EXHIBIT 13
Portions of 2000 Annual Report to Shareholders
SELECTED FINANCIAL DATA
(in millions, except per share amounts) 2000 1999 1998 1997 1996
PG&E Corporation/(1)/
For the Year
Operating revenues $26,232 $20,820 $19,577 $15,255 $ 9,610
Operating income (loss) (4,807) 878 2,098 1,762 1,896
Income (Loss) from continuing operations (3,324) 13 771 745 722
Earnings (Loss) per common share from continuing operations,
basic and diluted (9.18) 0.04 2.02 1.82 1.75
Dividends declared per common share 1.20 1.20 1.20 1.20 1.77
At Year-End
Book value per common share $ 8.76 $ 19.13 $ 21.08 $ 21.30 $ 20.73
Common stock price per share 20.00 20.50 31.50 30.31 21.00
Total assets 35,291 29,470 33,234 31,115 26,237
Long-term debt (excluding current portions) 4,736 6,682 7,422 7,659 7,770
Rate reduction bonds (excluding current portions) 1,740 2,031 2,321 2,611 --
Redeemable preferred stock and securities of subsidiaries
(excluding current portion) 635 635 635 750 694
Pacific Gas and Electric Company
For the Year
Operating revenues $ 9,637 $ 9,228 $ 8,924 $ 9,495 $ 9,610
Operating income (loss) (5,201) 1,993 1,876 1,820 1,896
Income (Loss) available for common stock (3,508) 763 702 735 722
At Year-End
Total assets $21,988 $21,470 $22,950 $25,147 $26,237
Long-term debt (excluding current portion) 3,342 4,877 5,444 6,218 7,770
Rate reduction bonds (excluding current portion) 1,740 2,031 2,321 2,611 --
Redeemable preferred stock and securities (excluding current
portion) 586 586 586 694 694
(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 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 the
provision for loss on generation-related regulatory assets and
undercollected purchased power costs, discontinued operations, and the
cumulative effect of a change in accounting principle, are discussed in
Management's Discussion and Analysis and in the Notes to the Consolidated
Financial Statements.
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), delivers
electric service to approximately 4.6 million customers and natural gas service
to approximately 3.8 million customers. On April 6, 2001, the Utility filed a
voluntary petition for relief under the provisions of Chapter 11 of the U.S.
Bankruptcy Code. Pursuant to Chapter 11 of the U.S. Bankruptcy Code, the Utility
retains control of its assets and is authorized to operate its business as a
debtor in possession while being subject to the jurisdiction of the Bankruptcy
Court. The factors causing the Utility to take this action are discussed in this
Management's Discussion and Analysis (MD&A) and in Notes 2 and 3 of the Notes to
the Consolidated Financial Statements.
PG&E Corporation's National Energy Group, Inc. (the NEG) is an integrated
energy company with a strategic focus on power generation, new power plant
development, natural gas transmission, and wholesale energy marketing and
trading in North America. The NEG businesses include its power plant development
and generation unit, PG&E Generating Company, LLC and its affiliates
(collectively, PG&E Gen); its natural gas transmission unit, PG&E Gas
Transmission Corporation (PG&E GT); and its wholesale energy and marketing
trading unit, PG&E Energy Trading Holdings Corporation, which owns PG&E Energy
Trading--Gas Corporation, and PG&E Energy Trading--Power, L.P. (collectively,
PG&E Energy Trading or PG&E ET). During 2000, the NEG sold its energy services
unit, PG&E Energy Services Corporation (PG&E ES). Also, during the fourth
quarter of 2000, the NEG sold its Texas natural gas and natural gas liquids
business carried on through PG&E Gas Transmission, Texas Corporation and PG&E
Gas Transmission Teco, Inc. and their subsidiaries (PG&E GTT). For more
information about the NEG's businesses, see "PG&E National Energy Group, Inc."
below.
PG&E Corporation has identified five reportable operating segments. The
Utility is one reportable operating segment and the other four are part of the
NEG (PG&E Gen, PG&E Gas Transmission, Northwest Corporation (PG&E GTN), PG&E
GTT, and PG&E ET). During 2000, the NEG has been integrating these lines of
business into two lines of business: (1) an integrated power generation and
energy trading and marketing business, and (2) a natural gas transmission
business. Financial information about each reportable operating segment is
provided in this MD&A and in Note 16 of the Notes to the Consolidated Financial
Statements.
This is a combined annual report of PG&E Corporation and the Utility. 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 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
current expectations and 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.
Although PG&E Corporation and the Utility are not able to predict all of
the factors that may affect future results, some of the factors that could cause
future results to differ materially from those expressed or implied by the
forward-looking statements or historical results include:
. the reorganization plan that is ultimately adopted by the Bankruptcy
Court;
. the regulatory, judicial, or legislative actions (including ballot
initiatives) that may be taken to meet future power needs in
California, mitigate the higher wholesale power prices, provide
refunds for prior power costs, or address the Utility's financial
condition;
. the extent to which the Utility's undercollected wholesale power
purchase costs may be collected from customers;
. any changes in the amount of transition costs the Utility is allowed
to collect from its customers, and the timing of the completion of the
Utility's transition cost recovery;
. future market prices for electricity and future fuel prices, which in
part, are influenced by future weather conditions, the availability of
hydroelectric power, and the development of competitive markets;
. the method and timing of valuation of the Utility's hydroelectric
generation assets;
. future operating performance at the Diablo Canyon Nuclear Power Plant
(Diablo Canyon) and the future ratemaking applicable to Diablo Canyon;
. legislative or regulatory changes, including the pace and extent of
the ongoing restructuring of the electric and natural gas industries
across the United States;
. future sales levels and economic conditions;
. 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 outcome of the Utility's various regulatory proceedings;
. fluctuations in commodity gas, natural gas liquids, and electric
prices and the ability to successfully manage such price fluctuations;
. the effect of compliance with existing and future environmental laws,
regulations, and policies, the cost of which could be significant; and
. the outcome of pending litigation.
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 the California energy crisis and its impact
on our liquidity. We then discuss statements of cash flows and financial
resources, and our results of operations for 2000, 1999, and 1998. Finally, we
discuss our competitive and regulatory environment, our risk management
activities, and various uncertainties that could affect future earnings. Our
MD&A applies to both PG&E Corporation and the Utility.
LIQUIDITY AND FINANCIAL RESOURCES
The California Energy Crisis
The state of California is in the midst of an energy crisis. The cost of
wholesale power has risen to levels almost ten times greater than those in 1999.
Rolling blackouts have occurred as a result of a broken deregulated electricity
market. Because of this crisis, PG&E Corporation and the Utility have
experienced a significant deterioration in their liquidity and consolidated
financial position. The Utility's credit rating has deteriorated to below
investment grade level. As of March 29, 2001, the Utility is in default or has
not paid amounts due under various bank agreements, commercial paper, and
payments to the California Power Exchange (PX), the California Independent
System Operator (ISO), qualifying facilities (QFs), and energy service providers
totaling over $4 billion. In addition, PG&E Corporation and the Utility
recognized a fourth quarter charge to earnings of $6.9 billion ($4.1 billion
after tax) to reflect the fact that the Utility could no longer conclude that
its generation-related regulatory assets and undercollected purchased power
costs were probable of recovery from ratepayers. This charge resulted in
accumulated deficits at December 31, 2000, of $2.0 billion and $2.1 billion for
the Utility and PG&E Corporation, respectively.
As more fully discussed herein, the Utility has been working with
regulators and state and federal legislators and California leaders in an effort
to seek an overall solution to the California energy crisis. However, the
ongoing uncertainty as to the timing and extent of any solution, in addition to
increasing debt and regulatory changes, caused the Utility to seek protection
from its creditors through a Chapter 11 Bankruptcy Filing. The filing for
bankruptcy protection and the related uncertainty around any reorganization
plan, that is ultimately adopted, will have a significant impact on the
Utility's future liquidity and results of operations. In addition to the $4
billion of defaults and amounts not paid mentioned
above, the Utility anticipates an aggregate of approximately $1.5 billion of
additional obligations that will become due and payable in April 2001. As of
March 29, 2001, the Utility had $2.6 billion of cash available to fund
operations.
See Notes 2 and 3 of the Notes to the Consolidated Financial Statements for
a detailed discussion of the California energy crisis and the events leading up
to the charge incurred by PG&E Corporation and the Utility. A discussion of the
current and future liquidity and financial resources, and mitigation efforts
undertaken by the Utility and PG&E Corporation follows.
Pacific Gas and Electric Company
The California energy crisis described in Note 2 of the Notes to the
Consolidated Financial Statements has had a significant negative impact on the
liquidity and financial resources of the Utility. Beginning in June 2000, the
wholesale price of electric power in California steadily increased to an average
cost of 18.16 cents per kilowatt-hour (kWh) for the seven month period of June
2000 through December 2000, as compared to an average cost of 4.23 cents per kWh
for the same period in 1999. Under California Assemby Bill 1890 (AB 1890), the
Utility's electric rates were frozen at levels that allowed approximately 5.4
cents per kWh to be charged to the Utility's customers as reimbursement for
power costs incurred by the Utility on behalf of its retail customers. The
excess of wholesale electricity costs above the generation-related cost
component available in frozen rates resulted in an undercollection at December
31, 2000, of approximately $6.6 billion, and rose to approximately $8.9 billion
by February 28, 2001.
The difference between the actual costs incurred to purchase power and the
amount recovered from customers was funded through a series of borrowings. In
October 2000, the Utility fully utilized its existing $1 billion revolving
credit facility to support the Utility's commercial paper program and other
liquidity requirements. On October 18, 2000, the Utility obtained an additional
$1 billion, 364-day revolving credit facility. On November 1, 2000, the Utility
issued $1 billion of short-term floating rate notes and $680 million of five-
year notes. On November 22, 2000, the Utility issued an additional $240 million
of short-term floating rate notes. On December 1, 2000, the bank group reduced
the size of the $1 billion, 364-day revolving credit facility to $850 million.
At December 31, 2000, the Utility had borrowed $614 million against its five-
year revolving credit agreement, had issued $1,225 million of commercial paper,
and had issued $1,240 million of floating rate notes.
In late 2000, the Utility began to implement cash conservation measures
that included layoffs of 1,000 temporary workers, suspension of dividend
payments, and deferral of merit increases and incentive compensation for
employees. Also, federal and state legislators and regulators recognized that
the wholesale power market was seriously flawed and they began seeking solutions
to the California energy crisis.
In response to the growing crisis, on January 4, 2001, the California
Public Utilities Commission (CPUC) approved an interim one-cent per kWh rate
increase, which would raise approximately $70 million in cash per month for
three months. Even if all this cash had been available to the Utility
immediately, $210 million represented approximately one week's worth of net
power purchases at the then current prices. Thus, the rate increase did not
raise enough cash for the Utility to pay its ongoing wholesale electric energy
procurement bills or make further borrowing possible.
On January 10, 2001, the Board of Directors of the Utility suspended the
payment of its fourth quarter 2000 common stock dividend in an aggregate amount
of $110 million payable on January 15, 2001, to PG&E Corporation and PG&E
Holdings, Inc., a wholly-owned subsidiary of the Utility. In addition, the
Utility's Board of Directors decided not to declare the regular preferred stock
dividends for the three-month period ending January 31, 2001, normally payable
on February 15, 2001. Dividends on all Utility preferred stock are cumulative.
Until cumulative dividends on preferred stock are paid, the Utility may not pay
any dividends on its common stock, nor may the Utility repurchase any of its
common stock.
On January 16 and 17, 2001, the outstanding bonds of the Utility were
downgraded to below investment grade status. Standard and Poor's (S&P) stated
that the downgrade reflected the heightened probability of the Utility's
imminent insolvency and the resulting negative financial implications for PG&E
Corporation and affiliated companies because, among other reasons, (1) some of
the Utility's principal trade creditors were demanding that sizeable cash
payments be made as a pre-condition to the purchase of natural gas and electric
power necessary for on-going business operations; (2) neither legislative nor
negotiated solutions to the California utilities' financial situation appeared
to be forthcoming in a timely manner, which continued to impede access to
financial markets for the working capital needed to avoid insolvency; and (3)
Southern California Edison's (SCE) decision to default on its obligation to pay
principal and interest due on January 16, 2001, diminished the prospects for the
Utility's access to capital markets.
This downgrade to below investment grade status was an event of default
under one of the Utility's revolving credit facilities and precluded the Utility
from access to the capital markets. As a result, the banks stopped funding under
the revolving credit facility. On January 17, 2001, the Utility began to default
on maturing commercial paper obligations. In addition, the Utility was no longer
able to meet its obligations to generators, QFs, the ISO, and PX, and began
making partial payments of amounts owed.
The Utility's credit ratings as of March 29, 2001, are as follows:
Corporate credit rating: D/D
Commercial paper: D
Senior secured debt: CCC
Senior unsecured debt: CC
Preferred stock: D
Shelf senior secured/unsecured subordinated debt: CCC/CC
Shelf debt preferred stock: D
After the downgrade, the PX notified the Utility that the ratings downgrade
required the Utility to post collateral for all transactions in the PX day-ahead
market. Since the Utility was unable to post such collateral, the PX suspended
the Utility's trading privileges effective January 19, 2001, in the day-ahead
market. The PX also sought to liquidate the Utility's block-forward contracts
for the purchase of power. On January 25, 2001, a California Superior Court
judge granted the Utility's application for a temporary restraining order, which
thereby restrained and enjoined the PX and its agents from liquidating the
Utility's contracts in the block-forward market, pending hearing on a
preliminary injunction on February 5, 2001. Immediately before the hearing on
the preliminary injunction, California Governor Gray Davis, acting under
California's Emergency Services Act, commandeered the contracts for the benefit
of the state. Under the Act, the state must pay the Utility the reasonable value
of the contracts, although the PX may seek to recover the monies that the
Utility owes to the PX from any proceeds realized from those contracts.
Discussions and negotiations on this issue are currently ongoing between the
state and the Utility.
On January 19, 2001, the Utility was no longer able to continue purchasing
power for its customers because of a lack of creditworthiness and the state of
California authorized the California Department of Water Resources (DWR) to
purchase electricity for the Utility's customers. Assembly Bill 1X (AB1X) was
passed on February 1, 2001, authorizing the DWR to enter into contracts for the
purchase and sale of electric power and to issue revenue bonds to finance
electricity purchases. The DWR has entered into long-term contracts with several
generators for the supply of electricity. However it continues to purchase
significant amounts of power on the spot market at prevailing market prices. The
DWR is not purchasing electricity for the Utility's entire net open position
(the amount of power that cannot be met by the Utility's own or contracted-for
generation). To the extent that the DWR is not purchasing electricity for the
entire net open position, the remainder is being procured by the ISO. To that
extent, the ISO may attempt to charge the Utility for those purchases.
As a result of (1) the failure by the state to assume the full procurement
responsibility for the Utility's net open position, as was provided under AB1X,
(2) the negative impact of recent actions by the CPUC that created new payment
obligations for the Utility and undermined its ability to return to financial
viability, (3) a lack of progress in negotiations with the state to provide a
solution for the energy crisis, and (4) the adoption by the CPUC of an illegal
and retroactive accounting change that would appear to eliminate the Utility's
true undercollected purchased power costs, the Utility filed a voluntary
petition for relief under provisions of Chapter 11 of the U.S. Bankruptcy Code
on April 6, 2001.
As of March 29, 2001, the Utility was in default and had not paid the
following:
Amount
Description (in millions)
----------- ------------
Items not paid
PX/ISO--real time market deliveries $1,448
Qualifying facilities 643
Direct access credits due to energy service providers 503
Commercial paper 861
Bank loans 939*
Other 26
Total Items Not Paid $4,420
Items coming due through April 30, 2001
PX/ISO--real time market deliveries $ 550
Qualifying facilities 340
Gas suppliers 470
Other 140
Total coming due $1,500
Total cash on hand at March 29, 2001 $2,600
*Loans that lenders have agreed to forbear through April 13, 2001.
Additionally, the Utility may be required by the CPUC to pay the DWR for
purchases that it has made on behalf of the Utility's customers. As discussed
further in Note 2 of the Notes to the Consolidated Financial Statements, there
is a dispute over how much the Utility must pay the DWR. Also, the DWR has
indicated that it intends to purchase power only at "reasonable prices." The ISO
has continued to purchase power at prices in excess of the DWR's as yet
undisclosed ceiling and has been billing the Utility for the differential. The
Utility does not yet know what the total expected billing is for these
purchases.
Subject to certain qualifications, the banks under the Utility's $1 billion
revolving credit agreement agreed to forbear from exercising any remedies with
respect to the Utility's default under that agreement until April 13, 2001.
Subject to the approval by the Bankruptcy Court, the Utility's intent is to
pay its ongoing costs of doing business while seeking resolution of the
wholesale energy crisis. It is the Utility's intention to continue to pay
employees, vendors, suppliers, and other creditors to maintain essential
distribution and transmission services. However, the Utility is not in a
position to pay maturing or accelerated obligations, nor is the Utility in a
position to pay the ISO, PX, and the QFs the amounts due for the Utility's power
purchases above the amount included in rates for power purchase costs. The
Utility's current actions are intended to allow the Utility to continue to
operate while efforts to reach a regulatory or legislative solution continue.
The Utility's plans will be subject to approval of the Bankrupcy Court.
The Utility has also deferred quarterly interest payments on the Utility's
7.90% Deferrable Interest Subordinated Debentures, Series A, due 2025, until
further notice in accordance with the indenture. The corresponding quarterly
payments on the 7.90% Cumulative Quarterly Income Preferred Securities, Series
A, (QUIPS) issued by PG&E Capital I, due on April 2, 2001, have been similarly
deferred. Distributions can be deferred up to a period of five years per the
indenture. Investors will accumulate interest on the unpaid distributions at the
rate of 7.90%.
The weakened financial condition of the Utility also has impacted its
ability to supply natural gas to its natural gas customers. In December 2000 and
January 2001, several gas suppliers demanded prepayment, cash on delivery, or
other forms of payment assurance before they would deliver gas, instead of the
normal payment terms, under which the Utility would pay for the gas after
delivery. As the Utility was unable to meet such demands at that time, several
gas suppliers refused to supply gas, accelerating the depletion of the Utility's
gas storage reserves and potentially exacerbating the electric power crisis if
the Utility were required to divert gas from industrial users, including natural
gas fired power plant operators.
The U.S. Secretary of Energy issued a temporary order on January 19, 2001,
requiring the gas suppliers to continue to make deliveries to avoid a worsening
natural gas shortage emergency. However, this order expired on February 7, 2001,
and certain companies, representing about 10% of the Utility's natural gas
suppliers, terminated deliveries after the order expired.
The Utility tried to mitigate the worsening supply situation by withdrawing
more gas from storage and, when able, purchasing additional gas on the spot
market. Additionally, on January 31, 2001, the CPUC authorized the Utility to
pledge its gas account receivables and its gas inventories for up to 90 days
(extended to 180 days in a CPUC draft decision issued on February 15, 2001) to
secure gas for its core customers. At March 29, 2001, the amount of gas accounts
receivables pledged was approximately $900 million. As of March 29, 2001,
approximately 30% of the Utility's suppliers of natural gas had signed security
agreements with the Utility and discussions were continuing with the Utility's
other
suppliers. Additionally, the Utility is currently implementing a program to
obtain longer-term summer and winter supplies and daily spot supplies.
PG&E Corporation
The liquidity and financial condition crisis faced by the Utility also
negatively impacted PG&E Corporation. Through December 31, 2000, PG&E
Corporation funded its working capital needs primarily by drawing down on
available lines of credit and other short-term credit facilities. At December
31, 2000, PG&E Corporation had borrowed $185 million against its five-year
revolving credit agreement and had issued $746 million of commercial paper. Due
to the credit ratings downgrades of PG&E Corporation, the banks refused any
additional borrowing requests and terminated their remaining commitments under
existing credit facilities. Commencing January 17, 2001, PG&E Corporation began
to default on its maturing commercial paper obligations.
Commencing on March 2, 2001, PG&E Corporation refinanced its debt
obligations with $1 billion in aggregate proceeds of two term loans under a
common credit agreement with General Electric Capital Corporation and Lehman
Commercial Paper Inc. In accordance with the credit agreement, the proceeds,
together with other PG&E Corporation cash, were used to pay $501 million in
commercial paper (including $457 million of commercial paper on which PG&E
Corporation had defaulted), $434 million in borrowings under PG&E Corporation's
long-term revolving credit facility, and $116 million to PG&E Corporation
shareholders of record as of December 15, 2000, in satisfaction of a defaulted
fourth quarter 2000 dividend. Further, approximately $85 million was used to
pre-pay the first year's interest under the credit agreement and to pay
transaction expenses associated with the debt restructuring. See Note 3 of the
Notes to the Consolidated Financial Statements for a detailed description of the
loan.
On March 15, 2001, PG&E Corporation's corporate credit rating was withdrawn
by S&P due to the March 2, 2001, refinancing of its obligations and the fact
that PG&E Corporation had no more public debt to be rated.
PG&E Corporation itself had cash of $297 million at March 29, 2001, and
believes that the funds will be adequate to maintain its continuing operations
throughout 2001. In addition, PG&E Corporation believes that the holding company
and its non-CPUC regulated subsidiaries are protected from the bankruptcy of the
Utility.
PG&E National Energy Group
In December 2000, and in January and February 2001, PG&E Corporation and
the NEG undertook a corporate restructuring of NEG, known as a "ringfencing"
transaction. The ringfencing complied with credit rating agency criteria,
enabling the NEG, PG&E GTN, and PG&E ET to receive or retain their own credit
ratings based on their own creditworthiness. The ringfencing involved the
creation or use of special purpose entities (SPEs) as intermediate owners
between PG&E Corporation and its non-CPUC regulated subsidiaries. These SPEs
are: PG&E National Energy Group, LLC, which owns 100% of the stock of the NEG;
PG&E GTN Holdings LLC which owns 100% of the stock of PG&E GTN; and PG&E Energy
Trading Holdings LLC, which owns 100% of the stock of PG&E Corporation's energy
trading subsidiaries, PG&E Energy Trading-Gas Corporation, PG&E Energy Trading
Holdings Corporation, and PG&E Energy Trading-Power, L.P. In addition, the NEG's
organizational documents were modified to include the same structural elements
as the SPEs to meet credit rating agency criteria. Ringfencing is intended to
reduce the likelihood that the assets of the ringfenced companies would be
substantively consolidated in a bankruptcy proceeding involving such companies'
ultimate parent, and to thereby preserve the value of the "protected" entities
as a whole. The SPEs require unanimous approval of their respective boards of
directors, including an independent director, before they can (a) consolidate or
merge with any entity, (b) transfer substantially all of their assets to any
entity, or (c) institute or consent to bankruptcy, insolvency, or similar
proceedings or actions. The SPEs may not declare or pay dividends unless the
respective board of directors has unanimously approved such action and the
company meets specified financial requirements.
STATEMENTS OF CASH FLOWS FOR 2000, 1999, AND 1998
PG&E Corporation normally funds 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.
PG&E Corporation Consolidated
Cash Flows from Operating Activities
Net cash (used) provided by PG&E Corporation's operating activities totaled
$(776) million, $2,155 million, and $3,388 million in 2000, 1999, and 1998,
respectively. The decrease of $2,931 million between 1999 and 2000 is
attributable to the California energy crisis previously discussed.
Cash Flows from Investing Activities
During 2000, 1999, and 1998, PG&E Corporation used $1.8 billion, $1.6
billion, and $1.6 billion, respectively, for upgrades and expansion of its
facilities in operation or under construction. These capital expenditures were
partially offset by the 1999 and 1998 divestitures of generation facilities at
the Utility and by the completed sales of the PG&E ES and PG&E GTT business
units in 2000. In 2000, PG&E Corporation sold its Energy Services retail
business for $85 million and its value-added-services business and various other
assets for $18 million. The NEG received $306 million, which included a working
capital adjustment for the sale of PG&E GTT. The sale also included the
assumption of liabilities associated with PG&E GTT and debt having a book value
of $564 million. In 1999 and 1998, the Utility received proceeds of $1,014
million and $501 million, respectively, from the sale of generation facilities.
In 1998, PG&E Corporation sold its Australian energy holdings for proceeds of
approximately $126 million, and the NEG sold its Bear Swamp facility for $479
million.
Cash Flows from Financing Activities
As of March 29, 2001, PG&E Corporation, itself, had $297 million in cash on
hand and had successfully refinanced its obligations that were in default. (See
previous discussion of PG&E Corporation's refinancing.) Net cash provided by
financing activities in 2000 totaled $2.4 billion, principally through
borrowings under credit facilities and issuances of short-term and long-term
debt needed to fund energy purchases. Net cash used by financing activities in
1999 and 1998 totaled $2.0 billion and $1.1 billion, respectively, and was used
principally to retire debt, repurchase outstanding common stock, and pay
dividends.
During 2000, 1999, and 1998, PG&E Corporation issued $65 million, $54
million, and $63 million of common stock, respectively, primarily through the
Dividend Reinvestment Plan and the stock option plan component of the Long-Term
Incentive Program. During 2000, 1999, and 1998, PG&E Corporation declared
dividends on its common stock of $434 million, $460 million, and $466 million,
respectively.
During 2000, 1999, and 1998, PG&E Corporation repurchased $2 million, $693
million, and $1,158 million of its common stock, respectively, primarily 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, PG&E Corporation 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, PG&E Corporation used this remaining
authorization to purchase 16.6 million shares at a total cost of $531 million. A
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 PG&E
Corporation's common stock on the open market. This authorization supplemented
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
its wholly owned subsidiary, PG&E Corporation repurchased an additional 7.2
million shares, at a cost of $159 million under this authorization. At December
31, 2000, the remainder under the share repurchase authorization is
approximately $380 million. PG&E Corporation is precluded by its March 2, 2001,
loan agreement with General Electric Capital Corporation and Lehman Commercial
Paper Inc. from repurchasing its common stock until the loan is repaid.
Utility
The following section discusses the Utility's significant cash flows from
operating, investing, and financing activities for the three year period ended
December 31, 2000.
Cash Flows from Operating Activities
Net cash (used) provided by the Utility's operating activities totaled
$(699) million, $2,196 million, and $3,736 million in 2000, 1999, and 1998,
respectively. The decrease of $2,895 million between 1999 and 2000 is
attributable to the California energy crisis and the significant deterioration
of the Utility's financial condition reflected by the deferred electric
procurement costs of $6,465 million which have not yet been recovered from
ratepayers and which were determined not to be probable of recovery through
regulated rates and recognized as a charge to earnings in the fourth quarter
2000.
Cash Flows from Investing Activities
The primary uses of cash for investing activities are additions to
property, plant, and equipment. The Utility's capital expenditures were $1,245
million, $1,181 million, and $1,382 million, for the years ended December 31,
2000, 1999, and 1998, 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.
Cash Flows from Financing Activities
In April 2000, a subsidiary of the Utility repurchased from PG&E
Corporation 11.9 million shares of its common stock at a cost of $275 million.
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. These repurchases are reflected as stock held by subsidiary in the
Consolidated Balance Sheet of the Utility. Earlier in 1999, the Utility
repurchased from PG&E Corporation, 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 2000, 1999, and 1998, the Utility
paid dividends on its common and preferred stock of $475 million, $440 million,
and $444 million, respectively.
The Utility's long-term debt that either matured, was redeemed, or was
repurchased during 2000 totaled $597 million. Of this amount, (1) $110 million
related to the maturity of its 6.63%, and 6.75% mortgage bonds due June 1, and
December 1, 2000, (2) $81 million related to the Utility's repurchase of various
pollution control loan agreements, (3) $113 million related to the maturity of
the Utility's various medium term notes, (4) $3 million related to the other
scheduled maturities of long-term debt, and (5) $290 million related to maturity
of rate reduction bonds.
The Utility's long-term debt that either matured, was redeemed, or was
repurchased during 1999 totaled $672 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) $100
million related to the maturities and redemption of various of the Utility's
medium-term notes and other debt. During 2000 and 1999, the Utility did not
redeem or repurchase any of its preferred stock.
On November 1, 2000, the Utility issued $680 million of five-year, fixed-
rate notes and $1,000 million of 364-day floating rate notes. On November 22,
2000, the Utility issued $240 million in floating rate notes.
PG&E National Energy Group
The California energy crisis has impacted the funding available for new
projects at the NEG. The NEG undertook a ringfencing strategy to facilitate
access to capital markets and insulate the NEG's assets from the risk of
bankruptcy at the Utility. The refinancing of PG&E Corporation's debts on March
2, 2001, further insulates NEG from the risk of bankruptcy at the Utility.
General
Historically, the NEG has obtained cash from operations, borrowings under
credit facilities, non-recourse project financing and other issuances of debt,
issuances of commercial paper, and borrowings and capital contributions from
PG&E Corporation. These funds have been used to finance operations, service debt
obligations, fund the acquisition, development, and/or construction of
generating facilities, and to start-up other businesses, finance capital
expenditures, and meet other cash and liquidity needs.
The projects that the NEG develops typically require substantial capital
investment. Some of the projects in which the NEG has an interest have been
financed primarily with non-recourse debt that is repaid from the project's cash
flows. This debt is often secured by interests in the physical assets, major
project contracts and agreements, cash accounts, and, in some cases, the
ownership interest in that project subsidiary. These financing structures are
designed to ensure that the NEG is not contractually obligated to repay the
project subsidiary's debt; that is, they are "non-recourse" to the NEG and to
its subsidiaries not involved in the project. However, the NEG has agreed to
undertake financial support for some of its project subsidiaries in the form of
limited obligations and contingent liabilities such as guarantees of specified
obligations. To the extent the NEG becomes liable under these guarantees or
other agreements in respect of a particular project, it may have to use
distributions it receives from other projects to satisfy these obligations.
