-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, QQNOr/mGyJ+fh3oYKXIecf2QxW8JWU/godQdX3YNRIaAg2CEacuBwurtH8UbJxVd TwFDyX+VIbkaGb3JUIWvDQ== 0001004980-00-000013.txt : 20000516 0001004980-00-000013.hdr.sgml : 20000516 ACCESSION NUMBER: 0001004980-00-000013 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 9 CONFORMED PERIOD OF REPORT: 20000331 FILED AS OF DATE: 20000515 FILER: COMPANY DATA: COMPANY CONFORMED NAME: PACIFIC GAS & ELECTRIC CO CENTRAL INDEX KEY: 0000075488 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC & OTHER SERVICES COMBINED [4931] IRS NUMBER: 940742640 STATE OF INCORPORATION: CA FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: SEC FILE NUMBER: 001-02348 FILM NUMBER: 633549 BUSINESS ADDRESS: STREET 1: 77 BEALE ST STREET 2: P O BOX 770000 MAIL CODE B7C CITY: SAN FRANCISCO STATE: CA ZIP: 94177 BUSINESS PHONE: 4152677000 MAIL ADDRESS: STREET 1: 77 BEALE STREET STREET 2: P O BOX 770000 CITY: SAN FRANCISCO STATE: CA ZIP: 94177 10-Q 1 FORM 10-Q SECURITIES AND EXCHANGE COMMISSION Washington, D. C. 20549 ---------------------------------- (Mark One) [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended March 31, 2000 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from __________to ___________ 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 One Market, Spear Tower P.O. Box 770000 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 Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding twelve months (or for such shorter period that the registrant was required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. Yes X No _________ Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date. Common Stock Outstanding May 9, 2000: PG&E Corporation 385,326,805 shares Pacific Gas and Electric Company Wholly owned by PG&E Corporation PG&E CORPORATION FORM 10-Q FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2000 TABLE OF CONTENTS PAGE PART I. FINANCIAL INFORMATION ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS PG&E CORPORATION STATEMENT OF CONSOLIDATED INCOME........................1 CONSOLIDATED BALANCE SHEET..............................2 STATEMENT OF CONSOLIDATED CASH FLOWS ...................4 PACIFIC GAS AND ELECTRIC COMPANY STATEMENT OF CONSOLIDATED INCOME........................5 CONDSOLIDATED BALANCE SHEET.............................6 STATEMENT OF CONSOLIDATED CASH FLOWS....................8 NOTE 1: GENERAL...........................................9 NOTE 2: THE CALIFORNIA ELECTRIC INDUSTRY.................10 NOTE 3: RISK MANAGEMENT AND FINANCIAL INSTRUMENTS........17 NOTE 4: UTILITY OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES OF TRUST HOLDING SOLELY UTILITY SUBORDINATED DEBENTURES...........20 NOTE 5: DIVESTITURES.....................................20 NOTE 6: COMMITMENTS AND CONTINGENCIES....................22 NOTE 7: SEGMENT INFORMATION..............................25 ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS. ....................27 THE UTILITY...............................................29 PG&E NATIONAL ENERGY GROUP................................35 REGULATORY MATTERS........................................37 RESULTS OF OPERATIONS.....................................40 LIQUIDITY AND FINANCIAL RESOURCES.........................42 ENVIRONMENTAL MATTERS.....................................45 RISK MANAGEMENT ACTIVITIES................................45 LEGAL MATTERS.............................................46 ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.........................................47 PART II. OTHER INFORMATION ITEM 1. LEGAL PROCEEDINGS.........................................48 ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.......48 ITEM 5. OTHER INFORMATION.........................................52 ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K..........................52 SIGNATURE..........................................................54 PART I. FINANCIAL INFORMATION ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS ---------------------------------------------------- PG&E CORPORATION STATEMENT OF CONDENSED CONSOLIDATED INCOME (in millions, except per share amounts)
Three months ended March 31, 2000 1999 (1) --------- --------- Operating revenues Utility $ 2,218 $ 2,085 Energy commodities and services 2,790 3,041 -------- -------- Total operating revenues 5,008 5,126 Operating expenses Cost of energy for utility 796 655 Cost of energy commodities and services 2,472 2,797 Operating and maintenance, net 717 775 Depreciation, amortization and decommissioning 347 438 -------- -------- Total operating expenses 4,332 4,665 -------- -------- Operating income 676 461 Interest expense, net 183 201 Other income, net 15 21 -------- -------- Income before income taxes 508 281 Income taxes 228 114 -------- -------- Income from continuing operations 280 167 Discontinued operations Loss from operations of PG&E Energy Services (net of applicable income taxes of $7 million) - (8) -------- -------- Income before cumulative effect of change in accounting principle 280 159 Cumulative effect of change in accounting principle (net of applicable income taxes of $8 million) - 12 -------- -------- Net Income $ 280 $ 171 ======== ======== Weighted Average Common Shares Outstanding 361 373 Earnings per common share, basic Income from continuing operations $ .78 $ .45 Discontinued operations - (.02) Cumulative effect of accounting change - .03 -------- -------- Net income $ .78 $ .46 ======== ======== Earnings per common share, diluted Income from continuing operations $ .77 $ .39 Discontinued operations - (.02) Cumulative effect of accounting change - .03 -------- -------- Net income $ .77 $ .40 ======== ======== Dividends declared per common share $ .30 $ .30 The accompanying Notes to the Condensed Consolidated Financial Statements are an integral part of this statement. (1) Amounts have been restated to reflect the change in accounting for major maintenance and overhauls at the PG&E National Energy Group (see Note 1 of the Notes to the Condensed Consolidated Financial Statements), and reclassification of PG&E Energy Services operating results to discontinued operations. 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. The accounting change did not have a material effect on operating expenses during the first quarter of 1999. Operating income previously reported for the first quarter of 1999 was $442 million. Net income previously reported for the first quarter of 1999 was $156 million ($0.42 per share).
PG&E CORPORATION CONDENSED CONSOLIDATED BALANCE SHEET (in millions)
Balance at March 31, December 31, 2000 1999 ------------ ----------- ASSETS Current assets Cash and cash equivalents $ 260 $ 281 Short-term investments 45 187 Accounts receivable Customers, net 1,459 1,486 Energy marketing 547 532 Price risk management 434 607 Inventories and prepayments 543 598 Deferred income taxes 111 133 -------- ------- Total current assets 3,399 3,824 Property, plant, and equipment Utility 23,185 23,001 Non-utility Electric generation 1,906 1,905 Gas transmission 2,549 2,541 Construction work in progress 458 436 Other 119 184 -------- ------- Total property, plant, and equipment (at original cost) 28,217 28,067 Accumulated depreciation and decommissioning (11,573) (11,291) -------- -------- Net property, plant, and equipment 16,644 16,776 Other noncurrent assets Regulatory assets 4,940 4,957 Nuclear decommissioning funds 1,300 1,264 Other 2,913 2,894 -------- -------- Total noncurrent assets 9,153 9,115 -------- -------- TOTAL ASSETS $ 29,196 $ 29,715 ======== ======== The accompanying Notes to the Condensed Consolidated Financial Statements are an integral part of this statement.
PG&E CORPORATION CONDENSED CONSOLIDATED BALANCE SHEET (in millions)
Balance at March 31, December 31, 2000 1999 ------------ ------------ LIABILITIES AND EQUITY Current liabilities Short-term borrowings $ 952 $ 1,499 Current portion of long-term debt 672 592 Current portion of rate reduction bonds 290 290 Accounts payable Trade creditors 619 708 Other 367 559 Regulatory balancing accounts 638 384 Energy marketing 594 480 Accrued taxes 529 211 Price risk management 391 575 Other 997 1,033 -------- -------- Total current liabilities 6,049 6,331 Noncurrent liabilities Long-term debt 6,468 6,673 Rate reduction bonds 1,955 2,031 Deferred income taxes 3,011 3,147 Deferred tax credits 222 231 Other 3,624 3,636 -------- -------- Total noncurrent liabilities 15,280 15,718 Preferred stock of subsidiaries 480 480 Utility obligated mandatorily redeemable preferred securities of trust holding solely utility subordinated debentures 300 300 Common stockholders' equity Common stock, no par value, authorized 800,000,000 shares, issued, 384,867,522 and 384,406,113 shares, respectively 5,916 5,906 Common stock held by subsidiary, at cost, 23,815,500 shares (690) (690) Reinvested earnings 1,861 1,670 -------- -------- Total common stockholders' equity 7,087 6,886 Commitments and contingencies (Notes 2 and 6) - - -------- -------- TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 29,196 $ 29,715 ======== ======== The accompanying Notes to the Condensed Consolidated Financial Statements are an integral part of this statement.
PG&E CORPORATION STATEMENT OF CONDENSED CONSOLIDATED CASH FLOWS (in millions)
For the three months ended March 31, 2000 1999 ---------- ---------- Cash flows from operating activities Net income $ 280 $ 171 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, amortization and decommissioning 347 438 Deferred income taxes and tax credits-net (145) (178) Other deferred charges and noncurrent liabilities (9) (125) Cumulative effect of change in accounting principle - (12) Net effect of changes in operating assets and liabilities: Short-term investments 142 21 Accounts receivable - trade 12 333 Regulatory balancing accounts payable 254 212 Inventories and prepayments 55 97 Price risk management assets and liabilities, net (11) (20) Accounts payable - trade (89) (167) Accrued taxes 318 223 Other working capital (118) 101 Other-net 26 (69) --------- --------- Net cash provided by operating activities 1,062 1,025 --------- --------- Cash flows from investing activities Capital expenditures (321) (372) Other-net 81 17 --------- --------- Net cash used by investing activities (240) (355) --------- --------- Cash flows from financing activities Net borrowings (repayments) under credit facilities (547) 161 Long-term debt matured, redeemed, or repurchased (201) (283) Common stock issued 10 20 Common stock repurchased - (503) Dividends paid (108) (115) Other-net 3 9 --------- --------- Net cash used by financing activities (843) (711) --------- --------- Net change in cash and cash equivalents (21) (41) Cash and cash equivalents at January 1 281 286 --------- --------- Cash and cash equivalents at March 31 $ 260 $ 245 ========= ========= Supplemental disclosures of cash flow information Cash paid for: Interest (net of amounts capitalized) $ 117 $ 148 Income taxes(net of refunds) $ 3 $ (2) The accompanying Notes to the Condensed Consolidated Financial Statements are an integral part of this statement.
PACIFIC GAS AND ELECTRIC COMPANY STATEMENT OF CONDENSED CONSOLIDATED INCOME (in millions)
Three months ended March 31, 2000 1999 --------- --------- Electric utility $ 1,601 $ 1,533 Gas utility 617 552 -------- -------- Total operating revenues 2,218 2,085 Operating expenses Cost of electric energy 513 409 Cost of gas 283 246 Operating and maintenance, net 551 626 Depreciation, amortization, and decommissioning 301 382 -------- -------- Total operating expenses 1,648 1,663 -------- -------- Operating income 570 422 Interest expense, net 141 154 Other income, net 5 11 -------- -------- Income before income taxes 434 279 Income taxes 200 126 -------- -------- Net income 234 153 Preferred dividend requirement 6 6 -------- -------- Income available for common stock $ 228 $ 147 ======== ======== The accompanying Notes to the Condensed Consolidated Financial Statements are an integral part of this statement.
PACIFIC GAS AND ELECTRIC COMPANY CONDENSED CONSOLIDATED BALANCE SHEET (in millions)
Balance at March 31, December 31, 2000 1999 ------------ ----------- ASSETS Current assets Cash and cash equivalents $ 87 $ 80 Short-term investments 23 21 Accounts receivable, net 1,126 1,210 Inventories 249 294 Prepayments 32 34 Deferred income taxes 109 119 --------- --------- Total current assets 1,626 1,758 Property, plant, and equipment Electric 15,840 15,762 Gas 7,345 7,239 Construction work in progress 217 214 --------- --------- Total property, plant, and equipment (at original cost) 23,402 23,215 Accumulated depreciation and decommissioning (10,756) (10,497) --------- --------- Net property, plant, and equipment 12,646 12,718 Other noncurrent assets Regulatory assets 4,879 4,895 Nuclear decommissioning funds 1,300 1,264 Other 906 835 -------- -------- Total noncurrent assets 7,085 6,994 -------- -------- TOTAL ASSETS $ 21,357 $ 21,470 ======== ======== The accompanying Notes to the Condensed Consolidated Financial Statements are an integral part of this statement.
PACIFIC GAS AND ELECTRIC COMPANY CONDENSED CONSOLIDATED BALANCE SHEET (in millions)
Balance at March 31, December 31, 2000 1999 ------------ ----------- LIABILITIES AND EQUITY Current liabilities Short-term borrowings $ 209 $ 449 Current portion of long-term debt 549 465 Current portion of rate reduction bonds 290 290 Accounts payable Trade creditors 468 577 Related parties 23 216 Regulatory balancing accounts 638 384 Other 323 333 Accrued taxes 344 118 Other 516 529 -------- ------- Total current liabilities 3,360 3,361 Noncurrent liabilities Long-term debt 4,767 4,877 Rate reduction bonds 1,955 2,031 Deferred income taxes 2,471 2,510 Deferred tax credits 221 231 Other 2,269 2,252 ------- ------- Total noncurrent liabilities 11,683 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 142 149 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, 7,627,765 shares (200) (200) Additional paid in capital 1,971 1,964 Reinvested earnings 2,213 2,107 -------- -------- Total stockholders' equity 5,877 5,771 Commitments and contingencies (Notes 2 and 6) - - -------- -------- TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 21,357 $ 21,470 ======== ======== The accompanying Notes to the Condensed Consolidated Financial Statements are an integral part of this statement.
PACIFIC GAS AND ELECTRIC COMPANY STATEMENT OF CONDENSED CONSOLIDATED CASH FLOWS (in millions)
For the three months ended March 31, 2000 1999 ----------- ----------- Cash flows from operating activities Net income $ 234 $ 153 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, amortization, and decommissioning 301 382 Deferred income taxes and tax credits-net (48) (194) Other deferred charges and noncurrent liabilities (52) (4) Net effect of changes in operating assets and liabilities: Short-term investments (2) (1) Accounts receivable 84 263 Regulatory balancing accounts payable 254 212 Inventories and prepayments 47 54 Accounts payable - trade (302) (179) Accrued taxes 226 291 Other working capital (24) 117 Other-net (30) (2) --------- --------- Net cash provided by operating activities 688 1,092 --------- --------- Cash flows from investing activities Capital expenditures (265) (304) Other-net 54 18 --------- --------- Net cash used by investing activities (211) (286) --------- --------- Cash flows from financing activities Net borrowings (repayments) under credit facilities (240) 258 Long-term debt matured, redeemed, or repurchased (102) (233) Common stock repurchased - (725) Dividends paid (122) (106) Other-net (6) - --------- --------- Net cash used by financing activities (470) (806) --------- --------- Net change in cash and cash equivalents 7 - Cash and cash equivalents at January 1 80 73 --------- --------- Cash and cash equivalents at March 31 $ 87 $ 73 ========= ========= Supplemental disclosures of cash flow information Cash paid for: Interest (net of amounts capitalized) $ 75 $ 91 Income taxes (net of refunds) $ - $ (3) The accompanying Notes to the Condensed Consolidated Financial Statements are an integral part of this statement.
