SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-Q/A Amendment No. 1 to (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, 2001 OR [_] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from _________to _________
(Mark One)
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C., 20549
FORM 10-Q/AAmendment No. 1 to
[X]
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15 (D) OF THE
SECURITIES EXCHANGE ACT OF 1934For the quarterly period ended March 31, 2002
OR[ ]
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934For the transition period from ___________ to __________
Commission
File
Number
_______________Exact Name of
Commission
Registrant
as specified
in its charter
_______________
State or other
Jurisdiction of
Incorporation
______________
IRS EmployerFile as specified Jurisdiction of
Identification
Numberin its charter Incorporation Number - ----------------------------------------------------------------------------------------------------------------------
___________1-12609
PG&E Corporation
California
California94-3234914
1-2348
California
94-0742640
Pacific Gas and Electric Company
PG&E Corporation
77 Beale Street
P.O. Box 770000
San Francisco, California 94177
________________________________________PG&E Corporation
One Market, Spear TowerP.O. Box 770000
Suite 2400San Francisco, California 94177
San Francisco, California 94105(Address
______________________________________(Address of principal executive offices)
(Zip(Zip Code)
Pacific Gas and Electric Company
(415) 973-7000
________________________________________PG&E Corporation
(415) 973-7000
(415) 267-7000- ----------------------------------------------------------------------------------------------------------------------Registrant's telephone number, including area code
______________________________________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 latest practicable date.
Common Stock Outstanding, April 26, 2002:
PG&E Corporation
389,405,450 shares
Pacific Gas and Electric Company
Wholly-owned by PG&E Corporation
INTRODUCTORY NOTEThis Amendment No. 1 to theregistrants (1) havethe Quarterly Report on Form 10-Q filedall reports required to be filedbySection 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 latest practicable date. Common Stock Outstanding April 30, 2001:PG&E Corporation387,135,242 sharesand Pacific Gas and Electric CompanyWholly owned by PG&E Corporation 1INTRODUCTORY NOTE PG&E Corporation has previously disclosed that its subsidiary, PG&E National Energy Group, Inc. (PG&E NEG), has used "synthetic leases" in connection with some of its power plant projects and turbine acquisition commitments. Subsequent to the issuance of PG&E Corporation's 1999 and 2000 Consolidated Financial Statements, management determined that the assets and liabilities associated with these leases should have been consolidated. This Amendment No. 1 to PG&E Corporation's and Pacific Gas and Electric Company's joint Quarterly Report on Form 10-Q/A(Utility) for the quarter ended March 31,2001, contains revised Consolidated Financial Statements2002, amends and restates in its entirety Part II, Item 4 (Submission of Matters to a Vote of Security Holders) to report the number of broker non-votes cast on five management proposals submitted to Utility shareholders for approval at the 2002 joint annual meeting of shareholders of PG&E Corporationforand thequarters ended March 31, 2001 and 2000. To reflectUtility held on April 17, 2002. The broker non-votes were omitted from therevisions, this Amendment No. 1 hereby amends Part I. Financial Informationoriginal report. The inclusion of theoriginal filing.broker non-votes does not affect whether these management proposals (identified as items five through nine in the joint proxy statement) were approved by the Utility’s shareholders. Each of the five proposals requested approval of amendments to the Utility’s articles of incorporation, and therefore required approval from a majority of the Utility’s outstanding voting stock. The number of affirmative votes required to approve the proposals was fixed as of the record date, and the results are unaffected by the number of votes cast against the proposals, abstentions, or broker non-votes.Although the full text ofthe amended Form 10-QPart II, Item 4 is contained herein, this Amendment No. 1 does not updatePart II, nor does thisinformation for any of the matters submitted for vote to PG&E Corporation’s shareholders or any other matters submitted for vote to the Utility’s shareholders. This Amendment No. 1 also does not update any other disclosures to reflect developments since the original date of filing.PART II. OTHER INFORMATION
Item 4. Submission of Matters to a Vote of Security HoldersPG&E Corporation:
On April 17, 2002, 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 (included as Item 1 in proxy statement):
For
Withheld
---------------
-------------
David R. Andrews
248,913,345
8,039,086
David A. Coulter
250,099,590
6,852,841
C. Lee Cox
248,955,573
7,996,858
William S. Davila
249,049,141
7,903,290
Robert D. Glynn, Jr.
250,437,192
6,515,239
David M. Lawrence, MD
250,383,063
6,569,368
Mary S. Metz
249,010,480
7,941,951
Carl E. Reichardt
250,443,456
6,508,975
Barry Lawson Williams
248,991,827
7,960,604
2. Ratification of the appointment of Deloitte & Touche LLP as independent public accountants for 2002 (included as Item 2 in proxy statement):
For:
238,798,417
Against:
15,350,850
Abstain:
2,803,164
Theexhibitsproposal was approved by a majority of the shares represented and voting (including abstentions) with respect to this proposal, which shares voting affirmatively also constituted a majority of the required quorum.3. Management proposal regarding a proposed amendment to PG&E Corporation's Articles of Incorporation to implement enhancement of simple majority voting (included as Item 3 in proxy statement):
For:
191,591,222
Against:
15,982,892
Abstain:
3,506,688
Broker non-vote (1):
45,871,629
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 and Bylaws to reduce the authorized range of directors and delete from the Bylaws the provision that
were filedrestates the authorized range of directors as set forth in the Articles of Incorporation (included as Item 4 in proxy statement):
For:
247,259,121
Against:
5,835,720
Abstain:
3,857,590
Broker non-vote (1):
0
The proposal was approved by a majority of the outstanding shares.
5. Consideration of a shareholder proposal regarding independent directors (included as Item 10 in proxy statement):
For:
63,085,072
Against:
140,397,397
Abstain:
7,598,333
Broker non-vote (1):
45,871,629
This shareholder proposal was defeated, as the number of shares voting affirmatively on the proposal constituted less than a majority of the shares represented and voting (including abstentions but excluding broker non-votes) withthe original filing have not been re-filed with this amendment but instead have been incorporated by referencerespect to theoriginal filing. 2PG&E CORPORATION AND PACIFIC GAS AND ELECTRIC COMPANY Form 10-Q/A FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2001 TABLE OF CONTENTSproposal.6. Consideration of a shareholder proposal regarding poison pills (Shareholder Rights Plan) (included as Item 11 in proxy statement):
PART I. FINANCIAL INFORMATION PAGEITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS PG&E CORPORATION REVISED CONDENSED STATEMENTS OF CONSOLIDATED OPERATIONS 4 REVISED CONDENSED CONSOLIDATED BALANCE SHEETS 5 REVISED STATEMENTS OF CONDENSED CONSOLIDATED CASH FLOWS 7 PACIFIC GAS AND ELECTRIC COMPANY CONDENSED STATEMENTS OF CONSOLIDATED OPERATIONS 8 CONDENSED CONSOLIDATED BALANCE SHEETS 9 STATEMENTS OF CONDENSED CONSOLIDATED CASH FLOWS 11 NOTE 1: GENERAL 12 NOTE 2: THE CALIFORNIA ENERGY CRISIS 15 NOTE 3: LONG-TERM DEBT 24 NOTE 4: BANKRUPTCY FILING 25 NOTE 5: RINGFENCING 26 NOTE 6: PRICE RISK MANAGEMENT 27 NOTE 7: UTILITY OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES OF TRUST HOLDING SOLELY UTILITY SUBORDINATED DEBENTURES 28 NOTE 8: COMMITMENTS & CONTINGENCIES 29 NOTE 9: SEGMENT INFORMATION 33 NOTE 10: REVISION FOOTNOTE 35 ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS 36 LIQUIDITY AND FINANCIAL 38 STATEMENT OF CASH FLOWS 41 RESULTS OF OPERATIONS 44 REGULATORY MATTERS 49 ENVIRONMENTAL MATTERS 51 PRICE RISK MANAGEMENT ACTIVITIES 53 LEGAL MATTERS 56 ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES 57 ABOUT MARKET RISK PART II. OTHER INFORMATION ITEM 1. LEGAL PROCEEDINGS 58 ITEM 2. CHANGES IN SECURITIES AND USE OF PROCEEDS 61 ITEM 3. DEFAULTS UPON SENIOR SECURITIES 61 ITEM 5. OTHER INFORMATION 62 ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K 63 SIGNATURE 66For:
136,698,687
Against:
68,676,772
Abstain:
5,705,343
Broker non-vote (1):
45,871,629
3PART I. FINANCIAL INFORMATION ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS --------------------------------------------------- PG&E CORPORATION CONDENSED STATEMENTS OF CONSOLIDATED OPERATIONS (in millions, except per share amounts) ForThis shareholder proposal was approved, as the
three months ended March 31, 2001 2000 ---- ---- (As revised, see Note 10) Operating Revenues Utility $ 2,562 $2,218 Energy commoditiesnumber of shares voting affirmatively on the proposal constituted more than a majority of the shares represented andservices 4,111 2,784 ------- ------ Total operating revenues 6,673 5,002 Operating Expenses Cost of energy for utility 3,343 796 Cost of energy commodities and services 3,839 2,472 Operating and maintenance 728 711 Depreciation, amortization, and decommissioning 103 347 ------- ------ Total operating expenses 8,013 4,326 ------- ------ Operating Income (Loss) (1,340) 676 Interest income 35 24 Interest expense (247) (183) Other income (expense), net (9) (9) ------- ------ Income (Loss) Before Income Taxes (1,561) 508 Income tax provision (benefit) (610) 228 ------- ------ Net Income (Loss) $ (951) $ 280 ======= ====== Weighted average common shares outstanding 363 361 Earnings (Loss) Per Common Share, Basic Net Earnings (Loss) $ (2.62) $ .78 ======= ====== Earnings (Loss) Per Common Share, Diluted Net Earnings (Loss) $ (2.62) $ .77 ======= ====== Dividends Declared Per Common Share $ - $ .30 ======= ====== The accompanying Notesvoting (including abstentions but excluding broker non-votes) with respect to theCondensed Consolidated Financial Statements are an integral partproposal, and the affirmative votes also constituted a majority ofthis statement. 4PG&E CORPORATION CONDENSED CONSOLIDATED BALANCE SHEETS (in millions, except share amounts)the required quorum.7. Consideration of a shareholder proposal regarding auditor services (included as Item 12 in proxy statement):
Balance at ---------- March 31, December 31, 2001 2000 ---- ---- (As revised, see Note 10)ASSETS Current Assets Cash and cash equivalents $ 682 $ 925 Short-term investments 2,911 1,634 Accounts receivable: Customers (net of allowance for doubtful accounts of $91 million and $71 million, respectively) 3,030 4,340 Regulatory balancing accounts 34 222 Price risk management assets 3,457 2,039 Inventories 370 392 Income taxes receivable - 1,241 Prepaid expenses and other 902 406 -------- -------- Total current assets 11,386 11,199 Property, Plant, and Equipment Utility 24,030 23,872 Non-utility: Electric generation 2,075 2,008 Gas transmission 1,555 1,542 Construction work in progress 1,852 1,605 Other 117 147 -------- -------- Total property, plant, and equipment (at original cost) 29,629 29,174 Accumulated depreciation and decommissioning (12,073) (11,878) -------- -------- Net property, plant, and equipment 17,556 17,296 Other Noncurrent Assets Regulatory assets 1,821 1,773 Nuclear decommissioning funds 1,328 1,328 Price risk management assets 1,101 2,026 Other 2,873 2,530 -------- -------- Total noncurrent assets 7,123 7,657 -------- -------- TOTAL ASSETS $ 36,065 $ 36,152 ======== ========For:
87,640,402
Against:
100,707,579
Abstain:
22,732,821
Broker non-vote (1):
45,871,629
The accompanying NotesThis shareholder proposal was defeated, as the number of shares voting affirmatively on the proposal constituted less than a majority of the shares represented and voting (including abstentions but excluding broker non-votes) with respect to the
Condensed Consolidated Financial Statements are an integral partproposal.8. Consideration of
this statement. 5PG&E CORPORATION CONDENSED CONSOLIDATED BALANCE SHEETS (in millions, except share amounts)a shareholder proposal regarding the Board of Directors' role (included as Item 13 in proxy statement):
Balance at ---------- March 31, December 31, 2001 2000 ---- ---- (As revised, see Note 10)LIABILITIES AND EQUITY Current Liabilities Short-term borrowings $ 3,586 $ 4,530 Long-term debt, classified as current 2,309 2,391 Current portion of rate reduction bonds 290 290 Accounts payable: Trade creditors 6,299 5,896 Regulatory balancing accounts 579 196 Other 571 459 Price risk management 3,533 1,999 Other 1,739 1,570 Total current liabilities 18,906 17,331 Noncurrent Liabilities Long-term debt 6,606 5,550 Rate reduction bonds 1,665 1,740 Deferred income taxes 951 1,656 Deferred tax credits 182 192 Price risk management 1,354 1,867 Other 3,715 3,864 Total noncurrent liabilities 14,473 14,869 Preferred stock of subsidiaries 480 480 Utility obligated mandatorily redeemable preferred securities of trust holding soley utility subordinated debentures 300 300 Common stockholders' equity Common stock, no par value, authorized 800,000,000 shares, issued 387,183,478 and 387,193,727 shares, respectively 5,971 5,971 Common stock held by subsidiary, at cost, 23,815,500 shares (690) (690) Accumulated deficit (3,056) (2,105) Accumulated other comprehensive loss (319) (4) Total common stockholders' equity 1,906 3,172 Commitments and Contingencies (Notes 1, 2 and 5) - - -------- -------- TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 36,065 $ 36,152For:
28,820,978
Against:
174,507,038
Abstain:
7,752,786
Broker non-vote (1):
45,871,629
The accompanying NotesThis shareholder proposal was defeated, as the number of shares voting affirmatively on the proposal constituted less than a majority of the shares represented and voting (including abstentions but excluding broker non-votes) with respect to the
Condensed Consolidated Financial Statements are an integral partproposal.9. Consideration of
this statement. 6PG&E CORPORATION CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS (in millions)a shareholder proposal regarding radioactive wastes (included as Item 14 in proxy statement):
For the three months ended March 31, 2001 2000 ---- ---- (As revised, see Note 10)Cash Flows From Operating Activities Net income (loss) $ (951) $ 280 Adjustments to reconcile net income (loss) to net cash provided (used) by operating activities: Depreciation, amortization, and decommissioning 103 347 Deferred income taxes and tax credits-net (527) (145) Price risk management assets and liabilities, net 25 (11) Other deferred charges and noncurrent liabilities (149) (9) Net effect of changes in operating assets and liabilities: Short-term investments (1,277) 142 Accounts receivable-trade 1,310 40 Inventories 22 55 Accounts payable 515 (90) Regulatory balancing accounts 571 254 Accrued taxes 1,241 318 Other working capital (217) (118) Other-net 9 26 Net cash provided by operating activities 675 1,089 Cash Flows From Investing Activities Capital expenditures (538) (450) Other-net (147) 81 Net cash used by investing activities (685) (369) Cash Flows From Financing Activities Net repayments under credit facilities (993) (547) Long-term debt issued 1,105 108 Long-term debt matured, redeemed, or repurchased (236) (201) Common stock issued - 10 Dividends paid (109) (108) Other-net - 3 Net cash used by financing activities (233) (735) Net Change in Cash and Cash Equivalents (243) (15) Cash and Cash Equivalents at January 1 925 282 Cash and Cash Equivalents at March 31 $ 682 $ 267 Supplemental disclosures of cash flow information Cash paid for: Interest (net of amounts capitalized) $ 235 $ 119 Income taxes paid (refunded) - net (1,241) 3For:
16,579,938
Against:
181,347,004
Abstain:
13,153,860
Broker non-vote (1):
45,871,629
The accompanying NotesThis shareholder proposal was defeated, as the number of shares voting affirmatively on the proposal constituted less than a majority of the shares represented and voting (including abstentions but excluding broker non-votes) with respect to the
Condensed Consolidated Financial Statements are an integral partproposal.10. Consideration of
this statement. 7PACIFIC GAS AND ELECTRIC COMPANY CONDENSED STATEMENTS OF CONSOLIDATED OPERATIONS (in millions) Fora shareholder proposal regarding confidential voting (included as Item 15 in proxy statement):
For:
62,374,367
Against:
141,389,907
Abstain:
7,316,528
Broker non-vote (1):
45,871,629
This shareholder proposal was defeated, as thethree months ended March 31, 2001 2000 ---- ---- Operating Revenues Electric $1,259 $1,601 Gas 1,303 617 Total operating revenues 2,562 2,218 Operating Expenses Costnumber ofelectric energy 2,427 513 Costshares voting affirmatively on the proposal constituted less than a majority ofgas 916 283 Operatingthe shares represented andmaintenance 574 551 Depreciation, amortization, and decommissioning 65 301 Total operating expenses 3,982 1,648 Operating Income (Loss) (1,420) 570 Interest income 7 6 Interest expense 201 141 Other income (expense), net (4) (1) Income (Loss) Before Income Taxes (1,618) 434 Income tax provision (benefit) (624) 200 Net Income (Loss) (994) 234 Preferred dividend requirement 6 6 Income (Loss) Available for (Allocated to) Common Stock $(1,000) $228 The accompanying Notesvoting (including abstentions but excluding broker non-votes) with respect to theCondensed Consolidated Financial Statements are an integral partproposal.11. Consideration of
this statement. 8PACIFIC GAS AND ELECTRIC COMPANY CONDENSED CONSOLIDATED BALANCE SHEETS (in millions, except share amounts)a shareholder floor proposal introduced at the annual meeting regarding annual disclosure of philanthropic links between the company and its directors was duly and properly conducted by ballot.
