EXHIBIT 13
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SELECTED FINANCIAL DATA
(IN MILLIONS, EXCEPT PER SHARE AMOUNTS) 1999 1998 1997 1996 1995
PG&E CORPORATION(1)
FOR THE YEAR
Operating revenues $20,820 $19,577 $15,255 $ 9,610 $ 9,622
Operating income 878 2,098 1,762 1,896 2,763
Income from continuing operations 13 771 745 722 1,269
Earnings per common share from continuing operations,
basic and diluted 0.04 2.02 1.82 1.75 2.99
Dividends declared per common share 1.20 1.20 1.20 1.77 1.96
AT YEAR-END
Book value per common share $ 19.13 $ 21.08 $ 21.30 $ 20.73 $ 20.77
Common stock price per share 20.50 31.50 30.31 21.00 28.38
Total assets 29,715 33,234 31,115 26,237 26,871
Long-term debt (excluding current portions) 6,673 7,422 7,659 7,770 8,049
Rate reduction bonds (excluding current portions) 2,031 2,321 2,611 -- --
Redeemable preferred stock and securities of subsidiaries
(excluding current portions) 635 635 750 694 694
PACIFIC GAS AND ELECTRIC COMPANY
FOR THE YEAR
Operating revenues $ 9,228 $ 8,924 $ 9,495 $ 9,610 $ 9,622
Operating income 1,993 1,876 1,820 1,896 2,763
Income available for common stock 763 702 735 722 1,269
AT YEAR-END
Total assets $21,470 $22,950 $25,147 $26,237 $26,871
Long-term debt (excluding current portions) 4,877 5,444 6,218 7,770 8,049
Rate reduction bonds (excluding current portions) 2,031 2,321 2,611 -- --
Redeemable preferred stock and securities (excluding
current portions) 586 586 694 694 694
(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 1995 and
1996 are identical because they reflect the accounts of the Utility as the
predecessor of PG&E Corporation. Matters relating to certain data above,
including discontinued operations and the cumulative effect of a change in
an accounting principle are discussed in Management's Discussion and
Analysis and in the Notes to 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 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 National Energy Group provides energy products and services
throughout North America.
The National Energy Group businesses develop, construct, operate, own, and
manage independent power generation facilities that serve wholesale and
industrial customers through PG&E Generating Company, LLC (formerly U.S.
Generating Company, LLC) and its affiliates (collectively, PG&E Gen); own and
operate natural gas pipelines, natural gas storage facilities, and natural gas
processing plants, primarily in the Pacific Northwest and in Texas, through
various subsidiaries of PG&E Corporation (collectively, PG&E Gas Transmission or
PG&E GT); purchase and sell energy commodities and provide risk management
services to customers in major North American markets, including the other
National Energy Group non-utility businesses, unaffiliated utilities, marketers,
municipalities, and large end-use customers through PG&E Energy Trading--Gas
Corporation, PG&E Energy Trading--Power, L.P., and their affiliates
(collectively, PG&E Energy Trading or PG&E ET); and provide competitively priced
electricity, natural gas, and related services to industrial, commercial, and
institutional customers through PG&E Energy Services Corporation (PG&E Energy
Services or PG&E ES). In the fourth quarter of 1999, PG&E Corporation's Board of
Directors approved a plan for the divestiture of PG&E Corporation's Texas
natural gas and natural gas liquids business. Also in the fourth quarter of
1999, PG&E Corporation's Board of Directors approved a plan for the divestiture
of PG&E Corporation's retail energy services.
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 wholly
owned and controlled subsidiaries. The consolidated financial statements of the
Utility reflect the accounts of the Utility and its wholly owned and controlled
subsidiaries. This Management's Discussion and Analysis (MD&A) should be read in
conjunction with the consolidated financial statements included herein.
This combined annual report, including our Letter to Shareholders and this
MD&A, contains forward-looking statements about the future that are necessarily
subject to various risks and uncertainties. These statements are based on
assumptions which management believes are reasonable 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. Actual results could differ
materially from those contemplated by the forward-looking statements.
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 pace and extent of the ongoing restructuring of the electric and
natural gas industries across the United States;
- operational changes related to industry restructuring, including changes
in the Utility's business processes and systems;
- the method and timing of disposition and valuation of the Utility's
hydroelectric generation assets;
- the timing of the completion of the Utility's transition cost recovery and
the consequent end of the current electric rate freeze in California;
- any changes in the amount the Utility is allowed to collect (recover) from
its customers for certain costs that prove to be uneconomic under the new
competitive market (called transition costs);
- future operating performance at the Diablo Canyon Nuclear Power Plant
(Diablo Canyon);
- the method adopted by the California Public Utilities Commission (CPUC)
for sharing the net benefits of operating Diablo Canyon with ratepayers
and the timing of the implementation of the adopted method;
- the extent of anticipated growth of transmission and distribution services
in the Utility's service territory;
- future market prices for electricity;
- future fuel prices;
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- the success of management's strategies to maximize shareholder value in
PG&E Corporation's National Energy Group, which may include acquisitions
or dispositions of assets, or internal restructuring;
- the extent to which our current or planned generation development projects
are completed and the pace and cost of such completion;
- generating capacity expansion and retirements by others;
- the successful integration and performance of acquired assets;
- the outcome of the Utility's various regulatory proceedings, including the
proposal to auction the Utility's hydroelectric generation assets, the
electric transmission rate case applications, and post-transition period
ratemaking proceedings;
- fluctuations in commodity gas, natural gas liquids, 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.
As the ultimate impact of these and other factors is 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 1999,
1998, and 1997. 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.
COMPETITIVE AND REGULATORY ENVIRONMENT
This section provides a discussion of the competitive environment in the
evolving energy industry, the California electric industry, the California
natural gas business, the National Energy Group, 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 "unbundle," or price separately, those activities that
are no longer considered 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 for 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 providers 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 (often a local gas distribution company) buys the gas
commodity from the pipeline.
In the electric industry, the Public Utilities Regulatory Policies Act of
1978 (PURPA) 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 Policies Act of 1992 was designed and
implemented through FERC Orders 888 and 889 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 either have implemented plans or are considering proposals to separate
the generation from the transmission and distribution of electricity through
some form of electric industry restructuring.
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To date, the states, not the federal government, have taken the initiative
on electric industry restructuring at the retail level. While many bills
mandating restructuring of the electric industry have been introduced in
Congress, none have passed. As a result, the pace, extent, and methods for
restructuring the electric industry vary widely throughout the country. For
instance, as of December 31, 1999, 21 states had enacted electric industry
restructuring legislation, including California, Texas, Illinois, Pennsylvania,
New Jersey, Massachusetts, Rhode Island, New Hampshire, and Connecticut. There
also are some states that have passed legislation precluding or significantly
slowing down restructuring. 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
by states or federal legislation to deregulate the electric generation and
natural gas supply business could impact the pace of growth of our National
Energy Group.
THE CALIFORNIA ELECTRIC INDUSTRY
In 1998, California became one of the first states in the country to
implement electric industry restructuring and establish a competitive market
framework for electric generation. Today, most Californians may continue to
purchase their electricity from investor-owned utilities such as Pacific Gas and
Electric Company, or they may choose to purchase electricity from alternative
generation providers (such as unregulated power generators and unregulated
retail electricity suppliers such as marketers, brokers, and aggregators). For
those customers who have not chosen an alternative generation provider,
investor-owned utilities, such as the Utility, continue to be the generation
providers. Investor-owned utilities continue to provide distribution services to
substantially all customers within their service territories, including
customers who choose an alternative generation provider.
COMPETITIVE MARKET FRAMEWORK:
To create a competitive generation market, a Power Exchange (PX) and an
Independent System Operator (ISO) began operating on March 31, 1998. The PX
provides a competitive auction process to establish market clearing prices for
electricity in the markets operated by the PX. The ISO schedules delivery of
electricity for all market participants. The Utility continues to own and
maintain a portion of the transmission system, but the ISO controls the
operation of the system. Unless or until the CPUC determines otherwise, the
Utility is required to bid or schedule into the PX and ISO markets 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.
In November 1999, the FERC approved the extension of the ISO's authority to
establish price limitations through 2000. The ISO Board increased the applicable
price limitation to $750 per megawatt-hour (MWh) on October 1, 1999, but has the
option to decrease it to $500 per MWh or make other changes, in view of the
FERC's decision. This limits the amount of volatility that occurs in the
California electricity market. However, the ISO will review the appropriate
level for any price limitations for the summer of 2000 in light of market
redesign efforts now being considered, including changes to reduce uninstructed
deviations from ISO dispatch orders and changes to permit loads to participate
by submitting bids for price-responsive demand in energy or ancillary services
markets.
The Utility is continuing 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.
TRANSITION PERIOD, RATE FREEZE, AND RATE REDUCTION:
California's electric industry restructuring established a transition period
during which electric rates remain frozen at 1996 levels (with the exception
that, on January 1, 1998, rates for small commercial and residential customers
were reduced by 10 percent and remain frozen at this reduced level) and
investor-owned utilities may recover their transition costs. Transition costs
are generation-related costs that prove to be uneconomic under the new
competitive structure. The transition period ends the earlier of December 31,
2001, or when the particular utility has recovered its eligible transition
costs.
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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 competitive transition charge (CTC), which
recovers the transition costs. These CTC revenues are being recovered from all
Utility distribution customers and are subject to seasonal fluctuations in the
Utility's sales volumes and certain other factors. As the CTC is collected
regardless of the customer's choice of electricity supplier (i.e., the CTC is
non-bypassable), the Utility believes that the availability of choice to its
customers will not have a material impact on its ability to recover transition
costs.
To pay for the 10 percent rate reduction, the Utility refinanced
$2.9 billion (the expected revenue reduction from the rate decrease) of its
transition costs with the proceeds from the rate reduction bonds. 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. During the rate freeze, the rate
reduction bond debt service will not increase Utility customers' electric rates.
If the transition period ends before December 31, 2001, the Utility may be
obligated to return a portion of the economic benefits of the transaction to
customers. The timing of any such return and the exact amount of such portion,
if any, have not yet been determined.
TRANSITION COST RECOVERY:
Although most transition costs must be recovered during the transition
period, certain transition costs can be recovered after the transition period.
Except for certain transition costs discussed below, 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.
Transition costs consist of (1) above-market sunk costs (costs associated
with utility generating facilities that are fixed and unavoidable and that were
included in customers' rates on December 20, 1995) and future sunk costs, such
as costs related to plant removal, (2) costs associated with long-term contracts
to purchase power at above-market prices from qualifying facilities (QF) and
other power suppliers, and (3) generation-related regulatory assets and
obligations. (In general, regulatory assets are expenses deferred in the current
or prior periods, to be included in rates in subsequent periods.)
Above-market sunk costs result when the book value of a facility exceeds its
market value. Conversely, below-market sunk costs result when the market value
of a facility exceeds its book value. The total amount of generation facility
costs to be included as transition costs is 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. These above- and
below-market sunk costs are related to generating facilities that are classified
as either non-nuclear or nuclear sunk costs.
The Utility cannot determine the exact amount of above-market non-nuclear
sunk costs that will be recoverable as transition costs until the valuation of
the Utility's remaining non-nuclear generating assets, primarily its
hydroelectric generating assets, is completed. The valuation, through appraisal,
sale, or other divestiture, must be completed by December 31, 2001. The value of
seven of the Utility's other non-nuclear generating facilities was determined
when these facilities were sold to third parties. The portion of the sales
proceeds that exceeded the book value of these facilities was used to reduce
other transition costs. On September 30, 1999, the Utility filed an application
with the CPUC to determine the market value of its hydroelectric generating
facilities and related assets through an open, competitive auction. (See
"Generation Divestiture" below.) The Utility plans to use an auction process
similar to the one previously approved by the CPUC and successfully used in the
sale of the Utility's fossil and geothermal plants. If the market value of the
Utility's hydroelectric facilities is determined based upon any method other
than a sale of the facilities to a third party, a material charge to Utility
earnings could result. Any excess of market value over book value would be used
to reduce other transition costs. (See "Generation Divestiture" below.)
For nuclear transition costs, revenues provided for transition cost recovery
are based on the accelerated recovery of the investment in Diablo Canyon over a
five-year period ending December 31, 2001. The amount of nuclear generation sunk
costs was determined separately through a CPUC proceeding and was subject to a
final verification audit that was completed in August 1998. The audit of the
Utility's Diablo Canyon accounts at December 31, 1996, 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. The independent accounting firm also issued an agreed-upon special
procedures report, requested by the CPUC, that questioned
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$200 million of the $3.3 billion sunk costs. The CPUC will review the results of
the audit and may seek to make adjustments to Diablo Canyon's sunk costs subject
to transition cost recovery. At this time, the Utility cannot predict what
actions, if any, the CPUC may take regarding the audit report.
Costs associated with the Utility's long-term contracts to purchase electric
power are included as transition costs. Regulation required the Utility to enter
into such long-term agreements with non-utility generators. Prices fixed under
these contracts are now typically above prices for power in wholesale markets.
(See Note 14 of Notes to Consolidated Financial Statements.) Over the remaining
life of these contracts, the Utility estimates that it will purchase
299 million MWh of electric power. To the extent that the individual contract
prices are above the 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 costs under long-term contracts are based on several variables,
including the capacity factors of the related generating facilities and future
market prices for electricity. During 1999, the average price paid under the
Utility's long-term contracts for electricity was 6.3 cents per kilowatt-hour
(kWh). The average cost of electricity purchased at market rates from the PX for
the year ended December 31, 1999, was 3.7 cents per kWh. The average cost of
electricity purchased at market rates from the PX for the period from March 31,
1998, the PX's establishment date, 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. At December 31, 1999 and
1998, the Utility's generation-related net regulatory assets totaled $4 billion
and $5.4 billion, respectively.
Certain transition costs can be recovered through 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, (3) up to
$95 million of transition costs to the extent that the recovery of such costs
during the transition period was displaced by the recovery of electric industry
restructuring implementation costs, and (4) transition costs financed by the
rate reduction bonds. Transition costs financed by the issuance of rate
reduction bonds will be recovered over the term of the bonds. In addition, the
Utility's nuclear decommissioning costs are being recovered through a
CPUC-authorized charge, which will extend until sufficient funds exist to
decommission the nuclear facility. During the rate freeze, the charge for these
costs will not increase Utility customers' electric rates. Excluding these
exceptions, the Utility will write off any transition costs not recovered during
the transition period.
The Utility is amortizing its transition costs, including most
generation-related regulatory assets, over the transition period in conjunction
with the available CTC revenues. During the transition period, a reduced rate of
return on common equity of 6.77 percent applies to all generation assets,
including those generation assets reclassified to regulatory assets. Effective
January 1, 1998, the Utility started collecting these eligible transition costs
through the non-bypassable CTC and generation divestiture. For the years ended
December 31, 1999 and 1998, regulatory assets related to electric industry
restructuring decreased by $1,359 million and $609 million, respectively, which
reflects the recovery of eligible transition costs.
During the transition period, the CPUC reviews the Utility's compliance with
accounting methods established in the CPUC's decisions governing transition cost
recovery and the amount of transition costs requested for recovery. The CPUC is
currently reviewing non-nuclear transition costs amortized during 1998 and the
first six months of 1999.
GENERATION DIVESTITURE:
In 1998, the Utility sold 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).
On April 16, 1999, the Utility sold three other fossil-fueled generation
plants for $801 million. At the time of sale, these three fossil-fueled plants
had a combined book value of $256 million and had a combined capacity of 3,065
MW.
On May 7, 1999, the Utility sold its complex of geothermal generation
facilities for $213 million. At the time of sale, these facilities had a
combined book value of $244 million and had a combined capacity of 1,224 MW.
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The gains from the sale of the fossil-fueled generation plants were used to
offset other transition costs. Likewise, the loss from the sale of the complex
of geothermal generation facilities is being recovered as a transition cost.
The Utility has retained a liability for required environmental remediation
related to any pre-closing soil or groundwater contamination at the plants it
has sold.
On September 30, 1999, the Utility filed an application with the CPUC to
determine the market value of its hydroelectric generating facilities and
related assets through an open, competitive auction. The Utility proposes to use
an auction process similar to the one previously approved by the CPUC and
successfully used in the sale of the Utility's fossil and geothermal plants.
Under the process proposed in the application, another subsidiary of PG&E
Corporation, PG&E Gen, would be permitted to participate in the auction on the
same basis as other bidders.
The sale of the hydroelectric facilities would be subject to certain
conditions, including the transfer or re-issuance of various permits and
licenses by the FERC and other agencies. In addition, the FERC must approve
assignment of the Utility's Reliability Must Run Contract with the ISO for any
facility subject to such contract. Under the proposed purchase and sale
agreement, the CPUC's approval of the proposed sale on terms acceptable to the
Utility in the Utility's sole discretion is also a condition precedent to the
closing of any sale.
On January 13, 2000, a scoping memo and ruling was issued that separates the
proceeding into two concurrent phases: one to review the potential environmental
impacts of the proposed auction under the California Environmental Quality Act
and a second to determine whether the Utility's auction proposal, or some other
alternative to the proposal, is in the public interest. The ruling notes that
the divestiture and valuation issues can best be considered after the
environmental impacts of a change in ownership have been reviewed. Potential
bidders will also be able to incorporate the costs of any mitigation measures
that may be required into their bids. The ruling sets a procedural schedule
which calls for a final decision on the Utility's auction proposal by
October 19, 2000, and a final environmental impact report published in
November 2000. The ruling also anticipates that a final CPUC decision approving
the sale would be issued by May 15, 2001. Finally, the ruling prohibits the
Utility from withdrawing its application without express CPUC authority. It is
uncertain whether the CPUC will ultimately approve the Utility's auction
proposal.
At December 31, 1999, the book value of the Utility's net investment in
hydroelectric generation assets was approximately $0.7 billion, excluding
approximately $0.5 billion of net investment reclassified as regulatory assets.
Any excess of market value over the $0.7 billion book value would be used to
reduce transition costs, including the remaining $0.5 billion of regulatory
assets related to the hydroelectric generation assets. If the market value of
the hydroelectric generation assets is determined by any method other than a
sale of the assets to a third party, or if the winning bidder for any of the
auctioned assets is PG&E Gen, a material charge to Utility earnings could
result. The timing and nature of any such charge is dependent upon the valuation
method and procedure adopted, and the method of implementation. As discussed
below, it is possible that the CPUC will require an interim valuation through an
estimate of market value of the assets prior to transfer, sale, or other
divestiture, which could also result in a material charge. While transfer or
sale to an affiliated entity such as PG&E Gen would result in a material charge
to income, neither PG&E Corporation nor the Utility believes that the sale of
any generation facilities to a third party will have a material impact on its
results of operations.
The Utility's ability to continue recovering its transition costs depends 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
determined value of the Utility's hydroelectric generation facilities,
(4) future Utility sales levels, (5) future Utility fuel and operating costs,
and (6) the market price of electricity. Given the current evaluation of these
factors, PG&E Corporation believes that the Utility will recover its transition
costs. 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.
POST-TRANSITION PERIOD:
In October 1999, the CPUC issued a decision in the Utility's post-transition
period ratemaking proceeding. Among other matters, the CPUC's decision addresses
the mechanisms for ending the current electric rate freeze and for establishing
post-transition period accounting mechanisms and rates. The decision requires
Diablo Canyon generation to be priced at prevailing market rates after the
transition period. This portion of the decision is further discussed below under
"Regulatory Matters - Post-Transition Period Ratemaking Proceeding."
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The CPUC decision requires the Utility to provide quarterly forecasts of
when the Utility's rate freeze (i.e., transition period) may end based on
various assumptions regarding energy prices and the book value of the Utility's
remaining generation assets. The Utility is required to notify the CPUC three
months before the earliest forecasted end of its rate freeze and provide draft
tariff language and sample calculations of the rates that would go into effect
when the rate freeze ends. After the Utility completes its transition cost
recovery, it must implement its post-rate-freeze rates.