PG&E CORPORATION AND PACIFIC GAS AND ELECTRIC COMPANY NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS NOTE 1: GENERAL Basis of Presentation - --------------------- This Quarterly Report on Form 10-Q is a combined report of PG&E Corporation and Pacific Gas and Electric Company (the Utility), a regulated subsidiary of PG&E Corporation. The Notes to Condensed Consolidated Financial Statements apply to both PG&E Corporation and the Utility. PG&E Corporation's condensed consolidated financial statements include the accounts of PG&E Corporation and its wholly owned and controlled subsidiaries, including the Utility (collectively, the Corporation). The Utility's condensed consolidated financial statements include its accounts as well as those of its wholly owned and controlled subsidiaries. The Utility's financial position and results of operations are the principal factors affecting the Corporation's consolidated financial position and results of operations. This quarterly report should be read in conjunction with the Corporation's and the Utility's Consolidated Financial Statements and Notes to Consolidated Financial Statements incorporated by reference in their combined 1999 Annual Report on Form 10-K, and the Corporation's and the Utility's other reports filed with the Securities and Exchange Commission since their 1999 Form 10-K was filed. PG&E Corporation and the Utility believe that the accompanying condensed consolidated statements reflect all adjustments that are necessary to present a fair statement of the consolidated financial position and results of operations for the interim periods. All material adjustments are of a normal recurring nature unless otherwise disclosed in this Form 10-Q. All significant intercompany transactions have been eliminated from the condensed consolidated financial statements. Certain amounts in the prior year's condensed consolidated financial statements have been reclassified to conform to the 2000 presentation. Results of operations for interim periods are not necessarily indicative of results to be expected for a full year. Effective January 1, 1999, PG&E Corporation changed its method of accounting for major maintenance and overhauls at the PG&E National Energy Group. Beginning January 1, 1999, the cost of major maintenance and overhauls, principally at the PG&E Generating Company (PG&E Gen) business segment, have been accounted for as incurred. Previously, the estimated cost of major maintenance and overhauls was accrued in advance in a systematic and rational manner over the period between major maintenance and overhauls. The change resulted in PG&E Corporation recording income of $12 million net of income tax ($0.03 per share), reflecting the cumulative effect of the change in accounting principle. The effect on 1999 results of operations was immaterial. The Utility consistently has accounted for major maintenance and overhauls as incurred. 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. NOTE 2: THE CALIFORNIA ELECTRIC INDUSTRY In 1998, California became one of the first states in the country to implement electric industry restructuring and establish a competitive market framework for electric generation. Today, most Californians may continue to purchase their electricity from investor-owned utilities such as Pacific Gas and Electric Company, or they may choose to purchase electricity from alternative generation providers (such as unregulated power generators and unregulated retail electricity suppliers such as marketers, brokers, and aggregators). For those customers who have not chosen an alternative generation provider, investor-owned utilities, such as the Utility, continue to be the generation providers. Investor-owned utilities continue to provide distribution services to substantially all customers within their service territories, including customers who choose an alternative generation provider. Competitive Market Framework - ---------------------------- An Independent System Operator (ISO) and Power Exchange (PX) operate in California to facilitate competition. The PX provides a competitive auction process to establish market clearing prices for electricity in the markets operated by the PX. The ISO schedules delivery of electricity for all market participants. The Utility continues to own and maintain a portion of the transmission system, but the ISO controls the operation of the system. Unless or until the California Public Utilities Commission (CPUC) determines otherwise, the Utility is required to bid or schedule into the PX and ISO markets all of the electricity generated by its power plants and electricity acquired under contractual agreements with unregulated generators. Also, the Utility is required to buy from the PX all electricity needed to provide service to retail customers that continue to choose the Utility as their electricity supplier, unless the CPUC decides otherwise. In November 1999, the Federal Energy Regulatory Commission (FERC) approved the extension of the ISO's authority to establish price limitations through 2000. The ISO Board increased the applicable price limitation to $750 per megawatt-hour (MWh) on October 1, 1999, but has the option to decrease it to $500 per MWh or make other changes, in view of the FERC's decision. This limits the amount of volatility that occurs in the California electricity market. However, the ISO will review the appropriate level for any price limitations for the summer of 2000 in light of market redesign efforts now being considered, including changes to reduce uninstructed deviations from ISO dispatch orders and changes to permit loads, to participate by submitting bids for price responsive demand in energy or ancillary services markets. For the quarters ended March 31, 2000 and 1999, the cost of electric energy for the Utility, reflected on the Statement of Consolidated Income, is comprised of the cost of PX purchases, ancillary services purchased from the ISO, cost of transmission, and the cost of Utility generation, net of sales to the PX as follows: March 31, March 31, 2000 1999 ------------ ----------- (in millions) Cost of fuel for electric generation and qualifying facilities (QF) purchases $ 229 $ 371 Cost of purchases from the PX 196 152 Cost of ancillary services 203 110 Proceeds from sales to the PX (115) (224) ------------ ----------- $ 513 $ 409 ============ =========== Transition Period, Rate Freeze, and Rate Reduction - -------------------------------------------------- California's electric industry restructuring established a transition period during which electric rates remain frozen at 1996 levels (with the exception that, on January 1, 1998, rates for small commercial and residential customers were reduced by 10 percent and remain frozen at this reduced level) and investor-owned utilities may recover their transition costs. Transition costs are generation-related costs that prove to be uneconomic under the new competitive structure. The transition period ends the earlier of December 31, 2001, or when the particular utility has recovered its eligible transition costs. Revenues from frozen electric rates provide for the recovery of authorized Utility costs, including transmission and distribution service, public purpose programs, nuclear decommissioning, and rate reduction bond debt service. To the extent the revenues from frozen rates exceed authorized Utility costs, the remaining revenues constitute the competition transition charge (CTC), which recovers the transition costs. These CTC revenues are being recovered from all Utility distribution customers and are subject to seasonal fluctuations in the Utility's sales volumes and certain other factors. As the CTC is collected regardless of the customer's choice of electricity supplier (i.e., the CTC is non-bypassable), the Utility believes that the availability of choice to its customers will not have a material impact on its ability to recover transition costs. To pay for the 10 percent rate reduction, the Utility refinanced $2.9 billion (the expected revenue reduction from the rate decrease) of its transition costs with the proceeds from the rate reduction bonds. The bonds allow for the rate reduction by lowering the carrying cost on a portion of the transition costs and by deferring recovery of a portion of these transition costs until after the transition period. During the rate freeze, the rate reduction bond debt service will not increase the Utility customers' electric rates. If the transition period ends before December 31, 2001, the Utility may be obligated to return a portion of the economic benefits of the transaction to customers. The timing of any such return and the exact amount of such portion, if any, have not yet been determined. Transition Cost Recovery - ------------------------ Although most transition costs must be recovered during the transition period, certain transition costs can be recovered after the transition period. Except for certain transition costs discussed below, at the conclusion of the transition period, the Utility will be at risk to recover any of its remaining generation costs through market-based revenues. Transition costs consist of (1) above-market sunk costs (costs associated with utility generating facilities that are fixed and unavoidable and that were included in customers' rates on December 20, 1995) and future sunk costs, such as costs related to plant removal, (2) costs associated with long-term contracts to purchase power at above-market prices from qualifying facilities and other power suppliers, and (3) generation-related regulatory assets and obligations. (In general, regulatory assets are expenses deferred in the current or prior periods, to be included in rates in subsequent periods.) Above-market sunk costs result when the book value of a facility exceeds its market value. Conversely, below-market sunk costs result when the market value of a facility exceeds its book value. The total amount of generation facility costs to be included as transition costs is based on the aggregate of above-market and below-market values. The above-market portion of these costs is eligible for recovery as a transition cost. The below-market portion of these costs will reduce other unrecovered transition costs. These above- and below-market sunk costs are related to generating facilities that are classified as either non-nuclear or nuclear sunk costs. The Utility cannot determine the exact amount of above-market non-nuclear sunk costs that will be recoverable as transition costs until the valuation of the Utility's remaining non-nuclear generating assets, primarily its hydroelectric generating assets, is completed. The valuation, through appraisal, sale, or other divestiture, must be completed by December 31, 2001. The value of seven of the Utility's other non-nuclear generating facilities was determined when these facilities were sold to third parties. The portion of the sales proceeds that exceeded the book value of these facilities was used to reduce other transition costs. On September 30, 1999, the Utility filed an application with the CPUC to determine the market value of its hydroelectric generating facilities and related assets through an open, competitive auction. (See "Generation Divestiture" below.) The Utility proposes to use an auction process similar to the one previously approved by the CPUC and successfully used in the sale of the Utility's fossil and geothermal plants. If the market value of the Utility's hydroelectric facilities is determined based upon any method other than a sale of the facilities to a third party, a material charge to Utility earnings could result. Any excess of market value over book value would be used to reduce other transition costs. (See "Generation Divestiture" below.) For nuclear transition costs, revenues provided for transition cost recovery are based on the accelerated recovery of the investment in Diablo Canyon Nuclear Power Plant (Diablo Canyon) over a five-year period ending December 31, 2001. The amount of nuclear generation sunk costs was determined separately through a CPUC proceeding and was subject to a final verification audit that was completed in August 1998. The audit of the Utility's Diablo Canyon accounts at December 31, 1996, resulted in the issuance of an unqualified opinion. The audit verified that Diablo Canyon sunk costs at December 31, 1996, were $3.3 billion of the total $7.1 billion construction costs. The independent accounting firm also issued an agreed-upon special procedures report, requested by the CPUC, that questioned $200 million of the $3.3 billion sunk costs. The CPUC will review the results of the audit and may seek to make adjustments to Diablo Canyon's sunk costs subject to transition cost recovery. In May 2000, the Utility filed a petition at the CPUC to close out the audit report without any changes in rates. The petition is not opposed by the two consumer advocacy groups who originally requested the audit, the Commission's Office of Ratepayer Advocates (ORA) and The Utility Reform Network (TURN). At this time, the Utility cannot predict what actions, if any, the CPUC may take regarding the audit report. Costs associated with the Utility's long-term contracts to purchase electric power are included as transition costs. Regulation required the Utility to enter into such long-term agreements with non-utility generators. Prices fixed under these contracts are now typically above prices for power in wholesale markets. Over the remaining life of these contracts, the Utility estimates that it will purchase 299 million MWh of electric power. To the extent that the individual contract prices are above the market price, the Utility is collecting the difference between the contract price and the market price from customers, as a transition cost, over the term of the contract. The contracts expire at various dates through 2028. The total costs under long-term contracts are based on several variables, including the capacity factors of the related generating facilities and future market prices for electricity. For the three months ended March 31, 2000 and 1999, the average price paid under the Utility's long-term contracts for electricity was 5.3 cents and 5.5 cents per kilowatt-hour (kWh), respectively. The average cost of electricity purchased at market rates from the PX for the three months ended March 31, 2000 and 1999, was 3.6 cents and 2.3 cents per kWh, respectively. Generation-related regulatory assets and obligations (net generation- related regulatory assets) are included as transition costs. At March 31, 2000 and December 31, 1999, the Utility's generation-related net regulatory assets totaled $4.0 billion. Certain transition costs can be recovered through a non-bypassable charge to distribution customers after the transition period. These costs include (1) certain employee-related transition costs, (2) above-market payments under existing long-term contracts to purchase power, discussed above, (3) up to $95 million of transition costs to the extent that the recovery of such costs during the transition period was displaced by the recovery of electric industry restructuring implementation costs, and (4) transition costs financed by the rate reduction bonds. Transition costs financed by the issuance of rate reduction bonds will be recovered over the term of the bonds. In addition, the Utility's nuclear decommissioning costs are being recovered through a CPUC-authorized charge, which will extend until sufficient funds exist to decommission the nuclear facility. During the rate freeze, the charge for these costs will not increase Utility customers' electric rates. Excluding these exceptions, the Utility will write off any transition costs not recovered during the transition period. The Utility is amortizing its transition costs, including most generation- related regulatory assets, over the transition period in conjunction with the available CTC revenues. During the transition period, a reduced rate of return on common equity of 6.77 percent applies to all generation assets, including those generation assets reclassified to regulatory assets. Effective January 1, 1998, the Utility started collecting these eligible transition costs through the non-bypassable CTC and generation divestiture. Regulatory assets related to electric industry restructuring increased by $15 million for the quarter ended March 31, 2000, and decreased $247 million for the quarter ended March 31, 1999. 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 February 2000, the CPUC approved substantially all non-nuclear transition costs that were amortized during the first six months of 1998. The CPUC is currently reviewing non-nuclear transition costs amortized from July 1, 1998, to June 30, 1999. Generation Divestiture - ---------------------- In 1998, the Utility sold three fossil-fueled generation plants for $501 million. These three fossil-fueled plants had a combined book value at the time of the sale of $346 million and had a combined capacity of 2,645 megawatts (MW). On April 16, 1999, the Utility sold three other fossil-fueled generation plants for $801 million. At the time of sale, these three fossil-fueled plants had a combined book value of $256 million and had a combined capacity of 3,065 MW. On May 7, 1999, the Utility sold its complex of geothermal generation facilities for $213 million. At the time of sale, these facilities had a combined book value of $244 million and had a combined capacity of 1,224 MW. The gains from the sale of the fossil-fueled generation plants were used to offset other transition costs. Likewise, the loss from the sale of the complex of geothermal generation facilities is being recovered as a transition cost. The Utility has retained a liability for required environmental remediation related to any pre-closing soil or groundwater contamination at the plants it has sold. On September 30, 1999, the Utility filed an application with the CPUC to determine the market value of its hydroelectric generating facilities and related assets through an open, competitive auction. The Utility proposes to use an auction process similar to the one previously approved by the CPUC and successfully used in the sale of the Utility's fossil and geothermal plants. Under the process proposed in the application, the PG&E National Energy Group would be permitted to participate in the auction on the same basis as other bidders. The sale of the hydroelectric facilities would be subject to certain conditions, including the transfer or re-issuance of various permits and licenses by the FERC and other agencies. In addition, the FERC must approve assignment of the Utility's Reliability Must Run Contract with the ISO for any facility subject to such contract. Under the proposed purchase and sale agreement, the CPUC's approval of the proposed sale on terms acceptable to the Utility in the Utility's sole discretion is also a condition precedent to the closing of any sale. The CPUC has ordered that the proceeding be divided into two concurrent phases: one to review the potential environmental impacts of the proposed auction under the California Environmental Quality Act and a second to determine whether the Utility's auction proposal, or some other alternative to the proposal, is in the public interest. The ruling sets a procedural schedule that calls for a final decision on the Utility's auction proposal by October 19, 2000, and a final environmental impact report published in November 2000. The ruling also anticipates that a final CPUC decision approving the sale would be issued by May 15, 2001. Finally, the ruling prohibits the Utility from withdrawing its application without express CPUC authority. It is uncertain whether the CPUC will ultimately approve the Utility's auction proposal. On February 17, 2000, the CPUC issued a decision in another proceeding, the 1998 Annual Transition Cost Proceeding (ATCP), that requires California investor-owned utilities to estimate the market value of their remaining non- nuclear generating assets, including the land associated with those assets, at a value not less than the net book value of those assets on an aggregate basis and to credit the Transition Cost Balancing Account (TCBA) with the estimated value. The decision encourages the utilities to base such estimates on realistic assessments of the market value of the assets. The decision provides that if the estimated market valuation is less than book value for any individual asset, accelerated amortization of the associated transition costs will continue until final market valuation of the asset occurs through sale, appraisal, or other divestiture. If the final value of the assets, determined through sale, appraisal, or other divestiture, is higher than the estimate, the excess amount would be used to reduce remaining transition costs, if any. The utilities are required to file the adjusted entries to their respective TCBA based on the estimated market values with the CPUC by May 31, 2000. The filing will become effective after appropriate review by the CPUC's Energy Division and will be subject to review in the next ATCP. On May 2, 2000, a proposed decision was issued recommending the establishment of an accounting mechanism to permit a regulatory asset to be recorded equal to the amount credited to the TCBA. If an estimate of the market value of the non-nuclear generating assets is adopted that exceeds the aggregate net book value of those assets, and if an appropriate accounting mechanism is not adopted, a charge to earnings would result. At March 31, 2000, the book value of the Utility's net investment in hydroelectric generation assets was approximately $0.7 billion, excluding approximately $0.5 billion of net investment reclassified as regulatory assets. Any excess of market value over the $0.7 billion book value would be used to reduce transition costs, including the remaining $0.5 billion of regulatory assets related to the hydroelectric generation assets. If the market value of the hydroelectric generation assets is determined by any method other than a sale of the assets to a third party, or if the winning bidder for any of the auctioned assets is the PG&E National Energy Group, a material charge to Utility earnings could result. The timing and nature of any such charge is dependent upon the valuation method and procedure adopted, and the method of implementation. As discussed above, it is possible that the CPUC will require an interim valuation through an estimate of market value of the assets prior to transfer, sale or other divestiture, which could also result in a material charge. While transfer or sale to an affiliated entity such as the PG&E National Energy Group would result in a material charge to income, neither PG&E Corporation nor the Utility believes that the sale of any generation facilities to a third party will have a material impact on its results of operations. The Utility's ability to continue recovering its transition costs depends on several factors, including (1) the continued application of the regulatory framework established by the CPUC and state legislation, (2) the amount of transition costs ultimately approved for recovery by the CPUC, (3) the determined value of the Utility's hydroelectric generation facilities, (4) future Utility sales levels, (5) future Utility fuel and operating costs, and (6) the market price of electricity. Given the current evaluation of these factors, PG&E Corporation believes that the Utility will recover its transition costs. However, a change in one or more of these factors could affect the probability of recovery of transition costs and result in a material charge. Post-Transition Period - ---------------------- The timing of the end of the rate freeze and corresponding transition period will, in part, depend on the timing of the valuation of the Utility's hydroelectric generating assets and the ultimate determined value of such assets since any excess of market value over the assets' book value would be used to reduce transition costs. If the value of the Utility's hydroelectric generation assets is significantly higher than the related book value, the transition period and the rate freeze could end before December 31, 2001, and potentially could end during 2000. In October 1999, the CPUC issued a decision in the Utility's post- transition period ratemaking proceeding. Among other matters, the CPUC's decision addresses the mechanisms for ending the current electric rate freeze and for establishing post-transition period accounting mechanisms and rates. The decision prohibits the Utility from continuing to price electric generation from Diablo Canyon based on the incremental cost incentive price (ICIP) after the transition period has ended. The ICIP, which has been in place since January 1, 1997, is a performance-based mechanism that establishes a rate per kilowatt-hour (kWh) generated by the facility. The ICIP prices for 1999, 2000, and 2001 are 3.37 cents per kWh, 3.43 cents per kWh, and 3.49 cents per kWh, respectively. The average price for base load electric energy (the price received for a constant level of electric generation for all hours of electric demand) sold at market rates to the California PX for the three- month periods ended March 31, 2000 and 1999, was 3.6 cents and 2.3 cents per kWh, respectively. The average price for base load electric energy sold at market rates to the California PX for the 12 months ending March 31, 2000 was 4.0 cents per kWh. Future market prices may be higher or lower. Under the CPUC's decision, after the transition period, the Utility must price Diablo Canyon generation at the prevailing market price for power. The CPUC decision requires the Utility to provide quarterly forecasts of when the Utility's rate freeze (i.e., transition period) may end based on various assumptions regarding energy prices and the market value of the Utility's remaining generation assets. The Utility is required to notify the CPUC three months before the earliest forecasted end of its rate freeze and provide draft tariff language and sample calculations of the rates that would go into effect when the rate freeze ends. After the Utility completes its transition cost recovery, it must implement its post-rate-freeze rates. After the rate freeze and transition periods end, the Utility must refund to electric customers any over-collected transition costs (plus interest at the Utility's three-month commercial paper rate) within one year after the end of the rate freeze. The Utility also will be prohibited from collecting after the rate freeze certain electric costs incurred during the rate freeze but not recovered during the rate freeze, including costs that are not classified as transition costs and are not related to generation assets such as under- collected accounting balances relating to power purchases. Through the end of its rate freeze, the Utility will continue