EXHIBIT 13
Selected Financial Data
(in millions, except per share amounts) 1997 1996 1995 1994 1993
- -------------------------------------------------------------------------------------------------------------------------
PG&E Corporation(1)
For the Year
Operating revenues $15,400 $ 9,610 $ 9,622 $10,350 $10,550
Operating income 1,728 1,896 2,763 2,424 2,560
Net income 716 722 1,269 950 1,002
Earnings per common share 1.75 1.75 2.99 2.21 2.33
Dividends declared per common share 1.20 1.77 1.96 1.96 1.88
At Year End
Book value per common share $ 21.30 $ 20.73 $ 20.77 $ 20.07 $ 19.77
Common stock price per share 30.31 21.00 28.38 24.38 35.13
Total assets 30,557 26,237 26,871 27,738 27,234
Long-term debt (excluding current portions) 7,659 7,770 8,049 8,676 9,292
Rate reduction bonds (excluding current portions) 2,776 - - - -
Preferred stock and securities of subsidiary with
mandatory redemption provisions (excluding
current portions) 437 437 437 137 75
Pacific Gas and Electric Company
For the Year
Operating revenues $ 9,495 $ 9,610 $ 9,622 $10,350 $10,550
Operating income 1,831 1,896 2,763 2,424 2,560
Income available for common stock 735 722 1,269 950 1,002
At Year End
Total assets $25,147 $26,237 $26,871 $27,738 $27,234
Long-term debt (excluding current portions) 6,218 7,770 8,049 8,676 9,292
Rate reduction bonds (excluding current portions) 2,776 - - - -
Preferred stock and securities with mandatory
redemption provisions (excluding current portions) 437 437 437 137 75
(1) PG&E Corporation became the holding company for Pacific Gas and Electric
Company on January 1, 1997. The Selected Financial Data of PG&E Corporation and
Pacific Gas and Electric Company for the years 1993 through 1996 are identical
because they represent the accounts of Pacific Gas and Electric Company as the
predecessor of PG&E Corporation. See Management's Discussion and Analysis of
Consolidated Results of Operations and Financial Condition for further
discussion of the holding company formation and matters relating to certain data
above.
16
Management's Discussion and Analysis of
Consolidated Results of Operations and Financial Condition
San Francisco-based PG&E Corporation provides energy services throughout the
United States and Australia. We were formed as a holding company on January 1,
1997, to respond to new business opportunities and changes in the energy
industry. As a result, Pacific Gas and Electric Company became a subsidiary of
its new parent holding company, PG&E Corporation, and its ownership interest in
its unregulated subsidiaries was transferred to PG&E Corporation. Under our new
corporate structure, we provide integrated energy services through our various
business lines:
Pacific Gas and Electric Company (Utility)
Our Utility provides gas and electric service to Northern and Central
California. Our Utility is regulated by the California Public Utilities
Commission (CPUC), the Federal Energy Regulatory Commission (FERC), and the
Nuclear Regulatory Commission, among others.
Unregulated Business Operations
We provide a wide range of integrated energy products and services designed to
take advantage of the opening of the competitive energy marketplace throughout
the United States. Through our other subsidiaries, we provide the following
energy services:
Gas Transmission: We own and operate approximately 10,000 miles of natural gas
pipelines, natural gas storage facilities, and natural gas processing plants in
the Pacific Northwest, Texas, and Australia through PG&E Gas Transmission (PG&E
GT). PG&E GT's Pacific Northwest operations are regulated by the FERC, and its
Texas operations are regulated by the Texas Railroad Commission.
Electric Generation: We develop, build, operate, own, and manage power
generation facilities across the United States through U.S. Generating Company
(USGen). In 1998, USGen expects to complete the acquisition of the New England
Electric System fossil fuel and hydroelectric power plants. This acquisition is
discussed further in the Acquisitions and Sales section below.
Energy Services and Commodities: We provide customers nationwide with
competitively-priced natural gas and electricity and services to manage and make
more efficient their energy consumption through PG&E Energy Services (PG&E ES).
Through PG&E Energy Trading (PG&E ET), we purchase and resell energy
commodities and related financial instruments in major domestic markets, serving
PG&E Corporation's other unregulated businesses, unaffiliated utilities, and
large end-use customers.
Overview
This is a combined annual report of PG&E Corporation and Pacific Gas and
Electric Company. Therefore, our Management's Discussion and Analysis of
Consolidated Results of Operations and Financial Condition apply to both PG&E
Corporation and the Utility. PG&E Corporation's consolidated financial
statements include the accounts of PG&E Corporation and its wholly owned and
controlled subsidiaries, including the Utility (collectively, the Corporation).
Our Utility's consolidated financial statements include its accounts as well as
those of its wholly owned and controlled subsidiaries. Because PG&E Corporation
did not become the holding company for the Utility until January 1, 1997, the
1995 and 1996 consolidated financial statements represent the accounts of the
Utility on a consolidated basis as predecessor of PG&E Corporation. Management's
Discussion and Analysis should be read in conjunction with the consolidated
financial statements.
In Management's Discussion and Analysis, we explain the results of operations
for the years 1995 through 1997 and discuss our financial condition. Our
discussion of financial condition includes:
. energy industry restructuring and how this restructuring will influence
future results of operations,
. liquidity and capital resources, including discussions of capital financing
activities, estimated capital spending for the next three years, and
uncertainties that could affect future results, and
. risk management activities.
17
Management's Discussion and Analysis of
Consolidated Results of Operations and Financial Condition
This combined annual report, including our Letter to Shareholders above and
our discussion of results of operations and financial condition below, contains
forward-looking statements that involve risks and uncertainties. Also, words
such as "estimates," "expects," "anticipates," "plans," "believes," 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, the outcome of the regulatory
proceedings related to those restructurings, our Utility's ability to collect
revenues sufficient to recover transition costs in accordance with its cost
recovery plan, the impact of our recent or planned acquisitions as discussed in
the Acquisitions and Sales section below, the approval of our Utility's 1999
General Rate Case application resulting in the Utility's ability to earn its
authorized rate of return as discussed in the Letter to Shareholders above and
in the Regulatory Activity section below, and our ability to successfully
compete outside our traditional regulated markets, as discussed in the Letter to
Shareholders above. The ultimate impacts on future results of increased
competition, the changing regulatory environment, our expansion into new
businesses and markets, and the CPUC's decision on the 1999 General Rate Case
application are uncertain, but all are expected to fundamentally change how we
conduct our 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 PG&E Corporation.
Results of Operations
In this section, we provide the components of our earnings for 1997, 1996, and
1995. We then explain why operating revenues and expenses for 1997 and 1996 were
different from the year before.
The following table shows our results of operations and total assets for 1997,
1996, and 1995. The results of operations for PG&E Corporation on a stand-alone
basis and intercompany eliminations have been shown as Corporate and Other.
Unregulated Corporate
Business and
Utility Operations Other Total
- ---------------------------------------------------------------------------
(in millions)
1997
Operating revenues $ 9,495 $6,351 $ (446) $15,400
Operating expenses 7,664 6,433 (425) 13,672
--------------------------------------------
Operating income (loss)
before income taxes $ 1,831 $ (82) $ (21) $ 1,728
============================================
Income available for
common stock $ 735 $ 8 $ (27) $ 716
============================================
Total assets $25,147 $6,224 $ (814) $30,557
============================================
1996
Operating revenues $ 8,989 $ 679 $ (58) $ 9,610
Operating expenses 7,179 595 (60) 7,714
--------------------------------------------
Operating income
before income taxes $ 1,810 $ 84 $ 2 $ 1,896
============================================
Income available for
common stock $ 707 $ 15 $ - $ 722
============================================
Total assets $23,567 $2,858 $ (188) $26,237
============================================
1995
Operating revenues $ 9,243 $ 447 $ (68) $ 9,622
Operating expenses 6,556 376 (73) 6,859
--------------------------------------------
Operating income
before income taxes $ 2,687 $ 71 $ 5 $ 2,763
============================================
Income available for
common stock $ 1,210 $ 59 $ - $ 1,269
============================================
Total assets $24,689 $2,578 $ (396) $26,871
============================================
Earnings Per Common Share: Basic and diluted earnings per common share were
$1.75, $1.75, and $2.99 for 1997, 1996, and 1995, respectively. Earnings per
common share were affected by the activity discussed below.
18
Utility Results:
1997 COMPARED TO 1996
Our Utility operating revenues in 1997 increased $506 million from 1996. The
largest portion of the increase was due to transition cost recovery related to
the revisions in the Diablo Canyon Nuclear Power Plant (Diablo Canyon)
ratemaking structure discussed in Electric Transition Plan below. A portion of
the increase is due to increased revenues associated with electric transmission
and distribution system reliability authorized by California Assembly Bill 1890,
the electric industry restructuring legislation. There was also an increase in
energy cost revenues to recover energy cost increases and changes in sales
volume provided by our Utility's energy rate recovery mechanism. Under energy
rate recovery mechanisms, energy rate revenues generally equal energy costs and,
thus, increases in the cost of energy do not affect operating income.
Our Utility operating expenses in 1997 increased $485 million from 1996. The
increase was due primarily to the increase in Diablo Canyon depreciation (which
provided the revenue increases discussed above for recovery of the increased
depreciation) and the increase in cost of energy. This increase was partially
offset by a decrease in expenses for several 1996 one-time charges associated
with gas transportation commitments and a 1996 one-time charge due to a
litigation reserve.
Other income increased in 1997 compared to 1996 primarily due to a gain on the
buyout of a long-term contract for gas transportation service.
1996 COMPARED TO 1995
Our Utility operating revenues in 1996 decreased $254 million from 1995 due to
revenue reductions ordered in the 1996 General Rate Case. The revenue decrease
was also due to a decline in the Diablo Canyon generation price, as provided in
the Diablo Canyon rate case settlement. This lower generation price was
partially offset by higher net generation, which was a result of fewer scheduled
refuelings in 1996 compared to 1995. We maintain an automatic adjustment clause
(Gas Balancing Account) pursuant to which 1996 revenues were increased to
reflect the increase in gas prices in 1996 as compared to 1995. However, this
increase to gas revenues was offset by a corresponding revenue decrease ordered
in the 1996 General Rate Case.
Our Utility operating expenses increased $623 million in 1996 primarily due to
charges for gas transportation commitments, increases in gas and purchased power
prices, increases in expenses related to transmission and distribution system
reliability, and increases in litigation costs.
Unregulated Business Results:
1997 COMPARED TO 1996
Our unregulated business operating revenues in 1997 increased $5,672 million
from 1996. This was primarily due to a $4,524 million increase in energy
commodities and services revenues from the acquisitions of Energy Source (ES) in
December 1996, Teco Pipeline Company (Teco) in January 1997, and Valero Energy
Corporation (Valero) in July 1997. Also contributing to the increase were the
new revenues from the gas pipeline operations of Teco and Valero.
Our unregulated business operating expenses in 1997 increased $5,838 million
from 1996 which essentially reflects the increase in the cost of gas for resale
due to the above acquisitions and our expansion into the energy commodities and
services industry.
Other income increased in 1997 compared to 1996 primarily due to the gain on
the sale of International Generating Company, Ltd. which was partially offset by
write-downs of certain nonregulated investments.
1996 COMPARED TO 1995
Our unregulated business operating revenues and operating expenses in 1996
increased $232 and $219 million, respectively, from 1995 primarily due to the
purchase of ES in December 1996. This purchase created $283 million of revenue
but was offset by an increase in the cost of gas for resale. The increase in
both operating revenues and operating expenses was partially offset by a
decrease due to the sale of DALEN Corporation in 1995.
Other income decreased in 1996 compared to 1995 primarily due to write-downs
of certain nonregulated investments in 1996.
19
Management's Discussion and Analysis of
Consolidated Results of Operations and Financial Condition
Common Stock Dividend: Our common stock dividend is based on a number of
financial considerations, including sustainability, financial flexibility, and
competitiveness with investment opportunities of similar risk. Our current
quarterly common stock dividend is $.30 per common share, which corresponds to
an annualized dividend of $1.20 per common share.
The CPUC set a number of conditions when PG&E Corporation was formed as a
holding company. One of these conditions requires our Utility to maintain, on
average, its CPUC-authorized capital structure, potentially limiting the amount
of dividends our Utility may pay PG&E Corporation. At December 31, 1997, our
Utility was in compliance with its CPUC-authorized capital structure. We believe
that our Utility will continue to meet this condition in the future without
affecting our ability to pay common stock dividends to common shareholders.
Financial Condition
We begin this section by discussing the energy industry. We also discuss how the
Corporation is responding to restructuring on a national level, including recent
and planned acquisitions. We then discuss liquidity and capital resources and
our risk management activities.
Energy Industry:
The Electric Business:
California has been in the forefront of the nation's move towards competitive
energy markets. In 1998, Californians will be able to choose who will provide
their electric power. Customers within our Utility's service territory can
purchase electricity (1) from our Utility, (2) from retail electricity providers
(for example, marketers including our energy service subsidiary, brokers, and
aggregators), or (3) directly from unregulated power generators. Our Utility
will continue to provide distribution services to substantially all electric
consumers within its service territory.
To create this competitive generation market, California has established a
Power Exchange (PX) and an Independent Systems Operator (ISO). The PX will be an
open electric marketplace where electricity prices are set. The ISO will oversee
California's electric transmission grid making sure that all generators have
comparable access. California utilities will retain ownership of utility
transmission facilities but will relinquish operating control to the ISO.
Competing electric providers will bid their electric commodity into the PX. The
PX will accept the lowest bids to satisfy the aggregate electric demand and
establish a market price. Customers choosing to buy power directly from non-
regulated generators or retailers will pay for that generation based upon
negotiated contracts. The PX and ISO are expected to be operational by March 31,
1998.
CPUC regulation requires our Utility to purchase all electric power for its
retail customers from the PX. And, we must bid all of our Utility-generated
electric power to the PX.
Generation revenues currently make up approximately 30 percent of our total
Utility revenues. The competitive market environment will significantly change
the way our Utility earns revenues. Over the past several years, we have been
taking steps to prepare for these changes. We have been working with the CPUC to
ensure a smooth transition into the competitive market environment. And, we have
made strategic investments throughout the nation that will further position us
as a national energy provider. The following sections discuss the transition
plan. A discussion of the investments we have made is included in Our Response
to Changes in Our Industry, below.
ELECTRIC TRANSITION PLAN
In the new competitive market, our Utility's generation revenues will be
determined principally by the market through sales to the PX. However, market-
based revenues may not be sufficient to recover (that is, to collect from
customers) all generation costs resulting from past CPUC decisions. To recover
these uneconomic costs, called "transition costs," and to ensure a smooth
transition to the competitive environment, our Utility in conjunction with other
California electric utilities, the CPUC, state legislators, consumer advocates,
and others, developed a transition plan, in the form of state legislation, to
position California for the new market environment.
20
There are three principal elements to this transition plan: (1) an electric
rate freeze and rate reduction, (2) recovery of transition costs, and (3)
economic divestiture of Utility-owned generation facilities. Each one of these
three elements, the impact of the transition plan on our Utility's customers,
and the impact of the transition plan on our application of Statement of
Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of
Certain Types of Regulation," are discussed below. The transition plan will
remain in effect until the earlier of March 31, 2002, or when we have recovered
our authorized transition costs as determined by the CPUC. This period is
referred to as the transition period. At the conclusion of the transition
period, we will be at risk to recover any of our Utility's remaining generation
costs through market-based revenues.
. Rate Freeze and Rate Reduction
The first element of the transition plan is an electric rate freeze and an
electric rate reduction. During 1997, electric rates for our Utility's customers
were held at 1996 levels. Effective January 1, 1998, we reduced electric rates
for our Utility's residential and small commercial customers by 10 percent and
will hold their rates at that level. The rate freeze will continue until the end
of the transition period.
To pay for the 10 percent rate reduction, we financed $2.9 billion of our
transition costs with rate reduction bonds. See Cash Flows from Financing
Activities below.
. Transition Cost Recovery
The second element of the transition plan is recovery of transition costs.
Transition cost recovery has five parts for determining: (1) which costs are
eligible for recovery as transition costs, (2) when they can be recovered, (3)
how transition cost revenues will be determined, (4) how transition costs will
be expensed, and (5) what happens when transition cost revenues differ from the
related expenses. Each of these five parts is discussed below.
The first part of transition cost recovery is determining which Utility costs
are eligible for recovery as transition costs. These costs include: (1) above-
market sunk costs (sunk costs are costs associated with Utility-owned generating
facilities that are fixed and unavoidable and currently included in our Utility
customers' electric rates) and future costs, such as costs related to plant
removal, (2) costs associated with the Utility's long-term contracts to purchase
power at above-market prices from Qualifying Facilities (QF) and other power
suppliers, and (3) generation-related regulatory assets and obligations. (In
general, regulatory assets are expenses deferred in the current or prior periods
to be included in rates in subsequent periods.) Transition costs that are
disallowed by the CPUC for collection from Utility customers will be written
off. Each of the types of eligible transition costs are discussed below.