Cash Flows from Operating Activities
Cash flow (used by) generated from operations totaled $(77) million, $(41)
million, and $(348) million for the years ended December 31, 2000, 1999, and
1998, respectively. The decrease in cash flows for 2000 compared to 1999 of $36
million is attributable to increases in working capital required to support the
expanded energy trading operations and a decrease in depreciation expense as a
result of the impairment of PG&E GTT assets in 1999. The increase in cash flows
generated from operations in 1999 as compared to 1998 of $307 million is due
principally to the increase in earnings, excluding the non-cash charge to
reflect impairment of the investment in PG&E GTT; an increase in working capital
balances of approximately $53 million; realization of gains in energy contracts
accounted for on a mark-to-market basis; and increases in the non-cash charges,
such as depreciation and the deferred tax provision, partially offset by the
increase in the amortization of out-of-market contractual obligations and an
increase in capitalized development costs.
Cash Flows from Investing Activities
The NEG recognized $65 million, $63 million, and $113 million in earnings
on investments, which are accounted for using the equity method for 2000, 1999
and 1998, respectively. The NEG received cash distributions from these
investments totaling approximately $104 million, $66 million and $69 million
during 2000, 1999 and 1998, respectively.
Four natural gas-fueled combined-cycle power plants are currently under
construction, which when completed will be owned or leased by the NEG. 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-megawatt (MW) power plant located in Massachusetts,
is scheduled to begin commercial service in 2001. Lake Road Generating Plant
(Lake Road), an approximately 780-MW power plant located in Connecticut, is
scheduled to begin commercial service in 2001. La Paloma Generating Plant, an
approximately 1,050-MW power plant, is located in California, and is scheduled
to begin commercial service in 2002. Lake Road and La Paloma are being financed
through a synthetic lease with a third-party owner. PG&E Gen will operate the
plant under operating leases. See Note 14 of the Notes to the Consolidated
Financial Statements. The estimated cost to construct these plants is
approximately $1.4 billion.
In October 2000, the NEG completed construction on an 11.5 MW wind project
that is the largest wind generating facility in the Eastern United States for a
total cost of $16 million.
In September 2000, the NEG purchased the Attala Generating Plant for $311
million. The seller is obligated to deliver a fully operating facility by July
1, 2001. Attala is a 500 MW natural gas-fired combined-cycle project, located in
Mississippi.
The NEG used $1.3 billion in cash for its investing activities in 1998.
During 1998, through its indirect subsidiary USGenNE, the NEG completed the
acquisition of a portfolio of electric generating assets and power supply
contracts from New England Electric System (NEES). The funding requirements for
this acquisition were $1,746 million and included the acquisition of (1)
electric generating assets classified as property, plant, and equipment; (2)
receivable for support payments of approximately $800 million; and (3)
approximately $1,300 million of contractual obligations.
The NEES assets include hydroelectric, coal, oil, and natural gas -fueled
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 ten years
to USGenNE for the purchase power agreements, and (2) require that USGenNE
provide electricity to NEES under contracts that expire over the next six to
eleven years.
In 1998, the NEG spent approximately $220 million on development and
construction activities. Also in 1998, the NEG entered into a sale/leaseback
transaction whereby it sold and leased back its Bear Swamp facility, comprised
of the Bear Swamp pumped storage station and the Fife Brook station, to a third
party. This transaction generated cash proceeds of $479 million. Finally in
1998, the NEG completed the sale of its Australian energy holdings for proceeds
of approximately $126 million, and executed some portfolio management
transactions, which generated cash proceeds of approximately $22 million.
Cash Flows from Financing Activities
The NEG maintains $1,350 million in five revolving credit facilities, which
support commercial paper and Eurodollar borrowing arrangements. At December 31,
2000 and 1999, the NEG had total outstanding balances related to such borrowings
of $1,181 million and $1,173 million, respectively. In addition, certain letters
of credit held by the NEG reduce the available outstanding facility commitments.
At December 31, 2000, approximately $36 million of letters of credit were
outstanding under these facilities. Since the NEG has the ability and intent to
refinance certain borrowings, $661 million and $649 million of such borrowings
are classified as long-term debt as of December 31, 2000 and 1999, respectively.
The remaining outstanding balances are classified as short-term borrowings in
the Consolidated Balance Sheets of PG&E Corporation.
Capital Requirements
The table below provides information about PG&E Corporation's capital
requirements at December 31, 2000:
Expected maturity date 2001 2002 2003 2004 2005 Thereafter
- ---------------------- ---- ---- ---- ---- ---- ----------
(dollars in millions)
Utility:
Capital spending $1,505
Long-term debt
Variable rate obligations $ 120 $ 697 $ 350 $ 40 $ 40 $ 20
Fixed rate obligations $ 274 $ 379 $ 354 $ 392 $1,012 $ 2,038
Average interest rate 8.0% 7.8% 6.3% 6.4% 6.9% 7.3%
Rate reductions bonds $ 290 $ 290 $ 290 $ 290 $ 290 $ 580
Average interest rate 6.2% 6.3% 6.4% 6.4% 6.4% 6.4%
National Energy Group:
Capital spending $2,445
Long-term debt
Variable rate obligations $ 16 $ 94 $ 584 $ 9 $ 9 $ 80
Fixed rate obligations $ 1 $ 34 $ 7 $ 1 $ 251 $ 325
Average interest rate 9.4% 6.9% 7.0% 9.4% 7.1% 8.9%
RESULTS OF OPERATIONS
In this section, we discuss the operations of the NEG and present the
components of our results of operations for 2000, 1999, and 1998. The table
below shows for 2000, 1999, and 1998, certain items from our Statement of
Consolidated Operations detailed by Utility and the NEG 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) includes the appropriate intercompany elimination. Following this table
we discuss our results of operations.
National Energy Group
The NEG has been formed to pursue opportunities created by the gradual
restructuring of the energy industry across the nation. The NEG integrates our
national power generation, gas transmission, and energy trading businesses. The
NEG contemplates increasing PG&E Corporation's national market presence through
a balanced program of development, acquisition, and contractual control of
energy assets and businesses, while at the same time undertaking ongoing
portfolio management of its assets and businesses. The NEG's ability to
anticipate and capture profitable business opportunities created by industry
restructuring will have a significant impact on PG&E Corporation's future
operating results.
Power Generation
We participate in the development, 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
NEES. The purchased assets include hydroelectric, coal, oil, and natural gas-
fueled generation facilities with a combined generating capacity of about 4,000
MW.
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 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 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. For the years ended December 31, 2000
and 1999, the SOS price paid to generators was $0.043 and $0.035 per kWh for
generation, respectively.
Like other utilities, New England utilities previously entered into
agreements with unregulated companies (e.g., qualifying facilities under Public
Utilities Regulatory Policies Act (PURPA)) to provide energy and capacity at
prices that are anticipated to be in excess of market prices. The NEG assumed
NEES' contractual rights and duties under several of these power purchase
agreements. At December 31, 2000, these agreements provided for an aggregate 470
MW of capacity. NEES will make support payments to us toward the cost of these
agreements. The remaining support payments by NEES total $0.8 billion in the
aggregate (undiscounted) and are due in monthly installments through January
2008. In certain circumstances, with our consent, NEES may make a full or
partial lump sum accelerated payment.
Currently, approximately 60% to 70% of the capacity is dedicated to serving
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 continue to 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
The NEG, through PG&E GTN, owns and operates gas transmission pipelines and
associated facilities, subject to regulation by the Federal Energy Regulatory
Commission (FERC). The pipeline and associated facilities extend over 612 miles
from the Canada-U.S. border to the Oregon-California border. PG&E GTN provides
firm and interruptible transportation services to third-party shippers on an
open-access basis. Its customers are principally retail gas distribution
utilities, electric generators that use natural gas to generate electricity,
natural gas marketing companies that purchase and resell natural gas to
utilities and end-use customers, natural gas producers, and industrial
consumers.
On January 27, 2000, PG&E Corporation 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 GTT. Given the
terms of the sales agreement, in 1999, PG&E Corporation recognized a charge
against pre-tax earnings of $1,275 million, to reflect PG&E GTT's assets at
their fair value.
On December 22, 2000, after receipt of governmental approvals, PG&E
Corporation completed the stock sale. The sales agreement had a provision, which
included a sales price adjustment for changes in working capital from December
31, 1999 to closing. The total consideration received was $456 million, which
includes the working capital adjustment, less $150 million used to retire the
PG&E GTT short-term debt, and the assumption by El Paso of PG&E GTT long-term
debt having a book value of $565 million. In December 2000, PG&E Corporation
recorded income of approximately $20 million reflecting the sales price true-up.
Energy Trading
The NEG's trading businesses purchase bulk volumes of power and natural gas
from the NEG's affiliates and the wholesale market. The NEG then transports and
resells these commodities, either directly to third parties or to other PG&E
Corporation affiliates. The NEG also provides risk management services to other
NEG businesses and to wholesale customers. (See "Price Risk Management
Activities" below; and Note 4 of the Notes to the 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. The disposal
has been accounted for as a discontinued operation, and PG&E Corporation's
investment in PG&E ES was written down to its then estimated net realizable
value. In addition, PG&E Corporation provided a reserve for anticipated losses
through the anticipated date of sale. The total provision for discontinued
operations was $58 million, net of income taxes of $36 million. Of this amount,
$33 million (net of taxes) was allocated toward operating losses for the period
leading up to the intended disposal date. In 2000, $31 million (net of taxes) of
actual operating losses were charged against this reserve. During the second
quarter of 2000, the NEG finalized the disposal of the energy commodity portion
of PG&E ES for $20 million, plus net working capital of approximately $65
million, for a total of $85 million. In addition, the sale of the Value-Added
Services business and various other assets was completed on July 21, 2000, for a
total consideration of $18 million. For the year ended December 31, 2000, an
additional estimated loss of $40 million (or $0.11 per share), net of income tax
of $36 million, was recorded. The additional loss was greater than the amount
originally provided for several reasons: (1) the sale was originally
contemplated to be a sale of the entity as a whole; (2) it was ultimately sold
in various pieces; (3) several assets were not sold and were subsequently
abandoned; and (4) wind-down costs associated with abandoned assets were greater
than originally contemplated. In addition, the worsening energy situation in
California also contributed to the additional loss incurred.
PG&E National Energy Group
---------------------------
PG&E GT
-------
(in millions) Utility PG&EGen NW Texas PG&E ET Eliminations & Total
Other/(1)/
2000:
Operating revenues $ 9,637 $ 1,211 $ 239 $ 873 $ 16,054 $ (1,782) $ 26,232
Operating expenses 14,838 1,073 105 869 15,974 (1,820) 31,039
Operating loss (4,807)
Interest income 266
Interest expense (788)
Other income (expense), net (23)
Income taxes (2,028)
Loss from continuing operations (3,324)
Net loss (3,364)
Net cash used by operating
activities (776)
Net cash used by investing (970)
activities
Net cash provided by financing 2,364
activities
EBITDA/(2)/ $(1,244) $ 227 $176 $ 108 $ 91 $ (55) $ (697)
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
Interest income 118
Interest expense (772)
Other income (expense), net 37
Income taxes 248
Income from continuing operations 13
Net loss (73)
Net cash provided by operating
activities 2,155
Net cash used by investing
activities (117)
Net cash used by financing
activities (2,043)
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
Interest income 101
Interest expense (781)
Other income (expense), net (36)
Income taxes 611
Income from continuing operations 771
Net income 719
Net cash provided by operating 3,388
activities
Net cash used by investing
activities (2,226)
Net cash used by financing
activities (1,113)
EBITDA/(2)/ $ 3,294 $ 200 $177 $ 15 $ (15) $ (7) $ 3,664
(1) Net income on intercompany positions recognized by segments using mark-to-
market accounting is eliminated. Intercompany transactions are also
eliminated.
(2) EBITDA is defined as income before provision for income taxes, interest
expense, interest income, deferred electric procurement costs, depreciation
and amortization, provision for loss on generation-related assets and
undercollected purchased power costs. EBITDA is not intended to represent
cash flows from operations and should not be considered as an alternative
to net income as an indicator of the PG&E Corporation's operating
performance or to cash flows as a measure of liquidity. Refer to the
Statement of Cash Flows for the U.S. GAAP basis cash flows. PG&E
Corporation believes that EBITDA is a standard measure commonly reported
and widely used by analysts, investors, and other interested parties.
However, EBITDA as presented herein may not be comparable to similarly
titled measures reported by other companies.
Overall Results
PG&E Corporation's financial position and results of operations are
impacted by the ongoing California energy crisis. Please see the Liquidity and
Financial Resources section and Note 2 of the Notes to the Consolidated
Financial Statements for more information on the California energy crisis.
Net loss for the year ended December 31, 2000 increased to $3,364 million
from a net loss of $73 million for the same period in 1999. Of the $3,291
million increase, the Utility's net loss allocated to common stock for the year
ended December 31, 2000 accounted for $4,271 million of the increase, partially
offset by an increase in the NEG net income of $980 million.
The decrease in performance of 2000 compared to 1999 results of operations
is attributable to the following factors:
. The Utility's earnings were impacted as a result of the write-off of
its remaining generation related regulatory assets and undercollected
purchased power costs ($4.1 billion, after taxes). Because of the
substantial uncertainty created by the California energy crisis, the
Utility can no longer conclude that energy costs, which had been
deferred on its balance sheets, are probable of recovery. Under
Statement of Financial Accounting Standard (SFAS) No. 71, "Accounting
for the Effects of Certain Types of Regulations," if a rate mechanism
provided by legislation or other regulatory authority were
subsequently established that made recovery from regulated rates
probable as to all or a portion of the undercollection that was
previously charged against earnings, a regulatory asset would be
reinstated with a corresponding increase in earnings.
. As a result of the high cost of power, with no offsetting revenues,
the Utility and PG&E Corporation had a net loss for California tax
purposes. California law does not permit carrybacks of such losses and
only permits carryforwards of 55% of such losses. As a result, PG&E
Corporation was unable to recognize $79 million of state tax benefits
because of California law. Income tax expense was also higher due to
depreciation adjustments and a reduction in investment tax credits.
. In 2000, the Utility recorded a provision ($83 million, after tax) for
potential losses associated with litigation discussed in Note 15 of
the Notes to the Consolidated Financial Statements.
. At the end of 1999, PG&E Corporation announced its plans to dispose of
PG&E GTT, and these assets were written down to estimated fair value
resulting in a charge of $890 million ($2.24 per share). PG&E GTT has
operated at a breakeven basis in 2000, while it reported a net loss
from operations of $7 million ($0.02 per share) in 1999. These
operations were sold on December 22, 2000.
. Also at the end of 1999, PG&E Corporation announced its plans to
dispose of PG&E ES and these assets were written down to net
realizable value. PG&E ES operated at a loss during 2000. However,
those losses were charged against reserves established in 1999 and did
not impact the current results from operations, while PG&E ES reported
losses of $98 million ($0.27 per share) for 1999. Additionally, during
the later half of 2000, PG&E Corporation recorded after-tax charges of
$40 million ($0.11 per share) to reflect the closing of transactions
to dispose of the retail energy services business and related
commodity portfolio.
. PG&E ET's net income in 2000, net of restructuring charges of $13
million after-tax ($0.04 per share) related to the move of natural gas
trading operations from Houston, Texas, to Bethesda, Maryland,
increased $57 million compared to 1999 results due to across the board
improvements in natural gas and power trading, asset management, and
structured transactions. While trading in electric commodities has
generally been profitable, the results of the gas trading operations
have improved significantly as a result of structured transactions.
Additionally, the gas trading operations benefited from the highest
gas prices in a number of years. The power trading operations have
been able to benefit from volatile prices throughout the United
States.
. PG&E Gen and PG&E GTN earnings decreased slightly from 1999 levels,
primarily attributable to a decline in operating results in the
generating business and a decrease in operating income at PG&E GTN
primarily as a result of settlements received in the amount of $19
million for negotiations regarding transportation contracts and other
related issues, resulting in the restructuring and/or termination of
these transportation contracts in 1999 with no similar transactions in
2000.
The effective tax rate for PG&E Corporation has decreased to 37.9% in 2000
compared to 95.0% in the prior year as a result of a higher effective tax rate
in 1999, largely due to the disposition of PG&E GTT which resulted in a capital
loss for tax purposes, which could not be fully recognized.
The decrease in performance of 1999 over 1998 results of operations is
attributable to the following factors:
. 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 was principally due to the write-down to
fair value of the natural gas business in Texas and the accrual for
the discontinuance of operations of the Energy Services segment. The
PG&E GTT write-down was approximately $890 million after taxes or
$2.42 per share and is comprised of the following pre-tax amounts:
$819 million write-down of net property, plant, and equipment, $446
million write-down of goodwill, and an accrual of $10 million for
selling costs. The PG&E ES discontinued operations generated a charge
of $58 million after tax.
. Partially offsetting these charges were increases in Utility income of
$153 million or $0.42 per share, primarily as a result of the 1999
General Rate Case.
. Also increasing income was an adjustment of a litigation reserve at
GTT, associated with a court-approved settlement proposal in the
amount of $35 million after tax.
. The 1998 income from continuing operation also included a loss on the
sale of the Australian energy holdings of $23 million, or $0.06 per
share, without a similar charge in 1999.
. In addition, PG&E Gen changed its method of accounting for major
maintenance and overhauls at its generating facilities. Beginning
January 1, 1999, the cost of major maintenance and overhauls,
principally at the PG&E Gen business segment, has been accounted for
as incurred. The change resulted in PG&E Corporation recording income
of $12 million after-tax ($0.03 per share), reflecting the cumulative
effect of the change in accounting principle for the year ended
December 31, 1999.
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.
Dividends
PG&E Corporation's historical quarterly common stock dividend was $0.30 per
common share, which corresponded to an annualized dividend of $1.20 per common
share.
On January 10, 2001, the Board of Directors of PG&E Corporation suspended
the payment of its fourth quarter 2000 common stock dividend of $0.30 per share
declared by the Board of Directors on October 18, 2000 and payable on January
15, 2001 to shareholders of record as of December 15, 2000. The California
energy crisis had created a liquidity crisis for PG&E Corporation, which led to
the suspension of payments of dividends to conserve cash resources. These
defaulted dividends were later paid on March 2, 2001 in conjunction with the
refinancing of PG&E Corporation obligations, discussed above under the Liquidity
and Financial Resources section.
Additionally, the parent company refinancing agreements mentioned above
prohibit dividends from being declared or paid until the term loans have been
repaid. The agreement is for a term of two years with an option on behalf of
PG&E Corporation to extend the term for an additional year.
On January 10, 2001, the Utility suspended the payment of its fourth
quarter 2000 common stock dividend of $110 million, declared in October 2000, to
PG&E Corporation and its wholly owned subsidiary PG&E Holdings, Inc. Until its
financial condition is restored, the Utility is precluded from paying dividends
to PG&E Corporation and PG&E Holdings, Inc.
Utility
Overall Results
The Utility's net loss allocated to common stock was $3,508 million in 2000
as compared to 1999 net income of $763 million. The decrease was primarily the
result of the write-off of its remaining generation-related regulatory assets
and undercollected purchased power costs, a provision for potential litigation
losses, and higher income tax expense as mentioned previously.
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 General Rate Case (GRC).
Operating Income
Operating loss for the Utility was $5,201 million in 2000 as compared to
operating income of $1,993 million in 1999. This decrease in the Utility's
operating income was primarily due to the write-off of its remaining generation
related regulatory assets and undercollected purchased power costs. In addition,
it is attributable to a provision for potential litigation losses and a lower
return on its assets, due to the sale of a portion of the Utility's generating
assets and the ongoing recovery of transition costs.
Operating income for the Utility was $1,993 million in 1999 as compared to
$1,876 million in 1998. This increase was 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.
Operating Revenues
The following table shows the components of the Utility's electric revenue
by customer class, natural gas revenues, and total revenues for the years ended
December 31:
2000 1999 1998
Residential $3,351 $3,294 $3,198
Commercial 2,804 2,940 2,883
Total residential and commercial 6,155 6,234 6,081
Legislative discount (453) (435) (396)
Revenues from residential and commercial 5,702 5,799 5,685
Industrial 509 864 933
Agriculture 386 392 351
Miscellaneous 257 177 222
Total electric operating revenues $6,854 $7,232 $7,191
Total gas operating revenues $2,783 $1,996 $1,733
Total operating revenues $9,637 $9,228 $8,924
Utility operating revenues increased $409 million or 4.4% to $9,637 million
in 2000 compared to $9,228 million in 1999. The increase in operating revenues
for 2000, as compared to 1999, related primarily to higher gas prices, which are
passed on to customers and collected in gas revenues, partially offset by a
decrease in electric revenues. The average price of gas per thousand cubic feet
was $4.92 in 2000 and $2.47 in 1999. Gas sales volumes for bundled sales and
transportation decreased by 9% from 1999 sales volumes due to warmer winter
weather, while gas sales volumes for transportation-only service increased by
25% due to increased demands by electric generators to meet air-conditioning
loads due to warmer summer weather and new transportation contracts.
Electric sales volumes increased for all customer classes, resulting in an
overall increase of 3% over 1999 sales volumes. Electric revenues from
industrial and commercial customers decreased because of higher wholesale power
market prices and resulting credits issued to direct access customers. These
customers, principally large industrial companies, procure electricity from
independent generators under long-term contracts and receive a credit on their
utility bills at prevailing market prices. In accordance with CPUC regulations,
the Utility provides an energy credit to those customers (known as direct access
customers) who have chosen to buy their electric generation energy from an
energy service provider (ESP) other than the Utility. The Utility bills direct
access customers based upon fully bundled rates (generation, distribution,
transmission, public purpose programs, and a competition transition charge).
However, the direct access customer receives an energy credit equal to the PX
price for wholesale electricity (calculated as the average market prices
multiplied by customer energy usage for the period), with the customer being
obligated to their ESP at their direct access contract rate. As wholesale power
prices began to increase in June 2000, the level of PX credits increased
correspondingly to the point where the credits exceeded the Utility's
distribution and transmission charges to direct access customers. During 2000,
the PX credits reduced electric revenue by $472 million, although the Utility
ceased paying most of these credits in December 2000. As of March 29, 2001, the
estimated total of accumulated credits for direct access customers that have not
been paid by the Utility is approximately $503 million. Such amounts are
reflected on the Utility's balance sheet. The actual amount that will be
refunded to ESPs will be dependent upon when the rate freeze ends and whether
there are any adjustments made to wholesale energy prices by FERC.
Utility operating revenues increased $304 million or 3.4% 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.
Operating Expenses
Utility operating expenses increased $7,603 million in 2000 compared to
1999.
The tables below summarize the changes in the Utility's operating expenses:
For the Year ended
December 31,
-----------
Increase Increase
(in millions) 2000 1999 (Decrease) (Decrease)
Cost of electric energy, net $ 6,741 $2,411 $ 4,330 179.6%
Deferred electric procurement costs (6,465) -- (6,465) --
Cost of gas 1,425 738 687 93.1%
Operating and maintenance, net 2,687 2,522 165 6.5%
Depreciation, amortization, and decommissioning 3,511 1,564 1,947 124.5%
Provision for loss on generation related regulatory assets and
purchased power costs 6,939 -- 6,939 --
Total $14,838 $7,235 $ 7,603 105.1%
For the Year ended
December 31,
-----------
Increase Increase
(in millions) 1999 1998 (Decrease) (Decrease)
Cost of electric energy, net $ 2,411 $2,321 $ 90 3.9%
Cost of gas 738 621 117 18.8%
Operating and maintenance, net 2,522 2,668 (146) (5.5%)
Depreciation, amortization, and decommissioning 1,564 1,438 126 8.8%
Total $ 7,235 $7,048 $ 187 2.7%
The overall increase in operating expenses is primarily attributable to the
write-off of the Utility's transition cost regulatory assets and undercollected
purchased power costs. In addition, operating expenses increased due to
increases in the cost of gas during the latter half of 2000. The average price
the Utility paid per thousand cubic feet of gas was $4.92 in 2000 and $2.47 in
1999.
Wholesale electric energy costs increased significantly during the latter
half of 2000. The average monthly costs per kWh of purchased power during the
latter half of 2000 were: June (16.33 cents), July (11.00 cents), August (18.70
cents), September (13.82 cents), October (13.62 cents), November (20.43 cents),
and December (33.24 cents). The amount of purchased power costs in excess of the
revenue for the generation component of frozen rates was reflected as deferred
electric procurement costs prior to the year-end write-off described above.
Revenues for the generation component of frozen rates were approximately 5.4
cents per kWh during 2000.
Depreciation, amortization, and decommissioning increased $1,947 million in
2000. The increase resulted primarily from an increase in recovery of transition
costs resulting from higher revenues from sales to the PX of Utility-owned
generation, including Diablo Canyon, and generation from QFs and other
providers. As mandated by the CPUC, these revenues, in excess of the related
costs, must be used to recover transition costs. See Note 2 of the Notes to the
Consolidated Financial Statements.
The Utility's operating expenses increased $187 million in 1999 as compared
to 1998. This increase reflected the increased cost of gas due to higher usage
and the increased amortization of electric transition costs, partially offset by
a decrease in operating and maintenance expense resulting from fewer owned-
generation facilities in 1999 as a result of divestitures.
Dividends
Dividends paid to PG&E Corporation increased from $440 million in 1999 to
$475 million in 2000, maintaining the CPUC-mandated capital structure. Dividends
paid to PG&E Corporation in 1998 were $444 million.
Dividends paid to preferred shareholders remained at the same level of $25
million in 2000 and 1999. Dividends paid to preferred shareholders decreased
from $29 million in 1998 to $25 million in 1999, primarily as a result of
redemptions.
As previously discussed, the Utility has suspended payment of its common
and preferred dividends. Dividends on preferred stock are cumulative. Until
cumulative dividends on preferred stock are paid, the Utility may not pay any
dividends on its common stock.
PG&E National Energy Group
Operating Income
Operating income at the NEG increased $1,509 million in 2000 as compared to
1999, primarily related to the charge to write PG&E GTT down to its net
realizable value in 1999 with no similar charge occurring in 2000. Additionally,
all business units reflected improved operating results over the prior year,
despite a $22 million charge related to the relocation of the energy trading
operations from Houston, Texas, to Bethesda, Maryland.
Operating income of the NEG 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
transport revenue 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.
Operating Revenues
The NEG operating revenues increased $5,003 million in 2000 compared to
1999. The NEG has focused its trading efforts on asset management and higher-
margin trades, resulting in increased trading volume of electric commodities
principally in the Southeast and Midwest. In addition, increases in the price of
power and gas have resulted in increased revenues.
The NEG's 1999 operating revenues increased $939 million as compared to
1998, 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 reflected revenue increases at
PG&E GTT 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.
Operating Expenses
Operating expenses at the NEG increased $3,494 million in 2000 compared to
the prior year. The increase results from the increased trading volumes
discussed above, and increases in the cost of power and gas, partially offset by
reduced depreciation and amortization expense at PG&E GTT reflective of the
disposal of the PG&E GTT assets.
The NEG'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, a full
year of operating expenses associated with the generation facilities in New
England, and growth of PG&E ET operations.
Dividends
The NEG currently intends to retain any future earnings to fund the
development and growth of its business. Further, the NEG is precluded from
paying dividends, unless it meets certain financial tests. Therefore, it is not
anticipating paying any cash dividends on its common stock in the foreseeable
future.
REGULATORY MATTERS
A significant portion of PG&E Corporation's operations is regulated by
federal and state regulatory commissions. These commissions oversee service
levels and, in certain cases, PG&E Corporation's revenues and pricing for its
regulated services. Following are the percentages of 2000 revenues that fell
under the jurisdiction of these various regulatory agencies:
Utility Consolidated
Cost of service-based 96.3% 39.2%
Market 3.7% 60.8%
The Utility is the only subsidiary with significant regulatory proceedings
at this time. The Utility's significant regulatory proceedings are discussed
below. Regulatory proceedings associated with electric industry restructuring
are discussed above in "The California Energy Crisis." See Note 2 of the Notes
to the Consolidated Financial Statements.
The Utility's General Rate Case
The CPUC authorizes an amount known as "base revenues" to be collected from
ratepayers to recover the Utility's basic business and operational costs for its
gas and electric distribution operations. Base revenues, which include non-fuel-
related operating and maintenance costs, depreciation, taxes, and a return on
invested capital, currently are authorized by the CPUC in GRC proceedings. The
CPUC's final decision in the Utility's 1999 GRC application increased annual
electric distribution revenues by $163 million and annual gas distribution
revenues by $93 million over 1998 authorized base revenues.
In March 2000, two interveners filed applications for rehearing of the 1999
GRC decision, alleging that the CPUC committed legal errors by approving funding
in certain areas that were not adequately supported by record evidence. In April
2000, the Utility filed its response to these applications for rehearing,
defending the GRC decision against the allegations of error. A CPUC decision on
the applications for rehearing is pending.
In the 1999 GRC decision the CPUC ordered that the Utility file a 2002 GRC.
As a result of the current energy crisis, the procedural schedule has been
delayed pending the CPUC's resolution of the Utility's request that it be
permitted to file an alternative schedule or an alternative to the 2002 GRC. An
earlier decision initially delaying the schedule affirms that rates would still
become effective on January 1, 2002, although the CPUC decision may not be
rendered until after that date.