to incur certain non-transition costs and place those costs into balancing and memorandum accounts for future recovery. There is a risk that the Utility will be unable to collect certain non-transition costs that, due to lags in the regulatory cost approval process, have not been approved for recovery nor collected when the rate freeze ends. The Utility is unable to predict the amount of such potential unrecoverable costs. In November 1999, the Utility filed an application for rehearing of the CPUC's decision. In March 2000, the CPUC denied the Utility's application for rehearing on the issues of Diablo Canyon ICIP and post-transition period recovery of non-transition costs. On April 17, 2000, the Utility filed a petition for review in the California Court of Appeal on the issue of post- transition period recovery of non-transition costs. The CPUC also has established the Purchased Electric Commodity Account (PECA) for the Utility to track energy costs after the rate freeze and transition period end. The CPUC intends to explore other ratemaking issues, including whether dollar-for-dollar recovery of energy costs is appropriate, in the second phase of the post-transition period electric ratemaking proceeding. There are three primary options for the future regulatory framework for utility electric energy procurement cost recovery after the rate freeze: (1) a CPUC-defined procurement practice, that if followed by the Utility, would pass through costs without the need for reasonableness reviews, (2) a pass-through of costs subject to after-the-fact reasonableness reviews, or (3) a procurement incentive mechanism with rewards and penalties determined based on the Utility's energy purchasing performance compared to a benchmark. The Utility proposed adoption of either a defined procurement practice or a procurement incentive mechanism, neither of which would involve reasonableness reviews. On March 17, 2000, the CPUC issued a proposed decision that states that after the rate freeze, there will be two electric rate proceedings to address electric energy procurement practices and rates. The Revenue Adjustment Proceeding (RAP) will be a forecast of costs, and the ATCP will include a review of procurement costs to the extent costs above the wholesale PX rate are included in the PECA. The volatility of earnings and risk exposure of the Utility related to post-transition period purchases of electricity is dependent on which of these options, or some other approach, is adopted. Further, pursuant to the 1997 CPUC decision establishing the ICIP, the Utility is required to begin sharing 50 percent of the net benefits of operating Diablo Canyon with ratepayers at the end of the transition period. The Utility is required to file an application by July 2000 with its proposal for the methods to be used in the valuation of the benefits associated with the operation of Diablo Canyon, and the mechanism to be used to share these benefits with ratepayers. The Utility and PG&E Corporation are unable to predict what type of valuation and sharing mechanism will be adopted and what the ultimate financial impact of the sharing mechanism will have on results of operations or financial position. The ultimate financial impact of the post-transition period issues discussed above will depend on the date the Utility's transition cost recovery is completed and the rate freeze ends, future costs including Diablo Canyon operating costs, future market prices for electricity, the method adopted by the CPUC for sharing net benefits of operating Diablo Canyon with ratepayers, the amount of any electric non-transition costs that have been incurred but not recovered as of the end of the rate freeze, the timing of various regulatory proceedings in which the Utility seeks approval for rate recovery of various costs incurred during the rate freeze, and other variables that PG&E Corporation and the Utility are unable to predict. After the transition period, the Utility's future earnings from its electric distribution will be subject to volatility due to sales fluctuations. NOTE 3: RISK MANAGEMENT AND FINANCIAL INSTRUMENTS The following table is a summary of the contract or notional amounts and maturities of PG&E Corporation's contracts used for non-hedging activities related to commodity risk management as of March 31, 2000 and 1999. Short and long positions pertaining to derivative contracts used for hedging activities as of March 31, 2000 and 1999, are immaterial. Maximum Natural Gas, Electricity, Purchase Sale Term in and Natural Gas Liquids Contracts (Long) (Short) Years - --------------------------------------------------------------------------- (billions of MMBtu equivalents (1)) Non-Hedging Activities - March 31, 2000 Swaps 1.74 1.66 7 Options 0.80 0.83 8 Futures 0.10 0.11 2 Forward Contracts 2.22 13.00 11 Non-Hedging Activities - March 31, 1999 Swaps 3.83 3.65 8 Options 1.08 0.99 5 Futures 0.55 0.57 3 Forward Contracts 2.62 2.67 9 (1) One MMBtu is equal to one million British thermal units. PG&E Corporation's electric power contracts, measured in megawatts, were converted to MMBtu equivalents using a conversion factor of 10 MMBtu's per 1 megawatt- hour. PG&E Corporation's natural gas liquids contracts were converted to MMBtu equivalents using an appropriate conversion factor for each type of natural gas liquids product. Volumes shown for swaps represent notional volumes that are used to calculate amounts due under the agreements and do not represent volumes exchanged. Moreover, notional amounts are indicative only of the volume of activity and are not a measure of market risk. PG&E Corporation's net gains (losses) on swaps, options, futures, and forward contracts held during the quarters ended March 31, 2000 and 1999, are as follows: March 31, March 31, 2000 1999 --------- --------- (in millions) Swaps $ (23) $ 235 Options 62 15 Futures 37 (9) Forward contracts (31) (203) ------- ------- Net gain $ 45 $ 38 ======= ======= The following table discloses the estimated fair values of risk management assets and liabilities as of March 31, 2000 and December 31, 1999. The ending and average fair values and associated carrying amounts of derivative contracts used for hedging purposes are not material as of March 31, 2000 and December 31, 1999. Average Ending Fair Value Fair Value - --------------------------------------------------------------------------- (in millions) Non-hedging activities - March 31, 2000 Assets Swaps $ 146 $ 48 Options 90 87 Futures 27 7 Forward Contracts 590 614 ------ ------ Total $ 853 $ 756 Noncurrent portion $ 322 Current portion $ 434 Liabilities Swaps $ 130 $ 42 Options 61 40 Futures 39 12 Forward Contracts 502 547 ------ ------ Total $ 732 $ 641 Noncurrent portion $ 250 Current portion $ 391 Non-hedging activities - December 31, 1999 Assets Swaps $ 643 $ 244 Options 106 92 Futures 175 47 Forward Contracts 667 596 ------ ------ Total $1,591 $ 979 Noncurrent portion $ 372 Current portion $ 607 Liabilities Swaps $ 592 $ 218 Options 109 81 Futures 201 67 Forward Contracts 561 456 ------ ------ Total $1,463 $ 822 Noncurrent portion $ 247 Current portion $ 575 PG&E Corporation, primarily through its subsidiaries, engages in risk management activities for both non-hedging and hedging purposes. Non-hedging activities are conducted principally through its unregulated subsidiary, PG&E Energy Trading (PG&E ET). In compliance with regulatory requirements, the Utility manages risk independently from the activities in PG&E Corporation's unregulated businesses (see Note 1 for further discussion). The Utility primarily engages in hedging activities which were immaterial for the three month periods ended March 31, 2000 and 1999. In valuing its electric power, natural gas, and natural gas liquids portfolios, PG&E Corporation considers a number of market risks and estimated costs and continuously monitors the valuation of identified risks and adjusts them based on present market conditions. Considerable judgment is required to develop the estimates of fair value; thus, the estimates provided herein are not necessarily indicative of the amounts that PG&E Corporation could realize in the current market. Generally, exchange-traded futures contracts require deposit of margin cash, the amount of which is subject to change based on market movement and in accordance with exchange rules. Margin cash requirements for over-the-counter financial instruments are specified by the particular instrument and often do not require margin cash and are settled monthly. Both exchange-traded and over-the-counter options contracts require payment/receipt of an option premium at the inception of the contract. Margin cash for commodities futures and cash on deposit with counterparties was $22 million at March 31, 2000. The credit exposure of the five largest counterparties comprised approximately $326 million of the total credit exposure associated with financial instruments used to manage price risk. Counterparties considered to be investment grade or higher comprise 88 percent of the total credit exposure. NOTE 4: UTILITY OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES OF TRUST HOLDING SOLELY UTILITY SUBORDINATED DEBENTURES The Utility, through its wholly owned subsidiary, PG&E Capital I (Trust), has outstanding 12 million shares of 7.90 percent cumulative quarterly income preferred securities (QUIPS), with an aggregate liquidation value of $300 million. Concurrent with the issuance of the QUIPS, the Trust issued to the Utility 371,135 shares of common securities with an aggregate liquidation value of approximately $9 million. The only assets of the Trust are deferrable interest subordinated debentures issued by the Utility with a face value of approximately $309 million, an interest rate of 7.90 percent, and a maturity date of 2025. NOTE 5: DIVESTITURES In December 1999, PG&E Corporation's Board of Directors approved a plan to dispose of PG&E Energy Services (PG&E ES), its wholly owned subsidiary, through a sale. In December 1999, the intended disposal was accounted for as a discontinued operation. In connection with this transaction, PG&E Corporation's investment in PG&E ES was written down to its estimated net realizable value. In addition, PG&E Corporation provided a reserve for anticipated losses through the date of sale. The total provision for discontinued operations was $58 million, net of income taxes of $36 million. During the three-month period ended March 31, 2000, $14.7 million was charged against this reserve. On April 12, 2000, the PG&E National Energy Group signed an agreement to sell specified assets, liabilities, and contracts of PG&E Energy Services Corporation. The consideration to be received by the PG&E National Energy Group is $20 million, plus net working capital of approximately $65 million, for a total of $85 million. The transaction is expected to close by June 2000. The remaining components of PG&E Energy Services Corporation, mainly the Value Added Services business and various other assets, will continue to be offered for sale. The PG&E National Energy Group expects to complete this disposition prior to year-end 2000. The disposition of PG&E ES has been reflected in the financial statements as a discontinued operation. The PG&E ES business segment generated net losses of $8 million (or $0.02 per share), for the three month period ended March 31, 1999. The total assets and liabilities, including the charge noted above, of PG&E ES included in the PG&E Corporation Consolidated Balance Sheet at March 31, 2000 and December 31, 1999 are as follows: March 31, December 31, 2000 1999 ----------- ----------- (in millions) Assets Current assets $ 83 $ 114 Noncurrent assets 88 83 ----- ----- Total Assets 171 197 Liabilities Current liabilities 40 61 Noncurrent liabilities 9 10 ----- ----- Total Liabilities 49 71 ----- ----- Net Assets $ 122 $ 126 ===== ===== On January 27, 2000, the PG&E National Energy Group signed a definitive agreement with El Paso Field Services Company (El Paso) providing for the sale to El Paso, a subsidiary of El Paso Energy Corporation, of the stock of PG&E Gas Transmission, Texas Corporation and PG&E Gas Transmission Teco, Inc. (collectively, PG&E GT-Texas). The consideration to be received by the PG&E National Energy Group includes $279 million in cash subject to a working capital adjustment, the assumption by El Paso of debt having value of $624 million, and other liabilities associated with PG&E GT-Texas. In 1999, PG&E Corporation recognized a charge against earnings of $890 million after-tax as follows: (1) an $819 million write down of net property, plant, and equipment, (2) the elimination of the unamortized portion of goodwill, in the amount of $446 million, and (3) an accrual of $10 million representing selling costs. Proceeds from the sale will be used to retire short-term debt associated with PG&E GT-Texas' operations and for other corporate purposes. Closing of the sale, which is expected in the first half of 2000, is subject to approval under the Hart-Scott-Rodino Act. The sale of PG&E GT-Texas represents disposal of the PG&E GTT business segment and a portion of the PG&E ET business segment. PG&E GT-Texas' total assets and liabilities, including the charge noted above, included in the PG&E Corporation Consolidated Balance Sheet at March 31, 2000 and December 31, 1999, are as follows: March 31, December 31, 2000 1999 ----------- ----------- (in millions) Assets Current assets $ 209 $ 229 Noncurrent assets 974 988 ----- ----- Total Assets 1,183 1,217 Liabilities Current liabilities 458 448 Noncurrent liabilities 578 624 ----- ----- Total Liabilities 1,036 1,072 ----- ----- Net Assets $ 147 $ 145 ===== ===== NOTE 6: COMMITMENTS AND CONTINGENCIES Nuclear Insurance - ----------------- The Utility has insurance coverage for property damage and business interruption losses as a member of Nuclear Electric Insurance Limited (NEIL). Under this insurance, if a nuclear generating facility suffers a loss due to a prolonged accidental outage, the Utility may be subject to maximum retrospective assessments of $15 million (property damage) and $4 million (business interruption), in each case per policy period, in the event losses exceed the resources of NEIL. The Utility has purchased primary insurance of $200 million for public liability claims resulting from a nuclear incident. The Utility has secondary financial protection which provides an additional $9.3 billion in coverage, which is mandated by federal legislation. It provides for loss sharing among utilities owning nuclear generating facilities if a costly incident occurs. If a nuclear incident results in claims in excess of $200 million, then the Utility may be assessed up to $176 million per incident, with payments in each year limited to a maximum of $20 million per incident. Environmental Remediation - ------------------------- The Utility may be required to pay for environmental remediation at sites where it has been or may be a potentially responsible party under the Comprehensive Environmental Response, Compensation and Liability Act and similar state environmental laws. These sites include former manufactured gas plant sites, power plant sites, and sites used by the Utility 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 a liability when site assessments indicate remediation is probable and a range of reasonably likely clean-up costs can be estimated. The Utility reviews its remediation liability quarterly for each identified site. The liability is an estimate of costs for site investigations, remediation, operations and maintenance, monitoring, and site closure. The remediation costs also reflect (1) current technology, (2) enacted laws and regulations, (3) experience gained at similar sites, and (4) the probable level of involvement and financial condition of other potentially responsible parties. Unless there is a better estimate within this range of possible costs, the Utility records the lower end of this range. The cost of the hazardous substance remediation ultimately undertaken by the Utility is difficult to estimate. A change in estimate may occur in the near term due to uncertainty concerning the Utility's responsibility, the complexity of environmental laws and regulations, and the selection of compliance alternatives. At March 31, 2000, the Utility expects to spend $303 million for hazardous waste remediation costs at identified sites, including divested fossil-fueled power plants. The Utility had an accrued liability of $275 million and $271 million at March 31, 2000 and December 31, 1999, respectively, representing the discounted value of these costs. Of the $275 million accrued liability discussed above, the Utility has recovered $148 million through rates, including $34 million through depreciation, and expects to recover another $99 million in future rates. Additionally, the Utility is mitigating its costs by obtaining recovery of its costs from insurance carriers and from other third parties as appropriate. Environmental remediation at identified sites may be as much as $501 million if, among other things, other potentially responsible parties are not financially able to contribute to these costs or further investigation indicates that the extent of contamination or necessary remediation is greater than anticipated. The Utility estimated this upper limit of the range of costs using assumptions least favorable to the Utility, based upon a range of reasonably possible outcomes. Costs may be higher if the Utility is found to be responsible for clean-up costs at additional sites or outcomes change. Further, as discussed in "Generation Divestiture" in Note 2, the Utility will retain the pre-closing remediation liability associated with divested generation facilities. PG&E Corporation believes the ultimate outcome of these matters will not have a material impact on its or the Utility's financial position or results of operations. Legal Matters - ------------- Chromium Litigation: Several civil suits are pending against the Utility in California state court. The suits seek an unspecified amount of compensatory and punitive damages for alleged personal injuries resulting from alleged exposure to chromium in the vicinity of the Utility's gas compressor stations at Hinkley, Kettleman, and Topock, California. Currently, there are claims pending on behalf of approximately 900 individuals. The Utility is responding to the suits and asserting affirmative defenses. The Utility will pursue appropriate legal defenses, including statute of limitations or exclusivity of workers' compensation laws, and factual defenses, including lack of exposure to chromium and the inability of chromium to cause certain of the illnesses alleged. PG&E Corporation believes that the ultimate outcome of these matters will not have a material adverse impact on its or the Utility's financial position or results of operations. Texas Franchise Fee Litigation: In connection with PG&E Corporation's acquisition of Valero Energy Corporation, now known as PG&E Gas Transmission Texas Corporation (PG&E GTT), PG&E GTT succeeded to the litigation described below. PG&E GTT and various of its affiliates are defendants in at least two class action suits and five separate suits filed by various Texas cities. Generally, these cities allege, among other things, that (1) owners or operators of pipelines occupied city property and conducted pipeline operations without the cities' consent and without compensating the cities, and (2) the gas marketers failed to pay the cities for accessing and utilizing the pipelines located in the cities to flow gas under city streets. Plaintiffs also allege various other claims against the defendants for failure to secure the cities' consent. Damages are not quantified. In 1998, a jury trial was held in the separate suit brought by the City of Edinburg (the City). This suit involved, among other things, a particular franchise agreement entered into by a former subsidiary of PG&E GTT (now owned by Southern Union Gas Company (SU)) and the City and certain conduct of the defendants. On December 1, 1998, based on the jury verdict, the court entered a judgment in the City's favor, and awarded damages of $5.3 million, and attorneys' fees of up to $3.5 million plus interest. The court found that various PG&E GTT and SU defendants were jointly and severally liable for $3.3 million of the damages and all the attorneys' fees. Certain PG&E GTT subsidiaries were found solely liable for $1.4 million of the damages. The court did not clearly indicate the extent to which the PG&E GTT defendants could be found liable for the remaining damages. The PG&E GTT defendants are in the process of appealing the judgment. In connection with the certification of a class in one of the class actions, the court ordered notice to be sent to all potential class members and setting an opt-out deadline of December 31, 1997. Notices were mailed to approximately 159 Texas cities. Fewer than 20 cities opted out by the deadline. In November 1999, the court signed an order dismissing from the class 42 cities because it determined there was no pipeline presence and no past or present sales activity, leaving 106 cities in the class. A settlement proposal has been presented to the court. On January 27, 2000, the court approved the settlement proposal and established a 14-day period whether to accept the negotiated settlement terms or opt out of the settlement. The Court also stated that if Corpus Christi does not accept the settlement proposal, it will be placed in a sub-class, whose claims will not be finalized as part of the settlement approval. Corpus Christi has the right to opt out of this subclass. The settlement proposal contemplates, among other things, that the PG&E Corporation defendants would pay a total of not more than $12.2 million to the settling class cities, inclusive of attorney fees, reduced by amounts attributable to opt-out cities. The defendants retain the right to reject the settlement if the settlement proposal is not approved by certain key cities and by 80 percent of the plaintiff class. Although a significant number of the 106 cities in the plaintiff class already have either approved the settlement by enacting the ordinance, or adopted resolutions to pass the ordinance, certain key cities and other cities have not approved the settlement and have opted out of the settlement. Corpus Christi has opted out of the general settlement, but is continuing to negotiate a possible sub-class settlement with representatives of the class defendants. Representatives of the class defendants and class counsel are negotiating changes to the settlement. The settlement is also subject to final court approval. 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. In January 2000, PG&E Corporation's National Energy Group signed a definitive agreement to sell the stock of PG&E Gas Transmission, Texas Corporation and PG&E Gas Transmission Teco, Inc. The buyer will assume all liabilities associated with the cases described above. Recorded Liability for Legal Matters: In accordance with SFAS No. 5, PG&E Corporation makes a provision for a liability when both it is probable that a liability has been incurred and the amount of the loss can be reasonably estimated. These provisions are reviewed quarterly and adjusted to reflect the impacts of negotiations, settlements, rulings, advice of legal counsel, and other information and events pertaining to a particular case. The following table reflects the current year's activity to the recorded liability for legal matters: PG&E Corporation Utility ------------ ----------- (in millions) Beginning balance, January 1, 2000 $ 125 $ 69 Provisions for liabilities 1 1 Payments (4) (4) Adjustments - - ----- ----- Ending balance, March 31, 2000 $ 122 $ 66 ===== ===== NOTE 7: SEGMENT INFORMATION PG&E Corporation has identified four reportable operating segments. The Utility is one reportable operating segment and the other three are part of the PG&E National Energy Group. These four reportable operating segments provide different products and services and are subject to different forms of regulation or jurisdictions. PG&E Corporation's reportable segments are described below. Utility: PG&E Corporation's Northern and Central California energy utility subsidiary, Pacific Gas and Electric Company, provides natural gas and electric service to one of every 20 Americans. PG&E National Energy Group: The PG&E National Energy Group businesses develop, construct, operate, own, and manage independent power generation facilities that serve wholesale and industrial customers through PG&E Generating Company, LLC and its affiliates (collectively, PG&E Gen); own and operate natural gas pipelines, natural gas storage facilities, and natural gas processing plants, primarily in the Pacific Northwest and in Texas, through various subsidiaries of PG&E Corporation (collectively, PG&E Gas Transmission or PG&E GT); and purchase and sell energy commodities and provide risk management services to customers in major North American markets, including the other PG&E National Energy Group non-utility businesses, unaffiliated utilities, marketers, municipalities, and large end-use customers through PG&E Energy Trading - Gas Corporation, PG&E Energy Trading - Power, L.P., and their affiliates (collectively, PG&E Energy Trading or PG&E ET). In the fourth quarter of 1999, PG&E Corporation's Board of Directors approved a plan for the divestiture of PG&E Corporation's Texas natural gas and natural gas liquids business. Also in the fourth quarter of 1999, PG&E Corporation's Board of Directors approved a plan for the divestiture of PG&E Corporation's retail energy services, conducted through PG&E ES. Segment information for the three months ended March 31, 2000 and 1999, respectively, was as follows:
Utility PG&E National Energy Group ------- ------------------------------------------- PG&E GT Elimi- ---------------- nations & PG&EGen NW Texas PG&E ET Other (1) Total ------- ------- ------- ------- ------- ------- (in millions) March 31, 2000 Operating revenues $ 2,214 $ 310 $ 45 $ 212 $2,237 $ (10) $ 5,008 Intersegment revenues 4 2 12 13 320 (351) - ------- ------- ------- ------- ------- ------- ------- Total operating revenues 2,218 312 57 225 2,557 (361) 5,008 Income from continuing operations 228 35 14 - 11 (8) 280 Total assets at quarter end 21,357 3,865 1,149 1,183 1,886 (244) 29,196 March 31, 1999 Operating revenues $ 2,083 $ 288 $ 46 $ 313 $ 2,396 $ - $ 5,126 Intersegment revenues 2 1 12 44 235 (294) - ------- ------- ------- ------- ------- ------- ------- Total operating revenues 2,085 289 58 357 2,631 (294) 5,126 Income from continuing operations 147 32 15 (24) (3) - 167 Total assets at quarter end 22,455 3,831 1,165 2,643 4,014 - 34,108 (1) Net income on intercompany positions recognized by segments using mark-to-market accounting is eliminated. Intercompany transactions are also eliminated.