The timing of the end of the rate freeze and corresponding transition period
will, in part, depend on the timing of the valuation of the Utility's
hydroelectric generating assets and the ultimate determined value of such assets
since any excess of market value over the assets' book value would be used to
reduce transition costs. If the value of the Utility's hydroelectric generation
assets is significantly higher than the related book value, the transition
period and the rate freeze could end before December 31, 2001, and potentially
could end during 2000. The CPUC is considering the Utility's proposal to auction
its hydroelectric assets, although the CPUC could also require the Utility to
implement an interim valuation of the assets. In another proceeding (the 1998
Annual Transition Cost Proceeding (ATCP)), a CPUC administrative law judge
issued a proposed decision on January 7, 2000, which contained a proposed change
to the rules previously in place for the amortization of transition costs. Under
the final decision, issued on February 17, 2000, on a prospective basis the
utilities are required to assess the estimated market value of their remaining
non-nuclear generating assets, including the land associated with those assets,
on an aggregate basis at a value not less than the net book value of those
assets and to credit the Transition Cost Balancing Account (TCBA) with the
estimated value. The decision encourages the utilities to base such estimates on
realistic assessments of the market value of the assets. The final decision did
not adopt the proposed decision's recommendation to establish a new regulatory
asset account that would allow a true-up when the estimated market value is
greater than actual market value. However, the decision states that crediting
the TCBA with the aggregate net book value of the remaining non-nuclear
generating assets is a conservative approach and remedies any concerns regarding
the lack of a true-up. The decision provides that if the estimated market
valuation is less than book value for any individual asset, accelerated
amortization of the associated transition costs will continue until final market
valuation of the asset occurs through sale, appraisal, or other divestiture. If
the final value of the assets, determined through sale, appraisal, or other
divestiture, is higher than the estimate, the excess amount would be used to pay
remaining transition costs, if any. The utilities are required to file the
adjusted entries to their respective TCBA based on the estimated market values
with the CPUC by March 9, 2000. The filing will become effective after
appropriate review by the CPUC's Energy Division and the TCBA entries are
subject to review in the next ATCP. If an estimate of the market value of the
non-nuclear generating assets is adopted that exceeds the aggregate net book
value of those assets, a charge to earnings would result.
After the rate freeze and transition periods end, the Utility must refund to
electric customers any over-collected transition costs (plus interest at the
Utility's authorized rate of return) within one year after the end of the rate
freeze. The Utility also will be prohibited from collecting after the rate
freeze any electric costs incurred during the rate freeze but not recovered
during the rate freeze, including costs that are not classified as transition
costs. Through the end of its rate freeze, the Utility will continue to incur
certain non-transition costs and place those costs into balancing and memorandum
accounts for future recovery. There is a risk that the Utility will be unable to
collect certain non-transition costs that, due to lags in the regulatory cost
approval process, have not been approved for recovery nor collected when the
rate freeze ends. The Utility is unable to predict the amount of such potential
unrecoverable costs.
The CPUC also has established the Purchased Electric Commodity Account for
the Utility to track energy costs after the rate freeze and transition period
end. The CPUC intends to explore other ratemaking issues, including whether
dollar-for-dollar recovery of energy costs is appropriate, in the second phase
of the post-transition electric ratemaking proceeding. There are three primary
options for the future regulatory framework for utility electric energy
procurement cost recovery after the rate freeze: (1) a CPUC-defined procurement
practice, that if followed by the Utility, would pass through costs without the
need for reasonableness reviews, (2) a pass-through of costs subject to
after-the-fact reasonableness reviews, or (3) a procurement incentive mechanism
with rewards and penalties determined based on the Utility's energy purchasing
performance compared to a benchmark. The Utility proposed adoption of either a
defined procurement practice or a procurement incentive mechanism, neither of
which would involve reasonableness reviews. The volatility of earnings and risk
exposure of the Utility related to post-transition period purchases of
electricity is dependent on which of these options, or some other approach, is
adopted.
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After the transition period, the Utility's future earnings from its electric
distribution will be subject to volatility as a result of sales fluctuations.
DISTRIBUTED GENERATION AND ELECTRIC DISTRIBUTION COMPETITION:
In October 1999, the CPUC issued a decision outlining how the CPUC, in
cooperation with other regulatory agencies and the California Legislature, plans
to address the issues surrounding distributed generation, electric distribution
competition, and the role of the utility distribution companies (such as Pacific
Gas and Electric Company) in the competitive retail electric market. Distributed
generation enables siting of electric generation technologies in close proximity
to the electric demand (referred to as "load"). The CPUC decision opened a new
rulemaking proceeding to examine various issues concerning distributed
generation, including interconnection issues, who can own and operate
distributed generation, environmental impacts, the role of utility distribution
companies, and the rate design and cost allocation issues associated with the
deployment of distributed generation facilities. With respect to electric
distribution competition, the CPUC directed its staff to deliver a report by
April 21, 2000, on the different policy options that the CPUC, in cooperation
with the California Legislature, can pursue. Following the issuance of the
report, the CPUC expects to open one or more new proceedings to address electric
distribution competition and competition in the retail electric market.
THE CALIFORNIA NATURAL GAS BUSINESS
Restructuring of the natural gas industry on both the national and the state
levels has given choices to California utility customers to meet their gas
supply needs. The Utility offers transmission, distribution, and storage
services as separate and distinct services to its industrial and larger
commercial gas (noncore) customers. Customers have the opportunity to select
from a menu of services offered by the Utility and they pay only for the
services that they use. Access to the transmission system is possible for all
gas marketers and shippers, as well as noncore end users.
The Utility's residential and smaller commercial gas (core) customers can
select the commodity gas supplier of their choice. However, the Utility
continues to purchase gas as a regulated supplier for those core customers who
request it, serving 3.8 million core customers in its service territory.
The Utility's costs of purchasing gas for core customers through 2002 are
regulated by the core procurement incentive mechanism, 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 (referred to as "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 Gas Accord settlement agreement, approved by the CPUC in 1997,
established gas transmission rates within California for the period from
March 1998 through December 2002 for the Utility's core and noncore customers
and eliminated regulatory protection against variations in noncore transmission
revenues. As a result, the Utility is at risk for variations between actual and
forecasted transmission throughput volumes.
Rates for gas distribution services continue to be set by the CPUC and are
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."
NATIONAL ENERGY GROUP
PG&E Corporation's National Energy Group has been formed to pursue
opportunities created by the gradual restructuring of the energy industry across
the nation. The National Energy Group integrates our national power generation,
gas transmission, and energy trading and services businesses. The National
Energy Group contemplates increasing PG&E Corporation's national market presence
through a balanced program of acquisition and development of energy assets and
businesses, while at the same time undertaking ongoing portfolio management of
its assets and businesses. PG&E Corporation's ability to anticipate and capture
profitable business opportunities created by restructuring will have a
significant impact on PG&E Corporation's future operating results.
Certain New England states where our National Energy Group operates electric
generation facilities were, like California, among the first states in the
country to introduce electric industry restructuring. As a result of this
restructuring and certain other regulatory initiatives, the wholesale
unregulated electricity market in New England features a bid-based market and an
ISO.
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INDEPENDENT POWER GENERATION:
Through PG&E Gen and its affiliates, we participate in the development,
construction, operation, ownership, and management of non-utility electric
generating facilities that compete in the United States power generation market.
In September 1998, PG&E Corporation, through its indirect subsidiary USGen New
England, Inc. (USGenNE), completed the acquisition of a portfolio of electric
generation assets and power supply contracts from the New England Electric
System (NEES). The purchased 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 an aggregate of $1.3 billion of PG&E Gen and USGenNE 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) above-market
contractual obligations of $1.3 billion, relating to acquired power purchase
agreements, gas agreements, and standard offer agreements.
As part of the New England electric industry restructuring, the local
utility companies were required to offer Standard Offer Service (SOS) to their
retail 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
customers choose an alternate supplier, they are precluded from going back to
the SOS.
In connection with the purchase of the generation assets, USGenNE entered
into wholesale agreements with certain of the retail companies of NEES to supply
at specified prices the electric capacity and energy requirements necessary for
their retail companies to meet their SOS obligations. These companies are
responsible for passing on to us the revenues generated from the SOS. USGenNE
currently is indirectly serving a large portion of the SOS electric capacity and
energy requirements for these companies, except in New Hampshire. For the year
ended December 31, 1999, the SOS price paid to generators was $0.035 per Kwh for
generation. On March 1, 1999, Constellation Power Source, Inc. (Constellation)
won the New Hampshire component of the SOS through a competitive bidding
solicitation. On January 7, 2000, USGenNE paid approximately $15 million to a
third party for this third party's assumption of 10 percent of the Massachusetts
Electric Company/Nantucket Electric Company SOS and 40 percent of the
Narragansett SOS.
Like other utilities, New England utilities previously entered into
agreements with unregulated companies (e.g., qualifying facilities under PURPA)
to provide energy and capacity at prices that are anticipated to be in excess of
market prices. We assumed NEES' contractual rights and duties under several of
these power purchase agreements. At December 31, 1999, these agreements provided
for an aggregate 470 MW of capacity. However, NEES will make support payments to
us toward the cost of these agreements. The support payments by NEES total
$0.9 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 servicing SOS customers. To the
extent that customers eligible to receive SOS choose alternate suppliers, or as
these obligations are sold to other parties, this percentage will decrease. As
customers choose alternate suppliers, or the SOS obligations are sold, a greater
proportion of the output of the acquired operating capacity will be subject to
market prices.
GAS TRANSMISSION OPERATIONS:
PG&E Corporation participates in the "midstream" portion of the gas business
through PG&E GT NW. PG&E GT NW owns and operates gas transmission pipelines and
associated facilities which extend over 612 miles from the Canada-U.S. border to
the Oregon-California border. PG&E GT NW provides firm and interruptible
transportation services to third party shippers on an open-access basis. Its
customers are principally retail gas
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distribution utilities, electric utilities that use natural gas to generate
electricity, natural gas marketing companies, natural gas producers, and
industrial consumers.
On January 27, 2000, PG&E Corporation's National Energy Group signed a
definitive agreement with El Paso Field Services Company (El Paso) providing for
the sale to El Paso, a subsidiary of El Paso Energy Corporation, of the stock of
PG&E Gas Transmission, Texas Corporation and PG&E Gas Transmission Teco, Inc.
(collectively, PG&E GTT). The consideration to be received by the National
Energy Group includes $279 million in cash subject to a working capital
adjustment, the assumption by El Paso of debt having a book value of
$624 million, and other liabilities associated with PG&E GTT.
In 1999, PG&E Corporation recognized a charge against earnings of $890
million after tax, or $2.42 per share, to reflect PG&E GTT's assets at their
fair market value. The composition of the pre-tax charge is as follows: (1) an
$819 million write-down of net property, plant, and equipment, (2) the
elimination of the unamortized portion of goodwill, in the amount of $446
million, and (3) an accrual of $10 million representing selling costs.
Proceeds from the sale will be used to retire short-term debt associated
with PG&E GTT's operations and for other corporate purposes. Closing of the
sale, which is expected in the first half of 2000, is subject to approval under
the Hart Scott Rodino Act.
ENERGY TRADING:
Through PG&E ET, we purchase bulk volumes of power and natural gas from PG&E
Corporation affiliates and the wholesale market. We then schedule, transport,
and resell these commodities, either directly to third parties or to other PG&E
Corporation affiliates. PG&E ET also provides risk management services to PG&E
Corporation's other businesses (except the Utility) and to wholesale customers.
(See "Price Risk Management Activities" below; and Note 3 of the Notes to
Consolidated Financial Statements.)
ENERGY SERVICES:
In December 1999, PG&E Corporation's Board of Directors approved a plan to
dispose of PG&E ES, its wholly owned subsidiary, through a sale. As of December
31, 1999, the intended disposal has been accounted for as a discontinued
operation. In connection with this transaction, PG&E Corporation's investment in
PG&E ES was written down to its estimated net realizable value. In addition,
PG&E Corporation provided a reserve for anticipated losses through the date of
sale. The total provision for discontinued operations was $58 million, net of
income taxes of $36 million. While there is no definite sales agreement, it is
expected that the disposition will be completed in 2000. The amounts that PG&E
Corporation will ultimately realize from this disposal could be materially
different from the amounts assumed in arriving at the estimated loss on disposal
of the discontinued operations. The PG&E ES business segment generated net
losses of $40 million (or $0.11 per share), $52 million (or $0.14 per share),
and $29 million (or $0.07 per share), for the years ended December 31, 1999,
1998, and 1997, respectively.
REGULATORY MATTERS
A significant portion of PG&E Corporation's operations are regulated by
federal and state regulatory commissions. These commissions oversee service
levels and, in certain cases, PG&E Corporation's pricing for its regulated
services. Following are the percentages of 1999 revenues that fell under the
jurisdiction of these various regulatory agencies:
UTILITY CONSOLIDATED
Cost of service-based 96.8% 42.3%
Market 3.2% 57.7%
The Utility is the only subsidiary with significant regulatory proceedings
at this time. Some of the items that affected reported 1999 results, and will
affect future Utility authorized revenues, include the 1999 General Rate Case,
the year 2000 cost of capital proceeding, the post-transition period ratemaking
proceeding, the FERC transmission rate cases, the catastrophic event memorandum
account proceeding, the CPUC's gas strategy investigation-Phase 2, and the 1997
and 1998 electric base revenue increase proceeding. These items are discussed
below. Any requested change in authorized electric revenues resulting from any
of the electric 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
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recovery of transition costs would be affected. Any change in authorized gas
revenues resulting from gas proceedings would increase or decrease the Utility's
customer gas rates.
THE 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 costs to determine the
amount the Utility may charge customers for base revenues (non-fuel related
costs). The Utility requested distribution revenue increases to maintain and
improve natural gas and electric distribution reliability, safety, and customer
service. The requested revenues, as updated, included an increase of
$445 million in electric base revenues and an increase of $377 million in
natural gas base revenues over the 1998 authorized revenues.
The Utility received a final decision on its 1999 GRC application on
February 17, 2000. This final decision increased electric distribution revenues
by $163 million and gas distribution revenues by $93 million, as compared to
revenues authorized for 1998. This revenue increase is retroactive to
January 1, 1999. The impact of these increases resulted in an increase in
earnings of $153 million, or $0.42 per share, and was reflected in the fourth
quarter of 1999.
The Utility's GRC application also contained a proposal for an Attrition
Rate Adjustment (ARA) to adjust revenues in 2000 and 2001 if a performance-based
ratemaking (PBR) mechanism is not adopted for 2000 or 2001. The final decision
denies the Utility's request for an ARA to adjust revenues in 2000, but adopts
an ARA for 2001. The final decision orders that the CPUC oversee an audit of the
Utility's 1999 distribution capital spending, and that the 2001 ARA be subject
to modification to take into account the results of the audit. The 2001 ARA will
also be subject to modification to recognize amounts recorded in a new balancing
account that the final decision requires be established for vegetation
management expenses.
THE YEAR 2000 COST OF CAPITAL PROCEEDING:
In November 1999, the Utility filed its 2000 cost of capital application
with the CPUC to establish its authorized rates of return on an unbundled basis
for electric and natural gas distribution operations. To reflect increasing
interest rates, the Utility has requested a return on equity (ROE) of
12.5 percent and an overall rate of return of 9.76 percent as compared to its
1999 authorized rates of 10.6 percent ROE and 8.75 percent overall rate of
return. The Utility has not requested any change in its authorized capital
structure for 2000. The Utility's current authorized capital structure is
46.2 percent long-term debt, 5.8 percent preferred stock, and 48 percent common
equity.
If granted, the requested ROE would increase electric distribution revenues
by approximately $127.8 million and natural gas distribution revenues by
approximately $36.6 million, based on the rate base authorized in the Utility's
1999 GRC. The Utility requested that a final CPUC decision be issued in
June 2000. On February 17, 2000, the CPUC issued a decision to allow the final
CPUC decision, when it is adopted, to be effective retroactively to
February 17, 2000.
Consistent with the rate freeze, there will be no change in electric rates
in 2000. Also, the return on the Utility's electric transmission-related assets
will be determined by the FERC in 2000. Finally, the return on the Utility's
natural gas transmission and storage business was incorporated in rates
established in the Gas Accord.
POST-TRANSITION PERIOD RATEMAKING PROCEEDING:
In October 1999, the CPUC issued a decision in the Utility's post-transition
period ratemaking proceeding. Among other matters, the CPUC's decision addresses
the mechanisms for ending the current electric rate freeze and for establishing
post-transition period accounting mechanisms and rates.
The decision prohibits the Utility from continuing to price electric
generation from Diablo Canyon based on the incremental cost incentive price
(ICIP) after the transition period has ended. The ICIP, which has been in place
since January 1, 1997, is a performance-based mechanism that establishes a rate
per kWh generated by the facility. The ICIP prices for 1999, 2000, and 2001 are
3.37 cents per kWh, 3.43 cents per kWh, and 3.49 cents per kWh, respectively.
The average price for base load electric energy (the price received for a
constant level of electric generation for all hours of electric demand) sold at
market rates to the California PX for the 12-month period ended December 31,
1999, was 3.7 cents per kWh. The average price for base load electric energy
sold at market rates to the PX from March 31, 1998, the PX's establishment date,
to December 31, 1998, was 3.2 cents per kWh.
15
Future market prices may be higher or lower. Under the CPUC's decision, after
the transition period, the Utility must price Diablo Canyon generation at the
prevailing market price for power.
Further, pursuant to the 1997 CPUC decision establishing the ICIP, the
Utility is required to begin sharing 50 percent of the net benefits of operating
Diablo Canyon with ratepayers commencing January 1, 2002. The CPUC may interpret
a more recent decision to commence the benefit-sharing at the end of the
transition period. The Utility is required to file an application by July 2000
with its proposal for the methods to be used in the valuation of the benefits
associated with the operation of Diablo Canyon, and the mechanism to be used to
share these benefits with ratepayers. The Utility and PG&E Corporation are
unable to predict what type of valuation and sharing mechanism will be adopted
and what the ultimate financial impact of the sharing mechanism will have on
results of operation or financial position.
The CPUC's decision also prohibits the Utility from collecting after the
rate freeze any electric costs incurred but not recovered during the rate
freeze, including costs that are not transition costs and are not related to
generation assets such as under-collected accounting balances relating to power
purchases.
See the discussion above under "Competitive and Regulatory Environment --
The California Electric Industry Post-Transition Period."
In November 1999, the Utility filed an application for rehearing the CPUC's
decision.
The ultimate financial impact of the provisions of the CPUC's decision
described above will depend on the date the Utility's transition cost recovery
is completed and the rate freeze ends, future costs including Diablo Canyon
operating costs, future market prices for electricity, the amount of any
electric non-transition costs that have been incurred but not recovered as of
the end of the rate freeze, the timing of various regulatory proceedings in
which the Utility seeks approval for rate recovery of various costs incurred
during the rate freeze, and other variables that PG&E Corporation and the
Utility are unable to predict.
FERC TRANSMISSION RATE CASES:
Since April 1998, all electric transmission revenues are authorized by the
FERC. During 1998 and 1999, the FERC issued orders that put into effect various
rates to recover electric transmission costs from the Utility's former bundled
rate transmission customers. All 1998 and 1999 rates currently are subject to
refund, pending final decisions in the transmission cases. In April 1999, the
Utility filed a settlement with the FERC that, if approved, would allow the
Utility to recover $345 million for the period of April 1998 through May 1999.
In May 1999, the FERC accepted, subject to refund, the Utility's March 1999
request to begin recovering, as of May 31, 1999, $324 million annually. In
October 1999, the FERC accepted, subject to refund, the Utility's request to
increase revenues to $370 million annually, beginning in April 2000. The Utility
does not expect a material impact on its financial position or results of
operations resulting from these matters.
CATASTROPHIC EVENT MEMORANDUM ACCOUNT PROCEEDING:
In September 1999, the Utility entered into a Settlement Agreement with the
CPUC's Office of Ratepayer Advocates (ORA), and other parties, in a proceeding
addressing the Catastrophic Events Memorandum Account. The settlement provides
for a $59 million increase in electric distribution revenue requirement and an
$11 million increase in gas distribution revenue requirement effective
January 1, 2000. The increase compensates the Utility for service restoration
following several events, beginning with the Oakland Hills fire of 1991 and
ending with the storms of February 1998. A CPUC decision is expected in early
2000.
