1987 to 1996 could be as much as $145 million (exclusive of interest).
If the Court's January and March 1996 rulings become final, PG&E's annual
systemwide city electric franchise fees for the remaining class member cities
not subject to the Court's rulings could increase by approximately $4 million
and damages for alleged underpayments for the years 1987 to 1996 could be as
much as $39 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.
Hinkley: In 1996, PG&E settled a 1993 lawsuit seeking damages for personal
injuries allegedly suffered as a result of exposure to chromium near PG&E's gas
compressor station at Hinkley. This lawsuit was settled for the aggregate sum of
$333 million, of which $50 million had been paid in 1994, with the remaining
$283 million paid in 1996. PG&E had previously reserved $200 million for this
litigation and in 1996 recorded an additional reserve of $133 million for this
settlement. The settlement does not resolve other pending chromium litigation,
described below.
Chromium Litigation: In 1994 through 1996, several civil suits were filed
against PG&E on behalf of more than 1,500 individuals. The complaints seek an
unspecified amount of compensatory and punitive damages for alleged personal
injuries resulting from exposure to chromium in the vicinity of PG&E's gas
compressor stations at Hinkley, Kettleman, and Topock.
PG&E is responding to the complaints and asserting affirmative defenses. PG&E
will pursue appropriate legal defenses, including statute of limitations or
exclusivity of workers' compensation laws, and factual defenses including lack
of exposure to chromium and the inability of chromium to cause certain of the
illnesses alleged.
Given the uncertainty, the Company cannot predict the outcome of this
litigation. However, 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.
41
<PAGE>
PG&E Corporation
Quarterly Consolidated Financial Data (Unaudited)
Quarterly Financial Data: Due to the seasonal nature of the utility business and
the scheduled refueling outages for Diablo Canyon, operating revenues, operating
income, and net income are not generated evenly every quarter during the year.
All four quarters of 1996 reflected a decline in price per kilowatt-hours as
provided in the modified pricing provisions of the Diablo Canyon rate case
settlement, and revenue reductions authorized by the 1996 General Rate Case
(GRC) and other related rate proceedings. In addition, maintenance and operating
expenses exceeded levels authorized by the GRC.
In the second quarter of 1996, the Company charged to earnings $133 million
for the settlement of a litigation claim. Revenues were also reduced due to a
greater number of scheduled refueling days and unscheduled outages.
In the third quarter of 1996, the Company took charges against earnings of
$182 million for contingencies related to gas transportation commitments.
In the fourth quarter of 1996, the Company charged to earnings $59 million in
write-downs of nonregulated investments.
The Company recorded additional litigation reserves of $50 million in the
first and third quarters of 1995. Diablo Canyon scheduled refueling days and
unscheduled outages reduced earnings per common share in the fourth quarter of
1995.
The Company's common stock is traded on the New York, Pacific, and Swiss
stock exchanges. There were approximately 198,000 common shareholders of record
at December 31, 1996. Dividends are paid on a quarterly basis, and net cash
flows are sufficient to maintain the current payment of dividends.
<TABLE>
<CAPTION>
Quarter ended December 31 September 30 June 30 March 31
-------------- --------------- ------------- -------------
(in thousands, except per share amounts)
<S> <C> <C> <C> <C>
1996
Operating revenues $2,700,686 $2,521,852 $2,138,666 $2,248,768
Operating income 508,970 524,846 288,375 573,394
Net income 149,030 233,695 111,780 260,704
Earnings per common share .34 .55 .25 .61
Dividends declared per common share .30 .49 .49 .49
Common stock price per share
High 24.25 23.88 23.75 28.38
Low 20.88 19.50 21.50 22.38
1995
Operating revenues $2,227,224 $2,637,653 $2,448,641 $2,308,247
Operating income 451,674 781,912 820,370 709,029
Net income 227,085 377,593 405,520 328,687
Earnings per common share .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
</TABLE>
42
<PAGE>
PG&E Corporation
Report of Independent Public Accountants
To the Shareholders and the Board of Directors of PG&E Corporation:
We have audited the accompanying consolidated balance sheet and the statement of
consolidated capitalization of PG&E Corporation (a California corporation) and
subsidiaries as of December 31, 1996, and 1995, 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, 1996. 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 schedules 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 PG&E Corporation and subsidiaries
as of December 31, 1996, and 1995, and the results of their operations and cash
flows for each of the three years in the period ended December 31, 1996, in
conformity with generally accepted accounting principles.