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS --------------------------------------------- PG&E Corporation is an energy-based holding company headquartered in San Francisco, California. PG&E Corporation's Northern and Central California energy utility subsidiary, Pacific Gas and Electric Company (the Utility), provides natural gas and electric service to one of every 20 Americans. The PG&E National Energy Group provides energy products and services throughout North America. The PG&E National Energy Group businesses develop, construct, operate, own, and manage independent power generation facilities that serve wholesale and industrial customers through PG&E Generating Company, LLC (and its affiliates (collectively, PG&E Gen); own and operate natural gas pipelines, natural gas storage facilities, and natural gas processing plants, primarily in the Pacific Northwest and in Texas, through various subsidiaries of PG&E Corporation (collectively, PG&E Gas Transmission or PG&E GT); purchase and sell energy commodities and provide risk management services to customers in major North American markets, including the other PG&E National Energy Group non-utility businesses, unaffiliated utilities, marketers, municipalities, and large end-use customers through PG&E Energy Trading-Gas Corporation, PG&E Energy Trading-Power, L.P., and their affiliates (collectively, PG&E Energy Trading or PG&E ET); and provide competitively priced electricity, natural gas, and related services to industrial, commercial, and institutional customers through PG&E Energy Services Corporation (PG&E Energy Services or PG&E ES). PG&E Corporation has entered into an agreement to sell its Texas natural gas and natural gas liquids business. PG&E Corporation also has entered into an agreement to sell the stock of PG&E ES, through which the buyer will acquire PG&E ES' retail electric and gas commodities business. This is a combined Quarterly Report on Form 10-Q of PG&E Corporation and Pacific Gas and Electric Company. It includes separate consolidated financial statements for each entity. The consolidated financial statements of PG&E Corporation reflect the accounts of PG&E Corporation, the Utility, and PG&E Corporation's wholly owned and controlled subsidiaries. The consolidated financial statements of the Utility reflect the accounts of the Utility and its wholly owned and controlled subsidiaries. This Management's Discussion and Analysis (MD&A) should be read in conjunction with the consolidated financial statements included herein. Further, this quarterly report should be read in conjunction with the Corporation's and the Utility's Consolidated Financial Statements and Notes to Consolidated Financial Statements incorporated by reference in their combined 1999 Annual Report on Form 10-K. This combined Quarterly Report on Form 10-Q, including 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. Factors that could cause future results to differ materially from those expressed in or implied by the forward-looking statements or historical results include: - regulatory changes, including the pace and extent of the ongoing restructuring of the electric and natural gas industries across the United States; - operational changes related to industry restructuring, including changes in the Utility's business processes and systems; - the method and timing of disposition and valuation of the Utility's hydroelectric generation assets; - the timing of the completion of the Utility's transition cost recovery and the consequent end of the current electric rate freeze in California; - any changes in the amount of transition costs the Utility is allowed to collect from its customers; - future operating performance at the Diablo Canyon Nuclear Power Plant (Diablo Canyon); - the method adopted by the California Public Utilities Commission (CPUC) for sharing the net benefits of operating Diablo Canyon with ratepayers and the timing of the implementation of the adopted method; - the extent of anticipated growth of transmission and distribution services in the Utility's service territory; - future market prices for electricity; - future fuel prices; - future weather conditions; - the success of management's strategies to maximize shareholder value in the PG&E National Energy Group, which may include acquisitions or dispositions of assets, or internal restructuring; - the extent to which our current or planned generation development projects are completed and the pace and cost of such completion; - generating capacity expansion and retirements by others; - the successful integration and performance of acquired assets; - the outcome of the Utility's various regulatory proceedings, including the proposal to auction the Utility's hydroelectric generation assets, the electric transmission rate case applications, and post-transition period ratemaking proceedings; - fluctuations in commodity gas, natural gas liquids, and electric prices and our ability to successfully manage such price fluctuations; - the pace and extent of competition in the California generation market and its impact on the Utility's costs and resulting collection of transition costs; - 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 our competitive and regulatory environment. We then discuss earnings and changes in our results of operations for the quarters ended March 31, 2000 and 1999. Finally, we discuss liquidity and financial resources, various uncertainties that could affect future earnings, and our risk management activities. Our MD&A applies to both PG&E Corporation and the Utility. THE UTILITY Transition Period, Rate Freeze, and Rate Reduction - -------------------------------------------------- California's electric industry restructuring established a transition period during which electric rates remain frozen at 1996 levels (with the exception that, on January 1, 1998, rates for small commercial and residential customers were reduced by 10 percent and remain frozen at this reduced level) and investor-owned utilities may recover their transition costs. Transition costs are generation-related costs that prove to be uneconomic under the new competitive structure. The transition period ends the earlier of December 31, 2001, or when the particular utility has recovered its eligible transition costs. Revenues from frozen electric rates provide for the recovery of authorized Utility costs, including transmission and distribution service, public purpose programs, nuclear decommissioning, and rate reduction bond debt service. To the extent the revenues from frozen rates exceed authorized Utility costs, the remaining revenues constitute the competitive transition charge (CTC), which recovers the transition costs. These CTC revenues are being recovered from all Utility distribution customers and are subject to seasonal fluctuations in the Utility's sales volumes and certain other factors. As the CTC is collected regardless of the customer's choice of electricity supplier (i.e., the CTC is non-bypassable), the Utility believes that the availability of choice to its customers will not have a material impact on its ability to recover transition costs. Transition Cost Recovery - ------------------------ Although most transition costs must be recovered during the transition period, certain transition costs can be recovered after the transition period. Except for certain transition costs discussed below, at the conclusion of the transition period, the Utility will be at risk to recover any of its remaining generation costs through market-based revenues. Transition costs consist of (1) above-market sunk costs (costs associated with utility generating facilities that are fixed and unavoidable and that were included in customers' rates on December 20, 1995) and future sunk costs, such as costs related to plant removal, (2) costs associated with long-term contracts to purchase power at above-market prices from qualifying facilities (QF) and other power suppliers, and (3) generation-related regulatory assets and obligations. (In general, regulatory assets are expenses deferred in the current or prior periods, to be included in rates in subsequent periods.) Above-market sunk costs result when the book value of a facility exceeds its market value. Conversely, below-market sunk costs result when the market value of a facility exceeds its book value. The total amount of generation facility costs to be included as transition costs is based on the aggregate of above-market and below-market values. The above-market portion of these costs is eligible for recovery as a transition cost. The below-market portion of these costs will reduce other unrecovered transition costs. These above- and below-market sunk costs are related to generating facilities that are classified as either non-nuclear or nuclear sunk costs. The Utility cannot determine the exact amount of above-market non-nuclear sunk costs that will be recoverable as transition costs until the valuation of the Utility's remaining non-nuclear generating assets, primarily its hydroelectric generating assets, is completed. The valuation, through appraisal, sale, or other divestiture, must be completed by December 31, 2001. The value of seven of the Utility's other non-nuclear generating facilities was determined when these facilities were sold to third parties. The portion of the sales proceeds that exceeded the book value of these facilities was used to reduce other transition costs. On September 30, 1999, the Utility filed an application with the CPUC to determine the market value of its hydroelectric generating facilities and related assets through an open, competitive auction. (See "Generation Divestiture" below.) The Utility proposes to use an auction process similar to the one previously approved by the CPUC and successfully used in the sale of the Utility's fossil and geothermal plants. If the market value of the Utility's hydroelectric facilities is determined based upon any method other than a sale of the facilities to a third party, a material charge to Utility earnings could result. Any excess of market value over book value would be used to reduce other transition costs. (See "Generation Divestiture" below.) For nuclear transition costs, revenues provided for transition cost recovery are based on the accelerated recovery of the investment in Diablo Canyon over a five-year period ending December 31, 2001. The amount of nuclear generation sunk costs was determined separately through a CPUC proceeding and was subject to a final verification audit that was completed in August 1998. The audit of the Utility's Diablo Canyon accounts at December 31, 1996, resulted in the issuance of an unqualified opinion. The audit verified that Diablo Canyon sunk costs at December 31, 1996, were $3.3 billion of the total $7.1 billion construction costs. The independent accounting firm also issued an agreed-upon special procedures report, requested by the CPUC, that questioned $200 million of the $3.3 billion sunk costs. The CPUC will review the results of the audit and may seek to make adjustments to Diablo Canyon's sunk costs subject to transition cost recovery. In May 2000, the Utility filed a petition at the CPUC to close out the audit report without any changes in rates. The petition is not opposed by the two consumer advocacy groups who originally requested the audit, the Commission's Office of Ratepayer Advocates (ORA) and The Utility Reform Network (TURN). At this time, the Utility cannot predict what actions, if any, the CPUC may take regarding the audit report. Costs associated with the Utility's long-term contracts to purchase electric power are included as transition costs. Regulation required the Utility to enter into such long-term agreements with non-utility generators. Prices fixed under these contracts are now typically above prices for power in wholesale markets. Over the remaining life of these contracts, the Utility estimates that it will purchase 299 million MWh of electric power. To the extent that the individual contract prices are above the market price, the Utility is collecting the difference between the contract price and the market price from customers, as a transition cost, over the term of the contract. The contracts expire at various dates through 2028. The total costs under long-term contracts are based on several variables, including the capacity factors of the related generating facilities and future market prices for electricity. For the three months ended March 31, 2000 and 1999, the average price paid under the Utility's long-term contracts for electricity was 5.3 cents and 5.5 cents per kilowatt-hour (kWh), respectively. The average cost of electricity purchased at market rates from the California Power Exchange (PX) for the three months ended March 31, 2000 and 1999, was 3.6 cents and 2.3 cents per kWh, respectively. Generation-related regulatory assets and obligations (net generation- related regulatory assets) are included as transition costs. At March 31, 2000 and December 31, 1999, the Utility's generation-related net regulatory assets totaled $4.0 billion. The Utility is amortizing its transition costs, including most generation- related regulatory assets, over the transition period in conjunction with the available CTC revenues. During the transition period, a reduced rate of return on common equity of 6.77 percent applies to all generation assets, including those generation assets reclassified to regulatory assets. Effective January 1, 1998, the Utility started collecting these eligible transition costs through the non-bypassable CTC and generation divestiture. Regulatory assets related to electric industry restructuring increased by $15 million for the quarter ended March 31, 2000, and decreased $247 million for the quarter ended March 31, 1999. Generation Divestiture - ---------------------- On April 16, 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 had a combined capacity of 3,065 MW. On May 7, 1999, the Utility sold its complex of geothermal generation facilities for $213 million. At the time of sale, these facilities had a combined book value of $244 million and had a combined capacity of 1,224 MW. The gains from the sale of the fossil-fueled generation plants were used to offset other transition costs. Likewise, the loss from the sale of the complex of geothermal generation facilities is being recovered as a transition cost. The Utility has retained a liability for required environmental remediation related to any pre-closing soil or groundwater contamination at the plants it has sold. On September 30, 1999, the Utility filed an application with the CPUC to determine the market value of its hydroelectric generating facilities and related assets through an open, competitive auction. The Utility proposes to use an auction process similar to the one previously approved by the CPUC and successfully used in the sale of the Utility's fossil and geothermal plants. Under the process proposed in the application, the PG&E National Energy Group would be permitted to participate in the auction on the same basis as other bidders. The sale of the hydroelectric facilities would be subject to certain conditions, including the transfer or re-issuance of various permits and licenses by the Federal Energy Regulatory Commission (FERC) and other agencies. In addition, the FERC must approve assignment of the Utility's Reliability Must Run Contract with the Independent System Operator (ISO) for any facility subject to such contract. Under the proposed purchase and sale agreement, the CPUC's approval of the proposed sale on terms acceptable to the Utility in the Utility's sole discretion is also a condition precedent to the closing of any sale. The CPUC has ordered that the proceeding be divided into two concurrent phases: one to review the potential environmental impacts of the proposed auction under the California Environmental Quality Act and a second to determine whether the Utility's auction proposal, or some other alternative to the proposal, is in the public interest. The ruling sets a procedural schedule that calls for a final decision on the Utility's auction proposal by October 19, 2000, and a final environmental impact report published in November 2000. The ruling also anticipates that a final CPUC decision approving the sale would be issued by May 15, 2001. Finally, the ruling prohibits the Utility from withdrawing its application without express CPUC authority. It is uncertain whether the CPUC will ultimately approve the Utility's auction proposal. On February 17, 2000, the CPUC issued a decision in another proceeding, the 1998 Annual Transition Cost Proceeding (ATCP), that requires California investor-owned utilities to estimate the market value of their remaining non- nuclear generating assets, including the land associated with those assets, at a value not less than the net book value of those assets on an aggregate basis and to credit the Transition Cost Balancing Account (TCBA) with the estimated value. The decision encourages the utilities to base such estimates on realistic assessments of the market value of the assets. The decision provides that if the estimated market valuation is less than book value for any individual asset, accelerated amortization of the associated transition costs will continue until final market valuation of the asset occurs through sale, appraisal, or other divestiture. If the final value of the assets, determined through sale, appraisal, or other divestiture, is higher than the estimate, the excess amount would be used to reduce remaining transition costs, if any. The utilities are required to file the adjusted entries to their respective TCBA based on the estimated market values with the CPUC by May 31, 2000. The filing will become effective after appropriate review by the CPUC's Energy Division and will be subject to review in the next ATCP. On May 2, 2000, a proposed decision was issued recommending the establishment of an accounting mechanism to permit a regulatory asset to be recorded equal to the amount credited to the TCBA. If an estimate of the market value of the non-nuclear generating assets is adopted that exceeds the aggregate net book value of those assets, and if an appropriate accounting mechanism is not adopted, a charge to earnings would result. At March 31, 2000, the book value of the Utility's net investment in hydroelectric generation assets was approximately $0.7 billion, excluding approximately $0.5 billion of net investment reclassified as regulatory assets. Any excess of market value over the $0.7 billion book value would be used to reduce transition costs, including the remaining $0.5 billion of regulatory assets related to the hydroelectric generation assets. If the market value of the hydroelectric generation assets is determined by any method other than a sale of the assets to a third party, or if the winning bidder for any of the auctioned assets is the PG&E National Energy Group, a material charge to Utility earnings could result. The timing and nature of any such charge is dependent upon the valuation method and procedure adopted, and the method of implementation. As discussed above, it is possible that the CPUC will require an interim valuation through an estimate of market value of the assets prior to transfer, sale, or other divestiture, which could also result in a material charge. While transfer or sale to an affiliated entity such as the PG&E National Energy Group would result in a material charge to income, neither PG&E Corporation nor the Utility believes that the sale of any generation facilities to a third party will have a material impact on its results of operations. The Utility's ability to continue recovering its transition costs depends on several factors, including (1) the continued application of the regulatory framework established by the CPUC and state legislation, (2) the amount of transition costs ultimately approved for recovery by the CPUC, (3) the determined value of the Utility's hydroelectric generation facilities, (4) future Utility sales levels, (5) future Utility fuel and operating costs, and (6) the market price of electricity. Given the current evaluation of these factors, PG&E Corporation believes that the Utility will recover its transition costs. However, a change in one or more of these factors could affect the probability of recovery of transition costs and result in a material charge. Post-Transition Period - ---------------------- The timing of the end of the rate freeze and corresponding transition period will, in part, depend on the timing of the valuation of the Utility's hydroelectric generating assets and the ultimate determined value of such assets since any excess of market value over the assets' book value would be used to reduce transition costs. If the value of the Utility's hydroelectric generation assets is significantly higher than the related book value, the transition period and the rate freeze could end before December 31, 2001, and potentially could end during 2000. In October 1999, the CPUC issued a decision in the Utility's post- transition period ratemaking proceeding. Among other matters, the CPUC's decision addresses the mechanisms for ending the current electric rate freeze and for establishing post-transition period accounting mechanisms and rates. The decision prohibits the Utility from continuing to price electric generation from Diablo Canyon based on the incremental cost incentive price (ICIP) after the transition period has ended. The ICIP, which has been in place since January 1, 1997, is a performance-based mechanism that establishes a rate per kWh generated by the facility. The ICIP prices for 1999, 2000, and 2001 are 3.37 cents per kWh, 3.43 cents per kWh, and 3.49 cents per kWh, respectively. The average price for base load electric energy (the price received for a constant level of electric generation for all hours of electric demand) sold at market rates to the California PX for the three-month periods ended March 31, 2000 and 1999, was 3.6 cents and 2.3 cents per kWh, respectively. The average price for base load electric energy sold at market rates to the California PX for the 12 months ending March 31, 2000 was 4.0 cents per kWh. Future market prices may be higher or lower. Under the CPUC's decision, after the transition period, the Utility must price Diablo Canyon generation at the prevailing market price for power. The CPUC decision requires the Utility to provide quarterly forecasts of when the Utility's rate freeze (i.e., transition period) may end based on various assumptions regarding energy prices and the market value of the Utility's remaining generation assets. The Utility is required to notify the CPUC three months before the earliest forecasted end of its rate freeze and provide draft tariff language and sample calculations of the rates that would go into effect when the rate freeze ends. After the Utility completes its transition cost recovery, it must implement its post-rate-freeze rates. After the rate freeze and transition periods end, the Utility must refund to electric customers any over-collected transition costs (plus interest at the Utility's three-month commercial paper rate) within one year after the end of the rate freeze. The Utility also will be prohibited from collecting after the rate freeze certain electric costs incurred during the rate freeze but not recovered during the rate freeze, including costs that are not classified as transition costs and are not related to generation assets such as under- collected accounting balances relating to power purchases. Through the end of its rate freeze, the Utility will continue to incur certain non-transition costs and place those costs into balancing and memorandum accounts for future recovery. There is a risk that the Utility will be unable to collect certain non-transition costs that, due to lags in the regulatory cost approval process, have not been approved for recovery nor collected when the rate freeze ends. The Utility is unable to predict the amount of such potential unrecoverable costs. In November 1999, the Utility filed an application for rehearing of the CPUC's decision. In March 2000, the CPUC denied the Utility's application for rehearing on the issues of Diablo Canyon ICIP and post-transition period recovery of non-transition costs. On April 17, 2000, the Utility filed a petition for review in the California Court of Appeal on the issue of post- transition period recovery of non-transition costs. The CPUC also has established the Purchased Electric Commodity Account (PECA) for the Utility to track energy costs after the rate freeze and transition period end. The CPUC intends to explore other ratemaking issues, including whether dollar-for-dollar recovery of energy costs is appropriate, in the second phase of the post-transition period electric ratemaking proceeding. There are three primary options for the future regulatory framework for utility electric energy procurement cost recovery after the rate freeze: (1) a CPUC-defined procurement practice, that if followed by the Utility, would pass through costs without the need for reasonableness reviews, (2) a pass-through of costs subject to after-the-fact reasonableness reviews, or (3) a procurement incentive mechanism with rewards and penalties determined based on the Utility's energy purchasing performance compared to a benchmark. The Utility proposed adoption of either a defined procurement practice or a procurement incentive mechanism, neither of which would involve reasonableness reviews. On March 17, 2000, the CPUC issued a proposed decision that states that after the rate freeze, there will be two electric rate proceedings to address electric energy procurement practices and rates. The Revenue Adjustment Proceeding (RAP) will be a forecast of costs, and the ATCP will include a review of procurement costs to the extent costs above the wholesale PX rate are included in the PECA. The volatility of earnings and risk exposure of the Utility related to post-transition period purchases of electricity is dependent on which of these options, or some other approach, is adopted. Further, pursuant to the 1997 CPUC decision establishing the ICIP, the Utility is required to begin sharing 50 percent of the net benefits of operating Diablo Canyon with ratepayers at the end of the transition period. The Utility is required to file an application by July 2000 with its proposal for the methods to be used in the valuation of the benefits associated with the operation of Diablo Canyon, and the mechanism to be used to share these benefits with ratepayers. The Utility and PG&E Corporation are unable to predict what type of valuation and sharing mechanism will be adopted and what the ultimate financial impact of the sharing mechanism will have on results of operation or financial position. The ultimate financial impact of the provisions of the post-transition period issues discussed above will depend on the date the Utility's transition cost recovery is completed and the rate freeze ends, future costs including Diablo Canyon operating costs, future market prices for electricity, the method adopted by the CPUC for sharing net benefits of operating Diablo Canyon with ratepayers, the amount of any electric non-transition costs that have been incurred but not recovered as of the end of the rate freeze, the timing of various regulatory proceedings in which the Utility seeks approval for rate recovery of various costs incurred during the rate freeze, and other variables that PG&E Corporation and the Utility are unable to predict. After the transition period, the Utility's future earnings from its electric distribution will be subject to volatility due to sales fluctuations. Distributed Generation and Electric Distribution Competition - ------------------------------------------------------------ In October 1999, the CPUC issued a decision outlining how the CPUC, in cooperation with other regulatory agencies and the California Legislature, plans to address the issues surrounding distributed generation, electric distribution competition, and the role of the utility distribution companies (such as Pacific Gas and Electric Company) in the competitive retail electric market. Distributed generation enables siting of electric generation technologies in close proximity to the electric demand (referred to as "load"). The CPUC decision opened a new rulemaking proceeding to examine various issues concerning distributed generation, including interconnection issues, who can own and operate distributed generation, environmental impacts, the role of utility distribution companies, and the rate design and cost allocation issues associated with the deployment of distributed generation facilities. With respect to electric distribution competition, the CPUC directed its staff to deliver a report by