Sunk costs associated with Utility-owned generation facilities are currently
included in our Utility customers' rates. Above-market sunk costs are those
whose values recorded on our balance sheet (book value) are expected to be in
excess of their market values. Conversely, below-market sunk costs are those
whose market values are expected to be in excess of their book values. In
general, the total amount of sunk costs to be included as transition costs will
be based on the aggregate of above-market and below-market values. The above-
market portion of sunk costs is eligible for recovery as a transition cost. The
below-market portion of sunk costs will reduce other unrecovered transition
costs. A valuation of Utility-owned generation facilities where the market value
exceeds the book value could result in a material charge if the Utility retains
the facility. This is because any excess of market value over book value would
be used to reduce other transition costs without being collected in rates.
We will not be able to determine the exact amount of sunk costs that will be
recoverable as transition costs until a market valuation process (appraisal,
spin, or sale) is completed for each of our Utility's generation facilities. The
first of these valuations occurred in 1997 when we agreed to sell three Utility-
owned electric plants for $501 million. The sale is expected to close during
1998. (See Generation Divestiture below.) The rest of the valuation process will
be completed by December 31, 2001. At December 31, 1997, our Utility's net
investment in Diablo Canyon and Utility-owned non-nuclear generation facilities
was $3.7 billion and $2.7 billion, respectively, including the plants to be sold
in 1998.
21
Management's Discussion and Analysis of
Consolidated Results of Operations and Financial Condition
Our Utility has agreed to purchase electric power from QFs and other power
suppliers under long-term contracts expiring on various dates through 2028. Over
the life of these contracts, the Utility estimates that it will purchase
approximately 360 million megawatt-hours (MWh) at an aggregate average price of
6.3 cents per kilowatt-hour (kWh). To the extent that this price is above the
market price, our Utility will be able to collect the difference between the
contract price and the market price from customers, as a transition cost, over
the term of the contract.
In addition, as of December 31, 1997, we have accumulated approximately $1.5
billion of generation-related net regulatory assets. The net regulatory assets
are eligible for recovery as transition costs.
The CPUC has the ultimate authority to determine which costs are eligible to
be recovered as transition costs. Reviews by the CPUC to determine the
reasonableness of transition costs are being conducted and will continue to be
conducted throughout the transition period.
The second part of transition cost recovery is determining when eligible
transition costs can be recovered. Under the transition plan, most transition
costs must be recovered by March 31, 2002. This recovery period is significantly
shorter than the recovery period of the related assets prior to restructuring.
Recovery of transition costs during this shorter period is referred to as
accelerated recovery. The CPUC believes that acceleration reduces risks
associated with recovery of all our Utility's generation assets, including
Diablo Canyon and hydroelectric facilities. As a result, in accordance with the
transition plan, we are receiving a reduced return for all of our Utility-owned
generation facilities. In 1997, the reduced return was 7.13 percent as compared
to an authorized return of 9.45 percent. The reduced return on non-nuclear
generation assets, effective July 28, 1997, resulted in a $24 million decrease
in earnings ($0.06 per share) in 1997 and will have a continued impact
throughout the transition period.
Although most transition costs must be recovered by March 31, 2002, certain
transition costs can be included in customers' electric rates after the
transition period. These costs include: (1) certain employee-related transition
costs, (2) above-market payments under existing QF and power-purchase contracts
discussed above, and (3) unrecovered electric industry restructuring
implementation costs. In addition, transition costs financed by the issuance of
rate reduction bonds are expected to be recovered over the term of the bonds.
Further, the Utility's nuclear decommissioning costs are being recovered through
a CPUC-authorized charge, which will extend until sufficient funds exist to
decommission the facility. During the rate freeze, this charge will not increase
our Utility customers' electric rates. Excluding these exceptions, we will
write-off any transition costs not recovered during the transition period.
The third part in transition cost recovery is determining the amount of
electric utility revenues under frozen rates that are available to recover
eligible transition costs. As directed by the CPUC, we have separated, or
unbundled, the Utility's previously authorized cost-of-service electric revenues
into separate categories. Unbundling enables us to allocate revenue provided by
frozen electric rates into transmission, distribution, public purpose programs,
and generation based upon their respective cost of service. Revenues provided by
frozen rates will also be used to recover other authorized Utility costs,
including nuclear decommissioning, rate reduction bond debt service, and
transition cost recovery.
The portion of the unbundled revenue to be provided for transition cost
recovery is based upon mechanisms approved by the CPUC. Revenue provided for
recovery of most non-nuclear transition costs is based upon their acceleration
within the transition period. For nuclear transition costs, revenues provided
for transition cost recovery are based on: (1) an established Incremental Cost
Incentive Price per kWh generated by Diablo Canyon to recover certain ongoing
costs and capital additions, and (2) the acceleration of our investment in
Diablo Canyon from a period ending in 2016 to a five-year period ending December
31, 2001.
The fourth part of transition cost recovery addresses the depreciation and
amortization of transition costs. Based on our Utility's evaluation of the
transition plan and state legislation and CPUC decisions related to the
transition plan, our Utility is depreciating Diablo Canyon over a five-year
period ending December 31, 2001. The change in depreciable life increased Diablo
Canyon's depreciation expense for 1997, as
22
compared to 1996, by $583 million. In addition, most generation-related
regulatory assets are being amortized on a straight-line basis, in accordance
with their recovery under the transition plan, beginning January 1, 1998.
Further, upon valuation of generation facilities, any losses will be amortized
over the remaining transition period as a transition cost. Any gains will be
recognized and used to reduce other transition costs at the time of valuation.
In the fifth part of transition cost recovery we compare (1) revenues provided
for transition cost recovery with (2) the costs associated with accelerated
recovery including the depreciation of Diablo Canyon and the amortization of
regulatory assets. If the revenues exceed the accelerated costs, certain
transition costs may be further accelerated until all transition costs are
recovered or March 31, 2002, whichever is earlier. If the accelerated costs
exceed the revenues, the costs will be deferred. At the end of the transition
period, any over collection of these amounts will be returned to customers.
Our Utility's ability to recover its transition costs during the transition
period will be dependent on several factors. These factors include: (1) the
continued application of the regulatory framework established by the CPUC and
state legislation, (2) the amount of transition costs approved by the CPUC, (3)
the market value of our Utility-owned generation facilities, (4) future Utility
sales levels, (5) future Utility fuel and operating costs, (6) the extent to
which our Utility's authorized revenues to recover distribution costs are
increased or decreased, and (7) the market price of electricity. Given our
current evaluation of these factors, we believe that we will recover our
transition costs. Also, we believe that our regulatory assets and Utility-owned
generation plants are not impaired. However, a change in one or more of these
factors could affect the probability of recovery of transition costs and result
in a material charge.
During 1997, the difference between billed revenues and authorized revenues
was used to recover transition costs, including most of the accelerated Diablo
Canyon sunk costs.
. Generation Divestiture
The third element of the transition plan is the economic divestiture of Utility-
owned generation facilities. In 1997, California utilities produced a
significant portion of the state's electric generation needs. In a competitive
market, the CPUC is concerned that this level of generation may give existing
utilities undue influence on the PX price. As part of the transition plan, we
have agreed to sell a significant portion of our generation facilities to
alleviate this concern.
In 1997, we agreed to sell three electric Utility-owned fossil-fueled
generating plants to Duke Energy through an auction process. The aggregate bid
accepted for these plants was $501 million. These three fossil-fueled plants
have a combined book value at December 31, 1997, of approximately $370 million
and a combined capacity of 2,645 megawatts (MW). The three power plants were
Morro Bay, Moss Landing, and Oakland.
The sales have been approved by the CPUC. However, they are still subject to
approval of the transfer of various permits and licenses. Additionally, the
Utility will retain liability for required environmental remediation of any pre-
closing soil or groundwater contamination at these plants. As a result of
retaining such environmental remediation liability, we do not expect any
material adverse impact on the Utility's or our financial position or results of
operations. We expect the sale of these three plants to close in 1998.
We plan to conduct another auction of our four remaining Utility-owned fossil-
fueled plants and our Utility-owned geothermal facilities in the first half of
1998. These additional plants have a combined generating capacity of 4,718 MW
and a combined book value at December 31, 1997, of approximately $790 million.
Together the eight power plants represent 98 percent of the Utility's fossil-
fueled generating capacity and all of the Utility's geothermal generating
capacity. The eight plants currently generate approximately 22 percent of the
Utility's total electric sales. The Utility is currently evaluating its options
related to its remaining generation facilities and may decide not to retain its
economic investment in those facilities. During the transition period, the
proceeds from the sale of our plants will be used to offset transition costs
associated with other Utility electric generation facilities. Therefore, we do
not expect any material adverse impact on the Utility's or our financial
position or results of operations
23
Management's Discussion and Analysis of
Consolidated Results of Operations and Financial Condition
from any of these divestitures.
. Customer Impacts of Transition Plan
Under the transition plan, once the PX and ISO are operational, all electric
customers may choose their electric commodity provider. During the transition
period, all customers will be billed for electricity used, for transmission and
distribution services, for public purpose programs, and for recovery of
transition costs. Customers who choose to purchase their electricity from non-
Utility energy providers will see a change in their total bill only to the
extent that their contracted electric commodity price differs from the PX price.
Transition costs are being recovered from all Utility distribution customers
through a nonbypassable charge regardless of their choice in commodity provider.
As transition costs are nonbypassable, we do not believe that the availability
of choice to our customers will have a material impact on our ability to recover
transition costs.
In addition to supplying commodity electric power, once the ISO and PX are
operational, commodity electric providers will be able to choose the method of
billing their customers and whether to provide their customers with metering
services. We will track cost savings that result when billing, metering, and
related services within our Utility's service territory are provided by another
entity. Once these cost savings, or credits, are approved by the CPUC and the
customer's energy provider is performing billing and metering services, we will
reduce the customer's bill by the savings. The electric provider will then
charge their customers for these services. To the extent that these credits
equate to our actual cost savings from reduced billing, metering, and related
services, we do not expect a material adverse impact on the Utility's or our
financial condition or results of operations.
. The Transition Plan and SFAS No. 71
In 1997, to comply with new accounting guidance, we discontinued the application
of SFAS No. 71 for the generation portion of our Utility business. The new
accounting guidance requires that regulatory assets and liabilities (both those
in existence today and those created under the terms of the transition plan) be
allocated to the portion of the business from which the source of the regulated
cash flows is derived. Under the transition plan, generation-related regulatory
assets are eligible for recovery as transition costs from customers of our
Utility's electric distribution business. Accordingly, they have been allocated
to that business. As we believe the recovery of our transition costs from these
customers is probable, the discontinuation of application of SFAS No. 71 to our
Utility's generation business did not have a material effect on our financial
statements. As of December 31, 1997, we have recorded approximately $1.5 billion
of generation-related regulatory assets.
Given the current regulatory environment, our Utility's electric transmission
business and most areas of the Utility's electric distribution business are
expected to remain rate regulated and, as a result, we will continue to apply
the provisions of SFAS No. 71. However, as discussed above, once the ISO and PX
are operational, unregulated electric providers may provide their customers with
billing and metering services. In the future, electric providers may be allowed
to provide other distribution services (such as customer inquiries and
uncollectibles). Any discontinuance of SFAS No. 71 for these portions of our
Utility electric distribution business is not expected to have a material
adverse impact on the Utility's or our financial position or results of
operations.
The Gas Business:
Through our Utility, we sell natural gas and provide natural gas transportation
services to our customers. Currently, our customers may buy gas directly from
competing suppliers and purchase gas transmission- and distribution-only
services from us. Our Utility transmission system transports gas throughout
California to our distribution system which, in turn, delivers gas to end-use
customers. Utility transmission and distribution services for all customers have
historically been "bundled" or sold together at a combined rate. Most of our
industrial and larger commercial (noncore) customers purchase their commodity
gas from marketers and brokers. Substantially all residential and smaller
commercial (core) customers buy their commodity gas as well as transmission and
distribution services from us. In order to ensure competitive prices for our
customers, we negotiate short-term supply arrangements with numerous providers.
24
Restructuring of the natural gas industry on both the national and the state
level has given choices to California utility customers to meet their gas supply
needs. The Gas Accord Settlement (Accord), a multi-party settlement approved by
the CPUC in 1997, continues the process of restructuring the gas industry in
California. The Accord is expected to be implemented in March 1998. More
specifically, the Accord has four principal elements:
1. The Accord separates or "unbundles" the rates for our Utility's gas
transportation system. Once the Accord is implemented, we will offer
transmission and distribution services as separate and distinct services to
our noncore customers. Unbundling will give these customers the opportunity
to select from a menu of services offered by the Utility and will enable
them to pay only for the services that they use. Unbundling will also make
access to the transmission system possible for all gas marketers and
shippers, as well as noncore end-users. As a result, the Accord will make
our Utility's transmission system more accessible to a greater number of
customers.
2. The Accord increases the opportunity for our Utility's core customers to
select the commodity gas supplier of their choice. Greater customer choice
will increase competition among suppliers providing gas to core customers
and will reduce our role in purchasing gas for such customers. Despite these
changes, we will continue to purchase gas as a regulated supplier for those
who request it.
3. The Accord changes the way in which our Utility's costs of purchasing gas
for core customers through 2002 are regulated. Prior to 1994, we were
authorized to collect all costs of purchased gas through rates as long as
the CPUC deemed the costs to be reasonable. The Accord replaces the CPUC
reasonableness reviews with the core procurement incentive mechanism (CPIM),
a form of incentive ratemaking. Apart from a "tolerance band" constructed
around market benchmarks, the CPIM will reward us if we are able to buy gas
for our core customers at a price below a specified market index price and
penalize us if we buy gas at a price above the market index price. Actual
core procurement costs measured from 1994 through 1997 have generally been
within the CPIM tolerance band.
4. The Accord settled various regulatory issues involving our Utility and
various other parties. Resolution of these issues did not have a material
adverse impact on the Utility's or our financial position or results of
operations.
The Accord also establishes gas transmission rates for the period from March
1998 through December 2002 for our Utility's core and noncore customers and
eliminates regulatory protection for variations in sales volumes for noncore
transmission revenues. As a result, we will be at risk for variations between
actual and forecasted noncore transmission throughput volumes. However, we do
not expect these variations to have a material adverse impact on the Utility's
or our financial position or results of operations. Rates for distribution
services will continue to be set by the CPUC and designed to provide us an
opportunity to recover our costs of service and include a return on our
investment.
Our Response to Changes in Our Industry:
ACQUISITIONS AND SALES
Over the past several years, we have taken steps to take advantage of the
changing electric and gas markets and to become a national energy company. In
order to accomplish this, we have made several investments to position ourselves
to expand and to integrate in the gas transmission market, the energy trading
market, the retail energy services market, and the unregulated electric
generation market. These investments are highlighted below.
In 1997, we created a gas transmission business in Texas, through the
acquisitions of Teco Pipeline Company (Teco) and Valero Energy Corporation's
(Valero) natural gas and natural gas liquids business. Teco was acquired for
approximately $378 million, consisting of $317 million of PG&E Corporation
common stock and the purchase of a $61 million note. Valero was acquired for
approximately $1.5 billion, consisting of 31 million shares of PG&E Corporation
common stock along with the assumption of approximately $780 million in long-
term debt. Valero pipeline operations have averaged approximately $147 million
in revenues and expenses each month since August 1997. Teco pipeline operations
have averaged approximately $6 million in revenues and expenses each month since
January 1997.
Further, in 1997, we strengthened our presence in the
25
Management's Discussion and Analysis of
Consolidated Results of Operations and Financial Condition
unregulated electric generation market. We completed our acquisition of our
partner's interests in three U.S. Generating Company (USGen) partnerships we
previously jointly owned with Bechtel Enterprises, Inc. (Bechtel). We are now
the sole owner of USGen, the largest independent power developer and manager
operating in the United States, U.S. Operating Services Company, USGen's
operations and maintenance affiliate, and its power marketing affiliate USGen
Power Services, L.P. Additionally, we have acquired all or part of Bechtel's
interest in several power projects that are affiliated with USGen. Through its
affiliates, USGen has ownership or management interests in 15 electric
generating facilities operating in eight states.
Additionally, in 1997, USGen was selected to buy a portfolio of electric
generating assets and power supply contracts from the New England Electric
System (NEES) for $1.59 billion, plus $85 million for early retirement and
severance costs previously committed to by NEES. Including fuel and other
inventories and transaction costs, financing requirements are expected to total
approximately $1.75 billion, of which approximately $1 billion will be funded
through a combination of project level debt as well as debt of USGen. In
addition, $750 million of equity will be contributed over two years and will be
financed initially using short-term debt of PG&E Corporation. The assets contain
a balance of hydro, coal, oil, and natural gas generation facilities. The
acquisition is subject to regulatory approval, among other conditions. We expect
the acquisition to be completed in the second half of 1998.