Balance at ---------- March 31, December 31, 2001 2000 ---- ----ASSETS Current Assets Cash and cash equivalents $ 154 $ 111 Short-term investments 2,610 1,283 Accounts receivable Customers (net of allowance for doubtful accounts of $53 million and $52 million, respectively) 1,574 1,711 Related parties 5 6 Regulatory balancing account 34 222 Inventories Gas stored underground and fuel oil 151 146 Materials and supplies 133 134 Income taxes receivable - 1,120 Prepaid expenses and other 443 45 Total current assets 5,104 4,778 Property, Plant, and Equipment Electric 16,446 16,335 Gas 7,584 7,537 Construction work in progress 300 249 Total property, plant, and equipment (at original cost) 24,330 24,121 Accumulated depreciation and decommissioning (11,281) (11,120) Net property, plant, and equipment 13,049 13,001 Other noncurrent assets Regulatory assets 1,780 1,716 Nuclear decommissioning funds 1,328 1,328 Other 1,194 1,165 Total noncurrent assets 4,302 4,209 TOTAL ASSETS $ 22,455 $ 21,988For:
17,922
Against:
159,866
Abstain:
0
Broker non-vote (1):
0
The accompanying Notes
This shareholder proposal was defeated, as the number of shares voting affirmatively on the proposal constituted less than a majority of the shares represented and voting (including abstentions but excluding broker non-votes) with respect to theCondensed Consolidated Financial Statements are an integral partproposal.(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 17, 2002, Pacific Gas and Electric Company held its annual meeting ofthis statement. 9PACIFIC GAS AND ELECTRIC COMPANY CONDENSED CONSOLIDATED BALANCE SHEETS (in millions, except share amounts)
Balance at ---------- March 31, December 31, 2001 2000 ---- ----LIABILITIES AND EQUITY Current Liabilities Short-term borrowings $ 3,051 $ 3,079 Long-term debt, classified as current 2,293 2,374 Current portion of rate reduction bonds 290 290 Accounts payable: Trade creditors 5,226 3,688 Related parties 177 138 Regulatory balancing accounts 579 196 Other 365 363 Price risk management 73 - Deferred income taxes - 172 Other 719 670 Total current liabilities 12,773 10,970 Noncurrent Liabilities Long-term debt 3,313 3,342 Rate reduction bonds 1,665 1,740 Deferred income taxes 921 929 Deferred tax credits 182 192 Price risk management 12 - Other 2,796 2,968 Total noncurrent liabilities 8,889 9,171 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 Preferredshareholders. Shares of capital stockwithout mandatory redemption provisions Nonredeemable - 5% to 6%, outstanding 5,784,825 shares 145 145 Redeemable - 4.36% to 7.04%, outstanding 5,973,456 shares 149 149 Common stock, $5 par value, authorized 800,000,000 shares, issued 321,314,760 shares 1,606 1,606 Common stock held by subsidiary, at cost, 19,481,213 shares (475) (475) Additional paid-in capital 1,964 1,964 Accumulated deficit (2,979) (1,979) Accumulated other comprehensive loss (54) - Total stockholders' equity 356 1,410 Commitments and Contingencies (Notes 1, 2, and 5) - - TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $22,455 $21,988The accompanying Notes to the Condensed Consolidated Financial Statements are an integral part of this statement. 10PACIFIC GAS AND ELECTRIC COMPANY CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS (in millions)
For the three months ended March 31, --------------- 2001 2000Cash Flows From Operating Activities Net income (loss) $ (994) $ 234 Adjustments to reconcile net income to net cash (used) provided by operating activities: Depreciation, amortization, and decommissioning 65 301 Deferred income taxes and tax credit-net (170) (48) Price risk management assets and liabilities, net 10 - Other deferred charges and noncurrent liabilities (110) (52) Net effect of changes in operating assets and liabilities: Short-term investments (1,327) (2) Accounts receivable 138 84 Income tax receivable 1,120 - Inventories (4) 45 Accounts payable 1,579 (302) Regulatory balancing accounts 571 254 Other working capital (352) 204 Other-net (6) (30) Net cash provided by operating activities 520 688 Cash Flows From Investing Activities Capital expenditures (284) (265) Other-net 22 54 Net cash used by investing activities (262) (211) Cash Flows From Financing Activities Net repayment under credit facilities (28) (240) Long-term debt matured, redeemed, or repurchased (187) (102) Dividends paid - (122) Other-net - (6) Net cash used by financing activities (215) (470) Net Change in Cash and Cash Equivalents 43 7 Cash and Cash Equivalents at January 1 111 80 Cash and Cash Equivalents at March 31 $ 154 $ 87 Supplemental disclosures of cash flow information Cash paid for: Interest (net of amounts capitalized) $ 109 $ 75 Income taxes paid (refunded) - net (1,120) -The accompanying Notes to the Condensed Consolidated Financial Statements are an integral part of this statement. 11PG&E CORPORATION AND PACIFIC GAS AND ELECTRIC COMPANY NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Note 1: GENERAL Basis of Presentation PG&E Corporation was incorporated in California in 1995 and became the holding companyof Pacific Gas and Electric Company(the Utility) on January 1, 1997. The Utility, incorporated in California in 1905, is the predecessorconsist of shares of common stock and shares of first preferred stock. As PG&ECorporation. Effective with PG&E Corporation's formation, the Utility's interests in its unregulated subsidiaries were transferred to PG&E Corporation. As discussed further in Note 4, on April 6, 2001, the Utility filedCorporation and avoluntary petition for relief under provisions of Chapter 11subsidiary own all of theU.S. Bankruptcy Code. Pursuant to Chapter 11outstanding shares of common stock, they hold approximately 95% of theU.S. Bankruptcy Code, the Utility retains control of its assets and is authorized to operate its business as a debtor in possession while being subject to the jurisdictioncombined voting power of theBankruptcy Court. This Quarterly Report on Form 10-Q/A is a combined reportoutstanding capital stock of Pacific Gas and Electric Company. PG&E Corporation and theUtility. Therefore, the Notes to the 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, the Utility, and PG&E Corporation's wholly owned and controlled subsidiaries. The Utility's condensed consolidated financial statements include its accounts as well as those of its wholly owned and controlled subsidiaries. PG&E Corporation and the Utility believe that the accompanying condensed consolidated financial statements reflect all adjustments that are necessary to present a fair statement of the condensed 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/A. 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 2001 presentation. Results of operations for interim periods are not necessarily indicative of results to be expected for a full year. The Utility's financial position and results of operations are the principal factors affecting PG&E Corporation's consolidated financial position and results of operations. This quarterly report should be read in conjunction with PG&E Corporation's and the Utility's Consolidated Financial Statements and Notes to Consolidated Financial Statements incorporated by reference in their combined 2000 Annual Report on Form 10-K/A, and PG&E Corporation's and the Utility's other reports filed with the Securities and Exchange Commission since their 2000 Form 10-K/A was filed. The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions. These estimates and assumptions affect the reported amounts of revenues, expenses, assets and liabilities and the disclosure of contingencies. Actual results could differ from these estimates. Accounting for Price Risk Management Activities PG&E Corporation, primarily through its subsidiaries, engages in price risk management activities for both trading and non-trading purposes, as described below. Trading Activities - ------------------ 12PG&E Corporation conducts trading activities principally through its subsidiaries owned by PG&E National Energy Group (PG&E NEG). Trading activities are conducted to generate profit, create liquidity, and maintain a market presence. Net open positions (that is, positions that are not hedged) often exist or are established due to the assessment of, and response to changing market conditions. Derivative and other financial instruments associated with electricity, natural gas, natural gas liquids, and related trading activities are accounted for using the mark-to-market method of accounting. Under mark-to-market accounting, PG&E Corporation's trading contracts, including both physical contracts and financial instruments, are recorded at market value, which approximates fair value. The market prices used to value these transactions reflect management's best estimates considering various factors, including market quotes, time value, and volatility factors of the underlying commitments. The values are adjusted to reflect the potential impact of liquidating a position in an orderly manner over a reasonable period of time under present market conditions. Changes in the market value of these contract portfolios, resulting primarily from newly originated transactions and the impact of commodity price or interest rate movements, are recognized in operating income in the period of change. Unrealized gains and losses on these contract portfolios are recorded as assets and liabilities, respectively, from price risk management. Non-Trading Activities - ---------------------- In addition to the trading activities, as discussed previously, PG&E Corporation, principally through the Utility and PG&E NEG, engages in non- trading activities using futures, forward contracts, options, and swaps to hedge the impact of market fluctuations on energy commodity prices, interest rates, and foreign currencies when there is a high degree of correlation between price movements in the derivative and the item designated as being hedged. Non- trading activities are conducted to optimize and secure the return on risk capital deployed within PG&E NEG's existing asset and contractual portfolio. In addition, non-trading activity exists within the Utility to hedge against price fluctuations of electricity and natural gas. Effective January 1, 2001, PG&E Corporation and the Utility adopted Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended by SFAS No. 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities." The Statement, as amended, requires PG&E Corporation and the Utility to recognize all derivatives, as defined in the Statement, on the balance sheet at fair value. Derivatives are included as price risk management assets or price risk management liabilities on the balance sheet. Changes in the fair value of derivatives that do not qualify for hedge accounting treatment, as well as the ineffective portion of a particular hedge, are recognized in current period earnings. Hedge effectiveness is measured based on changes in the fair value over time between the derivative contract and the hedged item. SFAS No. 133 recognizes three types of hedges: fair value hedges, cash flow hedges, and foreign currency hedges. A fair value hedge is a hedge of the exposure to changes in the fair value of a recognized asset or liability or of an unrecognized firm commitment, that are attributable to its fixed terms. If the derivative qualifies and is designated as a fair value hedge, the accounting treatment dictates that the changes in the fair value of the hedging instrument will be offset against the changes in fair value of the hedged assets, liabilities, or firm commitments attributable to the hedged risk and reflected in the income statement in the current period. A cash flow hedge is a hedge of the exposure to variability in the cash flows associated with a recognized asset or liability, or a forecasted transaction that is attributable to changes in variable rates or prices. If the derivative qualifies and is designated as a cash flow hedge, the accounting treatment dictates that the effective portions of the changes in the fair value of the hedging instrument will be recognized in other comprehensive income (loss), a separate component of stockholders' equity during the hedge period and will subsequently be recognized in the income statement when the hedged item affects earnings. Foreign currency hedges may either be classified as fair value or cash flow hedges and are subject to the same accounting guidelines as those described above, as applicable. Only the Utility currently has derivatives designated as fair value hedges. These consist of swaps used to hedge commodity price risk related to purchases of natural gas. Both PG&E Corporation and the Utility currently have 13derivatives designated as cash flow hedges. For PG&E Corporation these consist of interest rate swaps associated with variable rate debt payments used to hedge interest rate risk. Additionally, PG&E Corporation has entered into forward, future, and financial swap contracts for natural gas, fuel oil, and electricity in order to hedge the commodity price risk associated with the generating activities of the unregulated subsidiaries. The Utility's cash flow hedges consist of forwards used to hedge commodity price risk related to natural gas transmission. PG&E Corporation has certain foreign exchange forwards used to economically hedge foreign currency risk associated with future purchases and sales denominated in foreign currencies, and interest rate swaps used to economically hedge interest rate risk, both of which were not designated as accounting hedges. These foreign exchange and interest rate derivative instruments not designated as hedges are accounted for using the mark-to-market method of accounting, which requires that assets and liabilities be valued through earnings. Hedge effectiveness is measured quarterly. Any ineffectiveness is recognized in the income statement in the period that the ineffectiveness occurs. If a derivative instrument that has qualified for hedge accounting is liquidated or sold prior to maturity, the gain or loss at the time of termination remains in other comprehensive income (loss) until the hedged item impacts earnings. For derivative instruments not designated as hedges, the gain or loss is immediately recognized in earnings in the period of its change in value. PG&E Corporation and the Utility have certain derivative commodity contracts that result in the physical delivery of commodities used in the normal course of business. At this time, these derivatives are exempt from the requirements of SFAS No. 133 under the normal purchases and sales exception, and thus are not reflected on the balance sheet at fair value. The Derivative Implementation Group of the Financial Accounting Standards Board has recently defined normal purchases and sales to exclude certain commodity contracts that were previously exempt under the normal purchases and sales provisions of SFAS No. 133. As such, certain derivative commodity contracts may no longer be exempt from the requirements of SFAS No. 133. PG&E Corporation and the Utility are currently evaluating the impact of the recent implementation guidance, which would be accounted for on a prospective basis, and will evaluate the impact when the final decision regarding this issue is resolved. PG&E Corporation's transition adjustment to implement this new Statement was a non-material charge to earnings and a charge of $243 million to other comprehensive income (loss). The Utility's transition adjustment to implement this new Statement was a non-material charge to earnings and an increase of $90 million to other comprehensive income (loss). Net gains and losses for non-trading activities recognized in earnings at March 31, 2001, were included in various places on the income statement. These were included as part of energy commodities and services revenue, cost of energy commodities and services, other income (expense), net, or interest income or interest expense on PG&E Corporation's and the Utility's Condensed Statements of Consolidated Operations for the three-month period ended March 31, 2001. PG&E Corporation's and the Utility's derivative gains and losses included in other comprehensive income (loss) are reflected in earnings at the time of terminations or settlements of the derivative instruments, along with the amortization of the transition account. Derivative gains or losses that were reclassified from other comprehensive income (loss) to earnings were included in various places on the income statement. These were included as part of energy commodities and services revenue, cost of energy commodities and services, other income (expense), net, or interest income or interest expense on PG&E Corporation's and the Utility's Condensed Statements of Consolidated Operations for the three-month period ended March 31, 2001. As of March 31, 2001, the maximum length of time over which PG&E Corporation has hedged its exposure to the variability in future cash flows associated with commodity price risk is through December 2005 and for interest rate risk it is through February 2012. The Utility had $243 million of cash flow hedges for commodity forward contracts, which were derecognized or discontinued during the three-month period ended March 31, 2001. 14Earnings (Loss) Per Share Basic earnings (loss) per share is computed by dividing net income (loss) by the weighted average number of common shares outstanding during the period. Diluted earnings per share is computed by dividing net income (loss) by the weighted average number of common shares outstanding plus the assumed issuance of common shares for all potentially dilutive securities. The following is a reconciliation of PG&E Corporation's net income (loss) and weighted average common shares outstanding for calculating basic and diluted net income (loss) per share. Three Months Ended March 31, 2001 2000 ---- ---- (in millions) Net Income (Loss) $ (951) $280 ------ ---- Weighted average common shares outstanding 363 361 Add: Outstanding options reduced by the number of shares that could be repurchased with the proceeds from such purchase - 1 Shares outstanding for diluted calculation 363 362 Earnings (Loss) per common share, basic $(2.62) $.78 Earnings (Loss) per common share, diluted $(2.62) $.77 The diluted share base for 2001 excludes incremental shares of 457 million related to employee stock options. These shares are excluded due to the anti- dilutive effect as a result of the net loss. PG&E Corporation reflects the preferred dividends of subsidiaries as other expense for computation of both basic and diluted earnings per share. Comprehensive Income (Loss) The objective of PG&E Corporation's and the Utility's comprehensive income (loss) is to report a measure for all changes in equity of an enterprise that result from transactions and other economic events of the period other than transactions with shareholders. PG&E Corporation's and the Utility's other comprehensive income (loss) consists principally of changes in the market value of certain financial hedges with the implementation of SFAS No. 133 on January 1, 2001, as well as foreign currency translation adjustments. NOTE 2: THE CALIFORNIA ENERGY CRISIS In 1998, California became one of the first states in the country to implement electric industry restructuring and establish a competitive market framework for electric generation. Electric industry restructuring was mandated by the California Legislature in Assembly Bill 1890 (AB1890). The electric industry restructuring established a transition period, mandated a rate freeze, and included a plan for recovery of generation-related costs that were expected to be uneconomic under a competitive market (transition costs). The CPUC required the California investor-owned utilities to file a plan to voluntarily divest at least 50% of their fossil-fueled generation facilities and discouraged utility operation of their remaining facilities by reducing the return on such assets. The competitive market framework called for the creation of the Power Exchange (PX) and the Independent System Operator (ISO). Before it ceased operating, the PX established market-clearing prices for electricity. The ISO's role was to schedule delivery of electricity for all market participants and operate certain markets for electricity. Until December 15, 2000, the Utility was required to sell all of its owned and contracted for generation to, and purchased all electricity 15for its customers from the PX. Customers were given the choice of continuing to buy electricity from the Utility or buying electricity from independent power generators or retail electricity suppliers. Most of the Utility's customers continued to buy electricity through the Utility. Beginning in June 2000, wholesale prices for electricity sold through the PX and ISO experienced unanticipated and massive increases. The average price of electricity purchased by the Utility for the benefit of its customers was 18.2 cents per kWh for the period of June 1 through December 31, 2000, compared to 4.2 cents per kWh during the same period in 1999. The Utility was only permitted to collect approximately 5.4 cents per kWh in rates from its customers during that period. The increased cost of the purchased electricity has strained the financial resources of the Utility. Because of the rate freeze, the Utility has been unable to pass on the increases in power costs to its customers. In order to finance the higher costs of energy, during the third and fourth quarter of 2000, the Utility increased its lines of credit to $1,850 million (net increase of $850 million), issued $1,240 million of debt under a 364-day facility, and issued $680 million of five-year notes. The Utility continued to finance the higher costs of wholesale power while interested parties evaluated various solutions to the energy crisis. In November 2000, the Utility filed its Rate Stabilization Plan (RSP), which sought to end the rate freeze and pass along the increased wholesale electric costs to customers through increased rates. The CPUC evaluated the Utility's proposal and deferred its decision until after hearings could be held, although the CPUC did increase rates one cent per kWh for 90 days effective January 4, 2001. This increase resulted in approximately $70 million of additional revenue per month, which was not nearly enough to cover the higher wholesale costs of electricity, nor did it help with the costs already incurred. By January 16, 2001, the Utility had borrowed more than $3.0 billion under its various credit facilities to pay its energy costs. As a result of the California energy crisis and its impact on the Utility's financial resources, PG&E Corporation's and the Utility's credit rating deteriorated to below investment grade in January 2001. This credit downgrade precluded PG&E Corporation and the Utility from access to capital markets. Commencing in January 2001, PG&E Corporation and the Utility began to default on maturing commercial paper. In addition, the Utility became unable to pay the full amount of invoices received for wholesale power purchases and made only partial payments. The Utility had no credit under which it could purchase wholesale electricity on behalf of its customers on a continuing basis and generators were only selling to the Utility under emergency action taken by the U.S. Secretary of Energy. In January 2001 the California Legislature and the Governor authorized the California Department of Water Resources (DWR) to purchase wholesale electric energy on behalf of the Utility's retail customers. In February 2001, the California Legislature passed California Assembly Bill 1X (AB 1X), which authorized the DWR to purchase wholesale electricity on behalf of the Utility's customers. On March 27, 2001, the CPUC authorized an average increase in retail rates of 3.0 cents per kWh, which was in addition to the emergency 1.0 cent per kWh surcharge adopted on January 4, 2001 by the CPUC. The revenue generated by this rate increase was to be used only for power procurement costs that were incurred after March 27, 2001 and could not be used to pay amounts owed to creditors. Although the rate increase is authorized immediately, the 3 cent surcharge will not be collected in rates until the CPUC establishes the rate design, which is not expected to be adopted until June 2001. In light of the magnitude of the undercollected purchased power costs and the lack of solutions to the energy crisis, on April 6, 2001, the Utility sought protection from its creditors through a Chapter 11 bankruptcy filing. The filing for bankruptcy and the related uncertainty around the terms and conditions of any reorganization plan that is ultimately adopted will have a significant impact on the Utility's future liquidity and results of operations. PG&E Corporation, itself, had cash and short-term investments of $295 million at March 31, 2001 and believes that the funds will be adequate to maintain its operations through and beyond 2001. In addition, PG&E Corporation believes that PG&E Corporation, itself, and its other subsidiaries not subject to CPUC regulation are substantially protected from the continuing liquidity and financial difficulties of the Utility. A discussion of the events leading up to the bankruptcy filing, PG&E Corporation's and the Utility's actions, and the ongoing uncertainty follows. 16Transition Period and Rate Freeze California's deregulation legislation passed by the California Legislature in 1996 established a transition period, which was to begin in 1998. During this period, electric rates for all customers were frozen at 1996 levels, with rates for residential and small commercial customers being reduced in 1998 by 10% and frozen at that level. During the transition period, investor-owned utilities were given the opportunity to recover their transition costs. Transition costs were generation-related costs that were expected to be uneconomic under the new industry structure. To pay for the 10% rate reduction, the Utility refinanced $2.9 billion (the expected revenue reduction from the rate decrease) of its transition costs with the proceeds from the sale of rate reduction bonds. The bonds allow for the rate reduction by lowering the carrying cost on a portion of the transition costs and by deferring recovery of a portion of the transition costs until after the transition period. During the rate freeze, the rate reduction bond debt service did not increase the Utility customers' electric rates. If the transition period ends before March 31, 2002, the Utility may be obligated to return a portion of the economic benefits of the transaction to customers. The timing of any such return and the exact amount of such portion, if any, have not yet been determined. The rate freeze was scheduled to end on the earlier of March 31, 2002 or the date the Utility had recovered all of its transition costs. The Utility believes it recovered its eligible transition costs possibly as early as the end of May 2000. At August 31, 2000, the Utility's remaining transition costs were less than a then-recently negotiated $2.8 billion hydroelectric generation asset valuation. If the final valuation for the hydroelectric assets is greater than $2.8 billion, as the Utility expects, the Utility will have recovered its transition costs earlier. The undercollected wholesale electricity costs as of the end of the earlier determined transition period will be less than the August 31 balance of $2.2 billion, and could be zero depending on the ultimate valuation of the hydroelectric generating facilities and when the transition period actually ends. However, the CPUC has not yet accepted the Utility's estimated market valuation of its hydroelectric assets nor has the CPUC determined that the rate freeze has ended. Wholesale Prices of Electricity As previously stated, beginning in June 2000, the Utility experienced unanticipated and massive increases in the wholesale costs of the electricity purchased from the PX and ISO on behalf of its retail customers. The Utility believes that since it has not met the creditworthiness standards under the ISO's tariff since early January 2001, the Utility should not be responsible for the ISO's purchases made to meet the Utility's net open position. (The net open position is the amount of power needed by retail electric customers that cannot be met by utility-owned generation or power under contract to the utilities.) Further, it is unclear how much of the ISO's power purchases have been made by the California Department of Water Resources (DWR) on behalf of the Utility's customers. The Utility has filed a complaint in federal Bankruptcy Court against the ISO to prohibit the ISO from continuing to bill the Utility for the ISO's wholesale power purchases, unless and until the Utility is permitted to recover the costs of such power purchases through retail electric rates. It is expected that the wholesale costs will continue to be extremely high through 2001 unless significant changes occur in the wholesale electricity market. The generation-related costs component, which provides for recovery of wholesale electricity purchased by the Utility and, if available, for recovery of transition costs, was approximately 6.4 cents and 5.4 cents per kWh, during the three months ended 2001 and 2000, respectively. As discussed below, the CPUC approved an average 3.0 cents per kWh surcharge for power costs incurred after March 27, 2001, but the 3-cent surcharge will not be collected in rates until the CPUC establishes an appropriate rate design for the surcharge, which is not expected to be adopted until June 2001. During the quarter ended March 31, 2001, the excess of wholesale electricity costs billed to the Utility by the ISO above the generation-related cost component available in frozen rates has been expensed as incurred and is included in the cost of electric energy on the Utility's Condensed Statement of Operations. The amount of undercollected purchased power costs incurred for the three month period ended March 31, 2001 was approximately $1.9 billion. Under current CPUC decisions, if this undercollection is not recovered through frozen rates by the end of the transition period, it cannot be recovered. Once the transition period has ended and the rate freeze is over, the Utility's customers will be responsible for wholesale electricity costs. However, actual changes in customer rates will not occur until new retail rates are authorized by the CPUC or, to the extent allowed, by the bankruptcy court. 