Order Instituting Investigation (OII) into Holding Company Activities
On April 3, 2001, the CPUC issued an order instituting an investigation
into whether the California investor-owned utilities, including the Utility,
have complied with past CPUC decisions, rules, or orders authorizing their
holding company formations and/or governing affiliate transactions, as well as
applicable statutes. The order states that the CPUC will investigate (1) the
utilities' transfer of money to their holding companies since deregulation of
the electric industry commenced, including during times when their utility
subsidiaries were experiencing financial difficulties; (2) the failure of the
holding companies to financially assist the utilities when needed; (3) the
transfer by the holding companies' of assets to unregulated subsidiaries; and
(4) the holding companies' action to "ring fence" their unregulated
subsidiaries. The CPUC will also determine whether additional rules, conditions,
or changes are needed to adequately protect ratepayers and the public from
dangers of abuse stemming from the holding company structure. The CPUC will
investigate whether it should modify, change, or add conditions to the holding
company decisions, make further changes to the holding company structure, alter
the standards under which the CPUC determines whether to authorize the formation
of holding companies, otherwise modify the decisions, or recommend statutory
changes to the California Legislature. As a result of the investigation, the
CPUC may impose remedies (including penalties), prospective rules, or
conditions, as appropriate. PG&E Corporation and the Utility believe that they
have complied with applicable statutes, CPUC decisions, rules, and orders. As
described above, on April 6, 2001, the Utility filed a voluntary petition for
relief under Chapter 11 of the U.S. Bankruptcy Code. PG&E Corporation and the
Utility believe that to the extent the CPUC seeks to investigate past conduct
for compliance purposes, the investigation is automatically stayed by the
bankruptcy
filing. Neither the Utility nor PG&E Corporation can predict what the outcome of
the investigation will be or whether the outcome will have a material adverse
effect on their results of operation or financial condition.
The Utility's 2001 Attrition Rate Adjustment (ARA)
In July 2000, the Utility filed an ARA application with the CPUC to
increase its 2001 electric distribution revenues by $189 million, effective
January 1, 2001. The increase reflects inflation and the growth in capital
investments necessary to serve customers. The Utility did not request an
increase in gas distribution revenues. In December 2000, the CPUC issued an
interim order finding that a decision on the application cannot be rendered by
January 1, 2001, and determining that if attrition relief is eventually granted,
that relief will be effective as of January 1, 2001. Hearings are scheduled to
begin in June 2001, and a CPUC decision is expected by January 2002.
The Utility's Cost of Capital Proceedings
Each year, the Utility files an application with the CPUC to determine the
authorized rate of return that the Utility may earn on its electric and gas
distribution assets and recover from ratepayers. Since February 17, 2000, the
Utility's adopted return on common equity (ROE) has been 11.22% on electric and
gas distribution operations, resulting in an authorized 9.12% overall rate of
return (ROR). The Utility's earlier adopted ROE was 10.6%. The adopted ROR for
2000 resulted in an increase of approximately $49 million over 1999 electric and
gas distribution revenues. In May 2000, the Utility filed an application with
the CPUC to establish its authorized ROR for electric and gas distribution
operations for 2001. The application requests an ROE of 12.4%, and an overall
ROR of 9.75%. If granted, the requested ROR would increase electric distribution
revenues by approximately $72 million and gas distribution revenues by
approximately $23 million. The application also requests authority to implement
an Annual Cost of Capital Adjustment Mechanism for 2002 through 2006 that would
replace the annual cost of capital proceedings. The proposed adjustment
mechanism would modify the Utility's cost of capital based on changes in an
interest rate index. The Utility also proposes to maintain its currently
authorized capital structure of 46.2% long-term debt, 5.8% preferred stock, and
48% common equity. In March 2001, the CPUC issued a proposed decision
recommending no change to the current 11.22% ROE for test year 2001. This
authorized ROE results in a corresponding 9.12% return on rate base and no
change in the Utility's electric or gas revenue requirement for 2001. A final
CPUC decision is expected in the second quarter of 2001.
The Utility's FERC Transmission Rate Cases
Since April 1998, electric transmission revenues have been authorized by
the FERC, including various rates to recover transmission costs from the
Utility's former bundled retail transmission customers. The FERC has not yet
acted upon a settlement filed by the Utility that, if approved, would allow the
Utility to recover $345 million in electric transmission rates for the 14-month
period of April 1, 1998 through May 31, 1999. During this period, somewhat
higher rates have been collected, subject to refund. A FERC order approving this
settlement is expected by the end of 2001. The Utility has accrued $24 million
for potential refunds related to the period ended May 31, 1999. In April 2000,
the FERC approved a settlement that permits the Utility to recover $264 million
in electric transmission rates retroactively for the 10-month period from May
31, 1999 to March 31, 2000. In September 2000, the FERC approved another
settlement that permits the Utility to recover $340 million annually in electric
transmission rates and made this retroactive to April 1, 2000. Further, in
November 2000, the FERC accepted, subject to refund, the Utility's proposal to
collect $397 million annually in electric transmission rates beginning on May 6,
2001.
The Utility's Catastrophic Event Memorandum Account Proceeding
In April 2000, the CPUC approved a settlement agreement in a proceeding
addressing the Catastrophic Events Memorandum Account. The settlement provided
for a $59 million increase in electric distribution revenue requirement and an
$11 million increase in gas distribution revenue requirement which was collected
through rates during 2000. The increase compensates the Utility for costs
incurred for several emergencies, including the 1991 Oakland Hills Fire and the
1998 storms.
The Utility's 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 Office of Ratepayer Advocates; a division of the CPUC,
(ORA) recommended a disallowance of $88.4 million in Section 368(e) 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. It is
uncertain when a proposed decision will be issued by the CPUC. 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.
The Utility's Performance-Based Ratemaking (PBR) Application
In June 2000, the CPUC granted the Utility's request to withdraw its PBR
application filed in November 1998. The Utility had requested the withdrawal in
accordance with the 1999 GRC decision issued in February 2000, which required a
2002 GRC before a PBR mechanism could be implemented. In closing the PBR
proceeding, the CPUC ordered the Utility to file a new PBR application by
September 2000. This application would propose financial rewards and penalties
associated with utility performance in meeting prescribed standards for measures
such as electric reliability and customer service.
In September 2000, the Utility filed an application with the CPUC to
establish (1) performance standards and associated financial rewards and
penalties for electric and gas distribution service, (2) a revenue-sharing
mechanism for new categories of non-tariffed products and services (NTP&S)
offered by the Utility, and (3) ratemaking for proceeds from sales or transfers
of certain non-generation related land. The performance standards would cover a
period of five years commencing January 1, 2001. The total maximum annual reward
or penalty is $54 million per year, consisting of $52 million for electric
distribution and $2 million for gas distribution. The revenue-sharing mechanism
proposes to share net positive after-tax revenues from new categories of NTP&S
equally between ratepayers and shareholders. Finally, the Utility requested that
the CPUC establish basic rules about the allocation of gains and losses from the
Utility's non-generation-related land sales. In November 2000, the CPUC
suspended the proceeding until further notice.
MUNICIPALIZATION AND OTHER COMPETITION
With the uncertainties over future electric utility rates due to the
California energy crisis, municipalization is under consideration by many local
governments in California. Municipalization is the attempt by cities and local
utility districts to take over markets from private, investor-owned utility
companies. Local governments in California are increasingly looking at entering
the utility business as a source of new revenue. Those that already have
municipal utilities are examining expansion to provide new services or to sell
existing services outside of their current boundaries. Municipalization efforts
in San Francisco, Berkeley, and San Diego (among several other California
cities) are being pursued by grass roots organizations and proposals to
municipalize may go before voters. We cannot currently predict what the outcome
will be from these actions.
As wholesale electric prices increase, alternatives to the current model
become more attractive. These alternative technologies, such as distributed
generation which enables siting of smaller electric generation facilities in
close proximity to the electric demand, have the potential to strand Utility
investment and make recovery more challenging. The CPUC has opened a 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. This rulemaking is also intended to address
other areas of potential electric competition, such as billing services. There
has been little activity in this rulemaking since its issuance in 1999.
ENVIRONMENTAL MATTERS
We are subject to laws and regulations established to both maintain and
improve the quality of the environment. Where our properties contain hazardous
substances, these laws and regulations require us to remove those substances or
remedy effects on the environment. See Note 15 of the Notes to the Consolidated
Financial Statements for further discussion of environmental matters.
Utility
The Utility records an environmental remediation 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.
At December 31, 2000, the Utility expects to spend $320 million,
undiscounted, for hazardous waste remediation costs at identified sites,
including divested fossil-fueled power plants. 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. If 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 could spend as
much as $462 million on these costs. 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.
The Utility had an environmental remediation liability of $320 million and
$271 million at December 31, 2000 and 1999, respectively. The $320 million
accrued at December 31, 2000 includes (1) $114 million related to the pre-
closing remediation liability, associated with divested generation facilities
(see further discussion in the "Generation Divestiture" section of Note 2 of the
Notes to the Consolidated Financial Statements), and (2) $180 million related to
remediation costs for those generation facilities that the Utility still owns,
manufactured gas plant sites, and gas gathering compressor stations. Of the $320
million environmental remediation liability, the Utility has recovered $168
million through rates, and expects to recover another $87 million in future
rates. The Utility is seeking recovery of the remainder of its costs from
insurance carriers and from other third parties as appropriate.
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. In
March 2000, the Central Coast Board requested the Utility to provide specific
information regarding the "backflush" procedure used at Moss Landing. The
Utility provided the requested information to the Board in April 2000. The
Utility's investigation indicated that while it owned Moss Landing, significant
amounts of water were discharged from the cooling water intake. While the
Utility's investigation did not clearly indicate that discharged waters had a
temperature higher than ambient receiving water, the Utility believes that the
temperature of the discharged water was higher than that of the ambient
receiving water. In December 2000, the executive officer of the Central Coast
Board made a settlement proposal to the Utility under which the Utility would
pay $10 million, a portion of which would be used for environmental projects and
the balance of which would constitute civil penalties. Settlement negotiations
are continuing.
The Utility's Diablo Canyon employs a "once through" cooling water system
which is regulated under a NPDES Permit issued by the Central Coast Board. This
permit allows Diablo Canyon to discharge the cooling water at a temperature no
more than 22 degrees above ambient receiving water and requires that the
beneficial uses of the water be protected. The beneficial uses of water in this
region include industrial water supply, marine and wildlife habitat, shell fish
harvesting, and preservation of rare and endangered species. In January 2000,
the Central Coast Board issued a proposed draft Cease and Desist Order (CDO)
alleging that, although the temperature limit has never been exceeded, the
Diablo Canyon's discharge was not protective of beneficial uses. In October
2000, the Central Coast Board and the Utility reached a tentative settlement of
this matter pursuant to which the Central Coast Board has agreed to find that
the Utility's discharge of cooling water from the Diablo Canyon plant protects
beneficial uses and that the intake technology reflects "best technology
available" under Section 316(b) of the Federal Clean Water Act. As part of the
settlement, the Utility will take measures to preserve certain acreage north of
the plant and will fund approximately $5 million in environmental projects
related to coastal resources. The parties are negotiating the documentation of
the settlement. The final agreement will be subject to public comment and will
be incorporated in a consent decree to be entered in California Superior Court.
The Utility believes the ultimate outcome of these matters will not have a
material impact on the Utility's financial position or results of operations.
PG&E National Energy Group
In October and November 1999, the U.S. Environmental Protection Agency
(EPA) and several states filed suits or announced their intention to file suits
against a number of coal-fired power plants in Midwestern and Eastern states.
These suits relate to alleged violations of the Clean Air Act. More
specifically, they allege violations of the deterioration prevention and non-
attainment provisions of the Clean Air Act's new source review requirements
arising out of certain physical changes that may have been made at these
facilities without first obtaining the required permits. In May 2000 the NEG
received a request for information seeking detailed operating and maintenance
histories for the Salem Harbor and Brayton Point power plants. If EPA were to
find that there were physical changes in the past that were undertaken without
first receiving the required permits under the Clean Air Act, then penalties may
be imposed and further emission reductions might be necessary at these plants.
In addition to the EPA, states may impose more stringent air emissions
requirements. The Commonwealth of Massachusetts is considering the adoption of
more stringent air emission reductions from electric generating facilities. If
adopted, these requirements will impact Salem Harbor and Brayton Point. The NEG
has proposed an emission reduction plan that may include modernization of the
Salem Harbor power plant and use of advanced technologies for emissions removal.
It is also studying various advanced technologies for emissions removal for the
Brayton Point power plant.
The NEG's subsidiary, USGenNE, has proposed a number of state and regional
initiatives that will require it to achieve significant reductions of emissions
by 2010. The NEG expects that USGenNE will meet these requirements through a
combination of installation of controls, use of emission allowances it currently
owns, and purchase of additional allowances. The NEG currently estimates that
USGenNE's total capital cost for complying with these requirements will be
approximately $300 million.
PG&E Gen's existing power plants, including USGenNE facilities, are subject
to federal and state water quality standards with respect to discharge
constituents and thermal effluents. Three of the fossil-fueled plants owned and
operated by USGenNE are operating pursuant to NPDES permits that have expired.
For the facilities whose NPDES permits have expired, permit renewal applications
are pending. It is anticipated that all three facilities will be able to
continue to operate under existing terms and conditions until new permits are
issued. It is estimated that USGenNE's cost to comply with the new permit
conditions could be as much as $55 million through 2005. It is possible that the
new permits may contain more stringent limitations than prior permits.
During September 2000, USGenNE signed a series of agreements that require,
among other things, that USGenNE alter its existing waste water treatment
facilities at two facilities by replacing certain unlined treatment basins,
submit and implement a plan for the closure of such basins, and perform certain
environmental testing at the facilities. USGenNE has incurred $4 million in 2000
and expects to complete the required steps on or before December 2001. The total
expected cost of these improvements is $21 million.
Inflation
Financial statements, which are prepared in accordance with accounting
principles generally accepted in the United States of America, 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 do 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
PG&E Corporation's or the Utility's financial position or results of operations.
Quantitative and Qualitative Disclosures About Market Risk
Price Risk Management Activities
We have established a risk management policy that allows derivatives to be
used for both trading and non-trading 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 PG&E Corporation's or
the Utility's primary market risk exposures, which include commodity price risk,
interest rate risk, and foreign currency risk. 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, options, and other contracts. Net
open positions often exist or are established due to PG&E Corporation's and the
Utility's assessment of their responses 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.
PG&E Corporation and the Utility may only engage in the trading of
derivatives in accordance with policies established by the PG&E Corporation Risk
Management Committee. Trading is permitted only after the Risk Management
Committee authorizes such activity subject to appropriate financial exposure
limits. Under PG&E Corporation, both the NEG and the Utility have their own Risk
Management Committees that address matters relating to those companies'
respective businesses. These Risk Management Committees are comprised of senior
officers.
Market Risk
Commodity Price Risk
Commodity price risk is the risk that changes in market prices will
adversely affect earnings and cash flows. PG&E Corporation is primarily exposed
to the commodity price risk associated with energy commodities such as
electricity and natural gas. Therefore, PG&E Corporation's price risk management
activities primarily involve buying and selling fixed-price commodity
commitments into the future.
In compliance with regulatory requirements, the Utility manages price risk
independently from the activities in PG&E Corporation's unregulated business.
Price risk activities consist of the use of non-trading (hedging) financial
instruments to reduce the impact of commodity price fluctuations for electricity
and natural gas. While the use of these instruments has been authorized by the
CPUC, the CPUC has yet to establish rules around how it will judge the
reasonableness of these instruments. Gains and losses associated with the use of
the majority of these financial instruments primarily affect regulatory
accounts, depending on the business unit and the specific program involved.
In response to high wholesale electricity costs experienced during the
summer of 2000, the CPUC in August 2000 eliminated the requirement to procure
electricity in the spot market and authorized the Utility to enter into
"bilateral agreements" with third parties. These contracts are used to purchase
electricity from non-PX sources at fixed prices for terms that may extend to the
end of 2005. The purpose of bilateral contracts is to lock in supply and rates
on the future purchase of electricity and to reduce price volatility.
The CPUC has authorized the Utility 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. Furthermore, the
Utility was authorized to trade natural gas-based financial instruments to hedge
the gas commodity price swings in serving core gas customers.
PG&E Corporation's business units measure commodity price 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. We quantify market risk using a variance/co-variance value-at-risk model
that provides a consistent measure of risk across diverse energy markets and
products. The use of this methodology requires a number of important
assumptions, including the selection of a confidence level for losses,
volatility of prices, market liquidity, and a holding period.
PG&E Corporation uses 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 derivatives and commodity investments in our
trading portfolios and only derivative commodity investments for our non-trading
portfolio (but not the related underlying hedged position). PG&E Corporation and
the Utility express value-at-risk as a dollar amount of the potential loss in
the fair value of our portfolios based on a 95% confidence level using a one-day
liquidation period. Therefore, there is a 5% probability that the Company's
portfolios will incur a loss in one day greater than its value-at-risk. The
value-at-risk is aggregated for PG&E Corporation as a whole by correlating the
daily returns of the portfolios for electricity and natural gas for the previous
22 trading days.
The following tables illustrate the value-at-risk for PG&E Corporation's
daily commodity price risk exposure for the year ended December 31:
2000 1999
---- ----
Trading Non-Trading Trading Non-Trading
(Dollars in millions)
NEG:
Value at End of Period $11.5 $ 8.8 $4.4 $ --
Average 6.8 9.5 4.3 0.6
Low 5.5 7.6 1.3 --
High 12.3 11.1 6.2 1.7
Utility:
Value at End of Period -- 187.4 -- 3.2
Average -- 24.2 -- 4.0
Low -- 0.1 -- 2.9
High -- 207.8 -- 5.7
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.
Interest Rate Risk
PG&E Corporation and the Utility are exposed to the following types of
interest rate exposure:
Floating rate exposure measures the sensitivity of corporate earnings and
cash flows to changes in short-term interest rates. This exposure arises when
short-term debt is rolled over at maturity, when interest rates on floating rate
notes are periodically reset according to a formula or index, and when floating
rate assets are financed with fixed rate liabilities. PG&E Corporation manages
its exposure to short-term interest rates by using an appropriate mix of short-
term debt, long-term floating rate debt, and long-term fixed rate debt.
Financing exposure measures the effect of an increase in interest rates
that may occur related to any planned or expected fixed rate debt financing.
This includes the exposure associated with replacing debt at maturity. PG&E
Corporation will hedge financing exposure in situations where the potential
impairment of earnings, cash flows, and investment returns or execution
efficiency, or external factors (such as bank imposed credit agreements)
necessitate hedging.
Refunding exposure measures the effect of an increase in interest rates on
the ability to economically refund a callable debt instrument. Corporate bonds
typically are issued with a call feature that allows the issuer to retire and
replace the bonds at a lower rate if interest rates have fallen. The value of
this call feature to the issuer declines with increases in interest rates. PG&E
Corporation will hedge refunding exposure when it is economic to repurchase all
or part of the underlying debt instrument and replace it with a debt instrument
that has lower cost during its remaining life. The guideline for a refunding to
be economic is that the net present value savings should exceed 5% of the par
value of the debt to be refunded and the refunding efficiency should exceed 85%.
PG&E Corporation and the Utility use interest rate swaps to manage their
interest rate exposure. Interest rate risk sensitivity analysis is used to
measure PG&E Corporation's interest rate price risk by computing estimated
changes in the fair value in the event of assumed changes in market interest
rates. As of December 31, 2000, if interest rates had averaged 1% higher, it was
estimated that earnings would have decreased by approximately $24 million.
Foreign Currency Risk
PG&E Corporation is exposed to the following types of foreign currency
risk:
Economic exposure measures the change in value that results from changes in
future operating or investing cash flows caused by the timing and level of
anticipated foreign currency flows. Economic exposure includes the anticipated
purchase of foreign entities, anticipated cash flows, projected revenues and
expenses denominated in a foreign currency.
Transaction exposure measures changes in value of current outstanding
financial obligations already incurred, but not due to be settled until some
future date. This includes the agreement to purchase a foreign entity in a
currency other than the U.S. dollar, an obligation to infuse equity capital into
a foreign entity, foreign currency denominated debt obligations, as well as
actual non-U.S. dollar cash flows such as dividends declared but not yet paid.
Translation exposure measures potential accounting derived changes in
owners' equity that result from translating a foreign affiliate's financial
statements from its functional currency to U.S. dollars for PG&E Corporation's
consolidated financial statements.
PG&E Corporation's primary foreign currency exchange rate exposure was with
the Canadian dollar. The following instruments are used to hedge foreign
currency exposures: forwards, swaps, and options. Based on a sensitivity
analysis at December 31, 2000, a 10% devaluation of the Canadian dollar would be
immaterial to PG&E Corporation's consolidated financial statements.
New Accounting Standards
PG&E Corporation and the Utility will adopt SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Activities," as amended by SFAS No. 138,
"Accounting for Certain Derivative Instruments and Certain Hedging Activities,"
effective 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 portions thereof, that are not effective hedges must be
adjusted to fair value through income. If derivatives are effective hedges,
depending on the nature of the hedges, changes in the fair value of derivatives
either will be offset against the change in fair value of the hedged assets,
liabilities, or firm commitments through earnings, or will be recognized in
other comprehensive income until the hedged items are recognized in earnings.
PG&E Corporation estimates that the transition adjustment to implement this new
standard will be an immaterial reduction of net earnings and a negative
adjustment of $377 million to other comprehensive income. The Utility estimates
that the transition adjustment to implement this new standard will be an
immaterial reduction of net earnings and a positive adjustment of $44 million to
other comprehensive income. These adjustments will be recognized as of January
1, 2001 as a cumulative effect of a change in accounting principle. The ongoing
effects will depend on the future market conditions and hedging activities at
PG&E Corporation and the Utility.
PG&E Corporation and the Utility have certain derivative commodity
contracts for the physical delivery of purchase quantities transacted in the
normal course of business. At this time, these derivatives are exempt from the
requirements of SFAS No. 133 under the normal purchases and sales exception, and
thus will not be reflected on the balance sheet at fair value. The Derivative
Implementation Group of the Financial Accounting Standards Board is currently
evaluating the definition of normal purchases and sales. As such, certain
derivative commodity contracts may no longer be exempt from the requirements of
SFAS No. 133. PG&E Corporation and the Utility will evaluate the impact of the
implementation guidance on a prospective basis when the final decision regarding
this issue is resolved.
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 the Notes to
the Consolidated Financial Statements for further discussion of significant
pending legal matters.
PG&E Corporation
STATEMENTS OF CONSOLIDATED OPERATIONS
(in millions, except per share amounts)
Year ended December 31,
-----------------------
2000 1999 1998
Operating Revenues
Utility $ 9,637 $ 9,228 $ 8,924
Energy commodities and services 16,595 11,592 10,653
Total operating revenues 26,232 20,820 19,577
Operating Expenses
Cost of energy for utility 8,166 3,149 2,942
Deferred electric procurement cost (6,465) -- --
Cost of energy commodities and services 15,220 10,587 9,852
Operating and maintenance 3,520 3,151 3,083
Depreciation, amortization, and decommissioning 3,659 1,780 1,602
Loss on assets held for sale -- 1,275 --
Provision for loss on generation-related regulatory assets and undercollected
purchased power costs 6,939 -- --
Total operating expenses 31,039 19,942 17,479
Operating Income (Loss) (4,807) 878 2,098
Interest income 266 118 101
Interest expense (788) (772) (781)
Other income (expense), net (23) 37 (36)
Income (Loss) Before Income Taxes (5,352) 261 1,382
Income taxes provision (benefit) (2,028) 248 611
Income (Loss) from continuing operations $(3,324) $ 13 $ 771
Discontinued operations (Note 5)
Loss from operations of PG&E Energy Services (net of applicable income taxes of
$0 million, $35 million, and $41 million, respectively) -- (40) (52)
Loss on disposal of PG&E Energy Services (net of applicable income taxes of
$36 million, $36 million, and $0 million, respectively) (40) (58) --
Net income (loss) before cumulative effect of a change in accounting principle
(Note 1) (3,364) (85) 719
Cumulative effect of a change in an accounting principle (net of applicable income
taxes of $8 million) -- 12 --
Net Income (Loss) $(3,364) $ (73) $ 719
Weighted average common shares outstanding 362 368 382
Earnings (Loss) Per Common Share, Basic and Diluted
Income (Loss) from continuing operations $ (9.18) $ 0.04 $ 2.02
Discontinued operations (0.11) (0.27) (0.14)
Cumulative effect of a change in an accounting principle -- 0.03 --
Net Earnings (Loss) $ (9.29) $ (0.20) $ 1.88
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.
PG&E Corporation
CONSOLIDATED BALANCE SHEETS
(in millions, except share amounts)
Balance at
December 31,
-------------------------
2000 1999
ASSETS
Current Assets
Cash and cash equivalents $ 899 $ 281
Short-term investments 1,634 187
Accounts receivable
Customers (net of allowance for doubtful accounts of $71 million
and $65 million, respectively) 2,131 1,486
Energy marketing 2,211 532
Regulatory balancing accounts 222 --
Price risk management 2,039 400
Inventories 392 433
Income taxes receivable 1,241 --
Prepaid expenses and other 406 255
Total current assets 11,175 3,574
Property, Plant, and Equipment
Utility 23,872 23,001
Non-utility
Electric generation 2,008 1,905
Gas transmission 1,542 2,541
Construction work in progress 900 436
Other 147 184
Total property, plant, and equipment (at original cost) 28,469 28,067
Accumulated depreciation and decommissioning (11,878) (11,291)
Net property, plant, and equipment 16,591 16,776
Other Noncurrent Assets
Regulatory assets 1,773 4,957
Nuclear decommissioning funds 1,328 1,264
Price risk management 2,026 329
Other 2,398 2,570
Total noncurrent assets 7,525 9,120
TOTAL ASSETS $ 35,291 $ 29,470
PG&E Corporation
CONSOLIDATED BALANCE SHEETS
(in millions, except share amounts)
Balance at
December 31,
------------
2000 1999
LIABILITIES AND EQUITY
Current Liabilities
Short-term borrowings $ 4,530 $ 1,499
Long-term debt, classified as current 2,391 558
Current portion of rate reduction bonds 290 290
Accounts payable
Trade creditors 3,760 708
Energy marketing 2,096 480
Regulatory balancing accounts 196 384
Other 459 559
Accrued taxes -- 211
Price risk management 1,999 323
Other 1,563 1,058
Total current liabilities 17,284 6,070
Noncurrent Liabilities
Long-term debt 4,736 6,682
Rate reduction bonds 1,740 2,031
Deferred income taxes 1,656 3,147
Deferred tax credits 192 231
Price risk management 1,867 207
Other 3,864 3,436
Total noncurrent liabilities 14,055 15,734
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 387,193,727 and
384,406,113 shares, respectively 5,971 5,906
Common stock held by subsidiary, at cost, 23,815,500 shares (690) (690)
Reinvested earnings (Accumulated Deficit) (2,105) 1,674
Accumulated other comprehensive income (loss) (4) (4)
Total common stockholders' equity 3,172 6,886
Commitments and Contingencies (Notes 1, 2, 3, 7, 14, and 15) -- --
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $35,291 $29,470
The accompanying Notes to the Consolidated Financial Statements are an integral
part of this statement.
PG&E Corporation
STATEMENTS OF CONSOLIDATED CASH FLOWS
(in millions)
For the year ended December 31,
-------------------------------
2000 1999 1998
Cash Flows From Operating Activities
Net income (loss) $(3,364) $ (73) $ 719
Adjustments to reconcile net (loss) income to net cash provided (used) by
operating activities:
Depreciation, amortization, and decommissioning 3,659 1,780 1,602
Deferred electric procurement costs (6,465) -- --
Deferred income taxes and tax credits--net (767) (754) (107)
Other deferred charges and noncurrent liabilities 256 102 18
Provision for loss on generation-related regulatory assets and
undercollected purchased power costs 6,939 -- --
Loss on assets held for sale -- 1,275 --
Loss regulatory assets from discontinued operations 40 98 52
Cumulative effect of change in accounting principle -- (12) --
Net effect of changes in operating assets and liabilities:
Short-term investments (1,447) (132) 1,105
Accounts receivable--trade (2,324) 370 (342)
Inventories 41 23 (33)
Income tax receivable (1,241) -- --
Price risk management assets and liabilities, net 30 (28) (16)
Accounts payable 4,568 (293) 247
Regulatory balancing accounts (410) 305 537
Accrued taxes (211) 108 (123)
Other working capital 324 209 199
Other--net (404) (823) (470)
Net cash (used) provided by operating activities (776) 2,155 3,388
Cash Flows From Investing Activities
Capital expenditures (1,758) (1,584) (1,619)
Acquisitions -- -- (1,779)
Proceeds from sale of assets 415 1,014 1,106
Other--net 373 453 66
Net cash used by investing activities (970) (117) (2,226)
Cash Flows From Financing Activities
Net borrowings (repayments) under credit facilities 2,846 (145) 2,115
Long-term debt issued 1,023 -- --
Long-term debt matured, redeemed, or repurchased (1,155) (798) (1,552)
Preferred stock redeemed or repurchased -- -- (108)
Common stock issued 65 54 63
Common stock repurchased (2) (693) (1,158)
Dividends paid (436) (465) (470)
Other--net 23 4 (3)
Net cash provided (used) by financing activities 2,364 (2,043) (1,113)
Net Change in Cash and Cash Equivalents 618 (5) 49
Cash and Cash Equivalents at January 1 281 286 237
Cash and Cash Equivalents at December 31 $ 899 $ 281 $ 286
Supplemental disclosures of cash flow information
Cash paid for:
Interest (net of amounts capitalized) $ 719 $ 727 $ 774
Income taxes (net of refunds) 20 723 770
Supplemental disclosures of non-cash investing and financing
Retirement of long-term debt in the sale of PG&E Gas
Transmission--Texas 564 -- --
The accompanying Notes to the Consolidated Financial Statements are an integral
part of this statement.