Maximizing the benefits of the gas transmission, electric generation, and
energy service supply businesses on a national level requires procurement,
scheduling, and risk management capabilities. In order to assure the efficient
management of the risks and rewards of supplying our customers' energy needs and
to optimize our corporate assets, we have combined the trading and risk
management businesses of Energy Source (acquired in 1996), Teco, and Valero to
form PG&E Energy Trading (PG&E ET). PG&E ET purchases and resells energy
commodities and related financial instruments in major domestic markets, serving
PG&E Corporation's other unregulated businesses, unaffiliated utilities, and
large end-use customers.
Our national energy strategy does not currently contemplate continued
investment in international generation projects. Therefore, in 1997, we sold to
Bechtel our interest in International Generating Company, Ltd., a joint venture
between PG&E Corporation and Bechtel, together with all of our related project
interests. The sale has resulted in an after-tax gain of approximately $120
million, which was recorded in 1997.
REGULATORY ACTIVITY
This section discusses items affecting future Utility authorized revenues: the
1999 General Rate Case; a 1998 Revenue Adjustment associated with the electric
transition plan, discussed above; and the 1998 Cost of Capital Proceeding. Any
requested change in authorized electric revenues resulting from any of these
proceedings would not impact our Utility's customer electric rates because these
rates are frozen in accordance with the electric transition plan. However,
increases in authorized electric revenues would reduce the amount of revenue
available to recover transition costs.
. The Utility's 1999 General Rate Case (GRC)
In December 1997, we filed our 1999 GRC application with the CPUC. During the
GRC process, the CPUC examines our Utility's non-fuel related costs to determine
the amount we can charge customers. In our application, we requested an increase
in our Utility's authorized revenues, effective January 1, 1999. The requested
increase consists of an increase of $693 million in electric utility revenues
and an increase of $501 million in gas utility revenues over authorized 1997
revenues.
The 1999 GRC will not affect the authorized revenues of electric and gas
transmission services or of gas storage services. The authorized revenues for
each of these services are determined in other proceedings.
Electric transmission revenues for 1998 are expected to be authorized by the
FERC. In 1997, we filed an application with the FERC requesting electric
transmission revenues of $305 million. The requested revenue is consistent with
electric transmission revenues in CPUC-authorized 1997 electric rates. The FERC-
authorized rates will be effective
26
once the ISO and PX are operational.
Also, revenues associated with gas transmission and storage services were
authorized as part of the Gas Accord. See Gas Business, above, for a discussion
of the Gas Accord.
. The Utility's 1998 Electric Revenue Adjustment
The electric transition plan (see Electric Business above) allows for increases
in revenues previously authorized in the 1996 GRC for system safety and
reliability. The CPUC increased 1997 authorized revenues for these services by
$160 million. The CPUC also authorized an additional $86 million in 1998 for
system safety and reliability.
. The Utility's 1998 Cost of Capital Proceeding
The CPUC authorized a cost of capital for the Utility's gas and electric
distribution assets in 1998 of 9.17 percent. The authorized 1998 cost of common
equity is 11.20 percent which is lower than the 11.60 percent authorized for
1997. The CPUC contends that this decrease reflects the level of business and
regulatory risks the Utility now faces. The authorized cost of capital will
decrease 1998 authorized electric and gas revenue by approximately $25 million
and $9 million, respectively. The Utility has requested a rehearing of the Cost
of Capital decision. We believe that business and regulatory risks have not been
reduced and that our requested cost of common equity of 12.25 percent is more
appropriate. The rehearing is expected to occur in 1998.
Consistent with the rate freeze, there will be no change in electric rates in
1998 and the lower authorized revenues will be offset by additional transition
cost recovery. As discussed above, the CPUC separately reduced the authorized
return on our Utility's electric generation-related assets to 7.13 percent.
Also, the return on our Utility's electric transmission-related assets will be
determined by the FERC in 1998. Finally, the return on our Utility's gas
transmission and storage businesses was incorporated in rates established in the
Gas Accord.
Liquidity and Capital Resources:
Cash Flows from Operating Activities:
Net cash provided by operating activities totaled $2.6, $2.6, and $3.3 billion
in 1997, 1996, and 1995, respectively. Cash from operations exceeded capital
requirements for all years presented.
Cash Flows from Financing Activities:
PG&E CORPORATION
During 1997, we issued $752 and $317 million of common stock to acquire Valero
and Teco, respectively. These acquisitions did not require the use of cash. We
also issued $54 million of common stock through the Dividend Reinvestment Plan
and the employee Long-Term Incentive Plan. Also in 1997, we repurchased $804
million of our common stock on the open market and paid dividends of $524
million.
During 1996 and 1995, we issued $220 and $140 million shares of common stock,
respectively, through the employee Savings Fund Plan, the Dividend Reinvestment
Plan, and the employee Long-Term Incentive Plan. In 1996, we repurchased $455
million shares of our common stock and paid dividends of $844 million. In 1995,
we repurchased $601 million shares of our common stock and paid dividends of
$891 million.
In previous years, the Board of Directors (Board) authorized us to repurchase
up to $2 billion of our common stock on the open market or in negotiated
transactions. In 1997, the Board increased this authorization to a total of $4
billion. Through December 31, 1997, the Corporation had repurchased
approximately $2.3 billion of its common stock under this program. As part of
this Board authorization, in January 1998, the Corporation entered into a
specific transaction to repurchase 37 million shares of common stock at $30.3125
per share. In connection with this transaction, the Corporation has entered into
a forward contract with an investment institution. The Corporation will retain
the risk of increases and the benefit of decreases in the price of the common
shares purchased through the forward contract. This obligation will not be
terminated until the investment institution has replaced the shares sold to the
Corporation through purchases on the open market or through privately negotiated
transactions. The contract is anticipated to expire by December 31, 1998.
In January 1997, we established a $500 million revolving credit facility, and
in August 1997, we entered into an
27
Management's Discussion and Analysis of
Consolidated Results of Operations and Financial Condition
additional $500 million temporary credit facility. Both of these credit
facilities are to be used for general corporate purposes. There were no
borrowings under these facilities at December 31, 1997.
During 1997, our unregulated business operations issued $30 million and
retired $109 million of long-term debt. Also in 1997, we assumed approximately
$780 million of long-term debt in connection with the acquisition of Valero.
In 1996, we entered into additional loan agreements of $92 million to finance
the PG&E Gas Transmission acquisition of assets in Queensland, Australia.
During 1995, our unregulated business operations issued $400 million of bonds,
$70 million of medium-term notes, and $109 million of commercial paper which is
classified as long-term debt. Substantially all of the proceeds from the debt
issued in 1995 were used to refinance outstanding debt. The classification of
commercial paper as long-term debt is based on the availability of committed
credit facilities expiring in 2000 and management's intent to maintain such
amounts in excess of one year.
UTILITY
In 1997, 1996, and 1995, our Utility redeemed or repurchased $225, $1,113, and
$758 million, respectively, of long-term debt to manage the overall balance of
our Utility's capital structure. Long-term debt maturing during 1997, 1996, and
1995 was not refinanced.
In 1997, our Utility issued $360 million of variable rate pollution control
bonds and repurchased the same amount of fixed-rate pollution control bonds.
In 1996, our Utility repurchased $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.
In December 1997, a subsidiary of the Utility issued $2.9 billion of rate
reduction bonds through a special purpose entity established by the California
Infrastructure and Economic Development Bank. The proceeds will be used by the
Utility to retire debt and reduce equity. The bonds will facilitate a 10 percent
rate reduction for residential and eligible small commercial customers,
effective January 1, 1998. During the term of the bonds, the Utility will
collect from its residential and small commercial customers a separate
nonbypassable charge on behalf of the special purpose entity to recover
principal, interest, and related costs of the bonds. The bonds are secured by
the separate charge, which does not belong to the Utility. The bonds are not
secured by the Utility's assets. While the bonds are reflected as a long-term
liability on our balance sheet, creditors of the Utility do not have any
recourse to revenues from the separate charge.
The Utility maintains a $1 billion revolving credit facility which expires in
2002. The facility may be extended annually for additional one-year periods upon
mutual agreement between the Utility and the banks. There were no borrowings
under this credit facility in 1997 or 1996.
The table below provides information about our debt obligations and the rate
reduction bonds at December 31, 1997:
Expected maturity date 1998 1999 2000 2001 2002 Thereafter Total(1)
- ----------------------------------------------------------------------------------------------------
(in millions)
Long-term debt
Fixed rate $659 $294 $460 $330 $515 $4,712 $6,970
Average interest rate 5.8% 6.3% 6.0% 7.8% 7.7% 7.2% 6.9%
Variable rate - - - - - $1,348 $1,348
Rate reduction bonds $125 $265 $280 $300 $290 $1,641 $2,901
Average interest rate 5.9% 6.0% 6.2% 6.2% 6.3% 6.4% 6.3%
(1) The fair value of long-term debt and rate reduction bonds is essentially the
same as the book value.
28
Cash Flows from Investing Activities:
The primary uses of cash for investing activities are additions to property,
plant, and equipment; unregulated investments in partnerships; and acquisitions.
Capital Spending:
Our estimated capital spending for the next three years is shown below:
Year ended December 31, 1998 1999 2000
- --------------------------------------------------------------
(in millions)
Utility capital requirements $1,835 $1,739 $1,617
Other capital requirements 2,091 246 192
Maturing debt obligations and
sinking funds 784 559 740
--------------------------
Total $4,710 $2,544 $2,549
==========================
Utility expenditures will be primarily for improvements to facilities to
enhance their efficiency and reliability, to extend their useful lives, and to
comply with environmental laws and regulations.
Other capital expenditures will be primarily for the purchase of electric
generating assets and power supply contracts for NEES, discussed above in
Acquisitions and Sales.
Environmental Matters:
We are subject to laws and regulations established to both improve and maintain
the quality of the environment. Where our properties contain hazardous
substances, these laws and regulations require us to remove or remedy the effect
on the environment.
At December 31, 1997, the Utility expects to spend $232 million for clean-up
costs at identified sites over the next 30 years. If other responsible parties
fail to pay or identified outcomes change, then these costs may be as much as
$442 million. Of the $232 million, the Utility expects to recover $157 million
in future rates. The liability also includes $58 million related to power plant
decommissioning for environmental clean-up, which the Utility recovered through
depreciation. Additionally, the Utility is seeking recovery of costs from
insurance carriers and from other third parties. (See Note 13 of Notes to
Consolidated Financial Statements.)
Year 2000:
In 1995, we began and presently continue to review and assess our computer and
information systems in anticipation of the year 2000. At that time, our software
programs and systems for critical financial and operational information will be
required to recognize this date in the next millennium. The Year 2000 issue
exists because many computer programs use only two digits to identify a year in
the date field and were developed without considering the impact of the upcoming
change in the century. We currently expect to complete critical software
conversion modifications by the end of 1998. We do not currently anticipate any
material adverse impact on the Utility's or our financial position or results of
operations as a result of the Year 2000 issue.
Accounting for Decommissioning Expense:
In 1996, the Financial Accounting Standards Board issued an Exposure Draft (ED)
entitled "Accounting for Certain Liabilities Related to Closure and Removal of
Long-Lived Assets." A revised ED is expected in 1998. If the ED is adopted as
currently proposed: (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.
We do not believe that this change, if implemented as proposed, would have a
material adverse impact on the Utility's or our financial position or results of
operations. (See Note 2 of Notes to Consolidated Financial Statements for
discussion of electric industry restructuring.)
Legal Matters:
In the normal course of business, the Corporation and the Utility are 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 Utility's or
our financial position or results of operations. See Note 13 of Notes to
Consolidated Financial Statements for further discussion of significant pending
legal matters.
29
Inflation:
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 our construction costs, operating expenses, and interest
charges. In addition, the Utility's electric revenues will not reflect the
impact of inflation due to the current electric rate freeze. However, inflation
at the levels currently being experienced is not expected to have a material
adverse impact on the Utility's or our financial position or future results of
operations.
Price Risk Management: We have established an officer-level price risk
management committee and adopted a price risk management policy approved by the
Board for our trading and risk management activities. The price risk management
committee oversees implementation of our policy, approves the trading and price
risk management policies of our subsidiaries, and monitors compliance with the
policy.
Our price risk management policy allows derivatives to be used for both
hedging and non-hedging purposes (a derivative is a contract whose value is
dependent on or derived from the value of some underlying asset). We use
derivatives for hedging purposes primarily to offset underlying commodity price
risks. We also participate in markets using derivatives to create liquidity and
maintain a market presence. Such derivatives include forward contracts, futures,
swaps, and options. Our price risk management policy and the trading and risk
management policies of our subsidiaries prohibit the use of derivatives whose
payment formula includes a multiple of some underlying asset.
In 1997, we approved and implemented trading and risk management policies for
PG&E ET and continued to seek regulatory approval to manage commodity price
risks in our Utility business.
The fair value of market risk sensitive instruments (which includes our
hedging and non-hedging instruments described above) as of December 31, 1997, is
immaterial for financial instruments subject to commodity price risk.
Additionally, as of December 31, 1997, the Corporation calculated value-at-risk
based on a 95 percent confidence level using five-day holding periods. Using
this methodology, the potential for near-term losses in future earnings, fair
values, and cash flows from reasonably possible near-term changes in market
prices for financial instruments subject to commodity price risk is immaterial.
We anticipate an increase in the level of trading and risk management activity
in 1998 due to expected growth in our unregulated national energy businesses and
a continuing effort to manage anticipated price risks in our Utility business.
Our Utility manages price risk independently from the activities in our
unregulated businesses.
30
PG&E Corporation
Statement of Consolidated Income
(in millions, except per share amounts) Year ended December 31, 1997 1996 1995
- ------------------------------------------------------------------------------------------------------------------
Operating Revenues
Utility $ 9,495 $8,989 $9,243
Energy commodities and services 5,905 621 379
------------------------------------
Total operating revenues 15,400 9,610 9,622
------------------------------------
Operating Expenses
Cost of energy for utility 2,974 2,709 2,403
Cost of energy commodities and services 5,511 356 47
Operating and maintenance 3,298 3,427 3,049
Depreciation and decommissioning 1,889 1,222 1,360
------------------------------------
Total operating expenses 13,672 7,714 6,859
------------------------------------
Operating Income 1,728 1,896 2,763
Interest expense, net (665) (632) (678)
Other income and expense 201 13 79
------------------------------------
Income Before Income Taxes 1,264 1,277 2,164
Income taxes 548 555 895
------------------------------------
Net Income $ 716 $ 722 $1,269
====================================
Weighted Average Common Shares Outstanding 410 413 424
Earnings Per Common Share, Basic and Diluted $ 1.75 $ 1.75 $ 2.99
Dividends Declared Per Common Share $ 1.20 $ 1.77 $ 1.96
The accompanying Notes to the Consolidated Financial Statements are an integral part of this statement.
31
PG&E Corporation
Consolidated Balance Sheet
(in millions) At December 31, 1997 1996
- ------------------------------------------------------------------------------
Assets
Current Assets
Cash and cash equivalents $ 237 $ 131
Short-term investments 1,160 13
Accounts receivable
Customers, net 1,514 1,152
Regulatory balancing accounts 658 444
Energy marketing 830 387
Inventories and prepayments 626 584
-------- --------
Total current assets 5,025 2,711
Property, Plant, and Equipment
Utility 32,972 31,716
Gas transmission 3,484 1,594
Other 57 -
-------- --------
Total property, plant, and equipment (at original cost) 36,513 33,310
Accumulated depreciation and decommissioning (16,041) (14,302)
-------- --------
Net property, plant, and equipment 20,472 19,008
Other Noncurrent Assets
Regulatory assets 2,337 2,518
Nuclear decommissioning funds 1,024 883
Other 1,699 1,117
-------- --------
Total noncurrent assets 5,060 4,518
-------- --------
Total Assets $ 30,557 $ 26,237
======== ========
32
PG&E Corporation
Consolidated Balance Sheet
(in millions) At December 31, 1997 1996
- ------------------------------------------------------------------------------------------------------------------
Liabilities and Equity
Current Liabilities
Short-term borrowings $ 103 $ 681
Current portion of long-term debt 659 210
Current portion of rate reduction bonds 125 -
Accounts payable
Trade creditors 754 490
Other 620 548
Energy marketing 758 388
Accrued taxes 226 310
Other 739 653
----------------------
Total current liabilities 3,984 3,280
Noncurrent Liabilities
Long-term debt 7,659 7,770
Rate reduction bonds 2,776 -
Deferred income taxes 4,029 3,941
Deferred tax credits 339 380
Other 2,034 1,663
----------------------
Total noncurrent liabilities 16,837 13,754
Preferred Stock of Subsidiary With Mandatory Redemption Provisions
6.30% and 6.57%, outstanding 5,500,000 shares, due 2002-2009 137 137
Utility Obligated Mandatorily Redeemable Preferred Securities of
Trust Holding Solely Utility Subordinated Debentures,
7.90%, 12,000,000 shares, due 2025 300 300
Stockholders' Equity
Preferred stock of subsidiary, par value $25, authorized 75,000,000 shares
Without mandatory redemption provisions
Nonredeemable-5% to 6%, outstanding 5,784,825 shares 145 145
Redeemable-4.36% to 7.44%, outstanding 10,297,404 shares 257 257
Common stock, no par value, authorized 800,000,000 shares; issued and outstanding,
417,665,891 and 403,504,292 shares 6,366 5,728
Reinvested earnings 2,531 2,636
----------------------
Total stockholders' equity 9,299 8,766
Commitments and Contingencies (Notes 1, 2, 3, 4, 12, and 13) - -
----------------------
Total Liabilities and Stockholders' Equity $30,557 $ 26,237
======================
The accompanying Notes to the Consolidated Financial Statements are an integral part of this statement.