17The undercollected purchased power costs would generally be deferred for future recovery as a regulatory asset subject to future collection from customers in rates. However, due to the lack of regulatory, legislative, or judicial relief, the Utility has determined that it can no longer conclude that its uncollected wholesale electricity costs and remaining transition costs are probable of recovery in future rates. Transition Cost Recovery Beginning January 1, 1998, the Utility started amortizing eligible transition costs, including most generation-related regulatory assets. These transition costs were offset by or recovered through the frozen rates, market valuation of generation assets in excess of book value, net energy sales from the Utility's electric generation facilities, and the amount by which long-term contract prices to purchase electricity were lower than the PX prices. Transition costs and associated recoveries are recorded in the Utility's Transition Cost Balancing Account (TCBA). During the transition period, a reduced rate of return on common equity of 6.77% applies to all generation assets, including those generation assets reclassified to regulatory assets. During the transition period, the CPUC reviews the Utility's compliance with accounting methods established in the CPUC's decisions governing transition costs recovery and the amount of transition costs requested for recovery. In January 2001, the CPUC approved all transition costs that were amortized from July 1, 1998, to June 30, 1999. The CPUC currently is reviewing transition costs amortized from July 1, 1999, to June 30, 2000. Mitigation Efforts The Utility is actively exploring ways to reduce its exposure to the higher wholesale electricity costs and to recover its written-off undercollected wholesale electricity costs and TCBA balances. As previously indicated, the Utility believes the transition period has ended and filed an application with the CPUC asking it to so rule. The Utility has also filed an application with the FERC to address the current market crisis, filed a lawsuit against the CPUC in Federal District Court, worked with interested parties to address power market dysfunction before appropriate regulatory bodies, hedged a portion of its open procurement position against higher purchased power costs through forward purchases, and filed an application with the CPUC seeking approval of a five- year rate stabilization plan. The Utility's actions and related activities are discussed below. Application with the FERC - ------------------------- On October 16, 2000, the Utility joined with Southern California Edison (SCE) and The Utility Reform Network (TURN) in filing a petition with the Federal Energy Regulatory Commission (FERC) requesting that the FERC (1) immediately find the California wholesale electricity market to be not workably competitive and the resulting prices to be unjust and unreasonable; (2) immediately impose a cap on the price for energy and ancillary services; and (3) institute further expedited proceedings regarding the market failure, mitigation of market power, structural solutions, and responsibility for refunds. On December 15, 2000, the FERC issued an order in response to the above filing. The remedies proposed by the FERC include, among other things: (1) eliminating the requirement that the California investor-owned utilities must sellsubsidiary voted all of theirpower into, and buy all of their power needs from, the PX; (2) modifying the single price auction so that bids above $150 per megawatt hour (MWh) (15 cents per kWh) cannot set the market clearing prices paid to all bidders, effective January 1, 2001 through April 30, 2001; (3) establishing an independent governing board for the ISO; and (4) establishing penalties for under-scheduling power loads. The FERC did not order any refunds based on its findings, but announced its intent to retain the discretion to order refunds for wholesale electricity costs incurred from October 2000 through December 31, 2002. In March 2001, the FERC ordered refunds of $69 million for January 2001 and indicated it would continue to review December 2000 wholesale prices. In April 2001, the FERC ordered refunds of $588 thousand for February and March 2001. The generators have appealed the decisions. Any refunds will be offset against amounts owed the generators. On April 26, 2001, the FERC issued an order requiring all ISO-participating generators and nonpublic utility sellers 18participating in the ISO markets or using the ISO transmission system to offer their output in real-time to the ISO (except for hydroelectric facilities). The order also requires generators to justify prices above their marginal costs to generate. Further, when a stage 1, 2, or 3 emergency is in effect, price mitigation becomes effective. The real-time electric prices will no longer clear at the single highest price or at a soft cap of $150 per MWh, but will clear at a proxy price based on the highest cost units required to be used each day, and published fuel costs and emission credit information. This mitigation plan will become effective on May 29, 2001. The FERC will monitor bidding activities of generators, forward prices in the electricity and natural gas market and plant outages. Any bids that prove to be unjustified will be subject to refund. The FERC has requested comments on various aspects of its order. The FERC also has indicated that it intends to open an investigation into prices and sales into the Western United States and consider imposing price mitigation measures similar to those proposed for California markets. The order also requires that the ISO and the three California investor owned utilities file a proposal regarding the establishment of west-wide regional transmission organization (RTO) by June 1, 2001. Federal Lawsuit - --------------- On November 8, 2000, the Utility filed a lawsuit in federal district court in San Francisco against the CPUC Commissioners. The Utility asked the court to declare that the federally-approved wholesale electricity costs the Utility has incurred to serve its customers are recoverable in retail rates both before and after the end of the transition period. The lawsuit states that the wholesale power costs the Utility has incurred are paid pursuant to filed rates, which the FERC has authorized and approved and that under the United States Constitution and numerous federal court decisions, state regulators cannot disallow such costs. The Utility's lawsuit also alleges that to the extent that the Utility is denied recovery of these mandated wholesale electricity costs by order of the CPUC, such action constitutes an unlawful taking and confiscation of the Utility's property. On January 29, 2001, the Utility's lawsuit was transferred to the federal district court in Los Angeles where SCE has its identical case pending. On May 2, 2001, the court dismissed the Utility's complaint without prejudice to refile the lawsuit at a later time. Although ruling in the Utility's favor on five of the six grounds for dismissal, the court found that the Utility's complaint was not ripe because some of the CPUC's decisions that the Utility was challenging were interim orders that will only become final upon a grant or denial of rehearing. Legislative Action - ------------------ On February 1, 2001, the governor of California signed into law AB 1X. AB 1X extended a preliminary authority of the DWR to purchase power. Public Utilities Code Section 360.5, adopted in AB 1X, authorizes the CPUC to determine the portion of each electric utility's existing electric retail rate that represents the difference between the generation related component of the utility's retail rate in effect on January 5, 2001, and the sum of the costs of the utility's own generation, qualifying facilities (QF) contracts, existing bilateral contracts, and ancillary services (the California Procurement Adjustment or CPA). The CPA is payable to the DWR by each utility upon receipt from its retail end use customers. Initially, the DWR has indicated that it intended to buy power only at "reasonable prices" to meet the utilities' net open position, leaving the ISO to buy the remainder. The ISO billed, and is expected to continue to bill the Utility for those costs. AB 1X does not address whether or how the Utility will be able to pay for the ISO's wholesale power costs billed to the Utility that exceed the generation related costs components of electric rates. It is not clear whether the Utility will ultimately be responsible for these costs from February through April 6, 2001. The Utility has expensed these costs in the accompanying Condensed Financial Statements. By early January 2001, the Utility failed to meet the creditworthiness standards under the ISO's tariff for purchasing and scheduling power from third parties. On January 5, 2001, the ISO filed a proposed tariff amendment with the FERC to permit the Utility to continue scheduling transactions through the ISO. The ISO implemented its proposed tariff amendment immediately. On February 14, 2001, the FERC issued an order rejecting the ISO's proposed tariff amendment, prohibiting the Utility from scheduling power from a third party supplier, unless the Utility was creditworthy or was backed by creditworthy parties. The FERC order also stated that the ISO could continue to 19schedule power for the Utility as long as it comes from its own generation units and is routed over its own transmission lines. The ISO continued to charge the Utility for the power it buys on an emergency basis, despite the FERC ruling. On April 6, 2001, the FERC issued a further order directing the ISO to implement its prior order, which the FERC clarified, applies to all third party transactions whether scheduled or not. The ISO has not indicated that it will comply with the FERC and cease billing the Utility for its third party power purchases. The Utility has filed a complaint against the ISO in Bankruptcy Court regarding this issue. Rate Stabilization Plan (RSP) - ----------------------------- On November 22, 2000, the Utility filed an application with CPUC seeking approval of a five-year RSP beginning on January 1, 2001. The Utility requested an initial average rate increase of 22.4%. The Utility also proposed that it receive actual costs, including a regulated return, for electricity generation provided by it with the idea that profits that would have been generated at market rates be recovered from customers later in the five-year rate stabilization period. With respect to Diablo Canyon Nuclear Power Plant (Diablo Canyon) the Utility has proposed to defer all profits (discussed below in "Diablo Canyon Benefits Sharing"), until 2003, when the allocation of revenues between ratepayers and shareholders will be readjusted. The readjustment is intended to allow, by the end of 2005, the total net revenues earned by Diablo Canyon, over the five-year plan, to be allocated equally between shareholders and ratepayers according to existing CPUC decisions. On January 4, 2001, the CPUC issued an emergency interim decision denying the Utility's request for a rate increase. Instead, the decision permitted the Utility to establish an interim surcharge applied to electric rates on an equal- cents-per-kWh basis of 1.0 cent per kWh, subject to refund and adjustment. The surcharge was to remain in effect for 90 days from the effective date of the decision. The Utility was required to establish a balancing account to track the revenue provided by the surcharge and to apply these revenues to ongoing wholesale electricity costs. The surcharge was made permanent in the CPUC's March 27, 2001 decision, referred to below. On January 26, 2001, an assigned CPUC commissioner's ruling was issued in the Utility's rate stabilization plan proceeding. The ruling stated that in phase one of the case, the scope of the proceeding will include (1) reviewing the independent audit of the Utility's accounts to determine whether there is a financial necessity for additional relief for the utilities, (2) reviewing TURN's accounting proposal to transfer the undercollected balances in the Utility's Transition Revenue Accounts (TRAs) to theirrespectiveTCBAs and reviewing the generation memorandum accounts, and (3) considering whether the rate freeze has ended only on a prospective basis. On January 30, 2001, the independent consultants engaged by the CPUC issued their review report on the Utility's financial position as of December 3, 2000, as well as that of PG&E Corporation and the Utility's affiliates. The review found that the Utility made an accurate representation of its financial situation noting accurate representations of its borrowing capabilities, credit condition, and events of default. The review also found that the Utility accurately represented recorded entries to its TRA and TCBA. The review alleged certain deficiencies with respect to bidding strategies, cash conservation matters, and cash flow forecast assumptions. The Utility filed rebuttal testimony on February 14, 2001. Hearings to consider the issues and reports of the independent consultants began on February 20, 2001. On March 27, 2001, the CPUC ruled on parts of the Utility's RSP and granted an increase in rates by adopting an average 3.0 cents per kWh surcharge. Although the increase is authorized immediately, the 3.0 cents per kWh surcharge will not be collected in rates until the CPUC establishes an appropriate rate design for the surcharge, which is not expected to be adopted until June 2001. The revenue generated by the rate increase is to be used only for power procurement costs that are incurred after March 27, 2001. The CPUC declared that the revenues generated by this surcharge are subject to refund (1) if not used to pay for such power purchases, (2) to the extent that generators and sellers of power make refunds for overcollections, or (3) to the extent any administrative body or court denies the refunds of overcollections in a proceeding where recovery has been hampered by a lack of cooperation from the Utility. The 3.0 cents per kWh surcharge is in addition to the emergency interim surcharge approved in January 4, 2001, which the CPUC made permanent in this decision. The CPUC also modified accounting rules in response to a proposal made by TURN as described below. 20Also, on March 27, 2001, the CPUC issued a decision ordering the Utility and the other California investor-owned utilities to pay the DWR a per kWh price equal to the applicable generation-related retail rate per kWh established for each utility, for each kWh the DWR sells to the customers of each utility. The CPUC determined that the generation-related component of retail rates should be equal to the total bundled electric rate (including the 1 cent per kWh interim surcharge adopted by the CPUC on January 5, 2001) less the following non- generation-related rates or charges: transmission, distribution, public purpose programs, nuclear decommissioning, and the fixed transition amount. The CPUC determined that the Utility's company-wide average generation-related rate component is 6.471 cents per kWh before March 27, 2001, and 9.471 cents per kWh after March 27, 2001, reflecting the authorized 3-cent increase. The CPUC ordered the utilities to pay the DWR within 45 days after the DWR supplies power to their retail customers, subject to penalties for each day that payment is late. The amount of power supplied to retail end-use customers after March 27, 2001, for which the DWR is entitled to be paid would be based on the product of the number of kWh that the DWR provided 45 days earlier and the Utility's company-wide average generation-related rate of 9.471 cents per kWh. The CPUC also ordered that the utilities immediately pay the sums owed to the DWR for power sold by the DWR from January 18, 2001 through January 31, 2001, under California Senate Bill 7X. Based on an estimated number of kWh sold by the DWR, the Utility paid approximately $30 million to the DWR at the rate of $0.05471 per kWh as adopted by the CPUC. In addition, on April 3, 2001, the CPUC adopted a method to calculate the CPA, as described in Public Utilities Code Section 360.5 (added by AB 1X effective February 1, 2001). Section 360.5 requires the CPUC to determine (1) the portion of each electric utility's electric retail rate effective on January 5, 2001, the CPA, that is equal to the difference between the generation-related component of the utility's retail rate in effect on January 5, 2001, and the sum of the costs of the utility's own generation, QFs contracts, existing bilateral contracts (i.e., entered into before February 1, 2001), and ancillary services, and (2) the amount of the CPA that is allocable to the power sold by the DWR. The CPUC decided that the CPA should be a set rate calculated by determining each utility's generation-related revenues (for the Utility the CPUC has proposed that this be equal to 6.471 cents per kWh multiplied by total kWh sales by the Utility to the Utility's retail customers), then subtracting the result by each utility's total kWh sales. Each utility's CPA rate will be used to determine the amount of bonds the DWR may issue. Using the CPUC's methodology, but substituting the CPUC's cost assumptions with actual expected costs and including costs the CPUC has refused to recognize, the Utility's calculations show that the CPA for the 11-month period February through December 2001 would be negative by $2.2 billion, (i.e., there would be no CPA available to the DWR) assuming the DWR purchases 84% of the Utility's net open position. If AB 1X were amended to also include in the CPA all the incremental revenue from the 3 cent per kWh increase discussed above (approximately $2.3 billion for 11 months), then the amount available to the DWR for the CPA for the comparable 11-month period, assuming the Utility were allowed to recover its costs first, would be approximately $100 million. The Utility believes the method adopted by the CPUC is unlawful and inconsistent with Section 360.5 because, among other reasons, it establishes a set rate that does not reflect actual residual revenues, overstates the CPA by excluding and/or understating authorized costs, and to the extent it is dedicated to the DWR does not allow the Utility to recover its own revenue requirements and costs of service. The Utility's application for rehearing of this decision has been denied. To the extent the DWR does not buy enough power to cover the Utility's net open position, the ISO purchases emergency power on the high-priced spot market to meet system reliability requirements and the net open position. Despite the FERC's order prohibiting the ISO from charging non-creditworthy utilities for the ISO's third party power purchases, the ISO may continue to charge the Utility a proportionate share of the ISO's purchases. As discussed above, the Utility believes it is not responsible for such ISO charges. The DWR has advised the CPUC that its revenue requirement for the DWR's power purchases is $4.715 billion and has asked the CPUC to establish specific rates payable to the DWR to collect that revenue requirement as authorized by AB 1X. The DWR's stated revenue requirement is greater than the revenues that would be provided by the 3-cent surcharge. Unless the CPUC increases rates to provide sufficient revenues for the DWR to recover its revenue requirement, none of the revenues from the 3-cent surcharge will be available to the Utility to recover its procurement costs incurred after March 27, 2001 (including any ISO charges for which the DWR disclaims responsibility). 21Since the end of January 2001, the Utility has been paying only 15% of amounts due to qualifying facilities (QFs). On March 27, 2001, the CPUC issued a decision requiring the Utility and the other California investor-owned utilities to pay QFs fully for energy deliveries made on and after the date of the decision, within 15 days of the end of the QFs' billing period. The decision permits QFs to establish a 15-day billing period as compared to the current monthly period. The CPUC noted that its change to the payment provision was required to maintain energy reliability in California and thus provided that failure to make a required payment would result in a fine in the amount owed to the QF. The decision also adopts a revised pricing formula relating to the California border price of gas applicable to energy payments to all QFs, including those that do not use natural gas as a fuel. Based on the Utility's preliminary review of the decision, the revised pricing formula would reduce the Utility's 2001 average QF energy and capacity payments from approximately 12.7 cents per kWh to 12.3 cents per kWh. The CPUC also adopted TURN's proposal to transfer on a monthly basis the balance in each Utility's TRA to the Utility's TCBA. The TRA is a regulatory balancing account that is credited with total revenue collected from ratepayers through frozen rates and which tracks undercollected power purchase costs. The TCBA is a regulatory balancing account that tracks the recovery of generation-related transition costs. The accounting changes are retroactive to January 1, 1998. The Utility believes the CPUC is retroactively transforming the power purchase costs in the TRA into transition costs in the TCBA. However, the CPUC characterized the accounting changes as merely reducing the prior revenues recorded in the TCBA, thereby affecting only the amount of transition cost recovery achieved to date. The CPUC also ordered that the utilities restate and record their generation memorandum account balances to the TRA on a monthly basis before any transfer of generation revenues to the TCBA. The CPUC found that based on the accounting changes, the conditions for meeting the end of the rate freeze have not been met. The Utility believes the adoption of TURN's proposed accounting changes results in illegal retroactive ratemaking, constitutes an unconstitutional taking of the Utility's property, and violates the federal filed rate doctrine. The Utility also believes the other CPUC decisions are similarly illegal to the extent they would compel the Utility to make payments to the DWR and QFs without providing adequate revenues for such payments. The Utility has filed an application for rehearing of this decision. The Utility also has requested the Bankruptcy Court to enjoin the CPUC from requiring the Utility to implement the regulatory accounting changes. A hearing is set for May 14, 2001, to consider the Utility's request. Bilateral Contracts - ------------------- Under the terms of the AB 1890, the Utility was required to purchase all of its power from the PX and ISO to meet the needs of its customers. On August 3, 2000, after the California energy crisis had begun, the CPUC approved the Utility's use of bilateral contracts, subject to PG&E reaching an agreement with the CPUC on reasonableness standards. After two months of unsuccessful discussions with CPUC, on October 16, 2000, PG&E filed an advice letter seeking CPUC approval of specific reasonableness standards in order to expedite implementation of the August 3, 2000 decision. In spite of the Utility's efforts, the CPUC has not adopted reasonableness standards implementing the August 3, 2000 decision. In October 2000, the Utility entered into multiple bilateral contracts with suppliers for long-term electricity deliveries. As of March 31, 2001, individual contracts range in size from approximately 92,000 MWhs to 3,504,000 MWhs of supply annually. The contracts extended to 2005. As a result of the downgrade in PG&E's credit rating and also its subsequent bankruptcy filing, certain of these contracts were terminated. PX Energy Credits - ----------------- In accordance with CPUC regulations, the Utility provides a PX energy credit to those customers (known as direct access customers) who have chosen to buy their electric energy from an energy service provider (ESP) other than the Utility. As wholesale power prices began to increase beginning in June 2000, the level of PX credits issued to direct access customers increased correspondingly to the point where the credits exceeded the Utility's distribution and transmission charges to direct access customers. For the three months ended March 31, 2001, the PX credits reduced 22electric revenue by $322 million. The Utility ceased paying most of these credits in December 2000, and as of March 31, 2001, the total of accumulated credits for direct access customers that have not been paid by the Utility is approximately $510 million. The actual amount that will be refunded to ESPs will be dependent upon when the rate freeze ends and whether there are any adjustments made to wholesale energy prices by the FERC. Generation Valuation Under the California electric industry restructuring legislation, the valuation of the Utility's remaining generation assets (primarily its hydroelectric facilities) must be completed by December 31, 2001. Any excess of market value over the assets' book value would be used to offset the Utility's transition costs. In August 2000, the Utility and a number of interested parties filed an application with the CPUC requesting that the CPUC approve a settlement agreement reached by these parties. The agreement was filed in the Utility's proceeding to determine the market value of the hydroelectric generation assets. In this settlement agreement, the Utility indicated that it would transfer its hydroelectric generation assets, at a negotiated value of $2.8 billion, to an affiliate. Due to the high wholesale prices and the corresponding increase in the value of its hydroelectric generation assets, in November 2000 as part of an application with the CPUC seeking approval of a five-year RSP, the Utility withdrew its support from the settlement agreement, eliminating it from consideration in the proceeding. In December 2000, the Utility submitted updated testimony in the hydroelectric valuation proceeding indicating the market value of the hydroelectric assets ranges from $3.9 billion to $4.2 billion assuming a competitive auction or other arms-length sale. In January 2001, California Assembly Bill 6 was passed which prohibits disposal of any of the Utility's generation facilities, including the hydroelectric facilities, before January 1, 2006. At March 31, 2001, the book value of the Utility's net investment in hydroelectric generation assets was approximately $688 million. Diablo Canyon Benefits Sharing As required by a prior CPUC decision on June 30, 2000, the Utility filed an application with the CPUC requesting approval of its proposal for sharing with ratepayers 50% of the post-rate freeze net benefits of operating Diablo Canyon. The net benefit sharing methodology proposed in the Utility's application would be effective at the end of the current electric rate freeze for the Utility's customers and would continue for as long as the Utility owned Diablo Canyon. Under the proposal, the Utility would share the net benefits of operating Diablo Canyon based on the audited profits from operations, determined consistent with the prior CPUC decisions. If Diablo Canyon experiences losses, such losses would be deferred and netted against profits in the calculation of the net benefits in subsequent periods (or against profits in prior periods if subsequent profits are insufficient to offset such losses). Any changes to the net sharing methodology must be approved by the CPUC. The CPUC has suspended the proceedings to consider the net benefit sharing proposal. In the Utility's RSP, parties have proposed that the requirement to establish a sharing methodology be rescinded and the Diablo Canyon be placed on cost-of-service ratemaking. It is uncertain what future ratemaking will be applicable to Diablo Canyon. 