EXHIBIT 13
SELECTED FINANCIAL DATA
(in millions, except per share amounts) 1998 1997 1996 1995 1994
PG&E CORPORATION(1)
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For the Year
Operating revenues $19,942 $15,400 $ 9,610 $ 9,622 $10,350
Operating income 2,007 1,728 1,896 2,763 2,424
Net income 719 716 722 1,269 950
Earnings per common share 1.88 1.75 1.75 2.99 2.21
Dividends declared per common share 1.20 1.20 1.77 1.96 1.96
At Year-End
Book value per common share $ 21.08 $ 21.30 $ 20.73 $ 20.77 $ 20.07
Common stock price per share 31.50 30.31 21.00 28.38 24.38
Total assets 33,234 31,115 26,237 26,871 27,738
Long-term debt (excluding current portions) 7,422 7,659 7,770 8,049 8,676
Rate reduction bonds (excluding current portions) 2,321 2,611 -- -- --
Redeemable preferred stock and securities of
subsidiaries (excluding current portions) 635 750 694 694 725
PACIFIC GAS AND ELECTRIC COMPANY
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For the Year
Operating revenues $ 8,924 $ 9,495 $ 9,610 $ 9,622 $10,350
Operating income 1,876 1,831 1,896 2,763 2,424
Income available for common stock 702 735 722 1,269 950
At Year-End
Total assets $22,950 $25,147 $26,237 $26,871 $27,738
Long-term debt (excluding current portions) 5,444 6,218 7,770 8,049 8,676
Rate reduction bonds (excluding current portions) 2,321 2,611 -- -- --
Redeemable preferred stock and securities
(excluding current portions) 579 694 694 694 725
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(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 (the Utility) for the years 1994
through 1996 are identical because they reflect the accounts of the Utility
as the predecessor of PG&E Corporation. Matters relating to certain data
above are discussed in Management's Discussion and Analysis and in Notes to
the Consolidated Financial Statements.
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MANAGEMENT'S DISCUSSION AND ANALYSIS
PG&E Corporation is an energy-based holding company headquartered in San
Francisco, California. PG&E Corporation's businesses provide energy services
throughout North America. PG&E Corporation's Northern and Central California
energy utility subsidiary, Pacific Gas and Electric Company (the Utility),
provides natural gas and electric service to one of every 20 Americans. PG&E
Corporation's four unregulated businesses provide a wide range of energy
products and services through its wholesale and retail unregulated business
operations.
PG&E Corporation's wholesale unregulated business operations consist
of U.S. Generating Company (USGen) which develops, builds, operates, owns,
and manages power generation facilities that serve wholesale and industrial
customers; PG&E Gas Transmission (PG&E GT) which operates approximately 9,000
miles of natural gas pipelines, natural gas storage facilities, and natural
gas processing plants in the Pacific Northwest (PG&EGTNW) and Texas (PG&E
GTT); and PG&E Energy Trading (PG&E ET) which purchases and resells energy
commodities and related financial instruments in major North American
markets, serving PG&E Corporation's other unregulated businesses,
unaffiliated utilities, and large end-use customers.
PG&E Corporation's retail unregulated business operations consist of
PG&E Energy Services (PG&E ES) which provides competitively priced
electricity, natural gas, and related services to lower overall energy costs
for industrial, commercial, and institutional customers.
This is a combined annual report of PG&E Corporation and Pacific Gas
and Electric Company. It includes separate consolidated financial statements for
each entity. The consolidated financial statements of PG&E Corporation reflect
the accounts of PG&E Corporation, the Utility, and PG&E Corporation's other
wholly owned and controlled subsidiaries. The consolidated financial statements
of the Utility reflect the accounts of the Utility and its wholly owned
subsidiaries.
PG&E Corporation was formed in 1997 as the parent holding company for the
Utility and the unregulated businesses. Information for 1996 in PG&E
Corporation's consolidated financial statements is identical to information in
the Utility's consolidated financial statements because they represent the
accounts of Utility as the predecessor of PG&E Corporation.
This combined annual report, including our Letter to Shareholders and
this Management's Discussion and Analysis (MD&A), contains forward-looking
statements about the future that are necessarily subject to various risks and
uncertainties. These statements are based on the beliefs and assumptions of
management and on information currently available to management. These
forward-looking statements are identified by words such as "estimates,"
"expects," "anticipates," "plans," "believes," and other similar expressions.
Factors that could cause future results to differ materially from
those expressed in or implied by the forward-looking statements or historical
results include the impact or outcome of:
* the pace and extent of the ongoing restructuring of the electric and gas
industries across the United States;
* the outcome of regulatory and legislative proceedings and operational changes
related to industry restructuring;
* any changes in the amount the Utility is allowed to collect (recover) from its
customers for certain costs which prove to be uneconomic under the new
competitive market (called transition costs) in accordance with the Utility's
plan for recovering those costs;
* the successful integration and performance of our recently acquired assets;
* our ability to successfully compete outside our traditional regulated markets;
* internal and external Year 2000 software and hardware issues;
* the outcome of ongoing regulatory proceedings, including: the Utility's cost
of capital proceeding; the Utility's 1999 general rate case; the Utility's
proposal to adopt performance based ratemaking (PBR); the Utility's
transmission rate case applications; and the California Public Utilities
Commission's (CPUC) regulatory proceedings including its audit of the
Utility's affiliate transactions;
* fluctuations in commodity gas and electric prices and our ability to
successfully manage such price fluctuations; and
* the pace and extent of competition in the California generation market and its
impact on the Utility's costs and resulting collection of transition costs.
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Although the ultimate impacts of the above factors are uncertain, these and
other factors may cause future earnings to differ materially from results or
outcomes we currently seek or expect. Each of these factors is discussed in
greater detail in this MD&A.
In this MD&A, we first discuss our competitive and regulatory environment. We
then discuss earnings and changes in our results of operations for 1998, 1997,
and 1996. Finally, we discuss liquidity and financial resources, various
uncertainties that could affect future earnings, and our risk management
activities. Our MD&A applies to both PG&E Corporation and the Utility. The MD&A
should be read in conjunction with the associated consolidated financial
statements of both PG&E Corporation and the Utility.
Competitive and Regulatory Environment
This section provides a discussion of the competitive environment in the
evolving energy industry, the California transition plans, the New England
electricity market, and regulatory matters.
The Competitive Environment in the Evolving Energy Industry
Historically, energy utilities operated as regulated monopolies within
specific service territories where they were essentially the sole suppliers
of natural gas and electricity services. Under this model, the energy utilities
owned and operated all of the businesses necessary to procure, generate,
transport, and distribute energy. These services were priced on a combined
(bundled) basis, with rates charged by the energy companies designed to include
all of the costs of providing these services. Now, energy utilities face
intensifying pressures to make competitive those activities that are not natural
monopoly services. The most significant of these services are electricity
generation and natural gas supply.
The driving forces behind these competitive pressures are customers
who believe they can obtain energy at lower unit prices and competitors who
want access to those customers. Regulators and legislators are responding to
those customers and competitors by providing more competition in the energy
industry. Regulators and legislators are requiring utilities to "unbundle"
rates (separate their various energy services and the prices of those
services). This allows customers to compare unit prices of the Utility and
other pro-viders when selecting their energy service provider.
In the natural gas industry, Federal Energy Regulatory Commission
(FERC) Order 636 required interstate pipeline companies to divide their
services into separate gas commodity sales, transportation, and storage
services. Under Order 636, interstate gas pipelines must provide transportation
service regardless of whether the customer (typically a local gas distribution
company) buys the gas commodity from the pipeline.
In the electric industry, the Public Utilities Regulatory Policies
Act of 1978 specifically provided that unregulated companies could become
wholesale generators of electricity and that utilities were required to
purchase and use power generated by these unregulated companies in meeting their
customers' needs. The National Energy Policy Act of 1992 was designed to
increase competition in the wholesale unregulated generation market by requiring
access to electric utility transmission systems by all wholesale unregulated
generators, sellers, and buyers of electricity. Now, an increasing number of
states throughout the country have either implemented plans or are considering
proposals to separate the generation from the transmission and distribution of
electricity through some form of electric industry restructuring.
To date, the states, not the federal government, have taken the initiative on
electric industry restructuring at the retail level. While at least five bills
mandating deregulation of the electric industry were introduced in the U.S.
Congress over the past two years, none have been passed. As a result, the pace,
extent, and methods for restructuring the electric industry vary widely
throughout the country. For instance, California, Illinois, Pennsylvania, and
several New England states have passed electric industry restructuring
legislation. Other states are considering restructuring proposals. There are
also some states that have passed legislation precluding or significantly
slowing down deregulation. Differences in how individual states view electric
industry restructuring often relate to the existing unit cost of energy supplies
within each state. Generally, states having higher energy unit costs are moving
more quickly to deregulate energy supply markets.
Implementation of our national energy strategy depends, in part, upon
the opening of energy markets to provide customer choice of supplier. Undue
delays
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MANAGEMENT'S DISCUSSION AND ANALYSIS
by states or federal legislation to deregulate the electric generation and
natural gas supply business could impact the pace of growth of our retail
unregulated business operations.
California Transition Plans
The Electric Business:
In 1998, California became one of the first states in the country to implement
an electric industry restructuring plan. Today, many Californians may choose to
purchase their electricity from (1) investor-owned utilities such as Pacific Gas
and Electric Company, or (2) unregulated retail electricity suppliers (for
example, marketers, including PG&E Energy Services, brokers, and aggregators).
The restructuring plan contemplates that the investor-owned utilities, including
the Utility, will continue to provide distribution services to substantially all
customers within their service territories, including providing electricity to
customers who choose not to be served by another service provider. California
electric industry restructuring has two major components: the competitive market
framework and the electric transition plan, which are discussed below.
Competitive Market Framework:
To create a competitive generation market, a Power Exchange (PX) and an
Independent System Operator (ISO) began operating in 1998. The Utility is
required to sell to the PX all of the electricity generated by its power plants
and electricity acquired under contract with unregulated generators. Also, the
Utility is required to buy from the PX all electricity needed to provide service
to retail customers that continue to choose the Utility as their electricity
supplier. The ISO schedules delivery of electrici ty for all market participants
to the transmission system. The Utility continues to own and maintain a portion
of the transmission system, but the ISO controls the operation of the system.
During 1998, the Utility continued its efforts to develop and implement
changes to its business processes and systems, including the customer
information and billing system, to accommodate electric industry restructuring.
To the extent that the Utility is unable to develop and implement such changes
in a successful and timely manner, there could be an adverse impact on the
Utility's or PG&E Corporation's future results of operations.
Electric Transition Plan:
Market-based revenues, determined by the market through sales to the PX, may
not be sufficient to recover (that is, to collect from customers) all of the
Utility's generation costs. To allow California investor-owned utilities the
opportunity to recover their transition costs (generation costs that would
not be recovered through market-based revenues) and to ensure a smooth
transition to a competitive market, the California legislature developed a
transition plan in the form of state legislation that was passed in 1996. The
transition plan will remain in effect until the earlier of December 31, 2001, or
when the Utility has recovered its authorized transition costs as determined by
the CPUC, with provisions that certain transition costs can be recovered after
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. The transition plan contains three principal elements: (1) an
electric rate freeze and rate reduction, (2) the recovery of transition costs,
and (3) divestiture of utility-owned generation facilities. Each element is
discussed below.
Rate Freeze and Rate Reduction: The first element of the transition plan is
an electric rate freeze and an electric rate reduction. In 1997 and 1998, the
Utility held rates for its larger customers at 1996 levels, and it will hold
their rates at that level until the end of the transition period. On January
1, 1998, the Utility reduced electric rates for its residential and small
commercial customers by 10 percent from 1996 levels, and it will hold their
rates at that level until the end of the transition period. Collectively, these
actions are called a rate freeze.
To pay for the 10 percent rate reduction, the Utility refinanced $2.9
billion of its transition costs with the proceeds of rate reduction bonds
(see Note 9 of Notes to Consolidated Financial Statements). The bonds allow
for the rate reduction by lowering the carrying cost on a portion of the
transition costs and by deferring recovery of a portion of these transition
costs until after the transition period.
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Transition costs are being recovered from all Utility distribution
customers through a nonbypassable charge regardless of the customer's choice
of electricity supplier. As the customer charge for transition costs is
nonbypassable, the Utility believes that the availability of choice to its
customers will not have a material impact on its ability to recover
transition costs.
Revenues from frozen electric rates provide for the recovery of authorized
Utility costs, including transmission and distribution service, public purpose
programs, and nuclear decommissioning. To the extent the revenues from frozen
rates exceed authorized Utility costs, the remaining revenues constitute the
competitive transition charge (CTC) which recovers the transition costs. These
CTC revenues are subject to seasonal fluctuations in the Utility's sales volumes
and certain other factors.
Transition Cost Recovery: Transition costs consist of: (1) above-market sunk
costs (sunk costs are costs associated with Utility-owned generation assets
that are fixed and unavoidable and currently included in the Utility customers'
electric rates) and future costs, such as costs related to plant removal of
Utility-owned generation facilities, (2) costs associated with the Utility's
long-term contracts to purchase power at above-market prices from qualifying
facilities 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.)
Above-market sunk costs result when the book value of a facility is
in excess of its market value. Conversely, below-market sunk costs result
when the market value of a facility is in excess of its book value. The total
amount of generation facility 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 these costs is eligible for recovery as a transition
cost. The below-market portion of these costs will reduce other unrecovered
transition costs. A valuation of a Utility-owned generation facility where
the market value exceeds the book value could result in a material charge to
Utility earnings if the valuation of the facility is determined based upon any
method other than a sale of the facility to a third party. This is because any
excess of market value over book value would be used to reduce other transition
costs.
The Utility will not be able to determine the exact amount of
above-market non-nuclear sunk costs that will be recoverable as transition
costs until a market valuation process (appraisal, spin, sale, or other
valuation method) is completed for each of its generation facilities. Several
of these valuations occurred in 1997 and 1998, when the Utility agreed to
sell seven of its electric plants. The market value of these facilities
determined by these sales exceeded the book value and will therefore reduce the
amount of transition costs to be recovered. In addition, in December 1998, the
Utility requested that the CPUC allow it to hire appraisers to set the value of
its hydroelectric generation system. (See Generation Divestiture below.) The
remainder of the valuation process is expected to be completed by December 31,
2001. Nuclear sunk costs were separately determined through a CPUC proceeding
and were subject to a final verification audit. This audit was completed in
August 1998, the results of which are currently under review. (See Regulatory
Matters below for further details.)
Costs associated with the Utility's long-term contracts to purchase
electric power at above-market prices are included as transition costs. Over
the remaining life of these contracts, the Utility estimates that it will
purchase 322 million megawatt-hours. To the extent that the individual
contract prices are 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. The contracts
expire at various dates through 2028. During 1998, the average price paid per
kilowatt-hour (kWh) under the Utility's long-term contracts for electric
power was 7.4 cents per kWh. The average cost of electric energy for energy
purchased at market rates from the PX for the period from April 1, 1998, to
December 31, 1998, was 3.2 cents per kWh.
Generation-related regulatory assets and obligations (net generation-related
regulatory assets) are included as transition costs. These net regulatory assets
consist of those created prior to the transition period and those created during
the transition period. In 1998, the staff of the Securities and Exchange
Commission (SEC) issued interpretive guidance related to assets which are being
transitioned to a deregulated environment. The
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MANAGEMENT'S DISCUSSION AND ANALYSIS
guidance states that an impairment analysis should be performed for such
assets and that the impairment analysis should exclude transition cost
revenues. The Utility has determined that certain of its generation
facilities are considered impaired under the SEC's interpretive guidance.
Because the Utility expects to recover the impaired assets as a transition cost,
it recorded a regulatory asset for the impaired amounts as required. As a
result, in 1998, $3.9 billion was reclassified from property, plant, and
equipment to regulatory assets on the Utility's balance sheet. Prior year
amounts were also reclassified. The Utility's generation-related regulatory
assets total $5.4 billion at December 31, 1998.
Under the transition plan, most transition costs can be recovered until
December 31, 2001. This recovery period is significantly shorter than the
recovery period of the generation assets prior to restructuring and is referred
to as accelerated recovery. Accordingly, the Utility is amortizing its
transition costs, including most generation-related regulatory assets over the
transition period. The CPUC believes that the transition plan reduces risks
associated with recovery of all the Utility's generation assets, including the
Diablo Canyon Nuclear Power Plant (Diablo Canyon) and the hydroelectric
facilities. As a result, during the transition period, the Utility is receiving
a reduced return on common equity for all of its generation assets, including
those generation assets reclassified to regulatory assets. In 1998, the reduced
return on common equity was 6.77 percent as compared to an authorized return on
common equity of 11.20 percent. The reduced return on common equity related to
generation assets will be in effect throughout the transition period.
Certain transition costs can be included in a nonbypassable charge to
distribution customers after the transition period. These costs include: (1)
certain employee-related transition costs, (2) above-market payments under
existing long-term contracts to purchase power, 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 our nuclear
facility. During the rate freeze, this charge and the rate reduction bond debt
service will not increase the 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, revenues provided for the
recovery of most non-nuclear transition costs are based upon the acceleration
of such costs 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 accelerated recovery of
the investment in Diablo Canyon from a period ending in 2016 to a five-year
period ending December 31, 2001.
The Utility is amortizing its eligible transition costs, including
generation-related regulatory assets, over the transition period in conjunction
with the available CTC revenues. Effective January 1, 1998, the Utility started
collecting these eligible transition costs through the nonbypassable CTC. During
1998, regulatory assets related to electric utility restructuring decreased by
$609 million. This decrease reflects the recovery of eligible transition costs
of $486 million through accelerated amortization and $123 million through the
gain on the sale of generating plants.