33
PG&E Corporation
Statement of Consolidated Cash Flows
(in millions) Year ended December 31, 1997 1996 1995
- -------------------------------------------------------------------------------------------------------------------------
Cash Flows From Operating Activities
Net income $ 716 $ 722 $ 1,269
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, decommissioning, and amortization 2,014 1,316 1,449
Deferred income taxes and tax credits-net (159) (150) (116)
Other deferred charges and noncurrent liabilities 159 22 (25)
Gain on sale of assets (120) - -
Net effect of changes in operating assets and liabilities:
Accounts receivable (242) (70) 200
Regulatory balancing accounts receivable (74) 302 499
Inventories (4) 32 32
Accounts payable 210 217 62
Accrued taxes (54) 36 (162)
Other working capital (85) (6) 8
Other-net 257 160 99
-----------------------------
Net cash provided by operating activities 2,618 2,581 3,315
-----------------------------
Cash Flows From Investing Activities
Capital expenditures (1,822) (1,230) (945)
Investments in unregulated projects (75) (70) (157)
Acquisitions (41) (159) -
Proceeds from sale of assets 146 - 340
Other-net 21 (120) (123)
-----------------------------
Net cash used by investing activities (1,771) (1,579) (885)
-----------------------------
Cash Flows From Financing Activities
Net increase (decrease) in short-term borrowings (587) (115) 305
Long-term debt issued 386 1,088 591
Long-term debt matured, redeemed, or repurchased-net (961) (1,472) (1,297)
Proceeds from issuance of rate reduction bonds 2,881 - -
Preferred stock redeemed or repurchased - - (358)
Utility obligated mandatorily redeemable preferred securities issued - - 300
Common stock issued 54 220 140
Common stock repurchased (804) (455) (601)
Dividends paid (524) (844) (891)
Other-net (39) (14) (22)
-----------------------------
Net cash used by financing activities 406 (1,592) (1,833)
-----------------------------
Net Change in Cash and Cash Equivalents 1,253 (590) 597
Cash and Cash Equivalents at January 1 144 734 137
-----------------------------
Cash and Cash Equivalents at December 31 $ 1,397 $ 144 $ 734
=============================
Supplemental disclosures of cash flow information
Cash paid for:
Interest (net of amounts capitalized) $ 624 $ 598 $ 645
Income taxes 801 640 1,126
The accompanying Notes to the Consolidated Financial Statements are an integral part of this statement.
34
PG&E Corporation
Statement of Consolidated Common Stock Equity,
Preferred Stock, and Preferred Securities
Preferred Preferred
Stock of Stock of
Subsidiary Subsidiary
Total Without With
Additional Common Mandatory Mandatory
Common Paid-in Reinvested Stock Redemption Redemption
(dollars in millions) Stock Capital Earnings Equity Provisions Provisions
- ------------------------------------------------------------------------------------------------------------------
Balance December 31, 1994 $2,151 $3,806 $2,677 $8,634 $733 $137
---------------------------------------------------------------------------
Net income 1,269 1,269
Common stock issued
(5,316,876 shares) 27 113 140
Common stock repurchased
(21,533,977 shares) (108) (195) (298) (601)
Preferred securities issued(1)
(12,000,000 shares) 300
Preferred stock redeemed
(13,237,554 shares) (8) (8) (331)
Cash dividends declared
Common stock (830) (830)
Other (5) (5)
---------------------------------------------------------------------------
Balance December 31, 1995 2,070 3,716 2,813 8,599 402 437
---------------------------------------------------------------------------
Net income 722 722
Common stock issued
(9,290,102 shares) 47 173 220
Common stock repurchased
(19,811,396 shares) (99) (182) (174) (455)
Cash dividends declared
Common stock (729) (729)
Other 3 4 7
---------------------------------------------------------------------------
Balance December 31, 1996 2,018 3,710 2,636 8,364 402 437
---------------------------------------------------------------------------
Net income 716 716
Holding company formation 3,710 (3,710) -
Common stock issued
(2,302,544 shares) 54 54
Acquisitions (45,683,005 shares) 1,069 1,069
Common stock repurchased
(33,823,950 shares) (496) (308) (804)
Cash dividends declared
Common stock (485) (485)
Other 11 (28) (17)
---------------------------------------------------------------------------
Balance December 31, 1997 $6,366 $ - $2,531 $8,897 $402 $437
===========================================================================
(1)Relates to utility obligated mandatorily redeemable preferred securities of trust holding solely Utility subordinated debentures.
The accompanying Notes to the Consolidated Financial Statements are an integral part of this statement.
35
Pacific Gas and Electric Company
Statement of Consolidated Income
(in millions) Year ended December 31, 1997 1996 1995
- -----------------------------------------------------------------------------
Operating Revenues
Electric utility $7,691 $7,160 $7,387
Gas utility 1,804 1,829 1,856
Energy commodities and services - 621 379
----------------------
Total operating revenues 9,495 9,610 9,622
Operating Expenses
Cost of electric energy 2,501 2,261 2,117
Cost of gas 473 448 286
Cost of energy commodities and services - 356 47
Operating and maintenance 2,905 3,427 3,049
Depreciation and decommissioning 1,785 1,222 1,360
----------------------
Total operating expenses 7,664 7,714 6,859
Operating Income 1,831 1,896 2,763
Interest expense, net (570) (632) (678)
Other income and expense 116 46 149
----------------------
Income Before Income Taxes 1,377 1,310 2,234
Income taxes 609 555 895
----------------------
Net income 768 755 1,339
Preferred dividend requirement and redemption premium 33 33 70
----------------------
Income Available for Common Stock $ 735 $ 722 $1,269
======================
The accompanying Notes to the Consolidated Financial Statements are an integral part of this statement.
36
Pacific Gas and Electric Company
Statement of Consolidated Cash Flows
(in millions) Year ended December 31, 1997 1996 1995
- ------------------------------------------------------------------------------------------------------------------------------------
Cash Flows From Operating Activities
Net income $ 768 $ 755 $ 1,339
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, decommissioning, and amortization 1,914 1,316 1,449
Deferred income taxes and tax credits-net (182) (150) (116)
Other deferred charges and noncurrent liabilities 167 22 (25)
Net effect of changes in operating assets and liabilities:
Accounts receivable (582) (70) 200
Regulatory balancing accounts receivable (74) 302 499
Inventories 12 32 32
Accounts payable (80) 217 62
Accrued taxes (62) 36 (162)
Other working capital (128) (6) 8
Other-net 15 127 29
---------------------------
Net cash provided by operating activities 1,768 2,581 3,315
---------------------------
Cash Flows From Investing Activities
Capital expenditures (1,522) (1,230) (945)
Investments in unregulated projects - (70) (157)
Acquisitions - (159) -
Proceeds from sale of assets - - 340
Other-net (117) (120) (123)
---------------------------
Net cash used by investing activities (1,639) (1,579) (885)
---------------------------
Cash Flows From Financing Activities
Net increase (decrease) in short-term borrowings (681) (115) 305
Long-term debt issued 355 1,088 591
Long-term debt matured, redeemed, or repurchased-net (852) (1,472) (1,297)
Proceeds from issuance of rate reduction bonds 2,881 - -
Preferred stock redeemed or repurchased - - (353)
Company obligated mandatorily redeemable preferred securities issued - - 300
Dividends paid (739) (844) (891)
Other-net (14) (249) (488)
---------------------------
Net cash used by financing activities 950 (1,592) (1,833)
---------------------------
Net Change in Cash and Cash Equivalents 1,079 (590) 597
Cash and Cash Equivalents at January 1 144 734 137
---------------------------
Cash and Cash Equivalents at December 31 $ 1,223 $ 144 $ 734
===========================
Supplemental disclosures of cash flow information
Cash paid for:
Interest (net of amounts capitalized) $ 547 $ 598 $ 645
Income taxes 841 640 1,126
The accompanying Notes to the Consolidated Financial Statements are an integral
part of this statement.
37
Pacific Gas and Electric Company
Consolidated Balance Sheet
(in millions) At December 31, 1997 1996
- -------------------------------------------------------------------------------------------
Assets
Current Assets
Cash and cash equivalents $ 80 $ 131
Short-term investments 1,143 13
Accounts receivable
Customers, net 1,204 1,152
Regulatory balancing accounts 658 444
Related parties 459 -
Energy marketing - 387
Inventories and prepayments 523 584
-----------------------
Total current assets 4,067 2,711
Property, Plant, and Equipment
Electric 26,033 25,052
Gas 6,939 8,258
-----------------------
Total property, plant, and equipment (at original cost) 32,972 33,310
Accumulated depreciation and decommissioning (15,558) (14,302)
-----------------------
Net property, plant, and equipment 17,414 19,008
Other Noncurrent Assets
Regulatory assets 2,283 2,518
Nuclear decommissioning funds 1,024 883
Other 359 1,117
-----------------------
Total noncurrent assets 3,666 4,518
-----------------------
Total Assets $ 25,147 $ 26,237
=======================
38
Pacific Gas and Electric Company
Consolidated Balance Sheet
(in millions) At December 31, 1997 1996
- --------------------------------------------------------------------------------------------------------
Liabilities and Equity
Current Liabilities
Short-term borrowings $ - $ 681
Current portion of long-term debt 580 210
Current portion of rate reduction bonds 125 -
Accounts payable
Trade creditors 441 490
Related parties 134 -
Other 578 548
Energy marketing - 388
Accrued taxes 229 310
Deferred income taxes 149 157
Other 373 496
----------------------
Total current liabilities 2,609 3,280
Noncurrent Liabilities
Long-term debt 6,218 7,770
Rate reduction bonds 2,776 -
Deferred income taxes 3,304 3,941
Deferred tax credits 338 380
Other 1,810 1,663
----------------------
Total noncurrent liabilities 14,446 13,754
Preferred Stock With Mandatory Redemption Provisions
6.30% and 6.57%, outstanding 5,500,000 shares, due 2002-2009 137 137
Company Obligated Mandatorily Redeemable Preferred Securities of
Trust Holding Solely Utility Subordinated Debentures,
7.90%, 12,000,000 shares, due 2025 300 300
Stockholders' Equity
Preferred stock, par value $25, authorized 75,000,000 shares
Without mandatory redemption provisions
Nonredeemable-5% to 6%, outstanding 5,784,825 shares 145 145
Redeemable-4.36% to 7.44%, outstanding 10,297,404 shares 257 257
Common stock, no par value, authorized 800,000,000 shares,
403,504,292 shares outstanding, each year 4,582 5,728
Reinvested earnings 2,671 2,636
----------------------
Total stockholders' equity 7,655 8,766
Commitments and Contingencies (Notes 1, 2, 3, 12, and 13) - -
----------------------
Total Liabilities and Stockholders' Equity $25,147 $26,237
======================
The accompanying Notes to the Consolidated Financial Statements are an integral
part of this statement.
39
Pacific Gas and Electric Company
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 millions) Stock Capital Earnings Equity Provisions Provisions
- ------------------------------------------------------------------------------------------------------------------------------------
Balance December 31, 1994 $2,151 $ 3,806 $2,677 $ 8,634 $ 733 $137
----------------------------------------------------------------------------
Net income 1,339 1,339
Common stock issued
(5,316,876 shares) 27 113 140
Common stock repurchased
(21,533,977 shares) (108) (195) (298) (601)
Preferred securities issued(1)
(12,000,000 shares) 300
Preferred stock redeemed
(13,237,554 shares) (8) (14) (22) (331)
Cash dividends declared
Preferred stock (56) (56)
Common stock (830) (830)
Other (5) (5)
----------------------------------------------------------------------------
Balance December 31, 1995 2,070 3,716 2,813 8,599 402 437
----------------------------------------------------------------------------
Net income 755 755
Common stock issued
(9,290,102 shares) 47 173 220
Common stock repurchased
(19,811,396 shares) (99) (182) (174) (455)
Cash dividends declared
Preferred stock (33) (33)
Common stock (729) (729)
Other 3 4 7
----------------------------------------------------------------------------
Balance December 31, 1996 2,018 3,710 2,636 8,364 402 437
----------------------------------------------------------------------------
Net income 768 768
Holding company formation (1,146) (1,146)
Cash dividends declared
Preferred stock (33) (33)
Common stock (699) (699)
Other (1) (1)
----------------------------------------------------------------------------
Balance December 31, 1997 $2,018 $ 2,564 $2,671 $ 7,253 $402 $437
============================================================================
(1) Relates to Company obligated mandatorily redeemable preferred securities of
trust holding solely Utility subordinated debentures.
The accompanying Notes to the Consolidated Financial Statements are an integral
part of this statement.
40
Notes to Consolidated Financial Statements
Note 1:
Significant Accounting Policies
Basis of Presentation: PG&E Corporation became the holding company of Pacific
Gas and Electric Company (the Utility) on January 1, 1997. Prior to that time,
the Utility was the predecessor of PG&E Corporation. The Utility's interests in
its unregulated subsidiaries were transferred to PG&E Corporation.
This is a combined annual report of PG&E Corporation and the Utility.
Therefore, the Notes to Consolidated Financial Statements apply to both PG&E
Corporation and the Utility. PG&E Corporation's consolidated financial
statements include the accounts of PG&E Corporation and its wholly owned and
controlled subsidiaries, including the Utility (collectively, the Corporation).
The Utility's consolidated financial statements include its accounts as well as
those of its wholly owned and controlled subsidiaries. PG&E Corporation and the
Utility have identical 1995 and 1996 consolidated financial statements because
they each represent the accounts of the Utility as a predecessor of PG&E
Corporation. All significant intercompany transactions have been eliminated
from the consolidated financial statements. Certain amounts in the prior years'
consolidated financial statements have been reclassified to conform to the 1997
presentation.
The preparation of financial statements in conformity with generally
accepted accounting principles (GAAP) requires management to make estimates and
assumptions. These estimates and assumptions affect the reported amounts of
revenues, expenses, assets, and liabilities and the disclosure of contingencies.
Actual results could differ from these estimates.
Accounting principles utilized include those necessary for rate-regulated
enterprises which reflect the ratemaking policies of the California Public
Utilities Commission (CPUC) and the Federal Energy Regulatory Commission (FERC).
Operations: The Corporation is a national energy company providing electric
and gas utility services through its regulated subsidiary Pacific Gas and
Electric Company and other energy related services through its unregulated
integrated subsidiaries. The Utility generates electricity and procures,
transmits, and distributes both electricity and natural gas to customers
throughout most of Northern and Central California.
Through its other subsidiaries, the Corporation:
. Owns and operates natural gas pipelines, natural gas storage facilities,
and natural gas processing plants in the Pacific Northwest, Texas, and
Australia.
. Develops, builds, operates, owns, and manages power generation facilities
across the United States.
. Provides customers nationwide with competitively-priced natural gas and
electricity and services to manage and make more efficient their energy
consumption.
. Purchases and resells energy commodities and related financial instruments
in major domestic markets, serving PG&E Corporation's other unregulated
businesses, unaffiliated utilities, and large end-use customers.
Regulation and SFAS No. 71: The Utility is regulated by the CPUC, the FERC,
and the Nuclear Regulatory Commission, among others. The gas transmission
business in the Pacific Northwest is regulated by the FERC. The gas transmission
business in Texas is regulated by the Texas Railroad Commission.
The Corporation and the Utility account for the financial effect 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 them to record certain regulatory assets and liabilities which
will be included in future rates and would not be recorded under GAAP 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 the
Corporation and the Utility to write off regulatory assets when they are no
longer probable of recovery. On an ongoing basis, the Corporation and the
Utility review their regulatory assets and liabilities for the continued
applicability of SFAS No. 71 and the effect of SFAS No. 121.
41
Notes to Consolidated Financial Statements
Net regulatory assets including regulatory balancing accounts receivable and net
regulatory liabilities are comprised of the following:
December 31, 1997
- -------------------------------------------------------------------------------
(in millions)
Electric industry restructuring transition costs/(1)/ $1,535
Unamortized loss, net of gain, on reacquired debt 296
Regulatory assets for deferred income tax 278
Regulatory balancing accounts (net) 235
Other (net) 174
------
$2,518
======
December 31, 1996
- --------------------------------------------------------------------------------
(in millions)
Regulatory assets for deferred income tax $1,133
Unamortized loss, net of gain, on reacquired debt 377
Diablo Canyon regulatory assets 364
Regulatory balancing accounts (net) 323
Other (net) 555
------
$2,752
======
/(1)/ See Note 2, "Electric Industry Restructuring," for further discussion.