23Cost of Electric Energy For the three months ended March 31, 2001 and 2000, the cost of electric energy for the Utility, reflected on the Utility's Condensed Statement of Consolidated Operations, comprises the cost of fuel for electric generation and QF purchases, the cost of PX purchases, and ancillary services charged by the ISO, net of sales to the PX, as follows: 2001 2000 ---- ---- (in millions) Cost of fuel resources at market prices $2,631 $ 628 Proceeds from sales to the PX (204) (115) ------ ------ Total Utility cost of electric energy $2,427 $ 513 ------ ------ Note 3: LONG-TERM DEBT On January 16 and 17, 2001, in response to the continued energy crisis, Standard and Poor's (S&P) and Moody's Investors Service (Moody's) respectively, downgraded PG&E Corporation's credit ratings to below investment grade. The downgrade, in addition to PG&E Corporation's and the Utility's non-payment of commercial paper constituted an event of default under both the $436 million and the $500 million credit facilities. In response, the banks immediately terminated their outstanding commitments under these defaulted credit facilities. Through February 28, 2001, PG&E Corporation had $501 million in outstanding commercial paper, of which $457 million came due and was not paid. On March 2, 2001, PG&E Corporation refinanced its debt obligations with $1 billion in aggregate proceeds of two term loans under a common credit agreement with General Electric Capital Corporation and Lehman Commercial Paper, Inc. In accordance with the credit agreement, the proceeds, together with other PG&E Corporation cash, were used to pay the $501 million in outstanding commercial paper, $434 million in borrowings under PG&E Corporation's long-term revolving credit facility, and $116 million to PG&E Corporation's shareholders of record on December 15, 2000 in satisfaction of the defaulted fourth quarter 2000 common stock dividend. Further, approximately $99 million was used to pre-pay the first year's interest under the credit agreement and to pay transaction expenses associated with the debt restructuring. The loans will mature on March 2, 2003 (which date may be extended at the option of PG&E Corporation for up to one year upon payment of a fee of up to 5% of the then outstanding indebtedness), or earlier, if a spin-off of theshares ofPG&E NEG were to occur. As required by the credit agreement, PG&E Corporation has given the lenders a security interest in PG&E NEG. The loans prohibit PG&E Corporation from declaring dividends, making other distributions to shareholders, or incurring additional indebtedness unless it meets certain requirements. The loan also prohibits PG&E NEG from making distributions to PG&E Corporation and restricts certain other intercompany transactions. Further, as required by the credit agreement, NEG LLC has granted to affiliates of the lenders options that entitle these affiliates to purchase up to 3% of the shares of PG&E NEG at an exercise price of $1.00 based on the following schedule: Percentage of Shares Subject To PG&E NEG Options ------------------- Loans outstanding for: Less than six months 2.0% Six to eighteen months 2.5% Greater than eighteen months 3.0% 24The option becomes exercisable on the date of full repayment or earlier, if an initial public offering of the shares of PG&E NEG (IPO) were to occur. PG&E NEG has the right to call the option in cash at a purchase price equal to the fair market value of the underlying shares, which right is exercisable at any time following the repayment of the loans. If an IPO has not occurred, the holders of the option have the right to require NEG LLC or PG&E Corporation to repurchase the option at a purchase price equal to the fair market value of the underlying shares, which right is exercisable at any time after the earlier of full repayment of the loans or 45 days before expiration of the option. The option will expire 45 days after the maturity of the loans. PG&E Corporation will account for the options by recording the fair value of the option at issuance as a debt issuance cost to be amortized over the expected life of the loans. The options will be marked through an increase or decrease to current earnings. Under the credit agreement, PG&E NEG is permitted to make investments, incur indebtedness, sell assets, and operate its businesses pursuant to its business plan. Mandatory repayment of the loans will be required from the net after-tax proceeds received by PG&E NEG or any subsidiary of PG&E NEG from (1) the issuance of indebtedness, (2) the issuance or sale of any equity (except for cash proceeds from an IPO), (3) asset sales, and (4) casualty insurance, condemnation awards, or other recoveries. However, if such proceeds are retained as cash, used to pay indebtedness, or reinvested in PG&E NEG's businesses, mandatory repayment will not be required. Any net proceeds from an IPO must be used to reduce the outstanding balance of the loans to $500 million or less. In addition, all distributions made by PG&E NEG to PG&E Corporation other than (1) to reimburse PG&E Corporation for corporate overhead expenses, (2) pursuant to any tax sharing arrangements which PG&E NEG and PG&E Corporation are parties, and (3) pursuant to any note that may be repayable to PG&E Corporation in connection with an IPO and similar arrangements must be used to pay the loans. The credit agreement also prohibits PG&E Corporation from taking certain actions, including a restriction against declaring or paying any dividends for as long as the loans are outstanding. A breach of covenants, including requirements that (1) PG&E NEG's unsecured long-term debt have a credit rating of at least BBB- by S&P or Baa3 by Moody's, (2) the ratio of fair market value of PG&E NEG to the aggregate amount of principal then outstanding under the loans is not less than 2 to 1, and (3) PG&E Corporation maintain a cash or cash equivalent reserve of at least 15% of the total principal amount of the loans outstanding, entitles the lenders to declare the loans to be due and payable. During 2000 and 1999, two indirect wholly owned subsidiaries of PG&E NEG entered into two commitments relating to the acquisition of turbine equipment and two commitments relating to generation projects that are under construction, for which they act as the construction agent for the owners. Upon completion of the construction projects, expected to be in 2002, PG&E NEG will lease these facilities under lease terms of five years and three years, respectively. At the conclusion of each of these lease terms, PG&E NEG has the option to extend the leases at fair market value, purchase the projects, or act as remarketing agent for the lessors for sales to third parties. If PG&E NEG elects to remarket the projects, then PG&E NEG would be obligated to the lessors for up to 85 percent of the project costs if the proceeds are deficient to pay the lessor's investors. PG&E Corporation has committed to fund up to $604 million in the aggregate of equity to support PG&E NEG's obligation to the lessors during the construction and post-construction periods. In addition, PG&E NEG entered into operative agreements with a special purpose entity that will own and finance construction of another facility totaling $775 million. PG&E Corporation has committed to fund up to $122 million of equity support commitments to meet the obligations to the entity. PG&E NEG is attempting to replace PG&E Corporation's equity support commitments with substitute commitments of PG&E NEG. The trusts holding the assets and debt related to these facilities has been consolidated in the accompanying financial statements. Note 4: BANKRUPTCY FILING The Utility had been drawing on its $1 billion facility to pay maturing commercial paper. As of January 16, 2001, the Utility had drawn down $938 million under this facility. On January 16 and 17, 2001, S&P and Moody's respectively, downgraded the Utility's credit ratings to below investment grade. This downgrade resulted in an event of default under the $850 million credit facility, while the Utility's non-payment of commercial paper exceeding $100 million constituted events of default under both the $1 billion and $850 million credit facilities. 25On January 10, 2001, the Board of Directors of the Utility suspended the payment of its fourth quarter 2000 common stock dividend in an aggregate amount of $110 million payable on January 15, 2001, to PG&E Corporation and PG&E Holdings, Inc., a subsidiary of the Utility. In addition, the Utility's Board of Directors decided not to declare the regular preferred stock dividends of $6.3 million for the three-month period ending January 31, 2001, normally payable on February 15, 2001. Dividends on all Utility preferred stock are cumulative. Until cumulative dividends on preferred stock are paid, the Utility may not pay any dividends on its common stock, nor may the Utility repurchase any of its common stock. The Utility has also deferred quarterly interest payments of $6.1 million on the Utility's 7.90% Deferrable Interest Subordinated Debentures, Series A, due 2025, until further notice in accordance with the indenture. The corresponding quarterly payments of $5.9 million on the 7.90% Cumulative Quarterly Income Preferred Securities, Series A (QUIPS) issued by PG&E Capital I, due on April 2, 2001, have been similarly deferred. Distributions can be deferred up to a period of five years per the indenture. Under the indenture, investors accumulate interest on the unpaid distributions at the rate of 7.90%. After the downgrade, the PX notified the Utility that the ratings downgrade required the Utility to post collateral for all transactions in the PX day-ahead market. Since the Utility was unable to post such collateral, the PX suspended the Utility's trading privileges effective January 19, 2001 in the day-ahead market. The PX also sought to liquidate the Utility's block forward contracts for the purchase of power. On January 25, 2001, a California Superior Court judge granted the Utility's application for a temporary restraining order, which thereby restrained and enjoined the PX and its agents from liquidating the Utility's contracts in the block forward market, pending hearing on a preliminary injunction on February 5, 2001. Immediately before the hearing on the preliminary injunction, California Governor Gray Davis, acting under California's Emergency Services Act, commandeered the contracts for the benefit of the state. Under the Act, the DWR must pay the Utility the reasonable value of the contracts, although the PX may seek to recover the monies that the Utility owes to the PX from any proceeds realized from those contracts. Discussions and negotiations on this issue are currently ongoing between the state and the Utility. As a result of (1) the failure by the DWR to assume the full procurement responsibility for the Utility's net open position as was provided under AB 1X, (2) the negative impact of recent actions by the CPUC that created new payment obligations for the Utility and undermined its ability to return to financial viability, (3) a lack of progress in negotiations with the state to provide a solution for the energy crisis, and (4) the adoption by the CPUC of an illegal and retroactive accounting change that would appear to eliminate the Utility's true uncollected purchased power costs, the Utility filed a voluntary petition for relief under provisions of Chapter 11 of the U.S. Bankruptcy Code on April 6, 2001. Pursuant to Chapter 11 of the U.S. Bankruptcy Code, the Utility retains control of its assets and is authorized to operate its business as a debtor in possession while being subject to the jurisdiction of the bankruptcy court. Subject to the approval of the bankruptcy court, the Utility's intent is to pay its ongoing costs of doing business while seeking resolution of the wholesale power crisis. It is the Utility's intention to continue to pay employees, vendors, suppliers, and other creditors to maintain essential distribution and transmission services. However, the Utility is not in a position to pay maturing or accelerated obligations, nor is the Utility in a position to pay the ISO, PX, and the QFs, the massive amounts due for the Utility's power purchases above the amount included in rates for power purchase costs. The Utility's current actions are intended to allow the Utility to continue to operate while the bankruptcy proceedings continue. Note 5: RINGFENCING In December 2000 and during the first quarter of 2001, PG&E Corporation and PG&E NEG undertook a corporate restructuring of PG&E NEG, known as a "ringfencing" transaction. The ringfencing complied with credit rating agency criteria designed to further separate a subsidiary from its parent and affiliates, enabling PG&E NEG, PG&E Gas Transmission, Northwest Corporation (PG&E GTN), and PG&E Energy Trading Holdings Corp. to receive or retain their own credit rating, based upon their creditworthiness. The ringfencing involved the creation of new special purpose entities (SPEs) as intermediate owners between PG&E Corporation and its non CPUC-regulated subsidiaries. These new SPEs are: NEG LLC, which owns 100% of the stock of PG&E NEG; GTN Holdings LLC, which owns 100% of the stock of PG&E GTN; and PG&E Energy Trading Holdings LLC which owns 100% of the stock of PG&E Corporation's energy trading subsidiaries, PG&E Energy Trading-Power, L.P. and PG&E Energy Trading-Gas Corporation, and their affiliates (PG&E ET). In addition, PG&E NEG's organizational documents were 26modified to include the same structural elements as the SPEs to meet credit rating agency criteria. Ringfencing was undertaken to enable PG&E NEG and various of its affiliates to obtain or maintain investment grade ratings. The SPEs require unanimous approval of their respective boards of directors, which includes an independent director, before they can (a) consolidate or merge with any entity, (b) transfer substantially all of their assets to any entity, or (c) institute or consent to bankruptcy, insolvency, or similar proceedings or actions. The SPEs may not declare or pay dividends unless the respective boards of directors have unanimously approved such action and the company meets specified financial requirements. NOTE 6: PRICE RISK MANAGEMENT Trading and Non-Trading Activities PG&E Corporation's net gain (loss) on trading contracts for the three-month period ended March 31, are as follows: 2001 2000 ---- ---- (in millions) Swaps $(349) $ (23) Options (7) 62 Futures 32 37 Forward contracts 352 (31) Net gain $ 28 $ 45 Below is a table summarizing the quantitative information associated with PG&E Corporation's cash flow hedges for the three-month period ended March 31, 2001. Only the Utility currently uses fair value hedges. The Utility's fair value hedge is subject to a regulatory mechanism, and as such, it is deferred for future recovery or refund and included on the balance sheet with no immediate earnings impact. The Utility's price risk management strategies consist of the use of non-trading (hedging) financial instruments, designated as both cash flow hedges and fair value hedges. Gains and losses associated with the use of some of the Utility's financial instruments primarily affect regulatory accounts, depending on the business unit and the specific program involved. While the use of the Utility's financial instruments has been authorized by the CPUC, the CPUC has yet to establish rules around how it will judge the reasonableness of these instruments for electricity purchases. PG&E Corporation ---------------- (in millions) Amount of the hedge's ineffectiveness $(2) ---- Net loss recognized in earnings $(2) ---- PG&E Corporation and the Utility's estimated net derivative gains or losses included in other comprehensive loss at March 31, 2001 that will be reclassified into earnings within the next twelve months are a net derivative loss of $146 million for PG&E Corporation and a net derivative loss of $25 million for the Utility. 27The schedule below summarizes the activities affecting accumulated other comprehensive income (loss) from derivative instruments for the three-month period ended March 31, 2001. PG&E Corporation Utility ---------------- ------- (in millions) Beginning accumulated derivative gain (loss) from SFAS No. 133 transition adjustments at January 1, 2001 $(243) $ 90 Net change of current period hedging transactions gain (loss) (29) 1 Net reclassification to earnings (43) (143) Ending accumulated derivative gain (loss) (315) (52) Foreign currency translation adjustment (4) (2) Ending accumulated other comprehensive loss $(319) $ (54) Credit Risk The use of financial instruments to manage the risks associated with changes in energy commodity prices creates exposure resulting from the possibility of nonperformance by counterparties pursuant to the terms of their contractual obligations. The counterparties associated with the instruments in PG&E Corporation's and the Utility's portfolio consist primarily of investor-owned and municipal utilities, energy trading companies, financial institutions, and oil and gas production companies. PG&E Corporation and the Utility minimize credit risk by dealing primarily with creditworthy counterparties in accordance with established credit approval practices and limits. PG&E Corporation assesses the financial strength of its counterparties at least quarterly and requires that counterparties post security in the forms of cash, letters of credit, corporate guarantees of acceptable credit quality, or eligible securities if current net receivables and replacement cost exposure exceed contractually specified limits. PG&E Corporation experienced a loss of approximately $25 million due to the nonperformance of counterparties during the three-month period ended March 31, 2001. Counterparties considered to be investment grade or higher comprise 87% of the total credit exposure. At March 31, 2001, PG&E Corporation's and the Utility's gross credit risk amounted to $2.1 billion and $758 million, respectively. NOTE 7: 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% QUIPS, with an aggregate liquidation value of $300 million. Concurrent with the issuance of the QUIPS, the Trust issued to the Utility 371,135 shares of common securities with an aggregate liquidation value of $9 million. The Trust in turn used the net proceeds from the QUIPS offering and issuance of the common stock securities to purchase subordinated debentures issued by the Utility with a face value of $309 million, due 2025. These subordinated debentures are the only assets of the Trust. Proceeds from the sale of the subordinated debentures were used to redeem and repurchase higher-cost preferred stock. The Utility's guarantee of the QUIPS, considered together with the other obligations of the Utility with respect to the QUIPS, constitutes a full and unconditional guarantee by the Utility of the Trust's contractual obligations under the QUIPS issued by the Trust. The subordinated debentures may be redeemed at the Utility's option beginning in 2000 at par value plus accrued interest through the redemption date. The proceeds of any redemption will be used by the Trust to redeem QUIPS in accordance with their terms. Upon liquidation or dissolution of the Utility, holders of these QUIPS would be entitled to the liquidation preference of $25 per share plus all accrued and unpaid dividends thereon to the date of payment. 28On March 16, 2001, the Utility deferred quarterly interest payments on the Utility's 7.90% Deferrable Interest Subordinated Debentures, Series A, due 2025, until further notice in accordance with the indenture. The corresponding quarterly payments on the 7.90% QUIPS, issued by PG&E Capital I due on April 2, 2001, have been similarly deferred. Distributions can be deferred up to a period of five years under the terms of the indenture. Per the indenture, investors will accumulate interest on the unpaid distributions at the rate of 7.90%. On April 12, 2001, Bank One, N.A., as successor-in-interest to The First National Bank of Chicago, gave notice that an Event of Default exists under the Trust Agreement in that the Utility on April 6, 2001 filed a voluntary petition for relief under Chapter 11 of the United States Bankruptcy Code. Pursuant to the Trust Agreement, the bankruptcy filing by the Utility constitutes an Early Termination Event. The Trust Agreement directs that upon the occurrence of an Early Termination Event, the Trust shall be liquidated by the Trustees as expeditiously as the Trustees determine to be possible by distributing, after satisfaction of liabilities to creditors of the Trust, to each Security holder a like amount of the Utility's 7.90% Deferrable Interest Subordinated Debentures, Series A, due 2025. NOTE 8: 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 $12 million (property damage) and $4 million (business interruption), in each case per policy period, in the event losses exceed the resources of NEIL. The Utility has purchased primary insurance of $200 million for public liability claims resulting from a nuclear incident. The Utility has secondary financial protection, which provides an additional $9.3 billion in coverage, which is mandated by federal legislation. It provides for loss sharing among utilities owning nuclear generating facilities if a costly incident occurs. If a nuclear incident results in claims in excess of $200 million, then the Utility may be assessed up to $176 million per incident, with payments in each year limited to a maximum of $20 million per incident. Environmental Remediation Utility - ------- The Utility may be required to pay for environmental remediation at sites where it has been or may be a potentially responsible party under the Comprehensive Environmental Response, Compensation, and Liability Act, and similar state environmental laws. These sites include former manufactured gas plant sites, power plant sites, and sites used by it for the storage or disposal of potentially hazardous materials. Under federal and California laws, the Utility may be responsible for remediation of hazardous substances, even if it did not deposit those substances on the site. The Utility records in environmental remediation liability when site assessments indicate remediation is probable and a range of reasonably likely clean-up costs can be estimated. The Utility reviews its remediation liability quarterly for each identified site. The liability is an estimate of costs for site investigations, remediation, operations and maintenance, monitoring, and site closure. The remediation costs also reflect (1) current technology, (2) enacted laws and regulations, (3) experience gained at similar sites, and (4) the probable level of involvement and financial condition of other potentially responsible parties. Unless there is a better estimate within the range of possible costs, the Utility records the lower end of this range. At March 31, 2001, the Utility expects to spend $307 million for hazardous waste remediation costs at identified sites, including divested fossil-fueled power plants. The cost of the hazardous substance remediation ultimately undertaken by the Utility is difficult to estimate. A change in estimate may occur in the near term due to uncertainty concerning the Utility's responsibility, the complexity of environmental laws and regulations, and the selection of 29compliance alternatives. If other potentially responsible parties are not financially able to contribute to these costs or further investigation indicates that the extent of contamination or necessary remediation is greater than anticipated, the Utility could spend as much as $460 million on these costs. The Utility estimates the upper limit of the range using assumptions least favorable to the Utility, based upon a range of reasonably possible outcomes. Costs may be higher if the Utility is found to be responsible for clean-up costs at additional sites or expected outcomes change. The Utility had an environmental remediation liability of $307 million and $320 million at March 31, 2001 and December 31, 2000, respectively. The $307 million accrued at March 31, 2001 includes (1) $139 million related to the pre-closing remediation liability, associated with the divested generation facilities discussed further in the "Generation Divestiture" section of Note 2, and (2) $168 million related to remediation costs for those generation facilities that the Utility still owns, manufactured gas plant sites, and gas gathering compressor stations. Of the $307 million environmental remediation liability, the Utility has recovered $193 million through rates, and expects to recover another $84 million in future rates. The Utility is seeking recovery of the remainder of its costs from insurance carriers and from other third parties as appropriate. In December 1999, the Utility was notified by the purchaser of its former Moss Landing power plant that it had identified a cleaning procedure used at the plant that released heated water from the intake, and that this procedure is not specified in the plant's National Pollutant Discharge Elimination System (NPDES) permit issued by the Central Coast Regional Water Quality Control Board (Central Coast Board). The purchaser notified the Central Coast Board of its findings. In March 2000, the Central Coast Board requested the Utility to provide specific information regarding the "backflush" procedure used at Moss Landing. The Utility's investigation indicated that while it owned Moss Landing, significant amounts of water were discharged from the cooling water intake. While the Utility's investigation did not clearly indicate that discharged waters had a temperature higher than ambient receiving water, the Utility believes that the temperature of the discharged water was higher than that of the ambient receiving water. In December 2000, the executive officer of the Central Coast Board made a settlement proposal to the Utility under which it would pay $10 million, a portion of which would be used for environmental projects and the balance of which would constitute civil penalties. Settlement negotiations are continuing. The Utility's Diablo Canyon employs a "once through" cooling water system which is regulated under a NPDES Permit issued by the Central Coast Board. This permit allows Diablo Canyon to discharge the cooling water at a temperature no more than 22 degrees above ambient receiving water, and requires that the beneficial uses of the water be protected. The beneficial uses of water in this region include industrial water supply, marine and wildlife habitat, shellfish harvesting, and preservation of rare and endangered species. In January 2000, the Central Coast Board issued a proposed draft Cease and Desist Order (CDO) alleging that, although the temperature limit has never been exceeded, the Diablo Canyon's discharge was not protective of beneficial uses. In October 2000, the Central Coast Board and the Utility reached a tentative settlement of this matter pursuant to which the Central Coast Board has agreed to find that the Utility's discharge of cooling water from the Diablo Canyon plant protects beneficial uses and that the intake technology reflects the "best technology available", under Section 316(b) of the Federal Clean Water Act. As part of the settlement, the Utility will take measures to preserve certain acreage north of the plant and will fund approximately $4.5 million in environmental projects related to coastal resources. The parties are negotiating the documentation of the settlement. The final agreement will be subject to public comment and will be incorporated in a consent decree to be entered in California's Superior Court. PG&E Corporation believes the ultimate outcome of these matters will not have a material impact on its or the Utility's financial position or results of operations. PG&E National Energy Group - -------------------------- The U.S. Environmental Protection Agency (EPA) and the U.S. Department of Justice have initiated enforcement actions against a number of electric utilities, several of which have entered into substantial settlements for alleged Clean Air Act violations related to modifications (sometimes more than 20 years ago) of existing coal-fired generating facilities. In May 2000, PG&E NEG received a request for information seeking detailed operating and maintenance histories for the Salem Harbor and Brayton Point power plants and in November 2000, EPA visited 30both facilities. PG&E NEG believes this request for information is part of EPA's industry-wide investigation of coal-fired plants' compliance with the Clean Air Act requirements governing plant modifications. PG&E NEG also believes that any changes made to the plants were routine maintenance or repairs and, therefore, did not require permits. EPA has not issued a notice of violation or filed any enforcement action against PG&E NEG at this time. Nevertheless, if EPA disagrees with PG&E NEG's conclusion with respect to the changes made at the facilities, and successfully brings an enforcement action against PG&E NEG, then penalties may be imposed and further emission reductions might be necessary at these plants. In addition to the EPA, states may impose more stringent air emissions requirements. On May 11, 2001, the Massachusetts Department of Environmental Protection issued regulations imposing new restrictions of certain air emissions from existing coal-fired power plants. These requirements will primarily impact PG&E NEG's Salem Harbor and Brayton Point generating facilities. Through 2008, it may be necessary to spend approximately $265 million to comply with these regulations. In addition, with respect to approximately 600 megawatts (MW) (or about 12%) of PG&E NEG's New England capacity, it may be necessary to implement fuel conversion, limit operations, or install additional environmental controls. PG&E Gen's existing power plants, including USGenNE facilities, are subject to federal and state water quality standards with respect to discharge constituents and thermal effluents. Three of the fossil-fueled plants owned and operated by USGenNE are operating pursuant to NPDES permits that have expired. For the facilities whose NPDES permit have expired, permit renewal applications are pending, and it is anticipated that all three facilities will be able to continue to operate in substantial compliance with their prior permits until new permits are issued. It is estimated that USGenNE's cost to comply with the new permit conditions could be as much as $60 million through 2005. It is possible that the new permits may contain more stringent limitations than prior permits. During September 2000, USGenNE signed a series of agreements that require, among other things, USGenNE to alter its existing waste water treatment at two facilities by replacing certain unlined treatment basins, submit and implement a plan for the closure of such basins, and perform certain environmental testing at the facilities. Although the outcome of such environmental testing could lead to higher costs, the total expected cost of these improvements, which are underway, is $21 million. PG&E NEG anticipates spending up to approximately $330 million, net of insurance proceeds, through 2008, for environmental compliance at currently operating facilities, which primarily addresses: (a) new Massachusetts air regulations made public on April 23, 2001 affecting Brayton Point and Salem Harbor Stations; (b) wastewater permitting requirements that may apply to Brayton Point, Salem Harbor and Manchester Street Stations; and (c) requirements that are reflected in a consent decree concerning wastewater treatment facilities at Salem Harbor and Brayton Point stations. LEGAL MATTERS Utility The Utility's Chapter 11 bankruptcy on April 6, 2001, discussed in Note 4 automatically stayed the litigation described below against the Utility. Chromium Litigation - ------------------- Several civil suits are pending against the Utility in California state court. The suits seek an unspecified amount of compensatory and punitive damages for alleged personal injuries resulting from alleged exposure to chromium in the vicinity of the Utility's gas compressor stations at Hinckley, Kettleman, and Topock, California. Currently, there are claims pending on behalf of approximately 1,160 individuals. The Utility is responding to the suits and asserting affirmative defenses. The Utility will pursue appropriate legal defenses, including statute of limitations, exclusivity of worker's compensation laws, and factual defenses, including lack of exposure to chromium and the inability of chromium to cause certain of the illnesses alleged. The Utility has 31recorded a legal reserve in its financial statements in the amount of $160 million for these matters. PG&E Corporation and the Utility believe that, after taking into account the reserves recorded as of December 31, 2000, the ultimate outcome of this matter will not have a material adverse impact on PG&E Corporation's or the Utility's financial condition or future results of operations. Wilson vs. PG&E Corporation and Pacific Gas and Electric Company - ---------------------------------------------------------------- On February 13, 2001, two complaints were filed against PG&E Corporation and the Utility in the Superior Court of the State of California, San Francisco County: Richard D. Wilson v. Pacific Gas and Electric Company et al. (Wilson I), and Richard D. Wilson v. Pacific Gas and Electric Company, et al. (Wilson II). In Wilson I, the plaintiff alleges that in 1998 and 1999, PG&E Corporation violated its fiduciary duties and California Business and Professions Code Section 17200 by causing the Utility to repurchase shares of Pacific Gas and Electric Company common stock from PG&E Corporation at an aggregate price of $2,326 million. The complaint alleges an unlawful business act or practice under Section 17200 because these repurchases allegedly violated PG&E Corporation's fiduciary duties, a first priority capital requirement allegedly imposed by the CPUC's decision approving the formation of a holding company, and also an implicit public trust imposed by Assembly Bill 1890, which granted authority for the issuance of rate reduction bonds. The complaint seeks to enjoin the repurchase by the Utility of any more of its common stock from PG&E Corporation or