8-K 1 0001.txt FORM 8-K SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 8-K CURRENT REPORT Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 Date of Report: December 29, 2000 Exact Name of Commission Registrant State or other IRS Employer File as specified Jurisdiction of Identification Number in its charter Incorporation Number ---------- -------------- --------------- -------------- 1-12609 PG&E Corporation California 94-3234914 1-2348 Pacific Gas and California 94-0742640 Electric Company Pacific Gas and Electric Company PG&E Corporation 77 Beale Street, P.O. Box 770000 One Market, Spear Tower, Suite 2400 San Francisco, California 94177 San Francisco, California 94105 (Address of principal executive offices) (Zip Code) Pacific Gas and Electric Company PG&E Corporation (415) 973-7000 (415) 267-7000 (Registrant's telephone number, including area code) Item 5. Other Events. California Energy Crisis On December 27, 2000, emergency hearings began in the post transition period electric ratemaking proceedings of Pacific Gas and Electric Company (Utility) pending before the California Public Utilities Commission (CPUC). In connection with the hearings, the Utility submitted additional testimony in support of its rate stabilization plan filed with the CPUC on November 22, 2000. Current Financial Condition. In the testimony, the Utility stated that based on existing cash reserves, estimated receipts from customer bills and power market transactions, and normal payment schedules, it expects to utilize all of its cash reserves within the next three to seven weeks, and run out of cash by late January or early February 2001, assuming no electric rate increase or additional financing. The Utility also stated that it does not expect that it will be able to borrow funds absent clear CPUC actions to ensure recovery of the Utility's power procurement costs. The Utility's most recent estimate is that December 2000 prices will average more than $400 per megawatt hour (MWh). The Utility estimates that spot power market (i.e., real time energy) prices for 2001 will average over $180 MWh. The Utility noted that it expects this increase will cause the price the Utility pays qualifying generators (QFs) under long-term power purchase contracts to rise, as more QFs elect to receive PX prices instead of their short-term avoided cost payments otherwise due under the contracts. In the testimony, the Utility noted that although it has current cash reserves of $1.2 billion, it has payments due to the California Independent System Operator (ISO) on January 3 and February 1, 2001 for real-time energy purchases of $438 million and $583 million, respectively. In addition, the Utility estimates that its payment to the California Power Exchange (PX), due on February 15, 2001 for day- ahead energy purchases, will be $431 million. The Utility estimates that its payment to the ISO for energy purchases in December 2000, which is due on March 2, 2001, will be $1.7 billion. The Utility also noted that its monthly gas procurement disbursements are more than $200 million. (Although gas costs are recovered in full from customers, there is a lag of time between when the Utility pays for the gas and when the Utility receives revenues from customers for such gas costs.) The Utility noted that creditors have begun to demand advance payment in return for deliveries of natural gas and power, and that if such demands continue, the Utility expects to completely exhaust its cash reserves by the third week of January 2001. The Utility is evaluating what additional steps it would need to take to preserve its ability to continue serving its customers. The Utility must either raise substantial sums of new capital or default on its payment obligations. The Utility's cash deficit will total $4.8 billion through the end of the first quarter of 2001, assuming no electric rate increase, continued access to normal trade credit, and retention of its credit facilities. Excluding the $1.2 billion cash on hand, this would result in a financing requirement of $3.6 billion. If the Utility were unable to access its credit facilities because of an event of default, such as a significant ratings downgrade, the Utility would need to raise an additional approximate amount of $2 billion to pay maturing commercial paper and repay draws on its facilities. End of Rate Freeze. The Utility's testimony also notes that because the Utility's revenues from its generation facilities has been credited to its transition cost balancing account (TCBA) and generation memorandum accounts which track the recovery of the Utility's transition costs, the Utility will have recovered all of its transition costs by the end of December 2000, even assuming the value of the Utility's hydroelectric generation assets is equal to book value (approximately $700 million). To the extent the value of the hydroelectric assets is greater, the transition period would have ended sooner. Assuming a value of $4 billion (as supported by the Utility's updated testimony in the proceeding to value the hydroelectric assets), the transition period would have ended in April 2000. Therefore, the Utility does not believe that the CPUC needs to wait for a final market valuation of the Utility's hydroelectric assets before finding that the rate freeze has ended. Requested Rate Increase. The Utility submitted revised testimony on December 22, 2000, in its rate stabilization plan requesting an initial average rate increase of 26 percent, reflecting a rate component for current net power purchase costs for residential and small commercial customers capped at approximately 6.5 cents per kilowatt hour. This initial rate increase also reflects larger customers paying the Utility's actual cost of power, estimated in the rate stabilization plan based on recorded data through September 2000. Under the Utility's rate stabilization plan, this initial rate increase and subsequent rate increases are intended to recover the Utility's future power procurement costs and the under-collected power procurement costs. The initial rate increase is subject to an automatic increase of up to a maximum of 2 cents per Kwh per year as well as an additional annual upward adjustment, if actual power cost under-collections are higher than expected. The increased revenues from customers which would be collected under the rate stabilization plan would improve the Utility's ability to pay its ongoing net power purchase