Revenues and Regulatory Balancing Accounts: Electric and gas utility revenues
recorded by the Utility include amounts for services rendered but unbilled at
the end of the year. The Utility also records revenues 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 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.
Accounting for Derivative Instruments: The Corporation, through its
subsidiaries, engages in price risk management activities for both non-hedging
and hedging purposes. The Corporation conducts non-hedging activities
principally through its unregulated subsidiary, PG&E Energy Trading (PG&E ET),
using a variety of financial instruments. These instruments include forward
contracts involving the physical delivery of an energy commodity, swaps,
futures, options, and other contractual arrangements. Additionally, the
Corporation engages in hedging activities using futures, options, and swaps to
hedge the impact of market fluctuations on energy commodity prices, interest
rates, and foreign currencies. The Utility manages price risk independently from
the activities in our unregulated businesses.
The Corporation's net gains and losses associated with price risk
management activities during 1997 were immaterial.
Property, Plant, and Equipment: Plant additions and replacements are
capitalized. The capitalized costs include 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. The Utility recovers AFUDC in rates
through depreciation expense over the useful life of the related asset.
The original cost of retired plant and removal costs less salvage value is
charged to accumulated depreciation upon retirement of plant in service.
Property, plant, and equipment is depreciated using a straight-line
remaining-life method. The Utility's composite depreciation rates were 5.00,
3.65, and 4.09 percent for the years ended December 31, 1997, 1996, and 1995,
respectively. The increase in the composite rate in 1997 as compared to 1996
and 1995 reflects higher depreciation expense associated with Diablo Canyon
Nuclear Power Plant (Diablo Canyon). See Note 2, Electric Industry
Restructuring.
Gains and Losses on Reacquired Debt: Any gains and losses on reacquired debt
associated with regulated operations that are 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 unregulated operations are recognized in
earnings at the time such debt is reacquired.
42
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 include materials and supplies, gas stored
underground, and fuel oil. Materials and supplies and gas stored underground
are valued at average cost. Fuel oil is valued by the last-in-first-out method.
Cash Equivalents and Short-Term Investments: Cash equivalents (stated at cost,
which approximates market) include working funds. The Utility's short-term
investments consist primarily of money market funds and some commercial paper
with original maturities of three months or less. These investments were made
with the proceeds from the issuance of the rate reduction bonds. See Note 7,
Rate Reduction Bonds.
Note 2:
Electric Industry Restructuring
1997 was the first year of California's transition into a new competitive
electric generation market. In the new competitive market, the Utility's
generation revenues will be determined principally by the market. However,
market-based revenues may not be sufficient to recover (that is, to collect from
customers) certain generation costs resulting from past CPUC decisions. To
recover these uneconomic costs, called "transition costs," and to ensure a
smooth transition to the competitive environment, the Utility, in conjunction
with other California electric utilities, the CPUC, state legislators, consumer
advocates, and others, developed a transition plan, in the form of state
legislation, to position California for the new market environment.
There are three principal elements to this transition plan: (1) an electric
rate freeze and rate reduction, (2) recovery of transition costs, and (3)
economic divestiture of Utility-owned generation facilities. Each one of these
three elements and the impact of the transition plan on the application of SFAS
No. 71 are discussed below. The transition plan will remain in effect until the
earlier of March 31, 2002, or when the Utility recovers its authorized
transition costs as determined by the CPUC. This period is referred to as the
transition period. At the conclusion of the transition period, the Utility will
be at risk to recover any of its remaining generation costs through market-based
revenues.
Rate Freeze and Rate Reduction
During 1997, electric rates for the Utility's customers were held at 1996
levels. Effective January 1, 1998, the Utility reduced electric rates for its
residential and small commercial customers by 10 percent and will hold their
rates at that level. The rate freeze will continue until the end of the
transition period.
To pay for the 10 percent rate reduction, the Utility financed $2.9 billion
of its transition costs with rate reduction bonds. See Note 7, Rate Reduction
Bonds.
Transition Cost Recovery
Costs eligible for transition cost recovery include: (1) above-market sunk costs
(sunk costs are costs associated with Utility-owned generating facilities that
are fixed and unavoidable and currently included in the Utility customers'
electric rates) and future costs, such as costs related to plant removal,
(2) costs associated with the Utility's long-term contracts to purchase power at
prices from Qualifying Facilities (QF) and other power suppliers, and
(3) generation-related regulatory assets and obligations. (In general,
regulatory assets are expenses deferred in the current or prior periods to be
included in rates in subsequent periods.) Transition costs that are disallowed
by the CPUC for collection from customers will be written off.
Sunk costs associated with Utility-owned generation facilities are
currently included in the Utility customers' rates. Above-market sunk costs are
those whose values recorded on the Utility's balance sheet (book value) are
expected to be in excess of their market values. Conversely, below-market sunk
costs are those whose market values are expected to be in excess of their book
values. In general, the total amount of sunk costs to be included as transition
costs will be based on the aggregate of above-market and below-market values.
The above-market portion of sunk costs is eligible for recovery as a transition
cost. The below-market portion of sunk costs will reduce other unrecovered
43
Notes to Consolidated Financial Statements
transition costs. A valuation of Utility-owned generation facilities where the
market value exceeds the book value could result in a material charge if the
Utility retains the facility. This is because any excess of market value over
book value would be used to reduce other transition costs without being
collected in rates.
The Utility will not be able to determine the exact amount of sunk costs
that will be recoverable as transition costs until a market valuation process
(appraisal, spin, or sale) is completed for each of the Utility's generation
facilities. The first of these valuations occurred in 1997 when the Utility
agreed to sell three of its electric plants for $501 million. This sale is
expected to close during 1998 (see Generation Divestiture below). The rest of
the valuation process will be completed by December 31, 2001. At December 31,
1997, the Utility's net investment in Diablo Canyon and non-nuclear generation
facilities was $3.7 billion and $2.7 billion, respectively, including the plants
to be sold in 1998.
The Utility has agreed to purchase electric power from QFs and other power
suppliers under long-term contracts expiring on various dates through 2028. Over
the life of these contracts, the Utility estimates that it will purchase
approximately 360 million megawatt-hours (MWh) at an average aggregate price of
6.3 cents per kilowatt-hour (kWh). To the extent that this price is above the
market price, the Utility will be able to collect the difference between the
contract price and the market price from customers, as a transition cost, over
the term of the contract.
In addition, as of December 31, 1997, the Utility has accumulated
approximately $1.5 billion of generation-related net regulatory assets. The net
regulatory assets are eligible for recovery as transition costs.
The CPUC has the ultimate authority to determine which costs are eligible
to be recovered as transition costs. Reviews by the CPUC to determine the
reasonableness of transition costs are being conducted and will continue to be
conducted throughout the transition period.
Under the transition plan, most transition costs must be recovered by March
31, 2002. This recovery period is significantly shorter than the recovery
period of the related assets prior to restructuring. Recovery of transition
costs during this shorter period is referred to as accelerated recovery. The
CPUC believes that acceleration reduces risks associated with recovery of all
utility generation assets, including Diablo Canyon and hydroelectric facilities.
As a result, in accordance with the transition plan, the Utility is receiving a
reduced return for all of its generation facilities. In 1997, the reduced
return was 7.13 percent as compared to an authorized return of 9.45 percent.
The reduced return on non-nuclear generation assets, effective July 28, 1997,
resulted in a $24 million decrease in earnings ($.06 per share) in 1997 and will
have a continued impact throughout the transition period.
Although most transition costs must be recovered by March 31, 2002, certain
transition costs can be included in customers' electric rates after the
transition period. These costs include: (1) certain employee-related transition
costs, (2) above-market payments under existing QF and power- purchase
contracts, and (3) unrecovered electric industry restructuring implementation
costs. In addition, transition costs financed by the issuance of rate reduction
bonds are expected to be recovered over the term of the bonds. Further, the
Utility's nuclear decommissioning costs are being recovered through a CPUC-
authorized charge which will extend until sufficient funds exist to decommission
the facility. During the rate freeze, this charge will not increase Utility
customers' electric rates. Excluding these exceptions, the Utility will write-
off any transition costs not recovered during the transition period.
Under the terms of the transition plan, as directed by the CPUC, the
Utility has separated, or unbundled, its previously authorized cost-of-service
electric revenues into separate categories. Unbundling enables the Utility to
allocate revenue provided by frozen electric rates into transmission,
distribution, public purpose programs, and generation based upon their
respective cost of service. Revenues provided by frozen rates will also be used
to recover other authorized Utility costs, including nuclear decommissioning,
rate reduction bond debt service, and transition cost recovery.
The portion of the unbundled revenue to be provided for transition cost
recovery is based upon mechanisms approved by the CPUC. Revenue provided for
recovery of most non-nuclear transition costs is based upon their acceleration
44
within the transition period. For nuclear transition costs, revenues provided
for transition cost recovery are based on (1) an established Incremental Cost
Incentive Price per kWh generated by Diablo Canyon to recover certain ongoing
costs and capital additions, and (2) the acceleration of recovery of the
Utility's investment in Diablo Canyon from a period ending in 2016 to a five-
year period ending December 31, 2001.
Based on the Utility's evaluation of the transition plan and state
legislation and CPUC decisions related to the transition plan, the Utility is
depreciating Diablo Canyon over a five-year period ending December 31, 2001.
The change in depreciable life increased Diablo Canyon's depreciation expense
for 1997, as compared to 1996, by $583 million. In addition, most generation-
related regulatory assets are being amortized on a straight-line basis, in
accordance with their recovery under the transition plan, beginning on January
1, 1998. Further, upon valuation of generation facilities, any losses will be
amortized over the remaining transition period as a transition cost. Any gains
will be recognized and used to reduce other transition costs at the time of
valuation.
Any difference between (1) revenues provided for transition cost recovery
and (2) the costs associated with accelerated recovery, including the
depreciation of Diablo Canyon and the amortization of regulatory assets, is
being tracked. If the revenues exceed the accelerated costs, certain transition
costs may be further accelerated until all transition costs are recovered or
March 31, 2002, whichever is earlier. If the accelerated costs exceed the
revenues, the costs will be deferred. At the end of the transition period, any
overcollection of these amounts will be returned to customers.
The Utility's ability to recover its transition costs during the transition
period will be dependent on several factors. These factors include: (1) the
continued application of the regulatory framework established by the CPUC and
state legislation, (2) the amount of transition costs approved by the CPUC, (3)
the market value of Utility-owned generation facilities, (4) future Utility
sales levels, (5) future Utility fuel and operating costs, (6) the extent to
which the Utility's authorized revenues to recover distribution costs are
increased or decreased, and (7) the market price of electricity. Given its
current evaluation of these factors, the Utility believes that it will recover
its transition costs. Also, the Utility believes that its regulatory assets and
generation facilities are not impaired. However, a change in one or more of
these factors could affect the probability of recovery of transition costs and
result in a material charge.
During 1997, the difference between billed revenues and authorized revenues
was used to recover transition costs, including most of the accelerated Diablo
Canyon sunk costs.
Generation Divestiture
In 1997, California utilities produced a significant portion of the state's
electric generation needs. In a competitive market, the CPUC is concerned that
this level of generation may give existing utilities undue influence on the
market price for power. As part of the transition plan, the Utility has agreed
to sell a significant portion of its generation facilities to alleviate this
concern.
In 1997, the Utility agreed to sell three fossil-fueled electric generating
plants to Duke Energy through an auction process. The aggregate bid accepted
for these plants was $501 million. These three plants have a combined book
value at December 31, 1997, of approximately $370 million and a combined
capacity of 2,645 megawatts (MW). The three power plants were Morro Bay, Moss
Landing, and Oakland.
The sales have been approved by the CPUC. However, they are still subject
to approval of the transfer of various permits and licenses. Additionally, the
Utility will retain liability for required environmental remediation of any pre-
closing soil or groundwater contamination at these plants. The Utility does not
expect any material adverse impact on its financial position or results of
operations as a result of retaining such environmental remediation liability.
The Utility expects the sale of these three plants to close in 1998.
The Utility plans to conduct another auction of its four remaining Utility-
owned fossil-fueled plants and its geothermal facilities in the first half of
1998. These additional plants have a combined generating capacity of 4,718 MW
and a combined book value at December 31, 1997, of approximately $790 million.
Together the eight power plants represent 98 percent of the Utility's
fossil-fueled generating capacity and all of the
45
Notes to Consolidated Financial Statements
Utility's geothermal generating capacity. The eight plants generate
approximately 22 percent of the Utility's total electric sales. The Utility is
currently evaluating its options related to its remaining generation facilities
and may decide not to retain its economic investment in those facilities.
During the transition period, the proceeds from the sale of the plants will be
used to offset transition costs associated with other Utility electric
generation facilities. Therefore, the Corporation does not expect any material
adverse impact on its or the Utility's financial position or results of
operations from any of these divestitures.
The Transition Plan and SFAS No. 71
The Utility accounts for the financial effect of regulation in accordance with
SFAS No. 71. This statement allows the Utility 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. In addition, SFAS No. 121, "Accounting for the Impairment of Long-
Lived Assets and for Long-Lived Assets to be Disposed Of," requires the Utility
to write off regulatory assets when they are no longer probable of recovery.
In 1997, the Emerging Issues Task Force (EITF) of the Financial Accounting
Standards Board (FASB) reached a consensus on Issue No. 97-4, "Deregulation of
the Pricing of Electricity - Issues Related to the Application of FASB
Statements No. 71, Accounting for the Effects of Certain Types of Regulation,
and No. 101, Regulated Enterprises - Accounting for the Discontinuation of
Application of FASB Statement No. 71" (EITF 97-4), which provided authoritative
guidance on the applicability of SFAS No. 71 during the transition period. The
EITF requires the Utility to discontinue the application of SFAS No. 71 for the
generation portion of its operations as of July 24, 1997, the effective date of
EITF 97-4. The discontinuation of application of SFAS No. 71 did not have a
material effect on the Utility's financial statements because EITF 97-4 requires
that regulatory assets and liabilities (both those in existence today and those
created under the terms of the transition plan) be allocated to the portion of
the business from which the source of the regulated cash flows is derived. The
Utility has accumulated approximately $1.5 billion of generation-related
regulatory assets which are eligible for collection from distribution customers
and which the Utility considers probable of recovery. Substantially all
regulatory assets are reflected on the Utility's and PG&E Corporation's balance
sheets in regulatory balancing accounts and regulatory assets. In addition,
above-market generation-related sunk costs, which will be determined as part of
the market valuation process discussed above, and above-market QF costs will be
eligible for collection from distribution customers.
Given the current regulatory environment, the Utility's electric
transmission business and most areas of the distribution business are expected
to remain regulated, and as a result, the Utility will continue to apply the
provisions of SFAS No. 71. However, in May 1997, the CPUC issued decisions that
allow customers to choose their electricity provider beginning January 1, 1998.
The decisions also allow the electricity provider to provide their customers
with billing and metering services, and indicate that electricity providers may
be allowed to provide other distribution services (such as customer inquiries
and uncollectibles) in the future. Any discontinuance of SFAS No. 71 for these
portions of the Utility's electric distribution business is not expected to have
a material adverse impact on the Utility's or the Corporation's financial
position or results of operations.
Note 3:
Natural Gas Matters
Gas Accord: In 1998, the Utility will implement a multi-party settlement, called
the Gas Accord (Accord), that will continue to restructure the gas industry in
California. The Accord, which received CPUC approval in 1997, has four
principal elements. First, the Accord separates the rates for gas transmission
services from gas distribution services. Second, the Accord increases the
opportunity for residential and smaller commercial (core) customers to choose
the commodity gas supplier of their choice. Third, the Accord establishes a new
way to measure the reasonableness of the Utility's gas purchases based upon
market indices. Fourth,
46
the Accord settled numerous regulatory issues between the Utility and other
parties. The resolution of these issues did not have a material adverse impact
on the Utility's or the Corporation's financial position or results of
operations.
The Accord also establishes gas transmission rates for the period from
March 1998 through December 2002 for all customers and eliminates regulatory
protection for variations in sales volumes for transmission revenues from
industrial and larger commercial (noncore) customers. As a result, the Utility
will be at risk for variations between actual and forecasted noncore
transmission throughput volumes. However, these variations are not expected to
have a material adverse impact on the Utility's or the Corporation's financial
position or results of operations.
Transportation Commitments: The Utility has long-term gas transportation service
contracts with various Canadian and interstate pipeline companies. For the
duration of these contracts, the Utility has agreed to pay the pipeline
companies an amount each year for capacity rights on their pipelines. The
amount that the Utility pays each year varies due to changes in the rates of the
pipeline companies. The total amounts the Utility paid under these contracts
were approximately $255, $269, and $245 million in 1997, 1996, and 1995,
respectively. These amounts include payments made by the Utility to PG&E Gas
Transmission (PG&E GT) of approximately $49, $57, and $70 million in 1997, 1996,
and 1995, respectively. These payments are eliminated in the consolidated
financial statements of the Corporation. Also, a contract for Southwest
pipeline capacity expired in December 1997. Total payments associated with this
contract were approximately $149 million in 1997.