THE CPUC'S GAS STRATEGY INVESTIGATION, PHASE 2:
In January 1998, the CPUC opened a rulemaking proceeding to explore changes
in the natural gas industry in California. In July 1999, the CPUC issued a
decision identifying promising options for restructuring the natural gas
industry. In the decision, the CPUC reaffirmed the basic structure of the Gas
Accord. The CPUC further stated that it seeks to explore a market structure that
maintains the utilities' traditional role of providing fully integrated default
service while removing obstacles to competitive unbundled services. The CPUC
opened a new investigative proceeding to explore in more detail the anticipated
costs and benefits associated with the different market structure options it has
identified. On January 28, 2000, PG&E Corporation and a broad-based coalition of
shippers, consumer groups, marketers, and others filed a settlement with the
CPUC which would reaffirm the basic structure of the Gas Accord and continue the
Gas Accord through its original term of December 31, 2002.
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ELECTRIC BASE REVENUE INCREASE PROCEEDING:
Section 368(e) of the California Public Utilities Code was adopted as part
of the California electric industry restructuring legislation. It provided for
an increase in the Utility's electric base revenues for 1997 and 1998, for
enhancement of transmission and distribution system safety and reliability. In
accordance with Section 368(e), the CPUC authorized a 1997 base revenue increase
of $164 million. For 1998, the CPUC authorized an additional base revenue
increase of $77 million. Section 368(e) expenditures are subject to review by
the CPUC.
In July 1999, the ORA filed reports on the Utility's Section 368(e)
expenditures recommending a disallowance of $88.4 million in expenditures for
1997 and 1998. In August 1999, The Utility Reform Network (TURN) recommended an
additional $14 million disallowance for a total recommended disallowance for
1997 and 1998 expenditures of $102.4 million. The Utility opposed the
recommended disallowances and hearings were held in October 1999. A proposed
decision is not expected until the first quarter of 2000. Any proposed decision
would be subject to comment by the parties and change by the CPUC before a final
decision is issued. The Utility does not expect a material impact on its
financial position or results of operations resulting from these matters.
RESULTS OF OPERATIONS
In this section, we present the components of our results of operations for
1999, 1998, and 1997. The Utility received a final decision on its 1999 GRC
application on February 17, 2000. As discussed further in "Regulatory Matters"
above, the final decision did not increase electric revenues, although it
increased the deferral of electric transition costs by $163 million over the
amount that would have been deferred under the 1998 revenue requirement. This
revenue increase was retroactive to January 1, 1999. The impact of the 1999 GRC
resulted in an increase in earnings of $153 million, or $0.42 per share, and was
reflected in the fourth quarter of 1999.
The table below shows for 1999, 1998, and 1997, certain items from our
Statement of Consolidated Income detailed by Utility and National Energy Group
operations of PG&E Corporation. (In the "Total" column, the table shows the
combined results of operations for these groups.) The information for PG&E
Corporation (the "Total" column) excludes 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 1999
and 1998.
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UTILITY NATIONAL ENERGY GROUP
-------- ----------------------------------------------------------
PG&E GT ELIMINATIONS &
(IN MILLIONS) PG&E GEN NW TEXAS PG&E ET OTHER(1) TOTAL
1999
Operating revenues $9,228 $1,122 $224 $ 1,148 $10,521 $(1,423) $20,820
Operating expenses 7,235 1,007 104 2,446 10,582 (1,432) 19,942
Operating income 878
Other income, net 155
Interest expense, net (772)
Income taxes 248
Income from continuing operations 13
Net loss $ (73)
EBITDA(2) $3,523 $ 203 $181 $(1,178) $ (53) $ 19 $ 2,695
1998
Operating revenues $8,924 $ 649 $237 $ 1,941 $ 8,509 $ (683) $19,577
Operating expenses 7,048 489 101 1,996 8,528 (683) 17,479
Operating income 2,098
Other income, net 65
Interest expense, net (781)
Income taxes 611
Income from continuing operations 771
Net income $ 719
EBITDA(2) $3,294 $ 200 $177 $ 15 $ (15) $ (7) $ 3,664
1997
Operating revenues $9,495 $ 148 $233 $ 1,004 $ 4,808 $ (433) $15,255
Operating expenses 7,675 176 127 1,023 4,840 (348) 13,493
Operating income 1,762
Other income, net 212
Interest expense, net (664)
Income taxes 565
Income from continuing operations 745
Net income $ 716
EBITDA(2) $3,606 $ (40) $144 $ 16 $ (29) $ 57 $ 3,754
(1) Net income on intercompany positions recognized by segments using
mark-to-market accounting is eliminated. Intercompany transactions are also
eliminated.
(2) EBITDA measures earnings (after preferred dividends) before interest expense
(net of interest income), income taxes, depreciation, and amortization.
OVERALL RESULTS
PG&E Corporation had a net loss in 1999 of $73 million, or $0.20 per share.
In 1998 PG&E Corporation had net income of $719 million, or $1.88 per share. The
decrease is principally due to the write-down to fair value of our natural gas
business in Texas and the accrual for the discontinuance of operations of our
Energy Services segment. The PG&E GTT write-down was approximately $890 million
after taxes, and the PG&E ES discontinued operations generated a charge of
$58 million after tax. Partially offsetting these charges were increases in
Utility income, primarily as a result of the 1999 GRC, and an adjustment of a
litigation reserve associated with a court-approved settlement proposal. In
addition, PG&E Gen changed its method of accounting for major maintenance and
overhauls at its generating facilities. Effective January 1, 1999, PG&E Gen
adopted a method that accounts for expenditures associated with major
maintenance and overhauls as incurred. Previously, PG&E Gen estimated the cost
of major maintenance and overhauls and accrued such costs in advance in a
systematic and rational manner over the period between major maintenance and
overhauls. The cumulative effect of the accounting change resulted in
recognition of approximately $12 million of income, net of tax.
The Utility's net income available for common stock increased to $763
million in 1999 as compared to 1998 net income of $702 million, primarily
because of the impacts of the 1999 GRC. However, the increases from the
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GRC were partially offset by a reduction in the Utility's authorized cost of
capital and a lower return on its assets due to the sale of a significant
portion of its generating assets and recovery of transition costs (see Note 2 of
the Notes to Consolidated Financial Statements).
Net income for the Utility decreased $33 million in 1998 as compared to 1997
due to the reduced rate of return on generation assets and increased interest
expense associated with the rate reduction bonds.
OPERATING INCOME
Operating income for PG&E Corporation in 1999 was $878 million, which
includes the charge to write down the investment in PG&E GTT to its net
realizable value. Operating income for the Utility was $1,993 million in 1999 as
compared to $1,876 million in 1998. This increase is primarily because of the
impacts of the 1999 GRC. However, the increases from the GRC were partially
offset by a reduction in the Utility's authorized cost of capital and a lower
return on its assets due to the sale of a significant portion of its generating
assets and recovery of transition costs (see Note 2 of the Notes to Consolidated
Financial Statements).
Operating income of the National Energy Group decreased $62 million in 1999
as compared to 1998, excluding the charge to write PG&E GTT down to its net
realizable value. The decline resulted from mild weather in the Northeast, lower
interruptible sales in the Pacific Northwest, less portfolio management
activity, and trading losses in the U.S. gas portfolio. This decline was
partially offset by cost containment efforts across the organization and an
increase in the differential between natural gas liquids prices and the cost of
natural gas.
The operating income increase in 1998 as compared to 1997 was primarily due
to the growth of the National Energy Group, which contributed $195 million of
the increase. The 1998 income from continuing operations also includes a loss on
the sale of our Australian energy holdings.
OPERATING REVENUES
UTILITY:
Utility operating revenues increased $304 million in 1999 as compared to
1998. This increase is primarily due to: (1) a $147 million increase in gas
revenues from residential and commercial gas customers due to higher usage, (2)
a $93 million increase in gas revenues as a result of the GRC, (3) a $43 million
increase in revenues from small and medium electric customers due to increased
customers, and (4) a $16 million increase in revenues from an increase in gas
transportation volumes.
Utility operating revenues decreased $571 million in 1998 as compared to
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 1998, 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 TCBA, which affects
expenses, rather than revenues.
NATIONAL ENERGY GROUP:
The National Energy Group's 1999 operating revenues increased $939 million
as compared to 1998 operating revenues, principally due to: (1) the PG&E Gen
business segment receiving a full year of revenue from the New England assets
acquired in September 1998, and (2) increases in trading revenues at PG&E ET
reflecting the further maturation of its business. The 1999 operating revenues
also reflect revenue increases resulting from an improved differential between
the natural gas liquids prices and the incoming natural gas. These revenue
increases were partially offset by (1) a decline in interruptible revenues in
the Northwest due to the lower natural gas prices in the Southwest as compared
to Canadian prices, and (2) lower transportation revenue on the Texas
transmission system. In addition, effective July 1999, certain gas trading
activities conducted by PG&E GTT were transferred to PG&E ET, thus contributing
to the decline in PG&E GTT revenues.
Operating revenues associated with the National Energy Group increased
$4,893 million in 1998 as compared to 1997. This was primarily due to revenue
increases from energy trading volumes, 12 months of revenue from the
19
Texas acquisitions versus seven months in 1997, portfolio management activity by
PG&E Gen, and the acquisition of the New England generating assets in
September 1998.
OPERATING EXPENSES
UTILITY:
The Utility's operating expenses increased $187 million in 1999 as compared
to 1998. This increase reflects the increased cost of gas due to higher usage
and the increased amortization of electric transition costs.
Utility operating expenses in 1998 decreased $627 million as compared to
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.
NATIONAL ENERGY GROUP:
The National Energy Group's operating expenses increased $2,276 million in
1999 as compared to 1998, due to the charge associated with the disposition of
PG&E GTT, having a full year of operating expenses associated with the
generation facilities in New England, and growth of PG&E ET operations.
Operating expenses for the National Energy Group increased $4,613 million in
1998 as compared to 1997. This increase reflects the increase in the volumes of
energy commodities purchased, operating costs associated with the New England
assets acquired in September 1998 and the gas transportation assets acquired in
1997.
INCOME TAXES
PG&E Corporation has recorded income tax expense of $248 million for 1999.
The effective tax rate primarily results from two factors: (1) electric industry
restructuring has resulted in the reversal of temporary differences whose tax
benefits were originally flowed through to customers causing an increase in
income tax expense independent of pre-tax income, and (2) the disposition of
PG&E GTT resulted in a capital loss for tax purposes, which could not be fully
recognized.
Income taxes in 1998 increased $46 million as compared to 1997. The overall
effective tax rate increased 1.1 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.
DIVIDENDS
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. During 1999, the Utility has been in compliance with its
CPUC-authorized capital structure. PG&E Corporation and the Utility believe that
this requirement will not affect PG&E Corporation's ability to pay common stock
dividends. However, depending on the timing and outcome of the valuation of the
Utility's hydroelectric facilities discussed in "Generation Divestiture" above,
certain valuation methods could necessitate a waiver of the CPUC's authorized
capital structure in order to permit PG&E Corporation or the Utility to continue
paying common stock dividends at the current level.
20
LIQUIDITY AND FINANCIAL RESOURCES
CASH FLOWS FROM OPERATING ACTIVITIES
Net cash provided by PG&E Corporation's operating activities totaled
$2,287 million, $2,283 million, and $2,618 million in 1999, 1998, and 1997,
respectively. Net cash provided by the Utility's operating activities totaled
$2,200 million, $2,610 million, and $1,768 million in 1999, 1998, and 1997,
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 1999, 1998, and 1997, we issued $54 million, $63 million, and
$54 million of common stock, respectively, primarily through the Dividend
Reinvestment Plan and the stock option plan component of the Long-Term Incentive
Program. During 1997, we also issued $1.1 billion of common stock to acquire the
natural gas assets in Texas. During 1999, 1998, and 1997, we declared dividends
on our common stock of $460 million, $466 million, and $485 million,
respectively.
During 1999, 1998, and 1997, we repurchased $693 million, $1,158 million,
and $804 million of our common stock, respectively. The repurchases made in 1998
and through September 1999 were executed through separate, accelerated share
repurchase programs. 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, we repurchased in a specific transaction
37 million shares of common stock. As of December 31, 1998, approximately
$570 million remained available under this repurchase authorization. In
February 1999, we used this remaining authorization to purchase 16.6 million
shares at a cost of $502 million. In connection with this transaction, we
entered into a forward contract with an investment institution. We settled the
forward contract and its additional obligation of $29 million in
September 1999. We used a subsidiary of PG&E Corporation to make this
repurchase, along with subsequent stock repurchases. The stock held by the
subsidiary is treated as treasury stock and reflected as Stock Held by
Subsidiary on the Consolidated Balance Sheet of PG&E Corporation.
In October 1999, the Board of Directors of PG&E Corporation authorized an
additional $500 million for the purpose of repurchasing shares of the
Corporation's common stock on the open market. This authorization supplements
the approximately $40 million remaining from the amount previously authorized by
the Board of Directors on December 17, 1997. The authorization for share
repurchase extends through September 30, 2001. As of December 31, 1999, through
our wholly owned subsidiary, we repurchased 7.2 million shares, at a cost of
$159 million under this authorization. Any open market purchases will be made by
the wholly owned subsidiary of PG&E Corporation.
During 1999, our National Energy Group retired $128 million of long-term
debt. This amount includes PG&E GTT's June 1999 redemption of the outstanding
balance of $69 million of its senior notes, which resulted in a gain on
redemption of approximately $1.7 million. In 1998, our National Energy Group
retired $75 million of long-term debt and retired the notes used in the
acquisition of our Australian energy holdings. In 1997, our National Energy
Group issued $30 million and retired $109 million of long-term debt. Also in
1997, we assumed $780 million of long-term debt in connection with the
acquisition of our natural gas assets in Texas.
We maintain a number of credit facilities to support commercial paper
programs, letters of credit, and other short-term liquidity requirements. PG&E
Corporation maintains two $500 million revolving credit facilities, one of which
expires in November 2000 and the other in 2002. These credit facilities are used
to support the commercial paper program and other liquidity needs. The facility
expiring in 2000 may be extended annually for additional one-year periods upon
agreement with the lending institutions. There was $450 million of commercial
paper outstanding at December 31, 1999. PG&E Corporation introduced a
$200 million Extendible Commercial Note (ECN) program during the third quarter
of 1999. The ECN program supplements our short-term borrowing capability. There
was $76 million of extendible commercial notes outstanding at December 31, 1999,
which are not supported by the credit facilities.
21
PG&E Gen maintains two $550 million revolving credit facilities. One
facility expires in August 2000 and the other expires in 2003. The total amount
outstanding at December 31, 1999, backed by the facilities, was $898 million in
commercial paper. Of these loans, $550 million is classified as noncurrent in
the Consolidated Balance Sheet of PG&E Corporation.
In 1998, USGenNE, a subsidiary of PG&E Gen, established a $100 million
revolving credit facility that expires in 2003. As of December 31, 1999, there
is no outstanding balance on this facility.
PG&E GT NW maintains a $100 million revolving credit facility that expires
in 2002, but has an annual renewal option allowing the facility to maintain a
three-year duration. PG&E GT NW also maintains a $50 million 364-day credit
facility that expires in 2000, but can be extended for successive 364-day
periods. At December 31, 1999, PG&E GT NW had an outstanding commercial paper
balance of $99 million, which is classified as noncurrent in the Consolidated
Balance Sheet of PG&E Corporation.
PG&E GTT maintains four separate credit facilities that total $250 million
and are guaranteed by PG&E Corporation. At December 31, 1999, PG&E GTT had
$176 million of outstanding short-term bank borrowings related to these credit
facilities. These lines may be cancelled upon demand and bear interest at each
respective bank's quoted money market rate. The borrowings are unsecured and
unrestricted as to use.
UTILITY:
In December 1999, 7.6 million shares of the Utility's common stock, with an
aggregate purchase price of $200 million, was purchased by a subsidiary of the
Utility. This purchase is reflected as stock held by subsidiary in the
Consolidated Balance Sheet of Pacific Gas and Electric Company. Earlier in 1999,
the Utility repurchased and cancelled 20 million shares of its common stock from
PG&E Corporation for an aggregate purchase price of $726 million to maintain its
authorized capital structure. In 1999, 1998, and 1997, the Utility declared
dividends on its common stock of $415 million, $300 million, and $699 million,
respectively.
The Utility's long-term debt that either matured, was redeemed, or was
repurchased during 1999 totaled $654 million. Of this amount, (1) $290 million
related to the Utility's rate reduction bonds maturing, (2) $135 million related
to the Utility's repurchase of mortgage and various other bonds,
(3) $147 million related to maturity of various utility mortgage bonds, and
(4) $82 million related to the maturities and redemption of various of the
Utility's medium-term notes and other debt.
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, the Utility redeemed or repurchased $225 million of long-term debt
to manage the overall balance of its capital structure. Also 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.
During 1999 and 1997, the Utility did not redeem or repurchase any of its
preferred stock. 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.
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.)
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. The total
amount outstanding at December 31, 1999, backed by this facility, was
$449 million in commercial paper. There were no bank notes outstanding at
December 31, 1999.
22
CASH FLOWS FROM INVESTING ACTIVITIES
UTILITY:
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 2000 is approximately $1.3
billion, excluding capital expenditures for divested fossil and geothermal power
plants. The Utility's capital expenditures were $1,181 million, $1,382 million,
and $1,522 million for the years ended December 31, 1999, 1998, and 1997,
respectively.
During 1999, the Utility sold three fossil-fueled generation facilities and
its geothermal generation facilities. These sales closed in April and May 1999,
respectively, and generated proceeds of $1,014 million. In 1998, the Utility had
proceeds of $501 million from the sale of three fossil-fueled generation plants.
NATIONAL ENERGY GROUP:
PG&E Gen is associated with the construction of two natural gas-fueled
combined-cycle power plants, and plans to begin construction on a third plant in
early 2000. These power plants, referred to as "merchant power plants," will
sell power as a commodity in the competitive marketplace. The electricity
generated by these plants will be sold on a wholesale basis to local utilities
and power marketers, including PG&E ET, which, in turn, will sell it to
industrial, commercial, and other electricity customers.
Millennium Power, a 360-MW power plant located in Massachusetts, is
scheduled to begin commercial service in the fourth quarter of 2000. Lake Road
Generating Plant (Lake Road), an approximately 790-MW power plant located in
Connecticut, is scheduled to begin commercial service in 2001. Lake Road is
being financed through a synthetic lease with a third party owner. PG&E Gen will
operate the plant under an operating lease (See Note 14 of Notes to Consolidated
Financial Statements). La Paloma Generating Plant, an approximately 1,050-MW
power plant, is located in California, and is scheduled to begin commercial
service in 2002. The estimated cost to construct these plants is approximately
$1.4 billion.
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.
DEBT OBLIGATIONS AND RATE REDUCTION BONDS
The table below provides information about our debt obligations and rate
reduction bonds at December 31, 1999:
THERE-
EXPECTED MATURITY DATE 2000 2001 2002 2003 2004 AFTER
(dollars in millions)
Utility:
Long-term debt
Variable rate obligations........ $200 $100 $738 $310 $ -- $ --
Fixed rate obligations........... $265 $274 $379 $354 $392 $2,330
Average interest rate............ 6.6% 8.0% 7.8% 6.3% 6.4% 7.1%
Rate reduction bonds............... $290 $290 $290 $290 $290 $ 871
Average interest rate............ 6.2% 6.2% 6.3% 6.4% 6.4% 6.5%
National Energy Group:
Long-term debt
Variable rate obligations........ $ 44 $ 11 $109 $560 $ 9 $ 87
Fixed rate obligations........... $ 83 $ 95 $137 $ 47 $ 69 $ 672
Average interest rate............ 8.5% 9.1% 8.6% 9.8% 9.8% 8.2%
FAIR
VALUE AT
DEC. 31,
EXPECTED MATURITY DATE TOTAL 1999
(dollars in millions)
Utility:
Long-term debt
Variable rate obligations........ $1,348 $1,348
Fixed rate obligations........... $3,994 $3,869
Average interest rate............ 7.1%
Rate reduction bonds............... $2,321 $2,265
Average interest rate............ 6.3%
National Energy Group:
Long-term debt
Variable rate obligations........ $ 820 $ 820
Fixed rate obligations........... $1,103 $1,058
Average interest rate............ 8.5%
23
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, 1999, the Utility has accrued $271 million ($300 million on
an undiscounted basis) for clean-up costs at identified sites. If other
responsible parties fail to pay or expected outcomes change, then these costs
may be as much as $486 million. Of the $271 million, the Utility has recovered
$148 million through rates, including $34 million through depreciation and
expects to recover another $95 million in future rates. Additionally, the
Utility mitigates its cost by seeking recovery from insurance carriers and other
third parties. (See Note 15 of Notes to Consolidated Financial Statements.)