June 2, 2000, on the different policy options that the CPUC, in cooperation with the California Legislature, can pursue. Following the issuance of the report, the CPUC expects to open one or more new proceedings to address electric distribution competition and competition in the retail electric market. PG&E NATIONAL ENERGY GROUP The PG&E National Energy Group has been formed to pursue opportunities created by the gradual restructuring of the energy industry across the nation. The PG&E National Energy Group integrates our national power generation, gas transmission, and energy trading and services businesses. The PG&E National Energy Group contemplates increasing PG&E Corporation's national market presence through a balanced program of acquisition and development of energy assets and businesses, while at the same time undertaking ongoing portfolio management of its assets and businesses. The PG&E National Energy Group's ability to anticipate and capture profitable business opportunities created by restructuring will have a significant impact on PG&E Corporation's future operating results. Independent Power Generation - ---------------------------- Through PG&E Gen and its affiliates, we participate in the development, construction, operation, ownership, and management of non-utility electric generating facilities that compete in the United States power generation market. In September 1998, PG&E Corporation, through its indirect subsidiary USGen New England, Inc. (USGenNE), completed the acquisition of a portfolio of electric generation assets and power supply contracts from the New England Electric System (NEES). The purchased assets include hydroelectric, coal, oil, and natural gas generation facilities with a combined generating capacity of about 4,000 MW. As part of the New England electric industry restructuring, the local utility companies were required to offer Standard Offer Service (SOS) to their retail customers. Retail customers may select alternative suppliers at any time. The SOS is intended to provide customers with a price benefit (the commodity electric price offered to the retail customer is expected to be less than the market price) for the first several years, followed by a price disincentive that is intended to stimulate the retail market. Retail customers may continue to receive SOS through June 30, 2002, in New Hampshire (subject to early termination on December 31, 2000, at the discretion of the New Hampshire Public Service Commission), through December 31, 2004, in Massachusetts, and through December 31, 2009, in Rhode Island. However, if customers choose an alternate supplier, they are precluded from going back to the SOS. In connection with the purchase of the generation assets, USGenNE entered into wholesale agreements with certain of the retail companies of NEES to supply at specified prices the electric capacity and energy requirements necessary for their retail companies to meet their SOS obligations. These companies are responsible for passing on to us the revenues generated from the SOS. USGenNE currently is indirectly serving a large portion of the SOS electric capacity and energy requirements for these companies, except in New Hampshire. For the three months ended March 31, 2000, the SOS price paid to generators was $0.038 per kWh for generation. On March 1, 1999, Constellation Power Source, Inc. (Constellation) won the New Hampshire component of the SOS through a competitive bidding solicitation. On January 7, 2000, USGenNE paid approximately $15 million to a third party for this third party's assumption of 10 percent of the Massachusetts Electric Company/Nantucket Electric Company SOS and 40 percent of the Narragansett SOS. Like other utilities, New England utilities previously entered into agreements with unregulated companies (e.g., qualifying facilities under the Public Utility Regulatory Policies Act of 1978 (PURPA)) to provide energy and capacity at prices that are anticipated to be in excess of market prices. We assumed NEES' contractual rights and duties under several of these power purchase agreements. At March 31, 2000, these agreements provided for an aggregate 655 MW of capacity. However, NEES will make support payments to us toward the cost of these agreements. The support payments by NEES total $0.9 billion in the aggregate (undiscounted) and are due in monthly installments from September 1998 through January 2008. In certain circumstances, with our consent, NEES may make a full or partial lump-sum accelerated payment. Initially, approximately 90 percent of the acquired operating capacity, including capacity and energy generated by other companies and provided to us under power purchase agreements, is dedicated to servicing SOS customers. To the extent that customers eligible to receive SOS choose alternate suppliers, or as these obligations are sold to other parties, this percentage will decrease. As customers choose alternate suppliers, or the SOS obligations are sold, a greater proportion of the output of the acquired operating capacity will be subject to market prices. Gas Transmission Operations - --------------------------- PG&E Corporation participates in the "midstream" portion of the gas business through PG&E GT NW. PG&E GT NW owns and operates gas transmission pipelines and associated facilities which extend over 612 miles from the Canada-U.S. border to the Oregon-California border. PG&E GT NW provides firm and interruptible transportation services to third party shippers on an open- access basis. Its customers are principally retail gas distribution utilities, electric utilities that use natural gas to generate electricity, natural gas marketing companies, natural gas producers, and industrial consumers. On January 27, 2000, the PG&E National Energy Group signed a definitive agreement with El Paso Field Services Company (El Paso) providing for the sale to El Paso, a subsidiary of El Paso Energy Corporation, of the stock of PG&E Gas Transmission, Texas Corporation and PG&E Gas Transmission Teco, Inc. (collectively, PG&E GT-Texas). The consideration to be received by the PG&E National Energy Group includes $279 million in cash subject to a working capital adjustment, the assumption by El Paso of debt having a book value of $624 million, and other liabilities associated with PG&E GT-Texas. In 1999, PG&E Corporation recognized a charge against earnings of $890 million after tax, or $2.42 per share, to reflect PG&E GT-Texas' assets at their fair market value. The composition of the pre-tax charge is as follows: (1) an $819 million write-down of net property, plant, and equipment, (2) the elimination of the unamortized portion of goodwill, in the amount of $446 million, and (3) an accrual of $10 million representing selling costs. Proceeds from the sale will be used to retire short-term debt associated with PG&E GT-Texas' operations and for other corporate purposes. Closing of the sale, which is expected in the first half of 2000, is subject to approval under the Hart-Scott-Rodino Act. Energy Trading - -------------- Through PG&E ET, we purchase bulk volumes of power and natural gas from PG&E Corporation affiliates and the wholesale market. We then schedule, transport, and resell these commodities, either directly to third parties or to other PG&E Corporation affiliates. PG&E ET also provides risk management services to PG&E Corporation's other businesses (except the Utility) and to wholesale customers. (See "Price Risk Management Activities" below; and Note 3 of the Notes to Condensed Consolidated Financial Statements.) Energy Services - --------------- In December 1999, PG&E Corporation's Board of Directors approved a plan to dispose of PG&E ES, its wholly owned subsidiary, through a sale. The intended disposal has been accounted for as a discontinued operation. In connection with this transaction, PG&E Corporation's investment in PG&E ES was written down to its estimated net realizable value in 1999. In addition, in 1999, PG&E Corporation provided a reserve for anticipated losses through the date of sale. The total provision for discontinued operations was $58 million, net of income taxes of $36 million. During the three month period ended March 31, 2000 $14.7 million was charged against this reserve. On April 12, 2000, the PG&E National Energy Group signed an agreement to sell specified assets, liabilities, and contracts of PG&E Energy Services Corporation. The consideration to be received by the PG&E National Energy Group is $20 million, plus net working capital of approximately $65 million, for a total of $85 million. The transaction is expected to close by June 2000. The remaining components of PG&E Energy Services Corporation, mainly the Value Added Services business and various other assets, will continue to be offered for sale. The PG&E National Energy Group expects to complete this disposition prior to year-end 2000. The disposition of PG&E ES has been reflected in the financial statements as a discontinued operation. The PG&E ES business segment generated net losses of $8 million (or $0.02 per share) for the three-month period ended March 31, 1999. REGULATORY MATTERS A significant portion of PG&E Corporation's operations are regulated by federal and state regulatory commissions. These commissions oversee service levels and, in certain cases, PG&E Corporation's revenues and pricing for its regulated services. The Utility is the only subsidiary with significant regulatory proceedings at this time. Any change in authorized electric revenues resulting from any of the electric proceedings discussed below would not impact the Utility's customer electric rates because these rates are frozen throughout the transition period. However, any change would affect the amount of revenues available for the recovery of transition costs. Any change in authorized gas revenues resulting from gas proceedings would result in a change in the Utility's customer gas rates. The 1999 General Rate Case (GRC) - -------------------------------- The CPUC's final decision issued in February 2000 in the Utility's 1999 GRC application increased annual electric distribution revenues by $163 million and annual gas distribution revenues by $93 million, as compared to revenues authorized for 1998. Although the increase in electric and gas distribution revenues was retroactive to January 1, 1999, prior quarters were not restated. Instead, the entire increase was reflected in the fourth quarter of 1999. Had the Utility restated prior quarters, 1999 first quarter net earnings would have been $40 million higher than reported. The Utility's GRC application also contained a proposal for an Attrition Rate Adjustment (ARA) to adjust revenues in 2000 and 2001. The ARA would increase authorized revenues to offset cost increases during these periods. The final decision denies the Utility's request for an ARA to adjust revenues in 2000, but adopts an ARA for 2001. The final decision orders that the CPUC oversee an audit of the Utility's 1999 distribution capital spending, and that the 2001 ARA be subject to modification to take into account the results of the audit. The 2001 ARA will also be subject to modification to recognize amounts recorded in a new balancing account that the final decision requires be established for vegetation management expenses. In March 2000, two intervenors filed applications for rehearing of the 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 expected in the second quarter of 2000. Also in the 1999 GRC final decision, the CPUC ordered the Utility to file a 2002 GRC. The Utility currently intends to file a Notice of Intent with the CPUC in the third quarter of 2000. This date may be extended, depending upon the outcome of an April 27, 2000 ruling from two CPUC Commissioners, requesting comments on whether the CPUC should delay the Utility's 2002 GRC by six months. In seeking these comments, the Commissioners stated that if the 2002 GRC were delayed, rates could still become effective on January 1, 2002, although the CPUC decision may not be rendered until mid-2002. The Year 2000 Cost of Capital Proceeding - ---------------------------------------- In April 2000, the Utility reached a settlement with the ORA and several intervenor groups and will make a joint recommendation to the CPUC. The joint recommendation specifies a return on common equity (ROE) of 11.22 percent on electric and gas distribution operations, retroactive to February 17, 2000. The Utility's current authorized ROE is 10.6 percent. The joint recommendation also recommends no changes to the currently authorized Utility capital structure of 46.2 percent long-term debt, 5.8 percent preferred stock, and 48.0 percent common equity. If adopted by the CPUC, the recommendation would result in an authorized 9.12 percent overall return on Utility electric and gas distribution rate base. This would increase the Utility's 2000 electric and gas revenues by approximately $37 million and $12 million, respectively. A final CPUC decision on the parties' recommendation is expected in the second quarter of 2000. The Year 2001 Cost of Capital Proceeding - ---------------------------------------- On May 8, 2000, the Utility filed an application with the CPUC to establish its authorized rate of return (ROE) for electric and gas distribution operations for 2001. The application requests a ROE of 12.4 percent, and an overall rate of return (ROR) of 9.75 percent. The Utility's proposal for test year 2001 ROE for its electric distribution and gas distribution lines of business is 118 basis points higher than the 2000 settlement ROE of 11.22 percent currently pending before the CPUC. If granted, the requested ROE would increase electric distribution revenues by approximately $72 million and gas distribution revenues by approximately $23 million, as compared with the 2000 settlement ROE of 11.22 percent currently pending before the CPUC. 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 percent long-term debt, 5.8 percent preferred stock, and 48.0 percent common equity. 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. However, in April 2000, the FERC approved a settlement that permits the Utility to recover $264 million in electric transmission rates for the 10-month period of May 31, 1999 to March 31, 2000. Further, in October 1999, the FERC accepted, subject to refund, the Utility's proposal to collect $370 million annually in electric transmission rates beginning on April 1, 2000. The Utility does not expect a material impact on its financial position or results of operations resulting from these matters. Catastrophic Event Memorandum Account Proceeding - ------------------------------------------------ As previously disclosed, in September 1999, the Utility entered into a settlement agreement with the ORA, and other parties, providing for an increase in electric and gas distribution revenue requirements to compensate the Utility for service restoration costs recorded in the Catastrophic Events Memorandum Account. In April 2000, the CPUC approved the proposed settlement and collection over the remainder of the year. The CPUC's Gas Strategy Investigation, Phase 2 - ---------------------------------------------- In January 1998, the CPUC opened a rulemaking proceeding to explore changes in the natural gas industry in California. In July 1999, the CPUC issued a decision identifying options for restructuring the natural gas industry. In the decision, the CPUC reaffirmed the basic structure of the Gas Accord. The CPUC further stated that it seeks to explore a market structure that maintains the utilities' traditional role of providing fully integrated default service while removing obstacles to competitive unbundled services. The CPUC opened a new investigative proceeding to explore in more detail the anticipated costs and benefits associated with the different market structure options it has identified. In January 2000, the Utility and a broad-based coalition of shippers, consumer groups, marketers, and others filed a settlement with the CPUC which would reaffirm the basic structure of the Gas Accord and continue the Gas Accord through its original term of December 2002. RESULTS OF OPERATIONS The table below shows for the quarter ended March 31, 2000 and 1999, certain items from our Statement of Consolidated Income detailed by Utility and PG&E National Energy Group operations of PG&E Corporation. (In the "Total" column, the table shows the combined results of operations for these groups.) The information for PG&E Corporation (the "Total" column) excludes transactions between its subsidiaries (such as the purchase of natural gas by the Utility from the unregulated business operations). Following this table we discuss earnings and explain why the components of our results of operations varied from the quarter for 2000.
Utility PG&E National Energy Group ------- --------------------------------------------- PG&E GT Elimi- ---------------- nations & PG&EGen NW Texas PG&E ET Other (1) Total ------- ------- ------- ------- ------- --------- ------- (in millions) March 31, 2000 - -------------- Operating revenues $ 2,218 $ 312 $ 57 $ 225 $ 2,557 $ (361) $ 5,008 Operating expenses 1,648 255 25 210 2,544 (350) 4,332 ------- ------- ------- ------- ------- ------ ------- Operating income 570 57 32 15 13 (11) 676 Other income, net 15 Interest expense 183 Income taxes 228 Income from continuing operations 280 Net income $ 280 EBITDA (2) $ 864 $ 78 $ 42 $ 12 $ 17 $ (10) $ 1,003 March 31, 1999 - -------------- Operating revenues $ 2,085 $ 289 $ 58 $ 357 $ 2,631 $ (294) $ 5,126 Operating expenses 1,663 243 27 383 2,636 (287) 4,665 ------- ------- ------- ------- ------- ------ ------- Operating income 422 46 31 (26) (5) (7) 461 Other income, net 21 Interest expense 201 Income taxes 114 Income from continuing operations 167 Net income $ 171 EBITDA (2) $ 795 $ 70 $ 41 $ (7) $ (3) $ (7) $ 889 (1) Net income on intercompany positions recognized by segments using mark to market accounting is eliminated. Intercompany transactions are also eliminated. (2) EBITDA measures earnings (after preferred dividends) before interest expense (net of interest income), income taxes, depreciation, and amortization.
Overall Results - --------------- PG&E Corporation's net income for the first quarter of 2000 increased 63.7 percent to $280 million from $171 million in the prior year's first quarter. Of the $109 million increase, the PG&E National Energy Group accounted for $28 million of the increase and the Utility's first quarter net income available for common stock increased to $228 million from $147 million in the prior year. The strong increase in performance is attributable to the following factors: - In the first quarter of 2000, the Utility received the final order on its general rate case. Although the increase in revenue requirements was retroactive to January 1, 1999, the prior quarters were not restated and the entire increase was reflected in the fourth quarter of 1999. The outcome of the rate order increased first quarter Utility net earnings approximately $40 million ($0.11 per share) compared to the first quarter of 1999. - In the first quarter of 1999, Diablo Canyon completed a scheduled refueling outage for one of its plants. There was no such outage during the first quarter of 2000, resulting in an approximate $36 million ($0.10 per share) increase in 2000 first quarter net earnings. - PG&E ET's first quarter 2000 net income increased $14 million over 1999 first quarter results due to across the board improvements in gas and power trading, in asset management and structured transactions. This increase was net of a $4 million after-tax ($.01 per share) charge for severance costs associated with the restructuring of the PG&E National Energy Group. - At the end of 1999, PG&E Corporation announced its plans to dispose of PG&E GT-Texas and PG&E ES in separate transactions. The PG&E GT-Texas assets were written down to estimated fair value and the PG&E ES assets were reflected as discontinued operations. Net losses associated with those business segments amounted to $32 million ($0.08 per share) in the first quarter of 1999. - Effective the first quarter of 1999, PG&E Corporation changed its method of accounting for major maintenance and overhauls at PG&E National Energy Group. Beginning January 1, 1999, the cost of major maintenance and overhauls, principally at the PG&E Gen business segment, have 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. EBITDA has increased 12.8 percent to $1,003 million from $889 million in the prior year's first quarter as a result of the increased operating performance of the Utility and PG&E ET described above. Operating Revenues - ------------------ Utility operating revenues increased $133 million in the first quarter of 2000 to $2.2 billion over first quarter 1999 revenues of $2.1 billion. The increase is a result of higher sales to residential customers reflecting an increase in the number of customers and to industrial customers due to an increase in the average customer usage. This increase was partially offset by a decrease in natural gas sales because of milder winter weather. PG&E National Energy Group operating revenues declined $251 million in the first quarter of 2000 compared to the first quarter of 1999. The decline reflects a significant decline in trading volume in natural gas and natural gas liquids. PG&E National Energy Group has focused its trading efforts on asset management, structured transactions and higher margin trades resulting in a decrease in trading volume and an increase in gross profit margin. Operating Expenses - ------------------ Utility operating expenses decreased $15 million in the first quarter of 2000 to $1.6 billion from first quarter 1999. The decrease in operating expenses is a result of less depreciation expense because of the sale of 4,289 MW of fossil-fueled and geothermal generation facilities in the second quarter of 1999. Also contributing to the decrease in operating expenses was a decline in operating and maintenance expense reflecting the impact in 1999 of the Diablo Canyon scheduled refueling outage with no such scheduled outage in the first quarter of 2000. These decreases were partially offset by an increase in the cost of electric energy, which experienced both price and volume increases in the first quarter of 2000 over the first quarter of 1999. Operating expenses at PG&E National Energy Group declined $318 million in the first quarter of 2000 from $3 billion in the first quarter of 1999. The decrease results from the reduced trading volumes discussed above, cost control efforts throughout PG&E National Energy Group and reduced depreciation and amortization expense at PG&E GT-Texas reflective of the write-down to fair value of the PG&E GT-Texas assets held for sale. Income Taxes - ------------ The effective tax rate for the Corporation has increased to 44.9 percent in the current quarter from 40.6 percent in the prior year's first quarter as a result of: (1) electric industry restructuring which has resulted in the reversal of temporary tax differences at the Utility whose tax benefits were originally flowed through to customers causing an increase in income tax expense independent of pre-tax income and, (2) higher state taxes. Dividends - --------- We base our common stock dividend on a number of financial considerations, including sustainability, financial flexibility, and competitiveness with investment opportunities of similar risk. Our current quarterly common stock dividend is $.30 per common share, which corresponds to an annualized dividend of $1.20 per common share. We continually review the level of our common stock dividend, taking into consideration the impact of the changing regulatory environment throughout the nation, the resolution of asset dispositions, the operating performance of our business units, and our capital and financial resources in general. The CPUC requires the Utility to maintain its CPUC-authorized capital structure, potentially limiting the amount of dividends the Utility may pay PG&E Corporation. During 1999, the Utility has been in compliance with its CPUC-authorized capital structure. PG&E Corporation and the Utility believe that this requirement will not affect PG&E Corporation's ability to pay common stock dividends. However, depending on the timing and outcome of the valuation of the Utility's hydroelectric facilities discussed in "Generation Divestiture" above, certain valuation methods could necessitate a waiver of the CPUC's authorized capital structure in order to permit PG&E Corporation or the Utility to continue paying common stock dividends at the current level. LIQUIDITY AND FINANCIAL RESOURCES Cash Flows from Operating Activities - ------------------------------------ Net cash provided by PG&E Corporation's operating activities totaled $1,062 million and $1,025 million in the quarters ended March 31, 2000 and 1999, respectively. Net cash provided by the Utility's operating activities totaled $688 million and $1,092 million in the quarters ended March 31, 2000 and 1999, respectively. Cash Flows from Financing Activities - ------------------------------------ PG&E Corporation: We fund investing activities from cash provided by operations after capital requirements and, to the extent necessary, external financing. Our policy is to finance our investments with a capital structure that minimizes financing costs, maintains financial flexibility, and, with regard to the Utility, complies with regulatory guidelines. Based on cash provided from operations and our investing and disposition activities, we may repurchase equity and long-term debt in order to manage the overall size and balance of our capital structure. During the quarter ended March 31, 2000, we issued $10 million of common stock, primarily through the Dividend Reinvestment Plan and the stock option plan component of the Long-Term Incentive Program. During the quarter ended March 31, 2000, we paid dividends on our common stock of $108 million. In October 1999, the Board of Directors of PG&E Corporation authorized an additional $500 million for the purpose of repurchasing shares of the Corporation's common stock on the open market. This authorization supplements the approximately $40 million remaining from the amount previously authorized by the Board of Directors on December 17, 1997. The authorization for share repurchase extends through September 30, 2001. As of March 31, 2000, through our wholly owned subsidiary, we repurchased 7.2 million shares, at a cost of $159 million under this authorization. Any open market purchases will be made by the wholly owned subsidiary of PG&E Corporation. During the three months ended March 31, 2000, the PG&E National Energy Group retired $99 million of long-term debt. We maintain a number of credit facilities to support commercial paper programs, letters of credit, and other short-term liquidity requirements. PG&E Corporation maintains two $500 million revolving credit facilities, one of which expires in November 2000 and the other in 2002. These credit facilities are used to support the commercial paper program and other liquidity needs. The facility expiring in 2000 may be extended annually for additional one-year periods upon agreement with the lending institutions. There was $100 million of commercial paper outstanding at March 31, 2000. PG&E Corporation introduced a $200 million Extendible Commercial Note (ECN) program during the third quarter of 1999. The ECN program supplements our short-term borrowing capability. There was $98 million of extendible commercial notes outstanding at March 31, 2000, which are not supported by the credit facilities. PG&E Gen maintains two $550 million revolving credit facilities. One facility expires in August 2000 and the other expires in 2003. The total amount outstanding at March 31, 2000, backed by the facilities, was $903 million in commercial paper. Of these loans, $550 million is classified as noncurrent in the Consolidated Balance Sheet of PG&E Corporation. In 1998, USGenNE, a subsidiary of PG&E Gen, established a $100 million revolving credit facility that expires in 2003. As of March 31, 2000, there is no outstanding balance on this facility. PG&E GT NW maintains a $100 million revolving credit facility that expires in 2002, but has an annual renewal option allowing the facility to maintain a three-year duration. PG&E GT NW also maintains a $50 million 364-day credit facility that expires in 2000, but can be extended for successive 364-day periods. At March 31, 2000, PG&E GT NW had an outstanding commercial paper balance of $64 million, which is classified as noncurrent in the Consolidated Balance Sheet of PG&E Corporation. PG&E GTT maintains four separate credit facilities that total $250 million and are guaranteed by PG&E Corporation. At March 31, 2000, PG&E GTT had $192 