PG&E Corporation
STATEMENTS OF CONSOLIDATED COMMON STOCK EQUITY
(in millions, except share amounts)
Common Reinvested Total Compre-
Stock Earnings Accumulated Common hensive
Common Held by (Accumulated Other Comprehensive Stock Income
Stock Subsidiary Deficit) Income (Loss) Equity (Loss)
Balance December 31, 1997 $ 6,366 $ -- $ 2,543 $ (12) $ 8,897 $ --
Net income -- -- 719 -- 719 719
Foreign currency translation
adjustment -- -- -- 6 6 6
Comprehensive income -- -- -- -- -- $ 725
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) -- 7 -- 5
Balance December 31, 1998 5,862 -- 2,210 (6) 8,066
Net loss -- -- (73) -- (73) $ (73)
Foreign currency translation
adjustment -- -- -- 2 2 2
Comprehensive loss -- -- -- -- $ (71)
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) -- (2) -- (10)
Balance December 31, 1999 5,906 (690) 1,674 (4) 6,886
Net loss -- -- (3,364) -- (3,364) $ (3,364)
Common stock issued (2,847,269
shares) 65 -- -- -- 65
Common stock repurchased
(59,655 shares) (1) -- (1) -- (2)
Cash dividends declared on
common stock -- -- (434) -- (434)
Other 1 -- 20 -- 21
Balance December 31, 2000 $ 5,971 $ (690) $ (2,105) $ (4) $ 3,172
The accompanying Notes to the Consolidated Financial Statements are an integral
part of this statement.
Pacific Gas and Electric Company
STATEMENTS OF CONSOLIDATED OPERATIONS
(in millions)
Year ended December 31,
-----------------------
2000 1999 1998
Operating Revenues
Electric $ 6,854 $7,232 $7,191
Gas 2,783 1,996 1,733
Total operating revenues 9,637 9,228 8,924
Operating Expenses
Cost of electric energy 6,741 2,411 2,321
Deferred electric procurement cost (6,465) -- --
Cost of gas 1,425 738 621
Operating and maintenance 2,687 2,522 2,668
Depreciation, amortization, and decommissioning 3,511 1,564 1,438
Provision for loss on generation-related regulatory assets and undercollected
purchased power costs 6,939 -- --
Total operating expenses 14,838 7,235 7,048
Operating Income (Loss) (5,201) 1,993 1,876
Interest income 186 45 96
Interest expense (619) (593) (621)
Other income (expense), net (3) (9) 7
Income (Loss) Before Income Taxes (5,637) 1,436 1,358
Income taxes provision (benefit) (2,154) 648 629
Net Income (Loss) (3,483) 788 729
Preferred dividend requirement 25 25 27
Income (Loss) Available for (Allocated to) Common Stock $(3,508) $ 763 $ 702
The accompanying Notes to the Consolidated Financial Statements are an integral
part of this statement.
Pacific Gas and Electric Company
CONSOLIDATED BALANCE SHEETS
(in millions, except share amounts)
Balance at
December 31,
------------
2000 1999
ASSETS
Current Assets
Cash and cash equivalents $ 111 $ 80
Short-term investments 1,283 21
Accounts receivable
Customers (net of allowance for doubtful accounts of $52 million
and $46 million, respectively) 1,711 1,201
Related parties 6 9
Regulatory balancing account 222 --
Inventories
Gas stored underground and fuel oil 146 139
Materials and supplies 134 155
Income taxes receivable 1,120 --
Prepaid expenses and other 45 34
Deferred income taxes -- 119
Total current assets 4,778 1,758
Property, Plant, and Equipment
Electric 16,335 15,762
Gas 7,537 7,239
Construction work in progress 249 214
Total property, plant, and equipment (at original cost) 24,121 23,215
Accumulated depreciation and decommissioning (11,120) (10,497)
Net property, plant, and equipment 13,001 12,718
Other Noncurrent Assets
Regulatory assets 1,716 4,895
Nuclear decommissioning funds 1,328 1,264
Other 1,165 835
Total noncurrent assets 4,209 6,994
TOTAL ASSETS $ 21,988 $ 21,470
Pacific Gas and Electric Company
CONSOLIDATED BALANCE SHEETS
(in millions, except share amounts)
Balance at
December 31,
------------
2000 1999
LIABILITIES AND EQUITY
Current Liabilities
Short-term borrowings $ 3,079 $ 449
Long-term debt, classified as current 2,374 465
Current portion of rate reduction bonds 290 290
Accounts payable
Trade creditors 3,688 577
Related parties 138 216
Regulatory balancing accounts 196 384
Other 363 333
Accrued taxes -- 118
Deferred income taxes 172 --
Other 670 529
Total current liabilities 10,970 3,361
Noncurrent Liabilities
Long-term debt 3,342 4,877
Rate reduction bonds 1,740 2,031
Deferred income taxes 929 2,510
Deferred tax credits 192 231
Other 2,968 2,252
Total noncurrent liabilities 9,171 11,901
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 shares 1,606 1,606
Common stock held by subsidiary, at cost, 19,481,213 shares and 7,627,765 shares,
respectively (475) (200)
Additional paid-in capital 1,964 1,964
Reinvested earnings (Accumulated Deficit) (1,979) 2,107
Total stockholders' equity 1,410 5,771
Commitments and Contingencies (Notes 1, 2, 7, 14, and 15) -- --
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $21,988 $21,470
The accompanying Notes to the Consolidated Financial Statements are an integral
part of this statement.
Pacific Gas and Electric Company
STATEMENTS OF CONSOLIDATED CASH FLOWS
(in millions)
For the year ended
December 31,
------------
2000 1999 1998
Cash Flows From Operating Activities
Net income (loss) $(3,483) $ 788 $ 729
Adjustments to reconcile net income to net cash (used) provided by operating
activities:
Depreciation, amortization, and decommissioning 3,511 1,564 1,438
Deferred electric procurement costs (6,465) -- --
Deferred income taxes and tax credits--net (930) (485) (257)
Other deferred charges and noncurrent liabilities 480 101 31
Provision for loss on generation-related regulatory assets and
undercollected purchased power costs 6,939 -- --
Net effect of changes in operating assets and liabilities:
Short-term investments (1,262) (4) 1,126
Accounts receivable (507) 187 266
Income taxes receivable (1,120) -- --
Accounts payable 3,063 15 203
Regulatory balancing accounts (410) 305 537
Accrued taxes (118) 116 (227)
Other working capital 125 (39) (71)
Other--net (522) (352) (39)
Net cash (used) provided by operating activities (699) 2,196 3,736
Cash Flows From Investing Activities
Capital expenditures (1,245) (1,181) (1,382)
Proceeds from sale of assets 6 1,014 501
Other--net 32 234 40
Net cash used by investing activities (1,207) 67 (841)
Cash Flows From Financing Activities
Net borrowings (repayments) under credit facilities 2,630 (219) 668
Long-term debt issued 680 -- --
Long-term debt matured, redeemed, or repurchased (597) (672) (1,413)
Preferred stock redeemed or repurchased -- -- (108)
Common stock repurchased (275) (926) (1,600)
Dividends paid (475) (440) (444)
Other--net (26) 1 (5)
Net cash provided (used) by financing activities 1,937 (2,256) (2,902)
Net Change in Cash and Cash Equivalents 31 7 (7)
Cash and Cash Equivalents at January 1 80 73 80
Cash and Cash Equivalents at December 31 $ 111 $ 80 $ 73
Supplemental disclosures of cash flow information
Cash paid for:
Interest (net of amounts capitalized) $ 587 $ 531 $ 600
Income taxes (net of refunds) -- 1,001 1,115
The accompanying Notes to the Consolidated Financial Statements are an integral
part of this statement.
Pacific Gas and Electric Company
STATEMENTS OF CONSOLIDATED STOCKHOLDERS' EQUITY
(in millions, except share amounts)
Preferred
Accumulated Stock
Addi- Common Reinvested Other Total Without Compre-
tional Stock Earnings Compre- Common Mandatory hensive
Common Paid-in Held by (Accumulated hensive Stock Redemption Income
Stock Capital Subsidiary Deficit) (Loss) Equity Provisions (Loss)
Balance December 31, 1997 $2,018 $2,564 $ -- $ 2,671 $-- 7,253 $402
Net income -- -- -- 729 -- 729 -- $ 729
Foreign currency translation
adjustments -- -- -- -- (1) (1) -- (1)
Comprehensive income -- -- -- -- -- -- -- $ 728
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 -- -- -- 11 (10)
Balance December 31, 1998 $1,707 $2,087 -- $ 2,261 (1) $ 6,054 $294
Net income -- -- -- 788 -- 788 -- $ 788
Foreign currency translation
adjustments -- -- -- -- 1 1 -- 1
Comprehensive income -- -- -- -- -- -- -- $ 789
Common stock repurchased
(27,666,460 shares) (101) (123) (200) (502) -- (926) --
Cash dividends declared
Preferred stock -- -- -- (25) -- (25) --
Common stock -- -- -- (415) -- (415) --
Balance December 31, 1999 $1,606 $1,964 $(200) $ 2,107 -- $ 5,477 $294
Net loss -- -- -- (3,483) -- (3,483) -- $(3,483)
Common stock repurchased
(11,853,448 shares) -- -- (275) -- -- (275) --
Cash dividends declared
Preferred stock -- -- -- (25) -- (25) --
Common stock -- -- -- (578) -- (578) --
Balance December 31, 2000 $1,606 $1,964 $(475) $(1,979) $-- $ 1,116 $294
The accompanying Notes to the Consolidated Financial Statements are an integral
part of this statement.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
Note 1: General
Basis of Presentation
PG&E Corporation was incorporated in California in 1995 and became the
holding company of Pacific Gas and Electric Company (the Utility) on January 1,
1997. The Utility, incorporated in California in 1905, is 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.
As discussed further in Notes 2 and 3, on April 6, 2001, the Utility filed a
voluntary petition for relief under provisions of Chapter 11 of the U.S.
Bankruptcy Code. Pursuant to Chapter 11 of the U.S. Bankruptcy Code, the Utility
retains control of its assets and is authorized to operate its business as a
debtor in possesion while being subject to the jurisdiction of the Bankruptcy
Court.
This is a combined annual report of PG&E Corporation and the Utility.
Therefore, the Notes to the 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 inter-company
transactions have been eliminated from the consolidated financial statements.
The preparation of financial statements in conformity with accounting
principles generally accepted in the United States of America 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. PG&E Corporation's Northern and Central California energy
utility subsidiary, the Utility, delivers electric service to approximately 4.6
million customers and natural gas service to approximately 3.8 million
customers. PG&E Corporation's PG&E National Energy Group, Inc. (NEG) markets
energy services and products throughout North America.
The NEG is an integrated energy company with a strategic focus on power
generation, new power plant development, natural gas transmission, and wholesale
energy marketing and trading in North America. NEG businesses include its power
plant development and generation unit, PG&E Generating Company, LLC and its
affiliates (collectively, PG&E Gen); its natural gas transmission unit, PG&E Gas
Transmission Corporation (PG&E GT); and its wholesale energy and marketing
trading unit, PG&E Energy Trading Holdings Corporation, which owns PG&E Energy
Trading-Gas Corporation and PG&E Energy Trading-Power, L.P. (collectively, PG&E
Energy Trading or PG&E ET). During 2000, NEG sold its energy services unit, PG&E
Energy Services Corporation (PG&E ES). Also, during the fourth quarter of 2000,
NEG sold its Texas natural gas and natural gas liquids business carried on
through PG&E Gas Transmission, Texas Corporation and PG&E Gas Transmission Teco,
Inc. and their subsidiaries (PG&E GTT).
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 commercial paper with original maturities of three months or
less when purchased.
Restricted Cash
Restricted cash includes cash and cash equivalents, as defined above, which
are restricted under the terms of certain agreements for payment to third
parties, primarily for debt service. Restricted cash included under Cash and
Cash Equivalents in PG&E Corporation's and the Utility's Consolidated Balance
Sheets as of December 31, 2000 and 1999 is as follows:
(in millions) 2000 1999
Utility $ 50 $ 42
National Energy Group 53 81
Inventories
Inventories include materials and supplies, gas stored underground, coal,
and fuel oil. Materials and supplies, coal, and gas stored underground are
valued at average cost, except for the gas storage inventory of PG&E ET, which
is recorded at fair value. Fuel oil is valued by the last-in first-out method.
Income Taxes
PG&E Corporation and the Utility use the liability method of accounting for
income taxes. Income tax expense (benefit) 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% 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.
Earnings (Loss) Per Share
Basic earnings (loss) per share is computed by dividing net income (loss)
by the weighted average number of common shares outstanding during the period.
Diluted earnings per share is computed by dividing net income (loss) by the
weighted average number of common shares outstanding plus the assumed issuance
of common shares for all potentially dilutive securities.
The following is a reconciliation of PG&E Corporation's net income (loss)
and weighted average common shares outstanding for calculating basic and diluted
net income (loss) per share.
Years ended December 31,
-----------------------
(in millions) 2000 1999 1998
Income (loss) from continuing operations $(3,324) $ 13 $ 771
Discontinued operations (40) (98) (52)
Net income (Loss) before cumulative effect of accounting
change (3,364) (85) 719
Cumulative effect of accounting change -- 12 --
Net Income (Loss) $(3,364) $ (73) $ 719
Earnings (Loss) per common share, Basic and Diluted:
Weighted average common shares outstanding 362 368 382
Income (Loss) from continuing operations $ (9.18) $ 0.04 $ 2.02
Discontinued operations (0.11) (0.27) (0.14)
Cumulative effect of accounting change -- 0.03 --
Net Income (Loss) $ (9.29) $(0.20) $ 1.88
The diluted share base for 2000 excludes incremental shares of 2 million
related to employee stock options. These shares are excluded due to the anti-
dilutive effect as a result of the loss from continuing operations. For 1999 and
1998, the assumed conversion of stock options issued under the long-term
incentive plan increased the weighted average shares outstanding for dilutive
purposes to 369 million and 383 million, respectively. PG&E Corporation reflects
the preferred dividends of subsidiaries as other expense for computation of both
basic and diluted earnings per share.
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.
Capitalized interest and AFUDC for PG&E Corporation amounted to $19 million, $18
million, and $28 million for the years ended December 31, 2000, 1999, and 1998,
respectively. Capitalized interest and AFUDC for the Utility amounted to $18
million, $16 million, and $26 million for the years ended December 31, 2000,
1999, and 1998, respectively. 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 NEG businesses that apply Statement of Financial Accounting
Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of
Regulation," as amended. For the remainder of the NEG business operations, the
cost and accumulated depreciation of property, plant, and equipment retired or
otherwise disposed of is removed from related accounts and included in the
determination of the gain or loss on disposition.
Property, plant, and equipment are depreciated using a straight-line
remaining-life method. PG&E Corporation's composite depreciation rates were
4.44%, 3.60%, and 3.89% for the years ended December 31, 2000, 1999, and 1998,
respectively. The Utility's composite depreciation rates were 4.54 %, 3.41%, and
3.88% for the years ended December 31, 2000, 1999, and 1998, respectively.
Estimated useful lives of property, plant, and equipment are as follows:
Utility Non-Utility
Electric generating facilities 20 to 50 years 20 to 50 years
Electric distribution facilities 10 to 63 years N/A
Electric transmission 27 to 65 years N/A
Gas distribution facilities 28 to 49 years N/A
Gas transmission 25 to 45 years 22 to 40 years
Gas storage 25 to 48 years N/A
Other 5 to 38 years 2 to 7 years
The useful life of the Utility's property, plant, and equipment complies
with CPUC-authorized ranges.
Capitalized Software Costs
Costs incurred during the application development stage of internal use
software projects are capitalized. At December 31, 2000 and 1999, capitalized
software costs totaled $235 million and $216 million, net of $80 million and $59
million accumulated amortization, respectively. Such capitalized amounts are
amortized in accordance with
regulatory requirements ratably over the expected lives of the projects when
they become operational, over periods ranging from 2 to 15 years.
Gains and Losses on Reacquired Debt
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 amortization period of the debt reacquired,
consistent with ratemaking principles. Gains and losses on reacquired debt
associated with unregulated operations are recognized in earnings as
extraordinary gains or losses at the time such debt is reacquired.
Intangible Assets and Asset Impairment
PG&E Corporation amortizes the excess of purchase price over fair value of
net assets of businesses acquired (goodwill) using the straight-line method over
periods ranging from 5 to 40 years. PG&E Corporation periodically assesses
goodwill and intangible assets for potential impairment.
PG&E Corporation and the Utility periodically evaluate long-lived assets,
including property, plant, and equipment, goodwill, and specifically
identifiable intangible assets, when events or changes in circumstances indicate
that the carrying value of these assets may be impaired. The determination of
whether impairment has occurred is based on an estimate of undiscounted cash
flows attributable to the assets, as compared to the carrying value of the
assets.
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.
Regulation and Statement of Financial Accounting Standards (SFAS) No. 71
The Utility is regulated by the CPUC, the FERC, and the Nuclear Regulatory
Commission (NRC), among others. The gas transmission business in the Pacific
Northwest is regulated by the FERC.
PG&E Corporation and the Utility account for the financial effects of
regulation in accordance with SFAS No. 71. This statement allows for the
recording of a regulatory asset or liability for costs that will be collected or
refunded through the ratemaking process in the future.
Regulatory assets comprise the following:
Balance at
December 31,
------------
(in millions) 2000 1999
Rate Reduction Bonds/(1)/ $1,178 $ 727
Unamortized loss, net of gain, on reacquired debt 342 376
Regulatory assets for deferred income tax 160 705
Transition Revenue Account/(1)/ -- 69
Transition Cost Balancing Account/(1)/ -- 220
Diablo Canyon/(1)/ -- 1,891
Other, net 36 907
Total Utility regulatory assets $1,716 $4,895
PG&E GTN 57 62
Total PG&E Corporation regulatory assets $1,773 $4,957
(1) See Note 2 of the Notes to the Consolidated Financial Statements for
further discussion.
Regulatory assets are amortized over the period that the costs are
reflected in regulated revenues. The Utility has amortized its eligible
generation-related transition costs, including the Transition Cost Balancing
Account (TCBA) and the regulatory assets related to Diablo Canyon, over the
transition period in conjunction with the available competition transition
charge (CTC) revenues.
During 2000, the energy crisis materially and adversely affected PG&E
Corporation's and the Utility's cash flow and liquidity and created substantial
uncertainty about their prospects for the future. As a result, the Utility can
no longer conclude that energy costs, which have been deferred on its balance
sheet in accordance with SFAS No. 71, are probable of recovery through future
rates. Accordingly, the Utility wrote off the generation-related transition
costs and undercollected purchased power costs at December 31, 2000 (see Note 2
of the Notes to the Consolidated Financial Statements).
In general, the Utility does not earn a return on regulatory assets where
the related costs do no accrue interest. At December 31, 2000, the Utility did
not earn a return on the regulatory asset related to recording deferred taxes as
required by SFAS No. 109 "Accounting for Income Taxes" of $160 million. During
2000, all other assets that did not earn a return were recovered or written off
as referred to above.
At December 31, 1999, the Utility did not earn a return on (1) the $410
million regulatory asset related to recording deferred taxes as required by SFAS
No. 109, (2) the regulatory asset related to the Western Area Power
Administration contract of $86 million, and (3) a regulatory asset related to
the generation portion of certain employee benefits of $15 million.
Revenues and Regulatory Balancing Accounts
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.
Revenue Recognition
Revenues derived from power generation are recognized upon output, product
delivery, or satisfaction of specific targets, all as specified by contractual
terms. Regulated gas transmission revenues are recorded as services are
provided, based on rate schedules approved by the FERC. Substantially all of
PG&E ET's operations are accounted for under a mark-to-market accounting
methodology.
Staff Accounting Bulletin (SAB) No. 101, "Revenue Recognition," was issued
by the Securities and Exchange Commission (SEC), on December 3, 1999. SAB No.
101, as amended, summarizes certain of the SEC staff's views in applying
accounting principles generally accepted in the United States of America to
revenue recognition in financial statements. PG&E Corporation's consolidated
financial statements reflect the accounting principles provided in SAB No. 101.
Accounting for Price Risk Management Activities
PG&E Corporation, primarily through its subsidiaries, engages in price risk
management activities for both trading and non-trading purposes. PG&E
Corporation conducts trading activities principally through its unregulated
lines of business. Trading activities are conducted to generate profit, create
liquidity, and maintain a market presence. Net open positions often exist or are
established due to the NEG's assessment of and response to changing market
conditions. Non-trading activities are conducted to optimize and secure the
return on risk capital deployed within the NEG's existing asset and contractual
portfolio. In addition, non-trading activity exists within the Utility to hedge
against price fluctuations of electricity and natural gas.
Derivative and other financial instruments associated with electricity,
natural gas, natural gas liquids, and related trading activities are accounted
for using the mark-to-market method of accounting. Under mark-to-market
accounting, PG&E Corporation's trading 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
43
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
or interest rate movements, are recognized in operating income in the period of
change. Unrealized gains and losses on these contract portfolios are recorded as
assets and liabilities, respectively, from price risk management.
In addition to the trading activities, as discussed previously, PG&E
Corporation may engage in non-trading 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 non-trading
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 underlying item settles, 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.
PG&E Corporation and the Utility will adopt SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Activities," as amended by SFAS No. 138,
"Accounting for Certain Derivative Instruments and Certain Hedging Activities"
effective January 1, 2001. The Statement will require PG&E Corporation and the
Utility to recognize all derivatives, as defined in the Statement, on the
balance sheet at fair value. Derivatives, or any portion thereof, that are not
effective hedges must be adjusted to fair value through income. If derivatives
are effective hedges, depending on the nature of the hedges, changes in the fair
value of derivatives either will be offset against the change in fair value of
the hedged assets, liabilities, or firm commitments through earnings, or will be
recognized in other comprehensive income until the hedged items are recognized
in earnings. PG&E Corporation estimates that the transition adjustment to
implement this new standard will be a non-material reduction of net earnings and
a negative adjustment of $377 million to other comprehensive income. The Utility
estimates that the transition adjustment to implement this new standard will be
a non-material reduction of net earnings and a negative adjustment of $44
million to other comprehensive income. These adjustments will be recognized as
of January 1, 2001 as a cumulative effect of a change in accounting principle.
The ongoing effects will depend on the future market conditions and hedging
activities at PG&E Corporation and the Utility.
PG&E Corporation and the Utility have certain derivative commodity
contracts for the physical delivery of purchase quantities transacted in the
normal course of business. At this time, these derivatives are exempt from the
requirements of SFAS No. 133 under the normal purchases and sales exception, and
thus will not be reflected on the balance sheet at fair value. The Derivative
Implementation Group of the Financial Accounting Standards Board is currently
evaluating the definition of normal purchases and sales. As such, certain
derivative commodity contracts may no longer be exempt from the requirements of
SFAS No. 133. PG&E Corporation and the Utility will evaluate the impact of the
implementation guidance on a prospective basis when the final decision regarding
this issue is resolved.
Comprehensive Income
PG&E Corporation's and the Utility's comprehensive income consists of net
income and other items recorded directly to the equity accounts. The objective
is to report a measure of all changes in equity of an enterprise that result
from transactions and other economic events of the period other than
transactions with shareholders. PG&E Corporation's and the Utility's other
comprehensive income consists principally of foreign currency translation
adjustments and will include changes in the market value of certain financial
hedges upon the implementation of SFAS No. 133 on January 1, 2001. See
Accounting for Price Risk Management Activities above for discussion of
implementation of SFAS No. 133.
Cumulative Effect of Change in Accounting Method
Effective January 1, 1999, PG&E Corporation changed its method of
accounting for major maintenance and overhauls of generating assets at the NEG.
Beginning January 1, 1999, the cost of major maintenance and overhauls of
generating assets, 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)
as of December 31, 1999, reflecting the cumulative effect of the change in
accounting principle. The Utility has consistently accounted for major
maintenance and overhauls as incurred.
44
Related Party Agreements
In accordance with various agreements, the Utility and other subsidiaries
provide and receive various services from their parent, PG&E Corporation. The
Utility and PG&E Corporation exchange administrative and professional support
services in support of operations. These services are priced at either the fully
loaded cost or at the higher of fully loaded cost or fair market value depending
on the nature of the services provided. PG&E Corporation also allocates certain
other corporate administrative and general costs to the Utility and other
subsidiaries using a variety of factors, including their share of employees,
operating expenses, assets, and other cost causal methods. Additionally, the
Utility purchases gas commodity and transmission services and sells reservation
and other ancillary services to the NEG. These services are priced at either
tariff rates or fair market value depending on the nature of the services
provided. Intercompany transactions are eliminated in consolidation and no
profit results from these transactions. For the years ended December 31, 2000,
1999, and 1998, the Utility's significant related party transactions were as
follows:
(in millions) 2000 1999 1998
Utility revenues from:
Administrative services provided to PG&E Corporation $ 12 $ 23 $ 17
Transportation and distribution services provided to PG&E ES -- 134 --
Gas reservation services provided to PG&E ET 12 7 1
Other 2 3 4
Utility expenses from:
Administrative services received from PG&E Corporation $ 83 $ 66 $ 58
Gas commodity and transmission services received from PG&E ET 136 30 1
Transmission services received from PG&E GT 46 47 49
Stock-based Compensation
PG&E Corporation accounts for stock-based compensation using the intrinsic
value method in accordance with the provisions of Accounting Principles Board
Opinion No. 25, "Accounting for Stock Issued to Employees," as allowed by SFAS
No. 123, "Accounting for Stock-Based Compensation." Under the intrinsic value
method, PG&E Corporation does not recognize any compensation expense as the
exercise price of all stock options is equal to the fair market value at the
time the options are granted.
Reclassifications
Certain amounts in 1999 and 1998 financial statements have been
reclassified to conform to the 2000 presentation.
Note 2: The California Energy Crisis
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. Electric industry restructuring was mandated
by the California Legislature in Assembly Bill 1890 (AB 1890). The electric
industry restructuring established a transition period, mandated a rate freeze,
included a plan for recovery of uneconomic generation-related costs (transition
costs), and encouraged the disposition of a portion of utility-owned generation
facilities. The competitive market framework called for the creation of the
Power Exchange (PX) and the Independent System Operator (ISO). The PX would
establish market-clearing prices for electricity, and the ISO would schedule
delivery of electricity for all market participants and operate certain markets
for electricity. The Utility was required to purchase electricity for its
customers through the PX and ISO. Customers were given the choice of continuing
to buy electricity from the Utility or buying electricity from independent power
generators or retail electricity suppliers. Most of the Utility's customers
continued to buy electricity through the Utility.
Beginning in June 2000, wholesale prices for electricity sold through the
PX and ISO experienced unanticipated and massive increases. The average price of
electricity purchased by the Utility for the benefit of its customers was 18.2
cents per kWh for the period of June 1 through December 31, 2000, compared to
4.2 cents per kWh during the same period in 1999. The Utility was only permitted
to collect approximately 5.4 cents per kWh in rates from its customers
45
during that period. The increased cost of the purchased electricity has strained
the financial resources of the Utility. Because of the rate freeze, the Utility
was unable to pass on the increases in power costs to its customers through
current rates. In order to finance the higher costs of energy, during the third
and fourth quarter of 2000, the Utility increased its lines of credit to $1,850
million (net increase of $850 million), issued $1,240 million of debt under a
364-day facility, and issued $680 million of five-year notes.
The Utility continued to finance the higher costs of wholesale electric
power while interested parties evaluated various solutions to the energy crisis.
In November 2000, the Utility filed its Rate Stabilization Plan (RSP), which
sought to end the rate freeze and pass along the increased wholesale electric
costs to customers through increased rates. The CPUC evaluated the Utility's
proposal and deferred its decision until after hearings could be held, although
the CPUC did increase rates one cent per kWh for 90 days effective January 4,
2001. This increase resulted in approximately $70 million of additional revenue
per month, which was not nearly enough to cover the higher wholesale costs of
electricity, nor did it help with the costs already incurred.
By December 31, 2000, the Utility had borrowed more than $3.0 billion under
its various credit facilities to pay its energy costs. As a result of the
California energy crisis and its impact on the Utility's financial resources,
PG&E Corporation's and the Utility's credit rating deteriorated to below
investment grade in January 2001. This credit downgrade precluded PG&E
Corporation and the Utility from access to capital markets. Commencing in
January 2001, PG&E Corporation and the Utility began to default on maturing
commercial paper. In addition, the Utility became unable to pay the full amount
of invoices received for wholesale power purchases and made only partial
payments. The Utility had no credit under which it could purchase wholesale
electricity on behalf of its customers on a continuing basis and generators were
only selling to the Utility under emergency actions taken by the U.S. Secretary
of Energy.
In January 2001 the California Legislature and the Governor authorized the
California Department of Water Resources (DWR) to purchase wholesale electric
energy on behalf of the Utility's retail customers. In February 2001, the
California Legislature passed California Assembly Bill 1X (AB 1X), which
authorized the DWR to purchase wholesale electricity on behalf of the Utility's
customers.
On March 27, 2001, the CPUC authorized an average increase in retail rates
of 3.0 cents per kWh, which was in addition to the emergency 1.0 cent per kWh
surcharge adopted on January 4, 2001 by the CPUC. The revenue generated by this
rate increase is to be used only for electric power procurement costs that are
incurred after March 27, 2001. Although the rate increase is authorized
immediately, the 3.0 cent surcharge will not be collected in rates until the
CPUC establishes the rate design which is not expected to be adopted until May
2001.