other entities or persons unless good cause is shown, and seeks restitution from PG&E Corporation of $2,326 million, with interest, on behalf of the Utility. The complaint also seeks an accounting, costs of suit, and attorney's fees. In Wilson II, the plaintiff alleges that PG&E Corporation, the Utility, and other subsidiaries have been parties to a tax-sharing arrangement under which PG&E Corporation annually files consolidated federal and state income tax returns for, and pays, the income taxes of PG&E Corporation and participating subsidiaries. According to the plaintiff, between 1997 and 1999, PG&E Corporation collected $2,957 million from the Utility under this tax-sharing agreement. Plaintiff alleges that these monies were held under an express and implied trust to be used by PG&E Corporation to pay the Utility's share of income taxes under the tax-sharing arrangement. Plaintiff alleges that PG&E Corporation overcharged the Utility $663 million under the tax-sharing arrangement and has declined voluntarily to return these monies to the Utility, in violation of the alleged trust, the alleged first priority capital condition, and California Business and Professions Code Section 17200. The complaint seeks to enjoin PG&E Corporation from engaging in the activities alleged in the complaint (including the tax-sharing arrangement), and seeks restitution from PG&E Corporation of $663 million, with interest, on behalf of the Utility. The complaint also seeks an accounting, costs of suit, and attorney's fees. PG&E Corporation's and the Utility's analysis of these complaints is at a preliminary stage, but PG&E Corporation and the Utility believe them to be without merit and intend to present a vigorous defense. The Utility filed notice of automatic stay on April 11, 2001, pursuant to the Bankruptcy Code. On April 19, 2001, the court signed stipulations between PG&E Corporation and plaintiffs to stay all proceedings in the cases as against PG&E Corporation. PG&E Corporation and the Utility are unable to predict whether the outcome of this litigation, if it were to proceed, will have a material adverse effect on their financial condition or results of operation. Federal Securities Lawsuit - -------------------------- On April 16, 2001, a complaint was filed against PG&E Corporation and the Utility in the U.S. District Court for the Central District of California. The complaint alleges that PG&E Corporation and the Utility violated federal securities laws, generally acceptable accounting principles, and other regulations or accounting rules, by issuing allegedly false and misleading financial statements in the second and third quarters of 2000, reporting net income of $753 million for the nine-month period ending September 30, 2000, instead of an alleged net loss for that period of up to $2.1 billion. According to the complaint, defendants failed to properly account in the second and third quarters of 2000 for alleged under-collected power purchase costs and PG&E Corporation announced in March 2001 that it intended to take a $4.1 billion write-off. Plaintiff purports to bring the action individually and on behalf of a class of individuals who purchased PG&E Corporation's common stock during the period from June 1, 2000, to March 31, 322001, claiming that the alleged misrepresentations caused them to pay inflated prices for the stock. Plaintiff seeks damages in excess of $2.4 billion, punitive damages, interest, injunctive relief, and attorneys' fees. The complaint was filed after the Utility filed for reorganization under Chapter 11 of the U.S. Bankruptcy Code. The Utility informed plaintiff that the action is stayed by the automatic stay provisions of the Bankruptcy Code and on or about April 23, 2001, plaintiff filed a notice of voluntary dismissal without prejudice with respect to the Utility. Analysis of the complaint by PG&E Corporation is at a preliminary stage, but PG&E Corporation believes the allegations to be without merit and intends to present a vigorous defense. PG&E Corporation is unable to predict whether the outcome of this litigation will have a material adverse effect on its financial condition or results of operation. PG&E National Energy Group PG&E NEG is involved in various litigation matters in the ordinary course of its business. PG&E NEG is not currently involved in any litigation that is expected, either individually or in the aggregate, to have a material adverse effect on financial condition or results of operations of PG&E Corporation. Recorded Liability for Legal Matters In accordance with SFAS No. 5 "Accounting for Contingencies," PG&E Corporation makes a provision for a liability when both it is probable that a liability has been incurred and the amount of the loss can be reasonably estimated. These provisions are reviewed quarterly and adjusted to reflect the impacts of negotiations, settlements, rulings, advice of legal counsel, and other information and events pertaining to a particular case. The following table reflects the current year's activity to the recorded liability for legal matters: PG&E Corporation and Utility ----------- (in millions) Beginning balance, January 1, 2001 $185 Provisions for Liabilities 4 Payments (2) Adjustments (3) ---- Ending balance, March 31, 2001 $184 ---- NOTE 9: SEGMENT INFORMATION PG&E Corporation has identified three reportable operating segments, which were determined based on similarities in economic characteristics, products and services, types of customers, methods of distributions, the regulatory environment, and how information is reported to PG&E Corporation's key decision makers. As discussed below, these segments represent a change in the reportable segments. In accordance with accounting principles generally accepted in the United States of America, prior year segment information has been restated to conform to the current segment presentation. The Utility is one reportable operating segment and the other two are part of PG&E Corporation's PG&E NEG. These three reportable operating segments provide products and services and are subject to different forms of regulation or jurisdictions. PG&E Corporation's reportable segments are described below. Utility - ------- PG&E Corporation's Northern and Central California energy utility subsidiary, Pacific Gas and Electric Company, provides natural gas and electric service to its customers. 33PG&E National Energy Group - -------------------------- PG&E Corporation's subsidiary, the PG&E National Energy Group, Inc. (PG&E NEG) is an integrated energy company with a strategic focus on power generation, power plant development, natural gas transmission, and wholesale energy marketing and trading in North America. PG&E NEG has integrated its generation, development and energy marketing and trading activities to increase the returns from its operations, identify and capitalize on opportunities to increase its generating and pipeline capacity, create energy products in response to dynamic markets and manage risks. The newly combined business has been renamed PG&E Integrated Energy and Marketing (PG&E Energy), which includes PG&E Generating Company, LLC and its affiliates, and PG&E Energy Trading Holdings Corporation which owns PG&E Energy Trading-Power, L.P., PG&E Energy Trading-Gas Corporation, and their affiliates; and PG&E Interstate Pipeline Operations (PG&E Pipeline), which includes PG&E Gas Transmission Corporation (PG&E GTN), PG&E Gas Transmission, Texas Corporation, and PG&E Gas Transmission Teco, Inc., and their subsidiaries. During the fourth quarter of 2000, PG&E NEG sold its Texas natural gas and natural gas liquids business operated through PG&E Gas Transmission, Texas Corporation and PG&E Gas Transmission Teco, Inc. and their subsidiaries. Also during 2000, PG&E NEG sold its energy services unit, PG&E Energy Services Corporation. Segment information for the three months ended March 31, 2001, and 2000 was as follows:
National Energy Group Integrated Interstate NEG Other & Total Energy and Pipeline Elimini- Elimi- (in millions) Utility NEG Marketing Operations nations nations(2) TotalFor the three months ended March 31, 2001 Operating revenues $ 2,560 $ 4,113 $ 4,066 $ 56 $ (9) $ - $ 6,673 Intersegment revenues(1) 2 93 84 9 - (95) - Total operating revenues 2,562 4,206 4,150 65 (9) (95) 6,673 Net Income (loss) (1,000) 54 35 20 (1) (5) (951) Total assets at March 31, 2001(3) $ 22,455 $13,252 $ 11,833 $ 1,188 $ 231 $ 358 $ 36,065 For the three months ended March 31, 2000(4) Operating revenues $ 2,214 $ 2,788 $ 2,523 $ 257 $ 8 $ - $ 5,002 Intersegment revenues(1) 4 29 4 25 - (33) - Total operating revenues 2,218 2,817 2,527 282 8 (33) 5,002 Net Income 228 52 38 14 - - 280 Total assets at March 31, 2000(3) $ 21,357 $ 8,308 $ 5,976 $ 2,332 - $ (244) $ 29,421(1) Inter-segment electric and PG&E gas revenues are recorded at market prices, which for the Utility and PG&E Pipeline are tariffed rates prescribed by the CPUC and the FERC, respectively. (2) Includes PG&E Corporation, Pacific Venture Capital, PG&E Telecom, and elimination entries. (3) Assets of PG&E Corporation are included in "Other & Eliminations" column exclusive of investment in its subsidiaries. (4) Segment information for the prior year has been restated for comparative purposes as required by SFAS No. 131. 34NOTE 10: REVISION FOOTNOTE Subsequent to the issuance of PG&E Corporation's December 31, 2000, and March 31, 2001 Consolidated Financial Statements, management determined that the assets and liabilities relating to certain leases should have been consolidated. The facilities associated with the loans were under construction during 1999, 2000, and 2001. A summary of the significant effects of the revisions to the Condensed Statements of Consolidated Operations, Condensed Consolidated Balance Sheets, and Condensed Consolidated Statements of Cash Flows are as follows:
As Previously As As Previously As (in millions) Reported Revised Reported Revised ----------------------------------------------------------- Three months ended March 31, ----------------------------------------------------------- 2001 2000 -----------------------------------------------------------Condensed Statements of Consolidated Operations: Total Operating Revenues $ 6,675 $ 6,673 $ 5,008 $ 5,002 Total Operating Expenses 8,015 8,013 4,332 4,326 Balance at ----------------------------------------------------------- Condensed Consolidated Balance Sheets: March 31, 2001 December 31, 2000 ----------------------------------------------------------- Cash and cash equivalents $ 650 $ 682 $ 899 $ 925 Accounts receivable - customers 3,007 3,030 4,342 4,340 Property, plant and equipment - Construction work in progress 1,034 1,852 900 1,605 Other non-current assets 2,668 2,873 2,398 2,530 Total Assets 34,987 36,065 35,291 36,152 Accounts payable - trade creditors 6,240 6,299 5,856 5,896 Other current liabilities 1,733 1,739 1,563 1,570 Long-term debt 5,593 6,606 4,736 5,550 Three Months Ended March 31, ----------------------------------------------------------- Condensed Statements of Consolidated Cash Flows: 2001 2000 ----------------------------------------------------------- Accounts receivable - trade $ 1,335 $ 1,310 $ 12 $ 40 Accounts payable 496 515 (89) (90) Other - net, from operating activities 10 9 26 26 Capital expenditures (352) (538) (321) (450) Long-term debt issued 906 1,105 - 108 Cash and Cash Equivalents at March 31 650 682 260 267 Cash paid for interest (net of amounts capitalized) 218 235 117 11935Item 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), delivers electric service to approximately 4.6 million customers and natural gas service to approximately 3.8 million customers. On April 6, 2001, the Utility filed a voluntary petition for relief under the provisions of Chapter 11 of the U.S. Bankruptcy Code. Pursuant to Chapter 11 of the U.S. Bankruptcy Code, the Utility retains control of its assets and is authorized to operate its business as a debtor in possession while being subject to the jurisdiction of the Bankruptcy Court. The factors causing the Utility to take this action are discussed in this Management's Discussion and Analysis (MD&A) and in Notes 2 and 4 of the Notes to the Condensed Consolidated Financial Statements. PG&E Corporation's subsidiary, the PG&E National Energy Group, Inc. (PG&E NEG) is an integrated energy company with a strategic focus on power generation, power plant development, natural gas transmission and wholesale energy marketing and trading in North America. PG&E NEG has integrated its generation, development and energy marketing and trading activities to increase the returns from its operations, identify and capitalize on opportunities to increase its generating and pipeline capacity, create energy products in response to dynamic markets and manage risks. The newly combined business has been renamed PG&E Integrated Energy and Marketing (PG&E Energy), which includes PG&E Generating Company, LLC and its affiliates, and PG&E Energy Trading Holdings Corporation which owns PG&E Energy Trading-Power, L.P., PG&E Energy Trading-Gas Corporation, and their affiliates; and PG&E Interstate Pipeline Operations (PG&E Pipeline), which includes PG&E Gas Transmission Corporation (PG&E GTN), PG&E Gas Transmission, Texas Corporation and PG&E Gas Transmission Teco, Inc. and their subsidiaries. During the fourth quarter of 2000, PG&E NEG sold its Texas natural gas and natural gas liquids business operated through PG&E Gas Transmission, Texas Corporation and PG&E Gas Transmission Teco, Inc. and their subsidiaries. Also during 2000, PG&E NEG sold its energy services unit, PG&E Energy Services Corporation. This is a combined Quarterly Report on Form 10-Q/A of PG&E Corporation and the Utility. It includes separate consolidated financial statements for each entity. The Condensed 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. This MD&A should be read in conjunction with the Condensed Consolidated Financial Statements included herein. Further, this Quarterly Report should be read in conjunction with PG&E Corporation's and the Utility's Consolidated Financial Statements and Notes to Consolidated Financial Statements incorporated by reference in their combined 2000 Annual Report on Form 10-K/A. Subsequent to the issuance of PG&E Corporation's 2000 and 1999 Consolidated Financial Statements and unaudited report for the quarterly period ended March 31, 2001, management determined that the assets and liabilities relating to certain leases should have been consolidated. The facilities associated with the leases were under construction during 2001 (see Note 10). This combined Quarterly Report on Form 10-Q/A, including this MD&A, contains forward-looking statements about the future that are necessarily subject to various risk and uncertainties. These statements are based on current expectations and assumptions which management believes are reasonable and on information currently available to management. These forward-looking statements are identified by words such as "estimates," "expects," "anticipates," "plans," "believes," and other similar expressions. Actual results could differ materially from those contemplated by the forward-looking statements. Although PG&E Corporation and the Utility are not able to predict all of the factors that may affect future results, some of the factors that could cause future results to differ materially from those expressed or implied by the forward-looking statements, or historical results include: . the outcome of the Utility's regulatory proceedings; . whether and to what extent the Utility is determined to be responsible for the Independent System Operator's (ISO)charges billed to the Utility; 36. the terms and conditions of the reorganization plan that is ultimately adopted by the Bankruptcy Court and the extent to which the Utility's bankruptcy proceedings affect the operations of PG&E Corporation's other businesses; . the regulatory, judicial, or legislative actions (including ballot initiatives) that may be taken to meet future power needs in California, mitigate the higher wholesale power prices, provide refunds for prior power costs, or address the Utility's financial condition; . the extent to which the Utility's undercollected wholesale power purchase costs may be collected from customers; . any changes in the amount of transition costs the Utility is allowed to collect from its customers, and the timing of the completion of the Utility's transition cost recovery; . future markets prices for electricity and future fuel prices, which in part, are influenced by future weather conditions, the availability of hydroelectric power, and the development of competitive markets; . the method and timing of valuation and future ratemaking for, the Utility's hydroelectric and other non-nuclear generation assets; . future operating performance at the Diablo Canyon Nuclear Power Plant (Diablo Canyon) and the future ratemaking applicable to Diablo Canyon; . legislative or regulatory changes, including the pace and extent of the ongoing restructuring of the electric and natural gas industries across the United States; . future sales levels and economic conditions; . the extent to which our current or planned generation, pipeline, and storage capacity development projects of PG&E NEG, a wholly owned subsidiary of PG&E Corporation, are completed and the pace and cost of such completion; including the extent to which commercial operations of these development projects are delayed or prevented because of various development and construction risks; . the extent and timing of generating, pipeline, and storage capacity expansion and retirement by others; . illiquidity in the commodity energy market and PG&E NEG's ability to provide the credit enhancements necessary to support its trading activities; . PG&E NEG's ability to obtain financing for its planned development projects and its ability to refinance PG&E NEG's and its subsidiaries' existing indebtedness on reasonable terms; . restrictions imposed upon PG&E NEG under certain term loans of PG&E Corporation; . fluctuations in commodity gas, natural gas liquids, and electric prices and the ability to successfully manage such price fluctuations; . the effect of compliance with existing and future environmental laws, regulations, and policies, the cost of which could be significant; and . the outcome of pending litigation. As the ultimate impact of these and other factors is uncertain, these and other factors may cause future earnings to differ materially from results or outcomes we currently seek or expect. Each of these factors is discussed in greater detail in this MD&A. 37In this MD&A, we first discuss the California energy crisis and its impact on our liquidity. We then discuss statements of cash flows and financial resources, and our results of operations for first quarter 2001 and 2000. Finally, we discuss our competitive and regulatory environment, our risk management activities, and various uncertainties that could affect future earnings. Our MD&A applies to both PG&E Corporation and the Utility. LIQUIDITY AND FINANCIAL RESOURCES The California Energy Crisis The state of California is in the midst of an energy crisis. The cost of wholesale power has risen dramatically since June 2000. Rolling blackouts have occurred as a result of a broken deregulated electricity market. Because of this crisis, PG&E Corporation and the Utility have experienced a significant deterioration in their liquidity and consolidated financial position. The Utility's credit rating has deteriorated to below investment grade level. PG&E Corporation and the Utility recognized a fourth quarter charge to earnings of $6.9 billion ($4.1 billion after tax) to reflect the fact that the Utility could no longer conclude that its generation-related regulatory assets and undercollected purchased power costs were probable of recovery from ratepayers. In addition, during the first quarter of 2001, the Utility recognized after tax charges of $1.1 billion representing undercollected power costs incurred during that period. These charges resulted in accumulated deficits at March 31, 2001, of $3 billion for both the Utility and PG&E Corporation. As more fully discussed herein, the Utility had been working with regulators and state and federal legislators and California leaders in an effort to seek an overall solution to the California energy crisis. However, the ongoing uncertainty as to the timing and extent of any solution, in addition to increasing debt and regulatory changes, caused the Utility to seek protection from its creditors through a Chapter 11 Bankruptcy Filing. The filing for bankruptcy protection and the related uncertainty around any reorganization plan, that is ultimately adopted, will have a significant impact on the Utility's future liquidity and results of operations. See Notes 2,3, and 4 of the Notes to the Condensed Consolidated Financial Statements for a detailed discussion of the California energy crisis and the events leading up to the charge incurred by PG&E Corporation and the Utility. A discussion of the current and future liquidity and financial resources, and mitigation efforts undertaken by the Utility and PG&E Corporation follows. Pacific Gas and Electric Company - -------------------------------- The California energy crisis described in Note 2 of the Notes to the Condensed Consolidated Financial Statements has had a significant negative impact on the liquidity and financial resources of the Utility. Beginning in June 2000, the wholesale price of electric power in California steadily increased to an average cost of 18.16 cents per kilowatt-hour (kWh) for the seven-month period of June 2000 through December 2000, as compared to an average cost of 4.23 cents per kWh for the same period in 1999. Under California Assembly bill 1890 (AB 1890), the Utility's electric rates were frozen at levels that allowed approximately 5.4 cents per kWh to be charged to the Utility's customers as reimbursement for power costs incurred by the Utility on behalf of its retail customers. The excess of wholesale electricity costs above the generation-related cost component available in frozen rates resulted in an undercollection at December 31, 2000, of approximately $6.6 billion, and rose to approximately $8.5 billion by March 31, 2001. The difference between the actual costs incurred to purchase power and the amount recovered from customers was funded through a series of borrowings. In October 2000, the Utility fully utilized its existing $1 billion revolving credit facility to support the Utility's commercial paper program and other liquidity requirements. On October 18, 2000, the Utility obtained an additional $1 billion, 364-day revolving credit facility to support the issuance of additional commercial paper. On November 1, 2000, the Utility issued $1 billion of short-term floating rate notes and $680 million of five-year notes. On November 22, 2000, the Utility issued an additional $240 million of short term floating rate notes. On December 1, 2000, the size of the $1 billion, 364-day revolving credit facility was reduced to $850 million in order to comply with syndication agreement. At December 31, 2000, the Utility had borrowed $614 million against its five-year revolving credit agreement, had issued $1,225 million of commercial 38paper, and had issued $1,240 million of floating rate notes. In response to the growing crisis, on January 4, 2001, the CPUC approved an interim one-cent per kWh rate increase, which would raise approximately $70 million in cash per month for three months. Even if all this cash had been available to the Utility immediately, $210 million represented approximately one week's worth of net power purchases at the then current prices. Thus, the rate increase did not raise enough cash for the Utility to pay its ongoing wholesale electric energy procurement bills or make further borrowing possible. On January 10, 2001 the Board of Directors of the Utility suspended the payment of its fourth quarter 2000 common stock dividend in an aggregate amount of $110 million payable on January 18, 2001, to PG&E Corporation and PG&E Holdings, Inc., a wholly-owned subsidiary of the Utility. In addition, the Utility's Board of Directors decided not to declare the regular preferred stock dividends for the three-month period ending January 31, 2001, normally payable on February 15, 2001. Dividends on all Utility preferred stock are cumulative. Until cumulative dividends on preferred stock are paid, the Utility may not pay any dividends on its common stock, nor may the Utility repurchase any of its common stock. On January 16 and 17, 2001, the outstanding bonds of the Utility were downgraded to below investment grade status. Standard and Poor's (S&P) stated that the downgrade reflected the heightened probability of the Utility's imminent insolvency and the resulting negative financial implications for the PG&E Corporation and affiliated companies because, among other reasons, (1) some of the Utility's principal trade creditors were demanding that sizeable cash payments be made as a pre-condition to the purchase of natural gas and electric power necessary for on-going business operations; (2) neither legislative nor negotiated solutions to the California utilities' financial situation appeared to be forthcoming in a timely manner, which continued to impede access to financial markets for the working capital needed to avoid insolvency; and (3) Southern California Edison's (SCE) decision to default on its obligation to pay principal and interest due on January 16, 2001, diminished the prospects for the Utility's access to capital markets. This downgrade to below investment grade status was an event of default under one of the Utility's revolving credit facilities and precluded the Utility from access to the capital markets. As a result, the banks stopped funding under the revolving credit facility. On January 17, 2001, the Utility began to default on maturing commercial paper obligations. In addition, the Utility was no longer able to meet its obligations to generators, qualifying facilities (QFs), the ISO, and Power Exchange (PX), and began making partial payments of amounts owed. After the downgrade, the PX notified the Utility that the ratings downgrade required the Utility to post collateral for all transactions in the PX day-ahead market. Since the Utility was unable to post such collateral, the PX suspended the Utility's trading privileges effective January 19, 2001, in the day-ahead market. The PX also sought to liquidate the Utility's block-forward contracts for the purchase of power. On January 25, 2001, a California Superior Court judge granted the Utility's application for a temporary restraining order, which thereby restrained and enjoined the PX and its agents from liquidating the Utility's contracts in the block-forward market, pending hearing on preliminary injunction on February 5, 2001. Immediately before the hearing on the preliminary injunction, California Governor Gray Davis, acting under California's Emergency Services Act, commandeered the contracts for the benefit of the state. Under the Act, the state must pay the Utility the reasonable value of the contracts, although the PX may seek to recover the monies that the Utility owes to the PX from any proceeds realized from those contracts. Discussions and negotiations on this issue are currently ongoing between the state and the Utility. On January 19, 2001, the Utility was no longer able to continue purchasing power for its customers because of lack of creditworthiness and the State of California authorized the California Department of Water Resources (DWR) to purchase electricity for the Utility's customers. Assembly Bill 1X (AB 1X) was passed on February 1, 2001, authorizing the DWR to enter into contracts for the purchase and sale of electric power and to issue revenue bonds to finance electricity purchases. The DWR has entered into long-term contracts with several generators for the supply of electricity. However, it continues to purchase significant amounts of power on the spot market at prevailing market prices. The DWR is not purchasing electricity for the Utility's entire net open position (the amount of power that cannot be met by the Utility's own or contracted-for generation). To the extent that the DWR is not purchasing electricity for the entire net open position, the remainder is being procured by the ISO. To that extent, the ISO is charging the Utility for those purchases. 