During the transition period, the CPUC will review the Utility's compliance
with the accounting methods used by the Utility to recover transition costs and
the amount of transition costs requested for recovery. The CPUC is currently
reviewing non-nuclear transition costs amortized during the first six months of
1998. The Utility expects the CPUC to issue decisions regarding this review in
the second half of 1999. Transition costs that are disallowed by the CPUC for
collection from the Utility customers will be written off.
Generation Divestiture: In 1998, the Utility completed the sale of three
fossil-fueled generation plants for $501 million. These three fossil-fueled
plants had a combined book value at the time of the sale of
$346 million and had a combined capacity of 2,645 megawatts (MW).
22
Also in 1998, the Utility agreed to sell three other fossil-fueled
generation plants and its complex of geothermal generation facilities. The
winning bids total $1,014 million. As of December 31, 1998, these four plants
had a combined book value of $523 million and had a combined capacity of
4,289 MW. The sales are subject to the approval of regulatory agencies,
including the CPUC, and conditioned upon the transfer of various permits and
licenses. The Utility expects to complete the sale of these four plants in
1999.
The Utility will retain a liability for required environmental
remediation related to all of its fossil-fueled and geothermal generation plants
of any pre-closing soil or groundwater contamination at the plants it has or
will sell. The Utility records its estimated liability for the retained
environmental remediation obligation as part of the determination of the gain or
loss on the sale of each plant.
Any net gains from the sale of our Utility-owned generation plants will be
used to offset other transition costs. As a result, we do not believe sales of
any generation facilities to a third party will have a material impact on our
results of operations.
The Utility is currently evaluating its options related to its remaining non-
nuclear generation facilities, primarily the hydroelectric generation system. In
May 1998, the Utility notified the CPUC that it does not plan to retain the
hydroelectric assets as part of the Utility. In December 1998, the Utility filed
with the CPUC its proposed appraisal process for valuing generation assets,
primarily the hydroelectric system. The Utility expects to receive a response to
this request in 1999.
At December 31, 1998, the book value of the Utility's net investment in
hydroelectric generation assets was $1.4 billion. If the Utility decides to
dispose of the hydroelectric generation assets by any method other than a sale
of the assets to a third party, a material charge could result to the extent
that the market value of the assets exceeds their book value. The market value
of the hydroelectric assets is expected to exceed their book value by a material
amount.
Financial Impact: The Utility's ability to continue recovering its transition
costs will be dependent on several factors including: (1) the continued
application of the regulatory framework established by the CPUC and state
legislation, (2) the amount of transition costs ultimately approved for recovery
by the CPUC, (3) the market value of the remaining 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 (see Regulatory Matters),
and (7) the market price of electricity. Given our current evaluation of these
factors, we believe that the Utility will recover its transition costs under the
terms of the approved transition plan. 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.
The Gas Business:
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 was implemented in 1998, and has four
principal elements:
1. The Accord separates or "unbundles" the rates for the Utility's gas
transportation system. The Utility now offers transmission, distribution, and
storage services as separate and distinct services to its noncore customers.
Unbundling gives these customers the opportunity to select from a menu of
services offered by the Utility and enables them to pay only for the services
that they use. Unbundling also makes access to the transmission system
possible for all gas marketers and shippers, as well as noncore end-users. As
a result, the Accord makes the Utility's transmission system more accessible
to a greater number of customers.
2. The Accord increases the opportunity for the Utility's core customers to
select the commodity gas supplier of their choice. Greater customer choice
increases competition among suppliers providing gas to core customers and
reduces the Utility's role in purchasing gas for such customers. Despite
these changes, the Utility continues to purchase gas as a regulated supplier
for those who request it, serving a majority of core customers in its service
territory.
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MANAGEMENT'S DISCUSSION AND ANALYSIS
3. The Accord changes the way in which the Utility's costs of purchasing gas for
core customers through 2002 are regulated. The Accord replaces CPUC
reasonableness reviews with the core procurement incentive mechanism (CPIM),
a form of incentive ratemaking that provides the Utility a direct financial
incentive to procure gas and transportation services at the lowest reasonable
costs by comparing all procurement costs to an aggregate market-based
benchmark. If costs fall within a range (tolerance band) around the
benchmark, costs are considered reasonable and fully recoverable from
ratepayers. If procurement costs fall outside the tolerance band, ratepayers
and shareholders share savings or costs, respectively. The CPIM results for
1997 and 1998 had an immaterial impact on the Utility's results of
operations.
4. The Accord settled various regulatory issues involving the 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 within California for the
period from March 1998 through December 2002 for the Utility's core and noncore
customers and eliminates regulatory protection for variations in sales volumes
for noncore transmission revenues. As a result, the Utility is 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 gas distribution services will continue to be set by the CPUC and
designed to provide the Utility an opportunity to recover its costs of service
and include a return on its investment. The regulatory mechanisms for setting
gas distribution rates are discussed below under Regulatory Matters.
New England Electricity Market
Three New England states where our unregulated businesses operate electric
generation facilities (Massachusetts, New Hampshire, and Rhode Island) were,
like California, among the first states in the country to introduce electric
industry restructuring. Connecticut also has passed electric industry
restructuring legislation. As a result of this restructuring, the wholesale
unregulated electricity market in New England features a bid-based market and
an independent system operator.
In September 1998, PG&E Corporation, through its indirect subsidiary USGen
New England, Inc., completed the acquisition of a portfolio of electric
generation assets and power supply contracts from New England Electric System
(NEES). (See Note 5 of Notes to Consolidated Financial Statements.) The NEES
assets include hydroelectric, coal, oil, and natural gas generation facilities
with a combined generating capacity of about 4,000 MW.
Including fuel and other inventories and transaction costs, the financing
requirements for this transaction were approximately $1.8 billion, funded
through $1.3 billion of USGen debt and a $425 million equity contribution from
PG&E Corporation. The net purchase price has been allocated as follows: (1)
electric generating assets of $2.3 billion, (2) receivable for support payments
of $0.8 billion, and (3) contractual obligations of $1.3 billion.
As part of the New England electric industry restructuring, the local utility
companies providing service to retail customers were required to offer Standard
Offer Service (SOS) to their customers. Retail customers may select alternative
suppliers at any time. The SOS is intended to provide customers with a price
benefit (the commodity electric price offered to the retail customer is expected
to be less than the market price) for the first several years, followed by a
price disincentive that is intended to stimulate the retail market.
Retail customers may continue to receive SOS through June 30, 2002, in New
Hampshire (subject to early termination on December 31, 2000, at the discretion
of the New Hampshire Public Service Commission), through December 31, 2004, in
Massachusetts, and through December 31, 2009, in Rhode Island. However, if any
customers elect to have their electricity provided by an alternate supplier,
they are precluded from going back to the SOS.
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In connection with the purchase of the generation assets, we entered into
agreements to supply the electric capacity and energy requirements necessary for
NEES to meet its SOS obligations. NEES is responsible for passing on to us the
revenues generated from the SOS.
Like California utilities, the New England utilities entered into agreements
with unregulated companies to provide energy and capacity at prices which are
anticipated to be in excess of market prices. We assumed NEES's contractual
rights and duties under several of these power-purchase agreements, which in
aggregate provide for 800 MW of capacity. However, NEES will make support
payments to us toward the cost of these agreements. The support payments by NEES
total $1.1 billion in the aggregate (undiscounted) and are due in monthly
installments from September 1998 through January 2008. In certain circumstances,
with our consent, NEES may make a full or partial lump sum accelerated payment.
Initially, approximately 90 percent of the acquired operating capacity,
including capacity and energy generated by other companies and provided to us
under power-purchase agreements, is dedicated to providing services to customers
receiving SOS.
Regulatory Matters
The Utility is the only subsidiary with significant regulatory activity at
this time. Items affecting future Utility authorized revenues include: the
1999 general rate case, the 1999 cost of capital proceeding, the distribution
performance based ratemaking application, and the CPUC's gas strategy order
instituting rulemaking. These items are discussed below. Any requested change
in authorized revenues resulting from any of these proceedings would not
impact the Utility's customer electric rates through the transition period
because these rates are frozen in accordance with the electric transition plan.
However, the amount of remaining revenues providing for the recovery of
transition costs would be affected.
The Utility's 1999 General Rate Case (GRC):
In December 1997, the Utility filed its 1999 GRC application with the CPUC.
During the GRC process, the CPUC examines the Utility's distribution costs to
determine the amount we can charge customers. The Utility has requested rate
increases to maintain and improve gas and electric distribution reliability,
safety, and customer service. The requested revenues, as updated, include an
increase of $445 million in electric base revenues and an increase of $377
million in gas base revenues over authorized 1998 revenues. The Office of
Ratepayer Advocates (ORA) branch of the CPUC has recommended a decrease of $80
million in electric revenues and an increase of $104 million in gas base
revenues. However, recommendations by the ORA do not represent the positions of
the CPUC.
In December 1998, the CPUC issued a decision on interim rate relief
in the GRC. The decision granted the Utility's request to increase its
electric revenues by $445 million and its gas revenues by $377 million on an
interim basis pending a decision in the GRC. The decision allows the Utility
to reflect the revenue increases, resulting from the Utility request, in
regulatory assets recorded under regulatory adjustment mechanisms approved by
the CPUC. The decision does not increase any electric or gas rates charged to
customers on an interim basis. The regulatory assets will be adjusted to
reflect the final decision of the CPUC in the 1999 GRC when the decision is
issued. We cannot predict the amount of revenue increase or decrease the CPUC
ultimately will approve. If the CPUC issues an unfavorable decision for the
Utility, the ability of the Utility to earn its authorized rate of return, at
the current service levels, for the years 1999 through 2001 could be
adversely affected. The current procedural schedule provides for a final CPUC
decision in March 1999.
The 1999 GRC will not affect the authorized revenues of electric and gas
transmission services or gas storage services. The authorized revenues for gas
transmission and storage services are determined through the Gas Accord and
electric transmission revenues are determined by the FERC as described below.
Electric Transmission:
Since April 1, 1998, all electric transmission revenues are authorized by the
FERC. In December 1997, the FERC issued an order which put into effect,
subject to refund, rates to recover annual electric transmission revenues of
$301 million from the Utility's former
25
MANAGEMENT'S DISCUSSION AND ANALYSIS
bundled rate transmission customers. These rates became effective on April 1,
1998, the operational date of the ISO and PX. In May 1998, the FERC allowed a
$30 million increase in electric transmission revenues, effective October 30,
1998, also subject to refund.
The Utility's 1999 Cost of Capital Proceeding:
The Utility filed its cost of capital application in May 1998. If approved, the
authorized return on rate base for distribution assets would be 9.53 percent.
The 1999 cost of common equity would be 12.1 percent which is higher than the
11.2 percent authorized in 1998. This request would result in an increase of
$49.7 million in electric distribution revenues and an increase of $15.5 million
in gas distribution revenues over authorized 1998 revenues.
The ORA has recommended an overall return on rate base for electric and gas
distribution operations of 7.85 and 8.17 percent, respectively, and a cost of
common equity of 8.64 and 9.32 percent, respectively. If adopted, the ORA's
recommendation would result in a decrease from authorized 1998 revenues in
electric and gas distribution revenues of $162.5 million and $37.8 million,
respectively. However, recommendations by the ORA do not represent the positions
of the CPUC. We expect a final CPUC decision in early 1999.
The Utility's Distribution Performance Based Ratemaking (PBR) Application:
The Utility filed its distribution PBR proposal in November 1998. If approved
as filed, the distribution PBR will determine the Utility's gas and electric
distribution revenues for the years 2000 through 2004. Under the Utility's
proposal, distribution revenues for the year 2000 would be determined by
multiplying total distribution revenues by a rate formula, based principally
on inflation less a proposed productivity factor of 1.1 percent and 0.82
percent for electric distribution and gas distribution, respectively. These
productivity factors will be fixed for the five year duration of the PBR. The
revenues for years 2000 through 2004 would be determined by multiplying total
distribution revenues by the PBR authorized rate. We have proposed different
formulas for small customers (principally residential and commercial
customers) and large customers.
The proposal also includes a sharing mechanism for earnings that are
significantly above or below the authorized weighted average cost of capital. In
addition, the proposed PBR includes rewards and penalties that will depend upon
the Utility's ability to achieve performance standards for electric distribution
reliability; maintenance, repair, and replacement; customer service; and
employee safety. The Commission will have hearings in the PBR proceeding in
August 1999 to determine adopted values for the PBR formula and sharing
parameters. The final schedule is uncertain, but a Commission decision is
expected after January 1, 2000. In this event, the Utility proposes to implement
the PBR-based distribution component rates retroactively to January 1, 2000.
The CPUC's Gas Strategy Order Instituting Rulemaking (OIR):
In 1998, the Governor of California signed Senate Bill 1602, allowing the CPUC
to investigate issues associated with the further restructuring of natural gas
services. If the CPUC determines that further restructuring for core customers
is in the public interest, it shall submit its findings to the Legislature.
However, Senate Bill 1602 prohibits the CPUC from enacting any such gas industry
restructuring decisions prior to January 1, 2000.
The CPUC's Audit of Affiliate Transactions:
PG&E Corporation became the holding company of the Utility in 1997. At that
time, we transferred the unregulated subsidiaries of the Utility to PG&E
Corporation. A condition of the CPUC's approval of the holding company formation
was that the ORA oversee an audit of transactions between the Utility and its
affiliates for the period 1994 to 1996. The audit was completed in November
1997. The principal claim in the resulting audit report, substantially denied by
the Utility, was that the Utility underbilled affiliates by $35 million during
the period from 1994 to 1996. The auditors recommended the CPUC impose new
conditions, affecting the financing and business structure of PG&E Corporation.
We are opposing the recommended new conditions. A final CPUC decision is
expected during the first quarter of 1999.
26
If the CPUC imposed the recommended financial conditions on PG&E Corporation
without modification, such conditions could have an adverse impact on our
ability to implement our national energy strategy.
The Diablo Canyon Sunk Costs Audit:
In August 1998, an independent accounting firm retained by the CPUC completed
a financial verification audit of the Utility's Diablo Canyon plant accounts
as of December 31, 1996. The audit resulted in the issuance of an unqualified
opinion. The audit verified that Diablo Canyon sunk costs at December 31,
1996, were $3.3 billion of the total $7.1 billion construction 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.) The independent accounting firm also issued an agreed-upon special
procedures report which questioned $200 million of the $3.3 billion sunk costs.
The CPUC will review any proposed adjustments to Diablo Canyon's recoverable
costs, which resulted from the report. At this time, the Utility cannot predict
what actions, if any, the CPUC may take regarding the audit report.
Results of Operations
In this section, we present the components of our results of operations for
1998, 1997, and 1996. The table below shows for 1998, 1997, and 1996, certain
items from our Statement of Consolidated Income detailed by (1) Utility, (2)
wholesale and (3) retail business operations of PG&E Corporation. (In the
"Total" column, the table shows the combined results of operations for these
three groups.) The information for PG&E Corporation (the "Total" column)
excludes all transactions between its subsidiaries (such as the purchase of
natural gas by the Utility from the unregulated business operations).
Following this table we discuss earnings and explain why the components of
our results of operations varied from the year before for 1998 and 1997.
Wholesale Retail
---------------------------------- ------
PG&E GT
-------------
(In millions) Utility USGen NW Texas PG&E ET PG&E ES Corp./Other Eliminations Total
------- ----- -- ----- ------- ------- ----------- ------------ -----
1998
Operating revenues $8,924 $649 $237 $1,941 $8,509 $379 $ 8 $(705) $19,942
Operating expenses 7,048 489 101 1,996 8,528 470 3 (700) 17,935
------ ---- ---- ------ ------ ---- ---- ----- -------
Operating income (loss) 1,876 160 136 (55) (19) (91) 5 (5) 2,007
Other income, net 64
Interest expense 782
Income taxes 570
------ ---- ---- ------ ------ ---- ---- ----- -------
Net income $ 719
=======
1997
Operating revenues $9,495 $148 $233 $1,004 $4,808 $145 $13 $(446) $15,400
Operating expenses 7,664 176 127 1,023 4,840 190 98 (446) 13,672
------ ---- ---- ------ ------ ---- ---- ----- -------
Operating income (loss) 1,831 (28) 106 (19) (32) (45) (85) -- 1,728
Other income, net 201
Interest expense 665
Income taxes 548
------ ---- ---- ------ ------ ---- ---- ----- -------
Net income $ 716
=======
1996
Operating revenues $8,989 $105 $264 $ -- $ 283 $ -- $ 27 $ (58) $ 9,610
Operating expenses 7,179 118 136 -- 283 -- 56 (58) 7,714
------ ---- ---- ------ ------ ---- ---- ----- -------
Operating income (loss) 1,810 (13) 128 -- -- -- (29) -- 1,896
Other income, net 13
Interest expense 632
Income taxes 555
------ ---- ---- ------ ------ ---- ---- ----- -------
Net income $ 722
=======
27
MANAGEMENT'S DISCUSSION AND ANALYSIS
Overall Results:
PG&E Corporation:
Net income increased to $719 million in 1998 from $716 million in 1997. The
increase in 1998 net income was the result of a $279 million increase in
operating income, net of lower returns on the Utility's generation assets. This
increase was offset partially by increased interest costs for the Utility's rate
reduction bonds and debt associated with the recent unregulated wholesale
acquisitions of assets in Texas and New England.
The operating income increase of $279 million was primarily due to the growth
of our wholesale and retail operations which contributed $149 million of the
increase. This operating income increase was achieved despite operating losses
at PG&E ES and PG&E GTT. USGen contributed positively to operating income which
includes income generated from its portfolio management activities.