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 estimates the upper limit of the range 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 clean-up costs at additional sites or expected outcomes change.
In December 1999, the Utility was notified by the purchaser of its former
Moss Landing power plant that it had identified a cleaning procedure used at the
plant that released heated water from the intake, and that this procedure is not
specified in the plant's National Pollutant Discharge Elimination System (NPDES)
permit issued by the Central Coast Regional Water Quality Control Board (Central
Coast Board). The purchaser notified the Central Coast Board of its findings and
the Central Coast Board requested additional information from the purchaser. The
Utility has initiated an investigation of these activities during the time it
owned the plant. The Central Coast Board has been notified of the investigation
and the results will be presented to the Central Coast Board when the
investigation is complete. If the identified procedure was performed during the
Utility's ownership and was beyond the scope of the relevant NPDES permits, the
Central Coast Board may choose to initiate an enforcement action. If so, the
Utility could be subject to significant penalties. Until the investigation is
complete and the results discussed with the Central Coast Board, it is not
possible to determine whether the Utility will suffer a loss in connection with
this matter or to provide a more detailed estimate of such liability.
YEAR 2000 (Y2K)
PG&E Corporation successfully transitioned into the Year 2000 without any
Y2K-related service disruptions. There is, however, a risk that some
computer-related problems might not manifest themselves for a period of time and
that supplier or business partner Y2K problems may materialize and have an
adverse impact on our operations.
As of December 31, 1999, expenditures to address potential Y2K problems
totaled $185 million, of which $93 million is attributed to the Utility.
Included are systems replaced or enhanced for general business purposes and for
which implementation schedules were critical to our Y2K readiness.
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 current levels 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 risk management policy that 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
24
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
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.
We prepare a daily assessment of our 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.
We utilize historical data for calculating the price volatility of our
positions and how likely the prices of those positions will move together. The
model includes all derivative and commodity investments in our non-hedging
portfolio and only derivative commodity investments for our hedging portfolio
(but not the related underlying hedged position). We express value-at-risk as a
dollar amount of the potential loss in the fair value of our portfolio based on
a 95 percent confidence level using a one-day liquidation period. Therefore,
there is a 5 percent probability that our portfolio will incur a loss in one day
greater than our 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.
Our daily value-at-risk for commodity price-sensitive derivative instruments as
of December 31, 1999 and 1998, for non-hedging activities was $4.4 million and
$6.2 million, respectively. Our daily value-at-risk for commodity
price-sensitive derivative instruments as of December 31, 1999 and 1998, for
hedging activities was $30,000 and $210,000, respectively. For the year ended
December 31, 1999, the average, high, and low value-at-risk amounts for
non-hedging activities were $4.3 million, $6.2 million, and $1.3 million,
respectively. The average, high, and low value-at-risk amounts over the same
reporting period for hedging activities were $0.6 million, $1.7 million, and
$0.0 million, respectively. The average, high and low amounts for the reporting
period were computed using the value-at-risk amounts at the beginning of the
reporting period and the four quarter-end amounts.
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 intra-day trading activities.
In June 1999, the Financial Accounting Standards Board (FASB) issued
Statement of Financial Accounting Standards (SFAS) No. 137, "Accounting for
Derivative Instruments and Hedging Activities-Deferral of the Effective Date of
FASB Statement No. 133," which delayed the implementation of SFAS No. 133,
"Accounting for Derivative Instruments and Hedging Activities," by one year to
require adoption in years beginning after June 15, 2000. The Statement permits
early adoption as of the beginning of any fiscal quarter.
PG&E Corporation expects to adopt SFAS No. 133 no later than January 1,
2001. The Statement will require us 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. We currently are evaluating what the
effect of SFAS No. 133 will be on the earnings and financial position of PG&E
Corporation. However, we already use the mark-to-market method of accounting for
our commodity non-hedging and price risk management activities.
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.)
25
- --------------------------------------------------------------------------------
PG&E Corporation
STATEMENT OF CONSOLIDATED INCOME
(IN MILLIONS, EXCEPT PER SHARE AMOUNTS)
YEAR ENDED DECEMBER 31,
------------------------------
1999 1998 1997
OPERATING REVENUES
Utility $ 9,228 $ 8,924 $ 9,495
Energy commodities and services 11,592 10,653 5,760
------- ------- -------
TOTAL OPERATING REVENUES 20,820 19,577 15,255
------- ------- -------
OPERATING EXPENSES
Cost of energy for utility 3,149 2,942 3,208
Cost of energy commodities and services 10,587 9,852 5,368
Operating and maintenance, net 3,151 3,083 3,066
Depreciation, amortization, and decommissioning 1,780 1,602 1,851
Loss on assets held for sale 1,275 -- --
------- ------- -------
TOTAL OPERATING EXPENSES 19,942 17,479 13,493
------- ------- -------
OPERATING INCOME 878 2,098 1,762
Interest expense, net (772) (781) (664)
Other income, net 155 65 212
------- ------- -------
INCOME BEFORE INCOME TAXES 261 1,382 1,310
Income taxes 248 611 565
------- ------- -------
INCOME FROM CONTINUING OPERATIONS 13 771 745
DISCONTINUED OPERATIONS (NOTE 5)
Loss from operations of PG&E Energy Services (net of
applicable income taxes of $35 million, $41 million, and
$17 million, respectively) (40) (52) (29)
Loss on disposal of PG&E Energy Services (net of
applicable income taxes of $36 million) (58) -- --
------- ------- -------
NET INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF A CHANGE IN
ACCOUNTING PRINCIPLE (NOTE 1) (85) 719 716
CUMULATIVE EFFECT OF A CHANGE IN AN ACCOUNTING PRINCIPLE
(NET OF APPLICABLE INCOME TAXES OF $8 MILLION) 12 -- --
------- ------- -------
NET INCOME (LOSS) $ (73) $ 719 $ 716
======= ======= =======
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING 368 382 410
EARNINGS (LOSS) PER COMMON SHARE, BASIC AND DILUTED
INCOME FROM CONTINUING OPERATIONS $ 0.04 $ 2.02 $ 1.82
DISCONTINUED OPERATIONS (0.27) (0.14) (0.07)
CUMULATIVE EFFECT OF A CHANGE IN AN ACCOUNTING PRINCIPLE 0.03 -- --
------- ------- -------
NET INCOME (LOSS) $ (0.20) $ 1.88 $ 1.75
DIVIDENDS DECLARED PER COMMON SHARE $ 1.20 $ 1.20 $ 1.20
The accompanying Notes to the Consolidated Financial Statements are an integral
part of this statement.
26
- --------------------------------------------------------------------------------
PG&E Corporation
CONSOLIDATED BALANCE SHEET
(IN MILLIONS, EXCEPT SHARE AMOUNTS)
BALANCE AT
DECEMBER 31,
-------------------
1999 1998
ASSETS
CURRENT ASSETS
Cash and cash equivalents $ 281 $ 286
Short-term investments 187 55
Accounts receivable
Customers, net 1,486 1,856
Energy marketing 532 507
Price risk management 607 1,416
Inventories and prepayments 598 671
Deferred income taxes 133 --
-------- --------
TOTAL CURRENT ASSETS 3,824 4,791
PROPERTY, PLANT, AND EQUIPMENT
Utility 23,001 24,160
Non-utility
Electric generation 1,905 1,967
Gas transmission 2,541 3,347
Construction work in progress 436 407
Other 184 127
-------- --------
TOTAL PROPERTY, PLANT, AND EQUIPMENT (AT ORIGINAL COST) 28,067 30,008
Accumulated depreciation and decommissioning (11,291) (12,026)
-------- --------
NET PROPERTY, PLANT, AND EQUIPMENT 16,776 17,982
OTHER NONCURRENT ASSETS
Regulatory assets 4,957 6,347
Nuclear decommissioning funds 1,264 1,172
Other 2,894 2,942
-------- --------
TOTAL NONCURRENT ASSETS 9,115 10,461
-------- --------
TOTAL ASSETS $ 29,715 $ 33,234
======== ========
27
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PG&E Corporation
CONSOLIDATED BALANCE SHEET (CONTINUED)
(IN MILLIONS, EXCEPT SHARE AMOUNTS)
BALANCE AT
DECEMBER 31,
-------------------
1999 1998
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Short-term borrowings $ 1,499 $ 1,644
Current portion of long-term debt 592 338
Current portion of rate reduction bonds 290 290
Accounts payable
Trade creditors 708 1,001
Other 559 443
Regulatory balancing accounts 384 79
Energy marketing 480 381
Accrued taxes 211 103
Price risk management 575 1,412
Other 1,033 1,064
------- -------
TOTAL CURRENT LIABILITIES 6,331 6,755
NONCURRENT LIABILITIES
Long-term debt 6,673 7,422
Rate reduction bonds 2,031 2,321
Deferred income taxes 3,147 3,861
Deferred tax credits 231 283
Other 3,636 3,746
------- -------
TOTAL NONCURRENT LIABILITIES 15,718 17,633
PREFERRED STOCK OF SUBSIDIARIES 480 480
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, 384,406,113 and 382,603,564 shares, respectively 5,906 5,862
Common stock held by subsidiary, at cost, 23,815,500
shares (690) --
Reinvested earnings 1,670 2,204
------- -------
TOTAL COMMON STOCKHOLDERS' EQUITY 6,886 8,066
------- -------
Commitments and Contingencies (Notes 1, 2, 3, 4, 5, 14, and
15) -- --
------- -------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $29,715 $33,234
======= =======
The accompanying Notes to the Consolidated Financial Statements are an integral
part of this statement.
28
- --------------------------------------------------------------------------------
PG&E Corporation
STATEMENT OF CONSOLIDATED CASH FLOWS
(IN MILLIONS)
FOR THE YEAR ENDED
DECEMBER 31,
------------------------------
1999 1998 1997
-------- -------- --------
CASH FLOWS FROM OPERATING ACTIVITIES
Net (loss) income $ (73) $ 719 $ 716
Adjustments to reconcile net (loss) income to net cash
provided by operating activities:
Depreciation, amortization, and decommissioning 1,780 1,602 1,851
Deferred income taxes and tax credits--net (754) (107) (160)
Other deferred charges and noncurrent liabilities 102 18 121
Loss (gain) on sale of assets -- 23 (120)
Loss on assets held for sale 1,275 -- --
Loss from discontinued operations 98 52 29
Cumulative effect of change in accounting principle (12) -- --
Net effect of changes in operating assets and liabilities:
Accounts receivable--trade 370 (342) (242)
Inventories and prepayments 73 (179) (4)
Price risk management assets and liabilities, net (28) (16) 12
Accounts payable--trade (293) 247 210
Regulatory balancing accounts payable 305 537 126
Accrued taxes 108 (123) (54)
Other working capital 159 199 (85)
Other--net (824) (347) 218
Cash provided in discontinued operations 1 -- --
------- ------- -------
NET CASH PROVIDED BY OPERATING ACTIVITIES 2,287 2,283 2,618
------- ------- -------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (1,584) (1,619) (1,822)
Acquisitions and investments in unregulated projects -- (1,779) (116)
Proceeds from sale of assets 1,014 1,106 146
Other--net 453 66 21
------- ------- -------
NET CASH USED BY INVESTING ACTIVITIES (117) (2,226) (1,771)
------- ------- -------
CASH FLOWS FROM FINANCING ACTIVITIES
Net borrowings (repayments) under credit facilities (145) 2,115 (587)
Long-term debt issued -- -- 386
Long-term debt matured, redeemed, or repurchased (798) (1,552) (961)
Proceeds from issuance of rate reduction bonds -- -- 2,881
Preferred stock redeemed or repurchased -- (108) --
Common stock issued 54 63 54
Common stock repurchased (693) (1,158) (804)
Dividends paid (465) (470) (524)
Other--net 4 (3) (39)
------- ------- -------
NET CASH PROVIDED (USED) BY FINANCING ACTIVITIES (2,043) (1,113) 406
------- ------- -------
NET CHANGE IN CASH AND CASH EQUIVALENTS 127 (1,056) 1,253
CASH AND CASH EQUIVALENTS AT JANUARY 1 341 1,397 144
------- ------- -------
CASH AND CASH EQUIVALENTS AT DECEMBER 31 $ 468 $ 341 $ 1,397
======= ======= =======
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
Cash paid for:
Interest (net of amounts capitalized) $ 727 $ 774 $ 624
Income taxes (net of refunds) 723 770 801
The accompanying Notes to the Consolidated Financial Statements are an integral
part of this statement.
29
- --------------------------------------------------------------------------------
PG&E Corporation
STATEMENT OF CONSOLIDATED COMMON STOCK EQUITY
(IN MILLIONS, EXCEPT SHARE AMOUNTS)
COMMON TOTAL
ADDITIONAL STOCK COMMON
COMMON PAID-IN HELD BY REINVESTED STOCK
STOCK CAPITAL SUBSIDIARY EARNINGS EQUITY
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 on 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 on common stock (466) (466)
Other (2) 13 11
BALANCE DECEMBER 31, 1998 5,862 -- -- 2,204 8,066
Net loss (73) (73)
Common stock issued (1,879,474 shares) 54 54
Common stock repurchased (23,892,425 shares) (2) (690) (1) (693)
Cash dividends declared on common stock (460) (460)
Other (8) (8)
BALANCE DECEMBER 31, 1999 $5,906 $ -- $(690) $1,670 $ 6,886
====== ======= ===== ====== =======
The accompanying Notes to the Consolidated Financial Statements are an integral
part of this statement.
30
- --------------------------------------------------------------------------------
Pacific Gas and Electric Company
STATEMENT OF CONSOLIDATED INCOME
(IN MILLIONS)
YEAR ENDED DECEMBER 31,
------------------------------
1999 1998 1997
OPERATING REVENUES
Electric $7,232 $7,191 $7,691
Gas 1,996 1,733 1,804
------ ------ ------
TOTAL OPERATING REVENUES 9,228 8,924 9,495
------ ------ ------
OPERATING EXPENSES
Cost of electric energy 2,411 2,321 2,501
Cost of gas 738 621 707
Operating and maintenance, net 2,522 2,668 2,719
Depreciation, amortization, and decommissioning 1,564 1,438 1,748
------ ------ ------
TOTAL OPERATING EXPENSES 7,235 7,048 7,675
------ ------ ------
OPERATING INCOME 1,993 1,876 1,820
Interest expense, net (593) (621) (570)
Other income, net 36 103 127
------ ------ ------
INCOME BEFORE INCOME TAXES 1,436 1,358 1,377
Income taxes 648 629 609
------ ------ ------
NET INCOME 788 729 768
Preferred dividend requirement 25 27 33
------ ------ ------
INCOME AVAILABLE FOR COMMON STOCK $ 763 $ 702 $ 735
====== ====== ======
The accompanying Notes to the Consolidated Financial Statements are an integral
part of this statement.
31
- --------------------------------------------------------------------------------
Pacific Gas and Electric Company
CONSOLIDATED BALANCE SHEET
(IN MILLIONS, EXCEPT SHARE AMOUNTS)
BALANCE AT
DECEMBER 31,
-------------------
1999 1998
ASSETS
CURRENT ASSETS
Cash and cash equivalents $ 80 $ 73
Short-term investments 21 17
Accounts receivable
Customers, net 1,201 1,383
Related parties 9 14
Inventories
Fuel oil 2 23
Gas stored underground 137 130
Materials and supplies 155 159
Prepayments 34 50
Deferred income taxes 119 --
-------- --------
TOTAL CURRENT ASSETS 1,758 1,849
PROPERTY, PLANT, AND EQUIPMENT
Electric 15,762 17,088
Gas 7,239 7,072
Construction work in progress 214 273
-------- --------
TOTAL PROPERTY, PLANT, AND EQUIPMENT (AT ORIGINAL COST) 23,215 24,433
Accumulated depreciation and decommissioning (10,497) (11,397)
-------- --------
NET PROPERTY, PLANT, AND EQUIPMENT 12,718 13,036
OTHER NONCURRENT ASSETS
Regulatory assets 4,895 6,288
Nuclear decommissioning funds 1,264 1,172
Other 835 605
-------- --------
TOTAL NONCURRENT ASSETS 6,994 8,065
-------- --------
TOTAL ASSETS $ 21,470 $ 22,950
======== ========
32
- --------------------------------------------------------------------------------
Pacific Gas and Electric Company
CONSOLIDATED BALANCE SHEET (CONTINUED)
(IN MILLIONS, EXCEPT SHARE AMOUNTS)
BALANCE AT
DECEMBER 31,
-------------------
1999 1998
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Short-term borrowings $ 449 $ 668
Current portion of long-term debt 465 260
Current portion of rate reduction bonds 290 290
Accounts payable
Trade creditors 577 718
Related parties 216 60
Regulatory balancing accounts 384 79
Other 333 374
Accrued taxes 118 2
Other 529 561
------- -------
TOTAL CURRENT LIABILITIES 3,361 3,012
NONCURRENT LIABILITIES
Long-term debt 4,877 5,444
Rate reduction bonds 2,031 2,321
Deferred income taxes 2,510 3,060
Deferred tax credits 231 283
Other 2,252 2,045
------- -------
TOTAL NONCURRENT LIABILITIES 11,901 13,153
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 149 149
Common stock, $5 par value, authorized 800,000,000 shares,
issued 321,314,760 and 341,353,455 shares, respectively 1,606 1,707
Common stock held by subsidiary, at cost, 7,627,765 shares (200) --
Additional paid in capital 1,964 2,087
Reinvested earnings 2,107 2,260
------- -------
TOTAL STOCKHOLDERS' EQUITY 5,771 6,348
Commitments and Contingencies (Notes 2, 6, 14, and 15) -- --
------- -------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $21,470 $22,950
======= =======
The accompanying Notes to the Consolidated Financial Statements are an integral
part of this statement.
33
- --------------------------------------------------------------------------------
Pacific Gas and Electric Company
STATEMENT OF CONSOLIDATED CASH FLOWS
(IN MILLIONS)
FOR THE YEAR ENDED
DECEMBER 31,
------------------------------
1999 1998 1997
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 788 $ 729 $ 768
Adjustments to reconcile net income to net cash provided by
operating activities:
Depreciation, amortization, and decommissioning 1,564 1,438 1,748
Deferred income taxes and tax credits--net (485) (257) (182)
Other deferred charges and noncurrent liabilities 101 31 133
Net effect of changes in operating assets and liabilities:
Accounts receivable--trade 187 266 (582)
Inventories and prepayments 34 (21) 12
Accounts payable--trade 15 203 (80)
Regulatory balancing accounts payable 305 537 126
Accrued taxes 116 (227) (62)
Other working capital (73) (50) (128)
Other--net (352) (39) 15
------- ------- -------
NET CASH PROVIDED BY OPERATING ACTIVITIES 2,200 2,610 1,768
------- ------- -------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (1,181) (1,382) (1,522)
Proceeds from sale of assets 1,014 501 --
Other--net 234 40 (117)
------- ------- -------
NET CASH USED BY INVESTING ACTIVITIES 67 (841) (1,639)
------- ------- -------
CASH FLOWS FROM FINANCING ACTIVITIES
Net borrowings (repayments) under credit facilities (219) 668 (681)
Long-term debt issued -- -- 355
Long-term debt matured, redeemed, or repurchased (672) (1,413) (852)
Proceeds from issuance of rate reduction bonds -- -- 2,881
Preferred stock redeemed or repurchased -- (108) --
Common stock repurchased (926) (1,600) --
Dividends paid (440) (444) (739)
Other--net 1 (5) (14)
------- ------- -------
NET CASH PROVIDED (USED) BY FINANCING ACTIVITIES (2,256) (2,902) 950
------- ------- -------
NET CHANGE IN CASH AND CASH EQUIVALENTS 11 (1,133) 1,079
CASH AND CASH EQUIVALENTS AT JANUARY 1 90 1,223 144
------- ------- -------
CASH AND CASH EQUIVALENTS AT DECEMBER 31 $ 101 $ 90 $ 1,223
======= ======= =======
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
Cash paid for:
Interest (net of amounts capitalized) $ 531 $ 600 $ 547
Income taxes (net of refunds) 1,001 1,115 841
The accompanying Notes to the Consolidated Financial Statements are an integral
part of this statement.
