EX-13 3 dex13.txt 2000 AMENDED ANNUAL REPORT TO SHAREHOLDERS 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 $ 26,220 $ 20,819 $ 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 36,152 29,588 33,234 31,115 26,237 Long-term debt (excluding current portions) 5,550 6,785 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. 1 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. Subsequent to the issuance of PG&E Corporation's 2000 and 1999 Consolidated Financial Statements, management determined that the assets and liabilities relating to certain leases should have been consolidated. The facilities associated with the leases were under construction during 2000 and 1999 (See Note 17 of the Notes to the Consolidated Financial Statements). 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; 2 . 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), 3 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 4 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 5 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%. 6 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, 7 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 $(742) million, $2,170 million, and $3,388 million in 2000, 1999, and 1998, respectively. The decrease of $2,912 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 $2.3 billion, $1.7 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 $3.1 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 $1.9 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, 8 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. 9 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 $(43) million, $(26) million, and $(348) million for the years ended December 31, 2000, 1999, and 1998, respectively. The increase in cash flows generated from operations in 1999 as compared to 1998 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; 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. 10 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 lease with a third-party trust. PG&E Gen will operate the plant under a lease arrangement. The estimated cost to construct these plants is approximately $1.4 billion. These trusts are consolidated in the accompanying financial statements. 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. 11 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 $2,754 Long-term debt Variable rate obligations $ 16 $ 94 $ 584 $ 189 $ 170 $ 553 Fixed rate obligations $ 1 $ 34 $ 7 $ 1 $ 251 $ 325 Average interest rate 6.8% 4.3% 6.1% 7.3% 7.5% 7.9%
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 12 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.) 13 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 ------- Eliminations & (in millions) Utility PG&E Gen NW Texas PG&E ET Other/(1)/ Total 2000: Operating revenues $ 9,637 $ 1,199 $ 239 $ 873 $ 16,054 $ (1,782) $ 26,220 Operating expenses 14,838 1,061 105 869 15,974 (1,820) 31,027 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 (742) Net cash used by investing activities (1,690) Net cash provided by financing activities 3,075 EBITDA/(2)/ $ (1,244) $ 227 $ 176 $ 108 $ 91 $ (55) $ (697) 1999: Operating revenues $ 9,228 $ 1,121 $ 224 $ 1,148 $ 10,521 $ (1,423) $ 20,819 Operating expenses 7,235 1,006 104 2,446 10,582 (1,432) 19,941 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 2,170
14 Net cash used by investing activities (234) Net cash used by financing activities (1,940) 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 activities 3,388 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 15 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. 16 . 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). 17 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 18 (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 19 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 $4,992 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. 20 The NEG's 1999 operating revenues increased $938 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 $3,483 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 $2,275 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. 21 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 "ringfence" 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 22 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 23 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 24 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 25 "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. 26 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. 27 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%. 28 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. 29 PG&E Corporation STATEMENTS OF CONSOLIDATED OPERATIONS (in millions, except per share amounts)
Year ended December 31, ----------------------- 2000 1999 1998 (As revised, see Note 17) Operating Revenues Utility $ 9,637 $ 9,228 $ 8,924 Energy commodities and services 16,583 11,591 10,653 -------- -------- ------- Total operating revenues 26,220 20,819 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 3,508 3,150 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 31,027 19,941 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. 30 PG&E Corporation CONSOLIDATED BALANCE SHEETS (in millions, except share amounts)
Balance at December 31, ------------ 2000 1999 (As revised, see Note 17) ASSETS Current Assets Cash and cash equivalents $ 925 $ 282 -------- ------- Short-term investments 1,634 187 Accounts receivable Customers (net of allowance for doubtful accounts of $71 million and $65 million, respectively) 2,129 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 11,199 3,575 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 1,605 553 Other 147 184 -------- ------- Total property, plant, and equipment (at original cost) 29,174 28,184 Accumulated depreciation and decommissioning (11,878) (11,291) -------- ------- Net property, plant, and equipment 17,296 16,893 Other Noncurrent Assets Regulatory assets 1,773 4,957 Nuclear decommissioning funds 1,328 1,264 Price risk management 2,026 329 Other 2,530 2,570 -------- ------- Total noncurrent assets 7,657 9,120 -------- ------- TOTAL ASSETS $ 36,152 $29,588 ======== =======
31 PG&E Corporation CONSOLIDATED BALANCE SHEETS (in millions, except share amounts)
Balance at December 31, ----------- 2000 1999 (As revised, see Note 17) 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 3,800 722 Energy marketing 2,096 480 Regulatory balancing accounts 196 384 Other 459 559 Accrued taxes -- 211 Price risk management 1,999 323 Other 1,570 1,059 ------- ------- Total current liabilities 17,331 6,085 Noncurrent Liabilities Long-term debt 5,550 6,785 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 14,869 15,837 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 $36,152 $29,588 ======= =======
The accompanying Notes to the Consolidated Financial Statements are an integral part of this statement. 32 PG&E Corporation STATEMENTS OF CONSOLIDATED CASH FLOWS (in millions)