The operating losses at PG&EES reflect the continued start-up operations and
the impact of the developing retail energy market. At PG&E GTT, the natural gas
liquids operations have been adversely affected by the low price differential
between natural gas liquids (NGLs) prices and the cost of natural gas, which is
used to produce NGLs. In addition, low gas prices and a narrow spread in the
price of gas transported across Texas have reduced PG&E GTT's transportation and
gas sales.
The 1998 net income also includes a loss on the sale of our Australian energy
holdings. The sale represented a significant premium in Australian currency of
PG&E Corporation's 1996 investment in the assets. However, there was a 22
percent currency devaluation of the Australian dollar against the U.S. dollar
during the past two years. The net transaction resulted in a charge of
approximately $23 million in the second quarter of 1998. (See Note 5 of Notes to
Consolidated Financial Statements.)
Net income decreased from $722 million in 1996 to $716 million in 1997. The
1997 net income includes charges of approximately $51 million associated with
the write off of investments in power generation projects at USGen, which were
offset by the gain realized on the sale of our interests in International
Generation Company, Ltd. In April 1997, PG&E Enterprises, a wholly owned
subsidiary of PG&E Corporation, sold its interest in International Generating
Company, Ltd., which resulted in an after-tax gain of $120 million.
Utility:
Net income for the Utility decreased $39 million in 1998 from 1997 due to the
reduced rate of return on generation assets and increased interest expense
associated with the rate reduction bonds, discussed below.
Net income for the Utility increased $13 million in 1997 from 1996. Net
income for 1997 included a gain on the buy out of a long-term gas contract. The
increase in 1997 is also related to the increase in revenues associated with
electric transmission and distribution system reliability, discussed below. This
increase is partially offset by the reduction in returns on the Utility's Diablo
Canyon facility as required by electric industry restructuring legislation and
spending for system reliability and safety.
Operating Revenues:
Utility:
Utility operating revenues decreased $571 million in 1998 from 1997. This
decrease is primarily due to: (1) a $410 million decrease for the 10 percent
electric rate reduction provided to residential and small commercial customers,
which was partially offset by $108 million of higher revenues due to increased
consumption of electricity by these customers; (2) a $151 million decrease in
revenues from medium and large electric customers, many of whom are now
purchasing their electricity directly from unregulated power generators; (3) a
$63 million decrease in sales to commercial and agricultural electric customers
resulting from their lower demand for irrigation water pumping as a result of
heavier rainfall in the current year; and (4) a $100 million decrease for the
termination of the volumetric (ERAM) and energy cost (ECAC) revenue balancing
accounts. The ERAM and ECAC accounts were replaced with the transition cost
balancing account, which affects expenses, rather than revenues.
Utility operating revenues in 1997 increased $506 million from 1996. The
largest portion of the increase was due to electric transition cost recovery,
which began January 1, 1997, with respect to Diablo Canyon. A portion of the
increase is due to increased revenues
28
associated with electric transmission and distribution system reliability. There
was also an increase in energy cost revenues to recover energy cost increases
and changes in sales volumes provided by the Utility's balancing account
mechanisms in place in 1997 and 1996. Under these mechanisms, energy revenues
generally equal energy costs and, thus, increases in the cost of energy do not
affect operating income.
Wholesale Unregulated Business Operations:
Operating revenues associated with wholesale unregulated business operations
increased $5,143 million in 1998 from 1997. This was primarily due to revenue
increases of $3,701 million from PG&E ET, $937 million from PG&E GTT and $501
million from USGen. Energy trading volumes grew at PG&E ET as growth of PG&E
Corporation and deregulation of the energy markets continued. PG&E GTT's
revenues increased as a result of twelve months of revenue from the Texas
acquisitions versus seven months in 1997. USGen's revenue increased as a result
of an increase in the portfolio management activity and the acquisition of NEES
in 1998.
Operating revenues associated with wholesale unregulated business operations
increased $5,541 million in 1997 from 1996. This was primarily due to a $4,525
million increase in energy commodities revenues and an increase in revenues
resulting from our 1997 acquisitions.
Retail Unregulated Business Operations:
Retail unregulated business operations contributed $379 million of revenue in
1998, an increase of $234 million from 1997. This increase is primarily due to
deregulation in California and the expansion of our energy services business in
the electric and gas commodity markets.
Operating revenues associated with retail unregulated business operations
totaled $145 million in 1997, the first year of operation.
Operating Expenses:
Utility:
Utility operating expenses in 1998 decreased $616 million from 1997. This
decrease reflects a reduction in the amount of amortization of transition
costs, primarily due to lower revenues from residential and small commercial
customers discussed above in Operating Revenues-Utility. Also contributing to
the decrease in operating expenses was a reduction in gas transportation
demand charges of $134 million, due to the expiration of contracted pipeline
capacity.
Utility operating expenses in 1997 increased $485 million from 1996. The
increase was due primarily to an increase in amortization of Diablo Canyon costs
which are being recovered as a transition cost as discussed above, an increase
in cost of energy, and an increase in expenditures associated with system
reliability. These increases were partially offset by a decrease in expenses
resulting from several charges in 1996 associated with gas transportation
commitments and a litigation reserve.
Wholesale Unregulated Business Operations:
Operating expenses for our wholesale unregulated business operations increased
$4,948 million in 1998 from 1997. This reflects the increase in the volumes of
energy commodities purchased at PG&EETand operating costs associated with our
newly acquired New England assets at USGen and the gas transportation assets at
PG&E GTT.
Wholesale unregulated business operations operating expenses in 1997
increased $5,629 million from 1996, which reflects the increase in the volume of
energy commodities purchased due to our 1997 acquisitions.
Retail Unregulated Business Operations:
Retail unregulated business operations operating expenses increased $280
million in 1998 as compared to 1997. This increase is primarily due to the
expansion of our energy services business.
Retail unregulated business operations operating expenses totaled $190
million in 1997, the first year of operation.
Other Income, Net:
Other income, net was $64 million in 1998 as compared to $201 million in 1997.
The decrease was primarily due to the $23 million loss on the sale of our
Australian holdings, discussed above, and a $120 million gain recorded in 1997.
29
MANAGEMENT'S DISCUSSION AND ANALYSIS
Other income, net increased by $188 million in 1997 as compared to 1996
primarily due to a $120 million gain realized on the sale of interests in
International Generating Company, Ltd.
Interest Expense:
Interest expense increased $117 million in 1998 from 1997. This increase was
primarily a result of increased interest costs for the Utility's rate reduction
bonds and debt for the acquisition of the Texas and New England assets.
Interest expense in 1997 increased $33 million from 1996 primarily due to
interest costs related to the Texas acquisitions.
Income Taxes:
Income taxes in 1998 increased $22 million from 1997. The overall effective
tax rate increased 0.9 percent in 1998 largely due to accelerated book
depreciation and amortization related to electric industry restructuring.
These increases were partially offset by a lowered effective state tax rate
resulting from our expanded business operations.
The effective tax rate decreased slightly in 1997 as compared to 1996,
resulting in a $7 million decrease in 1997 taxes.
Common Stock Dividend:
We base our common stock dividend 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. We continually review the level of our
common stock dividend taking into consideration the impact of the changing
regulatory environment throughout the nation, the resolution of asset
dispositions, the operating performance of our business units, and our
capital and financial resources in general.
The CPUC requires the Utility to maintain its CPUC-authorized capital
structure, potentially limiting the amount of dividends the Utility may pay
PG&E Corporation. In 1998, the Utility was in compliance with its
CPUC-authorized capital structure. PG&E Corporation and the Utility believe
that the Utility will continue to meet this requirement in the future without
affecting PG&E Corporation's ability to pay common stock dividends.
Liquidity and Financial Resources
Cash Flows from Operating Activities:
Net cash provided by PG&E Corporation's operating activities totaled $2.3
billion, $2.6 billion, and $2.6 billion in 1998, 1997, and 1996, respectively.
Net cash provided by the Utility's operating activities totaled $2.6 billion,
$1.8 billion, and $2.6 billion in 1998, 1997, and 1996, respectively.
Cash Flows from Financing Activities:
PG&E Corporation:
We fund investing activities from cash provided by operations after capital
requirements and, to the extent necessary, external financing. Our policy is
to finance our investments with a capital structure that minimizes financing
costs, maintains financial flexibility, and, with regard to the Utility,
complies with regulatory guidelines. Based on cash provided from operations
and our investing and disposition activities, we may repurchase equity and
long-term debt in order to manage the overall size and balance of our capital
structure.
During 1998, 1997, and 1996, we issued $63 million, $54 million, and
$220 million of common stock, respectively, primarily through the Dividend
Reinvestment Plan, the Stock Option Plan, and the Long-Term Incentive Plan.
During 1997, we also issued $1.1 billion of common stock to acquire the
natural gas assets in Texas. During 1998, 1997, and 1996, we paid dividends
of $470 million, $524 million, and $844 million, respectively.
During 1998, 1997, and 1996, we repurchased $1,158 million, $804 million, and
$455 million, respectively, of our common stock. In February 1999, PG&E
Corporation used the remaining portion of an existing authorization to
repurchase 16.6 million shares at a price of $30.25 per share.
In 1998, our unregulated business operations retired $75 million of
long-term debt and retired the notes used in our acquisition of the
Australian holdings. During 1997, our unregulated business operations issued
$30 million and retired $109 million of long-term debt. Also in 1997, we
assumed $780 million of
30
long-term debt in connection with the acquisition of the natural gas assets in
Texas. In 1996, we entered into additional loan agreements of $92 million to
finance the acquisition of our energy holdings in Australia.
We maintain a number of credit facilities throughout our organization to
support commercial paper programs, letters of credit, and other short term
liquidity requirements. At PG&E Corporation, we maintain two $500 million
revolving credit facilities, one of which expires in November 1999 and the other
in 2002. The PG&E Corporation credit facilities are used to support the
commerical paper program and other liquidity needs. The facility expiring in
1999 may be extended annually for additional one-year periods upon agreement
between the lending institutions and us. There was $683 million of commercial
paper outstanding at December 31, 1998.
In September 1998, USGen obtained $1,675 million in revolving credit
facilities. Of these, $575 million is specifically related to the New England
operations. Of the New England facility, $475 million was used to execute a sale
leaseback transaction related to the newly acquired New England assets and
subsequently cancelled. No amounts are outstanding under the New England
facilities at December 31, 1998. USGen, itself, maintains two credit facilities
of $550 million each. One agreement expires in August 1999 and the other in
2003. These facilities were used in the acquisition of the New England assets
and for general corporate purposes. The total amount outstanding at December 31,
1998, backed by the facilities, was $540 million in eurodollar loans and $233
million in commercial paper. Of these loans, $550 million is classified as
noncurrent in the consolidated balance sheet.
At December 31, 1998, PG&E GTT had $70 million of outstanding short-term bank
borrowings related to two separate credit facilities. These lines are cancelable
upon demand and bear interest at each respective bank's quoted money market
rate. The borrowings are unsecured and unrestricted as to use.
PG&E GT NW maintains a $200 million revolving credit facility which expires
in the year 2000. At December 31, 1998 and 1997, PG&E GT NW had outstanding
commercial paper balances of $104 million and $80 million, respectively,
supported by this revolving facility. These balances were classified as
noncurrent obligations in the consolidated balance sheet.
Utility:
In 1998, the Utility repurchased $1.6 billion of its common stock from PG&E
Corporation to maintain its authorized capital structure.
The Utility's long-term debt that either matured, was redeemed, or was
repurchased during 1998 totaled $1.4 billion. Of this amount, (1) $249 million
related to the Utility's redemption of its 8% mortgage bonds due October 1,
2025; (2) $252 million related to the Utility's repurchase of various other
mortgage bonds; (3) $397 million related to the maturity of the Utility's 5 3\8%
mortgage bonds; (4) $204 million related to the other scheduled maturities of
long-term debt; and (5) $290 million related to rate reduction bonds maturing.
In 1997 and 1996, the Utility redeemed or repurchased $225 million and $1,113
million, respectively, of long-term debt to manage the overall balance of its
capital structure. In 1997, the Utility replaced $360 million of fixed interest
rate pollution control bonds with the same amount of variable interest rate
pollution control bonds. In 1996, the Utility replaced $988 million of variable
interest rate and fixed interest rate pollution control mortgage bonds and loan
agreements with the same amount of variable interest rate pollution control loan
agreements.
In 1998, the Utility redeemed its Series 7.44% preferred stock with a face
value of $65 million and its Series 6 7\8% preferred stock with a face value of
$43 million. During 1997 and 1996, the Utility did not redeem or repurchase any
of its preferred stock. 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 were used by the Utility to retire debt and reduce equity. (See Note 9
of Notes to Consolidated Financial Statements.)
31
MANAGEMENT'S DISCUSSION AND ANALYSIS
The Utility maintains a $1 billion revolving credit facility, which expires
in 2002. The Utility may extend the facility annually for additional one-year
periods upon agreement with the banks. This facility is used to support the
Utility's commercial paper program and other liquidity requirements. At December
31, 1998, the Utility had $567 million of commercial paper and $101 million of
bank notes outstanding. No amounts were outstanding at December 31, 1997.
Debt Obligations and Rate Reduction Bonds:
The table below provides information about our debt obligations and rate
reduction bonds at December 31, 1998:
Expected maturity date 1999 2000 2001 2002 2003 Thereafter Total
- ---------------------- ---- ---- ---- ---- ---- ---------- -----
(dollars in millions)
Utility:
Long-term debt
Variable rate obligations -- $200 $100 $738 $310 -- $1,348
Fixed rate obligations $260 $266 $274 $382 $372 $2,802 $4,356
Average interest rate 6.2% 6.6% 8.0% 7.8% 6.3% 7.1% 7.1%
Rate reduction bonds $290 $290 $290 $290 $290 $1,161 $2,611
Average interest rate 6.1% 6.2% 6.2% 6.3% 6.4% 6.4% 6.3%
---- ---- ---- ---- ---- ------ ------
Wholesale and Retail Unregulated
Business Operations:
Long-term debt
Variable rate obligations $ 7 $115 $ 12 $ 10 $560 $ 125 $ 829
Fixed rate obligations $ 71 $117 $ 94 $126 $ 46 $ 773 $1,227
Average interest rate 10.4% 9.1% 9.1% 8.7% 9.9% 8.2% 8.6%
---- ---- ---- ---- ---- ------ ------
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.
The Utility's estimated capital spending for 1999 is $1.7 billion. Utility
capital expenditures are based on estimates prepared for the Utility's GRC, but
exclude capital expenditures for divested fossil and geothermal power plants.
These estimates may be reduced if the CPUC authorized base revenues are
significantly lower than those requested by the Utility in its GRC filing.
In 1998, the Utility had proceeds of $501 million from the sale of
three fossil-fueled generation plants. Also in 1998, PG&E Corporation sold its
Australian energy holdings, for proceeds of approximately $126 million. In 1997,
PG&E Corporation sold its interest in International Generating Company, Ltd.,
resulting in an after-tax gain of approximately $120 million.
Also in 1998, the Utility agreed to sell three other fossil-fueled
generation plants and to sell its complex of geothermal generation
facilities. The winning bids total $1,014 million. As of December 31, 1998,
these four plants had a combined book value of $523 million and had a
combined capacity of 4,289 MW. The sales are subject to the approval of
regulatory agencies, including the CPUC, and conditioned upon the transfer of
various permits and licenses. The Utility expects to complete the sale of
these four plants in 1999.
Environmental Matters:
We are subject to laws and regulations established to both maintain and improve
the quality of the environment. Where our properties contain hazardous
substances, these laws and regulations require us to remove those substances or
remedy effects on the environment.
At December 31, 1998, the Utility expects to spend $296 million over the next
30 years for cleanup costs at identified sites. If other responsible parties
fail to pay or expected outcomes change, then these costs may be as much as $487
million. Of the $296 million, the Utility has recovered $104 million (including
remediation of generation plants divested, discussed above) and expects to
recover another $160 million in future rates. The Utility mitigates its cost by
seeking recovery from insurance carriers and other third parties. (See Note 15
of Notes to Consolidated Financial Statements.)
32
The cost of the hazardous substance remediation ultimately undertaken
by the Utility is difficult to estimate. A change in the estimate may 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 estimated costs 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 expected outcomes change.
Year 2000:
The Year 2000 issue exists because many computer programs use only two digits
to refer to a year, and were developed without considering the impact of the
upcoming change in the century. If PG&E Corporation's computer systems fail
or function incorrectly due to not being made Year 2000 ready, they could
directly and adversely affect our ability to generate or deliver our products
and services or could otherwise affect revenues, safety, or reliability for
such a period of time as to lead to unrecoverable consequences.
Our plan to address the Year 2000 issues focuses on mission-critical systems
whose components are categorized as in-house software, vendor software, embedded
systems, and computer hardware. The four phases of our plan to address these
systems are inventory and assessment, remediation, testing, and certification.
Certification occurs when mission-critical systems are formally determined to be
Year 2000 ready.
Our Year 2000 project is generally proceeding on schedule. The following
table indicates our Year 2000 progress as of January 11, 1999. The percentages
in this table reflect approximations based on a standardized reporting system
that combines subsidiary results to provide a consistent, company-wide view.
Year 2000 Readiness of Mission-Critical Items
Remediation Testing Certification
Complete Complete Complete
----------- -------- -------------
In-house software 94% 91% 11%
Vendor software 53% 26% 2%
Embedded systems 95% 91% 0%
Computer hardware 92% 60% 0%
Changes in company inventories, or issues uncovered in subsequent phases for
an item previously reported as completed, may lead to downward adjustments in
percentages from period to period. Also, the completion of these phases does not
address external interdependencies that could affect the ability of the company
to be Year 2000 ready. Even after systems are certified, we may continue various
kinds of testing through the end of 1999.