As more fully described below, the energy crisis has materially and
adversely affected the Utility's cash flow and liquidity and has created
substantial uncertainty about their prospects for the future. As a result, the
Utility can no longer conclude that energy costs, which had been deferred on its
balance sheet in accordance with SFAS No. 71, are probable of recovery through
future rates. Accordingly, the Utility has taken a charge against earnings of
$6.9 billion ($4.1 billion after tax) to write off its remaining generation-
related regulatory assets and undercollected purchased power costs. This charge
has resulted in an accumulated deficit at the Utility of $2.0 billion as of
December 31, 2000. PG&E Corporation's accumulated deficit at December 31, 2000
is $2.1 billion. Further, the Utility does not have authority to recover any
purchased power costs it incurs during 2001 in excess of revenues from retail
rates. Such amounts also will be charged against earnings, as incurred, absent a
regulatory or legislative solution that provides for recovery of such costs.
Under SFAS No. 71, if a rate mechanism provided by legislation or other
regulatory authority is subsequently established that makes recovery from
regulated rates probable as to all or a portion of the undercollection that was
previously charged against earnings, a regulatory asset will be reinstated with
a corresponding increase in earnings.
As discussed more fully herein, the Utility is seeking resolution on many
fronts. The ongoing uncertainty and lack of successful resolution continues to
have a negative impact on the Utility's ability to obtain funding and pay its
debt and power procurement liabilities. As discussed further in Note 3, on April
6, 2001, the Utility sought protection from its creditors through a Chapter 11
bankruptcy filing. The filing for bankruptcy and the related uncertainty around
any reorganization plan that is ultimately adopted will have a significant
impact on the Utility's future liquidity and results of operations. PG&E
Corporation, itself, had cash of $297 million at March 29, 2001 and believes
that the funds will be adequate to maintain its operations through and beyond
2001. In addition, PG&E Corporation believes that PG&E Corporation, itself, and
its other subsidiaries not subject to CPUC regulation are substantially
protected from the continuing liquidity and financial difficulties of the
Utility. A discussion of the events leading up to the charge, PG&E Corporation's
and the Utility's mitigation efforts and the ongoing uncertainty follows.
46
Transition Period and Rate Freeze
California's deregulation legislation passed by the California Legislature
in 1996 established a transition period, which was to begin in 1998. During this
period, electric rates for all customers were frozen at 1996 levels, with rates
for residential and small commercial customers being reduced in 1998 by 10% and
frozen at that level. During the transition period, investor-owned utilities
were given the opportunity to recover their transition costs. Transition costs
were generation-related costs that proved to be uneconomic under the new
industry structure.
To pay for the 10% 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 sale of 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 the transition costs until after the
transition period. During the rate freeze, the rate reduction bond debt service
did not increase the Utility customers' electric rates (See Note 9). If the
transition period ends before March 31, 2002, 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.
The rate freeze was scheduled to end on the earlier of March 31, 2002 or
the date the Utility has recovered all of its transition costs. The Utility
believes it recovered its eligible transition costs during August 2000 or
potentially earlier as a result of recording a credit to the Utility's account
for tracking the recovery of transition costs in recognition of the fair market
value of the Utility's hydroelectric generation facilities. On August 31, 2000,
the Utility recorded a $2.1 billion credit to the Utility's account for tracking
the recovery of the TCBA, which was an amount by which a negotiated $2.8 billion
hydroelectric generation asset valuation exceeded the aggregate book value of
such assets. At August 31, 2000, there was a balance of approximately $2.2
billion of undercollected wholesale electricity costs recorded in the regulatory
balancing account called the Transition Revenue Account (TRA). If the final
valuation for the hydroelectric assets is greater than $2.8 billion, as the
Utility expects, the Utility will have recovered its transition costs earlier.
The undercollected TRA balance as of the end of the earlier determined
transition period will be less than the August 31 balance of $2.2 billion, and
could be zero depending on the ultimate valuation of the hydroelectric
generating facilities and when the transition period actually ends. However, the
CPUC has not yet accepted the Utility's estimated market valuation of its
hydroelectric assets nor has the CPUC determined that the rate freeze has ended.
Wholesale Prices of Electricity
As previously stated, beginning in June 2000, the Utility experienced
unanticipated and massive increases in the wholesale costs of the electricity
purchased from the PX and ISO on behalf of its retail customers. For the year
ended December 31, 2000 and 1999, the average monthly prices in cents per kWh
that the PX and ISO charged the Utility for electricity were as follows:
2000 1999
January 4.38 3.15
February 3.78 2.87
March 3.24 2.87
April 3.28 2.90
May 6.08 2.82
June 16.33 2.95
July 11.00 3.85
August 18.70 4.10
September 13.82 4.09
October 13.62 6.18
November 20.43 4.46
December 33.24 3.97
It is expected that the wholesale costs will continue to be extremely high
through 2001 unless significant changes occur in the wholesale electricity
market. The generation-related cost component, which provides for recovery of
47
wholesale electricity purchased by the Utility and, if available, for recovery
of transition cost, was approximately 5.4 cents per kWh, during 2000.
The excess of wholesale electricity costs above the generation-related cost
component available in frozen rates was deferred to the TRA. The TRA balance as
of December 31, 2000, prior to being written off against earnings, was an
undercollection of approximately $6.6 billion. Under current CPUC decisions, if
the TRA undercollection is not recovered through frozen rates by the end of the
transition period, it cannot be recovered or offset against overcollections of
transition cost recovery. Once the transition period has ended and the rate
freeze is over, the Utility's customers will be responsible for reasonable
wholesale electricity costs. However, actual changes in customer rates will not
occur until new retail rates are authorized by the CPUC or, to the extent
allowed, by the bankruptcy court.
The Utility has reviewed on an ongoing basis the facts and circumstances
relating to the TRA and remaining transition cost regulatory assets. Due to the
lack of regulatory, legislative, or judicial relief, the Utility has determined
that it can no longer conclude that its uncollected wholesale electricity costs
and remaining transition costs are probable of recovery in future rates.
Accordingly, the Utility wrote off, as a charge against earnings, the TRA and
TCBA of approximately $6.9 billion. In addition, absent a regulatory, judicial,
or legislative solution that provides for full recovery of such costs, the
Utility will be unable to defer the costs of wholesale power purchases in excess
of amounts recovered through rates in 2001 and such expenses are expected to
reduce the Utility's future earnings accordingly.
Transition Cost Recovery
Beginning January 1, 1998, the Utility started amortizing eligible
transition costs, including most generation-related regulatory assets. These
transition costs were offset by or recovered through the frozen rates, market
valuation of generation assets in excess of book value, net energy sales from
the Utility's electric generation facilities, and the amount by which long-term
contract prices to purchase electricity were lower than the PX price. Transition
costs and associated recoveries are recorded in the Utility's TCBA. During the
transition period, a reduced rate of return on common equity of 6.77% applies to
all generation assets, including those generation assets reclassified to
regulatory assets.
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. In
January 2001, the CPUC approved all non-nuclear transition costs that were
amortized from July 1, 1998, to June 30, 1999. The CPUC currently is reviewing
non-nuclear transition costs amortized from July 1, 1999, to June 30, 2000.
Mitigation Efforts
The Utility is actively exploring ways to reduce its exposure to the higher
wholesale electricity costs and to recover its written-off TRA and TCBA
balances. As previously indicated, the Utility believes the transition period
has ended and filed an application with the CPUC asking it to so rule. The
Utility has also filed a lawsuit against the CPUC in Federal District Court,
filed an application with the CPUC seeking approval of a five-year rate
stabilization plan, filed an application with the FERC to address the current
market crisis, worked with interested parties to address power market
dysfunction before appropriate regulatory bodies, and hedged a portion of its
open procurement position against higher purchased power costs through forward
purchases. The Utility's actions and related activities are discussed below.
Application with the FERC
On October 16, 2000, the Utility joined with Southern California Edison and
The Utility Reform Network (TURN), in filing a petition with the FERC requesting
that the FERC (1) immediately find the California wholesale electricity market
to be not workably competitive and the resulting prices to be unjust and
unreasonable; (2) immediately impose a cap on the price for energy and ancillary
services; and (3) institute further expedited proceedings regarding the market
failure, mitigation of market power, structural solutions, and responsibility
for refunds. However, the reduced price cap requested, even if approved, would
still be above the approximate 5.4 cents per kWh available through frozen rates
for the payment of the Utility's wholesale electricity costs.
On December 15, 2000, the FERC issued an order in response to the above
filing. The remedies proposed by the FERC include, among other things: (1)
eliminating the requirement that the California investor-owned utilities must
sell all of their power into, and buy all of their power needs from, the PX; (2)
modifying the single price auction so that bids above $150 per megawatt hour
(MWh) (15 cents per kWh) cannot set the market clearing prices paid to all
bidders, effective January 1, 2001 through April 30, 2001; (3) establishing an
independent governing board for the ISO; and
48
(4) establishing penalties for under-scheduling power loads. The FERC did not
order any refunds based on its findings, but announced its intent to retain the
discretion to order refunds for wholesale electricity costs incurred from
October 2000 through December 31, 2002. In March 2001, the FERC ordered refunds
of $69 million for January 2001 and indicated it would continue to review
December 2000 wholesale prices. The generators have appealed the decision. Any
refunds will be offset against amounts owed the generators.
Federal Lawsuit
On November 8, 2000, the Utility filed a lawsuit in federal district court
in San Francisco against the CPUC. The Utility asked the court to declare that
the federally-approved wholesale electricity costs the Utility has incurred to
serve its customers are recoverable in retail rates both before and after the
end of the transition period. The lawsuit states that the wholesale power costs
the Utility has incurred are paid pursuant to filed rates, which the FERC has
authorized and approved and that under the United States Constitution and
numerous federal court decisions, state regulators cannot disallow such costs.
The Utility's lawsuit also alleges that to the extent that the Utility is denied
recovery of these mandated wholesale electricity costs by order of the CPUC,
such action constitutes an unlawful taking and confiscation of the Utility's
property. On January 29, 2001, the Utility's lawsuit was transferred to the
federal district court in Los Angeles where Southern California Edison has its
identical case pending.
Legislative Action
On February 1, 2001, the governor of California signed into law AB 1X. AB
1X extended a preliminary authority of the DWR to purchase power. Public
Utilities Code Section 360.5, adopted in AB 1X, authorizes the CPUC to determine
the portion of each electric utility's existing electric retail rate that
represents the difference between the generation related component of the
utility's retail rate in effect on January 5, 2001, and the sum of the costs of
the utility's own generation, qualifying facilities (QF) contracts, existing
bilateral contracts, and ancillary services (the California Procurement
Adjustment or CPA). The CPA is payable to the DWR by each utility upon receipt
from its retail end use customers.
49
The DWR has indicated that it intends to buy power only at "reasonable
prices" to meet the power needs of the retail electric customer that cannot be
met by the utility-owned generation or power under contract to the utilities;
i.e. the utilities' net open position. As the DWR has set a yet undisclosed
ceiling on what it will pay for power, the ISO has been left to pay the
remainder. The ISO has purchased energy at costs above the DWR's ceiling and, in
turn, is expected to bill the Utility for those costs. AB 1X does not address
whether or how the Utility will be able to pay for or recover purchase power
costs it has incurred because ISO purchases were not under the DWR's ceiling for
"reasonable prices." PG&E Corporation and the Utility cannot predict what
regulatory, legislative, or judicial actions may be taken with respect to this
issue.
In response to the ISO's concern over the weakened financial condition of
the Utility and its ability to pay for power purchases, on February 14, 2001,
the FERC issued an order stating that the ISO could not allow the Utility to
schedule power from a third party supplier, unless the Utility was creditworthy
or was backed by creditworthy parties. The FERC order also stated that the ISO
could continue to schedule power for the Utility as long as it comes from its
own generation units and is routed over its own transmission lines. The ISO has
stated that it will charge the Utility for the power it buys on an emergency
basis, despite the FERC ruling. On April 6, 2001, the FERC issued a further
order directing the ISO to implement its prior order which the FERC clarified
applies to all third -party transactions whether scheduled or not.
Rate Stabilization Plan (RSP)
On November 22, 2000, the Utility filed an application with the CPUC
seeking approval of a five-year RSP beginning on January 1, 2001. The Utility
requested an initial average rate increase of 22.4%. The Utility also proposed
that it receive actual costs, including a regulated return, for electricity
generation provided by it with the idea that profits that would have been
generated at market rates be recovered from customers later in the five-year
rate stabilization period. With respect to Diablo Canyon Nuclear Power Plant
(Diablo Canyon) the Utility has proposed to defer all profits (discussed below
in "Diablo Canyon Benefits Sharing"), until 2003, when the allocation of
revenues between ratepayers and shareholders will be readjusted. The
readjustment is intended to allow, by the end of 2005, the total net revenues
earned by Diablo Canyon, over the five-year plan, to be allocated equally
between shareholders and ratepayers according to existing CPUC decisions.
On January 4, 2001, the CPUC issued an emergency interim decision denying
the Utility's request for a rate increase. Instead, the decision permitted the
Utility to establish an interim surcharge applied to electric rates on an equal-
cents-per-kWh basis of 1.0 cent per kWh, subject to refund and adjustment. The
surcharge was to remain in effect for 90 days from the effective date of the
decision. The Utility was required to establish a balancing account to track the
revenue provided by the surcharge and to apply these revenues to ongoing
wholesale electricity costs. The surcharge was made permanent in the CPUC's
March 27, 2001 decision, referred to below.
On January 26, 2001, an assigned CPUC commissioner's ruling was issued in
the Utility's rate stabilization plan proceeding. The ruling stated that in
phase one of the case, the scope of the proceeding will include (1) reviewing
the independent audits of the utilities accounts to determine whether there is a
financial necessity for additional relief for the utilities, (2) reviewing
TURN's accounting proposal to transfer the undercollected balances in the
utilities' TRAs to their respective TCBAs and reviewing the generation
memorandum accounts, and (3) considering whether the rate freeze has ended only
on a prospective basis.
On January 30, 2001, the independent consultants engaged by the CPUC issued
their review report on the Utility's financial position as of December 31, 2000,
as well as that of PG&E Corporation and the Utility's affiliates. The review
found that the Utility made an accurate representation of its financial
situation noting accurate representations of its borrowing capabilities, credit
condition, and events of default. The review also found that the Utility
accurately represented recorded entries to its TRA and TCBA. The review alleged
certain deficiencies with respect to bidding strategies, cash conservation
matters, and cash flow forecast assumptions. The Utility filed rebuttal
testimony on February 14, 2001. Hearings to consider the issues and reports of
the independent consultants began on February 20, 2001.
On March 27, 2001, the CPUC ruled on parts of the Utility's RSP and granted
an increase in rates by adopting an average 3.0 cents per kWh surcharge.
Although the increase is authorized immediately, the 3.0 cents per kWh surcharge
will not be collected in rates until the CPUC establishes an appropriate rate
design for the surcharge, which is not expected to be adopted until May 2001, at
the earliest. The revenue generated by the rate increase is to be used only for
electric power procurement costs that are incurred after March 27, 2001. The
CPUC declared that the revenues generated
50
by this surcharge are subject to refund (1) if not used to pay for such power
purchases, (2) to the extent that generators and sellers of power make refunds
for overcollections, or (3) to the extent any administrative body or court
denies the refunds of overcollections in a proceeding where recovery has been
hampered by a lack of cooperation from the Utility. The 3.0 cents per kWh
surcharge is in addition to the emergency interim surcharge approved in January
4, 2001, which the CPUC made permanent in this decision. The CPUC also modified
accounting rules in response to a proposal made by TURN as described below.
Also, on March 27, 2001, the CPUC issued a decision ordering the Utility
and the other California investor-owned utilities to pay the DWR a per-kWh price
equal to the applicable generation-related retail rate per kWh established for
each utility as in effect on January 5, 2001, for each kWh the DWR sells to the
customers of each utility. The CPUC determined that the generation-related
component of retail rates should be equal to the total bundled electric rate
(including the 1 cent per kWh interim surcharge adopted by the CPUC on January
5, 2001) less the following non-generation-related rates or charges:
transmission, distribution, public purpose programs, nuclear decommissioning,
and the fixed transition amount. The CPUC determined that the Utility's company-
wide average generation-related rate component is 6.471 cents per kWh and that
this is the amount that should be paid to the DWR for each kWh delivered by the
DWR to the Utility's retail customers after February 1, 2001, until specific
rates are calculated. The CPUC ordered the utilities to pay the DWR within 45
days after the DWR supplies power to their retail customers, subject to
penalties for each day that payment is late. The amount of power supplied to
retail end-use customers after March 27, 2001, for which the DWR is entitled to
be paid would be based on the product of the number of kWh that the DWR provided
45 days earlier and the Utility's company-wide average generation-related rate
of 6.471 cents per kWh, and the additional 3 cent per kWh surcharge described
above.
The CPUC also ordered that the utilities immediately pay the sums owed to
the DWR for power sold by the DWR from January 18, 2001 through January 31,
2001, under California Senate Bill 7X. Based on an estimated number of kWh sold
by the DWR, the Utility paid approximately $30 million to the DWR at the rate of
5.471 cents per kWh as adopted by the CPUC.
In addition, on April 3, 2001, the CPUC adopted a method to calculate the
CPA, as described in Public Utilities Code Section 360.5 (added by AB 1X
effective February 1, 2001). Section 360.5 requires the CPUC to determine (1)
the portion of each electric utility's electric retail rate effective on January
5, 2001, the CPA, that is equal to the difference between the generation-related
component of the utility's retail rate in effect on January 5, 2001, and the sum
of the costs of the utility's own generation, QFs contracts, existing bilateral
contracts (i.e., entered into before February 1, 2001), and ancillary services,
and (2) the amount of the CPA that is allocable to the power sold by the DWR.
The CPUC decided that the CPA should be a set rate calculated by determining
each utility's generation-related revenues (for the Utility the CPUC has
proposed that this be equal to 6.471 cents per kWh multiplied by total kWh sales
by the Utility to the Utility's retail customers), then subtracting each
utility's statutorily authorized generation-related costs, and dividing the
result by each utility's total kWh sales. Each utility's CPA rate will be used
to determine the amount of bonds the DWR may issue.
Using the CPUC's methodology, but substituting the CPUC's cost assumptions
with actual expected costs and including costs the CPUC has refused to
recognize, the Utility's calculations show that the CPA for the 11-month period
February through December 2001 would be negative by $2.2 billion, (i.e., there
would be no CPA available to the DWR) assuming the DWR purchases 84% of the
Utility's net open position. (The net open position is the amount of power that
cannot be met by the utilities' own or contracted-for generation.) If AB 1X were
amended to also include in the CPA all the incremental revenue from the 3 cent
per kWh increase discussed above (approximately $2.3 billion for 11 months),
then the amount available to the DWR for the CPA for the comparable 11-month
period, assuming the Utility were allowed to recover its costs first, would be
approximately $100 million. The Utility believes the method adopted by the CPUC
is unlawful and inconsistent with Section 360.5 because, among other reasons, it
establishes a set rate that does not reflect actual residual revenues,
overstates the CPA by excluding and/or understating authorized costs, and to the
extent it is dedicated to the DWR does not allow the Utility to recover its own
revenue requirements and costs of service. The Utility intends to file an
application for rehearing of this decision.
The CPUC noted that although the DWR has assumed responsibility to purchase
some of the utilities' power requirements, it has not committed to purchase all
of the utilities' net open position. To the extent the DWR does not buy enough
power to cover the Utility's net open position, the ISO purchases emergency
power on the high-priced spot market to meet system reliability requirements and
the net open position. The ISO may attempt to charge the Utility a proportionate
share of the ISO's purchases. The Utility believes that under the current
circumstances and applicable tariffs it is not responsible for such ISO charges.
As the DWR has not advised the CPUC of its revenue requirement for the DWR's
power purchases, it is unclear how much of the 3 cent surcharge will be needed
by the DWR and how much, if
51
any, may be used by the Utility to recover its procurement costs incurred after
March 27, 2001 (including any ISO charges).
Since the end of January 2001, the Utility has been paying only 15% of
amounts due QFs. On March 27, 2001, the CPUC issued a decision requiring the
Utility and the other California investor-owned utilities to pay QFs fully for
energy deliveries made on and after the date of the decision, within 15 days of
the end of the QFs' billing period. The decision permits QFs to establish a 15-
day billing period as compared to the current monthly billing period. The CPUC
noted that its change to the payment provision was required to maintain energy
reliability in California and thus provided that failure to make a required
payment would result in a fine in the amount owed to the QF. The decision also
adopts a revised pricing formula relating to the California border price of gas
applicable to energy payments to all QFs, including those that do not use
natural gas as a fuel. Based on the Utility's preliminary review of the
decision, the revised pricing formula would reduce the Utility's 2001 average QF
energy and capacity payments from approximately 12.7 cents per kWh to 12.3 cents
per kWh.
The CPUC also adopted TURN's proposal to transfer on a monthly basis the
balance in each Utility's TRA to the Utility's TCBA. The TRA is a regulatory
balancing account that is credited with total revenue collected from ratepayers
through frozen rates and which tracks undercollected power purchase costs. The
TCBA is a regulatory balancing account that tracks the recovery of generation-
related transition costs. The accounting changes are retroactive to January 1,
1998. The Utility believes the CPUC is retroactively transforming the power
purchase costs in the TRA into transition costs in the TCBA. However, the CPUC
characterized the accounting changes as merely reducing the prior revenues
recorded in the TCBA, thereby affecting only the amount of transition cost
recovery achieved to date. The CPUC also ordered that the utilities restate and
record their generation memorandum account balances to the TRA on a monthly
basis before any transfer of generation revenues to the TCBA. The CPUC found
that based on the accounting changes, the conditions for meeting the end of the
rate freeze have not been met.
The Utility believes the adoption of TURN's proposed accounting changes
results in illegal retroactive ratemaking, constitutes an unconstitutional
taking of the Utility's property, and violates the federal filed rate doctrine.
The Utility also believes the other CPUC decisions are similarly illegal to the
extent they would compel the Utility to make payments to the DWR and QFs without
providing adequate revenues for such payments. The Utility plans to challenge
the decisions in appropriate legal forums.
Bilateral Contracts
Under the terms of AB 1890, the Utility was required to purchase all of its
power from the PX and ISO to meet the needs of its customers. On August 3, 2000,
after the California energy crisis had begun, the CPUC approved the Utility's
use of bilateral contracts, subject to the CPUC approving a set of standards or
criteria by which the reasonableness of such contracts would be reviewed on an
after-the-fact basis. The CPUC has yet to approve such standards or criteria.
In October 2000, the Utility entered into multiple bilateral contracts with
suppliers for long-term electricity deliveries. As of December 31, 2000, these
contracts ranged from approximately 1,228,000 MWhs to 6,344,800 MWhs of supply
annually. The contracts extended from 2001 to 2005. Each of the contracts was
for delivery beginning January 1, 2001 or later. As a result of the energy
crisis, certain of these contracts were terminated, subsequent to December 31,
2000.
PX Energy Credits
In accordance with CPUC regulations, the Utility provides a PX energy
credit to those customers (known as direct access customers) who have chosen to
buy their electric energy from an energy service provider (ESP) other than the
Utility. As wholesale power prices began to increase beginning in June 2000, the
level of PX credits increased correspondingly to the point where the credits
exceeded the Utility's distribution and transmission charges to direct access
customers. During 2000, the PX credits reduced electric revenue by $472 million,
although the Utility ceased paying most of these credits in December 2000. These
amounts are reflected on the accompanying consolidated balance sheet at December
31, 2000. As of March 29, 2001, the estimated total of accumulated credits for
direct access customers that have not been paid by the Utility is approximately
$503 million. The actual amount that will be refunded to ESPs will be dependent
upon when the rate freeze ends and whether there are any adjustments made to
wholesale energy prices by the FERC.
Generation Divestiture
In April 1999, the Utility sold three 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 a combined capacity of 3,065 MW.
In May 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 a combined capacity of 1,224 MW. The
Lake facility was sold at a gain of $8 million while the Sonoma facility was
sold at a loss of $39 million.
The gains from the sale of the fossil-fueled generation plants and the Lake
facility were used to offset other transition costs. Likewise, the loss from the
sale of the Sonoma 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.
Under the California electric industry restructuring legislation, the
valuation of the Utility's remaining generation assets (primarily its
hydroelectric facilities) must be completed by December 31, 2001. Any excess of
market value over the assets' book value would be used to offset the Utility's
transition costs.
In August 2000, the Utility and a number of interested parties filed an
application with the CPUC requesting that the CPUC approve a settlement
agreement reached by these parties. The agreement was filed in the Utility's
proceeding to determine the market value of its hydroelectric generation assets.
In this settlement agreement, the Utility indicated that it would transfer its
hydroelectric generation assets, at a negotiated value of $2.8 billion, to an
affiliate. Due to the high wholesale prices and the corresponding increase in
the value of its hydroelectric generation assets, in November 2000 as part of an
application with the CPUC seeking approval of a five-year RSP, the Utility
withdrew its support from the settlement agreement, eliminating it from
consideration in the proceeding.
In January 2001, California Assembly Bill 6 was passed which prohibits
disposal of any of the Utility's generation facilities, including the
hydroelectric facilities, prior to January 1, 2006. In December 2000, the
Utility submitted updated testimony in the hydroelectric valuation proceeding
indicating the market value of the hydroelectric assets ranges from $3.9 billion
to $4.2 billion assuming a competitive auction or other arms-length sale. At
December 31, 2000, the book value of the Utility's net investment in
hydroelectric generation assets was approximately $692 million.
Diablo Canyon Benefits Sharing
As required by a prior CPUC decision on June 30, 2000, the Utility filed an
application with the CPUC requesting approval of its proposal for sharing with
ratepayers 50% of the post-rate freeze net benefits of operating Diablo Canyon.
The net benefit sharing methodology proposed in the Utility's application would
be effective at the end of the current electric rate freeze for the Utility's
customers and would continue for as long as the Utility owned Diablo Canyon.
Under the proposal, the Utility would share the net benefits of operating Diablo
Canyon based on the audited profits from operations, determined consistent with
the prior CPUC decisions. If Diablo Canyon experiences losses, such losses would
be deferred and netted against profits in the calculation of the net benefits in
subsequent periods (or against profits in prior periods if subsequent profits
are insufficient to offset such losses). Any changes to the net sharing
methodology must be approved by the CPUC. The CPUC has suspended the proceedings
to consider the net benefit sharing proposal. In the Utility's RSP, parties have
proposed that the requirement to establish a sharing methodology be rescinded
and the Diablo Canyon be placed on cost-of-service ratemaking. It is uncertain
what future ratemaking will be applicable to Diablo Canyon.
Cost of Electric Energy
For the years ended December 31, 2000 and 1999, and the period March 31,
1998 (the PX establishment date) to December 31, 1998, the cost of electric
energy for the Utility, reflected on the Utility's Statement of Consolidated
Operations, comprises the cost of fuel for electric generation and QF purchases,
the cost of PX purchases, and ancillary services charged by the ISO, net of
sales to the PX, as follows:
Year Ended December 31,
------------------------
(in millions) 2000 1999 1998
Cost of fuel resources at market prices $ 9,512 $3,233 $ 3,370
Proceeds from sales to the PX (2,771) (822) (1,049)
Total Utility cost of electric energy $ 6,741 $2,411 $ 2,321
Note 3: Subsequent Events
Credit Rating Downgrades
As a result of the Utility's deteriorating financial condition from the
California energy crisis, the major credit agencies have downgraded the long-
term and short-term credit ratings of both PG&E Corporation and the Utility. The
following is a summary of current credit ratings by Standard & Poor's (S&P) and
Moody's Investors Service (Moody's) as of March 29, 2001, for the Utility:
Standard & Poors Current Ratings
Corporate credit rating D/D
Commercial paper D
Senior secured debt CCC
Senior unsecured debt CC
Preferred stock D
Shelf senior secured/unsecured subordinated debt CCC/CC
Shelf preferred stock D
Moody's Investors Service
Commercial paper Not prime
Mortgage B3
Secured pollution control bonds B3
Issuer rating Caa2
Senior unsecured notes Caa2
Unsecured debentures Caa2
Unsecured pollution control bonds Caa2
Bank credit facility Caa2
Preferred Stock caa
Shelf senior secured debt (P)B3
Shelf senior unsecured debt (P)Caa2
Shelf preferred stock (P)caa
Variable rate demand bonds Speculative Grade
PG&E Corporation
On January 16 and 17, 2001, in response to the continued energy crisis, S&P
and Moody's, respectively, downgraded PG&E Corporation's credit ratings to below
investment grade. The downgrade, in addition to PG&E Corporation's and the
Utility's non-payment of commercial paper constituted an event of default under
both the $436 million and the $500 million credit facilities. In response, the
banks immediately terminated their outstanding commitments under these defaulted
credit facilities. Through February 28, 2001, PG&E Corporation had $501 million
in outstanding commercial paper, of which $457 million came due and was not
paid.
On March 2, 2001, PG&E Corporation refinanced its debt obligations with $1
billion in aggregate proceeds of two term loans under a common credit agreement
with General Electric Capital Corporation and Lehman Commercial Paper, Inc. In
accordance with the credit agreement, the proceeds, together with other PG&E
Corporation cash, were used to pay the $501 million in outstanding commercial
paper, $434 million in borrowings under PG&E Corporation's long-
term revolving credit facility, and $116 million to PG&E Corporation's
shareholders of record on December 15, 2000 in satisfaction of the defaulted
fourth quarter 2000 common stock dividend. Further, approximately $85 million
was used to pre-pay the first year's interest under the credit agreement and to
pay transaction expenses associated with the debt restructuring.
The loans will mature on March 2, 2003 (which date may be extended at the
option of PG&E Corporation for up to one year upon payment of a fee of up to 5%
of the then outstanding indebtedness), or earlier, if a spin-off of the shares
of the NEG were to occur. As required by the credit agreement, PG&E Corporation
has given the lenders a security interest in the NEG. The loans prohibit PG&E
Corporation from declaring dividends, making other distributions to
shareholders, or incurring additional indebtedness until the loans have been
repaid, although PG&E Corporation could incur unsecured indebtedness provided it
meets certain requirements. The loan also prohibits NEG from making
distributions to PG&E Corporation and restricts certain other intercompany
transactions.