34
- --------------------------------------------------------------------------------
Pacific Gas and Electric Company
STATEMENT OF CONSOLIDATED STOCKHOLDERS' EQUITY
(IN MILLIONS, EXCEPT SHARE AMOUNTS)
PREFERRED
STOCK
COMMON TOTAL WITHOUT
ADDITIONAL STOCK COMMON MANDATORY
COMMON PAID-IN HELD BY REINVESTED STOCK REDEMPTION
(IN MILLIONS) STOCK CAPITAL SUBSIDIARY EARNINGS EQUITY PROVISIONS
BALANCE DECEMBER 31, 1996 $2,018 $ 3,710 -- $2,636 $ 8,364 $ 402
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
Net income 729 729
Common stock repurchased
(62,150,837 shares) (311) (481) (808) (1,600)
Preferred stock redeemed
(4,323,948 shares) (7) (3) (10) (98)
Cash dividends declared
Preferred stock (28) (28)
Common stock (300) (300)
Other 11 (1) 10 (10)
BALANCE DECEMBER 31, 1998 $1,707 $ 2,087 -- $2,260 $ 6,054 $ 294
Net income 788 788
Common stock repurchased
(27,666,460 shares) (101) (123) (200) (502) (926)
Cash dividends declared
Preferred stock (25) (25)
Common stock (415) (415)
Other 1 1
BALANCE DECEMBER 31, 1999 $1,606 $ 1,964 $(200) $2,107 $ 5,477 $ 294
====== ======= ===== ====== ======= =====
The accompanying Notes to the Consolidated Financial Statements are an integral
part of this statement.
35
- --------------------------------------------------------------------------------
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 wholly owned and controlled subsidiaries. The Utility's
consolidated financial statements include its accounts as well as those of its
wholly owned and controlled subsidiaries. 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 1999 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 used 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. Its businesses provide energy services throughout North
America. PG&E Corporation's Northern and Central California utility subsidiary,
Pacific Gas and Electric Company, provides natural gas and electric service to
one of every 20 Americans.
PG&E Corporation's National Energy Group provides energy products and
services throughout North America. The National Energy Group businesses develop,
construct, operate, own, and manage independent power generation facilities that
serve wholesale and industrial customers through PG&E Generating Company, LLC
(formerly U.S. Generating Company, LLC) and its affiliates (collectively, PG&E
Gen); own and operate natural gas pipelines, natural gas storage facilities, and
natural gas processing plants, primarily in the Pacific Northwest and in Texas,
through various subsidiaries of PG&E Corporation (collectively, PG&E Gas
Transmission or PG&E GT); purchase and sell energy commodities and provide risk
management services to customers in major North American markets, including the
other National Energy Group non-utility businesses, unaffiliated utilities,
marketers, municipalities, and large end-use customers through PG&E Energy
Trading--Gas Corporation, PG&E Energy Trading--Power, L.P., and their affiliates
(collectively, PG&E Energy Trading or PG&E ET); and provide competitively priced
electricity, natural gas, and related services to industrial, commercial, and
institutional customers through PG&E Energy Services Corporation (PG&E Energy
Services or PG&E ES). In the fourth quarter of 1999, PG&E Corporation's Board of
Directors approved a plan for the divestiture of PG&E Corporation's Texas
natural gas and natural gas liquids business. Also in the fourth quarter of
1999, PG&E Corporation's Board of Directors approved a plan for the divestiture
of PG&E Corporation's retail energy services.
REGULATION AND STATEMENTS OF FINANCIAL ACCOUNTING STANDARDS (SFAS) NO. 71
The Utility is regulated by the CPUC, the FERC, and the Nuclear Regulatory
Commission, among others. The gas transmission business in the Pacific Northwest
is regulated by the FERC. The gas transmission business in Texas is regulated by
the Texas Railroad Commission.
PG&E Corporation and the Utility account for the financial effects of
regulation in accordance with Statement of Financial Accounting Standards (SFAS)
No. 71, "Accounting for the Effects of Certain Types of Regulation." This
statement allows for the deferral as a regulatory asset costs that otherwise
would have been expensed if it is
36
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 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:
BALANCE AT
DECEMBER 31,
-------------------
(IN MILLIONS) 1999 1998
Utility:
Generation-related transition costs(1) $3,996 $5,355
Unamortized loss, net of gain, on reacquired debt 288 289
Regulatory assets for deferred income tax 295 293
Other, net 316 351
------ ------
Total Utility $4,895 $6,288
National Energy Group 62 59
------ ------
Regulatory assets $4,957 $6,347
====== ======
Regulatory liabilities $ 771 $ 526
====== ======
(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 1999,
regulatory assets related to electric industry restructuring decreased by $1,359
million. This decrease reflects the recovery of eligible transition costs of
$806 million through amortization and $553 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 was
discontinued in 1998. These balancing accounts have been replaced with
regulatory adjustment mechanisms that 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
our 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 Corporation'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
37
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 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.
In June 1998, the Financial Accounting Standards Board (FASB) issued
Statement of Financial Accounting Standards (SFAS) No. 137, "Accounting for
Derivative Instruments and Hedging Activities--Deferral of the Effective Date of
FASB Statement No. 133," which delayed the implementation of SFAS No. 133,
"Accounting for Derivative Instruments and Hedging Activities," by one year to
require adoption in years beginning after June 15, 2000. The Statement permits
early adoption as of the beginning of any fiscal quarter.
PG&E Corporation expects to adopt SFAS No. 133 no later than January 1,
2001. 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. We currently are
evaluating what effect of SFAS No. 133 will be on the earnings and financial
position of PG&E Corporation. However, we already use the mark-to-market method
of accounting for our commodity non-hedging and price risk management
activities.
In compliance with regulatory requirements, the Utility manages price risk
independently from the activities in PG&E Corporation's unregulated business.
During 1998, the CPUC authorized Pacific Gas and Electric Company to trade
natural gas-based financial instruments to manage price and revenue risks
associated with its natural gas transmission and storage assets, subject to
certain conditions. Also in 1998, the CPUC authorized the Utility to trade
natural gas-based financial instruments to hedge the gas commodity price swings
in serving core gas customers. In May 1999, the Power Exchange (PX) obtained
FERC approval to operate the "block forward market" which offers parties the
ability to buy and sell contracts to purchase electricity in the future at
prices set in the contracts. The Utility sought and obtained CPUC authority to
participate in the PX block forward market for contracts that call for delivery
of the purchased electricity by October 31, 2000, as well as to recover costs
(such as gains/losses and transaction fees) associated with its participation in
this market.
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. Nuclear fuel inventories are included in property,
plant, and equipment. 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.
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 National Energy Group businesses that apply SFAS No. 71. For the
remainder of our National Energy Group 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
3.60 percent, 3.89 percent, and 3.45 percent for the years ended December 31,
1999, 1998, and 1997, respectively. The Utility's composite depreciation rates
were 3.41 percent, 3.88 percent, and 3.26 percent for the years ended
December 31, 1999, 1998, and 1997, respectively.
38
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, coal, and
fuel oil. Materials and supplies, coal, and gas stored underground are valued at
average cost. Fuel oil is valued by the last-in first-out method.
CASH EQUIVALENTS AND SHORT-TERM INVESTMENTS
Cash equivalents (stated at cost, which approximates market) include working
funds and consist primarily of Eurodollar time deposits, bankers acceptances,
and 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 commodity and
transmission services from PG&E ET and transmission services from PG&E GT NW.
Intercompany transactions are eliminated in consolidation and no profit results
from these transactions. At December 31, 1999, the Utility has a net
intercompany payable to affiliates of $207 million, of which $163 million
relates to short-term borrowings, including interest. For the years ended
December 31, 1999 and 1998, the Utility's significant related party transactions
are provided in the table below.
(IN MILLIONS) 1999 1998
Utility revenues from:
Administrative services provided to PG&E Corporation $ 23 $17
Transportation and distribution services provided to PG&E ES 134 --
Gas reservation services provided to PG&E ET 7 1
Other 3 4
Utility expenses from:
Administrative services received from PG&E Corporation 66 58
Gas commodity and transmission services received from PG&E
ET 30 1
Transmission services received from PG&E GT NW 47 49
39
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING METHOD
Effective January 1, 1999, PG&E Corporation changed its method of accounting
for major maintenance and overhauls at the National Energy Group. Beginning
January 1, 1999, the cost of major maintenance and overhauls, principally at the
PG&E Gen business segment, were accounted for as incurred. Previously, the
estimated cost of major maintenance and overhauls was accrued in advance in a
systematic and rational manner over the period between major maintenance and
overhauls. The change resulted in PG&E Corporation recording income of $12
million net of income tax ($0.03 per share), reflecting the cumulative effect of
the change in accounting principle. The effect on current year results of
operations was immaterial. Accordingly, the unaudited quarterly consolidated
information has been restated. (See "Quarterly Consolidated Financial Data
(Unaudited)" below.)
The Utility has consistently accounted for major maintenance and overhauls
as incurred.
NOTE 2: THE CALIFORNIA ELECTRIC INDUSTRY
In 1998, California became one of the first states in the country to
implement electric industry restructuring and establish a competitive market
framework for electric generation. Today, most Californians may continue to
purchase their electricity from investor-owned utilities such as Pacific Gas and
Electric Company, or they may choose to purchase electricity from alternative
generation providers (such as unregulated power generators and unregulated
retail electricity suppliers such as marketers, brokers, and aggregators). For
those customers who have not chosen an alternative generation provider,
investor-owned utilities, such as the Utility, continue to be the generation
providers. Investor-owned utilities continue to provide distribution services to
substantially all customers within their service territories, including
customers who choose an alternative generation provider.
COMPETITIVE MARKET FRAMEWORK
To create a competitive generation market, a PX and an Independent System
Operator (ISO) began operating on March 31, 1998. The PX provides a competitive
auction process to establish market clearing prices for electricity in the
markets operated by the PX. The ISO schedules delivery of electricity for all
market participants. The Utility continues to own and maintain a portion of the
transmission system, but the ISO controls the operation of the system. Unless or
until the CPUC determines otherwise, the Utility is required to bid or schedule
into the PX and ISO markets 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.
In November 1999, the FERC approved the extension of the ISO's authority to
establish price limitations through 2000. The ISO Board increased the applicable
price limitation to $750 per megawatt-hour (MWh) on October 1, 1999, but has the
option to decrease it to $500 per MWh or make other changes, in view of the
FERC's decision. This limits the amount of volatility that occurs in the
California electricity market. However, the ISO will review the appropriate
level for any price limitations for the summer of 2000 in light of market
redesign efforts now being considered, including changes to reduce uninstructed
deviations from ISO dispatch orders and changes to permit loads to participate
by submitting bids for price responsive demand in energy or ancillary services
markets.
For the year ended December 31, 1999, and for the period of March 31, 1998
(the PX's establishment date) to December 31, 1998, the cost of electric energy
for the Utility, reflected on the Statement of Consolidated Income, is comprised
of the cost of PX purchases, ancillary services purchased from the ISO, cost of
transmission, and the cost of Utility generation, net of sales to the PX as
follows:
YEAR ENDED
DECEMBER 31,
-------------------
(IN MILLIONS) 1999 1998
Cost of fuel for electric generation and qualifying
facilities (QF) purchases $1,489 $ 2,030
Cost of purchases from the PX 1,114 723
Cost of ancillary services 630 617
Proceeds from sales to the PX (822) (1,049)
------ -------
Cost of electric energy $2,411 $ 2,321
====== =======
40
TRANSITION PERIOD, RATE FREEZE, AND RATE REDUCTION
California's electric industry restructuring established a transition period
during which electric rates remain frozen at 1996 levels (with the exception
that, on January 1, 1998, rates for small commercial and residential customers
were reduced by 10 percent and remain frozen at this reduced level) and
investor-owned utilities may recover their transition costs. Transition costs
are generation-related costs that prove to be uneconomic under the new
competitive structure. The transition period ends the earlier of December 31,
2001, or when the particular utility has recovered its eligible 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 being recovered from all Utility distribution customers
and are subject to seasonal fluctuations in the Utility's sales volumes and
certain other factors. As the CTC is collected regardless of the customer's
choice of electricity supplier (i.e., the CTC is non-bypassable), the Utility
believes that the availability of choice to its customers will not have a
material impact on its ability to recover transition costs.
To pay for the 10 percent rate reduction, the Utility refinanced
$2.9 billion (the expected revenue reduction from the rate decrease) of its
transition costs with the proceeds from the rate reduction bonds. 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. During the rate freeze, the rate
reduction bond debt service will not increase Utility customers' electric rates.
If the transition period ends before December 31, 2001, the Utility may be
obligated to return a portion of the economic benefits of the transaction to
customers. The timing of any such return and the exact amount of such portion,
if any, have not yet been determined.
TRANSITION COST RECOVERY
Although most transition costs must be recovered during the transition
period, certain transition costs can be recovered after the transition period.
Except for certain transition costs discussed below, 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.
Transition costs consist of (1) above-market sunk costs (costs associated
with utility generating facilities that are fixed and unavoidable and that were
included in customers' rates on December 20, 1995) and future sunk costs, such
as costs related to plant removal, (2) costs associated with 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 exceeds its
market value. Conversely, below-market sunk costs result when the market value
of a facility exceeds its book value. The total amount of generation facility
costs to be included as transition costs is 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. These above- and
below-market sunk costs are related to generating facilities that are classified
as either non-nuclear or nuclear sunk costs.
The Utility cannot determine the exact amount of above-market non-nuclear
sunk costs that will be recoverable as transition costs until the valuation of
the Utility's remaining non-nuclear generating assets, primarily its
hydroelectric generating assets, is completed. The valuation, through appraisal,
sale, or other divestiture, must be completed by December 31, 2001. The value of
seven of the Utility's other non-nuclear generating facilities was determined
when these facilities were sold to third parties. The portion of the sales
proceeds that exceeded the book value of these facilities was used to reduce
other transition costs. On September 30, 1999, the Utility filed an application
with the CPUC to determine the market value of its hydroelectric generating
facilities and related assets through an open, competitive auction. (See
"Generation Divestiture" below.) The Utility plans to use an auction process
similar to the one previously approved by the CPUC and successfully used in the
sale of the Utility's fossil and geothermal plants. If the market value of the
Utility's hydroelectric facilities is determined based upon any method other
than a sale of the facilities to a third party, a material charge to Utility
earnings could result. Any
41
excess of market value over book value would be used to reduce other transition
costs. (See "Generation Divestiture" below.)
For nuclear transition costs, revenues provided for transition cost recovery
are based on the accelerated recovery of the investment in Diablo Canyon Nuclear
Power Plant (Diablo Canyon) over a five-year period ending December 31, 2001.
The amount of nuclear generation sunk costs was determined separately through a
CPUC proceeding and was subject to a final verification audit that was completed
in August 1998. The audit of the Utility's Diablo Canyon accounts at
December 31, 1996, 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. The independent accounting firm
also issued an agreed-upon special procedures report, requested by the CPUC,
that questioned $200 million of the $3.3 billion sunk costs. The CPUC will
review the results of the audit and may seek to make adjustments to Diablo
Canyon's sunk costs subject to transition cost recovery. At this time, the
Utility cannot predict what actions, if any, the CPUC may take regarding the
audit report.
Costs associated with the Utility's long-term contracts to purchase electric
power are included as transition costs. Regulation required the Utility to enter
into such long-term agreements with non-utility generators. Prices fixed under
these contracts are now typically above prices for power in wholesale markets
(See Note 14). Over the remaining life of these contracts, the Utility estimates
that it will purchase 299 million MWh of electric power. To the extent that the
individual contract prices are above the 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 costs under long-term contracts are based on several variables,
including the capacity factors of the related generating facilities and future
market prices for electricity. During 1999, the average price paid under the
Utility's long-term contracts for electricity was 6.3 cents per kilowatt-hour
(kWh). The average cost of electricity purchased at market rates from the PX for
the year ended December 31, 1999, was 3.7 cents per kWh. The average cost of
electricity purchased at market rates from the PX for the period from March 31,
1998, the PX's establishment date, 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. At December 31, 1999 and
1998, the Utility's generation-related net regulatory assets totaled $4 billion
and $5.4 billion, respectively.
Certain transition costs can be recovered through 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, (3) up to
$95 million of transition costs to the extent that the recovery of such costs
during the transition period was displaced by the recovery of electric industry
restructuring implementation costs, and (4) transition costs financed by the
rate reduction bonds. Transition costs financed by the issuance of rate
reduction bonds will be recovered over the term of the bonds. In addition, the
Utility's nuclear decommissioning costs are being recovered through a
CPUC-authorized charge, which will extend until sufficient funds exist to
decommission the nuclear facility. During the rate freeze, the charge for these
costs will not increase Utility customers' electric rates. Excluding these
exceptions, the Utility will write off any transition costs not recovered during
the transition period.
The Utility is amortizing its transition costs, including most
generation-related regulatory assets, over the transition period in conjunction
with the available CTC revenues. During the transition period, a reduced rate of
return on common equity of 6.77 percent applies to all generation assets,
including those generation assets reclassified to regulatory assets. Effective
January 1, 1998, the Utility started collecting these eligible transition costs
through the non-bypassable CTC and generation divestiture. For the years ended
December 31, 1999 and 1998, regulatory assets related to electric industry
restructuring decreased by $1,359 million and $609 million, respectively, which
reflects the recovery of eligible transition costs.
During the transition period, the CPUC reviews the Utility's compliance with
accounting methods established in the CPUC's decisions governing transition cost
recovery and the amount of transition costs requested for recovery. The CPUC is
currently reviewing non-nuclear transition costs amortized during 1998 and the
first six months of 1999.
42
GENERATION DIVESTITURE
In 1998, the Utility sold 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).
On April 16, 1999, the Utility sold three other fossil-fueled generation
plants for $801 million. At the time of sale, these three fossil-fueled plants
had a combined book value of $256 million and had a combined capacity of 3,065
MW.
On May 7, 1999, the Utility sold its complex of geothermal generation
facilities for $213 million. At the time of sale, these facilities had a
combined book value of $244 million and had a combined capacity of 1,224 MW.
The gains from the sale of the fossil-fueled generation plants were used to
offset other transition costs. Likewise, the loss from the sale of the complex
of geothermal generation facilities is being recovered as a transition cost.
The Utility has retained a liability for required environmental remediation
related to any pre-closing soil or groundwater contamination at the plants it
has sold.
On September 30, 1999, the Utility filed an application with the CPUC to
determine the market value of its hydroelectric generating facilities and
related assets through an open, competitive auction. The Utility proposes to use
an auction process similar to the one previously approved by the CPUC and
successfully used in the sale of the Utility's fossil and geothermal plants.
Under the process proposed in the application, another subsidiary of PG&E
Corporation, PG&E Gen, would be permitted to participate in the auction on the
same basis as other bidders.
The sale of the hydroelectric facilities would be subject to certain
conditions, including the transfer or re-issuance of various permits and
licenses by the FERC and other agencies. In addition, the FERC must approve
assignment of the Utility's Reliability Must Run Contract with the ISO for any
facility subject to such contract. Under the proposed purchase and sale
agreement, the CPUC's approval of the proposed sale on terms acceptable to the
Utility in the Utility's sole discretion is also a condition precedent to the
closing of any sale.
On January 13, 2000, a scoping memo and ruling was issued that separates the
proceeding into two concurrent phases: one to review the potential environmental
impacts of the proposed auction under the California Environmental Quality Act
and a second to determine whether the Utility's auction proposal, or some other
alternative to the proposal, is in the public interest. The ruling notes that
the divestiture and valuation issues can best be considered after the
environmental impacts of a change in ownership have been reviewed. Potential
bidders will also be able to incorporate the costs of any mitigation measures
that may be required into their bids. The ruling sets a procedural schedule
which calls for a final decision on the Utility's auction proposal by
October 19, 2000, and a final environmental impact report published in
November 2000. The ruling also anticipates that a final CPUC decision approving
the sale would be issued by May 15, 2001. Finally, the ruling prohibits the
Utility from withdrawing its application without express CPUC authority. It is
uncertain whether the CPUC will ultimately approve the Utility's auction
proposal.
At December 31, 1999, the book value of the Utility's net investment in
hydroelectric generation assets was approximately $0.7 billion, excluding
approximately $0.5 billion of net investment reclassified as regulatory assets.