Although 91 percent of remediation and testing of embedded systems has been
completed, the remaining 9 percent in this area may require some of the more
challenging work.
In addition to internal systems, we also depend upon external parties,
including customers, suppliers, business partners, gas and electric system
operators, government agencies, and financial institutions to support the
functioning of our business. To the extent that any of these parties are
considered mission-critical to our business and experience Year 2000 problems in
their systems, our mission-critical business functions may be adversely
affected. To deal with this vulnerability, we have another phased approach. The
primary phases for dealing with external parties are: (1) inventory, (2) action
planning, (3) risk assessment, and (4) contingency planning. We have completed
our inventory and action planning phases for mission-critical external parties.
We expect to complete the risk assessment by March 1999 and the contingency
planning phase by July 1999.
Although we expect our efforts and those of our external parties to be
largely successful, we recognize that with the complex interaction of today's
computing and communications systems, we cannot be certain we will be completely
successful. Therefore, contingency plans for Year 2000 readiness are being
developed and tested throughout 1999 to address our external dependencies as
well as any significant schedule delays of mission-critical system work, should
they occur. These plans will take into account possible interruptions of power,
computing, financial, and communications infrastructures. Due to the speculative
nature of contingency planning, however, it is uncertain whether these plans
will be sufficient to remove the risk of material impacts on our operations
resulting from Year 2000 problems.
33
MANAGEMENT'S DISCUSSION AND ANALYSIS
In 1997 and through December 1998, we spent approximately $108 million to
assess and remediate Year 2000 problems. About $64 million of this cost was for
software systems that we replaced for business purposes generally unrelated to
addressing Year 2000 readiness, but whose schedule we advanced to meet Year 2000
requirements. The replacement costs for these accelerated systems were
capitalized. Our estimate of future costs to address mission-critical Year 2000
issues is approximately $140 million. About $60 million of these remaining Year
2000 costs will be capitalized because they relate to the purchase and
installation of systems and equipment for general business purposes and the
remaining $80 million will be expensed.
Based on our current schedule for the completion of Year 2000 tasks, we
expect to secure Year 2000 readiness of our mission-critical systems by the end
of the third quarter of 1999. However, as our current schedule is partially
dependent on the efforts of third parties, their delays may cause our schedule
to change.
If we, or third parties with whom we have significant business relationships,
fail to achieve Year 2000 readiness of mission-critical systems, there could be
a material adverse impact on the Utility's and PG&E Corporation's financial
position, results of operations, and cash flows.
Inflation:
Financial statements, which are prepared in accordance with generally accepted
accounting principles, report operating results in terms of historical 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 results of operations.
Price Risk Management Activities:
We have established a price risk management policy which 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 gather market
intelligence, create liquidity, and maintain a market presence. Such derivatives
include forward contracts, futures, swaps, and options. Net open positions often
exist or are established due to PG&E Corporation's assessment of its response to
changing market conditions. To the extent that PG&E Corporation has an open
position, it is exposed to the risk that fluctuating market prices may adversely
impact its financial results. 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.
PG&E Corporation prepares a daily assessment of its portfolio market risk
exposure using value-at-risk and other methodologies that simulate future price
movements in the energy markets to estimate the size and probability of future
potential losses. The quantification of market risk using value-at-risk provides
a consistent measure of risk across diverse energy markets and products. The use
of this methodology requires a number of important assumptions including the
selection of a confidence level for losses, volatility of prices, market
liquidity, and a holding period.
PG&E Corporation utilizes historical data for calculating the price
volatility of PG&E Corporation's positions and how likely the prices of those
positions will move together. The model includes all derivative and commodity
investments for its trading portfolio and only derivative commodity investments
for its hedging portfolio (but not the related underlying hedged position). PG&E
Corporation expresses value-at-risk as a dollar amount of the potential loss in
the fair value of its portfolio based on a 95 percent confidence level using a
one-day liquidation period. Therefore, there is a 5 percent probability that a
portfolio will incur a loss in one day greater than its value-at-risk. The
value-at-risk is aggregated for PG&E Corporation as a whole by correlating the
daily returns of the portfolios for natural gas, natural gas liquids, and power
for the previous 22 trading days. PG&E Corporation's daily value-at-risk for
commodity price sensitive derivative instruments as of December 31, 1998, is
$6.2 million for trading activities and $0.2 million for non-trading activities.
34
Value-at-risk has several limitations as a measure of portfolio risk
including, but not limited to, underestimation of the risk of a portfolio with
significant options exposure, inadequate indication of the exposure of a
portfolio to extreme price movements, and the inability to address the risk
resulting from intraday trading activities.
In June 1998, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards (SFAS) No. 133, Accounting for Derivative
Instruments and Hedging Activities, which is required to be adopted in years
beginning after June 15, 1999. The Statement permits early adoption as of the
beginning of any fiscal quarter. PG&E Corporation expects to adopt the new
Statement no later than January 1, 2000. The Statement will require PG&E
Corporation to recognize all derivatives, as defined in the Statement, on the
balance sheet at fair value. Derivatives, or any portion thereof, that are not
effective hedges must be adjusted to fair value through income. If derivatives
are effective hedges, depending on the nature of the hedges, changes in the fair
value of derivatives either will be offset against the change in fair value of
the hedged assets, liabilities, or firm commitments through earnings or will be
recognized in other comprehensive income until the hedged items are recognized
in earnings. PG&E Corporation is currently evaluating what the effect of SFAS
No. 133 will be on the earnings and financial position of PG&E Corporation. PG&E
Corporation uses the mark-to-market method of accounting for its commodity
trading and price risk management activities.
In November 1998, the Emerging Issues Task Force of the Financial Accounting
Standards Board released Issue 98-10, Accounting for Energy Trading and Risk
Management Activities. This Issue states that all energy-related contracts
entered into with the objective of generating profits on or from exposure to
shifts or changes in market prices be marked to market with the gains and losses
reflected in the income statement. The Task Force stipulates implementation for
fiscal years beginning after December 15, 1998. PG&E Corporation does not
believe that the effect of adoption of this standard on earnings or the
financial position of PG&E Corporation will be material.
Legal Matters:
In the normal course of business, both the Utility and PG&E Corporation are
named as parties in a number of claims and lawsuits. (See Note 15 of Notes to
Consolidated Financial Statements for further discussion of significant pending
legal matters.)
35
PG&E Corporation
STATEMENT OF CONSOLIDATED INCOME
(in millions, except per share amounts) Year ended December 31,
-----------------------------
1998 1997 1996
------- ------- -------
Operating Revenues
Utility $ 8,924 $ 9,495 $ 8,989
Energy commodities and services 11,018 5,905 621
------- ------- -------
Total operating revenues 19,942 15,400 9,610
------- ------- -------
Operating Expenses
Cost of energy for utility 3,029 3,287 3,142
Cost of energy commodities and services 10,194 5,481 356
Operating and maintenance, net 3,103 3,052 2,994
Depreciation, amortization, and
decommissioning 1,609 1,852 1,222
------- ------- -------
Total operating expenses 17,935 13,672 7,714
------- ------- -------
Operating Income 2,007 1,728 1,896
Interest expense, net (782) (665) (632)
Other income, net 64 201 13
------- ------- -------
Income Before Income Taxes 1,289 1,264 1,277
Income taxes 570 548 555
------- ------- -------
Net Income $ 719 $ 716 $ 722
======= ======= =======
Weighted Average Common Shares Outstanding 382 410 413
Earnings Per Common Share, Basic and
Diluted $ 1.88 $ 1.75 $ 1.75
Dividends Declared Per Common Share $ 1.20 $ 1.20 $ 1.77
The accompanying Notes to the Consolidated Financial Statements are an
integral part of this statement.
36
PG&E Corporation
CONSOLIDATED BALANCE SHEET
(in millions) Balance at December 31, 1998 1997
---- ----
Assets
Current Assets
Cash and cash equivalents $ 286 $ 237
Short-term investments 55 1,160
Accounts receivable
Customers, net 1,856 1,514
Regulatory balancing accounts -- 458
Energy marketing 507 830
Price risk management 1,416 500
Inventories and prepayments 835 626
-------- --------
Total current assets 4,955 5,325
Property, Plant, and Equipment
Utility 23,996 23,764
Wholesale and retail unregulated business
operations
Electric generation 1,967 --
Gas transmission 3,347 3,415
Construction work in progress 407 492
Other 127 55
-------- --------
Total property, plant, and equipment
(at original cost) 29,844 27,726
Accumulated depreciation and decommissioning (12,026) (11,617)
-------- --------
Net property, plant, and equipment 17,818 16,109
Other Noncurrent Assets
Regulatory assets 6,347 6,900
Nuclear decommissioning funds 1,172 1,024
Other 2,942 1,757
-------- --------
Total noncurrent assets 10,461 9,681
-------- --------
Total Assets $ 33,234 $ 31,115
======== ========
37
PG&E Corporation
CONSOLIDATED BALANCE SHEET
(in millions) Balance at December 31, 1998 1997
---- ----
Liabilities and Equity
Current Liabilities
Short-term borrowings $ 1,644 $ 103
Current portion of long-term debt 338 659
Current portion of rate reduction bonds 290 290
Accounts payable
Trade creditors 1,001 754
Other 443 466
Regulatory balancing accounts 79 --
Energy marketing 381 758
Accrued taxes 103 226
Price risk management 1,412 512
Other 1,064 893
------- -------
Total current liabilities 6,755 4,661
Noncurrent Liabilities
Long-term debt 7,422 7,659
Rate reduction bonds 2,321 2,611
Deferred income taxes 3,861 4,029
Deferred tax credits 283 339
Other 3,746 2,024
------- -------
Total noncurrent liabilities 17,633 16,662
Preferred Stock of Subsidiaries 480 595
Utility Obligated Mandatorily Redeemable
Preferred Securities of Trust Holding
Solely Utility Subordinated Debentures 300 300
Common Stockholders' Equity
Common stock, no par value, authorized
800,000,000 shares, issued and outstanding,
382,603,564 and 417,665,891 5,862 6,366
Reinvested earnings 2,204 2,531
------- -------
Total common stockholders' equity 8,066 8,897
------- -------
Commitments and Contingencies (Notes 1,
2, 3, 4, 5, 14, and 15) -- --
------- -------
Total Liabilities and Stockholders' Equity $33,234 $31,115
======= =======
The accompanying Notes to the Consolidated Financial Statements are an
integral part of this statement
38
PG&E Corporation
STATEMENT OF CONSOLIDATED CASH FLOWS
(in millions) For the year ended December 31,
-------------------------------
1998 1997 1996
---- ---- ----
Cash Flows From Operating Activities
Net income $ 719 $ 716 $ 722
Adjustments to reconcile net income to
net cash provided by operating activities:
Depreciation, amortization, and
decommissioning 1,609 1,852 1,222
Deferred income taxes and tax credits-net (107) (159) (150)
Other deferred charges and noncurrent
liabilities 18 121 116
Loss (gain) on sale of assets 23 (120) --
Net effect of changes in operating
assets and liabilities:
Accounts receivable -- trade (342) (242) (70)
Regulatory balancing accounts receivable 537 126 302
Inventories and prepayments (161) (4) 32
Price risk management assets and
liabilities, net (16) 12 --
Accounts payable -- trade 247 210 217
Accrued taxes (123) (54) 36
Other working capital 199 (85) (6)
Other-net (302) 245 160
------- ------- -------
Net cash provided by operating activities 2,301 2,618 2,581
------- ------- -------
Cash Flows From Investing Activities
Capital expenditures (1,619) (1,822) (1,230)
Acquisitions and investments in
unregulated projects (1,779) (116) (229)
Proceeds from sale of assets 1,106 146 --
Other-net 48 21 (120)
------- ------- -------
Net cash used by investing activities (2,244) (1,771) (1,579)
------- ------- -------
Cash Flows From Financing Activities
Net borrowings (repayments) under credit
facilities 2,115 (587) (115)
Long-term debt issued -- 386 1,088
Long-term debt matured, redeemed, or
repurchased (1,552) (961) (1,472)
Proceeds from issuance of rate reduction
bonds -- 2,881 --
Preferred stock redeemed or repurchased (108) -- --
Common stock issued 63 54 220
Common stock repurchased (1,158) (804) (455)
Dividends paid (470) (524) (844)
Other-net (3) (39) (14)
------- ------- -------
Net cash used by financing activities (1,113) 406 (1,592)
------- ------- -------
Net Change in Cash and Cash Equivalents (1,056) 1,253 (590)
Cash and Cash Equivalents at January 1 1,397 144 734
------- ------- -------
Cash and Cash Equivalents at December 31 $ 341 $ 1,397 $ 144
======= ======= =======
Supplemental disclosures of cash flow
information
Cash paid for:
Interest (net of amounts capitalized) $ 774 $ 624 $ 598
Income taxes 770 801 640
The accompanying Notes to the Consolidated Financial Statements are an
integral part of this statement.
39
PG&E CORPORATION
STATEMENT OF CONSOLIDATED COMMON STOCK EQUITY
Total
Additional Common
Common Paid-in Reinvested Stock
Stock Capital Earnings Equity
------ ---------- ---------- -------
(dollars in millions)
BALANCE DECEMBER 31, 1995 $2,070 $ 3,716 $ 2,813 $ 8,599
------ ------- ------- -------
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
------ ------- ------- -------
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
------ ------- ------- -------
Net income 719 719
Common stock issued (2,028,303 shares) 63 63
Common stock repurchased (37,090,630 shares) (565) (593) (1,158)
Cash dividends declared
Common stock (466) (466)
Other (2) 13 11
------ ------- ------- -------
BALANCE DECEMBER 31, 1998 $5,862 $ -- $ 2,204 $ 8,066
====== ======= ======= =======
The accompanying Notes to the Consolidated Financial Statements are
an integral part of this statement.
40
Pacific Gas and Electric Company
STATEMENT OF CONSOLIDATED INCOME
1998 1997 1996
-------- -------- --------
(in millions) Year ended December 31,
Operating Revenues
Electric utility $7,191 $7,691 $7,160
Gas utility 1,733 1,804 1,829
Energy commodities and services -- -- 621
------ ------ ------
Total operating revenues 8,924 9,495 9,610
------ ------ ------
Operating Expenses
Cost of electric energy 2,321 2,501 2,261
Cost of gas 708 786 881
Cost of energy commodities and services -- -- 356
Operating and maintenance, net 2,581 2,629 2,994
Depreciation, amortization, and decommissioning 1,438 1,748 1,222
------ ------ ------
Total operating expenses 7,048 7,664 7,714
------ ------ ------
Operating Income 1,876 1,831 1,896
Interest expense, net (621) (570) (632)
Other income, net 103 116 46
------ ------ ------
Income Before Income Taxes 1,358 1,377 1,310
Income taxes 629 609 555
------ ------ ------
Net Income 729 768 755
------ ------ ------
Preferred dividend requirement 27 33 33
------ ------ ------
Income Available for Common Stock $ 702 $ 735 $ 722
====== ====== ======
The accompanying Notes to the Consolidated Financial Statements are an
integral part of this statement.
41
PACIFIC GAS AND ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEET
1998 1997
-------- --------
(in millions) Balance at December 31,
Assets
Current Assets
Cash and cash equivalents $ 73 $ 80
Short-term investments 17 1,143
Accounts receivable
Customers, net 1,383 1,204
Regulatory balancing accounts -- 458
Related parties 14 459
Inventories
Fuel oil and nuclear fuel 187 207
Gas stored underground 130 102
Materials and supplies 159 189
Prepayments 50 25
-------- --------
Total current assets 2,013 3,867
Property, Plant, and Equipment
Electric 16,924 16,913
Gas 7,072 6,851
Construction work in progress 273 421
-------- --------
Total property, plant, and equipment (at original cost) 24,269 24,185
Accumulated depreciation and decommissioning (11,397) (11,134)
-------- --------
Net property, plant, and equipment 12,872 13,051
Other Noncurrent Assets
Regulatory assets 6,288 6,846
Nuclear decommissioning funds 1,172 1,024
Other 605 359
-------- --------
Total noncurrent assets 8,065 8,229
-------- --------
Total Assets $ 22,950 $ 25,147
======== ========
42
PACIFIC GAS AND ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEET
1998 1997
-------- --------
(in millions) Balance at December 31,
Liabilities and Equity
Current Liabilities
Short-term borrowings $ 668 $ --
Current portion of long-term debt 260 580
Current portion of rate reduction bonds 290 290
Accounts payable
Trade creditors 718 441
Related parties 60 134
Regulatory balancing accounts 79 --
Other 374 424
Accrued taxes 2 229
Deferred income taxes 3 149
Other 558 527
------- -------
Total current liabilities 3,012 2,774
Noncurrent Liabilities
Long-term debt 5,444 6,218
Rate reduction bonds 2,321 2,611
Deferred income taxes 3,060 3,304
Deferred tax credits 283 338
Other 2,045 1,810
------- -------
Total noncurrent liabilities 13,153 14,281
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 without mandatory redemption provisions
Nonredeemable -- 5% to 6%, outstanding 5,784,825 shares 145 145
Redeemable -- 4.36% to 7.04%, outstanding 5,973,456 shares 142 257
Common stock, $5 par value, authorized 800,000,000 shares;
issued and outstanding, 341,353,455 and 403,504,292 1,707 2,018
Additional paid in capital 2,094 2,564
Reinvested earnings 2,260 2,671
------- -------
Total stockholders' equity 6,348 7,655
Commitments and Contingencies (Notes 1, 2, 3, 4, 5, 14, and 15) -- --
------- -------
Total Liabilities and Stockholders' Equity $22,950 $25,147
======= =======
The accompanying Notes to the Consolidated Financial Statements are an
integral part of this statement.