million of outstanding short-term bank borrowings related to these credit facilities. These lines may be cancelled upon demand and bear interest at each respective bank's quoted money market rate. The borrowings are unsecured and unrestricted as to use. Utility: During the three months ended March 31, 2000, the Utility paid dividends on its common stock of $122 million. In April 2000, the Utility repurchased from PG&E Corporation 11.9 million shares of its common stock at a cost of $275 million. The Utility's long-term debt that either matured, was redeemed, or was repurchased during the three months ended March 31, 2000, totaled $102 million. Of this amount, $73 million related to the Utility's rate reduction bonds maturing, and $27 million related to the maturities and redemption of various of the Utility's medium-term notes and other debt. The Utility maintains a $1 billion revolving credit facility, which expires in 2002. The Utility may extend the facility annually for additional one-year periods upon agreement with the banks. This facility is used to support the Utility's commercial paper program and other liquidity requirements. The total amount outstanding at March 31, 2000, backed by this facility, was $209 million in commercial paper. Cash Flows from Investing Activities - ------------------------------------ Utility: The primary uses of cash for investing activities are additions to property, plant, and equipment, unregulated investments in partnerships, and acquisitions. The Utility's estimated capital spending for 2000 is approximately $1.3 billion, excluding capital expenditures for divested fossil and geothermal power plants. The Utility's capital expenditures for the three months ended March 31, 2000, was $265 million. PG&E National Energy Group: PG&E Gen is associated with the construction of three natural gas-fueled combined-cycle power plants. These power plants, referred to as "merchant power plants," will sell power as a commodity in the competitive marketplace. The electricity generated by these plants will be sold on a wholesale basis to local utilities and power marketers, including PG&E ET, which, in turn, will sell it to industrial, commercial, and other electricity customers. Millennium Power, a 360-MW power plant located in Massachusetts, is scheduled to begin commercial service in the first quarter of 2001. Lake Road Generating Plant (Lake Road), an approximately 790-MW power plant located in Connecticut, is scheduled to begin commercial service in 2001. La Paloma Generating Plant (La Paloma), an approximately 1,050-MW power plant, is located in California, and is scheduled to begin commercial service in 2001. Lake Road and La Paloma are being financed through synthetic leases with a third party owner. PG&E Gen will operate the plants under operating leases. The estimated cost to construct these plants is approximately $1.4 billion. PG&E Gen broke ground for the Madison Wind Power Project in New York in April 2000. This 11.5 MW project will be the largest wind generating facility in the Eastern United States and is expected to be operational in September 2000. The estimated cost to construct this plant is $16 million. USGenNE has proposed an emission reduction plan which may include a $400 million modernization of its 760-MW coal-fired power plant in Salem, Massachusetts. The proposed modernization will use advanced technologies for emissions removal, with construction beginning in 2002 and ending by January 2004. ENVIRONMENTAL MATTERS We are subject to laws and regulations established to both maintain and improve the quality of the environment. Where our properties contain hazardous substances, these laws and regulations require us to remove those substances or remedy effects on the environment. At March 31, 2000, the Utility has accrued $275 million ($303 million on an undiscounted basis) for clean-up costs at identified sites. If other responsible parties fail to pay or expected outcomes change, then these costs may be as much as $501 million. Of the $275 million, the Utility has recovered $148 million through rates, including $34 million through depreciation and expects to recover another $99 million in future rates. Additionally, the Utility mitigates its cost by seeking recovery from insurance carriers and other third parties. (See Note 6 of Notes to Condensed Consolidated Financial Statements.) The cost of the hazardous substance remediation ultimately undertaken by the Utility is difficult to estimate. A change in the estimate may occur in the near term due to uncertainty concerning the Utility's responsibility, the complexity of environmental laws and regulations, and the selection of compliance alternatives. The Utility estimates the upper limit of the range using assumptions least favorable to the Utility, based upon a range of reasonably possible outcomes. Costs may be higher if the Utility is found to be responsible for clean-up costs at additional sites or expected outcomes change. In addition to the potential $400 million modernization of the coal-fired power plant located on Salem Harbor in Salem, Massachusetts, USGenNE also is studying various modernization alternatives for its 1,586 MW coal-fired Brayton Point power plant in Somerset, Massachusetts. On April 18, 2000 the Conservation Law Foundation (CLF) served various PG&E Gen affiliates, including USGenNE, a notice of its intent to file suit under the citizen suit provision of the Resource Conservation Recovery Act. CLF stated in such notice that it plans in its suit to allege that the PG&E Gen affiliates, generator of fossil fuel combustion wastes, has and is contributing to the past and present handling, storage, treatment and disposal of such wastes at the Salem Harbor and Brayton Point power plants which may present an imminent and substantial endangerment to health or the environment. It further stated it will allege that PG&E Gen's management practices in connection with such wastes has resulted in severe groundwater contamination at both facilities. CLF has stated that it intends to seek an order requiring all necessary measures be taken to halt what it characterizes as the endangerment of health and environment. At this preliminary stage, we are unable to determine whether the ultimate outcome of this matter would have a material adverse effect on our results of operations or financial condition. RISK MANAGEMENT ACTIVITIES We have established a risk management policy that allows derivatives to be used for both hedging and non-hedging purposes (a derivative is a contract whose value is dependent on or derived from the value of some underlying asset). We use derivatives for hedging purposes primarily to offset underlying commodity price risks. We also participate in markets using derivatives to gather market intelligence, create liquidity, and maintain a market presence. Such derivatives include forward contracts, futures, swaps, and options. Net open positions often exist or are established due to PG&E Corporation's assessment of its response to changing market conditions. To the extent that PG&E Corporation has an open position, it is exposed to the risk that fluctuating market prices may adversely impact its financial results. Our risk management policy and the trading and risk management policies of our subsidiaries prohibit the use of derivatives whose payment formula includes a multiple of some underlying asset. We prepare a daily assessment of our portfolio market risk exposure using value-at-risk and other methodologies that simulate future price movements in the energy markets to estimate the size and probability of future potential losses. The quantification of market risk using value-at-risk provides a consistent measure of risk across diverse energy markets and products. The use of this methodology requires a number of important assumptions, including the selection of a confidence level for losses, volatility of prices, market liquidity, and a holding period. PG&E Corporation's daily value-at-risk for commodity price sensitive derivative instruments as of March 31, 2000, was $1.6 million for trading activities and $0.3 million for non-trading activities. Value-at-risk has several limitations as a measure of portfolio risk, including, but not limited to, underestimation of the risk of a portfolio with significant options exposure, inadequate indication of the exposure of a portfolio to extreme price movements, and the inability to address the risk resulting from intra-day trading activities. In June 1999, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 137, "Accounting for Derivative Instruments and Hedging Activities-Deferral of the Effective Date of FASB Statement No. 133," which delayed the implementation of SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," by one year to require adoption in years beginning after June 15, 2000. The Statement permits early adoption as of the beginning of any fiscal quarter. PG&E Corporation expects to adopt SFAS No. 133 no later than January 1, 2001. The Statement will require us to recognize all derivatives, as defined in the Statement, on the balance sheet at fair value. Derivatives, or any portion thereof, that are not effective hedges must be adjusted to fair value through income. If derivatives are effective hedges, depending on the nature of the hedges, changes in the fair value of derivatives either will be offset against the change in fair value of the hedged assets, liabilities, or firm commitments through earnings, or will be recognized in other comprehensive income until the hedged items are recognized in earnings. We currently are evaluating what the effect of SFAS No. 133 will be on the earnings and financial position of PG&E Corporation. However, we already use the mark-to-market method of accounting for our commodity non-hedging and risk management activities. LEGAL MATTERS In the normal course of business, both the Utility and PG&E Corporation are named as parties in a number of claims and lawsuits. (See Note 5 of Notes to Condensed Consolidated Financial Statements for further discussion of significant pending legal matters.) ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK ------------------------------------------------------------------- PG&E Corporation's and Pacific Gas and Electric Company's primary market risk results from changes in energy prices and interest rates. We engage in price risk management activities for both non-hedging and hedging purposes. Additionally, we may engage in hedging activities using futures, options, and swaps to hedge the impact of market fluctuations on energy commodity prices, interest rates, and foreign currencies. (See Risk Management Activities, above.) PART II. OTHER INFORMATION Item 1. Legal Proceedings ----------------- Moss Landing Power Plant 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 and organic debris from the intake, and that this procedure is not specified in the plant's National Pollutant Discharge Elimination System (NPDES) permit issued by the Central Coast Regional Water Quality Control Board (Central Coast Board). The purchaser notified the Central Coast Board of its findings and the Central Coast Board requested additional information from the purchaser. The Utility initiated an investigation of these activities during the time it owned the plant. The Utility notified the Central Coast Board that it had undertaken an investigation and that it would present the results to the Central Coast Board when the investigation was completed. On March 15, 2000, the Central Coast Board sent a letter to the Utility requesting specific information regarding the "backflush" procedure used at Moss Landing. The Utility completed its investigation and provided the requested information to the Central Coast Board on April 7, 2000. Until the results of the Utility's investigation are discussed with the Central Coast Board, it is not possible to determine whether the Utility will suffer a loss in connection with this matter or to provide a more detailed estimate of such liability. Item 4. Submission of Matters to a Vote of Security Holders --------------------------------------------------- PG&E Corporation: On April 19, 2000, PG&E Corporation held its annual meeting of shareholders. At that meeting, the shareholders voted as indicated below on the following matters: 1. Election of the following directors to serve until the next annual meeting of shareholders or until their successors are elected and qualified: For Withheld ---------- ---------- Richard A. Clarke 252,017,302 9,890,523 Harry M. Conger 252,942,092 8,965,733 David A. Coulter 252,110,956 9,796,869 C. Lee Cox 253,040,357 8,867,468 William S. Davila 253,036,334 8,871,491 Robert D. Glynn, Jr. 252,909,447 8,998,378 David M. Lawrence, MD 252,705,855 9,201,970 Mary S. Metz 252,995,318 8,912,507 Carl E. Reichardt 252,790,649 9,117,176 John C. Sawhill 253,084,819 8,823,006 Barry Lawson Williams 252,723,645 9,184,180 2. Ratification of the appointment of Deloitte & Touche LLP as independent public accountants for 2000: For: 256,379,276 Against: 2,506,940 Abstain: 3,021,609 The proposal was approved by a majority of the shares present and voting (including abstentions) which shares voting affirmatively also constituted a majority of the required quorum. 3. Management proposal regarding proposed amendments to PG&E Corporation's Articles of Incorporation to implement the elimination of a supermajority vote provision. For: 206,193,826 Against: 10,349,714 Abstain: 5,261,226 Broker non-vote:(1) 40,103,059 The proposal was approved by a majority of the outstanding shares. 4. Management proposal regarding proposed amendment to PG&E Corporation's Articles of Incorporation to decrease the authorized minimum and maximum number of directors: For: 250,306,476 Against: 6,974,397 Abstain: 4,626,543 Broker non-vote:(1) 409 The proposal was approved by a majority of the outstanding shares. 5. Consideration of a shareholder proposal to appoint independent directors to key Board committees: For: 95,827,965 Against: 115,539,858 Abstain: 10,431,336 Broker non-votes:(1) 40,108,666 This shareholder proposal was defeated, as the number of shares voting affirmatively on the proposal constituted less than a majority of the shares voting and present (including abstentions but excluding broker non- votes) with respect to the proposal. 6. Consideration of a shareholder proposal regarding confidential shareholder voting: For: 108,057,613 Against: 106,010,434 Abstain: 7,730,522 Broker non-votes:(1) 40,109,256 This shareholder proposal was defeated, as the number of shares voting affirmatively on the proposal constituted less than a majority of the shares voting and present (including abstentions but excluding broker non- votes) with respect to the proposal. - --------------- (1) A non-vote occurs when a broker or other nominee holding shares for a beneficial owner indicates a vote on one or more proposals, but does not indicate a vote on other proposals because the broker or other nominee does not have discretionary voting power as to such proposals and has not received voting instructions from the beneficial owner as to such proposals. 7. Consideration of a shareholder proposal regarding the treatment of abstentions: For: 30,290,100 Against: 180,368,498 Abstain: 11,173,674 Broker non-votes:(1) 40,075,553 This shareholder proposal was defeated, as the number of shares voting affirmatively on the proposal constituted less than a majority of the shares voting and present (including abstentions but excluding broker non- votes) with respect to the proposal. 8. Consideration of a shareholder proposal regarding cumulative voting: For: 72,824,979 Against: 135,858,343 Abstain: 13,115,837 Broker non-votes:(1) 40,108,666 This shareholder proposal was defeated, as the number of shares voting affirmatively on the proposal constituted less than a majority of the shares voting and present (including abstentions but excluding broker non- votes) with respect to the proposal. 9. Consideration of a shareholder proposal regarding compensation of directors in stock: For: 28,219,661 Against: 183,248,630 Abstain: 10,330,868 Broker non-votes:(1) 40,108,666 This shareholder proposal was defeated, as the number of shares voting affirmatively on the proposal constituted less than a majority of the shares voting and present (including abstentions but excluding broker non- votes) with respect to the proposal. 10. Consideration of a proposal regarding severance benefits received during mergers or acquisitions: For: 36,508,116 Against: 176,996,783 Abstain: 8,294,260 Broker non-votes:(1) 40,108,666 This shareholder proposal was defeated, as the number of shares voting affirmatively on the proposal constituted less than a majority of the shares voting and present (including abstentions but excluding broker non- votes) with respect to the proposal. - --------------- (1) A non-vote occurs when a broker or other nominee holding shares for a beneficial owner indicates a vote on one or more proposals, but does not indicate a vote on other proposals because the broker or other nominee does not have discretionary voting power as to such proposals and has not received voting instructions from the beneficial owner as to such proposals. Pacific Gas and Electric Company: On April 19, 2000, Pacific Gas and Electric Company held its annual meeting of shareholders. Shares of capital stock of Pacific Gas and Electric Company consist of shares of common stock and shares of first preferred stock. As PG&E Corporation and a subsidiary own all of the outstanding shares of common stock, they hold approximately 95% of the combined voting power of the outstanding capital stock of Pacific Gas and Electric Company. PG&E Corporation and the subsidiary voted all of their respective shares of common stock for the nominees named in the joint proxy statement and for the ratification of the appointment of Deloitte & Touche LLP as independent public accountants for 2000. The balance of the votes shown below were cast by holders of shares of first preferred stock. At the annual meeting, the shareholders voted as indicated below on the following matters: 1. Election of the following directors to serve until the next annual meeting of shareholders or until their successors are elected and qualified: For Withheld ----------- ----------- Richard A. Clarke 338,548,826 187,097 Harry M. Conger 338,566,995 168,928 David A. Coulter 338,547,768 188,155 C. Lee Cox 338,570,513 165,410 William S. Davila 338,567,649 168,274 Robert D. Glynn, Jr. 338,559,318 176,605 David M. Lawrence, MD 338,556,908 179,015 Mary S. Metz 338,563,724 172,199 Carl E. Reichardt 338,551,976 183,947 John C. Sawhill 338,569,718 166,205 Gordon R. Smith 338,561,480 174,443 Barry Lawson Williams 338,566,195 169,728 2. Ratification of the appointment of Deloitte & Touche LLP as independent public accountants for 2000: For: 338,539,587 Against: 47,602 Abstain: 148,734 Item 5. Other Information ----------------- Ratio of Earnings to Fixed Charges and Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends Pacific Gas and Electric Company's earnings to fixed charges ratio for the three months ended March 31, 2000, was 3.89. Pacific Gas and Electric Company's earnings to combined fixed charges and preferred stock dividends ratio for the three months ended March 31, 2000, was 3.67. The statement of the foregoing ratios, together with the statements of the computation of the foregoing ratios filed as Exhibits 12.1 and 12.2 hereto, are included herein for the purpose of incorporating such information and exhibits into Registration Statement Nos. 33-62488, 33-64136, 33-50707, and 33-61959, relating to Pacific Gas and Electric Company's various classes of debt and first preferred stock outstanding. Item 6. Exhibits and Reports on Form 8-K -------------------------------- (a) Exhibits: Exhibit 3.1 Restated Articles of Incorporation of PG&E Corporation, dated as of May 5, 2000 Exhibit 3.2 Bylaws of PG&E Corporation, dated as of May 5, 2000 Exhibit 10 Letter Regarding Relocation Arrangements Between PG&E Corporation and Thomas B. King Exhibit 11 Computation of Earnings Per Common Share Exhibit 12.1 Computation of Ratios of Earnings to Fixed Charges for Pacific Gas and Electric Company Exhibit 12.2 Computation of Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividends for Pacific Gas and Electric Company Exhibit 27.1 Financial Data Schedule for the quarter ended March 31, 2000, for PG&E Corporation Exhibit 27.2 Financial Data Schedule for the quarter ended March 31, 2000, for Pacific Gas and Electric Company (b) The following Current Reports on Form 8-K were filed during the first quarter of 2000 and through the date hereof (2): 1. January 21, 2000 Item 5. Other Events A. Pacific Gas and Electric Company's General Rate Case Proceeding B. Proposed Auction of Pacific Gas and Electric Company's Hydroelectric Generating Assets. C. 1998 Annual Transition Cost Proceeding - --------------- (2) Unless otherwise noted, all Current Reports on Form 8-K were filed under both Commission File Number 1-12609 (PG&E Corporation) and Commission File Number 1-2348 (Pacific Gas and Electric Company). 2. January 31, 2000 Item 5. Other Events Sale of Texas Gas Transmission Companies 3. February 23, 2000 Item 5. Other Events A. Pacific Gas and Electric Company's General Rate Case Proceeding B. 1998 Annual Transition Cost Proceeding C. Disposition of PG&E Energy Services Corporation 4. April 14, 2000 Item 5. Other Events A. Pacific Gas and Electric Company's 2000 Cost of Capital Proceeding 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 CHRISTOPHER P. JOHNS By __________________________ CHRISTOPHER P. JOHNS Vice President and Controller PACIFIC GAS AND ELECTRIC COMPANY KENT M. HARVEY By __________________________ KENT M. HARVEY Senior Vice President-Chief Financial Officer, Controller and Treasurer Dated: May 12, 2000 Exhibit Index Exhibit No. Description of Exhibit Exhibit 3.1 Restated Articles of Incorporation of PG&E Corporation, dated as of May 5, 2000 Exhibit 3.2 Bylaws of PG&E Corporation, dated as of May 5, 2000 Exhibit 10 Letter Regarding Relocation Arrangements Between PG&E Corporation and Thomas B. King Exhibit 11 Computation of Earnings Per Common Share Exhibit 12.1 Computation of Ratio of Earnings to Fixed Charges for Pacific Gas and Electric Company Exhibit 12.2 Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends for Pacific Gas and Electric Company Exhibit 27.1 Financial Data Schedule for the quarter ended March 31, 2000 for PG&E Corporation Exhibit 27.2 Financial Data Schedule for the quarter ended March 31, 2000 for Pacific Gas and Electric Company EX-3 2 RESTATED ARTICLES OF INCORPORATION OF PG&E CORPORATION ROBERT D. GLYNN, JR. and LESLIE H. EVERETT certify that: 1. They are the Chairman of the Board, Chief Executive Officer, and President, and the Vice President and Corporate Secretary, respectively, of PG&E Corporation, a California corporation. 2. The Articles of Incorporation of the corporation, as amended to the date of the filing of this certificate, including the amendments set forth herein but not separately filed (and with the omissions required by Section 910 of the California Corporations Code) are amended and restated as follows: FIRST: The name of the Corporation shall be PG&E CORPORATION SECOND: The purpose of the Corporation is to engage in any lawful act or activity for which a corporation may be organized under the General Corporation Law of California other than the banking business, the trust company business or the practice of a profession permitted to be incorporated by the California Corporations Code. THIRD: I. The Board of Directors of the Corporation shall consist of such number of directors, not less than seven (7) nor more than thirteen (13), as shall be prescribed in the Bylaws. II. The Board of Directors by a vote of two-thirds of the whole Board may appoint from the directors an Executive Committee, which Committee may exercise such powers as may lawfully be conferred upon it by the Bylaws of the Corporation. Such Committee may prescribe rules for its own government and its meetings may be held at such places within or without California as said Committee may determine or authorize. FOURTH: No shareholder may cumulate votes in the election of directors. This Article FOURTH shall become effective only when the Corporation shall have become a "listed corporation" within the meaning of Section 301.5 of the California Corporations Code. FIFTH: The liability of the directors of the Corporation for monetary damages shall be eliminated to the fullest extent permissible under California law. SIXTH: The Corporation is authorized to provide indemnification of agents (as defined in Section 317 of the California Corporations Code) through bylaws, resolutions, agreements with agents, vote of shareholders or disinterested directors, or otherwise, in excess of the indemnification otherwise permitted by Section 317 of the California Corporations Code, subject only to the applicable limits set forth in Section 204 of the California Corporations Code. SEVENTH: I. The Corporation is authorized to issue two classes of shares, to be designated respectively Preferred Stock ("Preferred Stock") and Common Stock ("Common Stock"). The total number of shares of capital stock that the Corporation is authorized to issue is 885,000,000, of which 85,000,000 shall be Preferred Stock and 800,000,000 shall be Common Stock. II. The Preferred Stock may be issued from time to time in one or more series. The Board of Directors of the Corporation is expressly authorized to provide for the issue of all or any of the shares of the Preferred Stock in one or more series, and to fix the designation and number of shares and to determine or alter for each such series, such voting powers, full or limited, or no voting powers, and such designations, preferences and relative, participating, optional or other rights and such qualifications, limitations or restrictions thereof, as shall be stated and expressed in the resolution or resolutions adopted by the Board of Directors providing for the issue of such shares and as may be permitted by the General Corporation Law of California. The Board of Directors is also expressly authorized to increase or decrease (but not below the number of shares of such series then outstanding) the number of shares of any series subsequent to the issue of shares of that series. If the number of shares of any such series shall be so decreased, the shares constituting such decrease shall resume the status that they had prior to the adoption of the resolution originally fixing the number of shares of such series. EIGHTH: I. The affirmative vote of the holders of not less than a majority of the outstanding shares of "Voting Stock" (as hereinafter defined) shall be required to implement or effect any "Business Combination" (as hereinafter defined) involving the Corporation or any "Subsidiary" (as hereinafter defined) of the Corporation and any "Related Person" (as hereinafter defined), or any "Affiliate" or "Associate" (as hereinafter defined) of a Related Person, notwithstanding the fact that no vote may be required or that a lesser percentage may be specified by law, in any agreement with any national securities exchange or otherwise. In addition, the provisions of either subparagraph (1) or (2) must be satisfied: (1) The Business Combination shall have been approved by the Board of Directors without counting the vote of any director who is not a "Disinterested Director" (as hereinafter defined); or (2) All of the following conditions are met: (i) The cash or "Fair Market Value" (as hereinafter defined) as of the date of the consummation of the Business Combination (the "Combination Date") of the property, securities or other consideration to be received per share by holders of a particular class or series of capital stock, as the case may be, of the Corporation in the Business Combination is not less than the highest of: (a) the highest per share price (including brokerage commissions, transfer taxes and soliciting dealers' fees) paid by or on behalf of the Related Person in acquiring beneficial ownership of any of its holdings of such class or series of capital stock of the Corporation (A) within the two-year period immediately prior to the first public announcement of the proposed Business Combination (the "Announcement Date") or (B) in the transaction or series of transactions in which the Related Person became a Related Person, whichever is higher; or (b) the highest Fair Market Value per share of the shares of capital stock being acquired in the Business Combination as of any date within the one-year period preceding: (A) the Announcement Date or (B) the date on which the Related Person became a Related Person, whichever is higher; or (c) in the case of Common