39As a result of (1) the failure by the state to assume the full procurement responsibility for the Utility's net open position, as was provided under AB 1X, (2) the negative impact of recent actions by the CPUC that created new payment obligations for the Utility and undermined its ability to return to financial viability, (3) a lack of progress in negotiations with the state to provide a solution for the energy crisis, and (4) the adoption by the CPUC of an illegal and retroactive accounting change that would appear to eliminate the Utility's true undercollected purchased power costs, the Utility filed a voluntary petition for relief under provisions of Chapter 11 of the U.S. Bankruptcy Code on April 6, 2001. Subject to the approval by the Bankruptcy Court, the Utility's intent is to pay its ongoing costs of doing business while seeking resolution of the wholesale energy crisis. It is the Utility's intention to continue to pay employees, vendors, suppliers, and other creditors to maintain essential distribution and transmission services. However, the Utility is not in a position to pay maturing or accelerated obligations, nor is the Utility in a position to pay the ISO, PX, and the QFs the amounts due for the Utility's power purchases above the amount included in rates for power purchase costs. The Utility's current actions are intended to allow the Utility to continue to operate while efforts to reach a regulatory or legislative solution continue. The Utility's plans will be subject to approval of the Bankruptcy Court. The Utility has also deferred quarterly interest payments on the Utility's 7.90% Deferrable Interest Subordinated Debentures, Series A, due 2025, until further notice in accordance with the indenture. The corresponding quarterly payments on the 7.90% Cumulative Quarterly Income Preferred Securities, Series A (QUIPS) issued by PG&E Capital I, due on April 2, 2001, have been similarly deferred. Distributions can be deferred up to a period of five years per the indenture. Per the indenture, investors will accumulate interest on the unpaid distributions at the rate of 7.90%. The weakened financial condition of the Utility also has impacted its ability to supply natural gas to its natural gas customers. In December 2000 and January 2001, several gas suppliers demanded prepayment, cash on delivery, or other forms of payment assurance before they would deliver gas, instead of the normal payment terms, under which the Utility would pay for the gas after delivery. As the Utility was unable to meet such demands at that time, several gas suppliers refused to supply gas, accelerating the depletion of the Utility's gas storage reserves and potentially exacerbating the electric power crisis if the Utility were required to divert gas from industrial users, including natural gas fired power plant operators. The U.S. Secretary of Energy issued a temporary order on January 19, 2001, requiring the gas suppliers to continue to make deliveries to avoid a worsening natural gas shortage emergency. However, this order expired on February 7, 2001, and certain companies, representing about 10% of the Utility's natural gas suppliers, terminated deliveries after the order expired. The Utility tried to mitigate the worsening supply situation by withdrawing more gas from storage and, when able, purchasing additional gas on the spot market. Additionally, on January 31, 2001, the CPUC authorized the Utility to pledge its gas account receivables and its gas inventories for up to 90 days (extended to 180 days in a CPUC draft decision issued on February 15, 2001) to secure gas for its core customers. At March 29, 2001, the amount of gas accounts receivables pledged was approximately $900 million. As of March 29, 2001, approximately 30% of the Utility's suppliers of natural gas had signed security agreements with the Utility and discussions were continuing with the Utility's other suppliers. Additionally, the Utility is currently implementing a program to obtain longer-term summer and winter supplies and daily spot supplies. PG&E Corporation - ---------------- The liquidity and financial condition crisis faced by the Utility also negatively impacted PG&E Corporation. Through December 31, 2000, PG&E Corporation funded its working capital needs primarily by drawing down on available lines of credit and other short-term credit facilities. At December 31, 2000, PG&E Corporation had borrowed $185 million against its five-year revolving credit agreement and had issued $746 million of commercial paper. Due to the credit ratings downgrades of PG&E Corporation, the banks refused any additional borrowing 40requests and terminated their remaining commitments under existing credit facilities. Commencing January 17, 2001, PG&E Corporation began to default on its maturing commercial paper obligations. Commencing on March 2, 2001, PG&E Corporation refinanced its debt obligations with $1 billion in aggregate proceeds of two term loans under a common credit agreement with General Electric Corporation and Lehman Commercial Paper Inc. In accordance with the credit agreement, the proceeds, together with other PG&E Corporation cash, were used to pay $501 million in commercial paper (including $457 million of commercial paper on which PG&E Corporation had defaulted), $434 million in borrowings under PG&E Corporation's long-term revolving credit facility, and $116 million to PG&E Corporation shareholders of record as of December 15, 2000, in satisfaction of a defaulted fourth quarter 2000 dividend. Further, approximately $99 million was used to pre-pay the first year's interest under the credit agreement and to pay transaction expenses associated with the debt restructuring. See Note 3 of the Notes to the Condensed Consolidated Financial Statements for a detailed description of the loan. On March 15, 2001, PG&E Corporation's corporate credit rating was withdrawn by S&P due to the March 2, 2001, refinancing of its obligations and the fact that PG&E Corporation had no more public debt to be rated. PG&E Corporation itself had had cash and short-term investment of $295 million at March 31, 2001, and believes that the funds will be adequate to maintain its continuing operations throughout 2001. In addition, PG&E Corporation believes that the holding company and its non-CPUC regulated subsidiaries are protected from the bankruptcy of the Utility. PG&E National Energy Group - -------------------------- In December 2000, and during the first quarter of 2001, PG&E Corporation and PG&E NEG undertook a corporate restructuring of PG&E NEG, known as a "ringfencing" transaction. The ringfencing complied with credit rating agency criteria, enabling PG&E NEG, PG&E GTN, and PG&E ET to receive or retain their own credit ratings based on their own creditworthiness. The ringfencing involved the creation or use of special purpose entities (SPEs) as intermediate owners between PG&E Corporation and its non-CPUC regulated subsidiaries. These SPEs are: PG&E National Energy Group, LLC, which owns 100% of the stock of PG&E NEG; PG&E GTN Holdings, LLC, which owns 100% of the stock of PG&E GTN; and PG&E Energy Trading Holdings, LLC, which owns 100% of the stock of PG&E Corporation's energy trading subsidiaries, PG&E Energy Trading-Gas Corporation, PG&E Energy Trading Holdings Corporation, and PG&E Energy Trading-Power, L.P. In addition, PG&E NEG's organizational documents were modified to include the same structural elements as the SPEs to meet credit rating agency criteria. Ringfencing was undertaken to enable PG&E NEG and various of its affiliates to obtain or maintain investment grade ratings. The SPEs require unanimous approval of their respective boards of directors, including an independent director, before they can (a) consolidate or merge with any entity, (b) transfer substantially all of their assets to any entity, or (c) institute or consent to bankruptcy, insolvency, or similar proceedings or actions. The SPEs may not declare or pay dividends unless the respective board of directors has unanimously approved such action and the company meets specified financial requirements. STATEMENTS OF CASH FLOWS PG&E Corporation normally funds investing activities from cash provided by operations after capital requirements and, to the extent necessary, external financing. Our policy is to finance our investments with a capital structure that minimizes financing costs, maintains financial flexibility, and, with regard to the Utility, complies with regulatory guidelines. PG&E Corporation Consolidated Net cash provided by PG&E Corporation's operating activities totaled $675 million and $1,089 million for the quarters ended March 31, 2001 and 2000, respectively. The decrease of $414 million between 2001 and 2000 is attributable to the California energy crisis previously discussed. 41Cash Flows from Investing Activities - ------------------------------------ Cash used in investing activities was $685 million during the quarter ended March 31, 2001, compared with $369 million used during the same quarter for 2000. In 2001, the primary use of cash for investing activities was $538 million for additions to property, plant, and equipment, compared with $450 million used for similar purposes in 2000. Cash Flows from Financing Activities - ------------------------------------ Cash used in financing activities for the quarter ended March 31, 2001, was $233 million compared with $735 million used for the same quarter in 2000. A loan in 2001 netted $906 million in proceeds which together with cash on hand and from operating activities, were used to repay defaulted commercial paper and other loans and the $109 million in dividends. The $735 million used in 2000 resulted from reduced borrowings of $547 million and a dividend payments of $108 million. Utility The following section discusses the Utility's significant cash flows from operating, investing, and financing activities for the three-month period ended March 31, 2001. Cash Flows from Operating Activities - ------------------------------------ Net cash provided by the Utility's operating activities totaled $520 million and $688 million for the quarters ending March 31, 2001 and 2000, respectively. The decrease of $168 million between 2001 and 2000 is primarily attributable to high energy costs offset by partial cash payment of these costs, and a tax refund received in the first quarter of 2001. Cash Flows from Investing Activities - ------------------------------------ The primary uses of cash for investing activities are additions to property, plant, and equipment. The Utility's capital expenditures for the three-month ended March 31, 2001, was $284 million. Cash Flows from Financing Activities - ------------------------------------ During the three months ended March 31, 2001, the Utility did not declare any preferred or common stock dividends, compared with a payment of dividends on its common stock of $122 million, for the quarter March 31, 2000. The Utility has suspended payment of its common and preferred dividends due to the negative impact on its financial condition from the ongoing energy crisis. Dividends on preferred stock are cumulative. Until cumulative dividends on preferred stock are paid, the Utility may not pay any dividends on its common stock. Until its financial condition is restored, the Utility is precluded from paying dividends to PG&E Corporation and PG&E Holdings, Inc. The Utility's long-term debt that either matured, was redeemed, or was repurchased during the three months ended March 31, 2001, totaled $187 million. Of this amount, $75 million related to the Utility's rate reduction bonds maturing, $93 million related to mortgage bonds maturing and $19 million related to the maturities and redemption of various of the Utility's medium-term notes and other debt. The Utility maintained a $1 billion revolving credit facility, which was due to expire in 2002. However this facility was cancelled by the bank-lending group on January 23, 2001, citing the event of default on non-payment of material debt. This facility was previously used to support the Utility's commercial paper program and other liquidity requirements. The total defaulted commercial paper outstanding at March 31, 2001, backed by this facility, was 42$873 million. At March 31, 2001, the Utility had drawn and had outstanding $938 million under this facility to repay maturing commercial paper. There was no new long-term debt issued in the period ended March 31, 2001. In addition, there was no additional commercial paper issued during this same period. Due to the bankruptcy filing, the Utility is unable at this time to repay unsecured pre-petition creditors. On May 1, 2001, the Utility did not make interest payments on the following unsecured debt: pollution loan control agreements, the 7.375% senior notes, and the $1.2 billion floating rates notes. The Utility received notice that another $100 million pollution control bond loan will be redeemed on May 18, 2001. Due to events of default under the credit agreement with a letter of credit, on April 27, 2001, the bank accelerated a pollution control loan and the $149 million loan was redeemed. In May 2001, three other letter of credit banks accelerated and redeemed pollution control loans totaling $305 million. All of these redemptions were funded by the letter of credit banks resulting in like obligations from the Utility to the banks. The Utility received notice from the QUIPS trustee that the Utility's bankruptcy filing was an event of default under the trust agreement and that the trustee will take steps to liquidate the trust and distribute 7.90% deferrable interest subordinated debentures to bondholders. PG&E National Energy Group General - ------- Historically, PG&E NEG has obtained cash from operations, borrowings under credit facilities, non-recourse project financing and other issuances of debt, issuances of commercial paper, and borrowings and capital contributions from PG&E Corporation. These funds have been used to finance operations, service debt obligations, fund the acquisition, development, and/or construction of generating facilities, and to start-up other businesses, finance capital expenditures, and meet other cash and liquidity needs. The projects that PG&E NEG develops typically require substantial capital investment. Some of the projects in which PG&E NEG has an interest have been financed primarily with non-recourse debt that is repaid from the project's cash flows. This debt is often secured by interests in the physical assets, major project contracts and agreements, cash accounts, and, in some cases, the ownership interest in that project subsidiary. These financing structures are designed to ensure that PG&E NEG is not contractually obligated to repay the project subsidiary debt; that is, they are "non-recourse" to PG&E NEG and to its subsidiaries not involved in the project. However, PG&E NEG has agreed to undertake financial support for some of its project subsidiaries in the form of limited obligations and contingent liabilities such as guarantees of specified obligations. To the extent PG&E NEG becomes liable under these guarantees or other agreements in respect of a particular project, it may have to use distributions it receives from other projects to satisfy these obligations. Cash Flows from Operating Activities - ------------------------------------ During the three months ended March 31, 2001, PG&E NEG used net cash of $186 million in operating activities. The decrease in operating cash was driven primarily by an increase in margin deposits related to its trading activities. Cash Flows from Investing Activities - ------------------------------------ During the three months ended March 31, 2001, PG&E NEG used net cash of $265 million in investing activities. PG&E NEG's cash outflows from investing activities were primarily attributable to capital expenditures on generating projects in construction and development. 43Cash Flows from Financing Activities - ------------------------------------ Net cash provided in financing activities was $166 million for the three months ended March 31, 2001. Net cash provided by financing activities resulted from long-term debt issued, offset by the repayment of long-term debt of $49 million. RESULTS OF OPERATIONS The table shows for the quarter ended March 31, 2001 and 2000, certain items from our Statement of Consolidated Operations detailed by Utility and PG&E NEG operations of PG&E Corporation. (In the "Total" column, the table shows the combined results of operations for these groups.) The information for PG&E Corporation (the "Total" column) includes the appropriate intercompany elimination. Following this table we discuss our results of operations. 44
PG&E National Energy Group -------------------------------------------- Integrated Interstate NEG Other & Total Energy and Pipeline Elimini- Elimi- (in millions) Utility NEG Marketing Operations nations nations(2) Total For the three months ended March 31, 2001Operating revenues $ 2,562 $ 4,206 $ 4,150 $ 65 $ (9) $ (95) $ 6,673 Operating expenses 3,982 4,121 4,097 25 (1) (90) 8,013 Operating loss (1,340) Interest income 35 Interest expense (247) Other income (expense), net (9) Income taxes (610) Net loss $ (951) Net cash provided by operating activities 675 Net cash used by investing activities (685) Net cash used by financing activities (233) EBITDA(2) $(1,365) $ 128 $ 84 $ 51 $ (7) $ (9) $ (1,246) For the three months ended March 31, 2000(3) Operating revenues $ 2,218 $ 2,817 $ 2,527 $ 282 $ 8 $ (33) $ 5,002 Operating expense 1,648 2,706 2,467 231 8 (28) 4,326 Operating loss 676 Interest income 24 Interest expense (183) Other income (expense), net (9) Income taxes 228 Net income $ 280 Net cash provided by operating activities 1,089 Net cash used by investing activities (369) Net cash used by financing activities (735) EBITDA(2) $ 864 $ 142 $ 84 $ 58 $- $ 8 $ 1,014(1) Net income on intercompany positions recognized by segments using mark-to- market accounting is eliminated. Intercompany transactions are also eliminated. (2) EBITDA is defined as income before provision for income taxes, interest expense, interest income, deferred electric procurement costs, depreciation and amortization, provision for loss on generation-related assets and undercollected purchased power costs. EBITDA is not intended to represent cash flows from operations and should not be considered as an alternative to net income as an indicator of the PG&E Corporation's operating performance or to cash flows as a measure of liquidity. Refer to the Statement of Cash Flows for the U.S. GAAP basis cash flows. PG&E Corporation believes that EBITDA is a standard measure commonly reported and widely used by analysts, investors, and other interested parties. However, EBITDA as presented herein may not be comparable to similarly titled measures reported by other companies. (3) Segment information for the prior period has been restated to conform with new segment presentation (see Note 9 of the Notes to the Condensed Consolidated Financial Statements). 45Overall Results - --------------- PG&E Corporation's financial position and results of operations continue to be impacted by the ongoing California energy crisis. Please see the Liquidity and Financial Resources section and Notes 2, 3, and 4 of the Notes to the Condensed Consolidated Financial Statements for more information on the California energy crisis. PG&E Corporation incurred a net loss for the quarter ended March 31, 2001 of $951 million from net income of $280 million for the same period in 2000. Of the $1,231 million decrease, the Utility's net loss allocated tocommon stock for thequarter ended March 31, 2001 accountednominees named in the 2002 joint proxy statement, for$1,228 millionthe ratification of thedecrease. The decrease in performance in the first quarter 2001 compared to 2000 resultsappointment ofoperations is attributable to the following factors: . The Utility's earnings were impactedDeloitte & Touche LLP asa result of the its undercollected purchased power costs ($1.1 billion, after taxes). Because of the lack of a regulatory, legislative, or judicial solution to the California energy crisis, the Utility cannot deferindependent public accountants forfuture recovery its uncollected purchased power costs. These costs have been expensed as incurred during the first quarter. . As a result of the high cost of power, with no offsetting revenues, the Utility2002, andPG&E Corporation have a net loss for California tax purposes through March 31, 2001. California law does not permit carrybacks of such losses and only permits carryforwards of 55% of such losses. As a result, PG&E Corporation was unable to recognize $33 million of state tax benefits because of California law. . As a result of the liquidity crisis attributable to the California energy crisis, PG&E Corporation has significantly increased its borrowings and unpaid debts accruing interest. Additionally, the effective interest rate paid on these new borrowings has also increased because of the higher risk associated with PG&E Corporation financial position. The incremental costs of these borrowings was $46 million, after-tax,for thefirst quarter of 2001. . PG&E Pipeline's earnings increased $6 million versus the prior year's first quarter because of higher short-term firm revenues, reflecting a high capacity load factor and strong pricing fundamentals on gas transportationfive management proposals tothe California and Pacific Northwest gas market. The effective tax rate for PG&E Corporation was 39.1% in 2001. PG&E Corporation has been unable to recognize the entire tax benefit of the loss carry forward in California described above. Dividends - --------- PG&E Corporation's historical quarterly common stock dividend was $0.30 per common share, which corresponded to an annualized dividend of $1.20 per common share. On January 10, 2001, the Board of Directors of PG&E Corporation suspended the payment of its fourth quarter 2000 common stock dividend of $0.30 per share declared by the Board of Directors on October 18, 2000 and payable on January 15, 2001 to shareholders of record as of December 15, 2000. The California energy crisis had created a liquidity crisis for PG&E Corporation, which led to the suspension of payments of dividends to conserve cash resources. These defaulted dividends were later paid on March 2, 2001 in conjunction with the refinancing of PG&E Corporation obligations, discussed above under the Liquidity and Financial Resources section. Additionally, the parent company refinancing agreements mentioned above prohibit dividends from being declared or paid until the term loans have been repaid. The agreement is for a term of two years with an option on behalf of PG&E Corporation to extend the term for an additional year. 46On January 10, 2001, the Utility suspended the payment of its fourth quarter 2000 common stock dividend of $110 million, declared in October 2000, to PG&E Corporation and its wholly owned subsidiary PG&E Holdings, Inc. Until its financial condition is restored, the Utility is precluded from paying dividends to PG&E Corporation and PG&E Holdings, Inc. Utility Overall Results - --------------- The Utility's first quarter net loss was $994 million in 2001 as compared to the prior year's first quarter net income of $234 million. The decrease was primarily the result of the $1.9 billion charge to earnings for undercollected wholesale purchased power costs in excess of the amounts provided in customer rates for recovery of such costs. The undercollected amounts include ISO costs incurred during the first quarter of 2001. Financial reporting standards require that the amounts be accounted for as expenses unless they can be deemed probable of recovery. Due to uncertainty created by the energy crisis, the Utility cannot meet the accounting probability standard. Operating Income - ---------------- There was an operating loss of $1,420 million for the first quarter of 2001 as compared to operating income of $570 million for the first quarter of 2000. This decrease is due to the charge to earnings for undercollected wholesale purchased power costs discussed above. Operating Revenues - ------------------ The Utility's operating revenues in the first quarter were $2.6 billion in 2001 as compared to operating revenues of $2.2 billion in 2000. Gas revenues increased $686 million while electric revenues decreased $342 million. The increase in gas revenues was primarily due to increased revenues from residential customers due to higher gas billing rates resulting from high natural gas prices and increased usage due to cooler temperatures in the first quarter of 2001. The decrease in electric revenues of $342 million was primarily due to credits issued to direct access customers (resulting from higher wholesale power market prices) and due to the reduction of revenue resulting from the CPUC's March 27, 2001, order, (which was retroactive to January 16, 2001) that a portion of the Utility's revenues be remitted to the DWR in compensation for the DWR's electricity purchases. See Note 2 of the Notes to the Condensed Consolidated Financial Statements for a discussion of the March 27, 2001, order and direct access credits. These decreases were partially offset by increased revenue from the Utility's 1.0 cent per kWh surcharge implemented on January 4, 2001. Direct access credits are provided to customers that procure electricity from independent generators under long-term contracts and receive a credit on their utility bills at prevailing market prices. In accordance with CPUC regulations, the Utility provides an energy credit to those customers (known as direct access customers) who have chosen to buy their electric generation energy from an energy service provider (ESP) other than the Utility. The Utility bills direct access customers based upon fully bundled rates (generation, distribution, transmission, public purpose programs, and a competition transition charge). However, the direct access customer receives an energy credit equal to the average market prices multiplied by customer energy usage for the period, with the customer being obligated to their ESP at their direct access contract rate. For the three-month period ending March 31, 2001, the estimated total of accumulated credits for direct access customers that have not been paid by the Utility is approximately $322 million. Such amounts are reflected on the Utility's condensed consolidated balance sheet. The actual amount that will be refunded to ESPs will be dependent upon when the rate freeze ends and whether there are any adjustments made to wholesale energy prices by FERC. 47Operating Expenses - ------------------ The table below summarizes the changes in the Utility's operating expenses:
Three months ended March 31, -------------- Increase Increase 2001 2000 (Decrease) (Decrease) ---- ---- ---------- ----------(in millions) Cost of electric energy, net $ 2,427 $ 513 $1,914 373% Cost of gas 916 283 633 224% Operating and maintenance 574 551 23 4% Depreciation, amortization, and decommissioning 65 301 (236) (78%) Total operating expenses $3,982 $1,648 $2,334 142%The Utility's operating expenses increased to a total of $4 billion in 2001 compared to a total of $1.6 billion in the first quarter of 2000. The overall increase in operating expenses is primarily attributable to the Utility's $1.9 billion charge to earnings for undercollected wholesale purchased power costs as described above. In addition, operating expenses increased due to the ongoing increases in the cost of gas, with the average costs reaching $9.24 per DTh in March 2001 compared to $2.27 per DTh in March 2000. Wholesale electric energy costs in excess of the revenue for the generation component of frozen rates were reflected as deferred electric procurement costs in 2000. The decrease of $236 million in depreciation expenses for the three months ended March 31, 2001 and 2000, respectively, is attributable to the utility no longer recording amortization of generation-related transition costs. In December 2000, the Utility wrote-off these remaining generation-related transition costs. Dividends - --------- The Utility has suspended payment of its common and preferred dividends. Dividends on preferred stock are cumulative. Until cumulative dividends on preferred stock are paid, the Utility may not pay any dividends on its common stock. Until its financial condition is restored, the Utility is precluded from paying dividends to PG&E Corporation and PG&E Holdings, Inc. PG&E National Energy Group Operating Income - ---------------- Operating income at PG&E NEG decreased $26 million in the first quarter of 2001 as compared to 2000, primarily related to income from a portfolio management transaction in 2000, and the disposition of the Texas operation in late 2000. This decrease was partially offset by favorable results in the merchant plants attributable to higher prices in the Northeast. Long-Term Contract Plants benefited from higher prices in the Mid-Atlantic region. PG&E Pipeline earnings increased as a result of higher short-term firm revenues. Operating Revenues - ------------------ PG&E NEG operating revenues increased $1,389 million in 2001 compared to 2000. The increase is a result of 48increased commodity sales as PG&E NEG has focused its trading efforts on asset management and higher-margin trades. In addition, increases in the price of power and gas and the higher short-term firm revenues described above have resulted in increased revenues. These increases were partially offset by a decrease in Interstate Pipeline Operations revenues as a result of the sale of the Texas operations in late 2000. Operating Expenses - ------------------ Operating expenses at PG&E NEG increased $1,415 million in 2001 compared to the prior year. The increase results from the increases in the cost of power and gas, partially offset by lower cost of sales and other operating expenses at PG&E Pipeline reflective of the disposal of the Texas assets. Dividends - --------- PG&E NEG currently intends to retain any future earnings to fund the development and growth of its business. Further, PG&E NEG is precluded from paying dividends, unless it meets certain financial tests. Therefore, it is not anticipating paying any cash dividends on its common stock in the foreseeable future. REGULATORY MATTERS A significant portion of PG&E Corporation's operations is regulated by federal and state regulatory commissions. These commissions oversee service levels and, in certain cases, PG&E Corporation's revenues and pricing for its regulated services. The Utility is the only subsidiary with significant regulatory proceedings at this time. The Utility's significant regulatory proceedings are discussed below. Regulatory proceedings associated with electric industry restructuring are discussed above in "The California Energy Crisis." See Note 2 of the Notes to the Condensed Consolidated Financial Statements. The Utility's General Rate Case (GRC) - ------------------------------------- The CPUC authorizes an amount known as "base revenues" to be collected from ratepayers to recover the Utility's basic business and operational costs for its gas and electric distribution operations. Base revenues, which include non- fuel-related operating and maintenance costs, depreciation, taxes, and a return on invested capital, currently are authorized by the CPUC in GRC proceedings. The CPUC's final decision in the Utility's 1999 GRC application increased annual electric distribution revenues by $163 million and annual gas distribution revenues by $93 million over 1998 authorized base revenues. In March 2000, two interveners filed applications for rehearing of the 1999 GRC decision, alleging that the CPUC committed legal errors by approving funding in certain areas that were not adequately supported by record evidence. In April 2000, the Utility filed its response to these applications for rehearing, defending the GRC decision against the allegations of error. A CPUC decision on the applications for rehearing is pending. In the 1999 GRC decision the CPUC ordered that the Utility file a 2002 GRC. As a result of the current energy crisis, the procedural schedule has been delayed pending the CPUC's resolution of the Utility's request that it be permitted to file an alternative schedule or an alternative to the 2002 GRC. An earlier decision initially delaying the schedule affirms that rates would still become effective on January 1, 2002, although the CPUC decision may not be rendered until after that date. 49Order Instituting Investigation (OII) into Holding Company Activities - --------------------------------------------------------------------- On April 3, 2001, the CPUC issued an order instituting an investigation into whether the California investor-owned utilities, including the Utility, have complied with past CPUC decisions, rules, or orders authorizing their holding company formations and/or governing affiliate transactions, as well as applicable statutes. The order states that the CPUC will investigate (1) the utilities' transfer of money to their holding companies since deregulation of the electric industry commenced, including during times when their utility subsidiaries were