43
PACIFIC GAS AND ELECTRIC COMPANY
STATEMENT OF CONSOLIDATED CASH FLOWS
1998 1997 1996
-------- -------- --------
(in millions) For the year ended December 31,
Cash Flows From Operating Activities
Net income $ 729 $ 768 $ 755
Adjustments to reconcile net income to net cash provided by
operating activities:
Depreciation, amortization, and decommissioning 1,438 1,748 1,222
Deferred income taxes and tax credits-net (257) (182) (150)
Other deferred charges and noncurrent liabilities 31 133 116
Net effect of changes in operating assets and liabilities:
Accounts receivable 266 (582) (70)
Regulatory balancing accounts receivable 537 126 302
Inventories and prepayments (3) 12 32
Accounts payable -- trade 203 (80) 217
Accrued taxes (227) (62) 36
Other working capital (50) (128) (6)
Other-net (39) 15 127
------- ------ -------
Net cash provided by operating activities 2,628 1,768 2,581
Cash Flows From Investing Activities
Capital expenditures (1,382) (1,522) (1,230)
Acquisitions and investments in unregulated projects -- -- (229)
Proceeds from sale of generation assets 501 -- --
Other-net 22 (117) (120)
------- ------ -------
Net cash used by investing activities (859) (1,639) (1,579)
------- ------ -------
Cash Flows From Financing Activities
Net borrowings (repayments) under credit facilities 668 (681) (115)
Long-term debt issued -- 355 1,088
Long-term debt matured, redeemed, or repurchased (1,413) (852) (1,472)
Proceeds from issuance of rate reduction bonds -- 2,881 --
Preferred stock redeemed (108) -- --
Common stock repurchased (1,600) -- --
Dividends paid (444) (739) (844)
Other-net (5) (14) (249)
------- ------ -------
Net cash used by financing activities (2,902) 950 (1,592)
Net Change in Cash and Cash Equivalents (1,133) 1,079 (590)
Cash and Cash Equivalents at January 1 1,223 144 734
------- ------ -------
Cash and Cash Equivalents at December 31 $ 90 $1,223 $ 144
======= ====== =======
Supplemental disclosures of cash flow information
Cash paid for:
Interest (net of amounts capitalized) $ 600 $ 547 $ 598
Income taxes 1,115 841 640
The accompanying Notes to the Consolidated Financial Statements are an
integral part of this statement.
44
PACIFIC GAS AND ELECTRIC COMPANY
STATEMENT OF CONSOLIDATED COMMON STOCK EQUITY,
PREFERRED STOCK, AND PREFERRED SECURITIES
Preferred Preferred Company
Stock Stock Obligated
Total Without With Mandatorily
Additional Common Mandatory Mandatory Redeemable
Common Paid-in Reinvested Stock Redemption Redemption Preferred
(dollars in millions) Stock Capital Earnings Equity Provisions Provisions Securities
- ------------------------------------------------------------------------------------------------------------------------------------
Balance December 31, 1995 $ 2,070 $3,716 $ 2,813 $ 8,599 $ 402 $137 $300
- -----------------------------------------------------------------------------------------------------------------------------------
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 8,364 402 137 300
- -----------------------------------------------------------------------------------------------------------------------------------
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 7,253 402 137 300
- -----------------------------------------------------------------------------------------------------------------------------------
Net income 729 729
Common stock repurchased
(62,150,837 shares) (311) (481) (808) (1,600)
Preferred stock redeemed
(4,323,948 shares) (3) (3) (105)
Cash dividends declared
Preferred stock (28) (28)
Common stock (300) (300)
Other 11 (1) 10 (10)
- -----------------------------------------------------------------------------------------------------------------------------------
Balance December 31, 1998 $ 1,707 $2,094 $ 2,260 $ 6,061 $ 287 $137 $300
====================================================================================
The accompanying Notes to the Consolidated Financial Statements are an
integral part of this statement.
45
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1: General
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. Effective with PG&E
Corporation's formation, 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, the Utility, and PG&E
Corporation's other wholly owned subsidiaries. The Utility's consolidated
financial statements include its accounts as well as those of its wholly
owned subsidiaries. PG&E Corporation and the Utility have identical 1996
consolidated financial statements because they represent the accounts of the
Utility as 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 1998 presentation.
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions. These estimates and assumptions affect the reported amounts of
revenues, expenses, assets, and liabilities and 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: PG&E Corporation is an energy-based holding company headquartered
in San Francisco, California. PG&E Corporation's businesses provide energy
services throughout North America. PG&E Corporation's Northern and Central
California energy utility subsidiary, Pacific Gas and Electric Company,
provides natural gas and electric service to one of every 20 Americans. PG&E
Corporation's four unregulated businesses provide a wide range of energy
products and services through its wholesale and retail unregulated business
operations.
PG&E Corporation's wholesale unregulated business operations consist
of U.S. Generating Company (USGen) which develops, builds, operates, owns,
and manages power generation facilities that serve wholesale and industrial
customers; PG&E Gas Transmission (PG&E GT) which operates approximately 9,000
miles of natural gas pipelines, natural gas storage facilities, and natural gas
processing plants in the Pacific Northwest (PG&EGTNW) and Texas (PG&E GTT); and
PG&E Ener gy Trading (PG&E ET) which purchases and resells energy commodities
and related financial instruments in major North American markets, serving PG&E
Corporation's other unregulated businesses, unaffiliated utilities, and large
end-use customers.
PG&E Corporation's retail unregulated business operations consist of
PG&E Energy Services (PG&E ES) which provides competitively priced
electricity, natural gas, and related services to lower overall energy costs
for industrial, commercial, and institutional customers.
Regulation and Statements of Financial Accounting Standards (SFAS) No. 71: The
Utility is regulated by the CPUC, the FERC, and the Nuclear Regulatory
Commission (NRC) 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.
PG&E Corporation and the Utility account for the financial effects of
regulation in accordance with SFAS No. 71, "Accounting for the Effects of
Certain Types of Regulation." This statement allows for the deferral as a
regulatory asset costs that otherwise would have been expensed if it is probable
that the costs will be recovered in future regulated revenues. In addition, SFAS
No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to be Disposed Of," requires PG&E Corporation and the Utility to write
off regulatory assets when they are no longer probable of recovery. On an
ongoing basis, PG&E Corporation and the Utility review their regulatory
46
assets and liabilities for the continued applicability of SFAS No. 71 and the
effect of SFAS No. 121.
Regulatory assets and liabilities are comprised of the following:
December 31, 1998 1997
- -------------------------------------------------------------------------------------------------------
(in millions)
Utility:
Generation-related transition costs/(1)/ $5,355 $5,964
Unamortized loss, net of gain, on
reacquired debt 289 283
Regulatory assets for deferred income tax 293 253
Other (net) 351 346
- -------------------------------------------------------------------------------------------------------
Total Utility $6,288 $6,846
Wholesale 59 54
-------------
Regulatory assets $6,347 $6,900
-------------
Regulatory liabilities $526 $ 477
-------------
/(1)/ See Note 2 of Notes to Consolidated Financial Statements, for further
discussion.
Regulatory assets and liabilities are amortized over the period that the
costs are reflected in regulated revenues. The majority of the Utility's
regulatory assets are included in generation-related transition costs. The
Utility is amortizing its eligible transition costs, including generation-
related regulatory assets, over the transition period in conjunction with the
available competitive transition charge (CTC) revenues. During 1998, regulatory
assets related to electric utility restructuring decreased by $609 million. This
decrease reflects the recovery of eligible transition costs of $486 million
through accelerated amortization and $123 million through the gain on the sale
of generating plants.
Revenues and Regulatory Balancing Accounts: In connection with electric industry
restructuring, use of the Utility's sales and energy cost balancing accounts for
electric utility revenues has been discontinued in 1998. These balancing
accounts have been replaced with regulatory adjustment mechanisms which impact
expenses instead of revenues. (See Note 2.) For gas utility revenues, sales
balancing accounts accumulate differences between authorized and actual base
revenues. Further, gas cost balancing accounts accumulate differences between
the actual cost of gas and the revenues designated for recovery of such costs.
The regulatory balancing accounts accumulate balances until they are refunded to
or received from Utility customers through authorized rate adjustments. Utility
revenues included amounts for services rendered but unbilled at the end of each
year.
Accounting for Price Risk Management Activities: PG&E Corporation, primarily
through its subsidiaries, engages in price risk management activities for both
non-hedging and hedging purposes. PG&E Corporation conducts non-hedging
activities principally through its unregulated subsidiary, PG&E ET. Derivative
and other financial instruments associated with PG&E Corporation's electric
power, natural gas, natural gas liquids, and related non-hedging activities are
accounted for using the mark-to-market method of accounting.
Under mark-to-market accounting, PG&E Corpo-ration's non-hedging
contracts, including both physical contracts and financial instruments, are
recorded at market value, which approximates fair value. The market prices used
to value these transactions reflect management's best estimates considering
various factors including market quotes, time value, and volatility factors of
the underlying commitments. The values are adjusted to reflect the potential
impact of liquidating a position in an orderly manner over a reasonable period
of time under present market conditions.
Changes in the market value of these contract portfolios, resulting primarily
from newly originated transactions and the impact of commodity price and
interest rate movements, are recognized in operating revenues in the period of
change. Unrealized gains and losses of these contract portfolios are recorded as
assets and liabilities, respectively, from price risk management.
In addition to the non-hedging activities discussed above, PG&E Corporation
may engage in hedging activities using futures, forward contracts, options, and
swaps to hedge the impact of market fluctuations on energy commodity prices,
interest rates, and foreign currencies when there is a high degree of
correlation between price movements in the derivative and the item designated as
being hedged. PG&E Corporation accounts for hedge transactions under the
deferral method. Initially, PG&E Corporation defers unrealized gains and losses
on these transactions and classifies
47
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
them as assets or liabilities. When the hedged transaction occurs, PG&E
Corporation recognizes the gain or loss in operating expense. In instances where
the anticipated correlation of price movements does not occur, hedge accounting
is terminated and future changes in the value of the derivative are recognized
as gains or losses. If the hedged item is sold, the value of the associated
derivative is recognized in income.
For regulatory reasons, the Utility manages price risk independently from the
activities in PG&E Corporation's unregulated business. In the first quarter of
1998, the CPUC granted approval for the Utility to use financial instruments to
manage price volatility of gas purchased for the Utility's electric generation
portfolio. The approval limits the Utility's outstanding financial instruments
to $200 million, with downward adjustments occurring as the Utility divests its
fossil-fueled generation plants. (See Utility Generation Divestiture, below.)
Authority to use these risk management instruments ceases upon the full
divestiture of fossil-fueled generation plants or at the end of the current
electric rate freeze (see Rate Freeze and Rate Reduction, below), whichever
comes first.
In the second quarter of 1998, the CPUC granted conditional authority to the
Utility to use natural gas-based financial instruments to manage the impact of
natural gas prices on the cost of electricity purchased pursuant to existing
power-purchase contracts. Under the authority granted in the CPUC decision, no
natural gas-based financial instruments shall have an expiration date later than
December 31, 2001. Further, if the rate freeze ends before December 31, 2001,
the Utility shall net any outstanding financial instrument contracts through
equal and opposite contracts, within a reasonable amount of time. Also during
the fourth quarter, the CPUC granted conditional authority to the Utility to use
natural gas-based financial instruments to manage price and revenue risks
associated with its natural gas transmission and storage assets.
Property, Plant, and Equipment: Plant additions and replacements are
capitalized. The capitalized costs include labor, materials, construction
overhead, and capitalized interest or an allowance for funds used during
construction (AFUDC). 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 for the
Utility and the unregulated businesses that apply SFAS No. 71. For our wholesale
and retail unregulated business operations, the cost and accumulated
depreciation of property, plant, and equipment retired or otherwise disposed of
are removed from related accounts and included in the determination of the gain
or loss on disposition.
Property, plant, and equipment is depreciated using a straight-line
remaining-life method. PG&E Corporation's composite depreciation rates were
4.11 percent, 3.70 percent, and 3.37 percent for the years ended December 31,
1998, 1997, and 1996, respectively. The Utility's composite depreciation rates
were 4.15 percent, 3.52 percent, and 3.37 percent for the years ended December
31, 1998, 1997, and 199 6, respectively.
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.
Inventories: Inventories include material and supplies, gas stored underground,
nuclear fuel, and fuel oil. Materials and supplies and gas stored underground
are valued at average cost. 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. 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 and consist primarily of
eurodollar time deposits, bankers acceptances, and
48
some commercial paper with original maturities of three months or less.
Income Taxes: PG&E Corporation uses the liability method of accounting for
income taxes. 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.
PG&E Corporation files a consolidated federal income tax return that includes
domestic subsidiaries in which its ownership is 80 percent or more. The Utility
and various other subsidiaries are parties to a tax-sharing arrangement with
PG&E Corporation. PG&E Corporation files consolidated state income tax returns
when applicable. The Utility reports taxes on a stand-alone basis.
Related Party Agreements: In accordance with various agreements, the Utility and
other subsidiaries provide and receive various services from their parent, PG&E
Corporation. Services include the Utility's provision of general and
administrative services. The Utility and other subsidiaries receive general and
administrative services and financing from PG&E Corporation. Corporate costs,
such as administrative costs, interest, and income taxes, are allocated to
subsidiaries using a variety of factors including their share of employees,
operating expenses, assets, and other cost causal methods. Also, the Utility
purchases gas transmission services from PG&EGTNW.
Note 2: California Electric Industry Restructuring
In 1998, California became one of the first states in the country to implement
an electric industry restructuring plan. California electric industry
restructuring has two major impacts on the financial statements. The two major
components are the competitive market framework and the electric transition
plan, which are discussed below.
Competitive Market Framework: To create a competitive generation market, a Power
Exchange (PX) and an Independent System Operator (ISO) began operating in 1998.
The Utility is required to sell to the PX all of the electricity generated by
its power plants and electricity acquired under contractual agreements with
unregulated generators. Also, the Utility is required to buy from the PX all
electricity needed to provide service to retail customers that continue to
choose the Utility as their electricity supplier. The ISO schedules delivery of
electricity for all market participants to the transmission system. The Utility
continues to own and maintain a portion of the transmission system, but the ISO
controls the operation of the system.
For the year ended December 31, 1998, the cost of energy for the Utility,
reflected on the Statement of Consolidated Income, is comprised of the cost of
PX purchases, ancillary services (standby power and miscellaneous services)
purchased from the ISO, cost of transmission, and the cost of Utility
generation, net of sales to the PX as follows:
For the year ended December 31, 1998
- ----------------------------------------------------------------------
(in millions)
Cost of fuel for electric generation $2,030
Cost of purchases from the PX 723
Net cost of ancillary services 406
Proceeds from sales to the PX (838)
- ----------------------------------------------------------------------
Cost of electric energy $2,321
- ----------------------------------------------------------------------
The Utility's cost of energy is recovered from retail customers under the
terms of the restructuring plan.
California Transition Plan: Market-based revenues determined by the market
through sales to the PX may not be sufficient to recover (that is, to collect
from customers) all of the Utility's generation costs. To allow California
investor-owned utilities the opportunity to recover their transition costs
(generation costs that would not be recovered through market-based revenues) and
to ensure a smooth transition to a competitive market, the California
legislature developed a transition plan in the form of state legislation that
was passed in 1996. The transition plan will remain in effect until the earlier
of December 31, 2001, or when the Utility has recovered its authorized
transition costs as determined by the CPUC, with provisions that certain
transition costs can be recovered after 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. The transition plan
contains three principal elements
49
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
consisting of the determination of: (1) an electric rate freeze and rate
reduction, (2) the recovery of transition costs, and (3) divestiture of utility-
owned generation facilities. Each element is discussed below.
* Rate Freeze and Rate Reduction:
The first element of the transition plan is an electric rate freeze and an
electric rate reduction. In 1997 and 1998, the Utility held rates for its larger
customers at 1996 levels, and it will hold their rates at that level until the
end of the transition period. On January 1, 1998, the Utility reduced electric
rates for its residential and small commercial customers by 10 percent from 1996
levels, and it will hold their rates at that level until the end of the
transition period. Collectively, these actions are called a rate freeze.
To pay for the 10 percent rate reduction, the Utility refinanced $2.9 billion
of its transition costs with the proceeds of rate reduction bonds. (See Note 9.)
The bonds allow for the rate reduction by lowering the carrying cost on a
portion of the transition costs and by deferring recovery of a portion of these
transition costs until after the transition period.
The frozen rates include a component for transition cost recovery. Transition
costs are being recovered from all Utility distribution customers through a
nonbypassable charge regardless of the customer's choice of electricity
supplier. As the customer charge for transition costs is nonbypassable, the
Utility does not believe that the availability of choice to its customers will
have a material impact on its ability to recover transition costs.
Revenues from frozen electric rates provide for the recovery of authorized
Utility costs, including transmission and distribution service, public purpose
programs, nuclear decommissioning, and rate reduction bond debt service. To the
extent the revenues from frozen rates exceed authorized Utility costs, the
remaining revenues constitute the CTC which recovers the transition costs. These
CTC revenues are subject to seasonal fluctuations in the Utility's sales volumes
and certain other factors.