Any excess of market value over the $0.7 billion book value would be used to
reduce transition costs, including the remaining $0.5 billion of regulatory
assets related to the hydroelectric generation assets. If the market value of
the hydroelectric generation assets is determined by any method other than a
sale of the assets to a third party, or if the winning bidder for any of the
auctioned assets is PG&E Gen, a material charge to Utility earnings could
result. The timing and nature of any such charge is dependent upon the valuation
method and procedure adopted, and the method of implementation. As discussed
below, it is possible that the CPUC will require an interim valuation through an
estimate of market value of the assets prior to transfer, sale or other
divestiture, which could also result in a material charge. While transfer or
sale to an affiliated entity such as PG&E Gen would result in a material charge
to income, neither PG&E Corporation nor the Utility believes that the sale of
any generation facilities to a third party will have a material impact on its
results of operations.
The Utility's ability to continue recovering its transition costs depends 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
determined value of the Utility's hydroelectric generation facilities,
(4) future Utility sales levels, (5) future Utility fuel and operating costs,
and
43
(6) the market price of electricity. Given the current evaluation of these
factors, PG&E Corporation believes that the Utility will recover its transition
costs. 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.
POST-TRANSITION PERIOD
In October 1999, the CPUC issued a decision in the Utility's post-transition
period ratemaking proceeding. Among other matters, the CPUC's decision addresses
the mechanisms for ending the current electric rate freeze and for establishing
post-transition period accounting mechanisms and rates. The decision requires
Diablo Canyon generation to be priced at prevailing market rates after the
transition period.
The CPUC decision requires the Utility to provide quarterly forecasts of
when the Utility's rate freeze (i.e., transition period) may end based on
various assumptions regarding energy prices and the book value of the Utility's
remaining generation assets. The Utility is required to notify the CPUC three
months before the earliest forecasted end of its rate freeze and provide draft
tariff language and sample calculations of the rates that would go into effect
when the rate freeze ends. After the Utility completes its transition cost
recovery, it must implement its post-rate-freeze rates.
The timing of the end of the rate freeze and corresponding transition period
will, in part, depend on the timing of the valuation of the Utility's
hydroelectric generating assets and the ultimate determined value of such assets
since any excess of market value over the assets' book value would be used to
reduce transition costs. If the value of the Utility's hydroelectric generation
assets is significantly higher than the related book value, the transition
period and the rate freeze could end before December 31, 2001, and potentially
could end during 2000. The CPUC is considering the Utility's proposal to auction
its hydroelectric assets, although the CPUC could also
require the Utility to implement an interim valuation of the assets. In another
proceeding (the 1998 Annual Transition Cost Proceeding (ATCP)), a CPUC
administrative law judge issued a proposed decision on January 7, 2000, which
contained a proposed change to the rules previously in place for the
amortization of transition costs. Under the final decision, issued on
February 17, 2000, on a prospective basis the utilities are required to assess
the estimated market value of their remaining non-nuclear generating assets,
including the land associated with those assets, on an aggregate basis at a
value not less than the net book value of those assets and to credit the
Transition Cost Balancing Account (TCBA) with the estimated value. The decision
encourages the utilities to base such estimates on realistic assessments of the
market value of the assets. The final decision did not adopt the proposed
decision's recommendation to establish a new regulatory asset account that would
allow a true-up when the estimated market value is greater than actual market
value. However, the decision states that crediting the TCBA with the aggregate
net book value of the remaining non-nuclear generating assets is a conservative
approach and remedies any concerns regarding the lack of a true-up. The decision
provides that if the estimated market valuation is less than book value for any
individual asset, accelerated amortization of the associated transition costs
will continue until final market valuation of the asset occurs through sale,
appraisal, or other divestiture. If the final value of the assets, determined
through sale, appraisal, or other divestiture, is higher than the estimate, the
excess amount would be used to pay remaining transition costs, if any. The
utilities are required to file the adjusted entries to their respective TCBA
based on the estimated market values with the CPUC by March 9, 2000. The filing
will become effective after appropriate review by the CPUC's Energy Division and
the TCBA entries are subject to review in the next ATCP. If an estimate of the
market value of the non-nuclear generating assets is adopted that exceeds the
aggregate net book value of those assets, a charge to earnings would result.
After the rate freeze and transition periods end, the Utility must refund to
electric customers any over-collected transition costs (plus interest at the
Utility's authorized rate of return) within one year after the end of the rate
freeze. The Utility also will be prohibited from collecting after the rate
freeze any electric costs incurred during the rate freeze but not recovered
during the rate freeze, including costs that are not classified as transition
costs. Through the end of its rate freeze, the Utility will continue to incur
certain non-transition costs and place those costs into balancing and memorandum
accounts for future recovery. There is a risk that the Utility will be unable to
collect certain non-transition costs that, due to lags in the regulatory cost
approval process, have not been approved for recovery nor collected when the
rate freeze ends. The Utility is unable to predict the amount of such potential
unrecoverable costs.
44
The CPUC also has established the Purchased Electric Commodity Account for
the Utility to track energy costs after the rate freeze and transition period
end. The CPUC intends to explore other ratemaking issues, including whether
dollar-for-dollar recovery of energy costs is appropriate, in the second phase
of the post-transition electric ratemaking proceeding. There are three primary
options for the future regulatory framework for utility electric energy
procurement cost recovery after the rate freeze: (1) a CPUC-defined procurement
practice, that if followed by the Utility, would pass through costs without the
need for reasonableness reviews, (2) a pass-through of costs subject to
after-the-fact reasonableness reviews, or (3) a procurement incentive mechanism
with rewards and penalties determined based on the Utility's energy purchasing
performance compared to a benchmark. The Utility proposed adoption of either a
defined procurement practice or a procurement incentive mechanism, neither of
which would involve reasonableness reviews. The volatility of earnings and risk
exposure of the Utility related to post-transition period purchases of
electricity is dependent on which of these options, or some other approach, is
adopted.
After the transition period, the Utility's future earnings from its electric
distribution will be subject to volatility as a result of sales fluctuations.
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, 1999 and 1998.
Short and long positions pertaining to derivative contracts used for hedging
activities as of December 31, 1999 and 1998, are immaterial.
MAXIMUM
NATURAL GAS, ELECTRICITY, PURCHASE SALE TERM IN
AND NATURAL GAS LIQUIDS CONTRACTS (LONG) (SHORT) YEARS
(BILLIONS OF MMBTU EQUIVALENTS(1))
Non-Hedging Activities--December 31, 1999
Swaps 2.28 2.20 7
Options 0.93 0.85 8
Futures 0.19 0.18 2
Forward contracts 1.47 1.42 12
Non-Hedging Activities--December 31, 1998
Swaps 6.21 6.06 8
Options 1.50 1.28 5
Futures 0.58 0.61 4
Forward contracts 3.70 3.55 5
(1) 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.
PG&E Corporation's natural gas liquids contracts were converted to MMBtu
equivalents using an appropriate conversion factor for each type of natural
gas liquids product.
Volumes shown for swaps, futures, and options represent notional volumes
that are used to calculate amounts due under the agreements and do not
necessarily represent volumes exchanged. Moreover, notional amounts are
indicative only of the volume of activity and are not a measure of market risk.
PG&E Corporation's net gains (losses) on swaps, options, futures, and
forward contracts held during the years ended December 31, 1999 and 1998 are as
follows:
YEAR ENDED
DECEMBER 31,
-----------------------
(IN MILLIONS) 1999 1998
Swaps $ 15 $ 69
Options (41) (49)
Futures (36) (63)
Forward contracts 98 101
---- ----
Net gain (loss) $ 36 $ 58
==== ====
45
The following table discloses the estimated fair values of price risk
management assets and liabilities as of December 31, 1999 and 1998. The ending
and average fair values and associated carrying amounts of derivative contracts
used for hedging purposes are not material as of December 31, 1999 and 1998.
AVERAGE ENDING
(IN MILLIONS) FAIR VALUE FAIR VALUE
Non-Hedging Activities--December 31, 1999
Assets:
Swaps $ 643 $ 244
Options 106 92
Futures 175 47
Forward contracts 667 596
------ ------
Total $1,591 $ 979
------ ------
Noncurrent portion $ 372
Current portion $ 607
Liabilities:
Swaps $ 592 $ 218
Options 109 81
Futures 201 67
Forward contracts 561 456
------ ------
Total $1,463 $ 822
------ ------
Noncurrent portion $ 247
Current portion $ 575
Non-Hedging Activities--December 31, 1998
Assets:
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
Liabilities:
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
PG&E Corporation, primarily through its subsidiaries, engages in price risk
management activities for both non-hedging and hedging purposes. Non-hedging
activities are conducted principally through its unregulated subsidiary, PG&E
ET. In compliance with regulatory requirements, the Utility manages price risk
independently from the activities in PG&E Corporation's unregulated businesses
(see Note 1 for further discussion). The Utility primarily engages in hedging
activities which, noted above, were immaterial for the years ended December 31,
1999 and 1998.
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
46
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, 1999.
NOTE 4: CONCENTRATIONS OF MARKET AND CREDIT RISK
MARKET RISK
Market risk is the risk that changes in market prices will adversely affect
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 1999. The credit
exposure of the five largest counterparties comprised approximately
$250 million of the total credit exposure associated with financial instruments
used to manage price risk. Counterparties considered to be investment grade or
higher comprise 70 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.
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 PG&E Gen, an
independent power developer, owner, and manager; PG&E Operating Services
Company, PG&E Gen's operations and maintenance affiliate; and USGen Power
Services, L.P., PG&E Gen's power marketing affiliate. Additionally, PG&E
Corporation has acquired all or part of interest in several power projects that
are affiliated with PG&E Gen.
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 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 1998 and 1997.
In September 1998, PG&E Corporation, through its indirect subsidiary USGen
New England, Inc. (USGenNE), 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 an
assessment of the fair values at the date of acquisition.
47
Including fuel and other inventories and transaction costs, PG&E
Corporation's financing requirements for this acquisition were approximately
$1.8 billion, funded through an aggregate of $1.3 billion PG&E Gen and USGenNE
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 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 assets include hydroelectric, coal, oil, and natural gas generation
facilities with a combined generating capacity of 4,000 MW. In addition, USGenNE
assumed 23 multi-year power purchase agreements representing an additional 800
MW of production capacity. USGenNE entered into agreements with NEES as part of
the acquisition, which (1) provide that NEES shall make support payments over
the next 9 years to USGenNE for the purchase power agreements, and (2) require
that USGenNE provide electricity to certain of NEES affiliates under contracts
that expire over the next 3 to 10 years.
In December 1999, PG&E Corporation's Board of Directors approved a plan to
dispose of PG&E ES, its wholly owned subsidiary, through a sale. As of December
31, 1999, the intended disposal has been accounted for as a discontinued
operation. In connection with this transaction, PG&E Corporation's investment in
PG&E ES was written down to its estimated net realizable value. In addition,
PG&E Corporation provided a reserve for anticipated losses through the date of
sale. The total provision for discontinued operations was $58 million, net of
income taxes of $36 million. While there is no definite sales agreement, it is
expected that the disposition will be completed in 2000. The amounts that PG&E
Corporation will ultimately realize from this disposal could be materially
different from the amounts assumed in arriving at the estimated loss on disposal
of the discontinued operations. The PG&E ES business segment generated net
losses of $40 million (or $0.11 per share), $52 million (or $0.14 per share),
and $29 million (or $0.07 per share), for the years ended December 31, 1999,
1998 and 1997, respectively.
The total assets and liabilities, including the charge noted above, of PG&E
ES included in the PG&E Corporation Consolidated Balance Sheet at December 31,
1999 and 1998, are as follows:
BALANCE AT
DECEMBER 31,
----------------------
(IN MILLIONS) 1999 1998
ASSETS
Current assets $114 $148
Noncurrent assets 83 54
---- ----
Total Assets $197 $202
LIABILITIES
Current liabilities $ 61 $ 72
Noncurrent liabilities 10 9
---- ----
Total liabilities 71 81
---- ----
NET ASSETS 126 121
==== ====
On January 27, 2000, PG&E Corporation's National Energy Group signed a
definitive agreement with El Paso Field Services Company (El Paso) providing for
the sale to El Paso, a subsidiary of El Paso Energy Corporation, of the stock of
PG&E Gas Transmission, Texas Corporation and PG&E Gas Transmission Teco, Inc.
(collectively, PG&E GTT). The consideration to be received by the National
Energy Group includes $279 million in cash subject to a working capital
adjustment, the assumption by El Paso of debt having a book value of $624
million, and other liabilities associated with PG&E GTT.
In 1999, PG&E Corporation recognized a charge against earnings of $890
million after-tax, or $2.42 per share, to reflect PG&E GTT's assets at their
fair market value. The composition of the pre-tax charge is as follows: (1) an
$819 million write down of net property, plant, and equipment, (2) the
elimination of the unamortized portion of goodwill, in the amount of $446
million, and (3) an accrual of $10 million representing selling costs.
Proceeds from the sale will be used to retire short-term debt associated
with PG&E GTT's operations and for other corporate purposes. Closing of the
sale, which is expected in the first half of 2000, is subject to approval under
the Hart Scott Rodino Act.
48
The sale of PG&E GTT represents disposal of the PG&E GTT business segment
and a portion of the PG&E ET business segment. PG&E GTT's total assets and
liabilities, including the charge noted above, included in the PG&E Corporation
Consolidated Balance Sheet at December 31, 1999 and 1998, are as follows:
BALANCE AT
DECEMBER 31,
-------------------
(IN MILLIONS) 1999 1998
ASSETS
Current assets $ 229 $ 366
Noncurrent assets 988 2,346
------ ------
Total Assets $1,217 $2,712
LIABILITIES
Current liabilities $ 448 $ 486
Noncurrent liabilities 624 1,174
------ ------
Total liabilities 1,072 1,660
------ ------
NET ASSETS 145 1,052
====== ======
NOTE 6: COMMON STOCK
PG&E CORPORATION
PG&E Corporation has authorized 800 million shares of no-par common stock of
which 384 million and 383 million shares were issued as of December 31, 1999 and
1998, respectively.
During the years ended December 31, 1999 and 1998, PG&E Corporation
repurchased $693 million and $1,158 million of its common stock, respectively.
The repurchases in 1998 and through September 1999 were executed through
separate, accelerated share repurchase programs. Under the 1999 agreement, PG&E
Corporation repurchased in a specific transaction 16.6 million shares of its
common stock at a cost of $502 million. In connection with this transaction,
PG&E Corporation entered into a forward contract with an investment institution.
PG&E Corporation settled the forward contract and its additional obligation of
$29 million in September 1999. A wholly owned subsidiary of PG&E Corporation
made this repurchase, along with subsequent stock repurchases. The stock held by
the subsidiary is treated as treasury stock and reflected as stock held by
subsidiary on the Consolidated Balance Sheet of PG&E Corporation.
In October 1999, the Board of Directors of PG&E Corporation authorized an
additional $500 million for the purpose of repurchasing shares of the
Corporation's common stock on the open market. This authorization supplements
the approximately $40 million remaining from the amount previously authorized by
the Board of Directors on December 17, 1997. The authorization for share
repurchase extends through September 30, 2001. As of December 31, 1999, a
subsidiary of PG&E Corporation has repurchased 7.2 million shares at a cost of
$159 million under this authorization.
UTILITY
All of the Utility's outstanding common stock is held by PG&E Corporation
and a subsidiary of the Utility. In connection with the formation of the holding
company, all of the Utility's then-outstanding 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 321 million and 341 million shares were issued as of December 31, 1999
and 1998, respectively.
Prior to December 1999, the Utility repurchased 20 million shares of its
common stock from PG&E Corporation for an aggregate purchase price of
$726 million to maintain its authorized capital structure. In December 1999,
7.6 million shares of the Utility's common stock, with an aggregate purchase
price of $200 million, was purchased by a subsidiary of the Utility. This
purchase is reflected as stock held by subsidiary in the Consolidated Balance
Sheet of Pacific Gas and Electric Company.
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 1999, the Utility was in compliance with its CPUC-authorized
capital structure.
49
NOTE 7: PREFERRED STOCK AND UTILITY OBLIGATED MANDATORILY REDEEMABLE PREFERRED
SECURITIES OF TRUST HOLDING SOLELY UTILITY SUBORDINATED DEBENTURES
PREFERRED STOCK OF UTILITY
The Utility has authorized 75 million shares of $25 par value preferred
stock which may be issued as redeemable or nonredeemable preferred stock. At
December 31, 1999 and 1998, the Utility had issued and outstanding 5,784,825
shares of nonredeemable preferred stock.
At December 31, 1999 and 1998, the Utility had issued and outstanding
5,973,456 shares of redeemable preferred stock. 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, 1999, range from $1.09 to $1.76 and from $25.75
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.
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, 1999. 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.
PREFERRED STOCK OF THE NATIONAL ENERGY GROUP
Preferred stock of the National Energy Group consists of $57 million of
preferred stock issued by a subsidiary of PG&E Gen. The preferred stock, with
$100 par value, has a stated dividend of $3.35 per share, per quarter, and is
redeemable when there is an excess of available cash. There were 549,594 shares
outstanding at December 31, 1999 and 1998.
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%, and a maturity date of 2025. These subordinated debentures are the only
assets of the Trust. Proceeds from the sale of the subordinated debentures were
used to redeem and repurchase higher-cost preferred stock.
The Utility's guarantee of the QUIPS, considered together with the other
obligations of the Utility with respect to the QUIPS, constitutes a full and
unconditional guarantee by the Utility of the Trust's contractual obligations
under the QUIPS issued by the Trust. The subordinated debentures may be redeemed
at the Utility's option beginning in 2000 at par 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.
50
NOTE 8: LONG-TERM DEBT
Long-term debt at December 31, 1999 and 1998, consisted of the following:
BALANCE AT
DECEMBER 31,
-------------------
(IN MILLIONS) 1999 1998
Utility long-term debt
First and refunding mortgage bonds
Maturity Interest rates
2000-2003 6.25% to 8.75% $ 816 $ 969
2004-2008 5.875% to 6.25% 600 615
2009-2021 6.35% to 7.59% 160 160
2022-2026 5.85% to 8.80% 2,004 2,117
------ ------
Principal amounts outstanding 3,580 3,861
Unamortized discount net of premium (29) (32)
------ ------
Total mortgage bonds 3,551 3,829
Pollution control loan agreements, variable rates, due 2010-2026 1,348 1,348
Unsecured medium-term notes, 5.56% to 8.45%, Due 2000-2014 418 498
Other Utility long-term debt 25 29
------ ------
Total Utility long-term debt 5,342 5,704
Current portion of long-term debt 465 260
------ ------
Total Utility long-term debt, net of current portion 4,877 5,444
------ ------
National Energy Group long-term debt
First mortgage notes, 10.02% to 11.50%, due 2000-2009 333 370
Senior notes
Maturity Interest rates
1999 10.58% -- 69
2005 7.10% 250 250
Medium-term notes, 6.61% to 9.25%, due 2000-2012 299 298
Senior debentures, 7.80%, due 2025 150 150
Amounts outstanding under credit facilities (See Note 10) 649 654
Other long-term debt 242 265
------ ------
Total National Energy Group long-term debt 1,923 2,056
Current portion of long-term debt 127 78
------ ------
Total National Energy Group long-term debt, net of current portion 1,796 1,978
------ ------
Total long-term debt $6,673 $7,422
====== ======
UTILITY
FIRST AND REFUNDING MORTGAGE BONDS:
First and refunding mortgage bonds are issued in series and bear annual
interest rates ranging from 5.85 percent to 8.80 percent. All real properties
and 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 $281 million and $501 million of the
bonds in 1999 and 1998, 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, 1999 and 1998,
are $345 million of bonds held in trust for the California Pollution Control
Financing Authority (CPCFA) with interest rates ranging from 5.85 percent
51
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, 1999 and 1998. Interest rates on the loans vary with average annual
interest rates. For 1999 the interest rates ranged from 2.36 percent to
3.39 percent. These loans are subject to redemption by the holder under certain
circumstances. These loans are secured primarily by irrevocable letters of
credit which mature in 2000 through 2003.
NATIONAL ENERGY GROUP
Long-term debt of the National Energy Group consists of first mortgage bonds
and other secured and unsecured obligations.