ARTHUR ANDERSEN LLP
ARTHUR ANDERSEN LLP
San Francisco, California
February 10, 1997
43
<PAGE>
PG&E Corporation
Responsibility for Consolidated Financial Statements
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 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 and
effective internal controls and maintaining unbiased and 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.
44
<PAGE>
EXHIBIT INDEX
Exhibit
Number Exhibit
23 Consent of Arthur
Andersen LLP
27 Financial Data Schedule
1
<PAGE>
EXHIBIT 23
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation of our
report dated February 10, 1997, included in Appendix I to the Report on Form 8-K
dated February 19, 1997, into the previously filed registration statements as
follows: (1) PG&E Corporation's Form S-3 Registration Statement File No. 333-
16255 (relating to PG&E Corporation's Dividend Reinvestment Plan); (2) Pacific
Gas and Electric Company's Form S-3 Registration Statement File No. 33-64136
(relating to $2,000,000,000 aggregate principal amount of Pacific Gas and
Electric Company's First and Refunding Mortgage Bonds and Medium-Term Notes);
(3) Pacific Gas and Electric Company's Form S-3 Registration Statement File No.
33-50707 (relating to $1,500,000,000 aggregate principal amount of Pacific Gas
and Electric Company's First and Refunding Mortgage Bonds); (4) PG&E
Corporation's Form S-8 Registration Statement File No. 33-50601 (relating to the
Pacific Gas and Electric Company's Savings Fund Plan for Employees); (5) PG&E
Corporation's Form S-8 Registration Statement File No. 33-23692 (relating to
PG&E Corporation's 1986 Stock Option Plan); (6) Pacific Gas and Electric
Company's Form S-3 Registration Statement File No. 33-62488 (relating to
10,000,000 shares of Pacific Gas and Electric Company's Redeemable First
Preferred Stock); (7) Form S-3 Registration Statement File No. 33-61959
(relating to $335,000,000 aggregate liquidation value of Cumulative Quarterly
Income Preferred Securities); and (8) PG&E Corporation's Form S-8 Registration
Statement File No. 333-16253 (relating to PG&E Corporation's Long-Term Incentive
Program).
ARTHUR ANDERSEN LLP
San Francisco, California
February 19, 1997
<TABLE> <S> <C>
<PAGE>
<ARTICLE> UT
<LEGEND> This schedule contains summary financial information extracted from
PG&E CORPORATION and is qualified in its entirety by reference to such
financial statements.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1996
<PERIOD-START> JAN-01-1996
<PERIOD-END> DEC-31-1996
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 19,007,880
<OTHER-PROPERTY-AND-INVEST> 1,834,459
<TOTAL-CURRENT-ASSETS> 2,671,433
<TOTAL-DEFERRED-CHARGES> 2,616,153
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 26,129,925
<COMMON> 2,017,521
<CAPITAL-SURPLUS-PAID-IN> 3,709,893
<RETAINED-EARNINGS> 2,635,887
<TOTAL-COMMON-STOCKHOLDERS-EQ> 8,363,301
437,500
402,056
<LONG-TERM-DEBT-NET> 7,770,067
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 680,900
<LONG-TERM-DEBT-CURRENT-PORT> 209,867
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 8,266,234
<TOT-CAPITALIZATION-AND-LIAB> 26,129,925
<GROSS-OPERATING-REVENUE> 9,609,972
<INCOME-TAX-EXPENSE> 554,994
<OTHER-OPERATING-EXPENSES> 7,714,387
<TOTAL-OPERATING-EXPENSES> 7,714,387
<OPERATING-INCOME-LOSS> 1,895,585
<OTHER-INCOME-NET> 54,441
<INCOME-BEFORE-INTEREST-EXPEN> 1,950,026
<TOTAL-INTEREST-EXPENSE> 639,823
<NET-INCOME> 755,209
33,113
<EARNINGS-AVAILABLE-FOR-COMM> 722,096
<COMMON-STOCK-DIVIDENDS> 728,727
<TOTAL-INTEREST-ON-BONDS> 0
<CASH-FLOW-OPERATIONS> 2,610,876
<EPS-PRIMARY> 1.75
<EPS-DILUTED> 1.75
</TABLE>