* Transition Cost Recovery:
Transition costs consist of: (1) above-market sunk costs (sunk costs are costs
associated with Utility-owned generation assets that are fixed and unavoidable
and currently included in the Utility customers' electric rates) and future
costs, such as costs related to plant removal of Utility-owned generation
facilities, (2) costs associated with the Utility's long-term contracts to
purchase power at above-market prices from qualifying facilities 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.)
Above-market sunk costs result when the book value of a facility is in excess
of its market value. Conversely, below-market sunk costs result when the market
value of a facility is in excess of its book value. The total amount of
generation facility 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 these costs is eligible for recovery as a transition cost. The below-market
portion of these costs will reduce other unrecovered transition costs. A
valuation of a Utility-owned generation facility where the market value exceeds
the book value could result in a material charge to Utility earnings if the
valuation of the facility is determined based upon any method other than a sale
of the facility to a third party. This is because any excess of market value
over book value would be used to reduce other transition costs.
The Utility will not be able to determine the exact amount of above-market
non-nuclear sunk costs that will be recoverable as transition costs until a
market valuation process (appraisal, spin, sale, or other valuation method) is
completed for each of its generation facilities. Several of these valuations
occurred in 1997 and 1998, when the Utility agreed to sell seven of its electric
plants. The market value of these facilities determined by these sales exceeded
the book value and will therefore reduce the amount of transition costs to be
recovered. In addition, in December 1998, the Utility requested that the CPUC
allow it to hire appraisers to set the value of its hydroelectric generation
system. (See Generation Divestiture below.) The remainder of the valuation
process is expected to be completed by December 31, 2001. Nuclear sunk costs
were separately determined through a CPUC proceed-
50
ing and were subject to a final verification audit. This audit was completed in
August 1998, the results of which are currently under review.
The Utility has long-term contracts to purchase electric power at above-
market prices. To the extent that individual contract prices are above market
price, the Utility is collecting the difference between the contract price and
the market price from customers, as a transition cost, over the term of the
contract. The contracts expire at various dates through 2028. The total amount
of the above-market costs under long-term contracts will be based on several
variables, including the capacity factors of the related generating facilities
and future market prices for electricity. During 1998, the average price paid
per kilowatt hour (kWh) under the Utility's long-term contracts for electric
power was 7.4 cents per kWh. The average cost of electric energy for energy
purchased at market rates from the PX (a measure of market prices) for the
period from April 1, 1998, to December 31, 1998, was 3.2 cents per kWh.
Generation-related regulatory assets and obligations (net generation-related
regulatory assets) are included as transition costs. These net regulatory assets
consist of those created prior to the transition period and those created during
the transition period. In 1998, the staff of the Securities and Exchange
Commission (SEC)issued interpretive guidance related to assets which are being
transitioned to a deregulated environment. The guidance states that an
impairment analysis should be performed for such assets and that the impairment
analysis should exclude transition cost revenues. Following this guidance, the
Utility determined that $3.9 billion of its generation assets were impaired. The
Utility has determined that certain of its generation facilities are considered
impaired under the SEC interpretive guidance. Because the Utility expects to
recover the impaired assets as a transition cost, it recorded a regulatory asset
for the impaired amounts as required. As a result, in 1998, $3.9 billion was
reclassified from property, plant, and equipment to regulatory assets on the
Utility's balance sheet. Prior year amounts were also reclassified. The
Utility's generation-related net regulatory assets total $5.4 billion at
December 31, 1998.
Under the transition plan, most transition costs can be recovered until
December 31, 2001. This recovery period is significantly shorter than the
recovery period of the generation assets prior to restructuring and is referred
to as accelerated recovery. Accordingly, the Utility is amortizing its
transition costs, including most generation-related regulatory assets over the
transition period. The CPUC believes that the transition plan reduces risks
associated with recovery of all the Utility's generation assets, including the
Diablo Canyon Nuclear Power Plant (Diablo Canyon) and the hydroelectric
facilities. As a result, during the transition period, the Utility is receiving
a reduced return on common equity for all of its generation assets, including
those generation assets reclassified to regulatory assets. In 1998, the reduced
return on common equity was 6.77 percent as compared to an authorized return on
common equity of 11.20 percent. The reduced return on common equity, related to
generation assets, will be in effect throughout the transition period.
Certain transition costs can be included in a non-bypassable charge to
distribution customers after the transition period. These costs include: (1)
certain employee-related transition costs, (2) above-market payments under
existing long-term contracts to purchase power, 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 our nuclear
facility. During the rate freeze, this charge and the rate reduction bond debt
service will not increase the 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, revenues provided for the recovery of
most non-nuclear transition costs are based upon the acceleration of such costs
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
51
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
accelerated recovery of the investment in Diablo Canyon from a period ending in
2016 to a five-year period ending December 31, 2001.
The Utility is amortizing its eligible transition cost, including generation-
related regulatory assets, over the transition period in conjunction with
available CTC revenues. Effective January 1, 1998, the Utility started
collecting these eligible transition costs through the nonbypassable CTC. During
1998, regulatory assets related to electric utility restructuring decreased by
$609 million. This decrease reflects the recovery of eligible transition costs
of $486 million through accelerated amortization and $123 million through the
gain on the sale of generating plants.
During the transition period, the CPUC will review the Utility's compliance
with the accounting methods used by the Utility to recover transition costs and
the amount of transition costs requested for recovery. The CPUC is currently
reviewing non-nuclear transition costs amortized during the first six months of
1998. The Utility expects the CPUC to issue a decision regarding this review in
the second half of 1999. Transition costs that are disallowed by the CPUC for
collection from the Utility customers will be written off.
In addition, in August 1998, an independent accounting firm retained by the
CPUC completed its financial verification audit of the Utility's Diablo Canyon
plant accounts at December 31, 1996. The audit resulted in the issuance of an
unqualified opinion. The audit verified that Diablo Canyon sunk costs at
December 31, 1996, were $3.3 billion of the total $7.1 billion construction
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.) The independent accounting firm also issued an agreed-upon
special procedures report, requested by the CPUC, which questioned $200 million
of the $3.3 billion sunk costs. The CPUC will review any proposed adjustments to
Diablo Canyon's recoverable costs, which resulted from the report. At this time,
the Utility cannot predict what actions, if any, the CPUC may take regarding the
audit report.
* Generation Divestiture:
In 1998, the Utility completed the sale of three fossil-fueled generation plants
for $501 million. These three fossil-fueled plants had a combined book value at
the time of the sale of $346 million and had a combined capacity of 2,645
megawatts (MW).
Also in 1998, the Utility agreed to sell three other fossil-fueled generation
plants and its complex of geothermal generation facilities. The winning bids
total $1,014 million. As of December 31, 1998, these four plants had a combined
book value of $523 million and had a combined capacity of 4,289 MW. The sales
are subject to the approval of regulatory agencies, including the CPUC, and
conditioned upon the transfer of various permits and licenses. The Utility
expects to complete the sale of these four plants in 1999.
The Utility will retain a liability for required environmental remediation
related to all of its fossil-fueled generation and geothermal plants of any pre-
closing soil or groundwater contamination at the plants it has or will sell. The
Utility records its estimated liability for the retained environmental
remediation obligation as part of the determination of the gain or loss on the
sale of each plant.
Any net gains from the sale of the Utility-owned generation plants will be
used to offset other transition costs. As a result, PG&E Corporation does not
believe sales of any generation facilities to a third party will have a material
impact on its results of operations.
The Utility is currently evaluating its options related to its remaining non-
nuclear generation facilities, primarily the hydroelectric generation system. In
May 1998, the Utility notified the CPUC that it does not plan to retain the
hydroelectric generation assets as part of the Utility. In December 1998, the
Utility filed with the CPUC its proposed appraisal process for valuing
generation assets, primarily the hydroelectric facilities. The Utility expects
to receive a response to this request in 1999.
At December 31, 1998, the book value of the Utility's net investment in
hydroelectric generation assets was $1.4 billion. If the Utility decides to
dispose of the hydroelectric generation assets by any method other than a sale
of the assets to a third party, a material charge could result to the extent
that the market value of the assets exceeds their book value. The
52
market value of the hydroelectric assets is expected to exceed their book value
by a material amount.
Financial Impact of Transition Plan: The Utility's ability to continue
recovering its transition costs will be dependent on several factors, including:
(1) the continued application of the regulatory framework established by the
CPUC and state legislation, (2) the amount of transition costs ultimately
approved for recovery by the CPUC, (3) the market value of the remaining
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 the current evaluation of these
factors, PG&E Corporation believes that the Utility will recover its transition
costs under the terms of the approved transition plan. 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.
Note 3: Price Risk Management and Financial Instruments
The following table is a summary of the contract or notional amounts and
maturities of PG&E Corporation's contracts used for non-hedging activities
related to commodity price risk management as of December 31, 1998. Short and as
of December 31, 1998 are immaterial.
Maximum
Natural Gas and Purchase Sale Term in
Electricity Contracts (Long) (Short) Years
- ------------------------------------------------------------------------------
(billions of MMBtu equivalents/(a)/)
Non-Hedging Activities
Swaps 6.12 5.94 8
Options 1.39 1.18 5
Futures 0.44 0.46 4
Forward Contracts 3.68 3.53 5
- ------------------------------------------------------------------------------
/(a)/ One MMBtu is equal to one million British thermal units. PG&E
Corporation's electric power contracts, measured in megawatts, were
converted to MMBtu equivalents using a conversion factor of 10 MMBtu's
per 1 megawatt-hour.
Maximum
Purchase Sale Term in
Natural Gas Liquids Contracts (Long) (Short) Years
- ------------------------------------------------------------------------------
(millions of barrels)
Non-Hedging Activities
Swaps 15.13 20.96 2
Options 19.24 17.69 1
Futures 24.16 25.18 1
Forward Contracts 5.01 5.29 2
- ------------------------------------------------------------------------------
Volumes shown for swaps represent notional volumes that are used to calculate
amounts due under the agreements and do not represent volumes exchanged.
Moreover, notional amounts are indicative only of the volume of activity and are
not a measure of market risk.
The following table discloses the estimated fair values of price risk
management assets and liabilities as of December 31, 1998. PG&E Corporation's
net gains and losses on swaps, options, futures, and forward contracts held
during the year for non-hedging purposes were $69 million, $(49) million, $(63)
million, and $101 million, respectively. The ending and average fair values and
associated carrying amounts of derivative contracts used for hedging purposes
are not material as of December 31, 1998.
Average Ending
Fair Value Fair Value
- ------------------------------------------------------------------------------
(in millions)
Assets
Non-Hedging Activities
Swaps $ 494 $ 947
Options 121 154
Futures 115 150
Forward Contracts 342 499
- ------------------------------------------------------------------------------
Total $1,072 $1,750
--------------------------
Noncurrent portion 334
- ------------------------------------------------------------------------------
Current portion $1,416
-------------
53
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Average Ending
Fair Value Fair Value
- ----------------------------------------------------------------------------
(in millions)
Liabilities
Non-Hedging Activities
Swaps $ 476 $ 908
Options 147 201
Futures 111 186
Forward Contracts 282 398
- ----------------------------------------------------------------------------
Total $1,016 $1,693
-------------------------
Noncurrent portion 281
- ----------------------------------------------------------------------------
Current portion $1,412
-----------
The impact of price risk management assets and liabilities on PG&E
Corporation's results of operations for fiscal 1997 was immaterial.
In valuing its electric power, natural gas, and natural gas liquids
portfolios, PG&E Corporation considers a number of market risks and estimated
costs and continuously monitors the valuation of identified risks and adjusts
them based on present market conditions. Considerable judgment is required to
develop the estimates of fair value; thus, the estimates provided herein are not
necessarily indicative of the amounts that PG&E Corporation could realize in the
current market.
Generally, exchange-traded futures contracts require deposit of margin cash,
the amount of which is subject to change based on market movement and in
accordance with exchange rules. Margin cash requirements for over-the-counter
financial instruments are specified by the particular instrument and often do
not require margin cash and are settled monthly. Both exchange-traded and over-
the-counter options contracts require payment/receipt of an option premium at
the inception of the contract. Margin cash for commodities futures and cash on
deposit with counterparties was immaterial at December 31, 1998.
Note 4: Concentrations of Market and Credit Risk
Market Risk: Market risk is the risk that changes in market prices will
adversely effect earnings and cash flows. PG&E Corporation is primarily exposed
to the market risk associated with energy commodities such as electric power,
natural gas, and natural gas liquids. Therefore, PG&E Corporation's price risk
management activities primarily involve buying and selling fixed price commodity
commitments into the future. Net open positions often exist or are established
due to PG&E Corporation's assessment of and response to changing market
conditions. To the extent that PG&E Corporation has an open position, it is
exposed to the risk that fluctuating market prices may adversely impact its
financial results.
Credit Risk: The use of financial instruments to manage the risks associated
with changes in energy commodity prices creates exposure resulting from the
possibility of nonperformance by counterparties pursuant to the terms of their
contractual obligation. The counterparties in PG&E Corporation's portfolio
consist primarily of investor owned and municipal utilities, energy trading
companies, financial institutions, and oil and gas production companies. PG&E
Corporation minimizes credit risk by dealing primarily with creditworthy
counterparties in accordance with established credit approval practices and
limits. PG&E Corporation routinely assesses the financial strength of its
counterparties and may require letters of credit or parental guarantees when the
financial strength of a counterparty is not considered sufficient. PG&E
Corporation has experienced no material losses due to the nonperformance of
counterparties in 1998. The credit exposure of the five largest counterparties
comprised approximately $127 million of the total credit exposure associated
with financial instruments used to manage price risk. Counterparties considered
to be investment grade or higher comprise 71 percent of the total credit
exposure.
Note 5: Acquisitions and Sales
In January 1997, PG&E Corporation acquired Teco Pipeline Company for $378
million, consisting of $317 million of PG&E Corporation common stock and the
purchase of a $61 million note.
In April 1997, through one of its wholly owned subsidiaries, PG&E Corporation
sold its interest in International Generating Company, Ltd., which resulted in
an after-tax gain of approximately $120 million.
54
In July 1997, PG&E Corporation completed its acquisition of Valero Energy
Corporation's natural gas business and a gas marketing business located in
Texas. PG&E Corporation issued approximately 31 million shares of its common
stock to acquire Valero along with the assumption of $780 million in long-term
debt, equating to a purchase price of approximately $1.5 billion. The
acquisition was accounted for as a purchase and accordingly, the purchase price
has been allocated to the assets acquired and the liabilities assumed based on
estimated fair values.
In September 1997, PG&E Corporation became the sole owner of USGen, an
independent power developer and manager; U.S. Operating Services Company,
USGen's operations and maintenance affiliate; and USGen Power Services, L.P.,
USGen's power marketing affiliate. Additionally, PG&E Corporation has acquired
all or part of interest in several power projects that are affiliated with
USGen.
In July 1998, PG&E Corporation sold its Australian energy holdings. The
sale represents a premium on the price in local currency of PG&E
Corporation's 1996 investment in the assets. However, the transaction
resulted in a non-recurring charge of $.06 per share in the second quarter of
1998. This charge was primarily due to the 22 percent currency devaluation of
the Australian dollar against the U.S. dollar during the past two years.
In September 1998, PG&E Corporation, through its indirect subsidiary USGen
New England, Inc., completed the acquisition of a portfolio of electric
generating assets and power supply contracts from the New England Electric
System (NEES). The acquisition has been accounted for using the purchase method
of accounting. Accordingly, the purchase price has been allocated to the assets
purchased and the liabilities assumed based upon a preliminary assessment of the
fair values at the date of acquisition.
Including fuel and other inventories and transaction costs, PG&E
Corporation's financing requirements were approximately $1.8 billion, funded
through $1.3 billion of USGen debt and a $425 million equity contribution from
PG&ECorporation. The net purchase price has been allocated as follows: (1)
electric generating assets of $2.3 billion classified as property, plant, and
equipment; (2) receivable for support payments of $0.8 billion; and
(3)contractual obligations of $1.3 billion classified as current liabilities and
other noncurrent liabilities. The NEES assets include hydroelectric, coal, oil,
and natural gas generation facilities with a combined generating capacity of
4,000 MW. In addition, USGen assumed 23 multi-year power-purchase agreements
representing an additional 800 MW of production capacity. USGen entered into
agreements with NEES as part of the acquisition, which: (1) provide that NEES
shall make support payments over the next ten years to USGen for the purchase
power agreements; and (2) require that USGen provide electricity to NEES under
contracts that expire over the next six to eleven years.
Note 6: Common Stock
PG&E Corporation: PG&E Corporation has authorized 800 million shares of no-par
common stock of which 382,603,564 and 417,665,891 shares were issued and
outstanding as of December 31, 1998 and 1997, respectively.
As of December 31, 1997, the Board of Directors had authorized the repurchase
of up to $1.7 billion of PG&E Corporation's common stock on the open market or
in negotiated transactions. As part of this authorization, in January 1998, PG&E
Corporation repurchased in a specific transaction 37 million shares of common
stock. As of December 31, 1998, approximately $570 million remains available
under this repurchase authorization. In February 1999, PG&E Corporation used
this remaining authorization to purchase 16.6 million shares at a price of
$30.25 per share. In connection with this transaction, PG&E Corporation has
entered into a forward contract with an investment institution. PG&E 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 PG&E Corporation through purchases on the open market or through privately
negotiated transactions. The contract is anticipated to expire by year-end.
55
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Utility: All of the Utility's stock outstanding is held by PG&E Corporation. In
connection with the formation of the holding company, all of the Utility's
common stock was converted on a share for share basis to PG&E Corporation common
stock.
The Utility has authorized 800 million shares of $5 par value common stock of
which 341,353,455 and 403,504,292 shares are issued and outstanding at December
31, 1998 and 1997, respectively.