The first mortgage notes are comprised of three series due annually through
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 that restrict the ability of PG&E GTT to incur additional indebtedness
and precludes cash distributions if certain cash flow coverages are not met. In
January 2000, PG&E GTT obtained an amendment that provides PG&E GTT the ability
to redeem in whole or in part, its Mortgage Notes, including the premium set
forth in the Mortgage Note Indenture, anytime after January 1, 2000. These notes
will be assumed by the buyer of PG&E GTT (see Note 5).
Other long-term debt consists of project financing associated with
unregulated generation facilities, premiums, and other loans.
REPAYMENT SCHEDULE
At December 31, 1999, PG&E Corporation's combined aggregate amounts of
maturing long-term debt and sinking fund requirements, for the years 2000
through 2004, are $592 million, $480 million, $1,363 million, $1,271 million,
and $470 million, respectively. The Utility's share of those maturities and
sinking fund requirements is $465 million, $374 million, $1,117 million,
$664 million, and $392 million, respectively.
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 non-bypassable tariff levied on residential and small commercial
customers which was authorized by the CPUC pursuant to state legislation.
The rate reduction bonds have maturities ranging from 6 months to 8 years,
and bear interest at rates ranging from 6.15 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, 1999, $2.3 billion of rate reduction bonds were outstanding.
The combined expected principal payments on the rate reduction bonds for the
years 2000 through 2004 are $290 million for each year.
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 not legally an asset of the Utility or PG&E
Corporation.
NOTE 10: CREDIT FACILITIES
PG&E CORPORATION
At December 31, 1999 and 1998, PG&E Corporation had borrowed $2,148 million
and $2,298 million, respectively, under various credit facilities discussed
below. $649 million and $654 million of these borrowings at December 31, 1999
and 1998, respectively, are classified as long-term debt. (See Note 8.) The
weighted average interest rate on the short-term borrowings was 5.4 percent and
5.6 percent for 1999 and 1998, respectively.
52
PG&E Corporation maintains two $500 million revolving credit facilities, one
of which expires in November 2000 and the other in 2002. These credit facilities
are used to support the commercial paper program and other liquidity needs. The
facility expiring in 2000 may be extended annually for additional one-year
periods upon agreement with the lending institutions. There was $450 million and
$683 million of commercial paper outstanding at December 31, 1999 and 1998,
respectively. PG&E Corporation introduced a $200 million Extendible Commercial
Note (ECN) program during the third quarter of 1999. The ECN program supplements
our short-term borrowing capability. There was $76 million of ECNs outstanding
at December 31, 1999, which are not supported by the credit facilities.
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 with the banks. This facility is used to support the Utility's
commercial paper program and other liquidity requirements. The total amount
outstanding at December 31, 1999, backed by this facility, was $449 million in
commercial paper. The total amount outstanding at December 31, 1998, backed by
this facility was $567 million in commercial paper and $101 million of bank
notes.
NATIONAL ENERGY GROUP
PG&E Gen maintains two $550 million revolving credit facilities. One
facility expires in August 2000 and the other expires in 2003. The amount
outstanding at December 31, 1999 and 1998, backed by the facilities, was
$898 million and $233 million, respectively in commercial paper. Also
outstanding at December 31, 1998, was a $540 million eurodollar loan drawn on
one of the revolving credit facilities, which was subsequently paid off in 1999.
At December 31, 1999 and 1998, $550 million of these loans is classified as
noncurrent in the consolidated balance sheet.
In 1998, USGenNE, a subsidiary of PG&E Gen, established a $100 million
revolving credit facility that expires in 2003. No amounts were outstanding at
December 31, 1999.
PG&E GT NW maintains a $100 million revolving credit facility that expires
in 2002, but has an annual renewal option allowing the facility to maintain a
three-year duration. PG&E GT NW also maintains a $50 million 364-day credit
facility which expires in 2000, but may be extended for successive 364-day
periods. No amounts were outstanding under either of these credit facilities at
December 31, 1999. At December 31, 1999 and 1998, PG&E GT NW had an outstanding
commercial paper balance of $99 million and $104 million, respectively, which is
classified as noncurrent in the Consolidated Balance Sheet of PG&E Corporation.
PG&E GTT maintains four separate credit facilities that total $250 million
and are guaranteed by PG&E Corporation. At December 31, 1999, PG&E GTT had
$176 million of outstanding short-term bank borrowings related to these credit
facilities. At December 31, 1998, PG&E GTT had $70 million of outstanding
short-term bank borrowings related to two credit facilities. These lines may be
cancelled 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
for ratemaking purposes 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 $1.6 billion in 1999 dollars (or $5.1 billion in future
dollars). This estimate assumes after-tax earnings on the tax-qualified and
non-tax-qualified decommissioning funds of 6.34 percent and 5.39 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 term of each facility.
For the year ended December 31, 1999, nuclear decommissioning costs
recovered in rates were $26.5 million. For the years ended December 31, 1998 and
1997, nuclear decommissioning costs recovered in rates were $33 million per
year, respectively. The CPUC has established a Nuclear Decommissioning Cost
Triennial
53
Proceeding to review, every three years, updated decommissioning cost estimates
and to establish the annual trust contribution, absent general rate cases.
At December 31, 1999, the total nuclear decommissioning obligation accrued
was $1.3 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 fair value, based on quoted market
prices, of these nuclear decommissioning funds:
YEAR ENDED DECEMBER 31,
-------------------------------
MATURITY
(IN MILLIONS) DATES 1999 1998
U.S. government and agency issues 2000-2030 $ 380 $ 379
Equity securities -- 223 246
Municipal bonds and other 2000-2031 201 164
Gross unrealized holding gains 474 394
Gross unrealized holding losses (14) (11)
------ ------
Fair value (net of tax) $1,264 $1,172
====== ======
The proceeds received from sales of securities were $1.7 billion in 1999,
and $1.4 billion in 1998 and 1997. The gross realized gains on sales of
securities held as available-for-sale were $59 million, $52 million, and
$40 million in 1999, 1998, and 1997, respectively. The gross realized losses on
sales of securities held as available-for-sale were $60 million, $39 million,
and $24 million in 1999, 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.
NOTE 12: EMPLOYEE BENEFIT PLANS
Several of PG&E Corporation's subsidiaries provide noncontributory defined
benefit pension plans for their employees and retirees. 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 plans. The schedules below aggregate all of the plans employed by PG&E
Corporation's subsidiaries.
54
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 as of and for
the years ended December 31, 1999 and 1998:
PENSION BENEFITS OTHER BENEFITS
------------------- -------------------
(IN MILLIONS) 1999 1998 1999 1998
CHANGE IN BENEFIT OBLIGATION
Benefit obligation at January 1 $(4,977) $(4,457) $ (949) $(907)
Service cost for benefits earned (121) (108) (19) (19)
Interest cost (347) (333) (69) (64)
Actuarial gain (loss) 372 (321) (19) (36)
Adopted plan benefits -- -- (4) --
Participant paid benefits -- -- (14) --
Benefits and expenses paid 266 242 104 77
------- ------- ------ -----
Benefit obligation at December 31 (4,807) (4,977) (970) (949)
CHANGE IN PLAN ASSETS
Fair value of plan assets at January 1 7,104 6,419 951 823
Actual return on plan assets 1,331 919 240 173
Company contributions 4 27 15 18
Participant paid benefits -- -- 14 13
Benefits and expenses paid (286) (261) (103) (76)
------- ------- ------ -----
FAIR VALUE OF PLAN ASSETS AT DECEMBER 31 8,153 7,104 1,117 951
PLAN ASSETS IN EXCESS OF BENEFIT OBLIGATION 3,346 2,127 147 2
(BENEFIT OBLIGATION IN EXCESS OF PLAN ASSETS)
Unrecognized prior service cost 93 104 17 19
Unrecognized net loss (gain) (2,963) (2,025) (546) (430)
Unrecognized net transition obligation 65 79 339 366
------- ------- ------ -----
PREPAID (ACCRUED) BENEFIT COST $ 541 $ 285 $ (43) $ (43)
======= ======= ====== =====
The Utility's share of the plans' assets in excess of the benefit obligation
for pensions in 1999 and 1998 was $3,344 million and $2,134 million,
respectively. The Utility's share of the prepaid benefit cost for the pensions
in 1999 and 1998 was $556 million and $301 million, respectively.
The plan assets of the Utility exceeded its share of the benefit obligation
for other benefits by $167 million and $24 million in 1999 and 1998,
respectively. The Utility's share of the accrued benefit liability for other
benefits in 1999 and 1998 was $22 million and $26 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:
PENSION BENEFITS OTHER BENEFITS
------------------------------ ------------------------------
DECEMBER 31, 1999 1998 1997 1999 1998 1997
(IN MILLIONS)
Service cost for benefits earned $(121) $(108) $(102) $(19) $(19) $(21)
Interest cost (347) (333) (316) (69) (64) (64)
Expected return on assets 634 567 486 83 73 60
Amortized prior service and transition cost (25) (26) (22) (27) (28) (28)
Actuarial gain recognized 111 114 74 20 22 13
----- ----- ----- ---- ---- ----
Benefit income (cost) $ 252 $ 214 $ 120 $(12) $(16) $(40)
===== ===== ===== ==== ==== ====
The Utility's share of the net benefit income for pensions in 1999, 1998,
and 1997 was $253 million, $215 million, and $123 million, respectively.
55
The Utility's share of the net benefit cost for other benefits in 1999,
1998, and 1997 was $9 million, $12 million, and $38 million, respectively.
Net benefit income (cost) is calculated using an expected long-term rate of
return on plan assets of 9.0 percent. The difference between actual and expected
long-term rate of return on plan assets is included in net amortization and
deferral and is considered in the determination of future net benefit income
(cost). In 1999, 1998, and 1997, 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 also has 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, 1999 1998 1997 1999 1998 1997
Discount rate 7.5% 7.0% 7.5% 7.5% 7.0% 7.5%
Average expected 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 8.5% 9.0% 9.0% 9.0% 9.0% 9.0%
The assumed health care cost trend rate for 2000 is approximately
8.5 percent, grading down to an ultimate rate in 2006 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 $ 6 $ (6)
Effect on postretirement benefit obligation $62 $(57)
LONG-TERM INCENTIVE PROGRAM
PG&E Corporation maintains a Long-term Incentive Program (Program) that
provides for grants of stock options to eligible participants with or without
associated stock appreciation rights and dividend equivalents. As of
December 31, 1999, 34,389,230 shares of PG&E Corporation common stock have been
authorized for award with 15,779,821 shares still available under this program.
Shares granted in 1999, 1998 and 1997, had approximate values of $23 million,
$27 million, and $12 million, respectively, using the Black-Scholes valuation
method. In addition, PG&E Corporation granted 9,712,900 shares on January 3,
2000 at an option price of $19.8125 and 18,000 shares on February 1, 2000 at an
option price of $22.1875, the then-current market prices.
Outstanding stock options become exercisable on a cumulative basis at
one-third each year commencing two years from the date of grant and expire ten
years and one day after the date of grant. Shares outstanding at December 31,
1999, had option prices ranging from $16.75 to $34.25 and a weighted-average
remaining contractual life of 7.8 years. As permitted under SFAS No. 123
"Accounting for Stock-Based Compensation," PG&E Corporation applies Accounting
Board Opinion No. 25 in accounting for the program. As the exercise price of all
stock options are equal to their fair market value at the time the options are
granted, PG&E Corporation
does not recognize any compensation expense related to the program using the
intrinsic value based method. Had compensation expense been recognized using the
fair value based method under SFAS No. 123, PG&E Corporation's consolidated
earnings would have been reduced by $16 million, $10 million and $4 million in
1999, 1998, and 1997, respectively.
56
The following table summarizes the program's activity as of and for the year
ended December 31, 1999, 1998 and 1997:
1999 1998 1997
------------------- ------------------- -------------------
WEIGHTED WEIGHTED WEIGHTED
AVERAGE AVERAGE AVERAGE
OPTION OPTION OPTION
(SHARES IN MILLIONS) SHARES PRICE SHARES PRICE SHARES PRICE
Outstanding--
beginning of year 11.1 $28.35 6.2 $26.21 3.5 $29.56
Granted during year 7.0 $30.94 6.4 $30.53 3.0 $22.55
Exercised during year (0.5) $25.86 (0.7) $29.63 (0.2) $27.36
Cancellations during year (1.2) $29.82 (0.8) $28.16 (0.1) $27.82
Outstanding-end of year 16.4 $29.43 11.1 $28.35 6.2 $26.21
Exercisable-end of year 3.0 $29.08 2.4 $29.06 1.9 $30.84
NOTE 13: INCOME TAXES
The significant components of income tax expense for continuing operations
were:
PG&E CORPORATION UTILITY
------------------------------ ------------------------------
YEAR ENDED DECEMBER 31, 1999 1998 1997 1999 1998 1997
(IN MILLIONS)
Current $1,002 $718 $ 725 $1,133 $ 886 $ 791
Deferred (702) (51) (119) (433) (201) (142)
Tax credits, net (52) (56) (41) (52) (56) (40)
------ ---- ----- ------ ----- -----
INCOME TAX EXPENSE $ 248 $611 $ 565 $ 648 $ 629 $ 609
====== ==== ===== ====== ===== =====
In 1999, the income tax expense of PG&E Corporation was allocated to
continuing operations ($248 million), discontinued operations ($71 million tax
benefit), and cumulative effect of a change in an accounting principle
($8 million).
The significant components of net deferred income tax liabilities were:
PG&E
CORPORATION UTILITY
------------------- -------------------
DECEMBER 31, 1999 1998 1999 1998
(IN MILLIONS)
DEFERRED INCOME TAX ASSETS:
Customer advances for construction $ 109 $ 68 $ 109 $ 68
Unamortized investment tax credits 118 127 118 127
Provision for injuries and damages 185 220 185 171
Deferred contract costs 182 242 -- --
Other 544 562 442 477
------ ------ ------ ------
TOTAL DEFERRED INCOME TAX ASSETS $1,138 $1,219 $ 854 $ 843
------ ------ ------ ------
DEFERRED INCOME TAX LIABILITIES:
Regulatory balancing accounts (47) 43 (47) 40
Plant in service 2,827 3,722 2,428 2,930
Income tax regulatory asset 297 391 287 381
Other 1,075 968 577 555
------ ------ ------ ------
TOTAL DEFERRED INCOME TAX LIABILITIES 4,152 5,124 3,245 3,906
------ ------ ------ ------
TOTAL NET DEFERRED INCOME TAXES $3,014 $3,905 $2,391 $3,063
====== ====== ====== ======
CLASSIFICATION OF NET DEFERRED INCOME TAXES:
Included in current (assets) liabilities $ (133) $ 44 $ (119) $ 3
Included in noncurrent liabilities 3,147 3,861 2,510 3,060
------ ------ ------ ------
TOTAL NET DEFERRED INCOME TAXES $3,014 $3,905 $2,391 $3,063
====== ====== ====== ======
57
The differences between income taxes and amounts determined by applying the
federal statutory rate to income before income tax expense for continuing
operations were:
PG&E CORPORATION UTILITY
------------------------------ ------------------------------
YEAR ENDED DECEMBER 31, 1999 1998 1997 1999 1998 1997
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) 10.1 3.2 5.2 6.2 6.6 4.6
Effect of regulatory treatment of depreciation differences 51.7 9.7 7.9 9.4 9.8 7.5
Tax credits--net (19.9) (4.0) (3.1) (3.6) (4.1) (2.9)
Effect of foreign earnings at different tax rates (1.3) 0.6 (2.1) -- -- --
Stock sale differences (6.8) -- -- -- -- --
Stock sale valuation allowance 30.2 -- -- -- -- --
Other--net (4.0) (0.3) 0.2 (1.9) (1.0) --
----- ---- ---- ---- ---- ----
EFFECTIVE TAX RATE 95.0% 44.2% 43.1% 45.1% 46.3% 44.2%
===== ==== ==== ==== ==== ====
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.
During 1999, PG&E Corporation generated a capital loss carryforward of
approximately $225 million, which will expire in 2005. A valuation allowance of
approximately $75 million has been recorded reflecting the estimated net
realizable value of this capital loss carryforward.
NOTE 14: COMMITMENTS
UTILITY
LETTERS OF CREDIT AND SURETY BONDS:
The Utility uses $409 million in standby letters of credit and surety bonds
to secure future workers' compensation liabilities.
RESTRUCTURING TRUST GUARANTEES:
Tax-exempt restructuring trusts were 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 $85 million to be used by the trusts for this purpose. Under the
CPUC authorization, the Utility's remaining guarantee is for up to a maximum of
$38 million of the loan. The remaining bank loan will be repaid and the
guarantee removed when the trust obtains 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 independent power producers that are qualifying facilities
(QFs) under the Public Utilities Regulatory Policies Act of 1978 (PURPA). The
CPUC established a series of QF long-term 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. Costs associated with
these contracts are eligible for recovery by the Utility as transition costs
through the collection of the nonbypassable CTC. The Utility's contracts with
these power producers expire on various dates through 2028. Deliveries from
these power producers account for approximately 23 percent of the Utility's 1999
electric energy requirements, and no single contract accounted for more than
five percent of the Utility's energy needs.
The Utility has negotiated with several QFs for early termination of their
power purchase contracts. For other contracts, the Utility has negotiated with
QFs to refrain from producing energy during the remaining term of the higher
fixed energy price period under their contract (a "buy-down") or to curtail
energy production for shorter periods of time (a "curtailment"). At
December 31, 1999, the total discounted future payments due under the
renegotiated contracts that are subject to early termination, buy-down, or
curtailment was $16 million, of which
58
$6.6 million has been recovered in rates and the Utility expects to recover the
remaining $9.4 million in future rates.
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. Costs associated with
these contracts to purchase power are eligible for recovery by the Utility as
transition costs through the collection of the nonbypassable CTC. At
December 31, 1999, the undiscounted future minimum payments under these
contracts were $32.7 million for each of the years 2000 through 2004 and a total
of $247 million for periods thereafter. Irrigation district and water agency
deliveries in the aggregate account for approximately 5.8 percent of the
Utility's 1999 electric energy requirements.
The amount of energy received and the total payments made under all of these
power purchase contracts were:
YEAR ENDED DECEMBER 31,
------------------------------
1999 1998 1997
(IN MILLIONS)
Kilowatt-hours received 25,910 25,994 24,389
Energy payments $837 $943 $1,157
Capacity payments $539 $529 $ 538
Irrigation district and water agency payments $ 60 $ 53 $ 56
NATURAL GAS TRANSPORTATION COMMITMENTS:
The Utility has long-term gas transportation service contracts with various
Canadian and interstate pipeline companies. These agreements include provisions
for payment of fixed demand charges for reserving firm capacity on the
pipelines. The total demand charges that the Utility will pay each year may
change due to changes in tariff rates. The total demand and volumetric
transportation charges the Utility paid under these agreements were
$97 million, $113 million, and $255 million in 1999, 1998, and 1997,
respectively. These amounts include payments made by the Utility to PG&E GT NW
of $47 million, $49 million, and $49 million in 1999, 1998, and 1997,
respectively, which are eliminated in the consolidated financial statements of
PG&E Corporation.
The Utility's obligations related to capacity held pursuant to long-term
contracts on various pipelines are as follows:
(IN MILLIONS)
2000 $100
2001 97
2002 78
2003 78
2004 78
Thereafter 98
----
Total $529
====
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.
NATIONAL ENERGY GROUP
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 PG&E Gen
contractual rights and duties under several power purchase contracts with
third-party independent power producers. At December 31, 1999, these agreements
provided for an aggregate
59
of 470 MW of capacity. Under the transfer agreement, PG&E Gen is required to pay
to NEES amounts due to the third-party power producers under the power purchase
contracts. PG&E Gen's payment obligations to NEES are reduced by NEES's monthly
payment obligation, payable in monthly installments from September 1998 through
January 2008. In certain circumstances, NEES, with the consent of PG&E Gen, will
make a full or partial lump-sum accelerated payment of the monthly payment
obligation to such party as PG&E Gen may direct. The approximate dollar amounts
under these agreements are as follows:
POWER
PURCHASE SUPPORT
(IN MILLIONS) CONTRACT PAYMENTS
2000 $ 233 $119
2001 228 120
2002 215 121
2003 217 112
2004 220 108
Thereafter 1,804 334
------ ----
Total $2,917 $914
====== ====
GAS SUPPLY AND TRANSPORTATION AGREEMENTS:
PG&E Gen is obligated to purchase and fuel suppliers are required to supply
all the fuel needed at PG&E Gen's facilities. Fuel requirements include the
quality and estimated quantity of fuel needed to operate each facility. The
price of fuel escalates annually for the term of each contract. In addition,
PG&E Gen has transportation contracts with various entities to deliver the fuel
to each facility. The approximate dollar obligations under these gas supply and
transportation agreements are as follows:
(IN MILLIONS)
2000 $ 103
2001 101
2002 101
2003 102
2004 11
Thereafter 848
------
Total $1,266
======
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), PG&E Gen entered into
agreements to supply the electric capacity and energy necessary for certain of
NEES affiliates to meet their obligations to provide standard offer service. The
agreements to provide standard offer service range in length from 3 to 10 years.