Further, as required by the credit agreement, NEG LLC has granted to
affiliates of the lenders options that entitle these affiliates to purchase up
to 3% of the shares of the NEG at an exercise price of $1.00 based on the
following schedule:
Percentages of Shares
subject to NEG Options
----------------------
Loans outstanding for:
Less than six months 2.0%
Six to eighteen months 2.5%
Greater than eighteen months 3.0%
The option becomes exercisable on the date of full repayment or, earlier,
if an initial public offering of the shares of the NEG (IPO) were to occur. The
NEG has the right to call the option in cash at a purchase price equal to the
fair market value of the underlying shares, which right is exercisable at any
time following the repayment of the loans. If an IPO has not occurred, the
holders of the option have the right to require the NEG or PG&E Corporation to
repurchase the option at a purchase price equal to the fair market value of the
underlying shares, which right is exercisable at any time after the earlier of
full repayment of the loans or 45 days before expiration of the option. The
option will expire 45 days after the maturity of the loans. PG&E Corporation
will account for the options by recording the fair value of the option at
issuance as a debt issuance cost to be amortized over the expected life of the
loans. The options will be marked to market through an increase or decrease to
current earnings.
Under the credit agreement, the NEG is permitted to make investments, incur
indebtedness, sell assets, and operate its businesses pursuant to its business
plan. Mandatory repayment of the loans will be required from the net after-tax
proceeds received by the NEG or any subsidiary of the NEG from (1) the issuance
of indebtedness, (2) the issuance or sale of any equity (except for cash
proceeds from an IPO), (3) asset sales, and (4) casualty insurance, condemnation
awards, or other recoveries. However, if such proceeds are retained as cash,
used to pay indebtedness, or reinvested in the NEG's businesses, mandatory
repayment will not be required.
Any net proceeds from an IPO must be used to reduce the outstanding balance
of the loans to $500 million or less. In addition, all distributions made by the
NEG to PG&E Corporation other than (1) to reimburse PG&E Corporation for
corporate overhead expenses, (2) pursuant to any tax sharing arrangements which
the NEG and PG&E Corporation are parties, and (3) pursuant to any note that may
be payable to PG&E Corporation in connection with an IPO and similar
arrangements must be used to pay the loans.
The credit agreement also prohibits PG&E Corporation from taking certain
actions, including a restriction against declaring or paying any dividends for
as long as the loans are outstanding. A breach of covenants, including
requirements that (1) the NEG's unsecured long-term debt have a credit rating of
at least BBB- by S&P or Baa3 by Moody's, (2) the ratio of fair market value of
the NEG to the aggregate amount of principal then outstanding under the loans is
not less than 2 to 1, and (3) PG&E Corporation maintain a cash or cash
equivalent reserve of at least 15% of the total principal amount of the loans
outstanding, entitles the lenders to declare the loans to be due and payable.
Utility
The Utility had been drawing on its $1 billion facility to pay maturing
commercial paper. As of January 16, 2001, the Utility had drawn down $938
million under this facility. On January 16 and 17, 2001, S&P and Moody's,
respectively, downgraded the Utility's credit ratings to below investment grade.
This downgrade resulted in an event of default under the $850 million credit
facility, while the Utility's non-payment of commercial paper exceeding $100
million constituted events of default under both the $1 billion and $850 million
credit facilities. Although they have the ability under the terms of the various
agreements, no bank has called for accelerated payment of any of the Utility's
outstanding debt, nor has any bank permanently waived any requirements violated
which resulted in the events of default described above. Lenders have agreed to
forbear from accelerating payments until April 13, 2001.
On January 10, 2001, the Board of Directors of the Utility suspended the
payment of its fourth quarter 2000 common stock dividend in an aggregate amount
of $110 million payable on January 15, 2001, to PG&E Corporation and PG&E
Holdings, Inc., a subsidiary of the Utility. In addition, the Utility's Board of
Directors decided not to declare the regular preferred stock dividends for the
three-month period ending January 31, 2001, normally payable on February 15,
2001. Dividends on all Utility preferred stock are cumulative. Until cumulative
dividends on preferred stock are paid, the Utility may not pay any dividends on
its common stock, nor may the Utility repurchase any of its common stock.
After the downgrade, the PX notified the Utility that the ratings downgrade
required the Utility to post collateral for all transactions in the PX day-ahead
market. Since the Utility was unable to post such collateral, the PX suspended
the Utility's trading privileges effective January 19, 2001 in the day-ahead
market. The PX also sought to liquidate the Utility's block forward contracts
for the purchase of power. On January 25, 2001, a California Superior Court
judge granted the Utility's application for a temporary restraining order, which
thereby restrained and enjoined the PX and its agents from liquidating the
Utility's contracts in the block forward market, pending hearing on a
preliminary injunction on February 5, 2001. Immediately before the hearing on
the preliminary injunction, California Governor Gray Davis, acting under
California's Emergency Services Act, commandeered the contracts for the benefit
of the state. Under the Act, the state must pay the Utility the reasonable value
of the contracts, although the PX may seek to recover the monies that the
Utility owes to the PX from any proceeds realized from those contracts.
Discussions and negotiations on this issue are currently ongoing between the
state and the Utility.
As of March 29, 2001, the Utility was in default and/or had not paid the
following:
Description Amount
in millions)
(unaudited)
Items not paid
PX/ISO--real time market deliveries $1,448
Qualifying facilities 643
Direct access credits due to energy service providers 503
Commercial paper 861
Bank loans 939*
Other 26
Total Items Not Paid $4,420
Items coming due through April 30, 2001
PX/ISO--real time market deliveries $ 550
Qualifying facilities 340
Gas suppliers 470
Other 140
Total coming due 1,500
Total cash on hand at March 29, 2001 $2,600
* Loans that lenders have agreed to forbear through April 13, 2001.
Additionally, the Utility may owe the DWR for purchases that the DWR has
made on behalf of the Utility's customers. As discussed further in Note 2 of the
Notes to the Consolidated Financial Statements, there is a dispute over how much
the Utility owes the DWR. Also, the DWR has indicated that it intends to
purchase power at only "reasonable prices." The ISO has continued to purchase
power at prices in excess of the DWR's as yet undisclosed ceiling and is
expected to bill the Utility for the differential. The Utility does not yet know
what the total expected billing is for these purchases.
As a result of (1) the failure by the state to assume the full procurement
responsibility for the Utility's net open position as was provided under AB1X,
(2) the negative impact of recent actions by the CPUC that created new payment
obligations for the Utility and undermined its ability to return to financial
viability, (3) a lack of progress in negotiations with the state to provide a
solution for the energy crisis, and (4) the adoption by the CPUC of an illegal
and retroactive accounting change that would appear to eliminate the Utility's
true uncollected purchased power costs, the Utility filed a voluntary petition
for relief under provisions of Chapter 11 of the U.S. Bankruptcy Code on April
6, 2001. Pursuant to Chapter 11 of the U.S. Bankruptcy Code, the Utility retains
control of its assets and is authorized to operate its business as a debtor in
possession while being subject to the jurisdiction of the bankruptcy court.
Subject to the approval of the bankruptcy court, the Utility's intent is to pay
its ongoing costs of doing business while seeking resolution of the wholesale
power crisis. It is the Utility's intention to continue to pay employees,
vendors, suppliers, and other creditors to maintain essential distribution and
transmission services. However, the Utility is not in a position to pay maturing
or accelerated obligations, nor is the Utility in a position to pay the ISO, PX,
and the QFs, the massive amounts due for the Utility's power purchases above the
amount included in rates for power purchase costs. The Utility's current actions
are intended to allow the Utility to continue to operate while efforts to reach
a regulatory or legislative solution continue.
The Utility has also deferred quarterly interest payments on the Utility's
7.90% Deferrable Interest Subordinated Debentures, Series A, due 2025, until
further notice in accordance with the indenture. The corresponding quarterly
payments on the 7.90% Cumulative Quarterly Income Preferred Securities, Series
A, (QUIPS) issued by PG&E Capital I, due on April 2, 2001, have been similarly
deferred. Distributions can be deferred up to a period of five years per the
indenture. Investors will accumulate interest on the unpaid distributions at the
rate of 7.90%.
National Energy Group
In December 2000 and in January and February 2001, PG&E Corporation and the
NEG undertook a corporate restructuring of the NEG, known as a "ringfencing"
transaction. The ringfencing complied with credit rating agency criteria,
enabling NEG, PG&E Gas Transmission, Northwest Corporation (PG&E GTN), and PG&E
ET to receive or retain their own credit rating, based upon their
creditworthiness. The ringfencing involved the creation of new special purpose
entities (SPEs) as intermediate owners between PG&E Corporation and its non
CPUC-regulated subsidiaries. These new SPEs are: PG&E National Energy Group,
LLC, which owns 100% of the stock of the NEG; GTN Holdings LLC, which owns 100%
of the stock of PG&E GTN; and PG&E Energy Trading Holdings LLC which owns 100%
of the stock of PG&E Corporation's energy trading subsidiaries, PG&E Energy
Trading--Gas Corporation, PG&E Energy Trading Holdings Corporation, and PG&E
Energy Trading-Power, L.P. In addition, the NEG's organizational documents were
modified to include the same structural elements as the SPEs to meet credit
rating agency criteria. Ringfencing is intended to reduce the likelihood that
the assets of the ringfenced entities would be substantially consolidated in a
bankruptcy proceeding involving such companies' ultimate parent, and to thereby
preserve the value of the "protected" entities as a whole. The SPEs require
unanimous approval of their respective boards of directors, which includes an
independent director, before they can (a) consolidate or merge with any entity,
(b) transfer substantially all of their assets to any entity, or (c) institute
or consent to bankruptcy, insolvency, or similar proceedings or actions. The
SPEs may not declare or pay dividends unless the respective boards of directors
has unanimously approved such action and the company meets specified financial
requirements.
Note 4: Price Risk Management and Financial Instruments
Trading and Non-Trading Activities
The following table is a summary of the contract or notional amounts and
maturities of commodity derivatives related to commodity price risk management
as of December 31, 2000 and 1999:
Maximum
Electricity, Natural Gas, Purchase Sale Term in
and Natural Gas Liquids Contracts (Long) (Short) Years
(billions of MMBtu equivalents/(1)/)
NEG:
Trading Activities--December 31, 2000
Swaps 2.04 1.95 6
Options 0.46 0.37 8
Futures 0.14 0.15 3
Forward Contracts 1.42 1.38 16
Trading Activities--December 31, 1999
Swaps 2.38 2.33 7
Options .94 .86 8
Futures .19 .18 2
Forward Contracts 1.49 1.46 12
Non-Trading Activities--December 31, 2000
Forward Contracts 1.70 0.74 22
Non-Trading Activities--December 31, 1999
Forward Contracts 0.02 0.01 3
Utility:
Non-Trading Activities--December 31, 2000
Swaps 0.06 0.07 1
Forward Contracts 0.02 -- 5
Non-Trading Activities--December 31, 1999
Swaps -- 0.01 1
(1) One MMBtu is equal to one million British thermal units. Electricity
contracts, measured in megawatts, were converted to MMBtu equivalents using
a conversion factor of 10 MMBtus per 1 MWh. Natural gas liquids contracts
were converted to MMBtu equivalents using an appropriate conversion factor
for each type of natural gas liquids product.
The following table is a summary of the contract or notional amounts and
maturities of PG&E Corporation's financial instruments used for non-trading
activities as of December 31:
2000 1999
----- -----
(in millions) Notional Contract Notional Contract
Amount Expiration Amount Expiration
Non-Trading Activities:
Interest Rate $1,756 2012 $ 724 2003
Foreign Currency 94 2003 104 2002
Notional amounts shown represent volumes that are used to calculate amounts
due under the agreements and do not necessarily represent volumes exchanged.
Because the changes in market value of these derivatives used as hedges are
generally offset by changes in the value of the underlying physical
transactions, the amounts at risk are significantly lower than these notional
amounts might suggest.
PG&E Corporation's net gain (loss) on trading contracts held during the
years ended December 31, are as follows:
(in millions) 2000 1999 1998
Swaps $ 173 $ 15 $ 69
Options 66 (41) (49)
Futures (106) (36) (63)
Forward Contracts 72 98 101
Net gain $ 205 $ 36 $ 58
The following table discloses PG&E Corporation's estimated average fair value
and ending fair value of price risk management assets and liabilities at
December 31, 2000 and 1999.
Average Ending
Fair Value Fair Value
---------- ----------
(in millions) Assets Liabilities Assets Liabilities
Trading Activities--December 31, 2000
Swaps $ 163 $ 75 $ 286 $ 121
Options 153 106 250 171
Futures 34 78 33 98
Forward Contracts 2,053 1,921 3,496 3,476
Total $2,403 $2,180 $4,065 $3,866
Noncurrent portion $2,026 $1,867
Current portion $2,039 $1,999
Trading Activities--December 31, 1999
Swaps $ 218 $ 197 $ 50 $ 33
Options 75 87 56 41
Futures 89 119 35 58
Forward Contracts 475 356 588 398
Total $ 857 $ 759 $ 729 $ 530
Noncurrent portion $ 329 $ 207
Current portion $ 400 $ 323
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
obligations. The counterparties in PG&E Corporation's and the Utility's
portfolio consist primarily of investor-owned and municipal utilities, energy
trading companies, financial institutions, and oil and gas production companies.
PG&E Corporation and the Utility minimize credit risk by dealing primarily with
creditworthy counterparties in accordance with established credit approval
practices and limits. PG&E Corporation assesses the financial strength of its
counterparties at least quarterly and requires that counterparties post security
in the forms of cash, letters of credit, corporate guarantees of acceptable
credit quality, or eligible securities if current net receivables and
replacement cost exposure exceed contractually specified limits. Neither PG&E
Corporation nor the Utility has experienced material losses due to the
nonperformance of counterparties in 2000. Counterparties considered to be
investment grade or higher comprise 76% of the total credit exposure. At
December 31, 2000, PG&E Corporation's and the Utility's gross credit risk
amounted to $3.3 billion and $978 million, respectively.
Fair Value of Financial Instruments
PG&E Corporation's financial instruments consist of cash and cash equivalents,
restricted cash, accounts receivable, accounts payable and certain accrued
liabilities, notes payable, commercial paper, capital leases, and long-term
debt.
The fair value of these financial instruments, with the exception of long-
term receivables, fixed rate debt, and interest rate swaps, approximates their
carrying value as of December 31, 2000 and 1999, due to their short-term nature
or due to the fact that the interest rate paid on the instrument is variable.
The carrying amounts of the long-term receivables approximate fair value at
December 31, 2000 and 1999, as the assumptions used to value these instruments
at the acquisition date had not changed.
The fair values of long-term receivables and long-term debt were estimated
using discounted cash flows analysis, based on PG&E Corporation's current
incremental borrowing rate. The approximate carrying values were based on
currently quoted market prices for similar types of borrowing arrangements.
The fair value of interest rate swap agreements, which are not carried on
the consolidated balance sheets, is estimated by calculating the present value
of the difference between the total fixed payments of the interest rate swap
agreements and the total floating payments using the appropriate current market
rates.
The carrying amount and fair value of PG&E Corporation's long-term
receivables, long-term debt, and interest rate swaps as of December 31, 2000 and
1999, is summarized as follows:
2000 1999
---- ----
PG&E Corporation Carrying Fair Value Carrying Fair Value
(in millions) Amount Amount
Long-term receivables $ 611 $ 526 $ 680 $ 680
Long-term debt 9,157 9,010 9,561 9,393
Interest rate swaps -- (73) -- (9)
Fair value of the Utility's rate reduction bonds, and Utility obligated
mandatorily 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 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. See Note 3 of the Notes to the Consolidated Financial Statements for
subsequent events regarding PG&E Corporation's and the Utility's credit
facilities.
At December 31, 2000 and 1999, the Utility's carrying amount and ending
fair value of its financial instruments was:
2000 1999
---- ----
Utility: Carrying Fair Value Carrying Fair Value
(in millions) Amount Amount
Nuclear decommissioning funds noncurrent
asset (see Note 11) $1,328 $1,328 $1,264 $1,264
Total long-term debt(1) (see Note 8) 5,716 5,320 5,342 5,217
Rate reduction bonds(2) (see Note 9) 2,030 2,044 2,321 2,265
Preferred stock with mandatory redemption
provisions (see Note 7) 137 98 137 140
Utility obligated mandatorily redeemable
preferred securities of trust holding
solely Utility subordinated debentures
(See note 7) 300 180 300 267
(1) Total long-term debt includes the current portion of long-term
debt.
(2) Rate reduction bonds include the current portion of rate
reduction bonds.
Note 5: Acquisitions and Disposals
On September 28, 2000, the NEG purchased for $311 million the Attala
Generating Company LLC, which owns a gas-fired power plant under construction.
Under the purchase agreement, the NEG prepaid the estimated remaining
construction costs, which are being managed by the seller. The project, which
was approximately 75% complete as of December 31, 2000, is expected to begin
commercial service in July 2001. In connection with the acquisition, the NEG
also assumed industrial revenue bonds in the amount of $158 million. The seller
has agreed to pay off the bonds prior to December 15, 2001; accordingly, the NEG
recorded a receivable equal to the amount of the outstanding bonds and accrued
interest at December 31, 2000.
On January 27, 2000, PG&E Corporation 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, PG&E Gas Transmission Teco, Inc., and their subsidiaries
(PG&E GTT). PG&E GTT assets consist of 8,500 miles of natural gas and natural
gas liquids pipeline, nine natural gas processing plants, and natural gas
storage facilities, all located in Texas. Given the terms of the sales
agreement, in 1999 PG&E Corporation recognized a charge against pre-tax earnings
of $1,275 million, to reflect PG&E GTT's assets at their fair 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.
On December 22, 2000, after receipt of governmental approvals, PG&E
Corporation completed the stock sale. The total consideration received was $456
million, less $150 million used to retire the PG&E GTT short-term debt, and the
assumption by El Paso of PG&E GTT long-term debt having a book value of $564
million. The final sale price is subject to adjustment during a 120-day working
capital true-up period. The NEG recorded a gain of approximately $20 million
based on its best estimate of the final sales price.
PG&E GTT's total assets and liabilities, including the charge noted above,
included in PG&E Corporation's Consolidated Balance Sheet at December 31, 1999,
were as follows:
(in millions)
Assets
Current assets $ 229
Noncurrent assets 988
Total assets 1,217
Liabilities
Current liabilities 448
Noncurrent liabilities 624
Total liabilities 1,072
Net assets $ 145
The following table reflects PG&E GTT's results of operations included in
PG&E Corporation's Statement of Consolidated Operations for the years ended
December 31:
(in millions) 2000 1999 1998
Revenue $ 873 $ 1,753 $2,064
Operating expenses 869 3,058 2,115
Operating income (loss) 4 (1,305) (51)
Interest expense and other, net (36) 7 (50)
Sales price true-up 20 -- --
Income (Loss) before income taxes (12) (1,298) (101)
Income tax provision (benefit) (32) (390) (31)
Net income (loss) $ 20 $ (908) $ (70)
In December 1999, PG&E Corporation's Board of Directors approved a plan to
dispose of PG&E Energy Services (PG&E ES), a wholly owned subsidiary, through a
sale. The disposal has been accounted for as a discontinued operation, and PG&E
Corporation's investment in PG&E ES was written down to its then estimated net
realizable value. In addition, PG&E Corporation provided a reserve for
anticipated losses through the anticipated date of sale. The total provision for
discontinued operations was $58 million, net of income taxes of $36 million at
December 31, 1999. Of this amount, $33 million (net of taxes) was allocated
toward operating losses for the period leading up to the intended disposal date.
In 2000, $31 million (net of taxes) of actual operating losses was charged
against this reserve. During the second quarter of 2000, the NEG finalized the
transactions related to the disposal of the energy commodity portion of PG&E ES
for $20 million, plus net working capital of approximately $65 million, for a
total of $85 million. In addition, the sale of the Value-Added Services business
and various other assets was completed on July 21, 2000, for a total
consideration of $18 million. For the year ended December 31, 2000, an
additional estimated loss of $40 million (or $0.11 per share), net of income tax
of $36 million, was recorded as actual losses in connection with the disposition
exceeded that originally estimated. The principal reason for the additional loss
was due to the mix of assets, and the structure and timing of the actual sales
agreements, as opposed to the one reflected in the initial provision established
in 1999. In addition, the worsening energy situation in California also
contributed to the additional loss incurred. The PG&E ES business segment
generated net losses from operations of $40 million (or $0.11 per share) for the
year ended December 31, 1999.
In September 1998, PG&E Gen through its indirect subsidiary USGen New
England, Inc. (USGenNE), acquired a portfolio of electric generating assets and
power supply agreements from a wholly-owned subsidiary of the New England
Electric System (NEES). The purchase price, including fuel and other inventories
and transaction costs, was approximately $1.8 billion funded through $1.3
billion of debt and a $425 million equity contribution from PG&E Corporation.
The net purchase price was allocated as follows: electric generating assets of
$2.3 billion classified as property, plant, and equipment, long-term receivables
of $0.8 billion, and out-of-market contractual obligations of $1.3 billion and
asset contracts related to acquired power sales agreement of $45 million. The
acquisition of the NEES assets was considered an asset purchase. Accordingly,
the purchase has been allocated to the assets purchased and the liabilities
assumed based upon an assessment of fair value at the date of acquisition. The
assets acquired included hydroelectric, coal, oil, and natural gas generation
facilities with a combined generating capacity of 4,000 MW. In addition, the
NEG, USGenNE, assumed 23 multi-year power purchase agreements representing an
additional 800 MW of production capacity. The NEG, through a wholly-owned
subsidiary, entered into the agreements as part of the acquisition, which (1)
provided that a wholly-owned subsidiary of NEES would make payments through
January 2008 for the purchase power agreements, and (2) required that the NEG,
through its wholly-owned subsidiary, provide electricity to certain NEES
affiliates under contracts that expire at various times through 2008.
In July 1998, PG&E Corporation sold its Australian energy holdings for $126
million. PG&E Corporation recognized a loss of approximately $23 million related
to the sale, which is included in other income (expense) on the Statement of
Consolidated Operations.
Note 6: Common Stock
PG&E Corporation
PG&E Corporation has authorized 800 million shares of no-par common stock,
of which 387 million and 384 million shares were issued as of December 31, 2000
and 1999, respectively.
During the years ended December 31, 2000 and 1999, PG&E Corporation
repurchased $2 million and $693 million of its common stock, respectively. The
2000 repurchases were for the Dividend Reinvestment Program. The
1999 repurchases were executed through open market purchases and an accelerated
share repurchase program. Under the 1999 accelerated share repurchase program
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 PG&E
Corporation's common stock. The authorization for share repurchases extends
through September 30, 2001. As of December 31, 2000, a subsidiary of PG&E
Corporation had repurchased 23.8 million shares at a cost of $690 million.
On January 10, 2001, the Board of Directors of PG&E Corporation suspended
the payment of its fourth quarter 2000 stock dividend of $.30 per common share
declared by the Board of Directors on October 18, 2000 and payable on January
15, 2001 to shareholders of record as of December 15, 2000.
On March 2, 2001, PG&E Corporation refinanced its debt obligations with the
$1 billion aggregate proceeds of two term loans under a common credit agreement
with General Electric Capital Corporation and Lehman Commercial Paper, Inc. (see
Note 3). In accordance with the credit agreement, a part of the proceeds,
together with other PG&E Corporation cash, was used to pay $116 million to PG&E
Corporation shareholders of record as of December 15, 2000, in satisfaction of
the defaulted fourth quarter 2000 common stock dividend. PG&E Corporation is
precluded by these loan agreements from declaring further dividends or
repurchasing its common stock.
Utility
PG&E Corporation and a subsidiary of the Utility hold all of the Utility's
outstanding common stock. The Utility has authorized 800 million shares of $5
par value common stock of which 321 million shares were issued as of December
31, 2000 and 1999.
In April 2000, a subsidiary of the Utility repurchased from PG&E
Corporation 11.9 million shares of the Utility's common stock at a cost of $275
million. In December 1999, 7.6 million shares of the Utility's common stock,
with an aggregate purchase price of $200 million, was purchased by the same
subsidiary of the Utility. Total shares purchased were 19.5 million with an
aggregate purchase price of $475 million. These repurchases are reflected as
stock held by subsidiary in the Utility's Consolidated Balance Sheet. 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.
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. On January 10, 2001, the Utility suspended the payment of its
fourth quarter 2000 common stock dividend of $110 million, declared in October
2000, to PG&E Corporation. The Utility has suspended payment of its common and
preferred dividends. Dividends on preferred stock are cumulative. Until
cumulative dividends on preferred stock are paid, the Utility may not pay any
dividends on common stock.
Note 7: Preferred Stock and Utility Obligated Mandatorily Redeemable Preferred
Securities of Trust Holding Solely Utility Subordinated Debentures
Shareholder Rights Plan of PG&E Corporation
On December 20, 2000, the Board of Directors of PG&E Corporation declared a
distribution of preferred stock purchase rights (the Rights) at a rate of one
Right for each outstanding share of PG&E Corporation's common stock, no par
value. The Rights apply to outstanding shares of PG&E Corporation common stock
held as of the close of business on January 2, 2001, and for each share of
common stock issued by PG&E Corporation thereafter and before the "distribution
date", as described below. Each Right entitles the registered holder, in certain
circumstances, to purchase from PG&E Corporation one one-hundredth of a share (a
Unit) of PG&E Corporation's Series A Preferred Stock, par value $100 per
share, at an initially fixed purchase price of $95 per Unit, subject to
adjustment. Effective December 22, 2000, the PG&E Corporation Dividend
Reinvestment Plan was modified to note these changes.
The Rights are not exercisable until the distribution date and will expire
December 22, 2010, unless redeemed earlier by the PG&E Corporation Board of
Directors. The distribution date will occur upon the earlier of (1) 10 days
following a public announcement that a person or group (other than the PG&E
Corporation, any of its subsidiaries, or its employee benefit plans) has
acquired or obtained the right to acquire beneficial ownership of 15% or more of
the then-outstanding shares of PG&E Corporation common stock and (2) 10 business
days (or later, as determined by the Board of Directors) following the
commencement of a tender offer or exchange offer that would result in a person
or group owning 15% or more of the then-outstanding shares of PG&E Corporation
common stock. After the distribution date, certain triggering events will enable
the holder of each Right (other than a potential acquiror) to purchase Units of
Series A Preferred Stock having twice the market value of the initially fixed
exercise price, i.e., at a 50% discount. Until a Right is exercised, the holder
shall have no rights as a shareholder of PG&E Corporation, including, without
limitation, the right to vote or to receive dividends.
A total of 5,000,000 shares of preferred stock will be reserved for
issuance upon exercise of the Rights. The Units of preferred stock that may be
acquired upon exercise of the Rights will be non-redeemable and subordinate to
any other shares of preferred stock that may be issued by PG&E Corporation. Each
Unit of preferred stock will have a minimum preferential quarterly dividend rate
of $.01 per Unit but will, in any event, be entitled to a dividend equal to the
per share dividend declared on the common stock. In the event of liquidation,
the holder of a Unit will receive a preferred liquidation payment.
The Rights also have certain anti-takeover effects and will cause
substantial dilution to a person or group that attempts to acquire the Utility
on terms not approved by PG&E Corporation's Board of Directors unless the offer
is conditioned on a substantial number of Rights being acquired. The Rights
should not interfere with any approved merger or other business combination, as
the Board of Directors, at its option, may redeem the Rights. Thus, the Rights
are intended to encourage persons who may seek to acquire control of the PG&E
Corporation to initiate such an acquisition through negotiations with the PG&E
Corporation Board of Directors. However, the effect of the Rights may be to
discourage a third party from making a partial tender offer or otherwise
attempting to obtain a substantial equity position in the equity securities of,
or seeking to obtain control of the PG&E Corporation. To the extent any
potential acquirors are deterred by the Rights, the Rights may have the effect
of preserving incumbent management in office.
Preferred Stock of Utility
The Utility has authorized 75 million shares of $25 par value preferred
stock, which may be issued as redeemable or non-redeemable preferred stock. At
December 31, 2000 and 1999, the Utility had issued and outstanding 5,784,825
shares of non-redeemable preferred stock.
At December 31, 2000 and 1999, 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, 2000, range from $1.09 to $1.76 and from $25.75
to $27.25, respectively.
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, 2000. 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.
At December 31, 2000, the redemption requirements for the Utility's
redeemable preferred stock with mandatory redemption provisions are $4 million
per year beginning 2002, and $3 million per year beginning 2004 for the series
6.57% and 6.30%, respectively.
Holders of the Utility's non-redeemable preferred stock 5%, 5.5%, and 6%
series have rights to annual dividends per share ranging from $1.25 to $1.50.
Due to the California energy crisis, the Utility's Board of Directors decided
not to declare the regular preferred stock dividends for the three-month periods
ending January 31, 2001 (normally payable on February 15, 2001) and April 30,
2001 (normally payable May 15, 2001).
Dividends on all Utility preferred stock are cumulative. All shares of
preferred stock have voting rights and equal preference in dividend and
liquidation rights. The dividend for the three-month period ending January 31,
2001 became a dividend in arrears and, as such, will accumulate from period to
period. 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. Until cumulative
dividends on its preferred stock are paid, the Utility may not pay any dividends
on its common stock, nor may the Utility repurchase any of its common stock.
Accumulated and unpaid preferred stock dividends for the three-month period
ending January 31, 2001 amounted to $6 million.
Preferred Stock of the NEG
Preferred stock of the NEG 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 non-cumulative quarterly dividend of $3.35 per share, and is redeemable
when there is an excess of available cash. There were 549,594 shares of
preferred stock outstanding at December 31, 2000 and 1999.