costs. However, based on current forward prices in the wholesale power market, the Utility would be required to obtain financing to pay the difference between the amount of revenues collected and the amount the Utility pays for power. Retained Generation Facilities. Finally, the Utility's testimony included the Utility's proposals with respect to its retained generation facilities to address the CPUC's question, raised in its December 22, 2000 order, whether power produced from retained generation assets should serve the utilities' customers and, if so, what ratemaking such actions would entail. The Utility proposed that for the next two years (after which the Utility expects the current supply shortage will be less critical), the Utility retain its generation facilities and sell the output of these facilities directly to its bundled customers on an incentive ratemaking basis to lower the costs of procured power for such customers. (Bundled customers are those that continue to choose the Utility as their generation provider, in contrast to direct access customers who have chosen an alternative generation provider.) For the hydroelectric facilities, the Utility has proposed to modify its rate stabilization plan proposal for these facilities to sell the output directly to retail customers for two years at a cost of service price, derived using the revenue sharing agreement (RSA)(submitted in connection with the application for approval of a settlement agreement involving the valuation and disposition of the hydroelectric assets which the Utility no longer supports) as a framework. The RSA would be modified to eliminate the revenue sharing concept for this two-year period but the method for determining cost of service and return would be retained. During this two-year period, the 10 percent shareholder share of foregone market revenues will be tracked in a regulatory balancing account by imputing revenues (in excess of costs) that would have been earned under a reasonably-based market price benchmark. These foregone revenues would be recaptured from market revenues or future sales to bundled customers. Following the two-year period, the 90/10 sharing would resume under the RSA. At that point, assuming the market is functioning properly, the Utility would sell its generation into the market and share with ratepayers 90 percent of net market revenues. During the initial two-year period, the Utility proposed that the settlement value of $2.8 billion be used as minimum valuation to calculate the hydroelectric cost of service under the RSA, provided that the rates for hydroelectric power are trued-up to reflect the final value of the assets (and to recover any additional depreciation and return). With respect to the Utility's Diablo Canyon Nuclear Power Plant (Diablo Canyon), the Utility proposed to continue to sell its power from Diablo Canyon directly to its retail customers at the 2001 Incremental Cost Incentive Price (ICIP), 3.49 per KWh, for the next two years. Similar to the proposal made in the Utility's rate stabilization plan, the Utility has proposed that during this two-year period, the 50 percent shareholder share of foregone market revenues will be tracked in a regulatory balancing account by imputing net revenues (in excess of costs) that would have been earned under a reasonably-based market price benchmark. These foregone revenues will be recaptured from market revenues or future sales to bundled customers. Following the two-year period of ICIP pricing, assuming the market is functioning properly, the Utility would sell into the market and share with ratepayers 50 percent of net market revenues. During the hearings, testimony was also given regarding PG&E Corporation's financial liquidity. PG&E Corporation currently has cash reserves of $307 million. If PG&E Corporation's and the Utility's credit ratings were to suffer a downgrade below investment grade, such a downgrade would constitute an event of default under PG&E Corporation's $ 436 million short-term and $500 million long-term revolving credit facilities and would constitute an event of default under the Utility's $850 million short-term revolving credit facility. Such a default would entitle the lenders to accelerate approximately $185 million of debt outstanding under PG&E Corporation's facilities. In addition, the downgrade of PG&E Corporation's long-term debt below investment grade by both Standard & Poor's and Moody's Investor Service, Inc., and the failure by PG&E Corporation to provide an acceptable letter of credit in the required amounts within the required time periods, would constitute an event of default under various capital infusion agreements. Upon an event of default under these agreements, PG&E Corporation would be obligated to pay an aggregate amount of at least $1 billion. The ratings downgrade would also adversely affect other PG&E Corporation and Utility outstanding debt securities, financing agreements and relationships. PG&E Corporation and the Utility believe that a ratings downgrade would preclude the ability of PG&E Corporation and the Utility to issue commercial paper and similar financial instruments. In addition, PG&E Corporation is the guarantor of obligations of its energy trading subsidiaries, PG&E Energy Trading-Power, L.P., PG&E Energy Trading-Gas Corporation, and PG&E Energy Trading-Canada Corporation, in the aggregate amount of up to $2.8 billion. Under many of the underlying trading agreements, the downgrade of PG&E Corporation's long-term debt below investment grade would entitle the counter-parties to demand substitute credit support from the energy trading subsidiaries. If the subsidiaries were unable to provide adequate substitute credit support, the counter-parties may declare a default, terminate the agreement, and make a claim under the parent guarantee. If claims were made under a substantial portion of the outstanding guarantees, PG&E Corporation may be unable to timely honor the guarantees. SIGNATURE Pursuant to the requirements of the Securities Exchange Act of 1934, the registrants have duly caused this report to be signed on their behalf by the undersigned thereunto duly authorized. PG&E CORPORATION By BRUCE R. WORTHINGTON --------------------- BRUCE R. WORTHINGTON Senior Vice President and General Counsel PACIFIC GAS AND ELECTRIC COMPANY By DINYAR B. MISTRY ------------------------------ DINYAR B. MISTRY Vice President and Controller Dated: December 29, 2000