Stock, the highest per share book value of the Common Stock as reported at the end of the three fiscal quarters which preceded the Announcement Date, and in the case of Preferred Stock the highest preferential amount per share to which the holders of shares of such class or series of Preferred Stock would be entitled as of the Combination Date in the event of any voluntary or involuntary liquidation, dissolution or winding up of the affairs of the Corporation, regardless of whether the Business Combination to be consummated constitutes such an event. The provisions of this paragraph I(2)(i) shall be required to be met with respect to every class or series of outstanding capital stock, whether or not the Related Person has previously acquired any shares of a particular class or series of capital stock. In all of the above instances, appropriate adjustments shall be made for recapitalizations and for stock dividends, stock splits and like distributions; and (ii) The consideration to be received by holders of a particular class or series of capital stock shall be in cash or in the same form as previously has been paid by or on behalf of the Related Person in connection with its direct or indirect acquisition of beneficial ownership of shares of such class or series of stock. If the consideration so paid for any such shares varied as to form, the form of consideration for such shares shall be either cash or the form used to acquire beneficial ownership of the largest number of shares of such class or series of capital stock previously acquired by the Related Person; and (iii) After such Related Person has become a Related Person and prior to the consummation of such Business Combination: (a) except as approved by the Board of Directors without counting the vote of any director who is not a Disinterested Director, there shall have been no failure to declare and pay at the regular date therefor any full quarterly dividends (whether or not cumulative) on the outstanding Preferred Stock; (b) there shall have been (A) no reduction in the annual rate of dividends paid on the Common Stock (except as necessary to reflect any subdivision of the Common Stock) except as approved by the Board of Directors without counting the vote of any director who is not a Disinterested Director, and (B) an increase in such annual rate of dividends as necessary to reflect any reclassification (including any reverse stock split), recapitalization, reorganization or any similar transaction which has the effect of reducing the number of outstanding shares of the Common Stock, unless the failure so to increase such annual rate is approved by the Board of Directors without counting the vote of any director who is not a Disinterested Director; and (c) such Related Person shall not have become the beneficial owner of any additional shares of Voting Stock except as part of the transaction which results in such Related Person becoming a Related Person; and (iv) After such Related Person has become a Related Person, the Related Person shall not have received the benefit, directly or indirectly (except proportionately as a shareholder), of any loans, advances, guarantees, pledges or other financial assistance or any tax credits or other tax advantages provided by the Corporation, whether in anticipation of or in connection with such Business Combination or otherwise; and (v) A proxy or information statement describing the proposed Business Combination and complying with the requirements of the Securities Exchange Act of 1934 and the rules and regulations thereunder (or any provisions subsequently replacing such Act, rules or regulations) shall be mailed to public shareholders of the Corporation at least 30 days prior to the consummation of such Business Combination (whether or not such proxy or information statement is required to be mailed pursuant to such Act or subsequent provisions). II. For purpose of this Article EIGHTH: (1) The term "Business Combination" shall mean any (i) merger or consolidation of the Corporation or a Subsidiary with a Related Person or any other person which is or after such merger or consolidation would be an Affiliate or Associate of a Related Person; (ii) sale, lease, exchange, mortgage, pledge, transfer or other disposition or guarantee (in one transaction or a series of transactions) to or with or for the benefit of any Related Person or any Affiliate or Associate of any Related Person, of any assets of the Corporation or of a Subsidiary having an aggregate Fair Market Value of $100 million or more; (iii) sale, lease, exchange, mortgage, pledge, transfer or other disposition (in one transaction or a series of transactions), to the Corporation or a Subsidiary of any assets of a Related Person or any Affiliate or Associate of any Related Person having an aggregate Fair Market Value of $100 million or more; (iv) issuance, pledge or transfer of securities of the Corporation or a Subsidiary (in one transaction or a series of transactions) to or with a Related Person or any Affiliate or Associate of any Related Person in exchange for cash, securities or other property (or a combination thereof) having an aggregate Fair Market Value of $100 million or more; (v) reclassification of securities (including any reverse stock split) or recapitalization of the Corporation, or any merger or consolidation of the Corporation with any of its Subsidiaries or any other transaction that would have the effect, either directly or indirectly, of increasing the voting power or the proportionate share of any class of equity or convertible securities of the Corporation or any Subsidiary which is directly or indirectly beneficially owned by any Related Person or any Affiliate or Associate of any Related Person; and (vi) any merger or consolidation of the Corporation with any of its Subsidiaries after which the provisions of this Article EIGHTH of the Articles of Incorporation shall not be contained in the Articles of Incorporation of the surviving entity. (2) The term "person" shall mean any individual, firm, corporation or other entity and shall include any group comprised of any person and any other person with whom such person or any Affiliate or Associate of such person has any agreement, arrangement or understanding, directly or indirectly, for the purpose of acquiring, holding, voting or disposing of Voting Stock of the Corporation. (3) The term "Related Person" shall mean any person (other than the Corporation, or any Subsidiary and other than any dividend reinvestment plan or profit-sharing, employee stock ownership or other employee benefit or savings plan of the Corporation or any Subsidiary or any trustee of or fiduciary with respect to any such plan when acting in such capacity) who or which: (i) is the beneficial owner (as hereinafter defined) of five percent (5%) or more of the Voting Stock; (ii) is an Affiliate or Associate of the Corporation and at any time within the two-year period immediately prior to the date in question was the beneficial owner of five percent (5%) or more of the then outstanding Voting Stock; or (iii) is an assignee of or has otherwise succeeded to the beneficial ownership of any shares of Voting Stock which were at any time within the two-year period immediately prior to such time beneficially owned by any Related Person, if such assignment or succession shall have occurred in the course of a transaction or series of transactions not involving a public offering within the meaning of the Securities Act of 1933. (4) A person shall be a "beneficial owner" of any Voting Stock: (i) which such person or any of its Affiliates or Associates beneficially owns, directly or indirectly; (ii) which such person or any of its Affiliates or Associates has, directly or indirectly, (a) the right to acquire (whether such right is exercisable immediately or only after the passage of time), pursuant to any agreement, arrangement or understanding or upon the exercise of conversion rights, exchange rights, warrants or options, or otherwise, or (b) the right to vote pursuant to any agreement, arrangement or understanding; or (iii) which is beneficially owned, directly or indirectly, by any other person with which such person or any of its Affiliates or Associates has any agreement, arrangement or understanding for the purpose of acquiring, holding, voting or disposing of any shares of Voting Stock. (5) For the purposes of determining whether a person is a Related Person pursuant to subparagraph (3) of this paragraph II, the number of shares of Voting Stock deemed to be outstanding shall include shares deemed owned through application of subparagraph (4) of this paragraph II but shall not include any other shares of Voting Stock which may be issuable pursuant to any agreement, arrangement or understanding, or upon exercise of conversion rights, warrants or options, or otherwise. (6) The term "Affiliate," used to indicate a relationship with a specified person, shall mean a person that directly, or indirectly, through one or more intermediaries, controls, or is controlled by, or is under common control with, such specified person. The term "Associate," used to indicate a relationship with a specified person, shall mean (i) any person (other than the Corporation or a Subsidiary) of which such specified person is an officer or partner or is, directly or indirectly, the beneficial owner of 10% or more of any class of equity securities, (ii) any trust or other estate in which such specified person has a substantial beneficial interest or as to which such specified person serves as trustee or in a similar fiduciary capacity, (iii) any relative or spouse of such specified person or any relative of such spouse, who has the same home as such specified person or who is a director or officer of the Corporation or any Subsidiary, and (iv) any person who is a director or officer of such specified person or any of its parents or subsidiaries (other than the Corporation or a Subsidiary). (7) The term "Subsidiary" means any corporation or other entity of which a majority of any class of equity securities is owned, directly or indirectly, by the Corporation; provided, however, that for the purposes of the definition of Related Person set forth in subparagraph (3) of this paragraph II, the term "Subsidiary" shall mean only a corporation of which a majority of the outstanding shares of capital stock of such corporation entitled to vote generally in the election of directors is owned, directly or indirectly, by the Corporation or, in the case of other entities, the Corporation has the direct or indirect contractual power to designate a majority of the individuals or representatives exercising functions similar to those exercised by directors of a corporation, or the Corporation has the power to approve a transaction which would otherwise be a Business Combination involving such entity. (8) The term "Disinterested Director" means any member of the Board of Directors, while such person is a member of the Board of Directors, who is not an Affiliate, Associate or a representative of the Related Person involved in a proposed Business Combination and was a member of the Board of Directors immediately prior to the time that the Related Person became a Related Person, and any successor of a Disinterested Director, while such successor is a member of the Board of Directors, who is not an Affiliate, Associate or a representative of the Related Person and is recommended or elected to succeed a Disinterested Director by the Board of Directors without counting the vote of any director who is not a Disinterested Director. (9) For the purposes of paragraph I(2)(i) of this Article EIGHTH, the term "other consideration to be received" shall include, without limitation, capital stock retained by the shareholders. (10) The term "Voting Stock" shall mean all of the outstanding shares of capital stock of the Corporation entitled to vote generally in the election of directors, and each reference to a proportion of shares of Voting Stock shall refer to such proportion of the votes entitled to be cast by such shares voting together as one class. (11) The term "Fair Market Value" means: (i) in case of capital stock, the highest closing sale price during the 30-day period immediately preceding the date in question of a share of such stock on the Composite Tape for the New York Stock Exchange Listed Stocks, or, if such stock is not quoted on the Composite Tape, on the New York Stock Exchange, or if such stock is not listed on such Exchange, on the principal United States securities exchange registered under the Securities Exchange Act of 1934 on which such stock is listed, or, if such stock is not listed on any such stock exchange, the highest closing bid quotation with respect to a share of such stock during the 30-day period preceding the date in question on the National Association of Securities Dealers, Inc. Automated Quotations System or any successor system then in use, or if no such quotations are available, the fair market value on the date in question of a share of such stock as determined in good faith by the Board of Directors without counting the vote of any director who is not a Disinterested Director; and (ii) in the case of property other than cash or stock, the fair market value of such property on the date in question as determined in good faith by the Board of Directors without counting the vote of any director who is not a Disinterested Director. (12) A Related Person shall be deemed to have acquired a share of Voting Stock at the time when such Related Person became the beneficial owner thereof. If the Board of Directors without counting the vote of any director who is not a Disinterested Director is not able to determine the price at which a Related Person has acquired a share of Voting Stock, such price shall be deemed to be the Fair Market Value of the shares in question at the time when the Related Person becomes the beneficial owner thereof. With respect to shares owned by Affiliates or other persons whose ownership is attributed to a Related Person under the foregoing definition of Related Person, the price deemed to be paid therefor by such Related Person shall be the price paid upon the acquisition thereof by such Affiliate, Associate or other person, or, if such price is not determinable by the Board of Directors without counting the vote of any director who is not a Disinterested Director, the Fair Market Value of the shares in question at the time when the Affiliate, Associate, or other such person became the beneficial owner thereof. III. The fact that any Business Combination complies with the provisions of paragraph I(2) of this Article EIGHTH shall not be construed to impose any fiduciary duty, obligation or responsibility on the Board of Directors, or any member thereof, to approve such Business Combination or recommend its adoption or approval to the shareholders of the Corporation, nor shall such compliance limit, prohibit or otherwise restrict in any manner the Board of Directors, or any member thereof, with respect to evaluations of or actions and responses taken with respect to such Business Combination. IV. The Board of Directors of the Corporation shall have the power and duty to determine for the purposes of this Article EIGHTH, on the basis of information known to them after reasonable inquiry and in accordance with the terms of this Article EIGHTH, whether a person is a Related Person and whether a director is a Disinterested Director. Once the Board of Directors has made a determination pursuant to the preceding sentence that a person is a Related Person, the Board of Directors of the Corporation, without counting the vote of any director who is not a Disinterested Director with respect to such Related Person, shall have the power and duty to interpret all of the terms and provisions of this Article EIGHTH and to determine on the basis of the information known to them after reasonable inquiry all facts necessary to ascertain compliance with this Article EIGHTH including, without limitation, (1) the number of shares of Voting Stock beneficially owned by any person, (2) whether a person is an Affiliate or Associate of another, (3) whether the assets which are the subject of any Business Combination have, or the consideration to be received for the issuance or transfer of securities by the Corporation or any Subsidiary of the Corporation in any Business Combination has, an aggregate Fair Market Value of $100 million or more, and (4) whether all of the applicable conditions set forth in paragraph I(2) of this Article EIGHTH have been met with respect to any Business Combination. Any determination pursuant to this Article EIGHTH made in good faith shall be binding and conclusive on all parties. V. The directors of the Corporation, when evaluating any proposal or offer which would involve a Business Combination or the merger or consolidation of the Corporation or any of its Subsidiaries with another corporation, the sale of all or substantially all of the assets of the Corporation or any of its Subsidiaries, a tender offer or exchange offer for any capital stock of the Corporation or any of its Subsidiaries or any similar transaction shall give due consideration to all factors they may consider relevant. Such factors may include, without limitation, (a) the adequacy, both in amount and form, of the consideration offered in relation not only to the current market price of the Corporation's outstanding securities, but also the current value of the Corporation in a freely negotiated transaction with other potential acquirers and the Board's estimate of the Corporation's future value (including the unrealized value of its properties, assets and prospects) as an independent going concern, (b) the financial and managerial resources and future prospects of the acquirer, and (c) the legal, economic, environmental, regulatory and social effects of the proposed transaction on the Corporation's and its Subsidiaries' employees, customers, suppliers and other affected persons and entities and on the communities and geographic areas in which the Corporation and its Subsidiaries provide utility service or are located, and in particular, the effect on the Corporation's and its Subsidiaries' ability to safely and reliably meet any public utility obligations at reasonable rates. VI. Nothing herein shall be construed to relieve any Related Person from any fiduciary obligation imposed by law. 3. The foregoing amendments and restatement of the Articles of Incorporation have been duly approved by the Board of Directors of the corporation. 4. The foregoing amendments and restatement of the Articles of Incorporation (other than the omissions required by Section 910 of the California Corporations Code) have been duly approved by the required vote of the shareholders in accordance with Section 902 of the California Corporations Code. The corporation has only one class of shares issued and outstanding which is common stock. The number of outstanding shares entitled to vote with respect to the foregoing amendments is 361,010,299. The number of shares voted in favor of the amendments exceeded the vote required. The percentage vote required for approval of the amendments was more than 50%. We further declare under penalty of perjury under the laws of the State of California that the matters set forth in this certificate are true and correct of our own knowledge. Date: May 4, 2000 /S/ ROBERT D. GLYNN, JR. _____________________________________ ROBERT D. GLYNN, JR. Chairman of the Board, Chief Executive Officer, and President /S/ LESLIE H. EVERETT _____________________________________ LESLIE H. EVERETT Vice President and Corporate Secretary EX-3 3 Bylaws of PG&E Corporation amended as of May 5, 2000 Article I. SHAREHOLDERS. 1. Place of Meeting. All meetings of the shareholders shall be held at the office of the Corporation in the City and County of San Francisco, State of California, or at such other place, within or without the State of California, as may be designated by the Board of Directors. 2. Annual Meetings. The annual meeting of shareholders shall be held each year on a date and at a time designated by the Board of Directors. Written notice of the annual meeting shall be given not less than ten (or, if sent by third-class mail, thirty) nor more than sixty days prior to the date of the meeting to each shareholder entitled to vote thereat. The notice shall state the place, day, and hour of such meeting, and those matters which the Board, at the time of mailing, intends to present for action by the shareholders. Notice of any meeting of the shareholders shall be given by mail or telegraphic or other written communication, postage prepaid, to each holder of record of the stock entitled to vote thereat, at his address, as it appears on the books of the Corporation. At an annual meeting of shareholders, only such business shall be conducted as shall have been properly brought before the annual meeting. To be properly brought before an annual meeting, business must be (i) specified in the notice of the annual meeting (or any supplement thereto) given by or at the direction of the Board, or (ii) otherwise properly brought before the annual meeting by a shareholder. For business to be properly brought before an annual meeting by a shareholder, including the nomination of any person (other than a person nominated by or at the direction of the Board) for election to the Board, the shareholder must have given timely and proper written notice to the Corporate Secretary of the Corporation. To be timely, the shareholder's written notice must be received at the principal executive office of the Corporation not less than forty-five days before the date corresponding to the mailing date of the notice and proxy materials for the prior year's annual meeting of shareholders; provided, however, that if the annual meeting to which the shareholder's written notice relates is to be held on a date that differs by more than thirty days from the date of the last annual meeting of shareholders, the shareholder's written notice to be timely must be so received not later than the close of business on the tenth day following the date on which public disclosure of the date of the annual meeting is made or given to shareholders. To be proper, the shareholder's written notice must set forth as to each matter the shareholder proposes to bring before the annual meeting (a) a brief description of the business desired to be brought before the annual meeting, (b) the name and address of the shareholder as they appear on the Corporation's books, (c) the class and number of shares of the Corporation that are beneficially owned by the shareholder, and (d) any material interest of the shareholder in such business. In addition, if the shareholder's written notice relates to the nomination at the annual meeting of any person for election to the Board, such notice to be proper must also set forth (a) the name, age, business address, and residence address of each person to be so nominated, (b) the principal occupation or employment of each such person, (c) the number of shares of capital stock of the Corporation beneficially owned by each such person, and (d) such other information concerning each such person as would be required under the rules of the Securities and Exchange Commission in a proxy statement soliciting proxies for the election of such person as a Director, and must be accompanied by a consent, signed by each such person, to serve as a Director of the Corporation if elected. Notwithstanding anything in the Bylaws to the contrary, no business shall be conducted at an annual meeting except in accordance with the procedures set forth in this Section. 3. Special Meetings. Special meetings of the shareholders shall be called by the Corporate Secretary or an Assistant Corporate Secretary at any time on order of the Board of Directors, the Chairman of the Board, the Vice Chairman of the Board, the Chairman of the Executive Committee, or the President. Special meetings of the shareholders shall also be called by the Corporate Secretary or an Assistant Corporate Secretary upon the written request of holders of shares entitled to cast not less than ten percent of the votes at the meeting. Such request shall state the purposes of the meeting, and shall be delivered to the Chairman of the Board, the Vice Chairman of the Board, the Chairman of the Executive Committee, the President, or the Corporate Secretary. A special meeting so requested shall be held on the date requested, but not less than thirty-five nor more than sixty days after the date of the original request. Written notice of each special meeting of shareholders, stating the place, day, and hour of such meeting and the business proposed to be transacted thereat, shall be given in the manner stipulated in Article I, Section 2, Paragraph 3 of these Bylaws within twenty days after receipt of the written request. 4. Attendance at Meetings. At any meeting of the shareholders, each holder of record of stock entitled to vote thereat may attend in person or may designate an agent or a reasonable number of agents, not to exceed three to attend the meeting and cast votes for his or her shares. The authority of agents must be evidenced by a written proxy signed by the shareholder designating the agents authorized to attend the meeting and be delivered to the Corporate Secretary of the Corporation prior to the commencement of the meeting. 