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 7.9% 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, due 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.
On March 16, 2001, the Utility deferred quarterly interest payments on the
Utility's 7.90% Deferrable Interest Subordinated Debentures, Series A, due 2025,
until further notice in accordance with the indenture. The corresponding
quarterly payments on the 7.90% Cumulative Quarterly Income Preferred
Securities, Series A, issued by PG&E Capital I due on April 2, 2001, have been
similarly deferred. Distributions can be deferred up to a period of five years
under the terms of the indenture. Investors will accumulate interest on the
unpaid distributions at the rate of 7.90%.
Note 8: Long-Term Debt
For further information and discussion on credit ratings, downgrades, and
events of default, see Note 3, Subsequent Events of the Notes to the
Consolidated Financial Statements.
Long-term debt at December 31, 2000 and 1999 consisted of the following:
Balance at
December 31,
------------
(in millions) 2000 1999
Utility long-term debt
First and refunding mortgage bonds
Maturity Interest rates
2001-2003 6.25% to 8.75% $ 706 $ 816
2004-2008 5.875% to 6.25% 600 600
2009-2021 6.35% to 8.08% 160 160
2022-2026 5.85% to 8.80% 2,004 2,004
Principal amounts outstanding 3,470 3,580
Unamortized discount net of premium (28) (29)
Total mortgage bonds 3,442 3,551
Senior notes, 7.375%, due 2005 680 --
Pollution control loan agreements, variable rates, due 2016-2026 1,267 1,348
Unsecured medium-term notes, 5.81% to 8.45%, due 2001-2014 305 418
Other Utility long-term debt 22 25
Total Utility long-term debt 5,716 5,342
Long-term debt, classified as current 2,374 465
Total Utility long-term debt, net of current portion $3,342 $4,877
National Energy Group long-term debt
First mortgage notes, 10.02% to 11.50%, due 2001-2009 $ -- $ 333
Senior notes, 7.10%, due 2005 250 248
Medium term notes
Maturity Interest Rates
2001-2003 6.61% to 6.96% 39 70
2001-2009 7.35% to 9.25% -- 229
Senior debentures
Maturity Interest Rates
2010 10.00% 159
2025 7.80% 150 150
Stock margin loan, LIBOR + 0.40% due 2003 -- 8
Premium on long-term debt, due 2000-2009 -- 63
Amounts outstanding under credit facilities (See Note 10) 661 649
Capital lease obligations, 8.80%, due 2015 15 16
Term loans, various, 2009-2011 107 116
Mortgage loan payable, 30 day commercial paper rate plus 6.07%, due 2010 8 9
Other long-term debt 22 7
Total National Energy Group long-term debt 1,411 1,898
Current portion of long-term debt 17 93
Total National Energy Group long-term debt, net of current portion $1,394 $1,805
Total long-term debt $4,736 $6,682
PG&E Corporation
Utility
The Utility's revolving credit agreement balance of $614 million, as of
December 31, 2000, went into default subsequent to year-end and remains as such.
It has been reclassified to short-term borrowings and is discussed in Note 10 of
the Notes to the Consolidated Financial Statements.
For further discussion of default status, see Note 3 of the Notes to the
Consolidated Financial Statements. For debt obligations, the priority and
subordination is as follows: senior secured debt (first and refunding mortgage
bonds), and then all other unsecured debt, including notes and bank loans.
First and Refunding Mortgage Bonds
First and refunding mortgage bonds are issued in series and bear annual
interest rates ranging from 5.85% to 8.80%. All real properties and
substantially all personal properties of the Utility are subject to the lien of
the mortgage, 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 $110 million and $281 million of the bonds
in 2000 and 1999, respectively, with interest rates ranging from 6.25% to 8.80%.
Included in the total of outstanding bonds at December 31, 2000 and 1999 are
$345 million of bonds held in trust for the California Pollution Control
Financing Authority (CPCFA) with interest rates ranging from 5.85% to 6.625% 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.
Senior Notes
In November 2000, the Utility issued $680 million of five-year senior notes
with an interest rate of 7.375%. The Utility used the net proceeds to repay
short-term indebtedness incurred to finance scheduled payments due to the PX for
August power purchases from the PX and for other general corporate purposes.
The interest rate on the senior notes is subject to adjustment until May 1,
2002. As such, in the event of a downgrade in the rating below A3 by Moody's or
A- by S&P prior to May 1, 2002, the interest rate on the notes will be
readjusted accordingly.
As a result of the credit rating downgrades by S&P and Moody's, as described
in Note 3 of the Notes to the Consolidated Financial Statements, there will be
an interest rate adjustment of 1.75% on the $680 million senior notes. The
revised rate will be increased to 9.125% from 7.375% on May 1, 2001, the next
interest payment date. An event of default under the senior notes occured
subsequent to December 31, 2000. Under the default provisions, the trustee or
holders of not less than 25% of the outstanding notes may declare the amounts
outstanding due and payable by notice to the Utility. Accordingly, the amount
outstanding, as of December 31, 2000, has been classified as current in the
accompanying financial statements.
Pollution Control Loan Agreements
Pollution control loan agreements from the CPCFA totaled $1,267 million and
$1,348 million at December 31, 2000 and 1999, respectively. Interest rates on
the loans vary with average annual interest rates. For 2000 the interest rates
ranged from 2.10% to 4.81%. These loans are subject to redemption by the holder
under certain circumstances. These loans are secured primarily by irrevocable
letters of credit (LOC), which mature in 2001 through 2003. In December 2000,
two of these loans totaling $81 million, were reacquired by the Utility. On
March 1, 2001, a $200 million loan was converted to a fixed interest rate of
5.35%. The Company is in default under the credit provider's reimbursement
agreements due to nonpayment of $100 million of commercial paper. Due to this
default, the credit providers can declare the $1,267 million of principal and
interest immediately due and payable. Through March 29, 2001, no banks had
accelerated the debt. Declaration of bankruptcy is also an event of default
under certain of the pollution control loan agreements. Under certain of the
default provisions, the trustee or holders of the pollution control bonds may
declare the amount outstanding due and payable. Accordingly, amounts outstanding
at December 31, 2000 under the pollution control agreements have been classified
as current in the accompanying financial statements.
Medium-Term Notes
The Utility has outstanding $305 million of medium-term notes due 2001 to 2014
with interest rates ranging from 5.81% to 8.45%. An event of default under the
medium-term notes occured subsequent to December 31, 2000. Under the default
provisions, the trustee or holders of not less than 25% of the outstanding notes
may declare amounts outstanding due and payable by notice to the Utility.
Accordingly, the amount outstanding at December 31, 2000 has been classified as
current in the accompanying financial statements.
National Energy Group
Long-term debt of the NEG consists of first mortgage notes and other secured
and unsecured obligations.
The first mortgage notes were comprised of three series due annually through
2009, and were 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 required 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 contained
covenants that restricted the ability of PG&E GTT to incur additional
indebtedness and precluded cash distributions if certain cash flow coverage were
not met. In January 2000, PG&E GTT obtained an amendment that provided 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 were assumed by the buyer of PG&E GTT as of December 31, 2000 (see
Note 5).
In May 1995, PG&E GTN issued $250 million of 10-year senior unsecured notes
and $150 million of senior unsecured debentures. Other long-term debt consists
of non-recourse project financing associated with unregulated PG&E Generating
facilities, premiums, and other loans.
Other long-term debt consists of project financing associated with unregulated
generation facilities, premiums, and other loans.
Repayment Schedule
At December 31, 2000, PG&E Corporation's combined aggregate amounts of capital
spending, maturing long-term debt, and sinking fund requirements are reflected
in the table below:
Expected maturity date 2001 2002 2003 2004 2005 Thereafter Total
(dollars in millions)
Utility:
Long-term debt
Variable rate obligations $ 120 $ 697 $ 350 $ 40 $ 40 $ 20 $1,267
Fixed rate obligations $ 274 $ 379 $ 354 $ 392 $1,012 $2,038 $4,449
Average interest rate 8.0% 7.8% 6.3% 6.4% 6.9% 7.3% 7.2%
Rate reductions bonds $ 290 $ 290 $ 290 $ 290 $ 290 $ 580 $2,030
Average interest rate 6.2% 6.3% 6.4% 6.4% 6.4% 6.4% 6.4%
National Energy Group
Long-term debt
Variable rate obligations $ 16 $ 94 $ 584 $ 9 $ 9 $ 80 $ 792
Fixed rate obligations $ 1 $ 34 $ 7 $ 1 $ 251 $ 325 $ 619
Average interest rate 9.4% 6.9% 7.0% 9.4% 7.1% 8.9% 8.1%
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.
On January 4, 2001, S&P lowered the short-term credit rating of the SPE to A-
3, and on January 5, 2001, Moody's lowered the short-term credit rating of the
SPE to P-3. As a result, on January 8, 2001, remittances for charges paid by
ratepayers for the pass-through certificates issued by the Trust were required
to be made on a daily basis, as opposed to once a month, as had previously been
required.
The rate reduction bonds have maturities ranging from 6 months to 7 years, and
bear interest at rates ranging from 6.16% to 6.48%. The bonds are secured solely
by the transition property and there is no recourse to the Utility or PG&E
Corporation.
At December 31, 2000, $2,030 million of rate reduction bonds were outstanding.
The combined expected principal payments on the rate reduction bonds for the
years 2001 through 2005 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 and Short-term Borrowings
See Note 3 for discussion of default status regarding credit facilities and
short-term borrowings.
At December 31, 2000 and 1999, PG&E Corporation had borrowed $5,191 million
and $2,148 million, respectively, through short-term borrowings and various
credit facilities. At December 31, 2000 and 1999, $661 million and $649 million,
respectively, of these borrowings were outstanding balances related to NEG
credit facilities, which are classified as long-term debt because the NEG has
the ability and intent to finance the amounts outstanding on a long-term basis.
The weighted average interest rate on the short-term borrowings as of December
31, 2000 and 1999, was 7.4% and 5.4%, respectively.
The following table summarizes PG&E Corporation's lines of credit (see Note 8
of the Notes to the Consolidated Financial Statements) as of December 31, 2000
and 1999:
Amount of Credit Amount of Credit
December 31, 2000 December 31, 1999
----------------- -----------------
Lines of Credit Revolving Revolving
(in millions) Credit Outstanding Credit Outstanding
Limits Balance Limits Balance
PG&E Corporation:
5-year Revolving Credit $ 500 $ 185 $ 500 $ --
364-day Revolving Credit 436 -- 500 --
Utility:
5-year Revolving Credit 1,000 614 1,000 --
364-day Revolving Credit 850 -- -- --
National Energy Group:
Revolving Credit 1,350 661 1,600 649
Total Lines of Credit $4,136 $1,460 $3,600 $ 649
Short-Term Borrowings
PG&E Corporation:
Commercial Paper 746 450
Extendible Commercial Notes -- 76
Utility:
Commercial Paper 1,225 449
Floating Rate Notes 1,240 --
National Energy Group:
Commercial Paper 520 524
Total Commercial Paper and Short-Term Notes $3,731 $1,499
Sub-total $5,191 $2,148
Less: Classified as long-term debt
NEG Revolving credit (661) (649)
Total Short Term Borrowings $4,530 $1,499
PG&E Corporation
PG&E Corporation had $436 million and $500 million revolving credit
facilities, which were scheduled to expire in November 2001 and August 2002,
respectively. These credit facilities were used to support PG&E Corporation's
commercial paper program and other liquidity requirements. As a result of the
credit downgrades on January 16 and 17, 2001 (see Note 3), PG&E Corporation
began to default under these credit facilities and the banks refused any
additional borrowing requests and terminated their commitments under the
facilities. As of December 31, 2000, $185 million had been drawn from the $500
million facility. In March 2001, PG&E Corporation secured $1 billion in
aggregate proceeds from two term loans under a common credit agreement with
General Electric Capital Corporation and Lehman Commercial Paper Inc. to
refinance defaulted commercial paper and revolving credit agreements. In
connection with PG&E Corporation's refinancing, the revolving credit facilities
were cancelled. The total amount of commercial paper outstanding at December 31,
2000, backed by the two facilities, was $746 million. The total amount of
commercial paper outstanding at December 31, 1999, backed by the $500 million
facility was $450 million.
Utility
The Utility had a $1 billion revolving credit facility which was scheduled to
expire in December 2002. In October 2000, the Utility obtained an additional
$1.0 billion credit facility (which was subsequently reduced to $850 million in
December 2000) which expires in December 2001. These facilities were used to
support the Utility's commercial paper program and other liquidity requirements.
As of December 31, 2000, $614 million had been drawn from the $1 billion
facility. Due to a subsequent credit rating downgrade, the banks refused any
additional borrowing requests and terminated their outstanding commitments under
the Utility's two credit facilities (see Note 3). The total amount of commercial
paper outstanding at December 31, 2000 backed by the two facilities was $1,225
million. The weighted average interest rate on the Utility's short-term
borrowings as of December 31, 2000 and 1999 was 7.5% and 5.3%, respectively. The
total amount outstanding at December 31, 1999 backed by the $1 billion facility
was $449 million in commercial paper.
In addition, the Utility issued a total of $1,240 million in 364-day floating
rate notes in November 2000. These notes mature on November 30, 2001, with
interest payable quarterly. The nonpayment of the Utility's outstanding
commercial paper is an event of default under the floating rate notes, entitling
the floating rate note trustees to accelerate the repayment of these notes. (See
Note 3)
National Energy Group
The NEG maintains $1,350 million in five revolving credit facilities, which
support commercial paper and Eurodollar borrowing arrangements. At December 31,
2000 and 1999, the NEG had total outstanding balances related to such borrowings
of $1,181 million and $1,173 million, respectively. In addition, certain letters
of credit held by the NEG reduce the available outstanding facility commitments.
At December 31, 2000, approximately $36 million in letters of credit were
outstanding. Since the NEG has the ability and intent to refinance certain
borrowings, $661 million and $649 million of such borrowings were classified as
long-term debt as of December 31, 2000 and 1999, respectively (see Note 8).
Certain credit arrangements contain, among other restrictions, customary
affirmative covenants, representations, and warranties and are cross-defaulted
to the NEG's other obligations. The credit agreements also contain certain
negative covenants including restrictions on the following: consolidations,
mergers, sales of assets and investments; certain liens on the NEG's property or
assets; incurrence of indebtedness; entering into agreements limiting the right
of any subsidiary of the NEG to make payments to its shareholders; and certain
transactions with affiliates. Certain credit agreements also require that the
NEG maintain a minimum ratio of cash flow available for fixed charges and a
maximum ratio of funded indebtedness to total capitalization. The NEG was in
compliance with all convenants at December 31, 2000.
Note 11: Nuclear Decommissioning
Decommissioning of the Utility's nuclear power facilities 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 $1.7 billion in 2000 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% and 5.39%, respectively, as well as
a future annual escalation rate of 5.5% 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, 2000, 1999, and 1998 nuclear decommissioning
costs recovered in rates were $25 million, $26 million, and $33 million,
respectively. The CPUC has established a Nuclear Decommissioning Cost Triennial
Proceeding to review, every three years, updated decommissioning cost estimates
and to establish the annual trust contribution, absent General Rate Cases.
At December 31, 2000, 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 CPUC.
The following table provides a summary of fair value, based on quoted market
prices, of these nuclear decommissioning funds:
For the year ended
December 31,
------------
(in millions) Maturity Date 2000 1999
U.S. government and agency issues 2001-2030 $ 409 $ 380
Equity securities 239 223
Municipal bonds and other 2001-2034 252 201
Gross unrealized holding gains 447 474
Gross unrealized holding losses (19) (14)
Fair value $1,328 $1,264
The proceeds received from sales of securities were $1.4 billion, $1.7
billion, and $1.4 billion in 2000, 1999, and 1998, respectively. The gross
realized gains on sales of securities held as available-for-sale were $74
million, $59 million, and $52 million in 2000, 1999, and 1998, respectively. The
gross realized losses on sales of securities held as available-for-sale were $64
million, $60 million, and $39 million in 2000, 1999, and 1998, respectively. The
cost of debt and equity securities sold is determined by specific
identification.
Under the Nuclear Waste Policy Act of 1982, the U.S. 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 plan. The schedules below aggregate all of PG&E Corporation's plans.
The following schedule reconciles the plans' funded status (the difference
between fair value of plan assets and the benefit obligation) to the prepaid or
accrued benefit cost recorded on the consolidated balance sheet:
Pension Benefits Other Benefits
---------------- --------------
(in millions) 2000 1999 2000 1999
Change in benefit obligation
Benefit obligation at January 1 $(4,807) $(4,977) $ (970) $ (949)
Service cost for benefits earned (119) (121) (16) (19)
Interest cost (386) (347) (72) (69)
Plan amendments (347) -- -- (4)
Actuarial gain (loss) (33) 372 (11) (19)
Divestiture (acquisition) 7 -- 17 --
Participants paid benefits -- -- (14) (14)
Benefits and expenses paid 280 266 57 104
Benefit obligation at December 31 $(5,405) $(4,807) $(1,009) $ (970)
Change in plan assets
Fair value of plan assets at January 1 $ 8,153 $ 7,104 $ 1,091 $ 951
Actual return on plan assets (66) 1,331 (33) 240
Company contributions 3 4 2 15
Plan participant contribution -- -- 14 14
Divestiture (2) -- -- --
Benefits and expenses paid (280) (286) (62) (103)
Fair value of plan assets at December 31 $ 7,808 $ 8,153 $ 1,012 $1,117
Funded Status
Plan assets in excess of benefit obligation $ 2,403 $ 3,346 $ 3 $ 121
Unrecognized prior service cost 399 93 15 17
Unrecognized net (loss) gain (2,001) (2,963) (348) (520)
Unrecognized net transition obligation 50 65 314 339
Prepaid (accrued) benefit cost $ 851 $ 541 $ (16) $ (43)
The Utility's share of the plan's assets in excess of the benefit obligation
for pensions in 2000 and 1999 was $2,407 million and $3,344 million,
respectively. The Utility's share of the prepaid (accrued) benefit cost for the
pensions in 2000 and 1999 was $864 million and $556 million, respectively.
The plan assets of the Utility exceeded its share of the benefit obligation
for other benefits by $3 million and $167 million in 2000 and 1999,
respectively. The Utility's share of the accrued benefit liability for other
benefits in 2000 and 1999 was $15 million and $22 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, December 31,
----------------------------- -----------------------------
(in millions) 2000 1999 1998 2000 1999 1998
Service cost for benefits earned $(119) $(121) $(108) $ (17) $ (19) $ (19)
Interest cost (386) (347) (333) (72) (69) (64)
Expected return on assets 679 634 567 91 83 73
Amortized prior service and transition
cost (55) (25) (26) (28) (27) (28)
Actuarial gain recognized 183 111 114 32 20 22
Settlement gain 6 -- -- 18 -- --
Benefit income (cost) $ 308 $ 252 $ 214 $ 24 $ (12) $ (16)
The Utility's share of the net benefit income for pensions in 2000, 1999,
and 1998 was $302 million, $253 million, and $215 million, respectively.
The Utility's share of the net benefit cost for other benefits in 2000,
1999, and 1998 was $7 million, $9 million, and $12 million, respectively.
Net benefit income (cost) is calculated using expected return on plan
assets of 8.5%. The difference between actual and expected return on plan assets
is included in net amortization and deferral and is considered in the
determination of future net benefit income (cost). In 1999 and 1998, actual
return on plan assets exceeded expected return, while actual return on plan
assets was below expected in 2000.
In conformity with SFAS No. 71, regulatory adjustments have been recorded in
the income statement and balance sheet of the Utility, which reflect the
difference between Utility pension income determined for accounting purposes and
Utility pension income determined for ratemaking, which is based on a funding
approach.
The CPUC has 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 amount of post-employment benefit costs included in
the regulatory assets as of December 31, 2000 is $34 million, and is expected to
be recovered through rates.
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, December 31,
------------------------ ------------------------
2000 1999 1998 2000 1999 1998
Discount rate 7.5% 7.5% 7.0% 7.5% 7.5% 7.0%
Average 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% 8.5% 9.0% 8.5% 9.0% 9.0%
The assumed health care cost trend rate for 2001 is approximately 8.0%,
grading down to an ultimate rate in 2005 and beyond of approximately 6.0%. 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:
(in millions) 1-Percentage 1-Percentage
Point Increase Point Decrease
Effect on total service and
interest cost components $ 5 $ (4)
Effect on postretirement benefit
obligation $45 $(42)
PG&E Corporation and its subsidiaries also sponsor defined contribution
pension plans. These plans are intended to qualify under Sections 401(a),
409(a), and 501(a) of the Internal Revenue Code. Employer contribution expense
reflected in the accompanying PG&E Corporation Consolidated Statement of Income
totaled $60 million, $53 million, and $49 million, for the years ended December
31, 2000, 1999, and 1998, respectively.
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, 2000, 30,992,530 shares of PG&E Corporation common stock had been authorized
for award under the Program, with 6,649,736 shares still available under the
Program. Options granted in 2000, 1999, and 1998 had weighted average fair value
at date of grant of approximately $3.26, $4.19, and $3.81 per share,
respectively, using the Black-Scholes valuation method. In addition, PG&E
Corporation granted stock options covering 26,852 shares on January 2, 2001 at
an exercise price of $19.56, and 5,498,500 shares on January 5, 2001 at an
exercise price of $12.63, the then-current market price. Significant assumptions
used in the Black-Scholes valuation method for shares granted in 2000, 1999, and
1998 were: expected stock price volatility of 20.19%, 16.79%, and 17.60%,
respectively; expected dividend yield of 5.18%, 3.77%, and 4.47%, respectively;
risk-free interest rate of 6.10%, 4.69%, and 6.03%, respectively; and an
expected 10-year life for all periods.
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, 2000 had
option prices ranging from $16.75 to $34.25 and a weighted-average remaining
contractual life of 9.2 years. As permitted under SFAS No. 123, "Accounting for
Stock-Based Compensation," PG&E Corporation applies Accounting Principles Board
Opinion No. 25 "Accounting for Stock Issued to Employees" in accounting for the
Program. As the exercise prices of all stock options is equal to the respective
fair market value at the date of grant, 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 pro forma consolidated earnings
(loss) per share would have been as follows:
2000 1999 1998
Net earnings (loss):
As reported $(3,364) $ (73) $ 719
Pro-forma (3,374) (79) 717
Basic and diluted earnings (loss) per share:
As reported (9.29) (0.20) 1.88
Pro-forma (9.32) (0.21) 1.88
The following table summarizes the Program's activity as of and for the years
ended December 31:
2000 1999 1998
---- ---- ----
Weighted Weighted Weighted
Average Average Average
Option Option Option
(shares in million) Shares Price Shares Price Shares Price
Outstanding--beginning of year 16.4 $29.42 11.1 $28.35 6.2 $26.21
Granted during year 10.2 $20.03 7.0 $30.94 6.4 $30.53
Exercised during year (1.2) $23.52 (0.5) $25.86 (0.7) $29.63
Cancellations during year (1.1) $26.57 (1.2) $29.82 (0.8) $28.16
Outstanding--end of year 24.3 $25.90 16.4 $29.43 11.1 $28.35
Exercisable--end of year 6.3 $27.73 3.0 $29.08 2.4 $29.06
The following summarizes information for options outstanding and exercisable
at December 31, 2000. Of the outstanding options at December 31, 2000,
11,271,169 shares had exercise prices ranging from $16.75 to $24.38 with a
weighted average remaining contractual life of 9.7 years, of which 2,143,943
shares were exercisable at a weighted average exercise price of $21.90, while
13,071,625 shares had option prices ranging from $24.50 to $34.25, with a
weighted average remaining contractual life of 8.8 years, of which 4,155,548
shares were exercisable at a weighted average exercise price of $30.73.
Performance Unit Plan
PG&E Corporation grants performance units to certain officers of PG&E
Corporation and its affiliates. The performance units vest one-third in each of
the three years following the year of grant. Each time a cash dividend is
declared on PG&E Corporation common stock, an amount equal to the cash dividend
per share multiplied by the number of outstanding but unearned units held by the
recipient of a performance unit will be accrued on behalf of the recipient. As
soon as practicable following the end of each year, recipients will receive a
cash payment of the dividends accrued for the year, modified by performance for
that year as measured against the applicable performance target. The number of
performance units granted and the amounts of compensation expense recognized in
connection with the issuance of performance units during the years ended
December 31, 2000, 1999, and 1998 was not material.
Note 13: Income Taxes
The significant components of income tax (benefit) expense for continuing
operations were:
PG&E Corporation Utility
Year Ended December 31, Year Ended December 31,
-------------------------------- --------------------------
(in millions) 2000 1999 1998 2000 1999 1998
Current $(1,261) $1,002 $ 718 $(1,224) $1,133 $ 886
Deferred (728) (702) (51) (891) (433) (201)
Tax credits, net (39) (52) (56) (39) (52) (56)
Income tax (benefit) expense $(2,028) $ 248 $ 611 $(2,154) $ 648 $ 629
In 2000, the income tax expense of PG&E Corporation was allocated to
continuing operations ($2,028 million benefit) and discontinued operations ($36
million tax benefit).
The significant components of net deferred income tax liabilities were:
PG&E Corporation Utility
Year ended Year ended
---------- ----------
December 31, December 31,
------------ -------------
2000 1999 2000 1999
(in millions)
Deferred income tax assets:
Customer advances for construction $ 176 $ 109 $ 176 $ 109
Unamortized investment tax credits 114 118 114 118
Provision for injuries and damages 203 185 203 185
Tax benefit of loss carryforward 70 -- 100 --
Deferred contract costs 124 182 -- --
Other 322 544 233 442
Total deferred income tax assets $1,009 $1,138 $ 826 $ 854
Deferred income tax liabilities:
Regulatory balancing accounts 17 (47) 17 (47)
Plant in service 2,185 2,827 1,719 2,428
Income tax regulatory asset 68 297 65 287
Other 564 1,075 126 577
Total deferred income tax liabilities 2,834 4,152 1,927 3,245
Total net deferred income taxes $1,825 $3,014 $1,101 $2,391
Classification of net deferred income taxes:
Included in current liabilities (assets) $ 169 $ (133) $ 172 $ (119)
Included in noncurrent liabilities 1,656 3,147 929 2,510
Total net deferred income taxes $1,825 $3,014 $1,101 $2,391
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, Year ended December 31,
------------------------ ----------------------
2000 1999 1998 2000 1999 1998
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) 4.4 10.1 3.2 4.3 6.2 6.6
Effect of regulatory treatment of depreciation
differences (2.1) 51.7 9.7 (2.0) 9.4 9.8
Tax credits--net 0.7 (19.9) (4.0) 0.7 (3.6) (4.1)
Effect of foreign earnings at different tax rates 0.1 (1.3) 0.6 -- -- --
Stock sale differences (1.4) (6.8) -- -- -- --
Stock sale valuation allowance 1.5 30.2 -- -- -- --
Other--net (0.3) (4.0) (0.3) 0.2 (1.9) (1.0)
Effective tax rate 37.9% 95.0% 44.2% 38.2% 45.1% 46.3%
As a result of the Utility's purchased power costs which were not recovered in
rates charged to the customers, PG&E Corporation and the Utility incurred a Net
Operating Loss (NOL) for 2000. The NOL was carried back to prior years in
accordance with federal income tax law resulting in a refund of approximately
$1.2 billion. For California income tax purposes 55% of the California NOL may
only be carried forward. The amount of this NOL carryforward is
$1.2 billion for PG&E Corporation of which $1.7 billion is attributable to the
Utility. The Company has recognized the benefits of its NOLs in the consolidated
financial statements.
During 1999, PG&E Corporation generated a capital loss carryforward from the
sale of stock of approximately $225 million. The capital loss carryforward
expires in 2005. A valuation allowance of approximately $75 million was recorded
in 1999 reflecting the estimated net realizable value of this capital loss
carryforward. PG&E Corporation, based upon its forecasted net capital gains,
believed that it was more likely than not that it would not be able to fully
utilize the full capital loss carryforward.
Note 14: Commitments
Surety Bonds
Utility
PG&E Corporation has arranged on behalf of the Utility $456 million in surety
bonds to secure future workers' compensation liabilities. Effective in March,
2001, three of the five insurers of surety bonds have cancelled their coverage.
The aggregate amount of this cancellation is approximately $285 million. This
cancellation relieves the insurers only for claims arising from incidents
occurring after the date of cancellation. They will still be responsible
indefinitely for all future claims arising from incidents occurring prior to the
date of cancellation. This cancellation has not impacted the Utility's self-
insurance program under California law or its ability to meet its current plan
obligations.
Restructuring Trust Guarantees
Utility
A tax-exempt restructuring trust was established to oversee the development of
the operating framework for the competitive generation market in California. The
CPUC has authorized California utilities to guarantee bank loans of up to $85
million to be used by the trust for this purpose. Under the CPUC authorization,
the Utility's remaining guarantee is for up to a maximum of $38 million of the
loan. Although the remaining bank loan was repaid, the guarantee remains in
place until the earlier of voluntary termination by the trust of the
commitments, or the trust obtaining proceeds from permanent financing or
recovery in rates, or the expiration date of bank loan commitments in December
2001.
Tolling Agreements
National Energy Group
In 2000 and 1999, the NEG, through PG&E ET, entered into tolling agreements
with several counterparties giving the NEG the right to sell electricity
generated by facilities owned and operated by other parties which are under
construction until June 2003. Under the tolling agreements, the NEG, at its
discretion, supplies the fuel to the power plants, then sells the plant's output
in the competitive market. Committed payments are reduced if the plant
facilities do not achieve agreed-upon levels of performance criteria. At
December 31, 2000, the annual estimated committed payments under such contracts
ranged from approximately $21 million to $304 million, resulting in total
committed payments over the next 28 years of approximately $6.2 billion
commencing at the completion of construction. Estimated amounts payable in
future years are as follows:
(in millions)
2001 $ 21
2002 98
2003 220
2004 280
2005 285
Thereafter 5,300
Total $6,204
During 2000, the NEG paid total committed payments of approximately $12
million under tolling agreements.