experiencing financial difficulties; (2) the failure of the holding companies to financially assist the utilities when needed; (3) the transfer, by the holding companies, of assets to unregulated subsidiaries; and (4) the holding companies' action to "ringfence" their unregulated subsidiaries. The CPUC will also determine whether additional rules, conditions, or changes are needed to adequately protect ratepayers and the public from dangers of abuse stemming from the holding company structure. The CPUC will investigate whether it should modify, change, or add conditions to the holding company decisions, make further changes to the holding company structure, alter the standards under which the CPUC determines whether to authorize the formation of holding companies, otherwise modify the decisions, or recommend statutory changes to the California Legislature. As a result of the investigation, the CPUC may impose remedies (including penalties), prospective rules, or conditions, as appropriate. PG&E Corporation and the Utility believe that they have complied with applicable statutes, CPUC decisions, rules, and orders. As described above, on April 6, 2001, the Utility filed a voluntary petition for relief under Chapter 11 of the U.S. Bankruptcy Code. PG&E Corporation and the Utility believe that to the extent the CPUC seeks to investigate past conduct for compliance purposes, the investigation is automatically stayed by the bankruptcy filing. Neither the Utility nor PG&E Corporation can predict what the outcome of the investigation will be or whether the outcome will have a material adverse effect on their results of operations or financial condition. On April 13, 2001, the Utility filed an application for rehearing of the classification of the OII as quasi-legislative, arguing that the issues of compliance, violations, and remedies for past violations must be reclassified as adjudicatory. A ruling is expected on May 14, 2001. The Utility's 2001 Attrition Rate Adjustment (ARA) - -------------------------------------------------- In July 2000, the Utility filed an ARA application with the CPUC to increase its 2001 electric distribution revenues by $189 million, effective January 1, 2001. The increase reflects inflation and the growth in capital investments necessary to serve customers. The Utility did not request an increase in gas distribution revenues. In December 2000, the CPUC issued an interim order finding that a decision on the application cannot be rendered by January 1, 2001, and determining that if attrition relief is eventually granted, that relief will be effective as of January 1, 2001. On May 8, 2001, the CPUC's Office of Ratepayer Advocates (ORA) submitted its report on the Utility's request, recommending that the CPUC deny the Utility's request and order that the Utility refund directly to ratepayers approximately $23 million accumulated during 1999 and 2000 in the Utility's Vegetation Management Balancing Account. The Utility believes that ORA's recommendations are unjustified and intends to challenge those recommendations in hearings scheduled to commence on June 6, 2002. Further, the Utility had proposed to return the approximately $23 million as a credit to the Utility's TRA in which undercollected power purchase costs are recorded. The Utility's Cost of Capital Proceedings - ----------------------------------------- Each year, the Utility files an application with the CPUC to determine the authorized rate of return that the Utility may earn on its electric and gas distribution assets and recover from ratepayers. Since February 17, 2000, the Utility's adopted return on common equity (ROE) has been 11.22% on electric and gas distribution operations, resulting in an authorized 9.12% overall rate of return (ROR). The Utility's earlier adopted ROE was 10.6%. In May 2000, the Utility filed an application with the CPUC to establish its authorized ROR for electric and gas distribution operations for 2001. The application requests an ROE of 12.4%, and an overall ROR of 9.75%. If granted, the requested ROR would increase electric distribution revenues by approximately $72 million and gas distribution revenues by approximately $23 million. The application also requests authority to implement an Annual Cost of Capital Adjustment Mechanism for 2002 through 2006 that would replace the annual cost of capital proceedings. The proposed adjustment mechanism would modify the Utility's cost of capital based on changes in an interest rate index. The Utility also proposes to maintain its currently authorized capital structure of 46.2% long-term debt, 5.8% 50preferred stock, and 48% common equity. In March 2001, the CPUC issued a proposed decision recommending no change to the current 11.22% ROE for test year 2001. This authorized ROE results in a corresponding 9.12% return on rate base and no change in the Utility's electric or gas revenue requirement for 2001. A final CPUC decision is pending. The Utility's FERC Transmission Rate Cases - ------------------------------------------ Electric transmission revenues, and both wholesale and retail transmission rates are subject to authorization by the FERC. The FERC has not yet acted upon a settlement filed by the Utility that, if approved, would allow the Utility to recover $391 million in electric transmission rates for the 14-month period of April 1, 1998 through May 31, 1999. During this period, somewhat higher rates have been collected, subject to refund. A FERC order approving this settlement is expected by the end of 2001. The Utility has accrued $29 million for potential refunds related to the 14-month period ended May 31, 1999. In April 2000, the FERC approved a settlement that permits the Utility to recover $298 million in electric transmission rates retroactively for the 10-month period from May 31, 1999 to March 31, 2000. The Utility has accrued $9 million for potential refunds relating to this period. In September 2000, the FERC approved another settlement that permits the Utility to recover $340 million annually in electric transmission rates and made this retroactive to April 1, 2000. Further, in November 2000, the FERC accepted, subject to refund, the Utility's proposal to collect $298 annually in electric transmission rates beginning on May 6, 2001. This decrease in transmission rates relative to previous time periods is due to unusually large balances owed to the Utility from the ISO for congestion and other transmission related services billed by the ISO. In March 2001, PG&E filed at FERC to increase its power and transmission related rates to the Western Area Power Administration (Western). The majority of the increase is related to passing through market power prices billed to the Utility by the ISO and others for services which apply to Western under a pre-existing contract between the Utility and Western. The Utility currently estimates that if FERC grants its request, it will collect from Western an additional $1.125 billion before the contract terminates on December 31, 2004, thereby reducing the revenue that needs to be collected through existing electric retail rates. ENVIRONMENTAL MATTERS We are subject to laws and regulations established to both maintain and improve the quality of the environment. Where our properties contain hazardous substances, these laws and regulations require us to remove those substances or remedy effects on the environment. See Note 8 of the Notes to the Consolidated Financial Statements for further discussion of environmental matters. Utility - ------- The Utility records an environmental remediation liability when site assessments indicate remediation is probable and a range of reasonably likely clean-up costs can be estimated. The Utility reviews its remediation liability quarterly for each identified site. The liability is an estimate of costs for site investigations, remediation, operations and maintenance, monitoring, and site closure. The remediation costs also reflect (1) current technology, (2) enacted laws and regulations, (3) experience gained at similar sites, and (4) the probable level of involvement and financial condition of other potentially responsible parties. Unless there is a better estimate within this range of possible costs, the Utility records the lower end of this range. At December 31, 2000, the Utility expects to spend $320 million, undiscounted, for hazardous waste remediation costs at identified sites, including divested fossil-fueled power plants. The cost of the hazardous substance remediation ultimately undertaken by the Utility is difficult to estimate. A change in the estimate may occur in the near term due to uncertainty concerning the Utility's responsibility, the complexity of environmental laws and regulations, and the selection of compliance alternatives. If other potentially responsible parties are not financially able to contribute to these costs or further investigation indicates that the extent of contamination or necessary remediation is greater than anticipated, the Utility could spend as much as $462 million on these costs. The Utility estimates the upper limit of the range using assumptions least favorable to the Utility, based upon a range of 51reasonably possible outcomes. Costs may be higher if the Utility is found to be responsible for clean-up costs at additional sites or expected outcomes change. The Utility had an environmental remediation liability of $307 million and $307 million at March 31, 2001 and December 31, 2000, respectively. The $320 million accrued at March 31, 2001 includes (1) $139 million related to the pre-closing remediation liability, associated with divested generation facilities (see further discussion in the "Generation Divestiture" section of Note 2 of the Notes to the Condensed Consolidated Financial Statements), and (2) $168 million related to remediation costs for those generation facilities that Utility still owns, manufactured gas plant sites, and gas gathering compressor stations. Of the $307 million environmental remediation liability, the Utility has recovered $193 million through rates, and expects to recover another $84 million future rates. The Utility is seeking recovery of the remainder of its costs from insurance carriers and from other third parties as appropriate. In December 1999, the Utility was notified by the purchaser of its former Moss Landing power plant that it had identified a cleaning procedure used at the plant that released heated water from the intake, and that this procedure is not specified in the plant's National Pollutant Discharge Elimination System (NPDES) permit issued by the Central Coast Regional Water Quality Control Board (Central Coast Board). The purchaser notified the Central Coast Board of its findings. In March 2000, the Central Coast Board requested the Utility to provide specific information regarding the "backflush" procedure used at Moss Landing. The Utility provided the requested information to the Board in April 2000. The Utility's investigation indicated that while it owned Moss Landing, significant amounts of water were discharged from the cooling water intake. While the Utility's investigation did not clearly indicate that discharged waters had a temperature higher than ambient receiving water, the Utility believes that the temperature of the discharged water was higher than that of the ambient receiving water. In December 2000, the executive officer of the Central Coast Board made a settlement proposal to the Utility under which the Utility would pay $10 million, a portion of which would be used for environmental projects and the balance of which would constitute civil penalties. Settlement negotiations are continuing. The Utility's Diablo Canyon employs a "once through" cooling water system, which is regulated under a NPDES Permit, issued by the Central Coast Board. This permit allows Diablo Canyon to discharge the cooling water at a temperature no more than 22 degrees above ambient receiving water and requires that the beneficial uses of the water be protected. The beneficial uses of water in this region include industrial water supply, marine and wildlife habitat, shellfish harvesting, and preservation of rare and endangered species. In January 2000, the Central Coast Board issued a proposed draft Cease and Desist Order (CDO) alleging that, although the temperature limit has never been exceeded, the Diablo Canyon's discharge was not protective of beneficial uses. In October 2000, the Central Coast Board and the Utility reached a tentative settlement of this matter pursuant to which the Central Coast Board has agreed to find that the Utility's discharge of cooling water from the Diablo Canyon plant protects beneficial uses and that the intake technology reflects "best technology available" under Section 316(b) of the Federal Clean Water Act. As part of the settlement, the Utility will take measures to preserve certain acreage north of the plant and will fund approximately $5 million in environmental projects related to coastal resources. The parties are negotiating the documentation of the settlement. The final agreement will be subject to public comment and will be incorporated in a consent decree to be entered in California Superior Court. The Utility believes the ultimate outcome of these matters will not have a material impact on the Utility's financial position or results of operations. PG&E National Energy Group - -------------------------- The U.S. Environmental Protection Agency (EPA) and the U.S. Department of Justice have initiated enforcement actions against a number of electric utilities, several of which have entered into substantial settlements for alleged Clean Air Act violations related to modifications (sometimes more than 20 years ago) of existing coal-fired generating facilities. In May 2000, PG&E NEG received a request for information seeking detailed operating and maintenance histories for the Salem Harbor and Brayton Point power plants and in November 2000, EPA visited both facilities. PG&E NEG believes this request for information is part of EPA's industry-wide investigation of coal-fired plants' compliance with the Clean Air Act requirements governing plant modifications. PG&E NEG also believes that any changes made to the plants were routine maintenance or repairs and, therefore, did not require 52permits. EPA has not issued a notice of violation or filed any enforcement action against PG&E NEG at this time. Nevertheless, if EPA disagrees with PG&E NEG's conclusion with respect to the changes made at the facilities, and successfully brings an enforcement action against PG&E NEG, then penalties may be imposed and further emission reductions might be necessary at these plants. In addition to the EPA, states may impose more stringent air emissions requirements. On May 11, 2001, the Massachusetts Department of Environmental Protection issued regulations imposing restictions on certain air emissions from existing coal-fired power plants. These requirements will primarily impact PG&E NEG's Salem Harbor and Brayton Point generating facilities. Through 2008, it may be necessary to spend approximately $265 million to comply with these regulations. In addition, with respect to approximately 600 megawatts (MW) (or about 12%) of PG&E NEG's New England capacity, it may be necessary to implement fuel conversion, limit operations, or install additional environmental controls. PG&E Gen's existing power plants, including USGenNE facilities, are subject to federal and state water quality standards with respect to discharge constituents and thermal effluents. Three of the fossil-fueled plants owned and operated by USGenNE are operating pursuant to NPDES permits that have expired. For the facilities whose NPDES permit have expired, permit renewal applications are pending, and it is anticipated that all three facilities will be able to continue to operate in substantial compliance with prior permits until new permits are issued. It is estimated that USGenNE's cost to comply with the new permit conditions could be as much as $60 million through 2005. It is possible that the new permits may contain more stringent limitations than prior permits. During September 2000, USGenNE signed a series of agreements that require, among other things, USGenNE to alter its existing waste water treatment at two facilities by replacing certain unlined treatment basins, submit and implement a plan for the closure of such basins, and perform certain environmental testing at the facilities. Although the outcome of such environmental testing could lead to higher costs, the total expected cost of these improvements, which are underway, is $21 million. PG&E NEG anticipates spending up to approximately $330 million, net of insurance proceeds, through 2008, for environmental compliance at currently operating facilities, which primarily addresses: (a) new Massachusetts air regulations made public on April 23, 2001 affecting Brayton Point and Salem Harbor Stations; (b) wastewater permitting requirements that may apply to Brayton Point, Salem Harbor and Manchester Street Stations; and (c) requirements that are reflected in a consent decree concerning wastewater treatment facilities at Salem Harbor and Brayton Point Stations. PRICE RISK MANAGEMENT ACTIVITIES We have established a risk management policy that allows derivatives to be used for both trading and non-trading purposes (a derivative is a contract whose value is dependent on or derived from the value of some underlying asset). We use derivatives for hedging purposes primarily to offset PG&E Corporation's or the Utility's primary market risk exposures, which include commodity price risk, interest rate risk, and foreign currency risk. We also use derivatives, including those used for non-hedging purposes, to participate in markets to gather market intelligence, create liquidity, maintain a market presence, and enhance the value of our trading portfolio. Such derivatives include forward contracts, futures, swaps, options, and other contracts. Net open positions (that is, positions that are not hedged) often exist or are established due to PG&E Corporation's and the Utility's assessment of their responses to changing market conditions. To the extent that PG&E Corporation has an open position, it is exposed to the risk that fluctuating market prices may adversely impact its financial results. PG&E Corporation and the Utility may only engage in the trading of derivatives in accordance with policies established by the PG&E Corporation Risk Policy Committee. Trading is permitted only after the Risk Policy Committee authorizes such activity subject to appropriate financial exposure limits. Under PG&E Corporation, both PG&E NEG and the Utility have their own Risk Management Committees that address matters relating to those companies' respective businesses. These Risk Management Committees are comprised of senior officers. Market Risk 53Commodity Price Risk - -------------------- Commodity price risk is the risk that changes in market prices will adversely affect earnings and cash flows. PG&E Corporation is primarily exposed to the commodity price risk associated with energy commodities such as electricity and natural gas. Therefore, PG&E Corporation's strategy for reducing its commodity price risk exposure for its price risk management activities primarily involves buying and selling fixed-price commodity commitments into the future. In compliance with regulatory requirements, the Utility manages price risk independently from the activities in PG&E Corporation's unregulated business. Price risk management strategies consist of the use of non-trading (hedging) financial instruments to attain our objective of reducing the impact of commodity price fluctuations for electricity and natural gas associated with the Utility's procurement obligations to meet its retail load. While the use of these instruments has been authorized by the CPUC, the CPUC has yet to establish rules around how it will judge the reasonableness of these instruments for electricity purchases. Gains and losses associated with the use of the majority of these financial instruments primarily affect regulatory accounts, depending on the business unit and the specific program involved. In response to high wholesale electricity costs experienced during the summer of 2000, the CPUC in August 2000 eliminated the requirement to procure electricity in the spot market and authorized the Utility to enter into "bilateral agreements" with third parties. These contracts are used to purchase electricity from non-PX sources at fixed prices for terms that may extend to the end of 2005. The purpose of bilateral contracts is to lock in supply and rates on the future purchase of electricity and to reduce price volatility. The CPUC has authorized the Utility to trade natural gas-based financial instruments to manage price and revenue risks associated with its natural gas transmission and storage assets, subject to certain conditions. Furthermore, the Utility was authorized to trade natural gas-based financial instruments to hedge the gas commodity price risks in serving core gas customers. PG&E Corporation's business units measure commodity price risk exposure using value-at-risk and other methodologies that simulate future price movements in the energy markets to estimate the size and probability of future potential losses. We quantify market risk using a variance/co-variance value-at-risk model that provides a consistent measure of risk across diverse energy markets and products. The use of this methodology requires a number of important assumptions, including the selection of a confidence level for losses, volatility of prices, market liquidity, and a holding period. PG&E Corporation uses historical data for calculating the price volatility of our contractual positions and how likely the prices of those positions will move together. The model includes all derivatives and commodity investments in our trading portfolios and only derivative commodity investments for our non-trading portfolio (but not the related underlying hedged position). PG&E Corporation and the Utility express value-at-risk as a dollar amount of the potential loss in the fair value of our portfolios based on a 95% confidence level using a one-day liquidation period. Therefore, there is a 5% probability that PG&E Corporation's portfolios will incur a loss in one day greater than its value-at- risk. The value-at-risk is aggregated for PG&E Corporation by correlating the daily returns of the portfolios for electricity and natural gas for the previous 22 trading days. PG&E NEG's daily value-at-risk commodity price risk exposure as of March 31, 2001, was $11.5 million for trading activities and $8.8 million for non-trading activities. The Utility's daily value-at-risk commodity price risk exposure as of March 31, 2001, was $11.8 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. 54Interest Rate Risk - ------------------ PG&E Corporation, primarily through PG&E NEG, uses interest rate swaps to manage fluctuations in cash flows resulting from their interest rate exposure. PG&E Corporation evaluates both the short-term and long-term interest rate exposures and considers its overall corporate finance objectives when considering proposed hedges. PG&E Corporation does not enter into interest rate derivatives instruments for other than hedging purposes. PG&E Corporation is exposed to the following types of interest rate risk and the strategies used to manage this risk are as described below: Floating rate exposure measures the sensitivity of corporate earnings and cash flows to changes in short-term interest rates. This exposure arises when short- term debt is rolled over at maturity, when interest rates on floating rate notes are periodically reset according to a formula or index, and when floating rate assets are financed with fixed rate liabilities. PG&E Corporation manages its exposure to short-term interest rates by using an appropriate mix of short-term debt, long-term floating rate debt, and long-term fixed rate debt. Financing exposure measures the effect of an increase in interest rates that may occur related to any planned or expected fixed rate debt financing. This includes the exposure associated with replacing debt at maturity. PG&E Corporation will hedge financing exposure in situations where the potential impairment of earnings, cash flows, and investment returns or execution efficiency, or external factors (such as bank imposed credit agreements) necessitate hedging. Refunding exposure measures the effect of an increase in interest rates on the ability to economically refund a callable debt instrument. Corporate bonds typically are issued with a call feature that allows the issuer to retire and replace the bonds at a lower rate if interest rates have fallen. The value of this call feature to the issuer declines with increases in interest rates. PG&E Corporation will hedge refunding exposure when it is economic to repurchase all or part of the underlying debt instrument and replace it with a debt instrument that has lower cost during its remaining life. The guideline for a refunding to be economic is that the net present value savings should exceed 5% of the par value of the debt to be refunded and the refunding efficiency should exceed 85%. Interest rate risk sensitivity analysis is used to measure PG&E Corporation's interest rate price risk by computing estimated changes in the fair value in the event of assumed changes in market interest rates. As of March 31, 2001, if interest rates had averaged 1% higher, estimated losses would have increased by approximately $25 million for PG&E Corporation and estimated losses would have increased by approximately $17 million for the Utility. Foreign Currency Risk - --------------------- PG&E Corporation's objective is to manage foreign currency exposure that may impact its cash flows, corporate earnings, and investment returns as a result of currency exchange rate movements. PG&E Corporation is exposed to the following types of foreign currency risk and the strategies used to manage this risk are as described below: Economic exposure measures the change in value that results from changes in future operating or investing cash flows caused by the timing and level of anticipated foreign currency flows. Economic exposure includes the anticipated purchase of foreign entities, anticipated cash flows, projected revenues and expenses denominated in a foreign currency. Transaction exposure measures changes in value of current outstanding financial obligations already incurred, but not due to be settled until some future date. This includes the agreement to purchase a foreign entity in a currency other than the U.S. dollar, an obligation to infuse equity capital into a foreign entity, foreign currency denominated debt obligations, as well as actual non-U.S. dollar cash flows such as dividends declared but not yet paid. Translation exposure measures potential accounting derived changes in owners' equity that result from translating a 55foreign affiliate's financial statements from its functional currency to U.S. dollars for PG&E Corporation's consolidated financial statements. PG&E Corporation's primary foreign currency exchange rate exposure was with the Canadian dollar. The following instruments are used to hedge foreign currency exposures: forwards, swaps, and options. Based on a sensitivity analysis at March 31, 2001, a 10% devaluation of the Canadian dollar would be immaterial to PG&E Corporation's consolidated financial statements. 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 the Notes to the Condensed Consolidated Financial Statements for further discussion of significant pending legal matters. 56ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK - ------------------------------------------------------------------ PG&E Corporation's andamend Pacific Gas and Electric Company'sprimary market risk results from changes in energy pricesArticles of Incorporation andinterest 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, included in Management's Discussion and Analysis above.) 57PART II. OTHER INFORMATION Item 1. Legal Proceedings ----------------- Pacific Gas and Electric Company Bankruptcy - ------------------------------------------- As previously reported, on April 6, 2001, the Utility filed a voluntary petition for relief under the provisions of Chapter 11Bylaws. The balance of theUnited States Bankruptcy Code. Bankruptcy law imposes an automatic stay to prevent parties from making certain claims or taking certain actions that would interfere withvotes shown below were cast by holders of shares of first preferred stock. At theestate or property of a Chapter 11 debtor. In general,annual meeting, theUtility may not pay pre-petition debts withoutshareholders voted as indicated below on theBankruptcy Court's permission. Since the filing, the Bankruptcy Court has approved various requests by the Utility to permit the Utility to carry on its normal business operations (including payment of employee wages and benefits, refunds of certain customer deposits, use of certain bank accounts, and use cash collateral) and to fulfill certain post- petition obligations to suppliers and creditors. Under the Bankruptcy Code, for the first 120 days after the initial filing, the debtor has the exclusive right to file with the Bankruptcy Court a plan of reorganization that specifies the treatment of claims. After the initial 120- day period (and any extensionsfollowing matters:1. Election of the
period granted byfollowing directors to serve until thecourt) creditorsnext annual meeting of shareholders or until their successors are elected andother partiesqualified (included as Item 1 ininterest may file their own plan of reorganization. The Utility intends to file a plan of reorganization within the 120-day period, subject to the uncertainties inherent in the bankruptcy proceedings. In addition, a number of QFs have requested the Bankruptcy Court to either terminate their contracts requiring them to sell power to the Utility or have the contracts suspended for the summer of 2001 so the QFs can sell power at market-based rates. Before the Utility filed its Chapter 11 petition, some QFs filed complaints in various state courts asking the court to terminate or suspend their contracts with the Utility. The Utility believes these actions have been automatically stayed. Under the Bankruptcy Code, the Utility has the right to reject or assume executory contracts (contracts that require future performance). If the court terminates or suspends the QF contracts or if the Utility rejects the contracts, the amountproxy statement):
For
Withheld
---------------
------------
David R. Andrews
339,609,614
302,968
David A. Coulter
339,614,326
298,256
C. Lee Cox
339,624,319
288,263
William S. Davila
339,623,099
289,483
Robert D. Glynn, Jr.