The CPUC requires the Utility to maintain its CPUC-authorized capital
structure, potentially limiting the amount of dividends the Utility may pay PG&E
Corporation. In 1998, the Utility was in compliance with its CPUC-authorized
capital structure.
Note 7: Preferred Stock and Utility Obligated Mandatorily Redeemable Preferred
Securities of Trust Holding Solely Utility Subordinated Debentures
Preferred Stock: The Utility has authorized 75,000,000 shares of $25 par value
preferred stock which may be issued as redeemable or nonredeemable preferred
stock. At December 31, 1998 and 1997, the Utility has issued and outstanding
5,784,825 shares of nonredeemable preferred stock.
At December 31, 1998 and 1997, the Utility has issued and outstanding
5,973,456 and 10,297,404 shares of redeemable preferred stock, respectively. The
Utility's redeemable preferred stock 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, 1998, range from $1.09
to $1.76 and from $25.00 to $27.25, respectively. In 1998, the Utility redeemed
its Series 7.44% preferred stock with a face value of $65 million. Also in 1998,
the Utility redeemed its Series 6 7\8% preferred stock with a face value of $43
million. During 1997 and 1996, the Utility did not redeem or repurchase any of
its preferred stock.
The Utility's redeemable preferred stock with mandatory redemption provisions
consists of 3 million shares of the 6.57% series and 2.5 million shares of the
6.30% series at December 31, 1998. 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.
Holders of the Utility's nonredeemable preferred stock 5%, 5.5%, and 6%
series have rights to annual dividends per share ranging from $1.25 to $1.50.
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. The estimated fair
value of the Utility's preferred stock with mandatory redemption provisions at
December 31, 1998 and 1997, was $143 million and $146 million, respectively,
based on quoted market prices.
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 $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 $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.
56
The subordinated debentures may be redeemed at the Utility's option beginning
in 2000 at par value 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, 1998 and 1997, was $303 million and $304
million, respectively, based on quoted market prices.
Note 8: Long-Term Debt
Long-term debt at December 31, 1998 and 1997, consisted of the following:
December 31, 1998 1997
(in millions)
Utility long-term debt
First and refunding mortgage bonds
Maturity Interest rates
1999-2002 5.500% to 8.75% $ 682 $1,241
2003-2007 5.875% to 6.250% 902 974
2008-2020 6.35% to 8.02% 160 160
2021-2026 5.85% to 8.80% 2,117 2,498
- -----------------------------------------------------------------------
Principal amounts outstanding 3,861 4,873
Unamortized discount net of premium (32) (42)
- -----------------------------------------------------------------------
Total mortgage bonds 3,829 4,831
Pollution control loan agreements,
variable rates, due 2010-2026 1,348 1,348
Unsecured medium-term notes,
5.37% to 8.45%, due 1999-2014 498 587
Other Utility long-term debt 29 32
- -----------------------------------------------------------------------
Total Utility long-term debt 5,704 6,798
Current portion of long-term debt 260 580
- -----------------------------------------------------------------------
Total Utility long-term debt, net of current
portion 5,444 6,218
Long-term debt of wholesale and retail
unregulated business operations
First mortgage notes
10.02% to 11.50%, due 1999-2009 370 409
Senior notes
10.58%, due 1999-2000 69 105
7.10%, due 2005 250 250
Medium term notes
6.61% to 9.29%, due 2000-2012 298 298
Senior debentures
7.80%, due 2025 148 148
Amounts outstanding under credit
facilities (See Note 10) 654 80
Other long-term debt 267 230
- -----------------------------------------------------------------------
Total wholesale and retail unregulated business
operations long-term debt 2,056 1,520
Current portion of long-term debt 78 79
- -----------------------------------------------------------------------
Long-term debt, net of current portion 1,978 1,441
- -----------------------------------------------------------------------
Total long-term debt $7,422 $7,659
========================
Utility:
* First and Refunding Mortgage Bonds:
First and refunding mortgage bonds are issued in series and bear annual interest
rates ranging from 5.50 percent to 8.80 percent. All real properties and
57
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
substantially all personal properties of the Utility are subject to the lien of
the bonds, and the Utility is required to make semi-annual sinking fund payments
for the retirement of the bonds. Additional bonds may be issued subject to CPUC
approval, up to a maximum total amount outstanding of $10 billion assuming
compliance with indenture covenants for earnings coverage and available property
balances as security.
The Utility redeemed or repurchased $501 million and $167 million of the
bonds in 1998 and 1997, respectively, with interest rates ranging from 6.25
percent to 8.80 percent. These bonds were to mature from 2002 to 2026.
Included in the total of outstanding bonds at December 31, 1998 and 1997, are
$345 million of bonds held in trust for the California Pollution Control
Financing Authority (CPCFA) with interest rates ranging from 5.85 percent to
6.625 percent and maturity dates ranging from 2009 to 2023. In addition to these
bonds, the Utility holds long-term pollution control loan agreements with the
CPCFA as described below.
* Pollution Control Loan Agreements:
Pollution control loan agreements from the CPCFA totaled $1,348 million at
December 31, 1998 and 1997. Interest rates on the loans vary with average annual
interest rates. For 1998 the interest rates ranged from 2.56 percent to 3.68
percent. These loans are subject to redemption by the holder under certain
circumstances. These loans are primarily secured by irrevocable letters of
credit which mature 2000 through 2003.
Wholesale and Retail Unregulated Business Operations: Long-term debt of
wholesale and retail unregulated business operations consists of first mortgage
bonds and other secured and unsecured obligations.
The first mortgage notes are comprised of three series due serially from 1999
to 2009, and are secured by mortgages and security interests in the natural gas
transmission and natural gas processing facilities and other real and personal
property of PG&E GTT. The mortgage indenture requires semi-annual payments with
one-half of each interest payment and one-fourth of each annual principal
payment escrowed quarterly in advance. The mortgage indenture also contains
covenants which restrict the ability of PG&E GTT to incur additional
indebtedness and precludes cash distributions if certain cash flow coverages are
not met.
Other long-term debt consists of project financing associated with
unregulated generation facilities, premiums and other loans.
Repayment Schedule: At December 31, 1998, PG&E Corporation's combined aggregate
amounts of maturing long-term debt and sinking fund requirements, for the years
1999 through 2003, are $338 million, $698 million, $480 million, $1,256 million
and $1,288 million, respectively. The Utility's share of those maturities and
sinking fund requirements is $260 million, $466 million, $374 million, $1,120
million and $682 million, respectively.
Fair Value: The estimated fair value of PG&E Corporation's total long-term debt
at December 31, 1998 and 1997, was $8.1 billion and $8.3 billion, respectively.
The estimated fair value of the Utility's total long-term debt at December 31,
1998 and 1997, was $6.0 billion and $7.0 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 9: 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.
58
The rate reduction bonds have maturities ranging from ten months to ten
years, and bear interest at rates ranging from 6.01 percent to 6.48 percent. The
bonds are secured solely by the transition property and there is no recourse to
the Utility or PG&E Corporation.
At December 31, 1998, $2.6 billion of rate reduction bonds were outstanding.
The combined expected principal payments on the rate reduction bonds for the
years 1999 through 2003 are $290 million for each year.
The estimated fair value of the rate reduction bonds was $2.6 billion at
December 31, 1998. 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 PG&E Corporation,
and the transition property is legally not an asset of the Utility or PG&E
Corporation.
Note 10: Credit Facilities
PG&E Corporation: At December 31, 1998 and 1997, PG&E Corporation had borrowed
$2,298 million and $183 million, respectively, under various credit facilities
discussed below. $654 million and $80 million of these borrowings December 31,
1998 and 1997, respectively are classified as long-term debt. (See Note 8.) The
weighted average interest rate on the short-term borrowings was 5.6 percent and
6.9 percent for 1998 and 1997, respectively. The carrying amount of short-term
borrowings approximates fair value.
PG&E Corporation maintains two $500 million revolving credit facilities. One
expires in November 1999 and the other in 2002. The facility expiring in
November 1999 may be extended annually for additional one-year periods upon
agreement between PG&E Corporation and the lending institutions. These credit
facilities are used to support PG&E Corporation's commercial paper program and
other liquidity needs. At December 31, 1998, PG&E Corporation had $683 million
of commercial paperoutstanding supported by these facilities. No amounts were
outstanding at December 31, 1997.
59
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Utility: 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 agreement between the Utility and the banks. At December 31, 1998,
the Utility had $567 million of commercial paper outstanding and $101 million of
bank notes outstanding. No amounts were outstanding at December 31, 1997.
Wholesale and Retail Unregulated Business Operations: USGen has $1,675 million
in revolving credit facilities, of which $575 million is specifically related to
its New England operations. The $575 million line is comprised of a $100 million
facility, expiring in 2003, and a $475 million facility, used to execute a sale
leaseback transaction and subsequently cancelled. As of December 31, 1998, no
amounts were outstanding under these facilities. The remaining facility is a
$1.1 billion revolving credit agreement comprised of two $550 million
facilities, one of which expires in 2003, and the other of which expires in
August 1999. As of December 31, 1998, the long-term facility has a $540 million
eurodollar loan drawn on it, and it also supports $10 million of outstanding
commercial paper. Both are classified as noncurrent debt in the consolidated
balance sheet. (See Note 8.) As of December 31, 1998, the short-term facility
supported $223 million in outstanding commercial paper, which had a weighted
average rate of 5.6 percent.
PG&E GT NW maintains a $200 million revolving credit facility which expires
in the year 2000. At December 31, 1998 and 1997, PG&E GT NW had outstanding
commercial paper balances of $104 mil-lion and $80 million, respectively,
supported by this revolving facility. These balances were classified as
noncurrent debt in the consolidated balance sheet. (See Note 8.)
PG&E GTThad $70 million and $100 million of outstanding short-term bank
borrowings related to two separate credit facilities at December 31, 1998 and
1997, respectively. These lines are cancelable upon demand and bear interest at
each respective bank's quoted money market rate. The borrowings are unsecured
and unrestricted as to use.
Note 11: 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 radioactivity
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 $1.5 billion in 1998 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, 1998, 1997, and 1996, nuclear
decommissioning costs recovered in rates were $33 million per year,
respectively. Based on the 1997 site study, the amount proposed to be recovered
in rates in 1999 and annually, until the commencement of decommissioning, is $33
million. This amount is currently under review in the Utility's 1999 General
Rate Case and will continue to be reviewed in future nuclear decommissioning
cost triennial proceedings.
At December 31, 1998, the total nuclear decommissioning obligation accrued
was $1.2 billion and is included in the balance sheet classification of
accumulated depreciation and decommissioning. Decommissioning costs recovered in
rates are placed in external trust funds. These funds along with accumulated
earnings will be used exclusively for decommissioning 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,
based on quoted market prices, of these nuclear decommissioning funds:
Year ended December 31, Maturity Dates 1998 1997
- -----------------------------------------------------------------------
(in millions)
Amortized cost
U.S. government and
agency issues 1999-2028 $ 379 $ 422
Equity securities -- 246 257
Municipal bonds and other 1999-2030 164 70
Gross unrealized holding gains 394 287
Gross unrealized holding losses (11) (12)
- -----------------------------------------------------------------------
Fair value (net, of tax) $1,172 $1,024
===================
The proceeds received from sales of securities were $1.4 billion in each year
in 1998 and 1997. The gross realized gains on sales of securities held as
available-for-sale were $52 million and $40 million, in 1998 and 1997,
respectively, and the gross realized losses on sales of securities held as
available-for-sale were $39 million and $24 million, in 1998 and 1997,
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 2010. 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.
60
Note 12: Employee Benefit Plans
Several of PG&E Corporation's subsidiaries provide noncontributory defined
benefit pension plans for their employees. In addition, these subsidiaries
provide contributory defined benefit medical plans for certain retired employees
and their eligible dependents and noncontributory defined benefit life insurance
plans for certain retired employees (referred to collectively as other
benefits). For both pension and other benefit plans, the Utility's plan
represents substantially all of the plan assets and the benefit obligation.
Therefore, all descriptions and assumptions are based on the Utility's plan. The
schedules below aggregate all of PG&E Corporation's plans.
The following schedule reconciles the plans' funded status (the difference
between fair value of plan assets and the benefit obligation) to the prepaid or
accrued benefit cost recorded on the consolidated balance sheet:
Pension Benefits Other Benefits
------------------ -------------------
December 31, 1998 1997 1998 1997
- ----------------------------------------------------------------------------------------------------------------------------------
(in millions)
Change in benefit obligation
Benefit obligation at January 1 $(4,457) $(4,231) $(907) $(921)
Service cost for benefits earned (108) (102) (19) (22)
Interest cost (334) (315) (64) (64)
Plan amendments 1 (47) -- --
Special term benefits -- (11) -- (15)
Actuarial gain (loss) (321) 16 (36) 63
Benefits and expenses paid 242 233 77 52
- --------------------------------------------------------------------------------------------------------------------------------
Benefit obligation at December 31 (4,977) (4,457) (949) (907)
Change in plan assets
Fair value of plan assets at January 1 6,419 5,526 823 669
Actual return on plan assets 919 1,139 173 144
Company contributions 27 2 18 48
Plan participant contribution -- -- 13 11
Benefits and expenses paid (261) (248) (76) (49)
- --------------------------------------------------------------------------------------------------------------------------------
Fair value of plan assets at December 31 7,104 6,419 951 823
Plan assets in excess of benefit obligation 2,127 1,962 2 (84)
(Benefit obligation in excess of plan assets)
Unrecognized prior service cost 104 121 19 20
Unrecognized net loss (gain) (2,025) (2,133) (430) (375)
Unrecognized net transition obligation 79 93 366 393
- --------------------------------------------------------------------------------------------------------------------------------
Prepaid (accrued) benefit cost $ 285 $ 43 $(43) $(46)
=========================================
The Utility's share of the plan's assets in excess of the benefit obligation
for pensions in 1998 and 1997 was $2,134 million and $2,003 million,
respectively. The Utility's share of the prepaid (accrued) benefit cost for the
pensions in 1998 and 1997 was $301 million and $60 million, respectively.
The plan assets of the Utility exceeded its share of the benefit obligation
for other benefits by $24 million in 1998. In 1997, the Utility's share of the
benefit obligation in excess of the plan assets was $64 million. The Utility's
share of the accrued benefit liability for other benefits in 1998 and 1997 was
$26 million and $29 million, respectively.
Unrecognized prior service costs and the net gains are amortized on a
straight-line basis over the average remaining service period of active plan
participants. The transition obligations for pension benefits and other benefits
are being amortized over 17.5 years from 1987.
Net benefit income (cost) was as follows:
61
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Pension Benefits Other Benefits
-------------------- --------------------
December 31, 1998 1997 1996 1998 1997 1996
- -----------------------------------------------------------------------------------------------
(in millions)
Service cost for benefits earned $(108) $(102) $(101) $(19) $(21) $(22)
Interest cost (333) (316) (304) (64) (64) (66)
Expected return on assets 567 486 434 73 60 49
Amortized prior service and transition
cost (26) (22) (23) (28) (28) (28)
Actuarial gain (loss) recognized 114 74 43 22 13 4
- ------------------------------------------------------------------------------------------------
Benefit income (cost) $ 214 $120 $49 $(16) $(40) $(63)
========================================================
The Utility's share of the net benefit income for pensions in 1998, 1997, and
1996 was $215 million, $123 million, and $49 million, respectively.
The Utility's share of the net benefit cost for other benefits in 1998, 1997,
and 1996 was $12 million, $38 million, and $61 million, respectively.
Net benefit income (cost) is calculated using expected return on plan assets
of 9.0 percent. 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 benefit income (cost). In 1998, 1997, and 1996,
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 determined for accounting purposes and
Utility pension income determined for ratemaking, which is based on a funding
approach.
The CPUC has also authorized the Utility to recover the costs associated with
its other benefit plans 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 the appropriate trusts.
The following actuarial assumptions were used in determining the plans'
funded status and net benefit income (cost). Year-end assumptions are used to
compute funded status, while prior year-end assumptions are used to compute net
benefit income (cost).
Pension Benefits Other Benefits
---------------------- ----------------------
December 31, 1998 1997 1996 1998 1997 1996
- --------------------------------------------------------------------------------
Discount rate 7.0% 7.5% 7.5% 7.0% 7.5% 7.5%
Rate of future compensation
increases 5.0% 5.0% 5.0% 5.0% 5.0% 5.0%
Expected long-term rate of
return on plan assets 9.0% 9.0% 9.0% 9.0% 9.0% 9.0%
The assumed health care cost trend rate for 1999 is approximately 9.0
percent, grading down to an ultimate rate in 2005 of approximately 6.0 percent.
The assumed health care cost trend rate can have a significant effect on the
amounts reported for health care plans. A one percentage point change would have
the following effects:
1-Percentage- 1-Percentage-
(in millions) Point Increase Point Decrease
- ----------------------------------------------------------------------------------------------------------------
Effect on total service and interest
cost components $ 8 $ (7)
Effect on postretirement benefit obligation $ 79 $(72)
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, 1998, 24.5 million shares of common stock have
been authorized for award under the program with 10,844,471 shares still
available under this plan. At December 31, 1998, stock options on 11,225,564
shares, granted at option prices ranging from $21.125 to $34.25, were
outstanding, of which 2,440,008 were exercisable. In 1998, 6,367,100 options
were granted at an average option price of $30.52, for an approximate value of
$24,258,651 using the Black-Scholes valuation method.
Outstanding stock options expire ten years and one day after the date of
grant and become exercisable on a
62
cumulative basis at one-third each year commencing two years from the date of
grant. In 1998, 1997, and 1996, stock options on 710,271; 235,315; and 72,960
shares, respectively, were exercised at option prices ranging from $16.75 to
$34.25. In addition, on January 4, 1999, PG&E Corporation granted 6,173,500
options at $30.9375, the then current market price.