5. Shareholder Action by Written Consent. Subject to Section 603 of the California Corporations Code, any action which, under any provision of the California Corporations Code, may be taken at any annual or special meeting of shareholders may be taken without a meeting and without prior notice if a consent in writing, setting forth the action so taken, shall be signed by the holders of outstanding shares having not less than the minimum number of votes that would be necessary to authorize or take such action at a meeting at which all shares entitled to vote thereon were present and voted. Any party seeking to solicit written consent from shareholders to take corporate action must deliver a notice to the Corporate Secretary of the Corporation which requests the Board of Directors to set a record date for determining shareholders entitled to give such consent. Such written request must set forth as to each matter the party proposes for shareholder action by written consents (a) a brief description of the matter and (b) the class and number of shares of the Corporation that are beneficially owned by the requesting party. Within ten days of receiving the request in the proper form, the Board shall set a record date for the taking of such action by written consent in accordance with California Corporations Code Section 701 and Article IV, Section 1 of these Bylaws. If the Board fails to set a record date within such ten-day period, the record date for determining shareholders entitled to give the written consent for the matters specified in the notice shall be the day on which the first written consent is given in accordance with California Corporations Code Section 701. Each written consent delivered to the Corporation must set forth (a) the action sought to be taken, (b) the name and address of the shareholder as they appear on the Corporation's books, (c) the class and number of shares of the Corporation that are beneficially owned by the shareholder, (d) the name and address of the proxyholder authorized by the shareholder to give such written consent, if applicable, and (d) any material interest of the shareholder or proxyholder in the action sought to be taken. Consents to corporate action shall be valid for a maximum of sixty days after the date of the earliest dated consent delivered to the Corporation. Consents may be revoked by written notice (i) to the Corporation, (ii) to the shareholder or shareholders soliciting consents or soliciting revocations in opposition to action by consent proposed by the Corporation (the "Soliciting Shareholders"), or (iii) to a proxy solicitor or other agent designated by the Corporation or the Soliciting Shareholders. Within three business days after receipt of the earliest dated consent solicited by the Soliciting Shareholders and delivered to the Corporation in the manner provided in California Corporations Code Section 603 or the determination by the Board of Directors of the Corporation that the Corporation should seek corporate action by written consent, as the case may be, the Corporate Secretary shall engage nationally recognized independent inspectors of elections for the purpose of performing a ministerial review of the validity of the consents and revocations. The cost of retaining inspectors of election shall be borne by the Corporation. Consents and revocations shall be delivered to the inspectors upon receipt by the Corporation, the Soliciting Shareholders or their proxy solicitors, or other designated agents. As soon as consents and revocations are received, the inspectors shall review the consents and revocations and shall maintain a count of the number of valid and unrevoked consents. The inspectors shall keep such count confidential and shall not reveal the count to the Corporation, the Soliciting Shareholder or their representatives, or any other entity. As soon as practicable after the earlier of (i) sixty days after the date of the earliest dated consent delivered to the Corporation in the manner provided in California Corporations Code Section 603, or (ii) a written request therefor by the Corporation or the Soliciting Shareholders (whichever is soliciting consents), notice of which request shall be given to the party opposing the solicitation of consents, if any, which request shall state that the Corporation or Soliciting Shareholders, as the case may be, have a good faith belief that the requisite number of valid and unrevoked consents to authorize or take the action specified in the consents has been received in accordance with these Bylaws, the inspectors shall issue a preliminary report to the Corporation and the Soliciting Shareholders stating: (a) the number of valid consents, (b) the number of valid revocations, (c) the number of valid and unrevoked consents, (d) the number of invalid consents, (e) the number of invalid revocations, and (f) whether, based on their preliminary count, the requisite number of valid and unrevoked consents has been obtained to authorize or take the action specified in the consents. Unless the Corporation and the Soliciting Shareholders shall agree to a shorter or longer period, the Corporation and the Soliciting Shareholders shall have forty-eight hours to review the consents and revocations and to advise the inspectors and the opposing party in writing as to whether they intend to challenge the preliminary report of the inspectors. If no written notice of an intention to challenge the preliminary report is received within forty-eight hours after the inspectors' issuance of the preliminary report, the inspectors shall issue to the Corporation and the Soliciting Shareholders their final report containing the information from the inspectors' determination with respect to whether the requisite number of valid and unrevoked consents was obtained to authorize and take the action specified in the consents. If the Corporation or the Soliciting Shareholders issue written notice of an intention to challenge the inspectors' preliminary report within forty-eight hours after the issuance of that report, a challenge session shall be scheduled by the inspectors as promptly as practicable. A transcript of the challenge session shall be recorded by a certified court reporter. Following completion of the challenge session, the inspectors shall as promptly as practicable issue their final report to the Soliciting Shareholders and the Corporation, which report shall contain the information included in the preliminary report, plus all changes in the vote totals as a result of the challenge and a certification of whether the requisite number of valid and unrevoked consents was obtained to authorize or take the action specified in the consents. A copy of the final report of the inspectors shall be included in the book in which the proceedings of meetings of shareholders are recorded. Unless the consent of all shareholders entitled to vote have been solicited in writing, the Corporation shall give prompt notice to the shareholders in accordance with California Corporations Code Section 603 of the results of any consent solicitation or the taking of the corporate action without a meeting and by less than unanimous written consent. Article II. DIRECTORS. 1. Number. As stated in paragraph I of Article Third of this Corporation's Articles of Incorporation, the Board of Directors of this Corporation shall consist of such number of directors, not less than seven (7) nor more than thirteen (13). The exact number of directors shall be eleven (11) until changed, within the limits specified above, by an amendment to this Bylaw duly adopted by the Board of Directors or the shareholders. 2. Powers. The Board of Directors shall exercise all the powers of the Corporation except those which are by law, or by the Articles of Incorporation of this Corporation, or by the Bylaws conferred upon or reserved to the shareholders. 3. Executive Committee. There shall be an Executive Committee of the Board of Directors consisting of the Chairman of the Committee, the Chairman of the Board, if these offices be filled, the President, and four Directors who are not officers of the Corporation. The members of the Committee shall be elected, and may at any time be removed, by a two-thirds vote of the whole Board. The Executive Committee, subject to the provisions of law, may exercise any of the powers and perform any of the duties of the Board of Directors; but the Board may by an affirmative vote of a majority of its members withdraw or limit any of the powers of the Executive Committee. The Executive Committee, by a vote of a majority of its members, shall fix its own time and place of meeting, and shall prescribe its own rules of procedure. A quorum of the Committee for the transaction of business shall consist of three members. 4. Time and Place of Directors' Meetings. Regular meetings of the Board of Directors shall be held on such days and at such times and at such locations as shall be fixed by resolution of the Board, or designated by the Chairman of the Board or, in his absence, the Vice Chairman of the Board, or the President of the Corporation and contained in the notice of any such meeting. Notice of meetings shall be delivered personally or sent by mail or telegram at least seven days in advance. 5. Special Meetings. The Chairman of the Board, the Vice Chairman of the Board, the Chairman of the Executive Committee, the President, or any five directors may call a special meeting of the Board of Directors at any time. Notice of the time and place of special meetings shall be given to each Director by the Corporate Secretary. Such notice shall be delivered personally or by telephone to each Director at least four hours in advance of such meeting, or sent by first-class mail or telegram, postage prepaid, at least two days in advance of such meeting. 6. Quorum. A quorum for the transaction of business at any meeting of the Board of Directors shall consist of six members. 7. Action by Consent. Any action required or permitted to be taken by the Board of Directors may be taken without a meeting if all Directors individually or collectively consent in writing to such action. Such written consent or consents shall be filed with the minutes of the proceedings of the Board of Directors. 8. Meetings by Conference Telephone. Any meeting, regular or special, of the Board of Directors or of any committee of the Board of Directors, may be held by conference telephone or similar communication equipment, provided that all Directors participating in the meeting can hear one another. Article III. OFFICERS. 1. Officers. The officers of the Corporation shall be a Chairman of the Board, a Vice Chairman of the Board, a Chairman of the Executive Committee (whenever the Board of Directors in its discretion fills these offices), a President, a Chief Financial Officer, a General Counsel, one or more Vice Presidents, a Corporate Secretary and one or more Assistant Corporate Secretaries, a Treasurer and one or more Assistant Treasurers, and a Controller, all of whom shall be elected by the Board of Directors. The Chairman of the Board, the Vice Chairman of the Board, the Chairman of the Executive Committee, and the President shall be members of the Board of Directors. 2. Chairman of the Board. The Chairman of the Board, if that office be filled, shall preside at all meetings of the shareholders and of the Directors, and shall preside at all meetings of the Executive Committee in the absence of the Chairman of that Committee. He shall be the chief executive officer of the Corporation if so designated by the Board of Directors. He shall have such duties and responsibilities as may be prescribed by the Board of Directors or the Bylaws. The Chairman of the Board shall have authority to sign on behalf of the Corporation agreements and instruments of every character, and, in the absence or disability of the President, shall exercise the President's duties and responsibilities. 3. Vice Chairman of the Board. The Vice Chairman of the Board, if that office be filled, shall have such duties and responsibilities as may be prescribed by the Board of Directors, the Chairman of the Board, or the Bylaws. He shall be the chief executive officer of the Corporation if so designated by the Board of Directors. In the absence of the Chairman of the Board, he shall preside at all meetings of the Board of Directors and of the shareholders; and, in the absence of the Chairman of the Executive Committee and the Chairman of the Board, he shall preside at all meetings of the Executive Committee. The Vice Chairman of the Board shall have authority to sign on behalf of the Corporation agreements and instruments of every character. 4. Chairman of the Executive Committee. The Chairman of the Executive Committee, if that office be filled, shall preside at all meetings of the Executive Committee. He shall aid and assist the other officers in the performance of their duties and shall have such other duties as may be prescribed by the Board of Directors or the Bylaws. 5. President. The President shall have such duties and responsibilities as may be prescribed by the Board of Directors, the Chairman of the Board, or the Bylaws. He shall be the chief executive officer of the Corporation if so designated by the Board of Directors. If there be no Chairman of the Board, the President shall also exercise the duties and responsibilities of that office. The President shall have authority to sign on behalf of the Corporation agreements and instruments of every character. 6. Chief Financial Officer. The Chief Financial Officer shall be responsible for the overall management of the financial affairs of the Corporation. He shall render a statement of the Corporation's financial condition and an account of all transactions whenever requested by the Board of Directors, the Chairman of the Board, the Vice Chairman of the Board, or the President. The Chief Financial Officer shall have such other duties as may from time to time be prescribed by the Board of Directors, the Chairman of the Board, the Vice Chairman of the Board, the President, or the Bylaws. 7. General Counsel. The General Counsel shall be responsible for handling on behalf of the Corporation all proceedings and matters of a legal nature. He shall render advice and legal counsel to the Board of Directors, officers, and employees of the Corporation, as necessary to the proper conduct of the business. He shall keep the management of the Corporation informed of all significant developments of a legal nature affecting the interests of the Corporation. The General Counsel shall have such other duties as may from time to time be prescribed by the Board of Directors, the Chairman of the Board, the Vice Chairman of the Board, the President, or the Bylaws. 8. Vice Presidents. Each Vice President, if those offices are filled, shall have such duties and responsibilities as may be prescribed by the Board of Directors, the Chairman of the Board, the Vice Chairman of the Board, the President, or the Bylaws. Each Vice President's authority to sign agreements and instruments on behalf of the Corporation shall be as prescribed by the Board of Directors. The Board of Directors, the Chairman of the Board, the Vice Chairman of the Board, or the President may confer a special title upon any Vice President. 9. Corporate Secretary. The Corporate Secretary shall attend all meetings of the Board of Directors and the Executive Committee, and all meetings of the shareholders, and he shall record the minutes of all proceedings in books to be kept for that purpose. He shall be responsible for maintaining a proper share register and stock transfer books for all classes of shares issued by the Corporation. He shall give, or cause to be given, all notices required either by law or the Bylaws. He shall keep the seal of the Corporation in safe custody, and shall affix the seal of the Corporation to any instrument requiring it and shall attest the same by his signature. The Corporate Secretary shall have such other duties as may be prescribed by the Board of Directors, the Chairman of the Board, the Vice Chairman of the Board, the President, or the Bylaws. The Assistant Corporate Secretaries shall perform such duties as may be assigned from time to time by the Board of Directors, the Chairman of the Board, the Vice Chairman of the Board, the President, or the Corporate Secretary. In the absence or disability of the Corporate Secretary, his duties shall be performed by an Assistant Corporate Secretary. 10. Treasurer. The Treasurer shall have custody of all moneys and funds of the Corporation, and shall cause to be kept full and accurate records of receipts and disbursements of the Corporation. He shall deposit all moneys and other valuables of the Corporation in the name and to the credit of the Corporation in such depositaries as may be designated by the Board of Directors or any employee of the Corporation designated by the Board of Directors. He shall disburse such funds of the Corporation as have been duly approved for disbursement. The Treasurer shall perform such other duties as may from time to time be prescribed by the Board of Directors, the Chairman of the Board, the Vice Chairman of the Board, the President, the Chief Financial Officer, or the Bylaws. The Assistant Treasurers shall perform such duties as may be assigned from time to time by the Board of Directors, the Chairman of the Board, the Vice Chairman of the Board, the President, the Chief Financial Officer, or the Treasurer. In the absence or disability of the Treasurer, his duties shall be performed by an Assistant Treasurer. 11. Controller. The Controller shall be responsible for maintaining the accounting records of the Corporation and for preparing necessary financial reports and statements, and he shall properly account for all moneys and obligations due the Corporation and all properties, assets, and liabilities of the Corporation. He shall render to the officers such periodic reports covering the result of operations of the Corporation as may be required by them or any one of them. The Controller shall have such other duties as may from time to time be prescribed by the Board of Directors, the Chairman of the Board, the Vice Chairman of the Board, the President, the Chief Financial Officer, or the Bylaws. He shall be the principal accounting officer of the Corporation, unless another individual shall be so designated by the Board of Directors. Article IV. MISCELLANEOUS. 1. Record Date. The Board of Directors may fix a time in the future as a record date for the determination of the shareholders entitled to notice of and to vote at any meeting of shareholders, or entitled to receive any dividend or distribution, or allotment of rights, or to exercise rights in respect to any change, conversion, or exchange of shares. The record date so fixed shall be not more than sixty nor less than ten days prior to the date of such meeting nor more than sixty days prior to any other action for the purposes for which it is so fixed. When a record date is so fixed, only shareholders of record on that date are entitled to notice of and to vote at the meeting, or entitled to receive any dividend or distribution, or allotment of rights, or to exercise the rights, as the case may be. 2. Transfers of Stock. Upon surrender to the Corporate Secretary or Transfer Agent of the Corporation of a certificate for shares duly endorsed or accompanied by proper evidence of succession, assignment, or authority to transfer, and payment of transfer taxes, the Corporation shall issue a new certificate to the person entitled thereto, cancel the old certificate, and record the transaction upon its books. Subject to the foregoing, the Board of Directors shall have power and authority to make such rules and regulations as it shall deem necessary or appropriate concerning the issue, transfer, and registration of certificates for shares of stock of the Corporation, and to appoint and remove Transfer Agents and Registrars of transfers. 3. Lost Certificates. Any person claiming a certificate of stock to be lost, stolen, mislaid, or destroyed shall make an affidavit or affirmation of that fact and verify the same in such manner as the Board of Directors may require, and shall, if the Board of Directors so requires, give the Corporation, its Transfer Agents, Registrars, and/or other agents a bond of indemnity in form approved by counsel, and in amount and with such sureties as may be satisfactory to the Corporate Secretary of the Corporation, before a new certificate may be issued of the same tenor and for the same number of shares as the one alleged to have been lost, stolen, mislaid, or destroyed. Article V. AMENDMENTS. 1. Amendment by Shareholders. Except as otherwise provided by law, these Bylaws, or any of them, may be amended or repealed or new Bylaws adopted by the affirmative vote of a majority of the outstanding shares entitled to vote at any regular or special meeting of the shareholders. 2. Amendment by Directors. To the extent provided by law, these Bylaws, or any of them, may be amended or repealed or new Bylaws adopted by resolution adopted by a majority of the members of the Board of Directors. EX-10 4 Exhibit 10 March 16, 2000 Mr. Thomas B. King PG&E Gas Transmission Corporation 1100 Louisiana, 10th Floor Houston, TX 77002 Dear Tom: Consistent with our recent discussions, I am pleased to confirm the relocation arrangements and other compensation items which the PG&E National Energy Group will provide to you in connection with your relocation from Houston, Texas, to Bethesda, Maryland. The relocation benefits will be as provided under our existing relocation plan, with the following modifications: 1. A moving allowance equal to one month's pay. 2. Reimbursement for travel expenses incurred in finding a principal residence in the Bethesda area, without a limitation on the number of trips required. Under the relocation plan, you also will be reimbursed for the reasonable cost of temporary housing, which, subject to my prior approval, can be extended beyond the period provided under the plan. 3. Reimbursement of all closing costs incurred in the sale of your existing residence and the purchase of a new residence. The relocation plan also will indemnify you for any loss that you may suffer on the sale of your existing residence. 4. The plan will provide for the reimbursement of any tuition loss which you incur as a result of your children changing schools, as well as enrollment and application fees, testing, and school travel costs incurred in placing your children in comparable schools in the Bethesda area. 5. You also will be provided with a temporary mortgage buy-down of $3,500 per month, payable for four years, commencing with the first mortgage payment for your new residence. Should you voluntarily resign from employment with PG&E Corporation or one of its subsidiaries or affiliates prior to December 31, 2004, you will be required to repay all amounts provided to you under the temporary mortgage buy-down. In addition to continuation of your current compensation and benefit package, and in recognition of the additional expenses associated with your relocation at our request to Bethesda, you also will receive a one-time payment of $150,000, net of taxes, and a one-time taxable payment of $75,000. Should you voluntarily resign from your position and Mr. Thomas B. King March 16, 2000 Page 2 no longer be employed by PG&E Corporation or one of its subsidiaries or affiliates prior to December 31, 2004, you will be required to repay the gross amount of this payment. Inasmuch as this payment is considered to be additional compensation, payment is conditioned on approval by PG&E Corporation's Nominating and Compensation Committee. I believe that this captures the key points of our discussions concerning relocation and compensation benefits. If so, would you please sign in the space provided below, and return the signed original to Brent Stanley. Should you have any questions, please feel free to discuss with Brent Stanley. Tom, I'm very pleased with the progress which the key officer team has made in the last few months in shaping the future strategy of the PG&E National Energy Group. I also understand and appreciate your commitment to making a success of this strategy, and look forward to working with you. Sincerely, /s/ Thomas G. Boren TGB:dah cc: G. Brent Stanley /s/ Thomas B. King _________________________ Thomas B. King EX-11 5 EXHIBIT 11 PG&E CORPORATION COMPUTATION OF EARNINGS PER COMMON SHARE
- ----------------------------------------------------------------------------------------- Three Months Ended March 31, ---------------------------------- (in millions, except per share amounts) 2000 1999 - ----------------------------------------------------------------------------------------- BASIC EARNINGS PER SHARE (EPS) (1) Earnings available for common stock $ 280 $ 171 ======== ======== Average common shares outstanding 361 373 ======== ======== Basic EPS $ .78 $ .46 ======== ======== DILUTED EARNINGS PER SHARE (EPS) (1) Earnings available for common stock $ 280 $ 171 Less: assumed cash settlement of forward contract that may be settled in Company stock or cash - 19 -------- -------- Earnings available for common stock as adjusted 280 152 ======== ======== Average common shares outstanding 361 373 Add: outstanding options, reduced by the number of shares that could be repurchased with the proceeds from such exercise (at average market price) 1 2 -------- -------- Average common shares outstanding as adjusted 362 375 ======== ======== Diluted EPS $ .77 $ .40 ======== ======== - ----------------------------------------------------------------------------------------- (1) This presentation is submitted in accordance with Item 601(b)(11) of Regulation S-K and Statement of Financial Accounting Standards No. 128.
EX-12 6 EXHIBIT 12.1 PACIFIC GAS AND ELECTRIC COMPANY COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES
- --------------------------------------------------------------------------------------------------- Three months Year ended December 31, ended ------------------------------------------------------- (dollars in millions) March 31, 2000 1999 1998 1997 1996 1995 - --------------------------------------------------------------------------------------------------- Earnings: Net income $ 234 $ 788 $ 729 $ 768 $ 755 $ 1,339 Adjustments for minority interests in losses of less than 100% owned affiliates and the Company's equity in undistributed losses (income) of less than 50% owned affiliates - - - - 3 4 Income tax expense 200 648 629 609 555 895 Net fixed charges 150 637 673 628 683 716 -------- -------- -------- -------- -------- -------- Total Earnings $ 584 $ 2,073 $ 2,031 $ 2,005 $ 1,996 $ 2,954 ======== ======== ======== ======== ======== ======== Fixed Charges: Interest on long- term debt, net $ 124 $ 523 $ 585 $ 485 $ 574 $ 616 Interest on short- term borrowings 19 81 50 101 75 83 Interest on capital leases - 2 2 2 3 3 AFUDC debt 1 8 12 17 8 11 Earnings required to cover the preferred stock dividend and preferred security distribution requirements of majority owned trust 6 24 24 24 24 3 -------- -------- -------- -------- -------- -------- Total Fixed Charges $ 150 $ 638 $ 673 $ 629 $ 684 $ 716 ======== ======== ======== ======== ======== ======== Ratios of Earnings to Fixed Charges 3.89 3.25 3.02 3.19 2.92 4.13 - ---------------------------------------------------------------------------------------------------- Note: For the purpose of computing Pacific Gas and Electric Company's ratios of earnings to fixed charges, "earnings" represent net income adjusted for the minority interest in losses of less than 100% owned affiliates, cash distributions from and equity in undistributed income or loss of Pacific Gas and Electric Company's less than 50% owned affiliates, income taxes and fixed charges (excluding capitalized interest). "Fixed charges" include interest on long-term debt and short-term borrowings (including a representative portion of rental expense), amortization of bond premium, discount and expense, interest of subordinated debentures held by trust, interest on capital leases, and earnings required to cover the preferred stock dividend requirements.
EX-12 7 EXHIBIT 12.2 PACIFIC GAS AND ELECTRIC COMPANY COMPUTATION OF RATIOS OF EARNINGS TO COMBINED FIXED CHARGES AND PREFERRED STOCK DIVIDENDS - ---------------------------------------------------------------------------------------------------- Three months Year ended December 31, ended ------------------------------------------------------- (dollars in millions) March 31, 2000 1999 1998 1997 1996 1995 - ---------------------------------------------------------------------------------------------------- Earnings: Net income $ 234 $ 788 $ 729 $ 768 $ 755 $ 1,339 Adjustments for minority interests in losses of less than 100% owned affiliates and the Company's equity in undistributed losses (income) of less than 50% owned affiliates - - - - 3 4 Income tax expense 200 648 629 609 555 895 Net fixed charges 150 637 673 628 683 716 -------- -------- -------- -------- -------- -------- Total Earnings $ 584 $ 2,073 $ 2,031 $ 2,005 $ 1,996 $ 2,954 ======== ======== ======== ======== ======== ======== Fixed Charges: Interest on long- term debt, net $ 124 $ 523 $ 585 $ 485 $ 574 $ 616 Interest on short term borrowings 19 81 50 101 75 83 Interest on capital leases - 3 2 2 3 3 AFUDC debt 1 7 12 17 8 11 Earnings required to cover the preferred stock dividend and preferred security distribution requirements of majority owned trust 6 24 24 24 24 3 -------- -------- -------- -------- -------- -------- Total Fixed Charges $ 150 $ 638 $ 673 $ 629 $ 684 $ 716 -------- -------- -------- -------- -------- -------- Preferred Stock Dividends: Tax deductible dividends $ 2 $ 9 $ 9 $ 10 $ 10 $ 11 Pretax earnings required to cover non-tax deductible preferred stock dividend requirements 7 27 31 39 39 100 -------- -------- -------- -------- -------- -------- Total Preferred Stock Dividends $ 9 $ 36 $ 40 $ 49 $ 49 $ 111 -------- -------- -------- -------- -------- -------- Total Combined Fixed Charges and Preferred Stock Dividends $ 159 $ 674 $ 713 $ 678 $ 733 $ 827 ======== ======== ======== ======== ======== ======== Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividends 3.67 3.08 2.85 2.96 2.72 3.57 - ---------------------------------------------------------------------------------------------------- Note: For the purpose of computing Pacific Gas and Electric Company's ratios of earnings to combined fixed charges and preferred stock dividends, "earnings" represent net income adjusted for the minority interest in losses of less than 100% owned affiliates, cash distributions from and equity in undistributed income or loss of Pacific Gas and Electric Company's less than 50% owned affiliates, income taxes and fixed charges (excluding capitalized interest). "Fixed charges" include interest on long-term debt and short-term borrowings (including a representative portion of rental expense), amortization of bond premium, discount and expense, interest on capital leases, interest of subordinated debentures held by trust, and earnings required to cover the preferred stock dividend requirements of majority owned subsidiaries. "Preferred stock dividends" represent pretax earnings which would be required to cover such dividend requirements.
EX-27 8
UT THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM PG&E CORPORATION AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS. 1,000,000 3-MOS DEC-31-2000 JAN-01-2000 MAR-31-2000 PER-BOOK 16,644 3,954 3,399 3,326 1,873 29,196 5,226 0 1,861 7,087 780 0 6,468 952 0 0 672 0 0 0 13,237 29,196 5,008 228 4,332 4,332 676 15 691 183 280 0 280 108 79 919 0.78 0.77
EX-27 9
UT THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM PACIFIC GAS AND ELECTRIC COMPANY AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS. 01 PACIFIC GAS AND ELECTRIC COMPANY 1,000,000 3-MOS DEC-31-2000 JAN-01-2000 MAR-31-2000 PER-BOOK 12,646 0 1,626 3,174 3,911 21,357 3,377 0 2,213 5,590 437 287 4,767 209 0 0 549 0 0 0 9,518 21,357 2,218 200 1,648 1,648 570 5 575 141 234 6 228 108 79 690 0.00 0.00
-----END PRIVACY-ENHANCED MESSAGE-----