The following table summarizes the Utility's capacity on various pipelines
and the related annual payments for capacity at December 31, 1997:
Total
Firm Annual
Capacity Demand
Held Charges Contract
Pipeline Company (MMcf/d) (in millions) Expiration
============================================================================
PG&E GT 600 $44 Oct. 2005
Transwestern 200 29 Mar. 2007
NOVA 600 20 Oct. 2001
ANG 600 13 Oct. 2005
As a result of regulatory changes, the Utility no longer procures gas for
most of its noncore customers, resulting in a decrease in the Utility's need for
capacity on these pipelines. Despite these changes, the Utility continues to
procure gas for substantially all of its core customers and its noncore
customers who choose bundled service. To the extent that the Utility's current
capacity holdings exceed demand for gas transportation by its customers, the
Utility will continue its efforts to broker such excess capacity.
Note 4:
Acquisitions and Sales
In December 1996, the Corporation acquired Energy Source, a wholesale commodity
marketing company for approximately $23 million. The acquisition was accounted
for as a purchase.
In January 1997, the Corporation acquired Teco Pipeline Company (Teco) for
approximately $378 million, consisting of $317 million of PG&E Corporation
common stock and the purchase of a $61 million note. Teco has investments in
natural gas pipelines and gas gathering and processing facilities located in
Texas. Teco also owns a gas marketing company in Houston. The acquisition was
accounted for as a purchase.
In April 1997, PG&E Enterprises (Enterprises), a wholly owned subsidiary of
PG&E Corporation, sold its interest in International Generating Company, Ltd.
(InterGen), a joint venture between Enterprises and Bechtel Enterprises, Inc.
(Bechtel), and all of its related project interests, to Bechtel. The sale has
resulted in an after-tax gain of approximately $120 million.
On July 31, 1997, the Corporation completed its acquisition of Valero
Energy Corporation's (Valero) natural gas business located in Texas. Valero
also owns a gas marketing business. PG&E Corporation issued approximately 31
million shares of its common stock to acquire Valero along with the assumption
of approximately $780 million in long-term debt, equating to a purchase price of
approximately $1.5 billion. The acquisition was accounted for as a purchase.
In August 1997, the Corporation announced that its subsidiary, U.S.
Generating Company (USGen), had agreed
47
Notes to Consolidated Financial Statements
to buy a portfolio of electric generating assets and power supply contracts from
the New England Electric System (NEES) for $1.59 billion, plus $85 million for
early retirement and severance costs previously committed to by NEES. Including
fuel and other inventories and transaction costs, financing requirements are
expected to total approximately $1.75 billion, of which approximately $1 billion
will be funded through a combination of project level debt as well as debt of
USGen. In addition, $750 million of equity will be contributed over two years
and will be financed initially using short-term debt of PG&E Corporation. The
assets to be acquired contain a balance of hydro, coal, oil, and natural gas
generation facilities. We expect the acquisition to be completed in the second
half of 1998. The acquisition is subject to regulatory approval, among other
conditions.
In September 1997, the Corporation completed an acquisition of two
partnerships previously jointly owned by it and Bechtel. In December 1997, the
Corporation closed the acquisition of a third such partnership. The Corporation
is now the sole owner of USGen, an independent power developer and manager, U.S.
Operating Services Company, USGen's operations and maintenance affiliate, and
USGen's power marketing affiliate, USGen Power Services, L.P. Additionally, the
Corporation has acquired all or part of Bechtel's interest in several power
projects that are affiliated with USGen.
In connection with the acquisitions completed in 1996 and 1997, discussed
above, the Corporation recorded approximately $432 million of goodwill, subject
to final purchase price adjustments. These amounts will be amortized on a
straight-line basis over a 30 to 40 year period.
Note 5:
Common and Preferred Stock and
Utility Obligated Mandatorily Redeemable
Preferred Securities of Trust Holding Solely
Utility Subordinated Debentures
Common Stock:
PG&E Corporation:
The Corporation has authorized 800 million shares of no-par common stock of
which 418 million shares were issued and outstanding as of December 31, 1997.
Prior to the formation of the Corporation, the Utility held $5 par value common
stock. The stock was converted to PG&E Corporation common stock (no par value)
at the formation of the holding company.
As of December 31, 1997, the Board of Directors has authorized the
repurchase of up to $1.7 billion of common stock on the open market or in
negotiated transactions. In January 1998, the Corporation repurchased 37
million shares of its common stock at $30.3125 per share. In connection with
this transaction, the Corporation has entered into a forward contract with an
investment institution. The Corporation will retain the risk of increases and
the benefit of decreases in the price of the common shares purchased through the
forward contract. This obligation will not be terminated until the investment
institution has replaced the shares sold to the Corporation through purchases on
the open market or through privately negotiated transactions. The contract is
anticipated to expire by December 31, 1998.
Utility:
The CPUC set a number of conditions when PG&E Corporation was formed as a
holding company. One of these conditions requires the Utility to maintain, on
average, its CPUC-authorized capital structure, potentially limiting the amount
of dividends the Utility may pay PG&E Corporation. At December 31, 1997, the
Utility was in compliance with its CPUC-authorized capital structure. The
Corporation believes that the Utility will continue to meet this condition in
the future without affecting the Corporation's ability to pay common stock
dividends to common shareholders.
Preferred Stock: Holders of the Utility's nonredeemable preferred stock at
December 31, 1997, have rights to annual dividends per share ranging from $1.25
to $1.50.
The Utility's redeemable preferred stock without mandatory redemption
provisions is subject to redemption at the Utility's option, in whole or in
part, if the Utility pays the specified redemption price plus accumulated and
unpaid dividends through the redemption date. Annual dividends and redemption
prices per share at December 31, 1997, range from $1.09 to $1.86 and from $25.00
to $27.25, respectively. In January 1998, the Utility redeemed all of its
48
7.44% redeemable preferred stock, of which $65 million was outstanding at
December 31, 1997, at a redemption price of $25 per share.
The Utility's redeemable preferred stock with mandatory redemption
provisions consists of 3 million shares of the 6.57% and 2.5 million shares of
the 6.30% series at December 31, 1997. The 6.57% series and 6.30% series may be
redeemed at the Utility's option beginning in 2002 and 2004, respectively, at
par value plus accumulated and unpaid dividends through the redemption date.
These series of preferred stock are subject to mandatory redemption provisions
entitling them to sinking funds providing for the retirement of stock
outstanding. The estimated fair value of the Utility's preferred stock with
mandatory redemption provisions at December 31, 1997, and 1996, was
approximately $146 million and $135 million, respectively, based on quoted
market prices.
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 the Utility, 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.
Utility Obligated Mandatorily Redeemable Preferred Securities of Trust Holding
Solely Utility Subordinated Debentures: The Utility, through its wholly owned
subsidiary, PG&E Capital I (Trust), has outstanding 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 the Utility 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 stock
securities to purchase subordinated debentures issued by the Utility with a face
value of approximately $309 million, an interest rate of 7.9 percent, and a
maturity date of 2025. These subordinated debentures are the only assets of the
Trust. Proceeds from the sale of the subordinated debentures were used to
redeem and repurchase higher-cost preferred stock.
The Utility's guarantee of the QUIPS, considered together with the other
obligations of the Utility with respect to the QUIPS, constitutes a full and
unconditional guarantee by the Utility of the Trust's contractual obligations
under the QUIPS issued by the Trust. The subordinated debentures may be
redeemed at the Utility'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 the Utility, 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 the Utility's QUIPS at December 31, 1997, and 1996, was approximately
$304 million and $291 million, respectively, based on quoted market prices.
Note 6:
Long-Term Debt
Long-term debt at December 31, 1997, and 1996, consisted of the following:
December 31, 1997 1996
==========================================================================
(in millions)
Utility long-term debt
First and refunding mortgage bonds
Maturity Interest rates
1998-2001 4.63% to 8.75% $ 861 $ 880
2002-2006 5.875% to 7.875% 1,354 1,392
2007-2019 6.35% to 8.875% 160 520
2020-2026 5.85% to 8.80% 2,498 2,628
---------------------
Principal amounts outstanding 4,873 5,420
Unamortized discount net of premium (42) (50)
---------------------
Total mortgage bonds 4,831 5,370
Pollution control loan agreements,
variable rates, due 2016-2026 1,348 988
Unsecured medium-term notes,
4.93% to 9.9%, due 1998-2014 587 829
Debentures, 12%, due 2000 - 58
Other long-term debt 32 31
---------------------
Total Utility long-term debt 6,798 7,276
Long-term debt of unregulated
business operations 1,520 704
---------------------
Total long-term debt 8,318 7,980
Current portion of long-term debt 659 210
---------------------
Long-term debt, net of current portion $7,659 $7,770
=====================
49
Notes to Consolidated Financial Statements
Utility:
Mortgage Bonds:
All real properties and substantially all personal properties of the Utility are
subject to the lien of the mortgage bonds, and the Utility is required to make
semi-annual sinking fund payments for the retirement of the bonds. Additional
mortgage bonds may be issued subject to CPUC approval, up to a maximum total
amount outstanding of $10 billion.
The Utility redeemed or repurchased $167 million and $182 million of
mortgage bonds in 1997 and 1996, respectively, with interest rates ranging from
5.375 percent to 8.875 percent.
Included in the total of outstanding mortgage bonds at December 31, 1997,
and 1996, are $705 million of mortgage bonds held in trust for the California
Pollution Control Financing Authority (CPCFA) with interest rates ranging from
5.85 percent to 8.875 percent and maturity dates ranging from 2007 to 2026. In
addition to these mortgage bonds, the Utility holds long-term loan agreements
with the CPCFA as described below.
Pollution Control Loan Agreements:
Loan agreements from the CPCFA totaled $1,348 million and $988 million,
respectively, at December 31, 1997, and 1996. Interest rates on the loans vary
with average annual interest rates for 1997 ranging from 3.01 percent to 3.92
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 2000.
Unregulated Business Operations: Long-term debt of unregulated business
operations, as of December 31, 1997, consisted primarily of first mortgage bonds
of $409 million, medium-term and senior notes of $404 million, unsecured notes
and debentures of $397 million, and other long-term debt of $310 million. The
fixed interest rates on these obligations range from 6.33 percent to 9.25
percent, with maturities ranging from 1998 to 2025.
Outstanding long-term debt as of December 31, 1996, consisted primarily of
$470 million of unsecured notes and debentures, and other long-term debt of $234
millon.
Repayment Schedule: At December 31, 1997, the Corporation's combined aggregate
amounts of maturing long-term debt and sinking fund requirements for the years
1998 through 2002, are $659, $294, $460, $330, and $515 million, respectively.
The Utility's share of those sinking fund requirements is $601, $217, $223,
$233, and $389 million, respectively.
Fair Value: The estimated fair value of the Corporation's total long-term debt
at December 31, 1997, and 1996, was approximately $8.3 billion and $8.0 billion,
respectively. The estimated fair value of the Utility's total long-term debt at
December 31, 1997, and 1996, was approximately $7.0 billion and $7.3 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 (for example, the present value of future cash flows).
Note 7:
Rate Reduction Bonds
In December 1997, PG&E Funding LLC (SPE), a special-purpose entity wholly owned
by the Utility, issued $2.9 billion of rate reduction bonds to the California
Infrastructure and Economic Development Bank Special Purpose Trust PG&E-1
(Trust), a special-purpose entity. The terms of the bonds generally mirror the
terms of the pass-through certificates issued by the Trust. The proceeds of the
rate reduction bonds were used by the SPE to purchase from the Utility the
right, known as "transition property," to be paid a specified amount from a
nonbypassable tariff levied on residential and small commercial customers which
was authorized by the CPUC pursuant to state legislation.
The rate reduction bonds have maturities ranging from ten months to ten
years, and bear interest at rates ranging from 5.94 percent to 6.48 percent.
The bonds are secured solely by the transition property and there is no recourse
to the Utility or the Corporation.
At December 31, 1997, the combined aggregate amounts of maturing rate
reduction bonds, for the years 1998
50
through 2002, are $125, $265, $280, $300, and $290 million, respectively.
The estimated fair value of the rate reduction bonds was approximately $2.9
billion at December 31, 1997. The estimated fair value of the bonds was
determined based on quoted market prices.
While the SPE is consolidated with the Utility for purposes of these
financial statements, the SPE is legally separate from the Utility. The assets
of the SPE are not available to creditors of the Utility or the Corporation, and
the transition property is legally not an asset of the Utility or the
Corporation.
Note 8:
Short-Term Borrowings
In January 1997, the Corporation established a $500 million revolving credit
facility, which expires in 2002. In August 1997, the Corporation entered into
an additional $500 million temporary credit facility which expires in 1998.
Both of these credit facilities are to be used for general corporate purposes.
There were no borrowings under these credit facilities at December 31, 1997.
In addition, the Utility maintains a $1 billion revolving credit facility
which expires in 2002. The facility may be extended annually for additional one-
year periods upon mutual agreement between the Utility and the banks. There
were no borrowings under this credit facility in 1997 or 1996.
At December 31, 1997, the Corporation had outstanding $103 million of
short-term bank borrowings at a 6.9 percent weighted average interest rate. In
addition to borrowing from banks on a short-term basis, the Corporation and
certain of its subsidiaries sell commercial paper, having a maturity of one to
ninety days, to provide financing for various corporate purposes. The carrying
amount of short-term borrowings approximates fair value. At maturity,
commercial paper can be either reissued or replaced with borrowings from the
revolving credit facility. At December 31, 1997, the Corporation had no
commercial paper outstanding.
At December 31, 1996, the Utility had outstanding $681 million of
commercial paper at a 5.83 percent weighted average interest rate. At December
31, 1997, the Utility required no short-term borrowings due to the receipt of
the rate reduction bond proceeds.
Note 9:
Nuclear Decommissioning
Decommissioning of the Utility's nuclear power plants is scheduled to begin in
2015 with scheduled completion in 2034. Nuclear decommissioning means to safely
remove nuclear facilities from service and reduce residual radio activity to a
level that permits termination of the Nuclear Regulatory Commission license and
release of the property for unrestricted use.
The estimated total obligation for nuclear decommissioning costs, based on
a 1997 site study, is approximately $1.4 billion in 1997 dollars (or $5.1
billion in future dollars). This estimate assumes after-tax earnings on the
tax-qualified and nontax-qualified decommissioning funds of 6.16 percent and
5.21 percent, respectively, as well as a future annual escalation rate of 5.5
percent for decommissioning costs. The decommissioning cost estimates are based
on the plant location and cost characteristics for the Utility's nuclear plants.
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, 1997, 1996, and 1995, nuclear
decommissioning costs recovered in rates were $33, $33, and $54 million,
respectively. Based on the 1997 site study, the amount approved to be recovered
in rates in 1998 and annually, until the commencement of decommissioning, is $33
million. This amount will be reviewed in future rate proceedings.
At December 31, 1997, the total nuclear decommissioning obligation accrued
was $1.0 billion and was included in the balance sheet classification of
Accumulated Depreciation and Decommissioning. Decommissioning costs recovered
in rates are placed in external trust funds. The earnings on the external
trusts accumulate in the fund balance and are included in the
51
Notes to Consolidated Financial Statements
balance sheet classification of Other Noncurrent Assets. These funds along with
accumulated earnings will be used exclusively for decommissioning and cannot be
released from the trust funds until authorized by the CPUC.
The following table provides a summary of amortized cost and fair value of
these nuclear decommissioning funds:
Year ended December 31, Maturity Dates 1997 1996
===============================================================================
(in millions)
Amortized cost
U.S. government and
agency issues 1998-2027 $ 422 $375
Equity securities - 257 281
Municipal bonds and other 1998-2021 70 33
Gross unrealized holding gains 287 199
Gross unrealized holding losses (12) (5)
-------------------
Fair value $1,024 $883
===================
The proceeds received during 1997 and 1996 from sales of securities were
approximately $1.4 billion and $1.5 billion in each year, respectively. During
1997 and 1996, the gross realized gains on sales of securities held as
available-for-sale were $40 million and $14 million, respectively, and the gross
realized losses on sales of securities held as available-for-sale were $24
million and $20 million, respectively. The cost of debt and equity securities
sold is determined by specific identification.
Under the Nuclear Waste Policy Act of 1982, the Department of Energy (DOE)
is responsible for the permanent storage and disposal of spent nuclear fuel.
The Utility has signed a contract with the DOE to provide for the disposal of
spent nuclear fuel and high-level radioactive waste from the Utility's nuclear
power facilities. The DOE's current estimate for an available site to begin
accepting physical possession of the spent nuclear fuel is 2012. At the
projected level of operation for Diablo Canyon, the Utility'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. The Utility is examining
options for providing additional temporary spent fuel storage at Diablo Canyon
or other facilities, pending disposal or storage at a DOE facility.