339,616,628
295,954
David M. Lawrence, MD
339,626,295
286,287
Mary S. Metz
339,617,986
294,596
Carl E. Reichardt
339,618,016
294,566
Gordon R. Smith
339,625,832
286,750
Barry Lawson Williams
339,624,009
288,573
2. Ratification of the
Utility's net open position will increase. If the contracts are not suspended and are ultimately assumed by the Utility, the Utility would be obligated to continue paying the power prices calledappointment of Deloitte & Touche LLP as independent public accountants forunder the contract even when market prices are lower. On April 9, 2001, the Utility also filed a complaint2002 (included as Item 2 inthe Bankruptcy Court against the CPUC and its Commissioners requesting that the court declare that any attempt by the CPUC to implement or enforce the regulatory accounting changesproxy statement):
For:
339,659,728
Against:
122,714
Abstain:
130,140
The proposal was approved bythe CPUC on March 27, 2001 would violate the automatic stay imposed by bankruptcy law, and asking the court to enjoin implementation or enforcement of such accounting changes. As previously disclosed, the accounting changes would require the Utility to restate all of its regulatory books and accounts retroactive to January 1, 1998, the effect of which would be to prolong the electric rate freeze and transform the Utility's under-collected wholesale power costs into generation-related transition costs. The CPUC has filedamotion to dismiss the Utility's complaint and/or for summary judgment. A hearing is set for May 14, 2001, to consider the Utility's request for a preliminary injunction and the CPUC's motion. On April 20, 2001, the Utility filed a cash flow forecast that indicated that based on projected revenues from approved rates, current regulatory rules, and expected outlays, the Utility projected that it expects to have adequate revenues over the next six months to pay its future operating costs, including ongoing payments to QFs and payments presently required to be made to the DWR. A critical assumption in the forecast is that DWR purchases the full net open position for the Utility's customers and that the ISO no longer charges the Utility for any costs other than those attributable to the Utility's own generation resources. On May 2, 2001, the Utility filed a complaint for injunctive and declaratory relief in the United States Bankruptcy Court asking the court to prohibit the California Independent System Operator (ISO) from charging the Utility for 58the ISO's wholesale power purchases made in violation of bankruptcy law, the ISO's tariff, and the FERC's February 14 and April 6, 2001 orders. In the order issued on February 14, 2001, the FERC rejected the ISO's January 5, 2001 proposed tariff amendment concerning credit standards and ordered that the ISO could only buy power on behalf of creditworthy entities. The Utility has not been a creditworthy company under the ISO tariff since January 4, 2001. Despite the FERC orders, the ISO has continued to bill the Utility for the ISO's wholesale power purchases. In its complaint, the Utility also seeks to have the court declare that any action by the ISO to purchase wholesale power for or on behalf of the Utility at costs the Utility is not permitted to fully recover through the generation- related cost component of retail rates, to compel the Utility to accept and pay for such purchases, or to accrue post-petition debt for such purchases (i.e., to accrue debts after April 6, 2001, when the Utility filed its petition under Chapter 11 of the federal Bankruptcy Code), is automatically stayed by bankruptcy law. In addition, the complaint seeks a permanent injunction prohibiting the ISO from taking such actions. In addition, continuing to charge the Utility for such purchases is potentially reducing the value of the Utility's assets significantly, depending on the average retail rate, the wholesale price the ISO has paid for real-time power, and the amount of power purchased by the DWR. The Utility estimates that, if the ISO's actions are not stayed or enjoined, the Utility also would incur costs associated with the DWR's pro rata share of ancillary services and other costs associated with the ISO's procurement of power from third parties unless the ISO were to allocate these other costs to, and bill, the DWR. At present, the Utility does not believe that the ISO is allocating any of these costs to the DWR, or billing the DWR for any such costs. Among other allegations, the Utility's complaint alleges that requiring the Utility to pay more than it can collect in its existing generation-related rates would be improper under the federal Bankruptcy Code because it is not in the best interest of the bankruptcy estate, would be an unauthorized post-petition use of the Utility's property, and if allowed to continue, would jeopardize the administration of the bankruptcy estate and the Utility's ability to reorganize. The Utility believes the ISO is violating its own tariff, as well as FERC orders and federal bankruptcy law by continuing to purchase power on behalf of the Utility. The United States Bankruptcy Trustee has appointed a ratepayers' committee composed of business representatives, members of government agencies, and consumer groups. As a party to the proceedings, the ratepayers' committee would be entitled to investigate the Utility's plan of reorganization and offer alternatives. On May 9, 2001, the Utility filed a motion with the Bankruptcy Court asking the Court to vacate the Trustee's appointment of the ratepayers' committee because the creation of the committee is not authorized by the Bankruptcy Code. Under the Bankruptcy Code, only creditors and equity security holders are eligible for appointment to a committee by the Trustee. Under the Bankruptcy Code, there are legitimate ways by which the ratepayers can be represented and heard in the process, for example, through the California Attorney General's Office. In addition, the Bankruptcy Code provides flexibility and discretion to the court to allow parties to intervene in the case when they have standing to do so. The first meeting of creditors is scheduled for June 7, 2001. The last day for creditors to file proofs of claim is September 5, 2001. Pacific Gas and Electric Company v. California Public Utilities Commissioners - ------------------------------------------------------------------------------ As described in the Annual Report on Form 10-K filed by PG&E Corporation and Pacific Gas and Electric Company for the year ended December 31, 2000, the Utility filed a lawsuit against the Commissioners of the California Public Utilities Commission (CPUC), currently pending in the United States District Court for the Central District of California, asking the court to declare that the federally approved wholesale power costs the Utility has incurred to serve its customers are recoverable in retail rates. On May 2, 2001, the court dismissed the Utility's complaint without prejudice to refile the lawsuit at a later time. Although ruling in the Utility's favor on five of the six grounds for dismissal, the court found that the Utility's complaint was not ripe because some of the CPUC's decisions that PG&E was challenging are non-final interim orders that will only become final upon a grant or denial of rehearing. 59Finding in the Utility's favor, the court ruled that: (i) the Utility's prior state court proceedings challenging the CPUC's October 21, 1999 post-transition-period ratemaking decision on state law grounds did not bar the Utility's federal claims, because the Utility had properly reserved its federal claims in its petition to the California Supreme Court, and because the Utility had not litigated the federal claims in the state court. (ii) Federal court jurisdiction over the Utility's preemption claim was proper. (iii) The court need not stay or dismiss the Utility's case in deference to the ongoing CPUC proceedings. (iv) The Johnson Act, which generally precludes federal courts from enjoining state utilities commission rate orders, did not apply to the Utility's action because the Utility had pleaded a claim that federal law preempted state law, which does not fall under the terms of the statute. (v) The Utility's case need not be dismissed with prejudice based on the CPUC's asserted sovereign immunity under the Eleventh Amendment to the U.S. Constitution, because the Eleventh Amendment does not bar an action, such as the Utility's, to enjoin state officers from violating federal law. Wilson vs. PG&E Corporation and Pacific Gas and Electric Company - ----------------------------------------------------------------- As described in the Annual Report on Form 10-K filed by PG&E Corporation and Pacific Gas and Electric Company for the year ended December 31, 2000, two complaints were filed against PG&E Corporation and Pacific Gas and Electric Company in the Superior Court of the State of California, San Francisco County: Richard D. Wilson v. Pacific Gas and Electric Company et al., ("Wilson I"), and Richard D. Wilson v. Pacific Gas and Electric Company et al., ("Wilson II"). PG&E Corporation and the Utility believe these complaints to be without merit. As previously disclosed, the Utility filed a notice of automatic stay on April 11, 2001, pursuant to the Bankruptcy Code. On April 19, 2001, the Court signed stipulations between PG&E Corporation and plaintiffs to stay all proceedings in the cases as against PG&E Corporation. PG&E Corporation and the Utility are unable to predict whether the outcome of this litigation, if it were to proceed, will have a material adverse effect on their financial condition or results of operation. Compressor Station Chromium Litigation - -------------------------------------- As described in the Annual Report on Form 10-K filed by PG&E Corporation and Pacific Gas and Electric Company for the year ended December 31, 2000, several suits are pending in California courts against the Utility. One of these suits also names PG&E Corporation as a defendant. On May 2, 2001, another complaint entitled Boyd, et al. v. PG&E, et al., was filed in Los Angeles Superior Court on behalf of 14 plaintiffs. The Utility has not been served yet. The complaint alleges personal injuries, wrongful death, and loss of consortium, arising from alleged exposure to chromium at the Utility's gas compressor stations located at Hinkley and Kettleman, California. Plaintiffs seek compensatory and punitive damages. The complaint does not name PG&E Corporation as a defendant. There are now ten cases comprising the compressor station chromium litigation. There are now approximately 1,160 plaintiffs in these cases. The Utility believes that all ten cases have been stayed by the automatic stay provisions of the Bankruptcy Code. PG&E Corporation and the Utility believe that the ultimate outcome of this matter will not have a material adverse effect on their financial condition or results of operation. Federal Securities Lawsuit - -------------------------- 60On April 16, 2001, a complaint was filed against PG&E Corporation and Pacific Gas and Electric Company in the federal court for the Central District of California entitled Jack Gillam; DOES 1 TO 5, Inclusive, and All Persons similarly situated vs. PG&E Corporation, Pacific Gas and Electric Company; and DOES 6 to 10, Inclusive. The complaint alleges that PG&E Corporation and the Utility violated federal securities laws, generally acceptable accounting principles, and other regulations or accounting rules, by issuing allegedly false and misleading financial statements in the second and third quarters of 2000, reporting net income of $753 million for the nine-month period ending September 30, 2000, instead of an alleged net loss for that period of up to $2.1 billion. According to the complaint, defendants failed to properly account in the second and third quarters of 2000 for alleged under-collected power purchase costs and PG&E Corporation announced in March 2001 that it intended to take a $4.1 billion write-off. Plaintiff purports to bring the action individually and on behalf of a class of individuals who purchased PG&E Corporation's common stock during the period from June 1, 2000, to March 31, 2001, claiming that the alleged misrepresentations caused them to pay inflated prices for the stock. Plaintiff seeks damages in excess of $2.4 billion, punitive damages, interest, injunctive relief, and attorneys' fees. The complaint was filed after the Utility filed for reorganization under Chapter 11 of the U.S. Bankruptcy Code. The Utility informed plaintiff that the action is stayed by the automatic stay provisions of the Bankruptcy Code and on or about April 23, 2001, plaintiff filed a notice of voluntary dismissal without prejudice with respect to the Utility. Analysis of the complaint by PG&E Corporation is at a preliminary stage, but PG&E Corporation believes the allegations to be without merit and intends to present a vigorous defense. PG&E Corporation is unable to predict whether the outcome of this litigation will have a material adverse effect on its financial condition or results of operation. Item 2. Changes in Securities and Use of Proceeds - -------------------------------------------------- The shares of PG&E NEG are owned directly by PG&E National Energy Group, LLC, a Delaware limited liability company (NEG LLC). NEG LLC is wholly owned by PG&E Corporation. As disclosed in a Current Report on Form 8-K filed by PG&E Corporation with the Securities and Exchange Commission on March 2, 2001, in connection with a two term loans obtained by PG&E Corporation from General Electric Capital Corporation and Lehman Commercial Paper Inc., NEG LLC has granted to affiliates of the lenders an option that entitles these affiliates to purchase 2 to 3 percentmajority of the sharesof PG&E NEG depending on how long the loans are outstanding, at an exercise price of $1.00. The percentage will be calculated onrepresented and voting (including abstentions) which shares voting affirmatively also constituted afully diluted basis asmajority of thedate of full repayment of the loans. The option becomes exercisable on the date of full repayment or, earlier, if an initial public offering of the shares of PG&E NEG (IPO) were to occur. PG&E Corporation has granted to the holders of the optionrequired quorum.3. Management proposal regarding a
further put option under which the holders of the option have the right to require PG&E Corporation to repurchase the option at a purchase price equal to the fair market value of the underlying PG&E NEG shares, which right is exercisable at any time after the earlier of full repayment of the loans or 45 days before expiration of the option if an IPO has not occurred. The put option will expire 45 days after maturity of the loans. The issuance of the put option by PG&E Corporation was not registered under the Securities Act of 1933 in reliance on the exemption afforded by Section 4(2). Item 3. Defaults Upon Senior Securities - ---------------------------------------- The Utility has authorized 75 million shares of First Preferred Stock ($25 par value), which may be issued as redeemable or non-redeemable preferred stock. At March 31, 2001, the Utility had issued and outstanding 5,784,824 shares of non- redeemable preferred stock and 5,973,456 shares of redeemable preferred stock. The Utility's redeemable preferred stock is subject to redemption at the Utility's option, in whole or in part, if the Utility pays the specified redemption price plus accumulated and unpaid dividends through the redemption date. The Utility's redeemable preferred stock with mandatory redemption provisions consists of 3 million shares of the 6.57 percent series and 2.5 million shares of the 6.30 percent series at December 31, 2000. The 6.57 percent series and 6.30 percent series may be redeemed at the Utility's option beginning in 2002 and 2004, respectively, at par value 61plus accumulated and unpaid dividends through the redemption date. These series of preferred stock are subject to mandatory redemption provisions entitling them to sinking funds providing for the retirement of stock outstanding. At December 31, 2000, the redemption requirements for the Utility's redeemable preferred stock with mandatory redemption provisions are $4 million per year beginning 2002, and $3 million per year beginning 2004, for the series 6.57 percent and 6.30 percent, respectively. Holders of the Utility's non-redeemable preferred stock 5 percent, 5.5 percent, and 6 percent series have rights to annual dividends per share ranging from $1.25 to $1.50. Due to the California energy crisis, the Utility's Board of Directors did not declare the regular preferred stock dividends for the three-month periods ending January 31, 2001 (normally payable on February 15, 2001) and April 30, 2001 (normally payable May 15, 2001). Dividends on all Utility preferred stock are cumulative. All shares of preferred stock have voting rights and equal preference in dividend and liquidation rights. The dividend for the three-month period ending January 31, 2001 became a dividend in arrears and, as such, will accumulate from period to period. Upon liquidation or dissolution of the Utility, holders of preferred stock would be entitled to the par value of such shares plus all accumulated and unpaid dividends, as specified for the class and series. Until cumulative dividends on its preferred stock are paid, the Utility may not pay any dividends on its common stock, nor may the Utility repurchase any of its common stock. Accumulated and unpaid preferred stock dividends for the three-month period ending January 31, 2001 amounted to $6 million. As previously reported, the total defaulted commercial paper outstanding as of May 10, 2001, was $873 million. As of May 10, 2001, the Utility had drawn and had outstanding $938 million under the bank credit facility, which was also in default. With regard to certain pollution control bond-related debt of the Utility, the Utility has been in default under the credit agreements with the banks that provide letters of credit as credit and liquidity support for the underlying pollution control bonds. These defaults included the Utility's non-payment of other debt in excess of $100 million and the Utility's filing of a petition for reorganization under Chapter 11 of the U.S. Bankruptcy Code. As a result of these defaults, several of the letter of credit banks caused the acceleration and redemption of four series of pollution control bonds. All of these redemptions were funded by the letter of credit banks resulting in like obligations from the Utility to the banks, which have not been paid. As of May 10, 2001, the total principal of the bonds (and related loans) accelerated and redeemed was $454 million. As of May 1, 2001, the Utility did not make interest payments of $5 million on pollution control bonds series 96B-F and 97A-C. With regard to certain pollution control bond-related debt of the Utility backed by the Utility's mortgage bonds, an event of default has occurred under the relevant loan agreements with the California Pollution Control Financing Authority due to the Utility's bankruptcy filing. The Utility's filing of a petition for reorganization under Chapter 11 of the U.S. Bankruptcy Code also constitutes a default under the indenture that governs its medium term notes ($287 million aggregate amount outstanding), five-year 7.375% senior notes ($680 million aggregate amount outstanding), and floating rate notes ($1.24 billion aggregate amount outstanding). In addition, on May 1, 2001, the Utility did not make interest payments on the 7.375% senior notes and the $1.24 billion floating rate notes. As of May 1, 2001, the total arrearage of these interest payments was $48 million. With regard to the 7.90% Quarterly Income Preferred Securities (QUIPS) and the related 7.90% Deferrable Interest Debentures (debentures), the Utility's filing of a petition for reorganization under Chapter 11 of the U.S. Bankruptcy Code is an event of default under the applicable indenture. Pursuant to the related trust agreement, the trustee is required to take steps to liquidate the trust and distribute the debentures to the QUIPS holders. Item 5. Other Information - -------------------------- Ratio of Earnings to Fixed Charges and Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends 62Pacific Gas and Electric Company's earnings to fixed charges ratio for the three months ended March 31, 2001, was a negative 6.67. Pacific Gas and Electric Company's earnings to combined fixed charges and preferred stock dividends ratio for the three months ended March 31, 2001, was a negative 6.40. The negative ratios of earnings to fixed charges and earnings to combined fixed charges and preferred stock dividends indicates a deficiency in earnings of $1,618 million and $1,618 million respectively. 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, relatingproposed amendment to Pacific Gas and Electric Company'svarious classesArticles ofdebt and first preferred stock outstanding.Incorporation to establish a classified board of directors (included as Item6. Exhibits and Reports on Form 8-K -------------------------------- (a) Exhibits: Exhibit 11 Computation5 in proxy statement):
For:
330,963,622
Against:
2,068,545
Abstain:
268,670
Broker non-vote (2):
6,611,745
The proposal was approved by a majority ofEarnings Per Common Share (incorporated by reference from PG&E Corporation andthe outstanding shares.4. Management proposal regarding proposed amendments to Pacific Gas and Electric Company's
Quarterly Report on Form 10-Q forArticles of Incorporation and Bylaws to reduce thequarter ended March 31, 2001, Exhibit 11.) Exhibit 12.1 Computationauthorized range ofRatiosdirectors and transfer the provision that establishes the authorized range ofEarningsdirectors from the Bylaws toFixed Charges for Pacific Gas and Electric Company (incorporatedthe Articles of Incorporation (included as Item 6 in proxy statement):
For:
332,684,409
Against:
248,428
Abstain:
368,000
Broker non-vote(2):
6,611,745
The proposal was approved by
reference from PG&E Corporation anda majority of the outstanding shares.5. Management proposal regarding a proposed amendment to Pacific Gas and Electric Company's
Quarterly Report on Form 10-Q forArticles of Incorporation and Bylaws to transfer thequarter ended March 31, 2001, Exhibit 12.1.) Exhibit 12.2 Computationprovision that prohibits cumulative voting in the election ofRatiosdirectors from the Bylaws to the Articles ofEarningsIncorporation (included as Item 7 in proxy statement):
For:
331,504,332
Against:
1,416,314
Abstain:
380,191
Broker non-vote(2):
6,611,745
The proposal was approved by a majority of the outstanding shares.
6. Management Proposal regarding a proposed amendment to
Combined Fixed Charges and Preferred Stock Dividends for Pacific Gas and Electric Company (incorporated by reference from PG&E Corporation andPacific Gas and Electric Company'sQuarterly Report on Form 10-Q forArticles of Incorporation to include constituency provision (included as item 8 in proxy statement):
For:
331,403,941
Against:
1,408,975
Abstain:
487,821
Broker non-vote(2):
6,611,745
The proposal was approved by a majority of the
quarter ended March 31, 2001, Exhibit 12.2.) (b) The following Current Reports on Form 8-K were filed during the first quarter of 2001 and through the date hereof (2): 1. January 4, 2001 Item 5. Other Events--California Energy Crisis 2. January 5, 2001 Item 5. Other Events-- California Public Utilities Commission Decision Issued 3. January 10, 2001 Item 5. Other Events-- A. Current Financial Condition B. Impending Natural Gas Shortage C. ISO's Requested Tariff Amendmentoutstanding shares.7. Management proposal regarding a proposed amendment to
Creditworthiness Standards 4. January 10, 2001 Item 5. Other Events--Suspension of PG&E Corporation andPacific Gas and ElectricCompany Dividends 5. January 17, 2001 Item 5. Other Events-- A. Ratings Downgrades 63B. Liquidity ImpactsCompany's Articles of Incorporation to require that shareholder action be taken at an annual or special meeting (included as item 9 in proxy statement):
For:
331,517,507
Against:
1,439,990
Abstain:
343,340
Broker non-vote(2):
6,611,745
The proposal was approved by a majority of the outstanding shares.
(2) 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
Financial Condition 6. February 1, 2001 Item 5. Other Events-- A. Wholesale Power Payments B. Liquidity Impacts and Financial Condition C. Federal Lawsuit D. Rate Stabilization Plan Proceeding E. Consulting Report F. CPUC Emergency Action 7. February 14, 2001 Item 5. Other Events-- A. Assembly Bill 1X B. Liquidity Impacts and Financial Condition C. Federal Lawsuit 8. February 28, 2001 Item 5. Other Events-- A. Recent Regulatory Action B. Liquidity C. Wilson vs. PG&E Corporation and Pacific Gas and Electric Company 9. March 2, 2001 - Filed by PG&E Corporation only Item 5. Other Events-- PG&E Corporation debt restructure 10. March 9, 2001 Item 5. Other Events A. Recent Regulatory Action B. 2001 Cost of Capital Proceeding 11. March 16, 2001 Item 5. Other Events - Liquidity and Financial Condition 12. March 23, 2001 Item 5. Other Events A. Recent Legislative and Regulatory Actions B. Accounting Treatment C. Bank Forbearance Agreement 13. March 30, 2001 Item 5. Other Events A. Recent Regulatory Actions B. Accounting Treatment C. Liquidity and Financial Condition 14. April 6, 2001 (as amended) filed by PG&E Corporation only Item 5. Other Events - Pacific Gas and Electric Company Bankruptcy 15. April 6, 2001 (as amended) filed by Pacific Gas and Electric Company only Item 3. Other Events - Bankruptcy or Receivership. 16. May 7, 2001 - filed by PG&E Corporation only Item 9. Regulation FD Disclosure 6417. May 8, 2001 Item 5. Other Events A. Federal Lawsuit B. Pacific Gas and Electric Company Bankruptcy (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). 65has not received voting instructions from the beneficial owner as to such proposals. SIGNATURE
Pursuant to the requirements of the Securities Exchange
Actact of 1934, the registrants have duly caused this report to be signed on their behalf by the undersigned thereunto duly authorized.PG&E CORPORATION By /s/ CHRISTOPHER P. JOHNS ------------------------ CHRISTOPHER P. JOHNS Senior Vice President and Controller (duly authorized officer and principal accounting officer) PACIFIC GAS AND ELECTRIC COMPANY By /s/ KENT M. HARVEY ----------------------- KENT M. HARVEY Senior Vice President, Chief Financial Officer, and Treasurer (duly authorized officer and principal financial officer)
PG&E CORPORATION
PACIFIC GAS AND ELECTRIC COMPANY
BY: LINDA Y.H. CHENG
LINDA Y.H. CHENG
LINDA Y.H. CHENG
Corporate Secretary
(duly authorized officer)
Dated:
March 5,June 13, 200266Exhibit Index Exhibit No. Description of Exhibit Exhibit 11 Computation of Earnings Per Common Share (incorporated by reference from PG&E Corporation and Pacific Gas and Electric Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2001, Exhibit 11.) Exhibit 12.1 Computation of Ratios of Earnings to Fixed Charges for Pacific Gas and Electric Company (incorporated by reference from PG&E Corporation and Pacific Gas and Electric Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2001, Exhibit 12.1.) Exhibit 12.2 Computation of Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividends for Pacific Gas and Electric Company (incorporated by reference from PG&E Corporation and Pacific Gas and Electric Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2001, Exhibit 12.2.) 67