Note 13: Income Taxes
The significant components of income tax expense were:
PG&E Corporation Utility
-------------------- --------------------
Year ended December 31, 1998 1997 1996 1998 1997 1996
- -----------------------------------------------------------------------------------
(in millions)
Current $677 $ 707 $ 705 $ 886 $ 791 $ 705
Deferred (52) (119) (132) (201) (142) (132)
Tax credits-net (55) (40) (18) (56) (40) (18)
- -----------------------------------------------------------------------------------
Total income tax expense $570 $ 548 $ 555 $ 629 $ 609 $ 555
=================================================
The significant components of net deferred income tax liabilities were:
PG&E Corporation Utility
December 31, 1998 1997 1998 1997
- -----------------------------------------------------------------------------------------------------------------------------------
(in millions)
Deferred income tax assets $ 1,219 $1,108 $ 843 $ 96
- -----------------------------------------------------------------------------------------------------------------------------------
Deferred income tax liabilities:
Regulatory balancing accounts 43 311 40 311
Plant in service 3,722 3,621 2,930 3,144
Income tax regulatory asset 391 430 381 420
Other 968 924 555 540
- -----------------------------------------------------------------------------------------------------------------------------------
Total deferred income tax liabilities 5,124 5,286 3,906 4,415
- -----------------------------------------------------------------------------------------------------------------------------------
Total net deferred income taxes $3,905 $4,178 $3,063 $3,453
========================================
Classification of net deferred income taxes:
Included in current liabilities $ 44 $ 149 $ 3 $ 149
Included in noncurrent liabilities 3,861 4,029 3,060 3,304
Total net deferred income taxes $3,905 $4,178 $3,063 $3,453
========================================
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, 1998 1997 1996 1998 1997 1996
- -----------------------------------------------------------------------------------------------------------------------
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) 3.3 5.3 3.8 6.6 4.6 3.7
Effect of regulatory treatment of depreciation
differences 10.4 8.1 6.0 9.8 7.5 5.9
Tax credits-net (4.3) (3.2) (1.4) (4.1) (2.9) (1.4)
Effect of foreign earnings at different tax rate .6 (2.2) -- -- -- --
Other-net (.8) .3 -- (1.0) -- (.8)
- ------------------------------------------------------------------------------------------------------------------------
Effective tax rate 44.2% 43.3% 43.4% 46.3% 44.2% 42.4%
=========================================================
63
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Historically, the benefits of certain temporary differences have been
utilized to reduce the Utility's customers rates. Accordingly, a regulatory
asset has been recorded reflecting the pre-tax amount that will be recovered
from customers as the temporary difference reverses. In connection with the
California electric restructuring plan, the Utility is collecting the regulatory
asset over four years.
Note 14: Commitments
Utility:
* Letters of Credit:
The Utility uses $385 million in standby letters of credit and surety bonds to
secure future workers' compensation liabilities.
* Restructuring Trust Guarantees:
Tax-exempt restructuring trusts have been established to oversee the development
of the operating framework for the competitive generation market in California.
(See Note 2.) 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. The bank loans will be repaid and the guarantees removed when
the trusts obtain proceeds from permanent financing or rate recovery.
* 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 1999 through 2001. Total capacity payments are
expected to remain at current levels during this period. Deliveries from these
power producers account for approximately 23 percent of the Utility's 1998
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 in the accompanying balance sheet. At
December 31, 1998, the total discounted future payments remaining under early
termination or suspension contracts is $48 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 supplier's retention of the FERC's authorization) and
variable payments for operation and maintenance costs incurred by the suppliers.
These contracts expire on various dates from 2004 to 2031. These costs are also
recoverable in rates. At December 31, 1998, the undiscounted future minimum
payments under these contracts are $32 million for each of the years 1999
through 2003 and a total of $280 million for periods thereafter. Irrigation
district and water agency deliveries in the aggregate account for approximately
7.5 percent of the Utility's 1998 electrict energy requirements.
The amount of energy received and the total payments made under all of these
power-purchase contracts were:
Year ended December 31, 1998 1997 1996
- ------------------------------------------------------------
(in millions)
Kilowatt-hours received 25,994 24,389 26,056
Energy payments 943 1,157 1,136
Capacity payments 529 538 521
Irrigation district and water
agency payments 53 56 52
* Natural Gas 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
64
total amounts the Utility paid under these contracts were $113 million, $255
million, and $269 million in 1998, 1997, and 1996, respectively. These amounts
include payments made by the Utility to PG&E GT of $49 million, $49 million, and
$57 million in 1998, 1997, and 1996, respectively.
The Utility's obligations related to capacity held pursuant to long-term
contracts on various pipelines are as follows:
- --------------------------------------------------------------------
(in millions)
1999 $102
2000 102
2001 99
2002 83
2003 83
Thereafter 188
- --------------------------------------------------------------------
Total $657
=======
As a result of regulatory changes, the Utility no longer procures gas for
most of its industrial and larger commercial (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
residential and smaller commercial (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.
Wholesale and Retail Unregulated Business Operations:
* Power-Purchase Contracts:
As a part of the acquisition of a portfolio of electric generating assets and
power supply contracts from NEES (See Note 5), NEES transferred to USGen
contractual rights and duties under several power-purchase contracts with third-
party independent power producers, which in the aggregate provide for
approximately 800 MW of capacity. Under the transfer agreement, USGen is
required to pay to NEES amounts due to the third-party power producers under the
power-purchase contracts. USGen's payment obligations to NEES are reduced by
NEES's monthly payment obligation, which equals, in the aggregate, approximately
$1.1 billion, payable in monthly installments from September 1998 through
January 2008. In certain circumstances, NEES, with the consent of USGen, will
make a full or partial lump-sum accelerated payment of the monthly payment
obligation to such party as USGen may direct. The approximate dollar obligations
under these agreements are as follows:
- --------------------------------------------------------------------
(in millions)
1999 $ 261
2000 272
2001 263
2002 238
2003 217
Thereafter 2,024
- --------------------------------------------------------------------
Total $3,275
=========
* Natural Gas Transportation Commitments:
As a part of the acquisition of a portfolio of electric generating assets and
power supply contracts from NEES (See Note 5), NEES transferred to USGen four
natural gas purchase agreements with contract expirations ranging from October
2008 to October 2013, as well as eleven natural gas transportation contracts
with contract expirations ranging from October 2006 to October 2014. The
approximate dollar obligations under the natural gas transportation agreements
are as follows:
(in millions)
1999 $ 58
2000 58
2001 58
2002 58
2003 57
Thereafter 465
- --------------------------------------------------------------------
Total $754
========
* Standard Offer Agreements:
As a part of the acquisition of a portfolio of electric generating assets and
power supply contracts from NEES (See Note 5), USGen entered into agreements to
supply the electric capacity and energy necessary for NEES to meet its
obligations to provide standard offer service. The agreements to provide
standard offer service range in length from 6 to 11 years. The price per MW hour
is standard for all agreements. The approximate dollar obligations under the
agreements are as follows:
65
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- --------------------------------------------------------------------
(in millions)
1999 $ 788
2000 767
2001 712
2002 483
2003 345
Thereafter 302
- --------------------------------------------------------------------
Total $3,397
==========
Note 15: Contingencies
Nuclear Insurance: The Utility has insurance for property damage and business
interruption losses as a member of Nuclear Electric Insurance Limited (NEIL).
Under this insurance, if a nuclear generating facility suffers a loss due to a
prolonged accidental outage, then the Utility may be subject to maximum
retrospective assessments of $17 million (property damage) and $5 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. The Utility has secondary
financial protection which provides an additional $9.6 billion in coverage,
which is mandated by federal legislation. It provides for loss sharing among
utilities owning nuclear generating facilities if a costly incident occurs. If a
nuclear incident results in claims in excess of $200 million, then the Utility
may be assessed up to $176 million per incident, with payments in each year
limited to a maximum of $20 million per incident.
Environmental Remediation: The Utility may be required to pay for environmental
remediation at sites where the Utility 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 potentially hazardous
materials. Under CERCLA, the Utility may be responsible for 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 remediation liability quarterly for each identified site.
The liability is an estimate of costs for site investigations, remediation,
operations and maintenance, monitoring, and site closure. The remediation costs
also reflect: (1) current technology, (2) enacted laws and regulations, (3)
experience gained at similar sites, and (4) the probable level of involvement
and financial condition of other potentially responsible parties. 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. A change in the estimate may 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 of $296 million and $232
million at December 31, 1998 and 1997, respectively, for hazardous waste
remediation costs at identified sites, including divested fossil-fueled power
plants.
Environmental remediation at identified sites may be as much as $487 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. The Utility estimated this upper limit of the range of costs 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 expected outcomes change.
Of the $296 million liability, discussed above, the Utility has recovered
$104 million and expects to recover another $160 million in future rates.
Additionally, the Utility mitigates its cost by seeking recovery of its costs
from insurance carriers and from other third parties as appropriate.
Legal Matters:
* Chromium Litigation:
Several civil suits are pending against the Utility in California state courts.
The suits seek an unspecified
66
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, California. Two of these suits also name PG&E Corporation as a
defendant. Currently, there are claims pending on behalf of approximately 2,300
individuals.
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.
PG&E Corporation believes that the ultimate outcome of these matters will not
have a material 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 Energy Corporation,
now known as PG&E GTT, PG&E GTT succeeded to the litigation described below.
PG&E GTT and various of its affiliates are defendants in at least two class
action suits and five separate suits filed by various Texas cities. Generally,
these cities allege, among other things, that: (1) owners or operators of
pipelines occupied city property and conducted pipeline operations without the
cities' consent and without compensating the cities; and (2) the gas marketers
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.
In 1998, a jury trial was held in the separate suit brought by the City of
Edinburg (the City). This suit involved, among other things, a particular
franchise agreement entered into by a former subsidiary of PG&E GTT (now owned
by Southern Union Gas Company (SU)) and the City and certain conduct of the
defendants.
On December 1, 1998, based on the jury verdict, the court entered a judgment
in the City's favor, and awarded damages of $5.3 million, and attorneys' fees of
up to $3.5 million plus interest. The court found that various PG&E GTT and SU
defendants were jointly and severally liable for $3.3 million of the damages and
all the attorneys' fees. Certain PG&E GTT subsidiaries were found solely liable
for $1.4 million of the damages. The court did not clearly indicate the extent
to which the PG&E GTT defendants could be found liable for the remaining
damages. The PG&E GTT defendants intend to appeal the judgment.
PG&E Corporation believes that the ultimate outcome of these matters could
have a material adverse impact on its financial position or results of
operations.
Note 16: Segment Information
PG&E Corporation's reportable operating segments provide different products and
services and are subject to different forms of regulation or jurisdictions. The
accounting policies of the reportable operating segments are the same as those
described in Note 1. PG&E Corporation's reportable segments are des-cribed
below.
Utility: PG&E Corporation's Northern and Central California energy utility
subsidiary, Pacific Gas and Electric Company, provides natural gas and electric
service to one of every 20 Americans.
Wholesale Unregulated Business Operations: PG&E Corporation's wholesale
unregulated business operations consist of USGen which develops, builds,
operates, owns, and manages power generation facilities that serve wholesale and
industrial customers; PG&EGT which operates approximately 9,000 miles of natural
gas pipelines, natural gas storage facilities, and natural gas processing plants
in the Pacific Northwest and Texas; and PG&EET which purchases and resells
energy commodities and related financial instruments in major North American
markets, serving PG&E Corporation's other unregulated businesses, unaffiliated
utilities, and large end-use customers.
67
Retail Unregulated Business Operations: PG&ECorporation's retail unregulated
business operations consist of PG&E ES which provides competitively priced
electricity, natural gas, and related services to lower overall energy costs
Segment information for the years 1998, 1997, and 1996 was as follows:
Wholesale Retail
------------------------------------- ---------
PG&E ET
-------------------- Corp. & Elimi-
Utility USGen/(5)/ NW TEXAS/(5)/ PG&E ET PG&E ES Other/(2)/ nations Total
- ------------------------------------------------------------------------------------------------------------------------------------
(in millions)
1998
Operating revenues $ 8,919 $ 645 $ 185 $1,640 $8,183 $365 $ 8 $ (3) $19,942
Intersegment revenues/(1)/ 5 4 52 301 326 14 -- (702) --
- ------------------------------------------------------------------------------------------------------------------------------------
Total operating revenues 8,924 649 237 1,941 8,509 379 8 (705) 19,942
- ------------------------------------------------------------------------------------------------------------------------------------
Depreciation, amortization and
decommissioning 1,438 52 39 65 5 7 3 -- 1,609
Interest expense/(3)/ (621) (43) (43) (77) (7) (1) (30) 40 (782)
Other income (expense) 76 18 3 13 5 (1) (6) (44) 64
Income taxes/(4)/ 629 28 31 (47) (17) (41) (13) -- 570
Net income 702 106 65 (71) (6) (52) (18) (7) 719
Capital expenditures 1,396 98 49 39 12 38 1 -- 1,633
Total assets at year-end $22,950 $3,844 $1,169 $2,655 $2,555 $ 202 $ 601 $(742) $33,234
1997
Operating revenues $ 9,495 $ 148 $ 186 $ 800 $4,613 $ 145 $ 13 $ -- $15,400
Intersegment revenues/(1)/ -- -- 47 204 195 -- -- (446) --
- ------------------------------------------------------------------------------------------------------------------------------------
Total operating revenues 9,495 148 233 1,004 4,808 145 13 (446) 15,400
- ------------------------------------------------------------------------------------------------------------------------------------
Depreciation, amortization and
decommissioning 1,748 19 38 33 3 1 10 -- 1,852
Interest expense/(3)/ (570) (5) (41) (26) (2) (1) (32) 12 (665)
Other income (expense) 83 (25) 1 13 3 -- 138 (12) 201
Income taxes/(4)/ 609 (17) 26 (8) (12) (17) (33) -- 548
Net income 735 (41) 40 (24) (19) (29) 54 -- 716
Capital expenditures 1,529 23 34 45 5 15 50 -- 1,701
Total assets at year-end $25,147 $989 $1,208 $2,800 $1,452 $60 $370 $(911) $31,115
1996
Operating revenues $ 8,989 $105 $ 206 $ -- $ 283 $-- $27 $ -- $ 9,610
Intersegment revenues/(1)/ -- -- 58 -- -- -- -- (58) --
- ------------------------------------------------------------------------------------------------------------------------------------
Total operating revenues 8,989 105 264 -- 283 -- 27 (58) 9,610
- ------------------------------------------------------------------------------------------------------------------------------------
Depreciation, amortization and
decommissioning 1,177 12 32 -- -- -- 1 -- 1,222
Interest expense/(3)/ (600) (7) (45) -- -- -- 20 -- (632)
Other income (expense) 20 9 (4) -- -- -- (12) -- 13
Income taxes/(4)/ 526 (6) 31 -- -- -- 4 -- 555
Net income 706 (6) 50 -- -- -- (28) -- 722
Capital expenditures 1,231 -- 173 -- -- -- -- -- 1,404
Total assets at year-end $23,567 $881 $1,772 $-- $-- $-- $205 $(188) $26,237
/(1)/ Intersegment electric and gas revenues are recorded at market prices,
which for the Utility and PG&E GT NW are tariffed rates prescribed by the
CPUC and FERC, respectively.
/(2)/ Assets of PG&E Corporation are included in the Other column exclusive of
investment in its subsidiaries.
/(3)/ Net interest expense incurred by PG&E Corporation is allocated to the
segments using specific identification.
/(4)/ Income tax expense for the Utility is computed on a stand-alone basis. The
balance of the consolidated income tax provision is allocated among the
unregulated wholesale and retail segments.
/(5)/ Income from equity-method investees for 1998, 1997, and 1996 was $113
million, $41 million, and $36 million, respectively, for USGen, and $3
million and $2 million, respectively, for PG&E GT Texas.
68
QUARTERLY CONSOLIDATED FINANCIAL DATA (UNAUDITED)
Quarter ended December 31 September 30 June 30 March 31
- -------------------------------------------------------------------------------------------------------
(in millions, except per share amounts)
1998
PG&E Corporation
Operating revenues $5,495 $5,307 $4,787 $4,353
Operating income 456 529 557 465
Net income 196 210 174 139
Earnings per common share, basic and diluted .51 .55 .46 .36
Dividends declared per common share .30 .30 .30 .30
Common stock price per share
High 35.00 33.38 33.19 33.19
Low 30.44 30.06 30.13 29.38
Utility
Operating revenues $2,218 $2,563 $2,117 $2,026
Operating income 443 513 494 426
Income available for common stock 169 199 186 148
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
69
REPORT OF INDEPENDENT PUBLIC ACCOUTANTS
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 Pacific Gas and Electric Company
(a California corporation) and subsidiaries as of December 31, 1998, and 1997,
and the related statements of consolidated income, cash flows, and common stock
equity of PG&E Corporation and subsidiaries and the related statements of
consolidated income, cash flows and common stock equity, preferred stock and
preferred securities of Pacific Gas and Electric Company and subsidiaries for
each of the three years in the period ended December 31, 1998. These financial
statements are the responsibility of the management of PG&E Corporation and
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 overal l 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, 1998, and 1997, and the results of their operations and their cash
flows for each of the three years in the period ended December 31, 1998, in
conformity with generally accepted accounting principles.
ARTHUR ANDERSEN LLP
San Francisco, California
February 8, 1999
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 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 has taken 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 is conducted in conformity with
applicable laws and with their commitment to ethical conduct.
70