Note 10:
Employee Benefit Plans
Retirement Plans: Several of the Corporation's subsidiaries provide
noncontributory defined benefit pension plans for their employees. The
Utility's plan represents substantially all of the plan assets and the projected
benefit obligation. All descriptions and assumptions are based on the Utility's
plan which covers the largest number of employees. The schedules below
aggregate all of the Corporation's plans.
Pension benefits are based on an employee's years of service and base
salary. The Corporation'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.
The following schedule reconciles the plans' funded status to the prepaid
pension cost or accrued pension liability recorded on the Consolidated Balance
Sheet:
December 31, 1997 1996
================================================================================
(in millions)
Actuarial present value of benefit obligations
Vested benefits $(3,659) $(3,486)
Nonvested benefits (198) (178)
----------------------
Accumulated benefit obligation (3,857) (3,664)
Effect of projected future compensation
increases (561) (529)
----------------------
Projected benefit obligation (4,418) (4,193)
Plan assets at market value 6,419 5,526
----------------------
Plan assets in excess of projected benefit
obligation 2,001 1,333
Unrecognized prior service cost 121 83
Unrecognized net gain (2,135) (1,559)
Unrecognized net transition obligation 74 86
----------------------
Prepaid pension cost (accrued pension liability) $ 61 $ (57)
======================
The Utility's share of the plan assets in excess of projected benefit
obligation for 1997 and 1996 was $2.0 and $1.3 billion, respectively. The
Utility's share of the prepaid pension cost for 1997 was $75 million and the
accrued pension liability for 1996 was $53 million.
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
52
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:
Year ended December 31, 1997 1996 1995
================================================================================
(in millions)
Service cost for benefits earned $ (101) $(100) $ (83)
Interest cost (313) (302) (291)
Actual return on plan assets 1,139 811 968
Net amortization and deferral (598) (353) (586)
-----------------------------------
Net pension income $ 127 $ 56 $ 8
===================================
The Utility's share of the plan's net pension income for 1997, 1996, and
1995 was $128, $57, and $8 million, respectively.
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 1997, 1996, and 1995, actual return on
plan assets exceeded expected return.
In conformity with SFAS No. 71, regulatory adjustments have been recorded
in the income statement and balance sheet of the Utility which reflect the
difference between Utility pension income or cost determined for accounting
purposes and that for rate making, which is based on a funding approach.
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.
December 31, 1997 1996 1995
================================================================================
(in millions)
Discount rate 7.5% 7.5% 7.25%
Rate of future compensation
increases 5% 5% 5%
Expected long-term rate of return
on plan assets 9% 9% 9%
Postretirement Benefits Other Than Pensions: Several of the Corporation's
subsidiaries provide contributory defined benefit medical plans for retired
employees and their eligible dependents and noncontributory defined benefit life
insurance plans for retired employees. The Utility's plan represents
substantially all of the plan assets and the total accumulated postretirement
benefit obligation. All descriptions and assumptions are based on the Utility's
plan which covers the largest number of employees. The schedules below
aggregate all of the Corporation's plans.
Most 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 costs for these benefits.
The CPUC has authorized the Utility to recover these benefits for 1993 and
beyond. Recovery is based on the lesser of the annual accounting costs or the
annual contributions on a tax-deductible basis to appropriate trusts. The
policy is to fund each year an amount consistent with the basis for rate
recovery.
The following schedule reconciles the medical and life insurance plans'
funded status to the postretirement benefit liability recorded on the
Consolidated Balance Sheet:
December 31, 1997 1996
==========================================================================
(in millions)
Accumulated postretirement benefit obligation
Retirees $(400) $(445)
Other fully eligible participants (140) (132)
Other active plan participants (367) (344)
--------------------
Total accumulated postretirement benefit
obligation (907) (921)
Plan assets at market value 823 666
--------------------
Accumulated postretirement benefit obligation
in excess of plan assets (84) (255)
Unrecognized prior service cost 20 22
Unrecognized net gain (375) (227)
Unrecognized transition obligation 393 420
--------------------
Accrued postretirement benefit liability $ (46) $ (40)
====================
The Utility's share of the accumulated postretirement benefit obligation in
excess of plan assets for 1997 and 1996 was $64 and $249 million, respectively.
The Utility's share of the accrued postretirement benefit liability for 1997 and
1996 was $29 and $38 million, respectively.
Plan assets consist primarily of common stocks and
53
Notes to Consolidated Financial Statements
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:
Year ended December 31, 1997 1996 1995
================================================================================
(in millions)
Service cost for benefits earned $(21) $(22) $(17)
Interest cost (65) (66) (65)
Actual return on plan assets 144 91 109
Amortization of unrecognized prior
service cost (2) (2) (2)
Amortization of transition obligation (25) (26) (26)
Net amortization and deferral (71) (38) (70)
----------------------------------
Net postretirement benefit income
(cost) $(40) $(63) $(71)
==================================
The Utility's share of the plan's net postretirement benefit cost for 1997,
1996, and 1995 was $38, $61, and $71 million, respectively.
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 1997, 1996, and 1995 were the same as those
used for the pension plan.
The assumed health care cost trend rate for 1998 is approximately 9.5
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, 1997, by approximately $76 million and the
1997 aggregate service and interest costs by approximately $8 million.
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 deter-
mination of future postretirement benefit cost. In 1997, 1996, and 1995, actual
return on plan assets exceeded expected return.
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. As of December 31, 1997, 24.5 million shares of common stock have
been authorized for award under the program. At December 31, 1997, stock
options on 6,181,819 shares, granted at option prices ranging from $16.75 to
$34.25, were outstanding, of which 1,902,545 were exercisable. In 1997,
3,048,400 options were granted at an average option price of $22.55.
Outstanding stock options expire ten years and one day after the date of
grant and become exercisable on a cumulative basis at one-third each year
commencing two years from the date of grant. In 1997, 1996, and 1995, stock
options on 232,815, 72,960, and 235,568 shares, respectively, were exercised at
option prices ranging from $16.75 to $33.13.
Effective January 1, 1996, the Corporation adopted SFAS No. 123,
"Accounting for Stock-Based Compensation." SFAS No. 123 requires the Corporation
to disclose stock option costs based on the fair value of options granted. For
the years ended December 31, 1997 and 1996, the fair value of options granted
was not material to the Corporation's results of operations or earnings per
share.
Note 11:
Income Taxes
The Corporation 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.
54
The significant components of income tax expense were:
PG&E Corporation Utility
Year ended December 31, 1997 1996 1995 1997 1996 1995
==================================================================================
(in millions)
Current $ 707 $ 705 $1,011 $ 791 $ 705 $1,011
Deferred (119) (132) (98) (142) (132) (98)
Tax credits-net (40) (18) (18) (40) (18) (18)
--------------------------------------------------------
Total income tax expense $ 548 $ 555 $ 895 $ 609 $ 555 $ 895
========================================================
The significant components of net deferred income tax liabilities were:
PG&E Corporation Utility
December 31, 1997 1996 1997 1996
=====================================================================================================
(in millions)
Deferred income tax assets $1,108 $1,308 $ 962 $1,308
Deferred income tax liabilities:
Regulatory balancing accounts 311 294 311 294
Plant in service 3,621 3,624 3,144 3,624
Income tax regulatory asset 430 454 420 454
Other 924 1,034 540 1,034
---------------------------------------------------
Total deferred income tax liabilities 5,286 5,406 4,415 5,406
---------------------------------------------------
Total net deferred income taxes $4,178 $4,098 $3,453 $4,098
===================================================
Classification of net deferred income taxes:
Included in current liabilities $ 149 $ 157 $ 149 $ 157
Included in noncurrent liabilities 4,029 3,941 3,304 3,941
---------------------------------------------------
Total net deferred income taxes $4,178 $4,098 $3,453 $4,098
===================================================
The differences between income taxes and amounts determined by applying the
federal statutory rate to income before income tax expense were:
PG&E Corporation Utility
Year ended December 31, 1997 1996 1995 1997 1996 1995
===============================================================================================================================
Federal statutory income tax rate 35.0% 35.0% 35.0% 35.0% 35.0% 35.0%
Increase (decrease) in income tax rate resulting from:
State income tax (net of federal benefit) 5.3 3.8 5.0 4.6 3.7 4.8
Effect of regulatory treatment of depreciation differences 8.1 6.0 3.2 7.5 5.9 3.2
Tax credits-net (3.2) (1.4) (0.8) (2.9) (1.4) (0.8)
Effect of lower taxes on foreign earnings (2.2) - - - - -
Other-net 0.3 - (1.0) - (0.8) (2.1)
------------------------------------------------------
Effective tax rate 43.3% 43.4% 41.4% 44.2% 42.4% 40.1%
======================================================
55
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 12:
Commitments
Letters of Credit: The Utility uses approximately $335 million in standby
letters of credit to secure future workers' compensation liabilities.
Restructuring Trust Guarantees: Tax-exempt trusts have been established to
oversee the development of the operating framework for the competitive
generation market (See Note 2, Electric Industry Restructuring). The CPUC has
authorized California utilities to guarantee bank loans of up to $300 million to
be used by the trusts for this purpose. Under this authorization, the Utility
has guaranteed up to a maximum of $135 million of these loans.
Power-Purchase Contracts: By federal law, the Utility is required to purchase
electric energy and capacity provided by cogenerators and small power producers.
The CPUC established a series of power-purchase contracts and set the applicable
terms, conditions, price options, and eligibility requirements.
Under these contracts, the Utility is required to make payments only when
energy is supplied or when capacity commitments are met. The total cost of these
payments is recoverable in rates. The Utility's contracts with these power
producers expire on various dates through 2028. Total energy payments are
expected to decline in the years 1998 through 2001. Total capacity payments are
expected to remain at current levels during this period. Deliveries from these
power producers account for approximately 18 percent of the Utility's 1997
electric energy requirements, and no single contract accounted for more than
five percent of the Utility's energy needs.
The Utility has negotiated early termination or suspension of certain power-
purchase contracts. 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, 1997, the total discounted future payments remaining under early
termination or suspension contracts is $53 million.
The Utility also has contracts with various irrigation districts and water
agencies to purchase hydroelectric power. Under these contracts, the Utility
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. These costs are also
recoverable in rates. At December 31, 1997, the undiscounted future minimum
payments under these contracts are $34 million for each of the years 1998
through 2002 and a total of $349 million for periods thereafter. Irrigation
district and water agency deliveries in the aggregate account for approximately
four percent of the Utility's 1997 electric energy requirements.
The amount of energy received and the total payments made under all of these
power-purchase contracts were:
Year ended December 31, 1997 1996 1995
- ------------------------------------------------------------------------------------------------
(in millions)
Kilowatt-hours received 24,389 26,056 26,468
Energy payments $ 1,157 $ 1,136 $ 1,140
Capacity payments $ 538 $ 521 $ 484
Irrigation district and water
agency payments $ 56 $ 52 $ 50
Note 13:
Contingencies
Nuclear Insurance: The Utility has insurance coverage for property damage and
business interruption losses as a member of Nuclear Electric Insurance Limited
(NEIL). Under this policy, if a nuclear generating facility of a member utility
suffers a loss due to a prolonged accidental outage, the Utility may be subject
to maximum assessments of $23 million (property damage) and $7 million (business
interruption), in each case per policy period, in the event losses exceed the
resources of NEIL.
The Utility 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
56
claims in excess of $200 million, the Utility 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 Corporation may be required to pay for
environmental remediation at sites where the Corporation 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, power
plant sites, and sites used by the Utility for the storage or disposal of
materials which may be determined to present a significant threat to human
health or the environment because of an actual or potential release of hazardous
substances. Under CERCLA, the Corporation's financial responsibilities may
include remediation of hazardous substances, even if the Utility did not deposit
those substances on the site.
The Utility records a liability when site assessments indicate remediation is
probable and a range of reasonably likely cleanup costs can be estimated. The
Utility 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 Utility records the lower end of this
range.
The cost of the hazardous substance remediation ultimately undertaken by the
Utility 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 Utility's
responsibility, the complexity of environmental laws and regulations, and the
selection of compliance alternatives. The Utility had an accrued liability at
December 31, 1997, of $232 million for hazardous waste remediation costs at
those sites, including fossil-fueled power plants, where such costs are probable
and quantifiable. Environmental remediation at identified sites may be as much
as $442 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 Utility is responsible. This upper limit
of the range of costs was estimated using assumptions least favorable to the
Utility, based upon a range of reasonably possible outcomes. Costs may be higher
if the Utility is found to be responsible for cleanup costs at additional sites
or identifiable possible outcomes change.
Of the $232 million liability discussed above, the Utility expects to recover
$157 million in future rates. The liability also includes $58 million related to
power plant decommissioning for environmental clean-up, which the Utility
recovered through depreciation. Additionally, the Utility is seeking recovery of
costs from insurance carriers and from other third parties. The Corporation
believes the ultimate outcome of these matters will not have a material adverse
impact on its or the Utility's financial position or results of operations.
Helms Pumped Storage Plant (Helms): Helms is a three-unit hydroelectric combined
generating and pumped storage plant owned by the Utility. At December 31, 1997,
the Utility's net investment was $691 million. This 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 the Utility to perform a cost-
effectiveness study of Helms. In July 1996, the Utility submitted its study,
which concluded that the continued operation of Helms is cost effective. The
Utility recommended that the CPUC take no action and address Helms along with
other generating plants in the context of electric industry restructuring.
Under electric industry restructuring, the uneconomic, above-market portion
of Helms is eligible for recovery as a transition cost. However, the Utility
will be placed at risk to recover its future operating costs in the newly
restructured electric generation market.
57
Notes to Consolidated Financial Statements
Because the CPUC has not specifically addressed the cost-effectiveness study,
the Utility is currently unable to predict whether there will be further changes
in rate recovery. The Corporation believes that the ultimate outcome of this
matter will not have a material adverse impact on its or the Utility's financial
position or results of operations.
Legal Matters:
Chromium Litigation:
In 1994 through 1997, several civil suits were filed against the Utility on
behalf of approximately 3,000 individuals. The suits seek an unspecified amount
of compensatory and punitive damages for alleged personal injuries and, in some
cases, property damage, resulting from alleged exposure to chromium in the
vicinity of the Utility's gas compressor stations at Hinkley, Kettleman, and
Topock.
The Utility is responding to the suits and asserting affirmative defenses.
The Utility 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.
The Corporation believes that the ultimate outcome of this matter will not
have a material adverse impact on its or the Utility's financial position or
results of operations.
Texas Franchise Fee Litigation:
In connection with PG&E Corporation's acquisition of Valero, now known as PG&E
Gas Transmission, Texas Corporation (GTT), GTT succeeded to the litigation
described below.
GTT and various of its affiliates are defendants in at least two class action
suits and five separate suits filed by various Texas cities. The class action
suits involve plaintiffs that serve as class representatives for classes
consisting of every municipality in Texas (excluding certain cities which filed
separate suits) in which any of the defendants engaged in business activities
related to natural gas or natural gas liquids or sold or supplied gas or used
public rights-of-way. Generally, these cities allege, among other things, that
(1) the defendants that own or operate pipelines have occupied city property and
conducted pipeline operations without the cities' consent and without
compensating the cities, and (2) the defendants that are gas marketers have
failed to pay the cities for accessing and utilizing the pipelines located in
the cities to flow gas under city streets. Plaintiffs also allege various other
claims against the defendants for failure to secure the cities' consent. Damages
are not quantified.
The Corporation believes that the ultimate outcome of these matters will not
have a material adverse impact on its financial position.
58
Note 14:
Segment Information
The Corporation's business segments consist of the Utility and Unregulated
Business Operations (consisting of gas transmission, electric generation, and
energy services and commodities).
The Corporation's business segment information was:
Pacific Gas and Electric Company
Unregulated
Electric Gas Total Business Corporate
(in millions) Utility Utility Utility Operations and Other Total
- -----------------------------------------------------------------------------------------------------------------------------
1997
Operating revenues $ 7,691 $ 1,804 $ 9,495 $5,905 $ -- $15,400
Intersegment revenues(1) 13 90 103 446 (549) --
------------------------------------------------------------------------------
Total operating revenues 7,704 1,894 9,598 6,351 (549) 15,400
------------------------------------------------------------------------------
Depreciation and decommissioning 1,521 264 1,785 104 -- 1,889
Operating income before income taxes(2) 1,510 321 1,831 (82) (21) 1,728
Capital expenditures 1,196 333 1,529 341 -- 1,870
Total assets at year end(3) 19,546 5,601 25,147 6,224 (814) 30,557
1996
Operating revenues $ 7,160 $ 1,829 $ 8,989 $ 621 $ -- $ 9,610
Intersegment revenues(1) 12 70 82 58 (140) --
------------------------------------------------------------------------------
Total operating revenues 7,172 1,899 9,071 679 (140) 9,610
------------------------------------------------------------------------------
Depreciation and decommissioning 920 256 1,176 46 -- 1,222
Operating income before income taxes(2) 1,758 52 1,810 84 2 1,896
Capital expenditures 922 309 1,231 173 -- 1,404
Total assets at year end(3) 18,431 5,136 23,567 2,858 (188) 26,237
1995
Operating revenues $ 7,387 $1,856 $ 9,243 $ 379 $ -- $ 9,622
Intersegment revenues(1) 13 85 98 68 (166) --
------------------------------------------------------------------------------
Total operating revenues 7,400 1,941 9,341 447 (166) 9,622
------------------------------------------------------------------------------
Depreciation and decommissioning 1,007 267 1,274 86 -- 1,360
Operating income before income taxes(2) 2,267 420 2,687 71 5 2,763
Capital expenditures 680 195 875 90 -- 965
Total assets at year end(3) 19,441 5,248 24,689 2,578 (396) 26,871
(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) Utility includes an allocation of common plant in service and allowance for
funds used during construction.