For the year ended December 31, ------------------------------- 2000 1999 1998 (As revised, see Note 17) 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 (2,322) 370 (342) Inventories 41 23 (33) Income tax receivable (1,241) -- -- Price risk management assets and liabilities, net 30 (28) (16) Accounts payable 4,594 (279) 247 Regulatory balancing accounts (410) 305 537 Accrued taxes (211) 108 (123) Other working capital 324 209 199 Other--net (398) (822) (470) ------- ------- -------- Net cash (used) provided by operating activities (742) 2,170 3,388 ------- ------- -------- Cash Flows From Investing Activities Capital expenditures (2,346) (1,701) (1,619) Acquisitions -- -- (1,779) Proceeds from sale of assets 415 1,014 1,106 Other--net 241 453 66 ------- ------- -------- Net cash used by investing activities (1,690) (234) (2,226) ------- ------- -------- Cash Flows From Financing Activities Net borrowings (repayments) under credit facilities 2,846 (145) 2,115 Long-term debt issued 1,734 103 -- 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 3,075 (1,940) (1,113) ------- ------- -------- Net Change in Cash and Cash Equivalents 643 (4) 49 Cash and Cash Equivalents at January 1 282 286 237 ------- ------- -------- Cash and Cash Equivalents at December 31 $ 925 $ 282 $ 286 ======= ======= ======== Supplemental disclosures of cash flow information Cash paid for: Interest (net of amounts capitalized) $ 749 $ 729 $ 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. 33 PG&E Corporation STATEMENTS OF CONSOLIDATED COMMON STOCK EQUITY (in millions, except share amounts)
Common Reinvested Total Stock Earnings Accumulated Common Comprehensive 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. 34 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. 35 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 ======== ========
36 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. 37 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. 38 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. 39 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. 40 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 (As revised, see Note 17) Utility $50 $42 National Energy Group 79 82 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 ======= ======= ========
41 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 $48 million, $20 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. 42 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
43 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 not 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 44 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 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 45 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. 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. 46 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 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 47 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. 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 48 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 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. 49 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 (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. 50 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 51 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 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 on 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 51 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 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 53 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. 54 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 55 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. 56 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: Amount (in millions) Description (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* 57 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 58 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. 59 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 ---- ---- Notional Contract Notional Contract (in millions) 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
60 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 ---- ---- (As revised, see Note 17) PG&E Corporation Carrying Carrying (in millions) Amount Fair Value Amount Fair Value Long-term receivables $ 611 $ 526 $ 680 $ 680 Long-term debt 9,971 9,824 9,664 9,496 Interest rate swaps -- (73) -- (9)
61 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 Carrying (in millions) Amount Fair Value Amount Fair Value 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. 62 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 63 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 64 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 65 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 66 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 (As revised, see Note 17) 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, 2009-2022 921 219 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 2,225 2,001 Current portion of long-term debt 17 93 -------- -------- Total National Energy Group long-term debt, net of current portion $ 2,208 $ 1,908 -------- -------- Total long-term debt $ 5,550 $ 6,785 ======== ========
67 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. 68 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 occurred 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 69 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. During 2000 and 1999, two indirect wholly owned subsidiaries of the NEG entered into two commitments relating to the acquisition of turbine equipment and two commitments relating to generation projects that are under construction, for which they act as the construction agent for the owners. Upon completion of the construction projects, expected to be in 2001 and 2002, the NEG will lease these facilities under lease terms of five years and three years, respectively. At the conclusion of each of the 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. In addition, the NEG entered into operative agreements with a special purpose entity that will own and finance construction of another 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 PG&E Corporation's equity support commitments with substitute commitments of NEG. The trusts associated with these projects are included in the accompanying financial statements. As of December 31, 2000, and 1999, project costs subject to these agreements totaled $837 million and $117 million, respectively, financing for these projects totaled $814 million and $103 million as of December 31, 2001 and 2000, respectively. 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 (dollars in millions) 2001 2002 2003 2004 2005 Thereafter Total 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 $189 $ 170 $ 553 $1,606 Fixed rate obligations $ 1 $ 34 $ 7 $ 1 $ 251 $ 325 $ 619 Average interest rate 6.8% 4.3% 6.1% 7.3% 7.5% 7.9% 7.0%