The price per MWh is standard for all agreements. For the year ended
December 31, 1999, the standard offer service price paid generators was $0.035
per Kwh for generation.
OPERATING LEASES:
PG&E Corporation and the National Energy Group have entered into various
long-term lease commitments.
PG&E Gen has an agreement to lease Lake Road under a five-year operating
lease agreement which is extendible. The lease term will commence upon the
completion of the construction of a gas-fired generating facility, which is
anticipated to be mid-2001. The minimum obligations under this lease cannot be
determined until the commencement of the lease because the minimum rent payments
are based on the final cost to complete the facility. The approximate
obligations below are based on the current estimated total cost of the facility.
USGenNE entered into a $479 million sale-and-leaseback transaction whereby
USGenNE sold and leased back its Bear Swamp facility to a third party. The
related lease is being accounted for as an operating lease. The rental expense
under this lease in 1999 was $2 million.
PG&E Gen leases the Pittsfield facility from General Electric Credit
Corporation. The rental expense for this facility in 1999 was $28 million.
60
PG&E GTT has an operating lease commitment in connection with gas storage.
The term of the gas storage facility lease and related arrangements run through
January 2008 and subject to certain conditions, has one or more optional renewal
periods of five years each at fair market value. The rental expense for this gas
storage facility in 1999 was approximately $10 million.
PG&E Corporation and our National Energy Group have leases for office space
primarily located in California, Maryland, Oregon, Massachusetts, and Texas. For
the year ended December 31, 1999, rent expense for these facilities amounted to
$27 million.
The approximate obligations under these operating lease agreements are as
follows:
(IN MILLIONS)
2000 $ 96
2001 110
2002 116
2003 109
2004 124
Thereafter 1,266
------
Total $1,821
======
NOTE 15: CONTINGENCIES
NUCLEAR INSURANCE
The Utility has insurance coverage for property damage and business
interruption losses as a member of Nuclear Electric Insurance Limited (NEIL).
Under this insurance, if a nuclear generating facility suffers a loss due to a
prolonged accidental outage, the Utility may be subject to maximum retrospective
assessments of $15 million (property damage) and $4 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 $9.3 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 it has been or may be a potentially responsible party under the
Comprehensive Environmental Response, Compensation and Liability Act and similar
state environmental laws. These sites include former manufactured gas plant
sites, power plant sites, and sites used by it for the storage or disposal of
potentially hazardous materials. Under federal and California laws, it may be
responsible for remediation of hazardous substances, even if it 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 clean-up 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 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. At December 31, 1999, the Utility expects to spend $300 million
for hazardous waste remediation costs at identified sites, including
61
divested fossil-fueled power plants. The Utility had an accrued liability of
$271 million and $296 million at December 31, 1999 and 1998, respectively,
representing the discounted value of these costs.
Of the $271 million accrued liability discussed above, the Utility has
recovered $148 million through rates, including $34 million through
depreciation, and expects to recover another $95 million in future rates.
Additionally, the Utility is mitigating its costs by obtaining recovery of its
costs from insurance carriers and from other third parties as appropriate.
Environmental remediation at identified sites may be as much as
$486 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 clean-up costs at additional sites or outcomes change.
Further, as discussed in "Generation Divestiture" above, the Utility will
retain the pre-closing remediation liability associated with divested generation
facilities.
PG&E Corporation believes the ultimate outcome of these matters will not
have a material impact on its or the Utility's financial position or results of
operations.
LEGAL MATTERS
CHROMIUM LITIGATION:
Several civil suits are pending against the Utility in California state
court. The suits seek an unspecified amount of compensatory and punitive damages
for alleged personal injuries resulting from alleged exposure to chromium in the
vicinity of the Utility's gas compressor stations at Hinkley, Kettleman, and
Topock, California. Currently, there are claims pending on behalf of
approximately 900 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 adverse impact on its or the Utility's financial position or
results of operations.
TEXAS FRANCHISE FEE LITIGATION:
In connection with PG&E Corporation's acquisition of Valero Energy
Corporation, now known as PG&E Gas Transmission Texas (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 are in the
process of appealing the judgment.
In connection with the certification of a class in one of the class actions,
the court ordered notice to be sent to all potential class members and setting
an opt-out deadline of December 31, 1997. Notices were mailed to approximately
159 Texas cities. Fewer than 20 cities opted out by the deadline. In
November 1999, the court signed an order dismissing from the class 42 cities
because it determined there was no pipeline presence and no
62
past or present sales activity, leaving 106 cities in the class. The parties in
this class action are negotiating the terms of a settlement agreement. The
settlement proposal contemplates, among other things, that the PG&E Corporation
defendants would pay $12.2 million to the class cities, inclusive of attorney
fees, reduced by amounts attributable to opt-out cities. The defendants retain
the right to reject the settlement if the settlement proposal is not approved by
certain key cities and by 80% of the plaintiff class. Although a significant
number of the 106 cities in the plaintiff class already have either approved the
settlement or adopted resolutions to pass the ordinance, certain key cities have
not yet approved the settlement. The settlement is also subject to court
approval. On January 27, 2000, the court approved the settlement proposal and
established a 14-day period whether to accept the negotiated settlement terms or
opt out of the settlement. The Court also stated that if Corpus Christi does not
accept the settlement proposal, it will be placed in a sub-class, whose claims
will not be finalized as part of the settlement approval. Corpus Christi has the
right to opt out of this subclass.
PG&E Corporation believes that the ultimate outcome of these matters will
not have a material adverse impact on its financial position or its results of
operations. As discussed above in Note 5, in January 2000, PG&E Corporation's
National Energy Group signed a definitive agreement to sell the stock of PG&E
Gas Transmission, Texas Corporation and PG&E Gas Transmission Teco, Inc. The
buyer will assume all liabilities associated with the cases described above.
RECORDED LIABILITY FOR LEGAL MATTERS:
In accordance with SFAS No. 5, PG&E Corporation makes a provision for a
liability when both it is probable that a liability has been incurred and the
amount of the loss can be reasonably estimated. These provisions are reviewed
quarterly and adjusted to reflect the impacts of negotiations, settlements,
rulings, advice of legal counsel, and other information and events pertaining to
a particular case. In the fourth quarter of 1999, PG&E Corporation reduced the
amount of the recorded liability for legal matters associated with a court
approved settlement proposal and other settlement discussions of certain matters
described above. Approximately $55 million of the adjustments, arising from a
pre-acquisition contingency related to a purchased business, are reflected in
"Other income, net" in PG&E Corporation's Statement of Consolidated Income. The
following table reflects the current year's activity to the recorded liability
for legal matters:
PG&E
CORPORATION UTILITY
(IN MILLIONS) ----------- --------
Beginning Balance, January 1, 1999 $175 $ 52
Provisions for liabilities 16 14
Payments (41) (29)
Adjustments (44) 13
---- ----
Ending Balance, December 31, 1999: $106 $ 50
==== ====
NOTE 16: GENERAL RATE CASE
In December 1997, the Utility filed its 1999 application with the CPUC
During the GRC process, the CPUC examines the Utility's costs to determine the
amount the Utility may charge customers for base revenues (non-fuel related
costs). The Utility requested distribution revenue increases to maintain and
improve natural gas and electric distribution reliability, safety, and customer
service. The requested revenues, as updated, included an increase of $445
million in electric base revenues and an increase of $377 million in natural gas
base revenues over the 1998 authorized revenues.
The Utility received a final decision on its 1999 GRC application on
February 17, 2000. This final decision increased electric distribution revenues
by $163 million and gas distribution revenues by $93 million, as compared to
revenues authorized for 1998. This revenue increase is retroactive to
January 1, 1999. The impact of these increases resulted in an increase in
earnings of $153 million, or $0.42 per share, and was reflected in the fourth
quarter of 1999.
NOTE 17: SEGMENT INFORMATION
PG&E Corporation has identified four reportable operating segments. The
Utility is one reportable operating segment and the other three are part of PG&E
Corporation's National Energy Group. These four reportable operating segments
provide different products and services and are subject to different forms of
regulation or jurisdictions. PG&E Corporation's reportable segments are
described below.
63
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.
NATIONAL ENERGY GROUP:
The National Energy Group businesses develop, construct, operate, own, and
manage independent power generation facilities that serve wholesale and
industrial customers through PG&E Generating Company, LLC (formerly U.S.
Generating Company, LLC) and its affiliates (collectively, PG&E Gen); own and
operate natural gas pipelines, natural gas storage facilities, and natural gas
processing plants, primarily in the Pacific Northwest and in Texas, through
various subsidiaries of PG&E Corporation (collectively, PG&E Gas Transmission or
PG&E GT); and purchase and sell energy commodities and provide risk management
services to customers in major North American markets, including the other
National Energy Group non-utility businesses, unaffiliated utilities, marketers,
municipalities, and large end-use customers through PG&E Energy Trading--Gas
Corporation, PG&E Energy Trading--Power, L.P., and their affiliates
(collectively, PG&E Energy Trading or PG&E ET). In the fourth quarter of 1999,
PG&E Corporation's Board of Directors approved a plan for the divestiture of
PG&E Corporation's Texas natural gas and natural gas liquids business. Also in
the fourth quarter of 1999, PG&E Corporation's Board of Directors approved a
plan for the divestiture of PG&E Corporation's retail energy services, conducted
through PG&E ES. PG&E ES had total assets of $197 million, $202 million, and
$60 million, as of December 31, 1999, 1998, and 1997, respectively.
64
Segment information for the years 1999, 1998, and 1997 was as follows:
UTILITY NATIONAL ENERGY GROUP
-------- ----------------------------------------------------------
PG&E GT ELIMINATIONS &
(IN MILLIONS) PG&E GEN NW TEXAS PG&E ET OTHER TOTAL
1999
Operating revenues $ 9,084 $1,116 $ 172 $1,034 $9,404 $ 10 $20,820
Intersegment revenues(1) 144 6 52 114 1,117 (1,433) --
------- ------ ------ ------ ------ ------- -------
Total operating revenues 9,228 1,122 224 1,148 10,521 (1,423) 20,820
Depreciation, amortization and
decommissioning 1,564 89 41 75 9 2 1,780
Interest expense(2) (593) (63) (41) (59) (12) (4) (772)
Other income (expense) 11 61 21 53 3 6 155
Income taxes(3) 648 16 32 (407) (36) (5) 248
Income from continuing operations 763 97 68 (897) (34) 16 13
Capital expenditures 1,181 323 30 19 14 -- 1,567
Total assets at year-end(4) $21,470 $3,852 $1,160 $1,217 $1,876 $ (57) $29,518
1998
Operating revenues $ 8,919 $ 645 $ 185 $1,640 $8,183 $ 5 $19,577
Intersegment revenues(1) 5 4 52 301 326 (688) --
------- ------ ------ ------ ------ ------- -------
Total operating revenues 8,924 649 237 1,941 8,509 (683) 19,577
Depreciation, amortization and
decommissioning 1,438 52 39 65 5 3 1,602
Interest expense(2) (621) (43) (43) (77) (7) 10 (781)
Other income (expense) 76 18 3 13 5 (50) 65
Income taxes(3) 629 28 31 (47) (17) (13) 611
Income (loss) from continuing operations 702 106 65 (71) (6) (25) 771
Capital expenditures 1,396 98 49 39 12 1 1,595
Total assets at year-end(4) $22,950 $3,844 $1,169 $2,655 $2,555 $ (141) $33,032
1997
Operating revenues $ 9,495 $ 148 $ 186 $ 800 $4,613 $ 13 $15,255
Intersegment revenues(1) -- -- 47 204 195 (446) --
------- ------ ------ ------ ------ ------- -------
Total operating revenues 9,495 148 233 1,004 4,808 (433) 15,255
Depreciation, amortization and
decommissioning 1,748 19 38 33 3 10 1,851
Interest expense(2) (570) (5) (41) (26) (2) (20) (664)
Other income (expense) 94 (25) 1 13 3 126 212
Income taxes(3) 609 (17) 26 (8) (12) (33) 565
Income (loss) from continuing operations 735 (41) 40 (24) (19) 54 745
Capital expenditures 1,529 23 34 45 5 50 1,686
Total assets at year-end(4) $25,147 $ 989 $1,208 $2,800 $1,452 $ (541) $31,055
(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) Net interest expense incurred by PG&E Corporation is allocated to the
segments using specific identification.
(3) 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
National Energy Group.
(4) Assets of PG&E Corporation are included in "Eliminations & Other" column
exclusive of investment in its subsidiaries.
(5) Income from equity-method investees for 1999, 1998, and 1997 was
$61 million, $113 million, and $41 million, respectively, for PG&E Gen, and
none, $3 million, and $2 million, respectively, for PG&E GTT.
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NOTE 18: FAIR VALUE OF FINANCIAL INSTRUMENTS
PG&E Corporation estimates fair value of its financial instruments based on
quoted market prices, where available. Fair value of the Utility's rate
reduction bonds, and Utility obligated manditorily redeemable preferred
securities of trust holding solely Utility subordinated debentures are all
determined based on quoted market prices. Fair value of the Utility's preferred
stock with mandatory provisions is based on indicative market prices. Where
quoted or indicative market prices are not available, the estimated fair value
is determined using other valuation techniques (for example, the present value
of future cash flows). Most of PG&E Corporation's and the Utility's debt is
determined using quoted market prices, but the fair value of a small portion of
Utility debt is determined using the present value of future cash flows. The
carrying value of PG&E Corporation's short-term borrowings approximates fair
value.
At December 31, 1999 and 1998, PG&E Corporation's carrying amount and ending
fair value of its financial instruments are:
1999 1998
------------------- -------------------
CARRYING FAIR CARRYING FAIR
(IN MILLIONS) AMOUNT VALUE AMOUNT VALUE
PG&E Corporation:
Current price risk management assets (see Note 3) $ 607 $ 607 $1,416 $1,416
Noncurrent price risk management assets (see Note 3) 372 372 334 334
Current price risk management liabilities (see Note 3) 575 575 1,412 1,412
Noncurrent price risk management liabilities (see Note 3) 247 247 281 281
Total long-term debt(1) (see Note 8) 7,265 7,095 7,760 8,079
Utility:
Nuclear decommissioning funds noncurrent asset (see Note 11) 1,264 1,264 1,172 1,172
Total long-term debt(1) (see Note 8) 5,342 5,217 5,704 6,008
Rate reduction bonds(2) (see Note 9) 2,321 2,265 2,611 2,676
Preferred stock with mandatory redemption provisions (see
Note 7) 137 140 137 143
Utility obligated mandatorily redeemable preferred
securities of trust holding solely Utility subordinated
debentures (see Note 7) 300 267 300 303
(1) Total long-term debt includes current portion of long-term debt.
(2) Rate reduction bonds include current portion of rate reduction bonds.
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QUARTERLY CONSOLIDATED FINANCIAL DATA (UNAUDITED)
QUARTER ENDED
(IN MILLIONS, EXCEPT PER SHARE AMOUNTS) DECEMBER 31 SEPTEMBER 30 JUNE 30 MARCH 31
1999
PG&E CORPORATION
Operating revenues $4,795 $6,217 $4,682 $5,126
Operating income (loss)(1)(2)(3) (579) 516 480 461
Income (loss) from continuing operations (547) 197 196 167
Net income (loss)(1)(2)(3) (611) 185 182 171
Earnings (loss) per common share from continuing
operations, basic (1.49) 0.54 0.53 0.45
Earnings (loss) per common share from continuing
operations, diluted (1.49) 0.54 0.50 0.39
Dividends declared per common share 0.30 0.30 0.30 0.30
Common stock price per share
High 26.69 33.25 34.00 33.69
Low 20.25 25.00 30.56 29.50
UTILITY
Operating revenues $2,323 $2,587 $2,233 $2,085
Operating income(3) 633 486 452 422
Net income(3) 272 185 178 153
Income available for common stock 265 179 172 147
1998
PG&E CORPORATION
Operating revenues $5,364 $5,208 $4,695 $4,310
Operating income(1) 485 554 579 480
Income from continuing operations 208 225 188 150
Net income(1) 196 210 174 139
Earnings per common share from continuing
operations, basic and diluted 0.54 0.59 0.49 0.39
Dividends declared per common share 0.30 0.30 0.30 0.30
Common stock price per share
High 35.06 33.44 33.19 33.56
Low 30.38 29.88 30.06 29.06
UTILITY
Operating revenues $2,218 $2,563 $2,117 $2,026
Operating income 446 512 494 424
Net income 176 205 193 155
Income available for common stock 169 199 186 148
(1) In the fourth quarter 1999, the National Energy Group adopted a plan to
dispose of the PG&E ES segment. This planned transaction has been accounted
for as a discontinued operation. Results of operations of PG&E ES have been
excluded from continuing operations for all periods presented. The operating
loss and net loss of PG&E ES for the quarters ending March 31, June 30, and
September 30, 1999, were $15 million and $8 million, $23 million and
$14 million, and $20 million and $12 million, respectively. The operating
loss and net loss for PG&E ES for the quarters ending March 31, June 30, and
September 30, 1998, were $17 million and $11 million, $22 million and
$14 million, and $27 million and $15 million, respectively.
(2) Amounts have been restated to reflect the change in accounting for major
maintenance and overhauls at the National Energy Group (see Note 1 of the
Notes to Consolidated Financial Statements), and reclassification of PG&E ES
operating results to discontinued operations (see above). The accounting
change resulted in a cumulative effect being recorded as of January 1, 1999,
of $12 million ($0.03 per share), net of income taxes of $8 million.
Operating income previously reported for 1999 was $442 million,
$454 million, and $492 million for each of the first three quarters,
respectively. Net income previously reported for 1999 was $156 million
($0.42 per share), $180 million ($0.49 per share), and $183 million ($0.50
per share) for the same periods.
(3) In the fourth quarter 1999, the Utility recorded the effects of the outcome
of the GRC. This resulted in an increase of $256 million in operating income
and an increase of $153 million in net income. Additionally, the National
Energy Group recorded an after-tax charge of $890 million reflecting PG&E
GTT's assets at their fair market value. (See Notes 5 and 16 of the Notes to
Consolidated Financial Statements.)
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INDEPENDENT AUDITORS' REPORT
To the Boards of Directors and Shareholders of
PG&E Corporation and Pacific Gas and Electric Company
We have audited the accompanying consolidated balance sheets of PG&E
Corporation and subsidiaries and of Pacific Gas and Electric Company and
subsidiaries as of December 31, 1999, and the related statements of consolidated
income, cash flows, and common stock equity of PG&E Corporation and the related
statements of consolidated income, cash flows, and stockholders' equity of
Pacific Gas and Electric Company for the year then ended. These financial
statements are the responsibility of management of PG&E Corporation and of
Pacific Gas and Electric Company. Our responsibility is to express an opinion on
these financial statements based on our audits. The consolidated financial
statements for the years ended December 31, 1998 and 1997 were audited by other
auditors whose report, dated February 8, 1999, expressed an unqualified opinion
on those statements.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audits to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such 1999 financial statements present fairly, in all
material respects, the consolidated financial position of PG&E Corporation and
Pacific Gas and Electric Company as of December 31, 1999, and the results of
their consolidated operations and cash flows for the year then ended in
conformity with generally accepted accounting principles.
As discussed in Note 1 of the Notes to Consolidated Financial Statements, in
1999 PG&E Corporation changed its method of accounting for major maintenance and
overhauls.
DELOITTE & TOUCHE LLP
San Francisco, California
March 3, 2000
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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 1999 consolidated financial
statements have been audited by Deloitte & Touche LLP, PG&E Corporation's
independent auditors. The audit includes consideration of internal accounting
controls and performance of 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 Deloitte & Touche, jointly and
separately, to review internal accounting controls and auditing and financial
reporting matters. The internal auditors and Deloitte & Touche 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.
69