(4) Corporate and other assets consist of cash and cash equivalents, short-term
investments, receivables transferred from affiliates, and other assets.
(5) Includes consolidating eliminations.
59
Quarterly Consolidated Financial Data (Unaudited)
Due to the seasonal nature of the Utility business and the scheduled refueling
outages for Diablo Canyon, operating revenues, operating income, and net income
are not generated evenly every quarter during the year.
PG&E Corporation 1997:
All four quarters of 1997 reflected an increase in revenues and expenses due to
the acquisitions discussed in the Notes to the Consolidated Financial
Statements.
In the second quarter of 1997, other income increased primarily due to the
gain on the sale of International Generating Company, Ltd., which was partially
offset by write-downs of certain nonregulated investments.
Utility 1997:
All four quarters of 1997 reflected an increase in operating revenues primarily
due to the revisions to the Diablo Canyon ratemaking structure, changes in sales
volume provided by the Utility's energy rate recovery mechanisms, and an
increase in energy cost revenues to recover energy cost increases. Operating
expenses increased primarily due to the increases in Diablo Canyon depreciation
and the cost of energy.
1996:
In the second quarter of 1996, operating expenses increased primarily due to the
settlement of a litigation claim. In the third quarter of 1996, operating
expenses increased primarily due to charges for gas transportation commitments.
In the fourth quarter of 1996, operating revenues and operating expenses
increased primarily due to the purchase of Energy Source in December 1996. Other
income decreased due to write-downs of certain nonregulated investments.
The Corporation's common stock is traded on the New York, Pacific, and Swiss
stock exchanges. There were approximately 180,000 common shareholders of record
at December 31, 1997. Dividends are paid on a quarterly basis.
Quarter ended December 31 September 30 June 30 March 31
- ----------------------------------------------------------------------------------------------------------------------------
(in millions, except per share amounts)
1997
PG&E Corporation
Operating revenues $4,889 $4,063 $3,083 $3,365
Operating income 265 628 371 464
Net income 94 257 193 172
Earnings per common share, basic and diluted .22 .62 .49 .42
Dividends declared per common share .30 .30 .30 .30
Common stock price per share
High 30.94 24.94 25.00 24.25
Low 23.00 22.69 22.38 20.88
Utility
Operating revenues $2,401 $2,541 $2,279 $2,274
Operating income 390 626 370 445
Income available for common stock 180 269 122 164
1996
PG&E Corporation and Utility
Operating revenues $2,700 $2,522 $2,139 $2,249
Operating income 509 525 288 574
Net income 141 225 104 252
Earnings per common share, basic and diluted .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
60
Report of Independent Public Accountants
To the Shareholders and the Board of Directors of PG&E Corporation and Pacific
Gas and Electric Company:
We have audited the accompanying consolidated balance sheets of PG&E Corporation
(a California corporation) and subsidiaries and of Pacific Gas and Electric
Company (a California corporation) and subsidiaries as of December 31, 1997, and
1996, and the related statements of consolidated income, cash flows, and common
stock equity, preferred stock, and preferred securities for each of the three
years in the period ended December 31, 1997. These financial statements are the
responsibility of the management of PG&E Corporation and of Pacific Gas and
Electric Company. Our responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial positions of PG&E Corporation and
subsidiaries and of Pacific Gas and Electric Company and subsidiaries as of
December 31, 1997, and 1996, and the results of their operations and their cash
flows for each of the three years in the period ended December 31, 1997, in
conformity with generally accepted accounting principles.
ARTHUR ANDERSEN LLP
San Francisco, California
February 9, 1998
Responsibility for Consolidated Financial Statements
At both PG&E Corporation and Pacific Gas and Electric Company (the Utility),
management is responsible for the integrity of the accompanying consolidated
financial statements. These statements have been prepared in accordance with
generally accepted accounting principles. Management considers materiality and
uses its best judgment to ensure that such statements reflect fairly the
financial position, results of operations, and cash flows of PG&E Corporation
and the Utility.
PG&E Corporation and the Utility maintain systems of internal controls
supported by formal policies and procedures which are communicated throughout
PG&E Corporation and the Utility. These controls are adequate to provide
reasonable assurance that assets are safeguarded from material loss or
unauthorized use and that necessary records are produced 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. PG&E Corporation and the Utility
believe that their systems of internal control provide this appropriate balance.
PG&E Corporation management also maintains a staff of internal auditors who
evaluate the adequacy of, and assess the adherence to, these controls, policies,
and procedures for all of PG&E Corporation, including the Utility.
Both PG&E Corporation's and the Utility's consolidated financial statements
have been audited by Arthur Andersen LLP, PG&E Corporation's independent public
accountants. The audit includes a review of the internal accounting controls and
performance of other tests necessary to support an opinion. The auditors' report
contains an independent informed judgment as to the fairness, in all material
respects, of reported results of operations and financial position.
The Audit Committee of the Board of Directors for PG&E Corporation meets
regularly with management, internal auditors, and Arthur Andersen LLP, jointly
and separately, to review internal accounting controls and auditing and
financial reporting matters. The internal auditors and Arthur Andersen LLP have
free access to the Audit Committee, which consists of five outside directors.
The Audit Committee has reviewed the financial data contained in this report.
PG&E Corporation and the Utility are committed to full compliance with all
laws and regulations and to conducting business in accordance with high
standards of ethical conduct. Management is taking the steps necessary to ensure
that all employees and other agents understand and support this commitment.
Guidance for corporate compliance and ethics is provided by an officers' Ethics
Committee and by a Legal Compliance and Business Ethics organization. PG&E
Corporation and the Utility believe that these efforts provide reasonable
assurance that each of their operations are conducted in conformity with
applicable laws and with their commitment to ethical conduct.
61
Directors
Boards of Directors of
PG&E Corporation and
Pacific Gas and
Electric Company*
Richard A. Clarke
Chairman of the Board, Retired,
Pacific Gas and Electric Company
Harry M. Conger
Chairman of the Board,
Homestake Mining Company
David A. Coulter
Chairman and Chief
Executive Officer,
BankAmerica Corporation and
Bank of America NT&SA
C. Lee Cox
Vice Chairman, Retired,
AirTouch Communications, Inc.
and President and Chief Executive Officer, Retired,
AirTouch Cellular
William S. Davila
President Emeritus,
The Vons Companies, Inc.
(retail grocery)
Robert D. Glynn, Jr.
Chairman of the Board,
Chief Executive Officer, and President,
PG&E Corporation and
Chairman of the Board,
Pacific Gas and Electric Company
David M. Lawrence, MD
Chairman and
Chief Executive Officer,
Kaiser Foundation Health Plan, Inc.
and Kaiser Foundation Hospitals
Richard B. Madden
Chairman of the Board and
Chief Executive Officer, Retired,
Potlatch Corporation
(diversified forest products)
Mary S. Metz
Dean, University Extension,
University of California, Berkeley
Rebecca Q. Morgan
President and
Chief Executive Officer,
Joint Venture:
Silicon Valley Network
(nonprofit collaborative addressing
critical issues facing Silicon Valley)
Carl E. Reichardt
Chairman of the Board and
Chief Executive Officer, Retired,
Wells Fargo & Company and
Wells Fargo Bank, N.A.
John C. Sawhill
President and
Chief Executive Officer,
The Nature Conservancy
(international environmental
organization)
Alan Seelenfreund
Chairman of the Board and
former Chief Executive Officer,
McKesson Corporation
(distributor of pharmaceuticals and
health care products)
Gordon R. Smith*
President and
Chief Executive Officer,
Pacific Gas and Electric Company
Barry Lawson Williams
President,
Williams Pacific Ventures, Inc.
(venture capital and real estate,
consulting, and mediation)
Permanent Committees of
PG&E Corporation and
Pacific Gas and
Electric Company**
Executive Committees
Within limits, may exercise powers
and perform duties of the Boards.
Robert D. Glynn, Jr., Chair
Harry M. Conger
Richard B. Madden
Mary S. Metz
Carl E. Reichardt
Gordon R. Smith**
Audit Committee
Reviews financial statements and
internal audit and control
procedures with independent
public accountants.
Harry M. Conger, Chair
C. Lee Cox
William S. Davila
Mary S. Metz
Barry Lawson Williams
Finance Committee
Reviews long-term financial and
capital investment policies and objectives, and actions required to achieve
those objectives.
Richard B. Madden, Chair
Richard A. Clarke
David A. Coulter
Carl E. Reichardt
John C. Sawhill
Barry Lawson Williams
Nominating and Compensation Committee
Recommends candidates for nomination as directors, recommends compensation and
employee benefit policies and practices, and reviews planning for executive
development and succession.
Carl E. Reichardt, Chair
David A. Coulter
David M. Lawrence, MD
John C. Sawhill
Alan Seelenfreund
Public Policy Committee
Reviews public policy issues which
could significantly affect customers, shareholders, employees, or the
communities served, and recommends plans and programs to
address such issues.
Mary S. Metz, Chair
Richard A. Clarke
William S. Davila
Rebecca Q. Morgan
John C. Sawhill
** The composition of the Boards of Directors is the same, except that Gordon R.
Smith is a member of the Pacific Gas and Electric Company Board of Directors
only.
** Except for the Executive Committee, all Committees listed above are
committees of the PG&E Corporation Board of Directors. The Executive
Committees of the PG&E Corporation and Pacific Gas and Electric Company
Boards have the same members, except that Gordon R. Smith is a member of the
Pacific Gas and Electric Company Executive Committee only.
62
Officers
PG&E Corporation
Robert D. Glynn, Jr.
Chairman of the Board,
Chief Executive Officer,
and President
Tony F. DiStefano
Senior Vice President,
Corporate Development
Scott W. Gebhardt
Senior Vice President
Thomas W. High
Senior Vice President, Administration and
External Relations
Jack F. Jenkins-Stark
Senior Vice President
Joseph P. Kearney
Senior Vice President
L. E. Maddox
Senior Vice President
Michael E. Rescoe
Senior Vice President,
Chief Financial Officer, and Treasurer
G. Brent Stanley
Senior Vice President,
Human Resources
Bruce R. Worthington
Senior Vice President and
General Counsel
Leslie H. Everett
Vice President and
Corporate Secretary
Christopher P. Johns
Vice President and
Controller
Jackalyne Pfannenstiel
Vice President,
Business Planning
Greg S. Pruett
Vice President,
Corporate Communications
Daniel D. Richard, Jr.
Vice President,
Governmental Relations
Linda Y. H. Cheng
Assistant Corporate Secretary
Wondy S. Lee
Assistant Corporate Secretary
Eric Montizambert
Assistant Corporate Secretary
Gabriel B. Togneri
Assistant Treasurer
Pacific Gas and
Electric Company
Robert D. Glynn, Jr.
Chairman of the Board
Gordon R. Smith
President and
Chief Executive Officer
Kent M. Harvey
Senior Vice President,
Chief Financial Officer,
and Treasurer
E. James Macias
Senior Vice President and
General Manager,
Generation, Transmission, and
Supply Business Unit
James K. Randolph
Senior Vice President and
General Manager,
Distribution and Customer Service Business Unit
Daniel D. Richard, Jr.
Senior Vice President,
Governmental and
Regulatory Relations
Gregory M. Rueger
Senior Vice President and
General Manager,
Nuclear Power Generation
Business Unit
Shan Bhattacharya
Vice President,
Distribution Engineering and
Planning
Thomas E. Bottorff
Vice President,
Rates and Account Services
Jeffrey D. Butler
Vice President,
Distribution Operations,
Maintenance, and Construction
Barbara Coull Williams
Vice President,
Human Resources
Leslie H. Everett
Vice President and
Corporate Secretary
Katheryn M. Fong
Vice President,
Customer Revenue Transactions
Roger J. Gray
Vice President,
General Services
Robert L. Harris
Vice President,
Community Relations
Russell M. Jackson
Vice President,
Customer Service
Christopher P. Johns
Vice President and
Controller
Junona A. Jonas
Vice President,
Gas and Electric Supply
Steven L. Kline
Vice President,
Regulatory Relations
Thomas C. Long
Vice President,
General Rate Case Project
William R. Mazotti
Vice President,
Gas and Electric Transmission
Roger J. Peters
Vice President and
General Counsel
Robert P. Powers
Vice President,
Diablo Canyon Operations and
Plant Manager
Frank J. Regan
Vice President,
Governmental Relations
Lawrence F. Womack
Vice President,
Nuclear Technical Services
Linda Y. H. Cheng
Senior Assistant
Corporate Secretary
Wondy S. Lee
Assistant Corporate Secretary
Eric Montizambert
Assistant Corporate Secretary
Gabriel B. Togneri
Assistant Treasurer
U.S. Generating Company
Joseph P. Kearney
President and
Chief Executive Officer
P. Chrisman Iribe
Executive Vice President and
Chief Operating Officer
PG&E Gas Transmission
Jack F. Jenkins-Stark
President and
Chief Executive Officer
Terrence E. Ciliske
President and
Chief Executive Officer of
PG&E Gas Transmission-Texas
Michael J. McDonald
Managing Director of
PG&E Gas Transmission - Australia
PG&E Energy Services
Scott W. Gebhardt
President and
Chief Executive Officer
James C. Davis
Senior Vice President,
Integrated Services
William R. Doucette
Senior Vice President,
Sales
PG&E Energy Trading
L. E. Maddox
President and
Chief Executive Officer
63
Shareholder Information
Shareholder Services Office
77 Beale Street, Room 2600
San Francisco, CA 94105-1814
Call Toll Free 1.800.367.7731
Fax 415.973.7831
For financial and other information about PG&E Corporation and Pacific Gas and
Electric Company, please visit our web sites, www.pgecorp.com and www.pge.com
If you have questions about your account or need copies of PG&E Corporation's or
Pacific Gas and Electric Company's publications, please write or call the
Shareholder Services Office at:
Manager of Shareholder Services
David M. Kelly
Mail Code B26B
P.O. Box 770000
San Francisco, CA 94177-0001
1.800.367.7731
If you have general questions about PG&E Corporation or Pacific Gas and Electric
Company, please write or call the Corporate Secretary's Office:
Corporate Secretary
Leslie H. Everett
One Market, Spear Tower, Suite 2400
San Francisco, CA 94105-1108
415.973.2880
Securities analysts, portfolio managers, or other representatives of the
investment community should write or call the Investor Relations Office:
Manager of Investor Relations
David E. Kaplan
One Market, Spear Tower, Suite 2400
San Francisco, CA 94105-1108
415.973.3007
PG&E Corporation
General Information
415.973.7000
Pacific Gas and Electric Company
General Information
415.973.7000
Stock Held in Brokerage Accounts
("Street Name")
When you purchase your stock and it is held for you by your broker, the shares
are listed with us in the broker's name, or "street name." We do not know the
identity of the individual shareholders who hold their shares in this manner-we
simply know that a broker holds a number of shares which may be held for any
number of investors. If you hold your stock in a street name account, you
receive all dividend payments, tax forms, publications, and proxy materials
through your broker. If you are receiving unwanted duplicate mailings, you
should contact your broker to eliminate the duplications.
PG&E Corporation Dividend Reinvestment Plan
If you hold PG&E Corporation or Pacific Gas and Electric Company stock in your
own name, rather than through a broker, you may automatically reinvest dividend
payments from common and/or preferred stock in shares of PG&E Corporation common
stock through the Dividend Reinvestment Plan (the "Plan"). You may obtain a Plan
prospectus and enroll by contacting the Shareholder Services Office. If your
certificates are held by a broker (in "street name"), you are not eligible to
participate in the Plan.
Direct Deposit of Dividends
If you hold stock in your own name, rather than through a broker, you may have
your common and/or preferred dividends transmitted to your bank electronically.
You may obtain a direct deposit authorization form by contacting the Shareholder
Services Office.
Replacement of Dividend Checks
If you hold stock in your own name and do not receive your dividend check within
five business days after the payment date, or if a check is lost or destroyed,
you should notify the Shareholder Services Office so that payment may be stopped
on the check and a replacement mailed.
Lost or Stolen Stock Certificates
If you hold stock in your own name and your stock certificate has been lost,
stolen, or in some way destroyed, you should notify the Shareholder Services
Office immediately.
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