70 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 ----------------- ----------------- Revolving Revolving Lines of Credit Credit Outstanding Credit Outstanding (in millions) 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:
71 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 72 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 73 Gross unrealized holding gains 447 474 (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) -- -- --
74 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. 75 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: 1-Percentage 1-Percentage (in millions) 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, 76 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. 77 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 ========= ======== ======= =========
78 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. 79 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 80 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 ====== 81 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 82 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 ====== 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. The approximate obligations under these operating lease agreements as of December 31, 2000 were as follows: (in millions) 83 2001 $ 72 2002 72 2003 69 2004 79 2005 79 Thereafter 965 ------ Total $1,336 ====== Operating lease expense amounted to $58 million, $67 million, and $35 million in 2000, 1999, and 1998, respectively. 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 84 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 85 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. 86 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 permits 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). 87 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: 88 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. 89 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 $ 1,189 $ 188 $ 817 $ 14,414 $ (11) $ 26,220 Intersegment revenues/(1)/ 14 10 51 56 1,640 (1,771) -- -------- -------- -------- -------- -------- -------- -------- Total operating revenues 9,637 1,199 239 873 16,054 (1,782) 26,220 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 1,083 15 -- 3 -- 2,346 Total assets at year-end/(5)(6)/ $ 21,988 $ 5,429 $ 1,204 $ -- $ 7,098 $ 433 $ 36,152 1999 Operating revenues $ 9,084 $ 1,115 $ 172 $ 1,034 $ 9,404 $ 10 $ 20,819 Intersegment revenues/(1)/ 144 6 52 114 1,117 (1,433) -- -------- -------- -------- -------- -------- -------- -------- Total operating revenues 9,228 1,121 224 1,148 10,521 (1,423) 20,819 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)/ 1,181 440 30 19 14 17 1,701 Total assets at year-end/(5)(6)/ $ 21,470 $ 3,970 $ 1,160 $ 1,217 $ 1,876 $ (105) $ 29,588 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. 90 (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. Note 17: Revision Footnote Subsequent to the issuance of PG&E Corporation's 2000 and 1999 consolidated financial statements, management determined that the assets and liabilities relating to certain leases should have been consolidated. The facilities associated with the leases were under construction during 2000 and 1999. A summary of the significant effects of the revisions to the Statements of Consolidated Operations, Consolidated Balance Sheets and Consolidated Statements of Cash Flows is as follows (in millions):
------------------------------------------------------------------------------------ Year ended December 31, 2000 1999 ------------------------------------------------------------------------------------ Statements of Consolidated As As Operations Previously As Previously As Reported Revised Reported Revised ------------------------------------------------------------------------------------ Operating revenues $26,232 $26,220 $20,820 $20,819 ------------------------------------------------------------------------------------ Operating expenses 31,039 31,027 19,942 19,941 ------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------ Consolidated Balance Sheets ------------------------------------------------------------------------------------ Cash and cash equivalents $ 899 $ 925 $ 281 $ 282 ------------------------------------------------------------------------------------ Trade accounts receivable (net of 2,131 2,129 1,486 1,486 $71M and $65M) ------------------------------------------------------------------------------------ Property, plant and equipment (net of accumulated depreciation) 16,591 17,296 16,776 16,893 ------------------------------------------------------------------------------------ Other non-current assets 2,398 2,530 2,570 2,570 ------------------------------------------------------------------------------------ Total assets 35,291 36,152 29,470 29,588 ------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------ Accounts payable- Trade Creditors 3,760 3,800 708 722 ------------------------------------------------------------------------------------ Other current liabilities 1,563 1,570 1,058 1,059 ------------------------------------------------------------------------------------ Total current liabilities 17,284 17,331 6,070 6,085 ------------------------------------------------------------------------------------ Long-term debt 4,736 5,550 6,682 6,785 ------------------------------------------------------------------------------------ Total non-current liabilities 14,055 14,869 15,734 15,837 ------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------ Statements of Consolidated Cash Flows ------------------------------------------------------------------------------------ Capital expenditures $(1,758) $(2,346) $(1,584) $(1,701) ------------------------------------------------------------------------------------ Long-term debt issued 1,023 1,734 - 103 ------------------------------------------------------------------------------------ Other-net, from investing activities 373 241 453 453 ------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------ Footnote 14 ------------------------------------------------------------------------------------ Operating lease commitments (total 5 years) 1,637 1,336 N/A N/A ------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------
91 QUARTERLY CONSOLIDATED FINANCIAL DATA (UNAUDITED)
Quarter ended (in millions, except per share amounts) December 31 September 30 June 30 March 31 2000 PG&E Corporation Operating revenues $ 8,079 $7,502 $5,637 $5,002 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 $ 4,794 $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 92 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. 93 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. As discussed in Note 17 of the Notes to the Consolidated Financial Statements, PG&E Corporation has revised its 1999 and 2000 financial statements to consolidate the assets and liabilities of certain leased facilities. DELOITTE & TOUCHE LLP San Francisco, California April 6, 2001, February 26, 2002 as to Note 17 94 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. 95