Power Purchase Contracts
Utility
The Utility is required to purchase electric energy and capacity provided
by independent power producers that are QFs under the Public Utilities
Regulatory Policies Act of 1978 (PURPA.) The CPUC required the Utility to enter
into a series of QF long-term power purchase contracts and approved 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 non-bypassable CTC. The Utility's contracts with
these power producers expire on various dates through 2028. Deliveries from
these power producers account for approximately 23% of the Utility's 2000
electric energy requirements, and no single contract accounted for more than
five percent of the Utility's energy needs.
Prior to 2000, the Utility has negotiated with several QFs for early
termination of their power purchase contracts. At December 31, 2000, the total
discounted future payments due under the renegotiated contracts was
approximately $145 million.
Approximately half of the Utility's suppliers under long-term QF contracts
have currently elected to receive PX-based prices for energy in addition to
contractual capacity payments. However, pursuant to a CPUC order issued on
February 22, 2001, PX-based-priced QFs reverted back to transition formula
prices on January 19, 2001. Since the end of January 2001, the Utility has been
partially paying amounts due QFs. On March 27, 2001, the CPUC issued a decision
requiring the Utility and the other California investor-owned utilities to pay
QFs fully for energy deliveries made on and after the date of the decision,
within 15 days of the end of the QFs' billing period. The decision permits QFs
to establish a 15-day billing period as compared to the current monthly billing
period. The decision also adopts a revised pricing formula relating to the
California border price of gas applicable to energy payments to all QFs,
including those that do not use natural gas as a fuel. Based on the Utility's
preliminary review of the decision, the revised pricing formula would reduce the
Utility's 2001 average QF energy and capacity payments from approximately 12.7
cents per kWh to 12.3 cents per kWh.
The amount of energy received and the total payments made under all of
these power purchase contracts were:
Year Ended December 31,
-----------------------
(in millions) 2000 1999 1998
Kilowatt-hours received 25,446 25,910 25,994
Energy payments $ 1,549 $ 837 $ 943
Capacity payments $ 519 $ 539 $ 529
Irrigation district and water agency pay $ 56 $ 60 $ 53
National Energy Group
The NEG, through its indirect subsidiary, USGenNE, assumed rights and
duties under several power purchase contracts with third-party independent power
producers as part of the acquisition of the NEES assets. At December 31, 2000,
these agreements provided for an aggregate of 800 MW of capacity. Under the
transfer agreement, the NEG is required to pay to NEES amounts due to the third-
party power producers under the power purchase contracts. The approximate dollar
amounts under these agreements are as follows:
(in millions)
2001 $ 228
2002 215
2003 217
2004 220
2005 220
Thereafter 1,585
Total $2,685
Natural Gas Supply and Transportation Commitments
Utility
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 $94 million,
$97 million, and $113 million in 2000, 1999, and 1998, respectively. These
amounts include payments made by the Utility to PG&E GTN of $46 million, $47
million, and $49 million in 2000, 1999, and 1998, 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)
2001 $100
2002 101
2003 77
2004 77
2005 68
Thereafter 29
Total $452
As a result of regulatory changes, the Utility no longer procures gas for
most of its industrial and larger commercial (non-core) 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 non-core 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.
The Utility's deteriorating credit situation has caused many of its gas
suppliers to decline to sell the Utility any more gas, even under existing gas
contracts, in the absence of accelerated payments. Specifically, some gas
suppliers (1) have made demands that the Utility provide prepayment, cash on
delivery, or other forms of payment assurance for gas supplies instead of the
normal payment terms under which the Utility would pay for gas delivery, which
the Utility is unable to meet given its current cash constraints, and (2) have
refused to sell gas to the Utility for future periods. Failure to procure gas
supplies to meet residential and smaller commercial gas (core) customer demands
could result in diverting gas supplies from industrial and larger commercial gas
(non-core) customers, which would only exacerbate the crisis.
The U.S. Secretary of Energy issued a temporary order on January 19, 2001
requiring the gas suppliers to continue to make deliveries to avoid a worsening
natural gas shortage emergency. However, this order expired on February 7, 2000,
and certain companies, representing about 10% of the Utility's natural gas
suppliers, terminated deliveries after the order expired. The Utility has tried
to mitigate the worsening supply situation by withdrawing more gas from storage
and, when able, purchasing additional gas on the spot market. Additionally, on
January 31, 2001, the CPUC authorized the Utility to pledge its gas account
receivables and its gas inventories for up to 90 days (extended to 180 days in a
CPUC draft decision issued on February 15, 2001) to secure gas for its core
customers. At March 29, 2001, the amount of gas accounts receivable pledged was
approximately $900 million. To date, approximately 30% of the Utility's
suppliers of natural gas have signed security agreements with the Utility and
discussions are continuing with the Utility's other suppliers. Additionally, the
Utility is currently implementing a program to obtain longer term summer and
winter supplies and daily spot supplies of natural gas.
National Energy Group
The NEG, through its subsidiaries PG&E Gen and PG&E ET, has entered into
various gas supply and firm transportation agreements with various pipelines and
transporters. Under these agreements, the NEG must make specific minimum
payments each month. The approximate dollar obligations under these gas supply
and transportation agreements are as follows:
(in millions)
2001 $ 87
2002 87
2003 87
2004 85
2005 85
Thereafter 708
Total $1,139
Acquisition of Turbine Rights
National Energy Group
On September 8, 2000, the NEG, through one of its subsidiaries, entered
into operative documents with a special purpose entity (the Lessor) in order to
facilitate the development, construction, financing, and leasing of several
power generation projects. The Lessor has an aggregate financing commitment from
debt and equity participants (the Investors) of $7.8 billion. The NEG, in its
role as construction agent for the Lessor, is responsible for completing
construction by the sixth anniversary of the closing date, but has limited its
risk related to construction completion to less than 90% of project costs
incurred to date. Upon completion of an individual project, the NEG is required
to make lease payments to the Lessor in an amount sufficient to provide a return
to the Investors. At the end of an individual project's operating lease term
(three years from construction completion), the NEG has the option to extend the
lease at fair value, purchase the
project at a fixed amount (equal to the original construction cost), or act as
remarketing agent for the Lessor and sell the project to an independent third
party. If the NEG elects the remarketing option, the NEG may be required to make
a payment to the Lessors, up to 85% of the project cost, if the proceeds from
remarketing are deficient to repay the Investors. PG&E Corporation committed to
fund up to $314 million of equity to support the NEG's obligation to the Lessor
during the construction and post-construction periods. The NEG is attempting to
replace PG&E Corporation equity support commitments with substitute commitments
of the NEG.
Standard Offer Agreements
National Energy Group
USGenNE entered into three standard offer agreements with NEES' retail
subsidiaries under which USGenNE will provide "standard offer" service to such
subsidiaries. The standard offer agreements initially covered all of the retail
customers served by NEES' distribution subsidiaries in Rhode Island, New
Hampshire, and Massachusetts at the date of USGenNE's acquisition of the NEES
assets. The Standard Offer Agreements continue through June 30, 2002 in New
Hampshire; December 31, 2004 in Massachusetts; and December 31, 2009 in Rhode
Island. The pricing per MWh is standard for all contracts and was below market
prices at the date of the agreement. On January 7, 2000, USGenNE paid
approximately $15 million by entering into an agreement with a third party which
assumed the obligation to deliver power to NEES to serve 10% of the
Massachusetts customers and 40% of the Rhode Island customers under the terms of
the standard offer agreements. The payment was recorded as a deferred standard
offer fee and is amortized over the remaining life of the standard offer
agreements.
Operating Leases
National Energy Group
The NEG and its subsidiaries have entered into several operating lease
agreements for generating facilities and office space. Lease terms vary between
three and 48 years. In November 1998, a subsidiary of the NEG entered into a
$479 million sale-leaseback transaction whereby the subsidiary sold and leased
back a pumped storage station under an operating lease.
During 2000 and 1999, two indirect wholly owned subsidiaries of the NEG
entered into two operating lease commitments relating to projects that are under
construction, for which they act as the construction agent for the lessors. Upon
completion of the construction projects, expected to be in 2001 and 2002, the
lease terms of five years and three years, respectively, will commence. At the
conclusion of each of the operating lease terms, the NEG has the option to
extend the leases at fair market value, purchase the projects, or act as
remarketing agent for the lessors for sales to third parties. If the Company
elects to remarket the projects, then the NEG would be obligated to the lessors
for up to 85% of the project costs if the proceeds are deficient to pay the
lessor's investors. PG&E Corporation has committed to fund up to $604 million in
the aggregate of equity to support the NEG's obligation to the lessors during
the construction and post-construction periods. The NEG is attempting to replace
PG&E Corporation's equity support commitments with substitute commitments of
NEG.
The approximate obligations under these operating lease agreements as of
December 31, 2000 were as follows:
(in millions)
2001 $ 97
2002 159
2003 166
2004 162
2005 88
Thereafter 965
Total $1,637
Operating lease expense amounted to $58 million, $67 million, and $35
million in 2000, 1999, and 1998, respectively.
In addition to those obligations described above, the NEG entered into
operative agreements with a special purpose entity that will own and finance
construction of a facility totaling $775 million. PG&E Corporation has committed
to fund up to $122 million of equity support commitments to meet the obligations
to the entity. The NEG is attempting to replace the PG&E Corporation's equity
support commitments with substitute commitments of NEG.
Construction
National Energy Group
An indirect wholly owned subsidiary of PG&E Gen entered into a turnkey
construction contract with a third-party contractor to construct a 360-MW
natural gas-fired combined-cycle power plant in Charlton, Massachusetts. The
total contract value is $72 million. The contractor's responsibilities include
designing and engineering the project and providing procurement and construction
services, start-up, training, and performance testing. The contractor had
guaranteed that substantial completion will occur on or prior to August 20,
2000. Through the date of these financial statements, substantial completion has
not occurred and the contractor is paying delay damages in accordance with the
terms of the turnkey construction contract. At December 31, 2000 and 1999,
approximately $69 million and $54 million, respectively, had been paid to the
contractor under the turnkey construction contract.
The same subsidiary also entered into a power island equipment and supply
contract with Westinghouse Power Corporation (WPC) to provide the power island,
the steam turbine, and the heat recovery steam generator. The total contract
value is $69 million. At December 31, 2000 and 1999, approximately $67 million
had been paid to WPC under the power island contract.
In another construction transaction, an indirect wholly-owned subsidiary of
PG&E Gen contracted with Siemens Westinghouse Power (SWP) in 2000 to provide the
combustion turbine generator, steam turbine generator and heat recovery steam
generator for its 1,080-MW natural gas-fired combined cycle power plant under
development in Greene County, New York. The total contract value is
approximately $223 million. At December 31, 2000, approximately $69 million had
been paid to SWP. Construction is expected to commence June 2001.
Long-Term Service Agreements
National Energy Group
The NEG has entered into long-term service agreements for the maintenance
and repair of certain of its combustion turbine or combined-cycle generating
plants under construction. These agreements, which are for periods up to 20
years, may be terminated in the event a planned construction project is
cancelled. Annual amounts for long-term service agreements committed for the
next five years under the current construction plan are as follows as of
December 31, 2000:
(in millions)
2001 $ 12
2002 35
2003 35
2004 34
2005 35
Thereafter 269
Total $420
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 $12 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
Utility
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, the
Utility may be responsible for remediation of hazardous substances, even if it
did not deposit those substances on the site.
The Utility records an environmental remediation 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.
At December 31, 2000, the Utility expects to spend $320 million for
hazardous waste remediation costs at identified sites, including divested
fossil-fueled power plants. 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. If 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 could spend as much as $462 million on these
costs. 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.
The Utility had an environmental remediation liability of $320 million and
$271 million at December 31, 2000 and 1999, respectively. The $320 million
accrued at December 31, 2000 includes (1) $140 million related to the pre-
closing remediation liability, associated with the divested generation
facilities discussed further in the "Generation Divestiture" section of Note 2
of the Notes to the Consolidated Financial Statements, and (2) $180 million
related to remediation costs for those generation facilities that the Utility
still owns, manufactured gas plant sites, and gas gathering
compressor stations. Of the $320 million environmental remediation liability,
the Utility has recovered $168 million through rates, and expects to recover
another $87 million in future rates. The Utility is seeking recovery of the
remainder of its costs from insurance carriers and from other third parties as
appropriate.
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. In
March 2000, the Central Coast Board requested the Utility to provide specific
information regarding the "backflush" procedure used at Moss Landing. The
Utility provided the requested information to the Board in April 2000. The
Utility's investigation indicated that while it owned Moss Landing, significant
amounts of water discharged from the cooling water intake. While the Utility's
investigation did not clearly indicate that discharged waters had a temperature
higher than ambient receiving water, the Utility believes that the temperature
of the discharged water was higher than that of the ambient receiving water. In
December 2000, the executive officer of the Central Coast Board made a
settlement proposal to the Utility under which it would pay $10 million, a
portion of which would be used for environmental projects and the balance of
which would constitute civil penalties. Settlement negotiations are continuing.
The Utility's Diablo Canyon employs a "once through" cooling water system
which is regulated under a NPDES Permit issued by the Central Coast Board. This
permit allows Diablo Canyon to discharge the cooling water at a temperature no
more than 22 degrees above ambient receiving water, and requires that the
beneficial uses of the water be protected. The beneficial uses of water in this
region include industrial water supply, marine and wildlife habitat, shell fish
harvesting, and preservation of rare and endangered species. In January 2000,
the Central Coast Board issued a proposed draft Cease and Desist Order (CDO)
alleging that, although the temperature limit has never been exceeded, the
Diablo Canyon's discharge was not protective of beneficial uses. In October
2000, the Central Coast Board and the Utility reached a tentative settlement of
this matter pursuant to which the Central Coast Board has agreed to find that
the Utility's discharge of cooling water from the Diablo Canyon plant protects
beneficial uses and that the intake technology reflects the "best technology
available" under Section 316(b) of the Federal Clean Water Act. As part of the
settlement, the Utility will take measures to preserve certain acreage north of
the plant and will fund approximately $4.5 million in environmental projects
related to coastal resources. The parties are negotiating the documentation of
the settlement. The final agreement will be subject to public comment and will
be incorporated in a consent decree to be entered in California's Superior
Court.
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.
National Energy Group
In October and November 1999, the U.S. Environmental Protection Agency
(EPA) and several states filed suits or announced their intention to file suits
against a number of coal-fired power plants in Midwestern and Eastern states.
These suits relate to alleged violations of the Clean Air Act. More
specifically, they allege violations of the deterioration prevention and non-
attainment provisions of the Clean Air Act's new source review requirements
arising out of certain physical changes that may have been made at these
facilities without first obtaining the required permits. In May 2000, the NEG
received a request for information seeking detailed operating and maintenance
histories for the Salem Harbor and Brayton Point power plants. If EPA were to
find that there were physical changes in the past that were undertaken without
first receiving the required permits under the Clean Air Act, then penalties may
be imposed and further emission reductions might be necessary at these plants.
In addition to the EPA, states may impose more stringent air emissions
requirements. The Commonwealth of Massachusetts is considering the adoption of
more stringent air emission reductions from electric generating facilities. If
adopted, these requirements will impact Salem Harbor and Brayton Point. The NEG
has proposed an emission reduction plan that may include modernization of the
Salem Harbor power plant and use of advanced technologies for emissions removal.
It is also studying various advanced technologies for emissions removal for the
Brayton Point power plant.
The NEG's subsidiary, USGenNE, has proposed a number of state and regional
initiatives that will require it to achieve significant reductions of emissions
by 2010. The NEG expects that USGenNE will meet these requirements through a
combination of installation of controls, use of emission allowances it currently
owns, and purchase of additional allowances. The NEG currently estimates that
USGenNE's total capital cost for complying with these requirements will be
approximately $270 million.
PG&E Gen's existing power plants, including USGenNE facilities, are subject
to federal and state water quality standards with respect to discharge
constituents and thermal effluents. Three of the fossil-fueled plants owned and
operated by USGenNE are operating pursuant to NPDES permits that have expired.
For the facilities whose NPDES permit have expired, permit renewal applications
are pending, and it is anticipated that all three facilities will be able to
continue to operate under existing terms and conditions until new permits are
issued. It is estimated that USGenNE's cost to comply with the new permit
conditions could be as much as $55 million through 2005. It is possible that the
new permits may contain more stringent limitations than prior permits.
During September 2000, USGenNE signed a series of agreements that require,
among other things, that USGenNE alter its existing waste water treatment
facilities at two facilities by replacing certain unlined treatment basins,
submit and implement a plan for the closure of such basins, and perform certain
environmental testing at the facilities. USGenNE has incurred $4 million in 2000
and expects to complete the required steps on or before December 2001. The total
expected cost of these improvements is $21 million.
Legal Matters
Utility
The Utility's Chapter 11 bankruptcy filing on April 6, 2001, discussed in
Notes 2 and 3, automatically stayed the litigation described below against the
Utility.
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 Hinckley, Kettleman, and
Topock, California. Currently, there are claims pending on behalf of
approximately 1,050 individuals. The trial of 18 test cases is currently
scheduled for July 2001.
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 has recorded a legal reserve
in its financial statements in the amount of $160 million for these matters.
PG&E Corporation and the Utility believe that, after taking into account the
reserves recorded as of December 31, 2000, the ultimate outcome of this matter
will not have a material adverse impact on PG&E Corporation's or the Utility's
financial condition or future results of operations.
Wilson vs PG&E Corporation and Pacific Gas and Electric Company:
On February 13, 2001, two complaints were filed against PG&E Corporation
and the Utility in the Superior Court of the State of California, San Francisco
County: Richard D. Wilson v. Pacific Gas and Electric Company et al. (Wilson I),
and Richard D. Wilson v. Pacific Gas and Electric Company, et al. (Wilson II).
In Wilson I, the plaintiff alleges that in 1998 and 1999, PG&E Corporation
violated its fiduciary duties and California Business and Professions Code
Section 17200 by causing the Utility to repurchase shares of Pacific Gas and
Electric Company common stock from PG&E Corporation at an aggregate price of
$2,326 million. The complaint alleges an unlawful business act or practice under
Section 17200 because these repurchases allegedly violated PG&E Corporation's
fiduciary duties, a first priority capital requirement allegedly imposed by the
CPUC's decision approving the formation of a holding company, and also an
implicit public trust imposed by Assembly Bill 1890, which granted authority for
the issuance of rate reduction bonds. The complaint seeks to enjoin the
repurchase by the Utility of any more of its common stock from PG&E Corporation
or other entities or persons unless good cause is shown, and seeks restitution
from PG&E Corporation of $2,326 million, with interest, on behalf of the
Utility. The complaint also seeks an accounting, costs of suit, and attorney's
fees.
In Wilson II, the plaintiff alleges that PG&E Corporation, the Utility, and
other subsidiaries have been parties to a tax-sharing arrangement under which
PG&E Corporation annually files consolidated federal and state income tax
returns for, and pays, the income taxes of PG&E Corporation and participating
subsidiaries. According to the plaintiff, between
1997 and 1999, PG&E Corporation collected $2,957 million from the Utility under
this tax-sharing arrangement, but paid only $2,294 million (net of refunds) to
all governments under the tax-sharing agreement. Plaintiff alleges that these
monies were held under an express and implied trust to be used by PG&E
Corporation to pay the Utility's share of income taxes under the tax-sharing
arrangement. Plaintiff alleges that PG&E Corporation overcharged the Utility
$663 million under the tax-sharing arrangement and has declined voluntarily to
return these monies to the Utility, in violation of the alleged trust, the
alleged first priority capital condition, and California Business and
Professions Code Section 17200. The complaint seeks to enjoin PG&E Corporation
from engaging in the activities alleged in the complaint (including the tax-
sharing arrangement), and seeks restitution from PG&E Corporation of $663
million, with interest, on behalf of the Utility. The complaint also seeks an
accounting, costs of suit, and attorney's fees.
PG&E Corporation's and the Utility's analysis of these complaints is at a
preliminary stage, but PG&E Corporation and the Utility believe them to be
without merit and intend to present a vigorous defense. PG&E Corporation and the
Utility are unable to predict whether the outcome of this litigation will have a
material adverse affect on their financial condition or results of operation.
National Energy Group
The NEG is involved in various litigation matters in the ordinary course of
its business. Except as described below, the NEG is not currently involved in
any litigation that is expected, either individually or in the aggregate, to
have a material adverse effect on financial condition or results of operations.
Texas Franchise Fee Litigation Against PG&E GTT
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.
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. The NEG completed the sale of PG&E GTT in December 2000.
Recorded Liability for Legal Matters:
In accordance with SFAS No. 5 "Accounting for Contingencies," 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. The following
table reflects the current year's activity to the recorded liability for legal
matters:
PG&E
(in millions) Corporation Utility
Beginning balance, January 1, 2000 $106 $ 50
Provisions for liabilities 144 144
Payments (45) (43)
Adjustments (20) 34
Ending balance, December 31, 2000 $185 $185
Note 16: Segment Information
PG&E Corporation has identified four reportable operating segments, which
were determined based on similarities in economic characteristics, products and
services, types of customers, methods of distributions, the regulatory
environment, and how information is reported to PG&E Corporation's key decision
makers. The Utility is one reportable
operating segment and the other three are part of PG&E Corporation's NEG. 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.
Utility
PG&E Corporation's Northern and Central California energy utility
subsidiary, Pacific Gas and Electric Company, provides natural gas and electric
service to its customers.
National Energy Group
PG&E Corporation's subsidiary, the NEG, is an integrated energy company
with a strategic focus on power generation, new power plant development, natural
gas transmission, and wholesale energy marketing and trading in North America.
The NEG businesses include its power plant development and generation unit, PG&E
Generating Company, LLC and its affiliates; its natural gas transmission unit,
PG&E Gas Transmission Corporation; and its wholesale energy marketing and
trading unit, PG&E Energy Trading Holdings Corporation which owns PG&E Energy
Trading--Power, L.P., PG&E Energy Trading-Gas Corporation, and their affiliates.
During 2000, the NEG sold its energy services unit, PG&E Energy Services
Corporation. Also during the fourth quarter of 2000, the NEG sold its Texas
natural gas and natural gas liquids business operated through PG&E Gas
Transmission, Texas Corporation and PG&E Gas Transmission Teco, Inc. and their
subsidiaries.
Segment information for the years 2000, 1999, and 1998 was as follows:
National Energy Group/(4)/
--------------------------------------------------
PG&E GT
----------------------
Eliminations &
(in millions) Utility PG&E Gen/(4)/ Northwest Texas/(4)/ PG&E ET Other/(5)/ Total
2000
Operating revenues $ 9,623 $1,201 $ 188 $ 817 $14,414 $ (11) $26,232
Intersegment revenues/(1)/ 14 10 51 56 1,640 (1,771) --
Total operating revenues 9,637 1,211 239 873 16,054 (1,782) 26,232
Depreciation, amortization
and decommissioning 3,511 91 41 70 11 (65) 3,659
Interest income 186 66 1 (4) 7 10 266
Interest expense/(3)/ (619) (61) (41) (49) (5) (13) (788)
Income taxes (benefits)/(2)/ (2,154) 57 37 (35) 55 12 (2,028)
Income (loss) from
continuing operations (3,508) 84 58 20 27 (5) (3,324)
Capital expenditures/(6)/ 1,245 495 15 -- 3 -- 1,758
Total assets at year-end/(5)/(6)/ $21,988 $4,568 $1,204 $ -- $ 7,098 $ 433 $35,291
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 income 45 62 -- 9 4 (2) 118
Interest expense/(3)/ (593) (63) (41) (59) (12) (4) (772)
Income taxes (benefits)/(2)/ 648 16 32 (407) (36) (5) 248
Income (loss) from
continuing operations 763 97 68 (897) (34) 16 13
Capital expenditures/(6)/ 1,181 323 30 19 14 17 1,584
Total assets at year-end/(5)/(6)/ $21,470 $3,852 $1,160 $1,217 $ 1,876 $ (105) $29,470
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 income 96 29 1 9 6 (40) 101
Interest expense/(3)/ (621) (43) (43) (77) (7) 10 (781)
Income taxes (benefits)/(2)/ 629 28 31 (47) (17) (13) 611
Income (loss) from
continuing operations 702 106 65 (71) (6) (25) 771
Capital expenditures/(6)/ 1,382 98 49 39 12 39 1,619
Total assets at year-end/(5)/(6)/ $22,950 $3,844 $1,169 $2,655 $ 2,555 $ 61 $33,234
(1) Inter-segment electric and gas revenues are recorded at market prices,
which for the Utility and GTN are tariffed rates prescribed by the CPUC
and the FERC, respectively.
(2) 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.
(3) Interest expense incurred by PG&E Corporation is allocated to the
segments using specific identification.
(4) Income from equity-method investees for 2000, 1999, and 1998 was $65
million, $63 million, and $113 million, respectively, for PG&E Gen, and
$1 million, zero, and $3 million, respectively, for PG&E GTT.
(5) Assets of PG&E Corporation are included in "Eliminations & Other"
column exclusive of investment in its subsidiaries.
(6) Capital expenditures and assets of the discontinued operations of
Energy Services are included in "Eliminations & Other" column. Total
assets for PG&E ES at December 31, 2000, 1999, and 1998 were $1
million, $197 million, and $202 million, respectively. Capital
expenditures for 2000, 1999, and 1998 were zero, $17 million, and $38
million, respectively.
QUARTERLY CONSOLIDATED FINANCIAL DATA (UNAUDITED)
Quarter ended December 31 September 30 June 30 March 31
(in millions, except per share amounts)
2000
PG&E Corporation
Operating revenues $ 8,082 $7,504 $5,638 $5,008
Operating income (loss)/(1)(4)/ (6,734) 629 622 676
Income (loss) from continuing operations (4,096) 244 248 280
Net income (loss)/(1)(4)/ (4,117) 225 248 280
Earnings (loss) per common share from continuing operations,
basic (11.28) .67 .69 .78
Earnings (loss) per common share from continuing operations,
diluted (11.28) .67 .68 .77
Dividends declared per common share .30 .30 .30 .30
Common stock price per share
High 28.78 30.90 26.67 22.01
Low 18.25 22.50 20.39 18.80
Utility
Operating revenues $ 2,600 $2,523 $2,296 $2,218
Operating income (loss) (6,856) 533 552 570
Net income (loss) (4,156) 217 222 234
Income (loss) available for (allocated to) common stock (4,163) 211 216 228
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
(1) In the fourth quarter 1999, the NEG 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. An estimated loss
of $19 million ($0.05 per share), net of income taxes of $13 million, was
recorded for the quarter and nine months ended September 30, 2000.
Additionally, an estimated loss of $21 million ($0.06 per share), net of
income taxes of $23 million, was recorded for the quarter and three-month
period ended December 31, 2000.
(2) Amounts have been restated to reflect the change in accounting for major
maintenance and overhauls at the NEG (see Note 1), 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 of 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 NEG recorded an after-tax charge of $890 million
reflecting PG&E GTT's assets at their fair market value. (See MD&A and Note
5.)
(4) In the fourth quarter of 2000, the Utility recorded a charge to earnings
for the write-off of regulatory assets representing transition costs and
undercollected purchased power costs. The write-off was $6.9 billion ($4.1
after-tax) and reflected the fact that based upon the current status of the
California energy crisis, the Utility could no longer conclude that the
regulatory assets were probable of recovery through regulated rates.
Also in the fourth quarter of 2000, the Utility recognized a $140 million
($83 million, after tax) provision for an increase in legal reserves.
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 Pacific Gas and Electric Company and
subsidiaries as of December 31, 2000 and 1999, and the related statements of
consolidated operations, cash flows and common stock equity of PG&E Corporation
and the related statements of consolidated operations, cash flows and
stockholders' equity of Pacific Gas and Electric Company for the years then
ended. These financial statements are the responsibility of the management of
PG&E Corporation and of Pacific Gas and Electric Company. Our responsibility is
to express an opinion on these financial statements based on our audits. The
consolidated financial statements for the year ended December 31, 1998 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 auditing standards generally
accepted in the United States of America. 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 2000 and 1999 financial statements present fairly, in all
material respects, the financial position of PG&E Corporation and Pacific Gas
and Electric Company as of December 31, 2000 and 1999, and the results of their
consolidated operations and cash flows for the years then ended in conformity
with accounting principles generally accepted in the United States of America.
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.
The accompanying consolidated financial statements have been prepared on a
going concern basis of accounting. As discussed in Notes 2 and 3 of the Notes to
the Consolidated Financial Statements, Pacific Gas and Electric Company, a
subsidiary of PG&E Corporation, has incurred power purchase costs substantially
in excess of amounts charged to customers in rates. On April 6, 2001, Pacific
Gas and Electric Company sought protection from its creditors by filing a
voluntary petition under provisions of Chapter 11 of the U.S. Bankruptcy Code.
These matters raise substantial doubt about Pacific Gas and Electric Company's
ability to continue as a going concern. Managements' plans in regard to these
matters are also described in Notes 2 and 3 of the Notes to the Consolidated
Financial Statements. The consolidated financial statements do not include any
adjustments that might result from the outcome of this uncertainty.
DELOITTE & TOUCHE LLP
San Francisco, California
April 6, 2001
RESPONSIBILITY FOR THE CONSOLIDATED FINANCIAL STATEMENTS
In 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
accounting principles generally accepted in the United States of America.
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 2000 and 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.